2009 Program and Abstracts - GCSSEPM Home€¦ · shale gas. As a result according to the Potential Gas Committee (June 18, 2009), the nation’s estimated gas reserves have surged

ii Program and Abstracts

Unconventional Energy Resources: Making the Unconventional Conventional iii

Unconventional Energy Resources: Making the Unconventional Conventional

29th Annual Gulf Coast Section SEPM FoundationBob F. Perkins Research Conference

2009

Program and Abstracts

Houston Marriott WestchaseHouston, Texas

December 6–8, 2009

Edited by

Tim CarrTony D’AgostinoWilliam Ambrose

Jack PashinNorman C. Rosen

iv Program and Abstracts

Copyright © 2009 by theGulf Coast Section SEPM Foundation

www.gcssepm.org

Published December 2009

The cost of this conference has been subsidized by generous grants from British Petroleum, Hess Corporation, Shell Exploration and Production Company, and Statoil.

http://www.gcssepm.org

Unconventional Energy Resources: Making the Unconventional Conventional v

Foreword

Driving down from Pittsburgh, Pennsylvania toMorgantown, West Virginia this week, on a clearNovember night, I could spot three drilling rigs work-ing in a distance of thirty miles of highway. Given thathills of Appalachia tend to hide a lot of activity, this isastounding. I would hazard a guess that each of theserigs were targeting a resource (Marcellus Shale) thattwenty-five years ago I had not given a second ofthought about for one of my former employers, forwhen I was working on the eastern overthrust.

As stated by the late Nobel Laureate RichardSmalley, providing for our world's future energy andresource needs is one of the great challenges of thiscentury. Increasing world populations (6.5 billion now,topping out at 9 billion in 2075) justly demand higherstandards of living that require more access to energy.At the same time, increased energy demand will needto be accompanied by less pollution, especially emis-sions greenhouse gases. Sufficient energy is critical toour industrial, cultural, and health infrastructure,including agriculture, transportation, information tech-nology, communication and many of the essentials thatour civilization takes for granted.

The United States is a member of the Organiza-tion for Economic Co-operation and Development(OECD), which consists of the 30 wealthiest countriesin the world (mean income over $33,000 per year in2006). I usually refer to this as the rich boys club. Thepopulation of OECD countries number about one bil-lion people and, on average, each year each individualconsumes 217 million BTUs (10.8 tons of coal or 374barrels of oil equivalent). On a per capita basis this isabout 59 pounds of coal or about a barrel of oil per day.OECD countries represent only 17% of the world'spopulation, but we consume 51% of the world's energy.

China, India, most of Latin America, and the restof Asia have been industrializing with astonishingspeed, yet their total energy consumption is only nowbeginning to increase rapidly. The per-capita annualenergy consumption of the 83% of humanity with aver-age incomes under $33,000 was 8.5 million BTUs perperson, barely 4% of the average of the wealthiestcountries - approximately 1.5 pints of oil or 2.25pounds of coal equivalent per person per day. Numer-ous studies show that per capita annual consumption ofabout 100 million BTUs is necessary to provide barelyminimal living standards in which infant mortality ratesbegin to decrease and approach 20 per thousand, andfemale life expectancies at birth begin to exceed 70

years. (For example, see Vaclav Smill, Energy at theCrossroads, 2003.) If the per capita energy consump-tion in the developing world were increased to only50% of that presently consumed by the citizens ofindustrialized nations, and if everyone in the prosper-ous industrialized nations were to conserve down tothat same level - that is, if everyone on earth used only100 million BTUs of energy per year - energy produc-tion worldwide still would have to increase by morethan 40% to 650+ quadrillion BTUs ofenergy(QBTU’s) compared to present worldwide pro-duction of approximately 460 QBTUs. This is atremendous challenge that can only be met by increas-ing our ability to tap resources that were previouslyunobtainable.

Energy, economy, and security are inextricablylinked. Secure supplies of energy are a depletingresource subject to short-term disruption by politicalevents. Energy resources must be constantly replen-ished through discovery of new resources andapplication of new technologies. However, attentionshould not be solely focused on conventional sourcesfor oil and gas. Unconventional resources potentially

could ensure supply of low-cost fuel well into the 21st

century. An array of unconventional energy sourcessuch as heavy oils, tar sands, oil shale and gas hydrates,as well as conventional, deeper ocean hydrocarbonresources, are being brought into play. Technological

advances have opened up oil and natural gas resourcesthat were previously unobtainable, including deep-

water areas (depths >305 m) coal-bed methane, and gas

in shale, that do not readily release their gas to wells.New unconventional resources such as oil shale and gashydrates are poised to be delivered from theoreticalresource to potential resource. The United States, asvalidated by history, has been the world leader in thedevelopment of technological solutions in manyspheres of human endeavor and is leading the wayagain in developing and deploying the appropriateenergy technologies to transform unconventionalresources into conventional reserves.

In the opening keynote address, from Scott Tin-ker and Eric Potter of the Texas Bureau stressunconventional resources are positioned to provide akey source of energy as alternative, non-fossil energysources are developed at commercial scale. They stressthat unconventional reservoirs are predominantly in“primary” production phase. Similar to conventional

vi Program and Abstracts

oil and gas fields in the 1940’s and 1950’s, only a smallpercentage of the total global in-place unconventionalresource base has been produced. There remains muchto learn about unconventional resource systems andfurther research and development is required. Thistheme is reiterated in many of the papers that follow.

We have a series of five great papers on gashydrates, which present formable technological chal-lenges, but provide a potentially vast global resource to

meet mid- and long-term energy demands. A series of

field programs in the last decade, in conjunction with

experimental studies and numerical simulation, show

that it should be possible to extract the most favorablegas hydrates with existing technologies. There may be20 quadrillion cubic meters of methane trapped withinglobal deposits. Twenty five percent of this resource isenough natural gas to supply the United States at cur-rent levels for more than 7,500 years.

Seven papers address the hot gas shale plays inmultiple basins across the United States and the world.New technologies are unlocking substantial amounts ofshale gas. As a result according to the Potential GasCommittee (June 18, 2009), the nation’s estimated gasreserves have surged an unprecedented 35 percent to1,836 trillion cubic feet. Much of this increase is attrib-uted to reevaluation of shale-gas plays in theAppalachian basin and in the Mid-Continent, GulfCoast, and Rocky Mountain areas. Tapping this previ-ously inaccessible resource is in full swing in theUnited States and is spreading to the rest of the world,raising hopes of a huge expansion in global reserves.One recent study cited in the New York Times (October10, 2009, page A1) calculates that the recoverable shalegas outside of North America could turn out to beequivalent to 211 years worth of natural gas consump-tion in the United States at the present level of demand,and maybe as much as 690 years. In 2008, marketedUS natural gas production was at its highest level insince 1974. In 2009, we may see an all time US recordin marketed gas production. It is pretty clear that it isunconventional production that is providing the pro-duction boost.

