An Assessment of Oil Shale Technologies

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An Assessment of Oil Shale Technologies

June 1980

NTIS order #PB80-210115



Library of Congress Catalog Card Number 80-600101

For sale by the Superintendent of Documents, U.S. Government Printing OfficeWashington, D.C. 20402 Stock No. 052-003 -00759-2



Foreword

For many decades, the oil shale resources of the Western United States have

been considered possible contributors to the Nation’s liquid fuel supply. This vol-ume reviews several paths to development of these resources and the likely conse-quences of following these paths. A chapter providing background informationabout the nature of oil shale is followed by an evaluation of technologies for recov-ery of shale oil. The economics and finances of establishing an industry of varioussizes are analyzed. The fact that much of the best shale is located on Federal landis examined in light of the desire to increase use of the resources. The conse-quences of shale development in terms of impact on the physical and social envi-ronments, and a discussion of the availability of water complete the report.

Policy options addressing barriers that could hinder the establishment of theindustry are presented. These options, designed primarily for Congressional con-sideration, are limited to the obstacles OTA identified as currently existing. Otherissues, of equal importance for the protection of the environment and the commu-

nities, but not constraints to development, are discussed in the body of the report.The assessment deals only with oil shale; no systematic attempt was made in thisstudy to compare this energy source with liquid fuel sources other than conven-tional petroleum or with alternative energy strategies. Other OTA assessmentsare addressing many of these topics.

Volume II evaluates the Federal Prototype Oil Shale Leasing Program. Bothvolumes were prepared in response to requests from the Senate Committee on En-ergy and Natural Resources. We hope they will be of value to the entire Congresswhen considering domestic energy policies.

JOHN H, GIBBONSDirector

///



Oil Shale Advisory Committee

James H. Gary, ChairmanColorado School of Mines

James BoydPrivate Consultant

William BrennanRancherRio Blanco County, Colo.

Robert L. Coble*Massachusetts Institute of Technology

Roland C. FischerColorado River Water Conservation

District

John D. HaunColorado School of Mines

Carolyn A. JohnsonPublic Lands Institute

Sidney KatellWest Virginia University

Estella B. LeopoldUniversity of Washington

*Resigned March 1 9 7 9 .* * D i e d April 1979.

Charles H. Prien**Denver Research Institute

John F. RedmondRetired, Shell Oil Co.

Richard D. RidleyOccidental Oil Shale, Inc.

Raymond L. SmithMichigan Technological University

Thomas W. Ten Eyck Rio Manco Oil Shale Co.

Wallace TynerPurdue University

Glen D. WeaverColorado State University

NOTE: The Advisory Committee provided advice and comment throughout the assessment, but doesnot necessarily approve, disapprove, or endorse the report, for which OTA assumes full responsibility.



Oil Shale Technology Project Staff

Lionel S. Johns, Assistant Director, OTAEnergy, Materials, and International Security Division

Audrey Buyrn, Materials Program Manager

Thomas A. Sladek, Principal Investigator

William E. Davis, Social and Economic ImpactsPatricia L. Poulton, Environmental and Water AvailabilityPhillip L. Robinson, Economic and Financial

Administrative Staff

Patricia A. Canavan Margaret M. Connors

Carol A. Drohan Jackie S. Robinson

Contributors

Bob Fensterheim, Health Program Donald G. Kesterke, U.S. Bureau of Mines*Mike Gough, Health Program Albert E. Paladino, National Bureau of Standards**

Steven Plotkin, Energy Program

Publishing Staff

John C. Holmes, Publishing Officer

Kathie S. Boss Debra M. Datcher Joanne Heming

*Oil Shale Project Director through January 1979, on detail to OTA from the U.S. Bureau of Mines.**Materials Program Manager through December 1978.



Acknowledgments

This report was prepared by the Office of Technology Assessment Materials

Program staff. The staff wishes to acknowledge the assistance and cooperation of the following contractors and consultants in the collection and analysis of data.

Steven C. Ballard, University of OklahomaColorado School of Mines Research InstituteDenver Research InstituteEnergy and Environmental Analysis, Inc.Renee Ford, editorThe John Muir Institute for Environmental Studies, Inc.Colin J. High, Dartmouth CollegeChristopher T. Hill, Center for Policy Alternatives,

Massachusetts Institute of TechnologyRobert Kalter AssociatesKevin Markey, Friends of the EarthThe Pace Company Consultants and Engineers, Inc.Plant Resources InstituteQuality Development Associates, Inc.Resource Planning Associates, Inc.The Rocky Mountain Center for Occupational and Environmental HealthBernel Stone, Georgia Institute of TechnologyGeorge W. Tauxe, University of OklahomaWater Purification AssociatesRichard W. Wright, Cardozo Law School, Yeshiva UniversityWyoming Research Corp.

The Materials Program staff also wishes to acknowledge the assistance of the large number of Federal, State, and local government groups and private-

sector parties who provided advice and guidance throughout the assessment.



Contents

ChapterPage

1.2.3.

4.5.6.7.8.9.

10.

Summary ... ... o.. ... ... ... o.. o.. .o . . . . . ... ... ... ... ... O.. 3Introduction, . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51Constraints to Oil Shale Commercialization: Policy Options to AddressThese Constraints. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Background. .., . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Technology .,... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Economic and Financial Considerations . . . . . . . . . . . . . . . . . . . . ., .,Resource Acquisition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Environmental Considerations. ., . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Water Availability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Socioeconomic Aspects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

AppendixesA. Description and Evaluation of the Simulation Model . . . . . . . . . . . . . . .B. Assumptions and Data for Computer Analyses. . . . . . . . . . . . . . . . . . . .C, Oil Shale Water Pollutants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .D. Technologies for Managing Point Sources of Wastewater. . . . . . . . . . .E. Acronyms, Abbreviations, and Glossary. . . . . . . . . . . . . . . . . . . . . . . . .

5585

119179235255359419

477480481488513

Vfl



CHAPTER 1





CHAPTER 1

Summary

Summary of Findings

Technology

Two basic retorting technologies are beingdeveloped: modified in situ (MIS) for under-ground retorting, and aboveground retorting(AGR) for processing mined shale. Thesetechnologies are not presently ready forlarge-scale commercialization, but a soundR&D base exists, and they could be madeready either by modular demonstration proj-ects or construction of pioneer plants. TheMIS process is being developed on two sitesand one commercial facility is planned.Aboveground retorts have been tested at up

to one-tenth of full size and at least onecommercial-scale retort is planned in conjunction with an MIS demonstration. Thereare no firm plans for testing other above--ground retorts, although several companieshave shown interest. One process would betested if a lease were provided for the De-partment of Energy (DOE) facility at AnvilPoints, Colo. With financial incentives, twoothers could be tested on private lands. Amultimineral aboveground process awaits theavailability of Federal land, either throughland exchange or limited leasing. Two true in

situ (TIS) processes are being developed withDOE cost sharing, but are only at preliminarystages. Underground mining would also bene-fit from additional research, development,and demonstration. No major technical prob-lems are anticipated either for open pit min-ing or for the conventional room-and-pillarmethod of underground mining. Minor uncer-tainties remain in the upgrading and refiningarea.

Economics

An oil shale industry could benefit the Na-

tion’s economy and security, but would alsoentail several economic risks. For example, a400,000-barrel-per-day (bbl/d) industry es-tablished by 1990 would reduce expendi-tures for imported oil by $4.2 billion per year

and expand regional employment, but would

lead to increases in local inflation for certaingoods, services, and property. The establish-ment of a l-rnillion-bbl/d industry by 1990could save more than $10 billion per year incharges for imported oil and would substan-tially increase local employment; however,the risks associated with overextended de-sign and construction capacity, insufficientequipment manufacturing capability, andpossible inefficiency from tight constructionschedules could cause damaging cost over-runs. Severe regional inflation could be ex-pected for land and housing as well as for

other goods and services.Shale oil may be price competitive with for-eign crude, but when expected real rates of return on investment are 12 percent or less,the commercialization of the industry couldstill be impeded by uncertainties and risks.Among these are cost estimates for construct-ing the facilities, the future price of oil, reg-ulations, and competition with lower cost in-vestments of similar risk in conventional oil orother alternatives. To establish a 200,000-bbl/d (or larger) industry within 10 yearswould require financial incentives. The most

effective would be production tax credits,purchase agreements, and price supports.The smaller firms may need loan guarantees.The net cost of an effectively designed andadministered incentives program could rangefrom $0.60 to $1.40/bbl* of shale oil syn-crude** produced. Financial incentives alonemay not spur development because alterna-tive investments with a greater return for anequivalent level of risk could compete for theavailable capital.

The Government also could build its own

commercial-scale or modular plants, but at*Present barrel equivalent over 20 years at lo-percent dis-count rate.

**A synthetic crude oil produced by adding hydrogen tocrude shale oil. Shale oil syncrude is a high-quality material,comparable with the best grades of conventional crude.

3



4 . An Assessment of 0il Shale Technologies

much higher cost. A Government effort toconstruct and supervise demonstration mod-ules (9,000 to 12,000 bbl/d each) would pro-vide technological information that could re-solve some hitherto unanswered questionsabout the implications of oil shale develop-ment. It might also reduce the initial costs of industry development. However, the Govern-ment’s experience in designing, financing,and operating facilities could be sufficientlydissimilar to that of possible private oper-ators to make the information inapplicable.Government efforts also probably would less-en the commercial and R&D interest of thebusiness community.

Resource Acquisition*

A 400,000-bbl/d production of shale oil

could be achieved by 1990 without extensiveleasing of additional Federal land if subsi-dies are provided so that two presently activeprojects are completed, three suspended proj-ects are resumed, and a new project on pri-vate land is initiated. If these financial incen-tives are not provided, then additional Feder-al leasing will probably be necessary if it isdesired to achieve this level of production. Toproduce 1 million bbl/d by IWO would requireleasing, land exchanges, and substantiallygreater subsidies.

Environment

Air and water quality, topography, wild-life, and the health and safety of the workerswill be affected by the development of an oilshale industry. Many effects will be similarto those caused by any type of mineral devel-opment, but the scale of operations, theirconcentration in a relatively small geo-graphic area, and the nature of the wasteswill present some unique challenges. Manyof the impacts will be regulated by State andFederal laws. The developers plan to comply

by using control technologies from other in-*On May 27, 1980, the Department of the Interior (DOI) an-

nounced it will lease up to four new tracts under the PrototypeProgram and will begin preparations for a new permanentleasing program.

dustries. While there is reason to believe thatthe methods can be made to work, they havenot been tested in commercial-scale oil shaleplants because none exist.

The potential leaching of waste disposalareas and in situ retorts after the plants are

abandoned is a major concern. If it occurs,the leachates could degrade the water qualityin the Colorado River system, a vital waterresource in the Southwest. Such “nonpoint”wastewater discharges are neither well un-derstood nor well regulated, although theClean Water Act provides a regulatoryframework. Techniques for preventing leach-ing need to be demonstrated on a commercialscale. It will be necessary to test a variety of development technologies to assure adequatecontrol of a large industry.

The Clean Air Act is the only existing envi-ronmental law that could prevent the crea-tion of a large industry. It could limit produc-tion in Colorado to 400,000 bbl/d, althoughadditional capacity could be installed inUtah. The procedures for obtaining environ-mental permits can take several years. Al-though unexpected regulatory delays shouldnot preclude the establishment of an individ-ual project, they could lead to cost overrunsand might prevent the deployment of a largeindustry.

Water Availability

A 500,000-bbl/d” industry would increaseby about 1.5 percent the water demands pro-

jected for the Upper Colorado River Basin inthe year 2000. Surplus surface water couldbe available to support this industry until atleast 2025, after which water scarcities maylimit all regional growth. Severe shortagescould be experienced as much as 20 yearssooner if the region develops more rapidlythan expected. Surface water scarcity maylead to intensified ground water develop-

ment, to a shift in the economic base, or to im-portation of water from other areas. Anylarge oil shale industry will need new reser-voirs and diversion projects. Their environ-mental effects, though small overall, will be



Ch 1–Summary q 5

substantial in the areas where they are built.The use of water for a 2-million-bbl/d oil shaleindustry, while increasing regional income byseveral billion dollars per year, would causelosses of about $25 million per year to farm-ing and hydroelectric power generation.

States that will not directly share in the in-creased regional income will experiencesome of these losses.

Socioeconomic

Oil shale development will change thecommunities in the sparsely populated oilshale region both socially and economically.Growth problems arising from the simultane-ous development of oil shale and other ener-gy resources are likely to be more difficult tosolve than those from shale development

alone. There is a potential for adverse ef-fects, whose severity will depend on where,when, and how rapidly the plants are built,and on how well the communities are pre-pared to cope with the growth. The communi-ties could accommodate the growth accompa-

nying an industry of up to 200,000 bbl/d by1990 if presently planned improvements andexpansions are completed. Social and per-sonal distress will occur unless active meas-ures are taken for their prevention. A l-mil-lion-bbl/d industry could not be accommo-dated without major Government involvementand massive mitigation programs. The partic-ipation of Federal, State, and local agencies,the public, and the developers would be es-sential to minimize the adverse living condi-tions that would inevitably arise.

Background

Oil shale deposits are found on all inhab-ited continents. Those in Colorado, Utah, andWyoming contain both a solid hydrocarbon(kerogen) that can be converted to crudeshale oil by heating, and sodium minerals thatcan be used in air pollution control, in glass-making, and to produce aluminum. Depositsof somewhat different chemical compositionand geology are found elsewhere. Those insome foreign countries (Scotland, Spain, Aus-

tralia) have been the sites of very small-scaleindustries in the past. Other countries (Brazil,the U. S. S. R., the People’s Republic of China)either have such industries or are buildingthem.

The deposits of the Green River formationare found in northwestern Colorado, south-western Wyoming, and northeastern Utah.(See figure 1.) The Federal Government ownsabout 70 percent of the land, which containsclose to 80 percent of the oil shale and nearlyall of the associated sodium minerals. Privateparties, Indian tribes, and the three Statesshare the rest. Large deposits are also foundthroughout the Midwestern and EasternStates. Because of their richness and accessi-bility, however, the Green River shales arethe ones most likely to be developed on a largescale in the near future.

The formation has been divided into sever-al distinct geological basins. (See figure 2.)The richest and most thoroughly explored de-posits occur in Colorado’s Piceance basin.The resources of Utah’s Uinta basin are, ingeneral, of somewhat poorer quality. TheWyoming deposits are relatively inferior andoften intermingled with rock that contains noorganic matter. Overall, the deposits containthe equivalent of over 8 trillion bbl of crude

shale oil. However, only a few hundred billionbarrels could be recovered economically withexisting technology.

In general, the oil shale region is ruggedcountry, with elevations ranging from 4,300to 9,000 ft above sea level. The climate is dry,and the weather is strongly influenced by thetopography. Although the soils are generallythin and dry, they support diverse plant com-munities and over 300 species of animals, in-cluding the largest migratory deer herd inNorth America and several threatened or en-dangered species.

Air quality is generally excellent, but highconcentrations of hydrocarbons* (possiblyfrom vegetation) and windblown dust are oc-casionally encountered, and thermal inver-

“Organic chemicals that contain only hydrogen and carbon.



6 q An Assessment of 0il Shale Technologies

Figure 1 .—The Western Oil Shale Region

..

i,

“1

.

)URCE The National Atlas, Department of the Interior

sions are frequent. Water quality in the although it does not, in general, satisfy drink-surface stream-s is good to excellent in theupper reaches but much poorer downstreambecause of the discharges from naturallysaline streams, irrigated fields, and townsand mineral development sites. The quality of the water in the extensive ground water aqui-fers* also varies widely. Some contain onlysaline brines; others contain potable water,

*An aquifer is an undergrounfl formation containing water,

ing water standards.

The population is approximately 120,000—about 3 persons per square mile. Only fourtowns in the shale region have populationsover 5,000: Grand Junction and Craig in Colo-rado, Vernal in Utah, and Rock Springs inWyoming. The economy is based on agricul-ture, minerals, tourism, and recreation. Coal,oil, and gas development is increasing rapid-

ly. The oil shale resources are also receivingconsiderable attention.



Ch. 1–Summary q 7

Figure 2.—Oil Shale Deposits of the Green River Formation

I

IDAHO

—.-

--iII

q Salt Lake City

I

GREATDIVIDE

BASIN

RIVER WYOMING. . %

BASINWASHAKIE

BASIN

UTAH

UINTA

SANDWASH

BASIN

Y’V e r n a l ~+~ ~

q @ ,,COLORADO

/“ i

/ a

Rifle

/’”

1 11

EXPLANATION

Area underlain by the Green Fhver FormatIon

In which the 011 shale IS unappralsed or

low grade

Area underlain by 011 shale more than

10 feet thick, whtch ytelds 25 gallons

or more 011 per ton of shale

SOURCE D C Duncan and V E Swanson, Orgarr/c.R/ch Sha/es of the United States and Wodd Land Areas, U S Geological Survey Circular 523, 1965



8 An Assessment of Oil Shale Technologies

Phofo credit George Wa//erste/n

Central Piceance basin, Colo.

Establishing an Oil Shale Industry: Perspectives and Tradeoffs

The Objectives for Development

The ultimate decision as to whether, how,and to what extent to develop oil shale will bepolitical. Diverse groups with disparate pref-erences for particular types and rates of de-

velopment will influence the decision. Someof the objectives of the different groups arediscussed below.

To position the industry for rapid deploy-ment.—The advocates of this objective be-lieve the industry should be ready to expandrapidly. They acknowledge that more infor-mation and experience are needed if produc-tion is to be expanded in times of nationalneed. Many techniques and sites would haveto be evaluated in order to answer the re-maining questions. Supporters favor policies

expanding technical, economic, and environ-mental R&D, which should include demon-stration plants to evaluate a full spectrum of technologies. Incentives and additional Fed-eral land might be employed to encourage pri-vate sector experiments. All programs would

be designed to maximize information genera-tion.

To maximize energy supplies.—This objec-tive has both economic and national securityimplications. Its pursuit would lead to the

rapid development of a large industry. Thebenefits that might accrue include reducedimport reliance, improved balance of pay-ments, stimulation of private investment, in-creased employment, and lower energy costsover the long term. Policy responses favoredby supporters of this objective emphasizeencouragement of the industry and removalof the restraints on its establishment. In-cluded might be leasing programs, substan-tial incentives, direct Government involve-ment in production, and the waiving of envi-ronmental laws.

To minimize Federal promotion.—This objective is supported by those who oppose gov-ernmental interference with private enter-prise, and by those who stress that oil shaleshould not be promoted at the expense of



Ch 1–Summary q 9

other energy resources. They believe the in-dustry should develop in response to marketpressures and opportunities without activeGovernment support or participation. Policiesfurthering this objective emphasize technicaland environmental R&D and testing to pro-

vide a basis for developing regulations andfor comparing oil shale with other energy al-ternatives. Planning for future mobilizationprograms would be carried out; leasing, landexchanges, and incentives programs wouldnot.

To maximize ultimate environmental infor-mation and protection.—Advocates of thisobjective emphasize the desirability of main-taining an ecological balance. They also be-lieve that oil shale should not be promotedmore than other energy sources that could beless harmful to the environment. They wouldphase development to evaluate its potentialimpacts and to design and test controls, Infor-mation on environmental effects and controlstrategies would be acquired for all technol-ogies that might be used in a commercial in-dustry. Policies would emphasize enforce-ment of existing regulations, siting of plantsto minimize potential impacts, monitoring andR&D to provide guidance for new regulations,and public education and participation.

To maximize the integrity of the social en-vironment .—Supporters of this objective em-

phasize personal and community needs. Theybelieve it essential that growth managementbe well planned and coordinated, and that de-velopment proceed at a gradual pace. Policiesstress involving the region’s residents in man-aging growth, structuring incentive and leas-ing programs to avoid excessive growth ratesin the communities, funding community im-provements and planning efforts, and allocat-ing responsibilities for impact mitigationamong the developers and the Federal, State,and local governments.

To achieve an efficient and cost-effectiveenergy supply system.—Supporters of thisobjective emphasize the importance of pro-viding a mix of energy alternatives with thebest overall ratio of costs to benefits. They

stress the need for positioning the industryand its technologies for long-term profitableoperations so that any future expansionscould be financed with internally generatedresources. The related objectives of efficientdevelopment of the resource and balanced

environmental and social protection are alsoemphasized. The pace of development wouldallow thorough evaluation of the technologiesso that the elements of production (includingland, labor, capital, water, and energy) couldbe used most efficiently if a large-scale indus-try were created. Policies would focus on in-centives that leave intact some degree of managerial risk, on thorough testing of di-verse technologies and sites, and on ad-vanced R&D and demonstration to provide abasis for comparing oil shale with its alterna-tives. The policies would not require a com-

mitment of funds and resources to the exclu-sion of other potential energy sources.

* * *

The Government, in preparing its oil shalepolicies, must consider all of these, as well aswell as other objectives. For example, theGovernment owns rich oil shale deposits andis responsible for protecting the Nation frominterruptions in energy supplies; this wouldencourage the rapid development of publiclands. On the other hand, the public trust

requires that these lands be developed effi-ciently, with equitable returns for the use of the public’s resources, and with fair treat-ment of the affected groups and regions. Thismandate would lead to a moderate pace of de-velopment. Finally, the Government is re-quired by law to protect the environment andto consider the socioeconomic consequencesof its major actions. These mandates requirecarefully managed development.

Depending on which objectives are empha-sized, a number of future industries can be

postulated. The following section evaluatesthe relative degree to which each of four pro-duction targets could be expected to attainthe objectives for development, given a con-struction deadline of 1990.





Ch l–Summary q 1 1

lion-bbl/d goal would require much strongersubsidies, additional long-term leasing of pub-lic land, permitting modifications, variances,and extensive Federal involvement in growthmanagement.

To maximize ultimate environmental infor-

mation and protection.—The quantity of pol-lutants and wastes generated will increase asthe rate of production increases. Establishinga l-million-bbl/d industry in 10 years wouldcause the most disturbance per unit of pro-duction because there would not be enoughtime to improve the control technologies, The100,000 -bbl/d goal is also given a low ratingbecause the limited number of technologiestested would provide neither extensive infor-mation on impacts nor guidance for the im-provement of controls and regulations. The400,000-bbl/d target would meet the needsfor information and testing of control technol-ogies but would incur a greater environment-al risk per unit of production than 200,000bbl/d. The latter would maximize the attain-ment of this objective.

To maximize the integrity of the socialenvironment. —The 100,000-bbl/d target israted high because it should be within thephysical capacities of the communities. A200,000-bbl/d industry would strain the abil-ity of the towns to absorb the number of ex-pected new residents; the amount of stress

would depend on the location of the develop-ment. Adjusting to the growth associated witha 400,000-bbl/d industry would be possible if the plantsites were dispersed in Utah andColorado, if plant construction were phased,and if preparations for the construction of new towns were started at once; but boom-town effects would most probably accompanythe growth. A l-million-bbl/d industry wouldrequire coordinated growth management

strategies and extensive financial outlays.Severe social disruption could ensue.

To achieve an efficient and cost-effectiveenergy supply system.—The 400,000-bbl/dtarget has the highest rating because it wouldprovide a balance of information generation

and of process development and demonstra-tion. The 100,000- and 200,000-bbl/d targetsare rated lower because only a few technol-ogies and sites would be tested. The l-million-bbl/d industry is also rated low because itsdeployment strategy would use many of theelements of production poorly. Furthermore,the plants might not generate sufficient profitcapital for subsequent expansion.

An illustration of the need for tradeoffsamong objectives can be seen at the l-million-bbl/d level. This choice has high attainment of

the positioning and energy production objec-tives (e.g., it would displace about 16 percentof the imported oil and reduce the balance of payments significantly); however, reachingthe target requires tradeoffs in all the otherareas (for example, it would violate the CleanAir Act).

Constraints

OTA analyzed the requirements for achiev-ing each of the production goals by 1990,given the present state of knowledge and the

current regulatory structure. The factorsidentified as hindering or even preventingreaching the goals are shown in table 1. Theconstraints judged to be “moderate” willhamper but not necessarily preclude develop-ment; those judged to be “critical” could be-come severe barriers. When it was inconclu-sive whether or to what extent certain fac-tors would impede development, they werecalled “possible” constraints.



12 q An Assessment of Oil Shale Technologies

Table 1.–Constraints to lmplementing Four Production Targets

1990 production target, bbl/d

100,000 200,000 400,000 1 million

Possible deterring factors Severity of impediment

Technological Technological readiness ... ., ... . None None None Critical

Economic and financial Availability of private capital ... None None None ModerateMarketability of the shale 011 . . . Possible Possible Possible PossibleI n v e s t o r p a r t i c i p a t i o n . . None Possible Possible Possible

Institutional Availability of land. . . . . . . . . None None Possible CriticalP e r m i t t i n g p r o c e d u r e s None None Possible CriticalMajor-pipeline capacity . None None None CriticalDesign and construction services . ... None None Moderate CriticalE q u i p m e n t a v a i l a b i l i t y None None Moderate Critical

Environmental C o m p l i a n c e w i t h e n v i r o n m e n t a l r e g u l a t i o n s . . None None Possible Critical

Water availability Availability of surplus surface water. . None None None PossibleA d e q u a c y o f e x i s t i n g s u p p l y s y s t e m s None None Critical Critical

Socioeconomic

Adequacy of community facilities and services . None Moderate Moderate CriticalSOURCE Otflce of Technology Assessment

Issues and Policy Options

Technology

Oil shale contains a solid hydrocarboncalled kerogen that when heated (retorted)yields combustible gases, shale oil, and a sol-id residue called spent, retorted, or proc-

essed shale. Crude shale oil can be obtainedby either aboveground or in situ (in place)processing. In aboveground processing, theshale is mined and then heated in retortingvessels. In a TIS* process, a deposit is firstfractured by explosives and then retorted un-derground. TIS is at present a primitive tech-nology, although R&D and field tests arebeing conducted. MIS* is a more advanced insitu method in which a portion of the depositis mined and the rest is shattered (rubbled) byexplosives and retorted underground. Themined portion can either be retorted on the

surface or discarded as waste. The crudeshale oil can be burned as a boiler fuel, or itcan be converted into a synthetic crude oil(syncrude) by adding hydrogen. The syncrudecan also be burned as boiler fuel, or it can be

*TIS = true in situ; MIS = modified in situ.

converted to petrochemicals or refined likemost conventional crudes. It is better as asource of jet fuel, diesel fuel, and the otherheavier distillates than of gasoline. (The proc-essing steps for an AGR system are shown infigure 4.)

Issues

1What are the advantages and disad-vantages of different mining and proc-essing methods?

Open pit mining allows large-scale, eco-nomical development and maximizes the re-covery of the resource. Its application, how-ever, is limited to a few areas in the Piceancebasin and to several in the Uinta basin. Alter-ations to the surface of the land are substan-

tial, and the stripped overburden must be dis-posed of along with the processing wastes.Open pit mining of oil shale has never beentested. The technique is highly developedwith other minerals, however, and few tech-nical problems are anticipated.



Ch I–Summary q 1 3

Photo credit Departmenf of Energy

Department of Energy’s batch retortpilot test plant, Laramie, Wyo.

Underground mining, which has been

tested in four mines in the Piceance basin, ismore generally applicable. The Piceancemines, however, were relatively small andwere located on the southern fringe. Miningconditions in other areas are considerablydifferent. Underground mining is especiallyaffected by the physical properties of the oreand by the presence of ground water. In gen-eral, it is more costly than open pit mining,and resource recovery is lower.

The advantages of TIS processing are thatmining is not required, spent shale is not pro-

duced on the surface, and the surface facil-ities needed are minimal. Its principal disad-vantages are that the technology is not welladvanced, that it is applicable only to depos-its that are not deeply buried, that oil recov-eries are lower than by other methods, and

that the retorted shale is left undergroundwhere it may be leached by ground water,

The MIS process requires mining 20 to 40percent of the deposit to be retorted, and in-volves more facilities and waste disposal onthe surface. More oil is recovered per ton of

rock processed than with TIS, but less thanwith aboveground processing. Oil recoveryper acre is probably higher with MIS thanwith a combination of underground miningand aboveground processing, but lower thanwith surface mining and aboveground proc-essing. The principal advantage of above--ground processing is its high oil recovery. Itsprincipal disadvantage is that it requireslarge mining and waste disposal operationsand substantial surface facilities.

2 Are the technologies ready for large-scale applications?

The commercial-scale deployment of thecritical retorting processes, at their presentdevelopmental stage, would entail apprecia-ble risks of both technological and economicfailure. All the components of an oil shaleproject must function together, which meansthat building a large-scale project is risky.Even though some of the other components,like the upgrading and refining processes, arehighly advanced, the oil shale processes are

not.More than 30 years of R&D by governmen-

tal and private organizations has provided abasis for commercialization tests. Two above--ground retorts have been tested for severalmonths at production rates approaching1,000 bbl/d, about one-tenth of the size of commercial modules. Others, like the Parahoretort, have been tested at rates of a few hun-dred barrels per day. These experimentshave produced a total of about 500,000 bbl of shale oil—the equivalent of 10 days’ produc-

tion from a 50,000bbl/d commercial plant.Additional testing, especially of the TIS proc-ess, is needed before a major industry can beestablished with a reasonable level of confi-dence. The MIS process is being developed onthree sites in the Piceance basin, and the re-



14 . An Assessment of Oil Shale Technologies

Figure 4.—The Components of an Underground Mining and Aboveground Retorting Oil Shale Complex

FUEL PRODUCTS AND BYPRODUCTSFROM UPGRADING UNITS

q Low Sulfur Fuel 011 q Ammoniaq Liquefied Petroleum Gas q sulfurq Coke

PROCESSED SHALE REVEGETATIONIN SHALLOW CANYON OR VALLEY- -~ .- -. \.

CompactedD . . . . . - . . . - A c

--- .\ --- - .’-- ..,, ,.m . - r . - -. f 1 L-,

Covered ProcesseShale Conveyors .

-. -.Yno.,..

,.

L YCatchment Dam HEADFRAME DISCHARGE

; Surface Runoff STATIONWater reused

Roof Upper BenchBolting Scaling

Loading Dnlhng-

— . . . .-.. ___

w. .

ROOM AND PILLAR MINING(Several Hundred Feet or moreUnderground)

SKIP LOADING STATION

SOURCE: C-b Shale Oil Project, Deta//ed Development Plan and Related Materlak, Ashland 011, Inc., and Shell Oil Co., February 1976, p. 1.24

suits of this work should assist in determiningits applicability to other areas.

produced, and the somewhat lower oil recov-ery efficiencies. With AGR, the effects of scaleup on the performance and reliability of the retorts themselves and on their associ-ated equipment (pollution controls, productrecovery devices, and materials-handlingequipment) are unknown.

3What are the major areas of uncer-tainty?

The effects of shale stability and strengthon mine design, on safety, and on resource re-covery from underground mines are present-ly unclear. The effects that large inflows of ground water would have on efficiency arealso not determined. Many uncertainties ex-ist with respect to the feasibility and envi-ronmental impacts of TIS processing. The ma-

jor questions about MIS concern its applica-bility to very rich or deeply buried shales, useof the large quantities of retort gas that are

4 What can be done to reduce the uncer-tainties?

TIS will require extensive evaluation, in-cluding theoretical, laboratory, and fieldstudies, before its commercial potential canbe determined. Some of the uncertain aspectsof MIS and AGR processing could also be re-solved with small-scale R&D programs. How-



Ch. l–Summary . 15

ever, demonstration projects will be neededto accurately determine the performance, re-liability, and costs of the various developmentsystems under commercial operating condi-tions. At a minimum, the retorting systemscould be demonstrated by the constructionand operation of modular retorts—the small-est production units that would be used in acommercial operation. The module for anMIS process might be a single retort with acapacity of several hundred barrels a day, ora cluster of retorts producing severalthousand. An AGR processing module mightproduce 10,000 bbl/d. (A commercial plantmight contain five or six of these modules. )Other technologies, such as open pit mining,may necessitate a substantially larger degreeof scaleup, perhaps to a full-scale commercialplant. The retorting technologies could also

be demonstrated in full-scale “pioneer”plants, as proposed by Colony Development.

Policy Options

q

q

R&D funding.—R&D programs could beconducted by Government agencies or bythe private sector, with or without Federalparticipation. Federal programs could beimplemented through the congressionalbudgetary process by adjusting the appro-priations for DOE and other executivebranch agencies, by providing additionalappropriations earmarked for oil shaleR&D, or by passing legislation specificallyfor R&D for oil shale technologies.

Demonstration programs.—Governmentownership of demonstration plants wouldmaximize its intervention and expense, butwould also provide it with the largestamount of information, This would, how-ever, discourage independent industry pro-grams. Funding by the private sector alonewould minimize Government involvementand expense, but the developers might notbe willing to invest in a timely manner and

share information. Cost sharing of the proj-ects would entail intermediate costs to the

public and intermediate levels of informa-tion. Modular demonstration projectswould require a smaller total capital in-vestment than a commercial plant, but theywould cost much more per barrel of oil pro-duced. The projects could be structured inseveral ways.—A single module on a single site would

have the lowest total cost but the highestper barrel cost. The information wouldbe useful only to the process and the siteevaluated.

—Several modules on a single site wouldhave higher total costs but the costs permodule and per barrel would be lower.A full-scale commercial plant, incorpo-rating several technologies, could besimulated.

—Single modules on several sites wouldhave even higher costs. Unit costs wouldbe similar to those for the single mod-ule/single site option. Several sites andprocesses could be evaluated.

—Several modules on several sites, theequivalent of a pioneer commercial in-dustry, would be the most costly butwould generate the maximum amount of information and experience.

Economics and Finances

An oil shale plant will be very costly andthe oil will be expensive. Trends in world oilprices suggest that shale oil may be competi-tive, both now and in the foreseeable future.On the other hand, the long-term profitabilityof the industry could be impeded by futurepricing strategies for competing fuels, by in-accuracies in the current cost estimates forconstructing facilities, and by risks that reg-ulatory problems or litigation could delay orbar a project’s completion. The following dis-cussion deals with oil shale’s economic as-pects and with some possible economic pol-

icies. All costs and prices are expressed inthird-quarter 1979 dollars.




Issues

1What are the economic and energy-supply benefits of oil shale develop-ment?

The output from a 400,000-bbl/d industrywould approximate the petroleum require-ments of the Department of Defense or wouldsatisfy about 70 percent of the demand forliquid fuels in the Rocky Mountain States. Al-million-bbl/d industry could provide about20 percent of the liquid fuels currently con-sumed in the entire Midwest, including 60percent of the jet fuel, diesel fuel, and dis-tillate heating oil. The amount of outputwould replace about 16 percent of the cur-rent imported oil requirement. At $32/bbl,this would reduce expenditures for imported

oil by about $10 billion per year (about 56percent of the balance-of-payments deficit in1979). * The effects of this industry on worldoil prices cannot be accurately predicted. Forillustration, if prices were depressed by 1percent, then expenditures for foreign oilwould be reduced by an additional $900 mil-lion per year. Employment in the oil shale re-gion would increase dramatically if an indus-try of any appreciable size were established.

2

What are the negative economic ef-

fects of establishing the industry?During its construction by 1990, a l-mil-

lion-bbl/d industry would cause a very small,but perceptible, increase in the national rateof inflation. In the longer term, this impactwould be offset by improvements in the bal-ance of payments. If the industry were em-phasized at the expense of less costly alter-natives, the long-term inflationary effects,through increased energy costs, might begreater. Inflationary impacts on the oil shaleregion would be significant for a 200,000-

bbl/d industry, substantial for 400,000 bbl/d,and severe for 1 million bbl/d, Costs of laborand housing would be most affected.

*Posted prices of some foreign crudes currently exceed$32/bbl.

3 How much will oil shale facilities cost?

According to the current cost estimates, tocomplete a 50, 000-bbl/d” syncrude project by1990 would require a capital investment of about $1.7 billion. The economic and finan-

cial requirements of the four production tar-gets are indicated in table 2, together withtheir requirements for water and labor. A 1-million-bbl/d industry (approximately 20 proj-ects) would cost about $35 billion, unless costoverruns resulted from regulatory delays, ac-celerated construction schedules, or attemptsto build many of the projects simultaneously,Establishing this industry by 1990 could costas much as $45 billion.

About 70 percent of the capital investmentwould probably come from corporate equity;the rest would be borrowed. The annual debt

requirement for a l-million-bbl/d industrywould constitute no more than 4 percent of annual business investment, and should notsignificantly strain U.S. private sector lend-ing capabilities.

4 Is oil shale competitive?

Estimates of a breakeven price for shale oilare highly dependent on assumptions, includ-ing the real rate of return required on invest-ment, capital costs, operating costs, annualreal escalations of operating costs, produc-tive life of the resource base, and the effec-tive tax rate for developers. OTA’s computersimulations indicate that prices of $48 and$62/bbl (in 1979 dollars) of shale oil syncrudewould be required to achieve real, aftertaxrates of return of 12 and 15 percent, respec-tively. (See table 3.)

OTA’s assumptions are more conservative(less optimistic) than those of many devel-opers who believe that syncrude breakevenprice estimates are $6 to $9/bbl below those

used by OTA. OTA based its analysis, how-ever, on the most recent cost estimates forthose technologies having advanced engineer-ing designs, and the results are believed torepresent accurately the present economic






Table 3.–Subsidy Effect and Not Cost to the Government of Possible Oil Shale Incentives a

(12-percent rate of return on invested capital)

Change in Total expected costTotal expected expected profit Probability to Government Breakeven

Incentive profit ($ million) ($ million) of loss ($ million) price ($/bbl)

C o n s t r u c t i o n g r a n t ( 5 0 % ) $707 $487 0.00 $494 $3400Construction grant (33%) . . . . . . . . 542 321 0.00 327 38.70L o w - i n t e r e s t l o a n ( 7 0 % ) 497 277 0.00 453 43.40P r o d u c t i o n t a x c r e d i t ( $ 3 ) 414 194 0.01 252 42.60Price support ($55) . . . . . . . . . . . . 363 142 0,01 172 NAI nc re as ed d ep le ti on a ll ow an ce ( 27 %) . . . . . 360 140 0.05 197 45,70Increased investment tax credi t (20%) . . . . . . 299 79 0.05 87 45.80Accelerated deprecia tion (5 years) ., . . . . . . . 296 76 0.05 79 46.00P u r c h a s e a g r e e m e n t ( $ 5 5 ) . . . 231 11 0.03 0 NANone . . 220 0 0.09 0 48.20




Construction grant (50%) ., ., ., $281 $477 0.00 $494 $40.60Construction grant (33%) . . . . . 119 315 0.19 327 47,70L o w - i n t e r e s t l o a n ( 7 0 % ) . , 81 277 0.23 453 54.70P r o d u c t i o n t a x c r e d i t ( $ 3 ) . , . , - 6 1 135 0.63 252 56.10Price support ($55) ., ., ., ., ., : : - 8 8 108 0.77 172 NAI nc re as ed de pl et io n a ll ow an ce (2 7% ) . , . . - 1 10 86 0.75 197 57.20I nc re as ed i nv es tm en t t ax c re di t ( 20 %) . .. ., - 1 31 65 0.77 87 58.80A c c e l e r a t e d d e p r e c i a t i o n ( 5 y e a r s ) . , - 1 2 7 69 0.76 79 58.90Purchase agreement ($55) ., ., ., ., ., ., - 1 5 0 46 0.92 0 NANone ., ., ., ., ., ... ., ., - 1 9 6 0 0.93 0 61.70

aThe Ca[culatlofls assume a $sslbbl price for conventional premmrm crude that escalates at a real rate of 3 percent per year Thus, the predtcled $48/bbl breakeven price fOr the f 2-PerCent dlscounf rate WIII

be reached In t 1 years, or In the fifth year of production Therefore, m narrow economic terms, 011 shale plants starfmg constructwn now which assume a 12-percent dlscounl rate WIII be profitable overthe life of the project wtfhout subsidy (See dscusslon especially ch 6, for caveats concerning this Conclusion ) The calculations are for a 50 000-bbl/d plant coshng $1 7 bdhon All monetary values are m

1979 dollars

SOURCE Resource Planrung Associates Inc Washington D C

position of shale oil. If OTA’s cost estimates q

proved correct and a 12-percent rate of re-

turn were sufficient to attract industry in-vestment, Government incentives might notbe required to foster shale oil development.Similarly, if OTA has overestimated the costsand required rate of return, this conclusionwould still hold. On the other hand, if the un-certainties discussed below should come topass and/or a rate of return higher than 12percent is required to attract capital, subsi-dies or other public policy actions would be q

required to encourage development.

Several uncertainties bear on forecasts of

competitiveness. Although OTA’s analysis at-tempted to capture them, the following onescannot be completely incorporated in a quan-titative analysis:

Unreliable cost estimates.—There areno cost data for commercial-size plants

because none have been built. Cost esti-mates for projects have traditionallybeen unstable, rising by more than 400percent between 1973 and 1978. Thecurrent range of estimates, based onpreliminary engineering designs and ex-perience with other industries, is be-lieved to be more accurate, although thepossibility of significant errors remains,Regulatory disincentives.— Projectsmay be delayed or precluded by proce-dures for obtaining permits, by siting orprocess changes necessitated by regula-

tions or litigation, or by future regula-tions that cannot be met economically.Unexpected delays would contribute tocost overruns.



Ch. 1–Summary . 19

q

q

Uncertain future world oil prices.—Present prices are high, and rising.There is a possibility, however, that fu-ture price changes may be less signifi-cant than commonly forecast, or thatthey could be sufficiently unstable toadd appreciably to the risks of oil shaledevelopment.

Cost overruns because of competitionwith other projects.—Individual proj-ects could be completed in 5 to 7 years(10 years if preliminary demonstrationtests were conducted for the technol-ogies). A 400,000-bbl/d industry couldprobably be put in place by 1990 withoutsevere cost overruns if the variousplants’ construction were coordinatedand phased. However, the 20 or so proj-ects needed for 1 million bbl/d by 1990

would face delays and cost overruns be-cause of the large demands for equip-ment, labor, and construction services.

These uncertainties make any forecast of breakeven prices unreliable. At the sametime, they may induce developers to seekhigher rates of return for their shale invest-ments. For example, a 15-percent real rate of return, which would be substantially greaterthan that required for more conventional in-vestments, would increase the price of shaleoil syncrude by $14/bbl (to about $62/bbl) and

thus would make it noncompetitive, withoutsubsidy, with the forecast prices of foreignoil.

The rate of return issue.—In addition tothe interactions between the uncertaintiesand required rate of return, there is anotherimportant interrelationship. It pertains to theflow of private capital given the rates of return for potential alternative investments.There has been much confusion over why theestimated costs of shale oil always have beenhigher than the actual costs of conventional

oil, even after the sustained high price risesof the 1970’s. As discussed above (and in ch.6), the effects of both increasingly detailedengineering cost estimates and of inflation onconstruction and capital equipment costs

have contributed significantly to the risingestimates of the cost for a barrel of shale oil.

Alternative investment possibilities alsocritically affect shale oil’s competitiveness.Shale oil is tied to conventional oil in twoways. First, it is a substitute in the market-

place, and therefore must be price competi-tive. Second, the companies that are potentialoil shale developers are the same ones thatproduce or refine petroleum, or are potentialdevelopers of other synthetic fuels. The prof-itability of shale oil must be “competitive” inthe sense of selling at a price that competeswith conventional oil while permitting a rea-sonable rate of return. A company with a fi-nite amount of capital is most likely to investin those projects that offer the highest rate of return at a given level of risk.

Price increases over the past 7 years havedramatically increased the profitability of both domestic and foreign petroleum develop-ment. As a consequence, companies maychoose to invest in petroleum so long as it hasa similar rate of return and does not entailthe extensive uncertainties of oil shale. Itfollows that public policies to encourage oilshale development must address making itsrisks and rates of return comparable to thoseof petroleum.

Oil shale investments at 12- or 15-percentrates of return are not likely to displace in-

vestments that have lower costs, lower risks,and higher rates of return, even if shale oilhas a competitive price. The incentives sum-marized in this chapter and discussed in de-tail in chapter 6 primarily address makingshale oil price competitive. They will not nec-essarily assure that it will compete success-fully with alternative investments. Fewer op-portunities in the future for investment inconventional petroleum projects will tend toincrease interest in oil shale investments.These considerations of price, cost, and rateof return also apply to other synthetic and al-

ternate energy industries. To the extent thatsubsidies or other policy actions encourageshale development alone, these other energyinvestment alternatives are put at at relativedisadvantage.




5Which incentives would be most effec-tive?

OTA analyzed 10 possible incentives on thebasis of 6 economic and financial criteria.(See table 4.) Price supports, purchase agree-ments, and production tax credits appear to

have the most overall economic merit. Debtguarantees or low-interest loans, however,will probably be necessary to encourage theparticipation of smaller firms. All incentivesprograms would have to be properly adminis-tered to be effective, and should be removedwhen no longer needed.

6 What would incentives programs cost?

The total net cost of subsidizing a 50,000-bbl/d plant with one of the more effective sub-

sidies could range from $200 million to $400million. (See table 3.) This cost would bespread over about 22 years, and would rangefrom $0.60 to $1.40/bbl of oil produced. It isdetermined by:

q the size and timing of the outflows fromthe Treasury,

q the size and timing of the increasedtaxes paid by the developers, and

q the discount rate assumed for Govern-ment expenditures. *

It is not necessarily true that the least costlyincentive would be the best choice. Firmswith different corporate circumstances willprefer different incentives because they mustavert different risks. It would be cost effec-tive to offer a choice of incentives (e.g., grantsand low-interest loans to smaller firms, taxcredits to larger firms with bigger tax liabili-ties) to encourage participation by a varietyof firms.

7What other economic factors could af-fect the establishment of an industry?

Attempts to establish a large industryquickly could be impeded by the capacity of

*The Office of Management and Budget uses a discount rateof 10 percent per year to compare the cost effectiveness of Gov-ernment programs.

existing major pipeline systems leading toMidwest markets and by shortages in designand construction services and plant equip-ment. These factors should not be major prob-lems for industries of up to 400,000 bbl/d.

Policy Options for Financial Support

Financial support could be provided eitherby incentives to private industry or by directGovernment ownership or participation.

Incentives to private industry .—Incentiveprograms could be structured for a high levelof risk reduction with relatively small netcosts and administrative burdens. The properincentives would share the risks associatedwith creating the projects, but would leavesome of the managerial risks intact. Thiswould help establish the industry but would

allow market risks and opportunities to gov-ern its development.

A possible disadvantage of incentiveswould be that the Government could not di-rectly control the pace of the industry’sgrowth unless extensive encouragement wereprovided. On the other hand, direct Govern-ment control is likely to discourage participa-tion by private firms and could incur the riskof managerial inefficiency. Also, with reli-ance on incentives, the Government would nothave direct access to the types of technicaland economic information that might be

needed to structure future oil shale policies. *Incentives legislation could include require-ments for disclosure of proprietary informa-tion and for specific test programs, but suchrequirements would discourage industrialparticipation. Information could also be ob-tained through licensing arrangements withthe owners of the technologies.

Direct Government participation or own-ership. —A Government-owned industrymight be desirable in a crisis situation. OTAdid not analyze this option in detail because

of its extremely high cost to the public. The*In its May 27, 1980, oil shale policy announcement, DOI in-

dicated it would seek Memoranda of Understanding and otherformal documents to expand its ability to obtain performanceinformation.







Ch 1–Summary 23

acres (less than 1 percent) of the Federal landhas been leased to private firms. It may benecessary to involve more Federal land inorder to test certain technologies, or to estab-lish a large industry rapidly.

Issues

1Could the private land support 1arge-scale development?

The private lands are extensive, but it isunlikely that a large industry will be sited onthem until the processing technologies havebeen proven to be economic. As shown in fig-ure 6, the private lands in the Piceance basingenerally lie along the southern fringe wherethe deposits are comparatively thin and lean,

and are sometimes mixed with layers of bar-ren rock. Development would be more costlythan on the Federal land to the north, wherethe deposits are more than 1,000 ft thick andyield more oil per ton. In addition, the private-ly owned resources contain no large depositsof sodium minerals and they are, in general,too deeply buried for economical open pitmining. The large sodium mineral depositsand the shallow oil shale beds are on Federalland.

There are some tracts, Colony and Union,for example, that contain commercially at-

tractive rich deposits. These firms have beendeveloping retorting technologies for about20 years, and projects with a total capacity of about 150,000 bbl/d have been proposed fortheir tracts. These projects have been sus-pended, however, pending a more favorableeconomic and regulatory climate. The tractsowned by Getty, Standard Oil of California,and others contain resources of comparablequality, but no projects have been announcedfor any of these private lands. In part, this re-flects the technological positions of the land-owners who do not own advanced retortingtechnologies. They may plan to license theprocesses of the other companies, once thesehave been demonstrated.

2What production is expected from theFederal lease tracts?

Production from the two Federal PrototypeProgram lease tracts that are presently ac-tive could reach 133,000 bbl/d by 1987. How-ever, only the lessees of Colorado tract C-b

are committed to commercial-scale produc-tion (57,000 bbl/d). Four other leases were of-fered in 1973, but those in Wyoming were notsold and those in Utah are suspended untilthe Supreme Court decides who owns theland. * The potential production from theUtah tracts (100,000 bbl/d) is not assured.

3What other projects have been pro-posed or are presently active?

Tosco is proceeding at a slow pace in re-

sponse to the diligence requirements of aState lease in Utah. Geokinetics, Inc., andEquity Oil are conducting small-scale R&Dprojects under cost-sharing arrangementswith DOE. Occidental Oil Shale is conductinglarge-scale tests of its MIS process under asimilar arrangement. Paraho Development isattempting to extend its lease for DOE’s re-search facility at Anvil Points, Colo., and toobtain funding for a modular demonstrationprogram. Superior Oil Co. has proposed aland exchange to develop a multimineralprocess in Colorado, and EXXON Corp. has

proposed to exchange its scattered holdingsfor a single tract of Federal land in the Pi-ceance basin.** DOE and the Department of Defense are preparing a plan to develop Na-val Oil Shale Reserve (NOSR) 1, near the An-vil Points site. If the current R&D is success-ful, if the land exchanges are consummated,and if favorable economic conditions exist,the total production from these projects couldexceed 250,000 bbl/d.

*On May 19, 1980, the U.S. Supreme Court reversed thelower court decisions and held that the Secretary of the In-

terior could reject Utah’s applications for oil shale lands (An-drus v, Utah, No , 78-1522).

**The Bureau of Land Management recently denied Superi-or’s initial proposal. Negotiations are continuing.



.


Figure 5.—Ownership of the Oil Shale Lands of the Green River Formation

SOURCE Map of the Ma/or 0// Shale Ho/dregs—Colorado, Wyorrrmg, Utah, Denver, Colo Cameron Engineers, Inc , January 1978

4 Will more Federal land be needed toinitiate an oil shale industry?

The need for more land will depend onwhether a large industry is to be created rap-idly, on the prevailing prices for imported oil,on whether financial incentives are provided,and on whether specific processing technol-ogies are to be tested. Different amounts of

shale oil that might result from various Gov-ernment actions are indicated in table 5. Anindustry producing at least 60,000 bbl/d couldemerge without additional Federal actions. A

360,000-bbl/d industry might result if incen-tives were provided to encourage Colony andUnion to resume their projects. * An industry

*The incentives would have to be carefully structured toachieve this result. See the section on economic and financialpolicies for a discussion of incentives programs.



Ch 1–Summary q 2 5

Figure 6.— Privately Owned Tracts in the Piceance basin

EXXONINTERNATIONAL NUCLEAR MEEKERRANGELY

.

JFEDERAL

PICEA

BASIN

k

TRACT C.a

GULFSTD OF

Q

INDIANA

MOBILEQUITY

Lb’wMOBILARCO

EQUITY

N C

STANDARD OFCALIFORNIA UNION COLONY\/

L

SERVICE v-

(OCCIDENTAL

~Qo

o+

~o v

a

Outhne of the Green Rwerforrnatjon

A P r o p o s e d odshale prolect

N

SOURCE Map of the Ma/or 0// Shale Ho/d/rigs-Colorado, Wyofn/ng, Utah. Denver, COIO Cameron Engineers, Inc , January 1978

t ~- , i“ , < — ,





Ch 1–Summary . 27

approaching 400,000 bbl/d could be realizedif incentives were provided and small tractsof Federal land were available for retort testprograms. A multimineral lease or land ex-change (such as proposed by Superior) andcontinuation of the Paraho lease at Anvil

Points are alternatives. If the Utah leasetracts resume development, a production of 500,000 bbl/d might be possible. If the tractC-a lessees returned to the original open pitmining concept, production could reach560,000 bbl/d. (This would require permis-sion to site processing facilities and to dis-pose of the solid wastes outside of the tractboundaries. ) Adding the EXXON land ex-change might increase production to 620,000bbl/d. Unless economic conditions becamevery favorable, a much stronger set of incen-tives would be needed to spur development of

the “second generation” tracts—those nearthe fringe of the Piceance basin. All of theseconditions, plus additional leasing or develop-ment of the NOSR in Colorado, would be re-quired to reach 1 million bbl/d by 1990.

5What are the options for making Fed-eral land available?*

The major options are governmental devel-opment of the NOSRs, leasing, and land ex-change, Leasing is allowed under the MineralLeasing Act of 1920, as amended. The Proto-type Program was structured under this Act.Land exchanges such as those proposed bySuperior and EXXON are authorized by theFederal Land Policy and Management Act of 1976 (FLPMA).

6 What are their advantages and disad-vantages?

The NOSRs contain poorer quality oil shalethan the Federal holdings in the central Pice-ance basin. NOSR 1 in Colorado, however, is

large enough to support production of *On May 27, 1980, DOI announced it will lease up to four

new tracts under the Prototype Program and will begin prepa-rations for a new perm~nent leasing effort. Also announcedwas the decision not to give special emphasis to the executionof exchanges.

200,000 bbl/d for at least 20 years. Onedrawback is that this reserve is located nearthe private lands that may be developed, andenvironmental and socioeconomic effectswould be concentrated if it were developedconcurrently. Any program for developing

the reserves (whether by a Government-owned corporation, leasing, or cooperativeagreement with industry) could be structuredto yield valuable information, but would alsoadd a level of administrative overhead,

Leasing has several advantages. Informa-tional requirements and environmental stipu-lations can be included in the lease provi-sions, and the pace of development can becontrolled (e.g., specifying preconstructionmonitoring periods, providing favorable roy-

alty arrangements, and including diligencerequirements). Under the Mineral LeasingAct, as amended, a portion of the leasing pro-ceeds would be returned to the affected Stateand could be used to mitigate the socioeco-nomic impacts accompanying development. Amajor long-term advantage would be that theGovernment would continue to own the land.

Additional leasing at this time also hasdisadvantages. It could increase environmen-tal and socioeconomic impacts by encourag-ing development before these impacts are ful-ly understood and strategies for their mitiga-tion in place. Delaying leasing, however,while information is collected could lead tobetter design of a future leasing program.Furthermore, it can be argued that new leas-ing is unwarranted now since existing proj-ects theoretically could yield about 400,000bbl/d, which is sufficient to test a variety of technologies at commercial scale.

Land exchanges could improve resourcemanagement by allowing consolidation of tracts that are presently too small, or too un-favorably situated, for economical develop-ment. Under FLPMA, however, environmen-tal stipulations, informational requirements,and developer participation in socioeconomic



28 q An Assessment of 01/ Shale Technologies

impact mitigation programs could not bemade conditions of any exchange.

Either lease tracts or land exchange par-cels could be selected to avoid ecologicallysensitive areas and to disperse socioeconomiceffects.

7What are the difficulties with leasingand land exchange?

All actions involving Federal land in the oilshale region may be affected by the unpat-ented mining claims that overlie most of theFederal holdings. * The claims have been asource of legal controversy since the 1920’s.If they are validated by the courts, the Gov-ernment could lose control of much of the oilshale land, including tracts potentially avail-able for leasing or land exchange.

Some provisions of the Mineral Leasing Actalso may inhibit industry’s response to leaseofferings. These provisions limit the numberof leases to one per person or firm and re-strict the size of a lease tract to a maximumof 5,120 acres.**

If a firm wishes to exchange its holdingsfor a Federal tract, the values of the landsmust be within 25 percent of one another.Given the lower quality of the private oilshale lands, such equivalent values may bedifficult to achieve. In addition, the evalua-

tion and review procedures for exchanges sofar have been time consuming. (The Superiorproposal has been in the review stage since1973. ) The experiences of Superior and Col-ony were the first attempts to use, for oilshale lands, the exchange authority underFLPMA. Colony did not immediately requestexpedited treatment. Inadequate informationin Superior’s initial request may have beenpartly responsible for the delay in evaluatingits request.

*On June 2, 1980, the U.S. Supreme Court ruled in favor of two groups of unpatented claimholders in Colorado. It is too

early to determine the effects of this action on other unpat-ented claims. Andrus v. Shell OiJ Co. (No. 78-1815, June 2,1980).

* *]n its May 27, 1980, decision paper, DO I stated that ‘t

would seek legislation to remove the statutory acreage limita-tions on lease size, and to permit holding a maximum of fourleases nationwide and two per State.

Policy Options

q

q

q

Amend the Mineral Leasing Act of 1920.

—The Act could be amended to increasethe acreage limitations, or to set the size of the tract according to the recoverableresources it contained. This might allow

more economies of scale, thereby improv-ing economic feasibility. It might also allowthe inclusion of a suitable waste disposalsite within a tract’s boundaries, thus avoid-ing the need for separate offtract disposalwhile still providing adequate shale re-sources for sustained, large-scale oper-ations. The number of leases per person orfirm could also be increased. This might en-courage firms that do not own oil shalelands because it would allow them to applyexperience obtained on one lease tract toanother while the first was still operating.However, the number participating in theleasing program could be reduced if a fewfirms acquired all of the leases. One possi-bility would be to increase the number butlimit it to one lease per State. This mightencourage a firm to develop a process inthe richer deposits in Colorado and thenapply it to the poorer quality resources inUtah or Wyoming.

Amend FLPMA. —FLPMA could beamended to allow the inclusion of condi-tions (such as environmental stipulations

and diligence requirements) in oil shaleland exchange agreements. This would im-prove the Government’s control over theexchanged parcel, but could discourageprivate participation.

Allow offsite land use for lease tracts.—Legislation could be passed to allow alessee to use land outside of the boundariesof a lease tract for facility siting and wastedisposal. * This might permit larger, moreeconomical operations (including perhapsan open pit mine) and would maximize re-source recovery on the tract, but could in-hibit subsequent development of the off-tract areas.

*DOI indicated in its May 1980 announcement that it wouldpropose such a legislative change.




q

q

q

Lease additional tracts under the Proto-type Program. —There is no statutory lim-itation on the number of tracts that couldbe leased under the Prototype Program.However, DOI originally committed to leas-ing no more than six. Because two of theoriginal tracts were not leased, offeringtwo new ones might be justified, providedthat the technologies to be tested were dif-ferent from the processes being developedon the existing tracts. (One of the primarygoals of the Prototype Program is to obtaininformation about a variety of technol-ogies. ) Leasing more than two more tracts,or leasing for the purpose of expandingnear-term shale oil production, would beopposed by critics of rapid oil shale devel-opment. Leasing could begin sooner thanunder a new leasing program, if some of the potential lease tracts previously nomi-nated were offered. A supplemental envi-ronmental impact statement (EIS) would berequired. Construction on the tracts couldprobably not begin until 1985 and produc-tion no sooner than 1990.

Lease only for testing of multimineralextraction. * —Multimineral extraction,wherein shale oil is obtained along withother commercially valuable minerals suchas nahcolite and dawsonite, has been re-ceiving increased attention. Potential de-velopers argue that obtaining the associ-

ated minerals would substantially increasethe profitability of the venture, The onlysuitable land for multimineral experimen-tation is federally owned.

Initiate a new, permanent leasing pro-gram.—An advantage would be that moreproduction than is possible under the pres-ent Prototype Program could be achieved.A full EIS and a new set of leasing regula-tions would be needed. Without the in-formation to be acquired by completing thepresent Prototype Program projects, it

might be difficult to prepare an accurateenvironmental assessment and to structurecomprehensive leasing regulations. Pro-

*DOI will offer at least one multimineral tract in its renewedPrototype Program.

duction could probably not begin until after1990. Abandonment of the Prototype Pro-gram would be implied, which might engen-der opposition.

Expedite land exchanges.—No regulations

governing land exchanges have been pro-

mulgated under FLPMA. Standardized andobjective procedures could significantlyexpedite the process. The review and ap-proval procedures could also be improvedby, for example, setting up a task forcewithin DOI specifically for oil shale pro-posals,

Government development.—The Govern-ment could develop the NOSRs. Unless thiswere done by leasing to private developers,it would involve competition with privateindustry, and would encounter political op-

position. It would also be costly; the publicwould have to pay the full cost of the facili-ties, and that might discourage independ-ent experiments by private firms. The op-tion would be helpful in obtaining informa-tion for developing policies and regulationsfor the industry, but the information mightnot be useful to private developers whenevaluating their investment alternatives.This is because of the discrepancy betweenGovernment and private developers’ ex-perience in financing and operating facil-ities. Some of the information is being ac-

quired in the present Prototype Program. Itcould also be obtained in additional leasingprograms or through licensing arrange-ments with the owners of the technologies.

Continuation of present policies.—Contin-uation of present policies concerning off-site disposal, lease limitations, and land ex-change procedures (without additionalleasing) would help protect the social andphysical environments. It would precludecommercial development beyond that pres-ently envisioned on the four lease tractsand the three to five private holdings thatcould support commercial operations. Bylimiting future leasing and land exchanges,shale oil production could not exceed300,000 to 400,000 bbl/d and the adverseimpacts of a larger industry would be




avoided. The gathering and evaluation of information would enhance understandingof the environmental consequences of de-velopment prior to further commercializa-tion, and the pace would provide leadtimefor the communities to prepare for growth.Given the long period needed to constructfacilities, however, this option would re-strict the contribution shale oil could makein the near term to the Nation’s liquid fuelsupply. The option also would tend to dis-courage further corporate interest andcould delay the testing of a variety of tech-nologies,

Environment

Oil shale facilities, like other mineraloperations, will emit pollutants and produce

large amounts of solid wastes. The severity of the environmental impacts will depend on thescale and duration of the operations, on thekinds of development technologies used, andon the efficiency of the control strategies. Theplants must be designed and operated in com-pliance with environmental laws. The devel-opers plan to achieve compliance largelythrough use of control technologies appliedsuccessfully in other industries. There ap-pears to be little reason to believe that theproposed controls cannot be made to work,but they have not yet been tested for ex-

tended ‘periods with theduring oil shale processing

Issues

wastes produced

1How will oil shale development affectthe environment?

The air in the oil shale region is relativelyunpolluted and, even if the best available con-trol technologies are used, a large industrywill affect visibility and air quality not only

near the facilities but also in nearby parksand wilderness areas. These impacts will beregulated under the Clean Air Act.

Water quality is a major concern in the re-gion. Oil shale operations could pollute the

water by accidental leaks and spills, by point-source wastewater discharges, and by non-point discharges, such as runoff and leachingof waste disposal areas and ground waterleaching of in situ retorts. Unless the pollutionis properly controlled, aquatic biota andwater for irrigation, recreation, and drinkingcould be adversely affected. Point-source dis-charges are well regulated under the CleanWater Act; developers plan to discharge noprocessing wastewater to surface streams,although they may discharge ground waterduring the early stages of development.Standards for injecting wastewaters intoground water aquifers are being promulgatedunder the Safe Drinking Water Act; develop-ers do not plan to inject any wastewaters, butmay reinject the ground water extracted dur-ing mining. Most of the wastewaters will betreated for reuse within the facility. Untreat-able wastes will be sent to solid-waste dispos-al areas. As mentioned, these areas have thepotential for nonpoint discharges that areneither well understood nor well regulated atpresent, although a framework for their regu-lation has been established under the CleanWater Act and the Resource Conservationand Recovery Act.

The extent to which development will af-fect the land will be determined by the loca-tion of the tract; the scale, type, and combina-tion of processing technologies used; and theduration of the operations. Land conditions(largely topographic changes from miningand waste disposal) and wildlife will be af-fected. The facilities must comply with theState laws that govern land reclamation andwaste disposal, which in some ways are lessstringent than the Federal laws governingreclamation of land disturbed by coal mining.Appropriate methods must be used to preventthe large quantities of solid wastes from pol-luting the air with fugitive dust and the waterwith runoff and leachates.

Many of the occupational safety and healthhazards will be similar to those of hard-rockmining, mineral processing, and the refiningof conventional petroleum. Workers might,however, be exposed to unique hazards be-




Phofo credit OTA staff

Colorado River flowing along Interstate 70

cause of the physical and chemical charac-

teristics of the shale and its derivatives, thetypes of development technologies employed,and the scale of the operations. To protectworkers from these hazards, the developerswill have to comply with the OccupationalSafety and Health Act and the Mine Safetyand Health Act. Specific practices will haveto be developed as the industry grows. Thismay be difficult if the growth is too rapid.

2What are the major uncertainties withrespect to the impacts of the industry?

Although extensive work has been under-taken on pollution control technologies andmitigating strategies and on procedures toprotect the safety and health of the workers,uncertainties remain. For example, it is not

known whether conventional methods could

treat all of the process wastewaters to dis-charge standards, should this become neces-sary or desirable in the water-short region.Nor is it known whether the proposed recla-mation techniques will adequately protect thewaste disposal areas from leaching. Weresignificant leaching to occur, it could havesevere effects on the region’s water quality.The stability of revegetated spent shale pileswill remain uncertain for many years, andthe effectiveness of strategies proposed forcontrolling the leaching of in situ retorts isunknown.

Worker fatalities and injuries have beenrare in the industry to date, but oil shale hasbeen mined and processed only for experi-mental purposes, and at rates that are insig-nificant compared with commercial-scale op-



32 . An Assessment of 01/ Shale Technologies

erations. Predictions of a safe working envi-ronment have yet to be verified under condi-tions of sustained large-scale production.

The rates and characteristics of atmos-pheric emissions have not been firmly de-fined, and their dispersion patterns cannot be

accurately predicted because modeling meth-ods are not yet adequate for the irregular ter-rain and complex meteorology of the oil shaleregion.

Laboratory studies, computer simulations,and pilot-scale test programs could clear upsome of these uncertainties (such as disper-sion behavior and wastewater treatment).Others (such as the efficacies of waste dis-posal practices) may need extensive test pro-grams involving commercial-scale modules orplants.

3What potential impacts are not pres-ently well regulated?

New Source Performance Standards forair and water pollution control have not yetbeen developed, although the regulatoryframework exists and they will be forthcom-ing as experience is gained with the oper-ations. Standards for hazardous air pollut-ants and visibility will be promulgated by theend of 1981. It does not appear, however, thatthe hazardous substances to be covered by

these regulations will be generated in signifi-cant quantities by oil shale operations. Non-point sources of water pollution are notpresently well regulated. Performance stand-ards for land reclamation that are specific tooil shale have not yet been developed. Stand-ards developed for coal under the SurfaceMining and Reclamation Act are not entirelysuitable for oil shale because of the signifi-cant differences that exist in geology, topog-raphy, waste characteristics, and other fac-tors. A regulatory framework similar to thatin the Act could be used for developing oil

shale standards.Environmental monitoring is presently re-

quired on private lands to assure compliancewith State and Federal regulations. The re-quirements, however, are not so strict as

those under the Prototype Leasing Program.Environmental groups believe that the sameconditions should apply to both private landsand Federal lease tracts. This, they believe,would provide better information about theenvironmental impacts from the technologiesoperating on private holdings, and would

allow comparison with the effects from theFederal lands. Furthermore, since one pur-pose of the Prototype Program is to obtain in-formation about a variety of technologies, ad-ditional monitoring of the private lands mightprovide these data. As a result, the need foradditional Federal leasing might be reduced.

Developers using private lands oppose thisaction and claim that existing requirementsare more than sufficient to monitor the ef-fects of their projects. They also point outthat additional monitoring is done voluntarily,

and assert that some of the tests required onthe lease tracts are of limited or dubiousvalue.

4 How much will pollution control cost?

Air pollution control is estimated to costapproximately $0.90 to $1.15/bbl of syncrudeproduced. Water pollution control is esti-mated to cost about $0.25 to $1.25/bbl of syn-crude, assuming the water is treated for re-use within the facilities. Land reclamation

will cost about $4,000 to $l0,000/acre dis-turbed, or about $0.01 to $0.04/bbl of syn-crude. The total cost, which may vary signifi-cantly with the location of a project, with thenature of the operation, and with other fac-tors, might be about $1.00 to $2.50/bbl (1.6 to2.4 cents/gal) of oil produced. Although sub-stantial, the cost should not preclude the es-tablishment of an industry since it wouldhave only a small effect on the product price.

5Will the size of the industry be limited

by existing environmental regulations?Existing regulations for water quality, land

use, and worker health and safety do not ap-pear to be obstacles. However, the industry’scapacity will probably be limited by air quali-



Ch. 1–Summary q 3 3

ty standards governing the prevention of sig-nificant deterioration (PSD). These specifythe maximum increase in the concentrationsof sulfur dioxide and particulate that can oc-cur in any area, Under the Clean Air Act, theoil shale region has been designated a Class IIarea, where some additional pollution and in-dustrial growth are allowed. Class I areas,where the air quality is more strictly regu-lated, however, are nearby. One of these, theFlat Tops Wilderness, is less than 40 milesfrom the edge of the Piceance basin, wheremost of the near-term development is likely totake place. A preliminary dispersion model-ing study by the Environmental ProtectionAgency (EPA) has indicated that an industryof up to 400,000 bbl/d in the Piceance basincould probably comply with the PSD stand-ards for Flat Tops, if the plants were dis-

persed. Additional capacity could be in-stalled in the Uinta basin, which is at least 95miles from Flat Tops. A l-million-bbl/d in-dustry could probably not be accommodated,because at least half of its capacity wouldhave to be located in the Piceance basin.

The lack of commercially available plantspecies that are adaptable to the oil shaleregion also could impose a temporary restric-tion on the industry’s land reclamation ef-forts. If commercial growers were to expandtheir production to keep ahead of the needs,this problem could be solved.

6Will the industry be limited by the pro-cedures for obtaining environmentalpermits?

Of the more than 100 permits required forconstruction and operation of an oil shale fa-cility, about 10—the major environmentalpermits—require substantial commitments of time and resources. It may take as long as 2years after the start of baseline monitoringprograms to obtain these permits, with an ad-

ditional minimum of 9 to 24 months requiredif an EIS needed. * If the regulatory agencies*A statement may take much longer. The programmatic EIS

for the Prototype Leasing Program required 4 years. Preparingthe draft EIS for the proposed Superior land exchange required2 Vears. The EIS for extending Paraho’s Anvil Points lease is inits fifth revision, after more than 2 years.

need additional technical information, or if agency personnel are overloaded with work,the process may even take longer. Althoughthe permitting process is lengthy, it shouldnot preclude the establishment of an individ-ual project. Particularly if many projects be-gin simultaneously, agency overloads coulddelay them all, thus causing cost overruns.This should not limit the size of the industry,but it might prevent a large industry frombeing established rapidly.

Policy Options for Air Quality Management

Increase information.—More R&D couldbe conducted on air pollutants, their ef-fects, and their controls. Studies of thedispersion behavior of oil shale emissions,for example, would lead to a better under-standing of the long-range consequences of these emissions on ambient air quality.This, in turn, would provide guidance forplant siting to reduce air quality deteriora-tion. Options include the evolution of ex-isting R&D programs in EPA and DOE, theirexpansion by redistributing or increasingappropriations, and the passage of legisla-tion specifically for air quality studies.R&D should be coordinated with any dem-onstration projects that are conducted.Data from these projects could help in set-ting performance standards for pollutioncontrol.

Change the standards.—The emissionsstandards for oil shale facilities have notyet been set because of a lack of informa-tion about the nature of the operations, Theestimated limit of 400,000 bbl/d in the Pi-ceance basin is based on estimates of theemissions that would occur if the best cur-rently available control technologies wereapplied. EPA could set stricter emissionsstandards that would reduce air pollution

and, if the standards could be met, wouldalso allow more production. If the plantemissions were cut in half, for example, upto 800,000 bbl/d could be installed in thePiceance basin, and more in Utah. This op-tion would entail much higher control




q

costs, and it might not be technologicallyachievable.

Another option would be to redesignatethe oil shale region from Class II to ClassIII. This would allow greater degradationof air quality (the extent of which cannotbe accurately predicted in the absence of reliable regional modeling studies) whileallowing more production. However, itwould not remove the limits imposed bynearby Class I areas, which at present ap-pear to be controlling.

Amend the Clean Air Act.—There arethree options for amending the Act. Eachdeals with the restriction posed by the PSDstandards.

At present, EPA distributes PSD permitsto developers on a first-come, first-servedbasis. The Act could be changed to require

a coordinated strategy for facility sitingthat would maximize production whilemaintaining air quality at regulated levels.EPA could allocate portions of the PSD in-crements based on its own analysis of needs and impacts, or it could consult withall of the potential developers in an attemptto evolve an optimum distribution. (Anamendment would be required to avoid im-pediments to such cooperation under theantitrust laws. ) Distributing the PSD incre-ment among the maximum number of facil-ities would amount to an implicit tightening

of the emissions restrictions, which wouldadd to the costs of air pollution control.The Act could be amended to exempt the

developers from maintaining the air quali-ty of the nearby Class I areas, while adher-ing to Class II standards in the oil shaleregion. The maximum size of the industrywould be limited, because the developerswould still have to comply with the region’sstandards. Alternatively, if this actionwere coupled with a redesignation of theoil shale region to Class III, there could be,at the cost of increased pollution in all

areas, at least twice as much production asis presently possible. (The Class III stand-ards allow twice as much pollution asClass II.)

Finally, the Act could be amended to ex-empt the developers from air quality regu-lations in both the oil shale area and thenearby Class I areas. This would allowhigh levels of production, again at the costof increased pollution over a large area.This action would encounter significant po-

litical and legal resistance.

Policy Options for Water Quality Management

Increase information.—More R&D couldbe conducted to develop and demonstratemethods for treating the process waste-waters to meet discharge standards. Al-though not a part of current developerplans, such treatment could provide addi-tional water resources for the water-shortregion. Additional attention could also begiven to preventing leaching of waste dis-posal areas and in situ retorts. Policy ac-tions would be similar to those for airquality R&D. Alternatively, requirementsfor developing strategies for dealing withthe long-term effects on water qualitycould be added to leases for Federal land.(The lessees in the current Prototype Leas-ing Program are required to develop anddemonstrate both reclamation methodsand procedures that will prevent the leach-ing of in situ retorts. )

Develop regulatory procedures and stand-

ards.—Promulgating standards in theareas that are not presently well regulatedwould reduce the uncertainty that futureregulations could preclude profitable oper-ations. Under the present approach, regu-lations evolve as the industry and its con-trol technologies develop. This introducesuncertainty, but allows the standards to beset with a knowledge of the technical andeconomic limitations. As an alternative,standards could be set that would notchange for a period of say, 10 years, afterwhich they could be adjusted to reflect the

experience of the industry. This would re-move the uncertainty, but the standardswould have to be carefully established toassure that they were both adequate to



Ch. 1–Summary q 3 5

protect the environment and attainable atreasonable cost.

q Ensure the long-term management of waste disposal sites and in situ retorts.—These locations may require monitoringand maintenance for many years after the

projects are completed. Long-term manage-ment could be regulated, for example, un-der the Resource Conservation and Recov-ery Act, which allows EPA to set standardsfor the management of hazardous materi-als, including mining and processingwastes. (Spent oil shale has not been classi-fied as a hazardous waste, but EPA hassuggested that it may be given a specialclassification because of the large volumesthat will be produced.) Alternatively, thedevelopers could be required to guaranteesuch management by incorporating appro-

priate provisions in leasing regulations.

Policy Options for Occupational Health and Safety

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Increase information.—R&D could be con-ducted on the cancer risks associated withprocessing oil shale and shale oil. Thiswork should take advantage of the exten-sive, but often conflicting, prior work andshould be coordinated with ongoing stud-ies. Policy actions would be similar to thosefor air quality R&D.

Undertake health surveillance,-A centralregistry of health records would facilitatethe identification of hazards and the devel-opment of protective methods. It could belocated in a regional medical center, withor without the active participation of Fed-eral agencies. Funds could be provided bythe Government, by the States, by labor or-ganizations, or by the developers.

Develop exposure standards.—As infor-mation about potential chemical healthhazards is analyzed, the National Instituteof Occupational Safety and Health, the Oc-

cupational Safety and Health Administra-tion, and the Mine Safety and Health Ad-ministration could address the necessityfor exposure standards.

Policy Options for Land Reclamation

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Increase information.—R&D and field test-ing could be conducted on reclamationmethods and the selection of plant speciesfor revegetation. This work would help setreclamation performance standards for

the oil shale industry. Policy actions wouldbe similar to those for air quality R&D. Ad-ditionally, the developers could continue tobe required in future leasing programs todevelop viable reclamation methods (cur-rently required of participants in the Proto-type Leasing Program).

Establish Federal reclamation stand-ards.—Legislation could be introduced toprovide standards that are appropriate tothe conditions in the oil shale region and tothe types of disturbance that will occur

with development. The standards shouldbe ecologically sound, economically achiev-able, and consistent with the public’s goalsfor postmining land use. Considerationshould be given to the relative merits of alternative control strategies and environ-mental performance standards necessaryto reduce erosion and leaching and to allowmore efficient use of the land for wildlife,grazing, or other purposes.

Expand the production of seeds and plantmaterials.—This might avoid a possible de-lay in reclamation programs. It could bedone by providing appropriations to theFederal plant materials centers and by ex-panding the cooperative programs be-tween these centers and commercial sup-pliers.

Protect the wildlife and their habitats.—Lease tracts and land exchange parcelscould be chosen to minimize disruption of ecologically fragile areas. This would re-quire extensive, site-specific character-ization studies in advance of leasing or ex-change. These studies would be expensive

and time consuming, but they could ulti-mately expedite subsequent actions by re-ducing the duration of the baseline moni-toring period that might be required of de-




velopers. (Provisions for wildlife mainte-nance were included in the leases for thePrototype Program.)

Policy Options for Monitoring and for

Permitting Procedures

Increase information.—Additional envi-ronmental monitoring of developments onprivate lands could be required. Thiswould entail changing existing laws andregulations. Its advantages include gather-ing comparable information for both pri-vate holdings and Federal lease tracts. Thenew information might reduce the need forleasing more Federal tracts to test technol-ogies not being used by the Prototype Pro-gram lessees. Its disadvantages include thepossibility of litigation. It would also in-

crease expenses for developers using pri-vate holdings,Further study of the permitting proce-

dures could help to design more efficientones while maintaining a high level of envi-ronmental protection. The studies could beconducted by the regulatory agencies or bythe General Accounting Office.

q Increase agency resources.—Increasingpersonnel and financial resources wouldallow the agencies to improve their re-sponse capabilities and increase their as-sistance to State and local regulators. Co-

ordination of the expanded resourceswould also be needed.

q Improve coordination among the agenciesand between the agencies and the pub-lic.-Coordinated reviews could be con-ducted to reduce jurisdictional overlaps,paperwork, and workloads. It might benecessary to mandate coordination to as-sure its effectiveness. Another approachwould be to establish a regionwide envi-ronmental monitoring system to determinebaseline conditions for all areas to be af-

fected by oil shale projects. This might re-duce the duration and the cost of the moni-toring programs now required of permitapplicants. Site-specific studies and mon-itoring would still be needed for certaindata. Another option would be to improve

q

q

q

q

the coordination of public participation inagency decisionmaking processes. Thismight help reduce confrontations, althoughit could lead to an expanded perception of risks and thus to stronger opposition.

Clarify the regulations and the permittingprocess.— Simplifying the procedureswould have the advantage of retaining thelaws and their protection while making iteasier to comply with them. Problems couldarise if procedures were changed while ap-plications were in process. Another ap-proach would be to establish detailed,standardized specifications for permit ap-plications. (EPA is doing this for the PSDprocess.) This would reduce, but not elim-inate, delays. Fully standardized forms areprobably not practical.

Expedite the permitting procedure.—Anauthority (such as the Energy MobilizationBoard) could be established with power tomake regulatory decisions if the agenciesdo not do so within a set period. This wouldprovide a single point of contact betweenthe developer and the regulatory system,but it would add to the bureaucracy and in-crease controversy. Another possibilitywould be to limit the period of litigation forpermitting actions, as was done in the caseof the Trans-Alaska oil pipeline.

“Grandfather” oil shale projects.—Plantsunder construction, or already operating,could be exempted from future regulations.(This concept is embodied in the EnergyMobilization Board legislation.) This wouldremove many regulatory uncertainties, butwould reduce environmental protection.Some environmental laws already contain“grandfather” clauses.

Waive existing environmental laws.—Thiswould remove virtually all of the problemsand delays associated with permitting.

However, it would have serious political,environmental, and social ramifications.The allocations of the waivers would behighly controversial. The extent to whichsuch action would speed the deployment of an oil shale industry is unclear.



Ch 1–Summary . 37

Water Availability

Oil shale development will affect the hy-drologic basins of the Green River, the WhiteRiver, and the Colorado River mainstem inColorado. These basins are located within the

semiarid Upper Colorado River Basin, whichincludes the Colorado River and its tribu-taries north of Lee Ferry, Ariz. (See figure 7.)The river system is one of the most importantin the Southwest, It serves approximately 15million people, and its waters are critical re-sources for towns, farming, industry and min-ing, energy development, recreation, and theenvironment. In the past, natural flows alongwith water storage and diversion projectshave generally been adequate. However, be-cause the region is developing, water suppliesare beginning to be strained, and at some

point in the future a scarcity of water maylimit further growth.

Issues

1What are the water needs of an oilshale industry?

Depending on the technologies used, pro-ducing 50,000 bbl/d of shale oil syncrudewould consume 4,800 to 12,300 acre-ft/yr of water for mining, processing, waste disposal,

land reclamation, municipal growth, andpower generation. This is the equivalent of from 2. I to 5.2 bbl of water consumed perbarrel of oil produced. A l-million-bbl/d in-dustry using a mix of technologies might re-quire 170,000 acre-ft/yr. This is slightly morethan 1 percent of the virgin flow* of the Colo-rado River at Lee Ferry, or 5 percent of thewater consumed in the Upper Basin at pres-ent. * *

‘Virgin flow is the flow that would occur in the absence of human-related activities.

**For comparison, irrigated agriculture along the WhiteRiver and the Colorado River consumes about 549.000 acre-ft/yr to produce 3 percent of Colorado”s crop production. This isequivalent to the water needs of a 3.2-m illion-bbl/d oil shale in-dustry.

2Is there enough surface water avail-able to support a large industry with-out curtailing other uses?

Surplus surface water will be available tosupply an industry of at least 500,000 bbl/dthrough the year 2000 if:

additional reservoirs and pipelines arebuilt;

anddemand for other uses increases no fast-er than the States” high growth rate pro-

jections;and

average virgin flows of the ColoradoRiver do not decrease below the 1930-74average (13.8 million acre-ft/yr).

Otherwise, surface water supplies would notbe adequate for this level of production un-

less other uses were curtailed, interstate andinternational delivery obligations as present-ly interpreted by the Government were notmet, or other sources of water were devel-oped. If the reservoirs and pipelines are built,flows do not decrease, and the region devel-ops at a medium rate (which the States re-gard as more likely), there should be suffi-cient surplus water to support an industry of over 2 million bbl/d through 2000.

In the longer term, surface water may notbe adequate to sustain growth. Surplus water

availability is much less assured after 2000.If the rivers’ flows do not decrease, and if alow growth rate prevails, demand will exceedsupply by 2027 even without an oil shale in-dustry. With a medium growth rate, the sur-plus will disappear by 2013. A high growthrate will consume the surplus by 2007, againwithout any oil shale development. This is apotentially serious problem for the region,and its implications for oil shale developmentare controversial. On the one side, it isargued that there is no surplus surface waterand this should preclude the establishment of

an industry. On the other side, it is main-tained that the facilities in a major industrycould function for much of their economiclifetimes without significantly interfering




Figure 7.—The Upper and Lower Colorado River Basins

k-q B O I S E I D A H O

\

wA

I

lbGreat

SaltLake

q .

J’

C H E Y E N N E

( M E X I C O

1 t1 0 0 MILES

SOURCE’ C. W Stockton and G. C Jacoby, “Long-Term Surface-Water SUPPIY and Streamfiow Trends In the UPper Colorado Rwer Basin Based on Tree-Ring Analyses,”Lake Powell Research Project Bulletin No. 18, March 1976, p. 2.



Ch. 1–Summary . 39

with other users, and in any case would userelatively little water. (A l-million-bbl/d in-dustry would accelerate the point of criticalwater shortage by about 3 years if only sur-face water were used.)

In any event, the analysis of future water

availability is clouded by the uncertain de-mand schedules of other users and by a long-standing legal conflict between the Upperand Lower Basin States. It is not clear howmuch water is legally available to the UpperBasin and therefore to the oil shale region,For example, the calculations presentedabove assume that 750,000 acre-ft/yr is sentfrom the Upper Basin to Mexico to satisfy anational delivery obligation incurred underthe Mexican Water Treaty of 1944-45. TheUpper Basin States maintain that they are notresponsible for this obligation and that the

water should be freed for their use. (Thequantity of water in question is equivalent tothe water needs of a 4.4-million-bbl/d oil shaleindustry. ) The region’s water problems can-not be solved, however, simply by reallocat-ing surface water supplies from the LowerBasin States, where water is an equally criti-cal resource. Rather, if growth is to be sus-tained in both basins, it may be necessary toincrease net supplies by more efficient mu-nicipal, industrial, and agricultural use; or toincrease gross supplies by importing waterfrom other hydrologic basins or possibly by

weather modification. All of these optionswould be expensive, will involve environmen-tal impacts, and could encounter legal, politi-cal, and institutional opposition.

3Will the costs of obtaining water limitthe size of the oil shale industry?

Although water is expensive in the West,the costs of water development will be a smallfraction of the costs of producing shale oiland therefore should not limit development.The costs of the most expensive water supplyoption, importation from other hydrologic ba-sins, could exceed $1/bbl of shale oil pro-duced. Other supplies would cost less than$0.50/bbl. This includes the amortized costsof reservoir and pipeline construction plus

the cost of treating the water to industrialstandards. Development of high-qualityground water would be least expensive, butwould be limited to specific areas.

4Will the use of water for oil shale de-velopment affect irrigated agricul-ture?

The effects on farming should be relativelysmall, especially when compared with thosecaused by competition for labor and by thepurchase of farmlands for municipal growth.Farm production in the Colorado portion of the Upper Basin would be reduced if rights toirrigation water were sold to oil shale devel-opers, but the present developers do not planto purchase irrigation water in significantquantities. In the longer term, if water short-

ages occur, the industry may have to pur-chase water, thus displacing farm produc-tion. The water laws of all three States allowthe transfer of rights between willing sellersand purchasers.

5Will developing water resources for oilshale have severe environmental im-pacts?

The environmental impacts will include re-duced stream flows, increased salinity in the

river system, and land alterations as a conse-quence of constructing reservoirs and diver-sion facilities. These should be small on theUpper Basin as a whole, but could be large insome areas, especially where reservoirs willbe built. Fish habitats and recreational activ-ities along the White River are expected to bethe most severely affected. Environmental im-pacts on the Lower Basin States should not besubstantial.

6What will be the economic effects of

developing water resources for oilshale?

The economic losses from decreased flowsand increased salinity could reach $25 mil-lion per year for a 2-million-bbl/d industry.



40 . An Assessment OfOil Shale Technologies

These would include the effects of increasesin salinity on farming and of reductions inriver flows on farming and hydroelectricpower production. (It is assumed that the de-velopers do not purchase irrigation water. )The positive effects of the same industrywould include a gain of several billion dollarsper year in regional income. A simple com-parison of the relative gains and lossesshould be made with caution, however, be-cause some of the adverse effects would oc-cur in areas that will not enjoy the benefits.For example, some of the impacts on farmingwill be experienced in the Lower Basin.

Policy Options

q Development of a water management sys-tem.—The U.S. Bureau of Reclamation(USBR)* and individual developers andother users have conducted preliminarywater management studies. No systematicbasinwide evaluation of water manage-

*N OW the Water Power Resources Service,

q

ment alternatives, however, has comparedwater supply options with respect to theirwater and energy efficiency, their costsand benefits, and their environmental andsocial effects. Such an assessment, involv-ing Federal, State, and local governments;regional energy developers; other users;and the general public, may be an appro-priate prelude to actions to construct newwater storage and diversion projects. Itcould be especially useful in evaluatingand coordinating such controversial op-tions as importation of water. Fundingcould be provided by DOI, DOE, or otheragencies. USBR or the Colorado River Com-pact Commission could manage the study.

Financing and building new reservoirs.—New reservoirs will be needed if a large in-dustry is to be established. These could be

provided through two mechanisms, First,Congress could appropriate funds for thosewater projects that have already been au-thorized under the Colorado River StorageProject Act. (At least one of these, the West




Divide project, may be suitable for supply-ing water to oil shale facilities in Colorado. )Second, legislation could be passed speci-fying both the construction and funding of water projects not now authorized for theregion, Alternatively, a State organizationor the oil shale developers themselvescould finance and build the water storage.A commitment to the facilities would sim-plify planning for the oil shale industry andfor other regional growth as well. The fa-cilities would be expensive, and their con-struction might be resisted especially if general tax revenues were used for thispurpose.

q Minimizing reservoir and diversion sitingproblems.—The siting, construction, andoperation of reservoirs and diversion proj-ects could be affected by the Endangered

Species Act, the National Wild and ScenicRivers Act, and the Wilderness Act. Prob-lems could be avoided if Congress directedthat the Federal agencies complete a sur-vey of endangered species in the area (in-cluding the designation of critical habitats,if any are found), identify the streamreaches that will be included in the Wildand Scenic Rivers System, and designatethe areas to be included in the NationalWilderness Preservation System. The stor-age and diversion facilities could then besited to minimize interference with these

areas. The environmental surveys in par-ticular could be time-consuming and ex-pensive, and expediting the selection proc-esses might involve departing from the pur-poses of the respective Acts.

q Make water available for oil shale.—Congress could take steps to assure thatwater was supplied to oil shale facilitiesfrom Federal reservoirs, both the existingones and any new ones that might be built,This policy would have to be carefully im-plemented to avoid interfering with other

users and with the water management poli-cies of the affected States,The Government could also provide wa-

ter from Federal reserved rights. Becauseof legal restrictions on the use of waterfrom Federal reservations, the only poten-

tial source appears to be the NOSRs in Col-orado and Utah. The States might resist al-locating this water to an oil shale industry.For example, the use of water from NOSR 1is in the early stages of litigation in Col-orado.

Supply water through interbasin diver-sions.—Water shortages in the UpperBasin could be reduced by importing waterfrom other hydrologic basins. Options in-clude transporting water directly to the oilshale region; or to satisfy all or part of thedelivery obligation to Mexico; or to supplywater to the cities in Colorado’s FrontRange Urban Corridor (to replace the wa-ter that is presently obtained from the oilshale region). All of these options could re-lease sufficient water to support a large in-dustry as well as allowing other types of re-gional growth. However, they all would beexpensive. Furthermore, the study of diver-sions into the Colorado River Basin isbanned by Federal statute until 1988, Thisban would have to be lifted before the op-tion of supplying water directly to the oilshale region could proceed. The other al-ternatives might not be impeded.

Encourage more efficient use of water.—Financial and technical assistance couldbe provided to encourage municipal, agri-cultural, and industrial water conservation

practices. Likely targets would be agricul-ture, powerplants, the oil shale facilities inthe development region itself, and the citieson the eastern slope of the Rocky Moun-tains that import water from the region,Large quantities of water could be saved,although at substantial cost. The imple-mentation of these policies could encounterresistance. Augmentation methods such asweather modification couldwould entail environmental,stitutional problems.

be tried butlegal, and in-

Socioeconomics

near-term de-The oil shale region in whichvelopment is likely to occur is a 3,200 m i2




rural area, sparsely populated and with lim-ited transportation. (See figure 8.) In north-western Colorado, about a dozen towns inthree counties are likely to be substantiallyaffected. * The population of one of thesecounties could increase by as much as seven-fold if a 500,000-bbl/d industry were estab-lished and other energy industries expanded.(See figure 9.) The benefits of this growthcould include increased employment, higherwages, a broader tax base, community im-provements, and stimulation of other busi-nesses. Among the negative consequencescould be a severe housing shortage, strain onpublic services and facilities, symptoms of social stress such as increased crime, andprivate-sector dislocations such as small-business failures. Even if the growth is rea-sonably well controlled, some residents mayperceive a deterioration in their quality of life. The term “modern boomtown” has beenused to describe communities that have expe-rienced these kinds of growth-related nega-tive impacts.

The region is presently growing and has ex-perienced some adverse effects, although lo-cal officials are confident that their commu-nities can deal with additional development.The oil shale developers have been respon-sive to the social effects of the industry’s ex-pansion. A sense of increased communityidentity and pride is already evident, and is

considered by some as a positive conse-quence of oil shale development. Whether thecommunities will continue to deal successful-ly with their growth, or be overwhelmed by it,will depend on a number of factors. Amongthese are:

q

q

q

q

q

the absolute numbers and abruptness of the population influx;the attitudes of both long-term residentsand newcomers;past experiences with boom and bustcycles;

the ability of local political structures toprepare for population growth; andthe availability of assistance—financialand other—for mitigation of impacts.

*This summary refers primarily to Colorado. Utah and Wyo-ming are discussed in ch. 10.

Issues

1How many people can the region ab-sorb?

Between 1985 and 1990, the physical facil-

ities of the small communities in Garfield andRio Blanco Counties that will be most affectedby oil shale development should be able to ac-commodate up to 35,000 people. This as-sumes presently planned improvements andexpansions (including the construction of Bat-tlement Mesa, a new town) can be completed.(See table 6.) This capacity, which is an in-crease of 250 percent over the present popu-lation, is compatible with the growth that willaccompany completion of the two presentlyactive oil shale projects (they could produce133,000 bbl/d). The growth accompanying an

industry of up to 200,000 bbl/d could be ac-commodated if the construction were phasedand if some of the new people lived in adja-cent Mesa County. If additional projects weresited in Utah, the industry could reach300,000 bbl/d. Major efforts would be neces-

Table 6.–Actual and Projected Population and EstimatedCapacity of Oil Shale Communities in Colorado

Population

1977 1980 1985-90Location a census b pro jected c capaci ty d

Garfield County

R i f l e . , 2,244Silt . . . . . . . . . 859N e w C a s t l e . . , 543G r a n d V a l l e y . 377Battlement Mesae –Other . . . . . –

4,3621,211

831589198

—

1 0 , 0 0 02,800 1 , 0 0 0

3 , 0 0 0

2,5001,700

Subtotal f . 4,023

Rio Blanco County M e e k e r , . 1,848Rangely . . . : : : : : : : ., 1,871Other. . . . 1,381

Subtotal . . ., ... 5,100

7,191

2,779 2,223 1.542

6,544

Total . . . . . . . . ., 9,123 13,735

21,000

6,000 6,000 2 , 0 0 0

1 4 , 0 0 0

3 5 , 0 0 0

a~es not Include Mesa or Moffat Counties both of which are more dlslant from the area Of devel-

opment

bAcluals from a special U S censuscEnd.of.lhe.year projections by the Colorado West Area COUflCIl of GovernmentsdEstlmated by OTA from various plarlrllrlgand needs assessments documents, assumes COM@hon of currently planned protects (e g housing, waler and sewer system expanwons streetand road Improvements, elc )

eA new [own, cons[ruc(lon anhclpaied 10 begin In the early 1980 sflncludes only [he Immediate 011 shale Wlnlty

SOURCE Off Ice of Technology Assessment



Ch. 1–Summary 43

Photo crecfff OTA stalt

Marker indicating original site of theNorthern Ute Indian Reservation near Meeker, Colo.

sary to assist the small communities in Utah if sudden, rapid growth accompanied industryexpansion. * In Colorado, additional growthcould be accommodated if some of the pres-ently planned facilities for workers and theirfamilies were constructed quickly. For exam-ple, according to current schedules, Battle-ment Mesa will house 1,500 residents in itsfirst phase of development (ultimate planscall for a maximum of 7,000 units for 21,000

people). If construction were accelerated,more could be housed in a shorter period of time.

The Colorado communities expect to beable to assimilate more residents becausethey have been preparing for an oil shale in-dustry for nearly 10 years. Local interestshave participated in broadly structured taskforces that assist in planning and managinggrowth. The industry has supported thesegroups. It also has aided local governments,has adopted programs to reduce negative im-

*Plaming for oil shale impacts in Utah has not been as ex-tensive as in Colorado for a number of reasons. Most importantis that mitigation funds from a major source (the State’s shareof bonus and lease payments under the Mineral Leasing Act)have been held in escrow pending settlement of the ownershipquestions.

pacts, and has invested in housing and in theland for Battlement Mesa. The communitieshave been developing municipal facilities andservices. New housing is being built, busi-nesses expanded, and health care extended.The State has appropriated more than $40million for over 75 projects, and the FederalGovernment has contributed technical assist-ance. These efforts have prepared the townsfor a reasonable number of new residents.

2Will oil shale development cause com-munity disruption?

Not enough is known about the causes of boomtowns to be able to predict the exactthreshold beyond which oil shale develop-ment would lead to serious impacts. How-ever, establishing a l-million-bbl/d industry

by 1990 would exceed the capacity of all of the communities, and stressful living condi-tions would be inevitable. It is known that thepossibility of disruption will be influenced bythe location of the growth, by the total num-ber of newcomers, by the rapidity with whichthey arrive, and by the ability of the com-munities to prepare for the influx. Sometowns in Wyoming have successfully accom-modated expanded coal development, whileothers that have experienced the same kindsof growth, and have had access to the samepreventive programs, have suffered for long

periods. The social and economic problemsaccompanying oil shale growth could be ag-gravated if development is concurrent withexpansions in other industries. The region isalready experiencing some rapid growth,particularly from coal mining.

3What role can industry play in dealingwith the socioeconomic consequencesof oil shale development?

Industry has contributed financial and

technical assistance to the growth manage-ment effort. The Mineral Leasing Act of 1920allows the affected States to share in the proceeds from leasing programs; Colorado re-ceived nearly $74 million as its share of thebonus payments for Federal tracts C-a and




I

Y

— — —1

IL .— I

I

I

II

I

I

I

I

I

I

II

II

I

I

II \\

\ I I

II

II




Figure 9.— Projected Growth of Counties in Northwestern Colorado From Oil Shale Development, 1980-2000

190,000

180,000

1 7 0 , 0 0 0

1 6 0 , 0 0 0

1 5 0 , 0 0 0

1 4 0 , 0 0 0

1 3 0 , 0 0 0

1 2 0 , 0 0 0

1 1 0 , OOO

1 0 0 , OOO

. 5 9 0 , 0 0 0~

# 8 0 , 0 0 0

7 0 , 0 0 0

6 0 , 0 0 0

5 0 , 0 0 0

4 0 , 0 0 0

3 0 , 0 0 0

2 0 , 0 0 0

1 0 , 0 0 0

*

MESA COUNTY /

e GARFfELD COUNTY

/ RIO BLANCO COUNTY

o

1 m n 1 1 9

1977 1980 1985 1990 1995

1977-actual t30mdation from special U.S. census

1980-ZOOO+ojections assun& oil shale development with a production I@/el of500,000 BPD by 1990 and 750,000 BPD by 1995 combined with otherenergy industry (e.g., coal, electric generation, oil & gas) expansion.

SOURCE: Colorado West Area Council of Governments.




C-b. From this fund has come the $40 millionfor community improvements in Colorado’s oilshale area. The lessees and other developershave contributed additional money and sup-port for planning efforts and other improve-ments. If more projects are initiated by leas-ing, more funds will become available. If, on

the other hand, the new projects are on pri-vate land or on land-exchange parcels, devel-oper participation will be voluntary.

It is in the developers’ best interest to par-ticipate. The benefits of such involvement areillustrated by the experience of the MissouriBasin Power Cooperative in installing a pow-erplant on the Laramie River in Wyoming.The developer invested $21 million in mitiga-tion efforts through grants and revenue guar-antees to towns, counties, and public agen-cies; by inkind services; with bond guaran-

tees; and with other types of assistance. Thecompany believes that it saved about $50 mil-lion in project costs by reducing employeeturnover and avoiding construction delays.Furthermore, all but about $3 million of theinitial outlay will be recovered. Ultimately,the amount spent for mitigation may be lessthan 1 percent of the total cost of the plant.

4 What role can the Federal Governmentplay?

The region should be able to accommodategrowth from the presently active projects,and no new Federal initiatives appear to beneeded unless an industry larger than200,000 bbl/d is desired before 1990. Al-though some towns and counties have experi-enced problems in obtaining funds for specif-ic improvements, the existing growth man-agement mechanisms have been successful todate. They involve a cooperative effort amonglocal citizens; municipal and county govern-ments; regional, State, and Federal agencies;the oil shale developers; and other energy in-dustries. These efforts must not be inter-rupted if the communities are to continue tobe able to deal with their growth problems.

Increased Federal involvement will be re-quired if production of over 200,000 bbl/d is

attempted before 1990. In this case, a coordi-nated growth management strategy would berequired to ensure that financing was avail-able for building houses, that public facilitiesand services could be provided, that basicneeds could be met, and that a reasonablystable work force could be maintained for the

industry. Many Federal, State, local, and pri-vate organizations, operating in many areasand at all levels, would have to be involved tocope with sustained, rapid growth.

Policy Options

The courts have affirmed that, under theNational Environmental Policy Act of 1969,the Federal Government must examine the so-cial impacts of its major actions. The prob-lems accompanying recent expansion of ener-gy industries have led to a call for more Fed-

eral involvement. The extent and nature of this involvement, however, are controversial.On the one side it is argued that socioeco-nomic changes are the inevitable results of in-dustrial development and are, at most, Stateand local problems. On the other side theposition is taken that national energy re-quirements are the root causes of negativeimpacts and, for reasons of equity, activeFederal participation in their amelioration isappropriate. Some examples of Federal as-sistance programs arising from the latterposition are the Coastal Zone ManagementAct Amendments of 1976, which are directedat communities experiencing impacts from oiland gas development on the Outer Continen-tal Shelf, and the Powerplant and IndustrialFuel Use Act of 1978, which established theImpacted Area Development Assistance Pro-gram (the sec. 601 program) to aid areas af-fected by coal and uranium development.

With respect to the socioeconomic prob-lems of oil shale development, there are threepolicy options available. These options couldbe considered in bills that deal with the ef-

fects of all types of energy development; orthey could be considered along with the im-pacts of similar energy forms (e.g., syntheticfuels); or they could be treated solely as theconsequences of oil shale development.



Ch 1–Summary . 47

q

q

Continuation of present policies.—Federalassistance could continue to emphasizetechnical and financial aid. Revenueschanneled through established programswould be the major mechanism, but otherprograms not now designed to deal specifi-cally with impact mitigation could be re-

directed to assist the communities. Con-gressional action would primarily involvecontinuing or increasing appropriations.

Increased growth management involve-ment. —New emphasis could be given to in-creased regulation. For example, socialand economic effects could be made cri-teria for selecting Federal tracts to be of-fered in leasing programs, Alternatively,mandatory participation of the lessees inmitigation efforts could be included in thelease terms. Greater Federal involvement

in monitoring and in technical assistance isanother possibility. Congressional action

could include amending existing laws,passing new legislation, or exercising over-sight powers.

Extension of impact mitigation programs.—Existing programs could be expanded ornew ones adopted. Amendments to extend

the assistance provided by the Powerplantand Industrial Fuel Use Act of 1978 arecurrently under consideration by Con-gress. * Among their features are the au-thorization of grants, loans, loan guaran-tees, and payment of interest on loans. Anexpediting process for providing assist-ance through current Federal programs isproposed, as is an interagency council tocoordinate Federal efforts. This assistanceis directed to the effects of major energydevelopments, which could include oilshale.

*S. 1699.



CHAPTER 2



——

CHAPTER 2

Introduction

At the request of the Senate Energy andNatural Resources Committee, OTA hasstudied the history and status of efforts to de-

velop the oil shale resources in Colorado,Utah, and Wyoming. The Committee’s requestcalled for a complete assessment of shale oilrecovery technology in general and of the cur-rent Federal Prototype Oil Shale Leasing Pro-gram in particular.

The remaining chapters of this volume dealwith the general context of oil shale develop-ment, The following subjects are discussed,

q Chapter 3— “Constraints to Oil ShaleCommercialization: Policy Options to Ad-dress These Constraints’ ’—describes

some alternative objectives that mightbe pursued to control the growth of theindustry. Four development scenariosare used as a framework for identifyingthe obstacles that might inhibit or pre-clude the establishment of industries of various sizes before 1990, (This analysisis based largely on information con-tained in the subsequent chapters.) Thecongressional policies that might be di-rected to these obstacles are then dis-cussed. Given these obstacles and poli-cies, the relative degree to which each

scenario would attain each objective fordevelopment is then described.

q Chapter 4—’’Background"-describethe oil shale region, discusses the re-sources, outlines the processes for ex-tracting shale oil and other materials,and summarizes the history and statusof development efforts in the UnitedStates and abroad.

Chapter 5—” Technologies ’’—describesthe mining and processing methods thatcould be employed to recover shale oil

and to refine it to finished fuels. The ad-vantages and disadvantages of the vari-ous processes are presented and theirstatus summarized. Research, develop-ment, and demonstration needs are iden-

q

q

q

tified, and some possible Governmentpolicies are discussed.

Chapter 6 — “Economic and Financial

Considerations”- deals with the costs of recovering shale oil and with the risksthat inhibit oil shale projects. Theserisks include the absence of certaintyabout the capital cost estimates for com-mercial plants, the future of conven-tional oil prices and their impact onshale oil prospects, and the adequacy of U.S. equipment manufacturing and con-struction and design capacity for rapiddeployment of a large industry. The needfor Government subsidies is evaluated.A number of financial incentives are ex-amined for their influence on the break-even price for syncrude from shale oil,the probability of project financial loss,and the net cost to the Government. Noexplicit attempt has been made to com-pare the economics of shale oil with thatof other synthetic fuels nor with possibil-ities such as conservation or solar en-ergy. Such a comparison is outside thescope and mandate of the present study.The chapter assumes that the commer-cial prospects of shale oil will continueto be determined until the end of thiscentury by its cost and price relationshipwith conventional oil.

Chapter 7—’’Resource Acquisition”’—discusses the characteristics of the oilshale lands that are owned by the Feder-al Government and by private parties.The possible need for involving addition-al Federal land is related to the level of shale oil production that is desired, andto the provision of other types of encour-agement, such as subsidies, The princi-pal mechanisms for providing such land

—leasing and land exchange—are de-scribed and evaluated.

Chapter 8—’’Environmental Considera-tions”—discusses the implications of de-

51



52 qAn Assessment of 0il Shale Technologies

q

q

velopment for the environment and forthe workers. Separate discussions areprovided for the potential effects on airquality, water quality, land characteris-tics, and the health and safety of theworkers. In each case the legal frame-work governing the effects is described,the potential impacts of development arediscussed, the proposed control technol-ogies are evaluated, and the areas of un-certainty are identified. A discussion isalso included of the procedures thattrol the issuance of environmentalmits for oil shale projects. Possibleernmental policy responses arecussed for each area of concern.

con-per-gov-dis-

Chapter 9—” Water Availabil i ty”-deals with the implications of oil shaledevelopment for the region’s scarce

water supply. The water resourcesthemselves are described, and the insti-tutional framework that governs theirallocation is discussed. Water require-ments of conventional users are projected to the year 2000 and comparedwith the physical resources to determineif surplus water might be available tosupport an oil shale industry. Mecha-nisms and policies for making additionalwater available are discussed.

Chapter 10—” Socioeconomic Aspects”

—deals with the effects of development

on the small, rural communities thatcharacterize the oil shale region. Thepopulation increases that might accom-pany development are estimated, andthe abilities of the communities to ac-commodate this growth are evaluated,The nature of the potential impacts isdiscussed and possible policy responsesare presented.

Volume II presents a history of the currentFederal Prototype Oil Shale Leasing Program,together with an analysis of a prior leasingattempt which, although unsuccessful, af-fected the character and conduct of the Pro-totype Program. The problems encountered inthe Program since its inception are discussed,and the status of development on the leasetracts is described, The ability of the Pro-

gram to achieve its original objectives is eval-uated.

Each aspect of this assessment is based onrecent publications, on contractor reportsprepared for OTA, and on the independent in-vestigations of the project staff. The resultsare current as of February 1980. It is impor-tant to note that the oil shale situation is in astate of flux and that new developments maysignificantly alter the status and outlook of the industry and affect the accuracy of any

conclusions presented herein.



CHAPTER 3

Constraints to Oil ShaleCommercialization: Policy Options to

Address These Constraints



Contents

Page Table No.Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . 55 8. Some Potential Oil Shale Development

Approaches to Development . . . . . . . . . . . . . . 55 Sites in Colorado and Utah . . . . . . .. , . .

Possible Objectives. . . . . . . . . . . . . . . . . . . . . . 559. Some Production Alternatives for the

Possible Futures . . . . . . . . . . . . . . . . . . . . . . . . 57Scenarios . . . . . . . . . . . . . . . . . . . . . . . . .

10, Constraints to Implementing Four

Requirements for Development. . . . . . . . . . . . 57Constraints to Development. . . . . . . . . . . . . . . 60Technological . . . . . . . . . . . . . . . . . . . . . . . . . . 62Economic and Financial . . . . . . . . . . . . . . . . . . 62Institutional . . . . . . . . . . . . . . . . . . . . . . . . . . . 63Environmental . . . . . . . . . . . . . . . . . . . . . . . . . 64Water Resources . . . . . . . . . . . . . . . . . . . . . . . 64

Production Targets .. ... .~ . . . . . . . . ,.11. Actual and Projected Population andEstimated Capacity of Oil ShaleCommunities in Colorado. . . . . . . . . . . . .

12. Subsidy Effect and Net Cost to theGovernment of Possible Oil ShaleIncentives. . . . . . . . . . . . . . . . . . . . . . . . .

Socioeconomic . . . . . . . . . . . . . . . . . . . . . . . . . 65

Policy Considerations. . . . . . . . . . . . . . . . . . . . 66Technology . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66Economic and Financial . . . . . . . . . . . . . . . . . . 67Institutional . . . . . . . . . . . . . . . . . . . . . . . . . . . 71Environmental . . . . . . . . . . . . . . . . . . . . . . . . . 74

Water Resources . . . . . . . . . . . . . . . . . . . . . . . 75Socioeconomic . . . . . . . . . . . . . . . . . . . . . . . . . 78List of Figures

Scenario Evaluation. . . . . . . . . . . . . . . . . . . . . 80

ListofTablesFigure No.10. Some Present and Potential Oil Shale

Development Sites in Colorado and Utah‘I’able No. Page 11. The Relative Degree to Which the

7. Requirements for the Production Production Targets Would Attain theScenarios . . . . . . . . . . . . . . . . . . . . . . . . . 58 Objectives for Development. . . . . . . . . . .

Page

60

61

61

65

68

Page

59

81



——

CHAPTER 3

Constraints to Oil Shale Commercialization:Policy Options to Address These Constraints

Introduction

This chapter describes the requirementsfor establishing an oil shale industry by 1990,discusses potential constraints to its estab-lishment, and presents policy options to ad-dress them, The effects of oil shale develop-ment on the physical, social, and economicenvironments are discussed in this chapteronly to the extent that they are obstructionsto development, Not all of these effects hinderdevelopment, and those not judged to be bar-riers are not included here, For instance, fill-ing a canyon with spent shale constitutes an

irrevocable alteration to the locale’s appear-ance; but does not, by itself, bar development.

The many important issues not identifiedas constraints are summarized in chapter 1and dealt with at length in the subsequentchapters. Comprehensive analyses are pre-sented of the economics of oil shale develop-ment (ch. 6), and of the effects productioncould have on the air, land, water, workerhealth and safety (ch. 8), on regional wateravailability (ch. 9), and on the social andeconomic structure of the region’s commu-

nities (ch. 10). As the next section explains,

these considerations all bear on decisionsabout the future of oil shale, even though theymay not be discussed here as barriers to itsdevelopment.

This chapter is organized as follows:q

q

q

q

q

Alternative objectives for developmentare identified. To provide a frameworkfor analysis, production scenarios arepresented that might result from pursu-ing different combinations of these ob-

jectives.

The requirements for investment capi-tal, water, labor, and a favorable combi-nation of marketability and land avail-ability are summarized for the produc-tion targets of the scenarios.The constraints to achieving the targetsare identified.Some policies for dealing with the con-straints are discussed.Given the requirements, constraints,and policies, the scenarios are evaluatedwith respect to the relative degree theycould attain each of the objectives fordevelopment.

Approaches to Development

Possible Objectives

Whether, how, and to what extent an oilshale industry should be developed will ulti-mately be a political decision. The past ef-forts of diverse groups—Government agen-cies, private firms, public-interest advocates,

and environmental conservationists—to in-fluence public policy on behalf of their goalswill undoubtedly continue, These interestshave different perceptions about the relativeimportance of certain basic values. The pref-

erences they show for particular types andrates of development reflect these differ-ences. Some of the varied, and often compet-ing, objectives for development are discussedbelow.

To position the industry for rapid deploy-

ment.—The supporters of this objective ac-knowledge that more information is neededabout oiI shale technologies if production is tobe expanded rapidly in times of nationalneed. Many techniques and sites would be re-

55



.


quired to answer most of the remaining ques-tions about the technical, economic, and envi-ronmental implications of full-scale devel-opment. Demonstration plants to allow theevaluation of a full spectrum of technologieswould be needed. Incentives and additionalFederal land might be made available to en-

courage private sector experiments. All pro-grams would be designed to maximize infor-mation generation. Growing internationaltensions, with the consequent potential for se-vere disruptions in oil supplies, provide a ra-tionale for this objective.

To maximize domestic energy supplies.—This objective emphasizes the rapid develop-ment of a large industry, and has both eco-nomic and national security implications. Thebenefits include reduced reliance on oil im-ports, improved balance of payments, stimu-lation of private capital investment, in-creased employment, and lower energy costsover the long term. Policies supporting thisobjective emphasize the encouragement of the oil shale industry and the removal of re-straints on its establishment. Among thesepolicies might be additional Federal leasing,substantial economic incentives, waiving of environmental laws, and direct Governmentinvolvement in the production of shale oil.

To minimize Federal promotion.—This objective is supported by those who oppose Gov-ernment involvement in the free market and

with private enterprise. Other supportersstress that oil shale should not be promoted atthe expense of other energy sources. In bothcases, the advocates believe the industryshould develop in response to traditional mar-ket pressures and opportunities and withoutthe active financial participation or supportof the Government. Policies that relate to thisobjective emphasize R&D, with particular at-tention to technological and environmentaluncertainties; this would provide a basis forcomparing oil shale with other energy alter-natives and for developing regulations. Plan-

ning for future programs to mobilize the in-dustry would be carried out; programs suchas leasing, land exchanges, and financial in-centives would not.

To maximize ultimate environmental infor-mation and protection.—The desirability of maintaining the existing environmental qual-ity of the oil shale region and its environs isemphasized by the supporters of this objec-tive. They also believe that oil shale shouldnot be promoted more than other potential en-

ergy sources that could be less harmful to theenvironment. They would prefer that devel-opment proceed slowly, if at all, until its po-tential impacts have been determined andcontrol strategies designed and thoroughlytested. The policies in this case would empha-size the enforcement of existing environmen-tal regulations, the siting of any new plants tominimize their impacts, continued monitoringand R&D to provide information for the pro-mulgation of new regulations, and public edu-cation and participation in decisions.

To maximize the integrity of the social en-vironment.-This objective emphasizes per-sonal and community needs. Its supporterswould prefer to see a slow but steady devel-opmental pace in order to avoid the poten-tially disruptive effects of too-rapid growth.Well-planned and coordinated growth man-agement is essential to meet this objective.Policies would stress the involvement of localresidents in the growth management process,efforts to avoid exceeding the growth capaci-ties of the communities, the funding of neededcommunity improvements, and the allocation

of responsibilities for both growth manage-ment and impact mitigation among the oilshale developers, and the local, State, andFederal governments.

To achieve an efficient and cost-effectiveenergy supply system.—Supporters of thisobjective emphasize the importance of pro-viding a mix of energy alternatives with thebest overall ratio of costs to benefits. Theystress the need to position the industry and itstechnologies for long-term profitable opera-tions. Future expansions could then be sup-

ported with internally generated financing.The related objectives of efficient develop-ment of the resource and balanced environ-mental and social protection are also empha-



Ch 3–Constraints to 011 Shale Commercialization: Policy Options to Address These Constraints . 57

sized. The proposed pace of developmentwould allow thorough evaluation of the tech-nologies so that the elements of production(land, labor, capital, water, energy, and in-cremental environmental changes) could beused most efficiently if a large-scale industrywere created. Policies would give attention toincentives that left intact a degree of mana-gerial risk, to thorough testing of diversetechnologies and sites, and to advanced R&Dthat would provide a basis for comparing oilshale with its alternatives. These policieswould not require a commitment of funds andresources to the exclusion of other potentialenergy sources.

Possible Futures

The Government, in preparing its policies

for oil shale development, is bound to consid-er and weigh along with others, all of the objectives discussed above. For example, theGovernment is responsible for protecting theNation from external threats of interruptionsin the supply of essential raw materials likepetroleum. This responsibility, when coupledwith the Government’s ownership of the rich-est oil shale deposits, would tend to encour-age the rapid development of public lands. On

the other hand, the public trust requires thatthese resources be developed with good man-agement practices, with minimum waste andinefficiency, and with equitable treatment of the affected groups and regions. This man-date would lead to a moderate pace of devel-opment. Furthermore, the Government is re-quired by its own laws to protect the environ-ment of the oil shale region and to considerthe socioeconomic consequences of each of its major actions. These mandates would leadto slow, carefully managed development.

Depending. on the emphasis given to thevarious development objectives, a number of future industries could be postulated, fromnone at all, to the production of severalmillion barrels of shale oil per day. Fourscenarios, based largely on shale oil produc-tion targets for 1990, will be considered as a

framework for evaluating the requirements,the effects, and the policy implications of de-velopment. These are:

Production target of Scenario shale oil (bbl/d)

Requirements for Development

q

q

q

q

q

q

q

q

q

q

q

Theand

1 . . . . . . . . . . . . . . . 1 0 0 , 0 0 0

2 . . . . . . . . . . . . . . . 2 0 0 , 0 0 0

3 . . . . . . . . . . . . . . . 4 0 0 , 0 0 0

4 . . . . . . . . . . . . . . . 1 , 0 0 0 , 0 0 0

In order to proceed, each project will need:

land,water,adequate mining and processing technol-ogies,access to markets,a favorable economic outlook,investment capital,compliance with environmental regula-tions,design and construction services,

equipment and construction materials,construction and operating labor, andhousing and community services.

requirements of the scenarios for designconstruction services, equipment, capi-

tal, water, and labor are shown in table 7.Also shown are the numbers of new residentswho will have to be accommodated by the re-gion’s communities. Water requirements in-crease directly with the level of productionbecause the amount each plant will need isindependent of the others. Ranges are givenbecause different technologies having differ-ent water requirements could be used. Be-cause of the assumptions made about thephasing of construction, the labor require-ments do not always increase directly with

the level of production. In addition, whereasscenario 4 produces 2.5 times more oil thanscenario 3, it requires from 2.5 to 4 timesmore capital. This cost escalation is attribu-table to the large demands for labor, materi-als, and equipment for 1 million bbl/d.

i. - ,1-



. —


Table 7.–Requirements for the Production Scenarios

Requirements

Resource Scenario 1 Scenario 2 Scenario 3 Scenario 4

InstitutionalDesign and construction services, % of 1978 U.S. capacity needed each year Minimal Minimal 12 35Plant equipment, % of 1978 U S. capacity needed each year Minimal Minimal 6-12 15-30Economic and financial a

Loans, $ billion ., ., $09-1.35 $1,8-2,6 $ 3 6 - 4 . 2 $ 9 0 - 1 3 5

Equity, $ billion ., ., 2 .1-315 4.2-5.9 84-9,8 21.0-31 5T o t a l , $ b i l l i o n ,,, ., ,, 30-4,5 6.0-8,5 12,0 -14,0 30,0 -45.0

A n n u a l , $ b i l l i o n b 06-0,9 1.2-1 7 24-2.8 6.0-9,0Water availability Water, acre-ft/yrc ., ., ., ., ., 9 ,800-24,600 19,600-49,200 39,200-98,400 100,000-250,000Socioeconomic W o r k e r s . ., ,,, 5,600 8,800-11,200 17,600-22,400 44,000-56,000New residents requiring housing and community services ., 23,000 41,200-47,200 82,000-95,000 118,000-236,000

aTh!rd-quarler 1979 dollarsbMaxlmum annual requlrernerl[s for a 5-year ConstructIon period

cAssumes 4900.12300 acre.ft/ yr for produchon of 50000 bbl/d Of shale oll syncrudedAssumes I 200 ~onstructlon ~orker~ and 1 600 operators per 51J OO&bbl/d plant Multlpllers used for [o[al Increase = z 5 x (Corlstruct[r) f) workers + 55 x (O~eralOrS) Ranaes reflect adjustments In

conslruct!on work forces assuming phasing ot plant construchon

SOURCE OftIce ot Technology Assessment

All projects share certain critical require-ments that do not appear in the table. First,permits will have to be obtained. Their num-ber and nature will depend on the project’slocation, on the technologies used, and onwhether the site is privately owned or is con-trolled by either the Federal Government or aState. In order to obtain the necessary per-mits, the firm will have to demonstrate itsability to comply with the regulations pro-mulgated under the Clean Air Act, the CleanWater Act, the Resource Conservation andRecovery Act, and other laws. Second, each

developer must have a transportation systemto move the products and byproducts to mar-kets. Third, a project must be economicallyfeasible. That is, market conditions must ap-pear favorable based on reliable cost esti-mates, contractor services and equipmentmust be available at reasonable costs, com-pliance with existing and future regulationsmust be possible, and the permitting processmust not unduly delay a facility’s construc-tion and operation. Finally, the developermust have land—either public, private, or acombination of both.

The interrelationship between the require-ments for land, marketability, and a condu-cive regulatory environment can be illus-trated by considering how some projects

might be combined to achieve the productiongoals of the scenarios. The locations of tractson which projects could be sited are shown infigure 10. The ownership of the tracts and thestatus of their development are shown intable 8. Many other tracts exist that could bedeveloped, thus the list of possible sites intable 8 is far from complete. It does not in-clude any tracts in Wyoming, for example,because no large-scale projects have beenproposed for that State. The only State-owned land shown is the tract leased for theSand Wash project. Utah has additional land

that could be leased. Also, the federallyowned tracts shown total only about 160,000acres—roughly 3 percent of the public’s oilshale land in Colorado and Utah.

In table 9, potential projects on thesetracts are combined in alternative ways toreach the production targets of the scenarios.The projects are assigned to four categories:active projects, suspended projects, projectsneeding additional Federal land, and projectson other private tracts. Three alternativesare shown for scenarios 1 and 2. The firstalternative represents the completion and

possible extension of presently active proj-ects. In the second, it is assumed that twopresently active projects are canceled, leav-ing a production shortfall. This is eliminated






Table 8.–Some Potential Oil Shale Development Sites in Colorado and Utah

AnnouncedSite Location Ownership Developer Project title Status production targetb

1 Utah2 Utah3 Utah4 Utah

5 Utah

6 Utah7 Colorado8 Colorado9 Colorado

10 Colorado11 Colorado12 Colorado13 Colorado14 Colorado

15 Colorado16 Colorado17 Colorado18 Colorado

19 Colorado20 Colorado21 Colorado

22 Colorado23 Colorado24 Colorado

25 Colorado

26 Colorado27 Colorado

StateFederala

PrivateState

Federal c

PrivatePrivateFederal c

Private

FederalFederalFederal c

FederalPrivate

PrivatePrivatePrivatePrivate

PrivatePrivatePrivate

PrivatePrivatePrivate

Private

PrivateFederala

Geokinetics Geokinetics TISNavy/DOE NOSR 2Texaco NoneTosco Sand Wash

Phillips/Sundeco/ SOHIO White River(tracts U-a & U-b)

SOHIO/Cleveland Cliffs NoneMobil/Equity NoneStandard of lndiana/Gulf (tract C-a) Rio BlancoSuperior Oil

EXXONMulti MineralOccidental/Tenneco (tract C-b)EXXON

Mobil/ARCO/Equity

ChevronTexacoGettySOHIO/Cleveland Cliffs

Cities ServiceARCOOccidental

ChevronUnionColony Development

Union

MobilNavy/DOE

Superior

Love RanchIntegrated MISCathedral BluffsWIIIOW CreekBX

NoneNoneNoneNone

NoneNoneLogan Wash

NoneNoneColony

Long Ridge

NoneNOSR 1 & 3

Small-scale field tests underway of TIS method At least 2,000 bbl/dNo development, NoneNo development, NoneBaseline monitoring and mine planning 50,000 bbl/d

underway,Suspended pending resolution of land- 100,000 bbl/d

ownership issue.No development, NoneNo development, NonePreparing for MIS retort demonstration, 76,000 bbl/dSuspended pending approval of land exchange 11,500 bbl/d

proposal.Proposal submitted for land exchange, 60,000 bbl/dNegotiations begun for use of USBM mine shaft ,50,000 bbl/dPreparing for MIS retort demonstration. 57,000 bbl/dProposal submitted for land exchange, NoneSmall-scale field tests underway of Equity’s None

TIS method,No development. NoneNo development. NoneNo development. NoneNo development, None

No development, NoneNo development, NoneSmall-scale field tests of Oxy’s MIS technique. Few hundred bbl/d

Results wiII support Cathedral Bluffs project.No development. NoneNo development, NoneSuspended because of economic and 4 6,000 b bl/ d

regulatory uncertainty,Suspended because of economic and 75 ,000 -150 ,00 0

regulatory uncertainty, bbl/dNo development, NoneDevelopment management plan being prepared, None

‘Naval Oil Shale ReservebBased on developers prehmlnary PlanscLeased under the Federal Prototype 011 Shale Leasing pro9ram

SOURCE Ofhce of Technology Assessment

Constraints to Development

The factors that will hinder or even pre-vent reaching the production goals of theOTA scenarios are shown in table 10. Theywere identified by analyzing the scenario re-quirements, given the present state of knowl-edge and the current regulatory structure.Constraints judged to be “moderate” willhamper, but not necessarily preclude, devel-

opment; those judged to be “critical” couldbecome major barriers. When it was incon-clusive whether or to what extent certain fac-tors would impede development, they werecalled “possible” constraints. Only those that

could be addressed by Federal action areshown.

Each potential constraint is important byitself, but the combined effect that more thanone might have on a scenario’s realizationshould also be considered. Thus, a moderaterestriction on the availability of land togetherwith one on permitting could preclude inves-

tor participation. Similarly, an inadequatecommunity water supply for the workers andtheir families coupled with a moderate re-striction on the availability of water for aproject could become a critical constraint.



Ch 3–Constraints to Oil Shale Commercialization Policy Options to Address These Constraints q 61

Table 9. –Some Production Alternatives for the Scenarios (barrels of shale oil per day)

Possible projects

Active projects R IO Blanco

C a t h e d r a l B l u f f s

Sand WashGeokinetics

Equity BX

Suspended projects Union Long RidgeColonyWhite River

Projects needing more Federal land SuperiorM u l t i M i n e r a lEXXON Love RanchEXXON WIIIOW CreekN O S R 1NOSR 2New lease tracts

Other private tracts . . . . . . . . . . . . .

Scenario 1 Scenario 2 Scenario 3alternatives alternates alternatives

Scenario 4alternates

1 -A 1 -B 1 -c 2-A 2-B 2 - c 3 - A 3 - B 4-A 4-B

76,0005 7 , 0 0 0

5 0 , 0 0 02 , 0 0 0 —

—‘ } —

—

—

—

—

76,0005 7 , 0 0 0

5 0 , 0 0 0

76,0005 7 , 0 0 0

5 0 , 0 0 0

21,000

150,00046,000

I 5 0 , 0 0 0 ”

5 7 , 0 0 0

2 , 0 0 0- }

—

1 1 , 5 0 0

5 0 , 0 0 0

6 0 , 0 0 0

6 9 , 5 0 0

—

76,000 150,000’5 7 , 0 0 0 1 0 0 , 0 0 0

5 0 , 0 0 0 5 0 , 0 0 0

— — —

5 7 , 0 0 0

—2 , 0 0 0

—

1 4 1 , 0 0 0

—

5 7 , 0 0 0 5 7 , 0 0 0 5 7 , 0 0 0 — — —

2 , 0 0 0 2 , 0 0 0)

2 , 0 0 0. }1 7 0 0 0 2 0 , 0 0 0 4 0 , 0 0 0 — — I

1 5 0 , 0 0 0 1 5 0 , 0 0 04 6 , 0 0 0 4 6 , 0 0 0

1 0 0 , 0 0 0 1 0 0 , 0 0 0

—‘ } —

41,000 :—

— — —

— — —

—

—

—

1 1 , 5 0 0

2 9 , 5 0 0

—

— — — —

— — —

—

—

—

— — —

—

11,5005 0 , 0 0 0

6 0 , 0 0 0

— 1 1 , 5 0 0 — 5 0 , 0 0 0

6 0 , 0 0 0

—

—‘} 242,000

—

—1 9 , 5 0 0

501,000 – — —

T o t a l 185,000 1 0 0 , 0 0 0 1 0 0 , 0 0 0 2 0 0 , 0 0 0 2 0 0 . 0 0 0 2 0 0 , 0 0 0 4 0 0 , 0 0 0 4 0 0 , 0 0 0 1,000,0001,000,000

‘Possibly ln~ol,,ng open PII mlmng and of flracf hasfe d(sposal

SOURLE Of’l~e of Techno ogy Assessmeof

Table 10.–Constraints to Implementing Four Production Targets


100,000 200,000 400,000 1 million

Possible deterring factors Severity of Impediment

Technological Technological readiness

Economic and financial

Availability of private capitalMarketability of the shale 0 1 1

Investor particlpation

Institutional Availability of landPermitting proceduresMajor- pipeline capacityDesign and construction servicesEquipment availability

Environmental Compliance with environmental regulations.

Water availability Availability of surplus surface waterA d e q u a c y o f e x i s t i n g s u p p l y s y s t e m s

Socioeconomic A d e q u a c y o f c o m m u n i t y f a c i l i t i e s a n d s e r v i c e s

None None None Critical

ModeratePossiblePossible

NonePossibleNone

NonePossiblePossible

NonePossiblePossible

NoneNoneNoneNoneNone

NoneNoneNoneNoneNone

PossiblePossibleNoneModerateModerate

CriticalCriticalCriticalCriticalCritical

PossibleNone None Critical

NoneCritical

PossibleCritical

NoneNone

NoneNone

None Moderate Moderate Critical

SOURCE Olflce of Technology Assessment




Technological

Technological readiness will not hinder thefirst three scenarios because the relativelyslow pace of their development will allow nor-mal scaleup practices to be followed. Sce-nario 4 presents a different case. To achieveits goals, the construction of almost all plantswill have to be started before 1984, whichdoes not allow sufficient time either to under-take much preliminary experimentation, or togain experience by modular demonstration orby the operation of pioneer facilities. In addi-tion, the necessity to standardize the plantdesigns could have a number of unfortunateconsequences. Among these could be that er-roneous equipment specifications and otherdesign flaws would be duplicated, and plantcomponents would be unreliable and short-lived. Unanticipated environmental problemscaused by the failure of pollution control sys-tems could delay the projects, increase theircosts, and have severe ecological conse-quences. Unreliability and less than optimumperformance could prevent some plants fromever operating at their design capacity.

Economic and Financial

For a project to be economically viable andattract investors, it needs to have a favorablecombination of market conditions, of con-

struction and operating costs, and of re-sources such as land, water, and workers.The necessary permits must also be readilyobtainable. Tradeoffs are possible. Thus, if adequate resources are available, and per-mits obtainable without undue expenditure of time and money, then somewhat less favor-able market conditions might be acceptable.

Until late in 1979, it was assumed that siz-able subsidies would be needed to offset unfa-vorable market conditions. However, in Janu-ary 1980, developers estimated that theycould profitably market shale oil syncrude at$35 to $40/bbl. * The present selling price forsimilar high-quality crudes is within this

*Whether shale oil requires subsidy for profitable marketingdepends in part on the discount rate developers are assumed torequire in order to proceed. See table 12,

range (e.g., Wyoming Sweet sold in January of 1980 for a posted price of around $35/bbl).The “spot” or noncontract prices for thesecrudes are considerably higher ($40 to $52/ bbl). Industry sources and petroleum econo-mists expect the world price of crude to con-tinue advancing in the future. Consequently,in a narrow economic sense shale oil appearsto have reached parity with conventionalcrude.

The situation calls into question the needfor financial incentives for the oil shale in-dustry. This assumes, however, that marketconditions continue to improve, and that insti-tutional barriers (e.g., regulations, permittingrequirements, and land availability) do notpreclude development. Such could be thecase if the developers responded to normalmarket pressures and opportunities. If, how-

ever, high levels of production must beachieved within a relatively short time, thenGovernment support will probably be re-quired to reduce the remaining risks associ-ated with oil shale development. The most im-portant of these risks are:

q

q

q

Present capital and operating cost esti-mates for oil shale plants could substan-tially underestimate actual costs. Nocommercial facility has ever been built,and most of the existing engineering de-sign estimates are preliminary. Esti-

mates for the costs of building plantshave consistently increased much fasterthan the rate of general inflation.Uncertainties in the regulatory or per-mitting process, or changes in the reg-ulations after a plant was built, could jeopardize a project’s economics or evenpreclude its development.Future petroleum prices might not allowshale oil to be profitably marketed oncethe plants were built. Since developersdo not know precisely what their produc-tion or construction costs will be, the

uncertainty of future prices for shaleoil’s primary competitor is a crucial risk.

Investor participation is not considered tobe a problem for scenario 1, and the financialcommunity will be able to supply the neces-



Ch 3–Constraints to 0il Shale Commerciailzation Policy Options to Address These Constraints q 63

sary capital for scenarios 1, 2, and 3. Thefinancial requirements of scenario 4 willstrain the Nation’s resources of investmentcapital only slightly or moderately. However,it is questionable whether investors would bewilling to risk participating in scenarios 2, 3,

and 4 because of such factors as the uncer-tainties in world oil prices, the existence of institutional barriers, and the doubtful futureof Government policies. “Possible” obstaclesare shown for these scenarios.

Institutional

Land

The availability of land is not expected tobe a problem with scenarios 1 and 2 becausepotential developers already have access to

sufficient private and public lands to achievethe relatively modest production goals. Itcould, however, cause some problems for sce-nario 3, particularly if multimineral recoveryor open pit mining were to be tested, It will bea critical obstacle for scenario 4. The produc-tion target (1 million bbl/d) will require about15 to 20 plants each on a tract of approxi-mately 5,000 acres, or a smaller number of larger operations, probably including someopen pit mines. It is doubtful that privateholdings are either large enough or containenough rich oil shale to support this many

projects by 1990.


As a production target increases in size, sowill the number of permits that must be ob-tained from the many different Governmentagencies. If many projects are involved, theseagencies are likely to be overwhelmed by thesheer number of applications that must be re-viewed, revised, and approved, The evalua-tion process could become more lengthy andcomplicated, which would increase the risk of

delays in project schedules. Financial lossesto the developers would be the outcome. Al-ternatively, if the agencies bypassed certainreview steps in order to expedite the permit-

ting process, design problems could slip bythat would subsequently need to be cor-rected, introducing additional delays; or, if not caught, would result in environmentaldamage. Regulatory changes during the de-velopment of the projects could mandate un-

anticipated, and possibly uneconomical, proc-ess modifications that could have more easilybeen made during the design phase. Thesefactors are likely to discourage some devel-opers in scenario 3; they would severely im-pede reaching the targets of scenario 4.

Pipelines

Under the first three scenarios, the exist-ing system of major pipelines should be ade-quate to convey the shale oil to nearby mar-kets as well as to more distant ones in the

Rocky Mountain region. Only relatively smallpipeline spurs, plus some truck and railtransport, will be needed to supplement thesystem. The system will not be adequate forscenario 4, and new pipelines will be neededto provide access to markets in the Midwest,

Design and Construction Services

Only about 20 architectural, engineering,and design firms in the United States have thecapacity to design and build an oil shale fa-cility. The projects that would be needed for

scenario 3 would require about 12 percent of their capacity; those in scenario 4 about 35percent. If other industrial expansion com-petes for their services, the availability of these firms could delay the attainment of bothscenarios. Contracting with foreign firmscould be a short-term solution. In the longerterm, as domestic firms expanded and small-er companies merged, the necessary array of technical expertise would become available.If the projects were to be completed beforethe 1990 deadline, however, these adjust-ments would have to take place in the early

1980’s, which may not be possible. In anycase, the demand for design and constructionservices would escalate project costs, espe-cially in scenario 4.




Equipment

Scenario 3 will require between 6 and 12percent of the U.S. production of valves, com-pressors, heat exchangers, pressure vessels,and other industrial equipment. If there wereshortages, scenario 4, which will need 15 to30 percent, could be severely hampered byproject delays and cost escalations. Deficien-cies in equipment supplies and design andconstruction services could escalate projectcosts by as much as 50 percent. *

Environmental

Although harm to the air, water, and landwould certainly increase as the industry ex-panded, existing regulations for water quali-ty, land use, and worker health and safety do

not appear, at present, to be obstacles underany of the scenarios. This observation isbased only on the results of laboratory tests,engineering design studies, and experiencewith small-scale plants. Therefore, it is notpossible to accurately evaluate large-scaleoperations with respect to the efficacies of their control systems, the characteristics of their ultimate emissions streams, the conse-quences of the scaleup necessary to buildthem, and thus their effects on the environ-ment. It is not known whether the industrywill be able to meet, in the future, permitting

standards and regulations for environmentalprotection.

The same types of uncertainties also applyto air quality. Recent studies, however, indi-cate that even when the best available con-trol technologies are used, production capac-ity will be limited by the standards for pre-vention of significant deterioration (PSD).These were promulgated under the Clean AirAct, and specify the maximum allowable in-creases in the ambient concentrations of sul-fur dioxide and particulate for any area.

The oil shale region has been designated asa Class II area, i.e., some additional air pollu-tion and moderate industrial growth are al-

*Such increases occurred in process plant construction dur-ing the period from 1973 to 1975. See ch. 6.

lowed. There are also Class I areas nearby,where the air quality must be kept virtuallyunchanged. These could be affected by oilshale operations. One of these, the Flat TopsWilderness, is less than 40 miles from theedge of the Piceance basin, and about 95miles from the eastern edge of the Uintabasin. A preliminary regional modeling studyundertaken by the Environmental ProtectionAgency (EPA) has indicated that by carefullysiting the plants in the Piceance basin, an in-dustry of up to 400,000 bbl/d could probablybe controlled to satisfy the PSD standards forFlat Tops. The standards might hinder sce-nario 3 if all the capacity were concentratedin the eastern Piceance basin, but this isunlikely. It is more probable that some proj-ects will be sited in the Uinta basin. Thus thescenario’s goal could probably be achieved.

Under scenario 4, air quality deteriorationwould be sufficiently large that compliancewould not be possible because at least half of the capacity (500,000 bbl/d) would be locatedin the Piceance basin.

Water Resources

The availability of surplus surface waterfor large-scale oil shale development dependson the rate of regional growth holding to themedium levels anticipated by the States, andthe long-term average flow of the Colorado

River remaining at or very near the levelsthat have obtained since 1930. If there arehigher rates of regional growth, or if theriver’s flows decrease by a few percent, pro-duction could be limited to about 500,000bbl/d unless water were diverted from otherusers. Shortages of surface water, whichcould hinder scenario 4, could be offset by de-veloping ground water, by purchasing sur-face water from other users, or by importingwater from other areas. However, thesestrategies could encounter institutional ob-stacles. For example, importation of water is

presently banned by Federal statutes, andground water could be developed only if therights of surface water users were protected.

All of the scenarios will require additionalreservoirs to assure year-round water sup-



Ch 3–Constraints to 0il Shale Commercialization Policy Options to Address These Constraints q 65

plies. In many cases, these will be small andlocated at the plantsites. However, a large in-dustry will need new reservoirs if the proj-ects, and all other users, are to have ade-quate water supplies, The existing reservoirswill not be adequate for scenarios 3 and 4,and new storage will have to be built in the

basins of the White River and the ColoradoRiver mainstem. Reservoir siting could be re-stricted on some streams by their designationas wild and scenic rivers, or by the presenceof rare and endangered species.

All of the scenarios will require diversionprojects to carry water from the streams andreservoirs to the oil shale plants. Their con-struction would also come under environmen-tal laws.

Socioeconomic

Social and economic obstacles will arise if the communities are unable to adapt to thegrowth caused by shale development, Theseobstacles have two aspects, The first relatesto the physical ability of the towns to provideadequate housing, facilities, and services.The second involves the effects of local livingconditions on workers and other residents.Even when physical facilities are adequate,the way of life can be unpleasant. In someWestern and Great Plains communitieswhere large and rapid growth has accompa-

nied energy industry construction, living con-ditions have become so intolerable that work-ers and their families have simply left. Theconsequences for the projects of this laborturnover were construction delays, cost over-runs, and poor workmanship.

Communities in the oil shale region are pre-paring for additional growth. In Colorado, forexample, the State government, and the oilshale counties and municipalities—with thesupport and cooperation of industry—havebeen preparing for increased developmentfor nearly 10 years. Consequently, the regionis awaiting expanded oil shale development,and is prepared to absorb a moderate num-ber of new residents. Assuming there are nobreakdowns from boomtown stresses, and

that presently planned facilities (such as thenew town of Battlement Mesa) can be built,the region could accommodate up to 35,000people between 1985 and 1990. (See table11. ) More could be incorporated if prepara-tions were begun at once. The establishedcommunities could expand and new towns

could be constructed, provided that financingwere available, regulatory actions could betaken in a timely fashion, and the politicaland administrative atmosphere were favor-able. However, if community and individualstress became too great and social institu-tions faltered, not even the total of 35,000residents could be absorbed without disrup-tion.

Although some social stress can be antici-pated, the area should be able to deal withthe growth associated with scenario 1. Sce-

nario 2 could probably be accommodated if project construction were phased, and if some projects were developed in Utah. Se-vere problems would accompany the growthexpected for scenario 3, and the growth forscenario 4 would greatly exceed the capaci-

Table 11 .–Actual and Projected Population and EstimatedCapacity o f Oil Shale Communities in Colorado

Population

1977 1980 1985-90Location a census b projected capacityd

Garfield County Rifle . 2,244 4,362 10,000

Silt : 859 1,211 2,800New Castle 543 831 1,000G r a n d V a l l e y . ~ ~ 377 589 3,000B a t t l e m e n t M e s ae ~ — 198 2,500Other ~ ~ – – 1,700

Subtotal f . ., 4,023 7,191 21,000

Rio Blanco County M e e k e r 1,848 2,779 6,000Rangely ... 1,871 2,223 6,000Other. . 1,381 1,542 2,000 — — —

Subtotal 5,100 6,544 14,000 — — —

T o t a l . , , . . 9,123 13,735 35,000

aooes not IflCIUcle MeSa or Mot[at Counties both of which are more dtslanl from the area of devel-

opmentbAc[ua15 from a special U S census

cEnd-of.the year projections by the Colorado West Area Counc[l of GovernmentsdEsllma[ed byOTA from various plannlng and needs assessment documents assumes comple

Ilon of currently planned orojects (e g housing waler and sewer system expamlons s{reetand road Improvements etc

‘A new town Construction antupated 10 begtr (n the early 1980 sf/nC/udes only Ihe Immedla!e 011 shale vlClnlty





ties of the communities. Not only would the cal stress would be inevitable for scenario 4,existing towns have to double or triple in size, and there is little doubt that adverse livingbut several new ones would have to be estab- conditions would prevent the realization of itslished. Disruption from social and psychologi- production goal.

Policy Considerations

Some possible Federal policy responses tothe constraints that would inhibit or precludethe expansion of the oil shale industry arediscussed in this section. Other issues and im-pacts that have not been identified as con-straints are dealt with in the subsequentchapters and summarized in chapter 1. Someexamples are the efficacies, over the longterm, of the proposed solid waste disposalpractices, and the consequences of de-creases in the flows of the Colorado Riversystem.

Technology

Accelerated research, development, anddemonstration would be needed to remove thetechnological barriers to scenario 4. Thefollowing programs might be considered.

R&D Policy Options

Some of the remaining technical questionscould be answered in small-scale R&D pro-grams. These could be conducted by Govern-ment agencies or by the private sector, with

or without Federal participation. If Federalinvolvement is desired, the R&D programscould be implemented through the congres-sional budgetary process by adjusting the ap-propriations for the Department of Energyand other executive branch agencies, by pro-viding additional appropriations earmarkedfor oil shale R&D, or by passing new legisla-tion specifically for R&D on oil shale technol-ogies.

Demonstration Options

In general, potential developers wouldprefer to follow conventional engineeringpractice, and to approach commercializationthrough a sequence of increasingly larger

production units. Union, Colony, and Parahohave progressed through this sequence to thesemiworks scale of operation—about one-tenth of commercial module scale. Largerdemonstration projects will be needed to ac-curately determine the performance, reliabil-ity, and costs of processing technologies un-der commercial operating conditions. ForUnion and Paraho, the next step is a modulardemonstration facility that would incorporateonly one retort. Although costing several hun-dred million dollars, this facility would pro-

vide the necessary experience and the techni-cal and economic data to decide whether tocommit much larger sums to commercialplants. Rio Blanco and Cathedral Bluffs arealso following the modular demonstrationpath. Colony regards the pioneer commercialplant as more suitable for demonstrating theTOSCO II technology.

As discussed in the section on economicand financial policies, whether the FederalGovernment plays an active role in fund-ing and operating the demonstration projectswill strongly influence the balance that isachieved between information generationand dissemination, timing of development,and cost to the Treasury. There are fourpossible structures for demonstration pro-grams. In all cases, the net cost of the pro-gram will depend on where the facilities aresited. If the site could be subsequently devel-oped for commercial production (e.g., a pri-vate tract, a potential lease tract, or a can-didate for land exchange), the facility wouldhave substantial resale value. Otherwise, itwould have only scrap value.

A single module on a single site.—This op-tion would provide comprehensive informa-tion about one process on one site. Eitherunderground or surface mining experiments



Ch 3–Constraints to 0il Shale Commercialization. P O licy Options to Address These Constraints q 67

could be performed, but probably not both.The costs would be small overall but large ona per-barrel basis, because there would be noeconomies of scale. Some of the mined shalecould be wasted because the single retortmight not be able to process all of it economi-cally.

Several modules on a single site.—Thisprogram might consist of an MIS operationcoupled with a Union retort for the coarseportion of the mined oil shale and a TOSCO IIfor the fine portion. As with the single-moduleoption, either surface or underground miningcould be tested, or possibly both if the planthad sufficient production capacity. The totalcosts would be larger than for the single-mod-ule program, but unit costs would be muchlower. For example, a three-module demon-stration plant would cost about twice as

much as a single-module facility; a six-moduleplant about four times as much. Differenttechnologies could be combined to maximizeresource utilization, and detailed informationcould be obtained for each. However, all of the information would be applicable to onlyone site. If many modules were tested, thedemonstration project would be equivalent toa pioneer commercial plant, except that atrue pioneer operation would probably notuse such a wide variety of technologies.

Single modules on several sites.—Several

technologies might be demonstrated, each ata separate location. For example, an under-ground mine could be combined with aTOSCO II retort on one site; a surface minewith a Paraho retort at another. Total costswould be large, as would unit costs, whichwould be comparable with those of the single-module/single-site option. The principal ad-vantage would be that different site charac-teristics, mining methods, and processingtechnologies could be studied in one program.

Several modules on several sites.—Foreach site, a combination of mining and proc-essing methods could be selected that wouldbe appropriate for the site’s characteristicsand the nature of its oil shale deposits. Themaximum amount of information would thusbe acquired in exchange for the maximum

amount of investment. Each project would re-semble the several-module/single-site option;the collection would constitute a pioneercommercial-scale industry.

Economic and Financial

Continuing uncertainties over eventualplant costs, along with present regulatorydeterrents, may mean that financial incen-tives will be needed. Government action toallow easier access to public oil shale land, orto remove regulatory impediments, could re-duce this need. If, however, assuring the pro-duction for scenarios 3 or 4 by 1990 is a major objective, then financial incentives shouldbe seriously considered. They would be par-ticularly important in meeting the goals of scenario 4, because the rapid deployment of a

large number of projects within 10 years islikely to create cost overruns and jeopardizeproject economics.

Government Financial Support

Several types of Government financial sup-ports are discussed below. These are basical-ly of two kinds: incentives to private industry,and direct Government ownership or partici-pation.

Incentives to industry.—An effective in-

centive must avert one or more economicrisks. It should also be cost-effective: its costto the Government should be low and its sub-sidy effect high. It should promote, or at leastnot impede, efficient investment and produc-tion decisions, and should encourage competi-tion. It should facilitate access to capital. Itshould entail small administrative and bu-reaucratic costs. Finally, it should be phasedout as market conditions improve and risksare reduced. The following analysis assumesthat only temporary incentives will be re-quired for the first generation of oil shalefacilities. If this assumption proves incorrect,the implications of subsidizing the industryshould be reevaluated; permanent subsidiesare a very different economic propositionfrom temporary ones.



——— -. . ——.—

68 q An Assessment of 011 Shale Technologies

OTA analyzed 10 possible economic incen-tives. These differ with respect to the criteriadescribed above and also with respect towhether the Government provides the incen-tive before or after production begins. Thelatter option is desirable because the Govern-ment could phase in the subsidy disburse-ment. Production incentives (those appliedafter production begins) limit the Govern-ment’s financial exposure and risk. The useof production subsidies alone, however, mayencourage only large corporations with ex-ceptional debt capacity.

The net cost to the Government of a partic-ular incentive can directly reflect the extentof its subsidy effect, but the relationship isnot necessarily linear: some incentives defi-nitely provide more subsidy at a lower cost tothe Treasury than others. (See table 12.) It is

also important to note that the corporate, fi-nancial, technical, and fiscal circumstancesof the potential developers will show consid-erable differences. Consequently, it is un-likely that any single “best” incentive will berevealed. However, some are clearly superiorto others from the viewpoints of both the Gov-ernment and developers. An optimal policymight be to provide a variety of incentives of approximately equal dollar value, and toallow each company to choose the one that ismost appropriate to its particular circum-stances. The implications of each of the in-centives follow. *

q Construction grant. —The Government pro-vides a direct grant to cover a prespecifiedpercentage of total construction costs.

*Fu1l discussion is found inch. 6.

Table 12.–Subsidy Effect and Net Cost to the Government of Possible Oil Shale Incentives’


Change in Total expected costTotal expected expected profi t Probability to Government Breakeven


Const ruc t ion grant (50%) $707 $487 0 0 0 $494 $34.00Construction grant (33%) ~ 542 321 0.00 327 38.70Low-interest loan (70%) ., ~ ., 497 277 0,00 453 43,40Production tax credit ($3) ., 414 194 0,01 252 42,60P r i c e s u p p o r t ( $ 5 5 ) , . 363 142 0.01 172 NAIncreased depletion allowance (27%) ~ ~ ~ 360 140 0.05 197 4570Increased Investment tax credit (20%) ~ ~ 299 79 0.05 87 4580A c c e l e r a t e d d e p r e c i a t i o n ( 5 y e a r s ) 296 76 0.05 79 46,00Purchase agreement ($55) . , 231 11 0.03 0 NANone ., ~ ~ ~ 220 0 0 0 9 0 4820



Incentive profit ($ million) ($ million) of loss ($ million) price ( $/bbl)

Construction grant (50%) $281 — $477 0.00 $494 $4060C o n s t r u c t i o n g r a n t ( 3 3 % ) . , ~ ~ ~ ~ ~ 119 315 0.19 327 47,70L o w - I n t e r e s t l o a n 81 277 0.23 453 5470Production tax credit ($3) ~ ., ~ ~ - 6 1 135 0 6 3 252 56.10Price support ($55) ., ., ... - 8 8 108 0 7 7 172 NAI nc re as ed de pl et ion al lo wa nc e ( 27 %) ., ., - 11 0 86 0.75 197 57.20Increased Investment tax credit (20%) ., - 1 3 1 65 0.77 87 58,80A c c e l e r a t e d d e p r e c i a t i o n ( 5 y e a r s ) . , . . . – 127 69 0.76 79 5890

Purchase agreement ($55) , . . - 1 5 0 46 0 9 2 0 NANone ., ... ., ., ., ., ~ ~ ~ ., - 1 9 6 0 0 9 3 0 61.70

aThe calcUlallonS assume a $3!j/bbl price for conventional premtum crude that escalates at a real rate of 3 percent per year Thus the predicted S48/bbl breakeven price fOr lhe 12-perCent discount rate ‘Will

be reached 10 11 years or In the I[tth year of produchon Therelore tn narrow economic Ierms 011 shale plants starting construction now which assume a 12.percent discount rate WIII be profitable overthe hle of the project wlthoul subsmy (See discussion for caveats concerning Ihls conclusion ) The calculations are for a 50,000 -bbl/d plant costing $1 7 blllton All monetary values are In 1979 dollars

SOURCE Resource Plannlng Associates Inc Washington O C



Ch 3–Constraints to Oil Shale Commercialization: Policy Options 10 Address These Constraints q 69

(OTA analyzed both 50- and 33-percentgrants.) This incentive has a strong effecton project financing. It benefits all devel-opers, and does not distort investment orproduction decisions. However, it wouldimpose large administrative burdens onboth the Government and industry. There

would be no assurance that productionwould occur even with the grants. Largeinitial lump-sum payments would be re-quired rather than phased-in treasury dis-bursements. The subsidy would probablybe politically unpopular.

Production tax credit.—The developer isallowed a credit against corporate incometaxes for each barrel of shale oil produced.(A $3 credit per bbl of crude shale oil wasanalyzed. ) This incentive provides a strongsubsidy effect, and moderately shares in-

vestment cost uncertainty. It imposes min-imal administrative burdens. It only slight-ly improves project financing, however,and entails some distortion of productprice, It most strongly affects firms thathave large tax liabilities, and its net cost tothe Government is high compared withother possible incentives. It is widely sup-ported by potential developers.

Price support.—A minimum price for shaleoil is guaranteed for a long enough periodto allow developers to recover their capi-tal. (OTA analyzed a minimum price of $55/ bbl of shale oil syncrude-the Governmentwould pay the difference if the marketprice were lower.) This incentive has avery strong effect on project economics. Itremoves most of the risk of price fluctua-tions in foreign oil. On the other hand, itdoes not prevent shale oil from being soldin the private market if prices there arehigher than the supported price. Withpresent and projected world oil prices, it isvery possible that no Government pur-chases would be necessary. In this case,the Government would gain income sincethe developers would pay taxes on theirproduction. This incentive limits the Gov-ernment’s financial exposure—a highly de-

sirable feature. * Its availability would alsohelp developers obtain project financing.

Price supports would benefit all firms.However, they might not be sufficient forfirms with limited debt capacity (i.e., firmsthat could not borrow the required capi-tal), especially if they were considering

costly commercial-size plants. The admin-istrative burden would range from slight tomoderate. This subsidy is supported by avariety of potential developers. Its char-acteristics make it attractive to both devel-opers and the Government.

Purchase agreement.—A developer con-tracts with the Government to sell shale oilat a specified price that is usually some-what above the expected market price.(OTA’s analysis assumed a price of $55/bblin constant 1979 dollars. ) This incentive is

similar to a price support except that thedeveloper must sell the oil to the Govern-ment; he does not have the option of sellingit in the open market. Purchase agreementsincrease profitability to a lesser extentbecause the firm does not benefit if themarket price is above the contract price.On the other hand, the Government sharesin both the risks and the potential benefitsof shale oil production. Consequently, theaverage cost to the Government is some-what lower than with a price support. Pur-chase agreements limit the possibility of

loss, but also reduce the likelihood of largeprofits. They are less popular with indus-try than are price supports. The adminis-trative costs are also higher than those of price supports, but their severity can becontrolled, to some extent, by the mannerin which the subsidy is constructed.

Low-interest loan. —The developer bor-rows a specified percentage of capitalcosts from the Government at an interestrate below the prevailing market rate.(OTA’s analysis assumed 70-percent fi-

*As indicated in table 12, the net cost to the Government of providing such an incentive —even if developers chose to sell tothe Government-would be low relative to most other incen-tives,




q

q

nancing at 3 percentage points below themarket rate. ) This incentive requires theGovernment to share significantly in therisk of project failure, and it has a markedeffect on a developer’s ability to obtainfinancing, but it tends to distort inputcosts, and to bias investment decisions infavor of capital-intensive technologies. Italso imposes large administrative burdens.This type of subsidy is usually designed toprovide the greatest benefits to firms withweak financial capability. In practice,however, it is difficult to deny loans tostrong firms.

Debt guarantees.—The Governmentagrees to pay back a loan if the developerdefaults. With this insurance, a firm canusually obtain lower interest rates. Usual-ly, only a fraction of the total loan is in-

sured, and the borrower is required to paya premium for the insurance. This incen-tive only slightly subsidizes the investment,but it provides maximum sharing of therisk of project failure. It considerablyeases borrowing problems. Loan guaran-tees primarily benefit financially weakfirms. They distort input cost, and theybias investment decisions toward capital-intensive technologies. They also impose asignificant administrative burden. Perhapsthe most obvious drawback is the uncer-tain financial exposure of the Government.The Government’s costs would be zero if noplants failed, but huge if even a few fail-ures occurred. The Government has hadconsiderable experience with debt insur-ance programs during the last 15 years,and the fees paid by firms for the protec-tion have, in sum, yielded it net income. If the participation of small- and medium-sized firms is desired, then either debtguarantees or low-interest loans will prob-ably be necessary.

Investment tax credit (10 percent), accel-

erated depreciation (5 years), and in-creased depletion allowance.—None of these would be likely to have a major im-pact on oil shale development. Their incen-

tive characteristics are discussed inchapter 6.

Direct Government Participation or Ownership

The Government could share the capitaland operating costs with industry, and there-by become a part owner of the project. Theconsequences would be similar to the con-struction grant option, except that the Gov-ernment would share all of the risks and ben-efits. Almost without exception, potential de-velopers believe that active Government par-ticipation would increase managerial com-plexity and inefficiency. Administrative bur-dens would be very high.

The Government could also contract for theconstruction of several modular plants itwould then operate, either alone or through

contracts. It could thus conduct operations toobtain accurate information on technical fea-sibility, project economics, and the relativemerits of different processes. This would beof assistance in evaluating its future policiestowards oil shale, in disseminating technicalinformation, and in improving its understand-ing of the value of its oil shale resources.After enough information had been obtained,the facility could be scrapped or sold to a pri-vate operator. This policy would provide theGovernment with information and experi-ence, but the cost would be much higher than

that of incentives to private developers.Because industrial partners would insist

on some protection of proprietary informa-tion, the Government would probably not beable to disseminate all project data as itchose. In addition, its experience in design-ing, financing, managing, and obtaining per-mits for an oil shale plant may not resemblethat of private industry. Thus, the informa-tion acquired may be of only limited use tosubsequent private developers.