In day two of the conference, we continue thetheme of turning unconventional resources into con-ventional reserves and providing the energy for thefuture. Twelve papers cover coal-bed methane and tight

gas and oil shale. Today tight gas makes up a signifi-cant portion of the nation's natural gas resource base,with the Energy Information Administration (EIA, Jan-uary 2009) estimating that 309.58 Tcf of technicallyrecoverable tight natural gas exists in the U.S. In 2008according to the EIA, coal-bed methane productionfrom basin across the US reached almost 2 TCF whilewere reserves approached 21 TCF. In oil shale theremay be 1.2 trillion to 1.8 trillion barrels locked in theshale formations that underlie a vast region stretchingfrom western Colorado to eastern Utah to southernWyoming. Not all of that oil is recoverable, but bysome of estimates, 800 billion barrels might be. That’smore than three ‘Saudi Arabias’ worth of oil andenough to serve current U.S. demand for a century.

In summary, whether or not unconventional natu-ral gas and oil production will grow in the future willdepend on price, technology, and access. We have littlecontrol of two of these components, but conferences

such as the 29th Annual Gulf Coast Section SEPMFoundation Bob F. Perkins Research ConferenceUnconventional Resources: Making the Unconven-tional Conventional can help to advance thetechnology.

I am only the convener of the conference andwould like to stress that this was a team effort. First Iexpress my gratitude to the authors of the papers pre-sented during the conference. They have produced aninformative statement of the promise and technicalchallenges of transforming our unconventionalresources into marketed energy. Their ideas will be ofgreat value to their peers all around the industry.

My thanks to the Trustees of the Foundation andNorman Rosen, who advanced the idea of the sympo-sium focused on unconventional resources. Normprovided continuous encouragement (gentle nagging),and the final editing of the papers that make up the vol-ume. Bill Ambrose, Tony D’Agostino, Jack Pashin andFrank Walles were reviewers par excellence andworked to round up many of the papers. My thanks alsoare due to Paul Weimer of UC Boulder who worked todrum up additional papers. My considerable gratitudealso goes to Gail Bergan of Bergan et al., Inc., who hadto wait and wait for us to provide the final manuscriptsfor the abstracts and published volume.

Tim Carr

Unconventional Energy Resources: Making the Unconventional Conventional vii

Unconventional Energy Resources: Making the Unconventional Conventional

29th Annual Gulf Coast Section SEPM FoundationBob F. Perkins Research Conference

Houston Marriott WestchaseHouston, Texas

December 6–8, 2009

Program

Sunday, December 6

4:00–6:00 p.m. Registration and Poster Setup (Grand Pavilion)6:00–8:00 p.m. Welcome Reception and Poster Preview (Grand Pavilion)

Monday, December 7

7:00 a.m. Continuous Registration (Grand Foyer)7:35 a.m. Presentation of Doris Curtis Award to John Armentrout7:45 a.m. Welcome remarks, Mike Styzen (Chair of the Board of Trustees, GCSSEPM Foundation)

(Grand Pavilion)8:00 a.m. Introduction to the Conference, Tim Carr (Conference Convenor)

Keynote Address

8:10 a.m. The Unconventional Bridge to an Alternate Energy Future ........................................................ 1Tinker, Scott W. and Potter, Eric C.

Session 1: Monday Morning—Gas Hydrates

8:40 a.m. Introduction: William Ambrose

8:50 a.m. Gas Hydrate Petroleum Systems in Marine and Arctic Permafrost Environments ..................... 2Collett, Timothy S.

9:20 a.m. Initial Results of Gulf of Mexico Gas Hydrate Joint Industry Project Leg II Logging-While-Drilling Operations ........................................................................................................... 3

Boswell, Ray; Collett, Timothy; McConnell, Dan; Frye, Matthew; Shedd, William; Godfriaux, Paul; Dufrene, Rebecca; Mrozewski, Stefan; Guerin, Gilles; Cook, Ann; Shelander, Dianna; Dai, Jianchun; and Jones, Emrys

10:00 a.m. Coffee break

viii Program and Abstracts

10:20 a.m. Production of Gas from Hydrate: How Much and How Soon? ................................................... 5Johnson, Arthur H.

10:50 a.m. Resource Potential of Deep-Water Hydrates Across the Gulf of Mexico: Part 1, Estimating Hydrate Concentration from Resistivity Logs and Seismic Velocities .......... 6

Sava, Diana and Hardage, Bob

11:20 a.m. Resource Potential of Deep-Water Hydrates Across the Gulf of Mexico: Part 2, Evaluating Hydrate Systems with 4C OBC Seismic Data ............................................... 7

Hardage, Bob; Sava, Diana; Murray, Paul; and DeAngelo, Mike

11:50—1:15 p.m.Lunch

Session 2: Monday Afternoon—Gas Shale

1:00 p.m. Introduction: Frank Walles

1:10 p.m. How Technology Transfer Will Expand the Development of Unconventional Gas, Worldwide . 8Holditch, Stephen A. and Ayers, Walter B.

1:40 p.m. Addressing Conventional Parameters in Unconventional Shale-Gas Systems: Depositional Envi-ronment, Petrography, Geochemistry, and Petrophysics of the Haynesville Shale .................... 9

Hammes, Ursula; Eastwood, Ray; Rowe, Harry D.; and Reed, Robert M.

2:10 p.m. Ancestral Basin Architecture: A Possible Key to the Jurassic Haynesville Trend ...................... 10Martin, Bruce J. and Ewing, Thomas E.

2:40 p.m. Arkoma Basin Shale Gas and Coal-Bed Gas Resources ............................................................. 11Milici, Robert C.; Houseknecht, David W.; Garrity, Christopher P.; and Fulk, Bryant

3:10 p.m. Coffee break

3:30 p.m. Unconventional Seals for Unconventional Gas Resources: Examples from Barnett Shale and Cotton Valley Tight Sands of East Texas .............................................................................. 12

Chaouche, A.

4:00 p.m. Lithostratigraphy and Petrophysics of the Devonian Marcellus Interval in West Virginia and Southwestern Pennsylvania ................................................................................................... 13

Boyce, Matthew L. and Carr, Timothy R.

5:30—7:45 p.m.Hot Buffet and Poster Session

8:00 p.m. Authors remove posters; contractor will start removing display boards at 8:15 p.m.

Tuesday, December 8

7:00 a.m. Continuous Registration

Session 3: Tuesday Morning—Coal-Bed Methane and Oil Shale

8:00 a.m. Introduction: Jack Pashin

Unconventional Energy Resources: Making the Unconventional Conventional ix

8:10 a.m. Estimating Resources and Reserves in Coal-Bed Methane and Shale Gas Reservoirs ............... 14Jenkins, Creties

8:40 a.m. Developing Exploration Strategies for Coal-Bed Methane and Shale Gas Reservoirs ............... 15Scott, Andrew R.

9:10 a.m. Getting Natural Gas Out of Shales and Coals ............................................................................. 17Palmer, Ian

9:40 a.m. Implications of Variable Gas Saturation in Coalbed Methane Reservoirs of the Black Warrior Basin .............................................................................................................................. 18

Pashin, Jack

10:10 a.m. Coffee break

10:30 a.m. Coal-Bed Natural Gas Production and Gas Content of Pennsylvanian Coal Units in Eastern Kansas ............................................................................................................................ 19

Newell, K. David and Carr, Timothy R.

11:00 a.m. Prospects and Progress in the Green River Formation Oil Shale, Western United States ......... 20Carroll, Alan R.

11:30 a.m. The History of US DOE Unconventional Energy Resources in the US, An Archive of References Available for Application to Current Oil Shale and Tar Sand Resources ................ 22

Mroz, Thomas H.

12:00—1:20 p.m.Lunch

Session 4: Tuesday Afternoon—Tight Gas Sands

1:30 p.m. Introduction: Tony D’Agostino

1:40 p.m. Tight-Gas Sandstone Reservoirs: The 200-Year Path from Unconventional to Conventional Gas Resource and Beyond ........................................................................................................... 23

Coleman, James

2:10 p.m. Many Technologies Applied to Develop Wattenberg Field, a Giant in Denver’s Backyard ....... 24Birmingham, Thomas J.

2:40 p.m. Coffee break

3:00 p.m. Geology of the Piceance Mesaverde Gas Accumulation ............................................................. 25Cumella, Stephen P.

3:30 p.m. Fracture Diagenesis and Producibility in Tight Gas Sandstones ................................................ 26Laubach, Stephen E.; Olson, Jon E.; and Eichhubl, Peter

4:00 p.m. Case Studies Examining the Discovery Sequence and Gas Accumulations in Tight-Gas Sandstones .................................................................................................................................... 27

Coleman, James and Attanasi, Emil

4:30 p.m. Conference ends

Author Index ....................................................................................................................................... A-1

x Program and Abstracts

GCSSEPM Foundation

Trustees and Executive DirectorMichael J. Styzen (Chairman)Shell International E&P Inc.Houston, Texas

Paul Weimer University of ColoradoBoulder, Colorado

Anthony D’AgostinoHess CorporationHouston, Texas

Patricia SantogrossiStatoilHouston, Texas

Norman C. Rosen, Executive DirectorNCR & AssociatesHouston, Texas

Executive Council

PresidentJohn WagnerUniversity of HoustonHouston, Texas

President ElectJohn HolbrookUniversity of Texas at ArlingtonArlington, Texas

Vice PresidentRichard KilbyMurphy E&PHouston, Texas

SecretaryLana CzerniakowskiMurphy E&P CompanyHouston, Texas

TreasurerJoanna MoutouxBHP Billiton Petroleum (Americas), Inc.Houston, Texas

Past-PresidentJanok P. BhattacharyaUniversity of HoustonHouston, Texas

Audio-Visual and Poster CommitteeMichael J. Nault (Chairman)Applied Biostratigraphix

Arden CallenderApplied Biostratigraphix

Program Advisory Committee Co-ChairmenWalter AyersTexas A&M University

William AmbroseTexas Bureau of Economic Geology

Tony D’AgostinoHess Corporation

Tim CarrWest Virginia University

Creties JenkinsDeGolyer and MacNaughton

Bruce MartinEncana Oil and Gas (USA), Inc.

Jack PashinGeological Survey of Alabama

Douglas PatchenWest Virginia University

Andrew ScottAltuda, Inc.

Frank WallesDevon Energy Corporation

Unconventional Energy Resources: Making the Unconventional Conventional xi

Contributors to the GCSSEPM Foundation

Sponsorship CategoriesPlease accept an invitation from the GCSSEPM Section and Foundation to support Geological and Geophysical

Staff and Graduate Student Education in Advanced Applications of Geological Research to Practical Problems ofExploration, Production, and Development Geology.

The GCSSEPM Foundation is not part of the SEPM Foundation. In order to keep our conferences priced at a lowlevel and to provide funding for university staff projects and graduate scholarships, we must have industry support.The GCSSEPM Foundation provides several categories of sponsorship. In addition, you may specify, if you wish,that your donation be applied to Staff support, Graduate support, or support of our Conferences. Please take amoment and review our sponsor categories for 2009, as well as our current and past sponsors. In addition, we askthat you visit our sponsors’ Web sites by clicking on their logo or name. Thank you for your support.

Corporate Sponsorships

Diamond($15,000 or more)

Platinum($10,000 to $14,999)

Gold($6,000 to $9,999)

Silver($4,000 to $5,999)

Bronze($2,000 to $3,999)

Patron($1000 to $1,999)

Individuals & Sole Proprietorships

Diamond($3,000 or more)

Platinum($2,000 to $2,999)

Gold($1,000 to $1,999)

Silver($500 to $999)

Bronze($300 to $499)

Patron($100 to $299)

Sponsor AcknowledgmentFor 2009, all sponsors will be prominently acknowledged on a special page inserted in the 2009 and 2010

Conference Abstracts volume and CDs, and with large placards strategically placed throughout the meeting areasduring these conferences.

Corporate-level Diamond sponsors will be acknowledged by having their logo displayed on the back cover of thejewel case for the Conference CD. Corporate level Platinum sponsors will be acknowledged by having their logoplaced in the front matter of the Program & Abstracts volume. All contributions used for scholarships and/or grantswill be given with acknowledgment of source.

In addition to the recognition provided to our sponsors in GCSSEPM publications, we proudly provide a link toour sponsors’ Web site. Just click on their logo or name to visit respective GCSSEPM sponsors.

The GCSSEPM Foundation is a 501(c)(3) exempt organization. Contributions to it are tax deductible ascharitable gifts and contributions.

For additional information about making a donation as a sponsor or patron, please contact Dr. Norman C. Rosen,Executive Director, GCSSEPM Foundation, 2719 S. Southern Oaks Drive, Houston, TX 77068-2610. Telephone(voice or fax) 281-586-0833 or e-mail at [email protected].

mailto:[email protected]

xii Program and Abstracts

2009 Sponsors

Individuals and Sole Proprietorships

Platinum

Shell Exploration and Production Company

Silver

Bronze

Silver Nancy Engelhardt-Moore

Michael J. Nault Ed Picou Mike Styzen

http://www.statoilhydro.com

http://www.shell.com

http://www.bp.com

http://www.hesscorporation.com

http://www.murphyoilcorp.com


http://www.bp.com


http://hesscorporation.com

http://www.bhpbilliton.com

http://www.conocophillips.com

Unconventional Energy Resources: Making the Unconventional Conventional xiii

2008 Sponsors

Individuals and Sole Proprietorships

Diamond

Platinum

Gold

Silver

Bronze

Patron

Silver Ed Picou Michael J. Nault Michael J. Styzen

http://www.devonenergy.com


http://www.bhpbilliton.com

http://www.schlumberger.com


http://www.nexenenergy.com

http://www.conocophillips.com

http://www.murphyoilcorp.com

http://www.nautilusworld.net

xiv Program and Abstracts

Credits

CD ROM Design and Publishing by

Rockport, Texaswww.bergan.com

Cover ImageThe cover image chosen for this year’s conference is Figure 3 from Carroll: “Prospects and Progress in the Green

River Formation Oil Shale, Western United States”

http://www.bergan.com

http://www.bergan.com

Unconventional Energy Resources: Making the Unconventional Conventional 1

The Unconventional Bridge to an Alternate Energy Future

Tinker, Scott W.Potter, Eric C.Bureau of Economic GeologyJackson School of GeosciencesThe University of Texas at Austin

AbstractThe global energy marketplace is undergoing a

predictable transition from coal in the 19th century, to

oil in the 20th century, to natural gas and other non-fos-

sil fuels in the 21st century. Oil as a percentage of total

global energy “peaked” in 1979, and thus the 20th cen-tury will undoubtedly be remembered as the golden ageof oil. The expansion of natural gas and other lower and

non-carbon forms of energy in the 21st century has far-reaching implications and brings with it a number offavorable outcomes.