Most of the information secured through

Government ownership could be made avail-able as a condition of granting private finan-cial incentives. Furthermore, this kind of Government intervention is likely to discour-



Ch 3–Constraints to 011 Shale Commercialization: Policy Options to Address These Constraints q 71

age private developers from undertakingtheir own modular development and R&D pro-grams. Government programs of this kindtend to reduce the benefits that a particularfirm could obtain from R&D or modular test-ing. Finally, when patenting and licensing

technologies, definite provision is made forthe dissemination of technical information onboth gratis and fee terms to possible users of the processes,

Institutional

Use of Federal Land*

The Federal Government owns over 70 per-cent of the oil shale lands and nearly 80 per-cent of the best shale resources. Essentiallyall of the large deposits of nahcolite and daw-sonite x in the Piceance basin are federally

owned. No permanent leasing program existsfor these lands, and the current Prototype OilShale Leasing Program is limited to no morethan six tracts of 5,120 acres each. To date,four tracts have been leased: Utah tracts U-aand U-b (the White River project) and Col-orado tracts C-a (Rio Blanco) and C-b(Cathedral Bluffs). The other two tracts wereproposed for Wyoming, but no bids were re-ceived when their leases were offered in1974. Development is proceeding on the Col-orado tracts, but the ones in Utah have beenstalled by litigation between the State and theFederal Government. ***

*On May 27, 1980 the Department of the Interior (DOI) an-nounced several oil shale decisions. Up to four new tracts willbe leased under the Prototype Program and preparationsstarted for a permanent leasing program. At least one multi-mineral tract will be included in the renewed Prototype Pro-gram. Land exchanges will not be given special emphasis, andno decision will be made to settle mining claims until the Su-preme Court rules on Andrus v. Shell Oi l (the oil shale miningdiscovery standard case). [NOTE: This case was decided onJune 2, 1980. No. 78-1815.] The administration will propose toCongress legislation to give DO I the authority to grant leasesbigger than the present statutory limitation of 5,120 acres, toprovide for off-lease disposal of shale and siting of facilities,and to allow the holding of a maximum of 4 leases nationwide

and 2 per State.* *Nahcolite is a mineral containing sodium; dawsonite con-tains aluminum.

***On May 19, 1980, the U.S. Supreme Court reversed thelower court decisions and held that the Secretary of the Interi-or could reject Utah’s applications for oil shale lands as schoolland indemnity selections (Andrus v. Utah, No. 78-1522).

Additional Federal land would not beneeded to achieve the goal of scenario 1, norto reach that of scenario 2 if economic condi-tions favored oil shale development. The goalof scenario 3 could also be met without moreFederal land if regulatory and economic un-

certainties were sufficiently reduced to en-courage Tosco, Colony, Union, and Rio Blancoto continue their commercialization pro-grams. On the other hand, implementation of scenario 4 would require a highly favorableeconomic and regulatory climate (probablyincluding Federal subsidies), or the use of ad-ditional Federal land, or both. In any of thescenarios, more public land may be requiredif large-scale multimineral recovery proc-esses or open pit mining are to be tested in thenear future.

The land could be leased, exchanged forprivate land, or developed by the Govern-ment. All three options may be affected by thefact that much of the best Federal oil shaleland is subject to unpatented mining claimsby private parties. The validity of some of these claims will be determined by the Su-preme Court in 1980. If the Court’s ruling fa-vors the claimants, much less Federal landmay be available for disposition.

Leasing.—Under the Mineral Leasing Actof 1920, the Department of the Interior (DOI)has the authority to lease public oil shale

lands to private developers. The Act limitsthe number of leases to one per person orfirm, and restricts the maximum size of asingle tract to 5,120 acres (8 mi2). Individualsand firms are allowed to hold shares in sever-al leases, but the total area covered by theseshares cannot exceed 5,120 acres.

Whether the acreage limitation will im-pede development will depend on the locationof the tract and on the types of developmenttechnologies to be employed. It might pre-clude large-scale operations in the thinner,

leaner deposits in Wyoming. However, a5,120-acre tract in the relatively rich areas of the Piceance and Uinta basins could easilysupport a commercial-scale operation over itseconomic lifetime. On the other hand, if avery large facility were desired, the acreage




limitation could impede efficient resource de-velopment, especially if surface mining wereto be used. If the entire tract were suitablefor surface mining, the need to dispose of min-ing and processing wastes within the tractboundaries would reduce overall resource re-covery, and might allow only relatively ineffi-cient development. One solution would be toinclude in the tract an area (such as a drycanyon) that contains no oil shale resourcesbut that could be used for waste disposal.This option would not require amending theLeasing Act, but it could complicate miningoperations and would reduce the value of thetract to the private sector. Another optionwould be to allow disposal in similar areasoutside the tract boundaries, as was original-ly proposed for tract C-a, but this would re-quire amending the Federal Land Policy andManagement Act of 1976 (FLPMA).

The argument in favor of limiting the num-ber of leases per individual or firm is that itprevents a small number of entrepreneursfrom cornering the lease market. The argu-ment against the restriction is that it preventsa developer from acquiring experience andtechnical information on one tract and thenapplying it to another while the first is stilloperating. The latter position is valid forpotential developers who do not have theirown oil shale land, but not for those whoseprivately owned tracts could be developed

commercially if the company could acquirethe necessary expertise in the richer depositson public land. The options are to increasethe number of leases allowed to two or threeper company or individual, regardless of thelocations of the tracts; or to allow one leaseper developer per State. The latter wouldallow a developer to obtain experience withthe richer oil shales in Colorado, for example,which could then be applied in Utah or Wyo-ming. Potential developers prefer the first op-tion because the shales in Utah and Wyomingare much poorer than those in Colorado. Bothoptions would require amending the MineralLeasing Act.

If additional leasing is desired, it could becarried out either in a new, permanent leas-ing program, or as part of the Prototype Pro-

gram. Opportunities exist for leasing at leasttwo additional tracts within the PrototypeProgram because of the two Wyoming leasesthat were not purchased during the 1974 of-fering. No congressional action would be re-quired to extend the Prototype Program, butits extension would constitute a major Feder-al action. Therefore, a supplementary envi-ronmental impact statement (EIS) would berequired. Its preparation could take from 1 to2 years.

Nomination of the tracts and preparationof leasing regulations could add severalmonths to a year to the front end of the sched-ule. Unless the preliminary steps were expe-dited, the leases could probably not be solduntil about 1983. If the leases were similar tothose for the existing Prototype tracts, a2-year environmental monitoring program

would be mandated before site developmentcould proceed. Thus, the first constructionwork could not begin until about 1985. If acommercial plant were built without a pre-liminary demonstration phase, commercialproduction could start in about 1990. With ademonstration phase, commercial productioncould not begin before 1992 or 1993.

The timespan could be reduced somewhatby offering the tracts that were considered inthe mid-1970’s as replacements for the Wyo-ming tracts. The nomination process was

completed for these tracts, and work was be-gun on a supplemental EIS. They were origi-nally selected as sites for in situ operations,and to offer them now for this type of devel-opment would be inconsistent with one of theProgram’s major goals, which was to test avariety of processing technologies. (Both of the active Prototype tracts are being devel-oped by in situ techniques. ) If they were alsosuitable for aboveground processing, theiruse in the program extension would shortenthe commercialization schedule by about ayear.

The other leasing option would be a new,permanent leasing program that would be in-dependent of the Prototype Program andtherefore not restricted by its six-tract limit.Implementing this option would take longer



Ch 3–Constraints to 0il Shale Commercialization Policy Options to Address These Constraints q 73

than extending the Prototype Program, be-cause of the need to prepare new leasing reg-ulations and an entirely new EIS. No congres-sional action would be required, unless theprogram were to be coupled with an incen-tives package or with amendments to the Min-eral Leasing Act.

The adoption of a new leasing programwould imply the abandonment of another objective of the Prototype Program, namely toobtain the technical, economic, and environ-mental information needed to design a perma-nent leasing program. For a variety of rea-sons, the Prototype Program has not yet pro-vided this information. (See vol. II. ) Its aban-donment would engender political oppositionfrom the individuals and groups that criticizeoil shale development, especially where pub-lic land is involved.

Land exchange. —Private interests ownseveral million acres of oil shale land. Of theapproximately 400,000 acres of privatelyowned land in Colorado, at least 170,000acres contain beds that are at least 10 ft deepwith a potential yield of 25 gal/ton, It hasbeen estimated that the total potential oilyield from these richer tracts is at least 80billion bbl. However, much of the privatelyheld land is located on the fringes of the oilshale basins, and contains thinner, leaner de-posits than does the adjacent Federal land,Furthermore, many of the private tracts arein small, noncontiguous parcels (mainly for-mer homesteads and small mining claims)that cannot be economically developed. Pri-vate oil shale development would be encour-aged if these lands were exchanged for moreeconomically attractive Federal tracts.

There are essentially two land exchangeoptions. The first involves “blocking up’ scat-tered or oddly shaped private tracts by ex-changing some of them for adjacent Federallands. (Superior Oil Co. proposed such an ex-change for its tract near the northern edge of the Piceance basin. ) The second option in-volves the exchange of large privately ownedparcels for equivalent Federal tracts, per-haps in an area that is more suitable for aspecific development method.

Both options are allowed by FLPMA. UnderFLPMA, the Government may exchange pub-lic land for private land, provided that the ex-change is in the public interest and that theproperties involved are within 25 percent of equal value. The difference can be made upwith cash. The major problem with ex-

changes under FLPMA is that the proceduresare time-consuming, complex, and costly. Sev-eral Federal agencies must be involved inestimating the relative values of the tracts inquestion and in determining whether the ex-change is in the public interest. An EIS maybe needed; its preparation could take as longas 2 years. The overall process, including re-view, evaluation, and approval by the agen-cies plus a period for public comment, cantake even more time.

There are several ways to improve the ex-

change process. One would be to streamlinethe review procedures, perhaps by setting upa task force within DOI to deal with exchangeproposals involving oil shale lands. Anotheroption would be for DOI to nominate Federaltracts, to characterize their environments,and to evaluate their resources, even if no ex-change proposals had been received from pri-vate parties. With this advance preparation,the exchange process would be shortened,and the Government would be able to controlthe location of the future oil shale plants.Both options would be costly and would en-

large the bureaucracy. Additional appropria-tions, and possibly authorizing legislation,would have to be provided by Congress.

A third option would be to exchange pri-vate land for Federal land that is adjacent toState-owned tracts. The mix of private andState land could then be developed under aState-controlled leasing program. This optionwould be most applicable to the Uinta basin,where the State’s extensive holdings are in-termingled with Federal and private tracts.

Government development.—The Govern-

ment could also develop its own oil shalelands. Two likely tracts are the 40,000-acreNaval Oil Shale Reserve I (NOSR 1) in Colora-do and the 90,000-acre NOSR 2 in Utah. (Theresources on NOSR 2 are of much poorer




quality.) These sites could be developedeither with a Government-owned corporation,or through a cost-sharing arrangement withindustry. The advantages and disadvantagesof different types of Government participa-tion are discussed in the section on economicand financial policies.


Developers view the costs and potentialrisks of the present regulatory process as oneof two primary impediments to development.Reaching the production goals of scenarios 1and 2 will probably not require expediting thepermitting process, but it will be needed tomeet the goals of scenario 3, and is even moreimportant for scenario 4. One or more of thefollowing actions could speed up the process:require regulatory agencies to make deci-

sions in a specified period of time; “grand-father” projects under development to makenew laws and regulations inapplicable tothem; create an energy board or authoritywith the power to overrule Federal regula-tory decisions; or limit litigation as was donewith the Alaskan oil pipeline. The first twooptions are likely to be a part of the powers of the Energy Mobilization Board.

Another possibility would be for regulatoryagencies themselves to take the lead in simpli-fying their own permitting procedures. This

could be done by the imposition of internaltime limits on the period of review, and couldbe combined with an arrangement wherebydevelopers applied for a package of relatedpermits. This would consolidate the numberof permits required, and eliminate some of the existing permit duplication. EPA RegionVIII appears to be adopting these procedures,although it is not clear whether and to whatextent they will actually expedite the permit-ting process.

Pipelines

A major pipeline would have to be built toship most of the l-million-bbl/d target of sce-nario 4 because existing pipelines to Wyo-ming and Midwestern refineries are inade-quate. Its construction could require access

across Federal land and eminent domainrights to private land, as well as extensiveregulatory actions and EISs. Congressionalaction might be needed to facilitate such aproject.

Design and Construction Services

and Equipment

To achieve the goals of scenario 4, Federalassistance might be needed to deal with scar-cities of heavy equipment and limited designand construction services. The following pol-icies might be developed:

q

q

q

q

q

q

Training programs could be set up forconstruction workers to provide a skilledwork force when construction begins.Equipment with long delivery timescould be identified and supplies in-

creased by either expanding existing ca-pacity, stimulating additional capacity,or encouraging early orders.Tariffs and quotas on imported equip-ment could be reduced or eliminated.Federally sponsored R&D programscould address the technical questions of scaling up to commercial-sized facilities.Developers, local governmental units, re-lated industries, concerned interestgroups, and appropriate Federal agen-cies could be encouraged to coordinatetheir efforts. This would help avoid con-

struction delays,Standardization of plant designs couldbe used to reduce complexity and simpli-fy construction.

Environmental

Air Quality

The PSD standards promulgated under theClean Air Act could hinder scenario 3 andwill, with current “best available controltechnologies, ” prevent achieving scenario 4.

Policy options for addressing these obstaclesinclude:

q Coordinate the issuance of PSD permits.—This option would not alter the PSD regula-tions nor relax air quality standards, but



Ch. 3–Constraints to Oil Shale Commercialization: Policy Options to Address These Constraints q75

q

q

would change the methods for issuing thePSD permits that are needed before con-struction of the plants can begin. Ratherthan issuing the permits on a first-comefirst-served basis, EPA would encourageall prospective developers to coordinate

their development plans before applyingfor their permits. The goal would be a sit-ing pattern that maximized productionwhile complying with air quality stand-ards. This might relieve some of the sitingdifficulties envisioned for the Piceance ba-sin as a result of its proximity to the FlatTops Wilderness area. The implementationof this type of option, however, could becomplicated by factors such as antitrustlaws.Redesignate the oil shale region fromClass 11 to Class III.—This option would be

initiated at the State level, with a require-ment for final approval from EPA. The cri-teria that would have to be satisfied in-clude:—the Governors of Colorado, Utah, or

Wyoming must specifically approve theredesignation after consultation withlegislators, and with final approval of local government units representing amajority of the residents of the area tobe redesignated, and

—the redesignation must not lead to pollu-tion in excess of allowable increments in

any other areas.This option would allow greater degrada-tion of air quality, but would permit moreindustrial development. While it would ap-pear that with such an option there couldbe about twice as much oil shale develop-ment as presently possible, there wouldstill be limitations owing to nearby Class Iareas. With this option it is expected thatthe production target of scenario 3 couldbe achieved, but not that of scenario 4.Amend the Clean Air Act. —This congres-sional option would exempt the oil shale re-

gion from compliance with certain provi-sions of the Act. Under this option Con-gress might direct EPA and the States toredesignate the oil shale region from aClass 11 to a Class III area, and to exempt

the developers from maintaining the visi-bility and air quality of nearby Class Iareas. This would remove both the majoruncertainties surrounding the siting of fa-cilities within the resource region itself and any siting barriers connected with the

degradation of the Class I areas. Such anoption should allow achievement of the sce-nario 4 production goal at the cost of in-creased air pollution in the oil shale andnearby regions.

Environmental R&D

The public and private sectors have car-ried out extensive work on the environmentalimpacts of oil shale development and on pollu-tion control technologies to reduce these im-pacts. Yet many questions remain about theeffects that a commercial-size industry wouldhave both on the physical environment and onworker health and safety. It is essential,therefore, that R&D keep pace with the indus-try’s development. The information generatedwould also assist regulatory agencies to de-velop emission and effluent standards for theindustry.

Options at the Federal level for improvingtechnical information include improved coor-dination of R&D among executive branchagencies, increased appropriations for oilshale R&D, the use of existing national com-

missions (e.g., the National Commission onAir Quality) and the passage of legislationspecifically directed to R&D on the environ-mental impacts of oil shale technologies. (En-vironmental R&D needs are discussed in ch. 8and summarized in ch. I.)

Water Resources

Policy options for removing obstacles asso-ciated with water resources are discussedbelow.

Financing and Building New Reservoirs

Major new reservoirs will be needed forscenarios 3 and 4 to ensure that the waterneeds of oil shale developers as well as all



.


other users can be satisfied. They could be fi-nanced and built by the Federal Government,by State organizations, or by the developers.The options for Federal involvement are dis-cussed below. (Those for the States and thedevelopers are discussed inch. 9.)

Congress could provide for the construc-tion and financing of new water projectsthrough two mechanisms. First, funds couldbe appropriated for a projector projects thathave already been authorized. Several havealready been evaluated by the Water andPower Resources Service (WPRS), * and theirconstruction approved. Actual constructioncannot not be started until they are funded.However, not all of these projects have beenevaluated for their suitability to supply waterfor oil shale development, and some projectsmay not be optimally located to serve oil shale

plants. A second option would be to pass leg-islation that would specify both the construc-tion and funding of new, but not previouslyauthorized, Federal water projects. Unlesslanguage were included to expedite construc-tion, these projects would require a long re-view process. They could, however, be de-signed and sited as water sources for oilshale (as well as other possible uses). An ex-ample would be constructing irrigation reser-voirs with additional capacity for oil shale re-quirements.

Under either option, DOI, through WPRS,could operate these reservoirs in accordancewith State water law. Their costs could be re-covered over the operating life of the facil-ities from revenues generated by selling wa-ter to oil shale developers and other users, inaccordance with authorizing legislation.

The Siting of Reservoirs and Direct

Flow Diversions

The construction of new reservoirs and di-rect flow diversions (e.g., pipelines) might behampered, delayed, or even disallowed underprovisions of the Endangered Species Act, theNational Wild and Scenic Rivers Act, and the

*Formerly the U.S. Bureau of Reclamation (USBR).

Wilderness Act. Potential problems could bereduced by the following mechanisms.

q

q

Identifying endangered or threatened spe-cies.—Two federally designated rare andendangered fish species, the humpbackchub and the Colorado River squawfish,

have already been found in the waters of the oil shale region, and additional speciesrequiring protection may be found duringfuture studies. The Endangered SpeciesAct may be interpreted as restricting activ-ities that might affect the critical habitatsof such species, although no critical habi-tat has been declared for the squawfish orhumpback chub. Knowing the approximatelocation of the critical habitats of endan-gered species would be helpful if it weredecided to establish an oil shale industrybecause the timely siting of reservoirs and

direct flow diversions could be affected byagency interpretations involving instreamflows. Should construction of these facili-ties begin before the critical areas wereidentified, there could be opposition totheir completion, and water supplies froma particular reach of a river could be de-layed or interrupted. If the locations of alldesignated critical habitats were identifiedby DOI and the required biological opinionsobtained, the facilities could be sited tominimize interference and delay.

Alternatively, Congress could designate

such reservoirs to be in the national inter-est, and could allow their construction inspite of the effect this might have on endan-gered species.

Designating wild and scenic rivers andwilderness areas. —To date, no rivers inthe oil shale region have been designatedfor inclusion in the Wild and Scenic RiversSystem; however, several within the basinsof the Colorado River mainstem are beingconsidered, Diversions of water from spe-cific stream reaches could be affected if

they are set aside. An early designation of the eligible rivers would assist in the plan-ning for future shale oil production. Giventhis information, direct flow diversionscould be sited downstream from the por-



Ch 3–Constraints to 0il Shale Commercialization, Policy Options to Address These Constraints q 77

tions designated as wild or scenic. Thiswould avoid a direct conflict within a givenriver stretch but could add to the watersupply costs. (Supply costs are discussed indetail inch. 9.)

To date, four areas in the basins of theWhite River and the Colorado River main-stem have been designated under the Wil-derness Act. Other areas are being consid-ered pursuant to the Roadless Area Reviewand Evaluation II (RARE II) program. * Newreservoirs would not be permitted in thedesignated areas. A complete listing of wil-derness areas that might be considered inthe near future would allow potential de-velopers to locate their water storage facil-ities elsewhere. Alternatively, Congresscould specifically exclude rivers and/ornew areas in the oil shale region from des-

ignation as wild and scenic rivers or wil-derness areas.

Federal Sources of Water for

Oil Shale Development

Congress, under its constitutional powers,could make water available from Federal wa-ter projects, or potentially from the reservedrights doctrine. (See ch, 9.) If Congress de-cides that water from congressionally fundedprojects should be made available for oilshale development, then any legislation

enacted should provide that the term “indus-trial use or purpose” includes the use of water for oil shale development,** Congresscould also amend the authorizing legislationfor those projects from which water for oilshale development might be sought, to permit

*“1’he Forest Service, in its RARE 11 progr~m, is evaluatingover 66 million acres of land to determine their suitability fordesignation as wilderness, During the period of initial evalua-tion, and up to final recommendation by Congress, these landswill be in some form of restrictive management.

**A Memorandum of Understanding ex ists between DOI andthe State of Colorado with respect to the use of water from ex-isting or authorized U.S. Bureau of Reclamation (now WPRS)

projects, The State desires thfit the water not be changed fromagricultural, municipal, or light industrial uses to energy pro-duct ion (including oil shale] that are inconsistent with State pol-icies. Under this memorandum, the State WT ill review any appli-cations to redistribute water from conventional uses to energyproduction. The memorandum could be superseded bV directcongressional directives of overriding national importance.

the use of their water for this purpose. Theobjective of this action would be to overcomeany administrative reluctance to permit theuse of water for oil shale development underan authorization that did not specificallymention oil shale,

The power of Congress over reserved wa-ters is more limited than its power overwaters in congressionally funded projects.Water rights covered by the reserved rightdoctrine must be used “in furtherance of thepurpose of the reservation. ” For this reason,Federal water rights do not seem to be likelysources for oil shale development, exceptperhaps in the case of lands set aside for theNaval Oil Shale Reserves. This question, how-ever, is in the early stages of litigation.

Interbasin Diversion

Interbasin diversion is a technically feasi-ble although costly option for bringing addi-tional water to the oil shale region, There arealso serious political obstacles to this alterna-tive. The Reclamation Safety of Dams Act of 1978, amending the Colorado River BasinProject Act, prohibits the Secretary of the In-terior from studying the importation of waterinto the Colorado River Basin until 1988. If itwere decided to pursue this option as ameans of supplying water to an oil shale in-dustry coming online in 1990, this prohibition

would have to be lifted.Interbasin transfers could be used to re-

lieve the water problems of the oil shale re-gion in several ways, Water could be trans-ferred directly to the oil shale region, eitherexclusively for oil shale development or forall users. Alternatively, the water needs of Colorado’s eastern slope cities, presentlybeing supplied in part from the Upper Col-orado River Basin, could be met from otherhydrologic basins. The water presently beingexported from the Upper Basin then could beused for oil shale development. In a third ap-plication of interbasin transfers, all or a por-tion of the 750,000 acre-ft/yr presently beingsupplied to Mexico by the Upper Basin Statesunder the Mexican Water Treaty of 1944-45,could be taken from another hydrological




basin (perhaps the Mississippi basin). Thewater thus freed in the Upper Basin could beassigned in part to oil shale development(750,000 acre-ft/yr would be sufficient for a3-million- to 7.5-million-bbl/d shale oil in-dustry).

The Allocation of Water Resources

If Congress were to pass legislation encour-aging the development of an oil shale indus-try, it might wish to address the issue of howthe necessary water would be supplied andhow oil shale legislation might affect waterallocation.

Water in the oil shale region is presentlydistributed by a complex framework of inter-state and interregional compacts, State andFederal laws, Supreme Court decisions, an in-ternational treaty, and administrative deci-sions. Within the Western States, waterrights are apportioned by the States to com-peting users according to a doctrine of priorappropriation under which water rights are aform of property separate from the land.

Oil shale developers presently hold exten-sive, but largely junior (i.e., low priority) sur-face water rights. Therefore, if water short-ages were to occur, existing developer sup-plies could be interrupted. More reliable sup-plies may be provided through developmentof ground water not tributary to the surface,

purchase of the consumptive portion of irriga-tion rights during the irrigation season, pur-chase of surplus water from Federal reser-voirs, or importation of water from more dis-tant hydrological basins. (The last two op-tions have been discussed above). A discus-sion of the amount of water needed for oilshale development is presented in detail inchapter 9.

If control over the water supply for oilshale is to be left to the States, then Congressshould probably so specify that decision in oilshale legislation to avoid any question of thepreemption of State water laws. Legislationthat would confirm preservation to the Statesof the same power over water for oil shale asthey have over other water supplies shouldrequire the developer to comply with State

procedures in securing a water supply, andprovide that the established State appropria-tion system has the same authority to grant,deny, or place conditions on a water right andpermit as would prevail in the absence of thelegislation.

If Congress were to attempt to remove thewater supply for oil shale production fromthe control of the State, strong legal andpolitical resistance would ensue. Such resist-ance could delay oil shale development.

Socioeconomic

The social and economic effects of oil shaledevelopment are not unique to the resourcebeing produced or to the technologies in-volved. Rather, they derive from an influx of

people, regardless of the cause. In this re-spect, they are similar to the effects of growth in other energy industries, such ascoal or oil and gas. Before looking at specificpolicy options for the effects of oil shale de-velopment, the perspective from which theyare viewed and the role of the Federal Gov-ernment in impact mitigation must be con-sidered.

Congress can view socioeconomic impactsfrom one of three policy perspectives:

q

q

As part of the consequences of all kinds

of energy development.—In recent ses-sions, Congress has considered bills thatwould provide assistance to communi-ties faced with problems from thegrowth of many different energy indus-tries, and programs for oil shale could beincluded in such legislation.As an aspect of specific energy initia-tives.— Proposed amendments to thePowerplant and Industrial Fuel Use Actof 1978 are illustrative of this more lim-ited approach. These amendments aredirected to the adverse effects of majorenergy developments, which could in-clude oil shale. They authorize grants,loans, loan guarantees, and payments of interest on loans; and propose an expe-diting process for present Federal pro-



Ch 3–Constraints to Oil Shale Commercialization: Policy Options to Address These Constraints q 79

grams as well as an interagency councilto coordinate Federal impact assistance.

q As the result of oil shale developmentalone. —In this case, specific languagedealing with socioeconomic effects couldbe included in bills providing for the de-velopment of oil shale resources.

The ways in which Congress deals with theimpacts will depend on which perspective isadopted.

Policy decisions must also consider the roleof the Federal Government in impact mitiga-tion. Assistance in coping with the conse-quences of growth is not expected in the usu-al course of economic development. Recently,domestic energy development has become anexception when the distinction has beendrawn between effects that can be handledby local communities—i.e., those that can be

considered a normal adjunct of development,and those that cannot be readily solved withlocal resources—boomtown problems. Theextent and nature of Federal involvement inimpact mitigation is highly controversial. Onthe one side, it is argued that social andeconomic difficulties are State and localproblems that should be viewed as the inevi-table consequences of industrial growth, andthus the Federal Government need not be in-volved with their amelioration. On the otherside, the position is taken that national energyrequirements are the root causes of impacts,

therefore a Federal role is appropriate. Sev-eral Western States propose that for reasonsof equity, the national goal of accelerateddomestic energy production requires directFederal participation in alleviating negativeimpacts. This question about the Federal rolemust be faced before decisions can be madeabout appropriate Federal actions for dealingwith the impacts of oil shale development.

No new Federal initiatives appear to beneeded for scenarios 1 and 2, as long as theexisting mechanisms are effective. Several

requirements must be met, however:q both Federal and State actions must sup-

port already established growth man-agement processes;

q

q

q

efforts to improve the delivery of Fed-eral programs should continue;State appropriations from funds desig-nated to assist the oil shale communitieswill be necessary; andsupport services, such as technical as-sistance to the local governments, should

not be reduced.Increased Federal participation will be

needed if the region is to accommodate thegrowth anticipated under scenarios 3 and 4.Several kinds of support could be given. Oneoption would be to provide additional financ-ing for expanding the communities and forplanning and establishing new ones. Anotherwould be to create Federal programs to solveproblems for which local groups have neitherthe time nor the resources. For instance, dif-ficulties may arise from inequities in the dis-tribution of revenues among States. Thesecould be evaluated, and Federal actionstaken for their correction. Such problems willoccur if the workers for Utah developmentschoose to live in Colorado; Utah will gain taxrevenues from the plants but Colorado willhave to pay for the consequences of in-creased growth in its rural areas. Yetanother option would be to expand FederalR&D efforts. As an example, it would be valu-able to have estimates of the maximum rateat which the communities could grow withoutexperiencing severe disruption. These esti-

mates could be used by policymakers to adjust the timing and location of additional Fed-eral oil shale leases to take into account so-cioeconomic impacts.

Which of the options would be best will de-pend on the success of local preparations andon the nature and timing of new development.If the industry grows slowly, Federal partic-ipation might be limited to R&D and other sup-porting activities. If it expands rapidly, sub-stantial direct financial support and activegrowth management efforts will be needed.For example, a coordinated strategy will be

required to cope with the growth that wouldaccompany the production of 1 million bbl/d,as envisioned by scenario 4; and the respon-sibilities would have to be shared by Federal,




State, regional, and local governmental unitsas well as by all private sectors. ExtensiveFederal participation would be unavoidable.One option would be to create a new Federalregional authority, for the impacts will ex-tend into Utah and Wyoming. The powersgranted to such an authority would depend on

the degree of coordination and cooperationbetween the public and private sectors, andon the severity of the negative impacts. Forinstance, construction of new homes, apart-ments, and other living facilities will have to

be financed. This will involve private partieslike lending institutions, and possibly the oilshale developers. But where private capital isinsufficient, the Federal or State govern-ments will have to step in. Housing is only onesector where the needs can be expected tooutstrip the resources, and where combined

efforts to meet them will be essential. Manyagencies, operating in many areas and at alllevels, would have to be involved to cope withthe growth that would accompany the estab-lishment of a l-million-bbl/d industry by 1990.

Scenario Evaluation

As has been shown for the four scenarios,different development strategies entail sub-stantially different requirements, conse-

quences, and Federal actions. Regardless of the strategy selected, tradeoffs among objec-tives and requirements are inevitable. This isindicated in figure 11, where the scenariosare rated according to the relative degrees towhich they are expected to attain the objec-tives for development. The following summa-rizes how the attainment of each objectivevaries with the production goals.

To position the industry for rapid deploy-ment.—The 400,000-bbl/d industry is giventhe highest rating because a wide varietyof technologies and sites would be evalu-

ated and substantial technical, environ-mental, and economic information wouldbe obtained; all of which would place theindustry in a good position for rapid scale-up. The l-million-bbl/d goal is rated nextsince production at this level would consti-tute a major industry; further rapid deploy-ment could then follow. It is rated lowerthan the 400,000-bbl/d” scenario because itsaccelerated construction schedule wouldpreclude valuable precommercial experi-ments and would probably not result in themost technically efficient plants. The othergoals are rated lower because fewer proc-esses could be evaluated.

To maximize energy supplies.—The bene-fits, and thus the ratings, are proportionalto the production rate.

q To minimize Federal promotion.—The100,000-bbl/d target is rated highest be-cause it could be achieved by completing

the presently active projects. The 200,000-bbl/d goal probably would require some in-centives, and the 400,000-bbl/d” one wouldrequire incentives, a small land exchange,and the short-term leasing of a FederalR&D facility in Colorado for a demonstra-tion project. The l-million-bbl/d targetwould require much stronger subsidies, ad-ditional leasing of public land for a longerperiod, permitting modifications, vari-ances, and extensive Federal involvementin growth management.

q To maximize ultimate environmental infor-mation and protection.—The quantity of pollutants and wastes generated will in-crease in proportion to the rate of produc-tion. Establishing a l-million-bbl/d industryin 10 years would cause the most disturb-ance per unit of production because therewould not be enough time to improve thecontrol technologies. The 100,000-bbl/d in-dustry is also given a low rating becausethe limited number of technologies testedwould provide neither extensive informa-

tion on impacts nor guidance for the im-provement of controls and regulations. The400,000-bbl/d target would meet the needsfor information and testing of control tech-nologies but would incur a greater environ-mental risk per unit of production than



Ch 3–Constraints to 011 Shale Commercialization Policy Options to Address These Constraints q 81

Figure 11 .—The Relative Degree to Which the Production Targets Would Attain the Objectives for Development


100,000 200,000 400,000 1 mil l ion

I To position the industry for rapid deploymentI I

To maximize energy supplies

To minimize federal promotion

I To maximize environmental information and I

1 I

protectionI

To maximize the integrity of the social

environment

To achieve an efficient and cost-effectiveenergy supply system

L o w e s t d e g r e e o f a t t a i n m e n t I I _ H i g h e s t d e g r e e o f a t t a i n m e n t


q

200,000 bbl/d. The latter would maximizethe attainment of this objective.

To maximize the integrity of the social en-vironment. —The 100,000-bbl/d target israted high because this level of growthshould be within the physical capacities of the communities. The 200,000-bbl/d” goalwould create some strain in the ability of the towns to absorb the number of ex-pected new residents; the degree of stresswould depend on the location of the devel-opment. Adjusting to the growth associatedwith a 400,000 -bbl/d industry would bepossible if the plantsites were dispersed inUtah and Colorado, if plant constructionwere phased, and if preparations for theconstruction of new towns were started atonce; but there would be a high probability

that boomtown effects would accompanythis level of growth. A l-million-bbl/d indus-try would require coordinated growth man-agement strategies and extensive financialoutlays. Severe social disruption could beanticipated.

q To achieve an efficient and cost-effectiveenergy supply system.—The 400,000-bbl/dtarget has the highest rating because,among other factors, it would provide abalance of information generation andprocess development and demonstration.The 100,000- and 200,000-bbl/d targets are

rated lower because only a few technol-ogies and sites would be tested. The l-mil-lion-bbl/d industry is also rated low be-cause its deployment strategy would poorlyutilize many of the elements of production.Furthermore, the plants might not generatesufficient profit capital for subsequent ex-pansion.

An illustration of the need for tradeoffs be-tween objectives can be seen at the l-million-bbl/d level. This choice has high attainment of the positioning and energy production objec-

tives (e.g., it would displace about 16 percentof the imported oil and reduce the balance of payments significantly). However, reachingthe target requires tradeoffs in all the otherareas. (For example, it would violate theClean Air Act.)



CHAPTER 4

Background



Contents

P a g e

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . 85The Need for a New Energy Supply System. , . 85The Purpose and Organization of This Chapter 86

Oil Shale Resources . . . . . . . . . . . . . . . . . . . . . 87The Genesis of Oil Shale. . . . . . . . . . . . . . . . . . 87

Worldwide Deposits . . . . . . . . . . . . . . . . . . . . . 87Deposits in the United States . . . . . . . . . . . . . . 88

Description of the Oil Shale Resource Region. 93Location . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 93Topography and Geology. . . . . . . . . . . . . . . . . 93Climate and Meteorology. . . . . . . . . . . . . . . . . 99Plants and Animals. ... , . . . . . . . . . . . .. ....100Air and Water Quality and Economic Base. .. 103

Oil Shale Products and Their PotentialApplications . . . . . . . . . . . . . . . . . . . . .. ...105

The Nature of Oil Shale . .................105Kerogen Pyrolysis. . . . . . . . . . . . . . . . . . . . . .. 105Associated Minerals. . . ..................107

The History of Oil ShaleDevelopment. .. ....108Scot land . . . . . . . . . . . . . . . . . . . . . . . . . . . . . , 108Sweden . . . . . . . . . . . . ................,..108France . . . . . . . . . ................,......109Spain . . . . . . . . . . . ......................109Germany . . . . . . . .......................109South Africa . . , . . . . . . . . . . . . . . . . . . . . . . . .109Australia . . , . . . . . . . . . . . . . . . . . . . . . . . . . . .109United States, . . . .....................,.110

Status of Foreign Oil Shale Industries . . . . . . .111Morocco . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 111Soviet Union . . . . . . . . . . . . . . . . . . . . . . . . . . .111People’s Republic of China. . .....,..,.....112Braz i l . . . . , . . . . . . . . . . . . . . . . . . . . . . . . . . . . 112

P a g e

Status of U.S. Oil Shale Projects . ..........113

Chapter 4 References. . ..................114

List of Tables

Table No.13. Potential Shale Oil in Place in the Oil

14

15

Shale Deposits of theUnited States . . . . .Potential Shale Oil in Place in the GreenRiver Formation: Colorado, Utah, andWyoming . . . . . . . . . . . . . . . . . . . . . . . . .Potential Shale Oil Resources of theGreen River Formation . . . . . . . . . . . . . .

16. Composition and Pyrolysis Products of Typical Colorado Oil Shale . . . . . . . . . . .

17. Status of MajorU.S. Oil Shale Projects. .

List of Figures

Figure No,12. Oil Shale Deposits of the United States. .13. Oil Shale Deposits of the Green River

Formation . . . . . . . . . . . . . . . . . . . . . . . . .14. The Oil Shale Resource Region of the

Green River Formation: Colorado, Utah,and Wyoming. . . . . . . . . . . . . . . . . . . . . .

15. Major Mountain Systems in the Vicinityof the Green River Formation . . . . . . . . .

16. Topographic Relief of the piceanceBasin, Colo,. . . . . . . . . . . . . . . . . . . . . . . .

17. Stratigraphy and Landform Units AlongParachute Creek,Piceance Basin, Colo. .

18. Idealized Cross Section of the Piceance

Page

89

91

92

106114

Page89

90

94

95

96

97

Basin, Colo. . . . . . . . . . . . . . . . . . . . . . . . . 98



CHAPTER 4

Background

Introduction

The United States has obtained energy for

human comfort, security, and productivityfrom a variety of sources over the past 200years. The availability of energy was instru-mental in its transformation from a largelyagricultural society until the late 18th cen-tury to a major industrial power in the 20th.

During all of the 18th century and early19th, human muscles and those of beasts of burden did most of the useful work. Through-out this period, wood was the primary fuel,supplemented by relatively small amounts of coal, coal oil, whale oil, mechanical energy

from falling water, and kerosene derivedfrom natural petroleum seeps. By the middleof the 19th century, coal had become thechief fuel and dominated the Nation’s energysupply system for about a hundred years.Petroleum-based fuels and natural gas en-tered the picture after 1859, the year inwhich the first commercial oil well wasdrilled in Pennsylvania. The use of petroleumgrew rapidly. It was further accelerated bythe arrival of the automobile age in the early1900’s. Natural gas, which was originallyburned or vented as a waste product from oil

wells, became a major fuel for domestic, com-mercial, and industrial heating by the end of World War II.

By the middle of the 20th century, oil andgas had become the leading sources of energyin the United States, having displaced coalbecause of their convenience. In 1972, ac-cording to the Department of Energy (DOE),the Nation’s economy consumed approxi-mately 72 Quads of energy from primarysources, * of which approximately 46 percentwas obtained from petroleum, 32 percentfrom natural gas, and 17 percent from coal.Relatively small amounts were supplied by

*One Quad equals 1 quadrillion ( 101 Btu. A primary energysource is one that may be converted to another form prior toend use. Coal burned for power genera t ion is an example.

hydroelectric dams, nuclear powerplants,

geothermal sources, biomass, and other ener-gy resources. Wood, once the principal ener-gy source for the Nation, was used largely bysome lumber mills and wood-processing facil-ities.

The Need for a New Energy

Supply System

In 1973, Arab oil exporting nations insti-tuted an embargo against the United Statesand other nations that supported Israel. Re-

duced petroleum availability was followed bya recession that lasted through 1974 and into1975. As a consequence, energy consumptiondeclined slightly, bottoming out at about 71Quads in 1975. By 1976, energy demand hadreturned to its 1973 level of about 74.5Quads/yr. It has continued to rise, althoughsomewhat less rapidly than prior to the em-bargo.

In 1978, approximately 78 Quads of energywere consumed in the United States—theequivalent of 13.4 billion bbl of fuel oil.Energy supply patterns had altered slightly

since 1972. In 1978, petroleum supplied about48 percent of the energy, natural gas about25 percent, and coal about 18 percent. Geo-thermal and biomass use had increased sub-stantially, but these resources, together withnuclear and hydropower, still provided onlyabout 9 percent of the Nation’s energy.

It is likely that energy consumption willcontinue to rise until conservation strategiesare adopted by all sectors of the economy. If historical growth trends for energy consump-tion are followed, the annual energy con-

sumption will reach 135 Quads by the year2000-the equivalent of over 23 billion bbl of fuel oil per year or nearly twice the 1978 con-sumption. Actual consumption should be con-siderably lower, because energy demand is

85




now growing more slowly than in the past.Conservation should slow it down further.

Several implications may be drawn fromthis discussion. First, the United States con-sumes enormous amounts of energy. (The1978 consumption was equivalent to over2,500 gal of fuel oil per citizen per year, ) Sec-ond, energy demand will continue to rise inthe near future. Third, the Nation runs onfossil fuel, with petroleum satisfying nearly50 percent of the total energy demand.

This last implication is crucial because itappears that the United States no longer hasadequate petroleum reserves of its own. Newpetroleum discoveries peaked in the 1950’s.Domestic oil production followed suit in about1970, except for the fields in Alaska and onthe Continental Shelf. Domestic discoveriesare increasing, at present, because of higher

oil prices, but it is unlikely that sufficient U.S.reserves exist to provide secure supplies be-yond the end of the 20th century. Because of the inability of domestic petroleum develop-ment to keep pace with growing demands forliquid fuels, the United States has become in-creasingly dependent on imported oil. In1978, the United States imported nearly 24percent of its total energy supply and nearly45 percent of its requirement for crude oiland refined petroleum products. A barrel of imported petroleum now costs five to sixtimes as much as it did in 1972.

The short-term reliability of imported oilsupplies is very uncertain, as exemplified bydisruptions arising from the Suez crisis of 1956, the Arab-Israeli War of 1967, the Araboil embargos of 1973 and 1974, and the pres-ent Iranian situation. Long-term reliability isalso questionable because worldwide oil pro-duction is expected to peak within the nextfew decades and to decline rapidly there-after. Eventually, it may be impossible to im-port oil at any price.

Growing reliance on increasingly scarce

and expensive energy imports has had manyadverse effects. Some of the economic im-pacts (such as balance-of-payments deficits)can be quantified with some degree of preci-

sion. Other, less tangible effects (such asthreats to national security and the socialand economic impacts of supply disruptions),although more difficult to quantify may proveto be much more significant. It has becomeapparent that an energy supply system needsto be evolved that is more appropriate to the

Nation’s present and projected needs and in-ternal resources. Just as wood was displacedby coal, coal by domestic petroleum and gas,and domestic petroleum by imported oil, it ap-pears that imported energy must be replacedby new sources of domestic energy.

An initial step in developing a new energysupply system should involve formulating acomprehensive policy that reduces demandthrough conservation, increases availabilityfrom domestic resources, and restricts im-ports. Conservation must be an important ele-ment of any such policy. However, there arelimits to the savings that can be accomplishedthrough conservation. Thus, it appears that itwill be necessary to develop new energy re-sources. Potential sources include additionalreserves of conventional oil and gas, en-hanced oil recovery, expanded coal develop-ment, solar-thermal and photovoltaics, windenergy, tidal energy, ocean thermal gradi-ents, increased nuclear fission for power gen-eration, nuclear fusion, biomass combustion,and the recovery of synthetic liquid and gas-eous fuels by the conversion of coal, tar

sands, biomass, and oil shale. The challengeis to derive optimal combinations of thesesources which, when coupled with conserva-tion and restricted imports, will provide suffi-cient energy for future economic growth anddevelopment, while simultaneously protectingthe Nation’s physical and social environ-ments.

The Purpose and Organization

of This Chapter

As noted in the Introduction to this report,

this assessment is concerned with only one of the Nation’s energy supply opportunities, oilshale—specifically with deposits in the GreenRiver formation of Colorado, Utah, and Wyo-



Ch 4–Background q 8 7

ming. Although the oil shale literature is ex- q

tensive, the information is inadequate con-cerning certain environmental, socioeconom-ic, technological, and financial aspects of oilshale development. However, the assess-ment’s overall analysis has been facilitatedby the extensive body of background informa-

tion acquired during the Nation’s long butq

sporadic involvement with oil shale as anenergy resource. The purpose of this chapteris to organize this background informationinto a supporting framework for the detailedanalyses found in subsequent chapters. Thefollowing subjects are discussed:

q

q the location and extent of the oil shaleresources of the United States and for-eign nations;

the characteristics of the resource re-gion in Colorado, Utah, and Wyoming, in-cluding brief descriptions of the geogra-phy, the geology, the climate, and thephysical and social environments;

the potential applications for materialsderived from the Green River oil shales,including oil, fuel gases, minerals, andspent shale; and

the history and status of development ef-forts in the United States and othercountries, with emphasis on the effortscurrently underway in the Green Riverformation.

Oil Shale ResourcesThe Genesis of Oi l Shale

Oil shale is a sedimentary rock that con-tains organic matter, which although not ap-preciably soluble in conventional petroleumsolvents can be converted to soluble liquidsby heating. Oil shale was formed in the dis-tant past by the simultaneous deposition of mineral silt and organic debris on lakebedsand sea bottoms. As the raw materials accu-mulated, heat and pressure transformed

them into a stable mixture of inorganic miner-als and solidified organic sludge. The forma-tion processes that yielded petroleum, tarsands, and coal were conceptually similar,but differed with respect to key physical andchemical conditions. In oil shale, these condi-tions resulted in the formation of chemicalbonds between individual organic molecules.The large size of the molecules formed by thisbonding prevents them from dissolving in nor-mal solvents. When heated in processesknown as pyrolysis and destructive distilla-tion, the bonds rupture forming smaller liquid

or gaseous molecules. These can then be sep-arated from the inorganic matrix, which re-mains behind as the spent shale waste prod-uct .

Photo credlf Department of the /nfer/or

Oil shale sample showing layers of organic composition

Worldwide Deposits

Oil shale deposits have been found on all of

the inhabited continents. The extent of theworldwide resources cannot be accuratelydetermined, but it appears to be very large in-deed. In 1965, the U.S. Geological Survey



88 q An Assessment 01 01/ Shale Technologies

(USGS) estimated that the world’s oil shaledeposits comprised over 4 quadrillion tons,having a total potential shale oil yield of over2 quadrillion bbl. If all of this oil were ex-tracted and distributed among the world’sresidents, each person would receive about600,000 bbl. However, the spent shale waste

would cover the entire surface of the world,land areas and oceans included, to a depth of about 10 ft.

The deposits in Asia contain the largestamount of potential shale oil resources, over700 trillion bbl; Africa is second, with nearly500 trillion bbl; North America contains over300 trillion bbl; South America (principallyBrazil) about 250 trillion bbl; Europe hasabout 170 trillion bbl; and Australia and NewZealand together have only about 120 trillionbbl.

Many of the world’s deposits have beensubjected to commercial-scale developmentat various times in the past. Those in Scot-land, France, Germany, Australia, Sweden,Spain, and South Africa are of historical in-terest because of the industries that onceflourished in those countries. The deposits inEstonia, Manchuria, Brazil, and Morocco areof current interest because they are the sitesof present or projected commercial develop-ment.

Deposits in the United States

Overview

The oil shale deposits in the United Statesare shown in figure 12, and their theoreticalshale oil yields are given in table 13. The de-posits in the Green River formation in Colora-do, Utah, and Wyoming are particularly note-worthy because they contain the largest con-centration of potential shale oil in the world.Because deposits in the Central and EasternUnited States underlie a larger area, they ap-

pear more impressive on maps than do thoseof the Green River. However, they containless than half the oil shale in the Green Riverformation, and do not yield as much oil on aunit basis because of a lower proportion of

hydrogen to carbon in their organic compo-nent.

Some of the eastern shales have attractedinterest because of the natural gas resourceslocked within the shale formations. DOE ispresently supporting a research and develop-ment (R&D) program to evaluate the potentialof eastern shales for producing this fuel, withspecial attention given to stimulating gas pro-duction from the Devonian shales that occurin and around eastern Ohio and the westernpart of West Virginia. The Antrim shales insouthern Michigan are also being investi-gated as potential sources of synthetic pipe-line gas, which would be obtained by under-ground gasification methods. DOE is alsoinvestigating the Chattanooga oil shales inTennessee and Kentucky. In addition to theirorganic component these shales contain low-

grade uranium and thorium ores. But they donot appear to have much commercial poten-tial because the beds are thin and unfavor-ably located, and ore concentrations are verylow.

The Green River Formation

The Green River formation is a geologic en-tity underlying some 34,000 mi2 of terrain innorthwestern Colorado, southwestern Wyo-ming, and northeastern Utah. (See figure 13. )The formation has been divided into severaldistinct geologic basins. The Green River,Great Divide, and Washakie basins occur pri-marily in Wyoming. Together with the SandWash basin in northern Colorado, these ba-sins underlie about 14,000 mi2. About 35 mil-lion years ago they were occupied by a singlelarge and long-lasting freshwater lake.

The Uinta basin in northeastern Utah andnorthwestern Colorado and the Piceance ba-sin in Colorado underlie about 20,000 mi2 of terrain, and were once occupied by a secondfreshwater lake. Most of Colorado’s Piceancebasin lies north of the Colorado River, but it

includes oil shale deposits within BattlementMesa and Grand Mesa on the south side of the river. Colorado oil shale also occurs in theSand Wash basin, which is north of the Pice-ance basin near the Wyoming border.






Figure 13.—Oil Shale Deposits of the Green River Formation

IIDAHO 8

I

—..

+

q Salt Lake City

II

L

.!. - *. , - GREATDIVIDEBASIN

WYOMING

UTAH

SANDWASHBASIN

I

:R

-’”’”s !’ WP”:LEXPLANATION

Area underlain by the Green River Formation Area underiain by oil shale more thanin which the oil shale is unappraised or 10 feet thick, which yields 25 gallonslow grade. or more oil per ton of shale.

SOURCE D C Duncan and V E Swanson, Orgarrlc-R/ch Shales of the Urvfed States and Wodd Land Areas, U S Geological Survey Circular 523, 1965

that can be put to use. A reserve is the equiv- mercial development. However, if the cost of alent of money in the bank. All of the rocks in extracting fuels from the resource is greater

the Green River formation occur in deposits. than the value of the fuels obtained, the re-Some of the deposits are also resources be- source is not a reserve. Reserves exist onlycause they contain sufficient oil shale, which when the resource can be extracted andwhen properly manipulated can yield useful processed to yield products that can be mar-fuels to warrant being considered for com- keted at a profit.




The total oil shale deposits of the GreenRiver formation contain, in place, * the equiv-alent of over 8 trillion bbl of crude shale oil,including all rocks that would yield from 5 to100 gal/ton of oil on destructive distillation.However, many of these deposits are too thin,

too deeply buried, or too low in oil yield to beincluded in a survey of oil shale resources,because it would not be economically feasibleto develop them.

In table 14, the quality of the Green Rivershale is evaluated according to thickness andpotential oil yield. Only deposits that yield atleast 15 gal/ton and are at least 15 ft thick areconsidered even marginally attractive. Thisgroup includes shales containing as much as1.4 trillion bbl of shale oil in place. The high-grade shales are further defined as shalebeds that are at least 100 ft thick that would

yield at least 30 gal/ton. Their in-place oil con-tent is an additional 0.4 trillion bbl, for a totalshale oil resource of about 1.8 trillion bbl, inplace.

The extent of the oil shale reserves cannotbe determined at present. Resources can beregarded as reserves only when processes fordeveloping them appear to be economicallyfeasible. This has yet to be demonstrated foroil shale processes. However, several at-tempts have been made to delineate particu-lar Green River resources that would present

a greater potential for profitable extraction.In 1972, the National Petroleum Council(NPC) used published geological data to clas-sify the shale beds according to thickness and

“~he ter-rn “in place” is used to indicate the quantity of oilthat would be created if the shale were retorted. As noted, oilshale deposits contain essentially no oil as such.

richness, accessibility to underground min-ing, and the extent to which they had been ex-plored. A summary of the results appears intable 15. Data are presented for four classesof oil shale resources. Classes 1 and 2 wereconsidered economically attractive for ex-

isting aboveground recovery technologies.They include only the more favorably locatedand better defined shale beds, which are atleast 30 ft thick and would yield at least 30gal/ton. These two classes contain about 130billion bbl of shale oil, in place. The shales inclass 3 might also be economically attractive,but they are less well-defined, and their unfa-vorable locations could hinder commercialdevelopment. Class 3 shales contain about186 billion bbl. The bulk of the Green Riverresources are in class 4, which includeslower grade, poorly defined, and unfavorably

located deposits. Class 4 shales contain near-ly 1.5 trillion bbl. Some of the deposits inclasses 3 and 4 may be suitable only for insitu processing.

The total estimate shown in table 15 (about1.8 trillion bbl) agrees well with the totalshown in table 14. However, the higher quali-ty resources in the first three classes containonly 315 billion bbl, which is about 2 percentof the total estimated. The potential yield of these deposits can be estimated by taking intoconsideration the inevitable losses that would

occur during mining and processing. Conven-tional underground mining methods can re-cover from 60 to 70 percent of the oil shale ina mining zone; large-scale aboveground min-ing can recover about 90 percent. Processingthe mined ore in aboveground retorts recov-ers approximately 90 to 100 percent of the oilthat would be recovered if the shale were dis-

Table 14.–PotentiaI Shale Oil in Place in the Green River Formation: Colorado, Utah, and Wyoming(billions of barrels)

Nature of the deposit Colorado Utah Wyoming Total

At least 100 ft thick with oil yields averaging at least 30 gal/ton ., 355 50 13 418At least 15 ft thick with oil yields averaging at least 15 gal/ton,

e x c l u d i n g t h e d e p o s i t s s h o w n a b o v e 840 270 290 1,400

T o t a l s ( r o u n d e d ) 1,200 320 300 1,820

SOURCE W C Culberfson and J K Pllman 011 Shale In Um(ed Slates Mmera/ Resources U S Geological Survey Professional Paper 8?0 1973

pp 497503




Table 15.–Potential Shale Oil Resources of the Green River Formation (billi ons of barrels)

Resource classa

Location 1 2 3 4 Total

Piceance basin (Colorado), ., ., ... 34 83 167 916 1,200Uinta basin (Utah and Colorado) . . . . – 12 15 294 321Wyoming basins .,, . . . . .,, . . . . . . . . . . . . . – – 4 256 260

T o t a l s . , . , . , . , , , , . , , , . , , . , . . . , , , , , , 3 4 95 186 1,466 1,781

a 1 Deposits atleast 30 ftthlck andaveraglng 359al/ton

2 Dei)ost sat least 30 ftthlckandaveragmg 30gal/ton3 Deposits slmllar to classes 1 and 2 but less well defined arm not as Iavorabley located4 Poorly dehned depostts ranging down to 15 gal/lon

SOURCE An Inmal Appraisal by the 011 Shale Task Group t971-1985 U S Energy Oul/ook–An /rMerm Repofl, The Nahonal Petroleum Council,Washington D C 1972

tilled under carefully controlled laboratoryconditions. If it is assumed that about 60 per-cent of the oil in the shale deposits could berecovered, the resources in classes 1 through3 could yield 189 billion bbl of crude shale oil.

The projected yield of 189 billion bbl of shale oil is only a small fraction of the totalpotential yield estimated—1.8 trillion bbl. Itis very small compared with the total in-placeshale oil content of the Green River deposits(some 8 trillion bbl). To put the figure in ameaningful perspective, the United Statesconsumed about 6.5 billion bbl of crude petro-leum in 1978, of which about 2.8 billion bbl of crude oil and refined products were im-ported. At the 1978 consumption levels, thehigher quality Green River resources havethe potential to supply all of the Nation’scrude oil needs for 29 years or to replace im-

ports for nearly 68 years. Looked at anotherway, the resources in the first three classescould sustain a l-million-bbl/d shale oil in-dustry for over 500 years. The class 1 re-sources in Colorado’s Piceance basin alonecould supply it for nearly 56 years.

With existing data, a preliminary evalua-tion of the Green River resources can bemade with respect to their promise of com-mercial development, but the actual reservevalue is still highly uncertain. It is likely thatsome of the deposits could not be developedwithout unacceptably damaging the environ-

ment. It is also possible that some favorablylocated resources could not be developed be-cause of particular geotechnical characteris-tics (such as highly fractured ore zones or thepresence of excessive amounts of ground wa-ter) that were not considered in NPC’s anal-ysis. In any case, the economic aspects of de-

velopment are not well-understood becauselarge-scale technologies have not as yet beenbuilt and operated. As previously observed,the key criterion in estimating reserves is eco-nomic feasibility.

If all the above factors were given carefulconsideration, it is possible that actual re-serves would be very small. On the otherhand, it is also possible that an evaluation of the potential of known resources for in situprocessing along with additional explorationand research, could increase the reserve esti-

mate. There are deficiencies in the NPC esti-mate that largely reflect the current status of technical and geological knowledge. For ex-ample, over 75 percent of the Uinta basin de-posits were placed in class 4 because theyhave not been as thoroughly explored asthose of the Piceance basin. The analysis alsodowngraded deposits that are not well-suitedto mining and aboveground retorting butmight be ideal for underground processing. If the survey were revised in the light of presentknowledge, it is possible that the reserve esti-mate would be substantially increased.




Description of the Oi l Shale Resource Region

Location

The oil shale deposits of the Green Riverformation underlie about 17,000 mi2 of ter-

rain in northwestern Colorado, northeasternUtah, and southwestern Wyoming. * Majorsettlements in the area and major tributariesthat drain the region’s watershed into theColorado River system are shown in figure 14.

Topography and Geology

At the time of their deposition, the oil shalebasins probably resembled the fairly uniformtopography of continuous lakebeds. Tectonicupheavals have since elevated them, and sub-stantial erosion by wind and water have al-tered their terrain. Today, most of the oilshale region is very rugged country. The to-pography of both the Uinta and Piceance ba-sins is typified by rolling plateaus, cliffs, andcanyons. The elevation ranges from approxi-mately 4,300 ft above sea level along theGreen River in the Uinta basin to more than9,000 ft at a point near the southeastern edgeof the Piceance basin. This irregular topogra-phy strongly influences such characteristicsas climate, air motion and dispersion pat-terns, and the duration of the growing sea-son.

The various mountain systems surroundingthe area of the Green River formation areshown in figure 15, and the general topo-graphic relief of the Piceance basin north of the Colorado River in figure 16. This figuredoes not show Battlement Mesa and GrandMesa, which lie to the south of the ColoradoRiver. These are part of the Piceance struc-tural basin, but the characteristics of their oilshale resources are not well known.

The main part of the Piceance basin isbounded by the White River on the north, bythe Grand Hogback on the east, by the RoanCliffs on the south, and by Douglas Creek andthe Cathedral Bluffs on the west. Within thebasin are topographically high areas such as

*This area is slightly larger than Vermont and New Hamp-shire combined.

the Roan Plateau, which is relatively flat butseverely eroded by stream courses.

The southern escarpments (steep cliffs)

that overlook the valleys of the Colorado andGreen Rivers are the most spectacular fea-tures of both the Piceance and Uinta basins.At several locations these sheer cliffs rise toheights of 4,000 ft above the adjacent rivervalleys. They are nearly continuous for a dis-tance of some ZOO miles from the intersectionof the Roan Cliffs with the Grand Hogbacknear Rifle along the Cathedral Bluffs on thewestern side of the Piceance basin, to the in-tersection of the Book Cliffs with the WasatchPlateau at the western tip of the Uinta basin.

Escarpments along tributary canyons are

similarly impressive. The topography alongone stretch of Parachute Creek in the Pice-ance basin is depicted in figure 17. * At thelocation shown, the maximum elevation is ap-proximately 8,100 ft above sea level at theridge of the escarpment, and the minimumelevation is about 6,100 ft in the adjacent bedof Parachute Creek. The topography in othertributary canyons is similar. For example, theRoan Creek Valley (near the southern edge of the Piceance basin) is more than 30 miles longand from 2,000 to 3,000 ft deep. The Federaloil shale lease tracts are located in less

eroded areas of the basin, and their topo-graphic relief is much less dramatic. On tractC-a, for example, the average difference inelevation between valley floors and nearbyridge tops is only about 300 to 600 ft.

Figure 18 is an idealized cross section of the Piceance basin that shows the strati-graphic relationships between the variousstructural members of the Green River forma-tion, the overlying Uinta formation, and theunderlying Wasatch formation.** The bound-

*The Parachute Creek valley was the site of two oil shale de-

velopment projects in the 1950’s and 1960’s, and additionalprojects are currently being considered for the same locations.

**The Uinta formation was previously called the EvacuationCreek member of the Green River formation in this area. See:C. W. Keighin, “Resource Appraisal of Oil Shale in the GreenRiver Formation, Piceance Creek Basin, Colorado, ” Quarterlyof the Co~orado School of Mines, vol. 70, No. 3, July 1975, pp.57-68.



94 . An Assessment Of Oil Shale Technologies

Figure 14.—The Oil Shale Resource Region of the Green River Formation: Colorado, Utah, and Wyoming

*. Rawlins

k $prlngs \

W-a weuAm VvYolMING

‘r~~3~WASH

1 / Craig .Sttaamhmat .Snrinnc----- “ ----- -r’ ‘“ ‘Y-

(/. /

UTAH

.1L,

d

F ti”’ER’%KEANCE- rRO\UINTA BASIN

Cn l nRArm

v’:;:;:on\Fi\

)

I l-.

Oil shale more than 15-ft thick and yielding 25 gal of 011per ton of shale or more,

Unassayed or low yield

SOURCE. E DISante, “A Look at 011 Shale–What’s It All About, ” Sha/e Country Magazine, VOI 1, No 1, January 1975, p 7




Figure 15.—Major Mountain Systems in the Vicinity of the Green River Formation

113” 112 111” 110” 109”44” —

r -m= i ‘t%l” “‘-: i’o---

‘*=

r--- l==---+==, - 1 43”

m.

--4x%!!--:-+% - -—-- —-1

-..J

25 0 100 males

SOURCE U S Department of the Interior, F/rra/ Errv/ronrnenta/ SIaternent for the Protofype 0// Sha/e /-eas/rrg Program, GPO stock No 2400-00785, 1973. p 112

aries of these members, which are visiblealong Parachute Creek, were shown in figure17. The Green River formation is about 3,000ft thick near the center of the basin.

The top strata of the section comprise theUinta formation, which underlies the sur-faces of high plateaus in the Piceance basin.The Uinta is largely barren sandstone andsiltstone with some interbedded oil shale.

Below the Uinta, at a depth of 500 to 1,000 ft,is the Parachute Creek member of the GreenRiver formation, which is almost entirely oilshale marlstone with occasional beds of vol-canic material (tuff) and sandstone. Near thebasin’s depositional center, the ParachuteCreek member contains scattered deposits of the minerals dawsonite, nahcolite, and halite.Dawsonite, which contains aluminum, is oc-casionally found in thin layers between the oil




Figure 16.—Topographic Relief of the Piceance Basin, Colo.

SOURCE Goider Associates, Inc., Water Management m O// Sha/e Mmmg, September 1977, NTIS No PB.276086, p 73

shale beds. More commonly it occurs as mi-croscopic crystals disseminated throughoutthe oil shale. Nahcolite is sodium bicarbon-ate. It is a source of soda ash, a raw materialfor glassmaking, and may also be used toremove sulfur dioxide from stack gases.Halite is sodium chloride, from which tablesalt is made. The Parachute Creek memberalso includes the Mahogany Zone, which con-tains oil shale yielding up to 70 gal/ton. Belowthe Mahogany Zone, near the center of thebasin, is a region from which soluble sodiumsalts have been leached out by the groundwater flows and which now contains saline

ground water. Near the bottom of the Para-chute Creek member is the “saline zone, ”which contains high concentrations of nahco-lite and other sodium salts that have not beenleached.

The lower extremities of the Garden Gulchand Douglas Creek members, which underliethe Parachute Creek member, roughly coin-cide with the bottom of the ancient lake onwhich the raw materials for the Green Riveroil shales accumulated. The upper 200 to 300ft of the Garden Gulch member contain claybeds and deposits of shale having an appre-ciable organic content. ’ The Garden Gulchshales are true shales in that their primaryinorganic components are aluminum-contain-ing illite clays, unlike the oil shales of Para-chute Creek, which are primarily composedof dolomite (calcium and magnesium carbon-

ate) rocks. Below the Douglas Creek memberis the Wasatch formation, which is largelybarren sandstone and mudstone. The Wa-satch rocks generally form valley floorsthroughout much of the Piceance basin. They






Figure 18.— Idealized Cross Section of the Piceance Basin, Colo.

SOUTH NORTHRoan Plateau

Ledge

SOURCE Bureau of Land Management, Dralt EnVlr0nIr7ental Stater77ent tor Proposed Development O( 0// Sha/e Resources by the Colony Deve/oprrrentOpera//on m Colorado, U S. Department of the Interior, 1975, p 111.13

do not contain any oil shale of commercial in-terest.

Variations in the properties of the variousstrata have had significant effects on the top-ographic relief of the region. The Uinta for-mation sandstones cover the oil shale depos-

its over much of the Piceance basin. Over thepast several million years, outcrops of theUinta rocks have weathered considerably.The organic-rich oil shale zones of the under-lying Parachute Creek member, however,have been much more resistant to weather-ing. The Mahogany Zone of the ParachuteCreek member is an outstanding example. Itis from 10 to 225 ft thick, contains oil shalethat has, in general, a high organic content,and underlies an area of more than 1,200 mi2

in the Piceance basin. It also extends into theneighboring Uinta basin. * Oil shale beds im-

*Green River oi l shale has a Iaminar appearance because of variations in the organic content of adjacent strata. Polishedsections of the richer beds resemble mahogany wood. Most oilshale projects in the near term will be focused on the richshales of the Mahogany Zone. The other potential source ofrich oil shale, the Garden Gulch member, is probably too deepfor near-term commercial development.

mediately above and below the MahoganyZone are lower in organic content and lessresistant to weathering. Where the zone out-crops along tributary canyons, its richershales have resisted erosion, but the leanersurrounding shales have not. Consequently,

the outcropping fringe of the zone is oftenhighly visible as an overhanging prominenceknown as the Mahogany Ledge, which ap-pears in most areas as a dark band along theescarpment, as shown near the top of figure17.

Gradual deterioration of the ledge has re-sulted in rockfalls and the formation of talus(debris) slopes between the bottom of theledge and the river valley below. Such slopeswere indicated in figure 17 as slip and rock-fall terrain. They are steep and unstable, par-ticularly if naturally or artificially undercut.

Because talus slopes are naturally unstableand lack sufficient permanent topsoil, they donot provide favorable growing conditions formost types of vegetation. However, varyingamounts and kinds of vegetation can grow onsome slopes depending on their aspect and



Ch 4–Background 99

the available moisture. The north-facingslopes generally have fairly abundant vegeta-tion; the south-facing slopes much less.

Climate and Meteorology

Climate

The climate of the oil shale region is clas-sified on the whole as semiarid to arid. An-nual precipitation varies from approximately7 inches in the Wyoming plains to approxi-mately 24 inches in the high plateaus of thePiceance basin. Most of this occurs as snow-fall, Snowpack, which commonly exceeds 30inches on protected slopes, provides surfacerunoff during the spring. Summer and fall areusually dry, but there are short, heavy thun-derstorms occasionally during the late sum-

mer months. These can cause flash floodingin low-lying areas, Relative humidity is gener-ally low to moderate, with high evaporationrates throughout the region. Because of theregion’s abundant sunshine, most valleyfloors and south-facing slopes are usually notcovered with snow during winter,

Average temperatures are generally mod-erate, but maximum daytime temperaturescan reach 100° F (38° C) at lower elevationsduring midsummer, and winter temperaturesmay drop to – 40

0 F ( –400 C) at higher eleva-

tions. The number of frost-free days variesfrom 50 at higher elevations to 125 at lowerelevations. The limited rainfall and low rela-tive humidity coupled with the short growingseason restrict the agricultural use of tillableareas. Some forage crops are produced alongthe tributary valleys within the basins, butmost food crops are grown outside of the ba-sin along major rivers where adequate irriga-tion water is available.

Meteorology

The meteorology of the oil shale region inColorado is typified by year-round gradientwinds from the west that are interrupted onlyby the passage of frontal systems. Migratory

low-pressure systems are frequently de-flected around the entire region by the SierraNevadas to the west and the Rocky Moun-tains to the east, Stagnant high-pressure cellssometimes persist for days over the basins,their passage blocked by the surrounding

high mountains. Adjacent mountain rangesalso contribute to the region’s dry climate.Moist air from the Gulf of Mexico is blockedby the Rocky Mountains, while moist air fromthe Pacific is blocked by the Sierra Nevadas.Flows from both directions lose most of theirmoisture before reaching the oil shale area.The frequent presence of dry, high-pressureair cells over the basins causes an abundanceof clear sunny days with light winds andlarge differences between daytime and night-time temperatures.

Air PatternsLocalized wind patterns and other meteor-

ological conditions are very sensitive to topog-raphy and elevation. For example, in the Pice-ance basin, shielding by the Cathedral Bluffs,the gentle downward slope of the basin to thenortheast quadrant and the existence of deepgullies, effectively channel surface windflows and decouple them from the prevailinggradient winds. The shielding effect is pro-vided by the sheer escarpment of the Cathe-dral Bluffs and Roan Cliffs along the southern

and western edges of the basin. When pre-vailing winds encounter the bluffs they mustrise approximately 3,000 ft to clear the upperridges. The rising air increases in speed andgenerates turbulent eddies whose duration isenhanced by the downward slope of the ba-sin’s upper surface. The shielding of the es-carpments combined with the basin’s down-slope minimizes the effect of gradient windson surface wind patterns except along veryhigh ridges and plateaus. Airflows in the Col-orado River valley, in tributary canyons, andalong the valleys and low hills atop the Roan

Plateau are almost entirely determined by lo-cal topography. They follow a drainage-windpattern and are nearly independent of the be-havior of prevailing gradient winds aloft.




The Mountain-Valley Breeze System

The predominance of drainage-wind pat-terns is exemplified by the mountain-valleybreeze system that has been observed on bothFederal oil shale lease tracts in Colorado. Thephenomenon is characterized by gentle down-valley air flows beginning around sunset andprevailing for about 10 hours in winter, fol-lowed by gentle up-valley flows starting atmidmorning. On clear nights, when the upperatmosphere is stable, layers of dense, cold airform near ground level. Any cold air thatenters the valley along adjacent slopes willtend to flow downslope into the stagnant coldlayer. In the early morning, sunlight gradual-ly warms the surrounding slopes. The cold airthen disperses and flows upslope to becomeentrained in the prevailing gradient winds. Atvarious times during the day and night, cir-cular flow patterns and eddies may prevailwithin the valley, but they will not carry airfrom the valley unless gradient windsthe upper ridges are quite strong.’

Thermal Inversions and Their Implications

The mountain-valley breeze system

along

oftencauses a layer of cold stagnant air to formbelow a layer of warm air—a thermal inver-sion. Such inversions exacerbate air pollutionproblems. There is little air transport out of

the cold layer, and pollutants emitted nearground level will tend to accumulate there. In-versions are usually broken by surface heat-ing during the daylight hours, but under cer-tain adverse conditions they may prevail forseveral days. Valleys with broad floors areespecially susceptible, particularly after asnowfall. Snow cover reflects sunlight and in-hibits the warming of the stagnant layer dur-ing the day, thus reducing the upward flow of warm air that is essential to disruption of theinversion. At night, the exposed snow surfaceenhances the downward flow of air from the

valley ridges, thus increasing the thickness of the inversion layer.

Studies have shown that Grand Junction,Colo., which is located outside of the oil shalebasins, experiences one of the highest inver-

sion frequencies in the United States. The in-versions occur most frequently during thewinter and persist over 50 percent of the timein the fall and winter months. Inversionsmight be expected to occur less frequently onthe slopes and plateaus of the Piceance basin.However, it has been predicted that inversionepisodes lasting from 3 to 6 days could occurat least once a year over the entire region.3

Recent investigations performed on the Fed-eral lease tracts have concluded that the pol-lutant dispersion potential of the basin isgood when contaminated air is releasedabove the higher plateaus, and relativelypoor when fumes are released into the val-leys. The same studies have predicted thattrapping inversions, * such as are associatedwith the mountain-valley breeze system,should seldom persist longer than 24 hours.

Plants and Animals

The Green River formation underlies alarge area. Its soil characteristics show con-siderable variation over this area. In com-bination with climate, meteorology, and to-pography, soil characteristics largely deter-mine the types of plant communities that canbe supported. These, in turn, influence thediverse animal species that feed directly orindirectly on them.

PlantsThe vegetation of the region is highly di-

verse, and its makeup is strongly affected byelevation. Most of the broader stream valleysin the region contain fertile alluvial (flood-plain) soils that support relatively luxuriantgrowths of cottonwood, shrubs, and otherspecies. In contrast, the surfaces of steepslopes and some upper plateaus are barerocks and ledges with little or no soil develop-ment. Vegetation is often absent or at bestquite sparse in such areas, especially in some

plateaus in Utah and Wyoming and in the Pi-ceance basin where the saline rocks of the

*A trapping inversion is one that traps contaminated air re-gardless of the temperature at which the contaminants are re-leased from their source.




Garden Gulch member are exposed, Somegently sloping upland areas contain thin andpoorly developed soils with occasional local-ized strips of alluvium. Plant cover in these lo-cations varies from very sparse in the poorerareas to relatively abundant over the alluvial

deposits. In general, the extent of vegetationis strongly influenced by aspect. South-facingslopes have much less vegetation becausetheir greater exposure to sunlight acceler-ates the evaporation of critical moisture.

In the high plains of southwestern Wyo-ming, soils are usually thin and dry, and vege-tation is predominantly saltbrush-grease-wood and related shrubs. There are limitedareas of Douglas fir forests and mountain ma-hogany woodlands in the northern fringes of the Green River and Washakie basins. Soilsare somewhat thicker in the Uinta basin, but

the arid climate inhibits plant growth exceptalong the valleys of the major rivers, Salt-brush-greasewood and other shrubs domi-nate, but there are occasional stands of mountain mahogany, oak shrub, pine, and fir.

In the Piceance basin, shrublands andwoodlands also dominate, and forestlandsare sparse. Shrubland plants consist primari-ly of mixed shrubs on moist soils at higherelevations and sagebrush, which dominatesin all dry soils. Woodlands occur in thinnersoils at lower elevations, and are dominated

by pinyon pine and juniper, except wheregrazing and other disruptions have allowedintrusions of brushes and grasses. Forestsare primarily cottonwood along streams atlower elevations, and Douglas fir and aspenon northern and eastern slopes at higherelevations,

Overall, plant life in the Green River for-mation area is less abundant than in otherregions that have ample rainfall and lessrugged terrain. However, the area containsdiverse plant communities that are welladapted to their environment. Some of thecommunities in the Piceance basin were stud-ied by the developers of Federal lease tractsC-a and C-b as part of the baseline-monitoringfunction required for the preparation of de-tailed development plans. The baseline stud-

ies included a census of existing plant speciesand a determination of the structural charac-teristics and successional status of plant com-munities. The results of these studies providean indication of the diversity of plant life inthe vicinity of proposed oil shale development

sites.The plants identified on tract C-a included

5 types of trees, 36 shrub species, and 168herbaceous species, of which 44 were classi-fied as grass or grass-like. One of the plants,dragon milkvetch, is on the Smithsonian In-stitution’s list of endangered plant species.However, the species is not consideredthreatened in Colorado.’ On tract C-b, 37types of trees, shrubs, and vines were identi-fied, together with 137 species of herbs.Vegetation community types included pinyon- juniper woodlands and rangelands, uplandand valley sagebrush, Douglas fir forests andaspen woodlands, mixed mountain shrub-lands, marshes, riparian areas, agriculturalfields, mountain grasslands and communitiesdominated by bunchgrass, Great Basin wildrye, rabbitbush, greasewood, and annualwild plants. No threatened or endangeredplant species were found on tract C-b or ontracts U-a and U-b, s Colony Development{ hasreported the presence of two endangeredplant species (yellow columbine and milk-vetch) and one threatened plant species (sulli-vantia) along the valley of Parachute Creek.6

Animals

Many types of mammals, cold-blooded ver-tebrates, birds, invertebrates, and aquaticsystems exist throughout the oil shale re-gions. The diversity of vertebrates is amongthe highest in the United States, a result of the highly diversified habitats of woodland,grassy shrubland, and high desert that char-acterize the area. In Colorado’s Piceancebasin, for example, more than 300 species of birds, reptiles, mammals, and amphibians

have been found or are believed to exist. Simi-lar numbers of animal species have been re-ported in other geologic basins of the GreenRiver formation. ’ Because of the relativelylow rainfall, wildlife of the region are highly




dependent on the stream systems and theriparian habitats of their environs.

COLORADO’S PICEANCE BASIN

The Piceance basin is Colorado’s most im-portant mule deer range. It is the principalwintering ground for the White River herd,the largest nonmigratory deer herd in NorthAmerica. Its size has been estimated at ap-proximately 100,000 head.8 The northeastcorner of the basin normally supports thehighest deer concentrations in winter, andthe entire basin is considered to be a deerrange in the summer. Antelope are also foundthere, but are primarily restricted to thenorthern edge. Limited numbers of elk live inthe general area of the basin and especiallyon the upper plateaus. A few mountain lionsroam over it, largely in pursuit of migratingdeer herds and sheep flocks, and a few blackbear are found at higher elevations in thesouthern part. Coyotes and bobcats are re-garded as abundant, but there has been nodetailed census of these predators. Theremay be as many as 150 to 200 cottontail rab-bits per square mile, and both snowshoehares and pine squirrels are found in theDouglas fir forests of the high plateaus. Othermammals present include yellow-bellied mar-mots, prairie dogs, ground squirrels, porcu-pines, chipmunks, red foxes, raccoons, badg-ers, and skunks, and from 150 to 250 wildhorses range throughout the entire area. Theavian species found in this basin include sagegrouse, partridge (stocked), pheasants, mal-

Phofo credit OTA staff

lards and other ducks, mourning doves, pi-geons, golden and bald eagles, and manyother species of migratory waterfowl, shore-birds, songbirds, hawks, eagles, and vultures.Fish species include trout, suckers, and min-news.g

UTAH’S UINTA BASIN

Utah’s Uinta basin is more primitive andisolated than the Piceance basin. It has beendescribed as an ideal natural faunal habi-tat. ’() Parts of the basin are utilized by muledeer herds as winter feeding areas, and smallnumbers of elk are also present in restrictedareas. Transplanted antelope have becomeestablished and appear to be flourishing.Bears have been reported in the area but areconsidered scarce. Mountain lions also rangeover the basin, but their numbers are un-known. Other mammal species include coy-otes, porcupine, bobcat, muskrat, beaver,mink, rabbits and hares, and others. The Bu-reau of Land Management (BLM) has esti-mated that about 130 head of wild horse in-habit Utah’s oil shale lands. Most bird speciesfound in the Piceance basin are also found inthe Uinta basin. Fish live in the clear head-waiters of various tributaries but are lessabundant in the heavily silted lower reachesof most rivers and streams. 11

WYOMING’S BASINS

Over 300 animal species have been identi-fied in Wyoming’s Green River and Washakiebasins. Of the larger mammals, elk and mooseare believed to inhabit the parts of Wyomingthat encompass the oil shale regions. Rela-tively few elk and moose live in the oil shalebasins per se, but black bear and lions havebeen observed. The basins also contain im-portant antelope ranges and habitats. Sizablenumbers of wild horses live in the Washakiebasin and winter in the highlands where pre-vailing winds sweep the heavy snowfalls fromgrazing areas. Several species of grouse,

ptarmigan, partridge, wild turkey, pheasant,ducks, and geese have also been observed inthe general vicinity of the oil shale lands.Tributaries support several trout varieties in-cluding the Colorado River cutthroat, and




some of the better trout habitats are locatedwithin the oil shale area. 12

ENDANGERED SPECIES

In compiling an inventory of animal spe-cies, the tract C-a lessees recorded sightingsof both peregrine falcons, listed as an endan-gered species by the U.S. Department of theInterior (DOI), and prairie falcons, a fully pro-tected species, The number of peregrine fal-cons was estimated at from one to four. Nofalcon nesting sites were found in the 170 mi2

survey area. It is unlikely that falcons wouldnest within the tract boundaries because of the absence of large cliff faces (their pre-ferred nesting location) and the scarcity of water. Approximately 30 greater sandhillcranes, endangered species in Colorado,were observed in the study area, but no nest-

ing sites were discovered within a 20-mileradius of the tract. The tract and its environsmay serve as staging and foraging areas forthe birds during their annual migrations, butthe area does not contain any importantcrane habitats. 13

The environmental reconnaissance ontract C-b did not reveal any rare, endan-gered, threatened, or protected animal spe-cies. However, a prairie falcon was sightedoutside of the tract boundaries.14 Environ-mental surveys for Colony Development re-vealed no endangered or threatened species

within the tract boundaries.15 BLM’s environ-mental statement for the Colony program listsseveral species of concern that might be pres-ent in the general area. These include thesouthern bald eagle, the prairie and pere-grine falcons, the humpback chub, the Colo-rado squawfish, the Colorado cutthroat trout,the bonytail sucker, the black-footed ferret,and the ferruginous hawk. 16

Air and Water Quali ty and Economic Base

Regional air and water quality, and theirpotential alterations because of oil shale de-velopment, are discussed in chapter 8. Theregion’s economic base, and the impacts itmight experience during the development of

an oil shale industry, are discussed inchapter 10.

Air Quality

In general, air quality is excellent through-out most of the region because of the region’srural character and lack of industrializationand urban development. Ambient concentra-tions of sulfur dioxide, nitrogen oxides, hy-drogen sulfide, and carbon monoxide arevery low compared with more densely popu-lated areas in the three oil shale States. Inboth the Piceance and Uinta basins, however,there are occasionally high ambient concen-trations of nonmethane hydrocarbons, partic-ulate, and ozone, The hydrocarbons are ap-parently emitted in aerosol form by sage-brush and other vegetation, because their

concentrations vary with the growing sea-sons for these plants. Windstorms and pass-ing automobile traffic on unpaved roads bothcontribute to high particulate concentrations.Haze is occasionally observed in the valley of the Colorado River and in the canyons of itstributaries. It has not been determinedwhether this haze is caused by photochemicalsmog or by a combination of suspended par-ticulate and local humidity. In general, thearea is free from man-induced odors. 17

Air quality problems may be encounteredin the future because of the region’s peculiarmeteorological conditions. As discussed pre-viously, the predominance of the mountain-valley breeze system coupled with high alti-tudes and the effects of surrounding moun-tain ranges on gradient winds aloft, leads tofrequent thermal inversions, especially dur-ing winter. To date, such inversions havebeen offensive only near the larger popula-tion centers outside of the oil shale basins,such as Grand Junction. However, inversion-related air pollution is likely to become moresevere as the region develops, regardless of whether such growth is associated with thecreation of an oil shale industry or expan-sions in other activities. The potential for in-versions may preclude siting processingplants in canyons and other low-lying areas,



.


thus, limiting them to higher areas such asthe Roan Plateau of the Piceance basin.

Water Quality

Water quality in the region is highly vari-able. It is good to excellent in most of the

upstream reaches of major tributaries suchas the Colorado River, but significantlypoorer in the downstream reaches. The grad-ual deterioration is caused by dischargesfrom numerous point and nonpoint sources.About half of the increase in salinity is re-lated to the discharge of naturally salinestreams into the river system. The rest is gen-erally related to the concentration of humanactivities, such as urban areas, mineral de-velopment sites, and irrigated farmlands.

A twentyfold increase in salinity has been

noted in the Colorado River between its head-waiters and Imperial Dam in Arizona. 18 Salini-ty is of special concern because the ColoradoRiver system is important to the entire South-west. Irrigated agriculture causes most of thehuman-related salinity effects through saltloading (picking up soluble salts from fieldsoils) and salt concentration (the evaporationand transpiration of relatively pure water inirrigation canals and fields).

Photo credit OTA staff

White River near Meeker, Colo.

Surface streams within the oil shale basinsalso show wide variations in water quality. InPiceance Creek, for example, the concentra-tion of dissolved solids range from less than400 mg/1 in the upper reaches to over 5,000

mg/1 at the discharge point into the WhiteRiver. f ’ Dissolved solids in Yellow Creek inthe Piceance basin range from about 700 to3,000 mg/1. Water quality deteriorates in thedownstream direction because of natural sur-face runoff, agricultural return flows, andthe discharge of saline ground water from

aquifers in the Green River and Uinta forma-tions. As described in chapters 8 and 9,ground water quality in the aquifers of the Pi-ceance basin varies enormously, from a lowof less than 250 mg/1 in the purer waters of the upper aquifer above the Mahogany Zoneto over 63,000 mg/1 in the highly saline brinesof the lower aquifer in the northern portionsof the basin. In general, the ground waterfrom all the aquifers in the Piceance basindoes not satisfy the drinking-water standardsof the U.S. Public Health Service. There areparticular problems with respect to dissolvedsolids, fluoride, and barium concentrations. 20

The quality of surface streams and groundwater in the Uinta basin shows similar ex-treme variability. The concentration of totaldissolved solids in the Uinta basin groundwater aquifers range from 350 mg/1 (which isconsidered potable water) to 72,000 mg/1(which is considered brine). In the Wyomingoil shale basins, surface streams have dis-solved solids concentrations from 150 to 855mg/1, while concentrations in ground waterrange from about 450 to 7,000 mg/l.

21

Population

The population density over the entire oilshale resource region is low, averaging about3 persons per square mile. The densities inmany areas are even lower. For example,when the oil shale resources of a 2,500 mi2

area of the Uinta basin were mapped in 1967,250 people lived in the entire area, with 200of them living in the town of Bonanza. Theaverage population density of the area wastherefore about 0.1 persons per square mile. 22

The population of the entire Green Riverformation region is approximately 120,000.About 62 percent live in Colorado, 17 percentin Utah, and 21 percent in Wyoming. The ma-

jor communities are Grand Junction, Rifle,




Meeker, Craig, and Rangely in Colorado; Ver- region’s present economy is based on agricul-nal in Utah; and Green River and Rock ture (crop raising and sheep and cattle ranch-Springs in Wyoming, Grand Junction, the ing), minerals production (oil, gas, uranium,largest Colorado town, has a population of trona, and coal), and tourism and recrea-approximately 24,000, Vernal ‘has about t i o n , 2 3 2 4 2 5

6,200, and Rock Springs about 28,000, The

Oil Shale Products and Their Potential

The Nature of Oil Shale

Green River oil shale is not a shale nor doesit contain appreciable amounts of liquid oil.The shale portion is actually a marlstone, andits principal constituents are dolomite, cal-cite, and quartz. In contrast, true shales arecomposed largely of silicate clays. They havea finely stratified or laminated structure and

tend to fracture along individual beddingplanes. Oil shale also has a stratified appear-ance and tends to fracture in a similar mat-ter, particularly when organic matter is pres-ent in low concentrations. These propertiesled early investigators to believe that theGreen River oil shales were true shales. How-ever, the appearance and fracture propertiesof Green River shale arise from variations inthe concentrations of organic matter it con-tains, and not to any great extent from thecharacteristics of the inorganic component,

Most of the organic component is a solidmaterial called kerogen, from the Greekwords for waxmaking, that is insoluble inmost standard petroleum solvents. About 10percent of the organic component is a solidsubstance called bitumen that can be dis-solved in certain solvents.

Kerogen is composed of carbon and hydro-gen molecules cross-linked together by sulfurand oxygen atoms to form relatively largethree-dimensional macromolecules with mo-lecular weights of about 3,000. These macro-molecules are embedded within the finergrained inorganic or mineral matrix of the oilshale rock. This organic continuous phasegives kerogen-rich oil shale most of its physi-cal strength and stability. When the organicmatrix is removed from very rich oil shale,

the mineralstrength andpowder,

Applications

residue has little cohesiveis easily crushed to a fine

Kerogen Pyrolysis

When kerogen is heated above 400” F(200

0 C), chemical bonds between and withinthe individual organic molecules are rup-tured, forming smaller molecules. Most of these can be readily isolated from the mineralmaterial as liquid and gaseous products.Some of the organic coproducts of kerogendecomposition remain trapped within the in-organic material as a coke-like residue.

A chemical change produced by heat iscalled pyrolysis, This process can also becalled destructive distillation, when an or-ganic substance is broken down by heat andthe products are distilled off, leaving a resi-due. When pyrolysis is carried out in a vessel

called a retort, the process is called retorting.Oil shale retorts may vary in size from labora-tory-size Fischer assay* units used to esti-mate the potential oil yield of oil shale rocks,to commercial-sized vessels that can process10,000 tons of raw oil shale per day, to in situretorts containing several hundred thousandtons of rock.

When kerogen is pyrolyzed, three combus-tible products are formed: vaporized oil,which can be condensed by cooling; a gaseousmixture containing hydrogen, oxides of car-bon, hydrogen sulfide, and hydrocarbon

*In a Fischer assay, small samples of crushed oil shale areheated to 9320 F (500° C] under carefully controlled conditions.The oil yield by this method is the standard measure of oil shalequality.

63-398 “) - 80 - 6




gases such as methane; and a coke-like solidresidue that remains behind in the retort.

The relative proportions of oil, gases, andcoke largely depend on the pyrolysis tempera-ture and atmospheric conditions in the retort,and to a lesser extent on the organic content

of the raw shale. The product yields from atypical Green River oil shale pyrolyzed at932° F (500° C) according to the standardFischer assay technique are summarized intable 16. As indicated, the raw shale con-

Table 16.–Composition and Pyrolysis Productsof Typical Colorado Oil Shalea

Mineral constituents

Mineral Weight percent of minerals

D o l o m i t e 32Calc i te 16Quartz ~ 15I l l i t e , . 19

L o w - a l b i t e 10A d u l a r i a 6Pyrite ., . 1

Acalcime ~ 1

T o t a l . 100

Ultimate analysis of organic constituent

Element Weight percent of organics

C a r b o n 7 6 5H y d r o g e n 103N i t r o g e n 2 5S u l f u r 1.2O x y g e n 9.5

T o t a l 1000

Yields from Fischer assay Pyrolysis

Weight percent oforganic constituent Weight percent ofDecomposition product in raw shale total raw shale

Oil 63 10,4N o n c o n d e n s a b l e g a s 15 2.5Fixed-carbon residue 13 2.2W a t e r v a p o r 9 1.4

T o t a l . . . . , 100 16,5

aPy@yzed by the slafldard Fischer assay procedure at 932°F 011 y(eld = ?6 7 gal/ton

SOURCE T A Sladek Recent Trends [n 011 Shale–Pad 1 Htstory Nature and ReservesMmera/ /nduslrfes f3u/e/in VOI 17 No 6 November 1974 pp 4.5

tained about 17 percent organic matter byweight and yielded about 27 gal/ton. Oil wasthe largest decomposition product. It com-prised 63 percent of the organic matteroriginally present in the shale, Noncondensi-ble gases comprised 15 percent, and the car-bon residue about 13 percent. The balance of hydrogen and oxygen content of the organic

matter was transformed to water vapor bythe pyrolysis process.

Each of the three main products of kerogendecomposition is a potential source of energy.Crude shale oil can be burned directly as afuel or it can be refined to produce fuels simi-

lar to those obtained from conventional petro-leum crude oils. As discussed in chapter 6,the physical and chemical properties of crudeshale oil differ from those of conventionalcrude, thus presenting some refining chal-lenges. However, shale oil can yield high-quality finished fuels such as gasoline and jetfuel.

The composition and properties of the off-gas from kerogen pyrolysis vary tremendous-ly with the nature of the pyrolysis process.Gas from the Fischer retort typically has aheating value comparable to that of naturalgas. Such high-quality gas could be used asplant fuel in the oil shale facility, or it couldbe pipelined to other areas for commercial orindustrial applications. In contrast, gasesfrom commercial directly heated retorts arehighly diluted with carbon dioxide (from com-bustion and from the decomposition of car-bonate minerals) and nitrogen. They haveonly about one-tenth the heating value of natural gas. Such gases could be usefulwithin the oil shale facility but they could notbe transported economically over any signifi-

cant distance, nor could they be upgraded tohigher heating values at reasonable cost. Sur-plus retort gases could become valuable by-products if they were burned for power gen-eration. Some developers plan to do this.

The coke residue is also a potential sourceof energy, but it is a very poor solid fuel com-pared with coal or with the raw shale itself.(A typical shale coke from the Fischer retorthas a heating value of about 250 Btu/lb; mostquality coals have heating values of about12,000 Btu/lb.) Transportation of the cokeresidue for offsite combustion would not bepractical because of its high content of inertmineral matter. Any energy values will haveto be recovered within the oil shale facilityeither by burning the residue in the retorts orby converting its carbonaceous component to






The History of Oil Shale Development

Useful hydrocarbons have been extractedfrom oil shale for many years. In the 14th cen-tury, Austrian and Swiss oil shales were py-rolyzed to yield “petro oleum, ” or “rock oil. ”

This was subsequently processed to yield anointment called Icthyol, a name derived fromthe Greek words for fish-oil, in reference tothe fossilized fish remains frequently encoun-tered in the marine oil shales of central Eur-ope.29 In 1694, England issued patent No. 33for a retorting process that was claimed toproduce “oyle from a kinde of stone. ”30

In 1859, the first commercial oil well wasdrilled in Pennsylvania. Prior to that year, atleast 50 commercial plants existed along theAtlantic seaboard of the United States for ex-tracting fuel oil from oil shales.]’ Also in 1859,

the first commercial oil shale retort beganoperating in Scotland. It started an industrythat lasted for over 100 years.

In 1874, workers on the transcontinentalrail line found that rocks picked up from ex-cavations along the Green River in Wyomingignited when used to protect campfires fromthe night winds. The March 1874 issue of Sci-entific American noted that the railroad su-perintendent :32

. . . has caused analyses and experiments tobe made with this substance which proves tobe a shale rock rich in mineral oils. The oilcan be produced in abundant quantities, say35 gallons to the ton of rock. The oil thus ob-tained is of excellent quality.

The rocks of interest were pieces of oil shalefrom the Green River formation.

The use of oil shale as a fuel resource thuspredates the large-scale use of conventionalpetroleum by several centuries. In the past150 years, commercial industries have ex-isted in Scotland, France, Germany, Spain,South Africa, Australia, and the United

States. At present, industries exist or arebeing started in Estonia, the People’s Repub-lic of China, Brazil, and perhaps the UnitedStates. The following section describes thehistory of foreign and U.S. development ef-

forts and defines the status of present indus-tries around the world.

Scotland

Scottish oil shales occur in seams from 4 to14 ft thick yielding approximately 22 gal/ton.Reserves were originally estimated to containabout 600 million bbl. The first retortingplant was built in 1859. Its economic viabilitywas immediately threatened by the rapid de-velopment of conventional petroleum thatfollowed the drilling of the first commercialoil well. The production of shale oil and val-uable byproducts such as waxes, ammonia,pyridines, * ammonium sulfate, and buildingmaterials enabled the Scottish industry to

survive for over 100 years despite the highcost of the oil in comparison with conven-tional crude oil. At its peak, the industry in-volved about 140 different companies andprocessed about 3.3 million ton/yr of oil shale.In 1919, the companies were consolidatedinto a single corporation that subsequentlybecame a subsidiary of the predecessor of British Petroleum. The industry was subsi-dized by the British Government with taxcredits and other incentives, but competitionfrom cheap petroleum forced the last plant toclose in 1962.

Sweden

Typical Swedish oil shales are about 50 ftthick and yield from 6 to 15 gal/ton. The totalresource is estimated to be about 2.5 billionbbl of shale oil in place. The Swedish oil shaleindustry began in the 1920’s, with the largestoperations near the city of Kvarntorp. Thesefacilities featured two types of abovegroundretorts and a unique type of in situ process inwhich the deposits were pyrolyzed with elec-tric heaters. The industry reached a maxi-mum capacity of 2 million tons of oil shale peryear (6,000 ton/d) and produced as much as

*Nitrogen-containing organic solvents also used to syn-thesize other useful products.




550,000 bbl/yr of crude shale oil. Because of the limited quantity of high-quality reserves,and price competition from petroleum crude,the industry ceased operation in 1966.

France

French resources total about 500 millionbbl of shale oil in place. They are of mediumquality and yield from 10 to 24 gal/ton. Theyare more properly called bituminous shales,rather than oil shales, because they containinclusions of asphaltic compounds. TheFrench industry began in 1840 and continuedintermittently until 1957. Its maximumthroughput was 0,5 million ton/yr of shale, at-tained in 1950. For most of its existence, theindustry was protected from competition withforeign oil by excise taxes and import duties.

Spain

The best Spanish resources yield from 30to 36 gal/ton. Reserves have been estimatedat about 280 million bbl of oil in place. TheSpanish industry began in 1922 using retortssimilar to those that had been developed inScotland. Maximum throughput for theseunits was 220 ton/d, reached in 1947. In 1955,new retorts from Scotland were installed. In1960, the enlarged industry processed 1 mil-lion tons, supplying more than half of Spain’srequirement of lubricating oil, Obsolete proc-essing technology and high operating costsforced the industry to cease operation in1966.

Germany

German resources are estimated to containonly about 2 million bbl of shale oil in place.Oil yields average only 12 gal/ton. Germanshales were developed as early as 1857, andseveral retorts were operated in the 1930’s.

A major development effort was initiated dur-ing World War II in response to wartime fuelshortages. The German industry used twotypes of aboveground retorts and one in situprocess. A plant with about 30 Lurgi above--ground retorts was operated from 1947 to

1949. In 1961, a plant was built in the town of Dotterhausen that burns finely crushed oilshale in a fluidized-bed combustor. The heatof combustion is used for power generation,and the spent shale product is used to makecement. The plant is the only active oil shale

facility in West Germany.South Africa

Very rich deposits are found in South Afri-ca. Oil yields reach 100 gal/ton, with an aver-age of 55 gal/ton, and the deposits are located

just beneath coalbeds. South African shale oilproduction began in 1935, and the industryattained a maximum throughput of 800 ton/din the 1950’s, with a corresponding shale oilproduction of 800 bbl/d. The industry was lo-cated in the country’s interior, and although

it was not directly subsidized by the govern-ment, its economic viability was enhanced bythe high cost of transporting competing petro-leum from the seacoast ports to interior mar-kets in the vicinity of the plants. The richerdeposits were eventually depleted, and the in-dustry ceased operations in 1962,

Australia

Oil shale deposits are found throughoutAustralia. Those of New South Wales andTasmania have been developed commercial-

ly. Total reserves are estimated at 270 millionbbl of shale oil in place. Most of the depositsare very rich, with oil yields as high as 180gal/ton. Shale oil production in New SouthWales began in 1862, and by 1892, about100,000 tons of shale were being processedeach year. The Australian Government begansubsidizing the industry in 1917, but produc-tion ceased in 1925. Production of Tasmanianshale oil began in 1910 and ceased in 1935. Inthe interim, about 41,000 tons of oil shalewere processed, and 85,000 bbl of shale oilwere produced.

Production was resumed in New SouthWales early in World War II under the direc-tion of the Australian Government. By 1947,annual throughput reached 330,000 tons, andabout 100,000 bbl of shale-derived gasoline




were produced annually. The production wasequivalent to about 3 percent of Australia’sgasoline consumption. The plant was closedin 1952 because of resource depletion, highoperating costs, and competition from con-ventional petroleum.

Unit ed States

As indicated previously, the U.S. oil shaleindustry was an important part of the Na-tion’s energy economy before the first oil wellwas drilled. At least 50 commercial plants forextraction of fuel oil from eastern oil shalesexisted prior to 1859. The industry disappeared shortly after commercial petroleumproduction began.

Between 1915 and 1920, supplies of domes-tic crude fell below demand, and oil importsincreased, especially from new oilfields inMexico. USGS indicated at that time that theUnited States had only a 9-year reserve of petroleum in the ground and that the outlookfor new discoveries was not good. At aboutthe same time, USGS announced that largefuel resources were contained in the oilshales of the Green River formation. Whencombined with predictions of forthcomingfuel shortages, the announcement triggeredan oil shale boom. Some 30,000 mining claimswere filed on Federal lands, and about 200companies were formed to develop the re-source. Retort development programs wereinitiated at several locations, and at least 25retorting processes were advanced to thepilot-plant stage. Total shale oil productionwas negligible, but interest was at an all-timehigh. The boom ended abruptly with the dis-covery of large oilfields in eastern Texas. Oilprices dropped to a few cents per barrel, andinterest in oil shale development essentiallydisappeared.

Little R&D was conducted in the UnitedStates until World War II. In 1944, out of con-

cern for the hazards of imported energy, Con-gress passed the Synthetic Liquid Fuels Act,which authorized USBM to establish a liquidfuel supply from domestic oil shale. USBM be-gan a comprehensive R&D program that has

continued to the present day, although over-sight authority was transferred to the EnergyResearch and Development Administration in1974 and to its successor, DOE, in 1978.

One of USBM’s most significant early acts

was the establishment of a research facilityat Anvil Points on the Naval Oil Shale Reservenear Rifle, Colo. Between 1944 and 1956, theAnvil Points facility was used for miningstudies that led to the application of the room-and-pillar technique of underground mining.The gas combustion retort, the predecessor of modern directly heated retorts, was also de-veloped during this period. In 1964, the facil-ity was leased by the Colorado School of Mines Research Foundation, and was the siteof a 4-year development program in which thegas combustion retort was evaluated and im-

proved by a consortium of six major oil com-panies: Mobil, Humble, Continental, PanAmerican, Phillips, and Sinclair.

In 1973, the facility was leased by Develop-ment Engineering, Inc. (DEI), which operatedit for 5 years during which the Paraho retort-ing process was developed. This is an im-proved version of the gas combustion retort.DEI then used the facility to produce over100,000 bbl of shale oil for refining studies,and has recently proposed to use Anvil Pointsfor further development work, including the

construction and operation of a commercial-size module of the Paraho retort.

Between 1963 and 1968, DOI evolved aleasing proposal that was intended to encour-age private development of the Federal oilshale lands in the Green River formation. Theprogram failed to attract private partici-pation. However, it gave rise to the currentFederal Prototype Oil Shale Leasing Program,which was conceived in 1969 and pro-mulgated in 1974 with the sale of leases tofour tracts in Colorado and Utah. The his-

tories of these leasing programs are pre-sented in volume II of this report. The statusof development efforts on the Federal leasetracts is described in the last section of thischapter.



Ch 4–Background 111

In addition to these activities on Federallands, private companies have also engagedin exploration and R&D programs on theirown lands, The companies that have beenmost heavily involved are: Union Oil, Occiden-tal Petroleum and its subsidiary OccidentalOil Shale, Inc.; Superior Oil Co.; and the Col-ony Development Operation group, which has

included Tosco, Atlantic Richfield, ClevelandCliffs Iron Co., and Ashland Oil Co. The activ-ities of these companies, and others that arepresently involved in oil shale development,are summarized in the following section,together with a status report on the indus-tries in other countries.

Status of Foreign Oil Shale Industries

Morocco

Oil shale is found in Morocco at Timahdit,in the Middle Atlas mountains, and at Tar-faya, on the Atlantic coast in the southernpart of the country. Other, smaller depositshave also been found. Most of the develop-

ment efforts involve the Timahdit deposits,which contain an estimated 4 billion to 9billion bbl of shale oil in a seam that is asmuch as 350 ft thick. The Moroccan Govern-ment is actively investigating abovegroundretorting, direct combustion of oil shale forpower generation, and modified in situ proc-essing technologies.

Soviet Union

The principal reserves of the U.S.S.R. arein the Baltic Basin, with additional deposits in

the Ukranian S.S.R. and the Central Asian Re-publics. The latter resources have been littleexplored and are not being developed; mostdevelopment activity is centered on the “ku-kersite” oil shales in the Baltic basin. Thetotal Baltic resource is estimated to be about21 billion tons, with about 11.3 billion tonsregarded as having commercial potential.About 8.4 billion tons occur in the EstonianS. S. R., with about 2.9 billion tons in the Lenin-grad area. The Estonian shales occur in bedsabout 10 ft thick and are buried beneath 30 to130 ft of overburden. They are of good quali-ty, yielding about 50 gal/ton.

The Estonian deposits were first developedin the 1920’s after the State achieved inde-pendence from Finland. In 1939, about 1.7million tons were processed. About 60 per-

cent of the shale was retorted to obtain fueloil; the rest was burned directly for processheat and power generation. During WorldWar II, the area was occupied by Germany,and the shale oil produced during this periodwas refined to obtain illuminating oil andbunker fuel oil for the German navy. When

the Estonian S.S.R. was created, the German-built plants were expanded to provide fuelgas for the cities of Tallinn and Leningrad.Shale oil and petrochemicals were also pro-duced, but most of the shale mined wasburned as a boiler fuel for power generation.

In 1970, about 14 million tons were mined.The present goal is to expand production to54 million ton/yr. About 75 percent of thepresent production is burned under boilers tosupply about 90 percent of Estonia’s electri-cal needs. The rest is retorted to produce fuel

oil, gasoline, fuel gas, and chemicals.The Soviet industry is estimated to have

mined about 560 million tons of kukersitebetween 1945 and 1975. As noted, only one-fourth of the mined shale is retorted. If all of the shale had been converted to oil, the aver-age production rate would have been about67,000 bbl/d, slightly more than would be pro-duced by a single commercial-scale oil shalefacility in the United States. The presenttarget of 54 million ton/yr is equivalent toabout 200,000 bbl/d.

Two types of large-scale retorts are used:the Kiviter gas generator which is similar tothe gas combustion and Paraho directlyheated retorts; and the Galoter retort whichuses spent shale as a heat carrier and isremarkably similar to the TOSCO II indirectly




heated design. At present, the largest Kiviterretort has a capacity of about 1,000 ton/d,about one-tenth the size of retorts planned forU.S. plants. The largest Galoter unit has acapacity of about 500 ton/d. A 3,30()-ton/d

nit is under construction. *

People’s Republic of China

Oil shale is found near Fushun in Manchu-a, and near Maoming in the Province of

Kwantung. The Manchuria deposits occur in450-f t-thick seams and overlie thick coalseams. The shale is mined by open pit meth-ods, together with the coal, Oil yields averageonly about 15 gal/ton. The deposits were firstdeveloped by the Japanese when they invadedManchuria during World War II. About 1.3million bbl of shale oil were recovered during

the war through use of retorts similar to thegas combustion design. Most of the oil was re-fined into fuel oil for the Japanese navy. Dur-ing the Korean war, production was ex-panded to about 50,000 bbl/d. Byproducts in-cluded chemical fertilizer from the nitrogenin the shale oil and cement from the spentshale. Additional shale was mined, mixedwith coal, and burned directly for power gen-eration.

During the past decade, the capacity of theManchuria industry has remained fairlyconstant, but six retorting plants have beenbuilt in the Kwantung Province. The total pro-duction from the Chinese plants is unknown,but it is unlikely to be more than about 50,000to 70,000 bbl/d. About two-thirds of the oil isrefined, the rest is burned directly for powergeneration.

Brazil

Brazil has very large deposits which couldcontain as much as 3 trillion bbl of potentialshale oil. The largest deposits of commercial

interest are those of the Irati formation,which begins in the State of Sao Paulo and ex-tends southward in an S-shaped curve for a

*For additional information on retorting technologies see ch.5.

distance of about 1,000 miles to the borderwith Uruguay. Irati shale yields about 20gal/ton on retorting, which is comparable to amedium grade of Green River shale.

Small retorts have been used intermittentlyin Brazil since 1862. Early operations pro-

duced illuminating gases for home use. Re-torting was discontinued in 1946 but resumedin the 1950’s under control of the nationalgovernment. In 1970, a 2,200-ton/d” demon-stration retorting plant was completed at SaoMateus do Sul in the State of Parana. Theplant has operated on an experimental basis.The Petrosix retorting process is used. It wasdeveloped by the engineering staff of Petro-bras, the national oil company, with the as-sistance of Cameron Engineers, a U.S. engi-neering firm. Little information has been re-leased about the demonstration but, given the

properties of the Irati shale and assuminghigh oil recoveries from the retort, the plantcould produce about 1,000 bbl/d of shale oil,eve. a million cubic feet of high-Btu gas perday, and about 15 ton/d of elemental sulfur.

At present, Petrobras is attempting to raiseabout $1.5 billion to build a commercial-sizeplant with a capacity of about 45,000 bbl/d.The plant would be sited near the presentdemonstration facility. About 20 Petrosix re-torts would be used. Current plans call for a25,000-bbl/d operation by 1983, with subse-

quent expansion to full capacity by 1985. Thedeposits in the immediate vicinity of the plant-site could supply the full-size facility forabout 30 years. Two additional plants of simi-lar size are contemplated for the State of RioGrande do Sul, which is south of the demon-stration plant.

Brazil’s enduring interest in oil shale de-velopment is related to its oil-import problem.It consumes about a million barrels of crudeoil per day, of which about 960,000 bbl/d areimported. The net drain of the national econ-omy is about $11 billion per year, which con-

tributes to a net deficit in the balance of inter-national payments of about $1.55 billion. It isdifficult to track the effect of this deficit in aneconomy with a 60-percent annual inflationrate, but the currency drain to purchase im-




ported oil is estimated to be equivalent to same proportion of its GNP on imported oil,about 6 percent of the nation’s gross national about 15 million bbl/d would be imported, orproduct (GNP). If the United States spent the nearly twice the present rate.

Status of U.S. Oil Shale Projects

The characteristics and status of 11 proj-ects that are at least at the stage of field test-ing in the Green River shales are summarizedin table 17. The list does not include severalrelatively new projects (such as Multi Miner-al Corp. ’s project for extraction of oil, nahco-lite, and alumina from deeply buried depositsin the Piceance basin) or projects that are be-ing conducted in the eastern shales. It alsodoes not include the numerous theoretical in-vestigations and laboratory-scale experi-ments that are being conducted by Federal

and State agencies and private companies.Two of the projects—Rio Blanco and

Cathedral Bluffs—are actively proceedingtowards commercial-scale operations on Fed-eral lease tracts in Colorado. The White River

project is also on a Federal lease tract, but itis inactive at present because of legal uncer-tainties.* Tosco’s Sand Wash project is Pro-ceeding towards commercialization at a rela-tively leisurely pace to maintain compliancewith the due-diligence provisions of the Utahleases. Three projects—Logan Wash, Geoki-netics, and BX—are of an experimental na-ture and are being partially funded by DOE.The four other projects—Colony, Union, Su-perior, and Paraho—are aimed towards ulti-mate commercial-scale operations but are in-

active at present for a variety of reasons,principally economic.

*The Rio Blanco, Cathedral Bluffs, and White River projectsare parts of the Federal Prototype oil Shale Leasing !Y )grarn,which is discussed in vol. II of this report.



114 An Assessment of 01/ Shale Technologies

Table 17.–Status of Major U.S. Oil Shale Projects

Production targetProject Location Proposed technology (barrels per day) Status summary

Rio Blanco Oil Shale Co.:Gulf, Standard of Indiana

Cathedral Bluffs 011 Shaleproject: Occidental Oil

Shale: Tenneco

White River Shale project:Sundeco; Philips; SOHIO

Colony Development Opera-tion: ARCO; Tosco

Long Ridge project: Union011 of California

Superior Oil Co.

Sand Wash project: Tosco

Paraho Development Corp.

Logan Wash project, Occi-dental Oil Shale: DOE

Geokinetics, Inc., DOE

BX 0il Shale project Equity0il Co. ; DOE

Federal lease tract C-a,Colorado

Federal lease tract C-b;Colorado

Federal lease tracts U-aand U-b; Utah

Colony Dow Westproperty ;Colorado

Union property; Colorado

Superior property;Colorado

State-leased land; Utah

Anvil Points: Colorado

D. A. Shale property;Colorado

State-leased land, Utah

Equity property; Colorado

MIS aand Lurgi-Ruhrgasaboveground retorts

Occidental MIS

Paraho abovegroundretorts

TOSCO II abovegroundretorts

Union ‘‘B’ abovegroundretort

Superior abovegroundretort

TOSCO II abovegroundretorts

Paraho abovegroundretorts

Occidental MIS

Horizontal-burn true in situ

True in situ retorting withsuperheated steam(Equity process)

76,000 Shaft sinking for MIS module development.(1987) Designing Lurgi -Ruhrgas module, PSDb

permit obtained for 1,000 bbl/d.5 7 , 0 0 0 Shaft sinking for MIS module development,(1986) Process development work being done at

Logan Wash, PSD permit obtained for5,000 bbl/d.1 0 0 , 0 0 0 Inactive because of litigation between Utah,

the Federal Government, and privateclaimants over landownership

46,000 Inactive pending improved economicconditions. PSD permit obtainedfor 46,000 bbl/d.

9 ,000 Inact ive pending improved economicconditions. PSD permit obtained for9,000 bbl/d.

11,500 Inactive pending BLM approval of landplus nahcolite, soda exchange proposal. PSD permit obtained

ash, and alumina for 11,500 bbl/d.5 0 , 0 0 0 Site evaluation and feasibility studies

underway. Lease terms require $8 millioninvestment by 1985,

7 , 0 0 0 Inactive following completion of pilot plant andsemiworks testing. Seeking Federal andprivate funding for a modular demonstrationprogram,

5 0 0 Two commercial-size MIS retorts planned for1980 m support of the tract C-b project. PSDpermit obtained for 1,000 bbl/d,

2 , 0 0 0 Continuation of field experiments, About(1982) 5,000 bbl have been produced to date.

Unknown Steam injection begun and wil l continue forabout 2 years. Oil production expected in1980. Production rate has not beenpredicted

aModdled In SIIU processingbp

reventlonof Slgnif[canl delerloratlon–an alr quallty permit that must be obtained before conslrucllon can be91fl (See ch 8 ]

SOURCE Off Ice ol Technology Assessment

Chapter 4 References

‘C. E. Banks and B. C. Franciscotti, “ResourceAppraisal and Preliminary Planning for SurfaceMining of Oil Shale, Piceance Creek Basin, Col-orado,” Quarterly of the Colorado School ofMines, vol. 71, No. 4, October 1976, pp. 257-285.

‘R. Nelson, “Meteorological Dispersion Poten-tial in the Piceance Creek Basin,” Quarterly of theColorado School of Mines, vol. 70, No, 4, October1975, pp. 223-238.

‘Bureau of Land Management, Draft Environ-mental Impact Statement—Proposed Develop-ment of Oi l Shale Resources by Colony Develop-ment Operation in Colorado, Department of the In-terior, Dec. 12, 1975, p. 111-9,

“Rio Blanco Oil Shale Project, Detailed Develop-ment Plan—Tract C-a, Gulf Oil Corp. and Stand-ard Oil Corp. (Indiana), March 1976, p. 3-6-12.5Environmental Protection Agency, Assessment

of the Environmental Impacts From Oil Shale De-velopment, EPA-600/7-77-069, July 1977, p. 100,‘Supra No. 3, at p. 111-121.7

Supra No. 4, at p. 9-11-18.D pe artment of the Interior, Final Environmen-

tal Statement for the Prototype Oi l Shale Leasing

Program, Washington, D. C., 1973, pp. H-79 to11-90.‘Supra No,4,atp.9-11-16.%upra No. 8, at p. 11-231.





CHAPTER 5

Technology

Introduction q .*. ... . * * ,, *,, , **,,.*.,.Page119

Summary of Findings. . . . . . . . . . . . . . . . .. ..119

An Overview of Oil Shale Processing . ......120

Oil Shale Mining. . . . . . . . . . . . . . . . . . . . . .. .123Surface Mining. . . . . . . . . . . . . . . . . . . . . . . . . 123Underground Mining . ...................125

Oil Shale Retorting. . ...................,128True In Situ. . . . . ................,......128Modified In Situ . .......................131Aboveground Retorting . .................137

Advantages and Disadvantages of theProcessing Options. . ..................153Oil Recovery . . . . . ......................154

Properties of Crude Shale Oil .. .... ... ....155

Shale Oil Refining. . ..................,..157Shale Oil Upgrading Processes . ....,......158Total Refining Processes . ................160Cost of Upgrading and Refining . ...........162

Markets for Shale Oil. . ..................163Shale Oil as a BoilerFuel . ................163Shale Oil as a Refinery Feedstock . .........164Shale Oil as a Petrochemical Feedstock .. ...166

Issues and Uncertainties . ................167R&D Needs and Present Programs. . ........170R&D Needs . . . . . . . . . . . . . . . . . . . . . . . . . . . .170Present Programs. . . . . . . . . . . . . . . . , . . , . . .172

Policy Options . . . . . . . . . . . . . . . . . .**.,*,.. 173R&D. . . . . . . . . . . . ................,.....173

PageDemonstra t ion . . . . . . . . . . . . . . . . . . . . . . . . .173

Chapter 5 References. . ..................175

List of Tables

Table No. Page18. Overall Shale Oil Recoveries for

Several Processing Options . . . . . . . . . 15519. Properties of Crude Shale Oil From

Various Retorting Processes. . . . . . . . . 15620. Supply of Finished Petroleum Products

in PADDs 2, 3, and 4 in1978 . . . . . . . . . 165

21. Technological Readiness of Oil ShaleMining, Retorting, and RefiningTechnologies . . . . . . . . . . . . . . . . . . . . . 168

List of Figures

FigureNo. Page19.20.

21.22.23.

24,

25.

26.27.

Oil Shale Utilization . . . . . . . . . . . . . . . 121The Components of an UndergroundMining and Aboveground Retorting OilShale Complex. . . . . . . . . . . . . . . . . . . . 122An Open Pit Oil Shale Mine. . . . . . . . . . 124Open Pit Oil Shale Mining. . . . . . . . . . . 125The Colony Room-and-PillarMining

Concept . . . . . . . . . . . . . . . . . . . . . . . . . 126Room-and-Pillar Mining on MultipIeLevels . . . . . . . . . . . . . . . . . . . . . . . . . . . 127The Original Mine Development Planfor Tract C-b . . . . . . . . . . . . . . . . . . . . . 128True In Situ Oil Shale Retorting . . . . . . 129Modified In Situ Retorting. . . . . . . . . . . 132



28.

29.

30.

31.

32.

33.34.35,

36.37,

38.

39.

4U.41.

P a g e

The RISE Method of MIS Oil ShaleRetorting . . . . . . . . . . . . . . . . . . . . . . ,. 134Initial Modular MIS RetortDevelopment Plan for Tract C-a . . . . . . 135Present MIS Retort Development Planfor Tract C-a . . . . . . . . . . . . . . . . . . . . . 136Retort Development Plan for theMulti Mineral MIS Concept.. . . . . . . . . 136

Preparation of a Multi Mineral MISRetort . . . . . . . . . . . . . . . . . . . . . . . . . . . 137A Set of Multi Mineral Misreports . . . 138The Operation of an NTU Retort.. . . . . 140Discharging Spent Shale Ash Froma40-Ton NTU Retort. . . . . . . . . . . . . . , . . 141The Paraho Oil Shale Retorting System 143The Paraho Semiworks Unit atAnvil Points, Colo. q , q q q q q q . q . . . q , . q143The Petrosix Oil Shale RetortingSystem . . , . . , . , . . . . . . . , , . . 0 . , . , 0 . 145The Petrosix Demonstration Plant,Sao Mateus do Sul, Brazil. . . . . . . . . . . 146The Union Oil “B” Retorting Process.. 147Block Diagram for the SuperiorMulti Mineral Concept . . . . . . . . . . . . . 149

42.43.

44,

45*

46.

47*

48.

49.

50.

P a q e

The Superior Oil Shale Retort.. , . . . . . 150The Colony Semiworks Test FacilityNear Grand Valley, Colo. . . . . . . . . . . . 151The TOSCO II Oil Shale RetortingSystem .,, , . . . . . 0 ., . . . . ., .,....,, 152The Lurgi-Ruhrgas Oil Shale Retorting

. ,0 ,0 . . . . . . . . . . . . . . . . . . . . . 153Refining Scheme Used by the U.S.

Bureau of Mines to Maximize GasolineProduction From Shale Oil . . . . . . . . . . 161Refining Scheme Employing CokingBefore an Initial Fractionation, Used byChevron U.S.A. in RefiningExperiments. ., . . . . . . . . . . . . . . . . . . . 161Refining Scheme Employing InitialHydrotreating, Used by Chevron U.S.A.in Refining Experiments . . . . . . . . . . . . 161Refining Scheme Employing InitialFractionation, Used by SOHIO inPrerefining Studies . . . . . . . . . . ... , . . 162The Petroleum Administration forDefense Districts. . . . . . . . . . . . . . . . . . 165



CHAPTER 5

Technology

Introduction

The mining and processing technologiesthat can be used to convert kerogen

f

the or-ganic component of oil shale, into marketablefuels are discussed in this chapter. The char-acteristics of these technologies will influ-ence the effects that an oil shale industry willhave on the physical environment, and theirtechnological readiness will affect the rate atwhich an industry can be established. Thefollowing subjects are discussed:

q

q

q

the general types of processing methodsand their major unit operations;the mining methods that could be used toremove oil shale from the ground and

prepare it for aboveground processing;the generic types of retorting methods

Summary

Oil shale c o n t a i n s a s o l i d h y d r o c a r b o n c a l l e d

k e r o g e n t h a t when heated (retorted) yields combusti-ble gases, crude shale oil, and a solid residue calledspent, retorted, or processed shale. Crude shale oilcan be obtained by either aboveground or in situ (inplace) processing. In aboveground retorting (AGR),the shale is mined and then heated in retortingvessels. In a true in situ (TIS) process, a deposit isfirst fractured by explosives and then retorted under-ground. In modified in situ (MIS) processing, a por-tion of the deposit is mined and the rest is shattered(rubbled) by explosives and retorted underground.The crude shale oil can be burned directly as boilerfuel, or it can be converted into a synthetic crude oil(syncrude) by adding hydrogen. The syncrude canalso be burned as boiler fuel, or it can be convertedto petrochemicals or refined to obtain finished fuels.Some of OTA’s major findings concerning these min-ing and processing technologies are:

q Limited areas of the oil shale deposits may beamenable to open pit mining. This technique hasnever been tested with oil shale but it is well-

q

q

q

q

q

that could be used to convert the oil

shale to liquid and gaseous fuels;the upgrading and refining methods thatcould be used to convert crude shale oilto finished products;the potential markets for shale-derivedfuels;the technological readiness of the majorsteps in the oil shale conversion system;the uncertainties and the research anddevelopment (R&D) needs that are asso-ciated with each major unit operation;andthe policies available to the Government

for dealing with the uncertainties,

of Findings

q

q

advanced with other minerals. More oil shale ex-perience has been acquired with undergroundmining, particularly room-and-pillar mining, andpreparing MIS retorts. Although uncertainties re-main, the mining technologies should advance

rapidly if presently active projects continue andsuspended ones resume.

TIS is presently a very primitive process, althoughR&D and field tests are being conducted. The prin-cipal advantages of TIS are that mining is notneeded and surface disturbance from facility sitingand waste disposal is minimized. The principaldisadvantages are a low level of technologicalreadiness, low recovery of the shale oil, and a po-tential for surface subsidence and leaching of thespent shale by ground water.

MIS is a more advanced in situ method. It is being

further developed on two lease tracts and a pri-vately owned site. The Department of Energy(DOE) is providing substantial R&D support. Theprincipal advantages of MIS are that large depos-

119




its can be retorted, oil recoveries per acre affectedare high, and relatively few surface facilities arerequired. However, some mining and some dis-posal of solid wastes on the surface are required,and the oil recovery per unit of ore processed islow relative to AGR methods. The burned-out MISretorts have a potential for ground water pollution.

q AGR also has a medium level of technologicalreadiness. Three retorts have been tested for sev-eral months at rates approaching one-tenth the ca-pacity of commercial-size modules. Others are stillat the laboratory or pilot-plant stages. The princi-pal advantage of AGR processing is high oil recov-ery per unit of ore processed. However, with somemining methods, oil recoveries per acre may belower than with MIS. Surface disturbance is high-est with AGR because of the extensive surface fa-cilities, and because large quantities of solidwaste are generated.

q The physical and chemical properties of crudeshale oil differ from those of many conventionalcrudes. However, depending on the nature of theupgrading techniques applied, the syncrude canbe a premium-quality refinery feedstock, compar-able with the best grades of conventional crude.Shale oil is a better source of jet fuel, diesel fuel,and distillate heating oil than it is of gasoline. Al-though some technical questions remain, the up-grading and refining processes are well-ad-vanced. Refining shale oil may cost from $0.25 to

q

q

$2.00 more per bbl than refining some of thepoorer grades of domestic crude.

The initial output from the pioneer oil shale in-dustry will probably be marketed near the oil shaleregion. Once the industry is established, the shaleoil will probably be used as boiler fuel or refined in

the Rocky Mountain States. A large industry willmost likely supply oil to Midwest markets. A 1-million-bbl/d industry could completely displacethe quantities of jet, diesel, and distillate heatingfuels that are presently obtained from foreignsources in the entire Midwest.

With the present technical status of the criticalretorting processes, deploying a major oil shale in-dustry would entail appreciable risks of techno-logical and economic failure. Although much R&Dhas been conducted, and development is proceed-ing, the total amount of shale oil produced to date

is equivalent to only 10 days of production from asingle 50,000-bbl/d plant. Because of its primi-tive status, much basic and applied R&D is neededfor the TIS method. The MIS approach and someof the AGR processes are ready for the next stageof development—either modular retort demonstra-tions or pioneer commercial-scale plants. Suchdemonstrations would be costly, but they wouldsubstantially reduce the risks associated with themuch larger capital investments needed to createan industry,

An Overview of Oil Shale Processing

Converting shale in the ground to finished broken with explosives to create a highlyfuels and other products for consumer mar- permeable zone through which hot fluidskets involves a series of processing steps. can be circulated; andTheir number and nature are determined by q AGR processes in which the shale isthe desired mix of products and byproducts mined, crushed, and heated in vesselsand by the generic approach that is followed near the minesite.in developing the resource. The alternative Figure 19 is a flow sheet for the steps com-approaches are: mon to all three options. How the steps would

q

q

TIS processes in which the shale is left be integrated in an AGR facility is shown in

underground, and is heated by injecting figure 20. In the first step, the oil shale ishot fluids; mined and crushed for aboveground process-MIS processes in which a portion of the ing, or the deposit is fractured and rubbledshale deposit is mined out, and the rest is for in situ processing. The main product is



Ch 5– Technology 121

Figure 19.– Oil Shale Utilization

Mining & Crushing

or In situ retortWastes &

bpreparation byproducts

7

Treated Re-Use

~ % *Reinfection

m ~ water Dischargea ~

o

Y ?- #

Wastes & ResiduesRetorting Treatment # \

byproductsDisposal

TA

~ ~

@

6 ~ Sulfur, NH3,*

Industrialq

byproducts markets

71 f

Upgrading<Wastes &

byproducts

I

9 ‘ ransportatonm ‘ e f ’ n ’ n g l’=% “ s t r bu t ” n t -+ C==laMay not be nee~e(j for some in S1 tu methods


raw oil shale with a particle size appropriatefor rapid heat transfer. Nahcolite ore can be

one of the various byproducts from this step.Dust and contaminated water are among itswastes, In the retorting step, the raw oil shaleis heated to pyrolysis temperatures (about1,000° F (535° C)) to obtain crude shale oil.Other products are the spent shale residue,pyrolysis gases, carbon dioxide, contami-nated water, and in some cases additionalnahcolite and dawsonite ore. The crude shaleoil may be sent to an upgrading section inwhich it is physically and chemically modifiedto improve its transportation properties, toremove nitrogen and sulfur, and to increaseits hydrogen content. (Crude shale oils fromsome in situ processes may not need upgrad-ing before transportation. ) Contaminated airand water, and in some units refinery coke,are the wastes produced along with gases

that contain sulfur and nitrogen compounds.Depending on the extent of the treatment, the

upgraded product—shale oil syncrude-canbe a high-quality refinery feedstock, compar-able with the best grades of conventionalcrude. In the refining step, which may be con-ducted either onsite or offsite, hydrogen isadded to convert the syncrude to finishedfuels such as gasoline, diesel fuel, and jetfuel. The syncrude, or the crude shale oil,could also be used directly as boiler fuel.After refining, the fuels are distributed toconsumer markets. Refining also produceswaste gases and various contaminated con-densates.

To protect the environment, contaminatedwater must be treated for reuse in the oilshale facility, for reinfection into the groundwater aquifer source, or for discharge into





Ch 5– Technology q 123

Oil Shale

Both MIS and AGR require mining. In thecase of AGR, the mined shale is conveyed toretorts where it is processed to recover shaleoil. With MIS, the shale may also be retorted

aboveground, or it may be discarded on thesurface as a solid waste.

Green River oil shale deposits are charac-terized by their extreme thickness and bytheir extensiveness. The richer shale zones inthe Piceance basin, for example, are morethan a thousand feet thick, in places, and arecontinuous over an area of 1,200 mi2. Depos-its of this nature could be amenable to eithersurface mining (strip or open pit) or to under-ground mining methods (such as room and pil-lar), depending on topographical features, ac-cessibility, overburden thickness, presence of ground water in the mining zone, and manyother factors. Surface mining may be feasiblefor very thick oil shale zones that are notdeeply buried, especially if their average oilyield is not high, Because of the thickness of the overburden, only a limited area of thePiceance basin and somewhat more of theUinta basin and the Wyoming basins is amen-able to surface mining. In other areas,streams have eroded gulleys and canyonsthrough the shale beds, exposing some of thericher shale zones. Shale that outcrops inthese areas, plus the shale in all deeplyburied beds, will probably be extracted byunderground mining,

Despite the high price of crude oil, oil shaleis a lean ore compared with many ores thatcontain valuable metals. Economies of scaleencourage massive mining installations, re-gardless of the mining method selected. Aprospective developer once characterizedcommercial-scale oil shale mines as “prodi-gious, ” because it connotated a larger sizethan “giant.’” A sense of this can be con-veyed by comparing their capacities with

those of more conventional mines. At present,the largest surface mine in the United Statesis Kennecott Copper’s Bingham Canyon pit inUtah, which produces about 110,000 ton/d of copper ore. The largest underground mine is

Mining

the San Manuel copper mine in Arizona,which yields about 50,000 ton/d of ore, About70,000 ton/d of 30 gal/ton oil shale wouldhave to be mined to support a single 50,000-

bbl/d plant that used aboveground retorts. *This mine would be substantially larger thanthe San Manuel mine. A 400,000-bbl/d indus-try of aboveground retorts would have tomine about 560,000 ton/d—the equivalent of 5 Bingham Canyon pits or 11 San Manuelmines. If the same industry used only MIS,about 230,000 to 460,000 ton/d would have tobe mined—the equivalent of four to sevenSan Manuel mines. ** Some of the mining

techniques that could be used to achievethese levels of production are describedbelow.

Surface Mining

The two principal types of surface mining—open pit and strip— both have been widelyused to develop coal seams and deposits of many other minerals. Their technical aspectsare fairly well-understood for these minerals.However, their feasibilities and effects varywith the nature of the ore body. Neither tech-nique has yet been applied to the oil shales of the Green River formation.

Surface mining is economically attractivefor large, low-grade ore deposits because itpermits high recovery of the resource andallows sufficient space for very large and ef-ficient mining equipment. An open pit minecould recover almost 90 percent of the oilshale in a very thick deposit. Strip miningcould provide even higher recoveries. In con-trast, underground mining would recover lessthan 60 percent. One of the reasons that in-dustry’s bids on a lease for Federal tract C-awere so high was that the deposit could be

*This assumes recovery of 100 percent of Fischer assay oil,a recoverv efficiency that h:)s been achieved in tests of the“rOSCO 11 technology.

**This assumes mining of 20 to 40 percent of the shnle in theretort volume, and an oil recovery of 60 percent of Fischerassay.




mined by open pit methods. About five timesas much shale could be recovered by open pit,which could have mined the entire deposit,than by underground room-and-pillar mining,which would have been limited to a relativelythin zone.2

A mature open pit mine is shown in figure21 and the steps in its operation in figure 22.In the first step, overburden is drilled andblasted loose over a large area above the oilshale zone. The burden is carried by trucks orconveyors to an offsite disposal area. Whenenough burden is removed to expose the shalebeds, the shale itself is drilled and blasted,and is hauled from the pit for processing inaboveground retorts. As mining proceeds, ahuge hole is formed, extending from the top of the overburden to deep into the oil shale de-posit. The walls of the pit are under pressure

from the overburden, and must be angled out-

Figure 21 .— An Open Pit Oil Shale Mine

Off site disposal

Ov n

SOURCE Hear/rigs on 0// Sha/e Leasing, Subcommittee on Minerals, Materials,and Fuels of the Senate Commltee on Interior and Insular Affairs,

94th Cong 2d sess , Mar 17, 1976, p 84

wards to transmit the pressure without col-lapsing.

Open pit mining was originally proposedfor tract C-a by the Rio Blanco Oil Shale Co.,the lessee. The pit was to have started in thenorthwest corner of the tract, and eventually

to have covered its entire surface. After afew decades, freshly removed overburdenand spent shale from the aboveground retortswould have been returned to the pit as back-fill. In the interim, the solid wastes wouldhave been disposed of on a highland to thenortheast of the tract boundaries. This con-cept was abandoned when the Department of the Interior (DOI) refused to allow offtractwaste disposal. Rio Blanco later switched toMIS techniques because the alternative—un-derground mining—would have reduced re-source recovery and threatened profitable

operations. * At present, there are no plansfor any open pit mines, although Rio Blancomay reconsider its original plan if offsite dis-posal were allowed.3

In strip mining, overburden is removedwith a dragline—a massive type of scrapershovel. When the dragline has filled its scoop,it pivots and dumps the burden into an adja-cent mined-out area. One difference betweenopen pit and strip mines is that in strip min-ing, the burden is simply cast into a nearbyarea; in open pit, it must be moved far from

the minesite to prevent interfering with thedevelopment of the pit. Strip mining has notbeen proposed for any of the Green River de-posits.

Surface mining of most oil shale deposits ismade difficult by the great thickness of theoverburden that covers them. In the center of the Piceance basin, for example, the 2,000-ft-thick oil shale zones are buried under about1,000 ft of inert rock and very lean oil shale.This does not necessarily preclude surfacemining, because the deposits are generallycharacterized by a favorable stripping ra-

tio—the ratio of overburden thickness to ore-body thickness. The thick beds in the centerof the Piceance basin have 1 ft of overburden

*This change in plans is discussed in vol. 11,



Ch 5–Technology 125

Figure 22.—Open Pit Oil Shale Mining

II

Jl--

/

OVERBURDEN

t4 0 -– —

“ — “ — — “

1OIL SHALE

SOURCE U S Energy Oullook–AnIfrtenrn RePort The National Petroleum Council Washington D C 1972

for every 2 ft of oil shale—a stripping ratio of 1:2. With coal, a stripping ratio of 10:1 isoften economically acceptable. A study by theNational Petroleum Council indicates thatopen pit mining would be favored for strip-ping ratios between 2:1 and 5:1, strip miningfor smaller ratios, and underground miningfor larger ratios than 5:1.’

However, the economic principles of coal

mining should be applied with caution to oilshale. Removing 1,000 ft of overburden to re-cover 2,000 ft of shale might be possible intheory, but the pit’s boundaries would be soextensive that it would have to be located ona very large tract. Furthermore, the large“front-end” investment in removing overbur-den many years in advance of retorting wouldprobably make open pit mining of deep depos-its uneconomical. Also, strip mining wouldnot be feasible in many parts of the oil shaleregion, even those with favorable strippingratios, because the dragline would have to

reach to the bottom of a 3,000-ft-thick layer of overburden and oil shale. It is not clear thatsuch a machine could be built.

Underground Mining

Many underground mining procedureshave been proposed for oil shale deposits5-10

but to date only room-and-pillar mining andmining in support of MIS retorting have beentested at any significant scale. In room-and-pillar mining, some shale is removed to formlarge rooms and some is left in place, as pil-lars, to support the mine roof, The relativesizes of rooms and pillars are determined bythe physical properties of the shale, by thethickness of the overburden, and by theheight of the mine roof. Most of the depositsof commercial interest are very thick andhave relatively few natural faults and fis-sures. The ore itself resists compression andvertical shear stresses. These propertiesallow the use of large rooms, and relativelylittle shale needs to be left as unrecoverablepillars.

The U.S. Bureau of Mines (USBM) studied

underground mining of oil shale at the AnvilPoints Experimental Station in the late 1940’sand early 1950's. 11 The primary purpose of




the mining program was to supply raw shale mining plan proposed for Colony Develop-for the Bureau’s retorting experiments, but ment’s 46,000-bbl/d facility in the Piceancethe program was also designed to develop a basin. 12 The rooms are 60 ft wide; the pillarssafe, low-cost mining method. The room-andare 60 ft square; and the mine roof is 60 ftpillar technique was adopted after extensive high. Mining is conducted in two 30-ft-hightesting. From their studies, which included benches. The upper bench is mined first byenlarging the rooms until the roof failed, the drilling blastholes into the walls of a produc-

investigators concluded that for safe mining tion room, and breaking the shale loose withconditions the rooms should be 60 ft wide explosives. The broken shale is carried bywith pillars that are 60 ft on a side. trucks to the crushers where it is crushed to

the size range required by the TOSCO 11Many of the modern mine designs have aboveground retorts. The walls and the roof

been patterned after the USBM experimental of the new room are then “scaled” to removemine. The design depicted in figure 23 is the shale that was loosened by the blasting but

Figure 23.—The Colony Room-and-Pillar Mining Concept

SOURCE R W Marshall Colony Development Operation Room. andPlllar 011 Shale Mlnlng, ” Quarterly 01 the Colorado School o/ Mines, VOI 69, No 2 April 1974. PP

171 184



Ch 5–Technology q 12 7

did not fall. Holes are drilled into the roof,and roof bolts are inserted to assure its integ-rity, thus protecting the miners from roof falls. The USBM studies indicated that roof bolts would have to be installed in the accesspassageways but not in areas that were ac-

tively being mined. These production roomswould be vacated long before there was anyserious danger of roof falls.

The lower bench is mined next, The se-quence is similar except the blastholes aredrilled into the floor of the upper bench, andadditional roof bolting is not needed, The cy-cle of drilling, blasting, loading, scaling, androof bolting was designed to produce about66,000 ton/d of shale. About 60 percent of theshale in the mining zone was to be removedfor processing in the aboveground retorts.The rest was to remain in the support pillars.

Colony estimated that enough shale is presentin the 60-ft seam to support the retorting fa-cility for at least 20 years.

The same type of mine was proposed by theColony partners for development of tract C-b,after considering longwall mining, long-holeblasting, continuous mining, block caving,open pit mining, in situ processing, and manyother options. The major advantages of theroom-and-pillar method were identified as: 13

it is highly flexible and can easily bemodified to accommodate new condi-

tions, new equipment, or technologicaladvances:it can be highly mechanized and highoverall production rates can be achievedbecause many areas can be mined simul-taneously:the mine openings are relatively easy toventilate:development of access passageways isalso a production operation because oilshale would be removed; andthe mine could be designed to minimizesurface subsidence.

disadvantages were the high cost of theroof support system and the relatively low re-covery. In this regard, it was estimated thatonly 30 to 50 percent of the shale in a 75-ft-thick interval could be recovered. Higher re-

coveries would be possible if the pillars weresubsequently mined out or if the mining wereconducted on multiple levels. (See figure 24, )

Figure 24. —Room-and-Pil lar Mini ngon Multiple Levels

&

\~ Pillar. Room

, >ill

~ MiningL e v e l

SOURCE Hearing on 0// Shale Leas/rig Subcommittee on Minerals Materials

and Fuels of the Senate Comm It lee on I n Ierlo r and I n su Iar Affairs

94th Cong 2d sess Mar 17 1976 p 83

The mine eventually would have extended

under the entire surface of tract C-b, asshown in figure 25. However, the conceptwas abandoned when it was discovered thatthe shale in the mining zone was highly frac-tured—a condition that would have requiredlarge support pillars thus reducing resourcerecovery to uneconomic levels. All of theoriginal partners subsequently withdrewfrom the tract, and it is now being developedby MIS methods by Occidental Oil Shale andTenneco Oil Co.

Mining to prepare for MIS retorts is dis-

tinguished from room and pillar both by thevolume of the deposit that is disturbed and bythe configuration of the disturbed areas. Asindicated, the underground mines both on theColony property and on tract C-b would havebeen developed in a 60-ft-high mining zone;





Ch. 5–Technology q 129

2.

3.

4.

The

fracturing or rubbling if the deposit isnot already permeable to fluid flow;injection of a hot fluid or ignition of aportion of the bed to provide heat for py-rolysis; andrecovery of the oil and gases throughwells.

principles of TIS processing are illus-trated in figure 26. Several types have beenproposed that differ from each other with re-spect to the methods for preparing and heat-ing the deposit. All use a system of injectionand production wells that are drilled accord-ing to a prescribed pattern. One that is com-monly used is the “five-spot” pattern in whichfour production wells are drilled at the cor-ners of a square and an injection well isdrilled at its center. The deposit is heatedthrough the injection well and the products

are recovered through the production wells,For efficient TIS processing, the deposit

must be highly permeable to fluid flow, whichis true of portions of the Green River oilshales. A good example is the Leached Zone

of the Piceance basin where ground waterhas dissolved salt deposits to leave largerubble-filled zones. It is estimated to containabout 550 billion bbl of shale oil in place. 14

There are interconnected fractures and voidsin other areas of the formation, but these, ingeneral, have only a very limited permeabili-ty. The permeability of most of the zones thatappear to have commercial promise is essen-tially zero. Deposits that lie near the surfacecould be fractured by injecting water or ex-plosive slurries, but mining would probablybe needed to increase the permeability of deeply buried deposits. MIS or AGR proc-esses are more appropriate for the deeper re-sources.

In 1961, Equity Oil Co. began developing aTIS process for the Leached Zone, which wastested in the Piceance basin between 1966and 1968. It involved dewatering a portion of the zone followed by injecting hot natural gas.Pyrolysis gases and a small amount of oilwere swept in the natural gas stream to pro-duction wells through which they were

Figure 26. —True In Situ Oil Shale Retorting

1? 11

PRC

‘DUC1NGWWQM13

SOURCE B F Grant Retorting 011 Shale Underground—Problems and Posslbllltles, ouarfedy of the Co/orado Schoo/ ofM(nes VOI 59, No 3, July 1964, p 40




pumped to the surface. The gas was sepa-rated from the oil, reheated, and reinfectedinto the deposit. The oil had a much lowerpour point, viscosity, and nitrogen contentthan oils from aboveground retorts. * Thesefavorable characteristics may have been re-lated to the solvent properties of the natural

gas, and to the absence of oxygen from the re-torting zone. The quality of the retort gaseswas also good, partly because of their naturalgas component, and partly because during re-torting combustion and the decomposition of carbonate minerals were minimal. **

Process development was not pursued be-cause too much of the natural gas was lost inthe unconfined formation. In 1968, AtlanticRichfield Co. (ARCO) purchased an interest inthe process and resumed its development. In1971, a revised concept was announced in

which superheated steam, rather than natu-ral gas, was to be used to heat the deposits. In1977, DOE contracted with Equity to test theconcept in a 50()-f t-thick seam in the LeachedZone of the Piceance basin. The seam under-lies about 0.7 acre of surface, and containsabout 700,000 bbl of oil in place. It has beenestimated that as much as 300,000 bbl couldbe recovered over a 2-year period, with abouthalf of the oil produced in the first 7 months. ’sSteam injection has begun at the site, and willcontinue through 1981. No detailed estimateshave yet been released of production rates or

retorting efficiency. If the process proves tobe technically and economically feasible, itcould be applied in portions of both the Pice-ance and the Uinta basins.

At present, no work is being done in slight-ly fractured formations, but much research isbeing performed to develop methods for in-creasing their permeability by enlarging nat-ural fractures and creating new ones. Some

*rI’hese properties have economic significance. Pour point isthe lowest temperature at which oil will flow. Oils with highpour points are hard to transport because they solidify at nor-

mal ambient temperatures. Viscosity is a measure of a fluid ”sresistance to flow. Oils with high viscosity are expensive topump. Reducing the high nitrogen content of most crude shaleoils consumes hydrogen, which is costly.

**Both of these processes produce carbon dioxide, which isa major constituent of gases produced by some above-ground re-torts.

of the fracturing techniques used have beenchemical explosives, electricity, and injectinghigh-pressure air and water. These methodshave been used to enhance recovery of con-ventional petroleum; oil shale fracturingposes a similar problem. Nuclear explosiveswere also proposed in the 1960’s, but were

not tested because of their potential for harm-ing the environment, A nuclear test—ProjectRio Blanco—was conducted in the Piceancebasin to fracture sand formations containingnatural gas. The test failed.

The earliest TIS work was by Sinclair OilCo., between 1953 and 1966. A thin section of shale in the Mahogany Zone of the Piceancebasin was fractured by injecting air. The bedwas ignited, although with difficulty, and asmall quantity of shale oil was collected be-fore the hot shale swelled and sealed the

fractures. After additional tests, Sinclair con-cluded that the zone’s limited permeabilitywould not permit profitable operations. *

Research on TIS processing began atUSBM in the early 1960’s. In 1974, the pro-grams and personnel were transferred to theEnergy Research and Development Adminis-tration, and in 1978, they moved to DOE. TheR&D programs have included laboratory ex-periments, computer simulations, pilot-plantstudies, and field tests. Among the latterwere tests of electrical, hydraulic, and ex-plosive fracturing and combustion retortingnear Rock Springs, Wyo. These revealedsome of the problems associated with the TISapproach. In one early test, for example,after inert gas at about 1,300° F (7050 C) waspumped into a fractured formation for a peri-od of 2 weeks, about 1 gal of shale oil was re-covered. In another experiment in a zone thatcontained 7,800 bbl of shale oil in place, itwas estimated that only 60 bbl of the close to1,000 bbl that were released were actuallyrecovered.

Low oil recoveries are often associated

with TIS processing because of the large im-

*rI’he results of a mathematical simulation indicated thatabout 18 years of continuous steam injections would be re-c~uired to heat the shale to pyrolysis temperatures within a 30-

ft radius of a fracture.




permeable blocks of shale in the fracturedformation. These cannot be fully retorted in areasonable length of time. Irregular fractur-ing patterns that can cause the heat carrierto bypass large sections of the deposit areanother problem. Oil shale that is located in

the bypassed regions will not be retorted,And, even if all of the shale in a fracturedarea were retorted, much of the oil would notreach the production wells, but would remaintrapped in the pores of the spent shale orwould diffuse beyond the production wells, tobe lost in surrounding areas.

To develop methods for improving recov-ery, an extensive R&D program has been con-ducted at the Federal research center in Lar-amie, Wyo. Aboveground batch retorts withcapacities of both 10 and 150 tons of shalehave been used to simulate in situ retorting,but under more controlled conditions than ex-ist underground. Oil recoveries of up to 67percent have been achieved, and an experi-ment in a “controlled-state” retort achieved95-percent oil recovery. *

In 1976 and 1977, the program was ex-panded to include field tests of different frac-turing and retorting techniques under cost-sharing contracts with Equity Oil, Talley -Frac, Inc., and Geokinetics, Inc.** The Equityprogram has been described. The Talley-Fracprogram was terminated after the fracturing

method failed. The Geokinetics process uses afracturing technique called surface uplift inwhich an explosive is injected into severalwells and detonated to fracture the shale andmake it permeable to fluid flow, The shale isignited by injecting air and burning fuel gasthrough one well. It is pyrolyzed by the heatthat sweeps through the bed in the gasstream, Oil and gases are pumped to the sur-face through outlying production wells. It ishoped that the technical feasibility of the

*rI’he large retorls resemble the classic Newia-Tex:]s-Utah

(N’I’U) retort that is described later in this chapter. Because of

the higher percentage of void volume in the rubble, these re-torts provided better simulations of hlIS processing thtin of ‘1’1S. “1’he controlled-state retort was much smfiller and wasequipped for better cent rol of retortin~ renditions.

**Tbe procurement also included a contract with OccidentalOil Shale, Inc., to develop its MIS process, which is discussed inthe next section.

process can be demonstrated for thin depos-its that are covered by less than 100 ft of overburden. It has been estimated that thereare at least 6 billion bbl of shale oil in place inthis type of deposit. It is common in the Uintabasin, 16) and at present, would be most eco-

nomically developed by strip mining.Geokinetics has been investigating the sur-

face uplift approach since 1973, and is pres-ently burning its 20th retort in Utah. Thelargest retort prior to 1979 measured 130 ftby 180 ft by 30 ft thick. A retort about 200 fton a side and 30 ft thick will be required todemonstrate the technical feasibility of theprocess. By 1982, DOE and Geokinetics hopeto have developed a commercial-scale opera-tion with a production capacity of 2,000bbl/d.17

Modified In Situ

In MIS processing, the permeability of oilshale deposits is increased by mining someshale from the deposit and then blasting theremainder into the void thus created. Thetwo-step process is depicted in figure 27. Inthe first step, a tunnel is dug to the bottom of an oil shale bed, and enough shale is removedto create a room with the same cross-section-al area as the future retort. Holes are drilledthrough the roof of the room to the desiredheight of the retort. They are packed with ex-plosives that are detonated in the secondstep. A chimney-shaped underground retortfilled with broken shale results. The accesstunnel is then sealed, an injection hole isdrilled from the surface (or from a highermining level) to the top of the rubble pile. Thepile is ignited by injecting air and burningfuel gas, and heat from the combustion of thetop layers is carried downward in the gasstream. The lower layers are pyrolyzed, andthe oil vapors are swept down the retort to asump at the bottom from which they are

pumped to the surface. The burning zonemoves slowly down the retort, fueled by theresidual carbon in the retorted layers. Whenthe zone reaches the bottom of the retort, theflow of air is stopped, causing combustion tocease.






retort 6 began in 1978, but the sill pillar—thelayer of unbroken shale that caps a retort—collapsed into the rubble pile. Operationswere disturbed while the top was resealed,but retorting was eventually completed, andabout 40 percent of the oil was recovered.DOE will share the costs of retorts 7 and 8,which are scheduled for 1980 and 1981,

The oil shale at the Logan Wash site is notconsidered to be of commercial quality be-cause of its low kerogen content. In 1976, Oxyacquired access to the higher quality re-sources of tract C-b by exchanging its tech-nical knowledge for a half interest in thelease. In 1978, Ashland Oil Co., Oxy’s partnerin the C-b Shale Oil Venture, withdrew andleft Oxy in full charge. In 1979, Tenneco OilCo. purchased a half interest in the lease for$110 million and is proceeding to develop the

tract in cooperation with Oxy, If presentplans are followed, Oxy’s technology could beused to produce about 57,000 bbl/d by 1985.

Oxy’s technique uses a vertical burn con-figuration— that is, the combustion zone pro-gresses vertically through the shale bed. It isalso theoretically possible to advance theburn front horizontally, in much the sameway as it is done in TIS processing. A crudeversion of this approach was implemented inGermany during World War II, when a fewMIS retorts were created by digging tunnelsinto oil shale deposits and then collapsingtheir walls into the void volume. These opera-tions were short-lived because oil recoverieswere extremely low, and they were very hardto control.

19

Horizontal MIS might be practical if a tech-nique could be developed to remove large sec-tions of oil shale strata. One possibility is touse solution mining: the injection of fluids intothe formation to dissolve soluble salts fromamong the oil shale layers, The result wouldbe a honeycomb pattern of voids that couldthen be distributed throughout the area to be

retorted by injecting and detonating an explo-sive slurry. This method would be limited toareas like the Leached Zone or the SalineZone that contain significant concentrationsof soluble salts. Other methods, such as long-

wall mining or mechanical underreaming,could be used in other areas. It might be pos-sible to operate mechanical underreamingmachines by remote control from the surface,thus reducing or even eliminating the needfor miners to work underground. None of these approaches has been tested in any oilshale deposit.

Other MIS techniques that use vertical-burn patterns have also been developed. Forexample, the firm of Fenix and Scisson de-signed two systems for underground mining,rubbling, and retorting in the vertical mode. z’)

To date, they have been tested only with acomputer model. DOE’S Lawrence LivermoreLaboratory has also developed an MIS tech-nique called rubble in situ extraction (RISE)with the aid of computer simulation and lab-oratory experiments in pilot-scale above-

-ground retorts.21-23

(See figure 28. ) Severallevels are mined, and a portion of the depositis removed at each. The remaining shale isbroken with explosives. Sufficient brokenshale is then removed so that there is a totalvoid volume of 20 percent in the retort area.The rubble is then ignited at the top, and re-torting proceeds as in the Oxy system.

The RISE approach was originally pro-posed by Rio Blanco Oil Shale Co. for tractC-a, but the firm is now going ahead with itsown process, which has benefited from tech-

nical information acquired under a licensingarrangement with Oxy. Livermore’s modelingstudies and laboratory experiments are con-tinuing.

The initial plans for developing tract C-a byMIS methods are shown in figure 29. Theywould have involved five precommercial re-torts of increasing size. The present plan,which was adopted after purchase of Oxy’sMIS technology, is shown in figure 30. In thenew development plan, a small pilot retort(retort “O”) will be followed by two demon-stration retorts of increasing size. The largest

(retort “2”) will be close to commercial scale.Several options of different size are beingconsidered for retort 2, with one option a re-tort with dimensions 60 ft by 150 ft by 400 fthigh, The method by which the shale is rub-






Figure 29.— Initial Modular MIS Retort Development Plan for Tract C-a

COMMERCIALFIELD 2 1

c’ ‘r

,,

. ’

r

~.,

)

,. -

.-

/ ‘> t -“

SOURCE RIO Blanco 011 Shale Project Revised Deta~/ed De~e/OP~eflt P/an Tracf C a Gulf 011 Corp and Standard 011 Co (Indiana), May 1977 P 125

bled, and the fraction of the shale that ismined from each retort area are two of themajor differences between the Rio Blanco ap-proach and Oxy’s technique. Oxy has testedseveral rubbling methods, including drillingblastholes up from a room at the bottom of theretort, drilling down from the top, and boringa central shaft the full length of the retortand then blasting the surrounding shale intothe shaft. In Rio Blanco’s approach, a roomwill be created at the bottom of the future re-tort, blastholes will be drilled from the sur-face into the roof of the room, and explosiveswill be detonated sequentially at differentlevels, The shale above the room will therebybe blasted loose in layers, with each layer of rubble falling to the bottom of the retort

volume before the next higher layer isblasted. Through this technique, Rio Blancohopes to obtain uniform size distribution inthe rubble. This is believed to be a key techni-cal requirement for efficient MIS retorting.Rio Blanco also proposes to mine twice thevolume (40 v. 20 percent) as is contemplatedby Oxy.

Another MIS method that is still being de-signed is the integrated in situ technology pro-posed by Multi Mineral Corp. for recoveringshale oil, nahcolite, alumina, and soda ashfrom oil shale deposits in the Saline Zone of the Piceance basin. This zone underlies theLeached Zone, is relatively free from ground




Figure 30.— Present MIS RetortDevelopment Plan for Tract C-a

\ Down-Hole

Escape%

Shaft

%=

I’HFVentilation Shaft

Off-Gas Shaft

- Access Shaft

figure 31, If technical and economic feasibili-ty is indicated during the test program, MultiMineral would proceed to a commercial-scalefacility that would produce 50,000 bbl/d of shale oil, 10,000 ton/d of nahcolite, 1,000ton/d of alumina, and 20,000 ton/d of sodaash.

The Multi Mineral approach resembles theRISE technique in that mining and rubblingare conducted at several levels along theheight of the retort, It departs from RISE inthat, after rubbling, the broken shale in theretort is removed from the bottom, crushedand screened, and returned to the top in acontinuous operation. This part of the retortdevelopment plan is shown in figure 32. Therubbled shale will contain free nahcolite and

+1 I I Ill I I I I I I z SeDarator

Figure 31 .— Retort Development Plan for theMulti Mineral MIS Concept

SOURCE The Pace Co Consultants and Engineers Inc Cameron Synthe(lcFue/s Report VOI 16 No 3 September 1979 p 28

water, and contains extensive resources of nahcolite and dawsonite in addition to oil

shale. Development is hindered because thezone is deeply buried (about 2,000 ft) belowthe surface of the basin. To reduce the costsof its R&D program, Multi Mineral has pro-posed to use an 8-ft-diameter shaft that wasdrilled by USBM in 1978 through the LeachedZone and into the Saline Zone. In the firstphase, mining and mine safety methods willbe tested, and about 8,000 tons of nahcoliteand 11,000 bbl of shale oil will be produced.The nahcolite will be used for stack-gasscrubbing tests in a powerplant. In the sec-ond phase, a retorting module will be used toproduce up to 3,000 ton/d of nahcolite, 10,000bbl/d of shale oil, 200 ton/d of alumina, and3,000 ton/d of soda ash. The modular retortand the access shafts and drifts are shown in

--(LEVEL B).-

(LEVE~D;- -

CROSS CUT

STOPE FLOOR

SOURCE B Welchman, Sa//ne Zone 0// Sha/e Deve/opmen/ by [he /nlegrated /n S/fU Process Multi Mineral Corp Houston Tex December 1979.p 9



Ch 5– Technology q 13 7

Figure 32.— Preparation of a Multi Mineral

MIS Retort

I

< HOLE NO. 1

HOLE NO. 2 ®

BACKFILLED n

SHAFT

2200’ \)/ LEVEL

\

w\

SOURCE B We(c hman Sa/~ne Zone O() Shd/e Deve/oprnent by fhe /nlegrd(edIn SJtu Process M u It I M I neral Corp H o uston Tex December 1979

D 15

nahcolite that is still associated with thelarge blocks of shale. Crushing will liberatemost of the associated nahcolite, and screen-ing will separate it from the shale particles.The shale will be backfilled to the top of theretort; the nahcolite is transported to the sur-face for processing. The result would be a re-tort that is filled with uniformly sized oil shaleparticles. With this configuration, Multi Min-eral hopes to avoid the channeling and by-passing problems that may occur in TIS andMIS processing.

In a commercial-scale facility, the retortswould be operated in sets of three, as shownin figure 33, In retort 3, the oil shale is beingpyrolyzed by injecting hot gases to produceshale oil (which is removed to the surface),

residual carbon, and soda ash and aluminumoxide—the products of the thermal decompo-sition of dawsonite. The last three productsremain in the retort rubble. In retort 2, the re-sidual carbon is being gasified by injecting amixture of steam and air. The heat from thegasification reaction is carried to retort 3. Inretort 1, the hot gasified shale is being cooledby passage of cold recycle gas. The heat thusrecovered is conveyed to retort 2. After theshale in retort 1 is cooled, the soda ash andthe aluminum oxide can be leached out withwater. The leachate is then pumped to thesurface and processed to recover its mineralvalues.

Temperature control is the key to the entireoperation. Oil alone could be recovered witha combustion-type method, such as Oxy’s, but

because of the high temperatures, the decom-position of the dawsonite would produce com-pounds insoluble in water. The gas-recycleheating method would avoid this problem bymaintaining lower retorting temperatures.The operation also depends on the ability of explosive rubbling techniques to producebroken shale that can be fed to conventionalcrushing equipment. Overall, the method isvery interesting because of its potential forsimultaneously recovering fuel and mineralsfrom deposits that may not be accessible withany other approach. However, too little is

known about the various steps to permit athorough evaluation at this time.