• Natural gas is abundant and is found in moreregions than oil; this illustrates energy diversityand security of supply.

• With substantial growth expected in worldwideLNG in the coming decades, natural gas willhave a global delivery infrastructure that willhelp stabilize energy prices, benefiting themacro-economies of most nations.

• A global natural gas infrastructure will helpmake the transition to alternatives smoother.

• Increased use of natural gas—to replace coal inpower generation and oil in transportation—would help reduce atmospheric emissions.

A subtle but important corollary to the long-termtrend toward natural gas shows an ever greater percent-age of natural gas production coming fromunconventional resources. One need only look to theUnited States, where coal-bed methane, shale gas andtight gas now represent over 50% of annual production(a benchmark achieved several years earlier than theTinker forecast published in a 2004 Oil and Gas Inves-tor article), and estimated unconventional natural gasresources have more than tripled the conventional gasresource base. As in the United States, a significantportion of the world’s remaining natural gas resource isprobably unconventional—tight gas, coal-bed gas,shale gas representing technologically proven uncon-ventional resources; and methane hydrates, ultra deep(15,000 to 30,000 ft), and brine gas resources as possi-ble future unconventional components. The bulk of theglobal unconventional natural gas has not yet beendeveloped, and it represents an enormous untappedresource.

2 Program and Abstracts

Gas Hydrate Petroleum Systems in Marine and Arctic Permafrost Environments

Collett, Timothy S.U.S. Geological SurveyDenver Federal Center, MS-939P.O. Box 25046Denver, Colorado 80225

AbstractA growing body of evidence indicates that a

large volume of natural gas is stored in gas hydratesand that the production of natural gas from gas hydratesappears to be technically feasible. There are numerousresearch projects underway to investigate the geologi-cal origin of gas hydrate, their natural occurrence, thefactors that affect their stability, and the possibility ofusing this vast resource in the world energy mix.Highly successful cooperative research projects, such

as the various phases of the Mallik gas hydrate produc-tion project in northern Canada, have for the first timetested the technology needed to produce gas hydrates,and other highly successful gas hydrate research stud-ies have been conducted in Japan, India, China, SouthKorea, northern Alaska, and the Gulf of Mexico. All ofthese projects have contributed greatly to an under-standing of the energy resource potential of gashydrates throughout the world.


Initial Results of Gulf of Mexico Gas Hydrate Joint Industry Project Leg II Logging-While-Drilling Operations

Boswell, Ray

U.S. Department of Energy

National Energy Technology Laboratory

3610 Collins Ferry Road

Morgantown, West Virginia 26507

Collett, Timothy S.

U.S. Geological Survey

Denver Federal Center MS-939 Box 25046

Denver, Colorado 80225

McConnell, Dan

AOA Geophysics

2500 Tanglewilde, Suite 120

Houston, Texas 77063

Frye, Matthew

U.S. Minerals Management Service

381 Elden Street

Herndon, Virginia 20170

Shedd, WilliamGodfriaux, PaulDufrene, Rebecca U.S. Minerals Management Service 1201 Elmwood Park Blvd New Orleans, Louisiana 70123

Mrozewski, StefanGuerin, GillesCook, Ann Lamont-Doherty Earth ObservatoryColumbia University 61 Rt. 9 WPalisades, New York 10964

Shelander, DiannaDai, Jianchun Schlumberger10001 Richmond Ave Houston, Texas 77042

Jones, Emrys Chevron Energy Technology Company1500 Louisiana Street Houston, Texas 77002

Abstract

The Gulf of Mexico gas hydrates Joint IndustryProject (the JIP), a cooperative research programbetween the US Department of Energy and an interna-tional industrial consortium under the leadership ofChevron, conducted its “Leg II” logging-while-drillingoperations in April and May of 2009. JIP Leg II wasintended to expand the existing knowledge base on gashydrates in the Gulf of Mexico to include the evalua-tion of gas hydrate occurrence in sand reservoirs. Theselection of the locations for the JIP Leg II drilling wasthe result of a geological and geophysical prospectingapproach that integrated direct geophysical evidence ofgas hydrate-bearing strata with evidence of gas sourc-ing, gas migration, and occurrence of sand reservoirswithin the gas hydrate stability zone. Logging-while-drilling operations for JIP Leg II included the drillingof seven wells at three sites. Despite drilling the deep-est and most technically challenging well yet attemptedin a marine gas hydrate program, the expedition was ontime, under budget, and met all its scientific objectives.

Minimal operational problems were encountered withthe advanced LWD tool string, and the continual refine-ment of drilling parameters enabled the successfulmanagement of a range of shallow drilling issues,including borehole breakouts and shallow gas andwater flows. Two wells drilled in Walker Ridge Block313 (WR 313) confirmed the pre-drill predictions bydiscovering gas hydrates at high saturations in multiplesand horizons having reservoir thicknesses up to 50 ft.In addition, drilling in WR 313 discovered an unpre-dicted, thick, strata-bound interval of shallow fine-grained sediments having abundant gas-hydrate-filledfractures. Two of three wells drilled in Green CanyonBlock 955 (GC 955) confirmed the pre-drill predictionof extensive sand occurrence having gas hydrate fillalong the crest of a structure associated with positiveindications of gas source and migration. Well GC955-H discovered ~100 ft of gas hydrate in sand at high sat-urations. Two wells drilled in Alaminos Canyon Block21 (AC 21) confirmed the pre-drill prediction of poten-


tial extensive occurrence of gas hydrates in shallowsand reservoirs at low saturations.

Further data collection and analyses at AC 21will be needed to better understand the nature of the

pore filling material. The JIP plans to use the results ofLeg II to plan Leg III drilling and coring operationsanticipated to occur in 2010.


Production of Gas from Hydrate: How Much and How Soon?

Johnson, Arthur H.Hydrate Energy International612 Petit Berdot DriveKenner, Louisiana 70065

AbstractResource estimates for gas hydrate that have

been reported during the past 30 years have pointed to atruly vast potential, but one that has persistentlyremained just over the horizon due to technical andeconomic hurdles. It is only in the last 10 years thatcommercial development of gas hydrate has been con-sidered in the context of a petroleum system. The newfocus is on components such as source, migration,traps, seals, and reservoir lithology. The petroleum sys-tem model, combined with recent drilling efforts, hasled to revised resource estimates and viable productionscenarios.

Most of the world’s gas hydrate occurs in lowconcentrations in impermeable shales (comprising 3%to 5% of the sediment volume) or as isolated veins thatcannot be commercially developed. In contrast, sandswithin the hydrate-stability zone typically have highhydrate saturations within the pore volume, exceeding80% saturation in some locations. Although the gashydrate reservoirs having commercial potential areonly a small fraction of the global hydrate volume, theystill have resource potential in the thousands of trillion

cubic feet (Tcf). Although it is unrealistic to considerthe global potential of gas hydrate to be in the hundredsof thousands of Tcf, there is a strong potential in thehundreds of Tcf or thousands of Tcf. The U.S. MineralsManagement Service (MMS) estimates a total gashydrate volume for the Gulf of Mexico of between11,112 and 34,423 Tcf, and a mean estimate of 6,717Tcf in place in sandstone reservoirs. A United StatesGeological Survey (USGS) assessment for the NorthSlope of Alaska reports a mean estimate of 85.4 Tcftechnically recoverable from hydrate.

Gas has been produced from hydrate-bearing res-ervoirs on a very limited scale through short-termproduction tests in the Canadian Arctic and on theNorth Slope of Alaska. A long-term, industry-scaleproduction test is planned for the North Slope in thesummer of 2010 and the potential for hydrate develop-ment for local use following soon after. Productiontesting for hydrate in the Gulf of Mexico will followwithin a few years. Japan is planning an offshorehydrate production test in 2011. Hydrate developmentprograms are also in progress in India and South Korea.


Resource Potential of Deep-Water Hydrates Across the Gulf of Mexico: Part 1, Estimating Hydrate Concentration from Resistivity Logs and Seismic Velocities

Sava, Diana

Hardage, Bob

Bureau of Economic Geology

The University of Texas at Austin

[email protected]

Abstract

The Bureau of Economic Geology has evaluatedhydrate concentrations across deep-water areas ofGreen Canyon, Gulf of Mexico, using well log data andfour-component (4C) seismic data acquired by compa-nies interested in deep oil and gas targets, not in near-seafloor hydrates. Even though these seismic and welllog data are not acquired for purposes of studying near-seafloor geology, we have found these off-the-shelfindustry data to be invaluable for evaluating hydratesystems positioned immediately below the seafloor. Wesummarize our data analyses and initial research find-ings in a two-paper sequence.

In this first paper, we describe how hydrate con-centration can be estimated from resistivity logs andthen from compressional (VP) and shear (VS) velocities

as a joint-inversion approach for quantifying theamount of in-place hydrate. We found no industry wellin the Green Canyon area where velocity-log data hasbeen recorded across shallow near-seafloor stratawhere deep-water hydrates are found. Consequently,we have utilized interval VP and VS velocities obtained

by processing deep-water 4C seismic data in our joint-inversion hydrate estimations.

The rock physics used to estimate deep-waterhydrate concentrations from resistivity logs and frominterval velocities is challenging because deep-water,near-seafloor sediments exist in a unique environmentcharacterized by high porosities (greater than 50 per-cent) and low effective pressures (literally zero at theseafloor). Rock physics analyses are further compli-

cated by the fact that resistivity and velocity responsesto the hydrate fraction in seafloor sediments depend onwhether the hydrate is layered (either horizontally orvertically) or dispersed, and if dispersed, whether thehydrate is part of the load-bearing matrix or is floatingfreely in pore spaces. Because the oil and gas industryis not yet focused on hydrate production, there is inade-quate core information to define the specific hydrate-sediment morphology that should be used in a rockphysics model that is applied to deep-water, near-sea-floor environments in the Green Canyon area. In thisfirst paper we illustrate how hydrate morphologyaffects the interpretation of resistivity and velocityresponses of hydrate-bearing sediment. We haveassumed a load-bearing morphology for our inversionwork and await specific core information to know ifthis assumption needs to be modified in future work.

We have found that the Hashin-Shtrikman LowerBound that can be used to describe the resistivity andelastic moduli of a mixture of arbitrary fractions ofquartz, clay, hydrate, and brine is a critical concept forevaluating relationships between resistivity, velocity,and hydrate concentration in deep-water, near-seafloorenvironments. We discuss our rock physics modelingapproach based on the application of Hashin-Shtrik-man theory. In the second paper of this series, wedescribe how we combine the rock physics models thatwe have developed with velocity attributes determinedfrom 4C seismic data to generate maps of hydrate con-centration across our study area.



Resource Potential of Deep-Water Hydrates Across the Gulf of Mexico: Part 2, Evaluating Hydrate Systems with 4C OBC Seismic Data

Hardage, BobSava, DianaMurray, PaulDeAngelo, MikeBureau of Economic GeologyThe University of Texas at [email protected]

AbstractWe have evaluated hydrate concentrations across

deep-water areas of Green Canyon, Gulf of Mexico,using well log data and four-component (4C) seismicdata acquired by companies interested in deep oil andgas targets, not in near-seafloor hydrates. Even thoughthe data are not acquired for purposes of studying near-seafloor geology, we have found these off-the-shelfindustry data to be invaluable for evaluating hydratesystems positioned close to the sea floor. We summa-rize our data analyses and initial research findings inthis publication as a two-paper sequence.

In this second paper of our two-part series, wedescribe how two images of deep-water hydrate sys-tems can be made from four-component ocean-bottom-cable (4C OBC) seismic data: a compressional (P-P)image and a converted-shear (P-SV) image. We furtherillustrate how we implement a raytracing procedure to

determine accurate values of P-wave velocity (VP) andSV-mode velocity (VS) across thin subsea-floor layers.These interval velocities are used with the rock physicstheory described in our first paper of this two-papersequence to (1) estimate hydrate concentration at cali-bration wells where there are resistivity logs to use foran independent calculation of the hydrate fraction, and(2) expand the hydrate estimation along 4C seismicprofiles that extend long distances away from calibra-tion wells.

We present maps of hydrate concentration esti-mated by our data analyses and physical assumptions.We found hydrate concentration to not exceed 40 per-cent of the available pore space across our GreenCanyon study area and to usually be in the range of 10to 20 percent of the available pore volume.



How Technology Transfer Will Expand the Development of Unconventional Gas, Worldwide

Holditch, Stephen A. Harold Vance Department of Petroleum EngineeringTexas A&M University3116 TAMUCollege Station, Texas 77843-3116

Ayers, Walter B. Harold Vance Department of Petroleum EngineeringTexas A&M University3116 TAMUCollege Station, Texas 77843-3116

Abstract For more than 50 years, the U.S. natural gas

industry has been developing unconventional gas reser-voirs. Production of natural gas from eastern DevonianShales and tight gas sands in Texas and in the RockyMountain and Midcontinent regions has been the prov-ing ground for many innovations in well drilling,completion, and stimulation. Over the past twodecades, successful gas production from coal seamsand from shales, such as the Barnett Shale, has led tonew drilling and completion technologies. In 2007,unconventional gas production was 9.15 Tcf, account-ing for 47% of the U.S. dry gas production, and eight ofthe top ten U.S. gas plays were producing from uncon-ventional reservoirs. Unconventional gas reservoirs, ledby shale, are expected to provide the majority of theU.S. gas supply growth in coming decades. Clearly,many basins worldwide contain large volumes ofunconventional gas resources that have not beenassessed. As conventional oil and gas reservoirs aredepleted in those basins, inevitably, unconventional gasreservoirs will be developed. The key to successfuldevelopment will be the proper application of existingtechnologies and the continued development of newtechnologies.