Aboveground Retorting

Hundreds of retorts have been invented inthe 600-year history of oil shale development.Most were never brought to the processingstage but some were tested using laboratory-scale equipment, and a few at pilot-plant andsemiworks scales. None has been tested at ascale suitable for modern commercial opera-tions. This section summarizes the technicalaspects of seven retorting systems that offerthe promise of being applicable in the nearfuture. One obsolete technology that is thebasis for severalalso discussed.

of the modern systems is

l – <. . . - 1




Figure 33.— A Set of Multi Mineral MIS Retorts

EXCESSGAS

RETORT 1 RETORT 2 (RETORT 3(HEAT RECOVERY) (CARBON RECOVERY) (PYROLYSIS) tI

COLD RECYCLE GASI ‘;

TK===========--====-=------=="*----=---*==---------; I

il,1

iI I

II

OIL

I

t11,1,

1,

; 1

I i

t

1 ,

I, 1

--- - ----- a

SOURCE B Welchman, Sa//rre Zone” 0(/ Shale Deve/oprnerrf by the Irrtegrafed In SIfu Process, Multl Mineral Corp , Houston, Tex December 1979, p 11

Although aboveground retorts differ wide-ly with respect to many technical details andoperating characteristics, they can begrouped into four classes:

Class 1: Heat is transferred by conduc-tion through the retort wall. The Pump-herston retorts used in Scotland, Spain,and Australia were of this class, as isthe Fischer assay retort that was devel-oped in the 1920’s. It is a laboratorydevice for estimating potential shale oilyields. Its oil yield is the standard to q

which the retorting efficiencies of allother retorts are compared. Becauseconduction heating is very slow, no mod-ern industrial retorts are in class 1.

Class 2: Heat is transferred by flowinggases generated within the retort bycombustion of carbonaceous retortedshale and pyrolysis gases. Retorts in thisclass are also called directly heated.

They include the Nevada-Texas-Utah(NTU) and Paraho direct processes de-scribed below, and also USBM’s gascombustion retort and the Union “A”

retort. Class 2 retorts produce a spentshale low in residual carbon and low-Bturetort gas. Their thermal efficiencies arehigh because energy is recovered fromthe retorted shale. However, recoveryefficiencies are relatively low—about 80to 90 percent of Fischer assay.

Class 3: Heat is transferred by gasesthat are heated outside of the retort ves-sel. Retorts in this class are also calledindirectly heated. They include the Para-ho indirect, Petrosix, Union “B,” and Su-

perior retorts discussed below, and alsothe Union SGR and SGR-3, the obsoleteRoyster design, the Soviet Kiviter, theTexaco catalytic hydrotort, and others.These retorts produce a carbonaceous



Ch. 5–Technology q 13 9

spent shale and a high-Btu gas. Thermalefficiencies are relatively low becauseenergy is not recovered from the residu-al carbon, but oil recovery efficienciesare high, from 90 to over 100 percent of Fischer assay.

q Class 4: Heat is transferred by mixinghot solid particles with the oil shale.They include the TOSCO II and Lurgi-Ruhrgas retorts described below, andalso the Soviet Galoter retort. Class 4 re-torts achieve high oil yields (about 100percent of Fischer assay) and produce ahigh-Btu gas. The spent shale may ormay not contain carbon, and thermal ef-ficiencies vary, depending on whetherthe spent shale is used as the heat car-rier. The retorts are sometimes referredto as indirectly heated, as in class 3, be-

cause they also lack internal combus-tion, and produce a similar gas product.

Several other conversion methods have beendeveloped that cannot easily be placed inthese classes. These include microwave heat-ing, bacterial degradation, gasification, andcirculation of hot solids slurries. Althoughsome of these processes have potentially val-uable characteristics, they will not be dis-cussed in this section because they have notyet been proposed for near-term commercialapplication.

The Nevada-Texas-Utah Retort

The NTU retort is a modified downdraftgas producer similar to units used in the 19thcentury to produce low-Btu gas from coal. Itis a vertical steel cylinder, lined with refrac-tory brick and equipped with an air supplypipe at the top and an exhaust pipe at the bot-tom. The top may be opened for charging abatch of shale; the bottom for discharging thespent shale after retorting. The unit was de-veloped and tested for oil shale processing bythe NTU Co. in California in 1925, and wasalso tested by USBM at Rifle, Colo., from 1925to 1929. Two units with nominal capacities of 40 tons of raw shale were built and operatedby USBM at Rifle between 1946 and 1951.They produced more than 12,000 bbl of shale

oil. Three units that were operated in Austra-lia during World War 11 produced nearly500,000 bbl. As noted previously, USBM usedtwo units to simulate in situ retorting.

The operating sequence for the NTU retortis shown in figure 34. The unit is loaded with

crushed oil shale and sealed. The gas burneris lighted, and air is blown in. Once the top of the shale bed is burning (step A), the fuel gasis shut off but the air supply continues. As theair flows through the burning layer, it isheated to approximately 1,500° F (815° C).This hot gas heats the shale in the lower lay-ers and induces the pyrolysis of the kerogen.The oil and gases produced are swept downthrough the cooler portions of the bed to theexhaust port (step B). The solid product fromthe conversion of the kerogen (residual car-bon) remains on the spent shale and is con-

sumed as the combustion zone moves downthe retort, providing fuel for additional com-bustion and thereby heat for additional pyrol-ysis. When all the carbon is burned from theupper layers of the bed, the four zones shownin step C are formed. The top layer containsburned and decarbonized spent shale. Thesecond layer is burning, releasing heat for py-rolysis in the third layer. In the bottom layer,the shale is being heated but is not yet at py-rolysis temperatures.

As time passes, the top layer expands

downward and the lower three zones moveuniformly down the retort. When the leadingedge of the combustion zone reaches the ex-haust port, oil production ceases, air injectionstops, and the retort is emptied. The dumpingof spent shale ash from the 40-ton NTU atLaramie is shown in figure 35. The entirecycle, from ignition to dumping, takes about40 hours.

NTU retorts are simple to operate, and re-quire no external fuel except for smallamounts of gas to start the retorting. Theycan process a wide variety of shales with oil

recoveries ranging from 60 to 90 percent of Fischer assay. They are unsuitable for mod-ern commercial applications because theyare batch units with high labor costs andsmall capacities. Over 600 150-ton retorts




Figure 34.—The Operation of an NTU Retort

r

AIR SUPPLY

BLOWER

h-GAS BURNER: ON

SHALE IGNITES:

ED

~1BURNER GAS AND

)

~1

SHALE OFF-GASHEAT REMAININGSHALE

1- BURNER FLUE GASSMOKE, AND FUMES

STEP A

E

— AIR S U P P L Y

BLOWER

GAS BURNER: OFF

STEP B

COMBUSTION ZONE;RESIDUAL CARBON BURNSIN AIR STREAM

PYROLYSIS ZONE:KEROGEN CONVERSIONWITHOUT FURTHERCOMBUSTION

PREHEAT ZONE:SHALE HEATED BYOFF-GAS TO BELOW

PYROLYSIS TEMPERATURE

LOW-BTU GAS AND OIL MISTTO SEPARATION EQUIPMENT

r

AIR SUPPLY

BLOWER

/%-

GAS BURNER: OFF

}SPENT SHALE ZONE:ALL RESIDUAL CARBON

}

BURNED

COMBUSION ZONE:RESIDUAL CARBON

1

BURNING

PYROLYSIS ZONE;KEROGEN CONVERSION

N!!iN\

l\ II

+

(

PREHEAT ZONE;

{

Y\ yt LOW-BTU GAS AND

OIL MIST

STEP C

SOURCE T A Sladek, Recent Trends In 011 Shale– Part 2 Mining and Shale 011 Extract Ion Processes, M(nera/ /ndustr/a/ Elu//ef/n VOI 18 No 1 January 1975 p 5

would be needed to produce 50,000 bbl/d of crude shale oil. In contrast, plants using someof the continuous technologies described be-low would require only about six retorts forthe same production capacity.

The Paraho Direct and Indirect Retorts

An NTU retort becomes a Paraho direct re-tort when it is turned upside down, made con-tinuous, and mechanically modified. The Par-aho retorts are based on USBM’s gas combus-tion retort which, in turn, evolved from theNTU retorts tested at Anvil Points in the late1940’s. The gas combustion process wastested in 6-, 10-, and 25-ton/d units by USBMbetween 1949 and 1955, and by a consortiumof six oil companies between 1964 and 1968.The Paraho direct retort is similar in design

to the gas combustion technology but it ismore likely to be commercialized.-It was de-veloped by Development Engineering, Inc.,(DEI) in the late 1960’s, and was tested forlimestone calcining in three cement kilns inSouth Dakota and Texas. Each kiln had a ca-pacity of 330 ton/d and was comparable tothe largest gas combustion retort tested bythe six oil companies.

After verifying the solids-flow character-istics of the Paraho technology in the lime-stone kilns, DEI leased the Anvil Points sitefrom the Federal Government in May 1972,

and began a 5-year program to develop thetechnology for oil shale processing. Fundingwas obtained from a consortium of 17 energycompanies and engineering firms. In returnfor a contribution of $500,000, each company



C h 5 – Technology q141

Figure 35.— Discharging Spent Shale Ash From a 40-Ton NTU Retort

.

SOURCE U S Department of Energy



14 2 q An Assessment of 0il Shale Technologies

was guaranteed a favorable royalty arrange-ment in any subsequent commercial applica-tion of DEI’s technology. The Paraho Develop-ment Corp. was formed to manage the proj-ect. * Two retorts, a pilot-scale unit 4.5 ft indiameter and 60 ft high and a semiworks unit

10.5 ft in diameter and 70 ft high, were in-stalled and tested after August 1973. Theywere used to produce over 100,000 bbl of crude shale oil, some of which was used forrefining and end-use experiments by DOEand the Department of Defense. Maximumthroughput rates reached about 400 ton/d inthe semiworks unit. Both direct and indirectheating modes were tested.

The Paraho retort is shown in figure 36,and the Anvil Points semiworks unit in figure37. In its direct mode, the retort is very simi-lar to the older gas combustion design. How-

ever, significant differences exist in the shalefeeding mechanism, in the gas distributors,and in the discharge grate. During operation,raw shale is fed to the retort through a rotat-ing distributor at the top. It descends as amoving bed along the vertical axis of the re-tort. As it moves, it is heated to pyrolysis tem-peratures by a rising stream of hot combus-tion gases. The oil and gas produced areswept up through the bed to collecting tubesand out of the retort to product separationequipment. The retorted shale retains the re-sidual carbon. As the shale approaches theburner bars, the carbon is ignited and givesoff the heat required for pyrolyzing addition-al raw shale. Passing beyond the burner bars,the shale is cooled in a stream of recycle gasand exits the bottom of the retort through thedischarge grate. It is then moistened and sentto disposal.

The retort may also be operated as a class3 retort. The configuration would resembledirectly heated operations except that airwould not be injected and the offgas steamwould be split into four parts after oil separa-

tion. One part would be the net product gas.Another would be sent through a reheatingfurnace and then reinfected into the middle of

*“ Paraho” is from the Portuguese words “para homen”’—for mankind.

Figure 36.— The Paraho Oil Shale Retorting System

RAWSHALE

(?w l t l -

1 OIL MISTSEPARATORS

- - - - -— -

MISTFORMATIONAND

PREHEATING- — --- - OIL

RETORTING OIL

ZONE PRODUCT ru

I I GAS ELECTROSTATIC-- — - --- t PRECIPITATOR

COMBUSTION F 1

ZONE-

4i

----—-RESIDUECOOLING

ANDGAS

PREHEATING \ - - - — - -

/v4

q

t * A A

RECYCLE GASBLOWER

AIR BLOWER

~ SpEED‘yCONTROLLER

RESIDUE

A. Direct Heating M o d e

RAWSHALE

OIL MiSTSEPARATORS

MISTFORMATION

ANDPREHEATING

——-—- — [~OILRETORTING OIL

ZONESTACK L

—

tGAS ELECTROSTATIC

- - — - —- < HEATER PRECIPITATOR

HEATING0

T RECYCLE GASi

—t

BLOWER

----- --RESIDUECOOLING PRODUCT GAS

ANDGAS

~REHEATIN$ AIR BLOWER—— — - -

c?-

‘)1(RESIDUE

B. Indirect Heating Mode

SOURCE C C Shlh, et al Techno/ogma/ Ovefv)ew Reporfs for Eight Sha/e 0//Recovery Processes report prepared for the U S Environmental Pro-

tection Agency by TRW under contract No EPA.600/7.79-075 March1979, pp 20 and 23




Figure 37.— The Paraho Semiworks Unit at Anvil Points, Colo.

SOURCE Paraho Development Corp




the retort. A third would not be reheated butwould be reinfected through the bottom of theretort to cool the shale before discharge. Thefourth would be used for fuel in the reheatingfurnace. All heat for kerogen pyrolysis wouldbe provided by the reinfected gases, and nocombustion would occur in the retort vesselitself.

To date, the Paraho retorting technologyhas been tested at about one-twentieth of thesize that would be used in commercial plants.Paraho would like to test a full-size moduleproducing about 7,300 bbl/d at Anvil Points,and has submitted a proposal to DOE for sucha program. Both direct and indirect heatingmodes would be tested. Permission has beenobtained from the Department of the Navy touse large quantities of shale from the NavalOil Shale Reserves for the program. An envi-

ronmental impact statement (EIS) is beingprepared for the project. Paraho has re-sponded to a DOE Program Opportunity No-tice for a $15 million engineering design studyof modular oil shale retorting, and wouldbase the design of the Anvil Points module onresults of the study. Outcome of the procure-ment has not yet been announced.

The Petrosix Indirectly Heated Retort

The Petrosix process was developed for theBrazilian Government by Petrobras, the na-

tional oil company, with the assistance of Cameron and Jones, Inc., a U.S. engineeringfirm, Russell Cameron, later president of Cameron Engineers, worked on the gas com-bustion program at Anvil Points, as did JohnJones, later president of Paraho. The systemis depicted in figure 38. Figure 39 is a photo-graph of the demonstration retort that hasbeen built and tested in Brazil. The retort is18 ft in diameter, and has a capacity of 2,200ton/d of Irati oil shale. It was built in 1972,and tested intermittently until quite recently.In 1975, a U.S. patent was issued for the proc-

ess, A 50,000-bbl/d plant is planned by theBrazilian Government, to be developed in atwo-stage project. The first stage would in-volve construction of a 25,000-bbl/d facilityabout 5 miles from the site of the demonstra-

tion plant near the city of Sao Mateus do Sulin the State of Parana. In the second stage,the full commercial plant would be built onthe same site, to include 20 Petrosix units,each about 33 ft in diameter. Brazil is notcommitted to either stage, but if financing isobtained in 1980, the first stage could be com-pleted by 1983 and the second by 1985. Inaddition to the shale oil, the plant wouldalso produce sulfur and liquefied petroleumgases. Preliminary plans are also being pre-pared for two additional commercial-scaleplants south of the present demonstrationplant in the State of Rio Grande do Sul.

Except for mechanical differences, thePetrosix retort is very similar to the Parahoindirect retort described above. This similari-ty is not surprising in view of the shared engi-neering heritage of the two systems. One

operational difference is that the Petrosixspent shale is discharged into a water bathand pumped in a slurry to a disposal pond.Paraho shale is discharged dry, with only alittle water added prior to disposal.

Little information has been released aboutthe demonstration program. Oil characteris-tics have been described, but these have littlerelevance to the processing of Green Rivershale. It can be predicted that the retortshould have high oil recovery efficiencies andproduce a retort gas with high heating value.

The spent shale would be carbonaceous. Inthe demonstration plant, recovery of energyfrom the spent shale was not possible be-cause of the slurry disposal method. In anycommercial plant, it is possible that the shalewould be burned in a separate unit to pro-duce heat for pyrolysis.

The Union “ B’ Indirectl y Heated Retort

The Union “B” retort is a class 3 retort thatevolved from the Union “A,” a class 2 retort,by the Union Oil Co. of California. Two other

systems, the SGR and SGR-3, have also beenproposed by Union, Union describes them allas continuous, underfeed, countercurrent re-torts. The “B” has not been field tested, butthe “A” was tested in Colorado in the 1950’s



Ch. 5–Technology q 14 5

Figure 38. —The Petrosix Oil Shale Retorting System

=ALGAS<” ’LSHALEFEED

PYROLYSIS

VESSEL

DISCHARGEMECHANISM

D

HIGH BTU GASFEED HOPPER

PRODUCT FOR

PURIFICATION

DISTRIBUTOR ELECTROSTATICPRECIPITATOR CONDENSER

q

CYCLONE

ISEPARATOR

HEAVYCOMPRESSOR

SHALE OILHOT

HEAVY

0 0 0 0 0 d ‘ A s

SHALE OIL9 \

WASTEWATER

HEATER

\ COOL GAS

WATER

JftJ -

SEAL SYSTEM

RETORTED SHALE SLURRYTO DISPOSAL

SOURCE 0// Sha/e Refer//ng Technology, prepared for OTA by Cameron Engineers, Inc , 1978

at up to 1,200 ton/d. Figure 40 is a sketch of the Union “B” design. It incorporates most of the design features of the “A.”

During operation, shale is fed through thebottom of the inverted-cone vessel. The re-torting process thereafter resembles that of acontinuous NTU retort. Hot gases enter thetop of the retort and pass down through therising bed, causing kerogen pyrolysis. Shaleoil and gas flow down through the bed. The oilaccumulates in a pool at the bottom, whichseals the retort and acts as a settling basinfor entrained shale fines. Oil and gas are

withdrawn from the top of the pool. The gasesare split into three streams. One is reheatedand reinfected to induce additional kerogenpyrolysis; one is used as fuel in the reheatingfurnace; and one is the net product. The shaleis discharged from the top of the retort andfalls into a water bath in the retorted shalecooler. From there it is conveyed to disposal.

The key to all of Union’s retorting systemsis the solids pump that is used to move the oilshale through the retort. In the “B” design,the solids pump is mounted on a movable car-riage and is immersed in the shale oil pool.





Ch 5– Technology . 147

TiT

A. The

rk!%

Figure 40.—The Union Oil “B” Retorting Process

Ii?

P-4

. “’=.+.’.’

AA-+--d 1

= OIL LEVEL

RETORTED SHALE/ DISCHARGE

\\\\\l\ll

th\\\\\\lllj?{!

r T—

r

TO WATER SEAL

7

RETORT* GAS

- R O C K P U M P

Mm * SHALE OIL

I

m

\ \ \ \~\\\ ‘ \ \ \\~. \ \ ’ \l\\ . ~. . .1 \ \ \ \ \“.’\\\\\\\\\\\\~.\

Retorting System

SHALE IN SHALE IN

I

SHALE IN SHALE IN

B. Hock Pump Detail

SOURCE 0/1 Strale Reforf/ng Technology, prepared for OTA by Cameron Engineers Inc .1978



148 . An Assessment of Oil Shale technologies

The pump consists of two hydraulic assem-blies that act in sequence. (See figure 40.)While the cylinder of one assembly is fillingwith oil shale, the other is charging a batch of shale into the bottom of the retort. When thisoperation is completed, the carriage moveshorizontally on rails until the full cylinder is

under the retort entrance. A piston thenmoves the oil shale in this cylinder upwardsinto the retort, while the other fills with freshshale from the other feed chute. The carriagethen returns to its original position and theprocess is repeated.

The “B” achieves high oil yields, and theretort gas has a high heating value, althoughmuch of it is consumed in the reheating fur-nace. The mechanical nature of the rockpump is troublesome because its movingparts would be subject to wear during opera-

tion. However, the pump is immersed in theshale oil pool, which should provide adequatelubrication. Union appears to be satisfiedwith its reliability.

In 1976, Union announced plans to build ademonstration plant on its private land in Col-orado. The “B” retort was to be used to pro-duce 7,000 bbl/d of shale oil from 10,000 ton/dof oil shale. Later, the announced capacitywas increased to 9,000 bbl/d. The demonstra-tion plant, called the Long Ridge project,would be the first step towards a 75,000-bbl/dcommercial-scale plant. Air quality permits

have been obtained for the modular plant,which could be completed before 1985. Con-struction has not begun because Union isawaiting financial incentives from the Feder-al Government.

The Superior Oil Indirectly Heated Retort

The Superior retort is unique among theaboveground retorts discussed in this sectionbecause it is designed for recovery of sodium-bearing minerals in addition to shale oil. Asdiscussed in chapter 4, the minerals nahcolite

and dawsonite occur in substantial quantitiesin portions of the Piceance basin. They arepotential sources of sodium bicarbonate,soda ash, and aluminum.

A block diagram for the Superior approachis shown in figure 41. In step 1, the minedoil shale is crushed to pieces smaller than 8inches and screened. About 85 to 90 percentof the nahcolite in the shale is in the form of distinct, highly friable nodular inclusions thatbecome a fine powder during the crushing

operation. This is screened from the coarsershale in step 2. The shale is then furthercrushed to smaller than 3 inches and is fed instep 3 to a doughnut-shaped traveling-grateretort, which includes sequential stages forheating, retorting, burning, cooling, and dis-charging the oil shale feed. The retort issketched in figure 42. In the heating section,oil is recovered by passing hot gases throughthe moving bed. In the carbon recovery sec-tion, process heat is recovered by burning theresidual carbon. In the cooling section, inertgases are blown through the bed of spent

shale, cooling the shale and heating the gasesfor use in the heating section. After dis-charge, the cooled spent shale is sent to otherunits in which alumina is recovered from cal-cined dawsonite and soda ash from calcinednahcolite. The alumina is shipped to offsitealuminum refineries; the soda ash to glassplants; and the nahcolite to refineries andpowerplants for use as a stack-gas scrubbingagent.

Superior chose the traveling-grate retortbecause it allows close temperature control,

important to maintaining dawsonite’s solubil-ity during the burning stage. Similar, simplerdevices have been used to sinter iron ore forsteelmaking and to roast lead and zinc sul-fides. Superior’s process has been tested foroil shale in pilot plants in Denver and Cleve-land. A commercial-scale plant would con-sume 20,000 ton/d of oil shale to produce10,000 to 15,000 bbl/d of shale oil, 3,500 to5,000 ton/d of nahcolite, 500 to 800 ton/d of alumina, and 1,200 to 1,600 ton/d of soda ash.

In the early 1970’s, Superior proposed tobuild a commercial-size demonstration plant

on its 7,000-acre tract in the northern Pi-ceance Basin. The deposit was to be devel-oped by deep room-and-pillar mining on sev-eral levels. The single retort was to produce




Figure 41 .— Block Diagram for theSuperior Multi Mineral Concept

14EH---TI I

I ISPENT SHALE

SHALE

STEP 2 STEP 3 STEP 4SHALE

NAHCOLITEASH

> OIL EALUMINA &

RECOVERY RECOVERY SODA ASHRECOVERY

q q q qNAHCOLITE OIL SODA ASH ALUMINA

SOURCE 01/ Shale Retorting Technology, prepared for OTA by Cameron Engl

neers, Inc .1978

11,500 bbl/d of shale oil, plus the byproductsdescribed above. Although the tract’s re-sources are extensive, its L-shaped configu-ration does not favor large-scale develop-ment. Superior therefore proposed to ex-change portions of the tract for adjacent landcontrolled by the Bureau of Land Manage-ment (BLM). Approval was delayed by BLMreview and by preparation of an EIS, a draftof which was recently released. In February1980, BLM denied the exchange because thetwo tracts involved were not considered tohave equivalent value. The decision is open toreview.

The TOSCO H Indirectly Heated RetortThe TOSCO II is a class 4 retort in which

hot ceramic balls carry heat to finely crushedoil shale, It is a refinement of the Aspecoprocess developed by a Swedish inventor.Patent rights were purchased by The OilShale Corp. (later Tosco) in 1952. Early devel-opment work was performed by the DenverResearch Institute, including testing of a 24-ton/d pilot plant. In 1964 Tosco, Standard OilCo. of Ohio (SOHIO), and Cleveland Cliffs IronCo. formed Colony Development, a joint ven-ture company, to commercialize the TOSCO IItechnology. Between 1965 and 1967, thegroup operated a 1,000-ton/d semiworksplant on its land near Grand Valley, Colo.,next to the site of Union’s semiworks opera-tions. In 1968, Colony prepared a preliminary

engineering design and cost estimate for acommercial-scale plant that would containsix TOSCO II retorts, and convert 66,000ton/d of oil shale into about 46,000 bbl/d of shale oil. In 1969, ARCO joined Colony, and asecond semiworks program began to testscaleup procedures and to evaluate environ-mental controls. The program continued untilApril 1972. Between 1965 and 1972 the semi-works plant converted 220,000 tons of oilshale into 180,000 bbl of shale oil.

In 1974, the 1968 cost estimate, which hadbeen updated in 1971, was further revised toincorporate operating data from the latterpart of the semiworks program and to ac-count for additional pollution controls. Theresulting cost estimate was about three timesas large as the previous estimate. This costescalation raised doubts about commercial

feasibility, and the project was postponed in-definitely. SOHIO and Cleveland Cliffs subse-quently withdrew from the Colony group.

Early in 1974, Tosco, ARCO, Ashland, andShell purchased a lease for tract C-b from theFederal Government. Initial developmentplans for the tract involved a plant similar tothat proposed for Colony’s private tract.These plans were also affected by the cost es-calations, and in 1976 suspension of opera-tions on tract C-b was granted by the Govern-ment. In 1977 Tosco and ARCO withdrew

from the tract. Shell withdrew in 1977. Ash-land, the remaining partner, teamed withOxy to develop the tract using MIS tech-niques.

Colony’s semiworks retort, which is aboutone-tenth of commercial scale, is shown infigure 43. The TOSCO II retorting system issketched in figure 44. Raw shale is crushedsmaller than one-half inch and enters the sys-tem through pneumatic lift pipes in which theshale is elevated by hot gas streams and pre-heated to about 500” F (260° C). The shalethen enters the retort, a heated ball mill, andcontacts a separate stream of hot ceramicballs. As the shale and balls mix, the shale isheated to about 950

0 F (5100 C), causing re-

torting to take place. Oil vapors and gases arewithdrawn. The oil is condensed in a fraction-




Figure 42.—The Superior Oil Shale Retort

COOLRECYCLE

GAS

SHALEFEED

HOTRECYCLE

S+LE HEATING

+

‘ A s -~ COOLRECYCLE

/GAS

1- --~---

1

SOURCE. 0// Sha/e Retorturg Tec/rno/ogy, prepared for OTA by Cameron Eng!neers, Inc , 1978 (after Arthur G McKee & Co j

ator. Some of the gases are burned in a heat-

er to reheat the ceramic balls to about 1,2000F (650° C). At the retort exit, the retortedshale and the cooled ceramic balls pass overa trommel, a perforated rotating separationdrum. The shale, which has been thoroughlycrushed during retorting, falls through holesin the trommel. It is cooled and sent to dispos-al. The larger balls pass over the trommeland are sent to the ball heater.

Oil yields exceeding 100 percent of Fischerassay have been reported for the TOSCO IItechnology. However, overall thermal effi-

ciencies are low because energy is not recov-ered from spent shale carbon, and much of the product gas is consumed in the ball heat-er. Tosco has patented processes to burn theretorted shale as fuel for the ball heater, thus

increasing energy recovery, and freeing

valuable retort gases for other uses.

the

The retort’s chief disadvantages are itsmechanical complexity and large number of moving parts. The ceramic balls are con-sumed over time. The need for a fine feed sizeresults in crushing costs that are higher thanthose of systems that can handle coarserfeeds. On the other hand, all crushing opera-tions produce some fine shale that could bescreened from the feed to coarse-shale re-torts and converted in auxiliary TOSCO IIunits. Disposal of TOSCO II spent shale

presents some problems because it is veryfinely divided and contains carbon.

At present Tosco is participating in twoprojects that are committed to its proprietary




Figure 43. — The Colony Semiworks Test Facility Near Grand Valley, Colo.

SOURCE Colony Development Corp




Figure 44.—The TOSCO II Oil Shale Retorting System

FLUE GAS PREHEAT SYSTEM

TO ATMOSPHERE4

STACK —

RAWCRUSHED

SHALE

WATER VENTURI BALLS

WET SCRUBBER

SEPARATOR FOUL WATER To

-h

z FOUL WATER

~ STRIPPER

CERAMIC u

BALLa NAPHTHA

HEATER:

SLUDGE”Fv< -

- HYDROCARBON ~ GAS OIL TO GAS 01 L

VAPORS HYDROGENATION

nHOT BALLS BOTTOMS OIL TO

:ACCUMULATOR DELAYED COKER

Q~u.w~

2wt-3-1 BALL CIRCULATIONE SYSTEM STACK

VENTURI

WETSCRUBBER

I

HOT FLUE GAS

PREHEAT SYSTEM HOT

(INCLUDES INCINERATOR) PROCESSED

SHALE

FLUE GAS+

*

cnnu CTFAM SLUDGE I

COOLER

“’++MOISTURIZER

MOISTURIZER4 SCRUBBER

r+)WATER STACK

VENTURI WETSCRUBBER

tSLUDGE

MOISTURIZED PROCESSED

- ‘+$%spOsALCOVERED PROCESSEDSHALE CONVEYOR

SOURCE 0// Shale Retorflng Technology prepared for OTA by Cameron Engineers, Inc , 1978.

retorting technology. The Colony project has The Lurgi-Ruhrgas Indirectly Heated Retortbeen mentioned previously. The other ven-ture, the Sand Wash project, is being devel- The Lurgi-Ruhrgas retorting system uses aoped on 14,000 acres of land in the Uinta class 4 retort in which hot retorted shale car-Basin leased from the State of Utah. Unlike ries pyrolysis heat to oil shale. The processthe Colony project, which has been sus- was developed jointly by Ruhrgas A. G. andpended pending resolution of economic uncer- Lurgi Gesellschaft fur Warmetechnik m. b. H.,tainties, Sand Wash is proceeding towards two West German firms that have been in-commercialization in compliance with the due volved in synfuels production for decades.diligence requirements of the State leases. A The process was developed in the 1950's forplant similar to the proposed Colony facility is low-temperature coal carbonization. A 20-

contemplated, but no schedule has been an- ton/d pilot plant was built in West Germany,nounced for its construction. At present, to test a variety of coals, oil shales, andwork consists of monitoring the environment, petroleum oils. European shales were testedand preparing to sink a mine shaft. in the late 1960’s, and Colorado oil shale in




1972. The plant has since been scrapped butsmaller retorts are available.

Coal processing plants using the Lurgi-Ruhrgas technique have been built in Japan,West Germany, England, and Argentina.There are also two Yugoslavian plants, each

built in 1963, with a capacity of 850 ton/d of brown coal. The Japanese plant is also of commercial size, and uses the process tocrack petroleum oils to olefins. No large-scaleoil shale plants have yet been built.

The retorting system is shown in figure 45.Finely crushed oil shale is mixed with hot re-torted oil shale in a mechanical mixer that re-sembles a conventional screw conveyor. Re-torting takes place in the mixer, and gas andshale oil vapors are withdrawn. Dust is re-moved from these products in a cyclone sepa-rator and oil is separated from the gas by con-densation. Retorted shale leaves the mixerand is sent to a lift pipe where it is heated toabout 1, 100° F (5950 C) in a burning mixtureof fuel gas and air. The hot retorted shale isthen sent back to the mixer, and the processis repeated.

High oil yields have been reported for theretort, and the product gas is of high quality.

Figure 45. —The Lurgi-Ruhrgas Oil ShaleRetorting System

WASTE HEAT

-OLIDS1 ~-~ FLUE GAS wAsTE

RECOVERY

OIL GASEOUS ANOLIQUID PRODUCTS

CONDENSER

DUST

MIXING SCREWTYPE RETORT SOLIDS

SURGE

LIFTBIN

PIPE

TO WASTE

~ AIR - FUEL

(!! Reqwed)

SOURCE 0// .Shale Retorf/ng Technology, prepared for OTA by Cameron Engtneers Inc 1978

Except for the mixer, the process is mechani-cally simple and has few moving parts. Itshould be capable of processing most oilshales, if they are crushed to a fine size. Thetwo major problems with the system appearto be accumulation of dust in the transferlines and dust entrainment in the oil. Dustycrude oil is not a severe problem because thedust is concentrated in the low-value residualproduct when the oil is subsequently refined.As with the TOSCO II process, requirementsfor a fine feed material will result in highcrushing costs. These costs would be partial-ly offset by the ability to process the fine frac-tion from any crushing process, includingthose used to prepare shale for coarse-shaleretorts.

In 1972, Lurgi proposed to develop its re-torting technologies with Colorado oil shale.

The program was not funded, but Lurgi’s in-terest in commercializing the technique hascontinued. In recent years Lurgi has beenworking with Dravo Corp. to interest U.S.firms in using the technology. At present, atleast one company—Rio Blanco—has ob-tained a license to investigate the use of Lurgi-Ruhrgas retorts. Present plans call forconstructing a modular Lurgi-Ruhrgas retortthat will be close to commercial size (2,200ton/d). It will be used to retort the shale thatwill be mined during the preparation of MISretorts on tract C-a.

Advantages and Disadvantages of

the Processing Options

The greatest advantage of TIS processingis that mining is not required, and spent shaleis not produced on the surface. The technical,economic, and environmental problems asso-ciated with above-ground waste disposal arethereby avoided. MIS does involve mining andaboveground waste disposal, although to alesser extent than with AGR. However, the

MIS waste is either overburden or raw oilshale. Both materials are found naturally ex-posed on the surfaces of deeper canyons inthe oil shale basins. Although raw shale haslow concentrations of the soluble salts, it doescontain soluble organic materials that could



154 . An Assessment of 011 Shale Technologies

be leached from the disposal piles. It shouldbe noted that the presence of spent shale un-derground has the potential to cause environ-mental problems because soluble salts couldbe leached by ground water. Therefore, envi-ronmental controls will also be needed forTIS and MIS methods.

Surface Facilities

TIS has another theoretical advantage inthat the required surface facilities are min-imal, consisting only of wells, pumps, gascleaning and product recovery systems, oilstorage, and a few other peripheral units.These facilities would probably resemblethose for processing of crude oil and naturalgas. MIS requires more facilities to supportthe mine and the waste disposal program.Aboveground processing, which uses thelargest number of facilities, causes the mostsurface disruption.

Oil Recovery

The advantage of AGR is that the condi-tions within the retorts can be controlled toachieve very high oil recoveries—approach-ing or even in some cases exceeding the yieldsachieved with Fischer assay retorts. Retort-ing efficiencies are usually lower for MISprocessing and much lower for TIS because

of the difficulty in obtaining a uniform dis-tribution of broken shale and void volume,which in turn, makes it difficult to maintainuniform burn fronts and leads to channelingand bypassing of the heat-carrier gases. Thefew estimates of the retorting efficiencies of TIS operations that have been published havenot been encouraging. (USBM achieved recov-eries of 2 to 4 percent in its field tests. ) MISretorting has not exceeded 60-percent recov-ery of the potential oil in the shale within the

retorts. It is expected that yields from MIS re-torts could be increased by injecting steam orhydrocarbon gases (as is done in Equity’s TISprocess), but it is doubtful that recoveries canreach those of carefully controlled above--ground retorts. On the other hand, the pres-

ent low efficiencies of MIS operations arepartially compensated for by their ability toconvert very large sections of an oil shale de-posit, by their ability to process shale of alower grade than would be practical for AGR,and by their lower cost of preparing the shalefor retorting.

It is difficult to compare overall recoveriesfrom MIS and AGR without making numerousassumptions about the operating characteris-tics of both systems. To make a rough com-parison, it could be assumed that AGR (withroom-and-pillar mining) and MIS were to beapplied to two 30()-f t-thick deposits with iden-tical physical characteristics. The net recov-eries from several development options aresummarized in table 18. The highest recovery(100 percent) is for full-subsidence mining inconjunction with AGR processing. It shouldbe noted that full-subsidence mining, foreither MIS processing or AGR, would resultin extensive surface disturbance and couldincrease risks to the miners. Subsidence min-ing has never been tested in oil shale. Its po-tential for surface disturbance could be re-duced by backfilling the mined-out areas withspent shale from surface processing, The re-torted shale in burned-out MIS retorts wouldalso reduce the severity of subsidence.

The three generic approaches to oil shaleprocessing also have various other advan-tages and disadvantages with respect towater needs, environmental effects, financialrequirements, and social and economic im-pacts. These aspects are discussed in the re-spective chapters of this report.




Table 18.–Overall Shale Oil Recoveries for Several Processing Options

First-stageCase retorting technology First-stage mining method

1 AGR Conventional room-and-pillar mining on three levels 60-ftrooms, 60-ft barrier and siII pillars.

2 MIS Conventional MIS mining. 40% of shale left behind in barrierpillars 20% of the disturbed shale IS removed to the surface

to provide void volume in the retorts3 MIS As in case 24 AGR As in case 1

5 MIS Full subsidence b6 MIS Full subsidence b7 AGR Full subsidence b

Second-stage processing

None

None

A GR processing of the mined shaleBarrier and siII pillars collapsed and

retorted by MISNoneAGR processing of the mined shaleNone.

Overall shaleoil recoverya

36%

29%

41 %,

74%

48%68%

100%

aAssurnlng AGR reco~ers 100 ~ercenl of the potential 011 In the shale retorted MIS assumed to recover 60 percent of the potential 011bEntlre deposit IS mned


Properties of Crude Shale Oil

Crude shale oil (also called raw shale oil,retort oil, or simply shale oil) is the liquid oilproduct recovered directly from the offgasstream of an oil shale retort. Synthetic crudeoil (syncrude) results when crude shale oil ishydrogenated. In general, crude shale oilresembles conventional petroleum in that it iscomposed primarily of long-chain hydrocar-bon molecules with boiling points that spanroughly the same range as those of typicalpetroleum crudes. The three principal differ-ences between crude shale oil and conven-tional crude are a higher olefin content (be-

cause of the high temperatures used in oilshale pyrolysis), higher concentrations of oxy-gen and nitrogen (derived from oil shale kero-gen), and, in many cases, higher pour pointand viscosity,

The physical and chemical properties of crude shale oil are affected by the conditionsunder which the oil was produced. Someretorting processes subject it to relativelyhigh temperatures, which may cause thermalcracking and thus produce an oil with a loweraverage molecular weight. In other processes

(such as directly heated retorting) some of thelighter components of the oil are incineratedduring retorting. The result is a heavier finalproduct. Others may produce lighter prod-ucts because of refluxing (cyclic vaporizationand condensation] of the oil within the retort.

One of the most important factors is the con-densing temperature within the retorting sys-tem—the temperature at which the oil prod-uct is separated from the retort gases, Thelower this temperature, the higher the con-centration of low molecular weight com-pounds in the product oil,

The properties of crude shale oil from sev-eral aboveground and MIS retorting proc-esses are listed in table 19.24 It is important tonote that the oils that are characterized wereproduced in small-scale test runs under con-

ditions that may not be representative of those that will be encountered in other areas,and with larger processing systems. The oilsfrom commercial-scale facilities in otherparts of the oil shale region may have proper-ties that are quite different,

The properties of the oil produced by dif-ferent AGR processes vary widely, but thedifferences between these oils and the in situoils are much more significant. In situ oils aregenerally much lighter, as indicated by theirhigher yields of material with relatively low

boiling points, and would produce more low-boiling product (such as gasoline) and lesshigh-boiling product (such as residual oil). Ingeneral, the low yields of residuum makeshale oils attractive as refinery feedstocks incomparison with many of the heavy conven-






tional crudes that are currently being proc-essed in the United States. For example, insitu oil from Oxy’s MIS process contains 1 to4 percent of material with a boiling range of over 1,000° F (5350 C), compared with 20 per-cent for crude from Alaska’s North Slope,

and 18 percent for Arabian Light crude.

25 26

Other foreign crudes, such as Kuwait andArabian Heavy, contain even larger residuumfractions. Oils from some AGR processes con-tain as much as 30 percent of residuumwhich, although higher than the contents of insitu crudes, is substantially lower than thatfor many conventional crudes.

Coal-derived liquids are often regarded asalternatives to shale oil feedstocks. However,syncrudes from coal have a much higher yieldof gasoline and low-boiling distillates thanshale oil, with little or no material boiling at

temperatures above 850° to 1,000° F (4550 to535° C), The coal liquids would be well-suitedfor gasoline production because their higherconcentrations of lower boiling constituentswhen refined would yield the desired lightnaphtha fractions. Shale oil, on the otherhand, has a much higher concentration of high-boiling compounds, and would favor pro-duction of middle distillates (such as dieselfuel and jet fuels) rather than naphtha, Shaleoil and coal-derived syncrudes should, there-fore, be regarded not as a competitive or sub-stitutable feedstocks but rather as comple-

mentary feedstocks, with each yielding a dif-

Shale Oil

Shale oil has been successfully refined inoil shale operations in Sweden, Scotland,Australia, West Germany, the U. S. S. R., andother countries, although on a relativelysmall scale and under unusual economic con-ditions. In the United States, the initial refin-ing research was conducted by USBM at the

Petroleum and Oil Shale Experiment Stationat Laramie, Wyo. It was coordinated with theearly development of the gas combustion re-tort at Anvil Points, Colo. The results of thiswork, plus the findings of other investigators,allowed a preliminary assessment to be made

ferent major fuel product from an equivalentamount of refining.

Among the negative characteristics of mostcrude shale oils are high pour point, highviscosity, and high concentrations of arsenicand other heavy metals and of nitrogen. The

pour point and viscosity are of economic im-portance because transporting viscous oilthat has a high pour point is difficult and cost-ly, thus suggesting the need for pretreatmentprior to marketing. * As shown in table 19, insitu oils with their relatively low pour pointsand viscosities could be marketed withoutpretreatment but they would retain their highnitrogen contents. This would reduce theirvalue as refinery feedstocks and boiler fuels.

High concentrations of arsenic and othermetals are a disadvantage because they poi-

son refining catalysts, especially in hydro-genation units. They must be removed prior tocatalytic processing, and a variety of physi-cal and chemical methods have been devel-oped for this purpose.28 29 It should be notedthat the concentrations of heavy metals incrude shale oil will vary with the location of the deposit from which the oil is recovered.Oils from some sites may be relatively free of such contaminants.

* S o m e convention:]] (Iru(ics h:)~[’ ({)mpilr[ ] t)l} h]gh pour

points. For example, the Alt[~mon I crude from Ut:)h hi]s ;{ pourpoint Of about 100° F (35° (;).

Refining

of the economic aspects of shale oil utiliza-tion, and justified continued efforts aimed atits recovery. In recent years, refining R&Dhas been revived because refiners now con-sider the availability of shale oil to be a dis-tinct possibility. There is also a need to per-form more precise and up-to-date economic

analyses.To date, refining studies have been con-

ducted on the upgrading of crude shale oil toa transportable product, and on the total re-fining of shale oil into finished fuels. The dif-




ference between these operations lies in thenature of the desired final product. As dis-cussed previously, some crude shale oils havepour points and viscosities that make trans-porting them difficult and expensive. In somesituations, economic considerations may dic-tate that the crude shale oil be partially re-fined (upgraded) near the retorting site to im-prove its transportation characteristics. Inother instances, a developer may desire to ob-tain a complete array of finished fuels froman integrated processing facility located nearthe minesite. In this case, a total-refiningfacility would be considered rather than amore simple upgrading plant.

To date, upgrading experiments have beencarried out largely at the bench scale, andin relatively small pilot plants. Theoreticalstudies and computer modeling have also

been used to evaluate the expected perform-ance of three types of upgrading processes:thermal, catalytic, and additive. Thermalprocesses include visbreaking (a relativelymild treatment) and coking (a severe treat-ment). Mild thermal treatment will reducepour point and viscosity, but the oil will retainits initial amounts of nitrogen and sulfur. Incontrast, severe thermal treatment reducespour point, viscosity, and sulfur content andalso causes the nitrogen compounds to con-centrate in the heavier products. The proper-ties of the lighter products will thus be con-

siderably improved.In catalytic processes, the shale oil is re-

acted with hydrogen in the presence of a cat-alyst. Viscosity is reduced, and the nitrogenand sulfur are converted to ammonia and hy-drogen sulfide gases that can be recovered asbyproducts. In additive processes, blendingagents are added that reduce the pour pointand allow the crude to be transported bypipeline. Such pour point depressants havebeen added in several instances with success,but the technique is not yet highly developed.

Total refining studies have focused eitheron the needs of existing refineries that wouldhave to be modified for processing shale oil,or on those of newly built facilities that couldbe designed specifically for shale oil feed-

stocks. These studies differ in their approachto the analysis of refining requirements.Studies of existing refineries must considerthe equipment that is in place, and must allowfor the limited flexibility of this equipment forprocessing a feedstock that is different fromthe one for which the refinery was designed.Studies of specially built refineries, in con-trast, need not be biased in this manner, andcan draw upon any processing technique thatis available within the refining industry.However, both types of studies must makeassumptions about feedstock characteristicsand desired product mixes. These will varywith the location of the refinery, the nature of the market it serves, and the type of retortingfacility that supplies its feedstocks. The op-timal refining conditions for one set of as-sumptions will probably not be applicable toanother set. For example, a refining methodto maximize gasoline production from TOSCOII shale oil would not maximize diesel fuelproduction from Oxy’s in situ oil.

Numerous computer studies and bench-scale refining investigations have been con-ducted for a wide range of shale oil feed-stocks and operating conditions. The resultsof these studies can be extrapolated, withsome degree of caution, to predict theperformance of commercial-scale refineries.However, refining tests both in pilot plantsand in commercial-scale facilities, because of much higher costs, have focused on only afew feedstocks, and have been conducted forparticular sets of operating constraints. Ingeneral, each large-scale study has dealt onlywith oil from aboveground retorts or with oilfrom in situ operations, but usually not withboth types of feedstocks. The conclusions of all studies are highly dependent on the com-bination of feedstock and refining conditionsassumed. Caution must be used when apply-ing the results to different conditions.

Shale Oil Upgrading Processes

The treatment techniques that can be usedto improve the transportation properties of crude shale oil are briefly described below.






Additives

Chemicals may also be added to crudeshale oil to improve its transportation proper-ties. Pour point depressants have been suc-cessful in some instances, but this does notmean that they would always work. A chemi-

cal that is suitable for one type of oil may notwork at all with oil from another retortingprocess. Furthermore, pour point depres-sants are disadvantageous because they onlychange the physical characteristics of the oiland not its chemical properties. Thus, theircost can be offset only if they save transpor-tation costs.

Conventional petroleum crudes are otherpotential blending agents. Since shale oil (atleast in Colorado) will be produced in an areathat also contains petroleum reserves, andeven active crude oilfields, the possibility ex-ists that the light petroleum crudes could bemixed with crude shale oil to form a trans-portable blend. The feasibility of this conceptis unclear because, in general, the blendwould not be as valuable as a refinery feed-stock on a per-unit basis as would the petro-leum alone. However, the decrease in unitvalue would be offset by the increased vol-ume. In the case of a refinery that does nothave a reliable supply of crude, this could bea significant advantage.

Total Refining ProcessesThe three primary factors that affect the

design of a refining system are:

. the characteristics of the crude shale oilfeedstock;

q the desired mix of finished products; andq the constraints imposed by the equip-

ment and operating practices of the pro-posed refinery.

The first factor probably will have the lowesteffect because, except for the higher nitrogen

and arsenic contents, the characteristics of crude shale oil are not widely different fromthose of conventional petroleum. The secondfactor—the product mix—is much more sig-nificant. This is evidenced by the changes

that have occurred in the proposed configura-tions of shale oil refineries since the 1950’s:the earlier studies placed much more empha-sis on gasoline production. For example, earlydesigns by USBM called for the extensive useof middle-distillate cracking and reforming toyield gasoline, The ratio of gasoline to distil-

late yields was nearly 3 to 1. 31 Most of therefinery configurations that have been pro-posed more recently indicate a gasoline-to-distillate ratio of about 1 to 4.”

The third factor—equipment and operat-ing constraints—has become increasingly im-portant in recent years. The modifications toconvert a conventional refinery to shale oilfeedstocks might not be economically justifi-able unless the refiner could be assured of anadequate supply of shale oil. The economicdesirability of building a refinery specifically

for shale oil would be thoroughly scrutinized.Modular retorts, or even a few pioneer com-mercial plants, would not produce enoughshale oil in the mid-term to justify a new refin-ery unless the refiner was assured that theoperations would continue until his invest-ment cost could be recovered. For this rea-son, the most recent studies have stressedmodifying existing facilities to make themsuitable for processing shale oil, rather thanbuilding new ones. In some cases, this entailsonly minor changes to installed equipment, inothers, the adaptation of an existing facility

by adding new units.The basic unit operations in crude oil refin-

ing are:

q coking,hydrotreating,distillation,hydrocracking,

q catalytic cracking, andq reforming.

The various refining schemes that have beenproposed for shale oil cannot easily be gener-

alized because, depending on both the de-sired product mix and the possible operatingconditions, many configurations could be de-signed that would achieve the same results.The one selected will largely depend on the






operating experience and evaluating the eco-nomics.

Chevron also investigated the possibility of substituting a fluidized catalytic cracker forthe hydrocracker in figure 48. A similar ap-proach was used by SOHIO in processing

85,000 bbl of Paraho shale oil at its Toledorefinery.35 The chief difference between theSOHIO runs and the Chevron experiments isthat SOHIO used an acid/clay treatment toupgrade the distillation products into jet fueland marine diesel fuel for military applica-tions. The residuum fraction from the columnwas used for fuel in the refinery.

The approach in which the crude oil isfractionated before hydrogenation or othertreatment is shown in figure 49. This scheme

Figure 49.— Refining Scheme Employing InitialFractionation, Used by SOHIO in Prerefining Studies

SOURCE. G L Baughman, The Refining and Market/rig of Crude Shale 0//

was used by SOHIO during the prerefiningstudies carried out before 10,000 bbl of Para-ho shale oil were refined at the Gary Westernrefinery in Fruita, Colo.36 During the actualrefinery run, a combination coker/fraction-ator was used rather than the separate units

shown in the diagram.The shale oil must also be treated to re-

move excess amounts of water, ash, andheavy metals such as arsenic. Water must beremoved because it can cause cavitation in

pumps and explosions in processing units.Ash, or particulate matter, must be removedto prevent its deposition in pipes, heat ex-changers, and catalyst beds. Recent studieshave shown that heating the crude oil toabout 165° F (75° C) then letting it stand forabout 6 hours allows the water and solid mat-ter to separate from the oil. As noted, arse-nic and other metals poison the hydrotreatingcatalysts. A variety of processes have beendeveloped for their removal; consequently,their presence no longer presents a technicalproblem. ARCO has patented several cata-lytic techniques and methods for heat treat-ing the oil in the presence of hydrogen. Re-cent studies by Chevron U.S.A. have shownthat an alumina guard bed preceding the hy-drotreater will effectively remove both arse-nic and iron from shale oil. 39

The quantity and quality of the fuels pro-duced will be determined by both the configu-ration of the equipment and the operatingconditions used in the refining step. The fuelsproduced by USBM at Anvil Points in the1940’s were quite satisfactory.’” However,some of the fuels from the Gary Western re-fining run in 1975 failed to meet certain mili-tary specifications, principally those for sta-bility. 41 This has been attributed to the ap-plication of refining techniques unsuitable forshale oil feedstocks, specifically inadequatehydrogenation. Subsequent refining tests at

SOHIO’s Toledo refinery show that, with ap-propriate refining, fuels can be produced thatare of superior quality and that can meet allapplicable specifications. 42

Cost of Upgrading and Refining

The most recent estimates of the cost of up-grading crude shale oil to a transportable re-finery feedstock have been prepared by Chev-ron U.S.A.43 The retorting complex that wasconsidered had a capacity of 100,000 bbl/d.

Conventional hydrotreating was the upgrad-ing technique evaluated. Chevron consideredtwo possible locations for the upgrading facil-ity: a newly built unit at the retorting site; anda unit to be added to an existing refinery atsome distance from the retorts. In both cases,




the estimated cost for upgrading 1 bbl of crude shale oil was $6.50, in first-quarter1978 dollars. The product would be a high-quality syncrude suitable as feedstock formost refineries in the United States.

It is more difficult to estimate the costs of the total-refining option for converting crudeshale oil into finished fuels. This is because inaddition to the properties of the crude oil con-sideration must be given to the location of po-tential refinery sites, the availability of refin-ing equipment, the proximity and stability of potential markets, the ease of product distri-bution, and other factors. Chevron consid-ered some of these in its analysis of refiningcosts, although in a relatively generalizedmanner. Three total-refining options and tworefining capacities and refinery locations

were considered. For a l00,000-bbl/d refin-ery located in an urban area in the RockyMountains (e.g., Denver), the refining cost

was estimated to range from $8.00 to $10.00/ bbl of crude shale oil. For a 50,000-bbl/drefinery located in a remote area of the RockyMountains (e.g., near the retorting facility),the refining cost would be approximately$10.00 to $12.00/bbl.* These are somewhat

higher than the costs for refining a high-qual-ity conventional crude oil because of the addi-tional amounts of hydrogen that would beneeded to reduce the nitrogen content of theshale oil crude.

Another study compared the cost of shaleoil refining with those of refining Wyomingsour crude oil and Alaskan crude. It was as-sumed that a refinery in the Rocky Mountainregion was modified for these feedstocks. Theincreased costs to refine crude shale oil,rather than the other crudes, was in the

range of $0.25 to $2.00/bbl.

44 45

*Costs are in first-quarter 1978 dollars.

Markets for Shale Oil

Crude shale oil has three major potentialuses: as a boiler fuel, as a refinery feedstock,and as a feedstock for producing petrochemi-cals, The output from a mature oil shale in-dustry will probably be used for all three pur-poses. However, the relative importance of the three markets will change with time asthe industry develops. In the mid-1980’s,when shale oil first becomes available in sig-nificant amounts, its most likely use will be asboiler fuel, with only a small quantity di-rected to nearby refineries that could be mod-ified to accommodate the feedstock withoutlarge capital expenditures. As more shale oilbecomes available, its use as a refinery feed-stock will increase as conventional petroleumbecomes scarcer. At a later date, when themarket for boiler fuels declines, shale oil willbegin to be used for petrochemical produc-tion.

Shale Oil as a Boiler Fuel

Shale oil will most likely first be used as aboiler fuel because of the relatively smallcapital investments and very short leadtimesthat would be required. Because of Govern-ment regulation, the current trend in the utili-ty industry is to replace oil- and gas-firedboilers with coal-fired units, thus freeing thenatural gas for domestic consumers. In someareas, it will be a two-stage transition, withthe gas first replaced by oil, and the oil laterby coal. During the transition, there maybe amarket for about 50,000 to 80,000 bbl/d of crude shale oil near the oil shale region. Inaddition, the refining industry has a small butsignificant demand for boiler fuel because re-fineries are also changing from natural gas tooil. Therefore, refineries located near the oil




shale region are likely to be near-term shaleoil customers. In the long run, the largestmarket for shale oil boiler fuel is likely to bein the Great Lakes States. Transportation dis-tances will probably preclude its use in theother two major markets for boiler fuels—the

east and west coasts.

Shale Oil as a Refinery Feedstock

There has been relatively little research onthe refining of crude shale oil because build-ing an oil shale plant takes about 5 to 7 years,whereas a refinery operator can evaluate anew potential feedstock in a few days, devel-op a feasible refining strategy within a mat-ter of weeks, conduct the necessary pilot-plant refining studies in a few months, andmodify the refinery to accommodate the new

feedstock in less than 3 years. Thus, neitherthe developer nor the refiner has any induce-ment to study shale oil refining until they aresure that the oil will, in fact, be forthcoming.

Another reason is that until quite recently,shale oil was not considered a highly desir-able refinery feedstock. During the 1950’sand 1960’s, the refining industry tended tomaximize gasoline yields at the expense of middle and heavy distillates. Because shaleoil is a good source of heavier distillates, notof gasoline, it was not highly regarded. How-ever, most projections indicate that gasolinedemand will peak in the early 1980’s and thendecline slightly, even though total demand forrefined products will continue to grow.46 Thiswill be the result of the increasing efficien-cies of gasoline engines in automobiles and of a greater use of diesel engines in automobilesand light trucks. Also, because the currentsupplies of conventional petroleum are be-coming more like shale oil with respect totheir distillate yields, the refining industry isbeing forced to adopt techniques that wouldbe equally suitable for shale oil.

For these reasons, shale oil’s desirability isincreasing, and its potential availability as apremium feedstock has encouraged the refin-ing studies that have been conducted byChevron and other organizations. These stud-

ies have dealt with four general types of refining facilities:

1.

2.

3.

4.

The

a new refinery just for shale oil;a new refinery for a mix of shale oil andconventional crude;an existing refinery modified for, and

dedicated to, shale oil; andan existing refinery processing a mix of shale oil and conventional crude.

first two approaches are precluded forthe foreseeable future because, as long as re-fined products continue to be imported, theUnited States will have excess refining ca-pacity. At least through the 1980’s, shale oilwill most likely be refined in existing refin-eries, either by itself or as a blend with con-ventional petroleum,

The shale oil produced by demonstrationfacilities will probably be processed in localrefineries* or in more distant refineriesowned and operated by the energy companiesthat participate in the oil shale programs.The much larger output from a commercial-ize industry will be more widely distributed;thus it will have to compete with other feed-stocks, at least regionally. Recent studieshave indicated that the Midwest is the mostlikely market area for large quantities of shale oil. This includes the States in the Petro-leum Administration for Defense District 2(PADD 2), as shown in figure 50. There willbe secondary effects in other districts, as aconsequence of the supplies of shale-derivedfuels in PADD 2, because the conventional pe-troleum that it displaces will become avail-able for use elsewhere.

The quantitative impact on the supplysituation in PADD 2 can be determined by re-fering to table 20, which indicates how thedistrict’s supplies of finished fuels were di-vided among domestic and foreign sources in1978. As shown, the district consumed about518,000 bbl/d of medium and heavy distillates

(jet fuels, diesel fuel, and distillate fuel oil)from foreign sources. According to Chevron’s

*’I’hese could include the Gary Western refinery in Fruita,

Colo., the Little America refinery in Rawlins, Wyo., the Chev-ron refinery in Salt Lake City, Utah, ond others.



Ch 5–Technology q 165

Figure 50.— The Petroleum Administration for Defense Districts

Includes Alaskaand Hawaii

SOURCE Natmna/ At/as, Department of the Intenor

Table 20.–Supply of Finished Petroleum Products in PADDs 2, 3, and 4 in 1978 (thousand bbl/d)a

P A D D 2 Midwest PADD 3 Texas and New Mexico PADD 4. Rocky Mountains —

Foreign Domestic Foreign Domestic Foreign Domesticsources sources Total sources sources Total sources sources Total

Gasoline. 976 1,540 2,516 422 604 1,026 33 219 252

Light ends 224 236 460 276 388 664 12 25 37J e t f u e l 81 131 212 50 71 121 7 29 36Kerosine 17 27 44 19 27 46 0 2 2D i s t i l l a t e f u e l o i l 420 672 1,092 194 279 473 13 113 126Residual fuel 011 150 173 323 237 340 577 4 38 42Petrochemical feedstocks. 18 26 44 211 298 509 0 1 1

Special naphthas and still gas 60 98 158 114 165 279 2 14 16O t h e r s 138 232 370 102 146 248 4 31 35

Total 2,084 3,135 5,219 1,625 2,318 3.943 75 472 547

ap,ADO = pe/rOleum ,4dmlfllSlfa10fl tor Defense Dlstrlcl

SOURCE G L Baughman The Refmmg and Markef~ng of Crude Sha/e 01/

studies, refining will convert about 74 per- tricts. The same size industry would producecent of a crude shale oil feedstock to similar about 170,000 bbl/d of gasoline, which woulddistillates.” A l-million-bbl/d industry would be equivalent to about 17 percent of the dis-

yield about 740,000 bbl/d of medium and trict’s gasoline currently obtained from for-heavy distillates. If it were marketed in PADD eign sources.2, this production would completely displacethe foreign supplies and free an additional An alternative marketing strategy would222,000 bbl/d of the fuels for use in other dis- be to sell the output from a major shale oil in-




dustry in PADD 4—the Rocky Mountain re-gion—and to supply any surplus fuels to adja-cent districts such as PADD 2 or PADD 3(Texas and New Mexico). As shown in table20, the Rocky Mountain district consumes rel-atively little distillate fuel (about 20,000bbl/d) from foreign sources. A l-million-bbl/d

shale oil industry could easily displace thisentire supply. The surplus production (about720,000 bbl/d) could displace about 95 per-cent of the supply of foreign-derived distil-lates in both PADD 2 and PADD 3. The gaso-line derived from the shale oil could supplyabout 67 percent of the total gasoline demandin the Rocky Mountain States.

As indicated previously, the capabilities of the refineries in the Midwest and the RockyMountain States will strongly affect the will-ingness of the refiners to accept shale oilfeedstocks. In some cases, shale oil could notbe accommodated without significant invest-ments of capital. However, the receptivity of refiners to shale oil will also be influenced bythe reliability of other feedstocks such as for-eign petroleum. The area in which the sup-plies of crude are most uncertain is the north-ern tier of States, which includes Montana,North and South Dakota, Minnesota, andWisconsin. These States have historically de-pended on refinery feedstocks from Canada,but, in recent years, a significant reduction inthese supplies has led the refiners in thisarea to look elsewhere. The result has beenthe present interest in building a pipeline totransport crude from Alaska and from for-eign nations into the area. An alternative—apipeline from the oil shale region—could alsobe built as the oil shale industry developed.

The area that covers Iowa, Missouri, Illi-nois, Indiana, Michigan, and Ohio also doesnot have an adequate indigenous supply of crude. However, unlike the northern tier,these States have good pipeline systems withadequate access to both foreign and domesticcrude supplies. The feasibility of marketing

shale oil in this area will largely be deter-mined by the cost differential between it andother crude supplies and by the differences inthe reliability of its supply versus that of

foreign crude. Recent marketing studies haveidentified several large refineries in this areathat, with only minor modifications would beable to handle crude shale oil. 48 Furthermore,some of the refineries only have access to theheavier petroleum crudes at present, andtheir production is being limited by their ca-

pacity to process the large quantities of resid-uum from the distillation of these fuels. Shaleoil, with its relatively small yield of bottomsfractions, would help alleviate this problem.

Shale Oil as a Petrochemical Feedstock

Three principal factors must be consideredin evaluating the suitability of shale oil sup-plies for producing petrochemicals:

q the yields of petrochemicals from shaleoil feedstocks;

the ability of existing and future petro-chemical plants to process the shale oil;and

q the logistics of supplying the shale oil tothe plants.

Because shale oil is produced by pyrolysis, itsolefin content is approximately 12 percent,which is appreciably higher than convention-al crudes. Together with its fairly high hydro-gen content, these characteristics make shaleoil, and its hydrogenated derivatives, appro-priate feedstocks for petrochemical produc-tion.” 50 Steam pyrolysis has been used toprocess crude shale oil, and the yields of olefin products have been comparable withthose from many conventional crudes. Shaleoil syncrudes, with even higher olefin yields,are considered to be premium petrochemicalfeedstocks. These conclusions are based onlaboratory studies under carefully controlledconditions. The feasibility of marketing shaleoil to the petrochemical industry depends onthe ability to replicate these conditions incommercial chemical plants.

Historically, the primary feedstock for pet-

rochemical plants has been natural gas liq-uids from the gulf coast. Because crude shaleoil is quite different from these liquids, itwould be difficult to switch traditionally de-




signed petrochemical plants to shale oil. How-ever, the production of domestic natural gasand its associated liquids is declining, and thepetrochemical industry is shifting to heavierfeedstocks such as naphtha and gas oils. Thesupplies of these feedstocks are uncertainand irregular. The availability of naphtha has

been affected by a growing demand for itsuse as a gasoline blending agent in responseto the phasing out of tetraethyl lead. Gas oilsare also being used more frequently for homeheating fuels, which causes seasonal varia-tions in their availability. Because of thesesupply uncertainties, new petrochemicalplants are being designed to be highly flexiblewith respect to feedstocks. As using heavierfeedstocks becomes more common in the in-dustry, shale oil may become a highly re-garded raw material.

The use of shale oil for petrochemical pro-duction is hampered by the distance betweenthe oil shale region and the petrochemicalplants. While refineries and oil-fired boilersare distributed fairly uniformly across the

United States, the petrochemical industry isconcentrated on the gulf coast. This concen-tration will continue into the foreseeable fu-ture. Therefore, it will be necessary to eithermove the shale oil to the coast, or to builda new petrochemical complex in the RockyMountain region. In the latter case, the half-

finished products from the new plant wouldstill have to be transported to the coast forfinal conversion to commercial chemicals.The former approach is more likely but is im-peded by the lack of a product pipeline sys-tem between the oil shale region and the gulf coast, and by the high cost of alternativemodes of transportation.

In summary, tests have shown that crudeshale oil and its derivatives could be used toproduce petrochemicals. However, these ma-terials cannot be considered to be viable feed-

stocks in the near future because existingchemical plants are generally unable to proc-ess them and there is ‘no economical transpor-tation link between the oil shale region andthe existing petrochemical plants.

Issues and Uncertaint ies

The technological readiness of the majormining and processing alternatives is summa-rized in table 21. Estimated degrees of read-iness are shown as judged by DOI in 1968,51

and as they appear under present conditions.There are significant differences between thetwo evaluations because much R&D work hasbeen conducted in the interim, and becausetwo new processing methods—MIS retortingand concurrent recovery of associated min-erals—have since entered the picture. Asshown, room-and-pillar, open pit, and MISmining methods are regarded as reasonablywell-understood. Open pit mining has notbeen tested with Green River shales, but it ishighly developed for other minerals such as

copper and iron ores. It was evaluated onpaper for application to the shales on tractC-a. Some highly relevent experience hasbeen obtained from the operation of large-scale lignite (a form of coal) mines in West

Germany. 5z In these operations, the lignite iscovered by 900 ft of overburden, and strip-ping operations will soon extend to 1,600 ft.This is comparable to the oil shale deposits,which are covered by a maximum of about1,800 ft of overburden.

Nevertheless, uncertainties remain withrespect to the effects of shale stability andstrength on mine design, mine safety, and re-source recovery. The effects of large inflowsof ground water, such as have been encoun-tered on tract C-a, could pose severe opera-tional difficulties, especially with under-ground mines. In all mines, the logistics asso-ciated with moving many thousands of tons of

raw material and solid wastes could presentsome formidable problems. Materials-han-dling systems exist that could be applied, butthey have yet to be tested in commercial oilshale operations.



. .


Table 21 .–Technological Readiness of Oil Shale Mining, Retorting, and Refining Technologies

Technological readiness

Unit operation In 1968 In 1979 Developments in the Interim Remaining areas of uncertainty

Mining Room and pillar

M I S

O p e n p i t

O t h e r

Retorting A b o v e g r o u n d

T I S

M I S

Multimineral

Upgrading and refining. . . . . . . . .

Medium

Unknown

Low

Low

Medium

Low

Unknown

Unknown

High

Medium

Medium

Medium

Low

Medium

Low

Medium

Medium

High


Mine design studies. Experience of Colony,Mobil, and the six-company program at AnvilPoints

Oxy experience at Logan Wash Mine designstudies.

Established procedure for other mineralsLarge-scale mines in West Germany. Minedesign studies for tract C-a,

Mine design studies No field experience

Pilot studies for Lurgi-Ruhrgas Semiworksprograms by Colony and Paraho Detaileddesigns by Colony and Union.

Field work and lab tests by USBM. Field testsby Equity, Geoknetics, and Talley-Frac.National lab support

Oxy experience, Design studies for tracts C-aand C-b. DOE and USBM design studiesModeling and lab support by national

laboratories.Pilot plant studies by Superior USBM lab

tests of product recovery methods. Nahcolitescrubbing tests.

Studies and refinery runs by SOHIO/Paraho,Chevron, and others. Marketing analysesby Oxy and DOE.

AGR is regarded as having a medium levelof readiness, as it was in 1968. The under-standing of its technical aspects has been im-proved since then by field tests in the Pice-ance basin, but the largest tests conducted todate have been at the semiworks scale—about one-tenth of commercial size. Their re-sults do not permit accurate cost projectionsfor commercial-scale plants. Particular prob-lems are noted with respect to the effect of scaling up the semiworks design to commer-cial size. The on-stream factor—the fractionof the time that the retorts could be expected

to operate at design capacity—is unknown.The reliability of some associated systems(emissions controls, product recovery de-vices, materials-handling equipment) is alsoquestionable.

Rock mechanics Ground water Deep shalesLogistics.

Rock mechanics Ground water Deep shalesLogistics

Rock mechanics Logistics Reclamation

All areas

Effects of scaleup on stream factor and recov-ery. Characteristics of emissions streamsReliability of peripheral equipment Materialshandling.

Stream factor and recovery. Characteristics ofemissions streams Rock mechanics Deepshales.

Effects of scaleup on stream factor and recov-ery Characteristics of emissions streamsReliability of peripheral equipment Use of

low-Btu gas Rich shales. Mixed shales,Fracturing Rock mechanics Deep shales,Effects of scaleup on stream factor and recov-ery Characteristics of emissions streamsReliability of peripheral equipment, Materialshandling Integration of recovery stepsUnderground waste disposal Marketabilityof byproduct minerals.

Effects of retorting conditions on crudecharacteristics Cost effectiveness of alter-nate processes Use of pour pointdepressants Effects of metals

Although understanding has increasedsince 1968, TIS must still be regarded asbeing in the conceptual stage. Many uncer-tainties remain, especially with respect toeconomics and environmental effects.

MIS retorting, a new concept since 1968,has advanced to a medium level of technologi-cal readiness, approaching that of above--ground retorts. This progress is largely a re-sult of Oxy’s development efforts in Colorado,but additional understanding has been ob-tained through simulations by USBM, DOE,

and the national laboratories, most notablythe Lawrence Livermore and Los AlamosLaboratories. The remaining uncertaintiesare similar to those for aboveground retorts,except the materials-handling problems may






R&D Needs and Present Programs

R&D Needs

Mining

Room-and-pillar mining and mining in sup-

port of MIS operations have been tested withoil shale, and an extensive body of informa-tion has been assembled. To date, however,all of the field tests have been conducted inone area—the southern fringe of the Pice-ance basin. In each case, the deposit wasreached through an outcrop along a streamcourse. The limited area in which miningtests have been conducted is unfortunate be-cause the characteristics of deposits in otherareas are quite different. They may be moreor less favorable to mine development. Forexample, there is little ground water in the

southern fringe. In contrast, the deposits ontracts C-a and C-b, nearer the basin’s center,lie within ground water aquifers, and the in-flow of water into the mine shafts has been aproblem on tract C-a. Similar problems wereencountered at the USBM shaft in the north-ern part of the basin. Work on this site wasalso impeded by the presence of highly frac-tured zones, which are not common on thesouthern fringe.

Similar surprises could be avoided in fu-ture projects if the suitability of the candi-

date mining techniques for developing depos-its throughout the oil shale region were betterunderstood, especially in these areas wherenear-term development is likely. This infor-mation could be obtained through coring androck mechanics studies, mathematical simu-lation, and experimental mining. Field testingof mining methods would be expensive,although overall costs could be minimizedthrough developing a single site that could beused to test many mining alternatives. Asingle shaft or adit, for example, could beused to test room and pillar, longwall, block

caving, and other methods. It should be notedthat open pit mining, because of the necessityfor costly and large-scale operations, wouldprobably not be amenable to testing in a lim-ited field program.

TIS Retorting

TIS is the most primitive of the processingmethods. It has some potentially valuable fea-tures but these cannot be evaluated because

of a lack of information. The potential im-pacts on surface characteristics and groundwater quality are especially unclear. TheR&D needs include:

q

q

q

q

q

q

q

q

development of less expensive drillingtechniques;development of efficient and cost-effec-tive fracturing and rubbling techniques;development of methods for determin-ing the success of a rubbling programthrough, for example, surveys of the per-meabili ty increase that has been

achieved;development of ignition methods and of methods for maintaining a uniform burnfront;study of the effects of heat-carrier com-position, rate of injection, and tempera-ture on product recovery;study of the effects of creep* on retortstability and product recovery;determination of the effects of groundwater infiltration on retorting; andevaluation of the long-term potential forsurface subsidence.

Valuable information is being obtained in theEquity and Geokinetics projects, but these re-sults are applicable only to specific types of oil shale deposits— the Equity process toshale in the Leached Zone; the Geokineticsmethod to thin, shallow beds. Additional fieldwork in other types of deposits would aid inevaluating the potential of TIS methods forlarge-scale production. To minimize the costand duration of these tests, they could be sup-plemented with initial theoretical studies andlaboratory programs.

*Creep is the gradual change in the shape of a solid object in-duced by prolonged exposure to stress or high temperatures.




MIS Retorting

MIS is more highly developed, but moretesting is needed before its potential applica-tion to other areas of the Green River forma-tion can be determined. The R&D needs aresimilar to those for TIS. They are:

q

q

q

q

q

q

the development of better rubbling tech-niques;the development of improved remotesensing procedures for permeability,fluid flow, and temperature;the development of methods for creatingand maintaining a better burn front;evaluation of the effects of heat-carriercharacteristics;evaluation of the effects of creep andsubsidence; andexamination of the effects of ground

water infiltration, retort geometry, andparticle-size distribution.

Many of these needs will be addressed in theMIS programs on tracts C-a and C-b and theUSBM shaft.

Aboveground Retorting

Several candidate retorting processeshave been tested in Colorado, but only forrelatively short periods, and in small-scalefacilities, More R&D is needed, and particu-lar emphasis should be given to:

evaluating the effects of scaleup on theflow patterns of solids and fluids withinthe retort vessel;determining the reliability and effec-tiveness of peripheral equipment suchas solids-handling systems, pollutioncontrols, and product separators;examining the effects of heat-carriercharacteristics on product recovery andequipment reliability; anddetermining the reliability of mechanicalcomponents such as Union’s rock pump;

Tosco’s retort vessel, separation trom-mel, and ball elevator; the Lurgi-Ruhrgasscrew conveyor; and the raw shale dis-tributors and spent shale dischargegrates of all retorts that use gas as aheat carrier.

Some of these needs could be addressed byfurther laboratory-scale and semiworks test-ing. Others could be estimated by theoreticalcalculations and modeling. All of them and es-pecially the need for reliability studies, willeventually have to be addressed in full-scaleretorting modules, either alone or as part of acommercial-size complex.

Upgrading, Refining, and Distribution

Because crude shale oil is sufficientlysimilar to conventional petroleum crude, nosubstantial problems are anticipated in therefining area. R&D on the effects of heavymetals on refining catalysts and of retortingconditions on oil properties could be con-ducted in the laboratory, provided that re-torts were operating that could supply a prod-uct resembling the crude oil that will be pro-

duced in commercial operations,In the upgrading area, the major need is re-

lated to the feasibility of using chemical addi-tives to depress the pour point of crude shaleoil. The necessary R&D could be conducted inthe laboratory or in a pilot refinery, againassuming the availability of a representativecrude shale oil.

R&D is also needed to determine the opti-mum distribution pattern for the finishedfuels, which will vary with the size of the in-

dustry, the location of the facilities, the needfor various fuels and feedstocks, and theavailability of a transportation system. R&Dis needed to determine optimal plans for like-ly combinations of these factors. Work hasbegun in this area, and more work could beconducted at relatively low cost, since it istheoretical rather than experimental innature. However, it will not be possible todefine an optimum pattern for the actualfuture industry until the sites of the produc-tion facilities are designated.

The System

All manufacturing and processing plantspotentially suffer from a lack of systems reli-ability. Because of the scale of operations andthe need for the coordinated performance of



. . . . .


many components, it is certainly possible thatoil shale plants will have significant prob-lems. On the other hand, they may not bemore severe than in other, more conventionalindustries. R&D programs, such as mathe-matical simulations and industrial engineer-ing studies, would help to eliminate some of

the uncertainties regarding the expected per-formance and reliability of oil shale systems.Basic data on the lifetimes of equipment,operating characteristics, and other factorscould be obtained from those minerals proc-essing and refining plants that oil shale facil-ities will resemble. However, because of theunique character of oil shale operations, pre-dictions from these studies will be tentative.It will only be possible to define performancecharacteristics after large-scale oil shaleplants are operated at their maximum pro-duction capacities.

Present Programs

Some of the current R&D programs forindividual retorting technologies were de-scribed previously. An effort that has notbeen discussed in detail is DOE’s integratedresearch, development, and demonstrationprogram for oil shale.53 Its major objective isto provide the private sector with the techni-cal, economic, and environmental informa-tion needed to proceed with the constructionof pioneer commercial plants. Its specificgoals are:

q by m id-1981: to provide technical de-signs, cost data, and environmental in-formation for construction and opera-tion of at least one AGR module;

q by 1982: to design at least one commer-cial-size MIS retort that could be used onthe Federal lease tracts or in other loca-tions; and

q by 1985 to 1990: to remove the remainingtechnical uncertainties that impede com-mercial-scale use of the alternate tech-

nologies in the various types of oil shaledeposits.

In situ processing has been given the majoremphasis throughout the program, and muchof the technical R&D will be conducted in the“Moon Shot” project that will address the

second goal. Initial support of AGR will focuson designing the retort module and on surfaceand underground mines to support singleplants and an industry of 1 million to 3 millionbbl/d. The decision to proceed with construc-tion of AGR modules will be determined bythe economic outlook for shale oil inmid-1980. DOE will consider a cost-sharedprogram if industry has not announced firmplans to proceed without Federal participa-tion. The program will also include resourcecharacterization studies that will help todelineate the portions of the oil shale basins

where the different types of developmenttechnologies would be most applicable. Otherstudies will include assessments of air,water, land, and socioeconomic impacts; of occupational safety and health; and of meth-ods for increasing the efficiency of water use.

These efforts should substantially advancethe understanding of the technological as-pects of oil shale development. The budget of over $387 million for fiscal years 1980through 1984 should be adequate to addressmost of the R&D needs identified in the previ-

ous section. This budget includes about $126million for developing and operating a com-mercial-scale MIS retort, and half of the esti-mated $200 million cost of an AGR module.

54

The demonstration facilities are especiallyimportant to the acquisition of firm engineer-ing and economic data. Unfortunately, onlyone in situ technology and one abovegroundretort will be tested, and it will be difficult toevaluate fully the effects of resource charac-teristics on the feasibility of alternate miningmethods.




Poli cy Opti ons

R&D

Some of the remaining technical uncertain-ties could be alleviated with additional small-

scale R&D programs. These could be con-ducted by Government agencies or by the pri-vate sector, with or without Federal partici-pation. If full or partial Federal control is de-sired, the programs could be implementedthrough the congressional budgetary processby adjusting the appropriations for DOE andother executive branch agencies, by provid-ing additional appropriations earmarked foroil shale R&D, or by passing new legislationspecifically for R&D on oil shale technologies.

Demonstration

Full-scale demonstrations will be needed toaccurately determine the performance, reli-ability, and costs of development systems un-der commercial operating conditions. In gen-eral, potential developers would prefer to fol-low conventional engineering practice andapproach commercialization through a se-quence of increasingly larger productionunits. Union, Colony, and Paraho have pro-gressed through this sequence to the semi-works scale of operation—about one-tenth of commercial size.

If this conservative approach were con-tinued, the next step would be a modulardemonstration facility. Although such a plantwould cost several hundred million dollars, itwould provide the experience and the techni-cal and economic data needed to decide onthe commitment of much larger sums to com-mercial-scale operation. Union has expressedits preference for this path; Rio Blanco andCathedral Bluffs are following it. Colony re-gards a pioneer commercial plant as the bestfacility for proving the TOSCO II technology.

The two general approaches to fundingsuch demonstration programs are discussedbelow. Selecting an option will depend on thedesired balance between information genera-

tion and dissemination, Federal involvement,timing of development, and cost.

Private Funding

If left alone, the industry would develop inresponse to normal market pressures and op-portunities, and the Government’s expenseand involvement would be minimized. How-ever, the Government would not be assured of access to the technical, economic, and envi-ronmental information that it needs to formu-late future policies and programs, although

some of this information could be obtainedthrough third-party reviewers or through li-censing arrangements. Another disadvantageis that industry may not risk even the relative-ly modest investment of a modular programuntil economic and regulatory conditionsclearly favor development. For example,Union and Colony have announced that theywill not proceed until Federal incentives areprovided and regulatory impediments re-moved. Industry may eventually proceed, butperhaps not in time for the resource to con-tribute substantially to the Nation’s fuel sup-

plies within the next decade.

Government Support

The alternatives are full Government fund-ing of demonstration facilities, indirect fund-ing through incentives to industry, and asharing of the costs with industry. The op-tions are discussed in detail in chapter 6 andsummarized in chapter 3. In brief, Federalownership would provide the Governmentwith the maximum amount of experience andinformation. It would also maximize Govern-




ment intervention and the commitment of public funds, and it might discourage privatedevelopers from proceeding with independ-ent demonstrations. Also, industry and Gov-ernment would design, finance, and operate a

demonstration project in very dissimilar

ways. The Federal experience with a Govern-ment-owned facility may have little relevanceto the problems that would be encountered bya private developer with the same productiongoal, The Government’s experience wouldtherefore provide little guidance for evaluat-ing oil shale as a private investment oppor-tunity.

Incentives programs could involve taxcredits, purchase agreements, price sup-ports, or other types of support, either singlyor in combination. They could be structuredto encourage the participation of specifictypes of firms and could be combined withregulatory changes, and possibly land ex-changes or additional leasing, to control boththe growth and the nature of the ultimatecommercial industry. They would cost lessthan Government ownership. They would alsotend to provide the Government with less in-formation and with no operating experience.However, disclosure requirements could beinserted into the leases or the incentives legis-lation as a prerequisite for project eligibility y.

The cost sharing of demonstration facilities

would entail intermediate expenditures of public funds and intermediate levels of infor-mation. The receptivity of industry to suchproposals would depend on how much theGovernment would intervene in designing andoperating the projects. If industry responded,the Federal investment that would be neededfor a single Government-owned plant could bespread over several projects, thereby in-creasing the total amount of information gen-erated.

Program Alternatives

Demonstration will require designing,building, and operating full-size productionunits, either as separate modules or incorpo-rated in pioneer plants.

A single module on a single site.—This op-tion would provide comprehensive informa-tion about one process on one site. Eitherunderground or surface mining experimentscould be performed, but probably not both.The costs would be small overall but large on

a per-barrel basis, because there would be noeconomies of scale. Some of the shale minedcould be wasted because the single retortmight not be able to process all of it economi-cally. If the site could subsequently be devel-oped for commercial production (e. g., a pri-vate tract, a potential lease tract, or a can-didate for land exchange), the facility wouldhave substantial resale value. Otherwise, itwould be valuable only as scrap.

Several modules on a single site.—Thisprogram might consist of an MIS operation,

coupled with a Union retort for the coarseportion of the mined oil shale and a TOSCO IIfor the fines. As with the single-module op-tion, either surface or underground miningcould be tested, depending on the site, orpossibly both if the plant had a sufficientlylarge production capacity. The total costswould be larger than for the single-moduleprogram, but unit costs would be lower. Forexample, a three-module demonstration plantwould cost about 2. I times as much as asingle-module facility; a six-module plantabout 3.7 times as much. Different technol-

ogies could be combined to maximize re-source utilization, and detailed informationcould be obtained for each. However, all of the information would be applicable to onlyone site. If many modules were tested, thedemonstration project would be equivalent toa pioneer commercial plant, except that atrue pioneer operation would probably notuse such a wide variety of technologies.

Single modules on several sites.—Severaltechnologies might be demonstrated, each ata separate location. For example, an un-

derground mine could be combined with aTOSCO II retort on one site; a surface minewith a Paraho retort at another. Total costscould be large, as would unit costs, whichwould be comparable with those of the single-







CHAPTER 6

Economic and Financial Considerations

I n t r o d u c t i o n . ., . . . ., . . . . ., . 0 . .,,,,,..,

Page

179

The Nature of the Investigations. . .........180

Summary of Major Findings. . .............180

Development, Commercialization, andDeployment . . . . . . . . . . . . . . . . . . . . . . . . . . 181

The Rationales for Federal Intervention. .. ..182

Impediments to the Commercialization of

Oil Shale . , , . . , , . . . , , . , . . . . , . , , . , . , 183Risks, Uncertainties, and Impediments

Associated With Oil Shale Development. .. 185Plant Capital Cost Estimates . . . . . . . . . . . . . . 186Increases in the General Rate of Inflation. .. .187Uncertain Future Prices of World Crude. .. ..189

Choosing Goals for Oil Shale Development. .. 191Information Base Goal . ..................191Foreign Oil Displacement Goal. . ...........192

A Comparison of Alternative FinancialIncentives q .., ,.O, .0. .,. . . . . . . . . . . . . . 193

Production Tax Credit . . . . . . . ., . .........197

Construction Grant. . . . . . . . , , . . . . . . . .. ...200Low-Interest Loan. . . . . . . . . . .............203Purchase Agreement . . . . . . . . . . . . . . , .. ...204Price Support . . . . . . . . . . . . . . . . . .........206Investment Tax Credit . ..................207Accelerated Depreciation ., . . . . . . . . ......208Increased Depletion Allowance. . ..........210

PageLoan Guarantee . . . . . . . . . . . . . . . . . . ......212Government Participation . ...............213

Government Ownership Versus Incentivesfor Private Development . . . . . . . . . .. ....215

Which Incentives Are Most Efficient andEffective? q . . q . q . . . ,. . , q q q q , . . , q q . q q . 21 5

Are Financial Incentives Needed?. . ........216Economic and Budgetary Impact. . .........217Industry Costs. . . . . . . . . . . . . . . . . . . . . .. ...217Cost to the Government. . .................218

Capital Market Impacts and FinancialFeasibility. . . . . . . . . . . . . . . . . . . . . ., .. ..221

Concerns. . . . . . . . . . . . . . . . . . . ...........222Scenario Framework . . . . . . . . . . . . . . . . . . . . 222Peak Financing Requirement . .............222

Aggregate Financial Feasibility. . ..........224A Caveat . . . . . . . . . . . . . . . . . . . . . .........224Finance Mix . . . . . . . . . . . . . . . , . . . . . . . . . . .225Smaller Companies and NewEquity . .......225

Secondary Financial Impacts and Benefits. ..226

Balance of Payments and Strength of U.S. Dollar . . . . . . . ..................226Taxes . . . . . . . . . . . ......................226Capital Costs Secondary Effects . ..........227

Financial Aspects of Policy Alternatives. . . . .227Impact on Peak Financing . ...............227



PageImpact on Private Sector Share of Peak

Financing. . . . . . . . . . . . . . . . . . . . . . . . . . 227General Impact of Subsidies. . .............227Summary.. . . . . . . . . . . . . . . . . . . . . . , . . . . . .228

Effect on Inflation and Employment . .......228

Construction Industry and EquipmentCapacity *.***..* . . . . . . . . . .**..*..* . . 229

Chapter 6 References. . ..................231List of Tables

Table No. Page22. Cost Estimates for Oil Shale Processing

Plants . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18623. Evaluationof Potential Financial

Incentives for Oil Shale Development .,, 19624. Summary of Companies’ Ordinal

Preferences for Incentives. . . . . . . . . . . . 19725. Subsidy Effect and Net Cost to the

Government of Possible Oil ShaleIncentives (12-percentrate of return

on invested capital) . . . . . . . . . . . . . . . . . 19726. Subsidy Effect and Net Cost to theGovernment of Possible Oil Shale

27.

28.29.

30.

P a g e

Incentives (15-percent rate of returnon invested capital) . . . . . . . . . . . . . . . . . 198Peak Financing in Billions for EachScenario . . . . . . . . . . . . . . . . . . . . . . . . . . 224Finance Mix . . . . . . . . . . . . . . . . . . . . . . . 225The Current DolIarImprovement in theAnnual U.S. Balance-of-PaymentsPosition Associated With AlternativeDevelopment Rate Scenarios. . . . . . . . . . 226

Summary of Estimates of theImprovement in Federal Tax RevenueAttributable to Shale Oil ProductionFrom the Taxes Paid byShale OilCompanies, Their Employees, TheirSuppliers, and Their Suppliers’Employees . . . . . . . . . . . . . . . . . . . . . . . . . 227

List of Figures

Figure No. Page51. Increases in Capital Cost Estimates . . . . 18852. A Summary of Variations in Each

Scenario. .o. o . . . . . . . . . . . . . . . . . . . . . 22253. Year-by-Year Financing in Billions for

Various Scenarios . . . . . . . . . . . . . . . . . . 223



CHAPTER 6

Economic and Financial Considerations

Introduction

The loss of oil imports from Iran coupled

with large OPEC price increases during 1979once more emphasized the vulnerability of the United States to its continued dependenceon imported oil. Rapidly escalating world oilprices combined with uncertain supplies anddwindling domestic reserves have seriouslyaffected the balance of payments, the rate of inflation, and the general health of the econ-omy. While expert opinions may differ aboutprices in the immediate future, they agreethat supplies will remain uncertain andprices will continue to rise. The recently re-newed interest in shale oil (and other synthet-

ic fuels) as contributors to the domestic fuelsupply has arisen in response to these uncer-tainties.

The present debate over the proper eco-nomic policy to pursue with respect to oilshale development centers around the follow-ing:

q

q

q

q

q

the potential it may have for alleviatingthe Nation’s energy-supply problems;the financial, environmental, and socio-economic costs and risks that could beencountered in developing an oil shale

industry;a comparison of its benefits and costswith those of other energy strategiessuch as conservation, solar, increaseddirect use of coal, other synthetic fuels,expanded domestic exploration and pro-duction, or continued reliance on foreignoil:the implications of both alternative pro-duction goals and the rate at which theindustry is established for maximizingthe benefits and minimizing the costsand risks of commercialization;

the relative advantages and disadvan-tages of different financial mechanisms

q

for achieving various production levels

and minimizing private and Governmentrisk; andthe major commercial and institutionalrisks and obstacles that currently ham-per commercial development, which of these can be predicted, and in whichcases is information insufficient to ade-quately evaluate policy options.

Considering the amount of capital that wouldneed to be invested and profitably returnedover long periods of time, a rational and in-formed choice about the commercial produc-

tion of shale oil (or any synthetic fuel) re-quires making reasonably confident esti-mates of the following factors and relation-ships:

q

q

q

q

q

the required capital and operating costsfor various levels of shale oil production,and a comparison of these costs withthose for alternative strategies for ob-taining equivalent benefits;the future effect of OPEC pricing pol-icies;

the corporate perceptions of specificrisks and deterrents that currently in-hibit private commercialization;the subsidies and incentives that wouldmost effectively, and at least cost, suffi-ciently reduce uncertainty to promotedevelopment; andthe temporary or permanent subsidiesthat would be required to maintain an in-dustry.

These are all complex issues open to a varietyof interpretations. Several of these questions

may be unanswerable at this time with the in-formation available.

179



180 qAn Assessment of Oil Shale Technologies

The Nature of the Investigations

This chapter reports the results of the fol--

lowing analyses:

The capital and operating costs havebeen estimated for commercial-size fa-

cilities in third-quarter 1979 dollars.This has been done for both surface re-torting and modified in situ (MIS) tech-nologies. The total costs of various pro-duction levels have been calculated forindustries based on both generic tech-nologies. The accuracy of current costestimates has been evaluated in the lightof the prior unreliability of such projec-tions, and an attempt has been made todisaggregate the factors responsible forthe escalating cost estimates for thesefacilities.

. The effect of uncertain prices for OPECcrude on shale oil commercialization hasbeen examined, a variety of projectionsfor these prices evaluated, and a proba-ble rate of increase for future realprices described.

q OTA has undertaken extensive qualita-tive and quantitative examinations of the relative effectiveness and outcomesof various possible financial incentivesfor stimulating commercial development.These were based on independently con-

ducted mathematical simulations of in-dustry economics, as well as on exten-sive discussions with private consult-ants, Government financial administra-tors, and industry representatives.

The relative advantages and the meritsof several different strategies, develop-ment schedules, and production targetshave been examined with respect totheir comparative costs, risks, and bene-fits.

q A detailed study has been carried out of the impact on capital availability andpricing of oil shale development at sever-al levels of production. The investigationindicates the probable impacts that al-ternative levels of oil shale productionwill have on the cost and availability of capital, both for the U.S. energy sectorand the economy as a whole, given a va-riety of different growth and demandcharacteristics for investment capital,This examination also considers the rel-ative impact that different Federal in-centives will have on capital markets.

q The effect of various levels and paces of oil shale development on the level of em-ployment, the balance of payments, therate of inflation, and Federal tax genera-tion,

Summary of Major Findings

The major conclusions of OTA’s economic analysisof the oil shale industry are as follows:

q The commercialization of oil shale has been gen-erally impeded in the past by several uncertain-ties. Among the most important are large and un-reliable plant capital cost estimates, the insuffi-cient number of high-grade private oil shale tractsplus limited access to Federal oil shale lands, un-

certainty about present and future environmentalregulations, and uncertainty over future prices foroil.

q It is likely, given current market conditions, re-source availability, and the regulatory climate thatwithout additional Federal action a shale oil pro-duction capacity of 100,000 bbl/d will be onlineby 1990-92. It is probable, given similar condi-tions, that the production of 200,000 bbl/d bythat date will require financial incentives, directGovernment participation, or major changes in theregulatory environment of the industry. The same

would be even more the case for a 400,000 -bbl/dindustry. Furthermore, the deployment of this sizeindustry by 1990 could require additional land ex-



Ch 6–Economic and Financial Considerations q 181

q

q

changes or Federal leases. The deployment of a 1-million-bbl/d industry by the same date would re-quire aggressive action in all of these areas.

Given recent increases in the price of oil, the po-tential marketability of shale oil improved substan-tially during late 1979 and early 1980. In narrow

economic terms, the production of shale oil may beprice competitive with foreign crude at this time.However, this conclusion is subject to several crit-ical limitations, It assumes that current capital andoperating cost estimates are within 20 percent ofactual costs, that the price for oil will continue torise throughout the rest of this century by at leasta real 3 percent per year, and that developers re-quire a real discount rate of no more than 12 per-cent. (The economics of shale oil and its potentialselling price are extremely sensitive to the dis-count rate assumed by the developers. )

If financial incentives to private industry are to beemployed, production tax credits, purchase agree-ments, and price supports have the most econom-ic merit based on a variety of criteria. However, itshould be noted that the subsidy effect of pur-chase agreements and price supports are depend-ent on the contract price that is set. Consequently,the success of these two incentives will depend onhow they are constructed and administered. Smalland moderate firms will require some kind of front-end subsidy if they are to significantly participatein oil shale development. If such participation is animportant goal of Government policy, debt guaran-

tees or debt insurance are probably the most effi-cient vehicles.

q

q

q

q

The deployment of a 400,000-bbl/d industry by1990 would begin to markedly strain the capacityof U.S. manufacturers to supply heavy equipmentto developers. To deploy a 1-million-bbl/d indus-try by that time would use between 15 and 30 per-cent of current U.S. annual production of this

equipment. There would be a similar strain on thecapacity of large integrated architectural/engi-neering firms capable of undertaking major proc-ess plant construction.

Existing capital markets and lending institutionsare able to supply sufficient capital for even therapid development of a large industry (1-million-bbl/d by 1990) without significant perturbations,

Oil shale development would provide a number ofeconomic benefits such as contributions to the na-tional fuel supply and direct substitution for for-

eign oil imports. A production of 500,000 bbl/dwould reduce the balance-of-payments deficit byabout $5 billion current dollars if the price of for-eign crude were $31/bbl.

Oil shale development, even at high rates of de-ployment, would have an insignificant impact onnational prices and rates of employment. How-ever, the production of even 200,000 bbl/d by1990 would noticeably increase local rents, landprices, and labor costs. Even moderate devel-opmental rates would favorably affect local em-ployment levels and this effect would extend to the

region with the deployment of a 400,000-bbl/d in-dustry by 1990.

Development, Commercialization, and Deployment’

In this assessment, the term commerciali- oil shale, it will be necessary for their atten-uation is used to designate the process by tion to be focused on the period between thewhich private industry adopts a technologyfor commercial use after most of the tech-nical uncertainties affecting its economic fea-sibility have been resolved. In the UnitedStates, commercialization of new technol-

ogies is primarily undertaken by private firmswithout direct Federal intervention. Never-theless, during the past decade the amount of direct Government involvement has risensharply. If Congress and the administrationdecide to stimulate the commercialization of

time when the major technical problems havebeen solved and the time when the technologyis commercially self-sufficient—the initialphase. Once a decision about the advisabilityof intervention has been made, the question

then is how the commercialization of the ini-tial phase can best be accomplished.

Government sponsored development pro-grams consist primarily of research and de-velopment (R&D) to solve the technical prob-



———— . ——— —— —


lems of a process. Thus far, such programsfor oil shale have been directed to developingspecific techniques for mining, retorting, rub-bling (in MIS processing), removing of impuri-ties, and hydrotreating the shale oil.

Commercialization, in which a technologyis adopted and made economically viable byprivate industry, involves the resolution of the institutional and economic deterrents thataffect profitability. Efforts by the Govern-ment to promote commercialization assumethat the adoption by private industry of aprocess, which is temporarily not commer-cially viable, will be expedited. The rationaleis that such assistance will enable an indus-try to become self-sufficient and profitablewithout further subsidy. A Government-spon-sored deployment program differs from oneto promote commercialization in that it doesnot assume that an industry will ultimately beself-sufficient or that incentives are tempo-rary. The deployment of the synthetic rubber

industry during World War II is a well-knownexample of such a program. In this case theindustry subsequently became profitablewithout subsidy, but this was not the main objective of the program.

Both deployment programs and commer-cialization support for synthetic fuel plantshave been proposed. Although they have simi-lar goals, these strategies imply very dissimi-lar relationships between Government and in-dustry. Deployment programs are govern-mentally controlled. The function of privatefirms is restricted to advising, constructing,and, in some instances, operating the facil-ities. Private corporations provide servicesfor a fee to the Government, which buys theproducts and services and retains ultimateauthority over the planning and the pacing.Commercialization, on the other hand, impliesthat the private sector makes the final deci-sions about adopting a technology.

The Rati onales for Federal Interventi on

From an economic point of view, Govern-ment involvement in commercialization maybe justifiable when private industry declinesto undertake an enterprise that meets majorsocial needs or benefits society. The penalty

for governmental inaction may take the formof a forgone social benefit, such as a de-crease in national security because of insuffi-cient domestic suppies of oil, or of increasedcosts to society, such as environmental dam-age because of inadequate regulation. Socie-ty would also have to pay if, as a consequenceof the Government’s failure to intervene, theprice of a resource increased at a later time.

The deliberate stimulation of a significantlevel of oil shale production could be ex-pected to have a number of social benefits. Itwould help reduce dependence on foreign oil.

It would position the United States severalyears closer to the deployment of a majorshale oil industry should this be made neces-sary by future political or economic events.Stimulated production might also have a mod-

erating effect on oil price increases, althoughit is not clear what level of production wouldbe needed for this to happen.

Private industry declines to invest in an en-terprise when it lacks confidence in the pros-pects for profitability. Higher expected prof-its are required of very risky projects than of more certain ones. Three types of risk for oilshale are discussed in this chapter:

1.

2.

3.

the possibility that capital and operatingcost estimates may seriously underesti-mate a project’s cost and thus jeopardizeits profitability or that the technologywill not perform as planned,the possibility that world oil prices mayfluctuate in such a way that productmarketability will be interrupted at

some point in the time period required torecoup the initial investment, andthe possibility that regulatory delays ora change in environmental standardsmay adverselv affect proiect economics.

J J * , —



Ch. 6–Economic and Financial Considerations 183

If the Government is already intervening insuch a way as to penalize a new technology,the private sector may be discouraged frompursuing it, despite its usefulness. For exam-ple, the regulation of the prices of domesticpetroleum and natural gas that is now being

phased out undoubtedly penalized oil shaledevelopment.

It is widely believed in oil shale industrycircles that the overall impact of Governmentpolicy (e.g., regulations, permitting processes,preferential treatment of conventional petro-leum, and limitation of access to shale re-sources on Federal land) has been one of themost important impediments to oil shale de-velopment,

A variety of groups and individuals opposeGovernment stimulation of the oil shale indus-

try (or other industries) because they believethat the free play of market forces will makemuch more efficient and productive marketdecisions than will any federally inspiredstimulation program. Those sharing this per-spective argue that favorable alteration of oil

shale economics by the Government will in-hibit the use of the most efficient energysources, encourage less efficient manage-ment of the industry itself, increase the costof energy, and foster continued dependenceon fossil fuels. However, those who would

allow the market to decide whether shale oilshould be produced, also tend to argue thattaxes on developers, restrictions on resourceacquisition, and regulatory constraintsshould also be radically reduced.

It does not necessarily follow from the fail-ure of market mechanisms to promote com-mercialization that the Government will orcan do it better. Government intervention is

justified only if its benefits (appropriatelycomputed) are greater than its actual realcosts. Since the choice is not between effi-

cient markets and inefficient Government orefficient Government and inefficient markets,but rather between inefficient markets andinefficient Government, the question is whichwill be more effective in a particular situa-tion.

Impediments to the Commercialization of Oil Shale*

The successful commercialization of a newtechnology ultimately depends on its profit-ability. Commercialization will not take place,

despite Government encouragement, if devel-opers are unable to obtain a return on theirinvestment commensurate with returns avail-able to them from other investments. Conse-quently, in determining the proper course topursue with respect to oil shale development,the Government needs to give careful consid-eration to the prospects for profitable oper-ation. An industry that requires permanentsubsidies is a different economic propositionfrom one that needs them only for the firstcommercial-size facilities. There are threetypes of factors that influence self-sufficient

profitable operation: technical, economic,and institutional.

Technical uncertainties primarily refer tothe difficulties associated with scaling up anew process from pilot to commercial size.

This usually involves solving technical prob-lems that could adversely affect operationand thus increase the risk of financial loss,

e.g., a component may be required to performbeyond the capacity of available equipment,or existing mining techniques may be inade-quate for the scale of commercial-size opera-tions. With MIS technologies, the need toproperly rubble shale in order to achieve nec-essary burn characteristics (and thus a highrate of shale oil recovery) is such a technicalproblem. With surface retorting, an examplewould be scale-up of 10 to 20 times of com-plex reaction systems handling massive quan-tities of solids.

Economic uncertainties are different forthose technologies that produce a substitutefor an older product than they are for thosethat produce primarily new products. Theeconomic risks associated with shale oilcenter around whether it can be produced






made without reaching an economic barrier.When a process has relatively low technicalperformance requirements, it may be possi-ble to reduce economic or institutional bar-riers by upgrading technical performance.However, if technical performance goals arehigh, production costs are close to or exceed

the selling price for competitive products,and institutional barriers are restrictive,then the technology will encounter seriousdifficulties. Under these conditions, the usualresponse of industry would be to postponecommercial commitment while waiting fortechnical improvements, reduced institution-al barriers, or improved market prices for theproduct.

Technical problems can be reducedthrough further R&D. Economic uncertaintycan be averted through some form of subsidy.

Institutional barriers can be minimizedthrough altering administrative or regulatoryrules and timetables.

Although other considerations are ex-tremely important (e.g., overall cost to theGovernment, financial exposure, and admin-istrative burden), the risks presented in com-mercializing a particular industry must be

seen, at least in part, from the point of view of present and potential developers. The suc-cess of any Government program to stimulatethe commercialization of a new technologydepends, to a large degree, on the extent towhich the policy incorporates the developersown perceptions of the risks, benefits, and

uncertainties associated with production.

Surface oil shale technologies are compar-atively well-understood with only a few re-maining technical uncertainties. They are, infact, very much the same today as they were20 years ago, and present little room in whichto maneuver with respect to changing theirscale of operations or improving their per-formance. For example, there is apparentlyno alternative to large-scale mining and thedisposal of sizable quantities of spent shale.

In real terms, these technologies are unlikelyto become significantly less costly than theyare now. Thus, the possibility of technicaltradeoffs from the technology itself is re-duced, and the improvement of overall com-mercial prospects must come through the re-duction of economic and institutional bar-riers.

Risks, Uncertainties, and Impediments Associated With


The commercialization of oil shale facesthree primary economic risks and uncertain-ties:

the uncertainty over the costs of buildingand operating commercial facilities;the risk of unfavorable recovery-cost dif-ferentials relative to conventional crude(except possibly those from such frontierareas as Outer Continental Shelf devel-opment); andthe uncertain future selling prices of world oil.

These are compounded by the partial con-nection between the costs of oil shale facil-ities and the rising price of energy,

There are three additional uncertaintiesrelated to the carrying capacity and responseof the institutional systems within which theoil shale industry operates that could serious-ly affect the economics of the industry. Theyare:

q

q

the possibility (under conditions of rapidlarge-scale deployment) of bottlenecksand shortages of equipment, architec-tural and engineering construction ca-pacity, and trained manpower for con-

structing and operating facilities;the possible scarcity of available andreasonably priced investment capitalduring the period of construction; and




the potentially unfavorable effects of present or future Federal and State reg-ulatory policies on commercial develop-ment.

Plant Capital Cost Estimates

50,000-bbl/d oil shale facility would re-quire a capital investment of around $1.5 bil-lion in 1979 dollars. Operating costs are esti-mated by industry at $8 to $13/bbl of crudeshale oil processed, exclusive of capital re-covery. Such an investment would be under-taken cautiously even if the estimates of capi-tal and operating costs for oil shale plantswere known to be accurate. However, duringthe past 10 years, capital cost estimates haveincreased much more rapidly than has thegeneral rate of inflation, and still do not ap-pear to be totally reliable. The experience of

Colony Development is illustrative but not ex-ceptional. Its direct capital cost estimates fora 43,000-bbl/d facility increased from $225million in 1972 to $1.3 billion in early 1979,and were $1.7 billion in February 1980. (Seetable 22.)

Cost escalations of this magnitude are notunusual for large, capital-intensive facilitiesinvolving complex novel technologies. Asdemonstrated by experience with light waterreactors, many coal gasification plants, Ca-nadian tar sands, and various weapons sys-

tems, cost estimates are likely to rise rapidlyas a process advances from initial to defini-

tive engineering designs. Also, as with similarprojects, oil shale development is highly vul-nerable to changes in the cost of capital andlabor. These costs have increased more rap-idly in recent years than the composite rate of inflation. In addition, oil shale developmentwill be particularly subject to regulatory re-

quirements, permitting procedures, and pos-sible environmental litigation that could delayor arrest construction and substantially addto costs.

A number of hypotheses have been offeredto explain these cost estimate increases.Some argue that since the historically mostaccurate method of estimating the price of shale oil is simply to add $5 to the price of im-ported oil, oil shale companies are exaggerat-ing their costs in order either to prepare themarket for high selling prices or to get large

governmental subsidies. This charge has itsbasis in the observation that the rise in shaleoil cost estimates has paralleled foreign oilprices, and seems to increase each time theGovernment gives serious consideration to in-dustry subsidies, Neither this nor any otherinvestigation has produced evidence that costincreases are contrived, Most of the vari-ations in cost increases and estimated pricesfor oil shale can be explained by examiningfour significant variables:

. increases in the general rate of inflation,

q escalations in the real costs of plant con-struction.

Table 22.–Cost Estimates for Oil Shale Processing Plantsa

Estimated costTime of estimate $ million

1 9 6 8 $ 1381 9 6 8 1441 9 7 0 . , 2501973 2801973 : : 250-300E a r l y 1 9 7 4 . . 400-500L a t e 1 9 7 4 , 850-9001976 9601977 1,0501979 : : 1,3501 9 8 0 1,700

— —

Data source Scope and detail of estimate

Department of the Interior InitialThe 011 Shale Corp InitialNational Petroleum Council InitialDepartment of the Interior InitialColony Development Operation InitialColony Development Operation Detailed (early version)Colony Development Operation DetailedThe Oil Shale Corp. UpdateThe Oil Shale Corp. UpdateOTA UpdateThe 011 Shale Corp. Update

aplanl~ “se underground rnlolog and above-ground retorting to produce approximately 50000 bbl Id Of shale 011 syncrude

SOURCE Office of Technology Assessment



Ch 6–Economic and Financial Considerations 187

more stringent environmental standardsfor oil shale operations, andincreases in estimates as a consequenceof more complete and detailed knowl-edge of a facility’s actual design,

Increases in the General Rate of InflationMany developers believe that chronic infla-

tion during the last 10 years has been the pri-mary cause of the exceptional cost escala-tions. Although inflation rates were very highbetween 1972 and 1976, this view is appar-ently incorrect. For oil shale developers fac-ing nominal rather than adjusted real prices,the overall impact of dollar inflation wouldappear quite large. The rate of general priceinflation also tends to drive up the interestrates on construction loans. However, as

shown in figure 51, during the period from1972 to 1977, not more than 12 percent or ap-proximately $100 million of the cost estimateincreases were due to changes in the generalprice index. The rate of general inflation is

Figure 51 .—Increases in Capital Cost Estimates

Surface shale plant estimates

.

.

lncreases from Maxenvironmentalcosts [ Min

.

1971 1972 1973 1974 1975 1976 1977

Year

“ Dupont Index This Index gives the gradient of change for Industrial process

plant costs Although not entirely appropriate for 011 shale plants, it IS the bestavailable Index However It probably somewhat understates plant cost escala

tions

S O U R C E E d w a r d W M e r r o w C o n s frafnts on the Cornmercia/lzatlon of 0//Sha/e 2293 DOE September 1978

important because of the way it affects theperceptions of developers. The factors thatinfluence relative price changes are, how-ever, considerably more significant.

Escalations of Plant Costs

Large plants are vulnerable during periodsof extreme inflation when the demand fornecessary equipment and services risessharply relative to their supply. Such a periodexisted in 1974. From mid-1973 to 1975 thegeneral price index increased in excess of 20percent, but chemical industry equipment in-creased by approximately 70 percent, andcertain key items such as compressors andheat exchangers increased by almost 100percent. It was during this period that thecost estimate for the Colony oil shale plant ap-

proximately doubled.The effects of severe sectoral inflation on

project costs are even greater than those sug-gested by the above numbers, which arebased on list prices that are often discounted.Discounts are eliminated as industry inflationaccelerates.

In a crash program for synthetic fuels,there will almost certainly be real cost esca-lations and overruns. The first few plantscommitted could contract for a significantpart of the available U.S. manufacturing ca-

pacity for key items such as valves, pumps,compressors, and pressure vessels. As addi-tional plants reach the procurement stage,equipment suppliers would be forced to quotelonger and longer delivery times. These entailhigher price contingencies for contractors tocover unknown increases in supplier costs,and can have a devastating impact on largecapital projects. Almost half the total per-barrel cost of synthetic fuels is estimated tobe solely the carrying cost of the capital in-vestment. project owners will, therefore, bewilling to bid up the prices for essential

equipment in order to save time. A singleweek’s delay could increase costs by millionsof dollars.

Because of the potential for extreme sec-toral inflation, costs could increase dramati-



. . .


cally in a crash program. Building 20 plantscould cost considerably more than twice thecost of building 10 plants. Any savings indesign costs by building duplicate plantswould be wiped out by cost increases. Plantconstruction costs during an all-out crash

program are likely to increase in real termsby 50 percent or more.3

Increases Due to Environmental Regulations

The environmental legislation passed dur-ing the late 1960’s and early 1970’s, alongwith the provision of substantial enforcementpower to the Environmental Protection Agen-cy, altered the context in which large-scaleindustrial development may now take place.Without question, this legislation, which hasbeen paralleled by similar State laws, hasbeen and will continue to be very costly to in-dustry. It is not possible, however, to accu-rately ascertain what the actual costs of meeting these standards are, because thecosts are both direct and indirect. Most esti-mates usually include only the former costcategory. Cost estimates for meeting some of the standards are discussed in detail in chap-ter 8.

In 1978, the RAND Corp. estimated that thedirect costs of pollution control technologiesfor oil shale developers ranged between 6.5and 15 percent of total capital costs. These

were primarily for eliminating hydrocarbons,particulate, and hydrogen sulfide from theretorting process, and for dust control andspent shale disposal. By assuming a zero val-ue for environmental costs in 1971, RANDgoes on to estimate that between 8 and 20percent of the increases in estimated capitalcosts or $65 million to $165 million between1971 and 1978 were caused by environmentalfactors.

These estimates do not include the possibleindirect environmental costs that might occur

because of:q necessary siting changes,q alterations of mining plans,q disruption of construction schedules,

q less efficient facility operation, andq costs of potential litigation.

Each of the above can have enormous im-pacts on plant economics; delays occurringlate in the construction stage are particularlycostly. A 6-month delay in the middle of con-

struction could add more than $100 million tocosts. Additional environmental equipmentcan substantially reduce reliability and theon-stream factor, * if operations must ceasewhen environmental equipment fails. A re-duction in the on-stream factor of 5 percentwill increase the required selling price of theproduct by 7 percent. A construction delaysuch as might be caused by environmentallitigation can be extremely costly afterground has been broken. The costly delaysand disruptions described here will probablycharacterize only a fraction of the projects

undertaken. Nevertheless, they constitute asignificant risk that must be included by de-velopers in their contingency plans.

Environmental regulations add to devel-opers’ estimates of uncertainty and risk. Theuncertainty is over how present regulationswill be interpreted, administered, and en-forced; and the risk derives from the possibili-ty of future regulations. Rather than makingan attempt to predict with some degree of ac-curacy what might be the indirect effects of environmental standards on plant economics,

developers have increased the size of theirestimates as a hedge against uncertainty,based on their informal sense of general risk.Although environmental regulations have sig-nificantly augmented industry’s capital costestimates, they nonetheless are responsiblefor less than than 20 percent of the overallcost estimate escalations since 1971.

The Learning Curve for New Plant Design

The escalations due to improved knowl-edge about costs, as a consequence of more

complete engineering designs, appear to beresponsible for the largest increases in capi-

*The on-stream factor is the proportion of operating daysper year.




tal cost estimates. Between 40 and 50 percentof the estimated increases between 1971 and1977 were of this kind.

Forecasting the costs of constructing a

commercial facility for a new technology isnormally based on a series of engineering de-

sign estimates, each of which is presumablymore detailed and accurate than the previousone. There are four types of such estimates.They start with initial estimates, which are“back of the envelope” predictions that giveonly a rough indication of eventual costs; pro-ceed through the preliminary design estimatein which the plant’s subsystem flows are de-fined, but component subprocesses are notdefined; continue with the detailed design inwhich estimates are prepared for specificmaterials and components; and end with thefinal design estimate in which precise costs

for all materials, components, and labor arepulled together. The final design estimateshould accurately locate the cost of immedi-ate construction to between plus or minus[usually plus) 15 percent of the eventual cost.

The cost of preparing a final engineeringdesign estimate for a commercial-size oilshale facility is between $12 million and $20million. To date, only detailed design esti-mates have actually been carried out. The in-tention of this iterative estimation process isto provide continually better design forecasts

based on continually more precise technicaldata derived from increasingly larger devel-opmental tests, As the designs become morecomplete and the technical data improve, thecosts become clearer.

The cost estimate escalations that tookplace between 1973 and 1976 occurred, inpart, because prior to the middle of 1974, nofinal or detailed engineering design estimateshad ever been prepared. Colony Oil Shale De-velopment Corp. ’s detailed design estimaterepresented an 80-percent increase over thepreliminary design estimate made 10 monthsearlier. The subsequent experience of otherdevelopers with their more detailed designswas similar,

Cost estimation increases are by no meanslimited to oil shale facilities. Similar in-

creases have characterized the developmentof coal gasification, coal liquefaction, Cana-dian tar sands, light water nuclear reactors,and a variety of new weapons systems. How-ever, several characteristics of oil shaleplants present particular design and estima-

tion problems. First, such plants are highlysite specific. The costs of transporting, min-ing, handling, and disposing of shale all de-pend on the nature of a site’s topography, ge-ology, and surrounding terrain. Second, theestimation of oil shale plant costs requires anarray of engineering, architectural, econom-ic, and technical skills possessed by only afew architectural and engineering firms.

The reliability, or on-stream factor, for theplant after it is constructed, figures signifi-cantly in the eventual cost of production. Costestimates compute the cost of building theplant, and then assume that it will be on-stream about 90 percent of the time. There isa high probability, however, that pioneerplants will not operate as planned for sometime, or until such time as additional in-vestments are made to correct their prob-lems. For this reason, companies tend to buildonly those designs that are known to work,even though new but untried approaches maypromise appreciable savings.

As technical data improve and developerscomplete more detailed design estimates, thegradient for real cost escalations will leveloff. It is probable, but not certain, that cur-rent cost estimates are fairly realistic andthat there will be no further substantial in-creases, other than normal inflation. How-ever, no commercial-sized facilities havebeen built, and cost estimates are unlikely tobecome stabilized without industry experi-ence in constructing and operating such facil-ities.

Uncertain Future Prices of World Crude

The market price of premium grades of conventional crude oil is a major determinantof the highest possible profitable sellingprices for syncrude from shale. Therefore,present and future prices for conventional




crude are among the basic factors that willcondition the economic viability of the oilshale industry. A developer who commits$1.4 billion to $1. i’ billion to a shale oil plantwith a very long payback period must be rea-sonably confident that the market value of theproduct will exceed its production costs.Uncertain future prices of international oilprevent firms from accurately predictingmarket values for shale oil. Since the Arab oilembargo of 1973-74, the actions of the OPECcartel and high international demand havepushed the price of world oil far above recov-ery costs.

Between September of 1979 and Februaryof 1980 the prices of world oil increased byover 30 percent. In March of 1980, the postedprices of the premium grades of conventionalcrude (the counterpart of upgraded shale oil)stood between $34 and $38/bbl. Their spot-market prices (e.g., for Wyoming Sweet andthe best grades of Nigerian and North Afri-can oil) are currently between $40 and $52/ bbl. Sweet crude oils were recently sold fromthe Elk Hills and Teapot Dome Petroleum Re-serves for $43 and $50/bbl respectively.These increases, along with the probability of further escalations in the future, have sub-stantially improved shale oil’s economic at-tractiveness. The future viability of shale oilis predicated on the assumption that in-creases in its production costs will lag behindthe rising price of world market crude. On thebasis of the best current capital and operat-ing cost estimates (compiled between Novem-ber of 1979 and February of 1980), it appearsthat shale oil may have reached parity withconventional oil without subsidy. However,this conclusion is subject to several criticallimitations.

First, this finding assumes that currentcapital and operating cost estimates are, inreal dollar terms, within 20 percent of beingaccurate. Given that such projects have

never been previously undertaken, still lackfinal engineering design estimates, and areprone to possibly severe inflation because of associated heavy equipment costs, this maybe a very risky assumption.

Second, most analysts expect internationaloil prices to increase by 3 or 4 percent peryear, over and above inflation. This will meanthat the price of oil will double, in real terms,by 2000. However, because international oilprices are still set, in part, by a cartel, thefuture of the market cannot be predicted withany certainty. Increasing or continued highdemand, decreasing world reserves, andOPEC or producer-state governmental poli-cies directed at conserving their reservesthrough price rationing could result in sus-tained price inflation for imported oil. On theother hand, prolonged recession in the indus-trial West or reduced international demandcould limit oil price increases in the future.Recent events strongly indicate that OPEC’scapacity to set international oil prices hasbeen substantially weakened. Nevertheless,the play of market forces is still likely to main-tain upward pressure on prices. In any event,future incremental price increases are notlikely to be regular. Instead, temporary peri-ods of oversupply and soft markets are likelyto alternate with shortfalls and high demand.Therefore, short periods of stable prices willprobably alternate with rapid price in-creases.

Finally, the question of whether presentand future oil prices will allow profitable sell-ing prices for shale oil without subsidy de-pends on the discount rate that firms are as-

sumed to require in order to undertake devel-opment. The average real aftertax returns oninvestment of U.S. industrial firms is gener-ally between 6 and 10 percent. Given therisks associated with a pioneering industry,oil shale developers will require a largerprofit than that obtained from less risky proj-ects. Industry sources generally maintainthat this would mean a real aftertax expectedprofit of between 12 and 15 percent. Break-even selling prices for shale oil are extremelysensitive to the discount rate, which at 12percent would make shale oil competitive

with conventional petroleum according toOTA’s analysis. However, if developers re-quire a is-percent rate of return to under-take investment, then subsidies will probablystill be necessary.



Ch 6–Economic and Financial Considerations q 191. -

Choosing Goals for Oil Shale Development

The Federal Government has a variety of options available to stimulate oil shale devel-opment. In order of increasing Governmentinvolvement, these include:

continuing present policies and provid-ing no additional incentives;encouraging precommercial modularplants;building and operating a number of Gov-ernment-owned modules;encouraging a few commercial-sizedplants; anddeploying a major industry.

Each option differs with respect to the costto the Treasury, the level of shale oil produc-tion, the risks of cost overruns and inefficien-

cy, and the impacts on the physical and socialenvironments. They also vary with respect tothe extent and types of financial incentivesthat would be most effective.

There are two major policy goals to be metby an oil shale industry. One is to deployenough production capacity to answer the re-maining uncertainties related to economicand technological feasibility and environmen-tal impacts, The other is to quickly displaceforeign oil imports.

Information Base GoalBecause no oil shale process has as yet

been commercialized, the economics, techni-cal operability, and environmental impacts of each of the processes are still not fullyknown. If the most promising processes wereoperated at either the precommercial modu-lar scale or at commercial capacity manyquestions could be answered and compari-sons among the various processes would bepossible, Operating experience could be ac-quired by providing incentives to industry, by

operation of Government-controlled modulartest facilities, or through some combination of both. A1though some questions could be an-swered by research, a moderate developmentand production program would reliably an-

swer most of the remaining technical, eco-nomic, and environmental questions. It wouldalso facilitate the selection of the most feasi-ble oil shale and synthetic fuel technologies

available today; provide information for ra-tional decisions regarding oil shale commer-cialization; and put the United States severalyears closer to full-scale production capacity.

A modest program for stimulating the con-struction of a limited number of commercialor modular facilities would be less likely tofail, Such a strategy reserves judgment con-cerning the ultimate extent of developmentuntil the processes have been tested. This hasthe advantage of allowing policymakers toevaluate commercial results and consider

alternatives for further reduction of oil im-ports prior to contracting for additionalfacilities, and should improve the chances of ultimately establishing a self-sufficient oilshale industry. It should be noted, however,that the information base strategy tends to ig-nore the fact that technology is not static butis continually changing, By gathering data on“today’s” processes, this approach may ig-nore possible (probable) future process devel-opments. It is possible that complete informa-tion could be obtained on several processes inthe next 10 years only to discover that a new

process may be more productive. Should pol-icy be to repeat the cycle and obtain more in-formation, or to build the obsolete plant?From an economic standpoint the choice isnot a simple one.

In the absence of time limitations, the over-demand for scarce capacity in constructioncompanies, in skilled labor, in plant materi-als, and in architectural engineering firmswould be reduced or even avoided. Whenthese are placed in short supply, costs esca-late, the quality of design is lowered, and

fewer plants may be constructed.

ICF in a recent study for the Budget Com-mittee of the U.S. Senate4 summarized thebenefits of proceeding with development in a



192 . An Assessment of 011 Shale Technologies

two-phased strategy by maintaining that suchan approach would:

q be an effective symbolic action showingthe seriousness with which the UnitedStates intends to reduce energy imports;

q provide the opportunity through follow-

on stages of development to reduce ener-gy imports directly through shale oil pro-duction, while maintaining the option toconsider more cost-effective ways of im-port reduction; and

q provide the flexibility that has beenfound to be critical in advancing newtechnologies to a commercially viablestage.

An information base strategy initially fol-lowed by review and possible subsequent ad-ditions, as discussed in this chapter, has alsobeen suggested by the RAND Corp., ICF, Cam-

eron Engineers, Booz-Allen, and the Congres-sional Budget Office. It assumes that the prin-cipal goals are to create a viable industry,minimize the cost to the taxpayer, and max-imize the efficient use of capital.

If, however, the primary goal is to reducedependence on foreign oil by 1990, then theextensive development of a large oil shale in-dustry might be more advisable. Economicanalysts have examined whether producingadditional oil shale (or other synthetic fuels)is more cost-effective than alternative ap-

proaches such as conservation. Their anal-yses depend on the assumption that the desir-ability of synthetic fuels is chiefly a matter of price rather than availability. Another OPECoil embargo could change this assumption.

Foreign Oil Displacement Goal

If present trends continue, the UnitedStates could import around 12 million bbl/d of oil by 1990. It is beyond the scope of thisreport to examine whether this import de-pendence could be reduced to the President’s

target of 8.5 million bbl/d through conserva-tion, synfuel production, and conversion fromoil to coal. To estimate the desirability of thecontribution that shale oil could make to re-ducing import reliance requires examining: 1)

how cost-effective shale oil development iscompared with other energy strategies inachieving import reductions; 2) whether thecosts and risks of a crash program to developa large industry outweigh its potentialbenefits and whether such a program wouldachieve its production goals; and 3) if a rapid

development strategy would have unaccept-able environmental costs.

Establishing a large industry to replaceforeign oil would have both positive and nega-tive effects. On the positive side, the economyand national security would benefit from a re-duction in oil imports; and in the oil shale re-gion, employment would rise and an in-creased tax base would provide revenues forcommunity development. On the negativeside, such a program would be extremelycostly. It would necessitate investing in nu-

merous plants, each with a capital cost of around $1.5 billion. Technologically inferiorprocesses might be used because of insuffi-cient time for supporting technical R&D, andthe accelerated construction schedule couldlead to cost overruns and managerial ineffi-ciency. (The use of a “technologically inferi-or” process could, however, be compensatedby the inflation savings; a better process built10 years later would probably cost muchmore in real terms because of inflation of plant costs.) Capital availability for other eco-nomic sectors could be restricted. It is also

questionable that mining and processingequipment could be supplied within the con-struction time frame. Furthermore, it is possi-ble that the lack of supporting environmentalR&D could lead to a conflict with environmen-tal standards. On balance, the socioeconomiceffects could well be more negative than posi-tive.

There is general agreement among the en-gineering and construction firms contactedby OTA that a program to establish a large oilshale industry (over 500,000 bbl/d by 1990)

would entail sizable cost overruns because of high inflation in critical supply industries. Itwould also impose severe time constraints ona developer’s operations. Contractual agree-ments for these facilities would have to begin




immediately and continue under conditions of tight scheduling for the next 8 to 12 years.Various studies of the consequences of Feder-al funding to stimulate the commercial adop-tion of new technologies, including the 1976study by the RAND Corp.,5 report that subjec-tion to severe time constraints has rarely re-sulted in the establishment of a viable indus-try. Furthermore, a rapid development effortwould probably require the commercial oper-ation of facilities before the technologies and

A major Government effort to establish anindustry based on a new technology undertime constraints does not allow sufficienttime to review progress, make cost-benefittradeoffs, and modify plans in response tonew knowledge, When a pressing nationalemergency requires a crash program, the re-sultant inefficiencies entailed by these re-strictions may be justified. However, whenthe primary purpose is to establish a self-suf-ficient industry, crash programs should be

their economics were fully understood. avoided.

A Comparison of Alternative Financial Incenti ves

Before oil from domestic shale can signifi-cantly supplant imported supplies, any devel-opment program must take into account the

major technological, environmental/regulato-ry, and economic uncertainties that discour-age private firms from undertaking such in-vestments. To overcome these uncertainties,Congress is contemplating implementing anincentive program that would share in therisks or subsidize the economics of oil shaledevelopment. In evaluating alternative incen-tives and their probable effects on oil shaledevelopment, the reactions and preferencesof developers must be taken into considera-tion.

In conducting this analysis, 10 alternativeincentive structures were examined:

q

q

q

Construction grant. The Governmentprovides a direct grant to cover a pre-specified percentage of total construc-tion costs, both a 50- and 33-percentconstruction grant were analyzed.Production tax credit. The developer re-ceives a tax credit for each barrel of shale oil produced, a $3/bbl credit com-puted on shale oil prior to upgrading wasanalyzed.Low-interest loan. The Government

lends the developer a prespecified per-centage of capital costs at an interestrate below the prevailing market rate;the analysis assumed 70-percent Gov-ernment financing at 3 percentagepoints below the market rate.

Price support. With this incentive, theGovernment guarantees the developer acertain price for shale oil; the analysis

assumed $55/bbl of hydrogen-upgradedsyncrude (hydrotreated shale oil). If themarket price for the product falls belowthe guaranteed price, the Governmentwould make up the difference.Purchase agreement. The developer con-tracts with the Government to sell shaleoil at a price higher than the prevailingmarket price; the analysis assumed aprice of $55/bbl of upgraded product.Increased depletion allowance. The de-veloper is allowed to claim a 27-percentdepletion allowance (at present it is 15

percent).Increased investment tax credit. The de-veloper can claim an additional invest-ment tax credit of 10 percent,Accelerated depreciation. The firm is al-lowed to depreciate its investment over 5years.Loan guarantee. The Government wouldagree to pay off a loan in the event thatthe firm defaults on its loan: the firmwould typically receive a lower interestrate than that prevailing in capital mar-kets.

Government participation. The Govern-ment would become an equity partici-pant in an oil shale project.

To evaluate how effectively the differentincentives will promote the development of a



—

194 qAn Assessment of 011 Shale Technologies

viable oil shale industry, each was analyzedin relation to three fundamental objectives of the congressional incentive program. * Theseobjectives are:

q

q

q

Subsidizing the economics of shale oilproduction. The mechanism by which

each incentive affects the perceived eco-nomics of oil shale development and howwell it functions as a subsidy was ana-lyzed.Sharing in project risks. The extent towhich each incentive allows the Govern-ment to share in the risks of oil shale de-velopment, and the extent to which it re-duces the variance of the present valueof the aftertax income from a projectwas analyzed. To conduct this analysis,a project risk was assigned for four spe-cific categories: the risk of unsuccessful

project completion, which stems largelyfrom technological and regulatory un-certainties; the risk associated with un-certain investment costs; the risk associ-ated with uncertain operating costs; andthe risk associated with uncertain futureprices for oil from shale.Facilitating access to capital. The extentto which each incentive would sufficient-ly induce capital markets to lend thelarge sums of money that will be re-quired to develop an oil shale industrywas examined. This consideration is

particularly important for understand-ing which types of firms would benefitfrom specific incentives (i.e., whether anincentive will benefit less well-capital-ized firms or those with limited ability toincur debt).

Once it was determined how well each in-centive met each of the program’s objectives,it was examined in the context of two impor-tant policy guidelines:

q Efficient use of the Nation economic re-sources. To make efficient investmentdecisions,** oil shale developers should

*Congress, before designing an incentive program, shouldspecify the relative emphasis to be placed on each objective.

**This definition of efficiency is in the somewhat narrowersense of its use in economics.

q

pay the same prices for resources (i.e.,land, labor, capital, and materials) thatare paid by firms engaged in other pro-duction activities in the general economy(i.e., the prices paid should equal the val-ue of these resources in alternativeuses). Similarly, the price received for

the shale oil by producers should equalits value to the economy. This will be themarginal price of crude oil, because up-graded shale oil and crude oil are almostequally substitutable. Therefore, OTAanalyzed the extent, if any, to whicheach incentive would interfere with de-velopers’ perceptions of the marketprices of the productive resources con-sumed in shale oil production or the mar-ket price for the final product.Minimal administrative burden. The costof administering an incentive program

represents a loss to the economy thatfalls on the public and private sectorsalike. In addition, the administrativeburden affects the time required to im-plement a program as well as its overalleffectiveness. Therefore, OTA analyzedthe administrative requirements foreach of the incentives.

Finally, the analysis was structured toassist Congress in developing an incentiveprogram to meet a third policy guideline: topromote a healthy state of competition in the

industry, Because of the potential multiplicityof objectives for an incentive program, andthe variety of types of firms involved, it isprobably necessary that the incentive pro-gram consist of a package of incentives. Thisshould allow firms in differing financial, tech-nical, and tax circumstances all to benefit.

To clarify the competitive implications of aprogram consisting of a combination of incen-tives, the kinds of firms that would mostbenefit from each incentive were identifiedbased on the analyses of the incentives, areview of industry statements, and discus-sions with industry representatives. Specificexamples of firm preferences for the differ-ent incentives have been documented. The ef-fects of the various incentives on the programobjectives and the policy guidelines are sum-



Ch 6–Economic and Financial Considerations . 195

marized in table 23. The rank-order prefer-ences of different shale oil developers for thevarious financial incentives are summarizedin table 24. In order to make a comparison of the incentives and evaluate their contribu-tions to the objectives of the total program

and the policy guidelines, a computerizedsimulation model developed by ProfessorsWallace Tyner (Purdue University) and Rob-ert Kalter (Cornell University]” was used totest and measure each of them against thecase in which no incentive is offered. Thepresent calculations with the Kalter-Tynermodel were prepared for OTA by ResourcePlanning Associates, Washington, D.C. Acomplete description of the simulation model,its capabilities, limitations, and how it wasemployed can be found in appendix B. Usingthe model, it was possible to estimate the fol-

lowing four variables (for all but the produc-tion tax credit and loan incentives):

. Expected profit. Expected economicprofit is defined as expected return inexcess of a company’s minimum re-quired aftertax return on its oil shale in-vestment. * OTA calculated both ex-pected profit and the change in expectedprofit relative to the no-incentive case.

Risk. The risk of the investment refersboth to the probability of the investmentresulting in an economic loss (i. e., earn-ing less than the minimum required rateof return), and to the degree of variationin possible profit outcomes, OTA meas-ured this variation in absolute terms(i.e., the ratio of change in expectedprofit to standard deviation of expectedprofits).

q Breakeven price. The breakeven price isthe constant price for hydrotreated**shale oil at which it would just earn itsminimum required rate of return.

q Cost to the Government. The expectedcost to the Government of providing theincentive is the gross subsidy to the firm

*Profi I was measured as the sum of each yea r’s cash flows,dis(:ounted using the company’s minimum required aftertaxrate of return as a discount rate (see app, B).

* *Inhydr~ treatment the physical properties of raw shale oil

are improved by adding hydrogen and removing nitrogen andsulfur. The product is often referred to as syncrude.

less increased tax payments to the Gov-ernment. * An incentive increases tax re-ceipts if the present value of the tax pay-ments is larger with the incentive than if an equal investment was made withoutthe incentive. OTA estimated both the

actual cost to the Government and theratio of the change in expected profit tocost.

With these computations, the way in whicha firm’s marginal tax rate** (and, for a low-interest loan, its cost of borrowed funds) in-fluenced expected profits was assessed, andthe sensitivity of expected profits to differentdiscount rates (defined as the minimum rateof return necessary to induce private devel-opment) was determined,

The numerical results of this analysis,

which are summarized in tables 25 and 26,were calculated using the best available datafor the cost of commercial oil shale facilities.They thus provide a reasonable approxima-tion of the magnitude of the probable effectsof each of the incentives. While these out-comes would not be expected for the opera-tion of an actual facility, they would be forthe average operations of a number of facil-ities. Because of the uncertainties inherent inthe estimation, the most useful application of these quantitative results is for establishingcomparisons among the incentives.

Congress is currently considering 10 majorkinds of incentives to be included in a domes-tic oil shale development program. The anal-ysis of the specific effects of each of these onthe three program objectives and the threepolicy guidelines is summarized below. Thediscussion also includes a quantitative evacu-ation of the impact on expected profits, on

*Government cost was calculated in present value terms aswas private profit. Net cost for each year (i. e., subsidv less in-creased tax revenues) was discounted at the Government’s dis-count rate (assumed to be 10 percent in real terms). The result-

ing present value calculations were summed for all years.**The marginal tax rate is the rate at which income from an

additional investment (e. g., an oil shale facility) is taxed by theGovernment. For most firms, this is 46 percent. However, afirm wiih excess tax deductions or credits from other opera-tions would apply the excess to the oil shale investment, there-by reducing its marginal tax rate.



Table 23.–Evaluation of Potential Financial Incentives for Oil Shale Development

Effect of incentive on program objectives Extent to which incentive meets policy guidelines

Promotion of Minimization of Promotion of competitionSubsidy ef fect Ri sk- shar mg e ffect Financing effect economic efficiency admi nist rati ve burden Eff ect on fi rms Fir m pr eferences —-.

Moderate, shares risk Slight, improves Minimal administrative Benefits firms withtion tax Strong, subs id izes($3/bbl) product price

ment tax Strong, subsidizes(additional investment cost

Slight adverse effect,distorts product price

Supported by relativelylarge firmsassociated with price un-

certainty (If tax credit varieswith product price)

project economics burden large tax Iiability andstrong financialcapability

Moderate: shares riskassociated with Investmentcost uncertainty

Slight, Improvesproject economics

Moderate adverse effect;distorts input costs,favors capital-intensivetechnologies

Minimal administrativeburden

Benefits firms withlarge tax Iiability andstrong financialcapability

Supported very strong-ly by most firms;however, firms thatwould not be able to

use the investmenttax credit do not favorits enactment

supper Strong, subsidizes Moderate; shares r iskassociated with priceuncertainty

Moderate; improvesborrowing capa-bility

Slight adverse effect,distorts product price

Moderateadministrative burden

Benefits all firmsexcept those withvery weak financialcapability

Moderately supportedby a wide rangeof firms

product price (If contract price IS higherthan market price)

guarantee Slight, subsidizesInvestment cost

Moderate, shares risk ofproject failure

Strong; improvesborrowing capa-bility

Slight adverse effect;distorts input costs:favors capital-lntenswetechnologies

Slight adverse effect;distorts input costs,favors capital-intensivetechnologies

Slight adverse effect,distorts product pricesupports)

No adverse effect

Moderate admin -istrative burden

Benefits firms withweak financialcapability

Supported by firmswith limited debtcapacity

ized Interest Slight; subsidizes70% debt at Investment costow market

Moderate: shares risk ofproject failure

Strong, Governmentprovides capital

Moderate admin-istrative burden

Benefits firms withweak financialcapability

Supported by firmswith Iimited debtcapacity

ase Strong, but less thanments price supports

Strong: shares risk of priceuncertainty

Moderate; improvesfinancial capability

Moderate (normallymore than price sup-ports)

Moderate admi-nistrative burden

Benefits all btrms butthose with very weakfinancial capability

Benefits all firms

Moderate, but lessthan for pricesupports

grant (33 & Strong, neutralof plant cost) subsidy

None Strong; Governmentprovides capital

Supported by firms inwidely varyingfinancialcircumstances

nment Slightpation Strong, shares all projectrisks Moderate, reduces No adverse effect on firm Major adminstrativeburden Benefits firms that arevery averse to risk(e. g., smaller, lesswell-financed firms)

Little supportfirm’s capital require- decisions; however,ment active Government

Involvement may leadto inefficiency

Slight, improves Moderate adverse effec t,project economics distorts input costs,

favors capital-lntenswetechnologies

rated de- Moderate, subsidizeson (5 years) Investment cost,

Moderate, shares riskassociated with Investment


Benefits firms withlarge tax Iiabilitiesand strong financialcapability

Supported by large,integrated oilcompaniesmaximum subsidy ef - cost uncertainty

feet IS Iimited by Fed-eral corporate incometax rate and interac-tion with the deple-tion allowance

ntage deple- Moderate, subsidizes None, Increases riskal lowance product price, va lue associated with price un-) of subsidy Increases certainty

as the need for thesubsidy decreases

Slight, improves Moderate adverse effec t,project economics distorts product price in

a variable and undesir-able manner


Benefits firms withlarge tax Iiabilitiesand strong financialcapability

Not supported

Resource Planmng Assoclales Inc






Table 26.–Subsidy Effect and Net Cost to the Government of Possible Oil Shale Incentives’ (l S-percent rate of return on invested capitalb)

Ratio of change Total Ratio of changein expected expected in expected

Total expected Change in Standard profit to cost to profit toprofit c expected profit deviation standard Probability Breakeven Government Government

Incentive ($ million) ($ million) ($ million) deviation of loss price ($) ($ million) cost

Construction grant (50%) .Construction grant (33%)Low-in terest loan (70%)Production tax credit ($3)Price support ($55). ., ...Increased depletion allowance

(27%) .Increased Investment tax

c r e d i t ( 2 0 % ) ,Accelerated deprecation

( 5 y e a r s ) .Purchase agreement ($55).None. . . .,

$281

11981- 6 1- 8 8

$477315277135108

$135140153153122

3 52,21.80,90 9

0.000 1 90 2 30 6 30.77

$40.60

47.7054.7058.30

NA

$494327453252172

96

9661.5463

-110 86 170 0.5 0,75 57.20 197 44

- 131 65 150 0,4 0.77 58.80 87 75

- 1 2 7- 1 5 0- 1 9 6

6946

0

149102153

0.50,40.0

0 7 60 9 20.93

58.90NA

61.70

7900

87NANA

aAll monetar yvalues are In constant 1979 dollarsbwllh 12.0ercent annual Ifltlatlon a 15-oercent real dlscounl rate IS acmroxlmatelv a 27-oercent nominal afteflax rate ot returncExPec(ed P(ofll IS the return In excess Of a 15.percenl discounted cas’h tlOW rale’of return on Inveslmenl

dstandard devla[lon IS a measure Df (he dispersion of possible profll OUtCOmeS around expected Profll

SOURCE Resource Planmng Associates Inc

This tax credit will strongly subsidize theproduction of shale oil. By reducing a firm’stax liability, it effectively increases the unitproduct price by an amount equal to the taxcredit per unit of production (i.e., per barrel)divided by 1 minus the firm’s Federal corpo-rate income tax rate. For example, if a com-pany’s tax rate is 46 percent, a $3/bbl creditbecomes an effective price boost of $5.60. Atcurrent imported oil price averages of $35/ bbl, the effective price with the credit wouldbe $42.60. This price boost could substan-tially improve a project’s economics by creat-ing a higher aftertax cash flow throughout itsproducing life, and a higher return on invest-ment.

ing costs and the resultant project profitabil-ity, it may provide a sufficient asset baseagainst which firms may borrow for projectfinancing. However, it will not assist projectfinancing as strongly as a purchase guaran-tee or a debt guarantee.

The production tax credit also can enhanceeconomic efficiency, because it does not dis-tort a firm’s perception of the market pricesfor the economy’s productive resources (i.e.,land, labor, capital, and materials), that are

consumed in development and production.Moreover, if subsidizing oil shale develop-ment meets national objectives, this tax cred-it with a sliding-scale phaseout can be usedby firms as a baseline for making their deci-sions. To promote efficient investment andproduction decisions, the price subsidy af-forded by the tax credit should reflect thepremium society is willing to pay to encour-age the development of oil shale resources.

Because it works through the existing taxframework, implementing a production taxcredit should be relatively straightforward,necessitating little or no administrative over-head. The chief administrative policies wouldbe to define a reference price for determiningthe value of the credit, to set an inflation ad-

justment formula, and to develop a mecha-

Although the production tax credit doesnot share in the risks of project noncomple-tion or price and cost uncertainties, it woulddecrease the risk of incurring a loss by im-proving project economics. Therefore, it mayslightly improve the ability of firms to acquirecapital financing. However, this tax creditalone would not encourage financial institu-

tions to lend to a financially less secure oilshale developer.

A production tax credit has a function sim-ilar to a price guarantee. Depending on lend-er expectations about investment and operat-




nism for ensuring that firms accurately re-port the amount of shale oil produced. (How-ever, reliance on tax-based incentives wouldtend to reduce the Government’s control overproduction levels.)

Large, integrated oil companies will most

readily benefit from this incentive (i.e., thosefirms having both a sufficient Federal incometax liability to use the credit and a strongability to raise debt). Moreover, in trying tosecure a competitive advantage in the oilshale development industry, those firms thathave already undertaken investment in oilshale, and that can accept exposure to therisks of project noncompletion and invest-ment and production cost uncertainties, mayfavor production tax credits over all other in-centives,

The production tax credit is supported bymost of the larger firms involved in oil shaleactivities. The Atlantic Richfield Co. (ARCO),Gulf, Union, and Occidental, all companieswith current oil shale investments, rank iteither first or second in their incentives pref-erence lists. However, Standard of Indiana,which is Gulf’s partner in Rio Blanco, ranks itlast, preferring incentives that deal with thefront-end investment uncertainties. Chevron,which is just starting its oil shale develop-ment activities, directly opposes it in favor of an investment tax credit that addresses the

investment cost risks, which Chevron feelsare considerable, (See table 24. )

In calculating the quantitative effect of thisincentive, the unit value of the subsidy (estab-lished as $3/bbl of unrefined shale oil) wasmultiplied by the entire annual output; thatproduct was then subtracted from the incometax obligation for each year of production. *The results indicate that the $3/bbl tax creditranks fourth, behind the 50- and 33-percentconstruction grants and the low-interest loan,in its tendency to increase profitability andreduce the risk of loss. In addition, becauseobtaining the tax credit is simpler administra-

*In OTA’S analysis, the tax credit was calculated on shaleoil output prior 10 hvrirotrea t ing. Because of processing losses,the output of hydrotreatd oil is 12 to 15 percent lower.

tively than obtaining a grant, it might be pre-ferred by some firms.

Expected Profit

In comparison with no incentive, the $3/bbl

tax credit would increase the expected profitof the 50,000-bbl/d facility by $194 million.This increase was the fourth highest of the in-centives tested. With the tax credit, the ex-pected profit of such a facility would be $392million, more than enough to induce its devel-opment. Moreover, this tax credit would re-tain its high ranking irrespective of a firm’smarginal tax rate, unless it has excess taxcredits (i. e., the tax credit expires before thefirm has earned enough income to offset it).Although some firms might hold excess taxcredits at the outset of production, few, if

any, would hold them over the entire lifetimeof a project, given the eventual large annualincome that can be expected, Therefore, anexcess credit situation would be likely to existfor no more than a few years of the tax cred-it’s duration which could be short or long de-pending on the phase-out provisions.

The production tax credit is highly sensi-tive to the discount rate, however, becausethe subsidy is spread over a project’s entirelifetime, In fact, over the range of ratestested, this incentive is one of the most sen-

sitive to the discount rate: averaged over thediscount rates, each percentage point drop inthe discount rate resulted in a $20 million in-crease in expected profit.

Risk

Because the production tax credit does notreduce the variation in possible future pricesand costs, it does not reduce the overall vari-ation in possible profit outcomes. However, itsignificantly reduces financial risk because it

boosts the expected profit. For this reason,the production tax credit ranks fourth behindboth construction grants and the low-interestloan in reducing the probability of loss in thevariation in profit relative to the change inexpected profit.



200 qAn Assessment of 0il Shale Technologies

Breakeven Price

In the absence of an incentive, the break-even price was $48.20/bbl of hydrotreatedproduct, with the production credit it was$5.60 less, or $42.60/bbl. This price ranksthird behind the breakeven prices for 50- and

33-percent construction grants and the low-interest loans; nonetheless, it is still withinthe commercially feasible range, given theaverage discounted price of oil—$53.00/bbl—over the production period.

Cost to the Government

The cost to the Government is commensu-rate with the credit’s strong effect on profit-ability. Overall, it is the fourth most costly in-centive, ranking below the 33- and 50-percentconstruction grants and the low-interest loan.Moreover, the production tax credit is one of the least cost-effective (as measured by theratio of change in expected profit to Govern-ment cost). It ranks below most of the otherincentives, including construction grants.However, it offers two advantages over con-struction grants. First, the cost to the Govern-ment would be spread more evenly over time;the production tax credit would requireabout $49 million per year over a 20-year pro-duction lifetime, compared with $170 millionper year over a 5-year construction period forthe 50-percent grant. Second, it would bemuch easier to administer for both oil shaledevelopers and the Government. Developerswould simply file for the credit on their taxreturn, thus making the Government audit of production records straightforward.

Construction Grant

Under a construction grant program, theGovernment transfers a sum of money to afirm undertaking an oil shale developmentproject. In return, the firm must only fulfill itsobligation to undertake the project withinsome period of time. The size of the grantwould be some prespecified fraction of the in-vestment costs. Alternatively, the Govern-ment could hold the inverse of a bonus-bidlease auction (i.e., firms could bid the amount

required to operate a project capable of pro-ducing a specified quantity of shale oil). Inthis case, with sufficient competition, firmswould bid on an amount equivalent to the neg-ative expected present value of their projected aftertax income. Instead of bidding abonus to be paid to the Government, they

would bid a bonus to be received from theGovernment. Those bidding the lowest bo-nuses, up to some aggregate bonus payoutfrom the Government, would receive theawards.

A construction grant would make it possi-ble for otherwise uneconomic projects tohave a profitable, positive expected presentvalue of aftertax income. The immediate ef-fect of a grant will be to facilitate capital ac-quisition because less funds probably will beneeded from external sources. * In addition,over the life of the project, there will presum-ably be lower debt repayment requirements.A construction grant reduces the uncertaintyover investment costs but not over operatingcosts or product prices. Thus, depending onits size, a construction grant may signifi-cantly reduce the risk of project failure.Moreover, it may reduce the amount of exter-nal financing needed, and because it im-proves project economics, it enables the firmto borrow. However, it does not create anasset on the firm’s balance sheet, and willthus provide no assurance to lenders of afirm’s ability to meet its debt repaymentobligations. * *

The construction grant is not economicallyefficient since it affects a firm’s perception of its investment costs, creating a bias in favorof more capital-intensive projects. Moreover,once the plant is constructed, output deci-sions will be based on the market price of oilrather than the strategic value of domestical-ly produced synthetic fuel. Finally, the con-struction grant will be costly to administer

*A construction grant program should not be confused witha loan program or a program to facilitate financing. To assistfinancing, the Government should consider a direct-loan orloan-guarantee program.

*‘Unless a grant is to be paid at a future date and a firm bor-rows against it in the short term.




and may result in project delays if not proc-essed expeditiously.

There will be problems in deciding the sizeof grants without an auction. A firm can re-fuse the project if the grant is too small, If thegrant is too large, on the other hand, the firm

would receive excess economic rent* fromthe project at society’s expense. To minimizethe cost to the Government, the grant shouldequal the absolute value of the negative ex-pected economic rent on the project (plus, fora risk-averse firm, any risk premium).**

Second, even if the Government uses anauction to distribute grants, firms will prob-ably collect excess rents at the expense of society. The grant program shares none of the risks of oil shale development. If theserisks are as substantial as currently ex-

pected, firms may require large risk premi-ums in their bonuses to ensure against eco-nomic loss. Although necessary and efficientfrom a firm’s perspective, the risk premiumrepresents an excessive transfer of incomefrom the public to the private sector. Also,unless competition is high and firms haveequal access to technical information, bidswill not be driven down to the level of the neg-ative expected economic rent. In this case,firms may strategically bid more than thisfigure in an attempt to receive higher thanthe risk-free required rate of return for

undertaking the project.The administrative requirements associ-

ated with this incentive could delay imple-mentation of an efficient program for severalyears. The construction grant is a neutralsubsidy; all firms should be able to use it.They may, however, dislike the grant on ideo-logical grounds. Those that are more risk-averse will be at a competitive disadvantagein acquiring grants in an auction (i. e., theirrequirement for higher risk premiums willreduce the probability of winning a grant).

*Excess economic rent here indicates a situation where thedeveloper has recovered more subsidy than would have beenrequired to under ttike the project.

**A risk premium is the additional margin of profit requiredby a firm in order to undertake development.

Construction grants are supported by firmsof widely varying size and financial condition.In addition to those with more limited debt ca-pacity, two financially strong companies,Gulf and Standard of Indiana, also supportthis incentive. Gulf supports only limitedgrants; its partner in the Rio Blanco develop-ment, Standard of Indiana, supports front-end cash construction grants for up to 25 per-cent of project investment to help offset theheavy initial capital requirements of earlyprojects. (See table 24.)

The effects of grants of 50 and 33 percentof plant cost (estimated to average $1.7 bil-lion including upgrading) were analyzed, as-suming that the cost would be incurred over aperiod of 6 years and that the Governmentwould pay its percentage of each year’s costat the end of the year in which the cost was

incurred.On purely economic grounds, construction

grants would be ranked highly by oil shalefirms. Compared with the other incentives,the 50-percent grant would offer the greatestincrease in expected profit, the greatest de-cline in risk of loss, and the lowest breakevenprice. The 33-percent grant also compareswell, ranking second in its effect on profit-ability, ability to lessen the probability of loss,and breakeven price. For the Government,however, construction grants would be

among the most costly incentives.

Expected Profit

In the simulations, (see table 25) the 50-per-cent construction grant yielded an expectedprofit of $707 million. When compared withan expected profit of $220 million when no in-centive was employed this represents a gainof $487 million, the largest of any incentivetested. The 33-percent grant, although rank-ing second behind the 50-percent grant, re-sulted in $321 million in expected profit. Both

grant levels would therefore be more thanadequate to induce private development of the 50,000-bbl/d oil shale facility.

In assessing the effect of a constructiongrant on profitability, an analysis was made

f, 3-83 B - 80 - :4



202 q An Assessment of Oi/ Shale Technologies

of its sensitivity to a firm’s marginal tax rateand discount rate. An individual firm’s mar-ginal tax rate was found to strongly influencethe grant’s effectiveness: the higher the rate,the lower the value of the incentive to thefirm. Because the grant reduces the amount

of investment that is depreciated against cor-porate income tax, the developer has a highertaxable income as a result of this subsidy. Inanalyzing this incentive, the highest marginaltax rate (46 percent) was used in the calcula-tions; the value of the grants for firms withlower marginal tax rates would therefore begreater than that stated in this report.

It was found that the effect of constructiongrants on profitability, however, would de-pend only slightly on the level of the discountrate. The results were calculated using a 12-percent discount rate, * but the expected in-

crease in profit stemming from constructiongrants changes very little with discount ratesof 10 and 15 percent. This is because the sub-sidy is concentrated in the constructionphase, thus is discounted over relatively fewyears.

Risk

Because the Government shares so large aportion of cost, construction grants have avery pronounced effect on risk reduction. Forthe representative facility, the probability of

loss dropped from 9 percent with no incentiveto O percent with both the 50- and 33-percentgrants. Thus, these grants rank highest in re-ducing the risk of loss. In addition, the con-struction grants result in the greatest reduc-tion in the variation of profit outcomes (asmeasured by standard deviation) relative tochange in expected profit.

Breakeven Price

The 50-percent construction grant also hasthe lowest breakeven price, $34,00/bbl of pre-

mium syncrude, compared with $48.20/bbl*On the basis of studies showing that the real, aftertax re-

turn for U.S. business averages from 5 to 10 percent, the 12-percent rate was selected as representative. It reflects the riskinvolved in oil shale investment compared with that of the aver-age investment.

when no incentive was offered. The 33-per-cent grant results in the second lowest break-even price, $38.70/bbl. Either price wouldplace the shale oil facility in the commerciallyviable range. Given an initial oil price of $35/bbl, and the expectation that the price

will rise over time (at 3 percent per year inreal terms), the price of oil at the start of pro-duction in 1986 would be $42/bbl. It is moremeaningful, however, to compare the break-even price with a composite price of oil overthe production lifetime—$53.00/bbl.* Be-cause the breakeven prices with both the 50-and 33-percent grants are less than thisamount, the project would be viable.


Construction grants of 50 and 33 percent

would be among the most costly to the Gov-ernment. In the simulations, the gross cost tothe Government for the 50-percent grant was$170 million per year for each of the 5 yearsof construction. The net cost, however, de-pends on the marginal tax rate of the recipi-ent. Because the grant would reduce theamount of investment subject to depreciation,the Government would recover about one-third of the gross subsidy paid to firms with a46-percent marginal tax rate, through in-creased income tax payments. With this taxrate, the net cost to the Government for the

50-percent grant was higher than any otherincentive—$494 million** and third highestfor the 33-percent grant. However, the con-struction grants are the most cost-effective,as measured by the ratio of change in ex-pected profit to Government cost. The netcost figures, however, do not include adminis-trative costs, which could be significant.

To guard against cost overloading, the Gov-ernment would have to establish precise ac-counting guidelines and be prepared to auditall grant recipients. Furthermore, the grant

*The composite price is a constant price, which when substi-tuted for the escalating market price, does not change the prof-it calculations (see app. A).

**All Government costs are calculated in present valueterms using a lo-percent real discount rate. This is the rateadopted by the Office of Management and Budget (OMB) forevaluating Government programs. (See OMB’S Circular A-95.)



Ch. 6–Economic and Financial Considerations q 203

application procedure would tend to be time-consuming for both the Government (complexauditing procedures would be required) andthe applicant, (a well-documented applicationwould be required). Alternatively, the Gov-ernment could simply offer to award $400

million ($80 million per year for 5 years) toany company that is willing to build a 50,000-bbl/d plant, the only stipulations being thatthe plant must be completed and operated.

Low-Interest Loan

The effects of a low-interest loan are sim-ilar to those of a debt guarantee. Its primarypurpose is to assist firms in financing thelarge capital outlays required for oil shaleprojects. Those that otherwise would be un-able to raise sufficient capital would benefit

most from this incentive.With a low-interest loan incentive, the Gov-

ernment lends money directly to firms at alower interest rate than would be provided byprivate lenders. The money may be obtainedfrom general funds, designated taxes (e.g.,the extra-profits tax currently being consid-ered in Congress), or through a Government-financing authority (similar to the FederalNational Mortgage Assistance Program).

A low-interest loan and a loan guaranteewould have similar effects on project eco-nomics. Both would reduce the interest costof debt; as a result, the firm would have alower payout obligation and higher cash flowover the life of the project. A low-interest loanprogram could have a significant effect onproject economics. It provides access to capi-tal for firms that otherwise could not borrowin capital markets or that must borrow atvery high rates.

Its risk-sharing features are identical tothose of the loan-guarantee program. As thedirect lender, the Government shares the

risks of project failure and default on debtrepayment. The equity owners of the develop-ment firm remain exposed to the risks of proj-ect failure and loss of capital. With the low-interest loan program there is only minor

sharing in the risk of investment cost uncer-tainty and none in the risks of operating costand product price uncertainty. Because theGovernment lends directly to the firms, a sub-sidized interest loan facilitates direct accessto capital for financially weaker firms.

The effects on economic efficiency parallelthose of a loan guarantee. The reduced inter-est rate serves as a capital subsidy, thus, itmay favor relatively capital-intensive tech-nologies. The primary effect on efficiency isto encourage participation of a greater num-ber of firms in oil shale development projects.If increased competition leads to the testingand development of a wider variety of tech-nologies, future production costs for shale oilmay be lowered.

Because the low-interest loan incentive re-

quires discretionary review and approval of loan applications, it will be time-consumingand laborious to administer. Delays in imple-menting an effective program may be encoun-tered.

The firms that will most benefit from a low-interest loan program will be relatively weakfinancially with limited access to capital mar-kets. If the Government were to make debtavailable to all firms at less than marketrates (i.e., rather than at the AAA rate), all,independent of financial condition, could pre-sumably benefit from the incentive. Like loan-guarantee incentives, low-interest loan incen-tives are preferred by companies with limiteddebt capacity because they need subsidizedinterest loans to raise project capital.