Over the past 5 years, a team of engineers andgeoscientists in the Crisman Institute at Texas A&MUniversity have worked to capture the critical geologicand engineering properties of unconventional gas reser-

voir in 25 North American basins. The primaryobjectives of this research are to (1) understand the gasresource distributions and the best technologies forunconventional gas recovery and economics, and (2)assess the volumes of unconventional gas in basins,worldwide, beginning with North America, using theconcept that resources are log-normally distributed(resource triangle). Our evaluations of North Americanbasins indicate that the Technically RecoverableResource of unconventional gas in any basin will beapproximately 5-10 times greater than the ultimaterecovery (cumulative production plus proved reserves)from all conventional oil and gas reservoirs in the samebasin.

Our research shows that historic unconventionalgas drilling and production have been impactedstrongly by technology and gas prices. The oil and gasindustry should continue developing new technology toaccess unconventional gas reservoirs in diverse set-tings. The Research Partnership to Secure Energy forAmerica (RPSEA) is supporting the development ofnew technology to optimize recovery of unconven-tional gas resources in the U.S. In coming decades, thistechnology that is being developed in the U.S. will bedeployed worldwide to increase natural gas productionfrom unconventional reservoirs and to contributeneeded energy supplies.


Addressing Conventional Parameters in Unconventional Shale-Gas Systems: Depositional Environment, Petrography, Geochemistry, and Petrophysics of the Haynesville Shale

Hammes, Ursula

Eastwood, Ray

Bureau of Economic Geology

Jackson School of Geosciences


Austin, Texas 78713

[email protected]

Rowe, Harry D.

Department of Earth and Environmental Sciences

Box 19049

University of Texas at Arlington

Arlington, Texas 76019

Reed, Robert M.Bureau of Economic Geology

Jackson School of Geosciences


Austin, Texas 78713

Abstract

The Upper Kimmeridgian to Lower TithonianHaynesville Shale of East Texas was deposited in abasin rimmed by carbonate platforms to the west andnorth during a second-order transgression spanning154–150 Ma. The Haynesville shale gas play is animportant resource target in Louisiana and East Texas.Wells are characterized by high initial production andsteep decline rates. Potential estimated ultimate recov-ery (EUR) per well is in the range of 4–7 Bcf, and play-reserves of more than 100 Tcf. However, depositionalenvironmental, mineralogy, lithology, textures, geo-chemistry, porosity, permeability, and wireline-logcharacteristics are all poorly documented or under-stood. This paper addresses previously undocumentedparameters related to depositional setting, facies, dia-genesis, pore space, petrophysics, and significantgeochemical markers of the Haynesville Shale.

The Haynesville Shale was deposited in a basinalsetting surrounded by carbonate shelf of the Haynes-ville/Cotton Valley Lime. Cotton Valley pinnacle reefsgrew within the shale-rich basin. Deposition was dur-

ing a rapid second-order transgression that resulted inbackstepping of carbonates and smothering of carbon-ate production by the Haynesville fine-grainedsediments. Carbonates were shed into the basin viagravity flows. The basin periodically exhibited arestricted environment of reducing anoxic conditions,as indicated by Molybdenum (Mo) and Fe/S concentra-tions. Relatively high TOC values (1–8%) are typicalof these mudrocks that ranged from calcareous, lami-nated and/or bioturbated mudstones to unlaminatedsiliceous mudstones. Bioturbation may be indicativefor smaller-scale sea-level fluctuations and/or anoxic/oxic cycles. Pores are limited and small in size, occur-ring as micropores and nannopores in both intraparticleand interparticle forms. Nanopores are common andwell-developed in some organic matter. Kerogen isseen to affect responses of all logs used for petrophysi-cal characterization of porosity and lithology.Therefore, corrections must be applied when calculat-ing porosity and clay volume.



Ancestral Basin Architecture: A Possible Key to the Jurassic Haynesville Trend

Martin, Bruce J.

25630 Zion Lutheran Cemetery Rd.

Tomball, Texas 77375

Ewing, Thomas E.

Yegua Energy Associates LLC

19240 Redland Rd Ste 200

San Antonio, Texas 78259

Abstract

Ancestral Gulf Coast Basin architecture controlsmuch of the Jurassic Haynesville shale mudstone trend.

Basement blocks developed during Early and Middle

Jurassic rifting and overlain by a variable thickness ofLouann Salt ultimately formed the foundation of large

Haynesville (Gilmer) carbonate platforms that provideboundaries to the Haynesville organic shale trend. Salt

movement influenced by basement features createdlocal fairways of salt deflation, which received thicker

Haynesville organic shale sequence and experienced

less subsequent disruption. Available data sets indicatethat salt movement in the Sabine uplift area terminated

during the Late Jurassic. Therefore, post-Jurassic fault-ing was minimized, preventing hydrocarbon loss from

the Haynesville organic shale reservoirs.

It is further proposed that the complex interac-

tion of basement and salt structuring control the uniquecharacteristics of the Haynesville shale mudstone res-

ervoirs. Upwelling and/or other enrichment processeswere controlled by paleo-structuring. The most favor-

able sites are the eastern and southern flanks of the

ancestral Sabine platform. An understanding of saltmovement via analysis of gravity-magnetic data

closely tied to seismic and well control provides aninexpensive, yet effective means of mapping large

areas. Detailed high-resolution gravity and magneticmapping may provide even further insights for exploi-

tation at lower cost than expensive 3D seismic.

Presently, the extent of the Haynesville trend

along the Sabine platform is not fully defined, due in

part to a lack of deep well control. This is particularly

true along the Texas side, where thick Haynesville/Bossier flanking wedges are unexploited, and are

beyond present economic limits. Should these wedges

provide favorable facies when tested, exploration couldshift to a deeper southern extension of the trend.

In certain areas, younger Jurassic faulting is

coincident with older reactivated basement trends, pro-

viding avenues for hydrothermal fluid pathways. Thesepathways may have allowed hydrothermal fluid migra-

tion into the overlying Haynesville shale mudstonereservoirs and certain Haynesville carbonate reservoirs

potentially enhancing these reservoirs. Mineral assem-blages associated with thermo-chemical sulfate

reduction have been found near these faulted areas,

indicating the migration of hydrothermal fluid. In atleast one case, dissolution by such fluid migration has

resulted in a substantial void or karst style secondaryporosity in the Haynesville carbonate section. The

extent of this activity is unknown due to the limiteddeep well control. However, it may be extensive due to

the high geothermal signature prevalent in the southern

and eastern parts of the Haynesville play area.

Future exploration of the Haynesville trend will

depend upon duplicating key factors found in theSabine area. Workflows utilizing reconnaissance tools

may help companies in updating their basin architec-ture models. Applying unconventional exploration

workflows in combination with the understanding ofhydrothermal flows to the Jurassic Salt Basins may

help unlock other potential areas, allowing for revital-

ization of a mature region.


Arkoma Basin Shale Gas and Coal-Bed Gas Resources

Milici, Robert C.Houseknecht, David W.Garrity, Christopher P.Fulk, BryantU.S. Geological Survey956 National CenterReston, Virginia 20192

AbstractShale gas is produced from the Woodford,

Caney, and Fayetteville shales (Devonian and/or Mis-sissippian), and coal-bed gas is produced from theHartshorne and McAlester coal beds in the Arkomabasin of Oklahoma and Arkansas. The U.S. GeologicalSurvey is currently assessing the technically recover-able hydrocarbon resources of the Arkoma basin andfor assessment purposes has divided the continuousshale gas (unconventional) resources into three totalpetroleum systems together with their associatedassessment units (AUs). Each of the gas shale AUs con-tains 2.5 % or more total organic carbon, is thermallymature with respect to gas generation over much of itsarea within the basin, and may be accessed by the drill

at depths less than 14,000 feet. In addition, the Wood-ford, Caney, and Fayetteville Shale Gas AUs underlierelatively large areas that have not been tested ade-quately by the drill. Coal-bed gas is currently beingproduced from the Hartshorne and McAlester coal bedsin the Arkoma basin, and for assessment purposes theyhave been grouped together into one total petroleumsystem and one AU. Much of the area where the coalbeds are relatively shallow in the northern part of theAU has been drilled. However, the area underlain bycoal in the southern part of the basin, which is deeperand more structurally deformed, remains largely unex-plored for coalbed methane.


Unconventional Seals for Unconventional Gas Resources: Examples from Barnett Shale and Cotton Valley Tight Sands of East Texas

Chaouche, A.Anadarko Petroleum [email protected]

Abstract

Assessment of undiscovered oil and gasresources is based on geological elements and pro-cesses of a petroleum system. Application of thepetroleum system in the oil industry varies largely onhow the processes of hydrocarbon generation, migra-tion, and entrapment are described. It is often depictedas a relationship between source and reservoir rocksconnected by fluid paths (e.g., carrier beds, faults, etc.)through geological time. When appropriate conditions(time, temperature, and trap formation) are reached, theeffort is focused on secondary migration from source toreservoir. Secondary migration efficiency is a functionof the distance between source and reservoir rocks.Tertiary migration (or dismigration) refers to fluidmovement from reservoir to reservoir and involvesmigration pathways (fault or sand beds and/or uncon-formities).

There has been much research on source rockquality and its relationship to hydrocarbon potential.Much less has been documented about the rate, mecha-nisms, and pathways by which gases migrate throughkilometer-scale sequences of fine-grained sediments.Mass balance calculations supported by laboratoryexperiments on good quality source rocks show thatsignificant volumes of hydrocarbons can be generatedand expelled from the source rock, but explorationresults show that only a small fraction (<10%) istrapped within conventional reservoirs. Dispersion inthe carrier beds (10 to 20%), retention in the sourcerock (30 to 40 %), dismigration (10 to 20%), and bio-degradation (10 to 20%) are commonly assumed to bethe altering mechanisms of the bulk fluid generation.The proximity of source rock and reservoir rockbecomes critical to fluid preservation andaccumulation.

The unconventional Barnett Shale and CottonValley Tight Sands of East Texas are no different fromother petroleum systems. The Barnett Shale is a classic

shale gas system that includes the elements of source,reservoir, and seal. The Cotton Valley Formation(CVF) exhibits an inter-fingering shale/sand systemthat juxtaposes source and reservoir offering preserva-tion and high migration efficiency.

Occurrences of sweet spots in Barnett Shale arerelated to the original source rock richness, maturity,and confinement of the source beds. The Fort Worthbasin of East Texas is asymmetric and has a polyphasedburial history. Its western part along the Washita highhas undergone uplift and erosion at the Miocene. Theresulting liable asphaltenes precipitation has created apermeability barrier within the shale preventing gasfrom escaping laterally to the west. The lower Barnettencased between the Marble Falls Limestone and theChappel Limestone has limited gas leakage to the topand the bottom, creating an optimum seal for the New-ark Field where the highest gas production per well hasbeen observed. Laminated carbonates and chemicallyinduced carbonate nodule deposits in the early organicdiagenesis provide vertical and lateral baffles to fluidflow thus enhance the confinement within the mostproductive Barnett Shale.

In the Cotton Valley Formation, significant per-meability reduction occurs within the inter-fingeringshale and tight sands. The migration of oil from shaleto sand has accumulated a significant volume of oil thatultimately has cracked to gas when burial reached thegas window in the Cotton Valley. This secondary crack-ing has resulted in high pressures extending far beyondthe source rock, flushing the interstitial water to over-laying formations. Different chemical water mixes haslead to mineralization and thus diagenetic sealsenhancing confinement, which has result in stair-steppressure offsets occurring independently of lithology

profiles.



Lithostratigraphy and Petrophysics of the Devonian Marcellus Interval in West Virginia and Southwestern Pennsylvania

Boyce, Matthew L.Dept of Geology and GeographyWest Virginia University98 Beechurst Ave., 330 Brooks HallMorgantown, West Virginia [email protected]

Carr, Timothy R.

Marshall Miller Professor of Geology

West Virginia University

98 Beechurst Ave., 330 Brooks Hall

Morgantown, West Virginia 26505

AbstractIn the Appalachian basin, the Middle Devonian

organic-rich shale interval, including the MarcellusShale, is an important target for exploration. Thisunconventional gas reservoir is widespread across thebasin and has the potential to produce large volumes ofgas (estimated to have up to 1,307 trillion cubic feet ofrecoverable gas). Although the Middle Devonianorganic-rich shale interval has significant economicpotential, stratigraphic distribution, depositional pat-terns and petrophysical characteristics have not beenadequately characterized in the subsurface. Based onlog characteristics, tied to core information, thelithostratigraphic boundaries of the Marcellus andassociated units were established and correlatedthroughout West Virginia and southwestern Pennsylva-nia. Digital well logs (LAS files) were used to generate

estimates of lithology and to identify zones of highergas content across the study area. In addition, a litho-logic solution was calibrated to X-ray Diffraction(XRD) data. Using previous studies on organic shale,relationships between the natural radioactivity (as mea-sured by the gamma-ray log) were incorporated withtechniques to identify gas-prone intervals. The compar-ison between the Uranium content and the measuredbulk density identified intervals in the Marcellus hav-ing high gas saturations and were used to generate anapproach to correct water saturations. These techniquesof identifying lithology and potential gas in the Marcel-lus are useful to identify areas of higher explorationpotential and to target zones for fracture stimulation orto land a horizontal leg.