This type of loan could be structured in avariety of ways. A loan for 70 percent of con-struction costs was analyzed. It was assumedthat loan funds would be made available dur-ing the years the construction costs would beincurred (e.g., if construction takes 5 years,funds would be dispersed over the 5-yearperiod at the rate of 70 percent of each year’s

cost per year. It was further assumed that thedeveloper would begin repayment at the endof the first year of production, that the loanwould be issued at an interest rate of 3 per-centage points below the prevailing market



204 An Assessment of 01/ Shale Technologies

rate (e.g., 9-percent nominal interest on theloan when the market rate is 12 percent), andthat amortization would occur over a 20-yearperiod.

A low-interest Government loan would be avery effective incentive, ranking close behind

the 33-percent construction grant and pro-duction tax credit in its effect on profitability.It would act to significantly reduce the risk of incurring a loss. However, it might be themost costly to the Government; as such, itcould be less cost-effective than other high-ranking incentives.

Expected Profit

The subsidized interest loan resulted in anexpected profit of $497 million comparedwith $220 million with no incentive. This $277million increase is less than the increases in-duced by the 50- and 33-percent constructiongrants but more than the $3/bbl productiontax credit. The size of the increase, however,depends on both the marginal tax rate for in-dividual firms and the access those firmshave to capital markets. For a firm with a 46-percent marginal tax rate, the 3-percent be-fore-tax difference between the Govern-ment’s interest rate and a firm’s borrowingrate becomes a 1.5-percent aftertax differ-ence, because interest payments are deducti-ble. The aftertax spread would be 2 percentfor a firm with a 3-percent marginal tax rate.Hence, the lower the marginal tax rate, themore the loan is worth. In addition, the higherthe rate of interest on alternative sources of debt financing, the more the loan is worth.Because different firms may have differentborrowing rates, they might value the Gov-ernment loan higher or lower than the valueOTA has computed.

Risk

The low-interest loan does not affect thedegree of variation in possible profit out-comes, because it does not reduce the vari-ation in future costs or prices. However, itdoes significantly reduce the risk of loss; withthe loan the probability of earning less than

12-percent return was 0.00, but it was 0.09when no incentive was offered. Moreover, theloan is effective in reducing the degree of variation in profit relative to expected profit,but to a lesser degree than the constructiongrants and production tax credit.

Breakeven Price

The low-interest loan resulted in a break-even price for premium grade synthetic crudefrom shale oil ($43.40/bbl) that is only slightlyhigher than the price resulting from the pro-duction tax credit ($42.60/bbl). However, it iswell below the price prevailing when there isno incentive ($48.20/bbl), and lower than theaverage expected market price over the pro-duction period ($53.00/bbl).


The low-interest loan costs the Governmentmore than any other incentive except the 50-percent grant. It also results in the lowestchange in profit per dollar cost. The grossoutlay for the 70-percent loan is actuallylarger than that for the 50-percent construc-tion grant because both are computed on thesame construction costs. Loan repaymentsafter the completion of the constructionphase would also be higher than the in-creased tax receipts under the 50-percentgrant program. However, because the subse-

quent receipts are discounted more heavilythan the initial outlay, the net cost to the Gov-ernment in present value terms would be al-most as great for the 70-percent loan as forthe 50-percent grant. Moreover, it actuallycould be higher than has been calculated, be-cause some firms might default on the loan. *

Purchase Agreement

In a purchase agreement, the Governmentsigns a long-term contract with a prospective

*These conclusions are extremely sensitive to the choice of Government discount rate. If Government cash flows were dis-counted at a rate of less than 10 percent, the loan would costless. For example, at a 5-percent real discount rate, the cost tothe Government is $2OI million compared with $453 millionwhen the discount rate is 10 percent.



Ch 6–Economic and Financial Considerations 205

oil shale developer to purchase some quantityof shale oil or hydrotreated syncrude at acontract price (either in nominal or realterms). The Government may set the contractprice directly, negotiate it with firms, or in-vite contract price bids. If the contract priceis negotiated or set by competition, the Gov-ernment can selectively apply the incentive tothe most efficient firms by granting the pur-chase agreement to firms bidding the lowestcontract prices. The Government can alwayscontrol the number of firms using the subsidyby limiting the number of projects and thequantity of shale oil production covered inguaranteed price contracts.

The purchase agreement incentive and theproduction tax credit subsidize shale oil pro-duction by providing (presumably) a higherprice to developers than they would receive

in the open market. Higher prices will benefita firm over the life of the project, or until thespecified quantity of shale oil has been pur-chased.

The purchase agreement reduces projectrisk stemming from the uncertainty over fu-ture oil prices. Because the product price isessentially fixed, the Government bears allthe risk of price variations. However, this in-centive does not share in the risks of projectnoncompletion or investment and operatingcost uncertainties,

It does offer some security to lenders, andmay provide a sufficient asset base for firmsto borrow against. As a result, the prospectsfor project financing are improved for firmswith limited ability to raise debt. Like the pro-duction tax credit, the purchase agreementalso has distinct economic efficiency advan-tages. It does not distort the prices of re-source inputs and thus encourages firms toutilize efficiently the Nation’s economic re-sources. In addition, it does not arbitrarily fa-vor any development technologies based ondifferences in capital intensity or required

construction time. Because it works throughthe product price mechanism, the extent of the subsidy for shale oil is readily apparent,and, in theory, should be set at a level that re-flects the social benefit of domestic shale oil

production. Finally, when combined with acompetitive bid mechanism, the purchaseagreement also subsidizes only the most effi-cient firms.

Despite its advantage for economic effi-ciency, this incentive imposes significant

burdens on administrative efficiency. TheGovernment must determine the amount of shale oil to be subsidized and the contractprice, and it must manage a system for allo-cating the price contracts. If competitive bid-ding is used to allocate contracts and set con-tract prices, managing the auction is anothermajor administrative requirement. Moreover,because the mechanisms are less familiar toindustry than for such other incentives as thetax credit, they will impose higher costs onfirms attempting to use and benefit fromthem. Although purchase agreements entail a

considerable amount of administrative bur-den, its type and extent are strongly depend-ent on the particular mechanisms employed.

According to this analysis, all firms exceptthose with very weak financial ability shouldbe able to benefit from purchase agreements.Unlike the tax credit, a firm’s ability to usethis incentive is not limited by the size of itsFederal tax liabilities. To some degree, thosethat have not yet invested in oil shale develop-ment and are strongly averse to the risk of in-vestment cost uncertainty may find this in-

centive less attractive than the investmenttax credit and the loan guarantee.

Expected Profit

In the simulations, a purchase agreementof $55/bbl resulted in an expected profit of $231 million compared with $220 million withno incentive. The $11 million gain in profit-ability ranks behind gains achieved with allthe other incentives tested. The effect onprofitability is less than that of the $55/bblprice support, because with the price support

a firm benefits when the price exceeds $55/ bbl (this occurs in the ninth year of produc-tion, assuming a 3-percent annual price in-crease). The subsidy effect of purchaseagreements (and also price supports) is tied to




the contract price. At such price, the pur-chase would cost the Government nothing.However, its subsidy effect is also low. Theuse of a higher contract price would havesubstantially increased its incentive impact.

Risk

Because it eliminates all variations inpossible future prices, the purchase agree-ment results in a large reduction (25 percent)in variations in possible profits. However, itdoes not reduce the probability of loss asmuch as the price support, because a compa-ny cannot benefit from upward variations inprice above the purchase agreement price.

Breakeven Price

Because this incentive establishes a mini-

mum price above the breakeven price whenno incentive exists, there is no meaningfulbreakeven price under the price support orthe purchase agreement.


At no direct cost, the purchase agreementwas the least costly incentive for the Govern-ment. Government costs are incurred fromthe first year of production until the marketprice equals or exceeds the fixed purchaseagreement price, If the market price in-

creases over time, the cost to the Governmentdeclines, and if the market price exceeds thefixed price, the Government will regain partof its subsidy through low-cost purchases of shale oil. It can also recapture part of thesubsidy through the increased taxes that re-sult from a developer’s larger taxable in-come. In analyzing this incentive, a high mar-ginal tax rate for the company was assumed;the cost to the Government would be higherthan calculated here if the company had alower marginal rate.

Price Support

A price support is currently being consid-ered in several proposals before Congress. Itis similar to a purchase agreement, except

that the Government does not take title to theshale oil; it simply pays the difference be-tween the support price and the prevailingfree-market price. If the free-market price ex-ceeds the contract price, the Governmentpays nothing. The price support, like the pur-chase agreement and the production tax

credit, subsidizes shale oil production since itis presumed to have a probability of beinghigher than the market price of imported oil.

The effects on project risk and efficiency of the price support are similar to those of thepurchase agreement: it reduces the risk of oilprice uncertainty, it improves access to debtcapital, and it improves project economics.Like the purchase agreement, the price sup-port entails significant administrative costs.However, in general, those associated withprice supports are lower than those for pur-

chase agreements.

Expected Profit

In the simulations (see table 25), a $55/bblprice support resulted in an expected profitof $363 million, which is more than enough toinduce a profit-maximizing firm to undertakean investment in oil shale. The level of profitpresents a gain of $142 million over the casein which no incentive is offered, placing theprice support midway in the ranking.

As with most of the other incentives, theexpected profit for individual firms using theprice support will depend on their marginaltax rates. The price support will be worthless to firms with high marginal tax ratesthan to those with low marginal tax rates,because the subsidized price increases tax-able income.

Expected profit is also very sensitive to afirm’s discount rate, because the price sup-port begins only after the start of productionand continues for a number of years. The ex-pected profit gain under this incentive variesmore with changes in the discount rate than itdoes with a construction grant. On the otherhand, the price support represents a relative-ly larger sum in the early years of production(assuming increasing oil prices) compared




with the constant tax credit. Thus, the $55/ bbl price support is somewhat less sensitiveto changes in the discount rate than is the$3/bbl production tax credit.

Risk

The price support is effective in reducingrisk because it eliminates the possibility of aprice for oil below the floor price. By reduc-ing the variation in possible future oil prices,it reduces the total variation in possible profitoutcomes. In the simulations, the variation inprofit with the price support was reduced byover 20 percent compared with no incentive.Given this reduction and the increased ex-pected profits, the probability of incurring aloss drops from 0.09 with no incentive to 0.01with the $55/bbl price support. This reduc-tion in risk is only slightly below that for con-struction grants, the low-interest loan, andthe production tax credit. (See table 25.)

Breakeven Price

Because this incentive establishes a mini-mum price above the breakeven price whenno incentive exists, there is no meaningfulbreakeven price under the price support orthe purchase agreement.


The price support, which ranks fifth in itsnet cost to the Government, would be spreadover most of the production life of the facility,with a larger share in the early period if theprice of oil continues to rise. In the analysis,the net cost figure of $172 million, which ac-counts for the partial recovery of the grosssubsidy through increased income taxes, wascalculated using a 46-percent tax rate. Thecost of this incentive to the Governmentwould be higher in the event of lower margin-al tax rates.

Investment Tax Credit

Several oil shale developers view the in-vestment tax credit as one of the most desir-able incentives. These firms have indicated

that an additional 10- or 15-percent invest-ment tax credit would be particularly attrac-tive. (See table 24.)

Like the production tax credit, an invest-ment tax credit strongly subsidizes the pro-duction of oil shale. Under current tax ac-

counting procedures, it effectively reducesthe cost of an investment by the percentage of the tax credit. That is, firms can deduct aspecified percentage of their capital costsfrom their income tax liabilities during thefirst year in which the project operates.When construction is scheduled over severalyears, a firm’s actual benefit is reduced bydiscounting because the tax credit is nottaken until the project begins operation. Theinvestment tax credit increases net cash flowearly in the life of the project when compa-nies often need such a boost. However, de-

pending on the dollar value of the investmenttax credit relative to a firm’s tax liabilities, itmay take several years to fully utilize the taxbenefit if other revenues are not available onwhich to use the tax writeoffs.

By reducing investment costs by a specifiedpercentage formula, the investment tax cred-it reduces the variance in investment cost,and allows the Government to share in therisk of capital-cost uncertainties. In the earlystages of oil shale commercialization, capital-cost uncertainty will be a major source of

risk,

As investment costs increase, the sharepaid by the Government increases in propor-tion to the percentage rate of the tax credit.Conversely, as investment costs decrease, theGovernment’s share decreases. The invest-ment tax credit does not share in the risks of project noncompletion and price and operat-ing cost uncertainties.

Although an investment tax credit will en-hance a project’s profitability and return oninvestment, it cannot overcome the financingproblems of firms with limited debt capabili-ty. Unlike the production credit, it does not in-duce lenders to provide the substantialamounts of capital required for oil shale de-velopment.




The effect of the investment tax credit oneconomic efficiency is less desirable than theproduction tax credit, for several reasons.First, it interferes with a firm’s perception of the market prices for the resources used in oilshale development. This incentive subsidizesinvestment costs only, and so favors the morecapital-intensive development technologies.In addition, because the value of the tax bene-fit decreases as the length of the constructionperiod increases, an investment tax credit in-centive favors development technologies withrelatively short construction leadtimes.

Because the investment tax credit has beenpart of the tax structure for several years, itis particularly easy to implement. Analysishas indicated that large, integrated oil com-panies (i.e., firms with large tax liabilitiesand strong financial capabilities) will prefer

and benefit most. By inference, firms thatprefer an investment tax credit to a produc-tion tax credit are more averse to the riskassociated with investment cost uncertaintythan to the risk associated with product priceuncertainty.

Expected Profit

In simulating the impact of a simple IO-per-centage point increase* in the investment taxcredit, it appeared unlikely that it would in-crease the profitability of oil shale ventures

enough to induce their development. In thequantitative analysis, the hypothetical facili-ty had expected profits of $299 million com-pared with $220 million without an incentive.On the basis of the effect of profitability, theincreased investment tax credit ranked nearthe bottom, above accelerated depreciationand the purchase agreement.

The investment tax credit’s effect on prof-itability (like the production tax credit) is notsensitive to the marginal tax rate unless afirm has excess credits at the time the in-creased tax credit expires. However, unlikethe production tax credit, the investmentcredit is claimed over a short construction

*The existing investment tax credit has an additional IO-per-cent tax credit for energy investment, However, this credit wasignored in the calculations because it was due to expire in1982.

period rather than a long production period.Therefore, its value is relatively more sen-sitive to a firm’s overall tax credit situation.This credit is, however, relatively insensitiveto a firm’s discount rate because all the taxcredit would be claimed early in the life of theproject and would thus be discounted over

relatively few years.

Risk

The investment tax credit was found tohave a slight effect on the risk of loss but vir-tually no effect on the variability of profit out-comes. With this incentive, the probability of a loss dropped to 0.05, the same level as theincreased depletion allowance and acceler-ated depreciation.

Breakeven Price

At $45.80/bbl, the breakeven price of theinvestment tax credit was slightly higher thanthat of the increased depletion allowance($45.70/bbl), and not significantly less ($2.20)than the breakeven price with no incentive.


For this incentive, the cost to the Govern-ment ($87 million) was among the lowest,ranking just above accelerated depreciation.Compared with the depletion allowance, how-

ever, the cost of the tax credit would be in-curred over a shorter period of time.

Accelerated Depreciation

Accelerated depreciation for tax account-ing has been discussed by several firms as apossible incentive for encouraging develop-ment projects. For example, they have sug-gested that oil shale investments be deductedfrom income over a period of 5 years insteadof 10 to 15 years, as is now expected. Somefirms have even suggested the possibility that

the entire oil shale investment could be writ-ten off in the first year of project operation.

Accelerated depreciation functions simi-larly to an investment tax credit. It provides amodest subsidy for development. However, in




comparison with an investment tax credit, ac-celerated depreciation will have a weaker,only moderate subsidy effect, which is limitedby the firm’s marginal income tax rate andthe interaction of depreciation with depletionin tax computation procedures.

Shortening the period over which invest-ment costs may be deducted from pretax in-come increases the present value of the taxdeductions and, thus, will lead to a higherreturn on investment for a project. In addi-tion, accelerated depreciation would improvecash flow in the early years of a project’soperation when firms are often short of cash.In effect, the Government pays an increasedshare of the investment cost through reduc-tions in income tax liability. The share paid isthe present value of depreciation deductionsmultiplied by the firm’s Federal income tax

rate, which thereby sets a ceiling on the sub-sidy effect of this incentive. The maximumbenefit would be obtained with an instantane-ous writeoff; in this case, the share paid bythe Government would be equal to 0.46 multi-plied by the cost of the investment (assuming46 percent of the firm’s corporate income taxrate).

However, the subsidy effect of accelerateddepreciation could be limited by the interac-tion of depreciation and percentage depletionin computing Federal income tax liability.

Percentage depletion is a deduction from tax-able income that is determined as a percent-age of gross production revenue in any year.However, the maximum deduction for per-centage depletion allowed in any year is 50percent of net income after subtracting allother deductibles allowed by the InternalRevenue Code. Such deductibles include de-preciation. Thus, increasing the depreciationallowance in any year would reduce the in-come ceiling on the depletion allowance andcould reduce the deduction allowed for per-centage depletion. In this case, the benefit to

a firm from accelerated depreciation wouldbe somewhat offset by the reduction in thetax benefits of percentage depletion,

Through accelerated depreciation, theGovernment shares in the risk stemming from

the uncertainty of investment cost. In effect,it pays a percentage share of the investmentcosts of a project, thus reducing their varia-tion. It has no effect on the risks stemmingfrom the possibility of project failure and theuncertainty of production cost and price,

Accelerated depreciation will improveproject economics but, by itself, is not suffi-cient to facilitate a firm’s access to debtmarkets. It does not provide an asset againstwhich firms may borrow.

Accelerated depreciation has a negativeeffect on economic efficiency. * It interfereswith the perceived prices of the resource con-sumed in oil shale development. Because itfunctions as a capital subsidy, it will favorthe more capital-intensive technologies. Itwill not affect the production signal providedby product price. Moreover, like the invest-ment tax credit, accelerated depreciationdoes not function through an easily observ-able mechanism (e. g., product price). There-fore, it will be relatively difficult for societyto ascertain the magnitude of the premium itis paying to develop domestic oil shale re-sources.

Depreciation, which is familiar in tax ac-counting, would probably entail a minimal ad-ministrative burden to implement.

Large, integrated firms with strong finan-

cial positions will benefit most from this in-centive. Their pretax income and tax liabil-ities from other business activities are suffi-ciently high that the accelerated depreciationwriteoffs can be taken as they become avail-able. In addition, unless the accelerated de-preciation is made retroactive, firms thathave not yet invested in oil shale developmentwill have a somewhat stronger preference forthis incentive than firms that have made in-vestments with a longer depreciation sched-ule.

‘This assumes that the existing depreciation period is effi-cient. In actuality, depreciation probably inefficiently biasesagainst capital-intensive projects. Shortening the ciepreciat ionperiod reduces some of this bias and hence promotes efficien-cy.




Expected Profits

In the simulations, the accelerated deprecia-tion schedule induced an increase in ex-pected profit of $76 million, which was thesecond lowest figure for any incentive tested.

The effect of accelerated depreciation onprofitability depends greatly on the tax situa-tion of a firm: it will benefit firms with highermarginal tax rates more than it will benefitthose with lower rates. This difference arisesfor two reasons. First, the amount of tax sav-ings for a given amount of depreciation isdirectly proportional to a firm’s tax rate. Sec-ond, a firm with a high marginal tax rate andwith other income-producing investments willbe able to write off the depreciation againstother income, whereas a firm with a low taxrate will be likely to have excess deductions.

In the latter case, the increased depreciationdeductions must be carried forward and arethus worth less, through discounting, thanthey would be if they could immediately offsettaxable income.

The value of this incentive is also affectedby the discount rate. The effect is slight,however, because both the tax writeoff andits timing are small. A 3-percentage point in-crease in the discount rate produced only alo-percent reduction in the change in ex-pected profits.

Risk

Accelerated depreciation was found tohave little effect on the risk of oil shale in-vestments. In the simulations, the probabilityof incurring a loss did not drop significantlynor did the absolute variation in possibleprofit outcomes. Relative to change in ex-pected profits, the variation in profit wasnext to the lowest, ranking above the pur-chase agreement.

Breakeven PriceBy analysis, the breakeven price with the

5-year depreciation incentive was found to be$46.00/bbl compared with $48.20/bbl for the12-year depreciation. This reduction in

breakeven price was the smallest of any in-centive tested.


Of the incentives tested, accelerated de-preciation is one of the least costly to the

Government and one of the most cost-effec-tive. In the simulations, the net cost to theGovernment was $79 million, and the ratio of change in expected profit to the Governmentwas 0.96. Moreover, because the incentive isgranted through the existing tax system, thecost of its administration would be negligible.(See table 25.)

Increased Depleti on Allowance

An increased percentage depletion allow-ance has been discussed as a possible incen-tive for encouraging oil shale development.Firms have suggested that the percentage de-pletion allowance be increased to 25 or 27percent.

The primary effect of an increased per-centage depletion allowance would be to sub-sidize the economics of oil shale development.Specifically, increasing the depletion allow-ance will increase the share of productionrevenues that are shielded from the Federalcorporate income tax. The depletion allow-ance, like a product-price increase, will im-

prove a firm’s cash flow throughout the pro-ducing life of a project. As a result, a firm’sreturn on investment for a project is im-proved.

The depletion allowance might be assumedto be as effective an incentive as the produc-tion tax credit because both function throughthe price mechanism. However, it has severalundesirable characteristics as a subsidy. Thepresumptions underlying its use as an incen-tive are that oil shale development is uneco-nomic and that the increasing (effective)

product price is the appropriate vehicle forits subsidization.

To be an efficient subsidy through the pricemechanism, the value of the price subsidyshould decrease as the product price in-




creases (i. e., as the need for the subsidydecreases). However, the percentage deple-tion allowance has the reverse effect. As theproduct price increases, the value of theprice subsidy also increases. Conversely, asthe product price decreases and the need for

the subsidy increases, the value of the sub-sidy actually decreases. This effect will makeit impossible to maintain the subsidy at a de-sired level.

In addition to its undesirable subsidy ef-fects, the percentage depletion allowance haspoor risk-sharing characteristics. In fact, itincreases the risk associated with the uncer-tainty about future shale oil prices. Becausethe value of the price subsidy increases withthe product price, this incentive magnifies theeffects on a firm of changes in the productprice. The variance of aftertax income in-

creases as the percentage depletion allow-ance is increased. This incentive does notshare in the risks either of project failure orof the uncertainties of investment and operat-ing cost. The depletion allowance will im-prove project economics but will not signifi-cantly influence a firm’s ability to raise debt.

The effect of the percentage depletion al-lowance on economic efficiency is similar tobut more adverse than the production taxcredit. It does not affect the prices of re-source inputs. Consequently, resources

should be combined in an economically effi-cient manner and a firm’s preference for spe-cific oil shale development technologiesshould not be influenced. However, in effect,it alters the price perceived by a firm andthus will influence its production and invest-ment decisions. Moreover, the contrary man-ner in which the subsidy effect increases asproduct price increases will make it difficultfor the Government to use this incentive topromote efficient decisions that reflect thesocial benefits of shale oil production.

Like accelerated depreciation, percentagedepletion is a familiar component of the U.S.tax code, and would thus be very easy to ap-ply. The firms that will benefit most from anincreased depletion allowance will be thosehaving large before-tax income and large tax

liabilities. Moreover, by inference, firms thatprefer an increased depletion allowance arerelatively unconcerned about risk of futuredecreases in product price. Rather, they areapparently betting in favor of continued long-term increases in the price of imported oil. No

firm seriously advocates this incentive. (Seetable 24.)

In analyzing this incentive, an increase inthe depletion allowance from the current 15to 27 percent was assumed. Such an increasewould be a significantly less effective incen-tive than the construction grants, the produc-tion tax credit, the low-interest loan, theprice support, or the purchase agreement.Compared with these other incentives, the in-creased depletion allowance would result ina much smaller gain in expected profits and

only a slight reduction in the risk of incurringa loss.

Expected Profit

The increased depletion allowance re-sulted in a comparatively modest gain in ex-pected profit—$140 million—compared withno incentive. Because firms cannot claimdepletion deductions in excess of 50 percentof taxable income, increasing the depletionallowance above 27 percent does not result insignificant additional expected profit.

For firms with lower marginal tax rates,the gain in expected profit would be evensmaller. In the simulations, for example, the$140 million gain in profitability calculatedusing a 46-percent tax rate would be reducedto only $70 million if the tax rate were 23 per-cent. (See table 26.)

The effect of an increased depletion allow-ance on profitability is also more sensitive tothe discount rate than any other incentivetested. This sensitivity stems from the in-crease in the incentive’s value that accompa-nies the increase in the real price of oil (andhence revenues). Thus, a higher value in lateryears is more sensitive to discounting than avalue that remains constant over time (as theproduction tax credit does, for example).



. ..

212 An Assessment of 0il Shale Technologies

Risk

Although a higher depletion allowance ac-tually increases the variation in possible prof-its, the gain in expected profits results in asmall reduction in the probability of loss. Inthe simulation the 27-percent depletion allow-

ance reduced the probability of loss to 0.05,compared with 0.09 when no incentive wasemployed. The increase in the variability of profit outcome occurs because profits aremore sensitive to changes in future priceswith the higher depletion allowance.

Breakeven Price

Although the increased depletion allow-ance will result in a reduced breakeven price,this reduction is likely to be small. In thesimulations, the breakeven price fell from

$48.20 to $45.70/bbl. (See table 25.)


The cost of this incentive to the Govern-ment is commensurate with its effect on ex-pected profit. In the analysis, the increaseddepletion allowance cost $197 million, whichmakes it the fifth most costly incentive. More-over, it is not a cost-effective option since itresults in the second lowest ratio of change inexpected profit to Government cost.

Loan Guarantee

Under a loan-guarantee incentive, whichhas been frequently discussed in Congressand by oil shale developers, the Governmentguarantees to lenders to repay a specifiedportion (e.g., 50 to 70 percent] of the projectdebt if a firm defaults on its debt paymentsbecause of the economic failure of its oil shaleproject. A loan guarantee would be adminis-tered selectively by a Government agencywithout charge or for a fee. Under a fee ar-

rangement, a firm effectively buys an insur-ance contract to guarantee debt repayment,

A loan guarantee is primarily designed tofacilitate project financing and, as a result,has only a limited subsidy effect on the eco-

nomics of oil shale development. Indeed, theonly effect on project economics is to reducethe interest rate on debt for firms with lowbond ratings. Thus, over the life of a project,a firm’s debt service obligation will be some-what reduced. A loan guarantee will be of lit-tle or no value in improving project economicsfor firms with strong balance sheets that canborrow at low rates.

This type of incentive requires the Govern-ment to share directly in the risks both of project failure and of default by a firm on itsdebt obligations. However, as long as a firm’sequity contribution to total project investmentremains at a reasonable level (e.g., 40 per-cent or more), a loan guarantee does not un-duly shield a firm from economic loss (i.e., theincentive does not introduce moral hazard). *In the event of default, the loan guarantee

does not protect equity owners against loss.As a result, it encourages management tooperate in an economically efficient manner,and provides only weak protection from therisk of investment cost uncertainty—but onlyif it is for a percentage share of the capital re-quired for the project and if the firm can bor-row at a lower interest rate than would other-wise be possible. A loan guarantee does notshare in the risks of operating cost and prod-uct-price uncertain y.

Of all the incentives that provide for pri-

vate lending, it has the strongest effect in im-proving the ability of firms with limited debtcapability to borrow in capital markets. Byguaranteeing the fulfillment of a specifiedportion of a firm’s obligations, the loan-guar-antee program provides an asset that finan-cially weaker firms may borrow against.

Given its limited effects on project econom-ics, a loan guarantee has relatively minor ef-fects on efficiency. It acts as a capital sub-sidy and so may favor more capital-intensivetechnologies. It does, however, improve com-petition in oil shale development by removinga major barrier to entry for less well-fi-

*Moral hazard would exist if the guarantee was constructedas to eliminate so much corporate risk that project failure is en-couraged+




nanced firms. Enhancement of competitionmay lead to testing a broader set of technol-ogies, and in the long run may result in higheroverall efficiency by reducing productioncosts.

This incentive will present certain admin-

istrative problems, even though the Govern-ment has previously used loan-guarantee pro-grams. A firm’s application must be selective-ly reviewed and approved, thus increasingthe potential for delay.

The loan-guarantee incentive benefitssmaller companies with an insufficient assetbase to back the major debt requirements forundertaking an oil shale development project(i.e., companies with a limited capability toraise debt that would otherwise have to bor-row at higher interest rates or be excluded

from oil shale development). In addition,larger companies with a large asset base butalso large debt (i. e., a high debt/asset ratio)may also need guarantees to embark on an oilshale project. With the increasing debt/equityratios evident in the petroleum industry, agrowing number of firms fit this description.Those with a strong balance sheet and largeasset base will not benefit from a loan-guarantee program, and for competitivereasons may not prefer its implementation.

Loan guarantees tend to be preferred byfirms that have limited debt capacity. Superi-or Oil backs them in principle, believing thatthey will help some companies obtain financ-ing to get their plants started. The Oil ShaleCorp. (Tosco) reported that it would needthem to obtain financial backing, and SOHIONatural Resources, a subsidiary enterprisewith limited debt capability, claims it couldalso take advantage of them. Occidental, aconsiderably larger firm, advocates any andall types of loans or loan guarantees, espe-cially nonrecourse loans. As would be ex-pected, the largest and financially strongest

companies find loan guarantees less desir-able. (See table 24. )

Government Participation

Government participation has been dis-cussed as part of several bills being con-sidered in Congress. Although it has certainfundamental advantages if the primary pur-

pose of an oil shale incentive program is toshare risk, it would meet strong resistance onideological grounds, and would be extremelydifficult to administer. Moreover, it may leadto inefficiency in oil shale development andproduction activities.

A Government participation program isbased on the assumption that oil shale devel-opment is economically sound but has veryhigh risks. Because of these risks, privatefirms are assumed to be reluctant to under-take projects, or willing to undertake themonly with the expectation of high profits ontheir investment to cover their risks. Govern-ment participation would provide a mecha-nism for it to share risks with private firmsthus encouraging them to commit capital tooil shale projects.

In such a program, the Government wouldprovide a specified share of equity. From thatpoint on, it would simply be an equity partnerin the project and would share proportionate-ly in any project losses or profits. Dependingon the terms of its agreement, the Govern-ment could either be a silent partner or par-

ticipate in management decisions. The part-nership could be managed through an exist-ing agency or a separate, newly formed ad-ministrative unit (e.g., the proposed EnergySecurity Corporation).

Because Government participation is sim-ply a joint venture arrangement between theGovernment and private firms, this incentivewould not provide any significant subsidy tooil shale development. It would, however,have the strongest effect of all the incentiveson the sharing of risk between public and pri-

vate sectors. In this program, the Governmentwould share in the risks associated with all



214 An Assessment of 011 Shale Technologies

project uncertainties in proportion to its per-centage ownership in a project. When theproject showed a loss, the Government wouldlose; when it showed a profit, the Governmentwould win. Government participation wouldreduce a firm’s exposure to economic loss. Atthe same time, it would decrease the potentialgains for a firm. That is, the variance in afirm’s expected present value of aftertax in-come would be proportionately reduced bythe multiple (1 – SG)2, where SG equals theshare of Government ownership.

The extent to which Government participa-tion would assist a firm in raising debt willdepend on the terms of its involvement in aproject. If the Government does not agree toguarantee a firm’s project debt, its participa-tion would have little effect on the firm’sability to borrow. Debt-financing support

would still come from the firm’s own assetstructure. Alternatively, if the Governmentprovided a share of project debt or guaran-teed a share of project debt, a firm’s debt re-quirements would be reduced, and loanscould be more easily acquired.

A Government participation programwould have essentially neutral effects on theeconomic efficiency of private sector invest-ment and operating decisions. By simply cre-ating a partnership or joint venture, the in-centive neither changes cost or prices, nor

provides a project subsidy. * The primary ef-fect of this incentive on economic efficiencywould be to reduce the effects of private sec-tor risk aversion. However, economic effi-ciency may decrease if the Government de-cides to operate as an active partner in oilshale development projects. Efficiency wouldbe reduced if Government participation, as aresult of inexperience or bureaucratic inter-ference, contributed to inefficient managerialdecisions.

A Government participation programwould entail the greatest administrative bur-

den of all incentives. A new Government bu-reaucracy would probably have to be created

*In theory, a Government participation program would becombined with a block grant program to achieve a highly effec-tive subsidy and risk-sharing incentive program.

to manage the program, with the likelihood of lengthy delays in getting the program to oper-ate effectively.

OTA’s analysis indicates that Governmentparticipation would most benefit firms thatare relatively risk-averse, thus unable to fi-

nance an oil shale development project alone.However, because private firms may join to-gether in partnerships, there may be no in-centive for them to enter a joint venture withthe Government as an active partner. If theGovernment adopted a silent-partner role,however, a firm could take full managerial re-sponsibility for a project, while still receivingthe risk-sharing and financial benefits of the

joint venture. Such an arrangement is notusually possible with any other private part-ner.

All firms except one oppose the Govern-ment participation incentive, primarily be-cause of their fears of bureaucratic ineffi-ciencies, of support of one technology to theexclusion of another, and of administrativeproblems. The only advocate, SOHIO, hassought $15 million in Government appropria-tions to help fund its already approved full-sized module program.

The Government could also contract for theconstruction of several modular plants itwould then operate, either alone or throughcontracts. It could thus conduct operations toobtain accurate information about technicalfeasibility, project economics, and the rela-tive merits of different processes. This wouldbe of assistance in evaluating its future pol-icies toward oil shale, in disseminating tech-nical information, and in improving its under-standing of the value of its oil shale re-sources. After enough information had beenobtained, the facility could be scrapped orsold to a private operator. This policy wouldprovide the Government with information andexperience. However, the cost would be much

higher than that of incentives to private de-velopers.

Considering that the technologies to betested are proprietary, it is by no means clearthat the Government would have the legal






ministrative involvement than do tax credits,accelerated depreciation, or increased deple-tion allowances. The absence of close super-vision of nontax incentives can lead to over-subsidizing developers. On the other hand,the creation of bureaucratic mechanismsthat are extremely time-consuming and com-plicated, or which make the acquisition of thesubsidy or its level dependent on futureevents that the developer cannot foresee, willradically reduce the subsidy effect of the in-centives.

OTA has concluded that production taxcredits, purchase agreements, and price sup-ports are the most viable subsidy mechanisms

to employ if the Government decides it isnecessary to provide financial incentives.The subsidy effect of the purchase agreementand price support incentives are relativelylow for the contract price ($55/bbl), whichwas computer simulated in the present anal-ysis. This should not detract from the qualita-tive merits of these incentives. Furthermore,this analysis indicates that either loan guar-antees or low-interest loans will be necessaryto ensure significant participation by smalleror even moderately sized firms. The high costof providing low-interest loans suggests thatdebt guarantees would be the best mecha-nism through which to ensure this partic-ipation.

Are Financial Incentives Needed?

The rationale for providing financial incen-tives is that hastening the commercializationof oil shale technologies, which although notimmediately viable would probably be capa-ble of commercialization at a later date,serves the long-run economic and national in-terests of the United States, The assumptionsunderlying this argument are that capital re-quirements, remaining technical uncertain-ties, risk of cost overruns, unstable regula-tory environments, and uncertainties aboutpresent or future profitable marketability in-

dicate to developers that their capital wouldbe more profitably employed in alternative in-vestments. An incentive or subsidy alters theeconomics of commercial production by at-tempting to either sufficiently reduce the riskor raise the profitability to encourage devel-opment.

Whether and to what extent oil shale de-velopment will require subsidization dependson the present and anticipated future rela-tionship between oil prices and the cost of producing shale oil. Expectations concerning

these future trends involve a consideration of such factors as: the developer’s confidence inthe accuracy of shale oil plant cost estimates,world petroleum demand, OPEC cartel pric-ing decisions, the political stability of foreignoil supply, and the rate of profit a company

requires to justify its investment relative toalternatives.

Assuming that developers have some confi-dence in their present estimates of plantcosts, and that these estimates contain con-tingencies for regulatory delay and environ-mental litigation, then the primary considera-tion becomes the ability to market at an ac-ceptable rate of return. Developers base theirevaluation of marketing potential on the re-quired rate of return and the feasibility of ob-taining this return given the price of compet-ing OPEC crude. Until very recently, it wasaccepted that the commercialization of shaleoil would require some form of subsidy.

In narrow economic terms it is no longerclear that shale oil requires subsidy to com-pete profitably with conventional petroleum.Price hikes during the end of 1979 and thebeginning of 1980 have increased averageposted spot prices for foreign and domesticcrudes by more than 30 percent. WyomingSweet and the best grades of North Africancrude now have posted prices of between $34

and $38/bbl. The spot-market prices for theseoils are between $40 and $50/bbl.

If it is assumed that developers require nomore than a 12-percent real return on theirinvestment, and that current capital and




operating cost estimates are reliable, thenshale oil could probably be produced andmarketed profitably without subsidy. Pre-dicted decreases in next year’s OPEC exports(3 million bbl/d) along with the expectation of continued real price increases of at least 3

percent per year, reinforce the belief that themarket outlook for shale oil will continue toimprove in the future. However, ruling out theneed for financial incentives would be unwisefor several reasons.

First, the present competitiveness of shaleoil assumes realistic capital and operatingcost estimates. For the reasons discussedearlier in this chapter, this is still a riskyassumption, and construction and operatingcosts are still escalating. Since a commercialor modular facility has never been con-structed or operated, scaling-up the technol-

ogy will almost certainly add hitherto unfore-seen costs as technical problems—even mi-nor ones—are encountered. If it takes placein the context of commercializing or deploy-ing a large number of synthetic fuel plants,the shortage of already scarce equipmentsuch as valves, compressors, and heat ex-changers can be expected to further inflateconstruction costs. World oil price increasesin excess of the 3- or 4-percent real annualgrowth assumed by developers would pushconstruction costs up still further.

Second, the present competitiveness of shale oil assumes that developers are willingand able to accept an anticipated real dis-count rate (i.e., rate of profit) of 10 or 12 per-cent on an inherently risky investment. Giventhe nature of the risk, it is questionablewhether developers would be willing to un-dertake the investment at this rate.

Finally, shale oil’s emerging competitive-ness is related to recent oil price increases. If these increases contribute to recession in theindustrialized West, petroleum demand canbe expected to decline. This could reduceprices in real terms, thus reducing the com-petitiveness of shale oil. In the longer term,however, it should move to parity with con-ventional crude as a result of dwindling oil re-serves. However, shorter term price declinescould take place as they did during the yearsimmediately following the oil embargo of 1973to 1974.

In the consideration of appropriate incen-tives, this relative change in the competitive-ness of shale oil implies that emphasis shouldbe placed on the desirability of incentivesthat help with financing, while reducing therisk of extreme OPEC selling price reductionsin real terms. Debt guarantees, price sup-ports, and purchase agreements are mostlikely to provide such assistance.

Economic and Budgetary Impacts

The economic and budgetary impacts of oilshale development will depend on the produc-tion levels and speed with which they aremet. Low production levels are unlikely tohave significant effects on Governmentspending, on the national rate of inflation, onthe level of national employment, or on thecost and availability of capital. To examinethese impacts, four growth-related produc-

tion scenarios were prepared that distinguishshale oil development by both the anticipatedlevel of production and the required degree of Federal involvement. Thetechnical descriptions of facilities, and the analytic

I ‘J – 2 “1 ~ ‘ - P _ ; ,

rationales, thethe envisionedassumptions of

these scenarios are discussed in detail inchapter 3. Briefly, the scenarios are:

Production target in bbl/d of Scenario oil by 19901 . . . . . . . . . . . . . . . . . . . . 100,0002 . . . . . . . . . . . . . . . . . . . . 200,0003 . . . . . . . . . . . . . . . . . . . . 400,0004 . . . . . . . . . . . . . . . . . . . . 1,000,000

Industry Costs

A standard commercial oil shale facility isconventionally described as one that wouldproduce 50,000 bbl/d, with an on-stream




operating factor of 90 percent, or 329 daysper year. Such a facility would actually con-sist of a series of integrated modular retorts(normally five or six) each with a capacity of between 8,000 and 12,000 bbl/d. No singleplant is likely to produce exactly 50,000 bbl/d.At present, the plans of the Colony operatorscall for a commercial facility with a 45,000-bbl/d capacity, tract C-b is projected to pro-duce 57,000 bbl/d, a 76,000-bbl/d plant is projected for tract C-a, Union Oil’s ultimate in-tention is to build a facility with a capacity inexcess of 75,000 bbl/d, and Superior and Geo-kinetics expect to operate commercially prof-itable plants with small production capaci-ties—11,500 bbl/d and 2,000 bbl/d, respec-tively.

Determining the most efficient and cost-ef-fective size for a commercial plant depends

on the amount, quality, and accessibility of the shale resource on the tract, the method of mining, the type of retorting technology, and avariety of other factors that affect the cost of shale extraction, transportation, waste dis-posal, and refining.

Current capital cost estimates for a 50,000-bbl/d commercial-sized oil shale plant rangebetween $1.4 billion and $1.7 billion. In gen-eral, these plants are expected to representan approximately 20-percent economy of scale in comparison with smaller (e.g., 9,000

to 12,000 bbl/d) modular plants. A very largecommercial facility of 100,000 bbl/d mightrepresent a 10- to 15-percent economy of scale relative to a 50,000-bbl/d operation.Whether and to what extent these economieswould actually be obtained would depend onthe particular properties of the developmentsite, the mining techniques used, the technol-ogy adopted, and how efficiently the projectsin question were managed.

The estimated costs of industries of differ-ent sizes are presented below. These esti-mates assume a 30:70 ratio of debt to equity.They include the cost of hydrotreating andupgrading to premium crude quality and mi-nor transportation costs. They do not includethe cost of major pipeline construction or unittrain costs for transportation out of Uinta or

Piceance Basins. Estimates are in third-quarter 1979 dollars and assume a 5-yearconstruction period for each plant.

Scenario 1 Scenario 2 Scenario 3 Scenario 4In billions 100,000 200,000 400,000 1,000,000of dollars bbl/d bbl/d bbl/d bbl/dLoans, ... , ., 0.9-I .35 1.8-2,6 3.6- 4.2 9.0-13.5Equity . . . ., . 2.1-3.15 4.2-5.9 8,4- 9.8 21.0-31.5

Total ... , . 3.0-4.5 6.0-8.5 12.0-14.0 30.0-45.0Maximumannual. , . . . 0.6-0,9 1.2-1.7 2.4-2.8 6.0-9.0

Given current estimates, an industry of 1million bbl/d would cost roughly $30 billion inthird-quarter 1979 dollars. But these esti-mates are unlikely to be completely accurate.Real cost escalations of 10 to 20 percentwould not be unexpected under the best of circumstances. More importantly, if 1 millionbbl/d are deployed over a lo-year period,

capital cost increases for plant constructionare inevitable. Under such circumstances,the demand for skilled labor, for pollutioncontrol equipment, for valves, for miningequipment, for compressors, for heat ex-changers, and for other needed equipmentwill completely outstrip supply. The conse-quences would be large price increases forthese goods and services as well as construc-tion delays. Hyperinflation of the costs of re-quired goods and services, equipment short-ages, and consequent construction delayscould easily inflate total capital costs for fa-

cilities by 30 to 50 percent in real terms.Therefore, the costs of this scenario couldeasily reach $45 billion.


Each of the scenarios decribed above as-sumes a different extent of Federal involve-ment in the industrialization of oil shale. Thescenarios differ from each other in theamount of the target production and the de-gree of governmental cost and financial expo-sure. The cost to the Treasury is, in turn, de-termined by the type and magnitude of the in-centives that are provided. Those that havebeen evaluated in this assessment vary sub-stantially in the amount and kind of risk thatthey avert for the developer. They also vary




with respect to their overall impact on projecteconomics and potential company profits.

In general, the incentives considered entailcosts to the Government that are directly re-lated to their impact on a firm’s expected

profits. (See tables 25 and 26.) That is, subsidy costs to the Treasury are closely corre-lated with their influence on overall projecteconomics. However, the relation betweenthe effect of incentives on a firm’s profits andthe cost of the incentives to the Government isnot exactly linear. Some subsidies clearlyprovide more financial encouragement withless governmental cost and exposure thanothers. The real cost to the Government is de-termined by: 1) the gross cost of the subsidy,2) the amount of increased tax payments dueto additional production, 3) the Government’s

assumed discount rate (what it is assumedcould be gotten if the capital were employedelsewhere), 4) the timing of the Government’spayment of the incentive, and 5) the timing of a developer tax or other payback to the Gov-ernment.

Calculating the cost of incentives to theGovernment is complicated by the difficultyin determining the first three of these factors.For example, the gross cost of the subsidy(i.e., the size of the offered subsidy) is hard topredict for several of the incentives. Thenumber of production tax credits that mightbe taken by developers is not entirely predict-able, nor is the extent of the financial obliga-tion that the Government might incur underdebt insurance or guarantee programs. Thenumber of takers for price supports couldvary substantially depending on how theywere constructed, on the support price level,and on future shale oil market conditions.

The amount of increased tax payment thatparticular incentives might generate is alsodifficult to predict. This is because the effec-tive tax rate that firms pay on production

varies according to the circumstances of thecorporation in question. The range is poten-tially from O to 46 percent on Federal taxes.

Finally, the calculation of these costsassumes that the Government’s discount rate

is known, and that the tax generation abilityof alternative Government uses of the moneysis also known. Since there is considerabledisagreement among economists over the as-sumption of what the Government discountrate should be, some uncertainty is intro-

duced into the calculation. These calculationsassume a Government discount rate of 10 per-cent, which is the rate suggested by OMB.

Given these difficulties, the reported coststo the Government of providing the incentivesshould be viewed as illustrative of the prob-able average cost of providing the incentive toa number of developers. It should also be re-membered that these estimates do not includethe administrative cost of overseeing the in-centive. Several percent could be added tothe cost of the incentive, in the cases of debt

guarantees, purchase agreements, block grants, and low-interest loans. The costs tothe Government reported in this chapterwould apply only to first-generation facilities.Subsequent plants would probably requireless governmental involvement and thuslower governmental costs. If the incentives in-cluded fade-out provisions as oil prices rosein real terms and shale oil became more com-petitive, then the Government’s costs wouldalso fall substantially for later plants—if theprice of world oil continues to rise faster thanthe cost of building and operating shale oil

facilities.In this chapter, the cost to the Government

of providing an incentive is the gross subsidyto the firm less increased tax payments to theGovernment. This cost was calculated inpresent value terms. The net cost for eachyear (i.e., the subsidy less tax revenues) wasdiscounted at the Government’s discount rate(i.e., 10 percent). The resulting present valuecalculations were summed for all years. Thenature of the Government cost calculations isdescribed in greater detail in appendix A.

Scenario 1: 100,000 bbl/d by 1990.—OTA’sanalysis indicates that the production of 100,000 bbl/d by 1990 will probably takeplace without further subsidy beyond the gen-eral purpose tax credits that are currently




available to any industrial or energy devel-oper. Consequently, this scenario would notrequire any additional cost to the Govern-ment.

Scenario 2: 200,000 bbl/d by 1990.—Thecost to the Government of subsidizing the

200,000 bbl/d envisioned in this scenariowould depend, in part, on which incentivesare used to stimulate production. As is shownin table 25, the estimated cost to the Govern-ment of subsidizing a 50,000-bbl/d plant willdepend on the incentives chosen. If the Gov-ernment chose to provide only one of the in-centives considered in this chapter, then itscosts would vary between approximately $0and $494 million in 1979 dollars. However,this range should be adjusted in severalways. First, the construction grant subsidiesare so costly and politically unpopular thatthey should probably be dropped from consid-eration. Second, although the purchaseagreement is a powerful incentive in theory,its impact when set at $55/bbl over the life of the project is too low to have a significant in-fluence on project economics. Consequently,it should also be dropped from consideration.

Each of the remaining subsidies wouldyield substantial profits if a 12-percent dis-count rate is assumed. Although all but thelow-interest loan will still yield a relativelysmall loss if a 15-percent discount rate is

assumed, this is offset by the fact that thepresent calculations assumed a l-year con-struction delay. The cost of this delay is $117million. If such a delay does not take place,then all of the incentives except the purchaseagreement will provide a small profit (orsmall loss) in addition to the 15-percent dis-count rate (return on investment).

Thus, the cost of spurring the constructionof a 50,000-bbl/d plant with the use of a singlesubsidy would be between approximately$100 million and $400 million over the life of

the project. Therefore, the cost to the Govern-ment of stimulating the production of 200,000bbl/d would be between $400 million and $1.6billion.

If it were certain that any of the incentivesincluded in these ranges would induce thedesired level of production, the least costlysubsidy would be the best choice from theGovernment’s perspective. Unfortunately,this is not necessarily the case. As discussed

previously the particular corporate and fi-nancial circumstances of individual devel-opers vary widely with respect to the specificrisks that they need or wish to avert. There-fore, their incentive needs may be quite dif-ferent. Some firms may find it difficult to usetax credits. Others may be too small or weakfinancially to take advantage of price sup-ports or purchase agreements. Instead, theyrequire some kind of financing subsidy suchas a low-interest loan or debt guarantee.Some form of choice among possible incen-tives is probably necessary in view of these

differences.If the Government provided a choice among

possible incentives, then the cost of financingthis scenario would probably be between $1.2billion and $1.4 billion in 1979 dollars.

Scenario 3: 400,000 bbl/d by 1990.—0nthe basis of the same assumptions that wereused in the second scenario, the cost to theGovernment of providing a single incentivewould be between $800 million and $3.2 bil-lion in 1979 dollars. If developers were giventheir choice among the incentives, then the

cost to the Government to stimulate this levelof production would be between $2.8 billionand $3.2 billion in 1979 dollars.

Scenario 4: 1 million bbl/d by 1990.—Thecosts to the Government discussed below as-sume that almost all of this production wouldtake place with incentives to private industryrather than through direct Government own-ership. However, since the list of incentivesbeing considered includes both a 33- and 50-percent construction grant, the followinganalysis captures the financial consequences

of Government participation. It also assumesthat an effort to deploy the industry by 1990would put enormous strain on U.S. manufac-turing capacity (e.g., valves, heat exchangers,



pressure vessels, and mining equipment), orarchitectural-engineering schedules, and onthe reservoir of skilled workers. This woulddelay construction timetables and producesizable cost overruns. The precise amount of these overruns cannot be predicted.

Conversations with representatives of in-dustry and major construction firms, plus anexamination of the available literature, sug-gest that such cost escalations could easilyreach or exceed 50 percent of the originalestimates. The calculations for the totalcapital cost of this scenario include thisassumption. It is difficult to predict the effectthat such overall cost increases would haveon the cost of Government subsidies, since alarge part of the increases would be ab-sorbed by the developers, Increases in thetotal capital costs of the target production

would not translate directly into higher gov-ernmental costs, but would more likely re-duce overall production because of projectfailures. How much the Government’s costsescalated would be sensitive to the particularincentives used. They would also be affectedby the degree to which hyperinflation of over-all plant costs and resulting project failuresreduced tax receipts.

In order to stimulate sufficient developercommitment to stand a chance of meeting theproduction target, firms would have to be

allowed to choose the incentive that benefitedthem most. In which case, the total direct costto Government would probably be between $6

billion and $7 billion. However, it is likely thatproject failures and construction delayswould prevent the production target frombeing met. Consequently, the above estimateof cost to the Government would be more like-ly to represent a production in 1990 of 500,000 to 750,000 bbl/d rather than the full1 million bbl/d.

It should be noted that the above calcula-tions do not include necessary administrativecosts nor do they capture all of the costs of additional refineries, piping, and transporta-tion facilities that would be required for thethird and particularly the fourth scenarios.The estimates are in present value terms anddo not represent, except for the block grants,payment by the Government of a single lumpsum. All the other incentives would allowphased expenditures over a number of years,thus, limiting the Government’s financial obli-gations during any one year. Most important-ly, the calculations use OMB’s lo-percent dis-count rate, and assume that the gross amountof the subsidies would be used in some equal-ly productive manner if it was not spent on oilshale. Assuming alternatively that thesemoneys were used less productively, then thereal cost to the Government of the subsidieswould fall substantially. For instance. the netcost to the Government of providing the low-interest loan would be $453 million if a

Government discount rate of 10 percent isassumed. The cost would be $201 million if a5-percent discount rate is assumed.

Capital Market Impacts and Financial Feasibil i ty

The capital outlays needed to develop a siz-able shale oil production capacity are im-mense, e.g., $30 billion to $45 billion for just al-million-bbl/d capacity, This has led many toquestion the financial feasibility of privatesector development and to argue that Govern-

ment financial guarantees and/or direct Gov-ernment participation are mandatory if thereis to be significant shale oil production capac-ity by 1990 or even by 2000. Still others haveasserted that even if the Government ensures

the necessary financing, its achievementwould mean severe distortions of the capitalmarkets, namely: 1) a significant increase incapital costs (interest rates and requiredreturn on equity), which would reduce otherbusiness investment and 2) distortions in par-

ticular economic segments such as housing,due to high interest rates and the “crowdingout” of mortgage financing. Yet proponents of shale oil development argue that there aresignificant long-run benefits to be gained.



These include capital market benefits interms of balance of payments, of inflation,and of strength of the U.S. dollar.

Concerns

There is a clear need to address systemati-cally the financial and economic issues of shale oil financing. Thus, it is necessary toconsider: 1) the level of required financingassociated with alternative rates of shale oildevelopment, 2) the financial feasibility, 3)the capital market impact in aggregate andon particular capital market segments, 4) fi-nancial aspects of Government policy alter-natives, and 5) the impact of shale oil on thebalance of payments, on inflation, on thestrength of the U.S. dollar, and on tax reve-nues.

Scenario Framework

The development envisioned in either sce-nario 1 or 2 would not entail significantcapital outlays, Thus these scenarios do notinvolve issues of financial feasibility andcapital market distortions. Financial-econom-ic considerations would, however, cause vari-ations to scenario 3 (pioneer commercial in-dustry) and scenario 4 (aggressive development). Two concerns within each scenarioare: the effects of delays and cost overruns

and variations in the timing of development.Delays and cost overruns.—In the absence

of delays and cost overruns, it was assumedthat the prototypical plant would take 5 yearsto build and cost $1.5 billion in 1979 dollars(the upper end of current estimates for room-and-pillar mining with surface retorting). Toassess the effect of delays and cost overruns,an adverse variation was considered to be a2-year delay and a $600 million overrun.

Alternative plant initiation schedules.—There are several ways to reach a target lev-

el for a given production capacity by 1990.One is to initiate the necessary capacity at auniform rate, and stop adding capacity in1985 to reflect the 5 years from initiation tocompletion. Another is to add plants at a uni-

form rate, for example, 100,000-bbl/d capac-ity (two prototypical plants) per year in sce-nario 3 and 200,000bbl/d (four prototypicalplants) in scenario 4. Third and more realisticis to gradually build up the development ratefrom current levels to a target level of capaci-ty additions. For each scenario, figure 52

shows the combinations of delay-overrun var-iations and capacity addition variations.

Figure 52.—A Summary of Variationsin Each Scenario

Uniform to 1985

/

100,000 bbl/d to 1985and then no add it ions

No delay or overrun Uni form

/

Cost = $1.5 billion

\

(100,000 bbl/dTime = 5 years per year)

/Gradual bui ldup

4Scenario

\

Uniform to 1985Y \ Delay and overrun I Un i fo rm

Cost = $2.1 billion

\

(200,000 bbl/dTime = 7 years per year)

Gradual bu i ldup

Peak Financing Requirement

While the total capital outlay to put a shaleoil industry in place may suggest financial in-feasibility and the possibility of severe distor-tions in the capital markets, it is critical torecognize that the total is spread over a num-ber of years. Moreover, once there is signifi-cant capacity in place, much of the cash gen-eration is available to finance furthergrowth, so that even a growing capacity be-comes “self-financing” at some point.

The key issue of aggregate financial feasi-bility and capital market impact is the peakannual financing requirement. The annual fi-nancing requirements for various scenario



Ch. 6–Economic and Financial Considerations . 223 ——

variations* are plotted in figure 53. The peak lays and overruns. It would be no more thanfinancing requirements are summarized in $4.2 billion for the delay-overrun variation.table 27.

Scenario 4.—The peak annual financingScenario 3.—The peak annual financing requirement would be no more than $6.0 bil-

requirement would be no more than $3 billion lion for a uniform addition of 200,000-bbl/d(1980 dollars) for a uniform addition of capacity per year with no delays and over-

100,000-bbl/d capacity per year with no de- runs. It would be no more than $8.4 billion forthe delay-overrun variation.

The use of the phrase “no more than” in

*For more details on the scenario variations, the cost and the paragraph above reflects the fact thatrevenue assumptions, the simulation methodology, and a de- very conservative assumptions about costtailed case-by-case development of the cash flows, see BernellK. Stone, Shale Oil Financing: An Assessment of Financing Re -

and cash flow were used in each scenario inquirements, Capital Market Impact, Financial Feasibility and order to make certain that peak financing re-Finonciai Aspects of Policy Alterno tives. quirements are not understated.

Figure 53. —Year-by-Year Financing i n Bill ions f or Various Scenarios

#3: Uniform to 1985

5 -

4 -

3 -

2 - \ \

1 \ \

o 11985 \

– 1

– 2 -

+#4: Uniform to 1985

10 -9 “

8 -

7 -

6 -

5 -4 -

3 - \ \

1 \ \

o I \1985

– 1 -

– 2 -

– 3 - – 4 L

#3: Uniform

5 -

4 -—..

/’/ -t/ + .

3 - 0

2 -

1

0

–1 – 2 t

1

109

8

7

6

5

4

#4: Uniform

–1 – 2

– 3- 4 [

?

#3: Gradual buildup

5

4 - / 0 / - - - - - -

3 -~%.

2 -

1 -

0 ‘

- 1

-2-

+#4: Gradual buildup

8 -,---

7 - /

6 - ,/’/

5 -4 -

3 -

2 -

1 -

0 ‘

– 1

– 2

– 3- 4 [

= No delay version————— = Delay versionSOURCE Off Ice of Technology Assessment



224 An Assessment of Oi/ Shale Technologies

Table 27.–Peak Financing for Each Scenario (billions of dollars)

Version No delay or overrun Delay and overrun

Scenario 3 Uniform to 1985 . . . . . . . $3.00 $3.00Uniform. ... . . . . 3.00 4.20Gradual buildup . . 2.40 3.90

Scenario 4

Uniform to 1985 .., ., . 6.00 6.00Uniform. . . . . . . . . . . . . 6.00 8.40Gradual buildup ... . . 4,95 7 3 5


Aggregate Financial Feasibil i ty

There is no significant problem of aggre-gate financial feasibility. Assuming that thecurrent rate of domestic business capital in-vestment grows at a conservative rate of 4percent into the mid-1980’s at the time of thepeak financing requirement, the $6 billionwould be less than 3 percent of total domesticbusiness investment and the $8.4 billionwould be less than 4 percent. *

While a figure of $6 billion to $8 billionsounds like a large annual outlay, 3 to 4 per-cent of net domestic business investmentshould cause no significant financial distor-tions in terms of interest rate shifts or capitalmarket flows. This amount is well within thenormal year-to-year fluctuation in domesticbusiness investment, and a small fraction of

year-to-year shifts in net domestic savings.Likewise, it is within normal shifts in capitalflows from abroad. In fact, the internationalcapital markets are now recycling manytimes this amount of petrodollars. Finally, it isa small fraction of the total annual mortgagefinancing market, where mortgage refinanc-ing intermediaries annually recycle tens of billions. Moreover, the experience of the past3 years has shown that thrift institutions cancompete for funds at times of high interestrates when rate ceilings are lifted. Hence,

*The annual rate of business expenditures for new plant andequipment in 1979 is $174 billion ($180 billion seasonally adjusted annual rate in the fourth quarter). Hence, by the time of peak financing in the mid-1980’s, business expenditures fornew plant and equipment should be well over $225 billion with4-percent annual growth,

this level of financing should cause no signifi-cant distortion of the housing industry.

The capital flows are well within the finan-cial capacity of the major petroleum compa-

nies. For instance, EXXON has announced a$6.5 billion capital investment plan for 1980.A survey of the 1979 annual reports of the 18major integrated oil companies indicates cap-ital investment programs exceeding $50 bil-lion per year. Moreover, cases such as theSOHIO financing of its Prudhoe Bay develop-ment, and its share of the Alaskan pipeline,indicate an ability for private enterpriseswith limited financial capacity to put togethercreative financing packages without Govern-ment assistance, when there are promisinginvestment opportunities.

Hence, not only is there no aggregate prob-lem of capital market capacity or distortion,but there is also no significant problem of ca-pacity or feasibility for the private sector toprovide financing as long as shale oil is aprofitable investment.

A Caveat

The analysis above has looked at an ag-gressive development scenario in a clearlyworst case for financial requirements andfound no significant problem. However, it hasignored other possible sources of significantadditional financing. Were shale oil financingto be only one of several Government-sup-ported projects, each with comparable peakfinancing requirements in the mid-to-late




1980’s, then there is a potential problem inthe sense of crowding out other domestic in-vestment, distorting particular markets suchas housing, or significantly increasing inter-est rates necessary to induce domestic savingand/or investment capital from abroad.

While consideration of financing induced byother Government programs is beyond thescope of this report, this possibility mustclearly be recognized, and an overall finan-cial impact assessment made.

Finance Mix

Thus far the analysis has focused on thetotal peak financing and secondary financialeffects. In general, the capital markets arevery efficient at shifting funds between capi-tal market segments. Therefore, the major

macro impact depends on the amount of over-all financing regardless of the particular mix.Nevertheless, there are mix issues, especiallycapacity to provide new equity and ability tosupport debt without guarantees.

The investment tax credit implies that theFederal Government automatically providesup to 20 percent of the total investment. * Ascenario of further Government support of development cost beyond the investment taxcredit could be an additional 20 percent for atotal Government share of 40 percent. These

two cases are summarized in table 28 assum-ing the remainder is 50-percent debt and 50-percent equity. The actual share of debt inthe total financing is less, namely 40 percentand 30 percent respectively.

Table 28 shows strikingly that there shouldbe no financing problem for the major oil com-panies. Both current earnings and retainedearnings (earnings after dividends) are manytimes this amount for the 18 largest compa-nies.

Debt capacity of the major oil companies is

also more than adequate. Even if peak needs*The use of 20 percent here assumes that the extra IO-per-cent investment tax credit continues. Otherwise, this figurewill drop to 10 percent.

Table 28.–Finance Mix

Government sharingCurrent Investment of construction

tax credit only costs 20%

Percent $ billions Percent $ billions

Government 20 1 6 40 3 2P r i v a t e d e b t 40 3 2 30 2 4

P r i v a t e e q u i t y 40 3.2 30 2 4T o t a l 100 8 0 100 8 0


were to persist for 10 years ($32 billion), thecurrent debt capacity would tolerate suchamounts in terms of debt-equity ratios and in-terest coverage. Hence, for the overall energyindustry, there is no significant problem of providing either debt or equity, assuming thatthe equity is primarily from retained earn-ings.

Smaller Companies and New Equity

For smaller companies, the financing bur-dens can be formidable. Likewise, the magni-tude of equity financing for a single commer-cial facility is onerous. The new equity mar-ket is not likely to provide significant venturecapital for new enterprises or small compa-nies in this area. Without Government assist-ance, a small company can participate only

via joint ventures. However, this limitation isnot unique to shale oil. Small companies can-not generally undertake billion dollar capitalinvestments in any industry. Moreover, suchcompanies generally lack the managerial andtechnical resources to undertake such ven-tures successfully. While financing is anobstacle for small companies, it is probablynot as severe as building the organization tomanage such a project.

Significant contributions to establishing alarge shale oil industry should not be ex-pected from small companies. Both technicaland managerial talent and financial re-sources for major development reside in thelarge energy companies.




Secondary Financial Impacts and Benefits

In addition to the peak capital require-ments and the direct impact on the capitalmarkets, there are also a variety of second-ary financial effects—balance of payments,

strength of the U.S. dollar, inflation, and taxrevenue (net effect on the Federal budget).

Balance of Payments and Strength

of U.S. Dollar

Shale oil development has two balance-of-payment effects—the direct effect of its pro-duction and the indirect effect from its in-fluence on the world oil price.

Direct effect.—Producing shale oil will re-duce the need for imports. There should be a

one-for-one substitution of shale oil for im-ported oil. At a $30/bbl current-dollar pricefor imported oil in the mid- to late 1980’s, theshift in balance of payments is $5.5 billion(scenario 3 with no delay) to $7 billion (sce-nario 4 with delay) in 1990. It would rise to$15.5 billion (scenario 3 with no delay) to$27.0 billion (scenario 4 with delay) in 2000.These effects are summarized in table 29.

Indirect effect.—The indirect effect arisesfrom price pressure exerted by domesticshale oil production on the price of world oil.

Table 29.–The Current Dollar Improvement in the Annual U.S.Balance-of-Payments Position Associated With Afternative

Development Rate Scenarios

Representative years

Improved source 1990 1995 2000

Scenario 3 with no delay or cost overrun and annual capacity additions at the rate of 100,000 bbl/d Direct subst i tu t ion (b i l l ions) a, ... ., ., ., $5.5 $10.5 $15.5Scenario 4 with 2-year delay and a $600 million cost overrun and uniform annual capacity additions at the rate of 200,000 bbl/d Direct subst i tu t ion (b i l l ions) b, ., ., ., ., ., 7,0 17.0 27.0

aThls assumes the current dollar price of world 011 IS $30/bbl In each year and corresponds 10

starf-of.year capaclly oi O 5 mllllon In 1990, 1 mllllon In 1995, and 1 5 mllllon In 2000 plus50 000-bbl/d average production from phase-in of 100,000 -bbl/d capacity In each year

blhls assumes the Currerl[ dollar prtce of world 011 IS$30/bbl in each Year and corresponds 10sfafl-ol-year lull produc!lofl capacity of O 6, 1 6, and 26 mllllon bbl/d respectively for 19901995, and 2000 plus 100000 bbl/d average produc!lon from phase-in of 200 000-bbl/d capac-Ily In each year

SOURCE Office ot Technology Assessment

For every dollar reduction in the price of world oil (at current import levels of approx-imately 3 billion bbl/yr), there is a $3 billionimprovement in the balance of payments.

Taxes

The direct effect of any shale oil incentivescan be either a reduction in taxes and/orGovernment payments to shale oil producers.Hence, the direct effect of incentives is to in-crease the Government deficit. To the extentthat there is a net increase in economic activi-ty, there are countervailing tax revenue bene-fits. These include: 1) the taxes paid by shaleoil producers, 2) the taxes paid by suppliersto the shale oil companies, 3) the taxes paidby workers for shale oil companies, and 4) thetaxes paid by workers for shale oil suppliers.

It is very difficult to assess the impact of shale oil financing on Federal tax revenue.One of the primary variables is the extent towhich shale oil production and related eco-nomic activity is incremental (net new domes-tic production) or substitutes for other eco-nomic activity.

Estimates of the incremental Federal taxrevenue are summarized in table 30. Two

cases are considered—loo-percent incre-mental domestic production and a more plau-sible 50-percent incremental production. Theeffect is modest in 1990 due to the assumptionof no taxes by the shale oil producers. How-ever, by 2000 it rises to several billion. Thesefigures exclude secondary activity such as in-cremental tax revenues due to servicing theemployees and suppliers. They also do notreflect any benefits of higher employment inreducing unemployment compensation andwelfare payments.

Any reduction in the Government deficitwill be a long-run benefit to the capital mar-kets to the extent that it reduces deficit fi-nancing and the associated “crowding out”of private sector financing by Governmentdebt.




Table 30.–A Summary of Estimates of the Improvement in

Federal Tax Revenue Attributable to Shale Oil Production Fromthe Taxes Paid by Shale Oil Companies, Their Employees,

Their Suppliers, and Their Suppliers’ Employees

Representative years

1990 1995 2000

Scenario 3–uniform 100,000-bbl/d capacity growth and no delay V a l u e o f a n n u a l p r o d u c t i o n ( b i l l i o n s ) $ 5 ,5 0 $ 1 0 5 0 $ 1 5 5 0Proportion of annual production paid in taxes 15 .20 25Net tax Improvement. 100% new activity (billions) 83 2,10 388Net tax Improvement 50% new activity (billions) 41 1.05 1,94Scenario 4–uniform 200,000-bbl/d capacity growth and delay Value of annual production (billions) 700 1700 2700Proportion of annual production paid in taxes. 15 .20 ,25Net tax Improvement 100% new activity (billions) 1.05 3 4 0 6 7 5Net tax Improvement. 50% new activity (billions) .53 1 70 3.38

Notes on the lax proportions1 The proportions used here ( 15 20 and 25) are developed In delall m Bernell K Stone

S)ra/e 0 1 / F/nanc/rrg ArJ 4ssessrnenf of Fmamng Reqwrernenls Caplfa/ Marker knpm Fman-c/a/ Feas@//lly and Fmanc/a/ Aspects of F’o/Icy Allemahves They assume a 20 percent before-Iax rate of return for the compames 20 percent dlrecl labor expense 50 percent supplrer ex

pense and 10-percent other Supplrer direct labor payments are assumed to be 50 percent ofsuppller revenue2 The corporate and personal [ax rates used were 50 and 25 percent respectively3 The propofllons assume no corporate Iaxes Irom shale 011 producers [n 1990 (due 10 acceleraled depredation and [nvestment lax Credltsj a 25 percent elfectwe rate tn 1995 and a full 50-percenl (ate In 2000


Capital Costs: Secondary Effects

been noted that this should be minor since thepeak capital outlays are small as a proportionof total business investment, and would re-quire only a modest change in saving. Thevarious secondary financial effects (balanceof payments, Government deficit, inflation)

also impact capital market rates. The long-run effect of improved balance of payments,reduced inflation, and reduced deficits willbe to reduce capital market rates—both in-terest rates and required equity returns nec-essary for any given level of savings. Thelong-run reduction should be several percent-age points. Moreover, while the short-run im-pact of higher inflation would be adverse, thefact that capital markets are “anticipatory”(i.e., future looking) means that current rateswill reflect not just current inflation but alsothe future improvement in inflation, balance

of payments, and the budget deficit. Thus, thelong-run improvements could outweigh boththe short-run effect of inflation and the in-creased financing need. Consequently, theoverall effect of shale oil on capital marketrates is at worst a minor short-run increaseand a clear long-run decrease.

The direct effect of more capital invest-ment is to raise capital costs. It has already

Financial Aspects of Pol icy Alternat ives

Impact on Peak Financing

From the viewpoint of aggregate impact,the most important Government action is thatwhich prevents or at least minimizes delays(i.e., by removing environmental delays andlicensing delays once a plant is started), thus,cost over-runs.

Impact on Private Sector

of Peak Financing

Government subsidies in the

Share

constructionand very early production stages reduce theprivate sector share of peak financing but notthe overall impact. This is because the Gov-ernment must raise its share via some com-bination of Government borrowing or more

taxes, either of which reduces funds avail-able for private sector financing.

General Impact of Subsidies

The overall effect of subsidies and/or riskreduction is to make investment more attrac-tive and ensure more rapid development thanwould otherwise take place. Subsidies alsomake possible more rapid private-sector de-velopment once a basic industry is in place,i.e., beyond the 1990 period.

Government willingness to subsidize, espe-cially via production subsidies and minimumprice guarantees, sends an important mes-sage to savers and the world capital mar-kets—namely that there will be a significant



228 q An Assessment of O/1 Shale Technologies

U.S. shale oil industry with decreasing reli-ance on foreign oil. Hence it should reduce in-flationary expectations, induce savings, in-duce investment from abroad, and strengthenthe U.S. dollar. These policies could, there-fore, have an immediate and significant bene-

ficial effect on the domestic capital marketsvia their impact on future expectations.

Summary

There is no significant problem in provid- .ing peak financing requirements even forrapid shale oil development in terms of ca-

pacity of the capital markets, increases incapital costs, or reallocations from otherindustrial-financial sectors of the economy.Major energy companies have the capacity toprovide any reasonable mix of debt and equi-ty via retained earnings.

Long-run secondary effects on balance of payments, strength of the U.S. dollar, infla-tion, and the budget deficit are all favorable.The overall impact on capital markets shouldalso be favorable, especially given that cur-rent rates will reflect future expectationsabout inflation and the balance of payments.

Effect on Infl ati on and Employment

Oil shale programs will undoubtedly be a

part of a larger synthetic fuels policy. All of the legislation before Congress is concernedwith the development of a synthetic fuels in-dustry as such. The development of oil shale,were it to take place, would do so in the con-text of some particular array of policies con-cerned with such issues as conservation, oilimport reduction, coal conversion, and/or in-creased solar power usage. Furthermore,shale oil development, like any other long-term financial commitment, will interact withGovernment policy and economic trends innumerous areas such as monetary policy,

fiscal policy, tax policy (the windfall profitstax is particularly relevant), the characteris-tics of the balance of payments, and overallcapital availability. To evaluate how pricesand employment will be affected by oil shaledevelopment, it would be necessary to exam-ine these effects for all of the major syntheticfuels proposals before Congress, and attemptto assess the course of the U.S. economy overthe next 10 years. This task is outside thescope of this report. However, the Congres-sional Budget Office in its September 7, 1979report to the Senate Budget Committee has at-tempted to make such an analysis.

The impacts on prices and employment na-tionwide of the deployment of the first sce-nario (100,000 bbl/d) would be insignificant.

Even the realization of the second scenario

(200,000 bbl/d), would have negligible effectson national inflation and employment. How-ever, the inflationary effects of this produc-tion on the cost of the machinery and equip-ment necessary to the industry might besmall, although discernible and could be sig-nificant, particularly on the price of labor,land, and rents, in the immediate geographi-cal areas of development.

Even the third scenario (400,000 bbl/d)would not have an appreciable effect on na-tional inflation rates or employment levels, It

would substantially affect local prices, havean enormous positive impact on local employ-ment, and a definable one on regional employ-ment. Depending on the phasing of the influxof workers, the local expenditures by the de-veloper, and the approach taken in dealingwith socioeconomic impacts, the inflationaryeffect on land, labor, rent, and goods could bevery large, particularly on land and rents.(See ch. 10.)

The prices for the machinery and equip-ment used for constructing the facilities

would escalate sharply. It has been estimatedthat the construction of an industry with a400,000-bbl/d capacity would use between 10and 20 percent of the current U.S. manufac-turing capacity for valves, pressure vessels,






q the availability of sufficient numbers of an adequately trained labor force tomeet construction schedules.

Meeting the production targets will neces-sitate substantial improvements in each area.Such an expansion of capacity will require a

national commitment to divert resources fromother areas and uses, will create bottlenecksin other parts of the economy, and will lead torapid inflation of costs in the relevant mining,construction, and equipment industries. Inorder to achieve this production goal the fol-lowing annual manpower and equipmentneeds would have to be met.

In these projections it is assumed that ap-proximately 20 commercial facilities havingan average capacity of 50,000 bbl/d will beconstructed. Most would not reach the designstage until at least 1982. Their construction isunlikely to be started until between 1983 and1984; and will not be completed until between1989 and 1990. Consequently, many of theprojects will be designed and constructed si-multaneously, thus, severely taxing the ca-pacity of equipment suppliers and construc-tion firms.

These projects because of their size, com-plexity, and the vast array of skills and exper-tise they require, will necessarily need to becontracted to a limited number of large archi-tectural-engineering firms. Only a few design

and construction firms have the managerial,technical, and economic experience to con-struct such plants. An examination of the ex-isting capacity of such firms by EngineeringNews Record on April 12, 1979, indicates thatof the construction firms involved in buildingmanufacturing process facilities, only 21 con-tracted in 1978 for work having a total dollar

value near the level of expenditure requiredto construct a small commercial oil shaleplant—$400 million per year.7 It can, there-fore, be concluded that no more than 21 firmshave the current capacity for such work.Many of these are already booked years inadvance. However, workloads between now

and 1985 will probably increase the numberof firms that are able to undertake projects of this magnitude. There is also the possibilitythat by combining together, smaller firms willbe able to undertake such projects.

In 1978, the construction industry con-tracted for $27.2 billion worth of new work,only $21.6 billion of which was industrialwork. Thus, the annual construction costs of the oil shale plants that would have to be builtbetween 1983 and 1990 to reach the million-barrel-per-day target represents 35 percent

of the workload in 1978.

In particular, shortages of skilled labor canbe expected during efforts to deploy an indus-try of this size. In 1978, there were approx-imately 45,000 workers in the United Stateshaving the necessary technical and profes-sional skills (e. g., draftsmen, engineers, man-agers, and scientists). From 1983 to 1990,shale oil plants producing 1 million bbl/dwould require 11,000 to 18,000 professionalemployees, which is more than 36 percentabove process industry requirements in 1978.

At this time, the United States has a total con-struction work force of around 4.5 million.During each year between 1983 and 1990,constructing the plants would require an ad-ditional 130,000 workers. The need for such alarge labor force would act to hamper thedeployment of an industry of this size, andwould substantially inflate labor costs.




Chapter 6 References

IThis discussion is indebted to that presentedby Robert Merrow, Constraints on the Commer-cialization of Oil Shale, RAND Corp., 1977,zThis discussion in this section draws on mater-

ial presented by Robert Merrow, Constraints onthe Commercialization of Oi l Shale, RAND Corp.,1977, and Synthetic Fuels: A Report Prepared forthe Budget Committee of the U.S. Senate, 1979.

‘Synthetic Fuels: Report by the Subcommitteeon Synthetic Fuels of the Committee on the Budget,United States Senate, September 1979, p. 180.Statement made by Cameron Engineers.

“Synthetic Fuels, Report by the Subcommittee

on Synthetic Fuels of the Committee on the Budgetof the United States Senate, Sept. 27, 1979, pp.46-47.

‘Edward W, Merrow, Constraints on the Com-

mercialization of Oi l Shale, RAND Corp., Septem-ber 1978, pp. 16-18.‘Wallace E, Tyner and Robert J. Kalter, “A Sim-

ulation Model for Resource Policy Evaluation, ”Cornell Agricultural Economics Staff Paper, Sep-tember 1977.‘“A Fluor Perspective on Synthetic Liquids, ”

Fluor Corp., 1979.



CHAPTER 7

Resource Acquisition



contents

Page

I n t r o d u c t i o n **** **** ** b e ** *, *O** 238

The E v o lu t i o n o f Le a s i n g a n d L a n d E x c h a n g e . 235

Leasing Programs q .*****@***.,*.,*****,* 237

L a n d E x c h a n g e s . . . . . . . . . . . . . . . . . . . . .. ..241

The Adequacy o f P r iva te Lands . . . . . . . . . . . . 241

P r e s e n t a n d P o t e n t i a l P r o j e c t s o n

P r i v a t e L a n d . . . . . . . q . . . . . . . . . . . . . , . . . 2 4 4

P r e s e n t a n d P o t e n t i a l P r o j e c t s o n

Federal Land.... . . . . . . . . . . . . . . . . . . . . . 246

I s More Federa l Land Needed? . . . . . . . . . . . . 249

P o l i c i e s q **** , ** , * . . * . . * , ** , * , * . , * . , 250

C h a p t e r 7 R e f e r e n c e s . . . . , . . . . . , . . . . . . . . . 2 5 2

List of Tables

Table No. Page31. Tracts Offered Under the Prototype Oil

Shale Leasing Program . . . . . . . . . . . . . . 240

Page32 . Distribution of the Oil Shale Resources in

Colorado and Utah. . . . . . . . . . . . . . . . . . 24433. Estimated Shale Oil Production by 1990

in Response to Various Federal Actions. 250

List of Figures

Figure No. Page

54. Ownership of the Oil Shale Resources of the Green River Formation . . . . . . . . . . . 235

55. Locations of the Tracts Offered forLease Under the Prototype Program . . . . 239

56. Privately Owned Tracts in the PiceanceBasin. ... ... ... ... ... ... .....,.. 243

57. Thickness of the Oil Shale Deposits in thePiceance Basin That Yield at Least 25gal/tonof Shale Oil. . . . . . . . . . . . . . . . . . 245

58. Location of the Sodium Mineral Depositsin the Piceance Basin . . . . . . . . . . . . . . . . 246



CHAPTER 7

Resource Acquisition

Introduction

On May 27, 1980, the Department of t he Interi or (DOI) announced several oil shale decisi ons. Up to

four new trac ts wi ll be leased under the Prototype Program and preparati ons started for a permanent l eas-ing program. At l east one multimineral tract wil l be incl uded in t he renewed Prototype Program. Land ex-changes will not be given special emphasis, and no decision will be made to settle mining claims until theSupreme Court ru les on Andrus v. Shell Oil (the oil shale mining claims discovery standard case). [Note:This case was decided on June 2,1980 (No. 78-1815).] The administrat ion wi ll propose to Congress leg-islati on to give DOI the authorit y to grant l eases bigger than t he present statutory li mitati on of 5,120acres, to provide for offlease disposal of shale and siting of facilities, and to allow the holding of a max-imum of four leases nationwide and two per State.

-

The resources of the Green River formationare owned by the Federal and State govern-ments, by Indian tribes, and by numerous pri-

vate parties. (See figure 54. ) Overall, the Fed-eral Government owns about 70 percent of the land surface, which overlies about 80 per-cent of the resources. The Federal land con-tains the thickest and richest oil shale de-posits and essentially all of the large depositsof sodium minerals. About 20,000 acres (lessthan 1 percent) of the Federal land has beenallocated for private development throughthe Prototype Oil Shale Leasing Program. Inthe future, it may be necessary to involvemore public land for either private or govern-mental development, if certain technologies

are to be tested or if a large industry is to beestablished rapidly. Releasing this landwould be affected by the laws that governleasing and land exchange, by unpatentedmining claims over most of the Federal land,and by other factors.

This chapter deals with the issues sur-rounding the use of Federal oil shale land.The following subjects are discussed:

q the possible need for committing morepublic land;

Figure 54.—Ownership of the Oil Shale Landsof the Green River Formation

PICEANCE BASIN(COLORADO)

ePRIVATE

FEEzl~.

FEDERAL 79-.

UINTA BASIN(UTAH)

INDIAN 8%BPRIVATE FEE 9%

STATE 6%

FE DE FiAL 77°

GREEN RIVER BASIN WASHAKIE BASIN(WYOMING) WYOMING-COLORADO)

@sATE%@’’’”o”S O U R C E M a p of the Ma/or 0/ / Shale H o / d / r i g s —Co/orado,Wyom/ng Utah,Denver, Colo Cameron Engineers, Inc , January 1976

q leasing and land exchange programsand their problems; and

q options for involving more Federal land.

The Evolution of Leasing and Land Exchange

The legal framework that governs the use both complex and unsettled. It incorporates aof public land for oil shale development is series of laws and policies dating back two

235




centuries that reflect conflicting philosophiesabout the role of the Federal Government astrustee of the public land.

The Continental Congress created the pub-lic domain from lands ceded to the new Con-federation by the individual States. In 1788,

the Constitution granted Congress the powerto dispose of the public domain (including sur-face, mineral, and other rights) for the com-mon benefit of all the States. By 1850, thepublic domain extended to the Pacific coast,including the oil shale lands in Colorado,Utah, and Wyoming. The Preemption Act of 1841 and the 1846 Lead Mines Statute au-thorized the transfer of public lands to pri-vate parties, and the Homestead Act of 1862allowed settlement of Federal lands in theWest for agricultural purposes. Some tractsalong streams in the Piceance Basin were ac-

quired by settlers under this Act. The MiningLaw of 1866 declared the mineral lands of thepublic domain to be free to exploration andopen to appropriation by those prospectorswho found “lode-type” deposits on the land.“Placer” deposits were excluded under thisAct but were subsequently opened to appro-priation under the Placer Act of 1870. *

The Mining Law of 1872 combined, re-vised, and augmented the 1866 and 1870laws, and subsequently governed disposal of all minerals that are not otherwise explicitly

covered by other legislation. Prospecting wasrecognized as a statutory right. Upon locatinga valuable mineral, a prospector could:

q stake a claim encompassing all or part of the deposit;

q develop the deposit;q mine, process, and sell the minerals; andq obtain ownership to the land’s surface

and its mineral values by paying from$2.50 to $5.00/acre, by performing about$500 worth of development work on theclaim, and by carrying out at least $100per year of “assessment” work until thetime that ownership was transferred bya legal document called a patent.

*A lode deposit is confined by rock in the place where it wasoriginally formed. Placer deposits are lode deposits that havebeen broken down, transported, and redeposited in alluvialsediment as a result of exposure to flowing water or ice.

The Secretary of the Department of the Inte-rior (DOI) was given authority to enforce theprovisions of the 1872 Mining Law and tooversee the filing of claims and the grantingof patents. The Petroleum Placer Act of 1897added “lands containing petroleum or othermineral oils” to those subject to the locationand patenting provisions of the 1872 MiningLaw. This action led to a flood of claims for oiland gas reserves, and large areas of publicland were transferred to private hands as aresult.

In the early 20th century, the philosophy of free exploration and occupation of the publicdomain came under scrutiny because of therise of the conservation movement and con-cern over the dwindling supply of strategicmaterials, including oil. This led to two ac-

tions:q

q

President Theodore Roosevelt’s execu-tive withdrawals of public lands thatcontained coal, timber, oil, water, andother essential resources; andDOI’s stricter enforcement of its re-quirements for granting of patents formining claims.

President Roosevelt’s withdrawals were pro-tested in Congress, especially by representa-tives of the Western States, but Presidential

authority for such withdrawals was subse-quently upheld by the Supreme Court. In l909and 1910, President Taft withdrew the re-maining public domain from appropriation byoil and gas claims. More controversy ensued,and in 1910, at President Taft’s request, Con-gress passed the General Withdrawal Act—The Pickett Act—which authorized the Presi-dent to withdraw public lands by Executiveorder from settlement, location, sale, or otherentry. The withdrawals were to be temporaryand could only be made for the purpose of evaluating the land for water powersites, ir-

rigation, classification, or other public uses.All lands thus withdrawn would remain openfor exploration, discovery, and appropriationunder those provisions of the Mining Law of 1872 that applied to metalliferous (metal-bearing) ores.



Ch. 7–Resource Acquisition “ 23 7

In 1914, Congress severed known fuel andfertilizer mineral rights from the rights to thesurface of lands appropriated for agricultur-al uses. The Stockraising Act of 1916 re-served to the Government all mineral rights.

The Mining Law and the other land-man-agement laws had little effect on oil shaleprior to 1916 because interest in the mineralwas negligible. However, in 1914, the U.S.Geological Survey began investigating the oilshale deposits to determine their potential foryielding fuels. Publication of the results in

1916 coincided with predictions of wide-spread fuel shortages as a result of diminish-ing petroleum reserves. Based on informalrepresentations that oil shale would betreated as a locatable mineral under thePetroleum Placer Act of 1897, more than10,000 claims of 160 acres each were filedbefore 1920. Filing for oil shale claims wasended in 1920 with the passage of the Miner-al Leasing Act. Also in 1920, DOI determinedthat oil shale had been a locatable mineral.Questions related to the valid location andmaintenance of these claims became a sourceof contention that has endured to the present.

Leasing Programs

The Mineral Leasing Act of 1920 ended theprocess of claiming Federal land for petro-leum, gas, coal, oil shale, phosphate, andsodium minerals. However, private firmscould be given an opportunity to developthese minerals through leasing programs ad-ministered by DOI. The Secretary of the In-terior was required to assess annual rentalsof 50 cents per leased acre, and the maximumsize of an oil shale lease tract was limited to5,120 acres (8 mi2). No individual or firmcould hold more than this acreage underlease. * Except for these provisions, the Sec-retary was given broad discretionary powersto select lease tracts and to shape the termsof development leases. Five oil shale lease ap-plications were filed with DOI after 1920.Three leases were issued, but all were subse-quently canceled.

In the early 1920’s, during the Harding ad-ministration, Secretary of the Interior Fallwas alleged to have accepted bribes from anoil company in consideration of noncompeti-tive leasing of Naval Petroleum Reserve No.3—the Teapot Dome field in Wyoming. In1930, during the era of caution that followed

the Teapot Dome scandals, DOI’s Solicitorsuggested that oil shale lands be withdrawnfrom leasing because shale oil was too expen-

*Shares in several leases could be held, but the total areacovered by the shares could not exceed 5,120 acres.

sive to produce compared with conventionalpetroleum, and therefore any additional leas-ing could only result in speculation, The sug-gestion was adopted by the Secretary andtransmitted to President Hoover, who issuedExecutive Order 5327, which withdrew theoil shale lands from leasing under the Miner-al Leasing Act. The order “temporarily” re-served the lands for the purpose of “investi-gation, examination, and classification, ” asrequired by the Pickett Act under which itwas promulgated.

Since 1930, this temporary order has been

modified on a few occasions. In 1932, for ex-ample, President Hoover’s Executive Order6016 permitted oil and gas leases on the oilshale lands, and in 1935, President Roose-velt’s Executive Order 7038 authorized pros-pecting permits and development leases forsodium-bearing minerals. The withdrawalorder has also been modified from time totime to permit disposition of surface rights inlimited areas. With these exceptions, it re-mained in effect and essentially unaltered forover 40 years, during which no oil shaleleases were issued.

In 1952, President Truman issued Execu-tive Order 10355, which authorized the Sec-retary of the Interior to rescind the with-drawal order. Subsequent Secretaries, how-ever, were reluctant to exert this authority




for fear of creating the environment for aleasing scandal like Teapot Dome. DOI’s hesi-tation was compounded by the uncertainstatus of unpatented mining claims on muchof the Federal land and by a feeling that shaleoil was not needed.

In the 1960’s and early 1970’s pressurefrom congressional delegates from Colorado,Utah, and Wyoming, and urging from Stateofficials and the energy industry, contributedto the formulation of two different but relatedleasing attempts. The first was promulgatedbetween 1964 and 1968 as part of a compre-hensive oil shale program in the Johnson ad-ministration under Secretary of the InteriorStewart Udall. Secretary Udall’s lease offer-ings failed to attract private participation.Other portions of his program were carriedforward into the Nixon administration, how-

ever, where they were supplemented by theFederal Prototype Oil Shale Leasing Programunder the direction of Secretaries Hickel andMorton. *

The Prototype Program officially began onJune 4, 1971, when President Nixon in-structed the Secretary of the Interior to ex-pedite a leasing program that would encour-age oil shale development while providing forenvironmental protection. On June 19, 1971,Secretary Morton announced plans for thePrototype Program and simultaneously re-

leased the preliminary environmental impactstatement (EIS). In April 1972, DOI desig-nated six tracts of about 5,120 acres each,which were offered for lease in 1974. Theirlocations are shown in figure 55. Dates forthe sale of individual leases and other detailsof the Program’s initiation are summarized intable 31.

It is noteworthy that the initial develop-ment plans covered a range of technologicaloptions: underground and surface mining,aboveground and in situ retorting, and miningin ground water aquifers and in dry zones. Itwas estimated that the six tracts would beproducing a total of 250,000 bbl/d by 1980.This goal was immediately set back because

*Both leasing attempts are discussed in detail in vol. 11.

no acceptable bids were received for the insitu tracts in Wyoming. The lack of responsewas related to the poor quality of the Wyo-ming resources and to the primitive status of in situ technologies. In 1976, DOI proposed tolease two other in situ tracts in the richer Col-orado shales. Several sites were investigatedand a supplemental EIS was begun. The ideawas abandoned in 1977 when Colorado tractsC-a and C-b switched from aboveground re-torting (AGR) to modified in situ (MIS) proc-essing. The reasons for this shift were tech-nical problems with the fractured oil shale ontract C-b and a ban on the disposal of miningand processing wastes outside of tract C-a’sboundaries. Development of both tracts wasresumed after a l-year delay and both arenow proceeding towards commercial opera-tions.

Development of the Utah tracts has beenstopped by legal battles between the FederalGovernment, the State of Utah, and privatefirms over ownership of the lands encompass-ing the tracts. There are basically two typesof conflict. The first is related to the cir-cumstances under which Utah was grantedstatehood. Under the Statehood Enabling Actof 1894, Utah was allowed to take title to foursections out of each township with the intentthat the proceeds from their sale or usewould be applied to public education. For var-ious reasons, selection of a large number of these sections was delayed, and in somecases whole townships were made ineligibleby their inclusion in Federal reservations. Inlieu of sections in these townships, Utah wasallowed to select other sections in other town-ships.

By the 1960’s, Utah’s stockpile of in lieu se-lections had reached 225,000 acres. BetweenSeptember 1965 and November 1971, Utahapplied for 157,225.9 acres of land in the oilshale area. Included were the present sites of lease tracts U-a and U-b. DOI declined totransfer the title to this land, and litigationensued. To avoid delaying the Prototype Pro-gram’s initiation, DOI and Utah agreed thatthe proceeds from the leasing of tracts U-aand U-b would be held in reserve until the



Ch. 7–Resource Acquisition q 239

Figure 55.— Locations of t he Tracts Offered for Lease Under the Protot ype Program

IDAHOI

— . .i

q Salt Lake City

o

1

\GREEN

I RIVERI

I

I

I

UTAH

\

‘)BASIN

WYOMING

q Rock Springs W-a &W-b

lx”WASHAKIE

/

BASIN

--— . .

--n-r--”--—---

S A N DI

I W A S HBASI N

COLORADO

25 MILES c1 1 1 1 $I

u ( H%/I II

011 shale deposits of the Green Rwer formation

SOURCE T A Sladek, R e c e n t T r e n d s In 011 Shale–Part 3 Shale 011 Refln~ng and Some 011 S h a l e P r o b l e ms , ” Mi n e r a l s Irrdustr/es Bullet/n, VOI 18, No 2 M a r c h 1 9 7 5

case was decided. Utah also agreed to holdthe lessees to the terms of the Federal leasesif the State took title. The lawsuit proceeded

through the U.S. District Court and the Cir-cuit Court, which ruled in favor of Utah, andis now in the U.S. Supreme Court, where itwill be heard during the 1980 session. *

*On May 19, 1980, the U.S, Supreme Court, in a 5-4 decision,reversed the lower court decisions and held that the Secretary

This case should not have unduly con-cerned the lessees because its outcome wouldnot have affected the leasing regulations.

However, the situation was complicatedwhen a mining company applied for a prefer-of the Interior could reject Utah’s applications for oil shalelands as school land indemnity selections because the selectedlands were grossly disparate in value to the school land grantsthat were lost to preemption or prior entry (Andrus v. Utuh, No.78-1 522).




Table 31 .–Tracts Offered Under the Prototype Oil Shale Leasing Program

Tract Location Date of sale Winning bidder Winning bid Development concept

C-a Colorado 1/8/74 Rio Blanco Oil Shale project $210,305,600 Open pit mining: aboveground retorting(Gulf 011, Standard Oil of Indiana)

C-b Colorado 2/1 2/74 C-b Shale Oil project (AtlanticRichfield, Tosco, Shell, Ashland)

U-a b

Utah 3/1 2/74 White River Shale Oil Development(Sun 011, Phillips Petroleum)

U-bb

Utah 4 /9 /74 White River Shale Oil Corp.(Sun Oil, Phillips, Standard of Ohio)

W-a Wyoming 5/14/74 NoneW-b Wyoming 6/11/74 None

117,788,000 Underground mining: abovegroundretorting a

75,596,800 Underground mining, abovegroundretortingc

45,107,200 Underground mining; abovegroundretorting

In situ (suggested by DOI)In situ (suggested by DO I)

alndlrec[ly healed retorfs (e g TOSCO It)bsubsequently umhed for common developmentccomblna[lon 01 Indtrec[ly heated and dwec!ly heated retorls (e g TOSCO II and paraho or 9as combustion)

SOURCE OftIce of Technology Assessment

P ho t o c r ed i t O T A s t a f f

Development on Federal Prototype Leasing tract C-b

ential State lease to the tract area. This mighthave superseded the Federal lease and there-fore obviated development of the tract by thePrototype lessees. Another suit was initiated,in this instance between the mining company

and the State of Utah. Proceedings have beenstayed pending resolution of the in lieu liti-gation.

A further complication was introduced bythe unpatented pre-1920 mining claims that

overlie most of the Federal oil shale lands, in-cluding the Utah lease tracts. In the early1970’s, when the Prototype leases were sold,DOI was confident that the unpatentedclaims would be invalidated, and that the

Government would retain title to the lands inquestion. In early 1977, however, a courtdecision in favor of the claimants was issuedin a case involving unpatented claims in Col-orado. Because this precedent could eventu-ally have resulted in validation of the claims



Ch 7–Resource Acquisition 241

overlying U-a and U-b, the lessees sued forand won a suspension in the lease terms, Thesuspension is still in effect, pending a Su-preme Court decision on the issue of unpat-ented claims. *

In summary, no permanent leasing pro-

gram exists for the Federal oil shale lands,and under the present Prototype Program,four tracts have been leased, but two are in-active because of legal uncertainties. The

*On June 2, 1980, the U.S. Supreme Court decided in favor of the Colorado claimants (Andrus v. Shell oil, No. 78-1815).

other two, Colorado tracts C-a and C-b, arebeing developed for MIS processing, The les-sees of tract C-a are also negotiating for ademonstration of the Lurgi-Ruhrgas AGRtechnology. If both tracts proceed to commer-cialization, they could produce a total of 133,000 bbl/d by 1987. With current plans,one mining technique, one in situ process, andone aboveground retort will be evaluated,Open pit mining will not be tested, nor willother in situ or AGR techniques. All of themining will be conducted in ground waterareas.

Land Exchanges

As discussed later, of the approximately400,000 acres of privately owned land in Col-orado, about 170,000 acres contain at least10 ft of oil shale yielding 25 gal/ton. The totalpotential oil yield from these richer tracts isat least 80 billion bbl, which would support al-million-bbl/d industry for 240 years. How-ever, much of the privately held land is lo-cated on the fringes of the oil shale basins,and contains thinner, leaner deposits thandoes the adjacent Federal land. Furthermore,some of the private tracts are in small, non-contiguous parcels (mainly former home-steads and small mining claims) that couldnot be economically developed. Private oil

shale development could be encouraged if these lands were exchanged for more eco-nomically attractive Federal tracts.

The exchanging of private mineral-bearingland for Federal land is allowed under sec-tion 206 of the Federal Land Policy and Man-agement Act of 1976 (FLPMA). Exchangesmay be consummated provided that they arein the public interest and that the propertiesinvolved are within 25 percent of equal value.The difference may be made up in cash.There are two options that would be particu-

larly suitable for the oil shale situations. Thefirst is the “blocking-up” of scattered or odd-ly shaped tracts by exchanging portions of them for adjacent Federal land, thereby cre-ating a tract geometry that could be devel-oped economically. Superior Oil Co. proposedsuch an exchange for its property in thenorthern Piceance basin. In this case, astringer of Superior land that extended intothe Federal holdings was to be exchanged fora parcel along the southern edge of the mainbody of the Superior property. EXXON Corp.has also proposed to exchange numeroussmall tracts along streambeds in the Piceancebasin for about 10,000 acres of Federal land

near the basin’s center.

The second option would involve exchang-ing a large block of private land on the fringeof the oil shale deposits for a substantiallysmaller block of Federal land in the richer,thicker areas. The Federal tract would haveto be much smaller, in general, because thedeposits under much of the Federal land areat least 1,000 ft thick; deposits on privatetracts along the basin’s fringe are seldommore than 250 ft thick.

The Adequacy of Pri vate Lands

Most of the privately owned lands in the through the filing of mining claims for oilPiceance and Uinta basins were acquired shale and other minerals under the Mining



—


Law of 1872. The provisions of the law re-quired that the mineral be “located” by theprospector; that is, he had to sample thedeposit and demonstrate, through assay, thatit contained the mineral of interest. In gener-al, the oil shales in Colorado and Utah aredeeply buried and therefore not visible fromthe surface. However, some deposits are visi-ble where streams have eroded through theoverburden. The early prospectors obtainedsamples from these outcrops, assayed them,filed claims for the outcrop and for the adja-cent land (which, it was inferred, also con-tained the mineral), and eventually obtainedpatents for the claimed land from the Govern-ment. Most of the original mining claims werequite small, but over the years the individualclaims have been purchased by major energycompanies and consolidated into much largerblocks that could be suitable for commercialdevelopment.

The locations of the larger privately ownedpatented or “fee” lands in the Piceance basinare shown in figure 56. * Because the oil shaledeposits were first detected along the Col-orado River, most of the fee lands are foundin the southern part of the basin. Because of the location requirements of the 1872 MiningLaw, they are generally found along stream-beds. Not shown in the figure are the numer-ous tracts of a few hundred acres that followthe streams in the central and northern parts

of the basin. These were primarily earlyhomesteads and grazing lands, but many of them have been acquired by the energy com-panies. They are still used for farming andstock raising, which retains control of thewater rights.

The location of the private lands has sever-al implications for oil shale development be-cause, although they are extensive, they arenot so commercially attractive as the Federallands to the north. There are three reasonswhy they are not so attractive. First, they are

much thinner and contain lower concentra-tions of kerogen than do the deposits on Fed-eral land. This is because the oil shale re-

*The term “fee’” is derived from the Middle English word~ie~: an inheritable or heritable estate in land.

sources were created on the bed of an an-cient lake by the deposition of silt and organicdebris carried into the lake by rivers andstreams. The lake had a bowl-shaped crosssection (hence, the term “basin”), and moresedimentation occurred near its depositionalcenters, which lie north of the geometriccenter of the basin—on Federal land. TheFederal deposits are therefore much thickerand, as a consequence, more amenable tolarge-scale development. The private lands,on the fringe of the basin corresponding tothe shoreline of the ancient lake, are muchthinner.

Second, because the level of water in thelake varied over time as the climate changed,the lakeshore advanced and receded. Whenthe water level was high, organic matter wasdeposited over a broader area and was con-

verted to oil shale before it could be decom-posed by exposure to the air. When the waterlevel was low, more inorganic silt was de-posited, and any organic debris that was laiddown near the shoreline decomposed whenthe shoreline receded. As a consequence, thedeposits on the basin’s fringe are muchleaner on the average than the deposits to thenorth, and they occasionally are intermixedwith layers of rock containing essentially noorganic matter, This complicated stratigra-phy reduces the average oil yield from depos-its on private land, and makes them less suit-

able for commercial development.The net effect of these two conditions is in-

dicated in table 32 and illustrated in figure57. As shown, the privately owned lands inColorado and Utah include about 340,000acres of deposits at least 10 ft thick thatwould yield at least 25 gal/ton of shale oil.The total potential yield from these depositsis about 100 billion bbl. In contrast, the Fed-eral lands have 1.2 million acres of equiva-lent deposits with a potential yield of 460 bil-lion bbl.

The third factor is that private lands con-tain essentially no commercially attractivedeposits of nahcolite and dawsonite—the so-dium minerals that are potential sources of aluminum, glass, and the chemicals used to



Ch. 7–Resource Acquisition 243

Figure 56.— Privately Owned Tracts in the Piceance Basin

dINTERNATIONAL NUCLEAR

M E E K E R

Y7MOBILEQUITY

&R COEOUITY S T A N D A R D O F

C A L I F O R N I A UNlON C O L O N Y \

O C C I D E N T A L

(4@ N

G o

moutline of the Green /?iver

formation A Proposed oil shale project

S O U R C E M a p of th e Ma/or 0/ / Shale Ho/dlrrgs-Colorado, Wyom/rtgUtah, Denver. Colo Cameron Engineers, Inc , January 1978



244 An Assessment of 0il Shale Technologies

Table 32.–Distribution of the Oil Shale Resources in Colorado and Utah

Ownership —Colorado Utah Total

— Federa l Private Federal Private Federal Private -

Ouantity of land (1 ,000 acres). . . . . . . . 1,420 400 3,780 1,100 5,200 1,600Deposits at least 10 ft thick and yielding at least 25 gal/ton

(1,000 acres ). . . . . . . . . . . . . . . . . . . . . 600 170 600 170 1,200 340

Potential yield of shale 011 (billion bbl). . . . . . . . . . 390 80 70 20 460 100

SOURCE Adapted from Prospec(s for 0(/ .Sha/e Oeve/oprnen(-Colorado, Urah, and Wyormng, Department of the Intertor 1968 pp A-1 and A-2

control air pollution from flue gases. Asshown in figure 58, the deposits of sodiumminerals stop short of the northern edge of the major private holdings. The only signifi-

cant exception is the land owned by SuperiorOil Co., which lies along the northern edge of the sodium mineral resources.

Present and Potent ial Projects on Private Land

Colony Development Operation (a consorti-um of Tosco and Atlantic Richfield Co.) andUnion Oil Co. own some of the more commer-cially attractive private land. The two com-panies have been developing retorting tech-nologies since the 1950’s and early 1960’s. Inthe late 1960’s Colony proposed to build acommercial-scale project on its property,which would use underground mining andaboveground processing in TOSCO II retorts.The project was delayed by economic uncer-tainties, and then resurrected in the 1970’safter the Arab oil embargo. It was subse-quently suspended when more detailed eco-nomic studies indicated a much higher costfor the project (and hence for its oil) thanpreviously anticipated. The retorting processhas been tested at the semiworks scale (about1,000 ton/d), and is regarded by Colony asbeing ready for commercial application.

The Colony project would produce 46,000bbl/d with six TOSCO II retorts, each proc-essing about 10,000 ton/d of ore. Because theproject would include a product pipelineacross Federal land, an EIS was required.This was completed by the Bureau of Land

Management (BLM) in 1977. At present, Col-ony has many of the major permits requiredto initiate the project, but it will not proceeduntil the economic climate is improved by fur-ther increases in oil prices or Government in-

centives, and until regulatory uncertaintiesare alleviated. 1

Union Oil Co. began developing retortingtechnologies in the 1950’s. It owns about30,000 acres of land in the southern PiceanceBasin, 20,000 acres of which contain oilshale. Union tested its “A” abovegroundretort on this land between 1954 and 1958.Since 1974, Union has been studying a projectthat would use the Union “B” retort to ex-tract 75,000 to 150,000 bbl/d of shale oil fromthe company’s resources. The plant is to bedeveloped with a modular stage in which asingle “B” retort with a capacity of about9,000 bbl/d will be tested. This project, theLong Ridge Experimental Shale Oil project, isin suspension until economic conditions im-prove sufficiently to warrant investment. Aminimum requirement at present is a produc-tion tax credit of $3/bbl of shale oil pro-duced. 2 Union has obtained all of the key en-vironmental permits required for the modularproject.

A third major oil project involving privateland is the Superior project, which would in-

volve the simultaneous recovery of shale oil,soda ash, alumina, and nahcolite from the so-dium mineral deposits. As indicated previ-ously, Superior has proposed to exchange along, thin portion of its tract for a parcel of



Ch 7–Resource Acquisition 245

Figure 57.—Thickness of the Oil Shale Deposits in the Piceance BasinThat Yield at Least 25 gal/ton of Shale Oil

RANGELY

rMEEKER

ET

RIFLE s

Private (Fee) lands,

Federal 011 shale lease tracts {GRAND JUNCTION

%/

SOURCE Cameron Eng ineers , Inc



.


Figure 58.— Location of the Sodium Mineral Deposits in the Piceance Basin

Is MEEKER

-

El Private (Fee) lands

mFederal 011 shale lease tracts

--- Extent of the nahcohte deposi ts)

++ Extent of the dawsorute deposits5

S O U R C E B Welchman,Sa//fre Zone 0/ / Sha/e an d th e /rrtegrated In SIfu Process, Houston. Tex The Mult i Mineral Corp , May 1979 p 17






Present and Potential Projects on Federal Land

As discussed in volume II and mentionedearlier here, only two projects are activelybeing conducted as part of the PrototypeLeasing Program. Rio Blanco Oil Shale Co. is

developing tract C-a using MIS methods. Ademonstration of the Lurgi-Ruhrgas above--ground retort may be included. Tract C-b isbeing developed as the Cathedral BluffsShale Oil project. Occidental’s MIS technol-ogy is being used, and no plans have been an-nounced for a concurrent demonstration of AGR technologies. The White River project ontracts U-a and U-b, which were unified for

joint development, is presently in suspensionpending resolution of ownership.

Paraho Development is also engaged in aproject involving Federal land at the DOEresearch facility in Anvil Points, Colo. AnvilPoints was the site of Paraho’s retort develop-ment program. Paraho is attempting to ex-tend the terms of its lease to include a mod-ular demonstration program and to obtainfunding for the project. The outlook is uncer-tain, because an EIS is required and none hasyet been issued, despite four attempts byDOE. Paraho’s management is also pursuinga production tax credit to improve theeconomic outlook for shale oil.

As mentioned earlier, EXXON Corp. has

also proposed to exchange its scattered hold-ings for a single tract of Federal land in Col-orado. The future of this proposal is uncer-tain. If Superior’s land-exchange experienceis regarded as typical, preparation and re-view of the EXXON proposal could take aslong as 8 years. Four years is more likely.

DOE and the Department of Defense arepreparing a management plan for developingNaval Oil Shale Reserve No. 1 (NOSR 1),which is contiguous to the Anvil Points site.This project is in the early stages, and the

potential production cannot be accurately es-timated. However, if all of the preliminary ex-ploration, design work, and permitting can becompleted by 1986, and if plant constructionwere expedited, DOE believes that NOSR 1

could be producing at least 100,000 bbl/d by1990.

Multi Mineral Corp. has proposed to use amine shaft on Federal land in the northern Pi-ceance basin to develop an MIS process to re-cover shale oil, alumina, and nahcolite fromdeeply buried deposits. The shaft was drilledin 1978 by the U.S. Bureau of Mines to devel-op mining techniques for sodium mineralsand oil shale in the saline zone. * The proposalinvolves a three-phase project that could leadto a 50,000-bbl/d operation.

If all of the presently active and proposedprojects involving Federal land were com-pleted, the total production could exceed300,000 bbl/d, plus any additional production

from NOSR 1. However, only 57,000 bbl/d of this production is assured, because onlyCathedral Bluffs is committed to commercial-ization. Rio Blanco is committed only to test-ing its development techniques at the precom-mercial level—approximately 2,000 bbl/d.The decision to proceed to commercial levelsof production will depend on the technicalfeasibility of the MIS and Lurgi-Ruhrgasmethods and on the existence of a favorableeconomic and regulatory climate. Therefore,achieving 300,000 bbl/d from these opera-tions is likely to require the following:

q

q

q

q

for Cathedral Bluffs: continued techni-cal progress and continuation of a favor-able economic outlook;for Rio Blanco: technical progress andfavorable project economics, perhaps in-cluding Federal financial incentives;for Paraho: extension of the terms of theAnvil Points lease and provision of a pro-duction tax credit;for White River: favorable resolution of the ownership dispute and possibly Fed-eral incentives (Standard Oil Co. of Ohio

(SOHIO) is a participant in the White

*The Multi Mineral technology is discussed in ch. 5. The ge-ology and stratigraphy of the oil shale basins are discussed inch . 4.



Ch. 7–Resource Acquisition 249

River project. SOHIO is also involved inthe Paraho operation.); and

q for EXXON: approval of the proposedland exchange.

The potential production from tract C-acould be expanded by 75,000 bbl/d if the les-

sees returned to their original open pit miningplan. However, to allow maximum recoveryof the oil shale resource, lands outside of thetract boundaries would have to be used forwaste disposal and the siting of the process-ing facilities. Such off tract land use is pres-

ently banned by Federal statutes, includingthe acreage limitation of the Mineral LeasingAct and the provisions of FLPMA, whichstate:

Is More Federal Land Needed?

Nothing in this Act, or in any amendment

made by this Act, shall be constructed aspermitting any person to place, or allow to beplaced, spent shale oil, overburden, or by-products from the recovery of other mineralwith oil shale, on any Federal land other thanFederal land which has been leased for therecovery of oil shale . . .

As discussed in chapter 6, shale oil ap-pears to be economically competitive, based

on the present and projected prices of foreigncrude oil and some premium-quality domesticcrudes. However, technical, economic, andregulatory risks are inhibiting potential de-velopers from making large capital invest-ment commitments to shale development.These uncertainties are aggravated by someof the characteristics of the private landswhich, in general, are not so favorable asthose of adjacent Federal lands. Further-more, the privately owned lands contain es-sentially no commercially attractive depositsof sodium minerals. Assuming that these min-

erals could be extracted economically, theycould be sold as byproducts to enhance theeconomic feasibility of a project. Whethermore Federal land must be provided depends

how much production is desired;how rapidly the industry is to be cre-ated;whether production of sodium minerals,or testing of the “multimineral” technol-ogies used to extract them, is desired;how much technical, economic, and envi-ronmental information is desired to as-sist policymaking and the setting of envi-ronmental regulations; andwhether financial incentives are pro-vided that will encourage the continua-tion of present projects on the Federal

lease tracts and also initiate projects onprivate lands.

The need for additional Federal land willdepend strongly on the size of the industryand the pace of its creation. It will also be af-fected by the other Federal oil shale policies,especially those involving financial incen-tives. This is shown in table 33, which indi-cates how the industry’s capacity in 1990might be affected by different Federal ac-tions. As shown for case 1, about 60,000 bbl/dcould be achieved with no additional actions,assuming that the Cathedral Bluffs project iscompleted and that Geokinetics reaches its

production target. If economic conditions en-courage Rio Blanco to continue and SandWash to accelerate, production could reach185,000 bbl/d by 1990. If incentives areadded (case 2) that assure completion of these two projects, that encourage the Colonyand Union projects to resume, and that alsoinitiate a new project on private land, produc-tion would reach 360,000 bbl/d. This could beexpanded in case 3 to nearly 400,000 bbl/d if the Superior land exchange is consummated(or a lease issued for the desired parcel) andtest sites are provided for the Paraho and

Multi Mineral processes. All three of theseprojects would involve providing access to ad-ditional Federal land.

If the ownership conflicts surrounding theUtah lease tracts are resolved in a manner




Table 33.–Estimated Shale Oil Production by 1990 in Response to Various Federal Actions

Case

Federal action 1 2 3 4 5 6 7 8

None. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . xIncentives for first-generation developers . . . . x x x x xTest sites for modular retortsb . . . . . . . . . . . . x x x x x xResolution of ownership issues on Utah tracts c. x x x x x

Offtract land use

d

. . . . . . . . . . . . . . . . . . . . x x x xProposed land exchanges. . . . . . . . . . . . . . x x xIncentives for second-generation developers

(or improved economics) . . . . . . . . . . . . . x xNaval Oil Shale Reserves or expanded

Prototype Program or permanent leasing. . . . xProduction, bbl/d . . . . . . . . . . . . . . . . . . . 6 0 , 0 0 0 - 3 6 0 , 0 00 3 9 0 , 0 0 0 4 9 0 , 0 0 0 5 6 0 , 0 0 0 6 2 0 , 0 0 0 8 5 0 , 0 00 1,000,000

185,000 f

aASSumeS the entry of one as-yetunannounced developerblncludo~ the proposed superior 011 land exchange and a Ieasmg of Anwl POIIIIS by parafio DeVe@rrrerrlCReSurnptlOrl of the tract U-a/(J-b project may also depend on the availablhty of Incentives and On other lmProvemenfs In Protect economicsaFor waste disposal from the o~n plt mme that was Ongmally proposed for traCt C-aelncludes the proposed Supertor 011 and EXXON land mcharwsfonly 59,000 bbllfj IS llrmly Cwnrnmed


favoring the lessees, and if appropriate in-centives are provided, the White River proj-ect could resume. This would add 100,000bbl/d to the industry’s capacity. Productioncould reach 560,000 bbl/d if Rio Blanco weregiven permission to use offtract lands andreturned to its original open pit mining plan,as assumed for case 5. If the EXXON land ex-change were completed (case 6), productionwould be increased by 60,000 bbl/d. Asshown for case 7, production might be in-creased to 850,000 bbl/d by providing sub-sidies that were sufficiently attractive to en-

courage the participation of the “second gen-eration” of developers—those who are not astechnically advanced as Colony and Union, orwho lack resources of equivalent quality. Thetotal additional capacity indicated corre-sponds to about five additional major projectson private land. The Government could alsobecome more directly involved in oil shale

development by leasing additional tracts orby developing NOSR 1 (case 8). The industry’scapacity in 1990 could then reach 1 millionbbl/d.

In summary, reaching 200,000 bbl/d by1990 may not require the release of substan-tial tracts of Federal land, if the presently ac-tive projects are technically successful and if the economic outlook remains favorable. Only60,000 bbl/d of this capacity is assured.About 400,000 bbl/d might be achieved if ef-

fective incentives were provided and testsites allocated for retorting demonstrations.Achieving 1 million bbl/d by 1990 might re-quire subsidies, land exchanges, permissionto use offtract land for waste disposal andfacility siting, and the leasing of additionaltracts or the development of the Naval OilShale Reserves.

q To amend the Mineral Leasing Act of proving economic feasibility. It might also

1920.—The Act could be amended to in- allow the inclusion of a suitable wastecrease the acreage limitations, or to set the disposal site within a tract’s boundariessize of the tract according to the recover- while still providing adequate oil shaleable resources it contained. This might al- resources for sustained, large-scale opera-low more economies of scale, thereby im- tions, thus avoiding the need for separate



Ch 7–Resource Acquisition . 251

q

q

q

offtract disposal authorization. The num-ber of leases per person or firm could alsobe increased. This might provide additionalencouragement to firms that do not own oilshale lands because it would allow them toacquire experience on one lease tract and

then apply it to another while the first wasstill operating. A disadvantage would bethat the number of firms participating inthe leasing program could be reduced if afew firms acquired all of the leases. Oneoption would be to increase the number toone lease per State. This might encouragea firm to develop a process in the richer de-posits in Colorado and then apply it to thepoorer quality resources in Utah or Wyo-ming.

To amend FLPMA.—FLPMA could beamended to allow including conditions(such as environmental stipulations anddiligence requirements) in any oil shaleland exchange agreement. This would im-prove the Government’s control over theexchanged parcel. It might also discourageprivate participation.

To allow offsite land use for leasetracts. —Legislation could be provided toallow a lessee to use land outside of theboundaries of a lease tract for facility sit-ing and waste disposal. This might permitlarger, more economical operations (in-

cluding perhaps an open pit mine) andwould maximize resource recovery on thetract. However, subsequent developmentof the offtract areas would be inhibited.(DOI estimated that Rio Blanco’s offtractdisposal plan would reduce resource re-covery from the disposal area by about 5percent.)

To lease additional tracts under the Proto-type Program.—There is no statutory lim-itation on the number of tracts that couldbe leased under the Prototype Program.

However, DOI originally committed to leas-ing no more than six. Because two of theoriginal tracts were not leased, offeringtwo new ones might be justified, providedthat the technologies to be tested were dif-ferent from the processes being developed

on the existing tracts. Leasing more thantwo more tracts, or leasing for the purposeof expanding near-term shale oil produc-tion, would encounter political oppositionby the critics of rapid oil shale develop-ment. Leasing could begin sooner than un-

der a new leasing program, if some of thepotential lease tracts previously nominatedwere offered. A supplemental EIS would berequired. Construction on the tracts couldprobably not begin until about 1985 andproduction no sooner than 1990. Consider-ation might be given to leasing a tract formultimineral operations, a process that isnot being evaluated in any project at pres-ent. (One of the primary goals of the Proto-type Program is to obtain informationabout a variety of technologies. )

To initiate a new, permanent leasing pro-gram.—An advantage would be that moreproduction could be achieved than is possi-ble under the present Prototype Program.A full EIS and a new set of leasing regula-tions would be needed. Without the infor-mation to be acquired by completing thepresent Prototype Program projects, itmight be difficult to prepare an accurateenvironmental assessment and to structurecomprehensive leasing regulations. Pro-duction could probably not begin until after1990. Abandonment of the Prototype Pro-

gram would be implied, which might engen-der political opposition.

To expedite land exchanges.—The reviewand approval procedures could be expe-dited by, for example, setting up a taskforce within DOI specifically for oil shaleproposals.

Government development.—The Govern-ment could develop the Naval Oil Shale Re-serves. Unless this were done by leasing toprivate developers, it would involve compe-tition with private industry, and would en-

counter political opposition. It would alsobe very costly because the public wouldhave to pay the full cost of the facilities,and it might discourage independent ex-periments by private firms. Informationuseful in developing policies and regula-




tions for the industry would be obtained.However, because the Government’s expe-rience with financing and operating a facil-ity would be substantially different fromthat of private developers, the informationmight not be useful in evaluating private in-

Chapter 7

IHO F. Coffer and A. Christianson, eds., EPA Pro-gram Conference Report: Oil Shale, EPA-600/ 0-79-025, July 1979, p. 90

vestment decisions. Some of the informa-tion is being acquired in the present Proto-type Program. It could also be obtained inadditional leasing programs or through li-censing arrangements with the owners of the technologies.

References

‘Ibid., at p. 27.31bid.



CHAPTER 8

Environmental Considerations

PageIntroduction . . . . . . . . . . . . . . . . . . . . . ......255

Summary of Findings . ...................256Air Quality . . . . . . . . . . . . . . . . . . . . . . . . . . . . 256Water Quality. . . . . . . . . . . . . . . . . . . . . . . . . .256Occupational Health and Safety . ..........257Land Reclamation. . . . . . . . . . . . . . . . . . . . . ..258Permitting. . . . . ........................259

Air Quality . . . . . . . . . . . . . . . .. ... ... .+ ...259Introduction . . . . . . . . . . . . . . . . . . . . . ......259Pollutant Generation . . ..................259Air Quality Laws, Standards, and Regulations 263Air Pollution Control Technologies . ........269Pollutant Emissions. . . . . . . . . . . . . . . . . . . . . .278Dispersion Modeling. . ...................279A Summary of Issues and Policy Options. ....288

Water Quality. . . . . . . . . . . . . . . . . . . . . . . . . .291Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . 29lPollution Generation. . . . . . . . . . . . . . . . . . . . . 292Summary of Pollutants Produced by Major

Process Types. . . . . . . . . . . . . . . . . . . . . . . .294Effects of Potential Pollutants on Water

Quality and Use. . . . ...................295Water Quality in the Oil Shale Region. .. ....296Water Quality Regulations. . ..............297

Technologies for Control of Oil Shale WaterPol lu t ion . . . . . . . . . . . . . . . . . . . . . . . . . . . . 304Ultimate Disposition of Waste Water . .......308Monitoring Water Quality . ...............309Information Needs and R&D Programs .. ....311Findings on Water Quality Aspects of Oil

Shale Development. . . . . ...............314

P a g e

Policy Options for Water Quality Management 314

Safety and Health. . . . . . . ................315Introduction . . . . . . . . . . . . . . . . . . . . . ......315Safety and Health Hazards . ..............316Summary of Hazards andTheir Severity. ....322Federal Laws, Standards, and Regulations. ..324Control and Mitigation Methods . ..........325Summary of Issues and R&D Needs . . . . . . . . . 326Current R&D Programs. . .................326Policy Considerations. . ..................327

Land Reclamation. . . . . . . . . . . . . . . . . . . . . . .328

Introduction . . . . . . . . . . . . . . . . . . . . . ......328Reasons for Reclamation . ................329Regulations Governing Land Reclamation. ...329Reclamation Approaches. . ...............330The Physical and Chemical Characteristics

of Processed Shale . . . . . . . . . . . . . . .. ....332Use of Topsoil as a Spent Shale Cover . ......335Species Selection and Plant Materials . . . . . . . 336Review of Selected Research to Date. .......339Summary of Issues andR&D Needs . . . . . . . . . 341Policy Options for the Reclamation of

Processed Oil Shales. . .................342

Permitt ing. . . . . . . . . . . . . . . . . . . . . . . . . . . . .343

Introduction . . . . . . . . . . . . . ..............343Perceptions of the Permitting Procedure. ....344Status of Permits Obtained by Oil Shale

Developers . . . . . . . . . . . . . . . . . . . .The Length of the Permitting ProcedureDisputes Encountered in the Permitting

Procedure . . . . . . . . . . . . . . . . . . . . .

0 . , . . 345. , , . . 346

. . . . . 346



PageUnresolved Issues. . .....................347Attempts at Regulatory Simplification. .. ....348Policy Options. . . ..............,.,....,.349

Chapter8 References. . ..................352

List of Tables

TableNo, Page

34.

350

36.

37.

38.

39.

40.

41.

42.43.

44.

45,

46.

47.

48.

49.

50.

51.

52.

53.

Pollutants Generated bythe ColonyDevelopment Project . . . . . . . . . . . . . . . . 262PollutantsGenerated by the Rio BlancoProject on TractC-a. . . . . . . . . . . . . . . . . 263Pollutants Generatedbythe OccidentalOperation on TractC-b . . . . . . . . . . . . . . 263The Federal and State Ambient AirQuality Standards and Prevention of Significant Deterioration StandardsThat Influence Oil Shale Development . . 266National Standards for Prevention of Significant Deterioration of AmbientAir Quality, . . . . . . . . . . . . . . . . . . . . . . . 267National New Source Performance

Standards for Several Types of Facilities 269EPA Standards for Best Available AirPollutionControl Technologies for OilShale Facilities. . . . . . . . . . . . . . . . . . . . . 269Technological Readinessof Air PollutionControl Technologies . . . . . . . . . . . . . . . . 276Costs of AirPollutionControl . . . . . . . . . 277Pollutants Emitted by theColonyDevelopment Project . . . . . . . . . . . . . . . . 278Pollutants Emitted by theRio BlancoProject on Tract C-a. . . . . . . . . . . . . . . . . 278Pollutants Emitted by the OccidentalOperation on TractC-b . . . . . . . . . . . . . . 279ASummary of Emission Rates From Five

Proposed Oil Shale Projects. . . . . . . . . . . 279A Comparison of Atmospheric EmissionsUsed in Modeling Studies. . . . . . . . . . . . . 282Modeling Results for Federal Oil ShaleLease TractC-a . . . . . . . . . . . . . . . . . . . . 284Models Used in SupportofPSDApplications for Oil Shale Projects . . . . . 285Areas of Inadequate Information andSuggested R&D Responses . . . . . . . . . . . . 288Generation Rates for Principal WaterPollutants for Production of 50,000 bbl/dof Shale Oil Syncrude. . . . . . . ..., . . . . . 294Quality of Some SurfaceStreams in theOil Shale Region . . . . . . . . . . . . . . . . . . . . 297

Quality of GroundWaterAquifers in thePiceance Basin. . . . . . . . . . . . . . . . . . . . . 297

Page

54. Effluent Limitations for PetroleumRefineries Using BestPracticablePollution Control Technology. . . . . . . . . . 299

55. Effluent Limitations for Best Available

56

57

Technology Achievable for PetroleumRefinery Facilities . . . . . . . . . . . . . . . . . . 299New Source Performance Standards forPetroleum Refineries . . . . . . . . . . . . . . . . 300

Colorado Water Quality Standards forStream Classification B2 . . . . . . . . . . . . . 30158. Utah Water Qualitv Standards for

59

60

61

Stream Classification CW . . . . . . . . . . . . 301Proposed Water Quality Criteria forDesignated Uses. . . . . . . . . . . . . . . . . . . . 302Primary Drinking WaterStandards . . . . 303Proposed Secondary Drinking WaterRegulations. ,.. .. ~.. .., ..~.... . . . . . 303

62. The Types of Contaminants in Oil ShaleWastewater Streams and Some PotentialProcesses for RemovingThem . . . . . . . . . 305

63. Relative Rankings of the Water

64.

65,

66.

67.

68.

69.

70.

Treatment Methods . . . . . . . . . . . . . . . . . 306

Estimated Costs of Water PollutionControl in Oil ShalePlants. . . . . . . . . . . . 306Sampling Schedule Summary for Surfaceand Ground Water Monitoring Programat Tract C-b During Development Phase. 312Animal Studies on the Carcinogenicity of Oil Shale and ShaleOil . . . . . . . . . . . . . . 320Benzo(a)pyrene Content of 0il Shale andIts Products and of Other EnergyMaterials . . . . . . . . . . . . . . . . . . . . . . . . . 320The Chemical and Physical Properties of Processed Shales . . . . . . . . . . . . . . . . . . . 332Estimates of Reclamation Needs UnderVarious Levels of Shale Oil Production. , 338

Status of the Environmental Permits forFive Oil Shale Projects, . . . . . . . . . . . . . . 345

List of Figures

59. Designated Class I Areas in Oil Shale Page

Region . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26860, Computation Modules in Atmospheric

Dispersion Models . . . . . . . . . . . . . . . . . . 28161. An Aboveground Spent Shale Disposal

Area . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 307

62. Summary of Occupational HazardsAssociated With Oil ShaleDevelopment. 323



CHAPTER 8

Environmental Considerations

Introduction

The region where oil shale development

will take place is, at present, relatively un-disturbed. The construction and operation of plants would emit pollutants and producelarge amounts of solid waste for disposal. Asa consequence, air, water, and soil could bedegraded and the topography of the landcould be altered. The severity of these im-pacts will depend on the scale of the opera-tions and the kinds of processing technologiesused, as well as the control strategies thatmust be adopted to comply with environmen-tal regulations.

Control strategies have been proposed forpurifying water and airborne emissionsstreams, for revegetation, for protecting wild-life, and for other specific areas of envi-ronmental concern. However, control tech-nologies that are applied to one area couldadversely affect another area. For example,to control air pollution, airborne streams arescrubbed to capture dust and gaseous con-taminants. This produces sludges and waste-water that have to be disposed of along withother wastes. All of these have the potentialto adversely affect the land and the water.

Airborne pollutants, such as trace metals,might enter surface streams and groundwater in fugitive dust and or rainfall andcould alter the chemical and biological bal-ances of the water systems. Plant and animallife as well as human health could be harmedboth by an increase in water contaminationand by the entry of the contaminants into thefood chain. Similarly, without adequate con-trols, the piles of solid waste could contami-nate the air and water through fugitive dust

emissions and by the leaching of soluble con-

stituents into surface and ground water sys-tems. Water quality could thus be degradedby altered nutrient loading, changes in dis-solved oxygen, and increased sediment andsalinity.

For these reasons, each potential environ-mental effect along with its control technol-ogy should be examined with respect to its netimpact on the total environmental system. Todo this requires full understanding of theseparate impacts on air, water, and land, theinteraction between the individual parts of

the ecosystem, and the efficacy of the controlstrategies. Such an analysis needs a completeand accurate data base which is as yet un-available because no commercial oil shaleplants have been built. OTA’s environmentalanalysis, therefore, is limited to examiningthe effects that an oil shale industry wouldhave on the separate areas of air, water,land, and occupational health and safety. Inorder to provide a basis for policy analysis,the effects are quantified wherever possibleand related to a production of 50,000 bbl/d.For each of the areas examined:

impacts of oil shale operations are de-scribed;applicable laws and regulations aresummarized, and their significance to oilshale analyzed;control strategies proposed for compli-ance with the laws and regulations aredescribed and evaluated; andpolicies that could be focused on key is-sues and uncertainties are identifiedand discussed.

255




Summary

Air Quality

Because of the oil shale region’s rural character,

i t s a i r i s r e l a t i v e l y c l e a n a n d u n p o l l u t e d . Oc c a s i o n a l -

l y , h o w e v e r , h i g h c o n c e n t r a t i o n s o f h y d r o c a r b o n s( p o s s i b l y f r o m v e g e t a t i o n ) a n d p a r t i c u l a t e f r o m

w i n d b l o w n d u s t occur . The development o f a large o i l

s h a l e i n d u s t r y ( o r a n y i n d u s t r i a l o r m u n i c i p a l g r o w th )

w i l l d e g r a d e t h e a i r ’ s v i s i b i l i t y a n d q u a l i t y . E v e n i f

the best ava i lab le contro l technolog ies a re u se d a n dcompliance is maintained with the provisions of theClean Air Act, its amendments, and the applicableState laws, degradation will occur. It will take placenot only near the oil shale facilities but also in nearbypristine areas (e.g., national parks, wildernessareas). Some places may be affected more thanothers from local concentrations of pollutants caused

by thermal inversions.Findings of the analysis include:

q Oil shale mining and processing will produce at-mospheric emissions including those pollutantsfor which National Ambient Air Quality Standards(NAAQS) have been established (i.e., sulfur diox-ide, particulate, carbon monoxide, ozone, lead,and nitrogen oxides); as well as various other cur-rently unregulated pollutants (such as silica,sulfur compounds, metals, trace organics, andtrace elements).

q Under the Clean Air Act, oil shale development willhave to comply with NAAQS and State air qualitystandards; maintain air quality, especially visibili-ty, in adjacent Class I areas (e.g., national parks);comply with prevention of significant deterioration(PSD) increments (these specify the maximum in-creases in the concentrations of sulfur dioxide andparticulate that can occur in any region); complywith New Source Performance Standards (NSPS);and apply the best available control technology(BACT).

q A wide variety of control technologies could be ap-plied to the emissions streams from oil shale proc-

esses. They are fairly well developed and havebeen successfully used in similar industries. Theyshould be adaptable to the first generation of oilshale plants. However, full evaluation will not bepossible until they have been tested in commer-cial-scale oil shale plants for sustained periods.

of Findingsq

q

q

The costs of controlling air pollution will be par-ticularly sensitive to the strictness of the environ-mental regulations and to the design characteris-tics and size of each project. Preliminary estimates

indicate that air pollution control could cost from$0.91 to $1.16/bbl of syncrude produced (rough-ly 3 to 5 percent of the selling price of the oil).

The only means for predicting the long-range im-pacts of oil shale emissions on ambient air qualityin the oil shale area and in neighboring regions aremathematical dispersion models, which are theEnvironmental Protection Agency’s (EPA) tool forenforcing the provisions of the Clean Air Act. Mod-eling of oil shale facilities presents a number ofproblems because of the topography and meteorol-

ogy of the region, the chemistry of the emissions,and the unknown quantities of emissions expectedfrom commercial-size facilities. In addition, dis-persion models developed to date have been pri-marily for flat terrain. Thus, their predictions con-tain significant inaccuracies. More R&D needs tobe undertaken in this area.

Even with the use of BACT, the industry’s capacitywill be limited by the air quality standards govern-ing PSD. A preliminary modeling study by EPA hasindicated that an industry of up to 400,000 bbl/din the Piceance basin could probably comply withthe PSD standards for Flat Tops (a nearby Class Iarea) if the plant sites were dispersed. Additionalcapacity could be installed in the Uinta basin,which is at least 95 miles from Flat Tops, A 1-mil-lion-bbl/d industry could probably not be accom-modated because at least half of its capacity(500,000 bbl/d) would be located in the Piceancebasin. Policy options to address this limitation in-clude the application of more stringent emissionstandards, changes in PSD increment allocationprocedures, and amending the Clean Air Act.

Water Quali ty

Water quality is a major concern in the oil shale re-gion, especially in regard to the salinity and sedimentlevels in the Colorado River system. The potential forpollution from oil shale development could come from



Ch. 8–Environmental Considerations q 257

point sources such as cooling system discharges;from nonpoint sources such as runoff and leaching ofaboveground waste disposal areas and ground waterleaching of in situ retorts; and from accidental dis-charges such as spills from trucks, leaks in pipe-lines, or the failure of containment structures, Un-less these pollution sources are properly controlled,the lowered quality of surface and ground waterresources could adversely affect both aquatic biotaand water for irrigation, recreation, and drinking.

Specific findings include the following:q

q

q

Surface discharge from point sources is regulatedunder the Clean Water Act, and ground water rein-fection standards are being promulgated under theSafe Drinking Water Act. Solid waste disposalmethods may be subject to the Toxic SubstancesControl Act and the Resource Conservation andRecovery Act. The general regulatory framework istherefore in place, although no technology-basedeffluent standards have been promulgated for theindustry under the Clean Water Act. Nonpointsources present regulatory and technological diffi-culties, and at present are subject to less stringentcontrols.

Developers are currently planning for zero dis-charge to surface streams and to reinject only ex-cess mine water. This eliminates point dischargeproblems because most wastewater will be treatedfor re-use within the facility, and untreatablewastes will be sent to spent shale piles. The costsof this strategy are low to moderate, and develop-

ment should not be impeded by existing regula-tions if it is used.

A variety of treatment devices are available for theabove strategy, and many of them should be well--suited to oil shale processes. However, uncertain-ties exist regarding whether conventional methodswould be able to treat wastewaters to dischargestandards because they have not been tested withactual oil shale wastes under conditions that ap-proximate commercial production. There are also anumber of uncertainties regarding the control ofnonpoint pollution sources. For example, no tech-

nique has been demonstrated for managingground water leaching of in situ retorts, nor hasthe efficacy of methods for protecting surface dis-posal piles from leaching been proven. It is notknown to what extent leaching will occur, but if itdid, it would degrade the region’s water quality.

q Although control of major water pollutants frompoint sources is not expected to be a problem, lessis known about the control of trace metals and tox-ic organic substances. Research is needed to as-sess their potential hazards and to develop meth-ods for their management. Other laboratory-scaleand pilot-plant R&D should be focused on charac-terizing the waste streams, on determining thesuitability of conventional control technologies,and on assessing the fates of pollutants in thewater system. Extensive work is already under-way; its continuation is essential to protectingwater quality, both during the operation of a plantand after site abandonment.

Occupational Health and Safety

The oil shale worker will be exposed to occupa-tional safety and health hazards. Many of these–

such as rockfalls, explosions and fires, dust, noise,and contact with organic feedstocks and refinedproducts–will be similar to those associated withhard-rock mining, mineral processing, and the refin-ing of conventional petroleum. However, the workersmight be exposed to unique hazards due to the phys-ical and chemical characteristics of the shale and itsderivatives, the types of development technologies tobe employed, and the scale of the operations. Poten-tial risks include safety hazards that might result indisabling or fatal accidents, and health hazardsstemming from high noise levels, contact with irritantand asphyxiant gases and liquids, contact with likely

carcinogens and mutagens, and the inhalation of fi-brogenic dust.

Specific findings include:q

q

Only a few fatalities have occurred during the min-ing of over 2 million tons of shale and the produc-tion of over 500,000 bbl of shale oil. The accidentrate has been one-fifth that for all mining, andmuch lower than that for coal mining. However,this record was achieved in experimental minesthat employed, for the most part, experiencedminers. Whether safety risks will increase or de-crease as mining activities are expanded cannot

be predicted.Although the carcinogenicity of oil shale dusts andcrude shale oil has been demonstrated by some in-vestigators, the conflicting results of other studiescombined with an overall lack of information pre-




q

q

q

elude a determination of the severity of the risk.The incidence of diseases in other industries indi-cates that exposure to these materials could behazardous.

The large variety of substances that will be en-countered in retorting may present as yet unde-

tected health hazards. Of special concern is thepossibility of carcinogens in shale oil and its de-rivatives, Possible synergistic effects from theproducts of modified in situ (MIS) operations(which combine mining with retorting) could in-crease the level of risk.

Shale oil refining poses no special hazards sincemost of its problems will be similar to those experi-enced in conventional petroleum refining.

Health and safety hazards will be reduced byusing pollution control technologies for air andwater pollutants and by requiring specific indus-

trial hygiene practices. These are required by lawand are expected to be implemented by oil shaledevelopers. However, it is essential that R&D onthe nature and severity of health effects keep pacewith the development of the industry. Such infor-mation will be useful in identifying and mitigatinglong-term effects on workers and the public.

Land Reclamation

An industry will require land for access to sites,for the facilities, for mining, for retorting, for oilupgrading, and for waste disposal. The extent to

which development will affect the land on and near agiven tract will be determined by the location of thetract; the scale, type, and combination of processingtechnologies used; and the duration of the opera-tions. The facilities must comply with the laws andregulations that govern land reclamation and wastedisposal. Nevertheless, there will still be effects onland conditions (through altered topography) andwildlife (through changes in forage plants and habi-tats). In addition, unless appropriate disposal andreclamation methods are developed and applied, thelarge quantities of solid wastes that will need to behandled could pollute the air with fugitive dust andthe water with runoff and Ieachates from storagepiles and waste disposal areas.

Specific findings include:q

q

q

q

q

q

Several approaches can be used to reduce thedeleterious effects associated with the disposal ofspent oil shale. These include reducing surfacewastes by using in situ processing or returningwastes to mined out areas; the chemical, physical,

or vegetative stabilization of processed shale; andcombinations of the above.

Research has shown that vegetation can be estab-lished directly on processed oil shales. However,intensive management is required, including theleaching of soluble salts, the addition of nitrogenand phosphorus fertilizers, and supplemental wa-tering during establishment. Revegetating spentshale covered with at least 1 ft of soil is less sus-ceptible to erosion and does not require as muchsupplemental water and fertilizer. Adapted plantspecies are required for either option,

The long-term stability and character of the vege-tation is unknown, but research on small plotssuggests that short-term stability of a few decadesis likely if suff icient t opsoil i s added.

Reclamation plans will have to be site specificsince environmental conditions vary from site tosite, Proper management will be required in all in-stances, if only to maintain plant communities insurrounding areas. H is even more important inthe reclaimed areas.

Shortages of adapted plants and associated sup-port materials such as mulches probably wouldoccur if a large (ea. 1 million bbl/d) industry is es-tablished. The problem is compounded by the in-creasing demands from other mining operationssuch as coal and other minerals.

The Surface Mining Control and Reclamation Actprovides for the kind of comprehensive planningand decisionmaking needed to manage the landdisturbed by coal development. New reclamationstandards that are applied to oil shale should pro-vide for postmining land uses that are ecologicallyand economically feasible and consistent withpublic goals.



Ch. 8–Environmental Considerations 259

Permitting

During the past 10 years an increasingly complexsystem of permits has been developed to assist theFederal, State, and local governments in protectinghuman health and welfare and the environment. Per-

mits are the enforcement tool established by Con-gress and the States to determine whether a pro-spective facility is able to meet specific requirementsunder the law.

Operation of an oil shale facility requires more than100 permits from Federal, State, and local agencies.Included are those for environmental maintenance,for protection of worker health and safety, and for theconstruction and operation of any industrial facility(e.g., building code permits, temporary permits forthe use of trailers, sewage disposal permits). Ofthese 100 permits, about 10 major environmentalones require substantial commitments of time and re-sources.Findings of the analysis include:

q The time required for preparing and processing apermit application depends on the type of actionbeing reviewed, the review procedures stipulatedunder the law, the criteria used by agencies to

judge the application, and the amount of publicparticipation and controversy that is brought tobear. If Federal land is involved, then an environ-mental impact statement (EIS) will most likely berequired. The EIS process may take at least 9months after the developer applies for permissionto proceed with the project. In the case of the cur-rent Federal lease tracts, additional time wasneeded to prepare detailed development plans(DDP) for approval by the Area Oil Shale Super-

q

q

visor of the U.S. Geological Survey (USGS). Oncethe requirements for an EIS and DDP are satisfied,obtaining all of the needed permits can take morethan 2 years. The project would not necessarily bedelayed by the full length of the permitting sched-ule, because other predevelopment activities such

as engineering design, contracting, and equip-ment procurement could proceed in parallel, if thedeveloper were willing to accept the risk that someof the permits might not be obtainable.

The principal problems encountered to date withthe permitting process are related to the needs ofthe regulatory agencies for technical informationand to differing interpretations of environmentallaw. Future problems may be more critical thanthose encountered thus far. Several relevant regu-lations are still pending that may increase costs orforce changes in the design of process facilities or

control technologies. They may also add to thecontrol requirements. Another problem that mightemerge is the ability of regulatory agencies to han-dle the increasing load of permit applications andenforcement duties.

Several attempts are being made to simplify regu-

Air Quality

Iatory procedures. These include the streamliningof permitting procedures within specific agencies;the design and testing of a permit review pro-cedure for major industrial facilities that will coor-dinate the reviews by Federal, State, and localregulators; and the proposed Energy MobilizationBoard to expedite agency decisionmaking and re-duce the impacts of new regulatory requirements.Colorado has recently announced a joint reviewprocess designed to accomplish the first two ofthese ends.

Introduction

The maintenance of air quality is neces-sary for the development of an environmen-

tally acceptable oil shale industry. In this sec-tion:

The types of atmospheric contaminantsproduced by oil shale unit operations arecharacterized.

q

q

q

Rates are estimated for the generation of air contaminants.

The applicable Federal and State air

quality regulations and standards aredescribed.

The effects of these regulations andstandards on a developing oil shale in-dustry are analyzed.




q The air pollution control technologiesthat may be applied to untreated emis-sion streams are described and evalu-ated. The net rates at which pollutantswill be emitted in treated streams are es-timated.

q

Modeling procedures that may be usedto predict and monitor compliance withair quality regulations are discussed.

q Potential problems that commercial-scale operations may encounter in meet-ing standards are identified.

q Key findings are summarized.q Policy options are discussed.

Pollutant Generation

Oil shale mining and processing will pro-duce atmospheric emissions including those

pollutants for which NAAQS have been es-tablished: sulfur dioxide (SO2), particulate,carbon monoxide (CO), ozone (0 S), lead, andnitrogen oxides (NOX); as well as variousother currently unregulated pollutants, suchas silica, sulfur compounds, metals, carbondioxide (CO2), ammonia (NH3), trace organics,and trace elements. The following discussionexamines the types of pollutants generated byeach unit operation. Where data are avail-able, the rates at which these contaminantswill be produced by different oil shale facil-ities are estimated.

Unit Operations and Pollut ants

Mining can be carried out either using un-derground (room and pillar) or surface (openpit) methods. The sequential steps in room-and-pillar mining are drilling, blasting, muck-ing (collection of the blasted shale), primarycrushing, and conveying the reduced shale tothe surface for retorting. Potentially hazard-ous substances (silica, salts, mercury, lead)may be released during blasting. Methanemay be released from underground gas de-

posits, and CO, NOX, and hydrocarbons (HC)may be emitted by incomplete combustion of the fuel oil used both for blasting and in mo-bile equipment. In addition, particulate canbe emitted as a result of blasting, raw shalehandling and disposal, and activities at the

minesite that produce fugitive dust (particu-late matter discharged to the atmosphere inan unconfined flow stream).

Atmospheric emissions are expected to bemuch larger in open pit than in room-and-pillar mining because of the significantly

larger quantities of solids that must be han-dled on the surface. The mine dust problemwill be further aggravated by road dust fromtransportation of overburden, and wind-blown dust from all operations.

Storage, transport, and crushing of oilshale result in the emission of particulate,CO, NOX, SO2, and HC from fuel in diesel en-gines, and particulate and silica from fugi-tive dust. Dust is the chief pollutant. Theamount generated depends on the grade of ore, the extent to which its size must be re-

duced for retorting, the number of transferpoints in the transportation system, and thelevel and effectiveness of control strategiesused.

Retorting technologies generate processheat by the combustion of fossil fuels, whichproduces a number of atmospheric emissions.The amount of SO2 emitted depends on thesulfur content of the fuels used in the plantand the extent to which sulfur-containingproduct gases are treated. The volume andconcentration of hydrogen sulfide (H2S), car-bonyl sulfide (COS), and carbon disulfide(CS2) in the offgas streams from retorts de-pend on the type of retorting technology. COShas been detected in the offgases from Law-rence Livermore Laboratory’s simulated MISretorts and trace quantities of COS and CS2

have been reported in the offgases from theOccidental MIS process under certain oper-ating conditions. It is not known whether theretort offgases from the Paraho, Union “B,”TOSCO II, or Superior processes contain COSor CS2.

The major source of NOX emissions is the

combustion of fuel in boilers, air compres-sors, and diesel equipment. The specific lev-els depend on the combustor design, the ex-tent of onsite fuel use, and the nitrogen con-tent of the fuels used to produce process heator steam. Most of the fuels consumed in oil






produced by a commercial-size oil shale facil-ity. The only field measurements that havebeen made to date have been for the small-scale, short-term pilot-plant or semiworksoperations of Colony Development, Paraho,and Occidental Oil Shale.4 These facilities do

not simulate normal operating conditions in afull-size facility, and the measurements thathave been made have been mostly of the regu-lated pollutants. Only a few of the nonregu-lated pollutants such as trace elements havebeen measured, and those measurementsthat have been reported show considerablevariation. Pollution production estimatesmust therefore be confined to regulated pol-lutants and must strongly rely on theoreticalcalculations.

The quantities of pollutants produced in anindustrial facility can be estimated by apply-

ing pollutant generation factors to the massflows of material through the plant. The pro-cedure used for the calculation, although anapproximation, gives estimates of the prob-lem’s scope. Generation factors obtainedfrom the literature were applied to the massbalances published for Colony’s proposedTOSCO II retorting plant on Parachute Creek,for Rio Blanco’s combination of MIS and AGRprocessing on tract C-a, and for the Occiden-tal MIS operation on tract C-b. All flows werescaled to a uniform production level of 50,000bbl/d of shale oil syncrude. The results are

summarized in tables 34 through 36. Note

that the tables show levels of pollutant gener-ation, not pollutant release.

Of the three designs —Colony, Rio Blanco,and Occidental—Colony produces the largestamount of particulate. This plan uses boththe most underground mining and TOSCO II

AGR, which requires a fine shale feed andproduces a very finely divided shale. Thisretorting method is also responsible for Col-ony’s exceptionally high production of HC. Inthe TOSCO II retorting system, vaporizedshale oil and gases evolved during pyrolysisare stripped of high molecular weight HC in acondenser, and then burned to reheat theheat carrier balls. Because combustion is in-complete, lighter weight HC are entrained inthe offgas stream from the ball heater.

In generating steam for power, the Occi-dental design in which large quantities of low-Btu gas are burned produces the mostNO X emissions. Rio Blanco, which plans toburn coke from the upgrading units, producesless NOX but more particulate. Colony’s on-site pollutant production in this step will benegligible because it plans to purchase mostof its electricity from offsite powerplants.

The emission of SO2, produced in the NH3

and sulfur recovery processes, is about thesame for all three designs. Although both Col-ony’s and Rio Blanco’s CO emissions are high-er than Occidental’s, the differences are not

significant.

Table 34.–Pollutants Generated by the Colony Development Project a (pounds per hour)b

Operation Particulate so, NO, HC c o

Mining . . . . . . . . . . . . . . . . 1,480 0 250 50 440Shale preparation. . . . . . . . . . . 15,940 0 0 0 0

Retorting c. . . . . . . . . . . . . . . . . . . . . . . 11,440 150 1,430 480 60Spent shale treatment and disposal . . . . . . . 1,350 0 130 10 0Upgrading. . . . . . . . . . . . . . . . . . . trace 10 20 10 traceAmmonia and sulfur recovery d. . . . . ., 0 32,200 0 0 0Product storage . . . . . . . . . . . . . . . . . . . . . 0 0 0 150 0

Steam and power. . . . . . . . . . . . . . . . . . – — — — —

Hydrogen production . . . . . . . . . . . . . . . . . 10 30 80 trace 10

Total .. . . . . . . . . . . . . . . , . . . . . 30,220 32,390 1,910 700 510c3Tafj~ shows the ItIVtIt Of pOllUlafll generation, not pollufanf releaseb Roo m .an d .pi llar mlnlng, TOSCO II retorting, scaled 1050,000 bbl/d Of shale oll syncrude productioncFlgures do not include components of the product gas and VaPOr streamalso, equivalent of H*S m retort 9as stream

SOURCE T C Borer and J W Hand, /derr//hcal/on and Proposed CorJlro/ 01 A/r Po//ufartfs from O/l Sha/e Operations, prepared by the Rocky MountainDiwslon, The Pace Company Consultants and Engineers, Inc for OTA, October 1979





.


pollution in order to maintain or improve airquality. The Act is universally applicable, butits provisions are most strongly directed tothose areas having the cleanest air (nondeg-radation areas) and those where air pollutionmay be hazardous to public health (nonattain-ment areas). The major elements of the pro-gram established by the Act are:

q

q

q

q

the establishment of NAAQS for criteriaair pollutants,the submission by each State of a Stateimplementation plan (SIP) to achieve andmaintain Federal air quality standards,the preconstruction review of major newstationary sources, andPSD.

National ambient air quality standards.—Regulation under the Act focuses on six cri-teria pollutants: particulate, SO2, CO, NOX,03,, and lead. Two types of ambient air qualitystandards are designated: primary stand-ards, which protect human health; and sec-ondary standards, which safeguard aspectsof public welfare, including plant and animallife, visibility, and buildings. The Act setsforth an exact timetable by which primarystandards are to be met. Secondary stand-ards are to be met on a more flexible sched-ule.

To achieve air quality goals, areas with aircleaner than NAAQS were divided into

Classes I, II, and III. Certain Federal areasthat existed when the Act was passed (e.g.,national parks, wilderness areas) were imme-diately designated as Class I areas where airquality was to remain virtually unchanged.All others were designated as Class II—areasin which some additional air pollution andmoderate industrial growth were allowed. In-dividual States or Indian governing bodiescan redesignate some Class II areas to ClassIII—areas in which major industrial develop-ment is foreseen and contamination of the airup to one-half the level of the secondary

standards would be permitted. The States orIndians can also redesignate Class II areas asClass 1. Either type of redesignation is subjectto hearings and consultations with the man-

agers of affected Federal lands (and States inthe case of Indian action).

The classification of an area with respectto the ambient air quality has important con-sequences. The Act divided the Nation into247 air quality control regions (AQCRs) so

that pollution control programs could be lo-cally managed. Compliance with an NAAQSis generally determined on an AQCR basis,but EPA allows smaller area designations forsome pollutants, if that is more suitable forcontrolling pollution.

These AQCR designations are highly signif-icant. Regions that are found by EPA to be innonattainment status—areas where air pol-lution presents a danger to public health—are subject to a particular set of restrictionsunder the Act. On the other hand, nondegra-dation regions—where air is cleaner than thestandards—are subject to a different set of regulations, which are intended for “preven-tion of significant deterioration. ” Regardlessof an area’s classification, almost every newmajor source of pollution is required toundergo a preconstruction review.

State implementation plan.—Each Statemust submit an implementation plan for com-plying with primary and secondary stand-ards. A State can decide how much to reduceexisting pollution to allow for new industryand development. State plans must also in-

clude an enforceable permit program for reg-ulating construction or operation of any newmajor stationary source in nonattainmentareas, or significant modification to an exist-ing facility. New processing plants and powerstations must also satisfy emission standardsset forth in the SIP.

Preconstruction review of major new sta-tionary sources. —Under the SIP, each newconstruction project is subjected to five typesof preconstruction review. The objective of the review process is to determine:

q

compliance with NAAQS and State AirQuality Standards (AQS);q compliance with any applicable NSPS;

suitability for a nonattainment area;




q

q

The

suitability for a nondegradation area.(PSD regulations, including the use of BACT and PSD increments* will apply);andvisibility.

major elements of these preconstruction

review procedures are:q Review for compliance with NAAQS.

The applicant must submit plans andspecifications for review that show:methods of operation, quantity andsource of material processed, use anddistribution of processed material, andpoints of emission and types and quanti-ties of contaminants emitted; a descrip-tion of the pollution control devices to beused; an evaluation of effects on ambientair quality and an indication of compli-

ance with PSD restrictions; and plansfor emission reduction during a pollutionalert. A permit will not be given if it isshown that the source will interfere withthe maintenance of any ambient airquality standard or will violate any Stateair quality regulation.

Review for compliance with NSPS. TheAct directed EPA to set national stand-ards for fossil fuel powerplants, refin-eries, and certain other large industrialfacilities. If NSPS have been establishedfor the new source, it must be shown

that the facility will not interfere withthe attainment or maintenance of anystandard and that BACT will be used forreducing pollution.

q Review in nonattainment areas. In non-attainment areas, a new facility may bebuilt only if: by the time operations com-mence total emissions from it, and othernew and existing sources, will be lessthan the maximum allowed under SIPS;the source complies with the more strin-gent of either emission limitations re-quired by the State or achieved in prac-

tice by such a source; and the owner oroperator demonstrates that all other ma-

*In part BAC’I’ is required 10 assure that no single facilitywili consume the entire PSf3 increment.

q

jor stationary sources owned or oper-ated by him in the State comply withemission limitations.

Review in nondegradation areas. Thistype of review, which concerns PSD, isdiscussed below.

The prevention of significant deteriora-tion.—All SIPS must specify emission limita-tions and other standards to prevent signifi-cant air quality deterioration in each regionthat cannot be classified for particulate orSO 2, or has air quality better than primary orsecondary NAAQS for other pollutants, orcannot be classified with regard to primarystandards because of insufficient informa-tion.

Under these PSD standards, maximum al-lowable increases in concentration of SO 2

and particulate are specified for each areaclass. For the other criteria pollutants, max-imum allowable concentrations for a speci-fied period of exposure must not exceed therespective primary or secondary NAAQS,whichever is stricter.

A State can redesignate a Class II or IIIarea with respect to PSD only if it follows cer-tain procedures. These include an assess-ment of the impacts of the redesignation, pub-

lic notice and hearings of such a redesigna-tion, and approval by EPA.

If a facility’s construction began after Jan-uary 1, 1975, a special preconstruction re-view must be undertaken if it is located in anondegradation area. To obtain a permit forsuch a facility, an applicant must demon-strate that it will not cause air pollution in ex-cess of NAAQS or PSD standards more thanonce per year in any AQCR. BACT must beused for all pollutants regulated by the Act,

and the effects of the emissions from the fa-cility on the ambient air quality in the areasof interest must be predicted. The air qualityimpacts that could be caused by any growthassociated with the facility must also be ana-lyzed.

63-898 0 - 80 - 18




Implications of the Clean Air Act for


The following provisions of the Act haveparticular significance for oil shale develop-ment:

q compliance with NAAQS and State AQS;q maintenance of air quality, especially

visibility, in adjacent Class I areas (e.g.,national parks);

q compliance with PSD increments;q compliance with NSPS; andq the application of BACT.

National Ambient Air Quality Stand-ards.—Ambient air quality standards pro-mulgated by individual States cannot be lessstringent than the national standards. Thus,the States set the controlling standards if

there is an approved SIP. Utah’s standardsare identical to the national standards, whileColorado and Wyoming have set more strin-gent standards for a number of the criteriapollutants. Table 37 shows both the nationalstandards (the same for Utah), and Colo-

rado’s and Wyoming’s standards. In additionto the standards shown for Wyoming, theState has also promulgated regulations tolimit ambient concentrations of H2S, hydro-gen fluoride, and other pollutants. The stand-ards are more relevant to large coal-fired

powerplants than they are to oil shale proc-essing.

Since the national standards are primarilydirected to urban areas, they should not seri-ously restrict oil shale development in thenear future. The annual-average pollutionlevels allowed by ambient standards aremuch higher than the values normally meas-ured in the oil shale development area. How-ever, the short-term standards for particu-late and HC are occasionally exceeded bynatural emissions such as windblown dust

and HC aerosols produced by revegetation.Such naturally caused infractions of NAAQScould have restricted regional development.They actually did affect oil shale developmentschedules on the four lease tractsColorado and Utah. According to

located inthe provi-

table 37.–The Federal and State Ambient Air Quality Standards and Prevention of Significant DeteriorationStandards That Influence Oil Shale Development (concentrations in micrograms per cubic meter)

Prevention of significantAmbient air quality standards deterioration standards

Federal (primary) Federal (secondary) Federal

Pollutant human health public welfare Wyominga Colorado a Utah a (Class 1) (Class II)so,Annual arithmetic mean, . .2 4 - h o u r m a x i m u m . . .3-hour maximum . . . . . . .

ParticulatesAnnual geometric mean. . . .24-hour maximum . . .

/VOX (as NO,)Annual arithmetic mean. . . . .

Oxidants (as O,)l-hour ., ., ., ... . .

co8 - h o u r m a x i m u ml-hour maximum . . . . .

Lead Q u a r t e r l y .

Nonmethane hydrocarbons 3-hour maximum (6-9 am). .

80 365

None

NoneNone

1,300

60260

1,300

80365700

80 365

None

2 5

25

2091

512

75260

60 150

60150

45150

75260

510

1937

100 100 100 100 100 None None

240 240 160 160 240 None None

10,00040,000

10,00040,000

10,00040,000

10,00040,000

10,00040,000

NoneNone

NoneNone

1,5 1.5 1,5 1.5 1 5 None None

160 b 160 b 160 b 160 b 160 b None None

astate amblen( alr ~uallly qandards are ,de”tl~al to the Federal prlrnary standards unless prlfllecl lrl llallcs The s!ncter standard IS the Conlro[llrlg standardbNot a standard, a guide 10 show achievement of o] standardcAllowable Incremental change m ambient Coflcefltratlon

SOURCE Olf{ce of Technology Assessment










are about 80-percent efficient for particleslarger than about 5 microns, * but less so forsmaller ones. Adding a wetting agent reducesthe surface tension and improves the wetting,spreading, and penetrating characteristics of the water, increasing efficiency to 90 to 98

percent. Chemical binders, such as latex orbitumastics, can also be added. They aid inparticle agglomeration and also increase theefficiency of removal. Water sprays, with orwithout chemical additives, are potentiallyapplicable to raw and spent shale storageand disposal, to crushing and screening, tomining and blasting, and to surface trans-portation. They could also control traffic dustfrom temporary roads, Larger, more heavilytraveled roads would probably need to bepaved.

Cyclones.—Cyclone separators remove

dust by means of centrifugal force. Single cy-clones remove about 90 percent of the largerparticles, but less than 50 percent of thosesmaller than about 10 microns. Their removalefficiencies could be increased by using sec-ond-stage cleaning in scrubbers, filters, orprecipitators. Cyclones will be used largely toclean retort gases, and possibly for primarydust control in crushers and enclosed convey-ors.

Scrubbers.— Wet scrubbers use water toremove dust entrained in gas streams. Many

different types of devices are available, in-cluding spray chambers, wet cyclones, me-chanical scrubbers, orifice scrubbers, ven-turi scrubbers, and packed towers. High-en-ergy venturi scrubbers are probably the onlytype that have sufficiently high removal effi-ciencies to satisfy emissions standards. Effi-ciencies between 93.6 and 99.8 percent havebeen achieved for particles smaller than 5microns, but these efficiencies entail highpressure losses and constant gas flow rates.Scrubbers require considerably more energythan baghouse filters or electrostatic precipi-

tators. Scrubbers for particulate removal will

*A micron is one-millionth of a meter. Removal efficienciesfor different particle sizes are important because effects onrespiration and visibility vary with the particle size.

probably be used for gas streams from re-torts and solid heaters.

Baghouse filters.—Fabric filters are gen-erally used where higher removal efficiencyis required for particles smaller than about

10 microns. A large number of bag-shaped fil-ters would be needed to clean large gas flows.In general, all of the filters would be enclosedin the same structure, called a “baghouse,”and would share input and output gas mani-folds. As a gas stream passes through thebaghouse, dust is removed by one or more of the following physical phenomena: inter-section, impingement, diffusion, gravitationalsettling, or electrostatic attraction. The ini-tial filtration creates a layer of dust on thebag fabric. This layer is primarily responsiblefor this method’s high removal efficiency; the

filter cloth serves mainly as a support struc-ture. The operation is very similar to that of ahousehold vacuum cleaner.

The efficiency of a baghouse filter dependson the particle size distribution, the particledensity and chemistry, and moisture. Undermost conditions a properly designed and op-erated baghouse will achieve a removal effi-ciency of at least 99 percent for particles assmall as 1 micron. Baghouse filters are likelyto be used for dust removal from crushers,screens, transfer points, and storage bins.

Electrostatic precipitators.—In electro-static precipitators, an electrical charge is in-duced on the surface of a dust particle andthe particle is captured on a screen havingelements with the opposite charge. Dry pre-cipitators have been used for many years;wet precipitators and charged droplet scrub-bers have been developed more recently. Alltypes are in common use in the electricalpower generating industry, in cement andsteel plants, and in many other industries.Precipitators have removal efficiencies of upto 99.9 percent, require little maintenance,can handle large flow rates, and have low en-ergy requirements. They might be used in sev-eral oil shale operations, including mine ven-tilation and the second-stage cleaning of dust-



Ch. 8–Environmental Considerations . 271

laden streams from crushers and conveyors.A wet precipitator was used at the Parahodemonstration plant for the combined remov-al of shale oil vapors and particulate fromthe retort offgas. One is being used in thePetrosix plant in Brazil for the same purpose.

HYDROGEN SULFIDE CONTROLThe systems for removing H2S that are like-

ly to be used for oil shale operations can gen-erally remove at least 98 percent of this pol-lutant. They will probably be applied to gasstreams from retorting and upgrading opera-tions.

Stretford Process. —In this process, thegas stream is scrubbed in an absorptiontower with a solution containing sodium car-bonate, sodium metavanadate, and anthra-quinone disulfonic acid (ADA). Reduction of

the metavanadate with H2S in solution causessulfur to precipitate. The metavanadate is re-generated by oxidation with the ADA, and thereduced ADA is then regenerated by beingoxidized in an air stream. The process wasdeveloped for coal- gas treatment, but it hasbeen used for many other purposes in a num-ber of plants, especially oil refineries, in theUnited States and Europe.

Any COS and CS2 that may also be in thegas stream would not be removed in this proc-ess and their presence would interfere with

H2S removal. Therefore, before H2S removalthe gas stream would need to be pretreated toremove these compounds.

Selexol and other physical absorptionprocesses. —In these processes, H2S is dis-solved in a solvent and subsequently recov-ered. The solvent is recycled. The earliestprocess, a simple water wash, was inefficientbecause H2S is not very soluble in water.Modern processes use solvents in which it ismore readily dissolved.

Absorption processes are usually used for

treating high-pressure gases and for reducingthe concentrations of H 2S and other sulfurcompounds to extremely low levels. Theseprocesses involve the selective absorption of H2S from gases containing CO2. This producesan H2S-rich stream that can be processed in a

Claus plant (see below). Absorption processescan also remove sulfur compounds, such asCOS, CS2, mercaptans, and thiophenes, whichcannot be processed in a Stretford unit. Be-cause of its low cost and simplicity, the Selex-01 process is a good candidate for use in oil

shale plants.Claus process. —The Claus process, which

is perhaps the oldest and best known methodfor recovering sulfur from streams that con-tain both H2S and SO2, has several variations.With a feed stream containing only H2S, therequired S02 is obtained by oxidizing part of the H2S to S02 by burning it in air, and thenmixing the combustion products with the feedstream. The S0 2 and H2S are then reactedwith each other in a series of converters toproduce elemental sulfur, which is removedby condensation. The feed stream must havea relatively high concentration of sulfur com-pounds in order to achieve a high conversionefficiency with reasonable equipment size.

This process has problems with both main-tenance and downtime, thus backup units areoften needed. Problems arise from sulfur con-densation in the supply and product pipe-lines. The procedures for startup and shut-down are time-consuming, and moisture andCO 2 in the feed gas are particularly trouble-some.

The tail or treated gas from a Claus plantstill contains fairly sizable concentrations of H 2S and S02. It can be recirculated, mixedwith a large volume of stack gas and re-leased, or treated in other systems. In oilshale plants, it is likely that the Claus planteffluent would require further treatment be-fore being released. Processes developed spe-cifically for this purpose include the SCOT,Beavon, and IFP techniques described below,

SCOT (Shell Claus Offgas Treating) proc-ess. In this process, the offgas is heated

with a reducing gas such as hydrogen,and the mixture is passed through a co-bait-molybdate catalyst bed where allthe sulfur compounds are reduced toH2S. The gas is then sent through an ab-sorber where the H2S is dissolved and




concentrated. The concentrated H2S isliberated from the absorbing medium byheating and is returned to the Clausplant.

The SCOT process is adversely af-fected by high concentrations of CO2.

Since gaseous emissions from oil shaleprocessing are expected to be rich inCO2, higher rates of recycling, more com-plete fuel combustion, and perhapssteam injection to dissolve the CO2 maybe necessary.

q Beavon process. In this process, the tailgas from a Claus plant is mixed with hotcombustion gases and passed through acatalyst where all the sulfur compoundsare converted to H2S. The H2S-rich gas iscooled by a slightly alkaline buffer solu-tion and then treated in a Stretford unit.

The Beavon process is also adversely af-fected by high CO2 concentrations in thefeed stream. Its use in oil shale plantswould require adaptations similar tothose needed for the SCOT process.

q IFP [Institute Francais du Petrok] proc-ess. The basic reaction in this process isthe same as in the Claus process exceptthat it takes place in a liquid rather thana gaseous phase. The liquid is a polyalky-lene glycol with a 5-percent concentra-tion of a glycol ester catalyst. Both H2Sand S02 are very soluble in this liquid,

and efficient conversion to sulfur re-sults. The most important operating vari-able is the H2S to S02 ratio which mustbe at least 2. The process is flexible andcan accommodate wide changes in con-taminant concentrations while maintain-ing constant conversion rates. Also, be-cause the gases can be treated at highertemperatures than in other processes,heat losses are reduced.

SULFUR DIOXIDE CONTROL

The amount of SO2 that will have to be re-

moved will depend on the prior degree of gastreatment and the type of fuel used in proc-essing. Most oil shale plants will probably usedesulfurized fuel for heating, processing, andpower generation. Where large amounts of S O2 are emitted, such as in the tail gas of a

Claus plant, its control may be required. Thefollowing technologies could be used for thispurpose.

q

q

q

Wellman-Lord process. This is a versa-tile process, widely used by many differ-ent industries, and should be adaptable

to the oil shale industry. Colony plans touse it for a commercial-scale above--ground retorting plant.

This process relies on the reaction of SO2 with sodium sulfate to produce sodi-um bisulfite. The bisulfite solution isnext heated in an evaporator. This re-verses the reaction, liberating a concen-trated stream of SO2. The SO2 can thenbe converted to either elemental sulfuror sulfuric acid. The regenerated sodiumsulfate produced when the reaction isreversed by heating, is dissolved and re-

cycled. The current version of this proc-ess is considered to be a second-genera-tion technique for SO2 removal. Previousproblems with sludge production andscaling have been reduced.Double alkali process. Double alkalitechnology resembles conventional wetstack-gas scrubbing methods but avoidsmost of their problems by using two alka-line solutions, sodium hydroxide and so-dium sulfite, to convert SO2 to sodium bi-sulfite. The spent scrubber solution is re-generated by using lime or limestone toconvert the bisulfite to sodium hydroxideand a precipitate that is a mixture of cal-cium sulfite and calcium sulfate. Theprecipitate sludge, which contains thecaptured S0 2, can be disposed of inponds.

Performance of the system is well-established, and over 99-percent S02 re-moval has been achieved with S02 con-centrations in the treated flue gas of lessthan 10 p/m. Potential environmentalproblems are associated with waste dis-

posal because the solid residue containssoluble alkaline sodium salts that couldpollute surface and ground water in thevicinity of disposal sites.Nahcolite ore process. Nahcolite is amineral that contains 70 to 90 percent




sodium bicarbonate. It is found in the oilshale deposits in the central Piceancebasin of Colorado. When crushed andplaced in contact with hot flue gases in abaghouse, nahcolite converts SO2 to drysodium sulfate. Typically, 20 percent of the required nahcolite would be used toprecoat the filter bags in the baghouse,and the remainder would be sprayed di-rectly into the flue gas stream. The sodi-um sulfate produced and any unreactednahcolite would be sent to disposal,Pilot-plant experiments have shown thatS0 2 removal efficiencies are between 50to 80 percent depending on flow ratesthrough the baghouse and the ratio of nahcolite to SO2.

NITROGEN OXIDES CONTROL

Nitrogen oxides are produced in the com-

bustion of fuels, NOX control can be ap-proached in two ways: by adjusting combus-tion conditions to minimize NOX production,or by cleaning the NOX that is produced fromthe stack gases, At present oil shale devel-opers plan to design combustor conditions forlow NOX production. Gas cleaning systemscould be added in the future, if the needarises for further NOX control, However, withproper design and maintenance of combus-tion equipment, external control systems willprobably not be needed in order to complywith existing regulations.

HYDROCARBON AND CARBON MONOXIDE CONTROLS

The emission of HC and CO will be causedby the incomplete combustion of the fuel forthe boilers, furnaces, heaters, and dieselequipment used in oil shale plants, The con-trol of external combustion sources such asboilers is primarily through proper design,operation, and maintenance. Well-designedunits emit negligible amounts of CO and onlysmall amounts of HC. Instrumentation isneeded to assure proper operating condi-tions, and comprehensive maintenance pro-

grams will be needed to keep emission levelsfrom rising due to fouling and soot buildup.The proper maintenance of diesel and otherinternal combustion engines can similarlykeep HC and CO emissions very low. Treating

the flue gas from combustion sources for par-ticulate or SO2 will also reduce HC and COemissions. With proper maintenance, it willprobably be unnecessary to further reduceemissions from these sources.

Other emissions of HC will be caused by

preheating raw shale prior to retorting andby storing crude shale oil and refined prod-ucts. Incineration is probably the only realis-tic way to control them. Storage tank emis-sions can be minimized by using floating-roof tanks, which can accommodate higher vaporpressures than cone-roof tanks without theneed for venting.

OTHER EMISSIONS CONTROLS

Emission control by direct flame incinera-tion systems (also called thermal combustion)is widely used to reduce the amounts of HC

vapors, aerosols, and particulate in gasstreams. These systems are also used to re-move odors and reduce the opacity of plumesfrom ovens, dryers, stills, cookers, and refuseburners. The operation consists of ductingthe process exhaust gases to a combustionchamber where direct-fired burners burn thegases to their respective oxides. A well-designed plant flare system is a good exampleof direct incineration control.

Catalytic incineration is also used for thesame purpose. The chief difference is that the

combustion chamber is filled with a catalyst.On contact with the catalyst, certain com-ponents of the process gases are oxidized.The use of a catalyst allows more completecombustion at lower temperatures, thus re-ducing fuel consumption and allowing the useof less expensive furnace construction. How-ever, catalysts are generally selective andmay not destroy as many contaminants as di-rect flame incineration. In addition, becauseof the potential for catalyst fouling and poi-soning, gas streams may need to be cleaned of smoke, particulate, heavy metals, and other

catalyst poisons,Condensation is usually combined with

other air pollution control systems to reducethe total pollutant load on more expensivecontrol equipment. When used alone, conden-




sation often requires costly refrigeration toachieve the low temperatures needed for ade-quate control.

Several methods can be used for coolingthe gas streams. In surface condensers, thecoolant does not contact the vapor or conden-

sate; condensation occurs on a wall separat-ing the coolant and the vapor. Most surfacecondensers are common shell-and-tube heatexchangers. The coolant normally flowsthrough the tubes; the vapor condenses on thecool outside tube surface as a film and isdrained away to storage or disposal.

Contact condensers usually cool the vaporby spraying a liquid, at ambient temperatureor slightly cooler, directly into the gas stream.They also act as scrubbers in removing va-pors that do not normally condense. The use

of quench water as the cooling medium re-sults in a waste stream that must be con-tained and treated before discharge.

The equipment used for contact condensa-tion includes simple spray towers, high-ve-locity jets, and barometric condensers. Con-tact condensers are, in general, less expen-sive, more flexible, and more efficient in re-moving organic vapors than surface condens-ers. On the other hand, surface condensersrecover marketable condensate and presentno waste disposal problem. Surface condens-ers require more auxiliary equipment and

need more maintenance.Condensers have been widely used (usually

with additional equipment) in controlling or-ganic emissions from petroleum refining, pe-trochemical manufacturing, drycleaning, de-creasing, and tar dipping. Refrigerated con-densation processes are being used for the re-covery of gasoline vapors at bulk terminalsand service stations.

The Technologi cal Readiness of Control Methods

As indicated, there are a wide variety of control technologies that could be applied tothe emissions streams from oil shale proc-esses. The selection of suitable technologiesfor a given facility would be based on a num-ber of factors. The degree of control needed

for each regulated pollutant would depend onthe size of the facility; its location; the natureof the oil shale deposit; the mining, process-ing, and refining methods; the desired mix of products and byproducts; the characteristicsof untreated emissions streams; and the emis-

sions levels allowed by applicable environ-mental standards. The specific control equip-ment selected would be influenced by all of these factors, plus such considerations as theproximity to water and electrical power, theavailability of land for solid waste disposal,the labor and material requirements formaintenance, the ease of operation, the dem-onstrated reliability in similar industrial situ-ations, the availability of equipment, the ex-perience of the developer, and the cost.

An important consideration is the relativetechnological readiness of each control meth-

od being considered. A developer needs confi-dence that a method can be directly trans-ferred to oil shale operations from other in-dustries without undergoing extensive R&D.All of the techniques described previouslyhave been applied to industrial processessimilar to those encountered in mining, retort-ing, and upgrading of oil shale and its prod-ucts. However, there are three characteris-tics of the potential oil shale industry that re-quire extrapolating these technologies be-yond the present levels of knowledge: thescale of oil shale operations, the physicalcharacteristics of the shale, and the nature of the emissions streams.

Scale of operation. —The proposed miningoperations are among the largest ever con-ceived and as such will require extraordinaryefforts to control air pollution. For example,underground mining on tracts U-a and U-bwould have mine ventilation rates as high as12 million ft3 /min. Cleaning this volume of gascould be both difficult and expensive. Thelarge ventilation volume is required by mininghealth and safety regulations and cannot be

reduced.Open pit mines could be much larger than

underground mines. Problems with fugitivedust would be increased by the larger quan-tities of solids that must be handled on the



Ch 8–Environmental Considerations q 275

surface. Much relevant experience has beengained through the extraction and processingof other minerals such as coal, copper, ura-nium, and bauxite. The simpler control tech-niques (such as water sprays) have beenthoroughly demonstrated. However, the po-

tential size of oil shale mines may createproblems for the more complex, collection-type control systems that have worked well insmaller mines. The cost of air pollution con-trol for deeply buried oil shale deposits is notknown. The amount of overburden that mustbe removed, and for which pollution controlwould be needed may be prohibitively large.

Physical characteristics of the shale.—Oilshale is a fine sedimentary material heldtogether by its kerogen content. When proc-essed in certain retorts (such as TOSCO II orLurgi-Ruhrgas) the shale can disintegrate intofine particles that are more difficult to collectand control than other mineral dusts. Otherretorts (such as Union “B” or Paraho) willproduce a coarser product with fewer prob-lems from dust. It is uncertain whether elec-trostatic precipitators will perform effective-ly in commercial-scale operations becausenot much is known about the electrical prop-erties of raw and spent shale particulate.

Characteristics of emissions streams.—Todate, the streams from small-scale versions of discrete subprocesses (such as pilot retorts)

have been used to obtain preliminary evalua-tions of the efficiencies of pollution controltechnologies. It is not known whether thesestreams accurately represent the streamsthat would have to be controlled in an inte-grated commercial-scale plant. For example,it is not certain that the pollutants generatedby commercial-scale retorting, when combin-ed with the pollutant streams from other sub-processes (such as upgrading), could be ade-quately controlled with conventional meth-ods. Also, the effect of volatilized traceelements on the catalysts used in the SCOT

and Beavon tail-gas cleaning systems and inincinerators has not been determined, Theconcentration of some of the pollutants gener-ated by certain processes may be too low forefficient control. For example, it is unknown

whether conventional H2S control methodswill work well with the low H2S concentra-tions in the offgas from MIS retorting. Remov-al efficiencies that are too low could haveconflicted with EPA’s previous BACT stand-ards for oil shale facilities, which required

99-percent total sulfur recovery, no matterhow small the concentration of sulfur com-pounds in the raw gas stream.

The technological readiness of the majorcontrol techniques is summarized in table 41.The readiness of dust control methods isshown to range from low to high, with a highconfidence in water sprays, cyclones, andscrubbers and a medium confidence in bag-houses and a low to medium confidence inelectrostatic precipitators. Similar rangesare shown for the other control techniques,The readiness of the nahcolite S0

2

removalprocess is rated as low because only a fewtest results have been published for its per-formance with oil shale streams. Also, thetechnology is relatively new and has not beenused extensively in other industries.

The Claus H2S process is regarded highlybecause it has a long record of successfulapplication worldwide. The SCOT andBeavon tail-gas cleaning systems have a highrating because they are generally used inconjunction with the well-established Claussystems. The fact that the feed to these sys-tems would already have been treated in aClaus unit removes some of the doubts aboutthe effects on their removal efficiencies of theunique characteristics of oil shale emissionsstreams. Combustion methods and evapora-tion controls to reduce HC and CO emissionsalso have a high rating because they shouldnot be sensitive to any great extent to thescale of operation or stream characteristics.Fugitive HC and CO emissions are much moredifficult to control.

The other control techniques are given

medium ratings either because they have notbeen tested with oil shale streams for sus-tained periods or because the effects on theirremoval efficiencies of the projected char-acteristics of streams from commercial-scale




Table 41 .–Technological Readiness of Air Pollution Control Techniques

Pollutant and control system Readiness rating Comments

Dust Water sprays High Effective and in general use with wetting agents added as needed, Low cost, Increased water needs,Road paving High Also reduces vehicle maintenance,Cyclone separators High Low cost, Effective only for large particles.Scrubbers High Low capital cost and maintenance requirements, High energy and water requirements needed for

high removal efficiency.Bag house filters Medium High efficiency, Moderate energy and maintenance requirements, Low cost. Not suitable for high-

temperature gas streams. Requires more area than other systems, Waste-disposal experiencelacking

Electrostatic precipitators Low to medium Efficiency sensitive to dust Ioading, temperature, and particle resistivity. Good removal efficiency,Low operating costs and maintenance. Good for large gas volumes. High capital cost.

H t S Stretford process

Selexol, purisol, rectisol,istosoliam, fluor solvent, andother physical systemsClaus process

Tail gas cleaning SCOT process

Beavon processIFP process

Medium Extensive application in refining industry, Good for large volumes of dilute gases, Being tested forMIS gases,

Medium Being tested for coal gasification streams, No experience with oil shale emissions,

High Extensive experience in several industries. Needs concentrated feed streams. High maintenanceneeds and downtime,

High Long experience with Claus plants.High Long experience with Claus plants,Medium Used with Claus plants that produce elemental sulfur May be applicable directly to retort gases,

so,Wellman-Lord process Medium Thirty Installations worldwide High capital cost. High energy requirements,Double alkali process Medium Used successfully in Japan since 1973. Waste disposal could be costly,Nahcolite ore process Low Limited but successful testing to date,

NOx

Combustion control High Can easily be designed into new plants Low capital and operating cost,Diesel exhaust control Medium Recirculation of exhaust gases can lead to maintenance problems.

—

HC and CO Combustion control High Use of excess air easily accomplished,Evaporation control High Use of floating roof tanks is very effective but Increases capital costs,Control of fugitive emissions Low Control is difficult because of the large number of dispersed sources

SOURCE T C Borer and J W Hand /derr//f/ca/lon and ProDosed Conlro/ of A/r Pllufarrk kern 0// .Sha/e OoeraOons DreDared bv the Rockv Moufltaln Ow!slon The Pace ComDanv COOSUltafltS andEngineers Inc for OTA, October 1979

plants are still not known. In the case of theStretford process, work is underway by Occi-dental Oil Shale which, if successful, couldsignificantly improve its readiness.

In general, the control technologies appearto be fairly well-developed, and should beadaptable to the first generation of oil shaleplants. Full evaluation will not be possible un-til the methods have been tested in commer-cial-scale operations for sustained periods.

Costs of Air Pollution Control

The costs of controlling pollutants froman oil shale plant would be particularly sensi-tive to the lifetime of a project, the plant de-

sign, the scale of operation, and the extent of emission removal required by environmentalstandards, Small-size, temporary plants suchas modular demonstration facilities wouldprobably be designed for minimum front-endcosts; therefore, control systems with smallcapital requirements would be used ratherthan those with low operating costs. The lat-ter systems would be economically attractiveover the 20-year operating life of a commer-cial plant but not over the 2- to 5-year lifetime

of a modular plant. The design of the plantwould also have an effect on the costs of con-trol. Systems to recover the byproducts sulfurand NH3 could be included in an integratedfacility, for example, not specifically for airpollution reduction but to increase plant reve-



Ch 8–Environmental Considerations . 277

nues. Additional control technologies wouldbe needed to satisfy environmental stand-ards, but overall control costs would be con-siderably less than if byproducts were not re-covered,

Another example of the effect of facility

design on control costs is whether the proc-esses of upgrading and refining are included.If so, other subprocesses such as retortingcould take advantage of the efficient controlsystems that are an integral part of any mod-ern refinery. If refining was not done onsite,control systems would still have to be pro-vided for the other operations. The same de-gree of removal efficiency could be achievedbut with higher costs.

The relation of the cost of pollutant controlto the degree of removal is usually not linear,

i.e., the costs generally are considerablyhigher to increase a pollutant’s removal from98 to 99 percent than from 90 to 95 percent.Consequently, most control costs will bestrongly influenced by the degree of removalrequired by environmental standards. Higherremovals will be more costly for individualplants but would allow the region to accom-modate a larger industry within the frame-work of the air quality regulations.

The Denver Research Institute (DRI) re-cently estimated the costs of environmentalcontrol in the three projects for which pollut-

ant generation wasthrough 36,5 DRI’sterns were basedplans but in somecover technologies

summarized in tables 34hypothetical control sys-primarily on developercases were modified tohaving higher projected —

removal efficiencies. Two regulatory sce-narios were considered. Under the “lessstrict” scenario for particulate control in theColony plant, for example, it was assumedthat particulate reductions from pointsources would average 98.5 percent, and thatfor nonpoint sources of fugitive dust reduc-tions of 92.2 percent would be required. Theaverage particulate reduction for the plantwas assumed to be 98.3 percent, Under the“more strict” scenario, overall particulatereductions of 99.5 percent were assumed forpoint and nonpoint sources. With some differ-ences, similar control scenarios were as-

sumed for other regulated pollutants, and forthe other two oil shale projects. Results of DRI’s analysis for the “more strict” case areshown in table 42.

As can be seen, the control costs for in-dividual contaminants vary widely from proj-ect to project. In each project, however, thelargest capital and operating costs are forS O2 and particulate removal. Capital costsfor SO2 control equipment, for example, areover $25 million for the tract C-a and C-b proj-ects, which strongly rely on MIS retorting andwhich will have to clean large quantities of

Table 42.–Costs of Air Pollut ion Control (thousand dollars)

Colony projecta Tract C-b projectb Tract C-a prolect’

Overall Capital Operating Overall Capital Op e r a t i n g - O v e r a l l Capital Operatingreduction cost cost reduction cost cost reduction cost cost

Fugitive dust 92 2% $ 1,460 $ 564 98 4% $ 1,460 $ 577 Highd $ 1,460 $ 543Part icula tes 99. 5 % 2 9 , 4 0 0 6 , 4 9 9 8 0 . 2 % 5 , 7 9 2 1,530 99.6% 34,340 8,499s o , 99,0% 9,910 7,240 99.0% 26,210 11,187 99.0% 29,800 12,844N O , (e) (f) (f) (e) 12,866 3,882 (e) 12,866 3,882HC and” CO, 50.5% f 7,785 3,766 56.5% 240 50 89.0% 878 182

To ta l . $58,555 $18,069 $46,588 $17,226 $79,344 $25,950

Cost per bbl of daily capacity $ 1,246 $ 817 $ 979Cost per bbl of oil produced – $ 1 ,1 6 — $ 0 .9 1 — $ 0 .9 7

a47 000 bbl/d of shale 011 syncrude b57 000 bbl/d of crude shale 011 c81 000 bb[/d Of crude shale 01[dR oads are paved Water sprays used for disposal areas eMaxlmum reduction achievable through adlustmenl of combustion conditionsfLCIW reducflofl requlremen!s because of low-temperature retorflng and use Of Iow-flltrogen fuel In combustors

SOURCE Oata adapted from Denver Research lnshfule Pred/cfed Cosk of Enwomnerrfa/ CcJmro/s for A Commerc/a/ 01/ Sha/e /rrdus(ry Vo/urne /–Arr Engmeenrrg Arra/ys/s prepared for the Department ofEnergy under confract No EP 78-S-02-5107 July 1979 pp 407-414



—— ——-


dilute retort gas. A much lower capital invest-ment (about $10 million) is needed for the Col-ony project because the TOSCO II retorts pro-duce a much smaller volume of retort gas.

According to DRI’s analysis, the overallcosts of air pollution control range from $0.91

(C-b project) to $1.16 (Colony project) per bblof oil produced These costs would have beenconsidered very high in the early 1970’s whenoil was selling for about $4/bbl. They are lesssignificant under present conditions with oilprices exceeding $30/bbl.

Pollutant Emissions

Controlled emissions rates are summarizedin tables 43 through 45 for three oil shaleprojects for which pollutant generation rateswere calculated previously. It was assumed

that the raw emissions streams from the unit

operations in each facility would be treatedin control systems similar to those for whichDRI prepared cost estimates. In the Colonyproject, for example, it was assumed thatdusty air streams from crushers and ore stor-age areas would be processed in baghouses,as would the flue gas from the retort preheat-er. Flue gases from the retort and the spentshale moisturizer would be treated in a hotprecipitator. A Stretford unit would be usedfor removal of sulfur compounds. NOX andCO emissions would be reduced by combus-tion controls on all burners, and HC emissionswould be reduced with floating-roof storagetanks and a thermal oxidizer flare system.

Table 46 summarizes the rates of pollutantemissions both for the three projects, and formodular demonstration projects proposed byUnion Oil Co. and Superior Oil. The Union and

Superior results are presented for their ac-

Table 43.–Pollutants Emitted by the Colony Development Project (pounds per hour) a

Operation Particulate so, NOx HC c o

Mining ., ., ., . . ., ., ... . .Shale preparation, ., .,Retorting, . . ., .Spent shale treatment and disposal” ~ ~ ~ . ~ ~Upgrading. ., . . ., ., . . ., .A m m o n i a a n d s u l f u r r e c o v e r y . . .P r o d u c t s t o r a g eSteam and power. ~ ~ ~ ~ ~ ~ ~ ~ . . .Hydrogen production .,

Total ., ., ...

10 0 2 5 0b 50 b

440 b

60 0 0 0 0120 140 1,430 270 5040 0 130 b 10 b

otrace 10 20 10 trace

o 100 0 0 00 0 0 20 00 trace 20 trace trace

10 30 80 trace 10

240 280 1,930 360 500 +

aR~~m.and.pillar Mlnlng TIJSCO II retorftng scaled to 50000 bbl/d of shale oll syncrude productionbThese emissions are not included 10 Colony PSO permlf aPPllcatlOn

SOURCE T C Borer and J W Hand /defrf/f/ca(/on and Proposed Con/ro/ of AM Pollufarrfs From 0(/ Shale Operations prepared by the Rocky MountainOwlsion, The Pace Company Consultants and Eng[neers Inc for OTA October 1979

Table 44.–Pollutants Emitted by the Rio Blanco Project on Tract C-a (pounds per hour)a

Operation Particulate so , NOx HC c oMining ., . ., 20 0 340 6 435Shale preparation. ., . ., . . . 26 0 0 0 0R e t o r t i n g . . , 92 52 320 98 0Spent shale treatment and disposal’ ~ ~ ~ ~ ~ 32 0 0 0 0 Upgrading. ., ., ., ., ., 6 0 6 13 0 Ammonia and sulfur recovery, ... ., . 0 0 0 0 0Product storage. ., 0 0 0 105 0

Steam and power ., ., . . . ~ 210 250 1,220 13 0Hydrogen production ., ., – — — — —

Total ., ., ., . . ., ., ... - 386 302 1,886 235 435

auflde@~OundMlnlng M [s and Tosco IIabovegfound retorting scaled 1050,000bblld of shale oil Swcrude woduchofl

SOURCE T C Borer and J W Hand. /derrf/l/ca(/orr and %oposed Confro/ O( AM f’o//ufanfs from 0// S/ra/e Opera(/errs, prepared by the Rocky MountainOwlslon The Pace Company Consultants and Engineers Inc for OTA October 1979




Table 45.–Pollutants Emitted by the Occidental Operation on Tract C-b (pounds per hour) a

Operation Particulate so, NOx HC c o

Mining 20 0 300 10 180R a w s h a l e d i s p o s a l 80 0 100 10 0R e t o r t i n g , 10 0 0 0 0Upgrading 10 10 80 trace 10Ammonia and sulfur recovery. 0 240 0 0 0P r o d u c t s t o r a g e 0 0 0 80 0

S t e a m a n d p o w e r 20 trace 2,800 b o 0H y d r o g e n p r o d u c t i o n 80 20 220 20 20

Total 220 270 3,500 120 210

a Underground mlnlng MIS retofilng scaled 1050000 bbl d of shale 011 syncrude productionbAssumes gas turbines for power generation

SOURCE T C Borer and J W Hand (der?hflcallon and Proposed Cofl(ro/ of AU Po//uranrs from 0// Shale Operal/ons prepared by the Rocky MountainDlvlslon The Pace Company Consultants and Engineers lnc for OTA October 1979

Table 46.–A Summary of Emissions Rates From Five Proposed Oil Shale Projects

Pollutant emissions, lb/hr

Project and retortinq technology Shale oil production P a r t i c u l a t e s S O2 NOx HC co

Colony TOSCO I I aboveground retort 50,000 bbl/d syncrude 240 280 1,930 360 500Rio Blanco MIS plus Lurgi-Ruhrgas aboveground retort 50,000 bbl/d syncrude 386 302 1,886 235 435Occidental MIS 50,000 bbl/d syncrude 220 270 3,500 120 210Superior Superior retort plus nahcoli te and alumina recovery 11,500 bbl/d crude 75 347 172 20 47Union Union Oil ‘ ‘B’ aboveground retort 9,000 bbl/d crude 35 81 100 59 43

SOURCE T C Borer and J W Hand /deflflf/cat/on and ProDosed ConVo/ ot AK Pol/u(an(s From 0// Sha/e Operations prepared by the Rocky Mounlain Olvlslon The pace Company Consultants and Enavneers Inc for OTA October 1979

tual design conditions, which provide aboutone-fifth of the shale oil produced by theother projects. Because emissions rates are

not always directly related to plant capacity,the much smaller modular projects are notexpected to have equivalently lower rates of emissions. In fact, S0 2 release from theSuperior project (11,500 bbl/d) is expected tobe significantly higher than from the three50,000-bbl/d projects. In part, the high rate of Superior’s emissions is related to the natureof its process, which includes unique sub-processes for the recovery of nahcolite andalumina. They also arise from the scale of operation, which does not encourage the useof large-scale, costly controls that would be

cost-effective for the larger operations at Col-ony and on the lease tracts.

EPA has granted PSD permits for the Col-ony and Union projects at the levels of opera-tion listed above. Permits have also been

granted for modular-scale operations on C-a(1,000 bbl/d) and C-b (5,000 bbl/d). EPA there-fore expects the projected emissions rates at

these production levels to comply with all ap-plicable Federal and State emissions regula-tions. However, it should be noted that theevaluation of the environmental impacts of oilshale development also requires a considera-tion of the effects of the emitted pollutants onambient air quality, which is protected byNAAQS and PSD limitations. Without large-scale operating facilities, the effects of emis-sions on air quality can only be predicted byusing mathematical models.

Dispersion ModelingThe Nature of Dispersion Models

The Clean Air Act, through the regulationspromulgated for attainment of NAAQS and




PSD standards, requires the use of mathe-matical models to relate the emissions from asource and the resulting incremental impactthat the source causes on a point some dis-tance away. At present, models are EPA’stool for enforcing the provisions of the Actand are the only means for predicting long-range impacts of oil shale emissions on am-bient air quality in the oil shale area and inneighboring regions.

Air quality models are mathematical de-scriptions of the physical and chemical proc-esses of transport, diffusion, and transforma-tion that affect pollutants emitted into the at-mosphere. In these models, specified emis-sions rates and atmospheric parameters areused as input data, and the effects on ground-level pollutant concentration and visibility of plume rise, dispersion, chemical reaction,

and deposition are simulated. Some modelsare designed to simulate small-scale airflowpatterns over complex terrain within a fewmiles of the pollution source. These near-source models can predict the effects of oilshale emissions in the immediate vicinity of the plant. They are used during preconstruc-tion review to indicate the facility’s expectedcompliance with PSD regulations.

Other models simulate broader airflowbehavior over distances of hundreds of miles.These regional dispersion models could be

used to simulate the effects on a large area of an entire industry, including numerous indi-vidual plants. Regional-scale models can beused to predict impacts on air quality in near-by Class I areas. The time scale of the inputdata and the output predictions should be ap-propriate to the size of the region being simu-lated. Small increments can be used for near-source modeling; increments of several daysfor regional dispersion models.

Most models incorporate a series of com-putational modules, as shown in figure 60. Amajor difference between the models lies in

the manner in which the input data are ma-nipulated and in the application of the com-putational modules. Usually, not all of themodules are used in any given model. Near-source models need to simulate complex air

flow near prominent terrain features, but canusually ignore chemical reaction, aerosolcoagulation, deposition, and visibility effects,which generally become most significant overlarger distances and longer time periods. Incontrast, regional models can sometimes ig-nore terrain features, but must consider long-range atmospheric conditions and their ef-fects on chemical reaction, coagulation, depo-sition, and visibility.

A key feature that must be considered inevaluating the use of any model to estimatecompliance with NAAQS and PSD regula-tions is its ability to simulate worst case con-ditions, which are those meteorological condi-tions that lead to the highest ground-level con-centrations. These conditions vary dependingon the location of the emitting facility, its con-figuration, and the nature of the surrounding

terrain. Some candidate worst case condi-tions for the oil shale region include:

q

q

q

q

q

It

several days of atmospheric stagnationduring which emissions would accumu-late under an inversion in a valley;a looping stack-gas plume that wouldbring maximum pollutant concentrationsdirectly to ground level;a plume trapped in a stable atmosphericlayer and transported essentially intactto nearby high terrain;fumigation, when a plume is transportedfrom a stable layer at medium heights tothe ground level. (Fumigation conditionsnormally persist for less than an hour.They are usually the worst case foremissions released from stacks); andmoderate wind conditions in which astable polluted layer spreads uniformlyand causes visibility reduction over alarge area. (This is usually the worstcase for emissions released near groundlevel.)

is reasonable to assume that some worst

case conditions (e. g., several days of atmos-pheric stagnation) could occur several timesa year, while others might occur only a fewtimes over the lifetime of an oil shale projectand might not be detected during a 1- to 3-






cell and with the reactions that occur withinthe cell. If the cell size or iteration incrementis too large, important details such as rapiddeposition in transition areas between low-lands and mountains may be missed. Thesedeficiencies can be compensated for by using

time trajectory models, numerical fluid flowmodels, box models, or sector averagemodels.

Problems Wit h Dispersion Modeli ng in

the Oil Shale Region

Modeling of oil shale facilities presents anumber of problems because of the topogra-phy and meteorology of the oil shale region,the chemistry of oil shale emissions, and theunknown quantities of emissions expectedfrom commercial-size facilities. Dispersion

models developed to date have been primarilyfor flat terrain. The terrain of the oil shaleregion is very complex, including many val-leys and canyons. Furthermore, some devel-opers have proposed siting their plants in themiddle of a cliff face or near a canyon rim.Simulating this geometry presents uniquemodeling problems. In addition, the chemistryof oil shale emissions is quite different fromthat of powerplants in urban areas and maylead to increased oxidant formation through

photochemical reactions between HC andNOX. * Thus, the conventional set of reactionsused to model urban photochemistry wouldhave to be augmented to accurately simulatethe oil shale situation.

Also, oil shale operations emit much fugi-

tive dust. Proper modeling of these emissionsmust consider the role of wind in creating theemissions as well as its role in dispersingthem. In the mountainous areas downwind of oil shale plants, precipitation may cause thewet deposition of the oil shale emission, thuslessening the regional transport of visibilityimpacts but increasing impacts on ground-level ecological systems.

Another problem in developing accuratedispersion predictions for oil shale facilitiesis the fact that the input data on emissionscan only be estimated, since no commercial-ize plants have yet been built. This problemis exemplified in table 47, which presents asummary of emissions data used in severalearly modeling studies. These studies variedwidely with respect to the quantities of theemissions that were assumed for varioustypes of retorting technologies and the levels

*Photochemical reactions are induced in the atmosphere byu] traviolet radiation from the Sun.

Table 47.–A Comparison of Atmospheric Emissions Used in Modeling Studies

Total emissions (lb/hr)

Production capacityStudy and site Retort (bbl/day) Study date so* NOx HC Particulates

BattelleColorado TOSCO II 50,000 1973 143 732 300 1,285

Federal Energy AdministrationColorado TOSCO II 50,000 1974 1,332 1,464 317 741

Stanford Research InstituteColorado and Utah TOSCO II 100.000 1975 3,111 4,078 600 650

ColonyColorado TOSCO II 63,000 1975 282 1,806 324 829

317 1,746 304 842Tract C-b

Colorado TOSCO II 45,000 1976 267 1,634 262 776353 1,894 313 968

Tract C-aColorado TOSCO II 6,000 1976 26 322 112 148

56,000 265 994 185 573Tracts U-a and U-b

Utah Paraho 10,000 1976 8.4 108 0.88 6850,000 148 1,369 55 452

SOURCE Adapled from the Enwronmenlal Prolectlon Agency A f’relvmrrary Assessmertrof fhe Env/ronrnerUa/ hnpacfs from (7// .Sha/e L7eve/oprnenfs July 1977 p 110




of production, Even if the estimates for theTOSCO II operations are scaled to the sameproduction capacity, they vary by as much asan order of magnitude. Much of this discrep-ancy is associated with assumptions by ana-lysts about environmental-control technol-

ogies and their efficiencies, Although individ-ual modeling runs provide some insight intosite-specific air quality effects for a givenretort capacity under specific meteorologicalconditions, substantial variations in the in-put-data assumptions prohibit comparing dif-ferent retorts, levels of development, andplant locations,

The Appli cat ion of Dispersion Models t o

Oil Shale Facilities

The application of flat-terrain models to

the oil shale region requires many adapta-tions in order to provide rough estimates of the impacts of a particular facility on am-bient air quality. Near-source models havebeen used to estimate the effects of emissionsfrom single proposed facilities. Such effectsmust be modeled to qualify for a PSD permitfrom EPA. A preliminary study has also beenundertaken by EPA to estimate the regionaleffects of several oil shale plants. Since onlyestimates are available for the levels of emis-sions from commercial-size facilities, model-ing results can only be considered approx-

ima te,One example of the use of near-source

models was a study performed for Colony De-velopment by Battelle Northwest Laborato-ries. Colony was considering two plant loca-tions: one in the valley of Parachute Creek,the other on an adjacent site atop Roan Pla-teau. A model predicted that NOX concentra-tions near the valley site would exceed thenational standards; SO 2 and particulatewould barely meet the standards. The modelpredicted that the corresponding pollutionlevels near the plateau site would be an orderof magnitude lower. Because of this predic-tion, Colony selected the plateau location. 67

Another example is the work undertakenfor Federal lease tract C-a. Models were runfor widely different operating conditions, in-

cluding completely different retorting tech-nologies and levels of operations. As noted involume II, the tract C-a lessees originally con-templated open pit mining and abovegroundretorting in a combination of TOSCO II anddirectly heated retorts (like the Paraho kiln).

In phase I, a single TOSCO II retort would beused to produce from 4,500 to 9,000 bbl/d of shale oil. In phase II, several TOSCO II anddirectly heated retorts would be used to pro-duce up to 55,800 bbl/d. The lessees con-ducted modeling studies that estimated theair quality impacts of each developmentphase. Both long- and short-term effects werestudied with an EPA Gaussian Valley model,modified to account for the mixing-layer ef-fects of rough terrain and for inversion epi-sodes. Results were reported in the DDP inMarch 1976.’

The lessees subsequently adopted a newplan that was also phased but which involvedunderground mining and MIS processing. Thelessees prepared a revised DDP and per-formed new modeling studies. Two mathe-matical models were used: long-term (annual)effects were studied with an EPA model modi-fied for high terrain and atmospheric stabil-ity; shorter term (3 to 24 hours) effects werestudied with a modified Gaussian model. Asin the earlier modeling studies, meteorologi-cal measurements made on the tract were

used as input data to the models. Worst casepredictions for both phases were reported inthe revised DDP in May 1977.

9

The results of both sets of studies are re-ported in table 48. Predictions are presentedfor both offtract ambient air quality and forthe incremental quality degradation. Alsoshown are the relevant NAAQS (either pri-mary or secondary, depending on which ismore stringent), the Federal PSD incrementlimitations, and the corresponding Coloradoambient air standards. All standards shownare those that currently apply to the oil shaleregion.

The models predicted that both phases of both plans should be in compliance with ap-plicable standards, However, the off tractconcentration of nonmethane HC was pre-



.


Table 48.–Modeling Results for Federal Oil Shale Lease Tract C-a

Revised DDP (May 1977) Original DDP(March 1976)

National standards Colorado standards Ofttract ambient air Of ft ra ct i nc re me nt Otftract ambient air Ofttract increment

Averag- PSO increment Ambient PSD Increment Phase lb

Phase IIc

Phase lb Phase II

cPhase l

d

Phase IIe Phase I

d

Phase IIe

Pollutant ing time NAAQSa

Class II Air Category II MIS MIS/TOSCO II MIS MIS/TOSCO II TOSCO II Aboveground TOSCO II Aboveground

S o2 Annual 80 20 80 20 8 4 8 3 2 2 7 10 11

24-hour

1

3652

365 91 102 8 5 3 23 28

3-hour 512

141,300 700

19

512 352 25 30 20

NO X

91

Annual 100 None 100

103 82 94

None 8 13 6Particulates Annual

1160

16 10 1419 45

819 9 12 0 3 3 16 22

24-hour 150 37 150 37 1010

12 1 3 34 41 22 29

NonmethaneH C

f

3-hour 160 None 160 None 65 90 0.3 25 221

Lead Quarterly

12915 None

156 6415 None — —

o , — —

l-hour

—

240

—

None

— —

160 None — — — — — — — —

bcapacll 4 0 0 0 bbl/d (MIS)aslrlcter Ot primary and secondary standards\

ccapaclty 57000 bbl/d (MIS) + 19.000 (TOSCO 11) dcapaclty 9 0 0 0 bbl/d (TOSCO l{)ecapaclly 55800 bbl/d (TOSCO II and. e 9 ~ paraho) Not a standard a guide to show achievement of the O, standard

SOURCE Data adapted from onglnal and revised detaded development plan for tract C.a See refs 8-9

dieted to exceed the Federal and State guide-lines during Phase I of the old plan. It shouldalso be noted that in the old plan the off tractincrement for HC is only slightly less than the3-hour average guideline. In the new plan,however, offsite concentrations and incre-ments for both phases are well within compli-ance.

With respect to the effect of scale of opera-tion, the table indicates that, in general, theimpact of the smaller scale phases of bothplans are nearly equal to those of the corre-sponding larger scale phases. This is ex-plained by the lessees’ intent to use the firstphase of each plan to obtain reliable data onemissions levels and dispersion characteris-

tics, and then to use these data to design con-trol technologies for the subsequent commer-cial phases. Also, final commitment to thecommercial operations was not to be madeuntil technical and economic feasibility stud-ies, based on operating data obtained in theearly phases, could be completed. To avoidunnecessary capital commitment in the initialphases, the first facilities were designed forminimum investment requirements.

It is difficult to interpret the technology-related effects of old and new plans for tract

C-a because the levels of operation are dif-ferent, and different models were used tosimulate air quality impacts. However, aqualitative comparison is possible. The tableindicates that the original concept (open pitmining and aboveground retorting) wouldhave caused higher ambient levels of SO2,

particulate, and nonmethane HC and lowerlevels of NOX than the revised concept (un-derground mining, MIS, and limited above--ground retorting). Although the revised facil-ity is to have 36 percent more shale oil capac-ity, ambient air impacts and PSD incrementsare generally lower.

With respect to regional modeling, EPA hasused a modified Gaussian model to predictthe effects on air quality at the Flat TopsWilderness Area of oil shale operations at theColony site (50,000 bbl/d), on tract C-a (1,000bbl/d), on tract C-b (5,000 bbl/d), and at theUnion site (9,000 bbl/d). * The total shale oilproduction was about 65,000 bbl/d, of whichabout 77 percent was assumed to come from

Colony’s TOSCO II retorts. The model waslimited in that only one source could be mod-eled at a time, so four runs were needed tomodel the industry. In each run it was as-sumed that the wind was blowing from thesource directly to Flat Tops. The cumulativeimpacts of the industry were estimated byadding the increments from each source. Re-sults indicated that about 20 percent of thePSD increment for particulate would be con-sumed, and about one-third of the S02 incre-ment. Simple linear scaling would indicatethat the industry would be limited to about

217,OOO bbl/d by the PSD restrictions on S0 2,and to about 325,000 bbl/d by the particulatePSD.

*Flat Tops Wilderness Area is approximately 65 miles fromtract C-a, and 50 miles from tract C-b and the proposed Colonyand Union projects.




Such scaling is highly inaccurate for anumber of reasons. First, Gaussian modelstend to overestimate ground-level concentra-tions of SO2, because they do not allow for for-mation of sulfate particles from S0 2 and theirsubsequent deposition. Second, it is impossi-ble for the wind to be blowing from four di-rections at the same time. Third, the pro-

jected SO2 and particulate concentrations atFlat Tops were affected strongly by the Col-ony project, which is predicted to emit moreS O2 and particulate than the technologiesproposed by tract C-a, tract C-b, and Union. Itwas EPA’s opinion that a better estimatewould be that as much as 400,000 bbl/d couldbe accommodated in the Piceance basin bythe PSD standards for Flat Tops. 10 EPA’sanalysis did not consider any project in theUinta basin, the eastern edge of which is

about 95 miles from Flat Tops. Therefore,there are no estimates available of the addi-tional capacity that could be installed in Utahwithout exceeding the PSD restrictions atFlat Tops. The proposed Dinosaur NationalMonument, about 50 miles north of tracts U-aand U-b, could also limit operations in Utah if it is designated as a Class I area. *

Evaluation of Modeling Efforts

Table 49 lists the models used by oil shaledevelopers to support PSD applications fortheir projects. EPA has accepted the resultsof these studies as evidence of expected com-pliance with air quality regulations, and PSDpermits have been granted. Note that, with

*A Department of the Interior task force in September 1979recommended Iha t the Dinosaur Nntional N!onument be desig-na led as a Class I n rcn.

the exception of the Colony project, onlysmall-scale plants were modeled. Some devel-opers, such as Rio Blanco and the tract C-blessees, have also modeled the effects of com-mercial-scale operations at the same loca-tions. However, EPA has not yet evaluated

the results of these studies for adequacyunder the PSD-permitting process.

The widespread reliance on the GaussianValley model should also be noted. All of thedevelopers relied on this model for simulationof near-source effects. PSD permits weregranted for the projects because the modelsrepresented the state-of-the-art of near-source dispersion, and because most of theprojects were of relatively small scale. Themodels used are deficient in many respects.For example, the Gaussian Valley model can

be used for estimating pollutant dispersion instable atmospheric conditions in complex ter-rain, However, as described previously, ittends to overestimate SO2 concentrations andcannot handle most worst-case conditions.Also, Gaussian models when applied to com-plex terrain introduce error by a factor of 5to 10 when computing concentrations on high-terrain features. This factor of error in themodel’s capability, coupled with a 2 to 5 errorfactor in estimating emission concentration,increases the level of uncertainty in deter-mining compliance with air quality stand-

ards. In a recent workshop conducted by theNational Commission on Air Quality, it wasrecommended that the Valley model be usedonly for screening purposes in complex ter-rain situations, and that it not be used for de-termination of compliance with NAAQS orPSD standards. ’

Table 49.–Models Used in Support of PSD Applications for Oil Shale Projects —

Maximum shaleProject Retorting technology 011 production Model used

Colony Development Operation TOSCO II 46,000 bbl/d Gaussian Valley model, modified for rough terrain, to studyeffects of long-distance transport. Box model for effects of

trapping inversions near source.Union 011 Co Long Ridge Union ‘‘B’ 9,000 bbl/d Modified Gaussian Valley model.

RIO Blanco 011 Shale (tract C-a) Modular MIS 1,000 bbl/d Modified Gaussian Valley modelC-b Shale 011 Venture (tract C-b) Modular MIS 5,000 bbl/d Modified Gaussian Valley modelOccidental 011 Shale Inc Logan Wash Modular MIS 5,000 bbl/d Modified Gaussian Valley model

SOURCE Ofllce of Technology Assessment




Other models that have been used to pre-dict emissions from proposed oil shale facil-ities include the CRSTER and the AQPUF2. *The CRSTER model is generally used by EPAto simulate effects of emissions from tallstacks in complex terrain. It tends to overesti-

mate pollutant concentrations where plumesare intercepted by terrain features higherthan the plume rise height, ” The CRSTERmodel used by Rio Blanco in their DDP couldnot handle fugitive dust emissions, gravita-tional settling, separated stacks, chemicalreactions in the plume, some high-terrainfeatures, and a change of wind direction withheight. All of these variables are important toaccurate prediction of some near-source ef-fects. The AQPUF2 model also used by RioBlanco in their DDP for short-term studieswas better able to simulate plume behavior in

complex wind fields and to compare the ef-fects of emitting stacks a significant distanceapart from each other. The effect of windspeed on the generation of fugitive emissionswas not simulated in any of the models used.

Research and Development Needs

The problems of modeling pollutant disper-sion in the oil shale area are also encounteredin other regions with complex terrain, suchas the Ohio River Valley and the Four Cornersarea of Colorado, Utah, Arizona, and NewMexico. The Dispersion Modeling Panel at arecent workshop conducted by the NationalCommission on Air Quality recommended thefollowing research on the modeling of atmos-pheric dispersion in such areas:]]

. Regional models should be developedthat can simulate effects at long dis-tances from the sources, For SO2, thesedistances could approach 600 miles. Up-wind pollutant concentrations should bedetermined and used as input data to themodels.

q The regional models should allow the use

of a fine-resolution grid spacing near thepollution sources, and a coarse spacingat greater distances. Given this capabil-

*CRSrI’ER is a Gaussian model developed by EPA, AQPUF2 isa segmented-plume Gaussian rough-terrain model,

q

q

ity, near-source effects and more distantimpacts could be modeled simultane-ously.Chemical reaction and deposition mod-ules should be included wherever themodeled region is large enough for these

effects to be significant.A simulation of photochemical oxidantformation and of the conversion of SO2 tosulfates should be combined in the samemodel.

More specific research needs can be iden-tified for the oil shale region. The models usedto date have given only rough estimates of theimpacts of oil shale development on ambientair quality. Because the models are only ap-proximations, they cannot provide definitiveanswers to crucial air quality questions. Nocommercial-scale oil shale facilities exist that

could supply the data for verification. Fur-thermore, essential information is lacking onmeteorological conditions in locations otherthan in the immediate vicinities of some of theproposed development sites.

The models themselves need to be im-proved for the oil shale region. Near-sourcemodels need to be modified to better simulatechemical reaction, coagulation, deposition,and visibility effects of oil shale plumes dur-ing stagnation periods. Models are also need-ed that can simulate the effects that several

facilities would have on air quality in a smallarea having complex terrain. This capabilitywill be critical in evaluating the effects of second-generation oil shale plants. A goodsite for analysis would be the southeasterncorner of the Piceance basin. PSD permitshave already been issued for three projects inthis area, which contains much of the private-ly owned oil shale land in Colorado. More ap-plications may be submitted in the near fu-ture. Models are also needed that can simu-late the effects of wind rate on generationand transportation of fugitive dust from stor-

age and disposal areas.Many of these improvements also are

needed by regional dispersion models. In par-ticular, existing models should be modified tosimulate long-range visibility effects of oil




shale plumes. This capability will be requiredto respond to the forthcoming visibility reg-ulations. Visibility models exist that deal withthe formation of aerosols and particulatefrom SO2 and NOX, but these models are ap-plicable to examinations of urban smog andpowerplant emissions. Greater emphasiswould have to be given to HC reactions inorder to modify these models to simulate oilshale plume effects.

The need to model the cumulative impactson regional air quality is particularly impor-tant. Each scenario should include specifica-tions for the locations of oil shale plants, acharacterization of their pollution controltechnologies, and estimates of their emissionsrates. The region’s meteorology would have tobe accurately characterized over periods of several days, or for at least the time required

for the full impact of the combined emissionsto be experienced in nearby Class I areas.Computational modules would have to be in-cluded for the effects of emissions, disper-sion, aerosol dynamics, chemical reaction,deposition, and visibility, The model alsoshould handle differences between daytimeand nighttime mixing heights and atmos-pheric chemistry, In addition, the regionalmodels would have to be validated, eitherthrough tracer studies in the oil shale regionitself or by examining the ability of the modelto simulate the behavior of emissions from a

group of coal-fired powerplants or smelters.One type of tracer study that could be used

to validate the models is the release of sulfurhexafluoride, or a similar tracer compound,followed by the monitoring of tracer concen-trations at numerous ground-level locations.A dense pattern of monitoring stations wouldbe needed to locate maximum concentrations,because the widely varying wind patterns inthe oil shale region prevent any attempt tocharacterize total wind fields by interpolat-ing data from a few stations. Baseline meas-

urements of pollutant concentrations and vis-ibility parameters upwind from the sourcewould be required to accurately simulate thechemical interactions of the tracer plumes.

The state-of-the-art of near-source and re-gional dispersion modeling is being advancedby R&D programs under the sponsorship of EPA and other organizations. The followingprojects are of particular importance to eval-uating the air quality impacts of oil shaleplants.

EPA is funding a project with DRI tocombine information on oil shale emis-sions and meteorology, and to use region-al models to assess air impacts from sev-eral commercial-size oil shale facilities.The model will also handle emissionsfrom other sources such as traffic, pow-erplants, and other mineral-processingplants.EPA is funding a project with the Univer-sity of Minnesota to develop a simplemodel of aerosol dynamics, including

conversion of gases to aerosols, that maybe of use in evaluating the effects of thechemistry of oil shale plumes on visibili-ty.Los Alamos Scientific Laboratory isfunding a project with the John Muir In-stitute for Environmental Studies to de-velop a multiple-source visibility modelthat could be applied to regional disper-sion studies in the oil shale area. In arelated study, the University of Wyomingand Los Alamos are funding a project todevelop a regional haze model whichmight be useful in assessing visibility ef-fects of oil shale plumes.EPA is funding an in-house project at Re-search Triangle Park to develop a multi-ple-layer atmospheric model that is de-signed to explain regional O3 patterns inthe Northeast. It may also be useful forexplaining the high O3 concentrationsencountered in the oil shale area.EPA is funding a project with SystemsApplications, Inc., to model the air quali-ty effects of oil shale industries with

capacities of 400,000 bbl/d (includingtract C-a, tract C-b, Colony, Union, Supe-rior, tract U-a, and tract U-b) and 1 mil-lion bbl/d. The model will handle all




sources simultaneously and will modelvisibility effects. The project is designedas an extension to EPA’s early regionalmodeling exercise. Its major objective isto estimate cumulative impacts on exist-ing and proposed Class I areas such asFlat Tops.

A Summary of Issues and Policy Options

Issues

INADEQUATE INFORMATION

Extensive work has been undertaken in thepublic and private sectors to determine thedegree of pollution control that will have to beused by oil shale facilities to protect air quali-ty. However, no large-scale facilities exist toverify the predictions arising from this work.Furthermore, the dispersion characteristics

of treated emissions streams cannot be accu-rately predicted because modeling and moni-toring methods are not yet adequate. In itspresent state of development, modeling canbe used, but the results must be carefully in-terpreted. Therefore, it is not known what im-pacts oil shale unit operations will have onair quality at various shale oil production lev-els. Specific areas of uncertainty and some

suggested R&D responses are summarized intable 50. Some of the uncertainties, such asdispersion behavior, could be reduced some-what by means of laboratory studies andcomputer simulations; others, such as theperformance characteristics of control tech-nologies, may necessitate full-size facilities

and extended programs under actual operat-ing conditions. It is important that emissionsstudies and monitoring and modeling pro-grams keep pace with oil shale development.

LIMITS ON OIL SHALE DEVELOPMENT

The atmosphere has a finite carrying ca-pacity; that is, it can only disperse limitedquantities of airborne pollutants. The effectof the carrying capacity of air in the oil shaleregion on the long-term development potentialof oil shale resources is unknown. A crude re-gional modeling study undertaken by EPA has

indicated that an industry of 200,000 t o400,000 bbl/d could probably be controlled tomeet PSD regulations in the Piceance basin. Itis unclear whether a larger industry (theorder of 1 million bbl/d) could be establishedin the Piceance and Uinta basins without vio-lating air quality regulations.

Additional questions arise regarding themanner in which PSD increments will be allo-

Performance of controltechnologies

Dispersion behavior

Trace element behavior

Table 50.–Areas of Inadequate Information and Suggested R&D Responses

Area of uncertainty Relevance Research need

Baseline air quality conditions and Inhibits accurate modeling of emis- Regional characterization studies, including measurement of visibility andmeteorological characteristics sions dispersion and deposition concentrations of criteria and noncriteria pollutants and determination of

meteorology, especially with respect to worst case conditions.

Emissions characteristics Prevents evaluation of control effec- Characterization of stream and fugltive emissions, beginning with pilot-planttiveness and cost and reduces studies and continuing with first-generation modules and pioneer commercial-modeling accuracy. size plants. Streams from individual unit operations should be Integrated to

simulate expected commercial conditions.

Inhibits modeling and cost Additional pilot-plant and demonstration-plant programs.estimation.

Inhibits evaluation of near-source and Improvement in modeling and monitoring techniques for complex terrain,regional air quality impacts. including development and validation of near-source and regional dispersion

models Models to be validated for the terrain and meteorology of the 011 shaleregion and for emissions similar to those expected from 011 shale operations.

Inhibits evaluation of the effects of 011 Monitoring of trace element concentrations in process feed streams, treatedshale development on human health, emissions streams, and fugitive emissions. Examination of the effects of

plants, and animals. conventional control technologies on trace elements. Determination of therelationships between trace element concentrations in soils and plants andnutritional problems. Development of indicator species Studies of the synergis-tic effects of trace elements on vegetation

SOURCE Ofl[ce of Technology Assessment




cated to potential oil shale developers. The oilshale region has been designated Class II, butseveral Class I areas exist nearby that couldbe affected by oil shale operations. The lawprohibits any facility to exceed the PSD limi-tation in any area, including the area in

which the facility is to be sited and any adja-cent areas, Thus, oil shale developers willhave to demonstrate that their facilities willsatisfy both Class II PSD standards and ClassI standards.

Under the present regulatory structure,PSD increments are allocated on a first-come,first-serve basis. The first oil shale plants in agiven area could exhaust the entire incre-ments. If this occurs, subsequent developers,who might be delayed by the preliminary sta-tus of their processing technologies, will notbe able to locate in the same area, regardlessof the efficiency of their air quality controlstrategies.

Under the provisions of the Act, new facil-ities can be located in a polluted area if theyare able to offset their emissions by reducingthe emissions of other industrial plants in thesame area. This strategy may be feasible inurban industrialized areas, especially whereexisting facilities are old and do not employstate-of-the-art air pollution control methods.It is not applicable to the oil shale areas atpresent because there are few industrial fa-

cilities against which to offset new emissions.It probably will continue to be inapplicable asthe area industrializes, because any newplants will be built with the best availablecontrol technologies to reduce emissions tominimum levels. A subsequent oil shale devel-oper would thus be forced to improve on thesecontrol methods. It is uncertain whether thiscould be done at reasonable cost.

These constraints could result in each oilshale plant being surrounded by a bufferzone in which no additional industrial activ-

ities (including oil shale development) wouldbe allowed. Without reliable regional airquality modeling studies, it is impossible topredict the width of these buffer zones, How-ever, it is very possible that such zones couldsubstantially reduce the area of a given oil

shale basin that could be developed, and thuslimit the ultimate size of the industry thatcould operate within the basin,

UNDEFINED REGULATIONS

The Clean Air Act stipulates a need to pro-tect visibility in Federal mandatory Class I

areas. While regulations are to be promul-gated by EPA by November 1980, and by theStates by August 1981, uncertainties still ex-ist as to the potential implications for oilshale development in regard to the siting of future oil shale facilities. In addition, EPA ispresently developing incremental PSD stand-ards for HC, CO, O3, NOX, and lead. Oil shalefacilities will have to comply with these newstandards.

Another area of uncertainty concernsemission standards for hazardous air pollut-

ants under section 112 of the Clean Air Act,To date, the emissions that are regulated areasbestos, vinyl chloride, mercury, and berylli-um. Controls have been required for indus-tries that produce these substances at highrates. To date, the oil shale industry has notbeen included under the regulations for thesepollutants because it is expected that theywill be generated at low levels, if at all. How-ever, EPA is in the process of developing haz-ardous emissions standards for POM, arse-nic, and possibly other substances. It does notappear at this time that these substances will

be regulated for oil shale operations, but theregulations could be applied to oil shale if thesubstances are found in the emissionsstreams during future characterization stud-ies. Furthermore, it is also possible that addi-tional regulations could be promulgated forsubstances that have already been detectedin these streams.

It should also be noted that a recent U.S.Circuit Court of Appeals decision in the caseof Alabama Power, et al. v. EPA may result insignificant changes in the PSD regulations.

The definition of baseline conditions, fugitivedust control requirements, and monitoring re-quirements are among the issues on whichthe court has rendered a decision. As a resultof the decision, EPA proposed certain revi-sions to the PSD regulations on September 5,




1979. However, the effect of the court deci-sion and the proposed regulations on the con-ditions for PSD permits for oil shale facilitiesis unclear at this time.

Policy Options

LIMITS ON DEVELOPMENT

Siting constraints will probably not besevere for an oil shale industry of 200,000 to400,000 bbl/d. However, it appears likely thata large industry (the order of 1 million bbl/d)could encounter siting difficulties because of the Class H status of the resource region, thepossibility that the initial facilities will ex-haust the total PSD increments over largeareas, and the existence of Class I areas nearthe region. If this appears to be the case,there are several possible actions that couldbe taken. These are briefly described below.

Retain the current regulatory structure.This option would not alter existing airquality standards and PSD regulationsas promulgated under the Clean Air Act.Under existing law, all oil shale facilitieswould have to undergo a preconstruc-tion review before a PSD permit wouldbe granted. The use of BACT would berequired, and the developer would haveto demonstrate that air quality regula-tions would not be violated either withinthe Class II area of development or in

nearby Class 1 areas. As indicated previ-ously, the current policy of allocatingPSD increments on a first-come, first-serve basis might constrain the commer-cialization of those technologies that arein the early phases of development, andin addition might limit the ultimate sizeof an oil shale industry within the re-source region.Coordinate issuance of PSD permits foroil shale plants. This option would notalter existing PSD regulations as promul-gated under the Clean Air Act. However,

it would change the current approach tothe issuance of PSD permits for oil shaleplants by EPA. Rather than issuing PSDpermits on a first-come, first-serve basis,EPA would encourage coordination with

all prospective oil shale developers priorto their preparation of PSD applications.This effort would seek a coordinatedstrategy for maximizing shale oil produc-tion while maintaining the ambient airquality at regulated levels. Implementa-tion could be constrained by, for exam-ple, antitrust laws.Alter existing regulatory procedure in al-location of PSD increments. Under thisoption, EPA would allocate a portion of the total PSD increment to each firmwhen it applied for a PSD permit. The re-maining portions of each incrementwould be reserved for future industrialgrowth. Although this option wouldallow for a certain level of additionalgrowth, it could impose technical andeconomic burdens on the individual ap-plicants, because each proposed facilitywould be required to maintain loweremission levels than would be the caseunder the existing regulatory structure.Redesignation of the oil shale regionfrom a Class II to a Class III area. Thisoption would lower air quality but wouldallow for more industrial development.The action would be initiated at theState level, with final approval beingnecessary from EPA. The following cri-teria would have to be satisfied:—the Governors of Colorado, Utah, or

Wyoming must specifically approvethe redesignation after consultationwith legislative representatives, andwith final approval of local govern-ment units representing a majority of the residents of the area to be redesig-nated;

—the redesignation must not lead to pol-lution in excess of allowable incre-ments in any other area; and

—other procedural and substantive re-quirements for redesignation underState and Federal law must be satis-fied.While such an option would appear to

allow for about twice as much oil shaledevelopment as is presently possibleunder a Class II area designation, con-




straints would still occur because of thenearby Class I areas.Amend the Clean Air Act. This congres-sional option would exempt the oil Shaleregion from compliance with certainprovisions of the Clean Air Act. Con-

gress might direct EPA and the States inquestion to redesignate the oil shale re-gion from a Class 11 area to a Class 111area, and to exempt the oil shale devel-opers from maintaining the visibility andair quality of nearby Class I areas. Thisoption would remove the major uncer-tainties surrounding the siting of oilshale facilities within the resource re-gion itself, and would remove any sitingbarriers connected with the degradationof nearby Class I areas. Such an optionwould allow development up to the Class

III standards, which permit lower airquality than Class II standards. Thus,this option would allow an industry of upto 800,000 bbl/d to be sited in the Pice-

ance basin and an unknown amount inUtah and Wyoming, but at the cost of in-creased air pollution.

IMPROVE TECHNICAL INFORMATION

Additional analysis is needed of the poten-tial effects of oil shale development on airquality. Such analysis will be useful in identi-fying long-term R&D needs in protecting airquality and in identifying siting problems im-posed by existing air quality regulations andstandards. Some options for improving thequality of technical information might in-clude: the further development of existingR&D programs, the coordination of R&D workby Federal agencies, the redistribution of funds within agencies for air quality re-search, increased appropriations to agencies

to accelerate their air quality studies, and thepassage of new legislation specifically tied tofunding R&D relating to air quality impacts atvarious levels of oil shale development.

Water Quality

Introduction

Development and operation of oil shale fa-cilities could contaminate surface and groundwater from point sources such as cooling wa-ter discharges, nonpoint sources such as run-off and erosion, and accidental dischargessuch as spills from trucks, leaks in pipelines,or the failure of containment structures. Thepollutants could adversely affect aquaticbiota, irrigation, recreation, and drinkingwater. The severity of these impacts will bedetermined by the scale of operation, theprocessing technologies used, and the typesand efficiencies of the pollution controls.

The water systems may be affected duringthe operating lifetime of an oil shale facility,

and such long-term impacts as those from theleaching of disposal piles could continue formany years after operations ceased. Accu-rate prediction of the impacts requires anunderstanding of the characteristics, trans-port routes, and fates of the pollutants that

might be released. Much work has been doneto describe the quantity and quality of sur-face and ground water resources in the oilshale region. However, little is known aboutthe nature and ultimate impacts of the pollut-

ants produced by oil shale processing. For ex-ample, a number of these pollutants may becarcinogenic, mutagenic, and teratogenic . *

Information is not available on the risksposed by these pollutants at the levels likelyto be encountered in the surface and groundwater affected by oil shale development.

In this section:

. The types of wastewaters produced byoil shale operations are characterized.

q Rates for the generation of these con-taminants are estimated.

q Potential impacts of effluent streams onsurface and ground water are identified.

*(krcino~ens cause cancer . Nlutagens cause mut[ltions inoffspring. ‘1’era togens cause fetal defects.




q

q

q

q

q

q

q

The quality of surface and ground waterresources in the oil shale region is exam-ined.The applicable Federal and State waterquality regulations and standards aredescribed.

The effects of these regulations andstandards on a developing oil shale in-dustry are analyzed.The pollution control strategies that maybe applied are described and evaluated.The net rates at which pollutants will beemitted in treated streams are then esti-mated.Procedures for predicting and monitor-ing compliance with water quality regu-lations are discussed.Issues and R&D needs are summarized.Policy options are discussed.

Pollution Generation

The following discussion examines thetypes of effluents generated by various oilshale processes. Where data are available,the rates at which these effluents are pro-

duced by different types of facilities areestimated.

Unit Operations and Effluent Streams

Mining will produce dusty air and gasesthat must be cleaned to protect the miners.Wet scrubbing of this mine ventilation air willproduce wastewater streams that will haveto be treated. If the shale deposits are locatedin ground water aquifers, then mine drainagewater will be produced that must be con-sumed, discharged to a surface stream, or re-

1%0(0 credit OTA staff

Mine dewatering at tract C-a— water quantity has been greater than anticipated at this site




injected into the aquifers. The drainage wa-ters will contain inorganic salts, chloride andfluoride ions, and boron. They should not con-tain significant concentrations of dissolvedgases or organic chemicals, although dis-solved H2S may be found in some locations.

Retorting produces water by combustion of hydrogen, by release of moisture present inthe feed shale, and by chemical decomposi-tion of kerogen. In some aboveground retorts(such as TOSCO 11 and Lurgi-Ruhrgas), thiswater is entrained in the retort’s gas streamand is condensed when the product gas iscooled. This “gas condensate” will be con-taminated with NH3, CO2, H2S, and volatile or-ganics, but will not contain appreciable quan-tities of inorganic salts. In other processes(such as in situ retorting or the Paraho orUnion “B” aboveground retorts) some of the

water may condense within the retort or inthe oil/gas separators. This “retort conden-sate’ will contain H2S, NH3, CO2, and dis-solved organics, plus inorganic salts thathave been leached from the shale in the re-tort, Trace elements and toxic metals couldalso be present.

Upgrading will include several operations:gas recovery, hydrogen generation, gas-oiland naphtha hydrogenation, delayed coking,NH 3 /acid-gas separation, foul-water strip-ping, and sulfur recovery. Gas recovery and

hydrogen generation produce little wastewa-ter. However, hydrotreaters and cokers pro-duce foul condensates that are contaminatedwith dissolved gases and organics. Gases areusually removed within the upgrading unit.Thus, the principal pollutants in the final ef-fluent stream are dissolved organic com-pounds.

Air pollution control.—Dust scrubbers andwater sprays will produce an effluent thatcontains suspended solids and dissolved in-organic salts. Effluent streams from gascleaning devices will also contain solids andsalts as well as HC, H2, NH3, phenols, organicacids and amines, and thiosulfate, and thio-cyanate ions, The principal sources of waste-water will be scrubbers and units for the re-covery of sulfur and NH3.

14 Different devices

produce significantly different quantities of wastewater with different types and concen-trations of contaminants. For example, aClaus/Wellman Lord sulfur recovery systemwould produce a neutralized acidic wastewa-ter;15 a Stretford sulfur absorption unit would

not.Steam generation and water cooling.—

High-quality water must be used to generatesteam for power generation or process needs.Generally, the boiler feedwater must betreated to remove inorganic salts. The treat-ment (usually lime softening or ion exchange)generates liquid wastes. In addition, thewater in a boiler becomes concentrated indissolved materials, and a portion must becontinually replaced with freshwater. Thechemical species in the boiler wastewater(blowdown) will be similar to those in the raw

water, but they will be more concentrated.Wet cooling towers will be used to cool the

water that is used in heat exchangers. Cool-ing towers work by evaporating a portion of the water passing through them. This evap-oration concentrates the chemicals that enterwith the feedwater, just as in a boiler. Thewater that must be removed to control the ac-cumulation of solids (blowdown) will be chem-ically similar to the feedwater but will alsocontain chemicals that are added to controlthe growth of algae in the tower.

Spent shale disposal. -Spent shale fromaboveground retorting will be exposed toleaching by rainfall, snowmelt, or irrigationwater. If wastes are disposed of by backfill-ing mines, they may be leached by groundwater. Leachates from various spent shaleshave been studied by a number of investi-gators. 16 17 Their properties vary widely withthe retorting process but in general they con-tain significant concentrations of total dis-solved solids (TDS), sulfate, carbonate, bicar-bonate, and other inorganic ions, and lesseramounts of trace elements and organic com-pounds. They are alkaline, with pH valuesranging from 8 to 13. Their addition to thenaturally occurring waters in the oil shale re-gion could result in significant water qualitychanges, but the severity of the risk is diffi-




cult to ascertain. For example, one leachatewas tested according to EPA procedures, andthe spent shale could not be classified as ahazardous waste on the basis of its trace ele-ments and toxicity .18 However, some spentshales could be classified as hazardous be-

cause of the presence of organic residues.

19

Leaching of in situ retorts.—In situ retort-ing presents an environmental problem be-cause ground water is found in many of thedeposits to which this process could be ap-plied. The increases in permeability thatwould result from mining, fracturing, and re-torting would facilitate leaching after dewa-tering operations are discontinued. Solublematerials in the spent shale would thus enterthe ground water and would eventually reachsurface streams. Such transport would takelong periods of time. However, if aquifers are

contaminated, cleanup would be virtually im-possible.

Summary of Pollutants Produced by

Major Process Types

Approximate rates of generation of majorpollutants are summarized for four facilitiesin table 51. * Five factors should be kept inmind in reviewing this table:

q

q

q

The rates are for the generation of pol-lutants—not for their release to the en-vironment. The rate of release will be de-termined by the strategies that are usedto remove the contaminants.Retort condensates are not shown forthe AGR processes because it is as-sumed that the retorts will be operatedat temperatures that will avoid conden-sation of water vapors within the retort.This should be achievable with most re-torting systems. However, others (likethe Union “B”) may produce substantialquantities of retort condensate.

No mine drainage water is shown for theaboveground plants because it is as-sumed that they will not be sited inground water areas. This assumption re-

*See app. C for details,

Table 51 .–Generation Rates for Principal Water Pollutants forProduction of 50,000 bbl/d of Shale Oil Syncrude (tons/d)a

Type of retortinq facility

Aboveground Aboveground MIS/direct indirect MIS aboveground

Gas condensates N H3 . 75.6 147 276 189

H 2 S 0.9 2 3 1 5 1.1c o2 136 17.5 541 371BOD : : 19.2 2 8 5 18,5 127

S u b t o t a l 232 63 837 574Retort condensates N H3 (b) (b) 3,5 2.4H 2 S. . . (b) (b) – –c o2 (b) (b) 48.2 33 1BOD ., (b) (b) 10.1 7.3

Subtotal – — 62 43Upgrading condensates N H3 . 134,2 1342 134,2 134,2H 2 S 58.8 58.8 58.8 58.8c o * 1,4 1 4 1 4 1.4B O D 3.7 3 7 3 7 3,7

S u b t o t a l 198 198 198 198

Blowdown and waste treatment c

C a / M g / N ad 6 0 6.3 12,2 11 2C h l o r i d e . 5.3 5 7 0 9 0.8Fluoride ., – — 0 3 0.2S u l f a t e 6.5 6.8 8.4 7 6

Subtotal 18 19 22 20Mine drainage treatment CO 3 =/ HCO3-e (f) (f) 23,1 23,1Boron (f) (f) 0 1 0.1Ca/ Mg/Nad. (f) (f) 145 14,5C h l o r i d e (f) (f) 0.7 0.7F l u o r i d e . (f) (f) 0 5 0.5S i l ica. . , . , (f) (f) 0 5 0.5S u l f a t e (f) (f) 126 12.6

Subtotal — — 52 52

T o t a l , 488 295 1,171 887

a;ons per stream daybAssumes above-ground retorts operated a! temperatures that do not Produce condensatecln~]”de~ water pretreatment Above-ground plants use Colorado Rwer wafer MIS and MIS’

above-ground plants use mme drainage walerdGalclum magnesium and sodium Ionsecarbonale and bicarbonate IOnS

fAs~umes above-ground relorflng plants are not located w ground water areas

SOURCE

q

Of ftce of Technology Assessment

fleets present developer proposals. Itwould not be valid for future plants inthe center of the Piceance basin.No retort leachates are shown for theMIS retorts because the rate of leachingand the efficacy of control systems can-not be accurately estimated. One studyestimated that a commercial MIS facilitymight yield over 2,000 ton/d of solublesalts, but only crude estimates weremade of the rate of release.20



Ch 8–Environmental Considerations q 29 5

No rates are shown for trace elements,heavy metals, or toxic organic chemicalsbecause these are produced in muchsmaller amounts than the major pollut-ants. However, they can be both morehazardous and more difficult to re-

move.

21-28

The estimates indicate that MIS processingon tract C-b will produce the greatest quanti-ty of wastewater contaminants for treatment,mostly because of the large gas condensatestream. A substantial difference is shown be-tween the aboveground direct and above--ground indirect plants with respect to therates at which pollutants are generated in thegas condensate streams: the directly heatedfacility produces about four times as muchdissolved gas (largely CO2 and NH3). This isbecause more air is introduced into directlyheated retorts. The trend is consistent withthe even higher gas condensate production of the MIS retorts, which are also assumed to bedirectly heated.

Eff ects of Potential Poll utants on

Water Quality and Use

Salinity

Oil shale development could increase thesalinity in surface and ground water systemsthrough two processes:

Concentration of naturally occurringsaltwater as high-quality water is with-drawn for consumptive uses. (This effectis discussed in ch. 9.)Salt loading from leaching of waste dis-posal piles and in situ retorts, from re-lease of saline mine or process waters,and from ground water disturbancescaused by reinfection.

Salinity increases are a significant problembecause as water becomes more mineralized,

its municipal, domestic, ecological and agri-cultural utility is reduced. * If dissolved solids

“I’his is of ma jor importance because the Colorado River sys-tem is one of the most important river systems in the South-west. I t serves :~pproxima tel~’ 15 m i]iion people. ~funicipalit ies,agrirul t u re, energv proriuc t ion. i ncfus t rv and mining, recrea-

increase over 500 mg/1, treatment for munici-pal and industrial water users becomes morecostly, and the yield of irrigated farmlandsmight be reduced. 29 For public drinking watersupplies, EPA recommends limits of 500 mg/1for dissolved solids and 250 mg/1 for both

chlorides and sulfates.

30

Oil and Grease

Because large amounts of shale oil will beproduced, processed, and transported, thereis a possibility of oilspills. If they cannot becontained or removed, detrimental impactswould occur to aquatic biota. Small spills,such as from pipeline leaks, could cause localdamage. If undetected, the long-term impactscould be substantial. Oil and grease in publicwater supplies cause an objectionable taste

and odor, and might ultimately endanger pub-lic health.

Suspended Solids

Sedimentation problems will be increasedbecause large amounts of land will be dis-turbed, which will increase the area’s sus-ceptibility to erosion. Suspended solids makesurface water cloudy and increase its tem-perature, thereby affecting aquatic life. Sus-pended solids in industrial waters can dam-age some types of equipment.

Temperature Alteration

An industry may alter stream tempera-tures by discharging warm waste streams, byconsuming cool water, or by lowering theground water table. Discharges from power-plants could also increase temperatures, butthe developers do not expect to do this. Theconstruction of new reservoirs could alsoalter stream temperatures. While tempera-ture is not a critical factor in water for in-dustrial use, for drinking, or for irrigation,

tion, wildlife, Federal lands, and Indian reservations all com-pete for its waters. PresentIV, salinity of the Colorado River atIIoover Dam is 745 mgl. Unless efficient control technologiescan be employed, estimates have indicated that a large oilshale industry has the potential, due to salt loading and saltcorwent ration, to increase the salinity level a t Hoover Dam bv

several mg 1.



—


large variations would affect all aquatic life,both directly and indirectly (e.g., by influenc-ing their susceptibility to disease and toxiccompounds. )3] Because the Colorado Riversystem is large, and variations in water tem-peratures occur naturally, it is not expected

that oil shale development will significantlyaffect its temperature. 32

Nutri ent Loading

The potential sources of nitrogen and phos-phorous are ground water discharge, runoff from raw and spent shale, municipal wastes,and chemical fertilizers used for reclaimingland. These nutrients would adversely affectnearby surface waters, but the effect on thetotal river system is uncertain. The overallimpact will depend on where the facilities arelocated and on the degree of waste treatmentused.

Toxic Substances

Sources of toxic trace elements and organ-ic chemicals include stack emissions fromprocessing operations, chemicals used in up-grading and gas processing, leachates fromraw and retorted shale, and associated in-dustrial and municipal wastes. These sub-stances are of concern because of their po-tential impact on aquatic life, and on humanhealth through drinking water supplies andirrigation. Concentrations of certain mineralsin the region’s water already exceed the lim-its set for certain water uses. * Oil shale de-velopment could increase these levels andcould also add other toxic contaminants. Forexample, cadmium, arsenic, and lead, andother heavy metals could be leached fromspent shale piles. Organic compounds (phe-nols, benzene, acetone) that are suspectedcarcinogens and that have been identified byEPA as high-priority hazardous water pollut-ants also are found in oil shale process

waters.*For example, the boron content in Eva ma lion Creek, near

lease tracts U-a and U-b exceeds the irrigation standard. Seethe next section on water quality in the oil shale region for amore detailed discussion,

Microbial Contamination

The microbial contamination of surfacewaters could occur if rapid populationgrowth overloads sewage treatment facil-ities. (See ch. 10 for a discussion of the prob-lems of rapid growth.) Improperly treated

sewage containing viruses, bacteria, andfungi could be released into the water system.These problems could be controlled by theconstruction or expansion of sewage treat-ment plants.

Water Quali ty in the Oi l Shale Region

The current properties of the water definehow it must be treated before it can be usedin oil shale facilities. More importantly, theydefine the level to which wastewater must betreated before it can be discharged. In gener-al, regulations do not permit the discharge orreinfection of wastewater unless it is at leastas pure as the receiving stream or aquifer. Asindicated by the data in table 52, the qualityof surface streams is highly variable. It alsotends to deteriorate between upstream anddownstream reaches, as exemplified for Pice-ance Creek east and west of tract C-b. All of the streams described in the table satisfy thestandards promulgated by EPA and the U.S.Public Health Service for the maintenance of aquatic life and wildlife. Moreover, with theexception of Evacuation Creek, all are suit-able for irrigation water supplies and for live-stock watering. Evacuation Creek’s boroncontent exceeds the irrigation standard, andits dissolved solids level exceeds the livestockwatering standard. However, none of thestreams satisfies the standards for publicdrinking water. The standard for dissolvedsolids is exceeded by all the streams, espe-cially Yellow Creek and Evacuation Creek.Evacuation Creek also exceeds the standardfor boron, sodium, and sulfate ions. The sodi-um standard is also exceeded by Yellow

Creek, and the sulfate standard by all threecreeks and the spring.

Ground water is generally of poorer qualitythan surface streams. The quality of alluvialaquifers and of the upper and lower bedrock




Table 52.–Quality of Some Surface Streams in the Oil Shale Region (mg/l)

Basin Piceance Uinta Piceance Piceance Piceance Piceance Piceance Uinta

Piceance Creek Piceance Creek Spring at EvacuationStream Colorado River Whi te River east o f C-b west of C-b Yellow Creek WIIIOW Creek Wallow Creek Creek

Reference 14 15 16 16 17 16 16 15

Ammonia

B i c a r b o n a t eBoronC a l c i u mC a r b o n a t eC h l o r i d eDissolved solidsFluorideHardnessMagnes iump HSilicaS o d i u mS u l f a t e

N Ab

1 6 8N A

7 2

NA205734

NANA19NA

7 0153158

0 0 6

24 10088

720 2

42551

0 0 3299

298 21378

188

NA

542NA700 0

16718

1 0NA47

8 216

130170

NA

601NA79

0 014

9440.7

NA69

8 217

160300

0.153

1,4700.6423 1 9

118124

2,4302.09

541112

8 71 0 5

746550

0 1

6060.2143

0 14 0

9951 7

57653

7 913

138350

0 1

5400.6161

0 10 8

9101 4

51628

7.913

125310

0 0 6

5751. 95

2140 0

664,948

0 91400

2097 9

10972

2.889

aSee reterence IISIbDala not ava(lable

SOURCE Office of Technology Assessme~t

ground water aquifers in the Piceance basinnear Federal lease tracts C-a and C-b isshown in table 53. * Water from the alluvialand upper aquifers could be used for irriga-tion, but its high dissolved solids contentcould harm many crops, Water from the low-er aquifer could be used only with very toler-ant plants on permeable soil, and that fromsome portions of the aquifer could not be usedat all because the lithium and boron concen-trations would be toxic to many plants. Ex-cept for the lower aquifer, the ground waterresources could be used for livestock, All of the water would be suitable for maintenanceof aquatic life and wildlife.

None of the aquifers meets drinking waterstandards. Special problems are encoun-tered with boron, which in one sample of low-er aquifer water exceeded the drinking waterstandard by a factor of 320.

34 Also, the aver-age fluoride concentration in lower aquiferwater is about 28 times the drinking waterstandard. 35 Dissolved solids concentrations inthe lower aquifer range from a level thatwould satisfy drinking water standards (500

mg/1) to over 40,000 mg/1, A concentration of 63,000 mg/1 was reported for one sample. 36

“I’he grounci water resources of the Piceance basin are de-scribed in ch. 9. The bedrock aquifers are separated by the oilshale deposits of the !vlahogany Zone. Alluvial aquifers aregenera]ly found near the surface in valley walls and floors.

Aquifer

Table 53.–Quality of Ground Water Aquifersin the Piceance Basin (mg/l)

Alluvial Alluvial Upper LowerReferenced 17 16 16 16

Ammonia 0337Bicarbonate 573B o r o n 1 25Calcium ., 102Carbonate 11.4C h l o r i d e 17.9Dissolved solids 1,190F l u o r i d e 0367Hardness 600Magnesium 8 3 9pH 6 5

Silica NASodium. 202S u l f a t e 467

aSee reference IIsl bDala not avadable


N Ab

1 , 2 2 0

NA57

NA42

1,7504 6

NA80

NA

NA490430

NA550

NA50NA16

9601 4

NA60NA

NA210320

NA9,100

NA7 4

NA690

9,40028

NA9 5

NA

NA3,98080

Water Quali ty Regulat ions

Regulations for the maintenance of surfaceand ground water quality have been promul-gated under the Clean Water Act and theSafe Drinking Water Act. They are imple-mented at the Federal and State levels, to-gether with additional State standards. In thefollowing discussion, the provisions of theseActs that are of particular significance to oilshale are emphasized.

63-898 0 - 80 - 20




The Clean Water Act

The objective of the Federal Water Pollu-tion Control Act (FWPCA) is “to restore andmaintain the chemical, physical, and biologi-cal integrity of the Nation’s waters. ” In 1972,FWPCA was amended to establish a complex

program to clean up the Nation’s waterwaysby limiting the effluents of all classes of pol-luters. These limits were to be tightened untilthe ultimate goal of no pollution dischargeinto navigable waters was achieved. The min-ing industry had difficulties meeting the re-quirements of this program. Congress re-sponded to these problems, and to the recom-mendations of the National Commission onWater Quality, by further amending the Actin 1977. The amended Act, now called the“Clean Water Act” refined FWPCA’s regula-tory scheme for point sources and empha-

sized the control of toxic effluents. EPA, theArmy Corps of Engineers, and the States areresponsible for implementing and enforcingthis Act.

The goals of the Act are:q

q

q

q

the discharge of pollutants into naviga-ble waters shall be eliminated by 1985;wherever attainable, water qualitywhich provides for the propagation of fish, shellfish, and wildlife and for rec-reation in and on water, shall beachieved by July 1, 1983;

discharge of toxic pollutants in toxicamounts shall be prohibited; anda major R&D effort shall be made to de-velop- the technology necessary to elimi-nate the discharge of pollutants into thenavigable waters, the waters of the con-tiguous zones, and the oceans.

To achieve these goals, emissions stand-ards are to be set to limit discharges frompoint and nonpoint sources, and ambientstandards are to be established for the quali-ty of surface waters.

Effluent standards. —Different ap-proaches are used for control of point andnonpoint sources. Point sources release a col-lected stream of pollutants through sewers,pipes, ditches, and other channels. These can

be monitored and regulated with some preci-sion, and they are suited to the application of control devices. Nonpoint sources are sitesfrom which there is uncollected runoff. Exam-ples are irrigated fields and waste disposalareas. They present regulatory and techno-logical difficulties, and as a result, they aresubject to less stringent legal controls.

FWPCA established a complex regulatoryscheme to control pollution from industrialpoint sources:

q

q

q

q

q

by July 1977, all nonmunicipal pollutersmust use the “best practicable pollutioncontrol technology currently available”(BPT); public sewage works must usesecondary treatment;by July 1983, nonmunicipal point sourcesmust use the “best available technologyeconomically achievable” (BAT), munici-pal sewage treatment plants must usethe “best practicable waste treatmenttechnology;”special effluent standards for toxic pol-lutants must be met prior to the 1977deadline;new facilities must use the “best avail-able demonstrated control technology;”andspecial restrictions, based on ambientwater quality standards, must be used if the national effluent standards will notmeet water quality targets in a givenbasin.

The 1977 amendments changed this frame-work: the July 1977 BPT deadline was ex-tended until April 1, 1979, for point-sourcepolluters who demonstrated a good-faith ef-fort to achieve compliance, and the BAT pro-visions were completely revised. Industrialpoint-source pollutants were divided intothree classes— toxic, conventional, and non-conventional. Each is treated differently.Toxic pollutants cause death, disease, behav-ioral abnormalities, cancer, genetic muta-

tions, physiological malfunctions, or physicaldeformations in any organisms or their off-spring. Sixty-five toxic pollutants must meetthe BAT standards by July 1, 1984; othersmust meet BAT standards within 3 years




after effluent limitations are established.Conventional pollutants include biologicaloxygen-demanding substances, suspendedsolids, fecal coliform, and changes in pH.They are subject to the application of “bestconventional control technology” by July 1,1984. In general, this standard is less strin-gent than the BAT standard. Nonconvention-al pollutants—those classified as neither tox-ic nor conventional—will be subject to theBAT standards no later than July 1, 1987.

Specific limits on these effluents must beadhered to by individual polluters. In prac-tice, effluent limitations are developed byEPA for each industry. No discharge of anypollutant from a point source is allowed un-less a National Pollutant Discharge Elimi-nation System (NPDES) permit has beengranted. To obtain a permit, the polluter must

meet the applicable effluent limitations, tech-nology standards, and water quality goals.Permits are obtained from EPA or from the in-dividual States, if they have taken over theregulatory role. Cancellation of permits fornoncompliance is one method of enforcing theAct, because without a permit, many industri-al operations cannot be carried out. It shouldbe noted that permits do not simply recapitu-late the effluent guidelines; additional ambi-ent standards may also be imposed.

Special attention is given to new sources

and to sources that discharge into publiclyowned treatment works. In practice, perform-ance standards for new sources are oftenequivalent to the 1983 BAT limitations devel-oped for existing industries. Any new sourcethat complies with an applicable standard of performance is not to be subjected to morestringent standards during the first 10 yearsof operation.

Expected effluent limitations for oil shalefacilities.—EPA has not yet developed stand-ards of performance for oil shale facilities.However, standards have been established

for petroleum refining, which has severalsimilarities. The BPT standards shown for pe-troleum refining in table 54 were based on

Table 54.–Effluent Limitations for Petroleum Refineries UsingBest Practicable Pollution Control Technology (BPT)

(pounds per 1,000 bbl of feedstock)

Average of daily valuesMaximum for for 30 consecutive

Effluent characteristic any 1 day days shall not exceed

Biochemical oxygen demand

( B O D 5 ) 192 10 2Total suspended solids 13 2 8 4Chemical oxygen demand 136 70011 and grease 6 0 3 2Phenolic compounds 0 1 4 0068Ammonia as N 8 3 3 8S u l f i d e 0124 0056Total chromium O 29 0 1 7Hexavalent chromium 0025 0011p H Must be within the range of 6.0 to 90

SOURCE E R Bales and T L Thoem feds j Pololoo Coflrro GUAInI-e lo, 0 .W k Lle~eoomenl Append/x Envlro!lfnenldl ProtectIon Agency Cinclnnaft Ohio July 1979 0 D 9

the following wastewater management proce-dures:

q

q

sour water stripping to reduce NH3 andH

2S;

segregation of sewers;no discharge of polluted cooling water;andoil, solids, and carbonaceous wastes re-moved just prior to discharge.

The BAT standards illustrated in table 55were defined using additional treatment

Table 55.–Effluent Limitations for Best Available TechnologyAchievable (BAT) for Petroleum Refinery Facilities

(pounds per 1,000 bbl of feedstock)

Effluent Iimitations


Effluent characteristic any 1 day days shall not exceed

Biochemical oxygen demand(BOD 5 ) . 32 2.6

Tota l suspended so l ids. 3.0 2 6C h e m i c a l o x y g e n d e m a n d 168 1340 1 1 a n d g r e a s e 0 6 0 0.48P h e n o l i c c o m p o u n d s 0015 0010Ammonia as N. 20 1 5S u l f i d e . 0066 0042T o t a l c h r o m i u m 0 1 5 0.13He x a v a l en t ch r om i u m , 0.0033 0.0021p H Must be within the range of 6.0 to 9.0

SOURCE E R Bales and T L Thoem {eds I f%luton Coofro/ Gwddnce Pm 0// 5?M/e Deve/op-rnenf Appendix Enwronmental Protect(on Agency Cincinnati Ohio July 1979 pc1 11



300 An Assessment o/Oil Shale Technologies

methods now practiced by some petroleumrefineries. These methods include:

q

q

q

q

q

q

q

q

use of air cooling rather than wet coolingtowers;reuse of sour water stripper wastes;reuse of cooling water in the water

treatment plant;using treated wastewater as coolantwater, scrubber water, and in the watertreatment plant;reuse of boiler blowdown as boiler feed-water;use of closed cooling water systems,compressors, and pumps;use of rain runoff as cooling tower make-up or water treatment plant feed; andrecycling of untreated wastewaterswherever practical.

NSPS for petroleum refineries, based on acombination of BPT and BAT standards, areshown in table 56. New sources must meetdischarge standards that reflect the greatestdegree of effluent reduction which the EPAAdministrator determines to be achievablethrough application of the best available dem-onstrated control technology, process altera-tions, or other methods including, wherepracticable, zero discharge systems.

Federal ambient water quality stand-ards. —The Water Quality Act of 1965 re-quired the States to adopt ambient standards

Table 56.–New Source Performance Standards for PetroleumRefineries (pounds per 1,000 bbl of feedstock)

Effluent Imitations


Effluent c haracteristic any 1 day days shall not exceed

Biochemical oxygen demand( B O D5 ) 1 4 7 7.8

T o t a l s u s p e n d e d s o l i d s . 9.9 6.3Chemical oxygen demand ~ ~ 104 540 1 1 a n d g r e a s e 4.5 2.4Phenolic compounds 0.105 0.051A m m o n i a a s N 8.3 3.8S u l f i d e 0093 0042

T o t a l c h r o m i u m . , 0220 0.13H e x a v a l e n t c h r o m i u m . 0.019 0.0084pH ., Must be within the range of 60 to 90

SOURCE E R Bales and T L Thoem (eds Po//uOofl CofMro/ Gwdance for Od Sha/e L7eve/opmenl Append/x Environmental Protection Agency Clnclnnatl Oh[o July 197[1 p012

for interstate waters. FWPCA required Statestandards for intrastate waters as well. EPAwill develop the standards if a State fails todo SO.

The ambient standards are the basis forpreventing the degradation of presently clean

waterways. The regulations provide, withoutqualification, that “No further water qualitydegradation which would interfere with orbecome injurious to existing instream wateruses is allowable. ” Thus, if a stream is suit-able for the propagation of wildlife; for swim-ming; or for drinking water, then it must re-main suitable for these uses. Because smallincreases in pollutant loads may not be incon-sistent with protecting a possible present use,the States are allowed to decide whether “toallow lower water quality as a result of necessary and justifiable economic or socialdevelopment. ” Such decisions cannot be ap-plied to waters that constitute an outstandingnational resource (e.g., national parks, wil-derness areas), and they cannot allow waterquality to fall below the levels needed to pro-tect fish, wildlife, and recreation.

Before a State can issue a discharge per-mit it must have a program for reviewing andrevising its water quality standards. EPA es-tablished the following guidelines for Statereview and revision:

q

standards must be reviewed every 3years and revised where appropriate;q standards must protect the public health

and welfare, and not interfere withdownstream water quality standards;

existing standards must be upgradedwhere current water quality could sup-port higher uses than those presentlydesignated;

q existing standards must be upgraded toachieve FWPCA’s 1983 goal of fishableand swimmable waters, where attain-able. Attainability is to be determined by

environmental, technological, social, ec-onomic, and institutional factors; andq existing water quality can degrade in

only specific instances, for example, if existing standards are not attainable




because of natural conditions such asleaching.

Once an ambient standard is established, aState must identify stream reaches for whichthe 1977 effluent limitations are not suffi-ciently stringent. For such areas, the State

must determine the total maximum pollutantloads that will allow the ambient standard tobe met, This information is used to set morestringent effluent standards.

Current State standards for Colorado andUtah. —In Colorado, streams may be assignedto one of four categories. Drainage from leasetracts C-a and C-b would discharge to the por-tion of the White River from the mouth of thePiceance Creek to the Colorado/Utah Stateline. This area is in Colorado’s water cate-gory B2. These waters are suitable, or are to

become suitable, for customary raw waterpurposes (e.g., irrigation, livestock watering)except for primary contact recreation, * Thewater quality criteria for category B2 arelisted in table 57. Colorado also has an anti-degradation policy applicable to all streams.

Utah has 11 stream classifications, Twostreams in and around oil shale tracts U-aand U-b, Evacuation Creek, and the WhiteRiver, are classified as CW (i.e., warm waterfisheries). Their waters are suitable for all

*Prim:~rV ronttirl rerrc:)tifjn includes sw imrnin~, water ski-ing. and diving.

Table 57.–Colorado Water QualityStandards for Stream Classification B2

Parameter Criteria for B2 streams

Settleable solids floating solids Free fromtaste, odor, color and toxicmaterials

Oil and grease Cannot cause a film or otherdiscoloration

Radioactive material Drinking water standardsFecal conform bacteria Geometric mean less than 1,000

units per 100 millilitersTurbidity Cannot increase more than 10

unitspH 60 to 90Temperature Maximum 900 F

Change Streams 50 FLakes 30 F

SOURCE E R Bates and T L Thoem (eds I Po/JufIorI ConfroI Go(dance for 01/ Sbd/e De,e)oprnenl Append/x E n v i r o n me n t a l Prolecl(on A g e n c j Clnc(nnatl Ohio JuIy 1979 pD 20

raw water uses (except contact recreation)without treatment, but with coagulation, sedi-mentation, filtration, and disinfection prior touse as domestic water supply. Temperaturelimitations are also imposed. The water quali-ty criteria for class CW are shown in table

58. In addition, Utah, like Colorado, has anantidegradation policy.

Table 58.–Utah Water Quality Standardsfor Stream Classification CW

Parameters Criteria for CW streams

Radioactive and chemical Drinklng water standardsSettleable solids. 011, floating solids, Free from

taste, odor, color, and toxicmaterials, turbidity, etc

Total coliform bacteria Less than 5,000 units per 100milliliters

Fecal conform bacteria Less than 2,000 units per 100milliliters

pH 65 to 85, no Increase >0.5Biochemical oxygen demand (BOD 5) Less than 5 milligrams per IiterDissolved oxygen >6.0milligrams per literTemperature Maximum 680 F

SOURCE E R Bates and T L Thoem (eds I Polluf(on ComroI Gufdafice to{ Oh Shd,e Oeve/oj

ment Appendtx Enwronmental P r o fecllon Aqenc~ Clncnnaf O h i o JIJY 1979 p021

Proposed State standards.—FWPCA re-quired the States to designate areawide pol-lution control planning agencies. The Colora-do West Area Council of Governments andthe Uinta Basin Council of Governments havebeen designated for the oil shale region.These agencies are to plan, promulgate, andimplement a program designed to protect sur-

face water quality. Stream classificationsand water quality standards are to be devel-oped. The multiple-use classifications pro-posed for streams, which may supersede ex-isting classifications previously discussed, in-clude:

q

q

q

q

The

Class I—aquatic life, water supply,recreation, and agriculture:Class II—water supply, recreation, andagriculture;Class III—recreation and agriculture;and

Class IV—agriculture.respective water quality criteria are

shown in table 59. The classifications and thequality criteria will apply to all streams in theoil shale region.






restraints of existing treatment techniquesand their costs. Interim standards were is-sued by EPA during 1975 and 1976 and wereput into effect in June 1977 (see table 60).These standards established both maximumcontaminant levels and monitoring require-ments for 10 inorganic and 6 organic chemi-cals, radionuclides, microbiological contami-nants, and turbidity. A study by the NationalAcademy of Sciences of the health effects of drinking water contaminants is to be the basisfor revised primary standards. The study wascompleted in June 1977, but the revisedstandards have not yet been issued.

Secondary standards, published in 1977,deal with contaminants that affect the odorand appearance of water but do not directlyaffect health (see table 61). They are not fed-erally enforceable and are only guidelines to

the States. The States may include monitoringrequirements in their laws and regulations.

Table 60,–Primary Drinking Water Standards (mg/l)

Maximum concentration

Inorganic chemicals (except fluoride)A r s e n i cB a r i u mC a d m i u mC h r o m i u mL e a dM e r c u r yN i t r a t e ( a s N ) ,

S e l e n l u mS i l v e r . . ,Fluoride (degrees Fahrenheit)5 3 7 a n d b e l o w53.8to 583 .,5 8 4 t o 6 3 . 863.9 to 70,670.7 to 7927 9 3 t o 9 0 . 5C h l o r i n a t e d h y d r o c a r b o n s E n d r l nL i n d a n eM e t h o x y c h l o rT o x a p h e n eChlorophenoxys 2, 4-D (2, 4-dichlorophenoxyacetic acid).

2, 4, 5-TP (Silvex)

0 0 51 000 10 0 50 0 50002

10 0

00 10 0 5

2 42 22 01.81 61 4

0.00020.0040. 1

0.005

0.1

0.01

SOURCE E R Bates and T L Thoem (eds ) Po//u1/on Comrol Gwdaoce for 011 Shale Developmenf Append/x Enwronmental Protecllon Agency Clnclnnall Ohio Ju ly 1979 pp D-

32-D-33

Table 61 .–Proposed Secondary Drinking Water Regulations

Pollutant Proposed level Principal effects

C h l o r i d e 250 mg/l TasteColor 15 color un its AppearanceCopper 1 mg/l Taste, fixture stainingCor ros iv ity (Noncorrosive) Deterioration of pipes, unwanted

metals in drinking waterFoaming agents O 5 mg/l Foaming, adverse appearanceHydrogen sulfide O 05 mg/l Taste, brown stains on laundry

and fixturesM a n g a n e s e . 0 0 5 m g / l Taste, brown stains, black

precipitatesO d o r 3 threshold Odor

odor numberpH ., .. 65-8.5 mg/l Corrosion below 65. incrusta-

tions, bitter taste, loweredgermicidal activity of chlorineover 8.5

Sulfate 250 mg/l Taste, Iaxative effectsTotal dissolved

s o l i d s 500 mg/l Taste, reduction in Iife of hot waterheaters, precipitation in cookingutensils

Z i n c 5 mg/l Taste

SOURCE E R Bales and T L Thoem teds I Po//ufIorI Conlrol Gwdance for 0/1 S/We Uevekmrr?er?f Append/x Enwronmen[al Protect Ion Agency Clnclnnafl Ohio Ju ly 1979 0

D 33

Ground Water Quality Standards

Federal.—The Safe Drinking Water Actapplies to deep-well injection of waste intoaquifers with less than 10,000 mg/l TDS thatare, or could become, sources of public drink-ing water. Seepage from pits, ponds, and la-goons is not regulated at this time.

Colorado. -No specific standards have

been promulgated for ground water quality.However, the basic standards applicable toall other State waters do apply. Regulationsare being developed that will limit the dis-charge or injection of some contaminants.Permits are now required for injection wells,and they will be required in the future forwastewater disposal in pits, ponds, and la-goons if there is a possibility of discharge to aground water system.

Utah.—Utah also has no special standardsfor ground water. However, ground water is

considered part of the State waters, so gener-al water quality standards do apply. Dis-charges to sources of potable water must notcause the water quality to exceed drinkingwater standards.




Implications of Water Pollution Control Standards

and Regulations for Oil Shale Development

As indicated above, the primary objectiveof the Clean Water Act is to eliminate thedischarge of pollutants into navigable watersby the late 1980’s. In order to accomplish thisobjective all potential polluters, including oilshale developers, will be required to applyBAT, BPT, and NSPS. Point source dischargeis well-regulated under the Act, and it is ex-pected that oil shale developers would complywith the stipulations promulgated in regardto NPDES. As will be discussed in the follow-ing section, the pollution control technologiesthat are being applied to oil shale wastewatereffluents are designed for zero discharge.However, in some instances (e.g., excess wa-ter from mine dewatering) it will need to bedischarged back into surface waters or rein-fected into underground aquifers. In thiscase, water will have to be treated to meetthe standards stipulated under the NPDESpermit system or by the Safe Drinking WaterAct for reinfection—that is surface andground water quality criteria and water useclassifications will have to be maintained asstipulated by the States and EPA. In addition,it is expected that oil shale facilities will haveto meet NSPS comparable to those developedfor petroleum refining facilities.

Technologies for Control of Oil ShaleWater Pollut ion

Treatment of Point Sources*

Contaminants may be removed from waste-water by physical, chemical, or biologicalmeans. For complex wastes, a series of de-vices using each of these principles will benecessary.

Physical treatment devices apply gravity,electrical charge, and other physical forcesto contaminants to remove them from waste-water. Typical operations are gravity separa-tion, air flotation, clarification, filtration,stripping, adsorption, distillation, reverse os-

*De!ails of the various technologies are described in app. D.

mosis, electrodialysis, thickening, and evap-oration.

Chemical treatment devices use chemicalproperties or chemical reactions to removecontaminants. Such systems can destroy haz-ardous substances that are not amenable toconventional physical and biological systems.For oil shale wastewaters, the most impor-tant devices are those that could oxidize or-ganic compounds or reduce salt concentra-tions. Included are ion exchange, wet air oxi-dation, photolytic oxidation, electrolytic oxi-dation, and direct chemical oxidation.

Biological treatment devices contact awaste with a population of micro-organismsthat digest its organic contaminants. By con-trolling the size of the population, and by ad-

justing oxygen and nutrient levels and equal-

izing the conditions of the entering stream, itis possible to develop and acclimate micro-or-ganisms that can nearly eliminate many haz-ardous organic compounds. Biological treat-ment systems can be divided into two groups:

q aerobic processes (such as activatedsludge, trickling filters, rotating biologi-cal contractors, aerated lagoons, com-porting, and stabilization ponds) inwhich the population is maintained un-der oxygen-rich conditions and the or-ganic compounds are decomposed to CO 2

and water; andq anaerobic processes (such as digestion)

in which oxygen levels are relatively lowand the organic compounds are de-graded to CO and methane gas.

Treatment systems. —Most devices can re-move some but not all contaminants. In atreatment system, different wastewaters aresent to different devices, each of which re-moves a specific type of pollutant, The rela-tionships among contaminants, the streams inwhich they are likely to occur, and the treat-

ment processes of choice are shown in table62. Although all contaminants may be foundin nearly all streams, the streams associatedwith each contaminant have been limited tothose in which concentrations will be high




Table 62.–The Types of Contaminants in Oil Shale WastewaterStreams and Some Potential Processes for Removing Them

Contaminant Stream. . ,Potential process

Suspended solids Mine drainageRetort condensateCooling tower blowdown

Oil and grease Retort condensate

Gas condensateCoking condensateDissolved gases Retort condensate

Gas condensateCoking condensate

Dissolved inorganics Mine drainage

Dissolved organics

Trace elements andmetals

Trace organics

TOXiCS

Sanitary wastes

Retort condensateGas condensateCooling tower blowdownIon exchange regenerantsRetort condensateGas condensateCoking condensateHydrotreating condensate

Retort condensateGas condensate

Retort condensateGas condensateUpgrading condensateRetort condensateGas condensateUpgrading condensateDomestic service

ClarificationFiltration

Gravity separation

Emulsion breaking

Steam stripping

Chemical oxidationIon exchangeReverse osmosisAdsorptionEvaporation

Solvent extractionAdsorptionBiological oxidationUltrafiltrationReverse osmosisWet air oxidation

Chemical oxidationIon exchangeAdsorptionUltrafiltrationReverse osmosisAdsorptionChemical oxidationIncineration

Biological treatment

SOURCE R F Probsleln H Gold and R E Hicks Wafer Reauwernertfs Po/kJ//on Effects and Costs of Wafer Supp/y and Trealrnen( for the 0// Sha/e /ndusfry prepared for OTA byWater Purlflcatlon Associates October 1979

enough to require removal prior to dischargeor reuse. 37 38

Many of the devices listed in table 62 havebeen tested individually on oil shale wastewa-ters and have been found to provide some de-gree of control. 39-50 Of great importance is theperformance of these units when combined toform a “treatment train” for a specificwastewater. A separate train—consisting of several individual treatment devices inseries—will be needed for each stream be-cause, in general, each will contain different

types of contaminants, Each contaminant willrequire a different type of removal process.For example, retort condensates may containsuspended solids, oil and grease, dissolvedgases, organics, inorganic, and trace ele-

ments. Mine drainage water may contain onlydissolved solids.

The removal efficiencies, reliabilities,adaptabilities, and relative costs of somepoint source control devices are summarizedin table 63. This information comes almost en-

tirely from experience in other industries.Few of the technologies have been tested withoil shale wastewaters, and none has beentested in the complex treatment trains thatwill be necessary to deal with the wastes thatwill be encountered in commercial-scale oilshale plants. The degree of adaptability of each technology is particularly importantbecause it indicates the likelihood that thetechnique will transfer without difficulty tothe oil shale situation.

Most suitable technologies.—The follow-ing technologies appear most suitable:

q

q

q

q

q

q

for oil and grease: dissolved air flotationor coalescing filters;for dissolved gases: air or steam strip-ping;for dissolved organics: rotating biologi-cal contractors or trickling filters forfirst-stage removal, carbon adsorption,or wet air oxidation for polishing;for suspended solids: pressure or multi-media filtration;for dissolved solids: reverse osmosis forfirst-stage removal, clarification for sec-

ond-stage, and ion exchange for polish-ing; andfor sludges: filtration and evaporation.

Costs.—Control costs depend on the oper-ating characteristics of the oil shale facilityand on the treatment methods selected. Theonly published cost estimates were preparedfor the Department of Energy (DOE). Theseestimates, upgraded for OTA to include thecost of treating excess mine drainage water,appear in table 64. Total treatment c o s t s

range from about $0,25 to $1 .25/bbl of shale

oil syncrude. The low estimate applies toaboveground retorting plants; the high to MISfacilities in ground water areas. Althoughsizable, the control costs should not them-selves preclude profitable operations.




Table 63.–Relative Rankings of the Water Treatment Methods

Contaminant Technology Removal efficiency, % Relative reliability Relative adaptability Relative cost

011 and grease Dissolved air flotationCoalescing filterClarification

90 99 80

Very highHighVery high

Very highHighVery high

MediumMediumHigh

Dissolved gases Air strippingSteam stripping

Flue gas strippingBiological oxidation

80 95

95 High

HighVery high

HighMedium

HighHigh

MediumMedium

MediumMedium

MediumLow

Dissolved organics Activated sludgeTrickling filterAerated lagoonRotating contactorAnaerobic digestionWet air oxidationPhotolytic oxidationCarbon adsorptionChemical oxidationElectrolytic oxidation

95 BOD/40 COD85 BOD80 BOD

90 BOD/20-50 COD60-95 BOD


90 BOD/90 COD95 BOD/61 COD

HighHighMediumHighHighMediumMediumMediumVery highMedium

MediumMediumMediumMediumMediumHighVery highHighVery highVery high

LowLowLowLowMediumVery highVery highMediumHighHigh

Suspended solids ClarificationPressure filtrationMultimedia filtration

509595

HighHighVery high

HighHighHigh

MediumMediumLow

Dissolved solids Clarification

DistillationReverse osmosisIon exchangeElectrodialysis

Low except for metals99

6 0 - 9 5High

1 0 - 4 0

High

MediumMediumHighMedium

MediumLowMediumLowMedium

Medium

Very highMediumHighVery high

Sludges ThickeningAnaerobic digestionVacuum filtrationSludge drying bedsEvaporation basinsFilter pressAerobic digestion

Product 6-8% solidsLow

Product 20-35% solidsProduct 90% solidsProduct 95% solidsProduct 35% solids

Low

Very highHighHighMediumVery highVery highLow

HighMediumHighLowLowHighLow

MediumMediumHighMediumLowHighHigh

SOURCE Adapted from 4ssessrnerU of 0// Sfra/e Rerorf Wasfewa(er Trealrneru and ConVo~ Tec/rno/ogy, Hamllfon Standard Owlslon of Uruled Technologies July 1978 pp 2-12 to 2-24

Table 64.–Estimated Costs of Water Pollution Control inOil Shale Plants ($/bbl of shale oil syncrude)a

torts. For an aboveground retorting facility,the leaching problem may be reduced by dis-

posal of the solid wastes in canyons, and cap-turing and treating any leachate that does oc-cur. (See figure 61. ) It is hoped that themoistened and compacted spent shale will beimpermeable to the flow of water. The top of the pile will be covered with topsoil o ranother growth medium that will be perme-able but that will no t contain substantialquantities of soluble contaminants. A n yleachates that reach the catchment basinwould be treated. This method may be effec-tive during the lifetime of the facility.

Above- Above--ground ground MIS/

Wastewater stream direct indirect MIS aboveground

Gas condensate $0.11 $0.13 $0.45 $0.31R e to r t c o n d e n s a te – — 0.13 0.09Upgrading

c o n d e n s a t e 0,12 0.12 0 1 2 0.12Excess mine

drainage ., . – — 0-0.55 0-0.55

Total . . ., $0.23 $0.25 $0.70-1.25 $0.52-1.07

aplants produce 50,1NI btjltd Of syncrude Aboveground plants are assumed to be not located In

ground water areas Cost estimates include operating expenditures and capital amorhzatlon

They also include nonwastewater costs such as botler feedwater treatment costs

SOURCE R F Probste!n, H Gold and R E Hicks, Wafer Requwernerrk, Po//u(/on Effecls and Cosk O( Waler Supp/y and rreatrnerrl for the 00 Sha/e /ndus/ry, prepared for OTA byWaler Purlflcatlon Associates, October 1979

Tests of these control strategies have no t

simulated conditions of commercial-scale dis-posal piles, and past research investigationsare limited in their applicability. Questionspersist concerning shale pile permeability,

Control of Nonpoint Sources

The major potential nonpoint sources areleachates from aboveground storage of rawor spent shale and from abandoned in situ re-




Figure 61 .—An Aboveground Spent ShaleDisposal Area

~~‘ + \

\’ --

1

Processed Shale=

-— Disposal Pile \ ’

Leachate D i t c h - - $

;

q%

+

// . , ,\

\ \

D r a i n a g e D!tch , \ \

/ ’

‘ /

‘ / ‘ / //;

/.— - / ‘ /,$? //’.

/ ;:::~&4/////7T~

y{//)’)’y”?-#

Leachate Ditch

/ / / /’

/ //

///)/ ,/ / Q

-—— Leachate Catch Basin

.:”&/

— Retent ion Dam—-

:&b--–– \ (ll\ \

\ , Emergency Spillway

‘\ \ ‘~.

\ / ‘\

‘ \ \ \ \

SOURCE: Surface Mining of Non-Coal Minerals, National Academy of

Sciences, Washington, D C., 1979, p. 126,

erosion potential, reclamation effectiveness,and the balance between erosion and soil pro-duction rates. Water and leachates may per-colate into underlying alluvial aquifers. *These effects need careful monitoring at

pioneer commercial facilities.The efficacies of these control strategies

after site abandonment are even less certain.Long-term monitoring and custodial care maybe required to assure that contaminants arenot released from the catchment basin as aresult of dam failure or extraordinarily heavyrainfall or snowfall,

For in situ processing, laboratory experi-ments indicate that high temperatures con-vert soluble solids in spent shale into insolu-ble mineral complexes. If such temperatures

could be achieved in commercial-scale oper-

*rI’here are other techniques as well, For example, preleach-ing of spent shale, capillarv brakes, and covering spent shalewith open pit overburden, See the section on land reclamationin this rhapter for more detail.

ations, they might serve as a primary methodfor reducing leaching. Several uncertaintiesprevent assessing the feasibility of this ap-proach. For example, the mineral complexesproduced in the field would have to remain in-soluble for long periods of time even if the

retorts were backflooded. Also, to eliminateleaching, all of the spent shale in the retortswould have to be insoluble. Because controlof MIS retorting is difficult, portions of theretorts may not become hot enough to pro-duce the insoluble complexes. Control of re-torting temperatures in TIS processing iseven less certain. Since there would be mas-sive amounts of waste, increased percolationby ground water, and thus greater leachingpotential, these uncertainties may mandatethe adoption of retort abandonment strate-gies.

Retorted shale can form a cement-like ma-terial if it is properly prepared, and waterslurries of finely crushed retorted shale couldbe injected into burned-out retorts to fill voidareas and to make the spent shale imper-meable to water flow. To prevent leaching,the cement formed from the injected slurrywould have to have very low permeability;otherwise, the cement itself might produce atroublesome leachate, thereby compoundingground water pollution, Distributing the slur-ry uniformly within the retort may also provedifficult.

Another approach would be to pump fresh-water through the retort to intentionallyleach out the soluble components. The leach-ates could be treated and then reinfected on adowngradient from the retorts. It is possiblethat leaching could be accelerated in thisway, but the process might be costly and time-consuming and the technology has yet to bedeveloped.

“Hydrologic barriers” might be used toprevent or control the flow of water into theretort area, thereby preventing the disper-sion of leachates. One possibility is drilling acontinuous series of holes around the retortarea and filling them with a cementitiousslurry. By itself, this technique may not be ful-ly effective since the retorts may be in aqui-




fers in which water moves vertically. The ef-fectiveness could be increased by cementing(grouting) the retorts to seal their more per-meable zones and fractures.

Another possibility would be to divert amajor portion of the ground water flow

around the retort area. In this “hydraulic by-pass” option, artificial channels or barrierswould capture most of the ground water flow-ing toward the retort area, direct it aroundthe area, and then return it to the ground wa-ter system.

Ultimate Disposition of Wastewater

At present, no developer plans to dischargewastewaters to surface streams; rather, thefinal wastes will be disposed of by recycling,evaporation, and reinfection. In the future,

consideration may be given to treating anddischarging all surplus process waters. Thiswould be much more expensive than treat-ment to industrial standards, but it would re-duce the impacts of development by augment-ing stream flows in a water-short region. If this option is adopted, water treatment needswill increase significantly and highly efficienttreatment methods will be necessary.

Recycling

Present developer plans call for treating

and recycling wastewaters whenever practi-cal. This depends only on the ability of wastetreatment systems to purify the wastewatersso that they could be reused in other portionsof the process. Nearly all of the wastewaterscould be reused after appropriate treatmentfor cooling tower makeup, for dust control,for shale disposal, for leaching, for revegeta-tion, and for generating steam that could beinjected into either aboveground or in situ re-torts. As discussed previously, efficient, reli-able, adaptable, and cost-effective methodsappear to be available for the major contami-

nated streams. Their capability of treatingthe wastes to discharge or reinfection stand-ards is not relevant as long as the streams areto be recycled.

Treated cooling tower wastewater couldbe reused after dilution with other treatedstreams. Treated gas condensates are alsosuitable for cooling water because theyshould have low concentrations of inorganiccontaminants and volatile organics. Retortcondensates could also be used after their

dissolved substances are removed.Water quality criteria have not been estab-

lished for dust control, shale disposal, orrevegetation, but water similar to river waterwould probably be acceptable. It should bepossible and practical to treat gas conden-sates to this level. Treated retort condensatesshould also be acceptable, although success-ful treatment has yet to be demonstrated.Steam raising, for example, with the thermalsludge system, is at present a more reliableoption. These condensates (either treated or

untreated) could also be used as a slurrymedium for grouting in situ retorts. Testswould be needed to determine if the waste-water contaminants were truly immobilizedso that they could not be leached by groundwater.

Evaporation

Most of the wastewaters will be disposedof in dust control and in the waste disposalpiles. The sludges and concentrates fromwastewater treatment will also be added to

the disposal piles. In essence, this converts apoint source of pollution, which would behighly regulated under existing laws, to anonpoint discharge, which is not well-regu-lated at present. However, the treated waste-waters would be quite different from the rawstreams described in table 51. For example,most of the NH3 and H2S will have been re-moved from the gas condensates and recov-ered as byproducts. The CO2 will also havebeen removed and vented to the atmosphere.The concentration of NH3 could be further re-duced by biological treatment and by using

the treated condensates as cooling water.The small quantity remaining may be usefulas fertilizer for reclaiming the waste disposalareas. Most of the potentially harmful organ-




ic compounds could be removed by biologicaltreatment and the more resistant ones by ad-sorption. However, some organic matter islikely to reach the shale disposal area. It isnot known whether the organics will remainlocked within the shale pile or will be

leached.Similar treatment could be used for the re-

torting and upgrading condensates, althoughthe chemicals in the retort condensate couldpose some special treatment problems. If thermal sludge systems were used, both theinorganic and the nonvolatile organic contam-inants would be reduced to a stable sludgesuitable for disposal in a sanitary landfill orin a hazardous-waste disposal area. The vola-tile organics would be entrained in the steamand subsequently incinerated in the retorts.

Reinfection

Reinfection may be legally allowed if thequality of the injected water is at least ashigh as that in the affected aquifer. Injectionof condensates or other highly contaminatedwastes would not be permitted without a highdegree of treatment, However, mine drainagewater might be reinfected if it had not beendegraded by evaporation or chemical changewhile on the surface. Otherwise, it firstwould have to be treated or diluted.

Until commercial-scale oil production be-gins, essentially all mine drainage water willrequire disposal, probably by reinfection. It isgenerally assumed that the chemicals in thedrainage water would not cause significantchanges in the quality of the source aquifers.However, water quality could be degradedbecause of the increased ground water flow,the exposure of new mineral surfaces byfracturing, and the changes in undergroundmicrobial populations. If such changes oc-curred, the treatment or disposal conditionswould have to be adjusted to compensate for

them.51

This might include treating the drain-age to a purity higher than that of the sourceaquifer.

Monitoring Water Quali ty

Because much surface water comes fromground water discharge, it is necessary tomonitor both surface and ground water tohelp prevent environmental damage. Moni-

toring provides a continuous check on compli-ance with regulations, a record of changes re-sulting from development, and a measure of the effectiveness of pollution control proce-dures.

Surface Water Monitoring

Surface water monitoring should include:q

q

q

q

A

instream sampling and chemical anal-ysis to detect and characterize pollut-ants of point and nonpoint origin:detection of spills and faulty contain-

ment structures that could result in ac-cidental discharges;measurement of streamflows to assesseffects of dewatering operations andconsumptive uses; andmeasurement of aquatic biota to deter-mine the changes resulting from develop-ment,

monitoring program is defined by thenumber and location of sampling stations, theparameters measured, the sampling frequen-cy and collection methods, the accuracy and

precision of the analytical techniques, andthe quality assurance safeguards. Tradition-al monitoring methods may not be well-suitedfor the oil shale situation. The uncertainpollutant release rates and pathways and thewide variations in regional water quality,complicate the development of a suitable pro-gram and limit the use of conventional tech-niques.

The number and location of sampling sta-tions depend on the objective of the monitor-ing program. For example, if the objective is

to detect changes over an entire basin, thestations would be located in the lowerreaches of major tributaries. They could de-




tect major changes but would be unable topinpoint their cause. In contrast, stationsnear pollution sources could both measurethe local effects of pollutant discharge andidentify the source. An oil shale programcould include stations on major streams, aswell as on the minor tributaries that draineach development site. Special stations arealso needed near solid waste disposal areasto detect leaching.

The selection of chemical, physical, andbiological parameters to be measured will bebased on the types and concentrations of pol-lutants that might be discharged, the ease of analysis, and the characteristics of the waterin the affected streams and aquifers. Thepossible parameters include the concentra-tions of the pollutants themselves as well asthe levels of “indicator” parameters that pro-

vide a measure of the potential environmentaldisturbance. These include pH, dissolved ox-ygen, hardness, temperature, flow rate, andthe characteristics of the aquatic biota.

Biological parameters are especially usefulbecause they reflect the stability and re-sponse of the ecosystem. Aquatic organismsare natural monitors of water quality sincethey respond in a predictable manner to thepresence of most types of pollutants. Changesmay indicate problems that are not easilydetected by direct measurements of water

quality. For example, heavy metals and someorganic compounds tend to concentrate in thebiota. Their levels in the tissues of certainfish could help predict pollution concentra-tions that are not readily measurable in thewater itself. Communities that could be moni-tored include invertebrates, fish, algae, andbacteria.

The sampling frequency can also vary.Ephemeral tributaries, for example, could bemonitored only during periods of heavy rain-fall or snowmelt; mainstream tributaries

could be monitored continuously. Frequentmonitoring of all possible parameters wouldbe very expensive and time-consuming.Therefore, priorities must be established onthe basis of cost, utility of the data, and thepotential for severe environmental impacts.

Ground Water Monitoring

Observation wells are used to detecttrends in water quality and to measure the ef-fects of operations such as wastewater rein-fection. The locations of the monitoring sta-tions should be selected according to:

q the locations of the potential pollutantsources;

q the geology and hydrology of the site tobe monitored;

q the probable movement and dispersionof pollutants underground; and

q the potential for hydrologic disturbancesof, for example, dewatering wells.

EPA has developed a monitoring methodologyfor the oil shale area.52 The important con-siderations are:

q

q

q

q

q

q

The

the identification of potential pollutants;the definition of hydrogeology, groundwater use, and existing quality;the evaluation of the potential for in-filtration of wastes by seepage;the evaluation of pollutant mobility inthe affected aquifers;the priority ranking of pollution sourcesbased on the mass, persistence, toxicity,and concentration of the wastes; theirmobility; and their potential for harm towater users; andthe design and implementation of pro-

grams for near-surface aquifers, deepaquifers, and injection wells.

siting of wells for near-surface aquifersis extremely important. They should beplaced down the ground water hydraulic gra-dient (i.e., “downstream”) from possible pol-lution sources such as reinfection wells, res-ervoirs, and disposal piles. The wells shouldallow sampling from different depths, and thechemical and physical parameters should beselected according to hydrological character-istics as well as the properties of potentialpollutants. Deep aquifers should be moni-tored near dewatering wells, in situ retorts,and reinfection wells. Monitoring of salinity,TDS, and water level should be emphasized.Monitoring deep aquifers in the Piceancebasin is especially difficult because the



— —

Ch, 8–Environmental Considerations q 311

ground water flows through fractures andfaults and not through the more common uni-formly porous media, A further complicationis the different permeability of adjacentstrata. Even flow rates are hard to measurein a fractured-rock system, and it is difficultto properly site the monitoring stations.

The monitoring of surface and ground wa-ter quality is exemplified by the program onFederal lease tract C-b that has been under-way since 1974. The sampling schedule andwater quality parameters are listed in table65. Thirteen surface water gauging stationshave been constructed: nine on ephemeralstreams and four on perennial drainages.Nine springs and seeps are also monitored.Temperature and conductivity are measuredcontinuously at all stations on the perennialstreams. Dissolved oxygen, pH, and turbidityare measured continuously at several of these stations; other parameters are meas-ured monthly, quarterly, or semiannually.

Water levels in alluvial aquifers are meas-ured continuously at 18 test wells. Conduct-ance, pH, temperature, and dissolved oxygenwill be measured monthly. The quantity andquality of water in the deeper bedrock aqui-fers are measured at 17 wells in the upperaquifer and 14 in the lower aquifer. Samplesare obtained for water quality twice a year,and water levels are measured monthly. Wa-ter quality is also measured in reservoirs,waste disposal piles, and mine sumps.

Information Needs and R&D Programs

Insights into the water quality impacts of oil shale development have been obtainedfrom laboratory and pilot plant studies, froma few field tests in the Piceance basin, andfrom experience in related industries. Addi-tional measurements and R&D programs areneeded to help reduce the level of uncertain-

ty. Uncertainties will remain, however, untilexperience has accumulated from commer-cial-sized modules and plants.

Need for Reliable Data on Wastewater Quality

Reliable data are lacking on the charac-teristics of the gas, retort, and upgradingcondensates from all of the proposed de-velopment technologies. The data should beobtained with pilot plants that integrate sev-

eral streams and several control devices andthat simulate commercial-scale conditions.In commercial plants, wastewaters may bemixed and the interactions of contaminantsfrom the different streams will affect treat-ability. Therefore, analyses of separatestreams are not sufficient.

More reliable estimates are needed of thequality and quantity of the mine drainagewater that will be encountered in specificareas. This information would help determinehow the water would have to be treated for

surface discharge, and would allow a com-parison to be made between surface dis-charge and other disposal methods.

Studies of leachates are also needed; inparticular, on their ability to penetrate thelinings of disposal ponds and catchment ba-sins.

Need for Assessing Control Technologies

Although individual methods have beentested successfully on a small scale, the per-formance of an integrated treatment system

has yet to be evaluated with actual effluentstreams. This could be done, for example, bytesting relatively inexpensive pilot-scale sys-tems as part of a retort demonstration pro-gram. These tests would help determine, forexample, if the dissolved organics in retortcondensates can be adequately controlledwith a series of conventional treatment proc-esses. The distribution and control of traceelements could also be assessed.

Need for Cost Inf ormation

According to present estimates, wastewa-ter treatment costs are expected to be only asmall fraction of the total cost of shale oil pro-



—— —— -..


Table 65.–Sampling Schedule Summary for Surface and Ground WaterMonitoring Program at Tract C-b During Development Phase

Surface water Seeps and spr ings Ground water

Alkalinity ., ...Ammonia ., ., ~ .,Arsenic. ... ., ., . ., .,Barium . ., ... .,B e r y l l i u m . . .

B i c a r b o n a t e . . . . . . . , . . , , , , , , . ,B A D . , . , . , . , , . . . . . . , , . . . . .Boron ., ., ., .C o b a l t . . , . . , . , , , . , , , , . . , , . , , . . , , .C o l o r . , . , , . , , , , . , , . . , . . . . . , , , , , ,COD.. . . . . . . . . . . .Col i form, total and fecal ., .,,.,,,,,. .,Conductivity, specific, ,,. ,,Copper. , .,, .,... ,.,.,, . .C y a n i d e . . , . , , . . , , , , , . . , . , , , , , . ,D i s s o l v e d o x y g e n . , , . , .F l u o r i d e . , . , . , .H a r d n e s s , . . , . , , , ’ , ” ’ ” .I r o nL e a d . . . . ’ . . , , . , , , , ‘ ,Lithium. ,.,, ,.,, ,,..,,.Magnesium, ,.,’.. . . . . .

M a n g a n e s e , , , ,Mercury. ., . . . . ., .,Molybdenum .,.., . . . . . . ,,,Nickel. , ,,. ,., . . . , , .Nitrate . . . . . . . . . . . ,,.Nitrogen (Kjeldahl), ,.,,.Odor .,,,Oil and grease, , , .,,, ,,.Phosphate, , ...,, ,,.Pesticides. .,... ,.., ,,.Phenol ,.. ,,,. .,,. .,,,Potassium, ., ., ., ..., ., .,Radiation, alpha .,, ,,, ,,,R a d i a t i o n , b e ta . , . ,Sediment ,.. ,. ,“.Silica ..,,, ,,. ,.., .,,,,Sulfate ,. ,, ....,,

S u l f i d eS u s p e n d e d s o l i d sT u r b i d i t y . . . . , . . , . , , , , , , , , , , , . . ,PA, ,, ., ..,.,.,, ..., ,,,T o t a l d i s s o l v e d s o l i d s . . , , , .Water level .,Stream flow. ,, . . . . . . . ..,’W a t e r t e m p e r a t u r e . , . .D i s s o l v e d o r g a n i c c a r b o n . , . ,

M(Z), Q(O,PC)M(Z)Q(o,PC)M(Z)O(o,PC)

—

Q

M(Z) Q(o,PC) —

M(Z~Q(o,PC) — —

Qo.QQ

M(Z)Q(o,PC)M(Z), Q(o,PC)

— —

QQ

M(Z), Q(o,PC)

M(Z) Q(o,PC)QQ

—

M(Z~Q(o.PC)M(Z), Q(o,PC)

—

QM(Z~Q(o,PC)

—

QM(Z), Q(o,PC)

QQ

M(Z), Q(o,PC)M(Z), Q(o,PC)M(Z), Q(o,PC)

o —

—

M(Z), Q(o,PC)M(Z), Q(o,PC)

—

M(Z) Q(o,PC)M(Z) Q(o,PC)M(Z) Q(o,PC)

o QQ

— —

—QQ

— —

Qs MQ

—

MQQQQQQ

QQQQQQ

—

Q —.QQs s —

—

o —

—

—

M,QQ

—

Q,SA,AM,Qs

Q(Al), SA(Aq)Q(Al), SA(Aq)Q(Al), SA(Aq)( L i s a

A(AI)

—SA(Al), SA(Aq)Q(Al), SA(Aq)

SA(Aq) —

Q(Al), SA(Aq) —

Q(AI)Q(Al), SA(Aq

—

M(AI)Q(Al), SA(AqQ(Al), SA(AqQ(Al), SA(AqQ(Al), SA(Aq)Q(Al), SA(Aq)O(Al), SA(Aq)

Q(Al), SA(Aq)Q(Al), SA(Aq)Q(Al), SA(Aq)Q(Al), SA(Aq)Q(Al), SA(Aq)Q(Al), SA(Aq)

—

Q(Al), SA(Aq) —

SA(Aq)A(Al), SA(Aq)Q(Al), SA(Aq)

SA(Al), SA(AqSA(Al), SA(Aq

— —

Q(Al), SA(Aq) — — —

M,Q(AI)Q(AI)

M E S A —

M, Q(Al), SA(Aq)SA(Al), SA(Aq)

KEY A =AnnUa~y (Z) =Maorgaglng slationson~SA = Semiannually (o) =Aflgagmg stations except major stahonsS= Semimonthly (PC) =F?ceance Creek gaging stationsO =Ouarferiy (Al) =Alluwal wellsM =Monlhly (Aqj =Oeepaquders

SOURCE E R Bales andT L Thoem(eds ) Pollution Con/ro/Gu/dancelor Oti Sha/e Deve/oprnerrl Apperrd/ces /o the l?ewsed L%a/(Reporl, comptiedbyJacobs Envwonmental Orw~onfor Envvonmental Protection Agency C{nclnnah Ohio July 1979 pp C-84-C-85

duction. However, inadequate attention to Lower cost treatment options should alsowater management could seriously impede a be explored. For example, the thermal sludgeproject’s construction and operation. Thus, system could significantly reduce treatmentwater treatment although not costly by itself costs by raising steam directly from processcould ultimately cause substantial cost esca- condensates. Another promising procedurelations. is the removal of dissolved organics from




treated condensates in the cooling water cir-cuit.

Discharging suitably treated wastewaters(especially excess mine water) to surfacestreams should be investigated as a mecha-nism for supplementing the region’s scarce

water resources. Some of the contaminants inthe treated wastes may require special atten-tion, and means to remove them should be ex-plored.

Need for Evaluating the Potential Impacts

of Eff luent Streams

Information is needed on the impacts of thepollutants on the environment. In particular,research is needed on the effect of the leach-ing of spent shale and other solid wastes onsalinity, sediment loading, temperature, nu-

trient loading, and microbial populations of surface waters. This work should address theimpacts that might occur both during theoperation of a facility and after the facility’suseful lifetime.

Specific R&D Needs

Research is needed in the following speci-fic areas:

q

q

q

q

q

q

characterization of the wastewaters, es-pecially for the presence of trace metals

and organic chemicals produced by eachretorting process;determination of the applicability of con-ventional treatment methods to oil shalewastewater and development of newtreatment methods if necessary;determination of the changes in groundwater quality and flows resulting frommine dewatering;development and demonstration of meth-ods to prevent leaching of MIS retorts byground water;studies to simulate and test the percola-

tion of rainfall and snowmelt throughspent and raw shales and native soilsand to assess resulting leachates;standardization of leachate samplingtechniques;

development of reliable models and test-ing them under simulated worst caseconditions, such as massive failure of acontainment structure; andresearch on the restoration of aquifersdisturbed by in situ processing,

Current R&D Programs

Below is a partial listing of the ongoing andproposed R&D programs by the Federal Gov-ernment and the private sector:

Under EPA grants, Colorado State Uni-versity is studying the water qualitywithin the oil shale areas, the leachingcharacteristics of raw and retorted oilshale, and the surface stability and wa-ter movement in and through disposalpiles. Specific objectives include devel-

oping procedures for assessing the quan-tity and quality of surface and subsur-face runoff from solid waste piles.Under an EPA contract, TRW and DRIare studying the environmental impactof oil shale development, including anevaluation of technologies for waste-water control.DOE’s Office of the Environment is as-sessing water quality aspects of theParaho process.DOE and the State of Colorado are devel-oping a program related to water pollu-

tion from MIS retorting.Under EPA contracts, the Monsanto Re-search Corp. is investigating the treat-ment of retort wastewaters and is study-ing the potential of in situ retorting forair and water pollution.The National Bureau of Standards, in co-operation with EPA and other agencies,is developing methods for measuring theenvironmental effects of increased ener-gy production.In its oil shale program managementplan, DOE has proposed to:

—assess the effect of mine and retortbackfilling on ground water quality;—study the leachability of raw and

spent shale and the effect of disposalon surface and ground water quality;

6 3-89B ‘ - 80 - ? :




q

q

—investigate the need for long-termcare of surface disposal areas; and

—design a solid waste disposal plan fora commercial MIS facility.

The National Science Foundation i ssponsoring work to characterize the con-taminants in spent shale and to develop

techniques for managing them.EPA is preparing a pollution controlguidance document for an oil shale in-dustry, that will consider all aspects of surface and ground water quality.

Findings on Water Quality Aspects of


Water quality is of major concern in the oilshale region, especially in regard to the

salinity and sediment levels in the Colorado

River system. Oil shale development has thepotential for water pollution, the extent of which will depend on the processing technol-ogies employed, the scale of operation, thetypes and efficiencies of the pollution controlstrategies used, and the regulations that areimposed.

Surface discharge from point sources isregulated under the Clean Water Act, andground water reinfection standards are beingpromulgated under the Safe Drinking WaterAct. Solid waste disposal methods may besubject to the Toxic Substances Control Actand the Resource Conservation and RecoveryAct. The general regulatory framework istherefore in place, although no technology-based effluent standards have been promul-gated for the industry under the Clean WaterA c t .

Developers are currently planning for zerodischarge to surface streams and to reinjectonly excess mine water. Most wastewaterwill be treated for reuse within the facility;untreatable wastes will be discarded in spentshale piles. The costs of this strategy are low

to moderate, and development should not beimpeded by existing regulations if it is imple-mented.

A variety of treatment devices are avail-able for the above strategy, and many of them

should be well-suited to oil shale processes. Itis less certain that the conventional methodswould be able to treat wastewaters to dis-charge standards because they have not beentested with actual oil shale wastes under con-ditions that approximate commercial produc-tion. Furthermore, no technique has been

demonstrated for managing ground waterleaching of in situ retorts, nor has the ef-ficacy of methods for protecting surface dis-posal piles from leaching been proven. It isnot known to what extent leaching will occur,but if it did, it would degrade the region’swater quality.

Although control of major water pollutantsfrom point sources is not expected to be asevere problem, less is known about controlof trace metals and toxic organic substances.Research is needed to assess the hazards

posed by these pollutants and to developmethods for their management. Other labora-tory-scale and pilot plant R&D should be fo-cused on characterizing the waste streams,determining the suitability of conventionalcontrol technologies, and assessing the fatesof pollutants in the water system. Such workis underway; its continuation is essential toprotecting water quality, both during the op-eration of a plant and after site abandon-ment.

Policy Options forWater Quality Management

For Increasing Available Informati on

Options for increasing the overall level of information regarding pollutants, their ef-fects, or their control include the evolution of existing R&D programs, the improved coordi-nation of R&D work by Federal agencies, in-creasing or redistributing appropriations toagencies to accelerate their surface andground water quality studies, and the pas-sage of new legislation specifically tied toevaluating water quality impacts. For exam-ple, pioneer plants receiving Federal assist-ance could be required to monitor water qual-ity effects, with particular emphasis on non-point discharges. Procedures for implementa-




tion could be similar to those for the existingFederal Prototype Leasing Program. Mecha-nisms for implementing these options are sim-ilar to those discussed in the air quality sec-tion of this chapter.

For Developing and EvaluatingControl Technologies

The Government could expedite the avail-ability of proven controls by accelerating itsefforts to design, develop, and test treatmenttechnologies for oil shale wastewaters. To bemost effective, this work would have to becoordinated with private efforts to developthe oil shale processing methods. This couldbe done under cost-sharing arrangements, in-cluding tests at the sites of retort demonstra-tion projects. (EPA is presently conducting a

program for retorting wastewaters under acontract with Monsanto Research Corp. )

For Developing Regulatory Procedures

The present approach could be followed inwhich regulations evolve as the industry andits control technologies develop, An approachcould also be used in which standards wouldbe set that would not change for a period of say, 10 years, after which they could be ad-

justed to reflect the experience of the indus-try. This would remove most of the uncertain-

ty about environmental regulations that isnow deterring developer participation. How-ever, the standards would have to be careful-ly established to assure that they were bothattainable at reasonable cost and adequate toprotect the environment. Mechanisms for im-

plementing improved regulation of nonpointdischarges include extension and modifica-tion of the Surface Mining Control and Recla-mation Act for oil shale, special controls reg-ulating nonpoint discharges under the CleanWater Act, or applying the Resource Conser-vation and Recovery Act waste disposalstandards to low-grade/high-volume mate-rials.

For Ensuring the Long-Term Management of

Waste Disposal Sites and Underground Retorts

These areas may require monitoring formany years after the projects are completed.Long-term management could be regulatedunder the Resource Conservation and Recov-ery Act, which allows EPA to set standardsfor the management of hazardous materials,including mining and processing wastes. Nosuch action has yet been taken by EPA, butCongress could direct it to do so. Congresscould also require the developers to guaran-tee such management by incorporating ap-propriate provisions in any bill encouragingoil shale development.

Safety and HealthIntroduction q

Anticipating occupational and environmen- q

tal health and safety hazards is an importantconsideration in the development of an oil q

shale industry. Anticipation and planning, es-pecially in the early phases of the industry, q

should guide efforts to reduce health andsafety risks and costs to society. To bring at- q

tention to known hazards, and to point out po-tential ones, this section covers the following q

subjects: q

the health and safety hazards associ-ated with oil shale operations;the environmental risks if contaminatedair and water are released;the applicable Federal health and safetylaws, standards, and regulations;the control and mitigation methods thatcould be applied to these risks;the issues regarding the coordination of

monitoring and education efforts;the R&D needs; andthe policy options.



316 “An Assessment of Oil Shale Technologies

Safety and Health Hazards

Occupational Hazards

Workers will be exposed to a number of oc-cupational safety and health hazards duringthe construction and operation of an oil shale

facility. Many of these hazards—such asrockfalls, explosions and fires, dust, noise,and contact with organic feedstocks and re-fined products —will be similar to those asso-ciated with hard-rock mining, mineral proc-essing, and the refining of conventional petro-leum. However, due to the physical and chem-ical characteristics of shale and shale oil, thetypes of development technologies to be em-ployed, and the scale of operations, oil shaleworkers might be exposed to unique hazards.They will be discussed as follows: safety haz-ards that might result in disabling or fatal ac-cidents; and health hazards stemming fromhigh noise levels, contact with irritant andasphyxiant gases and liquids, contact withlikely carcinogens and mutagens, and the in-halation of fibrogenic dust.

SAFETY HAZARDS

Mining.-The similarity of hard-rock min-ing to underground or open pit oil shale min-ing makes it possible to project likely occupa-tional safety risks. During mining, accidentsresult from rock and roof falls, explosions

and fires, bumps and falls, electrocution,heavy mining equipment, and vehicular traf-fic. Hard-rock mining is a high-risk occupa-tion; fatalities are five times more frequent inthe mining and quarrying industry than inmanufacturing. The frequency of disablinginjuries from underground mining (excludingthe coal industry) is two and a half timeshigher than from manufacturing. 53 M i n i n gcoal is even more dangerous.

While most hazards to oil shale minerswould be similar to those experienced byhard-rock workers, some are unique to oil

shale. A number of the oil shale facilities areplanning to use MIS processes in which partof the deposit is mined out and the remainderis then rubbled and burned underground. Thehigh temperatures and fires involved in MIS

may expose miners to risks that are not ex-perienced in other underground mining ac-tivities. The hazard of mine flooding is notunique to oil shale, nor would it be encoun-tered in all oil shale mines. However, it couldbe severe in mines that are developed withinground water areas. While the mining zoneswould be dewatered before mining could be-gin, there could be flooding if the pumpsfailed.

Retorting and refining.—Potential hazardsassociated with the retorting and upgradingof shale oil include explosions, fire and heat,bumps and falls, electrocution, and handlinghot liquids. However, the degree of risk forworkers involved in the processing of oilshale and its derivatives would not be ex-pected to be so high as in mining.

The processes involved in retorting and up-grading (e.g., materials handling, crushing,solids heating and cooling, waste disposal,and the handling of hot and hazardous liq-uids) are generally similar to those used inother operations such as mineral processing(e.g., limestone calcining, roasting of taconiteand copper ores, and leaching) and conven-tional petroleum refining. Although no com-parative study has been undertaken, thereare few unique features associated with re-torting, upgrading, and refining that would justify expecting higher worker safety risks

than those in similar industries.HEALTH HAZARDS

Mining. —During oil shale mining, as dis-cussed in the section of this chapter on airquality, hazardous substances including sili-ca dust will be generated by blasting anddrilling. In addition, blasting, raw shale han-dling and disposal, and other activities at theminesite will produce fugitive dust. Silica-containing dusts are noteworthy becausethey have been the single greatest health haz-ard throughout the history of underground

mining. Silica is highly toxic to alveolarmacrophages—’’scavenger” cells that moveabout on the inside of the lung and engulf andremove foreign particles that might damagethe lung. Silicosis, “shalosis,” and chronic




bronchitis* are among the diseases that mayresult from the inhalation of oil shale dust.

A survey conducted by the U.S. PublicHealth Service (USPHS) between 1958 and1961 found excessive dust levels in 6 out of 67inspected mines. 54 The chest X-rays of 14,076

miners employed in 50 hard-rock mines indi-cated that 3.4 percent had silicosis. ss * *These measurements were made before mod-ern mine hygiene practices were required bythe relatively recent occupational safety andhealth regulations and a more recent studyundertaken by the Mining Safety and HealthAdministration showed marked improve-ments in mine dust levels. This study exam-ined 22 hard-rock mines, 8 of which were in-cluded in the USPHS study, and found none of them in violation of the dust standards, 56)** *

Although few studies have been under-taken on the direct association between oilshale mining in the United States and the in-cidence of lung disease, there are studies onthe prevalence of lung disease in oil shaleminers in Estonia. Estonia mined 25 milliontons of oil shale in 1973, and has had oil shaleoperations for several decades. While the re-sults of the Estonian studies are more intrigu-ing than convincing, they do suggest an asso-ciation between oil shale mining and pulmo-nary fibrosis—an increase in the amount of fibrous material in the lung. One study also

indicated that chronic bronchitis was 2 to 2-1/2times more prevalent in 189 Estonian oil shaleminers than in a similarly aged control popu-lation.” (A similar degree of excess bronchitishas been observed in coal miners in the

*Sili~osis is a ~is~blin~ fibrotic disease of the lungs causedby inhalation of silica dust and marked by shortness of breath.“Shalosis” is a disease of the lungs and is related to specific ex-posures of oil shale mine dust. It resembles silicosis: its ex-istence as a specific disease remains to be proved. Inflammationof the bronchial tubes, or anv part of them, is known as bron-chitis.

**The 3.4 percent is probably a low estimate; generally sickindividuals who have left the work force or moved for health

and other reasons are under-represented in such surveys. If such individuals had been examined the incidence of silicosismight have been higher.

***This study is expected to be released in the near futurealong with a companion study undertaken by the National Insti-tute of Occupational Health and Safety which examines thehealth status of miners from 22 hardrock mines.

United States and England,58 and in goldminers in South Africa. 59)

In another study, postmortem examinationof 30 Estonian oil shale workers who died of accidents and various other diseases 60 foundthat all had pulmonary fibrosis and one-

fourth displayed classic silicotic nodules. * Anexamination of 1,000 Estonian oil shaleworkers failed to reveal any cases of pneumo-coniosis, a pulmonary disease caused by in-haled dusts. However, the workers had beeninvolved in the industry for only 5 to 14 years.Twenty years of exposure are usually re-quired for the symptoms of the disease to bedetected by a chest X-ray. Because Estonianindustrial hygiene standards are not known,the Estonian studies can only suggest an asso-ciation between oil shale mining and lung dis-ease. The Estonian studies provide no infor-

mation about the risk levels to be expected inmines maintained under U.S. health and safe-ty standards.

Studies of occupational diseases among oilshale miners in the United States have beenlimited because relatively few people haveworked in the industry. A study was under-taken involving miners from the oil shale re-search center at Anvil Points, Colo., whichhas operated intermittently s ince 1946.Eighty-six workers were identified, but only39 of them had been exposed to oil shale for

one or more years. Those 39 were comparedwith 26 other workers from the facility (e.g.,office workers, administrators) who had notbeen directly involved in the mining opera-tions. Results showed a twofold higher inci-dence of pneumoconiosis in the oil-shale ex-posed population. However, the interpreta-tion of these results is complicated by the factthat most of the oil shale miners had previous-ly worked in uranium-vanadium mines or mill-ing operations which are known to be causesof pneumoconiosis.61 Further evaluation of these populations was not performed because

of the age of the workers, their varying levelsof exposure, and their limited experience inoil shale mining.

*Silicotic nodules are small lumps on the surface of the lungformed as a response to deposition of silica specks.




A separate study of employees at the samefacility between 1974 and 1978 found no ad-verse health effects.62 An examination of thedeath certificates of 167 oil shale workers un-dertaken by the National Institute for Occu-pational Safety and Health (NIOSH) failed toreveal any association between oil shale ex-posure and respiratory diseases.63 Because of the limited number of workers studied, theirrelatively short exposures to oil shale mining,and in some cases their exposures to otherkinds of mining, no firm conclusions can bedrawn from these studies.

Some animal studies have demonstratedrelationships between oil shale exposure andrespiratory diseases, but the results conflictwith those of other experiments, making itdifficult to draw conclusions. One study indi-cated that Estonian oil shale had a weak fi-

brogenic* action in rats; both oil shale andspent shale ash produced pulmonary fibrosisin white rats after the dusts were depositedinto the trachea.64 Another study reportedpulmonary effects when Syrian hamsterswere exposed via intratracheal administra-tion or inhalation to finely ground oil shaledust and retorted shales.65 66 Increased alveo-lar microphage activity was also noted. Thesame study found that retorted shale dustwas associated with inflammation, and fre-quently caused increases in the fibrous mate-rial in the lung (fibrosis] and excessive

growth of cells that line the lung cavities (epi-thelial hyperplasia). However, a 2-year studywith rats, which evaluated the effects of rawor spent shale dust instilled intratracheally inmultiple exposures over an 8-month period,found essentially no pulmonary fibrosis. Theinvestigator considered the results to be neg-ative.67

Another area of concern is the possible ex-posure to carcinogens (e.g., polycyclic aro-matic hydrocarbons—PAHs) and trace ele-ments that might be produced during mining.

The NIOSH mortality study mentioned earli-er found that the percentage of oil shaleworkers who had died from colon and respi-

*A fibrogenic substance is conducive to the generation of fibrous materials in the respiratory tract.

ratory cancers was greater than the percent-age in the white male populations of Coloradoand Utah.68 Whether oil shale exposure con-tributed to the higher incidence is unclear,and the incidence rate among miners was nothigher than that of the white male populationin the United States.

A cancer morbidity study undertaken bythe Rocky Mountain Center for Occupationaland Environmental Health found more cyto-logical atypia* in the sputum and urine of oilshale miners than among controls, but no as-sociation was found between exposure andskin diseases. These data will be furtherstudied to identify any associations betweensuch abnormalities and occupational ex-posures. Animal studies undertaken to datehave not demonstrated that oil shale dust iscarcinogenic.

A third potential health hazard to oil shaleminers is exposure to excessive noise levels,particularly in underground operations car-ried out in relatively confined spaces. Noisearises from numerous sources such as boost-er fans, pneumatic drills, blasting, conveyors,and mining machines. The Bureau of Minesstudied 19 pieces of diesel-powered miningequipment and found only 2 had noise levelsbelow the current standards (90 decibels),and one of these exceeded the standard in anunderground environment. One study esti-

mated that of the 37,000 workers employed in650 metal and nonmetal mines, approximate-ly 14,000 (38 percent) were exposed to diesel-powered equipment noise levels greater thanthe standard.** Of these, 2,430 (17 percent)were overexposed on a time-weighted-aver-age basis.69 Evidence indicates exposure tonoise from a large number of mining ma-chines would produce hearing loss if the ex-posures exceeded 8 hours per day. 70 Highershort-term noise exposures may occur during

*Cytological atypia are premalignant cell types observed in

the examination of the body fluids.**A major health issue is the long-term effect of diesel smokeexposure in underground mining environments. The NationalAcademy of Sciences is conducting a study in this area whichwill be released in the near future. The health implications of diesel equipment used in underground oil shale mines is un-known at this time.




blasting. High noise levels are a potential haz-ard not only to hearing, but to the cardiovas-cular and nervous systems as well, and posea safety hazard.

Retorting and refining.—Retorting oilshale at high temperatures forms PAH-con-

taining carcinogens of which 3,4-benzo(a)py-rene (BaP) is the most studied. PAHs are amajor potential health hazard for retortingand refining workers in the oil shale industrybecause of their carcinogenicity. The prob-lems that might be encountered in oil shale re-fining are similar to those of conventional oilrefineries, where liquids and gases are trans-ported in airtight pipes under strict mainte-nance to detect and repair leaks.

Crude oil contains an enormous variety of potentially hazardous compounds, Even more

are produced during refining. Work crews in-volved in inspection, repair, and maintenanceare the most likely to be exposed to PAHs.Other hazardous substances found in crudeoil include chlorine, sulfur, nitrogen, andheavy metals (e.g., vanadium, arsenic, nickel,and cobalt). Toxic contaminants evolved dur-ing the refining process include H2S, hydro-gen chloride, hydrochloric acid, SO2, sulfuricacid, methane, ethane, methanol, nitric acid,NOX, mercaptans, CO, and benzene.

The high rate of cancer of the scrotumfound in 19th century chimney sweeps andmulespinners* is of historical interest be-cause it indicates that long exposure of scro-tal skin to PAH-containing oils and soots cancause cancer. In addition to scrotal cancer,cancers of the skin, lung, and stomach havealso been observed after latent periods of upto 20 years following exposure to PAH-con-taining substances. While the known carcino-gen BaP was identified in Scottish shale oil,71

a study found only a low incidence rate (lessthan 0.1 percent per year) of skin cancer for5,000 Scottish oil shale workers between

1900 and 1922.

72

*Mulespinners were workers who lubricated the “mules”(spindles) in the Scottish spinning and weaving industry. Shale-derived lubricants were commonly used in this industry.

Refined Scottish shale oils were known tobe carcinogenic, but the disease was largelypreventable by personal cleanliness. It is be-lieved that the disease occurred because theworkers wore the same clothes on the job dayafter day. The clothing was rarely, if ever,

laundered, and eventually it became impreg-nated with shale oil. Contact between thesoaked clothing and the areas where cancersoccurred was nearly continuous during eachworking day. This factor, coupled with thefact that daily bathing was rare, undoubtedlycontributed to the high incidence of cancer.

Two Estonian studies have shown an asso-ciation between oil shale processing andcancer. A study of 2,003 Estonian oil shaleworkers with a total of 21,495 person-yearsexposure during the period between 1959and 1975 found a significant excess of skincancer (fivefold for females and threefold formales). 73 An unusually high incidence of stomach and lung cancer was found amongpersons in the rural areas of Estonia wherethe oil shale industry is located. ” There is noinformation on the working conditions in Esto-nian oil shale operations; nor are dataavailable on the ambient concentrations of shale-derived pollutants in the vicinity of theplants. It is therefore impossible to relate theEstonian experience to problems that mightbe encountered in the United States.

Evaluating chemical carcinogenicity in ani-mal experiments is an accepted method forpredicting carcinogenicity in humans. Inves-tigations that tested the carcinogenicity of oilshale and shale oil in laboratory animals areshown in table 66. A conclusion that can bedrawn from these studies is that shale oil is acarcinogen when painted on animal skins.The experiment conducted by Biology Re-search Consultants (ref. 80 in table 66), inwhich hairless mice were bedded in raw orspent oil shale, found no carcinogenic hazard.However, this study did not examine the oil

shale extracts (e.g., shale oil tar and coke)with which carcinogenicity has been associ-ated.

Both the Kettering Laboratory (ref. 79) andEppley Institute (ref. 81) studies conclusively




Table 66.–Animal Studies on the Carcinogenicity of Oil Shale and Shale Oil

OrgansNature of study Ref a Materials tested examined Tumerous animals/animals exposed

Skin painting study of mice, rats, and rabbits

Skin painting of mice



Skin painting of mice (Kettering study)

Exposure to shale dust (Biology ResearchConsultants)

Skin painting of mice (Eppley study)

Intratrachael Instillation in hamsters (Eppleystudy)

75

76

77

78

79

79

79

79

Scottish shale OilS “green 011’

‘‘blue oil ’‘‘unfinished gas oil’‘‘Iubricatmg oil

CHCI 3extract of Scottish oil shaleScottish shale oil

Shale oil

Shale oilComposite petroleum control

Crude shale oilHydrotreated oilBaP control

Oil shale powderOil shale powderSpent shale powderSpent shale powderPowdered corn cobs (control)Powdered corn cobs (control)

Benzene extract of shale oil coke

TOSCO II effluentBenzene extract of raw shale oilBenzene extract of spent shaleBenzene controlNone (control)

Raw oil shaleSpent shaleShale 011 cokeTOSCO II effluentBaP controlSaline controlNone (control)

skinskinskinskin

skinskin

skin

skinskin

skinskinskin

skinlungsskinlungsskin

lungs

skin

skinskinskinskinskin

(b)(b)(b)(b)(b)(b)(b)

9/1001 2/100

1/503/50

0/206/10

1,284/10,000

(35%-90% tumerous)(0%-8% tumerous)

39/405/37

27/27

0/122/240/121 /240/1 26/24

48/50

1 /500/506/500/500/100

0/1000/1000/1000/ 100

27/1OO0/ 1000/200

aSee reference list bResplratory system

SOURCE Wllham Rom et al OcCuPdllOflallEflVlfOflmeflldl Healfh and .SaletY Aspecfs of a CO~rrJerCW 0// Wale lmlWy prePared for OTA by Rocky Mountain Center for Occupational and EnwronmentalHealth Unwerslty of Utah Oecember 1979

show that crude shale oil, shale oil tars, andshale coke have carcinogenic properties,which may be related to their BaP content.The second Eppley study (ref. 82), which in-vestigated respiratory system carcinogeni-city, found no effect. This contrasts to theskin exposure experiments. Whether or notoil shale and its derivatives are less of athreat to the respiratory system than to theskin deserves further study.

Although BaP may not be the only carcino-gen in shale oil and its products, it is probablythe most potent. The study summarized intable 67 shows that hydrotreating shale oil

Table 67.–Benzo(a)pyrene Content of Oil Shale andIts Products and of Other Energy Materials

Substance BaP concentration, p/ba

Raw oil shale ., . ., . . . 14T O S C O I I r e t o r t e d s h a l e , . , . , 28TOSCO II atmospheric effluent . . ., 140T O S C O I I r e t o r t c o k e . 129Raw shale oi l from Colorado, ., ., ., 3,200Hydrotreated shale 011 (0.25% N2) ., 800Hydrotreated shale 011 (0 ,05% N 2) ., 690Coal ., ., ., 4,000Libyan crude 011 ., 1,320

A s p h a l t f r o m c o n v e n t i o n a l c r u d e 10,000-100,000

aParis per bllllon

SOURCE R M Coomes Carcmogenlc Tesflng of 011 Shale Materials TweMh 0// Sha/e Syrr-poswm Proceedings Golden Colo The Colorado School o! Mines Press November1979




significantly reduces its BaP content,’{ Such areduction should be reflected in a lessening of its carcinogenicity, This predicted effect of hydrotreating was confirmed by the animaltests of the Kettering experiment (ref. 79,table 66).

The Estonian epidemiological studies andthe animal studies show that crude shale oil,shale oil tars, and shale coke are all car-cinogenic. Most of the studies to date suggestthat carcinogenicity is restricted to the skin.Occupational skin diseases from exposure tocertain industrial oils have long been a prob-lem, as was seen in the case of the scrotalcancer among chimney sweeps, One studyshowed that the effects of oil contact with theskin range from acute inflammation to kera-tosis (pitch warts which are regarded as apremalignant skin change.)84 Studies of oilshale retorting workers in the United Statesin the early 1950’s did not reveal any prob-lems with occupational skin disease, butworkers were exposed for a short time only. 85

A synergistic relationship has been foundbetween the ultraviolet radiation in sunlightand coal-tar pitch volatiles in causing skindiseases. A similar synergism might cause oc-cupational skin diseases in oil shale workerson the Colorado plateau, where ultravioletradiation levels are higher than at lower ele-vations.

Refining shale oil will be similar to otherrefining operations. Available epidemiologi-cal studies do not lead to clear-cut conclu-sions about relationships between working inrefineries and cancer. A retrospective mor-tality study sponsored by the American Petro-leum Institute that covered 17 U.S. oil refin-eries and over 20,000 workers was reportedin 1974,86) The study group included everyworker employed in the refineries for at leastone year between January 1, 1962, and De-cember 31, 1971. A 94-percent followup was

obtained. There were 1,165 deaths; 1,145death certificates were obtained. The stand-ardized mortality ratio (SMR) for all causes of death among refinery workers was 69.1 com-pared with the base rate of 100 for the U.S.male population. The lower death rate among

refinery workers was attributed to the“healthy worker effect;” i.e., employed work-ers are healthier on the average than the gen-eral population. Respiratory cancer in-creased with increasing exposure to aro-matic HC, but was still lower than found in

the general population (SMR of 79.9).On the other hand, two epidemiological

studies published by Canadian investigatorsshowed an increased cancer risk for refineryworkers. In a group of 15,032 male employeeswho worked for the Imperial Oil Co. between1964 and 1973, there were 1,511 deaths.Eighty percent were ascribed to circulatorysystem disease and to malignant abnormalgrowths (neoplasm). Mortality from all ma-lignant neoplasms in the exposed group wasgreater than in the nonexposed group. Can-cers of the digestive and the respiratory sys-

tems increased with duration of employ-ment.

87

A further study examined 1,205 men whohad been employed for over 5 years by ShellOil Canada in East Montreal,88{ Their mortali-ty rate was compared with death rates forthe Province of Quebec. The study group wasrelatively small, and only 108 deaths wereobserved. An increased incidence of cancerof the digestive system (SMR of 117) was notstatistically significant, and there was noevidence of excessive lung cancer (SMR of

35.4). An excess of brain cancer was foundamong those who had been exposed less than20 years, but it caused only three of thedeaths.

Societal Hazards

Air pollutants include particulate, gases,and trace-metal vapors. Particulate whichcontain absorbed PAH can be carcinogenic.The sulfur and nitrogen-containing emissionsare respiratory irritants. Among the sulfur-containing pollutants, the effects of acid

sulfates, sulfuric acid, and S02 dissolved inaerosols are the best documented. All threeare irritants and can make breathing diffi-cult. In addition, some epidemiological evi-dence relates chronic bronchitis and respira-tory diseases to SO2 and to particulate con-



. — —— —— ————. .


centrations in the air. Oxides of sulfur and ni-trogen, transported from industrial areas,may cause acidic rainfall that may reduce theproductivity of forest vegetation and kill fishby increasing the acidity of lakes andstreams. NOX oxides can react with HC in theatmosphere to produce O3, photochemicalsmog, and acid rain. Airborne NH3 may causeheadaches, sore throats, eye irritations,coughing, and nausea in humans.

Among the trace elements that may beemitted, mercury, lead, cadmium, arsenic,and selenium are considered to be potentialair and water pollutants. Arsenic is a car-cinogen, which when inhaled or ingested inlarge amounts, may also cause peripheralvascular disease and neuropathy. * Mercuryis a special problem because its vapors canpollute the air and earth many miles from the

plantsite. It can also contaminate surfacestreams and ground water aquifers. It canenter the food chain through the actions of micro-organisms, and can also pose a risk of irreversible neurological damage to humanswho eat fish that have been contaminated bymercury in streams.

Leachates from aboveground disposalareas and burned-out in situ retorts also posepotential problems. PAHs, salts, and metalsmay dissolve in surface streams and groundwater and infiltrate public drinking water

supplies. Water-soluble salts in spent shalecontain as much as 40 percent of the totalbenzene-soluble organic matter. All of thesematerials can be dissolved in water and dis-persed through soils. The exact nature of thethreat posed by these materials to humanhealth is unknown since, for example, PAHsare found throughout nature. However, thePAH content of spent shale leachates (up to100 to 1,000 times higher than is found in nor-mal ground or surface water) is a matter forconcern. Fluoride, if released in excessiveamounts in contaminated water, may cause

fluorosis (reduced bone strength and debilita-tion) and mottle tooth enamel.

*Neuropathy refers to pathological changes in theperipheral nervous system.

The severity of these hazards will dependon many factors. Many of the risks could bevery small if they are anticipated, and if ap-propriate control strategies are designed andfollowed. If caution is not employed, or if there are catastrophic failures in the controlsystems during or after plant operation, dam-age could be severe and long lasting.

Summary of Hazards and Their Severity

The safety and health hazards that mightbe associated with oil shale mining, retorting,and refining are identified in figure 62. Theyare ranked according to their known poten-tial to cause injury or death. As shown, min-ing has the highest potential for accidents,due to risks from rockfalls, explosions, mov-ing equipment, and general working condi-

tions. There were two fatalities during themining of over 2 million tons of shale and theproduction of over 500,000 bbl of shale oil.The accident rate has been one-fifth that forall mining, and much lower than that for coalmining. However, this record was achieved insmall-scale experimental mines that em-ployed, for the most part, experienced hard-rock miners. Whether safety risks will in-crease or decrease as mining activities areexpanded cannot be predicted. Risks mightincrease as the work force expands to includeinexperienced miners and as large, rapidly

moving mining equipment is used. On theother hand, the large mines proposed for oilshale plants may reduce risks because of theadditional room in which to maneuver ma-chines.

Fires and explosions are also identified asa hazard in mining. Although no severe fireshave occurred to date, laboratory studies in-dicate that airborne shale dust can propagatea methane explosion. Methane has beenfound in low concentrations in some oil shaledeposits, especially those in the saline zone of the Piceance basin. Oil shale dust is, how-ever, far less explosive than coal dust.

Dust is a major health hazard. Its effect onthe respiratory system is well-known. Exces-sive noise is also a recognized hazard. Cancer




Figure 62.—Summary of Occupational Hazards Associated With Oil Shale Development

Relat ive Rank ing

Occupat ional R isks Potential Effect M in ing

Acc idents Injury or death

Retor t ing Ref in ing

A

mnnFires and

explos ionsInjury or death

Hearing loss or

neuro logica l damage

Lung disease

Noise

D u s t

D u s t D e r m a t i t i s

v

Chemical

E x p o s u r eCancer

I IChemicalE x p o s u r e

Dermat i t is[ 1 I

I I I

Chem ic a l

E x p o s u r ePo is on ing

4.

Chemical

E x p o s u r eIrritant gases

KEY:

- Higher level of risk

D Medium level of nsk

a Lower level of nsk





from oil shale mining has not been identifiedas a major hazard. Although the carcinoge-nicity of oil shale dusts and crude shale oilhas been demonstrated by some invesigators,insufficient information and the conflictingresults of other studies prevent a determina-

tion of the severity of the risk. However, theincidence of diseases in other industries in-dicates that exposure to these materialscould be hazardous. Worker health should becarefully monitored if health damage is to beavoided, and prevention techniques im-proved, as the oil shale industry develops.

Retorting is regarded as having mediumrisks in all areas. This ranking primarilyreflects the low level of knowledge aboutretorting and its health and safety effects.However, the large variety of substances thatwill be encountered in retorting (from rawshale dust to trace-element emissions) maypose as yet undetected health hazards. Of special concern is the possibility of car-cinogens in shale oil and its derivatives.Possible synergisms in MIS operations (whichcombine mining with retorting) could in-crease the level of risk.

In contrast, shale oil refining is regardedas posing no special hazards in many areasand only moderate risks in the others. This isbecause most of the problems that will beassociated with shale oil processing should

be similar to those experienced in convention-al petroleum refining.

Federal Laws, Standards,

and Regulations

This section discusses the Federal lawsand standards applicable to oil shale occupa-tional health and safety, and some aspects of environmental health. Other laws which gov-ern specific impacts on air, water, and landare discussed elsewhere in this chapter.

Occupat ional Safet y and Healt h Act of 1970

This Act was passed to assure every work-ing person “safe and healthful working condi-tions;” it established the Occupational Safety

and Health Administration (OSHA) under theDepartment of Labor. Most OSHA standardspromulgated under the Act pertain to safety,e.g., walking and working surfaces, fire pro-tection, and personal protective equipment.In addition, health standards have been pro-

mulgated to limit worker exposure to hazard-ous chemicals and physical hazards, such asnoise and crystalline silica.

OSHA recently published a policy for theidentification, classification, and regulationof toxic substances posing occupational car-cinogenic risks. Under this policy, a sub-stance shown to cause cancer in two animalstudies can be classified as a “category I“carcinogen and regulated to control workerexposure to the lowest feasible levels.Whether any two of the positive carcinoge-

nicity results mentioned in table 66 are suffi-cient to cause a category I classificationawaits NIOSH review.

The Federal Mine Safety and Health

Amendments of 1977 (FMSHA)

These amendments apply to all metal andnonmetal mines. They prescribe health andsafety standards “for the purpose of the pro-tection of life, the promotion of health andsafety, and the prevention of accidents. ”FMSHA established the Mine Safety and

Health Administration (MSHA) in the Depart-ment of Labor, and directed the Secretary of Labor to develop, promulgate, revise, and en-force health and safety standards for work-ers engaged in underground and surface min-eral mining, related operations, and prepara-tion and milling. In addition, each mine oper-ator is to have a mandatory health and safetytraining program. FMSHA also authorizedthe Secretary of Labor to require frequent in-spections and investigations of mines: at leastfour times a year in the case of undergroundmines, and at least twice a year in surface

mines. Records of mine accidents and expo-sures to toxic substances are to be main-tained by mine operators.

Section 101(a) of FMSHA requires thatstandards on toxic material or harmful physi-




cal agents be set to “most adequately assure. . . (on the basis of the best availableevidence) that no miner will suffer materialimpairment of health or functional capacity(even if such miner has regular exposure tothe hazards dealt with by such standard forthe period of his working life). ” NIOSH hasthe responsibility to determine when the ma-terial or agents are toxic at the concentra-tions found in the mine.

Warning labels, protective equipment, andcontrol procedures are to be employed “toassure the maximum protection of miners. ”Medical examinations and tests, where ap-propriate, are to be provided at the opera-tor’s expense to determine whether a miner’shealth is adversely affected by exposures.

Memorandum of Understanding Between

OSHA and MSHA

Because of the overlapping jurisdiction be-tween OSHA and MSHA, an interagencyagreement was executed on March 29, 1979,to allocate the responsibilities for miningsafety between the two agencies. The agree-ment established that as a general policy, un-safe and unhealthful working conditions onminesites and in milling operations wouldcome under the jurisdiction of MSHA. Wherethese do not apply, or where no MSHA stand-ards exist for particular working conditions,

OSHA and its regulations would apply.Where uncertainties arise about jurisdiction,the appropriate MSHA District Manager andOSHA Regional Administrator (or the respec-tive State designees in those States with ap-proved mine-safety plans) shall attempt toresolve the matter. If they cannot do so, theissue will be referred to the national officesof the two agencies. If the issue cannot beresolved at that level, it will be referred to theSecretary of Labor for a final ruling.

The Toxic Substances Control Act

of 1976 (TSCA)

TSCA covers the manufacturing, process-ing, distribution, use, and disposal of chemi-cal substances in commerce. However, it

should be noted that if specific operations areregulated by other laws (e.g., Clean Air Act,Clean Water Act) their authority would prob-ably take precedence over regulations pro-mulgated under TSCA. TSCA regulationswould be promulgated only when regulationsunder the other Acts failed to remove a haz-ard. Also, chemicals that are not sold in com-merce are considered “R&D substances” andare exempt from some of the requirementsunder the Act.

Under TSCA, EPA must require industry togive notice 90 days prior to beginning themanufacture of any new substance that is notlisted on EPA’s Inventory of Existing Chem-icals. EPA can also require industry to testthe toxicity of chemicals already in commercethat may pose an unreasonable risk to humanhealth or the environment. Shale oil and its

refined products are included in the inven-tory list and therefore are not subject to pre-market regulations, but testing can be re-quired under other sections of TSCA if theAdministrator of EPA determines such sub-stances may pose an “unreasonable risk” tohealth or the environment.

Control and Mit igat ion Methods

Some of the oil shale’s health and safetyhazards can be reduced by using the pollutioncontrol technologies described elsewhere in

this chapter. Others will require specific in-dustrial hygiene controls. The three majorcontrol methods are:

q

q

q

worker training programs, including anintensive training program for new work-ers and refresher courses for workersthroughout their careers;the design and maintenance of safeworking environments; andhealth monitoring programs, includingexaminations and recordkeeping.

Initial training programs and refreshercourses are required by OSHA and MSHA.These agencies also promulgate standardsfor working environments. Health inspectionsare sometimes included in OSHA/MSHA rou-tine inspections, and special health inspec-




tions can be made if the agencies determinethat a serious health hazard exists. At pres-ent, exchange of worker-health informationamong companies is not required, althoughsome companies, especially in the coal miningindustry, have organized such programs toprovide data regarding occurrences of blacklung among miners who change jobs withinthe industry.

Summary of Issues and R&D Needs

Issues

The effect of the scale of operation of fu-ture oil shale facilities on worker safety isstill unknown. As indicated previously, the oilshale industry to date has a good safety rec-ord. It is not clear whether or not this recordcan be maintained in large facilities and in alarge industry.

The protection of worker health and safetyin an industry that is developing with greatspeed is also a major concern. To prevent un-due risks, it is important that the health haz-ards of oil shale and its related materials beidentified, and that appropriate measures beemployed for their control.

R&D Needs

Research is needed in the following areas

in order to improve the understanding of thepotential effects of oil shale development onthe workers and on the public:

q

q

additional data gathering and analysisare needed on the health effects of par-ticulate generated during oil shale min-ing and processing. Studies should in-clude: a) identification of absorbedPAHs; b) determination of particulatesize distributions; c) evaluation of therisk of fibrogenicity and carcinogenicity;d) ranking of the unit operations in termsof their degree of risk; and e) determina-tion of their health effects on nearbycommunities with respect to, for exam-ple, chronic bronchitis;characterization of worker exposure toPAHs, other chemical hazards, and

q

q

q

q

A

physical agents such as ionizing radia-tion, heat, and noise stress;evaluation of devices for controllingworker exposure, such as hermeticseals, ventilation equipment, and per-sonal protective equipment;environmental monitoring to determineambient levels of PAHs, trace elements,and other potentially harmful sub-stances;determination of the pathways followedby PAHs, salts, toxic trace elements, andother substances; andadditional controlled animal experi-ments to determine the toxicity, muta-genicity, and other characteristics of theraw materials and products encoun-tered in oil shale processing, and evalua-tion of their synergistic interrelation-ships.

mechanism that would aid in all of thesestudies, and in other ones that evolve as theindustry is created, would be an oil shalehealth registry or central repository for thehealth records of oil shale workers. Thesedata would aid in the statistical work neededto detect extraordinary health trends amongthe workers. These, in turn, could be relatedto working conditions and used to improvepreventive and protective measures.

Current R&D ProgramsThe following is a partial listing of the

health and safety R&D projects now under-way both in the private sector and by Govern-ment agencies.

q

q

q

Tosco is studying the fire and explosionpotential of oil shale mining and process-ing.The American Petroleum Institute isstudying the effects of oil shale on fe-tuses by exposing pregnant rats to rawand spent shale dust and shale oil.EPA is performing or contracting workthrough 10 of its laboratories to supportthe regulatory goals of the agency and toensure that an oil shale industry will bedeveloped in an environmentally accept-




able manner. The EPA Cincinnati labo-ratory is studying the handling of rawshale and the disposal of spent shale. Airpollution, wastewater characteristics,and water treatment methods are alsobeing studied and evaluated. The Las

Vegas laboratory is attempting to designand implement an optimal wastewatertreatment system. The Athens, Ga., labo-ratory is characterizing retort effluentsand developing instrumentation and con-trol systems. Biological and health ef-fects studies are being conducted at theGulf Breeze and Duluth laboratories;these are designed to determine path-ways by which HC enters the food chain,to characterize the aquatic life in the oilshale region before oil shale develop-ment occurs, and to determine the car-

cinogenic, mutagenic, and fetal effectsof oil shale and its derivatives andwastes. EPA is also preparing pollutioncontrol guidance documents for the oilshale industry.

DOE is conducting source characteriza-tion studies to determine emissions prop-erties and their health effects. Includedis an extensive program for sampling re-tort liquids, solid products, and wastes.Streams to be sampled include mine ventgases, mine air, retort water, raw andretorted shale, process water, and par-

ticulate, Biological testing will be con-ducted to include short- and long-termanimal exposure tests and medical andepidemiological studies of oil shale work-ers.

q The U.S. Department of Agriculture issponsoring work related to the socialconsequences of oil shale developmentand the revegetation of solid waste dis-posal areas.

q The National Science Foundation issponsoring projects to characterize thecontaminants in spent shale and to de-

velop techniques for managing them.

Policy Considerations

The major issue surrounding the healthand safety aspects of oil shale development isthe paucity of information on the nature andseverity of the health effects of oil shale, its

derivatives, waste products, and emissions.The effect of the scale of operation of oilshale facilities on worker safety is also un-known. Policy options for addressing theseissues follow,

Inadequate Information

Additional study is needed to determine theeffects on human health of the various chemi-cal substances and particulate encounteredduring the mining and processing of oil shaleand its products and wastes. Such informa-

tion would be useful in identifying and miti-gating long-term health effects on workersand the public. It would also be useful in set-ting new standards for worker health andsafety. Options for increasing the amount of information include expanding existing R&Dprograms; coordinating R&D work by Federalagencies; increasing appropriations to agen-cies to accelerate their health effects studies:and passing new legislation specifically call-ing for study of the health and safety aspectsof oil shale development. Methods for imple-menting these options are similar to those de-

scribed in the air quality section of thischapter.

Health Surveillance

Collection and maintenance of oil shaleworkers’ health records in a health registrywould facilitate hazard identification andplanning to reduce risks. The registry mightbe located in a regional medical center, withor without Federal agency input. Fundingcould be provided by Government, labor, orthe oil shale developers, or by a cost-sharing

arrangement between these groups. The reg-



...


istry location could be the focus of regularmeetings to exchange health and safety in-formation and to disseminate basic scientificfindings that apply to the oil shale industry.

Exposure Standards

As information about chemical health haz-ards is developed and analyzed, NIOSH andMSHA should determine whether exposure

standards are necessary to protect workerhealth and safety. In addition, sampling meth-ods should he in place to monitor exposures.

Worker-Education Campaigns

Worker education is already a part of the

mining industry. Information about newlyidentified risks should be conveyed to work-ers as soon as possible.

Land ReclamationIntroduction

An oil shale industry will use land for ac-cess to sites, for facilities, for mining, for re-torting, for oil upgrading, and for waste dis-posal. The extent to which development willaffect the land on and near a given tract willbe determined by the location of the tract; thescale, type, and combination of mining andprocessing technologies used; and the dura-tion of the operations. Comparatively littleland will be disturbed by the retorts and up-grading facilities themselves, but much largerareas will be disrupted by mining activitiesand waste disposal operations, particularly if the deposits are developed by open pit miningin conjunction with aboveground retorting,which produces retorted shale as a process

waste.It has been estimated that a l-million-bbl/dindustry using aboveground retorts wouldprocess approximately 600 million tons of raw oil shale per year, and would require thedisposal of approximately 10 billion ft 3 of compacted spent shale. Less of the surfacewould be disturbed by in situ retorting, al-though the surface would nevertheless be dis-turbed by drill pads. However, the disturb-ance would be different and less drastic thanfrom an open pit operation. At the same time,the amount of subsurface disturbance for a

given level of oil production would be in-creased because, although with an in situprocess relatively little oil shale is mined, oilrecovery rates are lower and some leaner oilshales would be retorted. Subsurface disrup-

tion from underground mining and in situ de-velopment could affect aboveground condi-tions through subsidence in the mined-outareas. But this might not happen until longafter operations at the site have ceased.

Oil shale plants must be built to complywith the laws and regulations that governland reclamation and waste disposal, Never-theless, there will still be effects on the topog-raphy (ultimately the terrain could be modi-fied to a landscape unlike the original) and onwildlife (through changes in forage plantsand habitats). In addition, unless appropriatecontrol methods are developed and applied,as required by law, the large quantities of raw and retorted shale could pollute the airwith fugitive dust and the water with bothrunoff and the effluent that has percolatedthrough raw shale storage piles and wastedisposal areas. Solid wastes such as cata-lysts, water treatment sludges, and refinerycoke, will be produced in relatively smallamounts, but will contain toxic componentsthat could degrade water quality unless prop-erly controlled. Similar care will be needed toremove, store, dispose, and revegetate thelarge amounts of overburden that will behandled in open pit mining operations.

Several avoidance and mitigation strate-gies have been proposed to minimize the over-

all land impacts of oil shale development. Oilshale plants, access corridors, and disposalareas could be sited to avoid esthetic deteri-oration and improve the feasibility of landreclamation and revegetation programs; and




mining and in situ retorting could be designedto decrease surface subsidence or reduce itsrate. In addition, most development planspropose to protect existing wildlife habitatsand migration routes, where possible, and toenhance the characteristics of adjacent

areas to promote wildlife readjustment. Rec-lamation and revegetation techniques havebeen developed and tested on a small scaleover limited periods of time for abovegroundsolid waste disposal, and backfilling mineshas been suggested to reduce the quantity of solid material that must be disposed of on thesurface.

As with air and water control methods, anumber of uncertainties surround the feasi-bility of methods for minimizing land disturb-ance and its effects on wildlife. At issue arethe feasibility of land restoration and revege-tation techniques, and the adequacy of strat-egies to control the leaching of solid wasteand raw shale piles. The methods for dispos-ing of solid wastes by backfilling mines andfor controlling leachates from solid waste dis-posal piles and underground retorts were dis-cussed previously in the water quality sec-tion. In this section the reclamation and re-vegetation of processed shales on the surfaceare examined.

Reasons for Reclamation

The primary purpose of reclaiming the sol-id wastes is to reduce their detrimental ef-fects. These include: changes in the land-scape, the disruption of existing land uses,the loss of the biological productivity on agiven land surface, and the degradation of airand water quality by erosion and leaching. Inaddition, secondary impacts such as fugitivedust would affect not only the immediate areabut adjacent areas as well.

Regulat ions Governing Land Reclamation

In order to ensure that mining operationswill incorporate reclamation concepts andminimize adverse effects, legislation has beenpassed and regulations have been promul-

gated governing oil shale mining, processing,and waste disposal,

Each State in the oil shale region has rec-lamation laws that apply to all mining opera-tions. USGS has regulations that control oilshale operations only on Federal lands. In ad-

dition, the Department of the Interior (DOI)established environmental stipulations gov-erning lands under the Prototype Oil ShaleLeasing Program that include additional spe-cific reclamation standards. The SurfaceMining Control and Reclamation Act(SMCRA), passed in 1977, provides a systemof comprehensive planning and decisionmak-ing needed to manage land disturbed by de-velopment. However, the Act applies only tocoal, and the detailed reclamation standardspromulgated under it may not be appropriateto oil shale in all cases. However, it providesa guide to measure the strictness of otherlaws applicable to oil shale for matters thatare not specific to coal.

The Colorado Mined Land Reclamation Actis administered by a board and division with-in the Department of Natural Resources. Itrequires permits for each mine operation,stipulates application procedures and crite-ria for permit approval, requires surety (e.g.,performance bonds), and sets procedures forenforcement and administration. The Act’sperformance standards are similar in con-

cept to those established by the Federal CoalAct. They are not, however, as detailed sincethey must apply to all minerals from oil shaleto sand and gravel (except for coal, which hasbeen amended to correspond to the new Fed-eral requirements); and, in some cases, theyare not so strict. For example, an operatormay choose the postmining use of affectedland; whereas, the Federal standard requiresapproval of such use by the permitting au-thority according to strict criteria. Also, anoperator may substitute other lands to be re-vegetated if toxic or acid-forming materials

will prevent their successful vegetation, andthe mitigation of such conditions is not feasi-ble. Mining would probably be prohibitedunder similar conditions by Federal stand-ards, if they were applicable to oil shale.

63-898 L - 80 - 22




The Utah Mined Land Reclamation Act isadministered by the Board of Oil, Gas, andMining. It provides for various powers of theboard, administrative procedures, surety,and enforcement. However, the Utah law onlyestablishes general reclamation goals anddoes not set detailed environmental perform-ance standards as do SMCRA and the Colora-do law. These goals include minimizing envi-ronmental degradation or “future hazards topublic safety and welfare” and establishing“a stable ecological condition comparablewith . . . land uses. ” They are open to broaddiscretionary interpretation by the Oil, Gas,and Mining Board.

The Federal standards that do apply to oilshale are limited to Federal lands;* they donot govern operations on private land, andare in no way comparable to the detailed

standards that apply to coal under SMCRA.For example, 30 CFR 231.4 establishes verygeneral goals requiring reclamation to“avoid, minimize or repair” environmentaldamage. Specific details must be set by site-specific leases. It is not applicable to true insitu oil shale methods using boreholes andwells, thus will not govern spent shale leach-ing for this technology. Part 23 of title 43authorizes, but does not require, the Bureauof Land Management (BLM) District Manag-ers to formulate reclamation requirementsand USGS Mining Supervisors to set stand-

ards for mine plans.More important are specific lease stipula-

tions. Environmental stipulations have beenincluded in the Prototype Oil Shale Leasesgoverning operations on current Federallease tracts. The reclamation and revegeta-tion performance standards that are includedtake into account the experimental nature of the program. For example, lessees are given10 years to demonstrate a necessary revege-tation technology; however, operations mustcease if such technology is not developed. Thelease and the environmental stipulations areadministered under the broad discretion of the Area Oil Shale Supervisor, who has re-

*About 70 percent of the oil shale land, containing about 80percent of the resources, is federally owned.

quired “best available control technologies”to minimize all environmental damage.

In summary, while reclamation is requiredunder State laws, there are no performancestandards specific to oil shale. Regulationsvary and are not so strict as the general re-

quirements of the Federal coal law. There areadditional requirements that pertain to Fed-eral leases.

Reclamation Approaches

Several reclamation approaches can beused to reduce the deleterious effects associated with the disposal of spent oil shale.These include returning surface wastes tomined-out areas; the chemical, physical, orvegetative stabilization of processed shale;and combinations of these approaches.

Reducing Surface Wastes

Mine backfilling was discussed in the sec-tion on water quality. As was indicated, thedisposal of wastes underground will be moreexpensive than surface disposal, but therecould be less surface subsidence caused bythe collapse of overburden materials abovethe mined-out rooms.

Chemical or Physical Stabilization

One approach that can be used to reduceerosion on disposal sites is to use chemical orphysical methods to stabilize the processedshale. Chemical stabilization may be shortterm—from a few months to a couple of years—or longer term. Short-term methodsconsist of spraying biodegradable chemicalson the surface; these reduce wind and watererosion by binding particles together. Suchchemicals have been used along with revege-tation to achieve temporary stability. 89 T h echemicals do not appear to inhibit seed germi-nation; however, they are expensive and, at

best, temporary.Longer term stabilization consists of add-

ing materials such as emulsified asphalt orprocessed limestone to induce chemical reac-




tions that harden the mixtures. Hardeningcan be accomplished by wetting of shalesprocessed at high temperatures, followed bycompaction. The hardened products have theadvantages of relatively high resistance toerosion and reduced leaching of soluble saltsinto the ground water. Their disadvantagesare that they are esthetically unattractiveand cannot support vegetation unless coveredby a suitable plant growth medium. The long-term effects of chemical stabilization are atpresent unknown.

Erosion can be reduced physically by cov-ering the processed shale with a layer of rocky material. Like the chemica l ap-proaches, physical methods inhibit the estab-lishment of a vegetative cover, are not esthet-

ically pleasing, and restrict the future uses of the land.

Vegetative Stabilization

Vegetation offers the most estheticallypleasing and productive means of stabilizing

waste materials. It also allows for multipleland use. In addition, vegetation theoreticallyoffers a means of continually adapting to thechanging environmental conditions that arelikely to occur on the disposal site over time.

Vegetation will also reduce the overlandflow of water and sedimentation during in-tense storms by increasing the permeabilityof the soil. This will increase the infiltrationof water, thus reducing surface water andpollution and flood hazards. Vegetative cover

P h o t o credit OTA staff

A variety of plant life will be required for revegetation of spent shale areas




will tend to ameliorate micro-climatic condi-tions and also reduce wind erosion and ex-tremes in soil temperatures.

Combinations of Stabilization Methods

Perhaps the most effective means of sta-bilizing waste piles will be combinations of approaches such as hardening the processedshales by chemical means and then establish-ing vegetation on a friable soilcover atop thesolidified wastes. The vegetative stabilizationof soil-covered spent shale appears to be thepreferred reclamation approach because thechemical and physical properties of proc-essed shale make it much less amenable tosupporting plant growth that resembles thediversity and density of the present natural

vegetation ecosystems.

The Physical and Chemical

Characteristics of Processed Shale

The physical and chemical characteristicsof the processed shale are determined by thesource of the raw shale; its particle size aftercrushing; and the retorting parameters suchas temperature, flow rate, and carbonate de-composition, which vary with different retort-

ing processes.

The characteristics of processed shalestha t make them undes i rable as a p lantgrowth media are:

q small particle size (texture), which en-courages erosion; and compaction or ce-mentation, which results in low permea-

bility to water and poor root penetration;q high pH (i. e., high alkalinity), which dis-

courages plant growth by making essen-tial nutrients insoluble and therefore un-available;

q high quantities of soluble salts, includingelements toxic to plant growth that in-hibit water and nutrient uptake; and

q the dark colors of some spent shales,which absorb solar radiation thus pro-ducing high temperatures that inhibits eed germi nati on a n d d r y t h e s o i lthrough evapotranspiration.

The characteristics of spent shale fromseveral processes are summarized in table 68and discussed below.

Texture

Raw shale that is finely crushed, as in theTOSCO II process, produces a fine silty spentshale that is highly susceptible to erosion.However, if the shale is coarsely crushed asin the gas combustion processes, a coarse-textured spent shale is produced that is less

susceptible to erosion. The resistance to wet-

Table 68.–The Chemical and Physical Propert ies of Processed Shales

ProcessingProcess temperature Color Texture a Salinity b

pH

TOSCO II ., . . . ., . . . . LOW Black Fine 18 9.1Gas Combustion . . ., ., ., . . High Gray Coarse 14 8.7Paraho

Directly heated. ., ., ., ., High Gray Coarse 7 12,2Indirectly heated . . . . ., . . . Low Black Coarse 10 12,3

Union“A” retort . . . . . . . . . High Gray Coarse 3-4 11,4‘‘B’ retort ., ... ., Low Black Coarse 13 8.5

Lurgl-Ruhrgas ., ., ., . . Low/high Gray Fine/coarse 3-7 11-12

aFl”~.[~Xlu~@ processed Shales are predornlrranlly smaller Ihiln 2 mm while coarse-[ extured processed shales are r)redomlnantly larger than 2 InrnbThe electrical ~OfrdUCtlVltY (rnrnhO/Crn) of a safuraled extract prepared rOrn spent shale Partlclw sfnaller than p mm

SOURCE Planf Resources Inshwie The free/arrrallorI oJProcessed O// Shale, prepared for OTA, January 1980





. .


Cementation

Processed shales retorted at high temper-atures and then moistened harden withinabout 3 days in a reaction similar to thatwhich takes place in cement. 10 6 The product of spent shale cementation is still susceptible to

weathering, and the reaction generally takesplace deeper in the waste pile where theprocess is accelerated by compaction, heat,and high pressure. If shale hardened by thisprocess were to be exposed by erosion, itmight prove to be impenetrable to moistureand plant roots.

Alkalinity

Processed shales retorted at temperaturesof about 5000 C (90 0

0 F) are less alkaline (pHsranging from 8 to 9*), than those retorted at750° to 800° C (1,400°to 1,500°F) (pHs of 11to 12). In general, the higher the alkinity of itsleachates, the lower the concentrations of soluble salts in the processed shale. At higherpHs many plant nutrients are insoluble, andplants will generally not grow in a strongly al-kaline soil medium.

If processed shales are to be used directlyas a growth medium, their alkalinity must bereduced. This can be done by leaching follow-ing deposition and proper compaction, or byadding costly acids or acid-formers. 107 Expo-

sure to the atmosphere over a period of sever-al months to several years will reduce it natu-rally.

Nutrient Deficiencies

Spent shales have been shown to be highlydeficient in the forms of nitrogen and phos-phorous available to plants. 108 Therefore ni-trogen and phosphorus fertilizers need to beadded. These can be applied at any time of year but spring fertilization has been recom-mended to prevent burning and to reduce fer-

tilizing weedy species.

109

It will probably benecessary to fertilize with nitrogen for sev-eral years until the ecosystem begins to fixand recycle its own nitrogen. 110

*PH is a means of expressing acidily or basicity. It rangesfrom 1, highly acidic through 7, neutral, to 14, highly alkaline.

Another means of assisting plants to sur-vive in nutrient-deficient soils is by inocu-lating them with selected strains of fungi thatproduce mycorrhizae. Mycorrhizae are struc-tures that combine the plant root and a fun-gus to increase the survival and growth of plants in nutrient-deficient soils by increasingnutrient uptake and resistance to a variety of stresses.

Free-living soil microbes are expected tobegin recolonization of the disturbed area.They will be valuable in fixing nitrogen fromthe atmosphere and recycling organic forms.How soon this will begin is not known. It isknown, however, that wetting and dryingstored topsoil deteriorates the conditions fa-vorable to such microbes. For this reason,prior to use topsoil should be deeply buried toprevent the wetting and drying that occurs

near the surface.11 1

Plant species used to reclaim spent shalespossibly will require inoculation with mycor-rhizal fungi to enhance their growth and sur-vival. 112 Colonizing species on disturbed landsare often nonmycorrhizal. 113 It has also beenfound that with increasing soil disturbance orthe addition of processed shale, the ability of the soil to be infected with mycorrhizal fungidecreases. The most successful revegetationspecies become mychorrhizal only late intheir establishment. There appears to be no

significant effect of the seed mixture, the fer-,tilizer, the mulch, or irrigation on a soil’s po-tential for mycorrhizal infection following itsdisturbance. 114

Salinity

Because spent shales are often quite salty,they present major problems for establishingvegetation, and for the water quality fromsurface runoff or drainage through them. 115-120

High concentrations of salt in the soil mediarestrict water and nutrient uptake. * These

can only be lowered by leaching with supple-mental water.

*Electrical conductivity is a measure of a soil’s salinity. Aconductivity of 4 mmho/cm is considered saline, and above 12mmho/cm, highly saline.




Leaching

Depending on the characteristics of thespent shales, about 5 acre-ft of water peracre will be needed for leaching and plantgrowth. 122 This is based on a net requirementof 48 inches of leaching water and an 80-per-

cent irrigation efficiency. The actual supple-mental water needed will vary with annualprecipitation, evaluation, and aspect, To en-sure adequate infiltration and to prevent ero-sion, it should be continually applied at lowrates (e. g., 2 to 3 cm/hr) and in a spray form.Leaching will probably not be uniform overthe entire surface, therefore surface monitor-ing and additional localized leaching may beneeded.

Toxicity

High concentrations of boron in spent shalecan be toxic to plants. On the other hand, theelements molybdenum, selenium, arsenic,and fluorine (also found in shale) are general-ly not toxic to plants. However, when theseelements are taken up by plants, they can be-come toxic to grazing animals. Susceptibilityto such toxicity varies among animal speciesas well as within a species. It is dependent onthe concentration of the elements within theplant, the size of the animal, its daily diet, andits general physiological condition. The condi-tions that encourage the uptake of these ele-

ments by plants, and their resulting toxicityin animals are complicated and poorly under-stood. Proper management should help toavoid or alleviate the problems with livestock.This can be achieved by restricting livestockgrazing to seasons when the elements arepresent at low concentration in the plants, byvarying the mix of plant species to be used inthe grazing areas, and by feeding seques-tering supplements to reduce the toxicity of the elements. The management of wildlife,however, is very difficult and problems willpersist in this realm.

The dominant soluble ions in spent shaleare sodium and sulfate, with abundant calci-um, magnesium, and bicarbonate also pres-ent. Of the trace elements identified in proc-

essed shale leachates, selenium and arsenicare not cause for concern, but fluorine,boron, and molybdenum are more serious. ’z]Plants grown on processed oil shales and soil-covered processed shales in northwesternColorado have been found higher in molyb-denum and boron than plants grown in ordi-nary soil, although their selenium, arsenic,and fluorine contents were moderate. 124

Excessive Heat

The color of the processed shale reflectsthe amount of residual carbon on the retortedparticles. Black and gray processed shalesare produced by low- and high-temperatureprocesses, respectively. The color influencesthe surface temperatures of the plant growthmedia which, in turn, affects seed germina-

tion and the plant-water relationship. Thedark-colored material warms up earlier inthe spring, inhibits seed germination more,and creates drier soils than does lighter col-ored processed shale. Temperatures of up to78° C (196° F) have been reported for theTOSCO II material. 125 126 The color can bemodified to a certain extent by the use of sur-face mulches or a covering of topsoil-like ma-terial, which reduces many of the salinity andalkalinity problems as well as the need forsupplemental water.

Another temperature problem encountered

in the massive disposal of spent shales is thatthe processed shales will probably go into thedisposal pile at temperatures in excess of 40”C (98° F). This will create a heat reservoir, Itis not known how long it will take to cool, If aspent shale pile is warmer than normal soilswithin the area, the site would be drier thanexpected because of the increased potentialfor evapotranspiration.

Use of Topsoil as a Spent Shale Cover

An alternative to revegetating directly onspent shale is the establishment of vegetationon a cover of topsoil or topsoil-like over-burden material placed over the spent shale.Such a soil cover offers several advantages.



— —


Because it does not have the problems of highsalinity and alkalinity, no supplemental wateris required for leaching. The material is amore suitable medium for plant growth be-cause it has greater water-holding capacity,more nutrients, and promotes a more intimate

relation with plant roots.Economics and a possible lack of longevityare the primary disadvantages of using a soilcover. Additional costs would be incurred forsegregating suitable materials from thosewith undesirable properties, for transportingand storing materials, and for surfacing overthe spent shales. In time, the natural geologi-cal process of erosion may eventually cutthrough the soil cover and expose the spentshale. An artificial soil profile using over-burden materials between the topsoil and thespent shale would greatly reduce, if not elimi-

nate, the problem. With proper managementmost erosion should be localized. However,with improper management such as overgraz-ing, reductions in vegetative cover could oc-cur that would allow larger areas to be ex-posed. If erosion were gradual over a fewhundred years, the vegetation possibly wouldadapt to the thinning soil cover, and naturalleaching and weathering could render thespent shale a more suitable growth medium.Despite these disadvantages, the use of a soilcover will provide for the more rapid estab-lishment of a vegetative cover that will per-

sist longer than would vegetation establisheddirectly on spent shale.The depth of the soil cover needed will vary

from site to site, but will generally range from1 to several ft in thickness. 127 128 Soil surveysof the Piceance basin indicate that sufficientsoil and soil-like material exists in the dispos-al sites, particularly those with deep alluvialdeposits, and this should provide adequatecover material.

The selection of topsoil or topsoil-like over-burdens will have to be based on chemicaland physical analyses. This is important be-cause the soil types and their toxicities vary.The treatment of the soil cover will be similarto the treatments of soil used for the reclama-tion of surface-mined coal areas, about whichthere is more knowledge.129 Soil surveys of the

basins will also be useful in deciding whatmaterials to use. It is doubtful that the capil-lary rise of salts will be a problem unless soilsare continually exposed to saturated condi-tions. This might happen if improper engi-neering of the disposal site created seeps orallowed pending.

Species Selection and Plant Materials

The selection of plant materials to be usedin reclaiming processed shale is determinedby several factors, the most important of which is species adaptability. Adaptability(suitability) is intimately tied to the ability of aplant to complete its entire lifecycle, and toreproduce itself from year to year over a longperiod. The plant’s growth form, drought re-sistance or tolerance to stress, mineral nutri-

tion requirement, and reproduction charac-teristics must all be considered. In addition tobeing adapted to the growth medium, plantsmust also be adapted to local temperatures,elevation, slope, aspect, and wind conditions.They should be able to survive the weeds andanimals that may invade the site. Palatabilityto livestock and wildlife as well as availabili-ty of seed and competition among speciesbeing planted are also important factors.

In addition to the results of actual revege-tation test plots, several information sources

and guides are available to assist in the selec-tion of species adapted to conditions likely tobe encountered in oil shale reclamation.130-134

These include the Plant Information Networkcomputerized data bank located at ColoradoState University. 135

In general, mixtures of various grasses,forbs, shrubs, and in some cases trees, aredesirable because they offer a greater rangeof adaptation. 136 Mixtures may include spe-cies adapted to each of the different microcli-mates, moisture levels, and soils. The results

of using a well-planned mixture can be a fast-establishing, long-term cover that is less vul-nerable to pests, disease, drought, and frost.

Recommended mixtures used in test plotsmay include both indigenous (native) and in-




troduced perennial species. In one study, amixture of native and introduced species dis-played the highest productivity and allowedthe least amount of invasions by weeds.’}’ Al-though a mixture of non-native species had ahigher plant density, it also allowed the great-

est invasion of weeds.

138

Weeds are undesir-able in that most are annuals (complete theirlifecycle in 1 year) dependent on precipita-tion; they are therefore an unreliable erosioncontrol. They also compete with the more de-sirable perennial species (species that persistfor several years) for water and nutrients.These annuals are expected to disappearwith natural succession over a few years.

Species selection is complex and involves,in addition to considerations of the speciesitself, a tradeoff among many interacting fac-

tors.139

These include: Federal, State, and lo-cal reclamation requirements; rehabilitationand land use objectives; the nature of the site;the timing of the program; species compatibil-ity; mechanical limitations in planting; seedand seedling availability; maintenance afterplanting; and cost,

Seeds

Planting seed by drilling or broadcasting isa common way of establishing vegetation in areclamation plan. Seed is available commer-

cially from collectors and seed companies. ’40While many commonly used seeds are availa-ble from dealers under contract, proceduresfor cultivating wildland plants for seed pro-duction have generally not been developed.Also, certain varieties of the native plantspecies may not be available from commer-cial sources. Until reliable seed productiontechniques are developed (which may requireup to 10 years), seeds for propagating nativeplants will generally have to be collectedfrom wildland populations. This may be aproblem for a large oil shale industry, sinceseed production from wildland populationscan be unpredictable from year to year; somenative species produce abundant seed cropsonly in years when conditions are especiallyfavorable.

Seeding is best done in late fall or earlyspring when soil moisture is high, althoughthe operation of seeding equipment in thespring may be hampered by wet soil condi-tions.’” Seeding rates may vary from 10 to 30lb of pure live seed per acre depending on

slope and whether the seed is broadcast ordrilled. Drier exposures and broadcast tech-niques require more seed.

Another problem in propagating plantsfrom seed is dormancy of seed. Extensivetreatment of the seed may be required inorder to overcome it. For these reasons, vege-tative propagation is a necessary alternativeto seed propagation for producing plantingstock of native species.

Containerized Plants

Container-grown plants have been success-fully used in several oil shale revegetationstudies. 142-144 They offer several advantagesover seed:

145

they make efficient use of scarce seed orseeds especially adapted for harsh sites,plant survival and growth are optimizedby rapid root growth into the surround-ing soil,well-developed plants are generally ableto withstand grazing or other stresses,and

they can be inoculated with fungi just be-fore seeding to ensure the developmentof mycorrhizae.

Container-grown plants can be hardened tothe fluctuating and more extreme environ-mental conditions they will encounter at therevegetation site by gradually exposing themto drier conditions and greater temperatureextremes. The higher cost of container-grownstocks is offset by their better survival rate. 146

They are recommended for fall or earlyspring planting on harsh sites where estab-lishment of seeds may be difficult or impossi-ble due to erratic or low precipitation orother environmental stresses. Bare root stockis another alternative, but can only be usedwith sufficient soil moisture to ensure goodroot penetration into the growth medium. 147





Ch. 8–Environmenlal Considerations q 339

pect of postmining land use will require care-ful monitoring. Indirect methods for protect-ing a site against livestock include adding lesspalatable species to the seed mixture, pro-viding salt blocks and permanent water sup-plies away from the seeded areas, controlling

livestock numbers, herding, fencing, and, if necessary, repellents. l48

Phot o credit OTA staff

Reclaimed sites will have to be protected from wildlife

Protection against wildlife will also be re-quired. This includes large herbivores as wellas small burrowing animals such as pocket

gophers that can be expected to move into therevegetated area. If not controlled, over-utilization of vegetation may occur and toxiccompounds may be brought to the surface byburrowing animals. 149

Monitoring and subsequent managementmust also ensure that refertilization, seeding,and additional control of erosion or weeds,are provided if necessary, Similarly, monitor-ing plant succession, productivity, and uti-lization should all be included in the reclama-tion management plan. 150

Review of Selected Research to Date

Research undertaken on the topic of oilshale reclamation falls into two categories:

q

q

baseline studies that describe the eco-logical characteristics of the existing en-vironment in the oil shale basins, andcharacterization studies of processedshale and the testing of reclamationmethods.

Data from both types of research are neededin designing, directing, and assessing pastand future reclamation studies.

Baseline Studies

A general description of the vegetation of the oil shale basins can be found in chapter 4.Additional descriptions that contribute to thebaseline data are available for Federal landsfrom BLM’s Unit Resource Analysis151 andManagement Framework Plans. 152 More spe-cific vegetation inventories have also beenmade for site-specific areas within thesebasins such as transmission and pipeline cor-ridors, Land classification systems have alsobeen developed for the piceance basin,153 154

Eighteen phyto-edaphic units (plant-soil units)were identified. 155 The description of eachunit provides information on soil, vegetation,climate, aspect, and landform interpretationsand hazards of land use. A section on rec-lamation considerations is provided to iden-tify the most hazardous characteristics of theunit (e. g., the potential for erosion and slump-

ing) that need special attention and care, par-ticularly after disturbance as a result of oilshale development. Management recommen-dations and alternatives are supplied to over-come the identified limitations.

Other information on plant community re-lationships (phytosociology) is currently beinggathered by Colorado State University for thePiceance basin. This will help the land man-agers and reclamation specialists to selectthe proper species to be used in reclamation.Such studies are lacking for the basins inWyoming and Utah, and few physiologicalstudies have been conducted with existingplant species at the proposed disposal sites orwith plant materials to be used in reclama-tion to determine their tolerance limits to thevarious adverse conditions likely to be en-




countered. Little is known about the naturalgenetic differences that exist in native plantcommunities. These might make the plantsmore or less adaptable to adverse environ-mental conditions encountered in oil shalereclamation.

Reclamation Studies

Investigations to determine the manage-ment needed to produce conditions favorableto the establishment and growth of plants onprocessed shales were initiated by private in-dustry in the mid-1960 ’s. ’5’ These were basedon previous knowledge developed by rangemanagers, biologists, and numerous arid andsemiarid studies, as well as other baseline in-formation from the oil shale basins.

Where possible, the sites for reclamation

tests have been selected to simulate, as close-ly as possible, the environmental conditionsto be encountered during the reclamation of disposal sites used for large-scale production.Sites have been selected in high- and low-rainfall areas, with various combinations of slope, aspect, and processed shale materials.However, most revegetation experimentshave been hampered by a lack of processedshale. This shortage, coupled with the highcosts of transporting retorted shales to fieldsites (in some cases from as far away asCalifornia), have restricted both the size of

the test plots (2 to 5,000 ft2), and the type of processed shale evaluated.

To date, field studies using spent oil shalesas plant growth media have centered on theTOSCO II, Union “A” and “B,” and Parahomaterials.157-162 These studies show that withintensive treatments plant growth can be es-tablished directly on spent shales, althoughuse of a soil cover is more successful.

It is difficult to compare the results of revegetation studies with the various proc-essed shales because the experimental de-signs varied so widely. Different plant spe-cies were used, and fertilizer, mulch, slope,aspect, and soil cover also varied. Most of theearly (1965 to 1973) revegetation studies forColony used spent shale from the TOSCO II

process. 163 During these studies the basicchemical data needed to design a reclamationprogram were incorporated into greenhouseand small field plots (100 ft 2). Revegetationwork on other processed shales, all of whichare coarser, had been confined to Union Oil

plots planted in 1966 and Colorado State Uni-versity plots planted in 1973. In the late1960’s and early 1970’s, larger field plots(41,000 ft2) were built using many of the resultsof the earlier experiments, including the ef-fects of soil supplements such as fertilizerand organic matter.

Since the early 1970’s, studies have beenconducted on disturbed soils without proc-essed shales to determine the establishmentof plant species, microbial activity, and long-term successional trends. These studies were

encouraged by the finding that the revegeta-tion of soil-covered processed shales wasmore successful than revegetation directly onprocessed shales. This was because the soilcover does not have the adverse chemical andphysical properties of processed shale thatinhibit plant growth.

Supplemental water has been used to es-tablish plants in most of the processed shalerevegetation studies. The addition of 10 to13 inches of water during the first growingseason with no subsequent irrigation has

resulted in the establishment of a vegeta-tive stand and the persistence of adaptedspecies for several years. The salt leachingrequirement (5 acre-ft of water per acre) is inaddition to this supplemental water. Onlylimited success in seeding and transplantinginto spent shale without supplementary wa-ter has been reported. 164 However, establish-ment without supplemental water might beachieved by mulching with straw or hay andallowing salts to be leached by natural pre-cipitation prior to seeding or planting, al-though the time period required for this couldbe unreasonable. Micro-watersheds consist-ing of low-level diversion b a r r i e r s o rmounded spent shale have also been pro-posed and initiated to concentrate water forplant growth.165




Several researchers have worked on theproblems of leaching soluble salts from theprocessed shales and the surface stability of several retorted shales including TOSCOI I .166-172 It appears unlikely that salts willmigrate to the surface by capillary rise inmost areas of low precipitation. Only in areaswhere soils were saturated by supplementalwater was there temporary desalinization of surface layers. When the supplemental wa-ter was discontinued, surface salinity beganto drop due to leaching from natural precip-itation. From these studies a better under-standing has developed of solutions to theproblem of establishing a self-sustainingvegetative cover.

Several studies are continuing, and a newsuccessional study has been initiated 173 t oevaluate the long-term feasibility of using

processed shales directly as plant growthmedia and the influence of various depths of soil cover over spent shale. It has been set upin the Piceance basin to obtain informationrelated to the reseeding of disturbed areas inorder to reestablish a diverse, functionalecosystem in as short a time as possible.Various seed mixtures, ecotypic varieties of native species, microbial activities, seedingtechniques, fertilizer levels, irrigation, andmulching treatments are being evaluated. Inaddition, the rate and direction of plant suc-cession is being monitored to identify signifi-

cant trends in vegetation changes, and to de-termine how these trends are influenced bythe various treatments and practices, 174

Few studies have been conducted on rawshale. This is because in the past it has beenassumed that most raw shale of commercialquality will be retorted. Additionally, the rawoil shales are hard and resilient. Whenmined, the shale fractures into coarse frag-ments that have extremely low water-holdingcapacities, which renders them undesirablegrowth media. For these reasons, it is likely

that raw shale of noncommercial qualitywould be buried deeper in the disposal pilesand not used as a growth medium,

Summary of Issues and R&D Needs

Research to date has shown that with in-tensive management vegetation can be estab-lished directly on processed oil shales. Theprimary requirements are the leaching of high levels of soluble salts with supplementalwater, the addition of nitrogen and phos-phorus fertilizers, and the use of adaptedplant species. However, the establishment of vegetation on spent shales covered with atleast 1 ft of soil is preferred because it is lesssusceptible to erosion and does not require asmuch supplemental water and fertilizer.Adapted plant species are required for eithersoil-covered or spent shales.

The long-term stability and the self-sus-taining character of the vegetation is un-known, but if sufficient topsoil is applied the

results of research on small plots indicatesthat short-term stability of a few decades ap-pears likely. Monitoring and subsequent man-agement must ensure that any necessary re-fertilization, seeding, and erosion and weedcontrol be provided. The reclamation man-agement plan must also include monitoringplant succession, productivity utilization, andthe presence of high concentrations of ele-ments toxic to plants and animals.

Whether or not the revegetation of spentshales is considered successful depends on

the desired land use and the performancestandards applied to measure the success.For example, the reestablishment of vegeta-tion that reduces erosion and is productive,self-sustaining, and compatible with sur-rounding vegetation might be considered suc-cessful for livestock but not for wildlife use.The minimum requirements for vegetationshould be to stabilize the disposal sites so thatthe detrimental effects caused by erosion canbe minimized. Where ecologically feasible,multiple land use of disposal sites should beencouraged.

Reclamation plans will have to be site spe-cific since environmental conditions vary




from site to site. Proper management will berequired in all instances, if only to protectplant communities in surrounding areas fromharm. Proper management is even more im-portant in the reclaimed areas. If the vege-tative cover were completely lost, the nega-tive effects would increase. The conditions

would not be as severe as those without anyreclamation because they would be reducedby restrictions in slope, catchment and diver-sion dams, and other mitigation completed inthe early stages of reclamation.

If revegetation completely failed, produc-tive land use would be severely reduced oreliminated. It is doubtful that, after oncebeing reclaimed, conditions would deterio-rate to the point of eliminating all vegetationfrom a disposal site, although a natural suc-cession of species would occur that would

favor those that had superior adaptability tothe harsh conditions. Weedy or unpalatablespecies of less use to livestock and wildlifewould undoubtedly invade the sites.

The types of reclamation needs for a large-scale industry (1 million bbl/d) are similar tothose generated for a small industry (50,000bbl/d), but differ in the amounts of materialsthat will be required and the rates at whichthey must be supplied. It is probable thatshortages of adapted plant materials and as-sociated support materials (such as mulchesand greenhouse facilities) would occur at thehigher production rates. The problem is com-pounded by the fact that demands for plantmaterials are increasing from other miningoperations such as coal and uranium. Theseverity of the shortages will depend onwhether the oil shales are processed in situ orsurface retorted, and whether the processedshales are disposed of underground or on thesurface. Surface reclamation needs will besomewhat less demanding with MIS process-ing or with underground disposal of surface-retorted shales.

Research on the reclamation of processedshales is continuing. Areas of major concernrequiring additional study include:

q the selection and propagation of speciesespecially adapted to conditions likely to

q

q

q

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q

q

be encountered in the reclamation of thespent shales. This should include theidentification of ecotypic variations,seed production by cultivating adaptedwildland plants, and research to deter-mine species performance under abnor-mal conditions (e.g., drought, salinity,and high temperatures);the role and use of soil microbes andmycorrhizal fungi in soil building andplant growth. Successful reclamationwill depend on developing a protocol toselect and/or maintain the essentialmycorrhizal fungi in disturbed habitatsor to develop methods to reinoculatethese fungi in habitats where they areabsent;the plant succession for large areas of afew hundred acres in size under naturaland disturbed conditions, including theinfluence of animals on revegetated sur-faces;the toxicity of elements such as fluorine,boron, molybdenum, selenium, and arse-nic to plants and grazing animals. A pro-gram to monitor these elements shouldbe established on newly reclaimed areasat least for the first few years;the probable heat retention within thedisposal pile and its effect on reclama-tion timing and revegetation;the rates of erosion on large, reclaimedareas of a few hundred acres in size. In-formation is needed on how much waterruns off the area following snowmelt inthe spring and after high-intensity sum-mer storms, including how much sedi-ment and soluble salts will be containedin the water; andthe viability of vegetation on raw shale,

Policy Options for the Reclamation of

Processed Oil Shales

For Increasing Available Information

More information is desirable on reclama-tion methods and the selection of proper plantspecies for revegetation programs. Optionsfor obtaining this information include the




evolution of existing R&D programs by theU.S. Department of Agriculture (USDA), EPA,and other agencies; the improved coordina-tion of R&D work by these agencies; increas-ing or redistributing appropriations to accel-erate reclamation and revegetation studies;and the passage of new legislation specifi-

cally for evaluating the impacts of land dis-turbance. Mechanisms are similar to thosediscussed in the air quality section of thischapter.

To Develop Reclamation Guidelines for Oil Shale

SMCRA provides for comprehensive plan-ning and decisionmaking to manage disturbedland. However, in general, the reclamationstandards promulgated under the act areonly appropriate for coal, but not necessarilyfor oil shale. Thus, new reclamation guide-

lines specifically for oil shale may be desir-able, with standards for postmining land usesthat are ecologically and economically feasi-ble and consistent with public goals. If theAct were amended to encompass oil shale,Congress could direct that reclamation guide-lines be developed by DOI’s Office of SurfaceMining, either alone or in conjunction withother agencies. Alternatively, Congress couldpass new legislation calling for the prep-aration and implementation of reclamationguidelines for oil shale.

To Expand the Product ion of Seeds andPlant Materials

While many common seeds are availablefrom commercial dealers, procedures for cul-

tivating specific wildland plants for seed pro-duction have generally not been developed.Also, seeds of certain native plant species arenot commercially available.

A shortage of seeds could be a problem fora large oil shale industry. For example, theUSDA’s plant materials centers often requireup to 15 years to identify and developadapted species for release to commercialsuppliers or to industry for trial plantings.Furthermore, the centers intentionally limittheir activities so that they will not competewith commercial producers. Thus, they havenot developed mass production capabilities,nor have they adopted some of the more re-cent propagation technologies (such as micro-propagation, cutting, and fungal and bacteri-al inoculation) that are used commercially. Inorder to meet the future demands of a largeoil shale industry, it may be necessary for thecenters to expand their facilities and prop-agation capabilities. This could be costly interms of facilities, technologies, and person-nel. Policy mechanisms for expanding cooper-ative agreements between the centers andcommercial producers need to be developed.These activities would not only benefit oilshale, but also most other reclamation andarid and semiarid revegetation projects aswell.

Permitting

Introduction the States to determine whether a prospec-tive facility is able to meet specific require-

During the past 10 years an increasingly ments under the law. The operation of an oilcomplex permitting system has been devel- shale facility requires well over 100 permitsoped to assist the Federal, State, and local and other regulatory documents from Feder-governments in protecting human health and al, State, and local agencies. They include thewelfare and the environment. Permits are the permits for maintaining the environment andenforcement tool established by Congress and for protecting the health and safety of work-




ers, and in addition, those that would beneeded for any industrial or commercial ac-tivity: building code permits, permits for theuse of temporary trailers, sewage disposalpermits, and others. Of these, a few—the major environmental ones—require substantialcommitments of time and resources. The ma-

jor environmental permits that must be ob-tained prior to the operation of an oil shale fa-cilit y are:

q

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a PSD permit required under the CleanAir Act;an Air Contaminant Emissions permit re-quired by the State of Colorado;a Special Primary Land Use permit—which is required for plant siting in RioBlanco County;a Mined Land Reclamation permit re-quired by the State of Colorado;

an NPDES permit required under theClean Water Act;a section 404 Dredge and Fill permit un-der the Clean Water Act if the operationaffects navigable waters;a Subsurface Disposal permit as re-quired by the State of Colorado if wateris reinfected;a permit for the disposal of solid wastesgenerated by the facility required underRCRA;testing of effects, recordkeeping, report-ing, and conditions for the manufacture

and handling of toxic substances as stip-ulated under TSCA; andan EIS as required by the National Envi-ronmental Policy Act-if an oil shale plantinvolves a major Federal action signifi-cantly affecting the environment.

The responsibilities for reviewing and ap-proving applications are distributed amongmany Federal, State, and local agencies. Fed-eral agencies include EPA, the Department of the Treasury, DOI (including BLM and USGS),the Department of Defense (e.g., the Army

Corps of Engineers), and the Interstate Com-merce Commission. State entities in Coloradoinclude the Department of Health, the De-partment of Natural Resources, and the StateEngineer. Because of varied and overlapping

regulations and statutes it has often been dif-ficult to know which agency must be con-tacted, and which permits are required fromwhich entity.

The following discussion examines:q

q

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how various parties view the permittingprocess;the current status of oil shale developersin obtaining the needed permits;the time required for preparing andprocessing permit applications;the disputes encountered so far in ob-taining such permits;the potential difficulties that might beencountered by a developing oil shale in-dustry; andpossible policy responses to permittingissues.

Perceptions of the Permitting Procedure

The various parties interested in environ-mental permits for oil shale facilities havewidely divergent views concerning the effec-tiveness and problems of the permitting pro-cedure. Industry is concerned about thelength of time it takes to obtain permits andthe uncertainty of obtaining them. The envi-ronmental community is watchful of the pro-cedure’s effectiveness in enforcing the law;and the regulators themselves are troubled

by their limited personnel and budgetary re-sources.

The high cost of oil shale projects makesunexpected delay costly, and industry is con-cerned with uncertain agency decision sched-ules or with unpredictable litigation that candelay or prevent project construction. Fur-thermore, some regulations and standardshave not yet been set because of a lack of suf-ficient knowledge about the impacts of shaleoperations and the effectiveness of their con-trol. Developers are particularly worried

about the effects of new regulations (such asfor visibility maintenance as part of the PSDprocess) on process design and project eco-nomics. They are concerned that new regula-tions could necessitate costly retrofits to ex-




isting plants or even the cessation of opera-tions. For facilities under construction, thenew regulatory requirements may mean rede-sign or addition of environmental controlequipment or strategies. These uncertaintiesincrease the risk that a project, once started,may not be completed. Prospective develop-

ers also express their frustration over thelengthy and expensive procedures for prepar-ing permit applications (including monitoringand modeling requirements) to meet some en-vironmental statutes. This discontent is some-times compounded by overlapping agency

jurisdictions and by repetitive paperwork.

The environmental community assertsthat, given the complexity of oil shale opera-tions, the extensive application and reviewprocedures are necessary to fully assess envi-ronmental impacts, the effectiveness of con-

trol measures, and compliance with environ-mental law. They suggest, in fact, that agencyenforcement of environmental laws is toooften compromised by weak regulations andby a lack of essential information on whichboth to base permitting decisions and to en-force the conditions of the permits. Informed,meaningful public involvement in the process-ing of environmental permits is therefore pro-moted by environmental groups to ensurethat all points of view are represented inagency proceedings. It is particularly impor-tant, these groups hold, that the technical

analyses on which agency decisions dependare subjected to independent scrutiny. How-ever, they believe that adequate provisions

are seldom made for public participation, andaccess is not provided to the informationneeded to evaluate the applications. Theynote that few agencies have an affirmativepublic involvement process. They find it isoften difficult to follow and monitor agencydecisionmaking.

The regulators feel overwhelmed by the in-creasing number of permits and by the com-plexity of the review. They believe that theirpersonnel and financial resources are toolimited for the present caseloads and certain-ly will be dwarfed by any rapid increase inapplications arising from an expanding ener-gy industry, EPA’s Region VIII, for example,includes not just the oil shale region, but mostof the Western coal and uranium resources.Regulatory personnel also contend that theyare handicapped by inadequate technical in-

formation about the technologies that theymust review and assess.

Status of Permits Obtained by

Oil Shale Developers

The number of permits needed for a givenfacility depends on its site; on whether it in-volves Federal land; on the scale, type, andcombination of processing technologies used;and on the duration of the operations. Asstated previously, the permits range fromthose required for a temporary trailer to the

major environmental permits required underFederal and State regulations and standards.Table 70 shows the status of the major per-

Table 70.–Status of the Environmental Permits for Five Oil Shale Projects

Regular openProject Type of tract EIS DDP approval PSD permit mining permit NPDES permit

R I O B l a n c o Federal lease tract Final programmatic Yesa For 1,000 bbl/d Yes 1st phaseC-a Issued a

Cathedral Bluffs Federal lease tract Final programmatic Yesa For 5,000 bbl/d Yes 1st phaseC-b Issued a

Long Ridge (Union) Private Not applicable Not applicable For 9,000 bbl/d Yes Not requiredb

Colony PrivateC Not applicable Not applicable For 46,000 bbl/d Not yet applied Not requlredb

S u p e r i o r Private/Federal

d

Not applicable Not applicable Not yet applied Not yet applied Not yet appliedaLlllgallon proceeding over aopro JaI of the momhed DDPbThese operallofls do not plan 10 discharge 10 Surf aCe StreaMS

cExchange of Federal land and plpellne rlgh[ of way otier BLM and ‘equesled‘Land exchange requested





mits obtained by five oil shale developers.These facilities are presently in differentstages of commercial development. The RioBlanco, Cathedral Bluffs, Colony, and Superi-or projects involve Federal land, while theUnion project is located on private holdings.DDPs for tracts C-a and C-b had to be ap-

proved by USGS because they are part of theFederal Prototype Oil Shale Leasing Program.Four of the projects have already beengranted PSD permits for their facilities. Note,however, that with the exception of the Col-ony project, only small-scale, first-phase con-struction air emissions have been approved.

All of the facilities have to obtain MinedLand Reclamation permits. Rio Blanco, Cathe-dral Bluffs, and Union have all been approvedfor commercial-scale modular operations.Colony and Superior have not yet applied.

NPDES permits are required under the CleanWater Act if a plant discharges to a surfacestream. So far Rio Blanco and CathedralBluffs have received such permits for thefirst phase of their commercial development.

The Length of the Permitting Procedure

The time required for preparing and proc-essing a permit application depends on thetype of action being reviewed, the review pro-cedures stipulated under the law, the criteriaused by agencies to judge the application, and

the amount of public participation and con-troversy. If Federal land is involved, then anEIS will most likely be required. This processmay take at least 9 months after the devel-oper applies for permission to proceed withthe project. * Then the applications for thenecessary construction and operation per-mits can be prepared and filed. In the case of the current Federal lease tracts, additionaltime was needed to prepare the DDPs for ap-proval by the Area Oil Shale Supervisor of USGS.

Once the requirements for an EIS and DDPare satisfied, obtaining all of the needed per-

*The programmatic EIS for the Prototype Leasing Programtook 4 years. Preparation of the draft EIS for the proposed Su-perior land exchange required 2 years.

mits can take more than 2 years. The prep-aration and review of the PSD application isperhaps the most comprehensive and time-consuming step. Baseline air monitoring is re-quired, along with extensive dispersion mod-eling to estimate the effect of the plant’s emis-sions on the region’s air quality. Once this

work is completed and an application sub-mitted to EPA, the approval process, as stipu-lated under the law, can take as long as 1year. However, EPA tries to rule on the appli-cation within 60 days, and to date an averageof about 90 days has been required. (This in-cludes internal staff review and a period forpublic comment. )

It should be noted that a project would notnecessarily be delayed by the full length of the permitting schedule, because other prede-velopment activities such as detailed engi-

neering design, contracting, and equipmentprocurement could proceed in parallel, if thedeveloper were willing to accept the risk thatkey permits might eventually proveobtainable.

Disputes Encountered in

the Permit ti ng Procedure

to be un-

The principal problems encountered todate are related to the needs of the regulatoryagencies for technical information, to differ-ing interpretations of environmental law,and, according to developers, to a lack of re-sponsibility for timely action on the part of the agencies.

Occidental’s application for a SubsurfaceDisposal permit for its sixth experimentalMIS retort on its property near De Beque,Colo., was delayed for several months by theColorado Water Quality Control Commis-sion’s consideration. (The commission had notrequired permits for the first five retorts. )The commission was concerned about the po-tential for ground water contamination by the

abandoned MIS retorts and was not satisfiedwith the evidence presented by Occidentalthat pollution would not occur. Additionaltechnical information was requested, and thecommission insisted on a cooperative environ-




mental monitoring and research program in-volving DOE, the State of Colorado, and sever-al universities. The dispute was resolvedwhen Occidental agreed to the program andthe investigators were given access to Oxy’ssite for sampling and experiments.

As work began on tracts C-a and C-bin late1977, soon after DOI approved the modifiedDDPs, a dispute arose among several environ-mental groups, permitting agencies, and thelessees over the timing of required permits.EPA initially informed the lessees that airquality and State mining and reclamationpermits would not be required until the min-ing of actual in situ retorts began, The envi-ronmental groups maintained that construc-tion commenced with shaft-sinking and con-struction of the surface facilities needed forthe MIS retorts. This work had already begun

and, according to the environmental groups,permits should have been in hand, They fur-ther contended that the interpretation of “commencement of construction” used by theagencies evolved during meetings that werenot open to public participation,

EPA’s recently appointed Regional Admin-istrator subsequently redefined “commence-ment of construction” to mean collaring of the shaft, an early activity in shaft-sinkingoperations, However, the State reclamationagency maintained that the developers werenot responsible for the previous interpreta-

tion of the law, Therefore, operations couldproceed, The State air pollution division post-poned the deadline for application submis-sion until the developers could submit the de-tailed engineering plans required for an emis-sions permit, but did not delay the construc-tion. EPA issued the permit in an expeditiousmanner and work was not significantly de-layed. Because a clear precedent was estab-lished, it is unlikely that this dispute will ariseagain. It took several months to resolve, butactivities on the tracts continued during thisperiod.

Finally, there has been protracted legal ac-tion between three environmental plaintiffsand DOI and the lessees of tracts C-a and C-bover the need for an EIS prior to DOI’s ap-

proval of DDPs that were submitted by thelessees in 1976. This dispute has thus far notdelayed construction on the tracts, It does,however, exemplify the type of uncertaintythat, the developers maintain, discouragesthem from initiating oil shale projects. Theplaintiffs claim that no statement to date has

adequately analyzed the effects of theseplans. Defendants believe that the 1973 pro-grammatic EIS appropriately evaluated the1976 plans and the alternatives to their ap-proval. The Federal district court agreedwith the defendants. The case was heard bythe 10th Circuit Court of Appeals which alsoruled in favor of the defendants.

Other than these disputes, there have beenno substantial interruptions that could bedirectly related to permitting. The onlylengthy application review period involved

Colony Development Operation’s PSD airquality permit. EPA did not expedite its re-view of this permit because the applicant in-dicated it was still inactive, awaiting morefavorable project economics. In addition, 1-year suspensions were requested in 1976 by

the lessees of the Federal tracts partiallybecause the baseline air quality conditions onthe tracts exceeded the primary NAAQS forparticulate and the guideline for HC. How-ever, the suspensions were granted for rea-sons not related to the permitting process.

Unresolved Issues

Although many precedents have been es-tablished, there remain unresolved issuesthat sustain a level of uncertainty that maydiscourage some developers from proceeding,whether on private or Federal land. These un-certainties may be more critical than thoseencountered thus far. Several regulations arestill pending that may increase costs or forcechanges in the design of process facilities orcontrol technologies. They may also add to

the control requirements. The pending regu-lations include:

q recordkeeping, reporting, and stipula-tions governing the manufacture and




handling of toxic substances as requiredunder TSCA;disposal practices and standards for sol-id waste under RCRA;emission and ambient air standards forhazardous air pollutants under theClean Air Act as amended;

visibility protection requirements formandatory Class I areas under the CleanAir Act as amended;possible application of the Safe DrinkingWater Act to the brackish ground wa-ters of the Piceance Basin; andpossible application of SMCRA, or simi-lar Federal-reclamation laws, to noncoalminerals.

Some environmental groups maintain thatthe effects of development are so poorly un-derstood that development will entail signifi-

cant risks. They believe that adequate regula-tions cannot be promulgated because knowl-edge is lacking about the severity of the risksand about the methods for their control. R&Dand further experience with the industry’soperations may result in the implementationof new regulations that will further reducethe economic attractiveness of oil shale proj-ects. This, however, is an uncertainty whichis inherent in any new industry.

Another problem that may emerge iswhether regulatory agencies will be able tohandle the increasing load of permit applica-tions and enforcement duties. Budgets andpersonnel are limited, and the States in par-ticular have experienced difficulty findingand keeping competent technicians and pro-fessionals. Increased oil shale operations,coal mining, oil and gas development, coal-fired powerplants and synthetic fuel facil-ities, uranium mines and mills, and other min-eral development in the region will furthertax their resources. The dissatisfaction ex-pressed to date may be insignificant com-pared to that which is likely as agencies be-

come more overloaded.

Att empts at Regulatory Simpli fi cati on

Several attempts are being made to simpli-fy regulatory procedures. A case in point isthe action of EPA’s Region VIII office tostreamline the PSD permit application pro-cess. The office evaluated its experience with

processing such permits and found that in afew cases, there are long review times whenthe applicant was not in a hurry to obtain apermit because the future of the project wasuncertain. An example is the application forthe Colony project, which has been sus-pended for several years. In other instances,delays resulted when the agency was delugedby permit applications prior to the enactmentof new, stricter regulations. An example isthe situation that arose in 1978 when theolder PSD regulations, which did not requireextensive baseline air quality monitoring,

were replaced by new regulations that re-quired monitoring for a l-year period. Whenthis happens, the agency’s resources areoverwhelmed and applications are delayed.

Other delays resulted when applicationswere incomplete (information was lacking) orwhen the information that was provided wasdeemed inadequate by the agency. The firstinformational problem could be easily re-duced by a quick review of the application forcompleteness. The second is more difficult,because it involves scientific and technical

judgment. It reflects, to an extent, the factthat the oil shale processes are new technolo-gies and their effects are not totally under-stood. Standardized procedures are not al-ways available for determining compliancewith the law. This difficulty could be reducedby developing standard procedures whereverpossible. This has been done already in someareas of the PSD process where, for example,the developers are required to use standarddispersion models authorized by EPA.

The Region VIII office recently issued a pol-icy statement that addresses its efforts to im-




prove the permitting procedures. A key ele-ment is designing a standard application thatdefines the specific data needs and recom-mends procedures for obtaining the data.There is also an effort to educate developersin using the application by holding public

workshops on the permitting procedure. Also,at the Federal level, one focus of the proposedEnergy Mobilization Board is to expediteagency decisionmaking and reduce the im-pacts of new regulatory requirements thatmay emerge after construction or operationsbegin.

The State of Colorado, with funding fromDOE, is designing and testing a permit reviewprocedure for major industrial facilities thatwill coordinate the reviews by Federal, State,and local regulatory agencies. The procedureis also planned to expand the public’s oppor-tunities to become involved in all phases of project planning and review. It is being testedwith a controversial molybdenum projectnear Crested Butte, Colo. A handbook will bedeveloped on completion of the test. This mayaid in applying similar methods to the permit-ting process for oil shale plants. *

Policy Options

The policy options presented here rangefrom working to better understand complex

regulatory processes, through using the re-sults of such work to reduce the complexities,to waiving the laws or regulations. This rangeencompasses actions over which there is littledisagreement through those which involve ex-treme controversy. Few would argue that reg-ulatory procedures could be improved, whilemany would resist changes that could resultin weakening environmental protections.

Study the Causes of Permitting Delays

Further study of the permitting procedurecould help to identify and eliminate some of the causes of regulatory inefficiency. Such

“Colorado hopes this joint review process, which providesfor concurrent rather serial review of applications, will alsoreduce the time needed for review.

studies have been conducted by EPA’s RegionVIII office for the PSD process. The NationalCommission on Air Quality is conducting amore comprehensive evaluation of alterna-tive means for achieving the goals of theClean Air Act with more manageable regula-

tory procedures. Similar studies could bemade of other laws and regulations.

Increase the Resources of the

Regulatory Agencies

Increasing the personnel and financial re-sources of the Federal regulatory agencieswould allow them to improve their responsecapabilities. The agencies could also providetechnical assistance to the State and localregulators to aid in their decisionmakingprocesses, However, a simple increase in

agency funding, without a methodology forcoordinating the expanded resources, wouldnot guarantee that procedures would im-prove.

Improve Coordination Among Agencies and

Between Agencies and the Public

The permitting process might be improvedif coordinated reviews were conducted by thevarious agencies. This strategy would help toidentify and reduce jurisdictional overlapsand to reduce personnel needs and paper-

work loads, A major advantage would be theopportunity for sharing analytical responsi-bilities and results. The public hearings thatare required for many separate permits couldalso be consolidated. The strategy could bepatterned after the voluntary joint reviewprocesses that are being developed in Col-orado and other States. However, unless theapproach were mandated, it is questionablethat interagency cooperation would be sig-nificantly improved.

Another approach would involve the estab-

lishment of a regional environmental monitor-ing system to determine baseline conditionswithin all areas to be affected by oil shaleprojects. The system could better character-ize baseline conditions than could individual,uncoordinated monitoring programs. It might



350 qAn Assessment of O// Shale Technologies

reduce the duration and the cost of the ad-vance monitoring programs that are requiredof permit applicants. Site-specific measure-ments would still be required to characterizebiological communities, soils, hydrology, andgeology for projects involving Federal land.

Baseline surveys could be conducted by Fed-eral agencies on potential lease tracts toshorten the time between a leasing decisionand commercialization. The cost of the pro-gram could be included in the cost of thelease. Individual monitoring of stack emis-sions, water discharges, and reclamation ef-forts would also still be needed as the proj-ects proceeded.

Improved coordination of public participa-tion might also shorten review time by reduc-ing controversy, political confrontation, andlitigation. Procedures might include advancepublic notification of the status of permit ap-plications, the dissemination of technical in-formation and R&D results, and the more di-rect involvement of the public in an agency’sdecisionmaking process through, for exam-ple, workshops and public meetings. It is pos-sible that increasing the public’s awarenessof the characteristics of a project might leadto perceptions of greater risk. On the otherhand, education could lessen nonproductivediscussions and confrontations. In any case,it may be difficult to educate the public in thetechnical aspects that determine whether anapplication satisfies the standards. To main-tain a high level of participation, some inter-vener groups may seek financial and techni-cal assistance. This would be controversial,especially from the point of view of the devel-opers.

Clarify the Regulations and

the Permitting Procedure

One option would be to expedite promulga-tion of standards for visibility and hazardous

emissions under the Clean Air Act, and to setthe as yet undefined NSPS for oil shaleplants. Additional regulations could also bedefined under RCRA, TSCA, and other laws.These actions would eliminate many of theregulatory uncertainties and would allow the

developers to integrate controls for the newstandards into their plant designs. If it is de-sired to reduce developer risks, new stand-ards should be firmly established and notsubject to change for an extended period.This may not be appropriate, since early ex-

perience with the industry may indicate aneed to modify the standards to achieve thedesired level of protection. In addition, theymay be difficult to establish. Excessively laxstandards would not adequately protect theenvironment; excessively strict ones mightunnecessarily preclude development. Thesehazards are particularly applicable to settingNSPS.

Another approach would be to simplify thepermitting procedures themselves, based oninformation from the investigations suggested

under the first option. This would have theadvantage of retaining the protection of theexisting laws while making it easier to complywith them. However, problems (such as theuncertain status of applications in progress)might arise during the transition from the oldregulatory system to the new. It is also oftendifficult to isolate the substance of environ-mental protection laws from the implementa-tion procedures. Any proposed changes in theprocedures would need careful examinationby the agencies, the developers, and the pub-lic.

A third approach would be to establish de-tailed, standardized specifications for permitapplications. This would reduce the problemof insufficient data being provided with theapplications and the delays that would becaused when agencies request the additionalinformation they feel is necessary for a thor-ough review. Fully comprehensive standard-ized forms are probably not possible, andsome interactions after an application is sub-mitted will still be needed.

A fourth option would be to have a mora-torium on new regulations until some of theactual effects of development are determinedon the Prototype Program lease tracts. (Moni-toring of environmental effects and develop-ment of control techniques is one of the major



Ch 8–Environmental Considerations 351

objectives of the Program. ) A disadvantage isthat the regulatory uncertainties would re-main. An advantage is that the regulationscould be promulgated from a better knowl-edge base,

Expedit e the Permitt ing Procedure

The proposed Energy Mobilization Boardwould expedite permitting by negotiating aproject schedule with a developer and thenenforcing the schedule by making regulatorydecisions if the responsible agency does notdo so within a specified period. Proponents of this strategy point out the advantages of acentral authority that could provide a singlepoint of contact between the developer andthe regulatory system. Opponents feel that

such an authority would add another layer of bureaucracy, would increase controversyover the projects that are expedited, andwould ultimately not have substantial effectson permitting delays.

Another method would be to limit the peri-od during which litigation can be initiatedagainst a particular permitting action, Thismechanism could be similar to that employedin the case of the Trans-Alaska oil pipeline. Itwould reduce the risk of agency actions being

subjected to legal challenges that could jeop-ardize a project’s completion schedule. Itshould be noted, however, that legal mecha-nisms already exist in some specific laws tolimit the period of litigation, The expeditingstrategy could extend this protection to most,if not all, of the relevant statutes,

Limi t the Applic ati on of New Environmental Laws

and Regulations

Plants already under construction, or thatare operating, could be exempted from theprovisions of new environmental laws and

regulations. This approach—’’grandfather-ing ”—is embodied in the legislation for theEnergy Mobilization Board. It would removemany of the regulatory uncertainties. How-ever, it is surrounded with controversy be-cause new regulations might be needed todeal with problems that could not be discov-ered until after operations begin. Many of thepresent laws contain provisions to exempt ex-isting facilities from new requirements.These include either automatic exemptionclauses or economic criteria against whichthe new regulatory requirements must be

tested.

Waiving Existing Environmental Laws

This strategy would exempt a project fromthe provisions of some or all existing environ-mental laws and regulations that might delayor prevent its construction and operation.This measure would remove virtually all of the problems and delays associated with thepermitting. However, it would have seriouspolitical, environmental, and social ramifica-tions since it could arbitrarily preempt envi-

ronmental protection under the law. Further-more, the waivers might give an undeservedcompetitive advantage to the developers whoreceived them. The allocation of the waiverswould be highly controversial, The extent towhich this action would speed the deploy-ment of the industry is unclear.













CHAPTER 9

Water Availability

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . .Page359

Summary of Findings . . . . . . . . . . . . . . . . . . . . 359

Analysis of Water Requirements for OilShale Facilities . . . . . . . . . . . . . . . . . . . . , .. 361Introduction . . . . . . . . . . ., . . . . . . . . . . . . . . . 36 1Process and Facility Models Analyzed .. ....361Water Requirements . . . . . ., . ............362An Evaluation of Assumptions in the Estimates363Range of Water Requirements. . ...........366

Water Resources: A Physical Description. .. .367SurfaceWater . . . . . . . . . . . . . . . . . . . . . . . . .367GroundWater. . . . . . . . . . . . . . . . . . . . . . , . , .373

AIIocationoftheColorado RiverSystemWaters q**.**.*.***** . ........374

Compacts, Treaties,andLegal Mechanisms. .375

Surface WaterAllocations. . ..............376Doctrine ofPriorAppropriation . ..........377Introduction . . . . . . . . . . . . . . . . . , , , . . . . . . .377SurfaceRights . . . . . . . . . . . . . . . . . . , . . . . . .377Ground WaterRights. . ..................379

FederalReservedRights . . . . . . . . . . . . . . . . . 3 7 9

Page

Physical AvailabilityofSurfac@ Water forOil ShaleDevelopment. . ...............380

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . .380

The Availability ofSurface WaterintheUpper Colorado RiverBasin . ............382Water Availability inHydrologic Basins

Affected by OiIShaie Development . ......385

Water AcquisitionStrategi@s andTheirCosts 388PerfectionofDeveloperWater Rights .......388Purchase ofSurplusWaterFrom FederaI

Reservoirs. . . . . . . . . . . . . . . . . . ..~..”.”.389Purchase ofIrrigationRights . .............389GroundWaterDevelopment. . ..........,..391InterbasinDiversions. . ..................392IntrabasinDiversions. . ..................393Summary ofSupplyCosts. . ...........000.394

Legal andInstitutiona~Considerations .. ....395TheLawoftheRiver. . . . . . . . . . . . . . . . . . . . . 3 9 5The Doctrine ofPrior Appropriation . .......396FederalReservedRights Doctrine . .........396Environmental Legislation . ...............397InstreamWaterFlow . . . . . . . . . . . . . . . . . . . . 3 9 8





CHAPTER 9

Water Availability

Introduction

The oil shale deposits are located within

the Upper Colorado River Basin, which in-cludes the Colorado River and its tributariesnorth of Lee Ferry, Ariz, These waters arecritical resources in the semiarid region.They are used for municipal purposes, irri-gated agriculture, industry and mining, ener-gy development, and maintaining recreation-al, scenic, and ecological values. In the past,natural flows within the basin along withwater storage and diversion projects havegenerally been adequate to satisfy demand.In the future, however, water resources maybe taxed by rapid population growth, by ac-

celerated mineral-resource development, andby increased recreational activities. Even-tually, the availability of water may limit re-gional growth including the expansion of in-dustrial developments such as oil shale.

This chapter analyzes the availability of water in the oil shale region. The followingsubjects are discussed:

Summary

Surplus surface water will be available to supplyan industry of at least 500,000 bbl/d through 2000if:

q

q

q

additional reservoirs and pipelines are built;and

demand for other uses increases no faster thanthe States’ high growth rate projections;

and average virgin flows of the Colorado River do notdecrease below the 1930-74 average (13.8 mil-lion acre-ft/yr).

Otherwise, surface water supplies would not be ade-quate for this level of production unless other useswere curtailed, interstate and international deliveryobligations as presently interpreted by the Govern-ment were not met, or other sources of water were

estimated water requirements for oil

shale facilities and their related growth;the surface water and ground water re-sources of the oil shale region;the laws, compacts, treaties, and otherdocuments that allocate the waters of the Colorado River system;the appropriation doctrine of Colorado,Utah, and Wyoming for distributingwater supplies within State boundaries;the Federal reserved right doctrine:the physical availability of surfacewater for oil shale development;strategies and costs for utilizing water

supplies;the uncertainties affecting water re-source assessments;the impacts of water use;some methods for increasing wateravailability; andthe policy options that might be imple-mented to increase the availability of water.

Findings

developed. On the other hand, if the reservoirs andpipelines are built, flows do not decrease, and theregion develops at a medium rate (which the Statesregard as more likely), there should be sufficientsurplus water to support an industry of over 2 millionbbl/d through 2000.

In the longer term, surface water may not be ade-quate to sustain growth; surplus water availability ismuch less assured after 2000. If the river’s flows donot decrease, and if a low growth rate prevails, de-mand will exceed supply by 2027 even without an oil

shale industry. With a medium growth rate, the sur-plus will disappear by 2013. A high growth rate willconsume the surplus by 2007, again without any oilshale development. This is a potentially serious prob-lem for the region, and its implications for oil shale

359




development are controversial. On the one hand it isargued that there is no surplus surface water andthis should preclude the establishment of an indus-try. On the other hand, it it maintained that thefacilities in a major industry could function for muchof their economic lifetimes without significantly in-

terfering with other users, and in any case would userelatively little water. (A 1-million-bbl/d industrywould accelerate the point of critical water shortageby about 3 years if only surface water were used. )

Other findings are:

q Depending on the process used, production of50,000 bbl/d of shale oil syncrude would con-sume 4,900 to 12,300 acre-ft/yr of water, in-cluding water for related municipal growth andpower generation.

q A million bbl/d industry would require about170,000 acre-ft/yr. * This would be about 1percent of the virgin flow of the Colorado Riverat the boundary of the Upper Basin, about 3percent of the water consumed at present by allusers in the Upper Basin, and about 2 percentof projected consumption in 2000.

q Potential oil shale developers already own rightsto substantial quantities of surface water. In1968, for example, five companies claimedrights to enough water to produce several mil-lion bbl/d of shale oil.

q Existing developer rights would probably notassure supplies because surface water is over-appropriated and oil shale rights could be inter-rupted during shortages. More reliable suppliescould be provided through purchase of surpluswater from existing Federal reservoirs, pur-chase of irrigation rights, ground water devel-opment, and importation of water from other hy-drologic basins.

q Costs of the most expensive water supply op-tion, importation from other basins, could ex-ceed $0.80/bbl of shale oil produced. Otherstrategies would cost less than $0.50/bbl of oil.These costs include the amortized costs of res-

* I+>or comp:]rison, irrigated [agriculture along the WhiteRiver and the Colorado River consumes about 549,000 acre-ft/yr to produce 3 percent of Colorado’s crop production. This isequ ivn]ent to the wn ter needs of a 3. 2-mill ion-bbl/d oil shale in-(iustrv.

q

q

q

q

q

ervoir and pipeline construction and the cost oftreating the water to industrial standards. De-velopment of high-quality ground water wouldbe least expensive but would be limited to spe-cific areas.

All strategies that relied on surface water would

require construction of new reservoirs and pipe-lines, principally in the White River basin in Col-orado and Utah. About 180,000 to 230,000acre-ft of new storage would be needed for a 1-million-bbl/d industry. Active capacity of exist-ing reservoirs in the Upper Basin is about 34.7million acre-ft. New construction for oil shalewould increase storage by less than 0,6 per-cent.

If a 2-million-bbl/d industry were developed,flows of the Colorado River would be reduced,and its salinity could increase by approximately

2 percent. Studies by the U.S. Water and PowerResources Service (WPRS)* and the ColoradoDepartment of Natural Resources (DNR) indi-cate that the economic losses from thesechanges could reach $25 million per year by theyear 2000–the equivalent of $0.04/bbl of oilproduced.

Sale of irrigation water to oil shale developerswould reduce farm production. At present, de-velopers do not plan to purchase such water insignificant quantities. Therefore, effects on thefarming industry should be small, especiallycompared with the effects of competition forlabor and the purchase of farmlands for munici-pal growth.

Studies by USBR and DNR indicate that envi-ronmental impacts of water-resource develop-ment for oil shale should be small overall on theUpper Basin but could be large in some areas.Fish habitats and recreational activities alongthe White River are expected to be the mostseverely affected. Impacts on the Lower Basinare not expected to be substantial.

Regional development could be limited by wateravailability after 2000. Importation of waterfrom other basins, conservation by municipal,agricultural, and industrial users, and possibly

*Formerly the U.S, Bureau of Recltimation (USBR), For easeof reference, most citations in this ch{)pter are to the USBR.





—


3.

4.

5.

6.

Paraho indirectly heated AGR,Union Oil “B” indirectly heated AGR,Occidental Oil Shale’s directly heatedMIS retorts, anda combination of directly heated MISretorts and Lurgi-Ruhrgas indirectly

heated AGR.The water requirements of these facilities

were scaled to a common basis of 50,000bbl/d of synthetic crude oil. Thus, units forupgrading crude shale oil to a high-qualitysynthetic crude are included. Each facilitygenerates sufficient electric power for it sown needs, and all solid waste dumps are re-vegetated. Wastewater is recycled whereverpractical, and only excess mine drainagewater is discharged or reinfected. Disposingof solid wastes by slurry backfill, either to themine or to the burned-out in situ retorts, is notincluded. The effects of byproduct coke, am-monia, sulfur, or gas are not evaluated. Truein situ processes are not analyzed because nodata are available.

With the exception of the Union “B” plant,each estimate discussed in this section is de-rived from a published conceptual design, 1-9

either the developer’s or one that has beenmodified to put plant material and energy bal-ances on a consistent basis. Although little in-

formation has been published, the Unionprocess is considered here because plans fora plant have been announced. ’() However, thedata cannot be treated with the same confi-dence as for other processes.

A number of other studies’ ’-” have been

completed but are not discussed in this sec-tion. Although they were based on data sup-plied by the developers, their conclusions didnot agree because different retorting pro-cedures, products, production rates, powersupply modes, shale grades, and disposal pro-cedures were assumed.

Water Requirements

The water requirements of the six oil shalefacilities, after scaling, are summarized intable 72. As can be seen, even facilities thatuse similar processes (e. g., indirect AGR) re-quire different amounts of water. However,when the requirement for each subprocess isrepresented as a percent of the total, there isa correlation among different plants that usesimilar kinds of technology, as shown in table73. It is noteworthy that:

Mining and dust control require consid-erably more water in AGR than in eitherMIS or MIS/AGR. This is because about

Table 72.–Water Requirements and Mine Drainage Production for 50,000-bbl/d Oil Shale Facilities (acre-ft/yr)

Retorting technology

Study

Reference

Unit operation Mining and handling.Power generation .,Retorting and upgradingShale disposal and

r e v e g e t a t i o nMunic lpa l useNet water requirements I n a c r e - f t / y r . ,In bbl water/bbl 011.

Mine drainage water In acre-ft/yr .In bbl water/bbl oil,

Paraho direct TOSCO II

McKee-Kunchal WPA/DRI Colony WPA/DRl

4 1 3 1

ParahoIndirect Union ‘'B” Oxy MIS MIS/AGR

McKee- Eyring-Kunchal Sutron Oxy 1977 Oxy 1979 WPA/DRl WPA/DRl

4 9 5 9 1 1

816 941 1,045 1,045665 (b) 1,233 1,233

2,616 2,375 5,038 3,821

1,644 1,385 3,895 3,956645 645 594 594

6,386 5,346 11,805 10,694271 2.27 5.02 4.53

(b) (b) (b) (b)(b) (b) (b) (b)

934 – 483 483 338 326 761 1,233 (b) (b) (b) (b)

3,487 1,470 9,234 2,502 3,601 3,051

4.020 3,090 2,818 1,103 1,103 1,461731 731 775 775 775 818

9,933 6,524 13,310 4,863 5,817 5,6564,22 2 7 7 5.66 2.06 2.47 2.40

(b) (b) 6,440-16,1004.032-6,452 12,326 8,454(b) (b) 2.74-6,86 1,56-2.50 5.25 3.60

a.$ee reference IISI at end of chapterbN ot apPllcab[e for projector Site analyzed

SOURCE R F Probslem et al Wafer Reqwrenrerrfs Po/M/on IIfecfs arm Costs of Wafer Supply and Treafcnenf (or the 0/( Shale hrdusfry reporl prepared for OTA by Water Punhcallon Assoc!ales October1979 p 8



Ch 9–Water Availability c 363

Table 73.–A Comparison of the Water Requirementsof the Various Subprocesses

Generic technology (in percent)

Indirect andSubprocess direct AGR MIS/AGR MIS

Mining and handling 9-18 4-1o

Power generation 8-12 ( a (a)Retorting and upgrading 35-44 54 51-69Disposal and revegetation 26-40 26 19-26M u n i c i p a l u s e 5-12 14 6-16

a~ot applicable ‘or project or slfe

SOURCf

q

q

R F Probsfeln et al Waler Ftequfremerrls PoI/ufIorI EVec[s am Costs of Waler Sup Dly and r[ewrnenl for Ihe O// Shale /ndu$vj reporl orepared for OTA by Water Purlhca

IIon Associates October 1979 D 9

four times as much shale is mined andhandled in aboveground processing. Thelarger amount of material also results inhigh water requirements for disposaland revegetation.

No water is needed for power generationin MIS and MIS/AGR because power willmost likely be generated by burning low-Btu gases in open-cycle gas turbines thatdo not need to be cooled. Even if com-bined-cycle systems were used, very lit-tle cooling water would be needed. Cool-ing water is needed for AGR because sol-id-fuel steam-cycle systems will prob-ably be used,Municipal water needs are proportionalto the number of mine and plant employ-ees. For the same output, more workers

are required for MIS (about 1,800) thanfor AGR (about 1,400 to 1,700). It is as-sumed that the MIS/AGR process wouldrequire slightly more workers (about1,900) than either technology by itself.

Retorting and upgrading require the mostwater. All the technologies need comparableamounts of water for upgrading, therefore,the differences among alternate technologiesreflect differences in retorting efficiencies.The large differences between similar above--ground technologies result from specific oper-

ating characteristics, especially the methodsfor heating the retort and for disposing andreclaiming the spent shale, More water is re-quired for indirect than for direct AGR be-cause indirect heating has a significantlylower overall thermal efficiency,

Spent shale disposal and reclamation re-quire large amounts of water in the TOSCO IIand Paraho indirect designs (about 4,000acre-ft/yr), while the estimate for the Parahodirect process is about 60 percent lower,Largely because of this difference, the over-

all requirement for Paraho direct is onlyabout 5,900 acre-ft/yr, while the TOSCO IIand Paraho indirect designs need about10,500 acre-ft/yr or almost twice as much.

The requirements for MIS retorting andupgrading are similar to those for indirectAGR. However, because little water is neededfor mining and waste disposal, overall waterrequirements for MIS are similar to those fordirect AGR; that is, about 5,800 acre-ft/yr.For similar reasons, the requirements forMIS/AGR are similar to those for MIS alone.

It has been assumed that none of the AGRplants will produce mine drainage water. TheMIS and MIS/AGR facilities, however, areassumed to produce such water in substan-tial quantity. This difference is not related tothe technologies but rather reflects the sitingassumptions made for the various plants. TheMIS and MIS/AGR facilities are on tracts C-aand C-b in the ground water areas of the cen-tral Piceance basin, while the AGR opera-tions are in drier areas along the southernfringe of the Piceance basin or the easternportion of the Uinta basin. Mining in ground

water areas produces mine drainage waterthat must either be used, discharged, or rein-fected. The amount produced varies with lo-cation, Estimates for tract C-b range from4,032 to 16,100 acre-f t/yr

16

and for tract C-ato at least 18,100 acre-ft/yr. 17 This watershould be regarded as an alternate water re-source and not as part of the process. Similaroperations in other locations may not producecomparable amounts of water.

An Evaluation of Assumptions in

the EstimatesDetailed breakdowns of the water required

and produced by each principal operation ineach model facility are shown in table 74.(Table 72 was derived from these data.)




Table 74.–Breakdown of Water Requirements and Water Production for 50,000 -bbl/d Oil Shale Facilities (acre-ft/yr)

ParahoParaho direct TOSCO II indirect Union ‘ ‘B’ Oxy MIS MIS/AGR

McKee- M c K e e= Eyring-Kunchal WPA/DRl Colony WPA/DRl Kunchal Sutron Oxy 1977 Oxy 1979 WPA/DRl WPA/DRl

Water required Mining and ore handling

Power generationRetorting and upgrading

Cooling tower makeupRetortingU p g r a d i n gOther boiler makeupSteam and treatment

l o s sService and fire waterPotable and sanitary

Disposal and reclamationShale moisturizingDisposal and

compactionRevegetation

Municlpal demand

934 (a)

952 d 1,850d

483

(c)

483

(c)

338

(c)

326

(c)

816 941

832b (c)

1,045

1,850b

1,045

1,850d

3,849 3,854’ — o — 939d

1,224 490e

3,8611,884

939557

3,939668939557

4,406 – — — — —

1,401 1 ,71Ob

6,875 e

2,731939 d

985 e

8063,753

939d

525

4,494’2,731

939d

551 e

3,626 e

1,873939529’

— 50 — 69 — 39

5726034

5726034

39(a)

113

5872,111

161

1096731

756028

— — — — — —

2,920(c) (c) 2.859 (c) – (c) (c) (c) (c)

1,664 972413

1,61 4b 1,614b

428608

1.485b

428608

1,485°

— 2,8704,020 2201,829b 1,829b

1,2081,6101 ,937b

346757

1 ,937b

346757

1 ,937b

1,239’222 d

2,045 d

Total required 9,979 9,378 16,182 15,105 13,542 8,479 16.920 12,405 12,300 10,962

Water produced Power generation 167d (c) 617a 617d 191 d

617d (c) (c) (c) (c)Retorting and upgrading

Cooling towerblowdown . 768 1,653e 1,240 1,319 880 (a) 625 e (a) 1,038e 907 e

Retort condensate 127 (a) (a) (a) 388 240 1,243 2,419 1,243 852Gas condensate 752 542 728 728 125 – (a) 3,072 2,157 1,480Upgrading

c o n d e n s a t e s 540 l 0 3d103 103 618 (a) l 0 3d

103 103 103Boiler and treatment

w a s t e 270 487e 557 557 309 (a) 486 e 384 530’ 513eService water effluent (a) 30 27 27 (a) (a) (a) 241 26 27Potable and sanitary

effluent (a) 26 26 26 (a) (a) (a) 161 23 20Surface runoff’ (a) 222 188 188 (a) (a) (a) (a) 201 177

Municipal effluent 969 d 969d 891 89 1d 1.098d 1,098 d 1, 162d 1, 162d 1, 162d1,227d

To ta l p r o d u c e d 3 ,5 9 3 4,032 4,377 4,456 3,609 1,955 3,619 7,542 6,483 5,306Net consumption In acre-ft/yr 6,386 5,346 11,805 10,649 9,933 6,524 13.301 4,863 5,817 5,656In bbl water/bbl oil. 271 2 2 7 5,02 4 5 3 4 2 2 2.77 5 6 5 2.06 2.47 2,40Mine drainage I n a c r e - f t / y r (c) (c) (c) (c) (c) (c) 6,440-16,1004,032-6,452 12,326 8,454 e

In bbl water/bbl 011 (c) (c) (c) (c) (c) (c) 2.74-6.86 1.56-2,50 5 2 5 3.60 e

atiot prowded bincludes mlnlng and re10flm9 cNot apphcab le ‘Esllma ted by OTA ‘Modd)ed lor OTA

SOURCE R F Probsteln ef al Waler Reqwrerrrenls Po//u(/orr Effects and Cosfs of VLXer Supp/y and Trearmertl for [he Od Shd/e /rrUIJs/ry reporl prepared for OTA by Waler Purlflca[lon Associates October1979 p 14

Paraho Direct sign assumed that a water-cooled steam cyclewould be used; the Water Purification Asso-ciates/Denver Research Institute (WPA/DRI)

design assumed that low-Btu gas would beburned in open-cycle gas turbines that re-quire no cooling water.

The two estimates for Paraho direct are

reasonably consistent. However, the McKee/ Kunchal water management plan is not suffi-ciently detailed for a thorough evaluation tobe made of the differences that appear. Thetwo designs differ principally in the mode of power generation. The McKee/Kunchal de-

The retorts are also operated differently. Ahigher retorting temperature is assumed in



Ch 9–Water Availability q 36 5

the WPA/DRI design, and the water producedduring retorting is vaporized and exhausted,In the McKee/Kunchal design, lower tempera-tures cause partial condensation of the retortwater. Also, upgrading was not considered byWPA/DRI, and it was necessary to adapt esti-

mates from the TOSCO II plant design,The chief uncertainty is the claim of mini-

mal water needs for spent shale disposal. TheWPA/DRI design, which was based on thisclaim, uses a conservative estimate of 5 per-cent by weight of water for compaction anda separate estimate for revegetation. TheMcKee/Kunchal estimate is not directly com-parable because it combines compaction andrevegetation. However, the total values arereasonably consistent.

Paraho’s claim that proper compaction canbe obtained with small water additions isbased on evidence from disposing about 150ton/d of spent shale. It is uncertain that suffi-cient moisture could be extracted from the at-mosphere to dispose of 72,000 ton/d, the out-put of a 50,000-bbl/d plant.

TOSCO II

Although the Colony water managementplan is very detailed, neither Colony norWPA/DRI assumed onsite power generation.

OTA’s analysis assumed that about 85 MW of power would be generated by a steam-cyclesystem.

A principal difference between the designsis that WPA/DRI substituted a bag filter andelectrostatic precipitator for Colony’s venturiwet scrubbers, thereby reducing water con-sumption. Both designs assumed that thespent shale is moisturized to 14 percent byweight of water to allow proper compaction.For revegetation, both designs assumed anaverage value of 608 acre-ft/yr over the 20-year life of the plant. During the first 10years, little revegetation would be done andwater would be used only for compaction anddust control. In the second 10 years, revege-tation programs would be expanded andwater needs would increase.

Paraho Indirect

It is not possible to fully evaluate theParaho indirect estimates because theMcKee/Kunchal report lacks a detailed watermanagement scheme. Compared with TOSCOH, retorting and upgrading requirements ap-pear low. Also, the requirement for revegeta-tion is much higher than for all other retorts.The reason given is the high carbon content of the spent shale, but this conclusion is not sup-ported by Union’s experience with similar re-torted shale. The high estimates for revegeta-tion may have been made to offset low esti-mates for compaction. l8

Union Oil “ B”

Because only crude data are available, judgment should be reserved on the low esti-mates for mining, retorting, and upgrading,The Environmental Protection Agency (EPA)recently published a considerably higher esti-mate for mining and processing that wouldlead to a total consumption more in line withestimates for other processes. 19 Unfortunate-ly, the higher estimate cannot be verified be-cause no background information was sup-plied. An older EPA document20 provides avalue for mining and processing consistentwith the Eyring/Sutron estimate. The relative-ly large requirement for spent shale disposalis a consequence of Union’s method for cool-ing the hot retorted shale by immersing it inwater,

Occi dental (Oxy) Modif ied In Sit u

The older Oxy estimate differs significant-ly from the WPA/DRI design in both water re-quirements and water production. Oxy’s re-quirements are higher for cooling water, forraw shale disposal, and for revegetation, Itappears that these uses were deemed appro-priate for disposing of excess mine drainagewater. Much less water is wasted in theWPA/DRI design and in the newer Oxy plan.Also, the production of retort condensate wasnot estimated in the older Oxy plan. TheWPA/DRI estimate (2,157 acre-ft/yr) wasbased on Oxy’s estimates of the steam flows




to the retorts. (Much more condensate wouldbe produced if ground water entered the re-torts during their operation. ) WPA/DRI alsoassumed that the retort gases are not com-pressed prior to gas cleaning. This reducesthe cooling water requirement, although it in-creases the cost of the gas cleaning equip-

ment. The net difference (considering conden-sate production and cooling water reduction)is about 6,700 acre-ft/yr, which accounts formost of the discrepancy between Oxy’s olderplan and the WPA/DRI study. In general, theWPA/DRI results agree quite well with Oxy’scurrent water management plan.

Modified In Situ/Aboveground Retorting

The only published water managementplan for a combined facility is that of the RioBlanco project on tract C-a. Details are not

sufficient for a thorough evaluation and theplan is now obsolete because Rio Blanco hassince revised its approach. The WPA/DRImodel, which combines MIS with Lurgi-Ruhr-gas retorts, is similar to the current plans forthe tract.

The principal difference between OTA’sprocess model and those of Rio Blanco orWPA/DRI is that OTA has assumed surfacedisposal of the spent shale, whereas theothers assumed that the waste is returned asa slurry to the burned-out in situ retorts. In

OTA’s analysis, it is assumed that the vaporlosses during moisturizing are the same as inunderground slurry disposal. The estimatesfor both revegetation and upgrading werelinearly scaled from the TOSCO II require-ments. The accuracy limitations noted in theMIS discussion also apply here.

Municipal Use

It is assumed that the tota l populat iongrowth will be 5.5 times greater than thenumber of employees.21 Because this large

multiplier is applied to uncertain employmentfigures, the estimates of municipal waterneeds are approximate. An aggregate re-quirement of 175 gal/person/d has beenassumed, with consumption at 40 percent of

this figure, The net requirement—70 gal/per-son/d—is conservatively high. The averagerequirement for all the facilities considered isabout 700 acre-ft/yr.

Mine Drainage Water

Probably the largest uncertainty of all,because it is highly site dependent, is theamount of mine drainage water produced. Asnoted above, estimates for the Federal leasetracts range from 6,400 to over 18,000 acre-ft/yr. This water should satisfy the processingneeds of the technologies proposed for tractsC-a and C-b. However, these needs couldprobably not be satisified by ground water onsites along the edge of Piceance basin.

Range of Water Requirements

The most likely ranges of the quantities of water that will be consumed by the three ge-neric technologies and by the combined plantare indicated in table 75, Also shown are thelikely ranges of mine drainage water produc-tion on tracts C-a and C-b. Overall, the re-quirements range from 4,900 to 12,300 acre-ft/yr—the equivalent of from 2.1 to 5.2 bbl of water consumed for each barrel of oil pro-duced. Given this range, a l-million-bbl/d in-dustry could require from approximately100,000 to 250,000 acre-ft/yr. Actual water

requirements would be determined by themix of technologies used. In table 76, theserequirements are estimated for an industrythat would result if present projects, both ac-tive and proposed, were completed. Some fea-tures of this industry are:

q

q

q

Indirect AGR, the method with the high-est unit water requirement, constitutes51 percent of the total production.Direct AGR and MIS, which require lesswater, constitute only 33 percent of pro-duction. The balance is provided by MIS/

AGR, which has an intermediate re-quirement.About 43 percent of the production willresult from mining in ground waterareas in the central and northern Pice-



Ch. 9–Water Availability q 367

Project

RIO BlancoCathedral BluffsLong RidgeColonySand WashEXXONWhite RiverSuperior

Table 75.–Likely Ranges of Water Requirements and Mine Drainage Productionfor Oil Shale Facilities Producing 50,000 bbl/d of Shale Oil Syncrude

Water requirementsa

Average shale grade,Technology gal/ton Acre-ft/yr Barrels per barrel of 011

Directly heated AGR 29-32 4,900-7,800 2 1 - 3 3Indirectly heated AGR 32-35 9,400-12,300 4 0 - 5 2

D i r e c t l y h e a t e d M I S 23-27 4,900-5.900 2 1 - 2 5M I S / A G R 23-25 5,700-6,700 2.4-29

Location Water production

M i n e d r a i n a g e w a t e r C-a/ C-b 4,000-16,100 1 6-69

a~el ~a[ef ~eqUlre~enls Low end assumes higher shale grade open cycle power systems high relorl efficiency and lower waste dls Posal and ‘eclamalion needs High end assumes lower shale grade sleam cycle or comt)lned cycle systems low retorhng efficiency and higher disposal and ‘ecIamaflon needs

SOURCE R F Probsleln el al Wafer Re~wreme~fs PoI/ufIorI Ef(eck and Cos(s of W a f e r SW@y and Treafrner?( for fhe 0// S/ra/e (ndus[ry re?orl p r eoared for OTA by Waler Purihcahon Assoclales October 1979 p 22

Table 76.–Water Requirements for Active and Proposed Oil Shale Projects

Location

Central Piceance basinCentral Piceance basinSouthern Piceance basinSouthern Piceance basinUinta basinCentral Piceance basinUinta basinNorthern Piceance basin

Deposit

Design capacity

Barrels PercentTechnology per day of total

WetWetDryDryDryWetDryWet

MIS/indirect AGR 76,000MIS 57.000Indirect AGR 75,000Indirect AGR 46,000Indirect AGR 50,000Indirect AGR 60,000Direct AGR 100,000lndirect AGR 11,500

16121610101321

2

Water requirements acre-ft/yr

For 50,000 For design Weightedbbl/d capacity contribution

6,200 9,424 - 992- –

5,400 6,156 64810.850 16.275 1,73610,850 9,982 1 08510,850 10,850 1 08510,850 13,020 1 , 4 1 1

6.350 12700 1,33410,850 2,496 217

Total 475,500 100 80,903 8,508


ance basin. These plants could obtain The following sections will use these esti-their process water from the aquifers in mates in conjunction with estimates of sur-the mining zone. Surface water would plus surface water availability and other

not be needed. critical factors to identify the level of shale oilThe total production from this combination production at which water scarcity might re-

(475,000 bbl/d) would require 80,903 acre- strict development. The issues section of this

ft/yr, On this basis, a 50,000-bbl/d plantchapter discusses the industries that might

would need about 8,500 acre-ft/yr; a l-mil-result if a different mix of technologies were

lion-bbl/d industry about 170,000 acre-ft/yr.used or if ground water were developed,

Water Resources: A Physical Description

Surface water is obtained from rivers and Surface Waterstreams; ground water from underground

aquifers. In some instances, these sources The Colorado River system, which includesare physically connected and should not be the Colorado River and its tributaries, sup-evaluated independently. For example, if the plies surface water to the oil shale region.ground water supplies in most Western The Colorado River flows 1,440 miles fromStates were fully utilized, surface flows source to mouth. Its drainage area of 244,000would decrease. m i2 includes parts of seven States and Mex-




ice. The waters of the Colorado River systemare divided between the Upper ColoradoRiver Basin (which includes parts of Col-orado, Utah, Wyoming, Arizona, and NewMexico), and the Lower Colorado River Basin(which includes parts of California, Nevada,Arizona, New Mexico, and Utah). (See figures63 and 64. ) The basins are divided at LeeFerry, Ariz., 1 mile south of the Paria Rivernear the border between Arizona and Utah.

Six major streams enter the Colorado Riverin the Upper Basin, From north to south, theseare the Green, the Yampa, the White, theGunnison, the Dolores, and the San Juan. Thedrainage area of the Upper Basin has been di-vided into a number of hydrologic subbasins,each corresponding to the watershed of a major river. Oil shale development may directlyaffect three of these subbasins: the Green

River basin in the southeastern corner of Wyoming; the White River basin, which in-cludes parts of western Colorado and easternUtah; and the basin of the Colorado Rivermainstem in Colorado.

Water quality in these streams is highlyvariable. The quality in most of the upstreamreaches of major tributaries is good to excel-lent although some smaller streams that re-ceive discharge from saline ground wateraquifers are of very poor quality. Water qual-ity is significantly poorer in most downstreamareas. The gradual deterioration is caused byflows of naturally saline streams into theriver system and by man-related dischargesfrom settlements, mineral development sites,and irrigated farmlands, Water quality andthe problems it causes are discussed furtherin chapters 4 and 8.

The Colorado River system drains an ex-tensive area, but its flows are relativelysmall. The average annual virgin flow* at LeeFerry was 13.8 million acre-ft/yr between

*Virgin flow is the flow that would occur in the absence of human activitv. Most of the water availability analyses in thischapter deals with the 1930-74 average because of its commonuse in other water resources analyses. The effects of differentassumptions rega rcling virgin flow are discussed in the issuessect ion,

Upper Colorado River near Rifle, Colo.Photo credit OTA staff



Ch 9–Water Availability 369

Figure 63. —Major Hydrologic Basins of the Colorado River System

M O N T A N A

/ O R E G O N

W Y O M I N G

r

IN E V A D A UTAH UPPER COLORADO

\ RIVER BASIN

L

S O U R C E U S B u r e a u of R e c l a m a t i o n Cr/f/Ca/ Wafer PrOb/erns F a c i n g the E/eVen western ~fafes— Wesfwlde study VO/u~e / &faln ffeporfNTIS NO PB-263 9 8 1 D e nv e r Colo Aprtl 1 9 7 5

1930 and 1974, in contrast to about 180 mil- nicipalities, agriculture, energy production,lion acre-ft/yr for the Columbia River and 440 industry and mining, recreation, wildlife,million acre-ftlyr for the Mississippi River. Federal lands, and Indian reservations allDespite its relatively low flows, the system is compete for its waters.one of the most important in the Southwest. It Flows vary seasonally, increasing withserves approximately 15 million people. Mu- spring snowmelts and heavy rainstorms in




Figure 64.—The Upper and Lower Colorado River Basins

i I \ 1

. CASPER- 1

/“/’+“

“Lja~e

t:” +Great -..

kSalt .’

I -1,.-.

w ‘a’”

q DENVER

(I

.

M E X I C O

t 1

100 M ILES

SOURCE: C. W. Stockton and G. C. Jacoby, “Long-Term Surface-Water Supply and Streamflowyses,” Lake Powell Research Pro/ect Bu/let/n No. 18, March 1976, p.2

i

Trends In the Upper Colorado River Basin Based on Tree-fllng Anal.



Ch 9–Water Availability q 371

the late summer and fall and declining duringthe rest of the year. They also vary from yearto year, as shown in figure 65. Flow recordsand examination of vegetation growth cyclesindicate that they may also vary over a muchlonger period, spanning decades or even cen-

turies. The fact that virgin flows at Lee Ferrybetween 1906 and 1974 averaged about 15.2million acre-ft/yr while between 1930 and1974 they averaged only 13.8 million acre-ft/yr is evidence of this long-term variability y.

The flow variations are significant becausethey reduce the accuracy of long-term projec-tions of water availability. They also furnisha rationale for building reservoirs to offsetseasonal fluctuations and stabilize suppliesduring dry years. Several reservoirs havebeen built in the Upper Basin for this pur-pose. The five largest were built by the Fed-eral Government under the Colorado RiverStorage Project Act (CRSP) of 1956: LakePowell in Arizona and Utah, Flaming Gorge inUtah and Wyoming, Fontenelle in Wyoming,Navajo in New Mexico, and the CurecantiUnit (which includes the Crystal, Morrow

Point, and Blue Mesa Reservoirs) in Colorado.These projects have been completed and arenow being filled, When full, the existingreservoirs will have a maximum active stor-age capacity of about 35 million acre-ft/yr.Lake Powell is by far the largest, and will

have an active capacity of about25

millionacre-ft. Other reservoirs have been author-ized by Congress but funds have not yet beenappropriated for their construction. These in-clude the Savery Pothook, Fruitland Mesa,and West Divide projects. The locations of theexisting CRSP reservoirs are shown in figure66.

Reservoirs have been effective in dampen-ing the fluctuations in the virgin flows. This isillustrated in figure 67, which compares ac-tual measured flows of the Colorado River atLee Ferry with the corresponding estimates

of virgin flows for the period 1953-78. TheFlaming Gorge and Navajo Reservoirs beganfilling in 1962; Lake Powell in 1963, andFontenelle in 1964. During prior years, actualflows varied widely, from 6 million acre-ft/yrto over 17 million acre-ft/yr. In 1962, the ac-

Figure 65.—Annual Average Virgin Flow of the Colorado River at Lee Ferry, Ariz.

2 6 -

2 4 -2 2 —

H I S T O R I C20- FLOW—

—

PAST DEPLETION

)

PLUS CRSP STORAGEAVERAGE

VIRGIN FLOW

u<PROGRESSIVE 10 YEAR

r

1922-78

AVERAGE OF VIRGIN FLOW AVERAGEr ‘ (Plotted at end of year) VIRGIN FLOW

iL

[~ ~

i

F11

IL N. N

omo

\\—

IWATER YEAR

——

ill0%

——

4

II

1!-1-

0b

m

SOURCE Upper Colorado River Commlsslon. Thlrt/efh Annua/ Reporf. Salt Lake City, Utah, Sept 30, 1978, p 44




Figure 66.— Major Dams and Reservoirs on the Colorado River and Its Tributaries

WYOMING,

t1

NEVADA

q cARSOmJ CIT’Y

Y

MM Hew# - a., -... --

r

o

Ii

o Colorado River Storage Project Act Dam and Reservoir

SOURCE Upper Colorado River Commlssmn, Th/rf/eth Annua/ Report, Salt Lake City. Utah, Sept 30, 1978. p. 44




u— Actual Flow

— - — Vlrgln F l o w

? 1

; ~:: i%%ggg;g$:$-r --YEAR

SOURCE Upper Co lo rado R ive r CommlsslonTtrfrtfethAnnua/ Report SaltL a k e City Utah, Sept 30.1978. p 44

tual flow dropped substantially, partly be-

cause of low virgin flow and partly because of the start of reservoir filling. In 1968, the ac-tual flow approached 8 million acre-ft/yr andhas remained within the range of 8.23 millionto 10.14 million acre-ft/yr ever since. Between1968 and 1978, virgin flows ranged from 5.5million to 19.3 million acre-ft/yr. Actual flowshave not yet stabilized because the reservoirsare still filling.

Ground Water

Ground water resources occur near the

surface in alluvial (floodplain) aquifers andmore deeply buried in bedrock aquifers. Inmost areas, alluvial aquifers contain relative-ly little water. The amount in bedrock aqui-fers is unknown but is though! to be very

large. It has been estimated that bedrockaquifers in the Piceance basin could containas much as 25 million acre-ft in storage. Thisis nearly twice the annual virgin flow of theColorado River at Lee Ferry and is equivalentto the storage capacity of Lake Powell. Theprimary bedrock aquifer near Federal tractsU-a and U-b in Utah is estimated to contain atleast 80,000 acre-ft.

The actual quantities of ground water thatcould be used for oil shale development areuncertain. The amount available is deter-mined by the location of the aquifers relativeto potential plantsites, the water quality, andphysical characteristics such as the depthand the recharge rate. The physical char-acteristics determine the quantity of waterthat can be stored or extracted, the rate atwhich water can be added or withdrawn, and

the change in water levels that will resultfrom withdrawing a given volume of water.

The principal aquifers of the Piceance ba-sin are located in the Uinta and Green Rivergeologic formations. (See figure 68.) The sys-tem is characterized by two bedrock aqui-fers, the “upper” and the “lower,” that areseparated by a 100- to 200-ft-thick confininglayer of rich oil shale known as the MahoganyZone. In addition, alluvial aquifers occur ingravel, sand, and clay along the bottoms of stream and creek valleys.

The bedrock aquifers are recharged byspringtime snowmelt, which replaces an esti-mated discharge of 26,110 acre-ft/yr. Waterenters the upper aquifer along the basinmargins above an altitude of 7,000 ft andmoves downward through the MahoganyZone to recharge the lower aquifer. General-ly, ground water in both of these aquifersflows from the recharge areas toward thedischarge areas in the north-central part of the basin. In the discharge areas watermoves upward f rom the lower aqui fe rthrough the Mahogany Zone to the upper

aquifer and is discharged both to the alluvi-um and by springs along the valley walls.Ult imately, the discharged ground waterflows into Piceance and Yellow Creeks andthen into the Colorado River system. 22




Figure 68.— Bedrock Ground Water Aquifers in Colorado’s Piceance Basin

West East

8000’

1

7000’

6000’

5000’

4000’

1 I Vertical Exaggeration x PO Wasatch fo rmat ion

3000’ I

– 8000’

- 7000’

—

- 6000’

- 5000’

- 4000’

3000’2 6 miles~Datum is mean sea level

m : ...”O“9 e .,’e. n n El. . .,0, u::.:.:.:...O.O.O

Sand & gravel SandstoneMarlstone

Marlstone, contains High&/or conglomerate &/or siltstone oil shale & saline minerals rewstivity zone

LEGEND

SOURCE Department of the Intenor, Draft Envlronrnental Sfaternenf-Proposed Deve/opmenfof 0/ / Sha/e Resources by fh e Co/ony Deve/oprnenfOperaf/on In Co/o.rado, Bureau of Land Management (1975), p Ill 34

Despite the large resources, little groundlittle water is withdrawn, and the ground

water development has taken place to date. z water system is in hydrologic equilibrium.The major economic use is for watering live- That is, the rates of recharge and dischargestock. In addition, natural seeps and springs are equal and the amount of water in storagesupply water to vegetation and wildlife in does not change significantly over time.many of the valley floors. Overall, relatively

Allocation of the Colorado River System Waters

Because of competing demands, disputes preme Court decisions, and internationalover the proper allocation of water resources treaties has been developed to govern distri-have permeated the political, social, econom- bution of the system’s waters. Together, theic, and legal histories of the seven States in provisions of this framework comprise “thethe Colorado River system. As a result, a com- law of the river.” Their interpretation is cru-plex framework of interstate and interra- cial to an understanding of the water avail-gional compacts, State and Federal laws, Su- ability problem.



Ch. 9–Water Availability . 375

Compacts, Treaties, and

Legal Mechanisms

The Colorado River Compact of 1922

The major provisions of this compact are:

1.

2.

3.

It divided the river system into the Upperand Lower Basins, and allocated 7.5 mil-lion acre-ft/yr to each basin for bene-ficial consumptive use, Authority wasalso given to the Lower Basin to increaseits annual use by 1 million acre-ft.It did not recognize a specific obligationto provide water to Mexico. However, aframework was established wherebyany future obligation would be sharedequally between the Upper and LowerBasins.The Upper Basin was prohibited from re-

ducing the flow at Lee Ferry to below anaggregate of 75 million acre-ft in any 10-year period. The Upper Basin was not towithhold water, nor was the Lower Ba-sin to demand water that could not rea-sonably be applied to domestic and agri-cultural uses.

The Boulder Canyon Project Act of 1928

This Act provided for the construction of Hoover Dam and its powerplant, and for theAll-American Canal. Its major provisions are:

1.

2,

3.

It suggested a specific framework forapportioning the water supplies allo-cated by the compact of 1922 among theLower Basin States of California, Ari-zona, and Nevada. (The States did notadopt this framework, but it was laterimposed on them by the Supreme Courtdecision in Arizona v. California, as dis-cussed below.)It required California to reduce its an-nual consumption to 4,4 million acre-ftplus not more than half of the surplus

water provided to the Lower Basin. (Thisrequirement was met through the Cali-fornia Limitation Act of 1929.)It authorized the Secretary of the Interi-or to investigate the feasibility of proj-

ects for irrigation, power generation,and other purposes.

The Upper Colorado River Basin

Compact of 1948

In this compact, the Upper Basin States ap-

portioned the water allocated under the com-pact of 1922. The negotiators recognized theproblem inherent in allocating water on astrict quantity basis because of flow fluctua-tions from year to year. As a result, waterwas apportioned on a percentage basis to allStates except Arizona. Major provisions of the compact are:

10

2.

3.

Arizona was guaranteed 50,000 acre-ft/yr, The remaining water was appor-tioned as follows:q to Colorado: 51.75 percent,q

to New Mexico: 11.25 percent,q to Utah: 23.00 percent, andq to Wyoming: 14.00 percent,It recognized that new reservoirs wouldbe needed to assist the Upper Basin inmeeting its delivery obligation to theLower Basin. Such reservoirs, however,would increase evaporative losses fromthe river system as a whole, thus reduc-ing the quantity of surplus water avail-able to the Lower Basin. The compactprovided that charges for such evapora-tive losses be distributed among the Up-

per Basin States. Each State was to becharged in proportion to the fraction of the Upper Basin’s water allocation thatwas consumed in that State on a yearlybasis, and its maximum consumptive usewas to be reduced accordingly.It provided for the division of water be-tween pairs of States on a number of specific rivers. The compact did not dealwith the White River, which delivers ap-proximately 500,000 acre-ft/yr to theUtah State line and which could supplywater for energy development.

Mexican Water Treaty of 1944-45

As part of negotiations over apportionmentof water from the Rio Grande, Tijuana, and




Colorado Rivers, the United States guaran-teed to deliver at least 1.5 million acre-ft/yr of water to Mexico. However, in times of severedrought or in the event of a failure in thedelivery systems, Mexico could receive lessthan 1.5 million acre-ft/yr.

Colorado River Storage Projec t Act of 1956

This Act provided for several new storagereservoirs to assist the Upper Basin States inmeeting their delivery obligation to the LowerBasin, while simultaneously increasing waterconsumption in the Upper Basin. The fiveCRSP reservoirs that have since been builtwere described in the earlier discussion of the fluctuating flows of the river.

The Supreme Court Decree inArizona v. California

This decision (376 U.S. 340 (1964)) imposedupon the Lower Basin States the water distri-bution framework that had been suggested bythe Boulder Canyon Project Act of 1928. TheLower Basin’s water allocation of 7.5 millionacre-ft/yr was to be apportioned as follows:

q to California: 4.4 million acre-ft/yr,q to Arizona: 2.8 million acre-ft/yr, andq to Nevada: 0.3 million acre-ft/yr.

The decree also required that approximately1million acre-ft/yr from the allocations toCalifornia and Arizona be diverted for thefive Indian tribes located along the lower Col-orado River.

Colorado River Basin Project Act of 1968

This Act instructed the Secretary of the In-terior to propose criteria for the coordinatedlong-range operation of reservoirs built underthe Boulder Canyon Project Act and the CRSPAct. Criteria were subsequently established

and now form the basis for operation of thereservoirs. (These operating criteria are of importance in estimating water availability inthe Upper Basin States, as discussed below.)The Act also identified the Mexican WaterTreaty as a national obligation, to be con-sidered in developing any subsequent waterprojects. It prohibited the Secretary fromstudying importation of water into the Colora-do River Basin until 1978. (This moratoriumwas subsequently extended to 1988 by theReclamation Safety of Dams Act of 1978.)

Surface Water Allocations

Each of the above documents assumes dif-ferent values for the quantity of virgin flowpast Lee Ferry. They therefore differ with re-spect to the total amount of water to be ap-portioned. In general, each State can inter-pret the law of the river so as to maximize itswater-resource position and can develop itswater programs on that basis. Consequently,an analysis of the opportunities for furthergrowth in the Upper Basin States is cloudedby uncertainty, and it is not possible to pre-dict with any exactitude the maximum size of the oil shale industry that could be accom-modated.

The annual virgin flows assumed in someof these documents are shown in table 77.

Table 77.–Estimates of Surface Water Allocations to the Oil Shale States (mill ions of acre-ft/yr)

Virgin flowSource of virgin flow estimate at Lee Ferry Colorado Utah Wyoming Total

Colorado River Compact of 1922 . . . . . . ... ., . . 18 0 5.06 2.25 1.37 8.68Mex ican Wate r Trea ty o f 1944 -45 . . . . . . . . . 16.2 4.12 1.83 1,12 7,07Upper Colorado River Basin Compact of 1948. , ., ., 15,6 3.81 1.70 1.03 6.54

Colorado River Basin Project Act of 1968 . . 14.9 3.45 1.53 0,93 5.91Average flow 1930 -74. . . . . . . . . . . . . . . . . . . . . . . . . 13.8 2.88 1,28 0.78 4.94

Assumes dehvery of 823 mllhon acreft/yr to Lower Basin Slates and Mexico 7500000 acre-ft/yr 10 Lower Basin (per 1922 compact) plus 750,000 acre-ft/yr 10 Mexico (per Mexican Waler Trealy of1944-45) less 20 OOOacre-ff/yr Inflow from the Pana River below Lake Powell = 8230000 acre-ft/yr Neglecfs evaporafwe losses from Upper Basin reservoirs Assumes apportionment among the 011 shale

Slates according to the Upper Colorado Rwer 8asm Compact of 1948





Also shown is the average virgin flow at LeeFerry between 1930 and 1974. For each flowfigure, the corresponding gross quantity of surface water allocated to each oil shaleState is also shown. It was assumed that theLower Basin States receive 8.23 million acre-ft/yr out of the Lake Powell Reservoir aboveLee Ferry, as called for in the operating cri-

teria prepared under the provisions of theCRSP Act of 1968. As indicated, the quantityof surface water available to the three Statesunder the terms of the various documentscould be as low as 4.94 million acre-ft/yr andas high as 8.68 million acre-ft/yr. The lowerfigure is more realistic for planning purposes,

Doctrine of Prior Appropriation

Introduction

The water rights policies of Colorado,Utah, and Wyoming are, in general, similar.Their respective constitutions hold that wateris the property of the public, not the landhold-er, and that it is the State’s responsibility to

apportion rights to use water among compet-ing users, Each State administers surfacewater rights and some ground water rightsaccording to a doctrine of prior appropria-tion, This differs from the riparian doctrinethat prevails in most Eastern States underwhich water rights are automatically theproperty of the owner of the land on whichthe water is found. Under the prior appro-priation doctrine, water rights are severablefrom the land, and one may own water rightswithout owning any land whatsoever.

Surface Rights

The key elements of the doctrine of priorappropriation are: the specific types of waterrights, the seniority system for determiningpriority of use, the preference system for dis-tinguishing among types of water uses, op-tions for transfer of water rights betweenparties, and policies for determining theabandonment of water rights.

Types of Water Rights

There are two categories of water rights:conditional and absolute. A potential user ac-quires a conditional water right by filing for aconditional decree from the State watercourts and then proceeding diligently to-

wards the actual use of the water. An abso-lute water right is created when a holder of aconditional right perfects that right by actual-ly diverting the water and applying it to abeneficial use. Beneficial uses have been de-fined to include any use in which water is notwasted.

Within each category there are two typesof water rights. A direct flow or diversionright permits the diversion of water from astream followed by its immediate application.A storage right permits the impoundment of water for later application. None of the threeStates recognizes the right of private partiesto require that sufficient stream flows bemaintained for the protection of instreamuses, such as rafting and fishing. However, aColorado law permits that State to obtain wa-ter rights for sufficient flows to preserve thenatural environment to a reasonable degree.

In Colorado, the water rights are adjudi-cated by the State Water Courts and adminis-tered by the State engineer. The right to ap-propriate water is limited only in that prop-erty rights of other parties cannot be im-paired. A conditional right is automaticallygranted if the user proceeds with due dili-gence towards perfection of the right and if the rights of other users are not jeopardized.Neither the courts nor the executive branchof government has discretionary authorityover the type, place, or quantity of use. Fur-

thermore, the State has no power to remove astream or any portion of its waters from ap-propriation. The State engineer only monitorsthe system to assure that rights are protectedand water is not wasted.

53-898 ‘1 - 3 f) - 2 ‘,




In Utah and Wyoming, a permit system isemployed in which the right to appropriatewater must be approved by the State engi-neer. He must consider the water rights of others, but is also allowed to consider publicinterest or public welfare when passing on anapplication for appropriation. Thus, in con-

trast to Colorado, the governments of Utahand Wyoming have discretionary authority toapprove some uses and deny others. Use of this power has been minimal.

It is noteworthy that the continuation of conditional decrees requires only due dili-gence and not actual use. In the past, rightshave been granted liberally by all threeStates and as a result, the quantities of watercovered by conditional decrees far exceedthe available resources. Not all of the condi-tional decrees have been perfected, and rela-

tively little of the claimed water is actuallybeing used. Consequently, surplus surfacewater appears to be available in the oil shaleregion. However, all of it has already beenclaimed, in part by oil shale developers. Simi-lar situations prevail in Utah and Wyoming.

Seniority of Water Rights

The prior appropriation doctrine is basedon the principle of “first-in-time, first-in-right. ” Thus, the more senior (older) the wa-ter right, the higher its priority for the use of

limited resources. If shortages occur, userrights that are junior in terms of the initiationdate are curtailed to assure water supplies tousers with more senior rights. Only when themost senior rights have been satisfied do lesssenior users have any rights to water.

The date of a right, assuming the appro-priation goes forward diligently to comple-tion, is the date of the first act evidencing anintent to take water for beneficial use. In gen-eral, this is the date on which the applicationfor a conditional decree was filed. In Col-orado, a State statute makes most waterrights a matter of public record. Rights to sur-face water are established solely by the ac-tions of individual users, but these rights arelegally protected only if they are formalized

by water court decrees in Colorado or by thepermitting process in Utah and Wyoming.

Preference Systems

A preference system has been establishedin each State to apportion water among dif-

ferent beneficial uses during times of short-age. Under its provisions, drinking water ormunicipal users have first preference, agri-culture is second, and industry is third. Thepreference system overrides the senioritysystem; water rights with a lower preferencemay be condemned in favor of a higher pre-ferred use, even if the preferred water rightis junior to the displaced right. In most cases, just compensation would be required for dis-placed senior water rights.

Transfer of Water Rights

Water rights are considered real propertyand may be sold or transferred. 24 They areconveyed by deed and may be severed fromthe land on which the water was originallyused, In Colorado, such transfers are re-viewed by the water courts and may only bedenied if other users would be harmed. InUtah and Wyoming, application for transferis made before the respective State engineer,who decides whether harm will occur toother users and also considers public interestand other factors. Sale and transfer of waterrights is complicated by the need to protect

junior appropriators, seasonal rights of someusers, appurtenance (right-of-way) of waterrights to land, and preferred use as definedby the individual States,

Abandonment of Water Rights

In all three States, absolute water rightsmay be partially or completely lost by aban-donment. In Colorado, failure to use an abso-lute right for a period of 10 years constitutesprima facie evidence of abandonment. Thestatus of water rights is reviewed periodical-ly by the division engineer in each of theState’s water divisions. In Utah and Wyo-ming, abandonment is defined as nonuse for a




period of 5 years. Unlike Colorado, theseStates have no provisions for a continuing re-view of the status of water rights.

Ground Water Rights

In Colorado, t r ibuta ry ground wate r(ground water that is hydrologically con-nected to the surface water system) is treatedessentially the same as a surface flow andthus is subject to the prior appropriation doc-trine. Nontributary ground water (groundwater that does not reach surface streams) isdivided into two categories: designatedground water basins and nondesignatedground water areas, Nontributary groundwater resources in designated basins arecontrolled by a permit system through theState Groundwater Commission. Nontribu-

tary ground water in nondesignated groundwater areas, on the other hand, is subject toprior appropriation. Permits for wells mustbe obtained from the State engineer, andground water rights must be adjudicated bythe water courts to assure legal protection,

just as with a surface right. Small wells (lessthan 15 gal/rein) for livestock or domestic usehave been defined by law to cause no injuryand are exempt from such regulations.

In Utah, all ground water is subject to theappropriation doctrine. Rights are adminis-tered by the State engineer and permits forwells may be sold as any other water rights.In Wyoming, permits must be obtained forany ground water use. Livestock wateringand domestic uses have preference over allother rights, regardless of seniority.

Federal Reserved Rights

The Federal reserved rights doctrine origi-nated in the Supreme Court decision in Win-ters v. United States (207 U.S. 564 (1908)) re-garding Indian water rights. It was held thatwhen Indian reservations were establishedby treaty with the United States, sufficientwater to supply all Indian lands was alsoreserved. The Court did not quantify suffi-

ciency. Rather, it reflected the opinion thatIndian reservations were created to trans-form a nomadic people into permanent set-lers and that those people required suffi-cient water for irrigation. 25

A major effect of this decision is that thevater rights set aside for Indian reservationsvere interpreted to be superior to those of allther subsequent appropriators who ob-tained their rights under State law, eventhough the Indian tribes had not yet put theirrights to beneficial use. Federal rights were

thus entered into the prior appropriationsystem of each affected State, together with11 other applicants and appropriators.

In Arizona v. California, the Court ex-ended the reserved right doctrine to Indianreservations created by Executive order and

to other Federal reservations such as na-tional recreation areas, wildlife refuges, andnational forests. In addition, the Court ad-dressed the question of the quantity of waterreserved for Indian use. It held that waterwas intended to satisfy the future as well asthe present needs of Indian reservations, andruled that sufficient water would be reserved

to irrigate all the practicably irrigable acre-age on the reservations. 26

A further Supreme Court decision inUnited States v. New Mexico (98 Sup. Ct. 3012(1978)) attempted to resolve the uncertaintyover the qualification of Federal reservedwater rights for areas other than Indian res-ervations. The Court concluded that the doc-trine applied only to the original purposes of the reservations, and that reserved waterrights could not be used for other purposes. 27

For example, the rights associated with a na-

tional forest could be used for maintainingthe forest and its wildlife, but not for indus-try, farming, or oil shale development.

While the Supreme Court has served noticethat it will interpret the purpose of Federalreservations narrowly, a number of uncer-



.


tainties remain concerning the quantities of be used, whether the use must take place onwater that could be claimed to serve these the reservation, and whether rights can bepurposes. With regard to Indian reserva- sold or leased for uses outside the reserva-tions, for example, it is still uncertain how tion.much water will be claimed, how much will

Physical Availabil i ty of Surface Water for Oi l Shale Development

Introduction

The size of the industry that could be sup-ported by surplus surface water is affectedby the following factors:

q

q

q

q

q

q

TheThe

the long-term average virgin flow in theColorado River system (this determinesthe gross quantity of water that is avail-able);

the compacts and other documents thatconstitute the law of the river (these de-termine how the gross water supply is al-located among the basins and States);the demands of other users (these con-sume part of the allocation to each State,the remainder is the surplus);the oil shale technologies employed(these determine how much water the in-dustry would need);the siting of the facilities (this deter-mines how the industry’s water de-mands will be distributed among Colora-

do, Utah, and Wyoming); andthe timing of their construction and theduration of their operation.

final factor is particularly important.region’s surface water resources are

finite, and they are not large. In the past, theyhave generally been adequate, when supple-mented by reservoir storage, to satisfy the de-mands of all users. At present, there is plentyof surplus water for a very large oil shale in-dustry, but the surplus is shrinking becauseof population growth (both in the Upper Basin

and in the urban areas to which its watersare exported), accelerated mineral resourcedevelopment, increases in irrigated agricul-ture, and expansions of other activities.

In the future, there may not be enoughwater for oil shale unless the demands of

other users are partially curtailed. When thiswill occur is not known. If it happens beforethe plants are built or during their useful life,then social and economic dislocations wouldresult. If, on the other hand, it occurs afterconservation and the development of otherenergy sources have sufficiently diminishedthe demand for liquid fuels, then the disturb-ances caused by the temporary presence of

an industry may not be overwhelming.This section evaluates whether the surface

water resources in the Upper Basin are phys-ically adequate, and legally available, to sup-port a large industry. Availability is analyzedfor the Upper Basin as a whole, and for thehydrologic subbasins that are likely to be af-fected. The factors analyzed were highlightedabove. Following is a summary of the assump-tions made and of the sources of supportinginformation.

Virgin Flow

An annual average flow of 13.8 millionacre-ft/yr past Lee Ferry is assumed. This isthe running average between 1930 and 1974.Virgin flows have been calculated since 1896,and the 1896-1974 average is considerablyhigher-15.2 million acre-ft/yr. However, thenatural flows (the basis of the calculatedvirgin flow) have been measured more accu-rately since 1930, and the 1930-70 average isconsidered a better estimate. The effects of flow fluctuations around the 13.8 millionacre-ft/yr average are discussed in the issuessection.

Law of the River

It is assumed that the allocation to the Up-per Basin is determined by the operating cri-



teria promulgated for CRSP reservoirs by theDepartment of the Interior (DOI). These cri-teria require a minimum discharge of 8.23million acre-ft/yr from the Lake Powell Reser-voir into the lower Colorado River. This in-corporates the Lower Basin’s allocationunder the Colorado River Compact of 1922(7.5 million acre-ft/yr), plus one-half of theMexican treaty obligation (750,000 acre-ft/ yr), less the contribution of the Paria River(20,000 acre-ft/yr), which discharges into theColorado River between Lake Powell and LeeFerry. The Upper Basin States do not agreewith these criteria. The effects of other inter-pretations of the law of the river are dis-cussed in the issues section.

It is also assumed that flows allocated tothe Upper Basin are distributed according tothe Upper Colorado River Basin Compact of

1948. As indicated previously, this compactallocated 50,000 acre-ft/yr to Arizona and, of the remainder, 51.75 percent to Colorado, 23percent to Utah, 14 percent to Wyoming, and11.25 percent to New Mexico,

Demands of Other Users

Section 13(a) of the Federal NonnuclearEnergy Research and Development Act of 1974 directed the U.S. Water ResourcesCouncil to assess the water requirements of emerging energy technologies and the avail-

ability of water for their commercialization.Studies were to be undertaken at the requestof the Energy Research and Development Ad-ministration (ERDA), In 1977, ERDA re-quested three such “l3(a)” assessments, onedirected to the water-resource aspects of oilshale development and coal gasification inthe Upper Basin. Oversight for these projectswas transferred to the Department of Energy(DOE) in 1978.

The Upper Basin 13(a) assessment was or-ganized under the management of DNR of the

State of Colorado. DNR’s work has been re-viewed by an interagency, intergovernmentalsteering committee that includes represent-atives of the Arizona Water Commission, theColorado Water Conservation Board, the

New Mexico Interstate Stream Commission,the Utah Division of Water Resources, theWyoming State Engineer’s Office, the U.S.Soil Conservation Service, the Department of Commerce, DOE’s Denver Project Office, theRegion VIII Office of the Department of Hous-ing and Urban Development, USBR, and EPA.Technical assistance and studies were pro-vided by USBR (hydrologic modeling), the U.S.Fish and Wildlife Service (USFWS) (fisheryand recreational impacts), the U.S. HeritageConservation and Recreation Service (recrea-tional data), Los Alamos Scientific Labora-tory (economic modeling), the U.S. Soil Con-servation Service (agricultural water con-sumption and conservation), the U.S. Geologi-cal Survey (USGS) (water quality), and sev-eral private contractors.

Because of this broad support and reviewbase, DNR’s estimates of present and futurewater depletions appear to be the best avail-able for the period between 1980 and 2000.OTA has relied on the values provided for“conventional’” (nonoil shale) depletions todefine the baseline water-demand conditionsunder which the oil shale industry could beestablished. DNR”s results have also beenused to evaluate water-supply options in theareas in which oil shale development is mostlikely to occur.

DNR projected water consumption pat-terns for conventional activities in 2000based on low, medium, and high regionalgrowth rates. The medium-growth scenario,which was based on declared plans by thevarious users for expanding their waterneeds, is considered by the States to be themost realistic. The high growth rate scenariowas derived from the medium scenario by as-suming that announced projects would befinished sooner than expected or would con-sume more water than anticipated. A fewprojects not considered in the medium-growth

scenario are included in the high-growth sce-nario. The low-growth scenario was derivedby assuming project delays or lower than an-ticipated water consumption. In this section,OTA considered only the medium growth



382 qAn Assessment of 011 Shale Technologies

rate. The low and high rates are consideredin the issues section.

Oil Shale Technologies

It is assumed that the technology mix usedby any future industry will resemble that of

the projects presently active or proposed. Thecharacteristics of this industry were de-scribed in table 76. About 51 percent of thefacilities use indirectly heated AGR, 33 per-cent directly heated AGR and MIS, and 16percent a combination of MIS and indirectlyheated AGR. On this basis, each plant wouldrequire about 8,500 acre-ft/yr for productionof 50,000 bbl/d of shale oil syncrude. The ef-fects of other technology mixes are discussedin the issues section.

Distribution of Facilities

If the siting pattern of the present projectswere extended to a major industry, 68 per-cent of the production would be based in Col-orado, 32 percent in Utah, and none in Wyom-ing, Although they are of lower quality, somedevelopment of Wyoming shales may occur if a major industry is established. Therefore, itwas assumed that approximately 5 percent of future production will come from Wyoming,about 70 percent from Colorado, and about25 percent from Utah. This assumption deter-mines which hydrologic subbasins will be im-

pacted. It also determines how much of theproduction could be sustained by the exten-sive ground water resources of the PiceanceBasin. In this section, it is assumed that all of the plants rely on surplus surface water. Thepossible substitution of ground water isdiscussed in the issues section.

Timing and Lifetime of the Projects

It is assumed that the facilities will be in-stalled before 2000, regardless of the indus-try’s size. As discussed in the other chapters,

establishing a large industry this quickly maybe difficult.

The Availability of Surface Water in the

Upper Colorado River Basin

Water Consumed by Conventi onal Act ivi ti es

At present, the following activities con-sume surface water in the Upper Basin:

.

q

q

q

q

q

q

thermal power— for steam-electric pow-er generation;agriculture— for i r r iga t ion , wa te r ingstock, and other agricultural purposes;wildlife and recreation—for mainte-nance of fish, wildlife, and recreationalareas;minerals—for extraction, processing,and transporting ores and concentrates;municipal and industrial—for domestic,commercial, retail, and manufacturingfacilities, including final processing of

raw materials into finished products;andexportation— for diversion and trans-portation to other basins or to otherareas within the Upper Colorado RiverBasin.

Water consumption patterns for these ac-tivities, at present and as projected to 2,000,are shown in table 78. Agriculture presentlydepletes nearly 71 percent of the total, waterexports are the second highest category at 24percent, and the remaining 5 percent is dis-tributed fairly evenly among the other uses. Acomparison with the year 2000 projections in-dicates shifts both in the absolute quantitiesof water consumed and in the distribution of consumption among the various activities.The following trends are indicated:

q

q

q

Agricultural water consumption is projected to increase by 19 percent. How-ever, agriculture’s share of total con-sumption is projected to decrease to 61percent from its present level of 71 per-cent.Thermal power’s water consumption is

projected to increase by a factor of 6.Exportation of water is projected to in-





..


Table 78.–Present and Projected Water Depletions for Activities Other ThanOil Shale Development in Colorado, Utah, and Wyoming (thousand acre-ft/yr)

Present Year 2000

Colorado Utah Wyoming Total Percent Colorado Utah Wyoming Total Percent

T h e r m a l p o w e r . 10 7 18 35 1,2 74 64 83 221 5,7A g r i c u l t u r e 1,197 527 279 2,003 70.7 1,380 671 330 2,381 61.3Wildlife and recreation 15 9 6 30 1,1 28 9 20 57 1,5

M i n e r a l s . , 19 12 21 52 1.8 33 12 64 109 2.8Municipal and industrial 21 10 4 35 1,2 49 19 8 76 2.0E x p o r t a t i o n 541 132 7 680 24,0 757 262 22 1,041 26.7

T o t a l 1,803 697 335 2,835 100.0 2,321 1,037 527 3,885 100,0

SOURCE

q

Colorado Oepariment of Natural Resources, Upper Co/orado Rwer Regmn See//on 13 (a) Assessmen/ A Report (O (he U S Wa/er Resources CouncI/ drafl August 1979

crease by 53 percent. The proportion of total depletions exported, however, willremain at about 25 percent.At present, the oil shale States togetherconsume about 2.84 million acre-ft/yr.The total depletion would increase 37percent to 3.89 million acre-ft/yr.

These trends are considered below in conjunction with law of the river allocations t o

estimate the quantities of surplus water thatwould be available to support additional re-gional growth.

Esti mation of Surplus Water i n the

Upper Basin

Surplus water is defined as the differencebetween the water allocated and the totalwater consumption, which includes water

used for beneficial purposes plus reservoirevaporative charges. * As discussed previous-ly (see table 77), the oil shale States should beentitled to a total of 4.94 million acre-ft/yr:2.88 million to Colorado, 1.28 million to Utah,and 0.78 million to Wyoming. In table 79, esti-mates are given for the quantities of surplussurface water at present and in 2000. Atpresent, approximately 1.66 million acre-ft/yr of surplus water is available. By 2000the surplus would be reduced to a b o u t469,000 acre-ft/yr. These surpluses are legal-ly available to the States. If all the present

*The term “reservoir evaporative charges” refers to thetotal amount of water that evaporates from certain reservoirsin the Upper Basin, The States are charged on a percentagebasis for losses from reservoirs that are built to serve the en-tire Upper Basin. Evaporation from reservoirs built for a spe-cific State are charged entirely to that State.

surplus were reserved for oil shale develop-ment, an industry of about 9.76 million bbl/dcould be accommodated. The projected sur-plus in 2000 would support a 2.76-mill ion-bbl/d industry without disrupting other users.

A more precise analysis, which consideredseasonal flow fluctuations, return flows fromirrigated fields, effects of fill rates, and sus-tained depletions on reservoir evaporation,was performed for DNR with USBR’s Colora-do River system simulation model. The modelpredicted a natural discharge from LakePowell of 8.63 million acre-ft/yr in 2 0 0 0—400,000 acre-ft/yr more than the minimumdischarge requirement, but 69,000 acre-ft/yrless than the year 2000 surplus shown intable 79. The surplus would support an o i lshale industry of 2.35 million bbl/d in the Up-per Basin. However, the industry’s total ca-pacity would be further reduced by the UpperColorado River Basin Compact of 1948 thatgoverns how water can be distributed amongthe individual States in the Upper Basin. Theeffects of this compact are indicated in table80, where the 400,000-acre-ft/yr surplus i sdistributed among Colorado, Utah, Wyoming,and New Mexico according to the compact’spercentage formula. As shown, the tota lshale oil capacity would be 2.09 million bbl/d:1.22 million in Colorado; 541,000 in Utah; and320,000 in Wyoming.

It is important to note that these calcula-tions apply to average flow conditions in theColorado River system. During dry years, nat-ural flows out of Lake Powell might not be suf-ficient to satisfy the delivery requirement tothe Lower Basin and might have to be aug-






q

The

eastern Utah, plus streams flowing northout of the Piceance basin into theserivers; and

the Colorado River mainstem basin,which includes the Colorado River main-stem in Colorado, streams that flow

south from the Piceance basin into theColorado, and upstream tributaries athigher elevations.

impacts on these subbasins can be esti-mated only after certain assumptions aremade regarding the locations of the oil shaleplants and the timing of their construction. If the trend indicated by the present oil shaleprojects were continued, about 40 percent of the shale oil production would come from theWhite River basin in Colorado, 30 percentfrom the Utah portion of that basin, and 25percent from the basin of the Colorado Rivermainstem in Colorado. The remaining 5 per-cent might come from as-yet unannouncedprojects in Wyoming’s Green River basin. Thewater requirements for a l-million-bbl/d in-dustry distributed in this manner are indi-cated in table 81. Also shown are the waterrequirements for conventional uses in 2000,as projected by DNR under its mediumgrowth rate scenario. As shown, the industrywould increase the total water consumptionin the three subbasins by about 10 percent.The increases in the Green River and Colora-do mainstem basins would be relatively small,but water demands in the White River basinwould increase by nearly 150 percent.

The Adequacy of Surface Water Resources

by Hydrologic Basin

In the Green River basin, water depletionsfor a l-million-bbl/d oil shale industry wouldbe approximately 8,500 acre-ft/yr. Two majorFederal reservoirs within this basin, Flaming

Gorge and Fontenelle, have well over 100,000acre-ft/yr of surplus water in storage that isavailable for sale to industrial users such asoil shale developers. Consequently, there ismore than enough water available within thebasin to provide for projected growth. It is un-likely that any new reservoirs will be needed.

Oil shale development would have a great-er effect on the White River basin. With a 1 -million-bbl/d industry, depletions would ap-proach 200,000 acre-ft/yr by 2000. About 60

percent would be used for oil shale. These de-pletions would strain the water resources of the White River because its total annual flowat the boundary of the basin is only about568,000 acre-ft/yr, 61 percent of which oc-curs between April and July. Although sever-al oil shale plants could be supplied from ex-isting resources, new reservoirs would beneeded and river flows would be substantial-ly reduced.

According to DNR, only about 6,000 acre-ft/yr could be obtained from streams withinthe Piceance basin because of their lowstreamflows. A l-million-bbl/d industry wouldrequire an additional direct-flow diversion of 4,500 acre-ft/yr from the White River below

Table 81 .–Water Requirements by Hydrologic Subbasin for a 1-Million-bbl/d Industry in 2000

Water for conventional Oil shale industry Increase due toSubbasin uses, acre-ft/yra Oil capacity bbl /d Water acre- ft /yrb Total water acre-ft/yr 011 shale, percent

White River, Colo. and Utah 80,000 700,000 119,000 199,000 149Colorado mainstem, Colo. . 1,220,000 250,000 42,500 1,262,500 3 5G r e e n R i v e r , W y o . 482,000 50,000 8,500 490,500 1 8

Total. ., 1,782,000 1,000,000 170,000 1,952,000 9.5

aconventlonal “~e~ ,flclude th~r~a[ power agriculture Wlldllfe and recreallon, minerals muruclpal and (ndus(nal and exporfs Eshmates for the Colorado Depafiment of Nafural Resources medium 9rowfh

rate scenariobBased on 8 5i30 acre. ft/yr for producflon of 50000 bblid Of shale 011 Swcrude





Meeker, a reservoir with an active capacityof 60,000 acre-ft on the south fork of theWhite River in Colorado, and a 120,000-acre-ft reservoir on the White River mainstem inUtah. An industry of more than 2 million bbl/dwould require these facilities plus a 35,000-

acre-ft reservoir on the White River main-stem between Meeker and Piceance Creek, atotal of 35,000 acre-ft of active capacity inseveral smaller reservoirs along ephemeralstreams in the Piceance basin, and a reser-voir of about 10,000 acre-ft/yr along PiceanceCreek. All reservoirs would store springrunoff. Water from the White River would bepumped to the reservoirs in the Piceance ba-sin during the rest of the year.

Within the Colorado mainstem basin, oilshale development would increase water de-

pletions only slightly. However, large waterdemands would be imposed by the growthrates projected for other uses, especially irri-gated agriculture. Reservoirs may be neededto supply both irrigation and oil shale devel-opment. DNR considered four siting schemesfor reservoirs in this basin.

In the first scheme, reservoirs would bebuilt at high elevations along tributaries likethe Roaring Fork and Eagle Rivers. Spring-time runoff would be trapped for release overthe dry months. The released water would berecovered from the Colorado River below Ri-fle and pumped to the oil shale plants. Theonly appreciable inflows to the reservoirswould occur in the spring and large active ca-pacities would be needed to sustain outflowsduring the dry seasons. Total capacitiesmight exceed 50,000 acre-ft for a l-million-bbl/d industry.

The second scheme also involves reservoirson upstream tributaries but at lower eleva-tions to permit capture of agricultural returnflows and of water from secondary streams.A total storage capacity of 30,000 to 50,000

acre-ft would be needed. The third scheme in-volves direct flow diversions from the Colo-rado River below Rifle, in conjunction withreservoirs on the Colorado mainstem or inside canyons in the Piceance basin. A l-mil-lion-bbl/d industry could be supplied with a

30,000-acre-ft/yr diversion and a 15,000-acre-ft reservoir. The reservoir could be lo-cated in a dry canyon because it would besupplied with pumped water from the Colora-do mainstem and would not rely on localstream flows.

In the fourth scheme, 50,000 acre-ft/yr of surplus water would be purchased from ex-isting USBR reservoirs (such as Reudi Reser-voir) and pumped to the oil shale facilities.This would supply all of the water requiredfor that portion of a l-million-bbl/d industryprojected for the Colorado mainstem basin.Larger levels of production could be sup-ported by any of the other three schemes,with reduced storage and diversion require-ments.

In summary, new storage requirements fora l-million-bbl/d industry could range from180,000 acre-ft, with reservoirs in the WhiteRiver basin and no storage in the Coloradomainstem basin, to about 230,000 acre-ft forstorage in both basins. The maximum storage

requirements would be encountered if high-altitude reservoirs were built. Less storagewould be needed if most water was obtainedby direct diversions from the mainstem riv-ers. The additional reservoirs would increasereservoir capacity in the Upper Basin byabout 0.6 percent. Evaporative losses fromthe new reservoirs should also be chargedagainst the industry. Their precise magnitudewould depend on the characteristics of thenew reservoirs and their sites, but should addonly a small percentage to each shale plant’sannual water requirements.




The followingeither alone o r

Water Acquisit ion Strategies and Their Costs

strategies could be u s e din combination to supp lv.- .

water to oil shale facilities:

q perfection of conditional water right de-crees,q purchase of surplus water from Federal

reservoirs,q purchase of water supplies and water

rights from irrigated agriculture,ground water development, and

. interbasin diversions.

A brief discussion of each strategy and i tsassociated costs follows. Constraints and im-pacts are discussed later.

Perfection of Developer Water RightsDescription

Most potential oil shale developers have al-ready acquired water rights. Some were ob-tained by direct filings through the prior ap-propriation system. These are now in t h eform of conditional decrees both for storageand for direct-flow diversions. Exact yieldsare not available because they are consid-ered proprietary information by the compa-nies. The rights are believed to be large butrelatively junior. The oldest was acquired in1949.

Other rights were purchased from irri-gated agriculture. Most of these are relative-ly senior absolute rights that were perfectedby the seller. To avoid a declaration of aban-donment, some developers have allowed thesellers to continue to use the water for farm-ing. Little information is available regardingthe potential yields of these rights. However,total historic consumption, which would de-termine the quantities of water that could betransferred to oil shale development, could be

as low as 10,000 to 20,000 acre-ft/yr.28

An idea of the extent of developers rightscan be gotten by examining their water posi-tions in 1968.29 Conditional storage rights held

by some potential developers at that time aretabulated below:

Developer Storage rights, acre-ft

EXXON , ... , . . . . . . . . . . 1 2 2 , 0 0 0Mobil ... , . . . . . . . ... , , 66,000Getty Oil. ., . . . . . . . . . . . 53,000Sinclair. . . . . . . . . . . . . ., 51,500Tosco . . . , .. 0.., ., . . . . 34,600

Total, ... , . . . . . . . . . . 327,100

These companies also owned conditional de-crees to over 1 million acre-ft/yr of direct-flow diversions from the Colorado and WhiteRivers and their tributaries. Substantialrights were also held for ground water. Supe-rior Oil, for example, held conditional de-

crees to over 2,400 acre-ft/yr of ground waterin the Piceance basin.

The rights of the limited sampling of com-panies shown above could support an indus-try of nearly 8 million bbl/d and would be suf-ficient for the shale oil production levels pro-

jected for the near term.

Developers who do not presently ownrights could file for new ones. In general, thisoption is considered undesirable because thequantity of water covered by rights issued todate already exceeds the resources of theriver system. Any new rights would be juniorto those of all other users and therefore themost likely for curtailment during watershortages.

Filing for new rights might be feasible fornear-term development, however, because of the improbability that all of the water cov-ered by present conditional decrees will beput to use for several decades. The long-termfeasibility of this strategy is highly uncertain

because supply curtailments will becomemore likely as regional growth proceeds. Toassure supplies in the long term, new filingswould have to be merged with other strate-gies.




costs

The costs of acquiring these kinds of rightsare negligible, comprising only legal fees forrecording the water claim, and for pursuingany resultant litigation, and small annual in-vestments to demonstrate due diligence. The

costs incurred by developers when they pur-chased their current irrigation rights areunknown but were probably small. There-fore, the costs of water supplies obtainedthrough the prior appropriation system com-prise only the costs of transporting the waterfrom the diversion point to the oil shale site,Transportation costs are discussed later withrespect to intrabasin diversions.

Purchase of Surplus Water From

Federal Reservoirs

Description

Oil shale developers could also purchasesurplus water from reservoirs operated byUSBR and other entities. Various amounts of water are presently available from existingreservoirs in the oil shale area. As notedpreviously, the Flaming Gorge and FontenelleReservoirs in the Green River basin have suf-ficient surplus water for much more shale oilproduction than is likely to occur in the basinin the near term. This water is not being usedfor any purpose and could be made available

to oil shale developers.In the basins of the White River and the

Colorado River mainstem, surplus water in

storage is adequate for initial development.For example, Green Mountain and Reudi Res-ervoirs in the Colorado mainstem basin couldsupply about 100,000 acre-ft of surpluswater, which would be sufficient for nearly600,000 bbl/d of shale oil production. How-ever, existing reservoirs could not support a

larger industry unless other users were par-tially curtailed. Therefore, new reservoirswould have to be built. New pipelines wouldalso be needed in all three basins to divertwater to the oil shale plants.

costs

Reservoir construction costs are highlysite-specific and are reflected in the chargesfor purchased water. These charges varywidely from reservoir to reservoir. Although

charges for existing reservoirs are known,only rough estimates are available for newreservoirs,

Some examples of long-term contracts forwater from existing USBR reservoirs areshown in table 82. As shown, charges in thelate 1960’s were from $7 to $11/acre-ft whileprevious charges were less than $1/acre-ft.The highest charge, $22.54/acre-ft in 1972, isfor a small diversion from the Emery Countyreservoir. Because future contracts will be

negotiated individually, water costs cannotbe accurately predicted, although it seemsunlikely that they would be much higher than$25/acre-ft.

Table 82.–Examples of the Charges for Purchasing Surplus Surface Water From U.S. Bureau of Reclamation Reservoirs

Year of Quantity of Unit cost,Project/reservoir River basin Purchaser contract diversion, acre-ft/yr $/acre-ft

Seedskadee/FontenelleSeedskadee/FontenelleEmery CountyGlen Canyon/Lake PowellGlen Canyon/Lake PowellNavajo

NavajoNavajoMissouri River/Bighorn and BoysenBoulder Canyon/Lake Mead

GreenGreenCentral UtahColoradoColoradoSan Juan

San JuanSan JuanYellowstoneLower Colorado

State of WyomingState of WyomingUtah Power & Light and othersResources Co and othersSalt River projectNew Mexico Public Service

Utah InternationalSouthern Union Gas Co.VariousColorado River Commission

196219741972196919691968

196819681967-71

1966

60,00060,000

6,000102,00040,00020,200

44,000658.000;

30,000

$ 0 . 4 05 0 0

22547.007.007 0 0

7 0 07.0011,000 5 0

SOURCE R F Probsleln H Gold and R E Hicks Wa(er Requ/remenfs Po/Iu/Ion Effecfs and Costs O( Wafer Supply arm Treamefl( for [he (7II Sha/e Indusky eporl prepared for OTA by Water PunflcallonAssociates October 1979



—.


Some cost estimates for new reservoirs inWestern Colorado are summarized in table83. Unit construction costs in 1979 dollarsvary from $120 to $740/acre-ft of storagecapacity. To obtain estimates of water costsfrom these reservoirs, assumptions must bemade about financing methods and operating

characteristics of the reservoirs. A roughestimate can be made if it is assumed thatstorage and delivery capacities are equal,and 10 percent of construction costs arecharged to water purchasers per year. Thenthe charges for the water would range fromabout $10 to about $75/acre-ft, which is sub-stantially higher than costs from existing res-ervoirs.

Table 83.–Estimated Construction Costs for ProposedReservoirs Within the Colorado River Water Conservation District

Storage Unit capitalcapacity, Construction costs,

acre-ft costs, mil l ion$ $/acre-ft

H a y p a r k , ,A z u r eT o p o n a s , . , . . . , . . , ,I r o n M o u n t a i n ,Yoeman Park . ~ ~ ~ ~B e a r W a l l o w . .Kendig, ., ., . ., ~Una. . . . . .Yamcolo ,,. ,.Bear, .., ,,. .G r o u s e M o u n t a i n .Rampart. .California ParkR a n g e l y . . , , . , , ,Dunkley. . . . .Pothook .,,

20,00030,00018,00060,0007,000

49,00015,000

196,0009,000

12,00079,00012,00037,00055,00057,00060,000

$ 6 011.43,3

2 8 94 9

11.95.0

363

5.8309.24.052

11 213,28 5

$300380180480740240320190640260120350140200230140

SOURCE R F Probslem H Gold and R E H!cks Wafer Reqwremenfs pollution Effecfs, andCos/s of Wafer Supp/y and Trearmerr/ for (he 0// .Sha/e /rrdus/ry report prepared for OTAby Water Purlhcatlon Associates October t979

Purchase of Irri gation Rights

Description

Most oil shale developers have indicatedthat they plan no further purchases of irriga-

tion rights. However, the strategy warrantsdiscussion because large quantities of waterare currently consumed by farming and thewater laws allow rights to be transferredfrom willing sellers to willing buyers.

The feasibility of using irrigation rights foroil shale development is site specific anddepends on their cost in comparison withother strategies, the proximity of irrigationdiversions to potential plantsites, and theseasonal nature of irrigation rights. Transferis unlikely in the Green River basin, for exam-

ple, because adequate and inexpensive waterappears to be available from existing Federalreservoirs. On the other hand, it could occurin the White River and the Colorado main-stem basins because of the limitations of ex-isting storage capacity.

In the White River basin, irrigated agricul-ture consumes about 37,000 acre-ft/yr, Thisamount of water could supply a 250,000-bbl/doil shale industry. If this water were trans-ferred to oil shale, additional storage wouldprobably be needed because of the seasonal

nature of irrigation rights. These rightsgenerally rely on direct diversions from ariver, and river flows might not be sufficientduring dry seasons to satisfy the oil shalewater requirement.

In the basin of the Colorado River main-stem, irrigated agriculture currently con-sumes about 430,000 acre-ft/yr, which ismuch more than would be required for anyprojected level of oil shale development. Pur-chase of irrigation rights would reduce, butprobably not eliminate, the need for new stor-age capacity. Irrigation water from the Col-orado mainstem could also be diverted to oilshale facilities in the White River basin, thusreducing the need for new storage in thatbasin. Some new interim storage would beneeded near the plantsites. In any case, newpipelines would be needed to transport waterfrom current diversion points to the oil shalefacilities.

costs

It is important to distinguish between the

purchase of a specific quantity of water foruse in a given year and the purchase of awater right that would authorize use in allfuture years. In recent years, the cost in Col-orado of purchasing irrigation water for one

.




year’s use has ranged from about $10 to$25/acre-ft, which is similar to the costs of purchasing water from existing Federal res-ervoirs. 30 The cost of purchasing a waterright for use in perpetuity, however, couldrange from $1,000 to $2,500 for each acre-

ft/yr covered by the right.

31

If capital to pur-chase the right were borrowed at lo-percentinterest, annual costs might range from $100to $250/acre-ft. These costs are substantiallyhigher than current prices for single-yeardiversions. The reason is that most farmingcould not be conducted without irrigation.Selling water rights essentially puts a farmerout of business.

Ground Water Development

Description

Ground water aquifers could be feasiblewater sources for oil shale development if they are favorably located relative to plant-sites, if the water quality is suitable for in-dustrial applications, and if physical char-acteristics (such as burial depth, storagevolume, and discharge rates) are advanta-geous. Although knowledge is incomplete, ex-isting data suggest that selected aquifers inthe Upper Basin are worthy of considerationfor some, if not all, potential oil shalefacilities.

In the Piceance basin, for example, up to25 million acre-ft is estimated to be stored intwo major bedrock aquifers that are sepa-rated by rich oil shale beds. This resource iscurrently being used in limited amounts forlivestock watering, for irrigated agriculture,and for localized domestic consumption. Thewater is generally high in dissolved solids andfluoride. For this reason, its use for conven-tional purposes will probably not increase. Itis likely that an oil shale industry would bethe only large-scale application for which thisground water would be suitable. * With prop-

*W~ter in the upper aquifer generally contains less than2,000 mg/1 of dissolved solids, while in the lower aquifer thesemay range from 1,000 to 63,000 mg/1. The fluoride content istypically from 10 to 70 mg/1. Federal drinking water standardsrecommend a dissolved solids limit of 500 mg/1 and a fluoridecontent of !ess than 1.0 mgll.

er pretreatment, much of it could be up-graded for such use. If this were done to thefullest extent, the aquifers could supply a 1-million-bbl/d shale oil industry for from 200 to500 years, depending on the processing tech-nologies used.

Less is known about ground water in theWhite River basin in Colorado and Utah andabout Utah’s water resources in general. It isknown that the Uinta basin contains large ar-tesian aquifers, one of which discharges inthe vicinity of Federal lease tracts U-a andU-b. The water is not potable but could betreated for use in oil shale processing.

Because bedrock aquifers in the Piceanceand Uinta basins often coincide with minableoil shale zones, ground water will be an im-portant consideration in most development

plans. Even if ground water is not intentional-ly developed for use as process water, it willbe produced on most tracts during mine de-watering and the preparation of in situ re-torts. In many locations, the water could sat-isfy all processing needs, In some areas, anexcess will be produced that will have to bedisposed of through evaporation, by reinjec-tion, or by discharge to surface streams. Puri-fying excess ground water to dischargestandards could be costly.

In the Piceance and Uinta basins, yieldsfrom test wells vary with location from lessthan 1,000 to over 4,000 acre-ft/yr. Two tofour of these wells would be sufficient to sat-isfy the needs of an oil shale plant producing50,000 bbl/d by directly heated AGR. Severaladditional wells would probably be drilled toprovide backup capacity.

costs

The cost of ground water development willvary with site, with water quality, and withthe water management program of the devel-oper. In a recent study the geohydrologic

characteristics of three wellsites in thePiceance basin were analyzed, and estimateswere prepared of drilling capital and pump-ing costs.32 For two of the sites, which hadprolific water-bearing zones extending to



. .


about 1,000 ft below the surface, a minimumcost of about $30/acre-ft was estimated fordelivery of 1,500 to 4,000 acre-ft/yr. The thirdsite contained much less permeable rocks,which reduced maximum flows and thus in-creased costs. The estimate of the maximumflow from this well was 700 to 900 acre-ft/yr,with a minimum cost of about $90/acre-ft. Inthe DNR study, water costs from a well yield-ing 3,000 acre-ft/yr from a depth of 500 ftwere estimated to be $22 to $30/acre-ft. 33

Another estimate is about $55/acre-ft for al,000-ft well yielding 1,500 acre-ft/yr. 34

The costs of well drilling and pumpingcould, therefore, range from $20 to $60/acre-ft, assuming that aquifers occur at reason-able depths and in reasonably permeable for-mations. These costs are comparable to thosefor surface water. Ground water could offer

a major economic advantage in that wellscould be located near the oil shale facilities,thus avoiding transportation costs. On theother hand, the poor quality of some groundwater would necessitate costly purification.

Water from some aquifers is highly salineor brackish. It would not need to be purifiedfor use in dust control and spent shale com-paction, but would have to be for use as boilerfeedwater or cooling water. Purification canbe quite costly. For example, treating brack-ish water to cooling water standards can cost

from $200 to $300/acre-ft,

35

and treatment toboiler feedwater standards can cost from$650 to $ 1,000/acre-ft. 36 These high treatmentcosts would not be needed for all of a plant’swater supply, because some requirementscould be satisfied with water of any quality.If the overall water management plan of anAGR facility is considered, a brackish groundwater supply would add about $250 to $530/ acre-ft to the costs of water acquisition.

Thus, the overall costs of ground water de-velopment and use could range from $20 to$600/acre-ft/yr. The lower estimate corre-sponds to a high-quality ground water frompermeable rocks at reasonable depths. Thehigher estimate corresponds to brackish wa-ter from relatively impermeable formations.

Interbasin Diversions

Description

Interbasin diversions move water from onemajor hydrologic basin to another. Exportsfrom the Upper Basin to the cities of Col-

orado’s Front Range Urban Corridor (Denver,Colorado Springs, etc. ) are examples of inter-basin diversions. Diversions could also beused in the future to increase overall wateravailability in the Upper Basin by relocatingwater from other major basins such as theColumbia River Basin or the Upper MissouriRiver basin. * As an illustration, diverting 1percent of the net water supply of the State of Washington in the Columbia River Basinwould provide 2 million acre-ft/yr of addi-tional water to the oil shale area, an amountequal to two-thirds of the present water con-

sumption in all of the Upper Basin States.

costs

Costs of interbasin diversions vary withpipeline construction and pumping costs,which in turn depend on the route, diameter,and length of the pipelines; on the numberand capacity of pumping substations; and onthe cost of purchased power for the pumps.These costs are highly project-specific, but, ingeneral, decrease with pipeline throughputand increase with distance. Variations in unit

costs can be illustrated by considering twoalternate pipelines; one providing water to asingle oil shale plant and the other supplyingwater to an entire industry. An oil shale plantproducing 50,000 bbl/d by directly heatedsurface retorting would consume about 6,000acre-ft/yr of water. This quantity could betransported to the site in an 18-inch-diameterpipe at a unit cost of about $12/acre-f t/mile.In comparison, about 240,000 acre-ft could beconveyed through a 90-inch-diameter pipelineat a unit cost of $1 .90/acre-ft/mile.37

*Under the CRP Act, the Secretary of the Interior was re-quired not to undertake reconnaissance studies of any plan forthe importation of water into the Colorado River Basin until1978. The Reclamation Safety of Dams Act of 1978 extendedthis moratorium until Nov. 2, 1988. Thus. no water importsfrom other major basins will be allowed until well after 1988,



CH. 9–Water Availability q 393

Four options illustrate typical distancesand costs that might be encountered with in-terbasin diversion for a large oil shale in-dustry. One option would be to bring water tothe White River basin from the Oahe Reser-voir on the mainstem of the Missouri River in

South Dakota. The distance would be 500 to600 miles, and the unit costs would be $950 to$1,150/acre-ft. A second alternative would beto transport water from the Missouri River atKansas City to the John Redmond Reservoir inKansas, then to Denver, and finally over theRocky Mountains to the White River basin. 38

The pipeline would be about 700 miles long,and the uni t t r anspor ta t ion cos t about$1,130/acre-ft. A third option would be totransport water about 800 miles from the Co-lumbia River Basin to the White River basin.Unit costs would be about $1,520/acre-ft. A

fourth possibility would be to divert water tothe White River area from the YellowstoneRiver, a distance of approximately 400 miles,This would cost about $750/acre-ft,

In summary, interbasin transfers for alarge industry would require 400- to 800-mile-long pipelines and would entail unit costs of $750 to $1,500/acre-ft. Exact costs vary wide-ly but are, in general, quite high. To thesecosts must be added the purchase price of thewater that is moved through the pipeline.

Intrabasin Diversions

Description

The total cost of a water supply includesthe cost of acquiring the water and the cost of moving it to the oil shale facility. As indicatedabove, transportation costs can outweigh ac-quisition costs if the facility is far from thewater source . The cos ts of t r ansport ingwater acquired in the oil shale area will alsobe high, although less than for transfers fromother major basins. The following discussion

describes some of the typical intrabasin di-versions that could occur within the oil shaleregion, and estimates the costs of movingwater through such diversion systems. Thiscost can then be added to the purchase price

of the water to obtain the overall cost of developing a given water supply.

Intrabasin diversions redistribute waterwithin a major hydrologic basin such as theUpper Basin, They include transfers betweenindividual subbasins such as the basins of the

Green River, the Colorado River mainstem,and the White River. Intrabasin diversionsare not an acquisition strategy, but are amethod for relocating acquired water to oilshale plants. Except for selected tracts usingground water and for the few oil shale plantsbuilt very close to major tributaries, new in-trabasin diversions will be needed.

Intrabasin diversions would not reduce thestrain on the resources of the Colorado Riversystem. They would simply redistribute wateramong individual subbasins. They could be

used, for example, to augment the sparse nat-ural flows of the White River with surplussurface water from the Colorado River main-stem. They could also be used to transportstored surplus water from Federal reservoirsin the Green River basin to developmentsalong the White River or the Colorado Rivermainstem. Such diversions would be requiredregardless of whether the oil shale water sup-plies are obtained from new or from existingreservoirs,

costs

The costs of transporting water by an in-trabasin diversion pipeline will depend on thefees charged by the supplying reservoir andthe costs of building and operating the pipe-line between the reservoir and the plantsite.Some USBR estimates of the unit costs of se-lected intrabasin diversion projects are sum-marized in table 84. Reservoir charges andoperating costs for the pipeline are esti-mated, but not the costs of acquiring thewater that is moved through the pipeline, Sev-eral types of supply systems and flow rates

are shown, and both existing and new reser-voirs are considered. The range of unit trans-portation costs is from $70 to $550/acre-ft. If the highest and lowest are excluded, therange is reduced to from $180 to $440/acre-ft.




Table 84.–Summary of Cost Estimates for Intrabasin Diversions Within the Oil Shale Area

Data source Type of reservoirUnit transportation cost,

Destination Flow volume, acre-ft/yr $/acre-ftUSBRa New Tract C-a 57,000USBR New

$240-390Tract C-b 18,000 260-280

USBR New Tracts C-a and C-b 75,000 240-440 USBR Existing Tracts C-a and C-b 75,000 310-350USBR New Tracts U-a and U-b

8,000 280-400USBR New Tracts U-a and U-b 36,000 70-160USBR Existing Tracts U-a and U-b 36,000 190-230USBR New Tracts C-a, C-b, U-a, and U-b 111,000 180DNR b Existing Green River basin 14,000 280

30,000 260DNR New Colorado River mainstem basin 29,000 550

84,000 400DNR New White River basin 141,000 380

240,000 360

au s EIUreaU of lleclarnallorr ,41(er~a(iw Wafer Sources /or Pro/otype Od Shale Oeve/opmen( Salt Lake City Utah September 1974

Dcolora(fo ~pa~ment of Natural Resources Upper Co/orado t%ver L3asm Sec/(on 13(a) Assessrneru A RepOfl fO (he (/ S wafer Resources CourJc// (Oraff) August 1979


Summary of Supply Costsq

Estimates of the costs of supplying indus- q

trial-quality water to oil shale sites by meansof the several acquisition and transportationstrategies discussed previously are summa- q

rized in table 85. The strategy costs includethe costs of purchasing the water, of trans-porting it from the point of acquisition to the q

point of use, and of treating it for use in thefacilities. The estimates are approximate.They were derived using the following as-sumptions:

q All surface water acquired in the oilshale region is transported over substan-

Water for interbasin diversions is pur-chased at a cost of $25/acre-ft.Surface water is of good quality anddoes not require substantial purificationprior to use.Ground water quality is variable. Onlybrackish ground water must be treatedprior to use.All ground water is developed in the im-mediate vicinity of the oil shale plants.Pipelines to points of use are of insignifi-cant length.Surplus water from existing reservoirs

costs $25/acre-ft. Water from new reser-voirs costs $100/acre-ft.

tial distances through intrabasin pipe- The lowest cost strategy is the developmentlines. of good quality ground water. Unit costs

Table 85.–Summary of Approximate Water Supply Costs for Several Acquisition Strategies

Component cost, $/acre-ft Strategy costs

Strategy Purchase Transportation Treatment $/acre-ft $/bbl of oila

Perfection of conditional decrees . . . . . . nil $180-440 nil $180-440 $0.09-0.23Purchase f rom exi st ing Federa l reservo i rs . . . $ 2 5 180-440 nil 205-465 0.11-0.24Purchase from new Federa l reservo i rs, . , . , 100 180-440 nil 280-540 0.14-0,28P u r c h a s e of se n i o r I r r i g a t io n r i g h t s . , . , 100-250 180-440 nil 280-690 0.14-0,36

High-quahty ground water . . 20-60 nil nil 20-60 nil-0.03Brack ish ground water . . . . . . . . . . 20-60 nil $250-530 270-590 0.14-0.30Interbasin diversions ., ., 25 750-1,500 nil 775-1,525 0.40-0,79

aAssumes that 8500 acre-ft/yr IS consumed per 50,000-bbl/d Plant

SOURCE R F Probslem H Gold and R E Hicks, Waler Requirements Po//u(Iorr E/lecls, and Cos(s of Wafer .SWIp/y arrd Trealmerrf for fhe 0// S/ra/e induslry report prepared for OTA by Water PurificationAssociates Oclober 1979



Ch. 9–WaterAva/labd/[y q 395

range from essentially zero to about $0.03/bblof oil. The perfection of conditional water de-crees is more costly, with unit costs rangingfrom $0.09 to $0.2/bbl of oil. It is comparableto purchasing surplus water from existingFederal reservoirs. Purchasing water fromnew Federal reservoirs is comparable in cost

to developing brackish ground water—about$0.14 to $0.28/bbl of oil. Water obtained bypurchasing senior irrigation rights costs a lit-tle more. Interbasin diversions are by far themost expensive, with unit costs from $0.40 to

$0.79.The higher unit cost for interbasin di-versions was calculated under the assump-tion that water would be transported for 800miles from the Columbia River Basin.

Except for interbasin diversions, the costsof water supplies range from essentially zero

to about $0.36/bbl of upgraded shale oil. Suchwater costs, which would have seemed unat-tractively high in the early 1970’s when oilprices were about $3.00/bbl, are less conse-quential with current oil prices.

Legal and Insti tuti onal Considerat ions

The previous sections evaluated the physi-cal and economic requirements of severalwater supply strategies. The feasibility of any

of them also depends on a number of legaland institutional factors, some of which areexamined below.

The Law of the River

As discussed previously, water develop-ment in the Upper Basin will be constrainedby the following factors:

q The operating criteria for Federal reser-voirs in the Upper Basin, which requirea minimum discharge of 8.23 million

acre-ft/yr from Lake Powell.q The Upper Colorado River Basin Com-

pact of 1948, which limits the percent-age of total Upper Basin depletions thatcan be consumed by each State.

Different assumptions about virgin flow, re-gional growth rates, processing technologies,and plantsites can lead to widely differentprojections of the maximum size of the oilshale industry that could be supplied by sur-plus surface water in 2000. Assuming 13.8-million-acre-ft/yr virgin flow, medium growth

rates, and an industry with an average waterrequirement of 8,500 acre-ft/yr per plant, thelimit appears to be about 2 million bbl/d.

This estimate assumes that the States inthe Upper Basin concur with the constraints

identified above. This is a questionable as-sumption because several aspects of the lawof the river are in direct conflict and not all

have been accepted by the States, particular-ly in the Upper Basin. For example, the Col-orado River Compact of 1922 assured deliv-ery of 7.5 million acre-ft/yr to both the Upperand Lower Basins. This would be possiblewith virgin flows of at least 15 million acre-ft/yr; it would not be possible with the lowerflows that have prevailed since 1930. The de-livery obligation of the Mexican Water Trea-ty of 1944-45 is another source of conflict.The treaty has not been a constraint on theUpper Basin States because of their lowwater demands in the past. However, it could

significantly affect future development pro-grams. If the obligation were imposed on theUpper Basin under the percentage formula of the Upper Colorado River Compact of 1948,Colorado’s share would be 388,000 acre-ft/yr,Utah’s 173,000 acre-ft/yr, and Wyoming’s10 105,OOO acre-ft/yr. If the Upper Basin Stateswere able to avoid the obligations through liti-gation, much higher levels of regional growthand energy development would be possible.

The States may choose to follow this path.For example, Colorado Governor RichardLamm maintains that Colorado and the other

Upper Basin States are not responsible forsatisfying the Mexican treaty obligation. 39

The director of the Colorado Water Conserva-tion Board describes the State’s position asfollows: 40




There has been a considerable amount of study, together with a considerable amountof speculation, concerning the amount of water which is still available to the State of Colorado under the terms of the ColoradoRiver Compact and the Upper Colorado RiverBasin Compact. The problem with any study

is that no one can actually define the preciseamount of water to which Colorado is en-titled under the terms of the compacts. In ad-dition to existing uncertainties concerningthe compacts, the Mexican Treaty of 1944further complicates any water supply study.There are some basic disagreements amongthe various states of the Colorado River Ba-sin as to the obligation of each State for therelease of water to satisfy the Mexican Trea-ty. At some future time it appears likely thatthese differences will be taken to the UnitedStates Supreme Court for resolution.

Analysis of the legal position of the States in

this controversial matter is beyond the scopeof this assessment. It is possible, as the abovecitation implies, that resistance to supplyobligations could be directed at the Mexicantreaty itself. However, because the treaty is anational commitment, it is more likely thatresistance will be manifested against theoperating criteria for Federal reservoirs inthe Upper Basin. These criteria have been im-plemented by DOI through requirements forminimum annual discharges from Lake Pow-ell. The 8.23 -million-acre-f ft/yr discharge re-quirement incorporates both the Lower Basin

allocation of 7.5 million acre-ft/yr and the Up-per Basin’s share of the Mexican obligation.The Upper Basin States do not agree with theoperating criteria. 41 42

The Doctr ine of Prior Appropriati on

As stated earlier, most of the water rightsheld by potential oil shale developers areeither conditional decrees, which are large inquantity but junior in date of appropriation,or absolute irrigation rights, which are smallbut senior. Under the appropriation doctrine,only the irrigation rights would providesecure water supplies. They would be limitedto about 10,000 to 20,000 acre-ft/yr. If themore junior decrees were perfected, they

could be curtailed during dry periods to pro-vide water to more senior users, with severeeconomic repercussions unless sufficientwater storage had previously been con-structed. Any new rights obtained throughthe prior appropriation system would be ex-tremely junior and even more susceptible to

curtailment. Any large-scale use of groundwater for oil shale development would haveto protect the water rights of senior surfacewater users.

Thus, the prior appropriation doctrine re-duces the attractiveness of developing watersupplies through perfection of existing or fu-ture conditional decrees. Given the con-straints of the appropriation system, it ap-pears that the most reliable strategies wouldbe additional purchase of highly senior irriga-tion rights, purchase of surplus surface wa-

ter from reservoirs, ground water develop-ment in selected areas, or interbasin diver-sions.

Federal Reserved Rights Doctrine

Under this doctrine, water has been setaside for use on Federal lands, but theamounts of water affected have not yet beenquantified. An important aspect of the doc-trine is that Federal rights, when perfected,will be senior to most others. Any more junioruser will face curtailment in times of water

shortage. The doctrine is an example of theconstraints imposed by prior appropriation.

The doctrine would affect any acquisitionstrategy that relied on flows originatingwithin the Upper Basin. The only strategiesthat would avoid the doctrine’s constraintswould be the development of nontributaryground water, interbasin transfers specifi-cally for use in oil shale facilities, or the pur-chase of irrigation rights that are senior tothe Federal rights. The latter would be dif-ficult because many of the potential Federal

rights date back to the late 19th century.It is possible, although uncertain, that the

Federal reserved rights could be used toassist oil shale development. Because the




Supreme Court has decided that the affectedwater may only be used to further the pur-poses for which a reservation was estab-lished, it appears that the only relevant rightswould be those that might be claimed for theNaval Oil Shale Reserves in Colorado and

Utah. These reserves were established in the1920’s and the rights, if they could be imple-mented, would be quite senior. However, thelegal position of the rights in Colorado is com-plicated because the reserves do not borderon the Colorado River and they contain littleground water. The Government has indicatedthat it intends to claim water for the Coloradoreserves; the claim is in the early stages of litigation by the State,

Environmental Legislat ion

There are a number of environmental lawswhich do not directly restrict water use butwhich could affect the siting of facilities, thescale of operation, and particular water ac-quisition strategies, It is difficult to predicttheir effects on development of water re-sources in the oil shale region, but it is impor-tant to note their existence and to recognizethat they could be of considerable conse-quence. Included are the following laws:

q

q

q

The Fish and Wildlife Coordination Act.This Act required that all Federal agen-

cies which direct, impound, or modifywater bodies must consult with USFWS.Plans for water resource developmentare reviewed by the Service to assurethat they include appropriate protectivemeasures for fish and wildlife.The Endangered Species Act, Under thisAct, Federal agencies are to conservethreatened or endangered species. Inthe Upper Basin there are species of en-dangered fish—the humpback chub andthe Colorado River squawfish—whichmight influence the siting of reservoirs

for energy development.The National Wild and Scenic RiversAct. This Act is designed to preserveportions of selected streams in a naturalstate. The addition of any streams in the

q

Upper Basin to this system might affecttheir future use for energy development,The Wilderness Act. This Act estab-lishes a National Wilderness Preser-vation System composed of federallyowned wilderness areas as designated

by Congress. The Act also stipulates theconditions under which reservoirs andother facilities can be built within theseareas. As a consequence of this Act, res-ervoirs and other water facilities neededfor energy development might be re-stricted in certain areas.

These laws should not reduce the availabil-ity of water within the Green River hydrologicbasin because there are presently no knownendangered species or designated waterareas within this basin. Furthermore, flowsof the Green River will be insignificantly af-fected by the projected levels of shale oil pro-duction.

In cont ras t , environmental leg is la tioncould constrain oil shale development in theWhite River basin. High levels of shale oilproduction are projected for this basin, andthe associated water requirements could sig-nificantly reduce river flows. Furthermore,the Colorado River squawfish, a federallydesignated rare and endangered species, isknown to inhabit the lower portions of theWhite River. In addition, the Flat Tops Wil-

derness area, an existing Federal wilderness,includes portions of the headwaters of thenorth and south forks of the White River. FlatTops could affect oil shale development inthat reservoirs and other structures wouldnot be permitted within the wilderness area,except under presidential approval.

Water availability within the basin of theUpper Colorado mainstem might be affectedby the Endangered Species Act, the Wilder-ness Act, and the National Wild and ScenicRivers Act. The Colorado River squawfish in-

habits the Colorado River from the back-waters of Lake Powell upstream to the con-fluence of Plateau Creek. The humpback chubis found in the Colorado mainstem down-stream from the Colorado/Utah State line.




This basin also contains three designatedwilderness areas, and additional areas arebeing considered for inclusion in the wilder-ness system pursuant to the ongoing RoadlessArea Review and Evaluation (RARE II) re-view. ’ New reservoir storage would probably

not be permitted in these areas. However,they are in high-elevation watersheds andthus would probably not contain potentialsites for reservoirs. In addition, severalrivers within this basin are being consideredfor wild and scenic designation.

Thus, these environmental laws might af-fect the siting of storage reservoirs and limitthe amount of water that could be divertedfrom certain rivers. Water supply strategiesthat require extensive storage, such as thepurchase of irrigation water, could be af-fected.

Instream Water Flow

Instream flow requirements are legallyconsidered only in Colorado, where the Statehas retained the right to obtain water forpreserving the natural environment to a rea-sonable degree. Instream rights are subjectto the prior appropriation system, and havepriority over consumptive rights only if theyare more senior in time. The State recognizedinstream rights in 1973, and thus these rightsare quite junior and should not impede theperfection of rights held by oil shale devel-opers, some of which date back to 1949. How-ever, if the oil shale industry were to file foradditional surface rights they would be juniorto the instream rights and would have a lowerpriority in times of water shortage. Otherwater acquisition strategies—such as thepurchase of senior irrigation rights, trans-basin diversions, and ground water devel-opment—would not be significantly affected.The purchase of surplus water from Federalreservoirs would be affected only if the

*The Forest Service, in its RARE 11 program, is evaluatingover 66 million acres of land to determine their suitability fordesignation as wilderness. During the period of initial evalua-tion and up to final disposition of the wilderness recommenda-tion by Congress, these lands will be in some form of restrictivemanagement.

perfection of instream rights reduced theamount of surplus water available for sale.

On the other hand, minimum flow bypassesaround reservoirs and dams are required foraquatic life under the Clean Water Act. De-pending on the interpretation given this Fed-eral statute by the States, the total amount of surplus surface water could be decreased.

Finally, USFWS is engaged in a study to de-velop strategies for reserving flows to main-tain fish and wildlife habitats. Although theyare not yet part of the legal system, suchstrategies might ultimately reduce surfacewater availability for any type of growth inthe oil shale region.

Interbasin Transfers

Several legal barriers constrain interbasintransfers of water to the oil shale region. TheYellowstone River Basin Compact of 1950 (65Stat. 663) requires approval of Wyoming andMontana before transfers of Yellowstonewater can occur. Moreover, the ColoradoRiver Basin Project Act of 1968 (82 Stat. 885)specifically prohibits the Secretary of the In-terior from undertaking feasibility studies of any plan to import water into the ColoradoRiver Basin until 1978. This moratorium onwater feasibility studies was extended underthe Reclamation Safety of Dams Act (92 Stat.2471) until November 1988. Thus, until thismoratoriumoccur.

is removed no new imports can

Salinity Standards

The States within the Colorado River sys-tem are committed to maintaining salinity ator below the average 1972 levels in the lowermainstem of the Colorado River. They havedeveloped salinity criteria for three points inthe Lower Basin—Hoover Dam, Parker Dam,

and Imperial Dam. The criteria have been ap-proved by EPA, but are tentative and subjectto revision.

Salinity criteria could constrain oil shaledevelopment because such development has



Ch. 9–Water Availability q 39 9

been linked, through theoretical calculations,to salinity increases in the river system. In-creases could occur through either of twomechanisms: salt loading (in which salinewastewaters are discharged from an oil shaleplant) or concentration (in which waters of

higher than average quality are removedfrom the Upper Basin tributaries for use in oilshale processing). Salinity increases fromconcentration are discussed in the next sec-tion of this chapter; those from salt loadingare discussed in chapter 8.

It is possible that salinity criteria could af-fect oil shale operations if such operationsacted to increase the salinity in the lowermainstem. If this were the case, acquisitionstrategies that increase the total depletionsfrom the river system would be constrained.These would include the perfection of surfacewater rights and the purchase of stored sur-face water . Ground water development

would be little affected, and interbasin diver-sions would not be constrained as long as thesalinity of incoming water was lower thanupstream surface flows within the basin. Thetransfer of senior irrigation rights wouldprobably not be impeded because, as dis-

cussed in chapter 4, irrigation return flowsare the chief man-related source of salinity inthe Colorado River system. A reduction inthese flows through diversion to oil shaleprocessing should decrease the salinity of thelower mainstem.

In summary, the effects of emerging salin-ity standards cannot be predicted with anyconfidence. Certain water acquisition strat-egies would feel them more than others. Theyshould not severely affect any strategy if water released from oil shale sites is treatedto achieve the discharge standards promul-gated under the Federal Water Pollution Con-trol Act.

Crit ical Uncertainties

The previous analyses have calculated thatan oil shale industry of up to 2 million bbl/dcould be supported to the year 2000 by sur-plus water that is legally available to the oilshale States. This calculation is based on fourkey assumptions:

The long-term average virgin flow is 13.8million acre-f ft/yr—the running averagebetween 1930 and 1974.The industry continues to use a mix of mining and processing technologies simi-lar to that which would be used if pres-ently active and proposed projects werecompleted.Water demand for conventional uses inthe Upper Basin increases at a mediumrate.The industry relies solely on surfacewater; ground water is not ‘developed.

Following is a discussion of how the indus-try’s capacity might be affected if otherassumptions were made in these areas. Con-sideration is also given to the problems of water availability beyond 2000.

Virgin Flow

As noted, the flows of the Colorado Rivervary widely. Estimates of future water avail-ability have been based on the flows meas-ured at Lee Ferry after 1930 because earlier

estimates of virgin flow were less accurate.(Before 1922, flows were not measured at LeeFerry; they were estimated from the meas-ured flows of upstream tributaries. ) How-ever, it is not clear that the flows encoun-tered in the past will continue into the future.The 13.8-million-acre-ft/yr average could sus-tain a large industry through 2000, but if thelong-term average decreased by 3 percent, to13.4 million acre-ft/yr, there would be nosurplus surface water available then. Meas-urements of tree rings in the Colorado RiverBasin suggest that the long-term average flow

may be closer to this level than to 13.8 millionacre-ft/yr. 43 On the other hand, if the flows in-creased to 14.2 million acre-ft/yr, 3 percentabove the 1930-74 average, there would besufficient surplus water in 2000 for a 4-million-bbl/d industry. The average flow be-



.


tween 1906 and 1974 was 15.2 million acre-ft/yr. The average between 1922 (when flowswere first measured at Lee Ferry) and 1974was 14.2 million acre-ft/yr.

Technology Mix

The industry’s actual average water re-quirement may be substantially higher orlower than the 8,500 acre-ft/yr per plant thatwould result if present trends continued. Anindustry based solely on directly heated AGRwould consume only about 4,900 acre-ft/yrper plant. The amount of surplus surface wa-ter projected for 2000 would be sufficient fora 3.5-million-bbl/d industry if only this tech-nology were employed. On the other hand, anindustry of indirectly heated AGR facilities(at 12,300 acre-ft/yr per plant) could produce

only 1.4 million bbl/d from the same surplus.

Conventional Depletions

Although the medium growth rate for con-ventional water uses is regarded by theStates as most likely, it is possible thatdemands could increase at a much higher orlower rate. DNR analyzed the effects of low,medium, and high growth rates. Although themedium rate would allow an industry of up to2 million bbl/d, a high rate would reduce thesurplus surface water by 247,000 acre-ft/yr

in 2000. Only a 550,00@ bbl/d industry couldbe accommodated. On the other hand, a lowgrowth rate would increase the surplus by326,000 acre-ft/yr and would allow an in-dustry of up to 3.9 million bbl/d.

In any case, surplus water availability ismuch less assured after 2000. If the lowgrowth rate prevails, demand will exceedsupply by 2027, even without an oil shale in-dustry. With a medium growth rate, thesurplus wil l disappear by 2013. A highgrowth rate will consume the surplus by

2007, again without oil shale development.The implications of this potential problem foroil shale are controversial. On the one side itis argued that possible long-term water short-ages should preclude the establishment of anindustry. On the other side, it is maintainedthat a major industry could function for muchof its economic lifetime without interferingwith other users, and in any case would userelatively little water. (A l-million-bbl/d in-dustry would accelerate the point of criticalwater shortage by about 3 years. )


If the presently active and proposed proj-ects were completed, more than 40 percent of the shale oil production would come fromground water areas in the central and north-ern Piceance basin. If additional Federalleasing were pursued, a much higher percent-age of the industry’s facilities would be sitedin this area. Ground water will have to be de-veloped on these sites in order to allow miningor in situ retorting. The ground water ex-tracted would have to be reinfected into thesource aquifer, or treated for discharge tosurface streams, or used in the facilities. If itwere used as process water, the need for sur-face water would be substantially reduced. If 15 percent of the roughly 25 million acre-ft inthe Piceance basin bedrock aquifers wereused for oil shale, it could support a l-million-bbl/d industry for 20 years. However, thisrate of consumption would exceed the re-charge rate for the aquifers. Thus, theground water levels would decrease andsome of the surface streams that are suppliedby ground water discharge would dry up.This would have relatively minor economicramifications because the rate of groundwater discharge is only about 20,000 acre-ft/yr. The environmental effects woulds bemixed, as discussed in the next section.



C h . 9 – W a t e r A v a i

The Impacts of Using Water for Oil Shale Development

Introduction

The use of water by an oil shale industrywill cause economic, social, and ecological

changes in both the Upper and the Lower Ba-sins of the Colorado River system. The effectsof salinity increases are of special concernbecause salinity levels in the Colorado Riverhave been identified as a matter of nationalconcern. 44his section discusses the salinityincreases that are expected to result fromuse of surface water for oil shale devel-opment. The overall impacts of water diver-sion on the Upper and Lower Basins are thendiscussed. Because of time restrictions, OTAdid not perform an independent analysis of these impacts, However, assessments have

recently been completed by DNR, USBR,USGS, and USFWS. The following discussionis largely based on the results of thesestudies.

Impacts From the Construction and

Operation of Water Supply Faci li ti es

Construction of dams, wells, and diversionfacilities would create jobs and increase dis-posable income. However, pressures on hous-ing and on community facilities and serviceswould result. Both the positive and the nega-tive effects would diminish once constructionwas completed. Operation of the facilitieswould require fewer than 10 employees perplant, out of a total work force of approx-imately 1,500. Consequently, relatively few of the socioeconomic impacts that may accruefrom creating an oil shale industry can beassociated with the water supply systems.

New reservoirs will flood land that maypresently be used for farming or grazing orthat may have special scenic or ecologicalvalue. Homes, farms, businesses, roads, and

utility lines would have to be relocated, andriparian and aquatic systems could be dis-turbed. These impacts should be minor com-pared to those of the mining and processing

operations. Because the reservoirs will berelatively small, the overall impacts would besmall compared to those that were associatedwith the construction of existing reservoirs.(The new reservoirs needed for a l-million-bbl/d industry would increase the total waterstorage in the Upper Basin by 0.6 percent. )These impacts will be site specific and havenot yet been analyzed.

Impacts From Changes in Surface Flows

Extraction of surface water will decrease

the instream flows of the Colorado River andits tributaries. These changes will have directeffects on water users and indirect effects onwater quality and aquatic ecosystems. Thedirect effects are considered in this section;the indirect effects in the section that follows.

Decreased flows would reduce hydroelec-tric power production at specific CRSP reser-voirs. According to the DNR assessment, rev-enue losses could reach $7 million per year in2000 as a result of a 2.44-million-bbld/ indus-try. ’5 Flow reductions would also decrease de-

liveries to the Central Arizona project andforce the agricultural industry in the LowerBasin to rely on more expensive ground waterpumping. Net farm income would be reducedby about $2.3 million per year by 2000 as aresult of a 2.44 million-bbl/d industry.46

According to USBR, environmental impactsin the Lower Basin depend more on reservoiroperating criteria than they do on the quanti-ty of water in a particular stream, and flowreductions in the Lower Basin would have sig-nificant effects only in that portion of the Col-




orado River between Glen Canyon Dam andLake Mead.47

Reductions in instream flow will also affectrecreational use of some stream reaches.Although most recreational activities, such asrafting, boating, and kayaking, would remain

unchanged in 2000 even with high levels of oilshale development, negative impacts wouldoccur in two river reaches. In the ColoradoRiver between Rifle, Colo., and its confluencewith the Gunnison River, rowing and raftingconditions would be degraded from the pres-ent fair condition to poor if a 2.44-million-bbl/d industry were established. Fishing con-ditions would be reduced from fair to poorwith substantially lower levels of develop-ment. In the White River from Meeker, Colo.,to Ouray, Utah, conditions for canoeing, kay-aking, and fishing would be reduced from ex-

cellent to good. Adverse public reactionshould be expected. Secondary impacts ontourism and recreational service suppliersmay occur, although no detailed analysis of these impacts has been undertaken.

Impacts on Water Quality

Withdrawal of water of relatively highquality from upstream tributaries of the Col-orado River system will increase salinity lev-els in the lower reaches of the Colorado Riverby making the water unavailable for dilutionof more saline streams that enter the river

below the withdrawal point. Some of the esti-mates that have been made of this salt con-centration* effect are summarized in table86.48-54 Included for each source are estimatesof salinity increases for the project or indus-try originally analyzed and estimates scaledto a common basis of a l-million-bbl/d indus-

. try. As shown, a l-million-bbl/d industry inthe Upper Basin could increase salinity levelsat Lower Basin measuring stations by 0.2 to2.4 percent. The estimates incorporate wide-ly differing assumptions regarding plantsit-ing, types of processing technologies, waterrequirements, and quality of water diverted.A very approximate average salinity in-crease for a l-million-bbl/d industry might beabout 1 percent.

It should be noted that similar effectswould be experienced if the same amount of

water were used for other purposes. The Uni-versity of Wisconsin study cited in table 86estimated that diversion of 300,000 acre-ft/yrof upstream water to oil shale would increasesalinity at Imperial Dam by about 20 mg/l. If the same quantity of water were used for irri-gation, the salinity increase would be about57 mg/1. Exportation of the water from the Up-per Basin would increase salinity by about 24mg/l.

55

The economic losses, including damage toagricultural, municipal, and industrial users

*Increases in salt loading are discussed in ch. 8.

Table 86.–Projected Salinity Changes in the Lower Colorado River From Oil Shale Development

Salinity increase from 011 shale

Shale 011 capacitySource of estimate Reference modeled, bbl/d Measuring station

Colorado Department of Health 48 1,000,000 bGlen Canyon Dam

N a t i o n a l A c a d e m y o f S c i e n c e s 49 800,000 Hoover Dam1,600,000

Stanford Research Institute ., ., 50 250,000 Hoover DamUnversity of Wisconsin 51 1,000,000 Imperial DamDepartment of the Intenor 52 1,000,000 Hoover Dam

Bureau of Land Management 53 47,000 Hoover DamU S . B u r e a u o f R e c l a m a t i o n 54 1,300,000 Imperial Dam2,440,000

Presentsalinity, mg/la

609745

745 850 745

745 850

For modelIndustry

mg/l

4241

2010-15

0 17

15

For 1 million bbl/d

mg/l Percent

4 0.71,6 0 22 5 0 34 0.7

20 2 410-15 1 3-20

2 6 0.35 0 66 0 7

aData from reference 59Calculated from estimates for Increases in the White River and the Colorado Mainstem

SOURCE Off ice of Technology Assessment



in the Lower Basin could reach $5.4 millionper year in 2000 for a 2.44-million-bbl/d in-dustry. This estimate is based on a salinity in-crease at Imperial Dam of 18.1 mg/l—l.8 per-cent of present salinity levels.’”

The full salinity impacts of water used in

the Upper Basin are not felt until much laterin the Lower Basin because of the dampeningeffects of Lake Powell and Lake Mead. Forexample, the Colorado River Basin SalinityControl Forum estimates that the full effectsdo not occur until after 17 years. The fore-casts for 2000 therefore underestimate salini-ty effects on the Lower Basin, In addition, anassumption of the USBR analysis is that threeauthorized desalinization plants will be inoperation by 2000, removing over 700,000ton/yr of salt.

To a lesser extent other water quality pa-rameters will be affected by the use of waterfor oil shale development. Sediment loadingwill increase in some reaches as the result inchanges in land use associated with thedams, pipelines, and roads for the water sup-ply facilities. Changes in river flow from res-ervoir operation could alter sediment trans-port and the biochemical oxygen demand insome reaches. These impacts have not yetbeen assessed in detail.

Impacts on River Ecology

Changes in instream flow can affect theaquatic ecosystem including the habitat of sport fish and rare and endangered species.Of special concern are the effects on rainbowtrout, a major sport fish, and the ColoradoRiver squawfish and humpback chub whichare endangered species. Analyses of the im-pact of water use for oil shale on the rainbowtrout, the squawfish, and numerous other fishspecies have been undertaken by USFWSand the U.S. Heritage and Conservation Serv-ice,57 but the effects on the humpback chub

have not been assessed due to lack of criteriain the USFWS study, These assessments donot include studies of the complete aquaticecosystem and exclude impacts on the ecol-

ogy of smaller streams at high elevation so noconclusions can be drawn on impacts onthese streams at present.

Limited effects on fishery habitats were in-dicated for the Upper Basin as a whole, ex-cept for the White River. For rainbow trout in

the Green River, the fry, juvenile, and adultstages would be little affected by a 2.44-million-bbl/d industry. Spawning conditionswould remain poor. Adult Colorado Riversquawfish in the Yampa River would not beaffected, but conditions for squawfish fry inthe same stream would improve from theirpresent poor level to fair. Conditions for adultsquawfish in the White River would degradefrom their present level of excellent to good.

Assessment of impacts on plants, inverte-brates, and other components of the aquatic

ecosystem have not been undertaken,

Transfer of Water From Irrigated

Agriculture

Although it is not necessary to take waterfrom irrigated agriculture to supply oil shaledevelopments, such transfers are legally per-mitted. Because the economic value of anacre-foot of water to an oil shale developer ismuch greater than to irrigated agriculture,transfers of water rights could occur in someareas. These transfers would have social and

economic ramifications, including a redistri-bution of income. Farm income would be re-duced, but these reductions would be coun-tered by a regional income gain because of in-creased employment in the oil shale industry,

According to DNR, the gain would be 10 to100 times greater than the 1 0SS.58 The numberof farming families would also be reduced.Significantly larger impacts would be experi-enced, however, from factors not directly re-lated to water use patterns, such as the com-petition for local labor and the purchase of

agricultural lands for municipal expansion.Irrigated agriculture diverts large quan-

tities of surface water, but only a portion isactually consumed. The balance eventually



.


returns to the water systems through agricul-tural return flows and/or percolation intoground water aquifers. Oil shale developerscan only purchase rights to the consumptiveportion of the diversion. Therefore, if irriga-tion rights were transferred to oil shale devel-opment, less water would be diverted fromsurface streams, and stream flows would in-crease. The effects of these increases werenot modeled for DNR because of their smallsize and because a significant diversion of agricultural water to oil shale development isnot anticipated in most areas. If significanteffects occurred at all, they would most likelybe in the White River Basin, where fish habi-tats and recreational opportunities would beimproved as a consequence.


The impacts caused by well-drilling andmaintenance would be similar to those for theconstruction of reservoir and pipeline facil-ities for surface water development—rela-tively small and of short duration. After the

wells are drilled, only a few workers wouldbe needed for maintenance. The numberwould be small in comparison with the esti-mated total work force of an operating oilshale plant. Unlike purchase of irrigationrights, ground water development should nothave significant effects on the economic baseof the oil shale region.

Stream flows would not be significantly re-duced for the overall basin, although substan-


Pumping water from the White River for agricultural purposes



Ch. 9–Water Availability q 40 5

tial reductions would occur in those areas inwhich ground water discharge supplies a major portion of surface flows, For example,some streams in the Piceance basin are fedby ground water discharge during most of theyear . Aquife r drawdown as a resu l t o f

ground water development would reduceflows in these streams, and in some caseswould completely eliminate them except dur-ing the spring snowmelt. Fishery habitat inthese streams would be severely affected.

According to DNR, the overall effects of ground water development on fish habitatsand recreation would be much less thanwould be encountered with water acquisitionstrategies that relied solely on surface waterdiversions. 5’ However, heavy dependence onground water could lead to using under-ground water resources faster than the rateof recharge and in some instances to mininggeologically old water. The use of such water

constitutes an irrevocable decision to exploita nonrenewable resource, hence precludingits use for other purposes in the future.

Oil shale projects that use low-qualityground water may produce a net decrease insalinity in Colorado. For example, the Superi-

or Oil project in Colorado’s Piceance basinwill use water from the lower bedrock aqui-fer that has a salinity concentration of about26,000 mg/l—about 30 times the salinity of the Colorado River at Imperial Dam. With-drawal of this water would reduce the quan-tity of salts discharged into Piceance Creekby about 24,500 ton/yr. As a result, the salin-ity of Piceance Creek would decrease byabout 1,040 mg/l. Salinity in the near reachesof the White River, into which Piceance Creekdischarges, would be reduced by about 40mg/l .60 Salinity at Glen Canyon Dam woulddecrease by about 1.6 mg/1—about 0.3 per-cent of its present level.

Methods for Increasing Water Availabil i ty

Sufficient water should be physically avail-able in the Upper Basin to support a large oilshale industry while simultaneously satisfy-ing the needs of other users. However, waterscarcity could constrain regional growthafter 2000. Additional surface flows could be

provided through conservation (i.e., more effi-cient use of water), interbasin diversions, andpossibly by weather modification. Water useefficiency and weather modification are dis-cussed below; interbasin diversions were dis-cussed earlier.

More Efficient Use

By reducing demand, water conservationwould increase net water availability. Oppor-tunities exist in municipalities, in irrigatedagriculture, and in industrial activities in-

cluding oil shale development.

Municipal

Because municipalities in the oil shale re-gion consume little water, conservation stra-

tegies would have to be focused on the largercities in Colorado’s Front Range Urban Cor-ridor that import water from the Upper Ba-sin. For example, if Front Range cities low-ered consumption by 20 percent, exportswould be reduced by about 100,000 acre-

ft/yr.61

Demand could be reduced by methodssuch as restricted lawn watering or imposedpeak-use surcharges, seasonal pricing differ-entials, and price incentives. Recycling sys-tems could also be considered, but implemen-tation could be hindered by high costs andtheir unfavorable image.

Irrigated Agriculture

Present irrigation methods are inexpensiveto the farmer but relatively inefficient. Evensmall improvements could release large

quantities of water for other purposes anddecrease the quantity and perhaps salinity of agricultural return flows. Losses from canalscould be reduced by adding impermeable lin-ings or pipelines. Sprinkler systems or trickleirrigation would reduce evaporation from



406 q An Assessment ot 011 Shale Technologies

field soils. Losses to noncrop vegetation couldbe reduced by eliminating the vegetation.Crop evapotranspiration and loss of cropcap-tured water could be reduced by substitutingcrops that need little or no irrigation water.

Few of these strategies could be introducedon a large scale, however, without substan-tial economic, social, and environmental pen-alties. Mechanical irrigation, for example,would be very expensive, as would fabricatedpipelines. Vegetation removal could threatenthe ecological balance along stream coursesand manmade waterways. Dryland farmingmight not be technically or economically fea-sible. Furthermore, conservation could berisky because if a farmer did not use all of thewater covered by his water rights, abandon-ment could be declared.62

Estimating possible reductions by conser-vation is technically straightforward. Esti-mating likely reductions is much more dif-ficult because of the social and economiccomplications. DNR concluded that reduc-

tions would probably not exceed 120,000acre-ft/yr even with vigorous programs.

Industrial

Oil shale plants will use water efficiently.

This is a consequence more of the nature of the processing technologies and the desire toavoid having to treat excess process water todischarge standards than it is of an interestin water conservation. * However, differenttechnologies consume different amounts of water for the same production rate and theoverall requirements of the industry could bereduced by encouraging the use of processeswith the lowest water requirements. It isunlikely that technologies would be chosensolely on this basis because water costs are avery small fraction of total processing costs.

*The U.S. Water Resources Council states that an AGR plantwould consume about 89 percent less water than a steam- elec-tric powerplant with the same net energy output, 25 to 87 per-cent less than a comparable coal gasification plant, and 40 to90 percent less than a comparable coal liquefaction facility.’)’




Offsite powerplants to support municipalgrowth could adopt conservation methodswithout substantially increasing power costs.It has been estimated that water require-ments for power generation in the oil shaleStates will increase by as much as 221,000acre-ft/yr before 2000, If the new power-plants relied on a combination of wet and drycooling, water consumption could be reducedby about 175,000 acre-ft/yr, sufficient waterfor production of 1 million bbl/d of shaleoil. 6 5

Weather Modification

Cloud seeding could be used to enhanceprecipitation and thereby increase surfacewater and ground water resources. The re-sults of three major projects during the last

two decades suggest that overall increases insnowfall could range from 5 to 20 percent. Itappears that if snowfall were increased by10 percent, runoff might increase by from 5 to20 percent and might add up to 2.0 millionacre-ft/yr to normal surface flows. Groundwater aquifers would also be affected be-cause they are recharged principally fromsnowpack. USGS has estimated that a 10-percent increase in snowfall in the Piceancebasin would add over 10,000 acre-ft/yr of

ground water that could be withdrawn without disrupting the aquifer equilibrium. 66

Preliminary cost estimates range from $1to $10/acre-ft of additional runoff, Therewould be additional costs for capturing andtransporting the augmented flows, and stor-

age facilities would still be needed, Any addi-tional runoff would be subject to the prior ap-propriation system because the augmentedflows would be indistinguishable from natu-ral flows. Because of the problem of uncer-tain ownership, the delivered water costmight well exceed the costs of other supplymethods.

The consequences of weather modificationare not well understood, but a successful pro-gram could be expected to have widespreadeffects on the region’s ecosystems. Species

composition, vegetation growth rates, andwildlife habitats might be altered. Althoughthere could be recreational benefits from in-creased snowfall and higher streamflows, ag-riculture and transportation could be ham-pered. Losses in precipitation to areas be-yond the zone of augmented rainfall or snow-fall could have severe ecological, agricul-tural, and economic impacts. There could belegal difficulties if cloud seeding were linkedto drought in downwind areas.

Poli cy Options

The distribution of water from the Colora-do River system is governed by a complexframework of interstate and interregionalcompacts, State and Federal laws, SupremeCourt decisions, and international treaties.Policy decisions affecting the use of thiswater for oil shale development must takeinto account both the provisions of thesedocuments and the need to protect the rightsof competing water users. A number of policy

options that would affect the availability of water for an oil shale industry in the UpperColorado River Basin are examined below.Their implementation could involve actions

by Congress, the administration, State gov-ernments, and the oil shale developers.

The Determinat ion of Water Needs

In order to more accurately assess the totalamount of surplus surface water that will beavailable for additional growth in the UpperBasin, the amount needed by all projected

users must be determined. The uncertaintyabout the future availability of water sup-plies to the Upper Basin would be reduced if the necessary determinations were carried




out by Congress, by Federal and State govern-ments, and by private developers. Some possi-ble options are:

The development of a water managementsystem.—Preliminary water managementstudies have been conducted by the Bureau of

Reclamation and by individual developersand other users. However, no systematicbasin-wide evaluation of water managementalternatives has compared water supply op-tions with respect to their water and energyefficiency, their costs and benefits, and theirenvironmental and social effects. Such anassessment—involving Federal, State, and lo-cal governments; regional energy developers;other users; and the general public—may bean appropriate prelude to actions to con-struct new water storage and diversion proj-ects. It could be especially useful in evaluat-

ing and coordinating such controversial op-tions as the importation of water. Fundingcould be provided by DOI, DOE, or otheragencies. The study could be managed by theBureau of Reclamation or by Colorado RiverCompact Commission.

The determination of the amount of waterneeded by the Federal Government.—Thiscould be done for Federal lands for whichwater rights are set aside under the Federalreserved rights doctrine. One possible alter-native for Congress is to provide legislation tofacilitate this determination in coordinationwith one of the administration’s task forcesdevoted to evaluating Indian and Federal re-served water rights.

It is anticipated that the largest Federalclaims in the oil shale region will be for theNaval Oil Shale Reserves. The U.S. Navy hasmade a preliminary filing with the Coloradowater court for 45,OOO acre-ft/yr. In addition,small amounts of water may be needed for di-versions, impoundments, wells, and streamflows. Although filings are being made underthis doctrine, most indications are that the

total amount of water that will be claimed bythe Federal Government in the oil shale re-gion will not be excessive. The exact quan-tities, however, have not been determined.Because the extent of future filings is un-

known, reliable estimates of water availabil-ity for regional growth cannot be made. Theuncertainty would be reduced if there weresome indication in the near future of theamounts that will be claimed under this doc-trine.

The determination of water needs by theColorado State Government.—In Colorado,the requirements for instream flows arelegally considered only where the State hasretained the right to obtain water for preser-vation of the natural environment. Coloradorecognized instream rights in 1973; thus,these rights are junior and should not impedethe perfection of rights held by other usersprior to this date. However, such rights couldaffect the amount of water available to userswho file in the future for additional surfacerights—any additional rights would have a

lower priority in times of water shortage. TheState is presently in the process of filing forrights for instream water needs. Completingthis process would further clarify the totalamount of water available for development inthis region.

The determination of water needs by mu-nicipalities, private developers, and otherwater u sers. —Water rights in the oil shaleStates have been granted liberally. As a re-sult, the quantities of water covered by condi-tional decrees far exceed the available re-sources of the river. At the same time, not allthe conditional decrees have been perfected,and relatively little of the claimed water is ac-tually being used. If it could be determinedhow much of the water allocated under theconditional decrees will actually be benefi-cially used in the near term (for municipal,agricultural, or industrial purposes), then theUpper Basin States would have a clearer indi-cation of the actual amount of surplus wateravailable.

Reservoir Siting and

Direct-Flow Diversions

All water acquisition strategies that relyon the large-scale development of surfacewater resources within the oil shale area



would necessitate the construction of newreservoirs and direct-flow diversions (e.g.,pipelines). Such construction might be ham-pered, delayed, or even disallowed under pro-visions of the Endangered Species Act, theNational Wild and Scenic Rivers Act, and theWilderness Act. Potential problems could bereduced through several mechanisms.

Identification of endangered or threat-ened species. —The Endangered Species Actprovides for the Federal identification of en-dangered and threatened species of fish,wildlife, and plants; prohibits private activitythat imperils such species; and requires Fed-eral agencies to avoid any activities thatwould jeopardize such species or result in thedestruction of critical habitats. A number of studies are underway to identify endangeredand threatened species in the Upper Basin.

To date, two federally designated rare andendangered fish species have been found inthe waters of the oil shale region. The Col-orado River squawfish inhabits the lower por-tions of the White River and the ColoradoRiver from the backwaters of Lake Powell up-stream to the confluence of Plateau Creek.The humpback chub lives in the Coloradomainstem downstream from the Colorado/ Utah State line, Additional species requiringprotection may be found in the future.

The Act may be interpreted as restricting

activities that might adversely affect thecritical habitats of such species, althoughnone has been declared for the squawfish orthe humpback chub. Knowing their approxi-mate locations would be helpful because thetimely siting of reservoirs and direct-flowdiversions could be affected by agency inter-pretations involving instream flows. Shouldconstruction of these facilities begin beforethe critical areas were identified, there couldbe opposition to their completion, and watersupplies from a particular reach of a rivercould be delayed or interrupted. If the loca-

tions of all designated critical habitats wereidentified by DOI and the required biologicalopinions obtained, the facilities could be sitedto minimize interference and delay.

Designation of rivers to be set aside underthe Wild and Scenic Rivers Act. —Any riverarea possessing one or more scenic, recrea-tional, archeologic, or scientific values and ina free-flowing condition, or under restorationto such condition, may be considered for in-clusion in the Wild and Scenic Rivers System.A number of rivers have already been desig-nated under this legislation, and Congress isconsidering adding others. To date none inthe oil shale region has been designated; how-ever, several within the Colorado mainstembasin are being considered for wild and sce-nic designation. The amount of water thatcould be diverted from specific river reachescould be reduced if these rivers are set aside,thus an early designation of rivers eligibleunder this legislation would be of value inplanning for future shale oil production.

Given this information, direct-flow diversionscould be sited downstream to those portionsof r ivers designated as wild and scenicrivers. This would avoid a direct conflictwithin a given river stretch but could add tothe water supply cost.

Designation of wilderness areas.—TheWilderness Act created the National Wilder-ness Preservation System to provide “thebenefits of an enduring resource of wilder-ness” for the whole Nation. In keeping withthe purpose of preservation, the use of these

areas is highly restricted. To date four areasin the White River basin and the Coloradomainstem basin have been designated underthis legislation. Also, additional areas arebeing considered for inclusion in the systempursuant to the ongoing RARE II review. Newreservoir storage would probably not be per-mitted in these areas, once designated. Sincethey are located at higher elevations in upperwatersheds, they would probably not containpotential sites for reservoirs; however, addi-tional wilderness areas at lower elevationscould pose problems in siting storage facil-

ities. A complete listing of wilderness areasthat might be considered in the near uturewould aid potential developers in locatingtheir facilities in other areas.



410 w An Assessment of Oil Shale Technologies

Financing and Building New Reservoirs

New reservoir and storage facilities wouldneed to be constructed if a large shale indus-try were to be created. There area number of possible policy options for the financing andconstruction of such facilities.

Federal financing. —Congress could pro-vide for the construction and funding of newFederal water projects through two mecha-nisms. First, Congress could appropriatefunds for those Federal water projects thatalready have been authorized. Several proj-ects have been evaluated by WPRS (formerlyUSBR), and their construction approved. Ac-tual construction of these projects cannotbegin until they are funded. However, not allof these projects have been evaluated fortheir suitability to supply water for oil shaledevelopment, and some project features may

not be optimally located to serve oil shaleprojects.

A second option available to Congress isthe passage of legislation that would specifythe construction and funding of new, notpreviously authorized Federal water proj-ects. However, unless language was includedto expedite construction, these projectswould require a long review process. Theycould, however, be designed and sited withtheir purposes as water sources for oil shale(as well as other possible uses) in mind. An

example would be constructing irrigation res-ervoirs with additional capacity for oil shalerequirements.

Under either option, DOI, through USBR,could operate these reservoirs in accordancewith State water laws. Their costs could berecovered over the operating life of the facil-ities from revenues generated by sellingwater to oil shale developers and other usersand in accordance with authorizing legisla-tion.

State participation. —A State organization,

such as the Colorado River Water Conserva-tion District (CRWCD), could finance and con-struct new storage facilities. CRWCD holdslarge storage decrees in the basin of the Col-

orado River mainstem. The river districtmaintains that these decrees will likely beused as a source of supply for an oil shale in-dustry. Several possibilities exist for thefunding of reservoirs. One possible fundingarrangement might be to sell water from ex-isting State-administered reservoirs, such as

Green Mountain and Reudi, to oil shale devel-opers at very high cost (e.g., $250/acre-ft/yr).The short-term needs of many potential oilshale developers, depending on the siting of their facilities, could be met from such exist-ing reservoirs. The profits from such salescould be used as leverage capital for market-ing public revenue bonds. The capital gener-ated from these bonds could then be used tofinance the new reservoir facilit ies thatwould be needed by an oil shale industry inthe longer term. A second funding scheme,which has been practiced by CRWCD in the

past, is to sell options for water from pro-posed reservoirs to potential water users,thus raising the funds needed for the con-struction of the reservoirs.

Developer financing.—Reservoir and stor-age facilities could be financed and con-structed by the oil shale industry itself.

Financing and Implementing

More Efficient Practices and Water

Augmentation

Surface flows in the Upper Basin could beincreased if water conservation procedureswere practiced by irrigated agriculture,municipalities, and industry. Weather modi-fication is another possibility. Since carryingout these approaches could be quite costly fora particular developer or municipality, theirchance of being implemented might improveif Federal and State governments were tosupply some special funding or incentives.The following are some possible ways thiscould be done.

Funding and implementing water usepractices.—Techniques for more efficientwater use in irrigation and farming were il-lustrated earlier. As noted, farmers would be



taking risks by adopting water conservationstrategies because capital recovery would beuncertain and they might lose water rights.At the sometime, improvements in irrigationand farming practices could substantially re-duce the demands for water in the Upper

Basin. A number of options are available thatwould encourage such improvements. Con-gress could provide financial incentives,through such mechanisms as tax advantages,to those farmers who used water more effi-ciently, Technical assistance teams specializ-ing in conservation techniques could also beprovided to cooperating farmers by the Fed-eral and State governments. In addition, Con-gress could give direct financial assistancethrough grant programs, administered eitherby Federal or by State agencies.

Individual municipalities could institute

voluntary education programs and regulatorystrategies aimed at reducing overall waterconsumption. Regulatory programs could re-strict the watering of lawns and promote theuse of water-saving devices. Cities could es-tablish peak-use surcharges, seasonal pricingdifferentials, and price incentives to reduceusage. Local municipalities could also adoptwater conservation techniques for theirwastewater treatment facilities.

Municipal conservation techniques, wheth-er voluntary or mandatory, are costly. Fi-

nancing is needed to pay for administrativepersonnel as well as to produce and distrib-ute educational materials. While these pro-grams would probably be administered at thelocal level, they could be financed at the Fed-eral or State level by direct grants or cost-sharing programs. To help pay for carryingout costly conservation procedures in munici-pal wastewater treatment facilities, Congresscould provide tax incentives for such expend-itures.

Although oil shale facilities are expected tobe efficient water users, a number of water-

conserving techniques could be used to mini-mize overall consumption. For example, somedevelopment technologies require less water

than others—directly heated AGR has thelowest requirement (4,900 acre-ft/yr for50,000 bbl/d of shale oil), while indirectly

heated AGR has the highest (about 12,300acre-ft/yr for the same output). Total industryconsumption could be reduced by encourag-ing the use of the lowest water-consumingprocess. One congressional option would beto provide financial incentives to those fa-c i l i t ie s tha t implemented th is process .Another would be to provide tax advantagesto any facility that introduced specific water-conserving techniques. Also, through Govern-ment contracts, Federal agencies could spe-cifically fund R&D by developers to improvethe efficient use of water.

Funding of weather modification pro-grams.—A number of Federal agencies, in-cluding the Departments of Commerce and of the Interior, have sponsored programs relat-ing to winter orographic weather modifica-tion, The Federal Government could continueto fund programs in the Upper Basin with theaim of eventually increasing overall regionalsurface flows. If programs are funded, theyshould include work to better understand theimpacts of weather modification.

Weather modification programs, althoughcostly, could be undertaken by a State organi-zation, municipality, or private developer.However, the ownership of any additionalsurface runoff would be uncertain under thecurrent water appropriation system, andlegal complications could arise if cloud seed-ing were linked to drought in other areas. It isunlikely that a particular municipality or pri-vate developer would undertake such a pro-gram without some assurance that a portionof any additional runoff would be availablefor its own use.



412 • An Assessment of 0il Shale Technologies

Federal Sources of Water for

Oi l Shale Development

Congress, under its constitutional powers,could make water avai lable for oil shale de-velopments from Federal water projects, or

potentially from the reserved right doctrine.If Congress decides that water from congres-sionally funded projects should be madeavailable for oil shale development, then anylegislation enacted should provide that theterm “industrial use or purpose” includes theuse of water for oil shale development. * Con-gress could also amend the authorizing legis-lation for those projects from which water foroil shale development might be sought to per-mit the use of their water for that purpose. Insuch a case, legislation may be required if theproject authorization does not list among the

contemplated purposes for its water “indus-trial purposes” or some other category thatcould encompass oil shale facilities. The objective of such legislation would be to over-come any administrative reluctance to permitthe use of water for oil shale developmentunder an authorization that did not specif-ically mention it.

The power of Congress over reserved wa-ters is more limited than its power over wa-ters in congressionally funded projects. Theuse of water under the reserved right doc-trine must be “in furtherance of the purposeof the reservation. ” For this reason, Federalwater rights do not seem to be likely sourcesfor oil shale development, except perhaps inthe case of lands set aside for the Naval OilShale Reserves. This matter, however, is inthe early stages of litigation. New reserva-tions of land set aside for the purpose of mak-ing water available for oil shale developmentwould not appear to be a feasible alternative,

*A Memorandum of Understanding exists between DOI andthe State of Colorado with respect 10 the use of water from ex-isting or authorized WPRS (formerly USBR) projects. The State

desires that the water not be changed from agricultural, munic-ipal, or light industry uses to energy production (including oilshale), that are inconsistent with State policies. Under thismemorandum, the State will review any application to redis-tribute water from conventional uses to energy production. Thememorandum could be superseded by congressional directivesof overriding national importance.

since Federal reserved water rights are subject to rights vested prior to the date of thereservation.

A final option available to Congress wouldbe to deny Federal water for oil shale devel-opment, if it decides that such developmentshould not be given a high priority.

The Al locat ion of Water Resources

If Congress were to pass legislation en-couraging the development of an oil shale in-dustry it might wish to address the issue of how the necessary water would be suppliedand how oil shale legislation might affectwater allocation.

Water in the oil shale region is presently

distributed by a complex framework of in-terstate and interregional compacts, Stateand Federal laws, Supreme Court decisions,and international treaty and administrativedecisions. Within Western States, waterrights are apportioned by the States to com-peting users according to a doctrine of priorappropriation under which water rights are aform of property separate from the land.

If control over the water supply for oilshale is to be left to the States, then Congressshould probably so specify in oil shale legisla-

tion to avoid any question of the preemptionof State water laws. Legislation that wouldconfirm preservation to the States of thesame power over water for oil shale as theyhave over other water supplies should re-quire the developer to comply with State pro-cedures in securing a water supply and pro-vide that the established State appropriationsystem has the same authority to grant, deny,or place conditions on water rights and per-mits as would prevail in the absence of thelegislation.

If Congress were to attempt to remove thewater supply for oil shale production fromthe control of the States, strong legal andpolitical resistance would ensue. Such re-sistance could delay oil shale development.



Interbasin Diversions

Interbasin diversion is a technically feasi-ble although costly* option for bringing addi-tional water to the oil shale region. There arealso serious political obstacles to this alter-native. The Reclamation Safety of Dams Act

of 1978, amending the Colorado River BasinProject Act, prohibits the Secretary of the In-terior from studying the importation of waterinto the Colorado River Basin until 1988. If itwere decided to pursue this option as ameans of supplying water to an oil shale in-dustry coming on line in 1990, this prohibitionwould have to be lifted.

Interbasin diversions could be used torelieve the water problems of the region inseveral ways. Water could be transferred di-rectly to the area, either exclusively for oil

*The cost of supplving water by interbasin transfers is esti-mated to be no more than 5 percent of the total cost of produc-ing a barrel of shale oil.

Chapter 91T. D. Nevens, et al., Predicted Costs of Environ-

mental Controls for a Commercial Oil Shale indus-try: Volume 1, An Engineering Analysis, Depart-ment of Energy, Washington, D. C., July 1979,

2R. E. Hicks and R. F. Probstein, “Water Man-agement in Surface and In Situ Oil Shale Process-

ing, ” paper No. 39e, 87th National Meeting of theAIChE, Boston, Mass., August 1979.3Colony Development Operation, An Environ-

mental Impact Analysis for a Shale Oil Complex atParachute Creek, Colorado, vol. I, Denver, Colo,,1974.

4J. M. McKee and S. K. Kunchal, “Energy andWater Requirements for an Oil Shale Plant Basedon Paraho Processes, ” Colorado School of MinesQuarterly, vol. 71, No. 4, October 1976, pp. 49-64.

‘C-b Shale Oil Venture, Oil Shale Tract C-b Mod-ifications to Detailed Development Plan, reportsubmitted to the Area Oil Shale Supervisor,Grand Junction, Colo., February 1977.

‘The Ralph M, Parsons Co., “Water Flow Dia-gram for Treatment of Mine Drainage Water,”personal communication to Water PurificationAssociates from C-b Shale Oil Venture, July 1978.

‘Rio Blanco Oil Shale Project, Revised Detailed

shale development or for all users. Alterna-tively, the water needs of Colorado’s easternslope cities, presently being supplied in partfrom the Upper Colorado River Basin, couldbe met from other hydrologic basins. Thewater presently being exported from the Up-per Basin then could be used for oil shale de-

velopment. In a third application of inter-basin transfers, all or a portion of the750,000 acre-ft/yr presently being supplied toMexico by the Upper Basin States under theMexican Water Treaty of 1944-45 could betaken from another hydrological basin (per-haps the Mississippi basin). The water thusfreed in the Upper Basin could be assigned inpart to oil shale development (750,000 acre-ft/yr would be sufficient for a 3,000,000- to7,500,000-bbl/d shale oil industry).

The transfer of water from another hydro-

logic basin could have detrimental impacts onthat basin, andcede diversion.

References

impact analysis should pre-

Development Plan, Oil Shale Tract C-a, report sub-mitted to the Area Oil Shale Supervisor, GrandJunction, Colo., May 1977.

8Rio Blanco Oil Shale Project, Supplemental Ma-

terial to Revised Detailed Development Plan, OilShale Tract C-a, report submitted to the Area Oil

Shale Supervisor, Grand Junction, Colo., Septem-ber 1977.9Eyring Research Institute and Sutron Corp., An

Analysis of Water Requirements for Oil ShaleProcessing by Surface Retorting, report TID-27954, Energy Research and Development Admin-istration, Washington, D. C., Aug. 5, 1976.

10R. F. Probstein and H. Gold, Water in Synthet-ic Fuel Production: The Technology and Alterna-tives, MIT Press, Cambridge, Mass., 1978.

1lGolder Associates, Inc., Water Managementin Oil Shale Mining: Volume 1, report prepared forthe U.S. Bureau of Mines, Washington, D, C., NTISNo. PB-276 085, September 1977.

12

Cameron Engineers, Inc., Draft WorkingPaper for a Case Study of Oil Shale Technology:Oil Shale Retorting Technology, prepared forOTA, Washington, D. C., March 1978.

“University of Oklahoma, Energy From the





and Related Land Impacts, Madison, WJis., July1975, p. 225.

“Department of the Interior, Final Environmen-tal Statement for the Prototype Oil Shale LeasingProgram, GPO stock No. 2400-00785, Washington,D. C., 1973, p. 111-76.

‘) Bureau of Land Management, Draft Environ-

menta l Impact Statement—Proposed Devel-opment of Oil Shale Resources by the Colony De-velopment Operation in Colorado, Department of the Interior, Dec. 12, 1975, p. IV-91.

%upra No. 46, at p. 21.‘%upra No, 48.%upra No, 51, at p, 20.“Supra No, 15, at p. xiii.“3Supra No, 42, at p. 1 xxxviii.

%upra No. 42, at p. xc,‘

>’’ Bureau of Land Management, Dra_ft Environ-

mental Statement—Proposed Superior Oil Compa-ny Land Exchange and Oil Shale Resource Devel-opment, Department of the Interior, 1979, p. 70,

‘)lSupra No. 23, at p. 9-79.“2Supra No. 13, at p. 148.

‘){

Hearings on Water Availability for Energy De-velopment in the West, Subcommittee on EnergyProduction and Supply of the Senate Committeeon Energy and Natural Resources, 95th Cong,, 2dsess., March 1978, committee print 95-134, p. 26.“Ibid., at p. 62,‘%upra No, 42, at p. 4-4,‘Wupra No, 22.



CHAPTER 10

Socioeconomic Aspects



PageIntroduction . . . . . . . . . . . 419

The Setting . . . . . . . . . . . 420Historical Background . . . . . . . . . . . . . . . . . . ,420The Oil Shale Country Today . .............421

Early Planning for Oil Shale Development. , , .423Mechanisms to Manage Growth . ..........426Local Infrastructures. . . . . . . . . . . . . . . . . . . .426Private Sector Contributions . .............429State Programs. . . . . . . . . . . . . . . . . . . . . ... , 430Evaluation of State and Local Mechanisms. ., 436Federal Programs............................ ....................438

PossibleConsequencesofOilSha leDeve lopment . . . . . . . . . . . . . . . . . . . .443

GeneralEffectsofRapidPopulationGrowth........... 443AnticipatedGrowthintheColorado Oil

ShaleRegion ......... . . . ...................................447Needs Arising FromAnticipatedGrowth ....449

Needs From Oil ShaleDevelopment. . .......452PotentialEffectsofAccelerated Development 460

Issues andPolicyApproaches . ............462S um m a r yof I s sue s . . . . . . . . . . . . . . . . . . . . . . 462Pol icyApproaches . . . . . . . . . . . . . . . . . . . . . ,464

Chapter l0References. . . . . . . . . . . . . . . . . . .470

List of Tables

TableNo. Page87. ComparisonofBasicto Local Service

EmploymentMultipliers. . . . . . . . . . . . . 42488. BaselineData-Selected Social

andEconomicStudies . . . . . . . . . . . . . . 42589. ImpactData—Selected Social andEconomicStudies . . . . . . . . . . . . . . . . . . 427

90, RevenuesoftheColoradoOilShaleTrustFund, FiscalYears 1975-79 . . . . . 432

91. ExpendituresoftheColorado OilShaleTrustFund,FiscalYears 1975-80 . . . . . 432

92. AppropriationsFromthe OilShaleFundsbyObject,FiscalYears 1975-80. 433

93. Projects Funded by the Colorado OilShaleTrustFund, 1975-80. . . . . . . . . . . 434

94. Wyoming Programs to Mitigate Socialand Economic Impacts. . . . . . . . . . . . . . 437

95*

96.

97.

98.

99.

100.

101.

102.

103.

1040

AllocationofOilShaleTrust Funds,Fiscal Years 1975-80 . . . . . . . . . . . . . . .SelectedFederalProgramsUsed byWesternStatesforAssistance WithSocialandEconomicEffectsofEnergyDevelopment. . . . . . . . . . . . . . . . . . . . . .PopulationGrowthofColorado OilShaleCounties, 1970-77. . . . . . . . . . . . .PopulationofColoradoCommunitiesAptToBeAffectedbyOilShaleDevelopment 1977. . . . . . . . . . . . . . . . .SelectedDemographicIndices ofOilShaleCountiesofColorado,July1975..PopulationProjectionsbyDevelopmentScenariofortheOilShaleCounties of Colorado . . . . . . . . . . . . . . . . . . . . . . . . .ProjectedPopulationGrowth of Selected Oil ShaleCommunities,1979-85. . . . . . . . . . . . . . . . . . . . . . . . . .

PriorityNeedsIdentifiedby OilShaleCounties andCommunities, 1980-85 . . .ActualandProjectedPopulation andEstimatedCapacityofOilShaleCommunitiesinColorado. . . . . . . . . . . .SelectedPolicyOptions, 1978Reportto

Page

438

439

447

448

448

449

4 5 1

4 6 0

460

thePresident ........ . . . . ......... 466

List of Figures

Figure No. Page69. CountiesoftheOilShale Region .,.... 42270.Communities intheColorado OilShale

Region. . . . . . . . . . . . . . . . . ......... 42371. Energy-RelatedEmployment, TaxRevenues, andNeedforPublic Servicesin an AreaAffectedbya Large-ScaleEnergyDevelopment . . . . . . . . . . . . . . . 444

72. PopulationProjections forColoradoOilShale Counties byDevelopmentScenario, 1980-2000 . . . . . . . . . . . . . . . 450

73. PopulationProjectionsfor SelectedOilShaleCommunitiesinColoradobyDevelopmentScenario, 1980-2000 . . . . 451

74. ProposedRoadFromRangely toTractC-a. . ., ., . . . . . . . . . . . . . . . . . . . 456





—


The Setting

Historical Background

Oil shale country covers about 17,000 mi 2

in the tristate area of Colorado, Utah, and

Wyoming. (See ch. 4 for a description of thegeography of the region.) Archeological evi-dence reveals that people probably have livedthere for at least 10,000 years. ’ The ances-tors of today’s Ute Indians arrived at an asyet undetermined time. The Utes were a no-madic people who lived in a few permanentsettlements and had many scattered huntingcamps. The earliest direct contact betweenthese indigenous people and Europeans wasmost probably with Spanish explorers, andBritish and French fur trappers and traders.Trade between the Indians and the Euro-

peans existed from the 1600’s onward.In the late 1700’s and early 1800’s, contact

with Western explorers, traders, hunters,and trappers increased. In 1776, the Esca-lante-Dominguez expedition passed throughthe region in search of an overland route toCalifornia. 2 In 1868, John Wesley Powell led aparty across Berthoud Pass, into MiddlePark, and eventually to the White River val-ley. A small group wintered at a site nearMeeker, Colo., which is now called Powell’sPark. ) The number of people entering thearea rapidly increased during the miningboom of the mid-1800’s. Settlement was madeeasier when transportation was improved.The Denver and Rio Grande Western Rail-road obtained the route through the ColoradoRiver valley to Salt Lake City. The ColoradoMidland and the Denver and Salt Lake Cityrailroads explored the White and YampaRiver valleys as alternative routes, althoughneither was built,

The United States obtained title to the landas part of the Mexican Cession of 1848. Fromthe time of the Cession until the 1880’s the

United States engaged in a number of treatynegotiations and councils with the Indians. 4

The treaties ceded the mineral lands to theUnited States and established reservationsfor the different bands of Utes. The final

treaty was ratified by Congress in 1880.Under its terms, the White River Utes weregiven land in Utah in the southern part of theUintah Indian Reservation to which they were

removed in September of 1881. Congress de-clared the former Ute lands as public domainon June 28, 1882.

While the ownership questions were beingdebated, squatters appropriated some land il-legally. In 1879, when miners founded Car-bonate in the Flattops area north of GlenwoodSprings, Colo., they displayed their aware-ness of this by naming their first building FortDefiance. Coal camps were established westof Glenwood Springs along what came to beknown as Coal Ridge Hogback. While silverand gold lured the miners, the rich grasslands

attracted cattle and sheep raisers. Largebeef herds roamed free; one in 1888 wasnumbered at 23,000. 5 The great runs lasteduntil the turn of the century, when theybecame uneconomic owing to severe winterscombined with overgrazing.

Ranching, mining, and recreation becamethe economic cornerstones of the region. Al-though no great precious metal strikes weremade, coal mining formed a stable industryfor many decades. Coal was produced for therailroads and for the steel mills of Pueblo,

Colo. (See ch. 4 for the history of oil shale andrelated mineral exploration. ) Farms andranches were established as homesteadingflourished. Hay production in the valleysbecame profitable, especially with the adventof irrigation. The visits of Theodore Rooseveltto the Flattops area in the early 1900’s, withtheir attendant publicity, gave impetus totourism.’ Communities grew, with Rifle,Meeker, and Rangely, Colo., as centers of trade. The town of Meeker was incorporatedin 1885. A trading post was built at the loca-tion of Rangely in the early 1880’s. Oil was

discovered nearby in the early 1900’s andproduction began in the early 1920’s. Smallercommunities sprang up along the valleys.West of Rifle, the town of De Beque was in-corporated in 1890. Grand Valley, founded in



Ch. 10–Socioeconomic Aspects Ž 421

1882, soon became a farming center. To theeast of Rifle, New Castle was the hub of thecoal communities. Many of the residents to-day are descendants of the early settlers, Oilshale country, therefore, is an area withstable communities populated by many long-

established families.

The Oil Shale Country Today

Agriculture, mining, and recreation havecontinued as the main economic activities. z

Livestock grazing is the leading agriculturaluse, followed by dry land farming, and irri-gated cropland production. Hay and winterwheat are major crops. The best irrigatedland is in Mesa County, Colo., outside the im-mediate oil shale area, where orchards havelong been established. Mineral resource pro-

duction, mostly oil and gas, and recently coal,constitutes the major mining activity. Tour-ism, fishing, and hunting have long been themainstays of the recreational sector, andwith the expansion of winter sports areas inthe mountains, year-round recreation hasbecome important. In recent decades, trade,manufacturing, and construction industrieshave grown, along with public and privateservices. Economic indices, such as retailsales and per capita and family income, havereflected a steady economic growth. a

The oil shale region encompasses abouteight counties. (See figure 69. ) In Colorado,these are Rio Blanco, Garfield, and Mesa;some social and economic effects from ex-panded oil shale development may also be feltin Moffat County, north of the Piceance basin.The counties in Utah that will be affected areUintah, Daggett, Grand, and Duchesne. Thetricounty area of Colorado covers 9,563 mi2,has a limited transportation system, and in-cludes about a dozen communities that couldbe affected by oil shale industry expansion,(See figure 70.)

Stretching along the southern edge of oilshale territory, Mesa County is the transpor-tation and service center for the westernslope of Colorado. Grand Junction, the largestcity of the region, is the site for the offices of

several energy companies. Interstate 70 (seg-ments of which are not yet completed) ex-tends eastward up the valley of the ColoradoRiver and westward into Utah; it is 260 high-way miles to Denver and 285 to Salt LakeCity. The only airport on the western slope

able to accommodate commercial jets is inGrand Junction. The Denver and Rio GrandeWestern Railroad also has extensive facil-ities there.

Garfield County lies adjacent to MesaCounty on the north. It encompasses the RoanCliffs along the southern border of the RoanPlateau, and is the site of most of the privateoil shale holdings. The Colorado River flowsthrough the eastern part of the county, andtransportation is readily available along thiscorridor. Glenwood Springs, the county seat,

is located in the eastern portion. Rifle, GrandValley, Silt, and New Castle are communitiesaffected by the present modest scale of oilshale development. Rifle is the home of manyoil shale workers from tracts C-a and C-b. Avanadium plant is located nearby, and coaldevelopment activities have recently in-creased along the valley. The Naval Oil ShaleReserve at Anvil Points lies between Rifle andGrand Valley. If present trends continue, theRifle vicinity will experience the most growth.

Rio Blanco is the county most likely to ex-perience the major effects of expanded oil

shale development. Lying between Garfieldand Moffat Counties, it is where the richestoil shale deposits in the United States arelocated. Most of these are on Federal lands inthe Piceance basin. Rio Blanco is the leastpopulated of the three, and has the most lim-ited surface transportation. The White Riverflows along the northern part; the two majorcommunities, Meeker (the county seat) andRangely, lie within the river valley. Rangely isa center for oil and gas development activ-ities. The primary north-south highway goesfrom Rifle through Meeker and Craig and

then on to Wyoming. The main east-west roadgoes from Meeker to Rangely, before turningnorth to Dinosaur, where it passes into Utah.A State highway goes south from Rangelythrough Garfield County and eventually to




Figure 69.—Counties of the Oil Shale Region

—— —

A C R O O KI

w .

L -1

.-

“1Q**

e-0°

. Iq

w

xo

I.1:

-. / I1 - . . *

-- l i

SOURCE The Natlona/ At/as, Department of the Interior

Grand Junction. A county road extends alongthe Piceance Creek valley and another goeseastward from Meeker up the White Rivervalley to recreation areas. These are the onlyimproved roads to serve the 3,263 mi 2 of RioBlanco County.

Moffat County, which occupies the ex-treme northwest corner of Colorado, abuts onWyoming to the north and Utah to the west.Its county seat, Craig, is in the east-centralportion. The population of Moffat County has

approximately doubled in the past decadewith most of the growth centered in Craig.Coal development and the construction of a760-MW coal-fired electric generation plantaccount for most of the expansion, which isexpected to continue with a possible doubling

in the size of the powerplant. Because MoffatCounty lies to the north of the principal oilshale areas, it will probably only experienceindirect effects from shale development. Thetown of Dinosaur, however, which is located18 miles northwest of Rangely in the extreme



Ch 1O–Socioeconom/c Aspects q 423

Figure 70.—Communities in the Colorado Oil Shale Region

VERNAL

32 mi.

I

r——_———— ———— 4

— J

— — ‘“F s u — — — — — — — — — — — — — —.” —

JUNCTION

SOURCE 0il Shale Tracf C-b S OCIO Ecomnic Ajssessment 76 VOI II

southwestern corner of the county, could bedirectly affected. It has already grown fromoil and gas exploration, and oil shale activ-ities in Utah as well as the Piceance basincould further accelerate its growth.

In sum, the oil shale region of Colorado,Utah, and Wyoming is a large area with asmall population. Most of the residents arefound in widely separated communities thatare linked by a few highways. Before the re-cent increase in energy-related industrial ac-

tivity, the main economic base was ranchingand farming, supplemented by tourism, recre-ation, and mining. A large number of new res-idents have migrated to Moffat County, to thenorth of the oil shale region. The fastest

growth from expansion of the shale industrywill most likely take place in the least popu-lated county, Rio Blanco, which contains therichest oil shale deposits. Garfield County isapt to experience major impacts from itsgrowth.

Early Planning for Oil Shale Development

Concern about the social and economic ef-fects on Colorado communities of large-scaleoil shale development was expressed in the

late 1960’s.9 As a result, planning activitiesbegan in the early 1970’s. The environmentalimpact statement (EIS) filed in conjunctionwith the Prototype Leasing Program exam-ined some social and economic elements.




However, its lack of detail prompted industryto take the initiative to undertake additionalanalysis. In 1972, an Oil Shale Regional Plan-ning Commission was formed, which took aninventory of the area and of shale technol-ogies. Contracts with consulting firms pro-

duced several planning documents. ’” The re-sponsibilities of the Commission were as-sumed later by the Colorado West Area Coun-cil of Governments (CWACOG). An aware-ness of the need to prepare for growthprompted these early planning efforts, but aswork proceeded, an atmosphere of uncertain-ty arose. When the lessees requested suspen-sions, expansion of the oil shale industry be-came questionable in the minds of many whowere charged with the responsibility of pre-paring for its consequences. ”

Local programs to minimize possible ad-

verse affects were begun after the leasing of tracts C-a and C-b. The C-a lessees, Rio Blan-co Oil Shale Co. (Gulf Oil and the StandardOil Co.—Indiana), prepared an impact anal-ysis for their operation. ’2 They hired a con-sultant, the Foundation for Urban and Neigh-borhood Development (FUND), to survey com-munity attitudes toward energy developmentin Rangely, Meeker, and Rifle. The lesseesalso engaged a planning firm, the Gulf OilReal Estate Development Co. (GOREDCO),that—with the participation and direction of the community—prepared a comprehensivedevelopment plan for Rangely. The masterplan was completed in 1976 and subsequentlyadopted by the town, certified to the county,and incorporated in the county plan. ThroughFUND an attorney was engaged to updateand codify Rangely’s municipal ordinances.The lessees also contributed to the improve-ment of the county road leading to tract C-a,and paid for the design and preparation of cost estimates for a 22-mile extension fromthe tract more directly to Rangely.

In 1976, the lessees of the C-b tract (at that

time consisting of Ashland, Atlantic Richfield,Shell, and Tosco) published a baseline de-scription and an impact analysis study. ’3 Likethe tract C-a lessees, they hired a consultingfirm, Quality Development Associates (QDA),

to prepare socioeconomic monitoring reportsand to work with local citizens on strategiesfor managing growth. The lessees were alsomembers of a private development, the Col-ony project. Several socioeconomic reportswere prepared as part of this joint effort, l4

and, under the direction of Atlantic Richfield,early plans were prepared for BattlementMesa, a proposed new town to accommodateworkers from the Colony project. ’5

The tracts C-a and C-b lessees each con-tributed $40,000 to help establish the RioBlanco County Planning Department. Themoney was used to prepare a comprehensiveplan that was adopted and certified to thecommunities in the latter part of 1976. Bothgroups of lessees funded development of agrowth-monitoring model by CWACOG, andthe original tract C-b partners and one of theC-a partners participated in the preparationof a tax study. Planning was also underway inUtah between 1970 and 1975. For example, in1975 a socioeconomic analysis was publishedby the White River Shale project that dealtwith the effects of the proposed developmentof a 100,000-bbl/d industry in Utah. 16

The value of the early studies varied be-cause each had a different emphasis, cover-age, and set of basic assumptions. Comparingthe mult ipl iers used to der ive projectedgrowth illustrates these differences. To ob-

tain an estimate of new employment fosteredby a project (local service employment), theexpected work force for the project (basicemployment) is multiplied by some factor(multiplier). Table 87 compares the multipli-

Table 87.–Comparison of Basic to Local ServiceEmployment Mutipliers

—Multipliers used

Const ruct ion Operat ingIIlustrative studya phase phase

1 . P r o t o t y p e E I S . 63 772. C-a (Rio Blanco) Social & Economic

S t a t e m e n t . 5 5

3 C-b Soclo-Economic Assessment 5 to 1 0 1 54. Colony EIS. ., .29 975. Uinta Basin Study 3 to 10 10 to 1.5

d~ee (e! 1 T for iUII htle of the sludles

SOURCE Of ftce of Technology Assessment



Ch. 1O– Socioeconomic Aspects Ž 425

ers used in five of the early studies,17 These The differences occurred for several rea-vary so much that a single increment of em- sons. In the EISs, socioeconomic factors re-ployment can result in a twofold to threefold ceived little emphasis because at that timedifference in the projected populations. (The they were not considered—as is now the casefive studies are compared in greater detail in —essential to environmental impact analysis.tables 88 and 89. ) In general, the EISS assumed that existing

Table 88.–Baseline Data–Selected Social and Economic Studies (each dot indicates the inclusion in the study of this category of data) —. —

Title of studyb

C-a social C-bPrototype EIS and economic socioeconomic Colony EIS Uinta Basin —Data categoriesa

Existing economic/demographic dataPopulation and employment

County populationNumber of households by countyNumber of households by communityLabor participation by county

EducationEnrollment by countyEnrollment by school districtEnrollment by cityStudent/teacher ratioMedian school years attainedDropout/turnover rates

Employment by industryTotal employed–sector by countyTotal employed–sector by cityTotal employed–sector by regionEmployment–other energy Industry

Family/lndwldual Income IndicatorsMedian family Income by countyPer capita Income by countyUnemployment rate by countyPoverty status by county

Rate of population growthBy county and communityProjected without 011 shale

q q q q q

q q q q

q

q q q qq

q

q

q

q

q q

q

q

q q

q

q

q

q q

q

q q

q

q

q q

q q

Existing public services/facilitiesEducationAge of school buildings by districtCertified staffExcess pupil capacity

Public safetyFire/pollee protection by areaManpower/number of vehicles

WaterEstimated deplet ion (1970) by reg ion . ,Status of projects by StateSource, storage capacity, number of taps per population served

by communityStatus of water rights

Wastewater and solid waste disposalTreatment facilities by community type/population served/design capacity

TransportationExisting roads/airports by countyStatus of current projectsAverage weekday traffic counts

HealthFacilities/manpower by countyMental health facilties

Recreation and land useResource Inventory

9

q

q

q

q

q

q

q

q

q q

q

q

q q

q

q

q

q

q




Table 88.–Baseline Data–Selected Social and Economic Studies –continued

Title of studyb

C-a social C-bData categoriesa Prototype EIS and economic socioeconomic Colony EIS Uinta Basin

—

R e c r e a t i o n a l f a c i l i t i e s b y t y p eL a n d b y o w n e r s h i p b y c o u n t yAgricultural land by county

Government structure/fiscal informationCounty/municipal government finance

R e v e n u e s a n d e x p e n d i t u r e s b y c o u n t yM u n i c i p a l r e v e n u e s a n d e x p e n d i t u r e sProperty tax valuation, average mill levy, and total levy by countyD i s t r i b t i o n o f l e v y r e v e n u e s b y c o u n t ySales tax In formation . ,R e t a i l t r a d e i n f o r m a t i o n

School district financesTotal expenditures by county.Total and per capita expenditures by districtsComparison of per pupil expenditures and mill levies by districts .,MiII levy by fund. assessed value revenue by source, by districtBonding principal and remaining capacity

HousingInventory and costs

E s t i m a te d h o u s i n g b y c o u n t yStatus of avai lable units by typeValue of owner-occupied units.V a l u e o f o t h e r u n i t sProjected needs by tenure by countyC h a r a c t e r i s t i c s b y t y p e b y c i t y

Public opinionLocal opinion regarding

Socioeconomic environment and quality of life .,Att i tudes about changes In qual i ty o f l i fe and society.Attitudes about perceived advantages/disadvantages

o f 0 1 1 s h a l e d e v e l o p m e n t

q

q q

q q

q q

q

q

q

q

q

q

q q

q q q

q

q

q

q

q

q

q

dBala ~ategorles are for Il[ustra[lon NO a!tempt has Deen made 10 Include all of the !nformallon In these studiesDsee ~ef I 7 for Ilsf(ng of full Ilfle

SOURCE Olflce of Technology Assessment

mechanisms could deal with most conse-quences of growth. When it became apparentthey could not, subsequent studies went intogreater detail about the effects of the ex-pected growth and possible remedial actions.Not all of the studies, however, included thesame types of information. For example, com-munity facilities and local government data

were not made a part of the C-a analyses be-cause they were in the Rangely master plan.Little attention was paid in any of the studiesto other resource development projects an-ticipated or underway in the region. As aresult, all of them are deficient in analyzingthe cumulative effects of industrial expan-sion.

Mechanisms to Manage Growth

Local Infrastructures Rangely, Rifle, and Grand Junction have full-time city managers, and Grand Junction andIn Colorado, Garfield, Rio Blanco, and Rifle have city planners. Rio Blanco County

Mesa Counties all have planning councils, has adopted an ordinance applying to landprofessional planning staffs, and approved use that, in certain circumstances, requirescountywide comprehensive plans. Meeker, filing an impact analysis statement specifying





428 . An Assessment o/ 011 Shale Technologies


Monthly meeting of the Rio Blanco County Impact Mitigation Task Force

been officially designated to serve in an ad-visory capacity to the county commissioners.One advisory panel represents Meeker andthe eastern part of the county, the otherRangely and the western portion. Many dif-ferent interests are reflected, including agen-cies such as the sanitation district and the

public schools, and less formally organizedgroups such as youth. The advisory panels,which also meet once a month, discuss differ-ent growth-related topics, and forward theirconcerns to the core group. They have pre-pared needs assessments on a variety of gen-eral subjects and have reviewed specificissues such as housing for teachers.

The Rifle area organization was formed inmid-1977 with a core group and series of working panels. When first established, it

was called the Development Impact Commit-tee, and consisted mainly of Rifle residents. Acounty commissioner from the area was amember but countywide communication wasnot extensive. Most of the development andplanning management activities were carried

out through the Rifle planning and adminis-trator’s offices. In the fall of 1979, the orga-nization was enlarged to involve other com-munities along the Colorado River valley. Thecore group was broadened to include all of the county commissioners and represent-atives from each of six towns. To advise the

core group, a West Garfield Impact Commit-tee was created composed of 19 voting mem-bers chosen to represent a wide range of in-terests. The Impact Committee will undertakeplanning activities and recommend to thecore group which projects they support forsubmission to the State for funding assist-ance. Prior to the establishment of this proc-ess, requests were made through the citiesdirectly to the county commissioners.

In December 1977, Mesa County organizedan Impact Assistance Team. Fifteen mem-

bers, representing local, State, and industryinterests, review funding requests made tothe county commissioners. Applicants mustprovide information to the team justifyingtheir requests . Responsibili ty for se tt ingpriorities rests with the commissioners.



Ch. 1O–Socioeconomic Aspects q 429

The Funct ions of the Local Planning Processes

The work of the special groups has cen-tered around three areas: physical planningand development, information generation andtransfer, and screening and placing prioritieson requests for funding. As an illustration of

the first function, the Rio Blanco advisory andcore groups, using population forecasts pro-vided by CWACOG, have reviewed the abilityof local public facilities, such as sewer andwater systems, to handle larger loads, andhave helped plan expansions where appropri-ate. Needs for housing, schools, recreationalfacilities, and downtown redevelopment havealso been considered. Each planning grouphas struggled with the implications of com-prehensive land planning for its region.

Because energy development often involvesuncertainties about factors such as the timingof construction and the size of work forces,obtaining accurate information is importantto officials and residents, The best estimatesavailable are required and, in this regard,most groups receive frequent updates fromindustry representatives about the status of their projects. Sharing information also in-volves communication between local officialsand citizens. The advisory groups provide apublic forum for the presentation, analysis,and discussion of issues, which allows indi-viduals to help determine future growth pat-terns. The core groups, especially whenscreening requests for impact mitigationfunds, help establish a consensus among localinterests on priorities and policies.

An important function of each group is rec-ommending to their respective county com-missioners which project applications shouldbe forwarded to the Federal and State gov-ernments for consideration for funding. TheRio Blanco County structure is unique in thisrespect, The involvement of the task forcecore group and advisory panel members withlocal officials, industry representatives, con-

sultants, CWACOG, State legislative and ex-ecutive staff, and Federal agency personnelbroadly allocates responsibility for decisions.Having the task force place priorities on ap-

plications for financial assistance validatesthe process and formalizes the responsibility.

This consideration of the functions of Col-orado’s local planning mechanisms illustratesseveral general questions related to socioeco-nomic effects. Among them are:

Ž Who identifies the consequences of growth?

q Who judges whether these are positiveor negative?

q Who determines which ones require re-dress?

Local entities address all three questions inthe model presently operating in Colorado. Insome instances, these are established govern-mental units, such as planning offices; inothers, unique panels with broad communityrepresentation. The latter arrangement has

several advantages. It allows individualsclose to the communities to judge the balancebetween positive and negative impacts, andprovides an opportunity for citizens with dif-ferent interests to propose solutions to localproblems, Many share the responsibility of deciding which difficulties are severe enoughto require assistance beyond that availablefrom local resources. The assumption under-lying the model is that those affected shouldhave the prerogative of deciding what a nega-tive impact is and how it might be amelio-rated.

Private Sector Contributions

Throughout the West, energy developmentindustries are contributing significantly togrowth management.19 As previously noted,several oil shale developers have voluntarilycontributed to projects in communities af-fected by their activities. The Rio Blanco OilShale Co., for example, spent over $700,000in direct grants and purchases of services toassist the Rangely area and over $135,OOO insupport of Rio Blanco County. The Colony De-

velopment Operation invested about $3 mil-lion to acquire land and plan for the newtown of Battlement Mesa. Industry has alsoadopted programs to deal with particular




problems. To reduce traffic and contribute to sistance to real estate developers for con-highway safety, the tract C-b lessees operate struction of apartment units in Rifle andbuses for their workers from Rifle to the Meeker, and for a mobile home park in Rifle.20

tract. They have also provided financial as-


Apartment units in Rifle, Colo., developed with industry assistance

State Programs

Colorado

Colorado’s programs largely involve finan-cial and technical assistance. Financial sup-port is directed to municipal, county, and pri-vate agencies with money obtained from twomain sources, lease revenues collected by the

Federal Government and severance taxes col-lected by the State. Technical assistance is inthe form of information gathering and dis-semination, advisory services, program co-ordination, and similar support activities.

AGENCIES INVOLVED IN MITIGATION PROGRAMS

Two State governmental groups are in-volved in Colorado’s programs for impactmitigation: the Division of Energy and Miner-al Impact in the Department of Local Affairs(DLA) and the Joint Budget Committee (JBC) of the General Assembly.

JBC is a legislative committee composed of

members from both houses of the ColoradoGeneral Assembly. It is responsible for draft-ing the State budget and forwarding it to theAssembly for final action. In 1974, the Gen-eral Assembly created the State Oil Shale



Ch. 10–Socioeconomic Aspects q 431

Coordinator’s Office, 21 which subsequentlyevolved into the Governor’s Socio-EconomicImpact Office (SEIO). SEIO, the lead agencyfor coordination within the State government,is now the Division of Energy and Mineral Im-pact in DLA. The Division reviews requestsfor Oil Shale Trust Fund assistance (de-

scribed below), and recommends projects forfunding to JBC. It is also responsible for con-tract negotiations and for administering ap-propriations. The Division also handles miti-gation programs for communities experienc-ing boomtown impacts from other types of de-velopment. DLA coordinates State and localmechanisms in several ways:

q

q

q

reliance on local and regional groups totake an advocacy role in presenting localneeds to State agencies,review of requests by State-level agen-

cies involved with or that might be af-fected by mitigation projects, andadministration of appropriations andcontracts through field representativesin concert with local officials and con-tractors.

Financial Assistance.–

Federal Revenues. —Under the provisionsof the Mineral Leasing Act of 1920, asamended,22 each State receives 50 percent of the proceeds from the sale or lease by theFederal Government of public lands within

the State. Colorado has created two distinctfunds to receive these revenues: one for thosereturned from oil shale lands and another forthose returned from lands other than oilshale. The former is called the Oil ShaleTrust Fund and the Oil Shale Interest EarnedFund; the latter is the Colorado Mineral Leas-ing Fund.

q Oil Sha le Trus t Fund and In te res tEarned Fund. Colorado’s Oil Shale TrustF u n d23 was created in 1974 to receivethose revenues specifically coming from

lease payments, royalties, and bonuseson the two Federal oil shale tracts inwestern Colorado. To date, the Oil ShaleTrust Fund has received payments cor-responding to the first three bonus pay-

ments paid to the Federal Governmentby the tract lessees. Under the bonus off-set provision of the Prototype LeasingProgram, expenditures for certain devel-opment work on the lease tracts can becredited against the final two payments.Since the lessees have proceeded with

development, it is likely that 100 percentof the final two bonus payments will beoffset, and that, therefore, neither theState nor the Federal Government willreceive any additional lease payments incash. (See table 90 for a summary of theFund’s revenues.)

The State statute creating the fundspecifies that the income shall be dis-bursed as follows:

. . . for appropriation by the GeneralAssembly to state agencies, school dis-

tricts, and political subdivisions of thestate affected by the development andproduction of energy resources from oilshale lands primarily for use by suchentities in planning for and providingfacilities and services necessitated bysuch development and production andsecondarily for other state purposes.24

The Oil Shale Trust Fund is not techni-cally a trust since there is no statutoryrequirement that the principal be keptintact. However, JBC has maintained theprincipal at approximately $60 million,

Upgrading of facilities in Rangely, Colo., utilizing

Oil Shale Trust Fund monies




Table 90.–Revenues of the Colorado Oil ShaleTrust Fund, Fiscal Years 1975-79

Lease/bonus Interest Total annualYear i ncomea earned incomeF Y 1 9 7 5 b . . . . . . . $ 2 4 , 6 0 7 , 0 2 0 0 $ 2 4 ,6 0 7 ,0 2 0F Y 1 9 7 6b . . . . . . . . 24,607,020 $2,685,600 27,292,620FY1977 b......... 24,607,020 3,811,271 28,418,291FY1978 b

o 4,219,970 4,219,970

F Y 1 9 7 9c

. . . . . : : . o 5,999,918 5,999,918asee[ext for discussion ofoffsefllng prowstonsapplymglo 197879bSummaryafld S/afus Repoflo/ (fie Mlflera/ Lease amj Severance Tax Fund, Second Annual Re

port lolhe Colorado Slale Legislature Eleparfmenl otLocal Affam 1979cStatefreasurer sotflce

SOURCE

q

Office of Technology Assessment

and appropriations have been madeonlyfrom interest earnings and from theprincipal in excess of $60 million. The in-terest earned by the State is set aside asthe Oil Shale Interest Earned Fund, aspecial account established in 1975. 25

Loans as well as grants from the interest

fund are permitted; the authorized pur-poses for appropriation of the interestearnings are identical to those of theprincipal fund. (See table 91 for a sum-mary of expenditures.)

Colorado Mineral Leasing Fund. Colo-rado’s share of public land monies col-lected by the Federal Government forleasing of minerals other than oil shale isplaced in the Colorado Mineral LeasingFund.26 The fund was created in 1977 tobe used for planning, construction, andmaintenance of public facilities, and theprovision of public services. Priority is tobe given to “those. .. political subdivi-sions socially or economically impacted

Table 91 .–Expenditures of the Colorado Oil Shale Trust Fund,Fiscal Years 1975-80

Amount of Amount OutstandingYear appropriation expended commitmentsF Y 1 9 7 5 a $ 451,187 $325,926b

oF Y 1 9 7 6a , , , 10,385,300 1 0 , 0 2 9 , 3 8 1 $ 2,000FY 1977

a

4,239,646 3,283,408 47,332FY 1978a

6,464.793 4,702,737 993,510F Y 1 9 7 9a

8,929,090 6,306,940 2,622,150

FY1980c

10,446,102 Not available Not availableasumma~Yafld~ldluS ~ePof/ Ofjhe /dmera/ [ease and Severance rar Fund Second Annual Reporf lo fhe Colorado State Leglsldture Oeparlmenlof Local Affairs 1979

b$ I ~~ P61 of the $.$51 I !37 orlglnal approprlahon was returned 10 the 011 Shale Trust FundCOe~drfmenl of Locdl Affatrs Dlwon of Energy and Mined Impact

SOURCE Offfice of Technology Assessment

by the development, processing, or ener-gy conversion of minerals” that areleased from the Federal Governmentand/or that are subject to State sever-ance taxation.27 The State statute pro-vides for an automatic distribution of themonies to the public schools, to the coun-

ties where the leased lands are located(except that no county can receive morethan $200,000 in any calendar year), tothe Colorado Water Conservation BoardConstruction Fund, and to the Local Gov-ernment Mineral Impact Fund.

State revenues.— In 1977 Colorado levieda severance tax on the production and exportof metallic minerals, molybdenum ore, oil andgas, coal, and shale oil.28 Proceeds are allo-cated to different accounts according to themineral being taxed. To date, most of the in-

come has been derived from oil and gas, mo-lybdenum, and coal. Two new funds were es-tablished at the time of passage of the sever-ance tax: a State Severance Tax Trust Fundand a Local Government Severance TaxFund. When shale oil revenues are realized,they will be distributed as follows:

q 40 percent to the State General Fund,40 percent to the State Severance TaxTrust Fund, and

q 20 percent to the Local Government Sev-erance Tax Fund.

Although separate legislation created theLocal Government Mineral Impact Fund andthe Local Government Severance Tax Fund,for practical purposes they have been com-bined into an Energy Impact Assistance Fundthat is administered by the Division of Miner-al and Energy Impact.

Mechanisms for Disbursement.–

The Colorado General Assembly makes ap-propriations from the oil shale principal andinterest funds based on the recommendationsof JBC. Requests for financial assistance from

the oil shale funds are initiated at the locallevel. Priorities for needs are assigned at thelocal level and forwarded to JBC. In addition,the requests are reviewed by the Division of Mineral and Energy Impact. JBC receives the



Ch. 1O–Socioeconomic Aspects q 433

requests in public hearings and subsequentlycorresponds with local officials if clarifica-tion is needed. After analyzing the requests,JBC incorporates, as a series of line items inthe appropriations bill, the sums recom-mended for expenditure from the oil shalefunds. (See tables 92 and 93 for a listing of

the general categories under which thesemonies have been expended and the projectsthat have been funded.)

In contrast to the legislative process con-trolling the oil shale monies, disbursementsfrom the Energy Impact Assistance portion of the Mineral Leasing Fund are at the discre-tion of the executive director of DLA. Obliga-tions are made by contracts negotiated andadministered by field representatives fromthe Department. DLA uses the same local andregional review process followed in the oil

shale appropriations procedure for the iden-tification of needs and the ranking of fundingrequests. It is assisted by a statewide energyimpact assistance advisory committee thatmakes recommendations to the executive di-rector of DLA.

Technical Assistance.–

Information gathering and dissemination,program coordination, regional planning, andadvisory services are the main types of tech-nical assistance provided to local planners.For the oil shale region, this assistance comes

from CWACOG and DLA.

Table 92.–Appropriations From the Oil Shale Funds by Object,Fiscal Years 1975-80

Amount appropriated Percent of totalPurpose FY 1975-80ab appropriation

Road, bridge, and drainageS c h o o l sWaterSewerHealth and mental healthM u n i c i p a l f a c i l i t i e sRecreationCoordination and planning

T o t a l

$14.2987369,262,7149,402,4032,802,058

440,6683,013500

370,0001,190,788

35.122.72 3 0

6 9117 40.92 9

$40,780.8671000

aSumnrary and Sralus Repor( ot the Minera/ lease and Severance Tax Fund Second Annual Report 10 Ihe Colorado Stale Leg,slafure Department of Local Affairs 1979bstale Approprlafton Acf for FY 197980 IS B 5251


Colorado West Area Council of Govern-ments.—CWACOG is a clearinghouse for themunicipalities and counties of northwesternColorado. With respect to energy develop-ment, it provides communities with informa-tion about industry plans and governmentassistance programs, and makes local groups

aware of the responses of neighboring juris-dictions to impact problems. It also assists themitigation task forces in preparing theirneeds assessments and in assigning prioritiesto the final requests submitted to the State;and it is the central agency through whichgrant applications to both State and Federalagencies must pass.

CWACOG uses a growth-monitoring sys-tem to project future employment and totalpopulation figures. Industry work force in-formation and economic and demographic

multipliers are combined for these forecasts.The computer model can accommodate up-dated information, and can supply outputssuch as projections based on alternativeassumptions and growth scenarios. The sys-tem provides a single source of data for gov-ernment and industry officials.

Field Representatives for DLA.—Field per-sonnel are located in several areas of Col-orado that are experiencing energy-relatedgrowth. They help organize community miti-gation teams and coordinate local, county,

and regional requests for funding assistance.They also negotiate and administer contractsinvolving the expenditure of impact funds.They serve a valuable function by expeditingState funding, advising local officials aboutcurrent assistance programs, and monitoringthe progress of authorized work.

Utah

Between 1970 and 1977, the population of Utah increased by 20 percent. Unlike otherWestern States, however, most of this growth

was from a high birth rate, with immigrationaccounting for only 4 percent of the increase.Although there has not been a large migrationto the State as a whole, energy development




Table 93.–Projects Funded by the Colorado Oil Shale Trust Fund, 1975-80

FY 1975 FY 1976 FY 1977

Recipient

Mesa County schools (Re-51 )Moffat County schools (Re-1 )Garfield County schools (Re-2)RIO Blanco County planningGarfield County planningMesa County planningGarfield County schools (Re-1)Mesa County schools (Re-49JT)Meeker schoolsColorado West Area Council of Gov’tsOffice of the Governor

AdministrationState Impact Report

Amount Recipient Amount

$42,575 Water Construction fund $2700,000(Colorado Water Board)

12,389 Piceance Creek Road 1,873,09110,000 RIO Blanco County schools (Re-1) 1,189,00010,000 Garfield County schools (Re-2) 1,000,00010,000 Moffat County schools (Re-1) 670,0008,000 Bonanza Road 497,9097,260 Rulison Bridge 471,0004,000 Roan Creek Road 467,595

781 Mesa County schools (Re-51) 4 00,000De Beque Bridge 299,658

87,187 Garfield County schools (Re-1) 200.00092,734 Colorado West Area Council of Gov’ts. 200,000

(technical assistance)Garfield County schools (Re-16) 121.057Routt County Road 100,000Oil Shale Coordinator’s Off Ice 100,000Town of Hayden, streets 50,000Mesa County schools (Re-49) 36,000Rio Blanco County schools (Re-4) 10,000

Recipient Amount

Piceance Creek Road $2,135,000Roan Creek Road 665,858Rangely sewer 460,000Craig Hospital 230,000Craig water tank 215,000Mesa County schools (Re-49) 147,000011 Shale Coordinator’s Off Ice 106,000Garfield County planning 100,000Moffat school leases 51,456Mental health services 34,000Hayden school site 25,000Colorado West Area Council of Gov’ ts 25,000Delta County 17,000De Beque sewer 15,000New Castle sewer planning 6,666Silt sewer planning 6,666

FY 1978 FY 1979 FY 1980Amount

$608,000532,125500,000479.000450,000450 1000438,750435,400350,000280,000275,000273,757250,000135.000125,000122,000114,079100.00095,85775,00074,00066,825

62,50041,00030,00025.00025,00020,00015,00010,0006,500

Recipient Recipient Amount Recipient Amount

De Beque waterGrand Valley BridgeRangely streetsCarbondale sewerMoffat County–Sunset SchoolHayden Elementary SchoolRifle sewerMeeker streetsMesa County schools (Re-51)Hayden waterCraig City HallGarfield County schools (Re-2)Moffat County bypassRoan Creek Road

Craig waterOak Creek waterOil Shale Coordinator’s OfficeRangely sewerMental health centerCarbondale Municipal BuildingMoffat–modular roomsRifle lift stationColorado West Area Council of Gov’ts

(Planning)Hayden drainageMeeker HospitalCraig drainageDelta County waterHayden recreationWalden waterRifle planningSilt planning

Rifle water 2,056,000County Road 24 1,000,000Rangely streets 900,000Craig High School 750,000Colorado Water Conservation Board 600,000Rifle bypass 500,000Meeker sanitation 368,000Meeker pool 350,000Meeker streets 320,000Mesa County airport water 293,250Garfield County airport 260,000Grand Valley water 250,000Fruita sewer 200,000Transportation planning, CWACOG 198,000

New Castle water 196,000Silt water 151,000Impact Coordinator’s Office 114,079Colorado Northwest Community

College 110000Mesa County sewer 104,450Regional School Fund 100,000Rangely Hospital 50,811Mesa County transportation 25,000RIo Blanco County Impact Coordinator 17,500Silt planning 15.000

Rifle school constructionRifle bypassMeeker sewage treatment expansionSilt water ImprovementsMeeker streets and drainageMesa County sewer system

ImprovementsC-a to Rangely Road engineeringDe Beque water systemRifle senior centerGrand Valley sewage treatment plantDinosaur water system

$2,750,2202,000,0001,440,0001,400,000

800,000

796,787300,000300,000172,500141,20666,153

SOURCE Summary and Status of the Mineral Lease and Severance Tax Fund Second Annual Report 10 the Colorado State Legislature. Colorado Department of Local Affairs 1979



Ch. 1O– Socioeconomic Aspects q 435

activities have been responsible for rapidpopulation increases in certain rural countiesand communities. Until the recent boom, thepopulation in most of these areas had de-creased over several decades, As a conse-quence, the communities have been ill-pre-

pared to respond effectively to currentchanges.

The oilfields of eastern Utah attracted peo-ple to Duchesne and Uintah Counties, al-though oil drilling there has peaked and thegrowth is now waning, Area residents hopethat the present emphasis on synthetic fuelswill lead to a boom from oil shale and tarsands development. 29 Increased coal mininghas caused growth in Carbon, Sevier, andEmery Counties. In 1960, the population of communities in these counties was under1,000; several even declined dur ing the

1960’s. Because there are no larger towns inthe area that can provide housing and otherservices, they have been forced to absorb allthe migration. A resurgence of uranium min-ing along with oil exploration has stimulatedgrowth in San Juan, Grand, and GarfieldCounties. The towns of Blanding, Moab, andMonticello, which have all gained new resi-dents, are expected to continue growing.

Utah created a Community Impact Accountin 1977 to assist areas affected by energydevelopment. 30 It is a “revolving account for

loans and grants to state agencies, politicalsubdivisions of the state, and special servicedistricts which are or may be socially or eco-nomically impacted by mineral resource de-velopment . . ."31 Revenues come from a por-tion of the State’s share of Federal minerallease payments, Projects are chosen by aboard comprised of chairpersons of severalState boards, councils, committees, and de-partments. The board establishes the criteriafor awarding grants and loans, determinesthe order in which projects will be funded,and serves as the sponsoring agency. The

chief criterion for determining which projectsto support is urgency of need. To date, almostall support has been for water and sewerprojects. Only those communities already im-pacted have received assistance even though

the legislation creating the account specifiedthat those expecting large population in-creases are eligible for help. The Uinta basin,where the oil shale deposits are located, hasnot received any funds from the account eventhough it is undergoing oil and gas explora-tion and development. Because the Communi-ty Impact Account is the only funding sourcein the State designed to respond to problemsassociated with energy development, re-quests for help have far surpassed the avail-able monies. In mid-l979, with only $4 millionavailable for distribution, a total of $11 mil-lion had been requested.

Adequate water supplies are one of theparamount needs in the energy-impactedareas of Utah. Several towns have had toplace moratoriums on additional buildingbecause water systems cannot service in-

creased demands, a nd du ri ng summermonths many communities are forced to ra-tion the available water. To help solve theseproblems, the City Water Loan Fund 32 w a screated by the State legislature in 1975. Itprovides interest-free loans to cities for theconstruction of water supply and water treat-ment facilities. The fund provides up to 80percent of the amount needed with the onlyqualification that the community be incor-porated. Originally the revenue came fromtaxes on the sale of alcoholic beverages, butrecently the funding source was changed to

State mineral lease royalties; the amountvaries from around $2 million to $2.5 millionannually. Surprisingly, the fund has prettywell been able to keep up with the demand forloans. Every application has received a loanoffer, even though not always the amount re-quested, A problem that might arise in thelong term could be that a loan taken out dur-ing a time of boom would have to be paid bythe remaining, smaller population during asubsequent time of bust. Also, since the loansare just for water-related projects, help islimited to only this one problem area.

Wyoming

Some of the largest growth in the WesternStates has been in Wyoming. Between 1970



436 ŽAn Assessment of Oil Shale Technologies

and 1978, the population in all but one of Wyoming’s 23 counties increased. In con-trast, in 15 of the 23 it declined in the decadebetween 1960 and 1970. Much of the recentgrowth has been related to energy develop-ment, although some reflects the trend of set-tling in rural areas for simpler living patterns

or for retirement. From 1970 to 1978, popula-tion expanded 30 percent or more in eightcounties . These are distr ibuted in threedistinct geographical areas. Lincoln, Uintah,Carbon, Sweetwater, and Teton Counties liein the west and southwest where there arecoal, uranium, and oil deposits and the onlylarge oil shale deposits in the State. Most of the growth in Campbell and Converse Coun-ties, in the Powder River basin in centralWyoming, has been from the opening of coaland uranium strip mines. Platte County, insoutheastern Wyoming, is the site of a 1,500-MW coal-fired plant.

Wyoming has several programs for manag-ing growth. The major tool, designed for largedevelopment activities, is the Wyoming In-dustrial Development Information and SitingAct.33 This Act, passed in 1975, requires thatany project with construction costs in excessof $63,588,000 obtain a siting and construc-tion permit from the Industrial Siting Council,a board appointed by the Governor. Before apermit is granted, the developer must submita plan for the alleviation of social, economic,

and environmental impacts, and can be re-quired by the council to undertake their miti-gation. For example, applicants can be askedto provide direct loans and grants to a politi-cal subdivision. Another management device,created by the Joint Powers Act, 34 allows twoor more agencies, such as cities, counties,and school districts, to form a Joint PowersBoard that can create, expand, finance, oroperate facilities. This not only makes possi-ble combined financing by the participatingpolitical entities but also makes them eligiblefor Joint Powers Loans. There is no ceiling on

a loan, and the terms must be no longer than40 years at an interest rate of not less than 5nor more than 10 percent.

Wyoming also has an array of mitigationprograms. (See table 94.) They are funded byFederal mineral lease revenues and Stateseverance and excise taxes. Most are admin-istered by the Farm Loan Board, composed of the Governor, secretary of state, auditor,treasurer, and state superintendent of public

instruction. Allocation of funds is specified inmost cases by the taxing legislation, andthere are few discretionary programs. Onealternative available to local communities togenerate discretionary revenue is an optionall-cent sales tax.35 It has been used successful-ly in several communities although approvalby the local voters must be sought every 2years. Case studies of boomtowns in Wyo-ming indicate that there are major differ-ences in the effects of rapid growth, and toaccommodate these differences, flexible pol-icies are needed. This is especially true for

providing such human services as day carecenters, youth assistance and senior citizenprograms, and alcohol counseling. Too fewfunds are available to alleviate the social im-pacts accompanying rapid growth.36

Evaluation of State and Local Mechanisms

State policies regarding social and econom-ic effects vary. In Colorado, local initiative iscentral in the mitigation process. The Stateand its oil shale counties and municipalitieshave been preparing for increased shale de-velopment for nearly 10 years. However, inthe past, this development has been inter-rupted or delayed by market changes, regula-tory modifications, and technological compli-cations, which has made planning difficult. Inaddition, oil and gas, coal, electric genera-tion, and uranium industries are all expand-ing at the same time as oil shale. This compli-cates the identification of impacts specifi-cally attributable to shale development andadds to the potential for disruption.

An elaborate planning infrastructure is in

place in the Colorado counties and munici-palities. Over $40 million has been appro-priated for oil shale impact mitigation, with




Table 94.–Wyoming Programs to Mitigate Social and Economic Impacts — .

ImplementingName of mitigation program Objectives Funding agencies Comments

Wyoming Industrial Develop-ment Information and SitingAct ( 1975)

Joint Powers Act ( 1975)

Provide information about new Industrial Not applicable Wyoming Sitingfacilities costing over $63,588,000 councilSiting and construction permits re-quired before building starts

Allows different political entitles to join Joint Powers Loans from Farm Loan Board

Council can require applicantsto take actions to mitigateadverse socioeconomicImpacts

Some towns and counties havedifficulty cooperating Small-er towns lack manpower toprepare detailed applications.

Grant funds extremely limited.competition keen

Requires feasibility study.authorizing legislation, andvote to approve any publicdebt (such as bonds) beforeconstruction can begin.

$160 million will probably be

together to finance and operate publicfacilities through a Joint Powers Board

FLB. aFLB is restrictedto $60 million inoutstanding loans

(FLB)a

Wyoming Government RoyaltyImpact Assistance Account( 1976)

Wyoming Water DevelopmentProgram ( 1975)

Grant program for communities in areasof mineral development

Mineral Leasing Act of1920, as amended b

FLB

Encourage optimal development ofhuman, Industrial, mineral, agricul-tural, water, and recreationalresources through projects andfacilities for water storage,distribution, and use

1 1/2-percent excise tax

on coalRevolving loan account,

up to $100 million canbe outstanding

Water DevelopmentCommission, Deptof Economic Plan-nlng and Develop-ment, FLB, localagencies

FLBCoal Tax Revenue Account(1975)

Grants to political subdivsions in areasImpacted by coal development for

2-percent severance taxon coal expended before synthetic

Public facilities. 50 percent must Maximum cumulative tax fuel development occurs

go for streets and highways revenues limited to$160 million

Capital Facilities RevenueAccount ( 1977)

Permanent capital facilities by legislativeappropriation, 30 percent for schooldistrict capital constructionentitlements, formula allocation tocommunity colleges, remainderfor highways

Capital FacilitiesCommission

Used mostly for major Statefacilities (university, prison),

1 1/2-percent excise taxon coal, trona, anduranium

Maximum tax revenueslimited to $250 million

approval of bonds needed forschool construction

Wyoming Community Program delayed by litigation.Development only recently implemented

Wyoming Community Develop-ment Authority ( 1975)

To provide funds for private mortgagesat low interest through mortgage

Mortgage monies gener-ated through issuance

lending institutions of bondsAuthority granted for up

to $250 million inbonds c

Authority

alhe Farm Loan Boaro conssk of [he Governor secrelarv of slate aud!lor treasurer artd slate SuDer(fltefldefll of oubl~c /nstruct(onbsee .eKt for a OIScusslon O! Federal flnanclal ass!slance ~r09rdmS

‘The 1980 Wfomlng Ieqlslalure oas under conslderalton rdtstoq lms amount 10$750 mltl{on

SOURCE O!flce of Technology Assessment

over 90 percent allocated to the four countiesof Mesa, Garfield, Rio Blanco, and Moffat.(See table 95.) Most of the remainder hasgone for the State’s support services. As a re-sult, the region is prepared for reasonablegrowth and is awaiting expanded oil shale de-velopment. However, the ability of existingstrategies to deal with a large or sudden pop-ulation influx, such as might occur with arapid expansion of the industry, is as yet un-

tested. Although the State has ambitious pro-grams, the General Assembly has adopted acautious approach to the expenditure of theOil Shale Trust Fund monies. While not re-quired to do so, JBC has elected to retain aprincipal of $60 million in the trust fund. This

has caused some discontent in the oil shaleregion where expenditure of the full amountwould accelerate preparations for growth.Because the trust fund is disbursed by legisla-tive appropriation, intrastate political differ-ences also come into play. The GeneralAssembly has greater representation fromthe eastern, more densely populated, urbanparts of the State; thus western slope Sena-tors and Representatives can be outvoted. Im-

pact mitigation, in this case, is subject to thepolitical compromises of the Colorado appro-priation process.

Utah and Wyoming have not been prepar-ing extensively for oil shale development im-



.


Table 95.–Allocation of Oil Shale Trust Funds,Fiscal Years 1975-80

Percentage of total appropriation

County or agency FY 1975-79 FY 1980

Garfield County – 285 – 6 1 9M e s a C o u n t y 13 0 12 4Moffat County 11 2 0 6

R IO B l a n c o C o u n t y 4 0 0 2 4 3Subtotal–oil shale region 927 - 9 9 2

D e l t a C o u n t y 0 1 0 a

J a c k s o n C o u n t y 0 0 5 0Routt County 3 7 0

Subtotal–all counties...... 9 6 6 9 9 2

Division of Energy and Mineral Impact 2 1 0.6C W A C O G 1 2 0 1

Total 100 100

For example, Douglas and Wheatland inWyoming have experienced few of the nega-tive effects identified in the literature asboomtown impacts. Rock Springs and Gillette,on the other hand, appear to be at the op-posite end of the spectrum, with the formerbeing the classical example of a town dis-

rupted by energy development. Yet these fourcommunities are undergoing the same typesof industrial growth (primarily coal, oil, andgas prospecting and production) and have thesame kinds of impact assistance available tothem.17 A conclusion from these cases is thatthe capability of adapting to rapid growth ap-pears to be highly site specific.

dThe 1979 Gepera( Assembly adopted Ihe policy 10 allOCa[e trust funds Oflly tO Ihe counties In IheImmediate 011 shale vtctnlly

SOURCE OTA bdSW on data for FY 197579 from Summary and Status Report of the Mineral Lease and Severance Tax Fund Second Annual Report to the Colorado Stale Legisla-

ture, Department of Local Affairs 1979 and FY 1980 from State Appropriation Act forFY 19791980 (S B 525)

pacts. Both States, however, have had tocome to grips with other energy industry ex-pansion, and presumably could use programssimilar to the ones now established for coaland uranium mitigation to adjust to oil shalegrowth. They emphasize a more centralizedprocess with State government playing alarger part in the determination of needs andthe allocation of assistance. Utah may belimited by a lack of funding, although thebonus payments from the U-a and U-b leasesales—now being held in escrow pending theoutcome of the ownership question—shouldbe available in the future. The State may ex-perience difficulty from a lack of adequatelocal infrastructures capable of handlingrapid growth. Evaluation is complicated forUtah as it is for Colorado by similar uncer-tainties about the future timing, pace, andsize of the industry. Wyoming has many pro-grams that could be adapted for oil shale im-pact mitigation. At present, its funding levelsappear to be adequate.

No State facing social and economic prob-lems from energy development is able to an-

ticipate which communities will be able to adjust to growth and which may be disrupted.Whether towns will suffer from rapid growthor take it in stride depends on a unique set of complicated factors within each community.

Federal Programs

Only a few of the over 1,000 existing Feder-

al programs are designed to deal with socio-economic impacts. A 1978 Report to the Presi-dent 38 lists 160 that were judged “potentiallyapplicable to energy impact issues. ” They areadministered by 20 departments or other Fed-eral agencies. About two dozen programsthat are of importance to the Western Stateshave been identified by Murdock and Leis-triz.39 (See table 96. ) Only those that contrib-ute to the alleviation of negative impacts fromoil shale development are examined in detailhere, Federal programs can be placed in twob ro a d c a te g o r ie s : f inanc ia l and techn ica l

a ss i s t a n c e .

Financial Assistance

Section 35 of the Mineral Leasing Act of 192040 is a major source of Federal financialassistance. This legislation originally pro-vided for the Federal Government to return3 71/2 percent of the revenues it receives frommineral leases on public lands to the States inwhich those lands are located; these monieswere to be used by the legislatures of theStates for support of public schools and

roads. In 1976, this section was amended bythe passage of the Federal Coal LeasingAmendments Act41 and the Federal Land Pol-icy and Management Act42 (also known as theBureau of Land Management Organic Act or




Table 96.–Selected Federal Programs Used by Western States for Assistance With Social and Economic Effects of Energy Development’

Name of program Implementing agency Objectives Comments

Assistance in planning and growth management Comprehensive planning Community Planning and Strengthen planning and declslon-making Urban orientation overall, smaller citiesassistance Development, HUD capabilities of States, local governments, and counties receive funding throughHUD 701 program and areawide planning organizations States Funds allocated on basis of pastNational Housing Act of population which IS a disadvantage to

1954, as amended (40 rapidly growing communitiesU S C 461) Some State and local concern over recent

decline in funding levels —

Community development block Community Planning andgrants–small cities Development, HUDHousing and Community

Development Act of 1974Title I (42 U S C5301-531 7)

Economic development– Economic Developmentplanning and technical Administration (EDA),assistance Commerce

Public Works and EconomicDevelopment Act of 1965,

as amended (42 U S C3151, 31 52) Title III

Assist communities in providing decenthousing and a suitable Iiving environ-ment, expand economic opportunities

Foster multicounty planning andImplementation capability, solve prob-lems of economic growth through projectgrants, feasibility and other studies, andmanagement and operational assistance

Primarily for urban areas, most fundsallocated by formula Some discretionaryfunds for special-purpose grants to small

communitiesProvides 100-percent funding that can be

used as local matching contribution forother programs

Can also be used for facility constructionas well as for planning

Criteria for project selection makes it dif -ficult for energy-impacted communitiesto obtain funding

Competition for funds is keen.

Technical assistance– Off Ice of Personnel Aid in problem-solving and delivering Few communities appear to have takenpersonnel sharing Management Improved services by sharing profession - advantage of program.Intergovernmental Person- al administrative, and technical Time involved in Iocating and negotiatingnet Act of 1970 (5 U S C expertise. for an individual may be a constraint for3371-3376) small counties and communities

Water quali ty p lanning Off ice of Water and Waste Develop water quality management plans Funds limited to planning onlysec 208 grants Management, EnvironmentalClean Water Act, as Protection Agency (EPA)amended (33 U S C 1251et seq. )

Assistance in expanding public facilities and servicesc

.

Water and waste disposal sys- Farmers Home Administration Provide amen! ties, alleviate health Sewer and water systems cannot serveterns for rural communities (FMHA), Agriculture hazards promote orderly growth of rural areas with a population in excess ofConsolidated Farm and areas by providing new and Improved 10,000 population, priority is given to

Rural Development Act, water waste disposal facilitiescommunities of less than 5,500 in -

sec 306 (7 U S C 1926) habitants

Community facilities loans FmHA Agriculture Construct, enlarge, or Improve community Targeted for areas with Iow-income ruralConsolidated Farm and facilities residentsRural Development Act, Priority to projects enhancing public safety

sec 306 (7 U S C 1926) (fire, pollee, rescue services), healthcare facilities needed to meet life/safetycodes, public buildings and courthouses,recreation facilities, new hospitals

Construct Ion grants for Office of Water and-Waste Assist in construction of municipal sewage Funds allocated to States on awastewater treatment works Management, EPA t reatment works population-based formula No funding ofClean Water Act as collector systems in ‘‘communities not in

amended (33 U S C 1251 existence” in October 1972et seq ) Some difficulty allocating funds on a timely

basis

Economic development and EDA, Commerce Assist State and local governments to..- —..——.

Targeted to communities experiencingadjustment assistance arrest and reverse long-term economic economic decline but funds are availableTitle IX– EDA deterioration, address dislocations from to energy-impacted areasPublic Works and Economic Federal actions, from compliance with Flexibility an advantage

Development Act of 1965, environmental requirements, and fromas amended (42 U S C severe changes in economic conditions3121 et seq )

— — —




Table 96.–Selected Federal Programs Used by Western States for Assistance With Social and Economic Effectsof Energy Developmenta —continued

Name of program Implementing agency Objectives Comments

Outdoor recreation Heritage Conservation and Financial assistance for p lanning, L imited funding restr ic ts the number of‘‘ BOR program’ Recreation Serv ice, Interior acquisition, and development of outdoor projects that can be supportedLand and Water Conserva- recreation areas and facilities A popular program

tion Fund Act of 1965,

et al. (16 U .S. C. 1-4et seq. )

Planning and site acquisition FmHA, Agriculture Assist in developing plans for growth Newly Implemented,Sec. 601 program management and housing and in Currently Iimited to coal and uraniumPower Plant and Industrial acquiring sites for housing and public Impacts,

Fuel Use Act of 1978 facilities(Public Law 95-620)

Assistance for housingRural housing loans FmHA, Agriculture To assist rural families through guar- Loans are regarded as a ‘ ‘source of last

Housing Act of 1949, as anteed/insured home loans resort to be used only if commercialamended. Title V, sec. lending Institutions cannot finance502 (42 U.S. C. 1471 et housing.seq., 42 U.S. C. 1480;42 U.S.C. 1472)

Rural housing site loans FmHA, A griculture Assist public or private nonprofit Priority given to housing for low- andHousing Act of 1949, as organizations to acquire and develop land moderate-income families

amended. Sees. 523 and to be subdivided on a nonprofit basis for524. (42 U.S. C. 1490c homes.and 1490d)

Rural rental housing loans FmHA, Agr iculture Prov ide economically des igned and con-Housing Act of 1949, as structed rental and cooperative rentalamended. Sees. 515 and housing for rural residents,521. (42 U.S.C. 1485,1490a)

dThe ~rogram~ l,~fed are ,Ilus(rdtlve of the types of aid avadable In Western States no attempt has been made to Include all possible Federal Pro9rams used by lmPacted communitiesbGeneral ~ategor[es are based o n the format used by Murdock & Le!slr[tz Errergy L7eve/opmerrf Irr Ihe b$’es(e~rr Umled S/aleS–hnPaC/ On Rural Areas (A y prae9er Publishers 1979)C R evenue ~har, ng acts suc~ as the Local Government Funds Act (publlc Law g4.5fj5) are not Included see [ext for a discussion of the Mineral Leasing Act Of 1920 aS amended


FLPMA). The Federal Coal Leasing Amend-ments Act increased the States’ share of royalty and lease proceeds to 50 percent, andspecifically directs the legislatures, whendistributing these proceeds, to give priority tothose subdivisions of the State where leasingoccurs under the Act. At the same time, thepurposes for which the funds could be usedwere broadened to include “planning, . . .construction and maintenance of public fa-cilities, and . . . provision of public serv-ices." 43 FLPMA further amends the 1920 Actto authorize the Secretary of the Interior to

make loans to States and their political sub-divisions. The amounts of the loans are not toexceed the revenues anticipated by the Statesor their jurisdictions for any prospective 10-year period. Loans are to be repaid, at 3-per-

cent interest, from these proceeds. The lan-guage of the Coal Leasing Amendments Actthat allows broader use of the funds and spe-cifies their application to affected areas isalso extended to the loans.44

Section 601 of the Power Plant and Indus-trial Fuel Use Act of 1978 45 established theEnergy Impacted Area Development Assist-ance Program (popularly, the sec. 601 pro-gram). Its objective is to “help areas im-pacted by coal or uranium development activ-ities by providing assistance for the devel-

opment of growth management and housingplans and in developing and acquiring sitesfor housing and public facilities and serv-ices. 4 6 The lead agency designated to admin-ister the section is the Farmers Home Admin-




istration (FmHA). The Governor of a Statewishing to participate must designate energy-impacted areas and prepare a State invest-ment strategy for allocating the funds. Grantapplications for impact aid must be consist-ent with the State investment plan. Local gov-ernments, councils of local governments, and

State agencies are among the eligible appli-cants. Grant funds will pay 100 percent of thecosts of developing plans for managinggrowth and/or plans for new housing, and upto 75 percent of the cost of acquiring or devel-oping sites for housing, public facilities, orservices.

Three criteria are specified for designationas an impacted area. First, employment incoal or uranium development activities musthave increased, or be expected to increaseover 3 years, by 8 percent or more from the

preceding year. Second, the increased em-ployment must result in a housing shortage orinadequate public facilities and services.Third, the available State and local financialresources must be inadequate to meet thecurrent needs or those projected for the fol-lowing 3 years. Within the oil shale region,the purchase of land by the city of Meeker forthe construction of low- and moderate-incomehousing was included as a priority project inthe 1979 Colorado investment strategy.

Technical Assistance

THE FEDERAL REGIONAL COUNCIL

The Energy Impact Office of the FederalRegional Council (FRC), Region VIII, overseesFederal technical assistance programs. TheOffice was created early in 1978 to coordi-nate the response of Federal agencies to localneeds. In addition to the development of animproved system of service delivery, the FRCefforts are designed to evaluate Federal legis-lation for impact assistance and to collect im-pact data and related information. The agen-cies comprising the Federal Regional Council

are the Departments of Agriculture; Com-merce; Energy (DOE); Health, Education, andWelfare; Housing and Urban Development(HUD); the Interior; Labor; Transportation;the Community Services Administration, and

the Environmental Protection Agency (EPA).Senior staff members of these agencies makeup an Intergovernmental Committee thatassists the Energy Impact Office.

Dissemination of information and inter-agency coordination are the main functions of

the Federal programs. Several examples canbe cited. FRC has a representative in the OilShale Environmental Advisory Panel (OSEAP)who serves as contact with this group. TheFederal Assistance Program Retrieval Sys-tem (FAPRS) is a computerized informationbank, keyed to programs described in the Cat-alog of Federal Domestic Assistance. The En-ergy Impact Office uses it to help communi-ties identify various Federal assistance pro-grams and determine their eligibility for aid.DOE’s Office of the Regional Representative,Region VIII, in cooperation with FRC, pub-

lishes an annual Regional Profile—Energy Im-pacted Communities47 that collates data onthe energy impacted areas.

OFFICE OF THE AREA OIL SHALE SUPERVISOR

The Office of the Area Oil Shale Super-visor of the U.S. Geological Survey (USGS)also provides technical assistance to commu-nities by serving as a clearinghouse for in-formation about social and economic impactsand programs for their alleviation.

Summary of Federal Support Ini ti ati ves

At the present time, there is no single Fed-eral policy with respect to the social and eco-nomic effects of energy development. At theregional level, the Federal point of view isbest expressed in the Region VIII DOE Region-al Profile. The edition of March 1979 reiter-ates a position taken in earlier volumes:

The Region VIII office maintains the posi-tion that local communities and countiesmust take the initiative to become involved inassessing, planning for, and mitigating ad-verse energy related impacts. To effect ateam effort involving industry, Federal,State, and local government, the initiativeand follow-up must first be taken by localleadership,”




Several programs are operating that ad-dress limited aspects of socioeconomic ef-fects but, at present, none directly addressesthe impacts that may come with synthetic fueldevelopment or the specific consequences of accelerated shale oil production. A wide vari-ety of assistance is available through avenues

not specifically designed to deal with energydevelopment impacts. These various Federalprograms have d i f fe rent emphases andmodes of providing help, and impacted com-munities must compete with everyone else forthe limited funds available.

These regular Federal programs usuallyrequire elaborate proposal development butsmall towns with limited manpower often donot have the expertise to prepare grant ap-plications. Fu rthe rmore, m any p rogr am shave lengthy review processes before deci-sions are made, which can be a disadvantagefor boomtowns. For example, EPA grants forsewer facility upgrading take about 3 yearsfrom the time of application to the time of decision; if a community does not get a grant,this time is lost entirely and the town can onlyfall further behind in its effort to keep up withits growth. In addition, although the specificprograms may be adequately meeting theneeds for which they were designed, theirlimited nature means that the cumulative im-pacts of all types of industrial developmentare not being addressed.

At present, the major role of the FederalGovernment is providing revenues for mitiga-tion; these monies come primarily from theMineral Leasing Act of 1920, as amended. Asomewhat expanded Federal impact mitiga-tion role is found in section 601 of thePowerplant and Industrial Fuel Use Act of 1978. The extent and nature of any additionalFederal involvement in impact mitigation arecontroversial. On the one side, it can beargued that social and economic impacts areState and local problems. They should beviewed as the inevitable consequences of in-

dustrial development, and the Federal Gov-

ernment need not be involved with their ame-lioration. This viewpoint, opposing Federal in-volvement, also contends that specific Fed-eral mitigation programs would increase bu-reaucracy, and cites the public’s growing dis-pleasure with the perceived intervention of Federal agencies in the daily life of the citi-

zenry as a reason for not expanding Federalactivities. On the other side is the positionthat national requirements are the rootcauses of the local impacts, therefore an ex-panded Federal role is appropriate. SeveralWestern States contend that because ex-panded domestic energy production is a na-tional goal, for reasons of equity the FederalGovernment should assume a more direct rolein the alleviation of negative impacts fromthis development.

Assuming additional Federal involvement

is desired, how can the Government most ap-propriately assist impacted communities?One position is that providing financialassistance is sufficient programmatically andonly the amounts need to be increased; newprograms and regulations are not desirable.Another position is that Federal regulationcould be used to mitigate impacts by, for ex-ample, pacing industry’s growth rate throughleasing policies. A third position is that theGovernment should be substantially involvedin mitigation programs that use Federalfunds. Part of this issue includes the question

of when and where the Federal Governmentmight to be involved. The provisions of thePowerplant and Industrial Fuel Use Act sug-gest that it should step in only when State andlocal governments cannot handle impactproblems. A similar position is that Federalparticipation should be confined to areas re-quiring long-term commitments, such as hous-ing, sewer, and water systems. Another pos-sible Federal approach could be to help speci-fic groups (such as retired persons on fixedincomes or young adults seeking to enter the job market) who may be particularly hard hit

in boomtowns.49




Possible Consequences of Oil Shale Development

General Effects of

Rapid Populat ion Growth

The recent development of energy re-

sources has caused large numbers of peopleto move into established rural communitieswithin short periods of time. All parts of acommunity are affected by this kind of growth. Local government agencies arepressed to provide additional services. A major difficulty is that the expanded facilitiesand services are needed before new tax reve-nues can be realized. A 3- to 5-year lag ap-pears to be the average between the time theincreased services and facilities are requiredand the time additional revenues can be gen-erated. (See figure 71. ) In the long run, how-

ever, local governments should benefit fromthe increased tax base resulting from energydevelopment.

Local governments need help in the earlystages of rapid growth. One traditionalmeans of raising the needed funds is by issu-ing bonds. While this remains important, ex-perience indicates that it is far from ade-quate. First of all, State law usually placeslimits on the amounts of indebtedness thatcounties and communities can incur throughbond issues. Second, the assessed valuationupon which bonding limits are based in-creases over the life of a project but fundsare needed during the early stages when thepopulation is growing rapidly. Third, local

I

4

._----

—




Fiqure 71 .— Energy-Related Employment, Tax Revenues, and Need for Public Services in an Area

EMPLOYMENT

-.Affected by a Large-Scale Energy Development

CONSTRUCTION I

PHASEI

I

OPERATIONPHASE

I I

Energy-RelatedI

Employment

L

II

PUBLIC SERVICES

TAX REVENUES

TIME

SOURCE S H Murdock and F L Leistritz. Energy Development in the Western United States, 1979, Praeger Publishers

residents are often afraid to approve bondissues because of the instability of the boomcycle. People who have moved in during con-struction, and who are among those needingnew services and infrastructure, usuallyleave at the end of the construction period.Longtime residents are fearful that they will

be left to discharge debts incurred during thisperiod. Consequently, voters in many of themost severely impacted communities have re- jected bond issues. Similar difficulties arefound with loan and loan-guarantee pro-grams. In this instance, the statutory or con-stitutional limits on the debt that rural com-munities can incur is an obstacle to the use of the loans to meet front-end funding needs.

Yet another statutory limitation can be aceiling on the expansion of local governmentbudgets. For example, in Colorado most smalltowns are prohibited from “the levying of agreater amount of revenue than was levied inthe previous year plus seven percent . . ." 50

The practical effect of this restriction on milllevy increases is to limit municipal and coun-ty budgets to a 7-percent-per-annum growth.

Finally, the ability of local governments torespond may be complicated because the de-velopment and the population growth may bein different places. When the project is in onetaxing jurisdiction and the community in adifferent one, there is a jurisdictional mis-match. In this case, the town that must pro-

vide increased facilities and services cannotlook forward to larger revenues from taxeson the new industry.

In the private sector, housing can be a major problem. It usually is in short supply; itsprices are often greatly inflated; and landmay not be available for new construction be-cause of terrain, price, or public ownership.Shortages of construction financing andmortgage money are common and, in somecases, new employees may not qualify formortgages. The need for temporary housingfor construction workers can exacerbatethese problems. Mobile homes often fill thisneed but their siting and providing services tothe sites add to the difficulties faced by localgovernment . Indus try has , in several in-stances, sought to assist by supplying capital



Ch. 10–Socioeconomic Aspec!s q 445

for housing construction. Because publichousing is statutorily limited to low- and mod-erate-income groups, Federal Governmentagencies cannot provide much help.

Other affected parts of the private sectorare the local retail trade and service indus-tries. These businesses often anticipate in-creased income from energy development.What may not be expected are increases inlabor costs, taxes, and competition. In somecases, this sector has not been able to meetthe new demands; business failures have

been the most extreme consequences. Morecommon have been difficulties in getting andkeeping help, providing the goods that cus-tomers want, and expanding stores and shopsto keep up with the increased business. Likelocal governments, retail businesses shouldprofit in the long run from energy devel-opment; their dislocations occur during theearly periods of rapid growth when servicescannot keep up with the new demands.

Those parts of the community that provideservices to the residents also are affected. Inmany areas, this support sector is inadequateprior to any sudden growth. For example,doctors and dentists are not readily availablein many rural regions. School systems, whileestablished, cannot offer broad curricula,

and may have difficulty attracting and keep-ing personnel. The number of public safetyprofessionals often is limited. Sheriff’s officesand town police departments seldom havelarge forces; fire protection is usually pro-vided by volunteer departments. Recreationfacilities may be lacking. Social welfare serv-ices may depend on itinerant professionals,such as a public health nurse or social work-er who visits the communities periodically.

The functions of a community’s social in-frastructure often are carried out through in-formal social networks. In rapid growth situ-ations, these networks can break down sim-ply because of the increased number of new-comers. If there are no established formalstructures, then the services cannot be pro-vided. For example, in many rural commu-nities the school is the center of recreationalactivities, and there are few structured pro-grams. Increased demands to use the schoolgym cannot be met because there aren’tenough hours in the day or enough basketballcourts to accommodate the large number of new players, Established informal recreationpatterns can thus be disrupted and nothingtakes their place until a formal communityprogram can be set up. The effects of rapidpopulation growth on the various aspects of





Adequate recreational areas are often lacking in boomtowns

the existing community support systems areamong the more ubiquitous social impacts of energy development activities.

Rapid growth inevitably causes socialchanges; those communities experiencing ex-cessive strains on their social structure from

sudden growth have been called modernboomtowns. 51 A well-documented example isthe Rock Springs—Green River (SweetwaterCounty) area of Wyoming.52 Here the popula-tion grew from 18,391 in 1970 to 36,860 in1974. Among the consequences were:

q

q

q

Housing availability fell far short of de-mand. In 1974, between 4,500 and 5,000families were living in mobile homes,many on scattered, isolated tracts in un-incorporated parts of the county.These housing areas often lacked ade-

quate water, sewer, and other facilities.Health care became a major problem.An estimated 40 percent of the residentshad to seek medical care outside thecounty; the mental health clinic caseload

q

q

q

It

expanded ninefold as alcoholism, suicideattempts, and divorce rates soared.Local government was overwhelmedwith difficulties. Costs for capital con-struction of public facilities, such aswater and sewer treatment plants, weregreater than the communities’ borrow-ing capacity, and demands for publicservices, such as fire and police protec-tion, were beyond the available re-sources.Schools could not keep up with the pupilincreases. The school districts were al-ready bonded up to the legal limit andwere not able to provide the needed ad-ditional services.As a result of the boomtown conditions,industry was unable to recruit and re-tain employees. Employee turnover in1973 ranged from 35 to 100 percent, andproductivity declined. Cost overruns re-sulted from construction delays. 53

is difficult to determine whether a com-munity will be able to respond adequately to



Ch. 10–Socioeconomic Aspects Ž 447

the pressures of growth; however, some gen-eralizations have been drawn from casestudies of towns like Rock Springs and GreenRiver. Boomtowns have been described ashaving the following characteristics:54

q

q

q

q

q

q

q

q

q

q

q

a small population base, usually under10,000 residents;geographic isolation from urban areas;rapid population growth;a shift in economic activities away fromagriculture, trade, and services to con-structing and operating energy-relatedindustries;demand for temporary and permanenthousing that exceeds supply, with ac-companying price escalation;increased symptoms of social stresssuch as crime, truancy, child abuse,alcoholism, and suicide;inability of the public sector to provide,in a timely fashion, services and facil-ities such as streets, water, and sewers;dislocations in the private sector such asbusiness failure, labor shortages, andcost increases;strain on health services from increasedneed for access to professionals and fa-cilities;high employee turnover with accompa-nying decline in productivity; andin the early stages, a lack of community

concern for planning and growth man-agement.

Alterations in human relationships under-lie the changes accompanying rapid growth. 55

Some social and behavioral scientists con-tend that these are among the most pervasiveand significant consequences of growth andare the basic causes of boomtown symp-toms.56 Among the alterations that have beenidentified in the social roles individuals mustfill are increased anonymity, impersonaliza-tion, and specialization. At the institutionallevel, greater bureaucratization, centraliza-

tion, and orientation of community unitstoward systems outside the local social struc-ture have been found. 57 Among the psycho-logical factors identified in boomtowns arevalue conflicts between established residents

and in-migrants, and shifts in personal inter-action patterns such as the deterioration of longtime friendship patterns, At the social in-stitution level, dramatic realinements of po-litical party membership, and an atmosphereof uncertainty about the future that under-

mines established systems of social controlhave been documented.58 On the other hand, acomparison of the experiences of four Colora-do boomtowns found a picture of resilienceand adaptability suggesting the “hope thatpeople can adjust to changes instead of beingoverwhelmed by them . . . ."59

Anti cipated Growth in the

Colorado Oil Shale Region

As a sparsely populated, rural region,western Colorado is vulnerable to boomtownconditions. The three oil shale counties had apopulation of 90,748 at the time of a specialcensus in 1977. Growth between 1970 and1977 ranged from 5 percent for Rio BlancoCounty to 27 percent for Garfield County; thelargest growth (58 percent) was in MoffatCounty, to the north of the oil shale region.(See table 97.) None of the communities in theimmediate area had a population over 3,000,(See table 98.) There are 2 to 19 persons persquare mile and a high proportion of olderresidents. (See table 99. ) Sixteen percent of the residents of the oil shale communities inRio Blanco and Garfield Counties are over 65years old, which is over sixty percent higherthan the national average. 60

The first step in attempting to forecastwhether there might be disruption is to gaugethe magnitude of possible migration to thearea. As indicated earlier in the chapter,

Table 97.–Population Growth of Colorado Oil ShaleCounties 1970-77

Population Population PercentCounty 1970 1977 changeR I O B l a n c o 4,842 5,100 5.3G a r f i e l d 14,821 18,800 26.8M e s a 54,374 66,848 22.9M o f f a t 6,525 10,303 5 7 9

SOURCE U S Bureau of Census data




Table 98,–Population of Colorado CommunitiesApt To Be Affected by Oil Shale Development, 1977

Location Population

Rio Blanco CountyMeeker ., ., ., 1,848R a n g e l y 1,871Garfield County

G l e n w o o d S p r i n g s 4,051Grand Valley, . : ., 377N e w C a s t l e 543Rifle. ... 2,244slit : : : ., 859Mesa CountyDe B e q u e , . 264Grand Junction ., ., 25,398Moffat CountyC r a i g ,. 6,677D i n o s a u r 347

SOURCE 1977 special census

Table 99.–Selected Demographic Indices ofOil Shale Counties of Colorado, July 1975

Number of people Percent agedCounty per square mile 65 and over

R I O B l a n c o 2 8.3G a r f i e l d 6 10 5M e s a 19 1 1 9Moffat ., : : ., . : ., 2 8 3

SOURCE Bureau of the Census City and County Data Book 1977

CWACOG has a growth-monitoring systemthat provides projections of future growth.Because this organization serves the day-to-day needs of the individual counties and com-munities, the projections are frequently mod-

ified in an attempt to reflect the current situ-ation. To an outsider, there appear to be sev-eral sets of data none of which coincide sinceit is possible for a town to be using one set of projections to plan for additional housing,another to determine water and sewagetreatment requirements, and a third to esti-mate the costs of providing public services.Although this arrangement creates some con-fusion as to which projections are the mostaccurate, it is important to modify projectionswhen the assumptions change. As an illustra-tion, Rangely’s projections have been over-

estimated in the past because they have as-sumed a new road would be built from thetown to tract C-a. Since the road was notbeing constructed when the most recent hous-ing projections were made, the CWACOG

housing data took this into account andRangely’s figures were adjusted downward;but because these revisions are not reflectedin all of the projections, discrepancies can befound between different sets of data.

Each year, CWACOG prepares for the re-

gion an official set of projections to the year2000, based on the following information:

q

q

q

q

q

baseline population data from the 1970regular and a 1977 special U.S. census;energy company employment projectionswith a family multiplier (2.0);support industry worker multipliers withaccompanying family multipliers (2.5);base worker distributions assigned bycounty and community; andcohort survival factors.

Three population projection scenarios are de-

rived using these factors:Scenario I—

Scenario II—

Scenario III—

Natural population growth with-out energy development;Growth with energy industry de-velopment, as presently planned;Growth with energy developmentincluding shale oil ‘production of 500,000 bbl/d in 1990 and 750,000bbl/d in 1995and 2000.

The first scenario is a conservative esti-mate of growth with a population inducedfrom non-energy-related employment figures.Its major benefit is to provide a lower limitagainst which to compare the growth sce-narios. The second scenario, growth withenergy development, contains base workerprojections from 18 companies including 6that expect to proceed with oil shale develop-ment. These are the developers of tracts C-aand C-b, Superior, Union Oil, Paraho, and Col-ony (Atlantic Richfield and TO S C O) .61 T h i sscenario has been selected by the CWACOGBoard as the officially endorsed set of projec-tions because it reflects the stated plans of companies active in the region. The third sce-

nario illustrates an upper limit generated byassumptions for a rapidly deployed oil shaleindustry.

The latest official CWACOG projectionsfor the oil shale counties, published in Novem-



Ch. 10–Socioeconomic Aspects 449

ber 1979, show that Rio Blanco and GarfieldCounties are expected to have sharp popula-tion increases under the energy developmentscenario. (See table 100 and figure 72. ) Thenumber of people in Rio Blanco County is fore-cast to be, by 1985, four times the 1977 spe-cial census count, while the number in Gar-

field County is seen as nearly tripling. MoffatCounty is projected to have a large increasein the early 1980’s but this growth is attrib-uted to coal and electric generation devel-opment, not to oil shale, Mesa County is ex-pected to grow without extreme fluctuations,but the number of people is projected to near-ly double by 1990 over the 1977 figure.

CWACOG prepares projections for individ-ual communities as well as for the counties.(See figure 73.) For the energy developmentconditions (Scenario II), these figures reveal:

Rifle’s population is projected to grow by1985 to over six times the 1977 count.Meeker’s population is projected to growby 1985 to over seven times the 1977count.Rangely’s population is projected togrow by 1985 to over three times the1977 count.

The projections for Scenario III, assumingan industry producing 500,000 bbl/d of shaleoil by 1990 and 750,000 bbl/d by 2000, dis-close exceptionally high growth for the re-gion. By 1985, Rio Blanco County is projectedto have almost 8 times the number of peoplecounted in 1977; Garfield is forecast to have

31

/ 2 times its 1977 count. Mesa and MoffatCounties are not forecast to have such spec-tacular growth, although Mesa County’s pop-ulation is seen as growing to almost 3 timesthe 1977 figure by 2000.

The populations of Rifle, Meeker, andRangely are projected to increase fromaround 2,000 to over 22,000 by 1985, with anet increase of approximately 18,860 resi-dents for Rifle. Like the counties, the biggestincrements for the towns occur in the earlyyears, between 1980 and 1985. Under Sce-

nario HI, the projected growth for these threecommunities exceeds 500 percent in the peri-od between 1980 and 1985. (See table 101. )

Needs Arising From Anticipated Growth

The projections are used by the countiesand communities to prepare plans for their

Table 1OO.– Population Projections by Development Scenario for the Oil Shale Counties of Colorado

R IO Blanco Garfield Mesa Moffat —

1977A c t u a l s a 5,100 18,800 66,848 10,3031979E s t i m a t e db 5,580 22.000 75,000 10,9251985S c e n a r i o Ic 51779 28,181 101.005 11,509Scenario II 22,809 50.559 107,855 15,306Scenario Ill 40,501 66,820 128.460 18,8921990Scenario I 6,177 32,080 121,091 13,311Scenario II 19,522 56,909 128,308 17.090S c e n a r i o I l l 35,881 71,621 147,583 24,3022000S c e n a r i o I 6,973 45,344 161,266 16,914S c e n a r i o l l 20,318 83,012 169,882 20,693S c e n a r i o I l l 44,303 95,365 190,484 27,905

aFrOrn a 1977 spec[al U S censusb End of {he ~ea[ ~sf(mate prepared (n July 1979 Dy the Colorado West Area COUflCll of GovernmentscBdsed on (he followlngScenar!o I – Natural poputal(on growth w,thoul energy developmentScendrlo 1: - Growth with energy development accordng to employment forecasts from 18 lnduslr,es acflve (n the region io!tlclal 1980 CWACOG projec-

hons I

Scenarto III –Energy development lncludlng shale 011 production of 500000 bbl d m 1990 and 750000 bbl d In 1995 and 2000

SOURCE Colorado Wesl Area Council of Governments




Figure 72.—Population Projections for Colorado Oil Shale Counties by Development Scenario, 1980-2000

32,000

28,000

24,000

6

F

~ 16 ,000

8 12,000L

8,000

4,000

/

/’/

//-/,

110,000

100,000

90,000

80,000

z 70,0000~ 60,000-1

z 50,000:

40,000

30,000

20,000

10,000

1977 1980 1985 1990 1995 2000

RIO BLANCO COUNTY

J I 1 I 1 1

1977 1980 1985 1990 1995 2000

MOFFAT COUNTY

KEY

POPULATION1977 SPECIAL CENSUS

SCENARIO I—WITHOUTENERGY DEVELOPMENT

SCENARIO II—WITHPRESENTLY PLANNEDENERGY DEVELOPMENT

SCENARIO III—WITHPLANNED ENERGY DEVELOPMENTAND OIL SHALE INDUSTRYOF 500,000 bbl/d IN 1980AND 750,000 bbl/d IN 1995

AND 2000OFFICIAL 1980 CWACOG PROJECTIONS

200,000

175,000

150,000z Q 1 2 5 , 0 0 0

%

+ 100,000CL

: 7 5 , 0 0 0

50,000

25 ,000

1 1 1 I I19771980 1 9 8 5 1 9 9 0 1995 2000

GARFIELD COUNTY

I I 1 I 1

1977 1980 1 9 8 5 1990 1995 2000

MESA COUNTY

SOURCE Colorado West Area Council of Governments






included as a service area the central part of Garfield County. This portion of the countyencompasses Rifle, site of the Clagett Memo-rial Hospital, and overlaps the Grand RiverHospital District in which the Rifle hospital isplaced. School districts, although not overlap-

ping, encompass a number of different com-munities, which makes it difficult to separatetheir requirements from those of the munici-palities. Sanitation and recreation districtswith differing boundaries add to the compli-cations.

For Garfield County, planning documentscontain over two dozen projects needed be-tween 1979 and 1984: 41 percent of them arein the area of education; 19 percent in thehealth and medical services; 15 percent inpublic services, especially water supply proj-ects; 11 percent each in mental health and

public facilities, the latter primarily roads;and 3 percent for welfare services.

Rio Blanco County and its communities,Meeker and Rangely, expect large growthfrom expanded shale development. For theperiod from 1980 to 1985, planning groupshave identified five categories of needs forthe county. About half are for public facilitiesand services: roads, highways, and bridges;airport improvements; trash compactors; apublic safety building; and similar projects.Educational necessities, hospital improve-

ments, recreational projects, and support forthe planning infrastructure make up the re-mainder.

Needs From Oil Shale Development

Several different kinds of energy industryactivities are taking place in the region.Unless it is rapid, the expansion of the oilshale industry, in and of itself, may notdisrupt the communities of western Colorado;combined with accelerated coal development,oil and gas exploration and production, theinstallation of electric generation plants, andthe possibility of other synthetic fuel activ-ities, the effects could be devastating. Sepa-rating the potential consequences of shaledevelopment from the combined effects is dif-

ficult, and local planners do not try to do so.The following discussion emphasizes oil shaledevelopment while recognizing that it will oc-cur in the larger context.

Mesa County

The effects on Mesa County depend on thelocation of development. At present, between30 and 40 percent of the employees at LoganWash facilities operated by Occidental OilShale, Inc., live in the Grand Junction area,and further development along the southernrim of the Piceance Basin would add to thesedirect effects in the county. Otherwise, theyare likely to be indirect, taking the form of demands on the transportation and servicesectors, both public and private, and on sup-port industries. Benefits, such as increasedrevenues and cash flow, will occur whenshale workers go to Grand Junction to pur-chase goods and services.

De Beque is the Mesa County communitynow experiencing direct effects of oil shaledevelopment activities. It is the nearest com-munity to Logan Wash and exemplifies sever-al of the problems associated with boomtowngrowth. It is located in Mesa County, whileLogan Wash is in Garfield County; thus taxrevenues from the energy development ac-crue to a jurisdiction different from the onereceiving the impacts. De Beque has had dif-ficulty preparing for increased growth, par-ticularly in dealing with the effects of infla-tion. A 1976 study detailed the improvementsneeded by the water supply system. Itestimated the costs at $608,000; when bidswere opened in 1978, they came to $787,000;but only $500,000 was available. The citywas unable to assume any additional debtand had to turn to the State for help. Whencompleted, the facilities will be adequate forthe present population but would have to beexpanded if a large number of new residentswere to be accommodated.

Garfield County

In 1975, the Colony Development Operationproposed that a new residential community,




to be called Battlement Mesa, be constructedsouth of the Colorado River near Grand Val-ley. The Garfield County commissionersgranted zoning approval for the developmentof 7,000 housing units for up to 21,000 resi-dents, to be constructed over a 10- to 15-year

period. Colony invested a little over $3 millionin land acquisition and related activities forBattlement Mesa. The new town was de-signed to serve the Colony shale activities onParachute Creek; actual development of thesite was suspended when the company chosenot to move ahead with its plant. It is prob-able the new town will be constructed in the1980’s.

RIFLE

Rifle is the community displaying the mostvisible effects of shale development activities.

It is estimated to have grown by about 1,000residents from the 1977 census figure of 2,244. Using the increase in the value of building permits as an indicator, it has grownabout 45 percent in the past 2 years, A pop-ulation of 10,000 has been used as the target

for planning purposes, and city officials feelthis number could be accommodated withinthe next 3 to 5 years. Over 40 projects havebeen identified as needed between 1979 and1984 to ease the effects of this expectedgrowth. About half of these are for public fa-

cilities, mostly water supply projects andpublic buildings. About 10 percent are forroads, and another 10 percent for publicservices, such as a new fire-rescue vehicle.Educational expansion, including programsand buildings, account for another 10 per-cent, with housing, health, and recreationprojects representing the remainder.

Rifle is beginning to display some symp-toms of boomtown stress. The incidence of re-ported spouse and child abuse is increasing.Statistics maintained by the police depart-

ment show a rise both in the number of juve-nile crimes and in cases of substance abuse;alcohol abuse is the biggest problem. Mentalhealth personnel note an increase in the num-ber of individuals having problems in their re-lations with other people. Consistent data col-


View of Rifle, Colo.




lected over several years are not available inthese categories, but what has been obtainedpoints to the emergence of increasing socialand psychological stress.64

A large number of retired persons live inthe area, and more than 20 percent of the

population is estimated to be over 60 yearsold. A number of programs have existed forseveral years for these residents, and theythemselves are active advocates for their in-terests. Should the current rate of inflationbe compounded by increased costs from rap-id growth those who live on fixed incomeswould suffer even more than they are now.

For some time, Rifle has had severe trafficcongestion. The main highway to the northgoes through the middle of town, passing theelementary and high schools. Dust and ex-haust fumes, particularly from trucks, havepolluted the downtown area. It has taken along time to correct the problem because of the necessity to coordinate plans with theState highway department. City services havebeen hampered by a lack of adequate officespace. Rifle is in the first stage of a plannedthree-stage water expansion project. The en-tire project will accommodate 10,000 resi-dents, in increments of 3,000 to 3,500 perstage. The sewer system is also currentlybeing upgraded.

Sufficient land is available for about 1,700

new housing units; construction has beenunderway in recent years. The junior highschool building is being expanded and, oncompletion of the addition, will become acombined junior-senior high school, A newelementary school is needed and the city hasapplied to the State for assistance in its con-struction. The hospital needs to expand itsoutpatient facilities. The nursing home isoperating almost to capacity, and will soonrequire repairs and renovation.

OTHER GARFIELD COUNTY COMMUNITIES

Grand Valley reflects the types of diffi-culties faced by communities living with theuncertainties of energy development. Severalyears ago, in anticipation of growth from in-creased oil shale development, the school was

expanded. Because the expected growth didnot come to pass, the school is presentlyoperating below capacity; and the citizens,while desiring it, view current promises of development with some skepticism.65 Like Siltand New Castle, Grand Valley has had toplace a moratorium on new building because

the water and sewer systems are operatingat, or beyond, capacity. The town applied foran EPA construction grant for a new sewagetreatment facility in 1976 but did not know if it would receive the funds until 1979. In theinterim, it tried to obtain money from the Col-orado Department of Health, but was unsuc-cessful. Although the EPA grant, plus assist-ance from the Oil Shale Trust Fund, has nowbeen received, the site had not been approvedin mid-l979.

Silt is one of the fastest growing commu-

nities in the valley. The population doubledbetween 1970 and 1977—from 434 to 859—and the town planner believes it was close to1,000 at the end of 1979.66 The CWACOG pro-

jections estimate 1,211 by the end of 1980under energy development conditions (Sce-nario II). Current plans call for public facil-ities to accommodate 2,800 residents by themid-1980’s. These facilities include an im-proved water supply and an expanded sewersystem. The sewer system improvements arecurrently in the design phase and the watersystem is already being upgraded. Like many

small communities, the town lacks sufficientskilled manpower. There is only one police of-ficer and no budget for additional personnel.Only two people are in the public works de-partment, and they cannot keep up with theincreased workload.

In New Castle, ultimate growth probablywill be limited by the availability of land,since the town is located in a fairly narrowpart of the Colorado River valley. The officialCWACOG energy development projections es-timate a population of 1,055 in 1985 and1,608 by 2000. The city is now improving itswater supply and distribution system to per-mit additional growth; a moratorium on newwater taps was necessary after a new ele-mentary-junior h igh school faci l i ty wasopened. A revitalization of coal mining in the




area could combine with oil shale develop-ment to add to growth pressures in the town.

Because Glenwood Springs, the countyseat, is located in the eastern part of GarfieldCounty, the community will experience moresecondary than direct effects. The city hasbeen growing mainly from recreational devel-opment in the Aspen and Vail areas. If thecommunities down the Colorado River valleyare unable to cope with rapid growth, theconsequences will extend to the GlenwoodSprings area.

In sum, Garfield County has received mostof the growth so far from oil shale develop-ment. This growth has been combined withthe expansion of other industries and, as aresult, the county has been pressed to meetthe needs of the new populace. All the com-

munities in the area have increased popula-tion, and three have had to place moratori-ums on new construction because of inade-quate water and sewer systems. Rifle shouldbe able to accommodate a population of 10,000 if current plans can be completed, butis already beginning to experience some of the symptoms of boomtown conditions. If ac-celerated growth occurs, Rifle will need addi-tional funds in order to make public facilitiesand services available to the new residents,and will have to increase its efforts to preventsocial and individual stress.

Rio Bl anco County

In anticipation of future growth, a signifi-cant planning effort has been underway for ahalf-dozen years, zoning and other growth-control laws have been enacted, and supportfor these measures appears widespread.Roads have been a longstanding need buttheir cost has proven a barrier to construc-tion. Extension of County Road 24 from theC-a tract site to Rangely was proposed by thedevelopers in their early plans (see figure 74);

however, the State legislature has been reluc-tant to appropriate funds for construction, Afeasibility study of 10 alternatives was madeand 1 was recommended to the State: plan-ning for it is now underway, Timing is criti-

cal; if the C-a tract begins production and theroad is not available, permanent employeeswill choose to live in Meeker or Rifle, both of which are now closer. Without this access,the opportunity to allocate some of the coun-ty’s growth to the Rangely area will be for-

feited.MEEKER

Meeker grew about 15 percent between1970 and 1977; its estimated population in1979 was 2,250 to 2,300.67 The community’sphysical infrastructure (e.g., water, sewer,streets), when current improvements arecompleted, could support between 4,000 and5,000 residents; this figure may be reached in1982 or 1983. However, the growth rate couldaccelerate. For instance, the draft EIS for theproposed Superior development, in projecting

cumulative growth for its own and sevenother energy projects, 68 places Meeker’s pop-ulation at 5,077 in the first year of operation,a doubling of the present estimated popula-tion in one calendar year. Even this projectioncould be low, since there are more than thisnumber of possible projects under considera-tion by different industries for the area.

Of the needs identified by local officials, 55percent are for public facilities and services,15 percent for the schools, 19 percent for rec-reational projects, 9 percent for day care and

senior citizens’ support, and 2 percent are forhospital projects, Housing so far has kept upwith demand. In the immediate area, foursubdivisions are under construction, and amobile home park has been approved. Underreview, but not yet approved (in late 1979),were another mobile home park and a num-ber of smaller subdivisions, none of which ispresently within the Meeker water servicearea. Furthermore, the town is presentlycommitted to the subdivisions now being builtfor 100 percent of its available water taps.Although the streets within the large subdivi-

sions will be built by the developer, the townmust provide the main arteries to thoseareas. The wastewater treatment plant iscommitted almost to capacity, and planninghas started for its expansion.



456qAn Assessment of Oil Shale Technologies

Figure 74.— Area of Proposed Road From Rangely to Oil Shale Tract C-a

SOURCE 1977 Ad Addendum to the R IO Blanco Oil Shale Project Social and Econmic Impact Statement.




The construction of water and sewer facil-ities is an example of the kinds of projects re-quiring adequate leadtime. If Meeker fails tobegin preparing to expand its water supplyand sewage treatment capacity now, it willnot be able to absorb increased growth in 3 to

5 years. These kinds of improvements alsoserve as examples of the financing difficultiesfaced by rural towns. In constructing its pres-ent water system Meeker created a $2.4 mil-lion debt that requires an annual debt serviceequivalent to 20 mills of the property tax levy.

Photo credit: OTA staff

Approximately $760,000 will be required toexpand the storage capacity of the water sys-tem and $2.5 million to upgrade the waste-water treatment plant. Thus, the city is fac-ing a potential additional debt of over $3 mil-lion in the next 3 to 5 years.

Meeker also reflects some of the adminis-trative difficulties faced by growing towns.Colorado’s statute, which restricts spendingby municipalities (except home-rule cities) toa 7-percent increase over the annual proper-ty tax revenues,69 means for Meeker that themaximum the town can increase its spending

is about $3,000 per year. Recently, the annualinflation rate has approached 16 percent,which makes such a small increase essential-ly nil in real revenues. The statute does pro-vide for some administrative relief with the

approval of the State DLA but an applicationfor an exemption filed by the city in 1976 wasturned down. A manpower shortage plaguesthe city government. During the summer,when demands for labor are highest, thetown has used inmates from the jail for assist-

ance. According to the town manager, all of the municipal government staff but two arepaid salaries lower than the HUD povertyguidelines for rural Colorado.70

Overall the incidence of symptoms of socialstress has not been increasing at the rateseen in other towns. A shift in the types of crimes committed has been noted, with in-creases in thefts, bad checks, and drug-re-lated incidents; and a rise in the number of runaways has occurred in recent years. Thenumber of cases reported by the police has in-creased at a faster rate than the populationgrowth. ” The hospital outpatient services areoperating at capacity; an additional emergen-cy room and laboratory are pressing needs.The school district is operating below its totalcapacity but some of the individual schoolsare full. A new elementary school will beneeded between 1981 and 1982.

Attitudes about growth have been divided.In a survey conducted in 1974, 35 percent of the respondents agreed and 53 percent dis-agreed with a statement that the majority of growth from resource development should oc-

cur in Meeker. The town manager said in1 9 7 972 that he felt the community wishesenough growth to pay the indebtedness in-curred by construction of public facilities andto provide new amenities such as a larger su-permarket and expanded recreation facil-ities.

RANGELY

Rangely finds itself in the paradoxical posi-tion of desiring additional growth but foiled inits efforts to obtain it. The biggest difficultyhas been gaining improved access to oil shaleactivities. The proposed road to tract C-a wasdiscussed above. - - ‘ - -

ences with oil andtown receptive tothe residents feel

Rangely’s earlier experi-gas booms have made theenergy development andthat growth from an ex-



458 q An Assessment Oil Shale Technologies

panded oil shale industry would be benefi-cial.

In addition to the access road, a dozen proj-ects are judged to be needed by 1985. Half of these are for public facilities, such as a watersupply pipeline to areas of new home con-

struction. With improvements, the water sys-tem could serve a population of about 11,000and the sewer treatment facilities are ade-quate to serve 10,000 people if the sewermains can be upgraded. Because of the needfor these improvements, however, the capaci-ty of the town between 1985 and 1990 is esti-mated at only 6,000 residents.73 Like mostrural health care facilities, the RangelyHospital has had to defer some maintenanceand equipment needs in order to meet oper-ating expenses but will have to take care of them before services can be provided for a

larger clientele.Recent school construction has provided

sufficient capacity to absorb more pupils, butthis again reflects Rangely’s paradox. If the

town is unable to attract more families, theexpansion of the schools will leave the build-ings half-full and the remaining residentsburdened with the debt of the expansion. Theoptimism of the citizens is reflected in theirwillingness to approve construction of a newindoor recreation facility that opened in thelate spring of 1979.

The Rangely area has a strong feeling of identification with eastern Utah. The town islocated about 15 miles east of the border. It isa little over 45 miles to Vernal, Utah, lessthan the distance to Meeker (57 miles) and toGrand Junction (85 miles). The road to GrandJunction goes over Douglas Pass (8,628 ft),making the route less appealing than the flat-ter highway to Utah. For these reasons, it iseasier for Rangely residents to travel to Ver-

nal. Colorado officials have sometimes actedin a way that the residents view as reinforc-ing their links with Utah; it took about 40years to get the State to build the road overDouglas Pass. If the region experiences rapid


Recreational facility in Rangely, Colo.




growth from oil shale development, the feel-ings of being ignored could add to other nega-tive impacts. Moreover, if the oil shale activ-ities are in Utah but the workers live in Col-orado, a prime example of the problems of ju-risdictional mismatch will occur.

In sum, Rio Blanco is the least populatedcounty with the most limited highway system.Planning is well advanced with provision forextensive community participation. Some ur-gent needs, such as improved access to theFederal oil shale tracts, have not been metwith as rapid a response as the local citizensmight have wished; the State legislature hasbeen reluctant to appropriate the large sumsnecessary for these projects. Rangely desiresgrowth but will not receive much if a road totract C-a is not constructed; Meeker is less in-clined to have more growth than it has al-

ready gotten from coal development, yet mayhave to absorb new population from oil shaleactivities.

Summary

The socioeconomic consequencesshale development depend, among

of oilother

things, on the location of the activities. In-creased development of the private landsalong the southern rim of the Piceance basinwill lead to growth in Garfield and MesaCounties and the communities of the Colorado

River valley. Additional activity on the Fed-eral lands in Rio Blanco County will mostly af-fect Meeker and Rangely, although Riflecould grow as well from this expansion. InMoffat County, Craig could be influenced byactivities in the northern section and, if devel-opment occurs in Utah, Dinosaur and Rangelywould be directly affected. Growth will tendto concentrate in established communitieswhere services are already available. Thelimited surface transportation system willalso foster concentration. In Rio Blanco Coun-ty it is encouraged by a zoning policy that is

intended to direct growth to Meeker andRangely.

The needs by county and community be-tween 1980 and 1985 are summarized in ta-

ble 102. The table shows clearly where thelocal leaders see the greatest constraints ongrowth: water supply systems for the munici-palities, schools, and medical and healthservices and facilities. Several towns in-dicate a need for more personnel. Rifle andMeeker are the communities with the largest

number of priorities. Assuming that the proj-ects now underway are completed, Rifleshould be able to absorb, between 1985 and1990, up to 10,000 people, The other GarfieldCounty communities in the oil shale vicinitycould accommodate about 7,000 and therural areas between 1,500 and 2,000 per-sons. If construction were started immediate-ly, the new town of Battlement Mesa mighthouse 2,500 people by 1985. In Mesa County,De Beque might be able to accommodate atotal of 700 to 1,000 but most workers fromthe southwestern part of the Piceance basin

will probably reside in the Grand Junctionarea. In Rio Blanco County, both Meeker andRangely are judged to be capable of providingfor 6,000 persons apiece, ” A total of 2,000people might live in the rural areas. Alto-gether, by 1985 Garfield County could accom-modate about 21,000 and Rio Blanco about14,000, for a total of 35,000 residents. (Seetable 103, )

O t h e r t h a n t h e p l a n n i n g e f f o r t s o f CWACOG, no systematic evaluation of thefull range of consequences for the entire re-

gion is being undertaken. For example, thedraft EIS for the proposed Superior Oil Co.project 75discusses, in the section on cumula-tive impacts, seven other activities that mightinteract with the Superior development. How-ever, a total of 30 energy-related projects areidentified by CWACOG and impact studies aspossibly affecting the region. Similarly, plan-ning documents give attention to individualcounties or communities but do not addressareawide problems in detail. For instance,the relationships and responsibilities of local,State, and Federal government agencies are

critical for communities facing boomtownconditions, but they are not dealt with in anyof the plans. Jurisdictional mismatches alsoare seldom addressed. Development on pri-






Whether the consequences of growth are fa-vorable or unfavorable depends on whetherthe people can adapt to the stresses accompa-nying change. This ability is unique to eachcommunity and must be viewed as part of adynamic set of complex events. Conclusions

about the possible effects of future oil shaledevelopment must recognize the complex andchanging nature of the different communitiesand of the events impinging on them.

Industrial expansion in western Coloradowill have positive as well as negative conse-quences, In the economic sphere, a primarybenefit will be increased economic activity.The direct effects of increased employment,higher wages, and stimulation of support in-dustries and services would be felt through-out the region. Both the public and privatesectors would benefit from industrial and

services expans ion. Towns and countiesshould enjoy a broader tax base. A sense of identity and pride, combined with an antici-pation of the advantages of growth, have al-ready been manifested. Planning activities,such as the preparation of the master planfor Rangely, have contributed to the public’sexpectations for the future. The successfuloperation of the task forces that propose solu-tions for growth problems is tangible evi-dence of increased sociological and psycho-logical cohesion. The confidence that manylocal officials express in their community’sability to deal with growth is also an indica-tion that, to date, the social consequences of oil shale development have been positive. Theinvolvement of the oil shale developers ingrowth management efforts shows industry’sresponsiveness to the social effects of its ex-pansion.

Oil shale development has been and willcontinue to take place concurrently withother activities, especially energy-relatedones, such as coal, uranium, oil, and gas pro-duction. Dealing with the cumulative effectsof all the growth may prove difficult. In addi-

tion, the nature of new oil shale ventures isunclear, Factors of particular importance forsocial and economic adjustment will be the:

q

q

q

q

q

q

number—how many new oil shale devel-opments occur;size—how large the facilities will be;

location—where shale mining and proc-essing activities take place;

timing—when each is built and how thisrelates to other development;

rapidity—how quickly any new ventures

are built; andtype—the nature of the technology andancillary processes chosen.

The position of the State regarding both oilshale development and social and economicimpact mitigation is also not certain. Untilmore is known about these factors, the exactnature of the population in-migration that willaccompany new development cannot be ade-quately projected, nor can the full dimensionsof the consequences, both positive and nega-tive, be forecast. So long as oil shale devel-opment continues according to the plansalready laid, the people of oil shale countryshould be able to adjust to the resultinggrowth. Only if expansion occurs suddenly orto a greater degree than now planned willboomtown consequences occur. (See ch. 3 fora further discussion.)




Issues

Summary of Issues

Identifying and Evaluating Social and

Economic Impact s

In the usual course of economic

and Policy Approaches

develop-ment, Government assistance in coping withthe consequences of growth is not a primeconcern. One question underlying energy de-velopment is the distinction between effectsthat can be handled by local communities—that is, those that can be considered a normalconcomitant of development; and those thatare problems because they cannot be readilysolved by local resources—boomtown effects.An example of criteria used to make thisdistinction is found in section 601 of thePowerplant and Industrial Fuel Use Act of 1978. These include increased employment of 8 percent or more per year in coal or uraniumactivities, a resulting or projected housingshortage, and inadequate State and local fi-nancial resources to meet needs over a 3-yearperiod.

Thus far, Federal agencies have assisted inthe identification of boomtown conditionsmainly through data-gathering and informa-tion-sharing activities. With respect to eval-uation, the position is that “local communitiesand counties must take the initiative to be-

come involved in assessing, planning for, andmitigating socioeconomic impacts . . . .“76

The process of evaluating impacts involvestheir c lassif icat ion as e i ther posit ive ornegative. This requires making value judg-ments about what is good or bad for particu-lar individuals, communities, regions, and theNation. Often there are conflicts—what isseen as good for the Nation may entail diffi-culties for individuals or disruptions of com-munities. Additionally, what is judged as apositive impact for one group may appear as

a negative one for a different group.The process is further complicated be-

cause the basis for distinguishing positivefrom negative impacts is seldom clearly de-lineated, and the assumptions underlying the

definitions of the two classes are rarelyspelled out. As an illustration, concepts suchas the “degradation of the quality of life” areused; and a variety of indices, like an in-

crease in the number of visits to a mentalhealth clinic, are cited to support the findingof “degradation.” Yet there is hardly eververification of the causal chain presumablylinking rapid population influx to the indicesand thence to perceived changes in the quali-ty of life.

Finally, several of the most importantboomtown consequences are hard to measure(for example, the ability of newcomers to adjust to an established community); and thechanges in the social structure may not bemanifested immediately. A question that hasnot received great attention is whether thelong-term basic changes are more importantthan the immediate ones occurring at theonset of a boom.

The debates about oil shale developmentinclude conflicts involving these kinds of value judgments. On the one hand is the needfor synthetic fuel production; on the other arethe boomtown consequences for communities.Who participates in the definition of positiveand negative impacts and in the resolution of the value conflicts that emerge is an impor-

tant issue. At present, in Colorado, localgroups play a large part in this evaluation.They identify the impacts they believe will af-fect their communities, decide which ones aresevere enough to require corrective action,and participate in the decisions to allocateresources for mitigation. Federal programsdesigned to assist communities must recog-nize what has been done to date and face theissue of the allocation of responsibility forthese decisions.

Determining a Maximum Growth RateHow rapidly can the communities expand?

How much growth can be accommodated be-fore a community breaks down? The socialand economic impacts of oil shale develop-




ment will depend on the total number of new-comers, the rapidity with which they c o m einto the area, the size of the industry’s expan-sion, its location within the oil shale region,and the ability of the communities to prepare.The maximum amount of growth the differentareas can accommodate without incurringboomtown consequences is a critical ques-tion.

Attempts to determine a maximum ra tehave discovered that generalizations are dif-ficult to derive and that the capability to adjust to rapid growth turns out to be highly sitespecific. Whether communities will sufferfrom rapid growth or take it in stride dependson a unique set of factors within each indi-vidual community, for example, the thresholdwhen negative impacts outweigh positiveones. Since the positive and negative impacts

may vary from one town to the next, estab-lishing this threshold is highly dependent onlocal conditions. In the past decade, identify-ing and measuring the social changes that ac-company rural energy development have re-ceived increasing attention. The results havebeen an expansion of the factual base de-scribing these changes, and a more system-atic framework for seeking to explain them.To date, however, there are neither sufficientfacts nor theories to understand fully whyone town becomes vulnerable to boomtownimpacts but a similar one does not.

No systematic study of the factors deter-mining a maximum growth rate is being car-ried out for the oil shale communities. Thegroups presently involved in growth manage-ment and planning would benefit from a de-

termination of thresholds of growth for theirindividual communities and policy makerscould use this information when consideringthe rate of future development. The popula-tion of the Colorado oil shale region wasabout 10,000 in 1977 and is projected to beabout 14,000 by the end of 1980. OTA esti-

mates that the communities could accommo-date up to 35,000 total residents during theperiod from 1985 to 1990. This assumes thatconstruction of the new town of BattlementMesa in Garfield County is started in the near

growth.

The Mitigation of Impacts

Solving the problemsvolves local, regional, State, and Federalagencies. Questions about the role of theFederal Government fall into two categories:

q the extent to which the Federal Govern-ment should be involved, and

q the form the involvement might take.

The first category raises the fundamentalquestion of whether the Federal Governmentshould be involved at all. The extent andnature of Federal involvement in impact miti-gation are controversial. On the one hand it isargued that social and economic impacts areState and local problems which should beviewed as the inevitable consequences of in-dustria l development. On the other hand isthe posit ion that national requirements arethe root causes of the local impacts, thereforean expanded Federal role is appropriate. Sev-eral Western States have taken the stancethat expanded domestic energy production isa national goal and thus, for reasons of equi-ty, the Federal Government should assume amore direct role in the alleviation of negativeimpacts from this development.

The second category deals with the natureof Federal involvement. One position statesthat present programs are sufficient but thatthe amount of money they provide needs to beincreased. Another is that Federal regulationcould be used to mitigate impacts by, for ex-ample, pacing industry’s growth rate throughleasing policies. A third position is that theGovernment should be directly involved inmitigation programs that use Federal funds.

The question of the effectiveness of mitiga-tion programs arises as well. Some observerscontend that the success of oil shale mitiga-tion processes to date is proof of their effec-




tiveness. Others maintain that the processeshave never been adequately tested becauserapid, large-scale development has not yet oc-curred, and that existing programs couldbreak down under such circumstances. Mostquestions about the effectiveness of the proc-esses relate to intrastate issues. For example,

it can be questioned whether the legislativeapproach to disbursement of the Oil ShaleTrust Fund deals adequately with the desiresof the oil shale counties. The Federal Govern-ment could respond to such questions by, forexample, providing funds directly to the com-munities. The desirability of such an action isa topic of current debate, however.

Increased Federal assistance probably willbe required if the region experiences sus-tained rapid growth. This could come aboutfrom accelerated oil shale development, but

is more likely to be the consequence of com-bined growth from several industries. Asidefrom the planning efforts of CWACOG, whichare limited to northwestern Colorado, no sys-tematic evaluation of the full range of effectsfrom an increase in all types of industrialgrowth on the entire region is being under-taken. Thus, it is difficult to determine whichtypes of Federal assistance might be the mostproductive.

Policy Approaches

Confronting the social and economic ef-fects of an expanding domestic energy indus-try involves policies for all parts of the Na-tion. Concern for the consequences of oilshale development, however, for the timebeing centers only on northwestern Colorado,east-central Utah, and southwestern Wyo-ming. In addition, although the impacts them-selves are basically similar regardless of thegeographic region, the responses of particu-lar communities can differ significantly de-pending on the State and location involved.Flexible policies are best, given this situation.

The following discussion is concerned withpolicies that bear most directly on the effectsof a larger oil shale industry.

Background

The initial action responsible for consid-eration, in public policy decisions, of the so-cioeconomic effects of Federal projects wasthe National Environmental Policy Act of 1969 (NEPA).77 It requires Federal agencies to

consider environmental factors in decisionsinvolving “major Federal actions significantlyaffecting the quality of the human environ-ment. “78 The broad wording of the Act has ledto a considerable amount of litigation. Inthese court cases, 79 NEPA has been inter-preted as granting authority for the imposi-tion of conditions to mitigate adverse socialas well as environmental impacts. As a resultof the litigation, and subsequent regulationsissued under NEPA, socioeconomic consid-erations have of late received greater em-phasis in the preparation of EISs.

T h e C o a s t a l Z o n e M a n a g e m e n t A c tAmendments of 1976 80 set up a program of assistance for communities experiencing im-pacts from Outer Continental Shelf (OCS)energy development. Loans, loan guarantees,and grants are available to States and com-munities where an energy facility planningprocess has been established under theCoastal Zone Management Act of 1972 8 1

(CZMA). Site plans must include the identifi-cation and mitigation of anticipated adverseimpacts from OCS-related development. The

program is tied closely to land use planningmechanisms that State and local governmentsare required to develop if they participate inthe coastal zone management program. Theimpact assistance portion depends upon theinitiative of the States in meeting the CZMArequirements; Federal involvement is there-fore indirect, in the sense that the policymakes Federal funding contingent upon theestablishment of State and local land useplanning processes.

In March 1978, DOE published for the En-ergy Impact Assistance Steering Group a Re-

port to the President—Energy Impact Assist-ance. 82 The Steering Group, composed of rep-resentatives from Federal, State, local, and




Indian Tribal governments, was establishedfollowing a meeting of several Governors withthe president in mid-1977. At that time theGovernors expressed concern for potentialadverse results from the 1977 National Ener-gy Plan. Four policy options were presented

representing “different points along a con-tinuum ranging from minimal new efforts toundertaking major program reform and in-vestment of substantial new Federal funds, ](See table 104.)

In an effort to pull together the variousFederal programs that can assist communi-ties, the Region VIII FRC has created anEnergy Impact Office. Its establishment wasa direct response to recommendations of theNational Governors Conference and of theGeneral Accounting Office (GAO) .8’ A GAOreport, published in 1977, concluded that atthat time the need for additional Federal as-sistance to impacted communities had notbeen demonstrated, Among its conclusions,the report stated:

Rocky Mountain State and local govern-ments should be primarily responsible forproviding facilities and services prior to orconcurrent with population increases , . .

It is not industry’s responsibility to pro-vide the facilities and services needed be-cause of energy resource development. Butindustry does have a strong and continuing

responsibility to communicate its plans toState and local governments, as soon as pos-sible, and to establish and maintain a con-tinuing liaison with these governments,

The Federal Government should continueto provide some assistance ., . (but) the needfor additional Federal assistance at this timehas not been demonstrated.

GAO believes there should be some assur-ances that impacted communities will re-ceive funds available to mitigate the socio-economic impacts of energy resource devel-opment.85

A theme running through each of theseFederal policy documents is that the Federalrole regarding the social and economic ef-fects of energy development should be pri-marily indirect assistance. Examples are pro-

viding funds to the States and improving thedelivery of existing Federal programs (e.g.,the establishment of a “one-stop shoppingcenter” where local officials can go to deter-mine whether their towns are eligible for themany Federal programs already available).

A recent departure from this theme isfound in the Energy Impacted Area Develop-ment Assistance Program that was enactedin the Powerplant and Industrial Fuel Use Actof 1978 (sec. 601).86 This program, admin-istered by FmHA, is designed “to help areasimpacted by coal or uranium development ac-tivities by providing assistance for the devel-opment of growth management and housingplans and in developing and acquiring sitesfor housing and public facilities and serv-ices. ” The probability of greater Federal in-

volvement in the direct amelioration of im-pacts is reflected in the amendments to thePowerplant and Industrial Fuel Use Act con-sidered during the fall of 1979. A review of the problems, legislative issues, and propos-als being considered by the 96th Congress isavailable in a Congressional Research Serv-ice (CRS) study titled Energy Impact Assist-ance: A Background Report prepared for theSenate Committee on Energy and Natural Re-sources. 87

I n g en er al , t h e We s te r n St a te s h av e

adopted policies that supplement and fill gapsin Federal programs. Colorado providesfunds, from Federal revenues and a State sev-erence tax, and technical assistance to coun-ties and towns with growth problems. TheState’s position is that local initiative must becentral in the mitigation process. As a result,sentiments are strong among leaders in Col-orado’s oil shale communities that local gov-ernment should play a significant part in thecontrol and management of growth. 88 For anumber of years, because of the delays in oilshale development, these leaders were skep-

tical about its eventual occurrence; now theyare fearful that a national crash programmight ignore the plans that they have so care-fully laid and cause a population surge thatthe communities could not absorb. Utah has




Table 104.–Selected Policy Options, 1978 Report to the President

Option A Option B Option C Option OModification and expansion of

Expansion of industry role and Enhancement of State, local, and existing programs to assuremodif ication/repriorit izat ion of Tribal capabil it ies through new greater Federal share of New Federal grant program

Need areas existing programs initiatives and programs long-term costs to pay long-term costs

Information

Participation indecision making

Planning andmanagement

Coordination ofassistance pro-grams

Financing

implementation or national energyinformation systems by DOEwith State/local/Tribal accessto certain NEIS data

Encourage States to require in-m-industry release of employment,population, and siting data forproposed projects as precondi-tion for receipt of certain State/local permits (water, construc-tion, etc )

Opation A, plus nave appropriateFederal agencies give prior noti-fication to State/localities, andTribes of BLM, OCS Ieasingplans, decisions and other datarelated to industry projects pro-posed to Federal agencies, im-prove conformance with NEPAand A-95 review processes

. . , . , ,. A . , , . - Option B, plus establishment Option Cby DOE of a new informationsystem to gather and dis-seminate impact assistancerelated data from energy de-velopers ($1 5 million).

Continued ad hoc efforts byState/ local governments andTribes to impact Federal deci-sion processes on energy re-source development and projectsiting.

Conduct joint Federal/State/lo-cal/Tribal impact assessments

Provide Federal technical assist-ance and information to commu -mties which are now, or ex-pected to experience energy de-velopment

Increase funding under selectedexisting planning program by$20 million and target to energyimpact areas

Expand the role of the FederalRegional Councils in coordinat-ing and packaging assistancefunds to energy-impacted areas,make greater use of joint fund-ing authority.

Modify requirements of selectedexisting programs to provide foreligibility and priority for fundsto impact areas (within existingstatutory Iimits)

Increase funding of selected pro-grams by $30 million to offsetreduction in funds for other pri -ority needs (e g , urban pov-erty)

Give priority to States, etc ,securing industry cost-sharing

Possible amendment to Federaltax code to encourage prepay-ment of taxes by Industry

Issue Presidential Executive orderrequiring Federal agencies toprovide for State/local/Tribal in-volvement m all energy develop-ment decisions affecting their

jurisdictions, and to provide forconsideration of the findings ofthe impact assessment teamsprior to final decisions.

Option A, except Incorporate newplanning monies into proposedcomprehensive State energyplanning and management bill,and specifically target newfunds to support State/local/Tribal participation on assess-ment teams and ongoing im-pact-related capabilities. A set-aside of funds for Tribes wouldbe provided. Also, bonus fundsfor States with energy facility -siting mechanisms.

Option A, plus designate DOE aslead agency to oversee and sup-port coordination of programs atthe regional level through an in-interagency board

Establish Federal loan and loan-guarantee programs in EDA withforgiveness provisions and com-petitive interest rates to be usedby States, communities, and ln-dian Tribes ($75 million)

Fund sec. 306 of the proposedCoal Conversion Act ($60 mil-lion)

Give priority to States, etc , withenergy facility-siting mecha-nisms

Annual $50 million $160 millionauthorization

SOURCE Department of Energy DOE /lR-0009, UC 13.

Option B, plus establishmentof due process mechanism to

review appeals of Gover-nors/Tribal officials.

Option B, plus require allFederal energy decisions tobe compatible with approvedState impact mitigationstrategies

Option B, plus issue Execu-We order mandating appro-priate Federal agencies tosupport FRC efforts and togive priority consideration tofunding requests channeledthrough this mechanism

Option B, plus increase EDAfunds by additional $50 mil-lion and authorize grants aswell as loan/guarantees.($125 million plus$60 mil-lion for 306). Priority toStates, etc , with Increasedcommitment of State/local/Tribal revenues and facilitysiting procedures.

SuboptionConsolidate Coastal Energy

Impact Program and sec.306 program into EDA tocreate single, flexible pro-

gram to relet Infrastructureneeds m all States

Option C

Option Bq Establish Federal/State

assessment teams asspecified.

qFederal assistance toState to develop facility -siting mechanisms and toprovide intial and sec-ond-round planninggrants ($1 5 million).

ŽFederal compatibility re-quirement

The Federal agency desig-nated as the lead assess-ment agency would be re-sponsible for coordinatingall relevant Federal pro-grams,

Establish a new program toprovide grants to theStates for.

–State revolving funds($200 million)

–Highways constructionand railroad grade sepa-rations.

–Mismatches ($10 million)(Interstate and State/Tribal)

–Loan guarantees ($15million).

Fund housing support insec. 306 but expand andaugment to cover energyfacility construction and 011shale development ($60million).

$212 million $300 million



Ch. 10–Socioeconomic Aspects . 467

been faced with rapid growth from coal anduranium development, and has not plannedextensively for oil shale activities. The Statecreated a Community Impact Account in 1977to provide loans and grants to areas impactedby mineral resource development. Because itis the only funding source in the State de-signed to respond to problems associatedwith energy development, requests for helphave far outstripped the available monies.Wyoming does not anticipate consequencesfrom shale development in the near future,The State has an array of mitigation pro-grams dealing with other energy industry im-pacts that could be adapted to growth prob-lems from accelerated oil shale activities.

Evaluation of Existing Policies

The diverse nature of present policies, Fed-eral and State, makes their overall evaluationdifficult. State policies vary: Colorado placesemphasis on local initiative and advocacy,whereas Utah and Wyoming emphasize morecentralized State determination of needs andallocation of funds. At the present time, thereis no single Federal policy with respect to thesocial and economic effects of energy produc-tion. Some programs are operating that ad-dress certain aspects of these effects but, atpresent, none speaks directly to the generalimpacts that may come with synthetic fuel de-

velopment nor to the specific effects of accel-erated shale oil production. A limited amountof assistance is available through avenuesnot specifically designed to deal with energydevelopment impacts, but these Federal pro-grams each have different emphases andmodes of providing help. While they may beadequately fulfilling their policy mandates,the specific nature of the mandates meansthat the entire range of problems is not beingaddressed. Additionally, even though stepshave been taken to consolidate the frag-mented nature of Federal programs, effective

implementation of a more uniform set of prac-tices has yet to reach the oil shale commu-nities.

An increasing recognition of the problemscaused by national energy decisions has led

to several reviews of existing policies and tosuggestions of ways to achieve a more unifiedpolicy. Congress has had before it proposalsfor a comprehensive inland energy impact as-sistance program, but to date none has beenenacted. Up to the present, return to the

States of portions of the lease, rental, andbonus payments for development on Federallands has been the major Federal contribu-tion to mitigation efforts.

Colorado has an ambitious set of policiesand programs to assist with impact mitiga-tion. Overall, these efforts have been suc-cessful in helping the oil shale counties andmunicipalities to get ready for shale develop-ment. The ability of existing policies to dealwith a large or sudden population influx,such as might occur with the rapid expansionof the oil shale industry, is as yet untested.

The uncertainties about the specific growthof the industry make it difficult to evaluatewhether any policies—Federal or State—willbe adequate to deal with the effects of rapidexpansion of the industry.

Approaches to Impact Mitigation

There are three approaches available toCongress when considering the social andeconomic effects of oil shale development.The impacts can be viewed:

q

as part of the consequences of all kindsof energy development;Ž as an aspect of specific energy initia-

tives; or as the result only of shale development.

From the perspective of the first approach,oil shale impacts would be included alongwith the problems accompanying all domesticenergy efforts. As noted above, Congress hasrecently considered bills providing compre-hensive assistance for these problems, andprograms for oil shale could be in such legis-lation. The second approach would place

shale impacts along with those from othermajor national efforts. Proposed amendmentsto the Powerplant and Industrial Fuel Use Actof 1978 are illustrative. These amendmentsare directed to the adverse effects of major




energy developments, which could include oilshale. They authorize grants, loans, l o a nguarant ees, a n d p a y m en t s of interest o nloans, and propose an expediting process forpresent Federal programs as well as an inter-agency council to coordinate Federal assist-ance. The third approach sees the effects a s

the result of oil shale development alone. Inthis case, specific language dealing with so-cioeconomic impacts could be included inbills providing for the development of o i lshale resources.

Regardless of the approach adopted for oilshale, there are three options that Congresscan consider to address social and economicimpacts.

CONTINUATION OF PRESENT PROGRAMS

Under this option, Federal assistancewould continue to emphasize revenue sharingand technical assistance. Funding throughexisting channels, such as the Mineral Leas-ing Act, as amended, would be the m a j o rmechanism. Certain other existing Federalprograms, not now designed to deal specifi-cally with socioeconomic impact mitigation,could be redirected. For instance, EPA waterand sewer grants could be accelerated, withadditional appropriations made availableand limited to impacted communities. Restric-tions on existing programs could be modified.

An example is Federal housing programs,n o w res t r ic ted to projec ts for l o w- a n dmoderate-income families, that could be pro-vided to rural communities undergoing rapidgrowth regardless of local income levels.

The advantages of this option are that i twould require only minor adjustments to ex-

isting l a ws . Mechanisms for delivery a r ealready in place. Flexibility would be main-tained since the focus would be on a l readyestablished programs designed to meet a va-riety of needs. The disadvantages include thepossibility that the amount of aid might not beadequate to meet the demands of severely im-pacted communities. In this case, appropria-t ions would have to be increased for someprograms now being held at particular fund-

ing levels. The fragmentation of programs,now viewed by some States and localities as abarrier to effic ient delivery of Federal a id ,probably would not be reduced.

INCREASED FEDERAL INVOLVEMENT INGROWTH MANAGEMENT

This option would emphasize regulation.Present Federal revenue sharing would con-tinue. Several possibilities exist for increasedg ro wth ma n a g e me n t p a r t i c ip a t io n . c o n s id -eration of social and economic effects on adjacent communities could be made a part of execu t ive agency c r i te r ia when se lec t ingFederal lands for energy mineral leasing. Inthis case, given natural resource deposits of approximately equal value, leases would bemade available only in areas where the socio-economic impacts could be minimized. Also,

the number and timing of leases could be adjusted to take into account the ability of near-by communities to absorb growth. Finally, thele a se p ro v i s io n s c o u ld in c lu d e ma n d a to ryparticipation of lessees in mitigation efforts.

Greater involvement of Federal agencies inmonitoring socioeconomic impacts and in pro-v id in g a ss i s t a n c e to mi t ig a t io n e f fo r t s i sanother alternative. For example, the regula-tory activities of the Area Oil Shale Super-visor’s Office could be expanded to includemonitoring social and economic indices in off-tract communities. Attention could be givento difficult ies not now being systematicallyfaced, such as interstate jurisdictional prob-lems between Utah and Colorado. The RegionVIII Energy Impact Office could have a fieldrepresentative permanently sta tioned in oilshale country to provide the services of FRClo c a l ly . T h i s r e p re se n ta t iv e c o u ld p ro v id etechn ica l a ss is tance to a rea p lanners andcould address problems they are too busy toconsider now, such as anticipating the post-boom period. Increased technical assistancecould also address the problems of definingand identifying boomtown conditions. A de-termination of the maximum growth commu-n i t i e s c o u ld su s ta in w i th o u t e x p e r i e n c in gsevere disruption would be valuable for pol-icymakers at all levels.




Identifying and evaluating social and eco-n o m i c i m p a c t s , d e t e r m i n i n g a m a x i m u mg ro wth ra te fo r sp e c i f i c s i t e s , a n d c o o r -dinating Federal programs are needed in allp a r t s o f th e c o u n t ry e x p e r ie n c in g e n e rg y -rela ted growth, Thus, actions to deal withthese problems would be of nationwide value,

For this reason, R&D could be undertaken byany of several agencies on a national basis,and would not necessarily have to be limitedto the oil shale region.

Among the advantages of this option is thatit would supplement existing mitigation pro-grams already established by local and re-gional entities. It would provide a link be-twe e n F e d e ra l d e c i s io n ma k in g b o d ie s a n dS ta te a n d lo c a l a g e n c ie s r e sp o n s ib le fo rgrowth management. Access to Federal pro-grams would be enhanced. Among the disad-

v a n t a g e s a r e t h e i n c r e a s e d b u r e a u c r a c yneeded to implement the option, and the pos-sibility that local individuals would perceivethe Federal efforts as increased infringementon their lives. Energy development companieswould most likely object to additional leaserestric tions and to required partic ipation inmi t ig a t io n p ro g ra ms . Execu t ive agenc iesmight find implementation burdensome.

EXPANSION OF FEDERAL PROGRAMS FORIMPACT MITIGATION

U n d e r t h i s o p t i o n , p r o g r a m s a l r e a d y

e n a c te d wo u ld b e e x p a n d e d o r n e w o n e s

adopted. The Powerplant and Industrial FuelUse Act of 1978, section 601 program, is theobvious candidate for extension. Under thisA c t ,89 F e d e ra l a s s i s t a n c e wa s p ro v id e d fo rareas experiencing rapid growth from coal oruranium production. The assistance is aimedat improved planning for growth manage-

ment, and for land acquisit ion for housingand public facilities development. Expansionof the program would include areas affectedby growth from industries other than coaland uranium producers, and could encom-pass a wider range of problems than growthmanagement planning and land acquisit ion.A bill to expand the section 601 programs iscurrently under consideration. *

The advantages of this option are that i texpands an already existing program. Themechanisms for implementation are in place

and have already been operating under thepresent law, Disadvantages include the needfor increased appropriations to fund the vari-ous elements of the program and expansion of th e F e d e ra l b u re a u c ra c y to c a r ry o u t th eAct’s provisions. Some flexibility may be lostas uniform standards are applied to all Stateswishing to participate in the expanded pro-gram.

*S. 1699.



—- .


Chapter 10 References1For a discussion of current controversies

about the early inhabitation of the North Ameri-can continent, see Graham Chedd, “On the Trailof the First Americans, ” Science 80, vol. 1, No. 3,March/April 1980, pp. 44-51. For general informa-

tion, see Handbook of North American Indians(Washington, D. C.: The Smithsonian Institution,1979).

2Angelico Chavez (tr.), Ted J. Warner (cd.), TheDominguez-Escalante Journal: Their ExpeditionThrough Colorado, Utah, Arizona and New Mexicoin 1776 (Provo, Utah: Brigham Young UniversityPress, 1976).

This was Powell’s second expedition to theRockies. It followed a trail pioneered by Berthoudin 1861; Jim Bridger served as guide. Powell’swife accompanied the group and was the onlywoman to spend the winter. Powell made a trip inNovember, which he nearly didn’t complete, to get

supplies at Green River City, Wyo, Powell’s Park,a few miles west of Meeker, Colo., was the site of the “Meeker Massacre” in 1879, Here, a group of Ute Indians shot and killed Nathan Meeker andseveral other workers at the Indian Agency. SeeRobert Emmitt, The Last War Trail: The Utes andthe Settlement of Colorado (Norman, Okla.: Univ.of Oklahoma Press, 1954) and Marshall Sprague,Massacre: The Tragedy at White River (Boston,Mass.: Little, Brown & Co., 1957).

4The Ute Indians signed four treaties with theUnited States: in 1840, 1863, 1868, and 1880, SeeGerald T. Hart, Leroy R. Hafen, Anne M. Smith,and the Indian Claims Commission, Ute Indians II

(New York, N. Y.: Garland Publishing, Inc., 1974)and George E. Fay, Land Cessions in Utah and Col-orado by the Ute Indians, 1861-1899 (Greeley,Colo.: Univ. of Northern Colorado, Museum of An-thropology, Misc. Series No. 13, 1970). See alsoEmmitt, Supra No. 3.

5Range wars erupted in the latter part of the19th and early decades of the 20th centurieswhen sheep and cattle raisers fought over the useof the rangelands. See James H. Baker and LeRoyR. Ha fen (eds.), History of Colorado (Denver, Colo.:Linderman Press, 1927).

6In 1901, Roosevelt spent 5 weeks huntingmountain lion near Meeker; the party killed 14, of

which the largest weighed over 220 lb and wasover 8 ft long. In 1905, he returned for a bear huntin the area south of New Castle.

7Bureau of the Census, County and City DataBook, 1977 (Washington, D, C.: Government Print-

ing Office, 1978). See also Colorado Departmentof Agriculture, Agricultural Land Conversion inColorado (Denver, Colo.: Resource Analysis Sec-tion, 1979).

‘Bureau of the Census, Congressional District

Data Book, 93d Cong. (Washington, D. C.: Govern-ment Printing Office, 1973).

‘) Frank G. Cooley, “The Growing Awareness of Oil Shale’s Impact on Communities in WesternColorado, ” Rocky Mountain Association of Geolo-gists—1974 Guidebook to the Energy Resources of the Piceance Creek Basin, Colorado, 171-3.

‘[’Altogether, more than 20 studies were pub-lished between 1970 and 1977 dealing with one oranother aspects of oil shale development. See,e.g., Oil Shale Regional Planning Commission andthe Colorado West Area Council of Governments,Profile of Development of an Oil Shale Industry inColorado (Rifle, Colo.: CWACOG, 1973), and Col-

orado West Area Council of Governments, OilShale and the Future of a Region: A Summary Re-port (Rifle, Colo.: CWACOG, 1974).

11Alys Novak, “Oil Shale—1976/1977, ” ShaleCountry, vol. 2, No. 12, December 1976, pp. 2-6.

12Rio Blanco Oil Shale Project, Social and Eco-nomic Impact Statement—Tract C-a (Gulf OilCorp. - Standard Oil Co. (Indiana), March 1976);an Addendum was published in May 1977.

‘ ] C-b Oil Shale Project, Oil Shale Tract C-bSocio-Economic Assessment, 2 vols. (Ashland Oil,Inc. - Shell Oil Co,: March 1976).

14Colony Development Operation, An Environ-mental Impact Analysis for a Shale Oil Complex at

Parachute Creek, Colorado (Denver, Colo.: 1974).15Jonijane Paxton, “Whither Now, BattlementMesa?” Shale Country, vol. 2, No. 6, June 1976,p.15,

1 6Western Environmental Associates, Inc . ,Baseline Description of Socio-Economic Conditionsin the Uinta Basin and Socio-Economic ImpactStudy of Oil Shale Development in the Uinta Basin(Denver, Colo.: White River Oil Shale Corp., 1975).

17The five studies are:a.

b.

Department of the Interior, Final Environ-mental Statement for the Prototype OilShale Leasing Program, 6 vols. (Washing-ton, D. C.: Government Printing Office,

1973),Rio Blanco Oil Shale Project, Social andEconomic Impact Statement—Tract C-a(Gulf Oil Corp. - Standard Oil Co. (Indiana),March 1976), including 1977 Addendum,




c.

d.

e.

C-b Oil Shale Project, Oil Shale Tract C-bSocio-Economic Assessment, 2 vols. (Ash-land Oil, Inc. - Shell Oil Co., March 1976).Department of the Interior, Final Environ-mental Impact Statement: Proposed Devel-opment of Oil Shale Resources by the ColonyDevelopment Operation in Colorado, 2 vols,(Washington, D. C.: Government Printing Of-fice, 1975).Western Environmental Associates, Inc.,Baseline Description of Socio-Economic Con-ditions in the Uinta Basin and Socio-Econom-ic Impact Study of Oil Shale Development inthe Uinta Basin (Denver, Colo.: White RiverOil Shale Corp., 1975).

18 Rio Blanco County Ordinances, sec. 1003;1974.

19See Steve H. Murdock and F. Harry Leistritz,E n e r g y D e v e l o p m e n t in the Western UnitedStates—Impact on Rural Areas (New York, N. Y.:Praeger Publishers, 1979).

20It is difficult to place a dollar value on the con-tributions of industry, In Wyoming, the MissouriBasin Power Cooperative (a consortium of REAelectric cooperatives) estimates that it spent $21million in mitigation efforts in conjunction withthe construction of the 1,500-MW Laramie RiverStation in Platte County. This included in-kindservices; direct grants and revenue guarantees totowns, counties, and agencies; bond guarantees;and similar assistance. The cooperative believesit saved approximately $50 million in costs by re-ducing employee turnover and by allowing theplant to be constructed on schedule. Furthermore,they anticipate recovering all but about $3 millionof the $21 million outlay as the bonds are paid and

other revenues become available. Eventually theamount spent for mitigation probably will fall be-tween one-half and 1 percent of the total cost of the plant. (Personal communication from Dr.James Thompson to OTA, Nov. 5, 1979.)

21CO1. Gen’1 Ass’y, H.B. 1200 (1974, 2d sess.).2241 Stat. 437 (1920), as amended and supple-

mented, 30 U. S. C., sec. 181 et seq. (1976),23C.R.S. 1973,34-63-104.24C.R.S. 1973, 34-63-104 (l).25C.R.S. 1973.34-63-104 (2).26C.R.S. 1973, 34-63-101 and 102, as amended.27C.R.S. 1973, 34-63-102 and 39-29-110.28C.R.S. 1973, 39-29-101 through 114 (Supp.

1977).29Personal communication, Stan L. Albrecht to

OTA, Oct. 16, 1979.30U.C.A. 1953, 63-51-1 through 4.

31U.C.A. 1953, 53-7-1 and 2; 65-1-64 and 65; and65-1-115.

32U.C.A. 1953, 73-10-8 and 73-10-23.33W.S. 35-12-101 through 121,34W.S. 9-1-129 through 136.35W.S. 39-6-412.36Personal communication, Dr. James Thompson

to OTA, Oct. 16, 1979. An example of an imagina-tive program is the Wyoming Human ServicesProject (WHSP). The WHSP program trained hu-man service personnel at the University of Wyo-ming campus and then placed the students inWyoming boomtowns for field experience. Aftercompleting the program, many students found jobs in the communities and stayed to continuetheir service. See Judith A, Davenport and JosephDavenport, III, Boom Towns and Human Services(Laramie, Wyo.: Univ. of Wyoming, 1979).

37Personal communication, Dr. James Thompsonto OTA, Oct. 16, 1979. See also Stan L. Albrecht,“Socio-Cultural Factors, “ in Mohan K. Wali (cd.),Mining Ecology.

“Department of Energy, Report to the Presi-dent—Energy Impact Assistance (Washington,D. C.: DOE/IR-0009, UC-13; March 1978).

39Supra No. 19. Under Public Law 95-238, DOEhas awarded grants to Colorado and Utah for so-cioeconomic planning. Also, grants have beengiven to Rio Blanco and Garfield Counties and thethe Northern Ute Indian Tribe.

40Supra No, 22.4190 Stat. 1083

201 et seq. (1976).4290 Stat. 2743

(1976).43Supra No. 41.

1976), amending 30 U.S.C. sec.

(1976), 43 U.S.C. § 1701-1782

44For a number of reasons, the loan program au-thorized by FLPMA has yet to be implemented.

4592 Stat. 3323 (1978).46Ibid.‘department of Energy, Regional Profile—Ener-

gy Impacted Communities—Region VIII (Denver,Colo.: TIC-1OOO1, UC-13; 1979).

48Federal Energy Administration, A Report—Regional Profile—Energy Impacted Communities(Denver, Colo.: Region VIII Socioeconomic Pro-gram Data Collection Office, July 1977) pp. 5-6.

49For a complete discussion of alternatives, seeEconomic Impact of the Oil Shale Industry inWestern Colorado, hearing before the Subcom-

mittee on Public Lands of the Committee on Interi-or and Insular Affairs, U.S. Senate, 93d Cong., 2dsess., Jan. 19, 1974; Inland Energy DevelopmentImpact Assistance Act of 1977 (S. 1493), hearings





Ch. 10–Socieconomic Aspects Ž 473

Valley View Hospital Needs Assessment63 Personal communication, Dan Deppe (city

manager) to Dr. Donald Scrimgeour and MissEllen Hutt, July 1979.

64Donald P. Scrimgeour and Marilyn Cross, De-velopment Patterns and Social Impacts: A Focuson the Oil Shale Region (Denver, Colo,: Quality De-

velopment Associates, July 1979).65Discussion with Mr. Floyd McDaniel, Chair-man, Planning Commission, Grand Valley, August1979.

66Personal communication, Peter Kernkamp(town planner) to Dr. Donald Scrimgeour and MissEllen Hutt, July 1979.

67Personal communication, Bob Young (townmanager) to Dr. Donald Scrimgeour and MissEllen Hutt, July 1979.

68Department of the Interior, Draft Environmen-tal Statement: Proposed Superior Oil CompanyLand Exchange and Oil Shale Resource Develop-ment (Denver, Colo.: BLM, August 1979) pp. 77-90.

69

Supra No. 50.70Supra No. 67.71Supra No. 64.72Supra No. 67.73Personal communication, Mr. William Bren-

nan to OTA, January 1980.74Ibid,

75Supra No. 68.76Supra Nos. 47 and 48.7783 Stat. 852 (1970), as amended by 89 Stat.

424 (1975), 42 U.S.C. 4321-4347.78Ibid.79See, for example, Calvert Cliffs Coordinating

Committee, Inc. v. U.S. Atomic Energy Commission,

449 F.2d 1109 (D.C. Cir. 1971), cert. denied, 404U.S. 942.8090 Stat. 1013 (1976), 16 U.S.C. 1451-1464.8186 Stat. 1280 (1972), 16 U.S.C. 1451-1464.82Supra No. 38.83Ibid., pp. 59-81.84Rocky Mountain Energy Resource Develop-

ment: Status, Potential, and Socioeconomic Issues(Washington, D, C.: GAO, July 1977), EMD-77-23.

85Ibid., pp. 5-7.86Supra No. 45.87Energy Impact Assistance: A Background Re-

port, printed at the request of the Committee onEnergy and Natural Resources, U.S. Senate, 96th

Cong., 1st sess., October 1979 (publ. No. 96-34)(committee print).88For a spirited elucidation of this position, see

Raymond L. Gold, “On Local Control of WesternEnergy Development, ” The Social Science Journal,vol. 16, No. 2, April 1979, pp. 121-127.

89Supra No. 45.



Appendixes



APPENDIX A

Description and Evaluation of the Simulation Model

To evaluate quant i ta t ively the al ternat ive in-centives, a computerized model was used, devel-oped by Tyner and Kalter1 that captures the prob-abilistic attributes of the oil shale development

process through Monte Carlo simulation tech-niques. The core of the model is a discounted cashflow algorithm computing the after tax profit.

In computing aftertax profit, the model uses aconventional discounted cash flow algorithm inwhich the net cash flow for each year (i. e., reve-nues less costs and taxes) is discounted to the be-ginning of the project. These discounted cashflows are then summed to arrive at the aftertaxnet profit.

With the model, the user can input probabilitydistributions of prices and costs instead of singlevalue estimates. The model then constructs aprobability distribution for aftertax profits using

the Monte Carlo method. With this method, themodel makes repeated runs in which profit is cal-culated. In each run the model randomly selectsvalues from the input distributions. The resultingprofit calculations are then cumulated into prob-ability y distributions characterized by an expectedvalue and standard deviation, The expected valuegives the average profit for all the Monte Carloruns and the standard deviation provides a meas-ure of dispersion or variation about this averagevalue. The model also totals the number of MonteCarlo runs that results in positive profits andplots a histogram of the frequency distribution of the profit outcomes, From this output the user can

compute the probability that a loss will be in-curred.

Although the model was designed to test the ef-fects of alternative mineral leasing systems onprofits and Government revenues, it incorporatesseveral financial incentives, including construc-tion grants, price supports, purchase agreements,investment tax credits, depletion allowances, andvariable depreciation schedules. Indeed, its au-thors used an earlier version to evaluate the ef-fects of some of these incentives on the profitabili-ty and risk of oil shale development. ’

However, because the model was not designedspecifically to test incentives, it has several lim-

itations. First, it does not provide for inflation in-dexing of the floor price under a price supportprogram. Thus, if the user inputs nominal (i.e.,gross of inflation) values into the model, the real(i.e., net of inflation) floor price will decline over

time. Alternatively, the user can input all real val-ues (as OTA did) which implicitly indexes thefloor price. However, this solution causes somedistortion in the tax calculations. With inflation,

income increases in nominal value, but theamount of depreciation deducted for tax purposesremains constant. Thus, in real terms, the value of depreciation decreases with inflation. However,since the model does not account for this real de-crease when the user inputs all real values, themodel underestimates the amount of tax pay-ments. This distortion was not considered serious,given the short depreciation period and the higherfraction of depreciation claimed in early periods.

Second, the model has a limited capability withrespect to purchase agreements. To model a pur-chase agreement for the entire production, theuser can input the purchase price in place of the

market price for oil. However, the model cannotdirectly handle purchase agreements for only aportion of the output in a given year. To evaluatea partial purchase agreement, the user must per-form offline calculations to obtain an average of the market and purchase agreement prices,weighted by the proportion of output sold for eachprice, A similar calculation must then be per-formed for the standard deviation of the pricedistribution.

Third, the model has no capability to simulatethe effects of production tax credits. It does allowfor a price subsidy, but this subsidy is not a taxcredit. Unlike a tax credit, the subsidy increases

taxable income and hence income tax payments.Because of this limitation, the model was not usedto perform the necessary calculations for the$3/bbl tax credit. To estimate the increase in ex-pected profit, the per barrel tax credit was multi-plied by each year’s production. The total annualcredits were than discounted to the present andsummed. The same procedure was used to calcu-late the expected cost to the Government, exceptthat the Government discount rate was used inthe calculation. To evaluate the effect on risk, itwas assumed that the standard deviation wouldnot change as a result of the tax credit. Thisassumption follows because the tax credit does

not alter costs or prices; these alterations deter-mine the standard deviation. Because the stand-ard deviation is the same for the tax credit as it iswith no incentive, it was possible to transform thehistogram computed for the no-incentive case into

477




a histogram for the production tax credit case.With this new histogram an estimate could bemade of the percentage of cases falling below thezero profit level. Finally, the breakeven price wascalculated by subtracting the production taxcredit from the breakeven price with no incentive.

Fourth, the model is not able to simulate the ef-

fect of low-interest loans. Although the user couldadjust the discount rate downward to account forthe low-interest loan, this method has several limi-tations because it fails to account for all the termsof the loan. In particular, this method is not sen-sitive to the time when the loan is received andthe time when it must be repaid. Moreover, theapproach is based on very restrictive and unreal-istic assumptions about the structure of debt fi-nancing for the project.3

Accordingly, the model was not used to performthe calculations for the low-interest loan. Thesteps for the low-interest loan computations arereferenced in table A-1, The actual cash flows

(both loan payments and repayments) to the firmwere set up based on the Government’s lendingrate and the structure of the loan. These cashflows were then discounted using the borrowingrate for the firm on the open market (assumed tobe 3-percentage points higher than the Govern-ment lending rate), A similar calculation was per-formed to estimate the expected cost to the Gov-ernment. As with the production tax credit, it wasassumed that the standard deviation of the distri-bution of profits would not change, since the loandoes not alter any of the costs or prices in themodel. With the estimated mean for the profitdistribution and the standard deviation, the histo-

gram of profit distribution from the no-incentiverun was subsequently used to estimate the prob-ability of a loss. The price increment was thencomputed, which, when multiplied by the produc-tion for each year, yielded a discounted valueequal to the estimated increase in expected prof-its. The price increment was then subtracted fromthe breakeven price with no incentive to yield thebreakeven price under the low-interest loan pro-gram.

Finally, the model does not directly calculatethe net cost to the Government. However, if theGovernment and the firm use the same discountrate, the cost to the Government exactly equals

the gain in expected profit to the firm calculated

Table A-1 .–Calculating Change in Expected Profit and Cost tothe Government for a Low-Interest Loan

Assumptionsq The average total construction cost is $1.7 billion• 70 percent of one-fifth of the total construction cost, $238 million, is

loaned at the end of each of the 5 years of constructionŽ Interest IS calculated on the principal from the moment the first loan is

madeq The loan principal plus interest is amortized over 20 yearsq The interest rate is 3 percent in real termsq The firm market borrowing rate is 6 percent in real termsq The Government’s discount rate is 10 percent in real terms

CalculationsResult

Step ($ million)1.

2

3.

4.

5.

6.

7.

8.

9.

10,

11.

Calculate annual loan amounts (1 ,700x .7x 2), ., ‘ 238/yr ‘Calculate the future value in year 5 of five payments of$ 2 3 8 . 0 0 ( 3 - p e r c e n t I n t e r e s t ) . .Calculate the annual principal and Interest payment to theGovernment (years 6-25) based on the future value instep 2 (3-percent In terest)Calculate the present value to the firm year 5 of thep a y m e n t f r o m s te p 3 ( 6 - p e r c e n t I n t e r e s t )Calculate the present value to the firm in year O of thev a l u e f r o m s t e p 4 ( 6 - p e r c e n t I n t e r e s t ) ,Calculate the present value to the firm in year O of theannual loan amount from step 1 (6-percent Interest).Calculate the change in profit for the firm (1 ,003-726)Calculate the present value to the Government in year 5 ofthe payment from step 3 (l O-percent interest) .,Calculate the present value to the Government in year O ofthe va lue from step 8 ( l O-percent In terest)Calculate the present value to the Government in” year O ofthe annual loan amounts from step 1 ( 10-percenti n t e r e s t )Calculate the net cost the Government (901-448)

1,264

85/yr

974

726

1,003277

723

448

401453

SOURCE :Office of Technology Assessment

by the model. This is so because, except for small

tax payments to State governments, all the mone-tary exchanges occur between the Federal Gov-ernment and the firm. If the discount rates are thesame, the present value of the exchanges to bothentities is the same, Therefore, since a lo-percentGovernment discount rate has been assumed, thenet cost to the Government of each incentive isequal to the net gain in profitability to the firmcalculated at a lo-percent discount rate. The onlyexception occurs with the Government loan. Be-cause it has been assumed that the real interestrate on debt financing for firms is less than 10percent, the present value to the firm of the low-interest loan is less than its cost to the Govern-

ment.



Appendix A–Description and Evaluation of the Simulation Model Ž 479

Appendix A References

1Wallace E. Tyner and Robert J. Kalter, “A Simula- Foundation, April 1975.tion Model for Resource Policy Evaluation, ” Cornell Ag- 3tewart C. Meyers, “Interactions of Corporate Fi-ricultural Economic Stuff Paper, September 1977. nancing and Investment Decisions—Implications for

2Wallace E. Tyner and Robert J. Kalter, An Analysis Capital Budgeting, ” in Modern Developments in Finan-

of Federal Leasing Policy for Oil Shale Lands, prepared cial Management, Hinsdale, Ill.: Dryden Press, 1976.for the Office of Energy R&D Policy, National Science



APPENDIX B

Assumptions and Data for Computer Analyses

Most of the assumptions used in the computer simulation analyses are embodied inthe input data displayed in table B-1. All cost and price data in the exhibit are in constant1979 dollars.

Table B-1 .–Data Used for Quantitative Analysisa

Data item Value used Explanation

costsCapital cost distribution

Maximum capi ta l cost,Most probable capital cost:M i n i m u m c a p i t a l c o s t

Operating and maintenance(O&M) cost distribution.

M a x i m u m O & M c o s t .Most probable O&M cost :M i n i m u m O & M c o s t

Operat ing cost Increase

C o n s t r u c t i o n p e r i o d

Fraction of costs occurring eachyear during construction

Year 1 .,Year 2Year 3 ., : : : : :Year 4 .,Y e a r 5Year 6 .,

PricesIni tial oi l price (1979) ., .,Mean annual 011 price increase

Standard deviation of annual oilprice change distribution

Taxes and transfers

Federal corporate tax, .,S t a t e c o r p o r a t e t a xState severance tax . ,Investment tax cred i t ,

D e p l e t i o n a l l o w a n c eRoyalty .,

D e p r e c i a t i o n I i f e t i m eAnnual rent .,D e p r e c i a t i o n m e t h o d

$2.0 billion$1.7 billion$1.4 billion

$17/bbl$12/bbl$ 9/bbl

4 percent/year

6 years

102530250010

$35/bbl3 percent

3 percent

46 percent3 percent4 percent

10 percent

15 percent1 percent

12 years$2,600

Sum-of -years

The capital cost data apply to all the capital equipment needed to mine and retort shale and hydro-treat the raw shale oil product, the costs do not Include land acquisition or interest charges, Datawere based on recent industry cost estimates,

Operating costs include hydrotreating costs. Data were based on recent industry cost estimates

Operating costs were assumed to increase 4 percent per year in real terms (I e., net of inflation)to account for probable Increases in labor costs due to expansion of shale Industries in sparselypopulated areas Assumption was based on expectations expressed to OTA by industry sources

A 6-year construction period (i. e , a l-year delay between the fourth and fifth years) decreased

expected profits by $117 million for the no-incentive, 12-percent discount rate case.

Based on the price of imported oil, which at the time of the analysis ranged from $33 to $37/bbl.The assumed 3-percent real increase in oil prices accounts for increasing scarcity as cheap do-

mestic supplies are exhausted, and is midway in the range (2-4 percent) used by DOE planners

Based on historical trends from the American Petroleum Institute, Basic Petroleum Data Book,1976.

Current Federal corporate income tax rate,Colorado corporate income tax rate.Colorado severance tax on 011 shale reserves,Investment tax credit of 10 percent applies to all investments, an existing additional 10-percentcredit for energy-related Investments was ignored because it is to expire in 1982,

Depletion allowance computed on 011 shale revenues and deducted from taxable income.Current royalty is 12.5 cents per ton of mined shale; this is equivalent to a royalty on 011 revenues

of less than 1 percent.Based on discussions with industry sources.Based on a 50-cent-per-acre rent on Federal shale leases of 5,200 acres,Provides the most rapid tax writeoff,

digits with switch-over to straight

IineProductionMaximum output of facility ., 50,000 bbl/d Size of typical commercial facility,Production l i fetime ., ., ., 22 years Based on production lifetime of 20 to 30 years in industry cost estimates.Annual output

Y e a r 1 15,000 bbl/d 2-year buildup accounts for probable startup difficulties.Year 2 ..., : ..........35,000 bbl/dYears 3 to 22, ., ., ., 50,000 bbl/d

aAll monetary values in constant 1979 dollars

SOURCE :Office of Technology Assessment

480



APPENDIX C

Oil Shale Water Pollutants

Introduction

The types and amounts of water contaminants that are likely to be produced by ma-

jor kinds of oil shale facilities are discussed here,

Water Pollutants Produced by Major Oil Shale Processes

Types and Origins of Pollutants

The following summarizes the major sources of each class of waterborne contaminants found inoil shale facilities.

q

q

q

Suspended solids will occur primarily inwater from the dust-control systems used inshale mining and crushing operations. Minedrainage water will also contain suspendedsolids, as will a retort condensate streamthat picks up fine shale partic les as i ttrickles down through the broken shale. Inaboveground retorts, some fine shale may beentrained in the retort gas and captured inthe gas condensate, but levels should be low,thus should not be a problem to treat, Coolingwater will pick up dust from the atmosphere,particularly if the cooling tower is near ashale crushing or disposal site. Precipitatedsalts and biological matter may also be pres-ent in the cooling tower blowdown.Oil and grease will be present in the retortcondensate water that is removed from thein situ retort together with the product oil.Some oil remains in the water after productrecovery and must be removed prior to fur-ther treatment. Part of the oil forms an emul-sion in the water and its removal may be dif-ficult. 1 Volatile hydrocarbons leave with theretort offgas and condense in the gas conden-sate water. Tests indicate that the oil in thegas condensate occurs in well-defined drop-lets that can be separated without difficulty.2

Oils in the coker and hydrotreater conden-sates are expected to be similar to those inthe gas condensate.Dissolved gases include all of the NH3 a n dsome of the CO2 and H2S formed in the retort-ing process. These gases dissolve in the re-tort and gas condensates. Any NH3 and H2Sthat are formed during upgrading will ap-pear in the hydrotreater condensates.

q

q

q

Dissolved inorganic will be found in minedrainage water and retort condensates be-cause these streams leach sodium, potassi-um, sulfate, bicarbonate, chloride, calcium,and magnesium ions from the shale that theycontact. 3 In addition, some inorganic vola-tilize and may be captured from the gasphase in the retort, Of the heavy metals pres-ent in raw oil shale, cadmium and mercury

(probably as their respective sulfides) are ex-pected to be present in the gas condensate inlow concentrations.’ An analysis of TOSCO IIgas condensate water showed the presenceof cyanide, sodium, calcium, magnesium, sili-ca, and iron ions, with only trace amounts of some of the heavy metal elements.5

Dissolved organics arise largely from the or-ganic compounds in the raw oil shale, whichmay be altered during pyrolysis and end upin the retort, gas, or hydrotreater conden-sates. The types of organics in each conden-sate will probably depend on the volatilityand volubility of the organics and the tem-perature at which the wastewater is con-densed. No data are available on this subjectbut it is known that a wide range of com-pounds, particularly carboxylic acids andneutral compounds, can be expected.6 Manyof the individual compounds should be biode-gradable, but studies have shown that lessthan 50 percent of the organic matter can beremoved by conventional biological oxida-tion. This poor performance is attributed tothe effect of toxic compounds on waste-treat-ment bacteria. Both inorganic and organictoxic substances may be responsible. Thespecific types of toxic pollutants will differ

with the retorting process and with rawshale composition. 789

Trace elements and metals are not expectedto occur in large concentrations in the majorwaste streams except those streams dis-

481




c u sse d u n d e r d i s so lv e d in o rg a n ic s .10 11

Chromium was used for corrosion control inolder cooling-water systems but other agentsare now available and should be used toavoid the problem of chromium contamina-tion of blowdown streams. If trace elementand metal removal is required, chemicaltreatment, specific ion exchange, and mem-

brane processes are available.Trace organics are toxic or hazardous or-ganic compounds present in low concentra-tions. They may occur in the retort and gascondensate streams and in the wastewaterstream from the upgrading section. Theseconstituents can generally be removed to-gether with other dissolved organics by ul-trafiltration with carbon adsorption for final q

cleaning (“polishing”).Toxics, including carcinogens, mutagens,priority pollutants, and other hazardous-sub-

Table C-1 indicatesprocess streams and

stances, have been reported for varioustypes of oil shale processing wastes. Any tox-ic substances present in the wastewaterstreams will be removed along with the traceorganics or inorganic substances. It is not ex-pected that thermal oxidation, which is oftenemployed to destroy hazardous organic com-pounds, will be required for the wastewaterstreams, although it may be considered forconcentrates or sludges. However, the pres-ence of toxic substances may interfere withbiological oxidation processes used for bulkorganic removal. If this is a problem, thesubstances could be removed in any of sever-al conventional pretreatment steps.

Sanitary wastes in “domestic” and servicewaste streams can be kept separate andtreated in commercially available packagebiological treatment units.

The Amounts of Pollutants Produced

he principal contaminated MIS process. It is similar to the design proposedtheir f low rates for four by Occidental and Tenneco for tract C-b. The

commercial-scale [50,000 bbl/d)* oil shale facil- “MIS/aboveground” plant combines Occidental’sities. These facilities correspond to the plants forwhich water requirements are estimated in chap-ter 9. The “aboveground direct” plant uses di-rectly heated aboveground retorts like the Parahodirect or gas combustion. The “aboveground in-direct” uses indirectly heated retorts like TOSCOII. It is similar to the design proposed by ColonyDevelopment. The “MIS” plant uses Occidental’s

MIS process-with Lurgi-Ruhrgas indirectly heatedaboveground retorts. It is similar to Rio Blanco’sdesign for tract C-a.

The flow rate estimates were derived fromtables 71, 74, and 75. (See ch. 9.) Estimates havebeen added for the internally recycled gas wash-ing and hydrotreater wash streams that were notconsidered in chapter 9. (The water availability

*Barrels per stream day.

Table C-1 .–Flow Rates of Contaminated Streams in Oil Shale FacilitiesProducing 50,000 bbl/d of Shale Oil Syncrude (acre-ft/yr)

Aboveground Abovegrounddirect redirect MIS MIS/aboveground

C o o l i n g t o w e r b l o w d o w n 1,550-1,820 1,320-2,070 1,040-1,280 910-1,130B o i l e r b l o w d o w n . . . 325 370-405Boiler feedwater treatment wastes

370 350165 190-210 185 180

Gas washing condensate ., 1,070-1,190 (a) 3,320-3,640 2,270-2,500G a s c o n d e n s a t e ( n e t ) . . 490-540 730-800 2,160-2,370 1,480-1,630Retor t condensate, . . . . (a) (a) 1,240-1,370 850-940C o k e r c o n d e n s a t e . . , 60 60 60 60Hydrotreater wash condensate 875 875 875 875Net hydrotreater condensate 40 40E x c e s s m i n e d r a i n a g e (a) (a) 0-10,000 0 - 1 0 , 0 0 0

a)@glecfed for processes designs or sites considered

SOURCE R F Probstem H Gold and R E Hicks, Wafer Reqwernenfs Po//ufIorI Mecfs and Cos/s of Waler Supply arrd Treafrnerd for (he 0(/ Sfra/e /n-dus(ry. prepared for OTA by Water Purlflcahon Associates October 1979



Appendix C–Oil Shale Water Pollutants q 483

analysis presented there deals only with streamsthat cross the project boundaries.) These addi-tional streams are of significance for water quali-ty analysis because they contain all of the NH3,most of the CO2, and some of the H2S that is re-moved from gas streams in the plants. Flow rateranges are shown in some cases to account for the

expected variations in shale grades and plant de-signs, as discussed in chapter 9. The followingpoints should be noted with respect to the flowrate estimates.

q

q

q

q

q

Cooling tower blowdown varies substantiallyamong the plants, largely because of differ-ent modes of power generation.Boiler blowdowns are fairly uniform becauseit is assumed that boilers will generate steamfor use in the upgrading units, which areidentical for all four plants.For the same reason, all four plants have thesame flow rates for coker condensate, hydro-treater wash condensate, and net hydro-

treater condensate.Excess mine drainage is indicated for theMIS and MIS/aboveground plants because itwas assumed that they would be located inthe ground water areas of the Piceance ba-sin. The other two plants were assumed to belocated in drier areas (e.g., in the Uinta basinor along the edge of the Piceance basin),No retort condensate is shown for the AGRplants because it was assumed that conden-sation in the retort would be avoided by adjusting the operating temperature. A large

q

value is shown for the MIS retort condensatebecause of unavoidable condensation in thelower portions of the MIS retorts. The valuefor MIS/aboveground is a weighted averageof Lurgi-Ruhrgas (no condensate) and MIS(large quantities of condensate).Large values are also shown for gas conden-

sate and gas washing condensate in all sys-tems except the aboveground indirect. In theaboveground direct and the two MIS oper-ations, large quantities of moist retort gasmust be treated, resulting in large volumes of condensate. Much of the moisture is a com-bustion product. In contrast, the above--ground indirect has no combustion within theretort and produces less gas that must becooled and cleaned.

In table C-2, estimates are presented of the con-centrations of contaminants in the condensatestreams. It is important to note that extensivedata on contaminant concentrations are not avail-

able for the process condensate streams and thatpublished measurements show considerable vari-ation. Only the estimate for the aboveground in-direct gas condensate is based on extensive fieldmeasurements.13 The other values are consistentwith material balance calculations and informa-tion from the literature but they are at best ap-proximate. Moreover, only concentrations of major contaminants are shown. Trace contaminants,including most toxic elements, are not indicatedbecause information on their occurrence is evenmore limited, Although toxic elements are not ex-

Table C-2.–Contaminant Concentrations in Oil Shale Process Condensate Streams (mg/1)a

Gas condensate Retort condensate Hydrotreater condensate

Contaminant Aboveground direct Aboveground redirect MIS or MIS/aboveground MIS or MIS/aboveground All plants

N H 3 17,990C 5,150 21 ,330C 720 41 ,000c

H 2 S 206 c 810 118C — 18,000 C

C O2

b 32,400 C 6,150 41 ,800C 9,940 NoneCalcium : Low d 6 Low 20 LowM a g n e s i u m . Low 2 Low 17 LowP o t a s s i u m Low 0 4 Low 100 LowS o d i u m Low 5 Low 3,600 LowC h l o r i d e Low 5 Low 280 LowF l u o r i d e Low 0.3 Low 39 LowB o r o n , Low Low Low 25 LowS u l f a t e Low Low Low 1,200 LowOr g a n i c c a r b o n — 6,100 — — —

BOD e ., 10,000 10,000 2,200 2,220 10,000

alrace elements and organlcs forwhich data are unavailable are flOl shown

bBlcarbonafe and carbonate concentrations reporled as CO, e(lulvalenfcln Internal acid wash before gas separation and wash recYcledBa5ed on avadable dala or estlmaleseBlochemlcal oxygen demand estimated al one half of the fheorellcal oXY9en demand

SOURCE R F Probstem H Gold and R E Hicks Wafer l?equ~rerneflfs, Po//ufIorI Ef/ecK and Cos/s of Waler Supp/y and Treafrnefll for rhe 0// Shale /ndustry prepared tor OTA by Waler Punflcaf!onAssociates October 1979








considered, based on an average of three cyclesof concentration for AGR (surface water supply)and four cycles of concentration for MIS retorting(mine drainage water supply). The relatively lownumbers assumed for concentration cycles arebased on the assumption that all of the blowdownwater is needed for solid waste disposal. Under

this assumption there is no advantage to the morecostly procedure of using a larger number of cycles.

Table C-9 gives the estimated composition of the waste streams from treating the raw supply

Table C-9.–Estimated Concentrations of the PrincipalContaminants in an Ion Exchange Regenerant Waste Stream

From Boiler Feedwater Treatment’ (mg/l)

Type of facility

AGR with MIS retorting with mineContaminant surface water supply drainage water supply

C a l c i u m 950 660

Chloride : 2,400 790M a g n e s i u m 250 4,600Sodium ., 990 2,200S u l f a t e 2,080 3,460

avo]ume 01 regenerant wastewater assumed to be approximately 75 Percent ot the volume of

treated water

S O U R C E R F Probsteln H Gold and R E Htcks Wa/er Ileqwrernen(s Po//u/IorI E/(ec/s am-l

COSM of Waler Supply and TrealmerU for (he 0(/ S/ra/e /frdus/(y prepared Ior OTA byWaler Purlflca[ton Associates October 1979

water by ion exchange to obtain a high-qualitywater for boiler feed. The estimates assume theremoval of all the calcium, magnesium, and sul-fate ions from the supply water. Most of the otherions will also be removed but only the principalones are shown for the waste streams. The wastevolume is about 7.5 percent of the water treated.

This corresponds to a fairly efficient ion ex-change treatment system. Boiler blowdown wastecomposition is not shown because the quality of this water is usually equivalent to that of the rawwater entering the plant. It can therefore bemixed with the raw water and used as a makeupsource.

Table C-10 gives the estimated pollutant pro-duction rates in the cooling tower blowdown andboiler waste treatment streams based on the com-positions of tables C-8 and C-9. Also shown are thetotal production rates from these two sources; thestreams would usually be combined in the plantand used for solid waste disposal. There is not a

great deal of difference in the total quantities of pollutants produced by the facilities considered,In table C-1 it was assumed that oil shale mines

in ground water areas might result in productionof from O to 10,000 acre-ft/yr of excess minedrainage water for a 50,000-bbl/d in situ facility.At this time, it is not known whether the waterwill be treated for discharge to surface streams,

Table C-10.–Production Rates for Principal Pollutants in Cooling Tower Blowdown and Boiler Treatment Wastes (ton/d)

Contaminant Aboveground direct Aboveground indirect MIS MIS/aboveground

Cooling tower blowdown

C a l c i u m . 1 35 1,36 0.86 0 7 6C h l o r i d e 3 8 5 3.88 0 3 5 0.30

Fluoride . . . — — 0.26 0 2 3M a g n e s i u m 0 3 8 0.38 1.04 0,91S o d i u m . 2.88 2 9 0 5.18 4,55S u l f a t e 5.26 5 2 9 6 0 4 5.31

Boiler treatment wastes

Calcium . 0,58 0.71 0.45 0.44C h l o r i d e 1,47 1 79 0.54 0,53M a g n e s i u m 0 1 5 0.19 3.16 3.08S o d i u m . 061 0.74 1,51 1.47S u l f a t e 1 28 1.55 2.38 2,32

Total

C a l c i u m . 193 2.06 1.32 1.20C h l o r i d e 5 3 3 5,66 0 8 9 0 8 3F l u o r i d e — — 0.26 0.23M a g n e s i u m 0,53 0 5 6 4.20 3.99Sodium : 3 4 9 3.64 6.69 6.02S u l f a t e 6 5 4 6.84 8.42 7,63

T o t a l . 17.82 1876 21.78 19,90

SOURCE R F Probstein H Gold and R E Hicks, Waler r7e9u/remerr/s Po//u/lon Effec/s and Cos/s of Waler Supp/y and Trea/merrl /or (he Od Sha/e /ndusVy prepared for OTA by Water Purlflcatlon

Associates Oclober 1979





APPENDIX D

Technologies for Managing

Point Sources of Wastewater

Introduction

This appendix describes the wastewater streams that will be produced in oil shalefacilities, including leachates from solid waste disposal. The physical, chemical, and bio-logical treatment devices and systems are then described, Finally, developer plans are re-viewed to show how water supply, wastewater treatment units and systems, and methodsof disposition might be combined into comprehensivecommercial-scale oil shale facilities.

Oil Shale Waste Streams That Will

water management schemes for

Require Treatment

The major point source streams that will re-quire treatment are:

q

q

q

q

q

The

excess mine drainage water—principally forplants near the center of the Piceance basin;retort condensates—especially and perhapsexclusively for in situ operations;gas condensates—for all systems;coker and hydrotreater condensates from allplants that have onsite upgrading or refiningoperations; andstreams from service operations—includingboiler feedwater treatment wastes and cool-ing tower blowdown.

other streams are either relatively small orrelatively clean and consequently require little

treatment. They include boiler blowdown, rainand service water runoff, and sanitary wastes.Sanitary wastes will certainly need treatment,but they should be similar to typical domestic

q

Individual Methods for Point

Physical Methods

Gravity separators are used to treat nearly alloily wastewaters. They are especially commonin refineries and chemical plants. The simplestare impingement-type devices such as API

separators, corrugated plate interceptor sepa-rators and parallel plate interceptor sepa-rators. These devices are very inexpensive andreliable but they can be used only for first-stage oil removal. Additional treatment is usu-

wastes and can easily be handled in commercially.available biological u-nits.

Leachate from spent or raw shale piles on thesurface is not considered as a separate stream re-quiring treatment during the operating life of theplant. With proper compaction and irrigation,water will be either retained in the pile or lost byevaporation. There should therefore be little ac-cumulation of leachates. 1 There will be storm andsnowmelt runoff, but this will be in limited quan-tities and will have a low salt content.2 The smallquantity of water that may percolate through thepile after intentional leaching can be expected tobe low in both organic and inorganic substances, ]This water can be used for dust control in rawshale crushing operations and will thus find its

way back to the retort, Leachate from spent insitu retorts poses a potential problem of unknownmagnitude, Design concepts for its control are dis-cussed in chapter 8.

Source Wastewater Treatment

q

ally needed before the wastewater can be sentto sensitive treatment systems like biologicaloxidizers.Coalescing cartridge separators (figure D-1)are more effective devices that can reduce oilconcentrations to as low as 1 mg/l. In this type

o f se pa rato r , o i ly wa ste wa ter i s p u mpe dthrough a coarse filter medium within the car-tridges, causing oil droplets and some mechan-ically emulsified oil to coagulate into largeglobules which float to the top of the separator

488



Appendix D– Technologies for Managing Point Sources of Wastewater q 489

Figure D-1 .—Cartridge-Type Coalescing Oil-WaterSeparator

O I L YM IXTU R E

E R

SOURCE. Assessment of Oil Shale Retort Wastewater Treatment and Control Technology, Hamilton Standard Division of United Technologies,July 1978, p 5-3.

q

q

and are removed. These devices have high re-moval efficiencies but tend to clog if the watercontains suspended particles. They can also befouled by growth of micro-organisms on thefilter medium.Air flotation is even more effective but is rela-tively complex. One device—the dissolved air

flotation cell—is shown in figure D-2. In thisseparator, air is injected into the oily waste-water as fine bubbles, The oil droplets adhereto the air bubbles and rise to the surface as afroth, which is skimmed off by a motor-drivenrake, Some small suspended particulate con-taminants can also be removed in the froth andothers will settle to the bottom of the cell andcan be removed as a sludge. Coagulant canalso be added to aid removal efficiency. If limeis added, for example, it will precipitate someheavy metals and certain anions such as car-bonates.Clarification [also called coagulation/sedimen-tation or precipitation/sedimentation) may beused to settle out oil, to remove suspendedsolids, or to precipitate toxic metals, carbon-ate, and other anions. A slant-tube clarifier isshown in figure D-3. Accumulation of oil drop-lets and particulate on the tubes greatly en-hances separation of the materials comparedwith the performance of simpler gravity de-vices, Chemicals can also be added in an up-

Figure D-2.— Dissolved Air Flotation

OILY WA TE R

IN FLUENT W A T E R

D I S C H A R G E

OVER FLOWD R I V E N S H U T O F F

R A K E

SOURCE: A

BACK PRESS. —.

* a * a m I I I

o \ EXCESS

AIR OUT

L E V E L

C O N T R O L L E R

ssessmentssessrnent ofOil Shale Retort Waste water Treatment and Control Technology, Hamilton Standard Division of United Technologies, July 1978, p. 5-3.

63-898 0 - 80 - 32




Figure D-3.—Clarification and Precipitation

R A P I D S E D I M E N T A T I O N

AN D C O N T I N U O U S

G R A V I T Y D R A I N A G E.

.

C L A R I F I C A T I O NI

IN LET

MIX TA N K

/

/ \

C L A R I F I E RS I P H O N

S L U D G E C O L L E C T O R

SOURCE: Assessment of Oil Shale Retort Wastewater Treatment and Control Technology, HamiltonStandard Division of United Technologies, July 1978, p. 5-3

stream mixing tank to aid precipitation (such assodium hydroxide) or coagulation (such as alumor a polyelectrolyte).

q Filters can be used to remove particles and insome cases oil. Some of the more common filter-ing devices are shown in figure D-4. Pressurefilters are generally automatic devices in whichthe contaminated water is sucked inwardsthrough a series of leaves on which a filter cakeforms. The filter may be used to remove par-ticles from dilute wastewaters as the first stage

in a treatment system, or it can be used to de-water the sludge products from other separa-tors. The filter cake is generally very low inmoisture, which eases disposal problems.

Vacuum filtration can also be used to removesuspended particles from wastewater but ismore suitable for dewatering concentratedstreams and sludges. Two vacuum devices areshown in figure D-4, In the rotary vacuum filter,a rotating drum dips into a trough filled withwastewater, and suction is applied to the insideof the drum. Water is drawn through the per-forated surface of the drum and solids are de-posited on the outside as a filter cake. As the

drum rotates, the dewatered sludge is scrapedoff and falls into a receiving trough. A filterpress is functionally similar except that thewastewater is sucked or pumped through aseries of plate-and-frame assemblies. The de-

q

watered sludge is periodically removed fromthe filter medium by mechanical cleaning. Ul-trafiltration, in which the wastewater is forcedthrough a membrane, is often used for separa-tion of oil and water. It is generally limited toseparation of chemically stabilized emulsionsand is not suitable for mechanical emulsions.

In multimedia filters, granular materialssuch as sand forma filtering bed through whichthe wastewater is pumped. The water passesthrough a series of layers with granules of in-

creasingly fine size, The collected solids aresubsequently removed by backflushing withclean water. This filter produces a sludge,rather than a dry cake, which requires addi-tional dewatering before disposal. The multi-media filter is generally more economical thanpressure filters for high flow rates and diluteslurries.Stripping with steam (figure D-5) or with air orflue gases is used to remove NH 3 and sulfidegases from wastewater. The operation is car-ried out in a packed column or a plate column,and two-stage processing is sometimes em-ployed to provide independent recovery of NH3

and sulfuric acid, If the stripper is part of atreatment system that includes biological treat-ment, some NH3 is usually left in the stripperproduct to act as a nutrient for the micro-orga-nisms.



Appendix D–Technologies for Managing Point Sources of Wastewater . 491

Figure D-4.— Filters for Wastewater Treatment

I

A. Pressure fi l ter

I

1’ -

I C Y C L E

D. Filter press

B. Rotary vacuum fi l ter

,“.. . “. .“ . . . .

O I L Y

“ . . . -. . , . : . . . . “ . . ‘ . ,.. . .

. . , . . .

. . . . ~: ..,::,:::’ : ,. . . . . . ~,~. . .

. , . . ,.. . Fmcc . . . : , ‘. . . “ “ , .

wATCm “ “ . . . .- :

‘ : “

C. Ultrafi l tration

I )

- - -

. . ~c O A L

.,

A N

O I L

CO NCm NIRATa

E. Multimedia fi l tration

SOURCE: Assessment of Oil Shale Retort Wastewater Treatment and Control Technology, Hamilton Standard Division of United Technologies, July 1978, PP 5-4, 5-6,5-11, and 5-12

“ .

Adsorption is used to remove dissolved metals, .organic compounds, and many toxic sub-stances. Adsorption with regenerated carbonslurries and with resin particles is shown infigure D-6. Other systems use activated carbon

particles that are contained in a fixed bed, ei-ther without regeneration or with regenerationwithin the column. In all cases, the separationinvolves physical adsorption of the contami- q

n a n t s o n th e su r fa c e s o f th e p a r t i c u la temedium.

Distillation (figure D-7) is a simple process inwhich wastewater is purified by boiling. Theproducts are a very clean steam, which can becondensed with cooling water or in air-cooledcondensers, and a highly contaminated concen-

trate. Very pure water can be obtained, but theprocess has large energy requirements. Coolingwater is also needed in most applications.Reverse osmosis can also recover very purewater from concentrated salt solutions. Somedissolved organic materials can also be re-




Figure D-5.—Steam Stripping

H E A T

I N T E R -

w ASTE W ATE R

V A PO R S

I

W A T E R

SOURCE: Assessment of Oil Shale Retort Wastewater Treatment and Control Technology, Hamilton Standard Division of United Technologies,

July 1978, p, 5-4

moved. A typical reverse osmosis system isshown in figure D-8. Each element in the sepa-ration system contains a membrane that sepa-

rates the clean product (permeate) from theconcentrated waste or residual. The membraneis pressurized on one side, which forces thepure water through the membrane and leavesthe salt and organic contaminants on the otherside. The process is very effective, but prob-lems arise if the wastewater stream containsvery fine suspended solids (colloids) that canclog the membranes and reduce their perform-ance.

q Electrodialysis cells consist of an anode and acathode separated by two membranes—onenear the cathode through which cations (posi-tively charged ions) can pass and one near the

anode that is permeable to anions (negativelycharged ions). A system consisting of severalsuch cells is shown in figure D-9. The waste-water is pumped between the membranes.Upon application of an electric current, the ani-ons migrate through one membrane towardsthe anode and the cations migrate through theother to the cathode. The concentration of ionicspecies in the central chamber is thereby re-duced. The concentrated streams beyond themembranes are the waste products. Electrodi-alysis is very effective in removing dissolvedsalts but it is very expensive because eachsystem must be specifically designed and manu-

factured for the particular application.. Thickeners (figure D-1 O) are used between asludge-generating step (such as clarification)and a sludge-dewatering step (such as vac-uum filtration). These concentrate the sludge

q

q

q

through gentle agitation and thereby reducethe amount of water that must be removed insubsequent processes.Evaporation (figure D-1 1) is a final step for con-centrating solid residues. It is generally ac-complished in evaporation basins, which aresimply lined ponds into which the sludge ispumped and allowed to stand while the mois-

ture evaporates, or in sludge drying beds,which contain a layer of coarse sand over alayer of fine sand over clay or perforatedplastic drainage tiles. Both systems requirelarge areas of land compared to other morecompact devices such as vacuum filtration butthey are inexpensive and require little mainte-nance. Sludge drying beds are faster but moreexpensive. Both systems require mechanicalremoval of the dried sludge, usually with abackhoe or front-loader.

Chemical Methods

Ion exchange is a process in which ions held byelectrostatic charges on the surface of resinsare exchanged for ions with similar charges inthe wastewater. An example is a home watersoftening system in which sodium ions (fromrock salt) are exchanged for calcium ions in thewater supply, thereby reducing the hardness of the water. The process is classified as adsorp-tion because the ion exchange occurs on thesurface of the resin particles and the ions to beremoved must undergo a change of phase: fromthe liquid phase of the wastewater to the solidphase of the resin. By this technique, harmful

ions in the wastewater can be exchanged forthe harmless ions of the resin. Ion exchangecan be used only for removing ions (such asthose from dissolved salts) from solution; it can-not be used for non-ionic contaminants such asorganic compounds and suspended solids. A re-generating ion exchange system is shown infigure D-12. Such a system is suitable for recov-ery of valuable ions from dilute streams. It hasa limited capacity, thus would not be useful forfirst- or second-stage salt removal but wouldmore likely be reserved for “polishing” atreated effluent from another treatment tech-nology.

Wet air oxidation was developed for destruc-tion of organic contaminants. In this process(see figure D-13), wastewater is exposed to airunder elevated temperature and pressure, thuscausing organic compounds to oxidize com-



Appendix D–Technologies for Managing Point Sources of Wastewater • 493

Figure D-6.—Adsorption Systems for Wastewater Treatment

A D S O R P T I O N

IN FLUENT

W A STEW AT E R

R E G E N E R A T E DC A R

BON SLUR RY

I

TR E ATE DE F F L U E N T

FIN ES

‘

REM OVA LSCREEN

i

DEW ATE R I N G

SCREEN

R E G E N E R A T I O N

S T O R A G E FU RN ACE

R E G E N E R A T E D

CA R BON

S L U R R Y T A N K S

F I N E S T O-

W A S T E

A. Carbon adsorpt ion wi th external regenerat ion

II T A N K

B. A two-tank adsorption system

SOURCE: Assessment of Oil Shale Retort Wastewater Treatment and Control Technology, Hamilton Standard Division ofUnited Technologies, July 1978, pp. 5-4 and 5-6




Figure D.7.– Distillation Figure D-8.– R e v e r s e O s m o s i s

CON DENsERW A S T E W A T E R . . q

FEE D

P R E P R O C E S S I N G

F E E D W A T E R T O

D I S C H A R G EOR R E U S E

D R A I N T O W A S T E

T A N KP R O D U C T W A T E R

( PE R M E A T E)

SOURCE: Assessment of Oil Shale Retort Wastewater Treatment and Control

SOURCE: Assessment of Oil Shale Retort Wastewater Treatment and Control Technology, Hamilton Standard Division of United Technologies,July 1978, p 5-7.

Technology, Hamilton Standard Division of United Technologies,July 1978, p. 5-7

Figure D-9.—Electrodialysis

O U T L E T O F C O N C E N T R A T I O N S T R E A M

O I L .

-1 - -

C A T H O D E

C O M P A R T M E N T

A N O D E

C O M P A R T M E N T

S T R E A M S T R E A M

SOURCE: Assessment of Oil Shale Retort Wastewater Treatment and Control Technology, Hamilton Standard Division of United Technologies, July 1978, p. 5-7.



Appendix D-Technologies for Managing Point Sources Wastewater q 49 5

F i g u r e D 1 0 . - M echanical Sludge Thickening

B L A D E

CON D U I T COUNTER F LOW

TO MOTOR

D R IV E U N IT \ \

!N FLUE

CON D

O V E R

A L A R

t

P L A N

BASE

HAN D R A I L

SOURCE: Assessment of Oil Shale Retort Waste Water Treatment anrd Control Technology, Hamilton Standard Division of United Techno log ies , July 1978, p. 5-9




Figure D-11 .—Evaporation Systems for Sludge Drying

A. Evaporation pond

(

A

v

1

- -

I

- _ & _ - .- y ~ -

P L A N W A L K

/

3-1 N COARSE-SAND

F

A

“OR

B. Sludge drying bed

United Technologies, July 1978, pp. 5-10 and 4-11.



Figure D-12. —A Regenerable Ion Exchange System

U N I T

E J E C T O R

I

O U T L E-,

T O W A S T ES U PP O R T I N G B E D T A N K

SOURCE Assessment of 011 Shale Retort Wastewater Treatment and Control Technology, HamiltonStandard Divlsion of United Technologies. July 1978, p 5-14

Figure D-1 3. — Wet Air Oxidation

R EA C T O R

S E P A R A T O R I

A IR

HOLD I N G F E E D H I G H7A N K

A I R E X P A N S I O N

C O M P R E S S O R E N G I N E

E X H A U ST

P U M P

SOURCE. Assessment of 0il Shale Retort Wastewater Treatment and Control Technology, Hamilton Standard Division of United Technologies, July 1978, p 5-14




pletely or at least decomposing them into formsthat are more easily treated. In particular, theprocess can be used to increase the biodegrad-able properties of compounds that are normallyrefractory (resistant) to biological oxidation.The method is very effective but is costly be-cause the highly corrosive environment within

the equipment requires expensive materialsand construction methods.Photolytic oxidation processes (figure D-14) uselight to oxidize organic contaminants. They canbe used in conjunction with chemical oxidizers.One technique that works well in many indus-trial situations is the combination of ultravioletlight and ozone gas. The process has the disad-vantage of requiring relatively long residencetimes.Electrolytic oxidation is similar to electrodial-ysis except that it can be used to oxidize orreduce dissolved contaminants to their gaseousforms. A typical system is shown in figure D-15.

The method is costly to operate, and is general-ly reserved for removing very valuable or veryhazardous substances, It has been used with in-dustrial wastewaters to remove, for example,

chromic acid and cyanide. In oil shale plants, itcould be employed for removing hazardousorganics.Chemical oxidation relies on contacting waste-water with oxidizing chemicals. As mentionedpreviously, chemical oxidation can be com-bined with other oxidizing systems. The exam-

ple of ozone combined with ultraviolet light wasmentioned above. The chemical combination of ozone and hydrogen peroxide has been found towork well with refinery wastes, which are simi-lar to the expected wastes from oil shale proc-essing. Potassium permanganate has beentested with oil shale streams.

Biological Methods

Anaerobic and aerobic digestion.-The princi-pal anaerobic system is the anaerobic digester,which is a closed, heated vessel in which the

microbial population is maintained under an at-mosphere of its own waste gases. Such systemshave a long history of application in treatmentof municipal wastes. A typical digester is

Figure D-14.— Photolytic Oxidation

M I X E R

f

F I R S T

S T A G E

S E C O N D

S T A G E

G A S

T E M P E R A T U R E

C O N T R O L

T E M P E R A T U R E

CONTROL



Appendix D–Technologies for Managing Point Sources of Wastewater Ž 499

Figure D-15.— Electrolytic Oxidation

CATHODE WATER1

1

s

c

C A T H O D E IN F I -U EN T

W A S T E W A T E R

S E T T L I N G

R

SOURCE Assessment of Oil Shale Retort Wastewater Treatment and Control Technology, Hamilton Standard Division of United Technologies. J u l y1978, p 5-15

shown in figure D-16. The illustration shows aflare stack for disposal of the digester gas. It isalso possible to use the gas for many industrial 2.purposes. In municipal systems, the gas is usedas fuel for the compressors that maintain theatmosphere within the unit. Some of the com-

mon aerobic biological systems, in which diges-tion takes place in an oxygen-rich atmosphere,are described below,1. Activated sludge processes treat waste

streams that contain 1 percent or less of sus-pended solids. In this process, flocculatedbiological growths are continuously circu-lated in contact with organic wastewater inthe presence of oxygen. Organic compoundsthat can be decomposed include polysaccha-rides, proteins, fats, alcohols, aldehydes, fat-ty acids, alkanes, alkenes, cycloalkanes, andaromatics. The process is widely used for in- 3,dustrial wastes and is even more common in

municipal treatment plants, It is relativelyinexpensive to fabricate and operate, and isusually cost effective for a variety of organiccontaminants. Its major disadvantages arecomplex control procedures and high main-tenance and power requirements. A typical

activated sludge system is shown in figureD-1 7,

Trickling filters are also commonly used formunicipal wastewater treatment. One sys-tem is shown in figure D-18. In this process,the microbial population lives on the fixed

elements of the filtering medium, and thewastewater trickles past them. Stones werea common medium in the past; plastic ismore common today. Extra nutrients areoften added to the entering waste stream toaccelerate the biodegradation process. Theprocess requires relatively little land areaand can achieve high throughputs with theproper adjustments of acidity, nutrients, andtrace chemicals. It does not work well if thewaste is chemically unstable or if it containssuspended solids.Aerated lagoons are similar to activatedsludge processes except that the micro-orga-

nisms are not circulated. The lagoons areessentia lly stabil ization ponds that areequipped with mechanical agitators andaerators to provide the microbial populationwith uniform conditions and with the oxygenthat they need to grow. About 60 to 90 per-




Figure D-16. —An Anaerobic Digestor

F L A R E

I

I

I N F L U E N T S L U D G E

H E A T

E X C H A N G E R

“ 1

M I X E R S

S U P E R N A T A N T

SLUDGE EFFLUENT

SOURCE: Assessment of Oil Shale Retort Wastewater Treatment and Control Technology, Hamilton Standard Divi-

sion of United Technologies, July 1978, pp. 2-12 to 2-24.

Figure D-1 7.—The Activated Sludge Process

IN F

I R E C Y C L E D S L U D G E

the air. Biodegradation occurs very rapidly.A unique advantage of RBCs is that differentstrains of micro-organisms can be estab-lished on each of the disks, One strain couldbe established on an upstream disk to re-

move the organic compounds that might beharmful to another strain on a downstreamdisk. This could not be done in other biologi-cal systems in which all micro-organisms areexposed to essentially the same environ-ment.



Appendix D–Technologies for Managing Point Sources of Wastewater q 501

Figure D-18.— Trickling. Filter Waste Treatment

CHEM IC A L P H A D J U S T M E N T N I T ROG EN

& P H O S PH O R U S

R A W W A S T ETRICK L 1 N G

FI LTE R

PR IM AR Y

C L A R I F I E R

TR E A T E D

A I R W A S T EW A T ER

SEC ON D A R Y

SLU DG E C L A R I F I E R

SOURCE Assessment of Oil Shale Retort Waste water Treatment and Contro/ Technology, Hamilton Standard Division of United Technologies,

July 1978 p 5-17

Figure D-19.—Aerated-Lagoon Waste Treatment

N U T R I E N T F E E D

M E C H A N I C A L A E R A T O R S

I N F L U E N T L I Q U I D

\

E A R T H C O N S T R U C T I O N )

C LA F? 1 F I E R

E X C E S S S L U D G E

SOURCE Assessment of Oil Shale Retort Wastewater Treatment and Control Technology. Hamilton Standard Division of United Technologies, July 1978 p

5-17

Figure D-20.— Rotating Biological Contractor

S E C O N D A R Y S E TTL I N G

I J

SOURCE Assessment of Oil Shale Retort Wastewater Treatment and Control Technology, Hamilton Standard D iv is ion o f United Technologies. July 1978, P

518




Status of Point Source Water Polluti on Control MethodsThe removal efficiencies, reliabilities, adapt-

abilities, and cost features of some point sourcecontrol technologies are summarized in table D-1.

Removal Efficiency

All of the systems could perform adequately forfirst-stage oil and grease removal, and meetingdischarge standards should be possible if a bio-logical oxidation unit is used for final cleaning. If not, single-stage cleaning in a coalescing filterwould be sufficient. For dissolved gases, any of the stripping techniques should be adequatealone, and a biological oxidation unit could beused for final removal of any residual NH 3. For re-moval of organic compounds, carbon adsorption

would be suitable if used in conjunction with pre-treatment and post-treatment systems. Photolyticmethods should also work, but they are not welldemonstrated. Any filtration method would re-duce suspended solids to acceptable levels. Fordissolved inorganic, clarification would general-ly have low removal efficiency but could be suit-able for removing metals. Distillation would bevery effective for salt removal. Ion exchange orreverse osmosis would also work well, but theirlimited capacities might restrict their use to finalremoval of low-level contaminants. For sludges,sludge drying beds and evaporation basins wouldbe very effective in the semiarid oil shale region.The alternate processes would be much less effec-tive.

Table D-1 .–Relative Ranking of the Water Treatment Methods

Contaminant Technology Removal efficiency, % Relative reliability Relative adaptability Relative cost

Oil and grease Dissolved air flotation 90 Very high Very high MediumCoalescing filter 99 High High MediumClarification 80 Very high Very high High

Dissolved gases Air stripping 80 H i g h -High Medium

Steam stripping 95 Very high High MediumFlue gas stripping High Medium MediumBiological oxidation High Medium Medium Low

Dissolved organics Activated sludgeTrickling filterAerated lagoonRotating contactor

Anaerobic digestionWet air oxidationPhotolytic oxidationCarbon adsorptionChemical oxidationElectrolytic oxidation


90 BOD/20-50 COD

60-95 BOD64 BOD/74 COD99 BOD99 BOD

90 BOD/90 COD95 BOD/61 COD

HighHighMediumHigh

HighMediumMediumMediumVery highMedium

MediumMediumMediumMedium

MediumHighVery highHighVery high

LowLowLowLow

MediumVery highVery highMediumHighHigh

Suspended solids Clarification 50 High High MediumPressure filtration 95 High High MediumMultimedia filtration 95 Very high High Low

Dissolved solids Clarification Low except for metals High Medium MediumDistillation 99 Medium Low Very highReverse osmosis 60-95 Medium Medium MediumIon exchange High High Low HighElectrodialysis 10-40 Medium Medium Very high

Sludges Thickening Product 6-8% solids Very high High MediumAnaerobic digestion Low High Medium Medium

Vacuum filtrationProduct 20-35% solids High High High

Sludge drying beds Product 90% solids Medium Low MediumEvaporation basins Product 95% solids Very high Low LowFilter press Product 35% solids Very high High HighAerobic digestion Low Low Low High

BOD = biological oxygen demand COD = chemical oxygen demand

Adapted from: Assessment of Oil Shale Retort Wastewater Treatment Control Technology, Hamilton Standard Division of United Technologies, July 1978, pp 2-12 to 2-24



. —

Appendix D–Technologies for Managing Point Sources of Wastewater 503

Reliability

For oil and grease removal, the coalescing filterhas the only potentially severe reliability problembecause it tends to clog. For dissolved gases, all of the stripping techniques should be sufficiently re-liable, Biological oxidation is considered less reli-

able because of the need for carefully controlledinlet conditions. For organics removal, chemicaloxidation should be the most reliable; the biologi-cal systems (activated sludge, trickling filters, ro-tating contractors, and anaerobic digestion) shouldalso be satisfactory. All systems for removal of suspended solids should be highly reliable, Fordissolved solids, clarification and ion exchangeare highly reliable. Distillation is downgradedbecause of its potential for corrosion; reverseosmosis because of potential fouling problems;and electrodialysis because it has a relativelyshort history of successful applications. For han-dling sludge, thickening, anaerobic digestion, and

all of the filtration techniques should be highlyreliable,

Adaptability

Few treatment techniques have been extensive-ly tested with oil shale waste streams, and mostwill be adapted directly from other industries.Physical and chemical conditions in which a de-vice will be expected to operate may differ signifi-cantly from those for which it was originally de-veloped and in which it is normally operated. Forexample, a method suitable for petroleum refiner-ies may not work well in the oil shale industry

where it will be exposed to shale fines, organo-metallic complexes, or other contaminants pecu-liar to oil shale wastewaters. Although a systemcannot be fully evaluated until it has been testedunder commercial operating conditions, indica-tions of the expected performance can be ob-tained by examining how easily the technique hasbeen adapted to other new industries significant-ly different from the one for which it was devel-oped.

As shown in table D-1, all of the systems for oiland grease removal are highly adaptable. For dis-solved gases, air stripping and steam strippingare highly adaptable; flue gas stripping is down-graded because suitable gases may not be avail-able. Biological systems are downgraded becausethey may have problems with the high NH 3 con-

centrations in some oil shale wastewaters. Theycould probably be used only with some pretreat-ment system. For dissolved organics, the oxida-tion systems and carbon adsorption are veryadaptable, the biological systems less so becauseof potentially toxic substances and because theyare sensitive to inlet conditions. All methods forremoving suspended solids are highly adaptable.However, problems may be encountered with theremoval of dissolved solids because of possible in-terference from high salt loadings or membraneclogging. The only significant problem with distil-lation is its need for cooling water, which may notbe readily available at oil shale sites. For sludge

handling, thickeners and filters are highly adapt-able. Sludge drying beds and evaporation pondsshould have no technical adaptability problems,but they are downgraded because evaporationwould mean a loss of the contained moisture,which could be recovered with filtration systems.Aerobic digestion is downgraded because some of the components of oil shale sludges may resist bio-logical degradation.

cost

Costs in table D-1 are based on experience with

similar systems in other industries. As indicated,systems with moderate capital and operatingcosts are available for all of the major contami-nants, and many of the lower cost options alsohave reasonable removal efficiencies, reliability,and adaptability. The only potentially seriousproblem is in removal of dissolved solids, wherethe medium-cost systems (reverse osmosis andclarification) have questionable removal efficien-cies.



504 Ž An Assessment of Oil Shale Technologies

Integrated Wastewater Treatment Systems

Generally, no one device is able to remove allthe contaminants from a process stream, Further-more, certain process streams may be combinedbefore treatment or at different stages of treat-ment to take advantage of scale economies.

Treatment systems that have been proposed foroil shale wastewater streams are shown in figureD-21 for mine drainage water, figure D-22 for gascondensate, and figure D-23 for retort conden-sate. These systems and their component unitsare discussed below.

Excess Mine Drainage Water

This water can be used without treatment as aslurry medium for backfilling burnt out in situretorts,’ but sufficient ground water may not beavailable over the lifetime of the plant for this

control option. Additional water might have to beimported from other sites. Another disposal op-tion is reinfection, but for this purpose the watershould be free of suspended solids and contain noconstituents that would react adversely with thewater in the receiving strata. 5 6 7 W h i l e m i n edrainage water could easily be treated to meet

these requirements, reinfection is a costly dis-posal option, because deep wells would be re-quired to avoid contamination of aquifers thatdischarge to the surface, and an extensive pipingnetwork would be needed. It has been suggested

that the reinfection option be used only for veryobjectionable and relatively untreatable wastesand that underground disposal of the relativelyclean mine drainage water would be wasteful in aregion where water is scarce. 17 18

For the option of discharge to a river, dissolvedsolids would have to be reduced to less than 500mg/l, which can easily be achieved by a mem-brane process such as reverse osmosis, as shownin figure D-21. Treatment is not expected to be dif-ficult, but conclusive test data are not yet avail-able. 19 Discharge permits will probably also speci-fy a phenol concentration of no more than 0.001mg/1 and a boron concentration of less than 0.75

mg/1. Specific ion absorbents are available forthese substances and can be used, as suggested inoption A of figure D-21. Alternatively, a second-stage reverse osmosis step may prove more eco-nomical, as suggested in option C of figure D-21. Asingle-stage, high-pH reverse osmosis step mayalso prove adequate, particularly if some of the

Figure D-21 .—Possible Treatment Options for Excess Mine Drainage

Option A

(Reference 8)

Option B

(Reference 9)

Spent Shale

MineBackfill to burned

water out MIS retorts

-r

Mine Pretreatment Reverse*

Phenol BoronAerated

holding pondDischarge

osmosis adsorption adsorption

Option C

(Reference 9)

Sodium hydroxide1

Mine Pre- 9Stage 1 reverse Stage 2 Aerated

m pH Dischargem reverseosmosis adjustment

holdingosmosis pond stream

Option D Mineq

Weak acid*

Steam pHm

Reverseq

Aerated Dischargeion exchange stripping Adjustment osmosis holding pond

(1-wk retention) stream

SOURCE R F Probstein, H. Gold, and R. E Hicks, Wafer Requirernents, Pollution Effects and Costs of Water Sq@y and Treafrnerrt for the Oi/ Sha/e /rrdustry, prepared

for OTA by Water Purificatlon Associates, October 1979




Figure D-22.— Possible Treatment Options for Gas Condensates

Option A

(Reference 10)

SteamGas Oil-water stripping Biological Organic Cooling

condensate separation & NH3 oxidation polishing(if required) Tower

recovery

Option Bq

(Reference 11)q

q .

FilterStream

Gas stripping Chemical Biological& oil-water Filter

condensate & NH3treatment

separationoxidation

recovery.

DesalinizationCarbonsorption

SOURCE R F Probstetn H Gold and R E Hicks, Wafer RequirementsReaufrernenfs, Po//utIorI Effects and Cosfs of Wafer Supp/y and Treatrnenf for the 0// Shale Industry, prepared

for OTA by Water Purification Associates, October ’1979

dissolved salts are first removed by chemical pre-treatment in a weak acid ion exchange degasifieras shown in option D of figure D-21,

An aerated holding pond would be used in anyof the options to dissipate any NH 3 and phenolthat are not removed in the treatment units. Thepond would also serve as an equalization basinfor blending in waters that can bypass the treat-ment train. The size of the bypass stream willvary with the quality of the drainage water, theeffectiveness of the aeration pond, and the cri-teria of the discharge permit.

Gas Condensate

This stream requires treatment for removal of dissolved gases and organics. Dissolved NH 3 willlargely be combined with CO2 in the form of am-monium bicarbonate. Both gases can easily be re-moved by steam stripping. Stripping has beentested in the laboratory with both a synthetic am-monium bicarbonate solution and an actual gascondensate. 20 21 It was found that the smallamount of oil present in the condensate was rap-idly removed in the stripping operation, but evenif an oil-water separator is required before the

stripper (as suggested in figure D-22) separationdifficulties due to emulsification are not ex-pected.

Organic control by biological oxidation has notyet been demonstrated on an actual gas conden-sate stream, The organic mix is different from

that of retort condensates and may prove to bemore or less amenable to biodegradation. Otherprocesses such as resin adsorption, carbon ad-sorption, and wet air oxidation are available fororganics control and may prove adequate in com-bination. Preliminary laboratory investigations onretort condensates suggest that no single process(except possibly wet air oxidation) will be capableof controlling all the organics present.

The use of a cooling tower as part of the treat-ment systems (as shown in option A of figure D-22)would have two advantages. First, experiencewith similar wastewaters has shown that some

degradation of organics occurs in a properlyoperated cooling tower circuit. 22 Second, the vol-ume of blowdown water leaving the cooling toweris one-half to one-tenth that of the makeup water,depending on the number of concentration cyclesused. Final organic polishing, if necessary, cantherefore be done on a smaller, more concen-trated stream. Because the wastewater streamwill previously have been subjected to high-tem-perature steam stripping, air pollution by volatili-zation of organics in the cooling tower is not ex-pected to be a problem. This assumes that any or-ganics created in the biological oxidation step willbe either nonvolatile or nontoxic.

Although salts are not a major contaminant inthe gas condensate stream, desalination by re-verse osmosis could be used to remove inorganicand organics. In option B of figure D-22, a desali-nation step is included to provide a very clean dis-charge stream. An effluent stream could also be



Figure D-23.— Possible Treatment Options for Retort Condensates

Option A

(Reference 12)

Option B

(Reference 13)

Retort

condensate*

Filter & Lime treatment Activateoil-water & ammonia

*carbon

separation removal sorption

Retort Thermalc o n d e n s a t e> treatment sludge

1

Boiler makeup

Sludge

r

Option CRetort

Discharge or re-use(References 14, 15) condensate > treatment

q

IConcentrate

Evaporation pond

Option D(Reference 16)

q

Retort API Chemical Dissolved Steamair

Multimedia Biological Ultra

separator treatment flotation stripping filtration treatment filtrationq q

Carbon Ultravioletfilter sterilizer I

SOURCE: R. F. Probstein, H. Gold, and R. E. Hicks, water Requirement, Pollution Effects and Costs of Water Supply and Treatment fo r the Oi l Shale I n d u s t ry , prepared for OTA by Water Purification Associates,October 1979.



Appendix D–Technologies for Managing Point Sources of Wastewater 507

taken from any intermediate stage of the treat-ment system to provide water for various reuseoptions.

Retort Condensate

The retort condensate stream presents themost formidable treatment challenge. As dis-cussed in chapter 8, this stream is created whenwater and oil vapors condense within in situretorts, and some aboveground retorts if they areoperated at a low top temperature. The conden-sate will be contaminated with oil, dissolvedgases, inorganic salts, and organic substances, allof which will have to be removed.

In the conventional treatment scheme of optionA in figure D-23, oil and suspended solids are firstseparated from the water. Oil-water separationby API units may not be adequate because of emulsions, and some emulsion-breaking technique

will probably be required. The techniques thatwould be appropriate for oil shale wastewatershave not yet been determined.

The addition of lime will facilitate NH3 removaland will also remove calcium, magnesium, andcarbonate ions. NH3 is easily removed by steamstripping, but unlike the gas condensate, the re-tort condensate contains strong acid anions thatwill “fix” the NH3 as ammonium ions, which can-not be directly stripped. Lime addition will ele-vate the pH and convert ammonium to NH3.

23 T hepH elevation is also needed to prevent scaling andfouling of the steam stripping column by carbon-ate precipitates.

Removal of organic substances from retort con-densates has not been adequately demonstrated.Activated carbon adsorption (option A in figureD-23) would remove only about half of the organ-ics and would be expensive, given the high organ-ic concentrations found in retort condensates. 24 2 5Biological treatment (option D) has been sug-gested for control of organics, but complete re-moval by biological processing may not be achiev-able. The two major problems with biologicaltreatment are the presence of resistant (biore-fractory) and toxic materials. It is expected thatas much as half of the organic matter in retortwater will be biorefractory and that adequate re-

moval may not be possible even with novel proc-ess modifications such as the addition of pow-dered activated carbon to the biological unit. Lab-oratory tests have shown that the addition of pow-dered activated carbon to the aeration basin in anair-activated sludge biological system improves

organics removal by only about 10 percent, indi-cating that much of the biorefractory organicmatter is not adsorbed on carbon. Polymeric res-ins have been shown to facilitate removal of or-ganics from retort condensates,26 but it is notknown whether the ones removed are those thatare resistant to biological and activated carbon

treatment.The inhibition of biological action by toxic sub-

stances is also expected to be a problem, The tox-ics may be either organic or inorganic, and can beexpected to be different in the condensates fromdifferent retorts. Their characteristics and con-centrations may even change with time if retort-ing conditions are not constant—a normal situ-ation in MIS processes. Even with all of its poten-tial disadvantages, biological oxidation couldprove more economical and more effective thanother processes (such as wet air oxidation) whencombined with appropriate pretreatment and pol-ishing steps.

Wet air oxidation removes a much wider varie-ty of organics but it is also more expensive. In thisprocess, organic material in water is oxidized byair at about 500° F (260° C). The water is pressur-ized to prevent boiling. The reaction takes about30 minutes and a pressure vessel is required thatis large enough to contain the water for thislength of time. The cost of wet oxidation is notstrongly dependent on the concentration of thewaste, and unlike biological treatment it can becost effective for very concentrated wastes. Wetair oxidation also has several technical advan-tages, Because it relies on chemical oxidation, theorganic material that is to be destroyed does not

have to be biodegradable. In fact, biorefractorymaterials are often converted to biodegradablesubstances, and a biological process could be ef-fectively used as a polishing step. No data havebeen published on the performance of a wet airoxidation process with oil shale retort conden-sates, but an investigation has been initiated.27

Reverse osmosis membranes (option C in figureD-23) are also available for organics control, 28 butrecent tests have shown that considerable pre-treatment will be required to provide a feed thatwill not plug or foul the membranes, 29 In fact, apretreatment system similar to the treatmenttrain of option A in figure D-23 may be required

for very dirty condensates. If this is done, then itis not clear that a final reverse osmosis step willbe required to provide an effluent suitable forsome of the low-quality reuse options. Neverthe-less, reverse osmosis is of interest because it alsoprovides a means for control for some of the inor-




ganic contaminants for which lime softening is notadequate. Ion exchange demineralization afterorganics removal is an alternative to reverseosmosis, but its costs escalate rapidly with in-creasing salt concentrations in the feed.

It is apparent that even if the retort condensateis to be treated to only the low-quality levels re-

quired by some re-use options, an elaborate treat-ment system similar to that shown as option D infigure D-23 will be required. Even here additionaltreatment steps may be required. API separatorsmay not be adequate, and an ultrafiltration stepupstream of the steam stripper may be needed toremove emulsified oil and large organic mole-cules. As discussed above, biological oxidationand carbon adsorption will not adequately controlthe remaining organics, and resin adsorption orwet air oxidation steps may be required. An addi-tional processing step to remove inorganic mayalso be required for some re-use options.

In view of the difficulty in treating the retort

condensate (option B in figure D-23) in which thetreated water is used to raise steam for retortingis the most attractive. Volatilized organics will beincinerated in the retort, and other substancescan be removed in a concentrated sludge for dis-position at a hazardous-waste disposal site. Astripping pretreatment step may be needed toavoid accumulating NH 3 and CO2 in the thermalsludge device. No information has been publishedon the feasibility of a thermal-sludge steam rais-ing process fed with retort condensates. Scalingand fouling may be problems unless appropriatepretreatment steps are used.

Other Wastewater Streams

The two other major streams are the coker andhydrotreater condensates from the shale oil up-grading section. Compositions of these streamsare not known, but they should be somewhat simi-lar to the gas condensate. The exception is the

concentration of dissolved gas because, in theabsence of CO2, the NH3 will probably react withH 2S to form ammonium hydrogen sulfide. Differ-ent steam stripping conditions will be required inthat more stages or more steam will be needed toremove H2S. Modifications should not be extremebecause, unlike in the retort condensate, thereshould be no NH3-fixing inorganic anions present.The treatment systems can be expected to be simi-lar to any of the options shown in figure D-22.

Blowdown streams, regenerant streams, con-centrates, and sludge products from water treat-

ment processes must also be handled. If a thermalsludge process is included in any water treatmenttrain, it could be used to reduce the reverseosmosis concentrates and ion exchange regener-ant streams to a disposable sludge. If not, vaporcompression evaporators may be used. Thesehave been successfully demonstrated on a com-mercial-scale at, for example, electric power gen-erating stations. Because cooling towers willprobably be operated with few cycles of concen-tration, blowdown streams should not have highsalt concentrations, and should be suitable fordust control and shale disposal operations.

Water Management Plans for Oi l Shale Faci l i t ies

Complete water management plans must con-sider supply, treatment, waste recovery and re-moval, and ultimate disposition. Figures D-24through D-26 are flow sheets that show how wa-ter would be used, treated, and disposed of inthree typical oil shale facilities. The flows into,within, and out of the plants are indicated in gal-lons per minute.

Figure D-24 is a water management plan for anaboveground direct facility that uses Paraho re-

torts. The major sources of water are the Colora-do River, contaminated runoff from the facilitysite and its associated disposal area, and gas con-densates from the retorting section. No upgradingfacilities are included, so there are no upgradingcondensates. The total water inflow is 2,357 gal/

rein, of which about 40 percent is lost to the at-mosphere through evaporation within the facility.The rest is eventually used for dust control and inthe solid waste disposal area for spent shalemoistening, compaction, and revegetation. Theprincipal components of this water are treatedriver water, sanitary wastes, blowdowns, runoff,service water, and condensates.

Figure 1)-25 is a plan for an aboveground in-direct plant that uses TOSCO II retorts. Because

the retorts are indirectly heated, and because up-grading facilities are included, water require-ments are substantially higher than for the Par-aho plant. The total inflow is 7,386 gal/rein fromthe Colorado River, from surface runoff, and fromgas condensates and upgrading condensates.



Appendix D–Technologies for Managing Point Sources of Wastewater q 509

Figure D-24.— Major Streams in a 50-000-bbl/d Aboveground Direct (Paraho) Oil Shale Plant (gal/rein)

Colorado River water

1883

(7)Domestic

watersystem

/ q

@

16

Biologicaltreatment

663 686Clarification

I

BFW ~ CWtreatment - treatment

I17

(2)

Steamsystem

BD

Coolingtower

B D

BFW = Boiler Feed WaterCW = Cooling Water

( ) = Losses

s = Sludge

TW = Treater Waste

BD = Blowdown

GC = Gas Condensate

Revegetation

Dust Shale

control disposal

(25) 221 791Equalization

43water

system &

Oil/water 156

separationb

Runoff and 138

Ieachates

(29)

Retorting 336 307gas treatment GC Treatment

— \

SOURCE R F Probsteln, H Gold, and R E Hicks, Water Requlrerrrents, Po//ufIonEflects and Costs of Water SUPP/y an d Treatrrrent for the 0// Shale /fldus-try, prepared for OTA by Water Purl flcatlon Associates, October 1979

About 40 percent of the water is lost throughevaporation. The rest is eventually used for dustcontrol, or finds its way to the spent shale pile.

Figure D-26 is a plan for an MIS facility that islocated in a ground water area, Excess minedrainage water is produced, and over 70 percentof it is reinfected. The rest is used in the plant,together with retort condensates, gas conden-sates, and surface runoff, The plant uses a ther-mal sludge system to process the retort conden-sate and to generate steam for injection into the in

situ retorts. The system produces no liquid efflu-ent. The total net inflow is about 5,059 gal/rein, of which 34 percent is lost through evaporation and34 percent is converted to steam for the retorts.The rest is used to control dust and for disposal of the mined raw shale.

In summary, the aboveground direct plant willdispose of about 604 gal/min of treated waste-water and treated condensates in the spent shaledisposal pile. An additional 22 I gal/rein of treatedwastewater will be used for dust control. The



510 Ž An Assessment of 0il Shale Technoiogies

Figure D-25.—Major Streams in a 50,000-bbl/d Aboveground Indirect (TOSCO II) Oil Shale Plant (gal/rein)

Colorado River water

2177 2198 3937Clarification

watersystem

Biologicaltreatment

1

BFW ~

treatment

(1191)

Steamsystem

2400

Cwtreatment

(1630)

Coolingtower

BD

Revegetation

Dust Shale

control disposal w

Retortinggas treatment

upgrading

GC

1072 ~ (53)

Stripping andN H3 recovery (6)

503 Organics 497

(20)removal.

/ 631

17water .

37 system Oil/water 134r separation

\

Runoff and 117Ieachates/ v

BFW = Boiler Feed WaterCW = Cooling Water

( ) = LossesS = SludgeTW = Treater WasteBD = Blowdown

GC = Gas CondensateRC = Retort Condensate

SOURCE: R. F. Probstein,H. Gold, and R. E. Hicks,Water Requ/refnenrs, Pollutlorr Eflecfs afl~ COS@ of water SUPPIY and Treatment for the 0// Shale hrdustry, preparedfor OTA by Water Purification Associates, October 1979.




To reinfection

Figure D-26.— Major Streams in a 50,000-bbl/d MIS Oil Shale Plant (gal/rein)

Mine drainage water

7656

treatment

924

14

Biologicaltreatment

14

380

(13)

m

6539 ‘ ‘ 737A A ClarificationY

(5)

treatment treatment

Coolingtower

Steamsystem

882

wL

Revegtation Dust Shalecontrol disposal

(26)Equalization

-42

watersystem \

Oil/water 141

separation \

Runoff and125

4

(68)

\

( ) = Losses

s = Sludge

SOURCE: R.F. Probstein, H Gold, and R E Hicks, Water Requirements, Pollution Effects and Costs of Water Supply and Treatment for the Oil Shale Industry, preparedfor OTA by Water Purification Associates, October 1979





APPENDIX E

Acronyms, Abbreviations, and Glossary

acre-ft

acre-ft/yrAGRAPIAQCRARCOBACTBaPBATbblbbl/dBLM

BODBPT

Btucmcm/hc oc o 2

COSCRSCRSP

CRSS

CS2

CWACOG

CZMADDPDEIDLA

DNR

DODDOEDOIDRIEISEPAERDA

FAPRS

Acronyms and Abbreviations

—acre-feet

—acre-feet per year—aboveground retorting—American Petroleum Institute ‘—Air Quality Control Regions—Atlantic Richfield Co,—best available control technology—benzo(a)pyrene—best available technology—barrel(s)—barrels per day—Bureau of Land Management,

Department of the Interior—biochemical oxygen demand—best practicable control

technology currently available—British thermal unit—centimeter—centimeters per hour—carbon monoxide—carbon dioxide—carbonyl sulfide—Congressional Research Service—Colorado River Storage Project

Act of 1956—Colorado River System Simulation

Model—carbon disulfide—Colorado West Area Council of

Governments—Coastal Zone Management Act—detailed development plan—Development Engineering, Inc.—Department of Local Affairs

(Colorado)—Department of Natural Resources

(Colorado)—Department of Defense—Department of Energy—Department of the Interior—Denver Research Institute—environmental impact statement—Environmental Protection Agency—Energy Research and Development

Administration—Federal Assistance Program

Retrieval Systems

FLPMA

FmHAFMSHA

FRCftft2

ft3

FUND

FWPCA

galgal/reingal/tonGOREDCO

HCHEW

H2SIFSJBC

mg/lmg/m3

mi2

MISmm

mmho/cm

MSHA

µgµg/m3

NAAQS

NASNEPA

NH3

NIOSH

NOX

NOSR

—Federal Land Policy and

Management Act of 1976—Farmers Home Administration—Federal Mine Safety and Health

Amendments of 1977—Federal Regional Council—feet—square feet—cubic feet—Foundation for Urban and

Neighborhood Development—Federal Water Pollution Control

Act of 1972—gallon—gallons per minute—gallons per ton—Gulf Oil Real Estate Development

c oo

—hydrocarbons—Department of Health, Education,

and Welfare—hydrogen sulfide—Institute Francais du Petrol—Joint Budget Committee of the

General Assembly (Colorado)—milligrams per liter—micrograms per cubic meter—square miles—modified in situ—millimeters

—milliohms per centimeter(conductivity)

—Mine Safety and HealthAdministration

—megawatt—microgram—micrograms per cubic meter—National Ambient Air Quality

Standards—National Academy of Sciences—National Environmental Policy Act

of 1969—ammonia—National Institute for

Occupational Safety and Health—nitrogen oxides—Naval Oil Shale Reserve

513




NPCNPDES

NSPS

O3

OCSOMBOSEAP

OSHA

OxyPADD 2

PAHsPbp/mPOMPSD

QDAQuadRARE II

RCRA

R&D

—National Petroleum Council—National Pollutant Discharge

Elimination System—New Source Performance

Standards—Nevada, Texas, and Utah—ozone

—Outer Continental Shelf —Office of Management and Budget—Oil Shale Environmental Advisory

Panel—Occupational Safety and Health

Administration—Occidental Petroleum—The Petroleum Administration for

Defense District 2—polycyclic aromatic hydrocarbons—lead—parts per million—polycyclic organic matter—prevention of significant

deterioration—Quality Development Associates—1 quadrillion = 1015 Btu—Roadless Area Review and

Evaluation (Forest Service)—Resource Conservation and

Recovery Act of 1970—research and development

RISEscf SCOT

SEIO

SIP

SMCRASMRso,SOHIOSRITDSTISton/dToscoTSCA

UBCOG

USBMUSBRUSFWSUSGSUSPHSWPAWPRS

—rubble in situ extraction—standard cubic foot—Shell Claus Offgas Treating

process—Governor’s Socio-Economic Impact

Office (Colorado)—State implementation plan

—Surface Mining Control andReclamation Act of 1977—standardized mortality ratio—sulfur dioxide—Standard Oil Co. of Ohio—Stanford Research Institute—total dissolved solids—true in situ—tons per day—The Oil Shale Corp.—Toxic Substances Control Act of

1976—Uintah Basin Council of

Governments

—U.S. Bureau of Mines—U.S. Bureau of Reclamation—U.S. Fish and Wildlife Service—U.S. Geological Survey—U.S. Public Health Service—Water Purification Associates—Water and Power Resources

Service

Adit: A nearly horizontal opening to a mine. Calcite: The mineral calcium carbonate, found in

Aquifer: An underground formation containingwater.Aromatic hydrocarbon: A compound of carbon

and hydrogen characterized by a ring of sixcarbon atoms, e.g., benzene.

Best available control technology (BACT): Themost advanced control technology that can beused for new sources of pollution. Required fornonattainment regions (where air pollution pre-sents a danger to the public health) by theClean Air Act as amended in 1977.

Biochemical oxygen demand: A chemical measureof the power of an effluent to deoxygenatewater.

Bitumen:The smaller (about 10 percent) soluble,organic component of oil shale.

Breakeven price: The constant price at whichshale oil syncrude would just earn its minimumrate of return.

nature in the form of limestone, marble, orchalk.Catalytic cracking: A process of breaking down

petroleum hydrocarbons by heating them in thepresence of a catalyst. The products are hydro-carbons of lower molecular weight, havinglower boiling points, e.g., gasoline.

Coking: One of the processes used to upgradeshale oil and improve its transportation proper-ties. The oil is thermally decomposed at hightemperatures (900° to 980° F or 480° to 525° C)forming coke as a solid product.

Criteria pollutants: Under the Clean Air Act, thereduction and prevention of air pollution is reg-

ulated by measuring five criteria pollutants:particulate, sulfur oxides, carbon monoxide,nitrogen dioxide, and photochemical oxidants.National Ambient Air Quality Standards weredeveloped for six pollutants associated with the



Appendix E–Acronyms, Abbreviations, and Glossary 515

criteria pollutants. Sulfur oxides are measuredby sulfur dioxide and photochemical oxidantsare measured by ozone and hydrocarbons,

Crude short: The condition when a company haslimited or inadequate access to crude petro-leum.

Dawsonite: The mineral, dihydroxy sodium alumi-

num carbonate. It is a potential source of alu-mina, which can be converted to aluminum.

Deposit: A natural accumulation, e.g., of coal,iron ore, or oil shale.

Deposit dewatering: The removal of ground waterfrom an oil shale deposit.

Distillates: The liquid products condensed fromvapor during distillation (as of petroleum),

Light distillates contain the lowest boilingconstituents of the petroleum, from which gas-oline is produced.

Middle distillates contain higher concentra-tions of the high boiling constituents, fromwhich diesel and jet fuels are produced.

Heavy distillates contain higher concentra-tions of the high boiling constituents, fromwhich lubricating and residual oils are pro-duced.

Distillation: A separation process in which a sub-stance is vaporized, and the vapor collectedafter condensation as a liquid.

Diversion: A channel constructed to divert waterfrom one source or body of water to another.

Interbasis diversion-Moving water fromone major hydrologic basin to another.

Intrabasin diversion—The redistribution of water within a major hydrologic basin.

Dolomite rock: Similar to limestone but composed

mainly of the mineral, calcium magnesium car-bonate (Ca Mg (CO3)2).Electrostatic precipitator: A device that uses an

induced electrical charge to recover fine parti-cles from a flowing gas stream.

Environmental impact statement (EIS): The Na-tional Policy Act of 1969 requires that an en-vironmental impact statement be prepared for“major Federal actions significantly affectingthe quality of the human environment.”

Fischer assay: Small samples of crushed oil shaleare heated to 932° F (500° C) under carefullycontrolled conditions. The oil yield by thismethod is the standard measure of oil shale

quality.Fracturing: Breaking up a deposit by means of chemical explosives, electricity, or injectinghigh-pressure air and water to increase its per-meability to fluid flow.

Fugitive dust: Particulate matter discharged tothe atmosphere in an unconfined flow stream.

Gas oil: A liquid petroleum distillate with a viscos-ity and boiling range between kerosene and lu-bricating oil (450° to 500° F or 230° to 260° C).

Ground water aquifer: Water contained under-ground in the interstices of soil and rock, ob-

tainable through wells or springs.Halite: The natural mineral form of sodiumchloride (NaCl).

High-Btu gas: Gas with a high heating value, e.g.,pure butane has a heating value of 3 , 2 0 0Btu/ft 3.

Hydrocarbons: Organic compounds containingonly carbon and hydrogen.

Hydrocracking: The breaking apart of relativelyheavy petroleum hydrocarbons into smaller,lighter molecules by means of heat in thep re se n c e o f h y d ro g e n a n d u s i n g s p e c i a lcatalysts .

Hydrologic basin: The entire area of land drained

by a river and its tributaries.Hydrotreating: The hydrogenation of crude shaleoil to convert it to -synthetic crude oil (syn-crude).

Kerogen: The organic oil-yielding material pres-ent in oil shales. It is not a definite compoundbut a complex mixture varying from one shaleto another, and is only slightly soluble in or-dinary organic solvents,

Low-Btu gas: Gas with a relatively low heatingvalue (about 100 Btu/ft3), e.g., producer gas,

Locatable minerals: Minerals on public land thatcan be transferred to private ownership by theprocess of staking claims and filing for patents.

Marlstone: A hardened mixture of dolomite andcalcium carbonate.Middle distillate cracking and reforming: Break-

ing down and converting straight chain petro-leum hydrocarbons into cyclic and aromatic hy-drocarbons, by means of heat, pressure, andcatalysts (usually in the presence of hydrogen).Used to produce fuels with high octane ratingfrom lower grade products.

Mining:Block caving— Sections of the area being

mined are undercut and then allowed to cavein, thus crushing the material being mined.

Continuous—A machine cuts and loads ore

from a mine face in a continuous operation,without the use of drills and explosives.Long-wall—The ore seam is removed in one

operation along a working face that maybe sev-eral hundred yards long. The mine roof col-




lapses as the working face advances throughthe ore body. The technique is commonly usedfor coal mining, especially in Great Britain.

Open pit—The overburden is drilled andblasted loose over a large area and removed toexpose the oil shale beds. These are thendrilled and blasted.

Room-and-pillar-Some shale is removed toform large rooms, and some is left in place, aspillars, to support the mine roof.

Solution—The injection of fluids into the for-mation to dissolve soluble salts from among theoil shale layers, thereby creating a honeycombpattern of voids.

Strip—The overburden and deposit are re-moved with a dragline—a massive type of scraper shovel.

Subsidence—The mine roof is allowed to col-lapse into the working area after the ore isremoved.

Mining bench: A shelf or ledge made in a mine

tunnel or working when an upper section is cutback.Modular retort: The smallest unit that would be

used in commercial practice . I ts capacityvaries with the developer.

Molecular weights: The relative mass of a mole-cule as compared with that of an atom of hydrogen. It is calculated by adding up theweights of the molecule’s constituent atoms.

Mucking: Removal material broken up in the min-ing process.

Nahcolite: A mineral chemically identical to com-mercial baking soda (sodium bicarbonate).

New Source Performance Standards (NSPS): The

Clean Air Act requires that the EnvironmentalProtection Agency set standards of perform-ance for major new potential sources of pollu-tion, and that such facilities use the most ad-vanced technology available for pollution con-trol.

Nonattainment area: The air in the region doesnot satisfy the National Ambient Air QualityStandards as established under the require-ments of the Clean Air Act.

Nondegradation area: The air in the region iscleaner than that required by the National Am-bient Air Quality Standards.

Nonmethane hydrocarbons: All the organic com-

pounds of carbon and hydrogen that are notstraight chain, saturated (no more hydrogencan be added) molecules in which the carbonatoms are joined to each other by single bonds.

Nonpoint source: A site from which there is un-

collected runoff, e.g., a mining operation, con-struction site, or agricultural area.

Olefin hydrocarbons: Unsaturated (lower ratio of hydrogen to carbon) compounds of carbon andhydrogen having at least one double bond.

Onstream factor: The fraction of the time that aplant could be expected to operate at design ca-

pacity.Organic compounds: The compounds of carbon.These fall roughly into two classes: compoundscontaining only carbon and hydrogen (hydro-carbons), and compounds in which one or morehydrogen atoms have been replaced by otherelements or groups of elements (heteroatomiccompounds).

Overburden: The material overlying a depositthat must be removed before surface mining.

Paraffin hydrocarbons: Saturated compounds of carbon and hydrogen having only single bonds.

Particulate: Minute separate airborne particles,one of the criteria pollutants under the Clean

Air Act,Perfection of water right decree: Meeting all therequirements under applicable law to establishlegal rights to the water—implies not onlyownership but also actual use.

pH: A means of expressing the acidity or alkalini-ty of a solution. At normal temperatures, purewater has a pH of about 7 (neutral); the pH of astrong acid is about 1 and that of a strong baseabout 14.

Photochemical reactions: Chemical reactions in-duced in the atmosphere by ultraviolet radia-tion from the Sun.

Phreatophyte: A deep-rooted plant that obtainswater from the water table or the layer of soil just above it.

Placer deposit: A deposit of alluvial materialfound along and in riverbanks, streambanks,and in beach sands.

Polycyclic organic compounds: A compoundwhose molecular structure contains two ormore rings (usually fused) that are mostly con-structed of carbon atoms (e.g., anthracene).

Pour point: The lowest temperature at which aliquid will flow.

Prevention of significant deterioration (PSD): Astatutory program of the Clean Air Act aimedat preserving the existing high air quality in

those areas having the cleanest air (nondegra-dation regions).Pyrolysis: The breaking down of complex mate-

rials into simpler units by means of heat.Radionuclide: A radioactive atom.



Appendix E–Acronyms, Abbreviations, and Glossary 517

RARE II: The Roadless Area Review and Evalua-tion process being undertaken by the ForestService for all potential wilderness areas in thenational forest system.

Refluxing: Distillation in which the liquid is con-densed with the rising vapor in a fractionatingcolumn.

Reserve: A resource that can be extracted fromthe deposit and processed to yield productsthat can be marketed at a profit.

Resource: A naturally occurring substance withproperties that can be put to use.

Retort: The vessel or container in which the oilshale is pyrolyzed to recover the shale oil.

Retort plant:Commercial scale—A commercial-size oil

shale facility would use several modular re-torts in parallel to obtain the desired produc-tion rate,

Pilot-plant scale—About one-hundredth of the capacity of a commercial scale module.

Pioneer commercial scale—Would containseveral commercial size modules

and deposited in layers by water, wind, or ice(e.g., sandstone, limestone, shale.)

Shale oil syncrude: A synthetic crude oil pro-duced by adding hydrogen to crude shale oil,comparable with the best grades of conven-tional crude.

Spent shale: The retorted residual material after

the oil and gas products are removed. Its prop-erties vary with the type of retorting procedureused; indirectly heated retorts product a car-bonaceous spent shale, while directly heatedretorts produce a material essentially strippedof carbon.

Spot market price: The nonposted price for a bar-rel of oil,

Syncrude: Synthetic crude oil, produced from anysource other than conventional petroleum.

Trona: A hydrated mixture of sodium carbonateand sodium bicarbonate. It is a source of sodaash for glass production.

Upgrading: The treatment of crude shale oil to im-

prove it to a transportable refinery feedstock,e g hydrotreating