Estimating Resources and Reserves in Coal-Bed Methane and Shale Gas Reservoirs

Jenkins, CretiesDeGolyer and MacNaughton5001 Spring Valley Road, Suite 800EDallas, Texas 75244

AbstractIn the past two decades, production from coal-

bed methane and shale gas reservoirs has more thandoubled in the United States and now provides about16% of total annual gas production. Estimatingresources and reserves in these reservoirs is challeng-ing and requires a thorough understanding of (1) thefactors that control the storage, distribution, and pro-duction of this gas, (2) the data required to properlycharacterize these reservoirs, (3) the techniques used toforecast well and reservoir performance, and (4) therules and guidelines governing the assignment ofresources and reserves.

It is important not just to estimate provenreserves, but all reserves and resources classes in orderto capture the full spectrum of development opportuni-ties. Accurate estimates require detailed information,but since little of this may be available, it is up to theevaluator to exercise good judgment and apply tech-niques that capture the inherent uncertainty in theestimates. It is also important to recognize that therules, guidelines, and techniques are still under devel-opment for unconventional gas, and that it may beseveral years before consistent procedures are appliedthroughout the industry.


Developing Exploration Strategies for Coal-Bed Methane and Shale Gas Reservoirs

Scott, Andrew R.Altuda Energy CorporationSan Antonio, [email protected]

Abstract

Coal and shale reservoirs are playing a progres-sively more important role in unconventional naturalgas production and reserves in the United States andworldwide. Shale gas and coal-bed methane now repre-sent 19.4 percent of total dry natural gas production inthe United States and 21.9 percent of gas reserves.Shale gas production and reserves exceeded coal-bedmethane for the first time in 2008. At first glance coaland shale reservoirs appear to have few similarities andare often treated as separate entities in terms of explo-ration strategies. Although there are certainlydifferences between these two reservoir systems, theyalso have a number of similarities indicating that many,but not all, of the exploration concepts developed foridentifying coal-bed methane sweet spots may also beapplicable to shale gas reservoirs.

Both coal seams and shale reservoirs are charac-terized as fractured systems in which the microporous,organic fraction of the coal and the clay and mineralshale matrix have nearly zero permeability. Gas andfluid migration occur through naturally occurring frac-tures (cleats) in coals and either natural or inducedfractures in shales. Natural gas is sorbed to the organicmatter in both the coals and shales, but the coals con-tain more sorbed gas per ton than the shales due to ahigher organic content. However, in addition to sorbedgas, shale reservoirs have additional gas stored withinthe mineral matrix which contributes to additional totalgas in the system. This free matrix gas compensates forthe lower organic content (relative to coals), and there-fore, sorbed gas in shale reservoirs.

Most coal-bed methane wells occur at depths lessthan 3,000 feet due to permeability restrictions, but thedeepest coal-bed methane wells in the world producefrom 7,500 feet in the Piceance Basin. Shale gas wellsrange between 500 feet in the Antrim Shale to 12,000feet in the Woodford and Haynesville/Bossier shales.Coal and shale reservoirs may contain nearly 100 per-cent thermogenic or secondary biogenic gases and,

regionally, will have a mixing zone that contains boththermogenic and biogenic gas components. Exception-ally high production rates for both coal seams andshales require a certain minimal level of thermal matu-rity: 0.8 to 1.0 percent in coal beds and more than 1.0 to1.2 percent in shales.

Recovery factors in coal reservoirs is highly vari-able ranging from more than 80 percent in highpermeability coals to less than 15 percent in lower per-meability coal seams; coal seams with less than 1 mdpermeability are generally not economical. Most com-mercial coal beds have recovery rates between 30 and60 percent. Shale gas recovery rates appear to be gener-ally lower than in coal beds, generally ranging between10 and 20 percent, but recovery rates in the AntrimShale have been reported to be as high as 60 percent.However, recovery factors for shale reservoirs is morecomplicated than for coal reservoirs due to the combi-nation of sorbed and matrix gas. Therefore, publishedrecovery factors for many shale plays are still beingevaluated indicating that the final range of recoveryrates may vary significantly from what is predictedtoday.

The six key hydrogeologic factors affect coal-bed methane producibility are depositional systems,tectonic/structural setting, coal rank or thermal matu-rity, gas content, permeability, and hydrodynamics. Ifall six factors come together in a synergistic way, thenexceptionally high coalbed methane producibility mayresult.

This model was initially developed from threeend-member basins that had markedly different proper-ties: (1) Piceance, (2) Powder River, and (3) San Juanbasins. The Piceance Basin was characterized by highthermal maturity coal seams (vitrinite reflectance, VR,values exceeding 1.0 percent), exceptionally high gascontent (more than 700 scf/ton) values, and low perme-ability (generally less than 1 md). This lowpermeability results in marginal production rates over



much of the basin. The Powder River Basin is charac-terized, by thick, laterally extensive coal seams(individual seams >100 ft thick), low thermal maturity(VR values generally <0.5 percent), and low gas con-tent values (generally <32 scf/ton).

However, the presence of exceptionally thickcoal seams at shallow depths make drilling costs lowerand the economics much better than the Piceance Basindespite the low levels of thermal maturity and gas con-tent values. Therefore, the Piceance Basin represents ahigh thermal maturity play characterized by predomi-nantly thermogenic gases, whereas the Powder RiverBasin is recognized as a secondary biogenic coalbedmethane play with lower levels of thermal maturity andcorresponding gas content ranges.

The prolific San Juan Basin represents an inter-mediary between the Piceance and Powder Riverbasins. The San Juan Basin is characterized by thick(up to 90 ft net coal) laterally continuous coals of highthermal maturity (VR values 0.80 to 1.5 percent, north-ern basin). Fresh, meteoric water transported basinwardthrough permeable coal beds has carried microbes thathave bioconverted the coal and thermogenic, wet gascomponents into secondary biogenic methane. This hasresulted in fully saturated coals and exceptionally high

gas content values (>600 scf/ton) where meteoricrecharge has occurred in the northern part of the basin.

These same six hydrogeologic factors can also beapplied to shale reservoirs, although the tectonic andstructural setting, rock properties, and completion tech-niques appear to be much more important in shalereservoirs than in coals. As in coal reservoirs, shale gasplays can be characterized using two end members: (1)the Barnett Shale, and (2) Antrim shale, which corre-spond with the thermogenic (Piceance-type) andsecondary biogenic (Powder River-type) plays, respec-tively. An intermediary, San Juan-type play has notbeen clearly identified in shale gas plays to-date, butsuch an intermediary play probably will be less produc-tive than the Barnett Shale due to the physicaldifferences between shale and coal reservoirs. Just as incoal-bed methane, a detailed understanding of thehydrodynamics of the reservoir system will be requiredto identify potential sweet spots associated withupward flow potential. This is particularly true for theAntrim- and intermediary-type shale gas plays, butunderstanding hydrodynamics, and the distribution ofhydrocarbon and artesian overpressure is an overlookedbut important component of shale gas plays.


Getting Natural Gas Out of Shales and Coals

Palmer, IanHiggs-Palmer TechnologiesAlbuquerque, New Mexico [email protected]

AbstractThis paper will discuss some established proce-

dures and recent learnings in regard to wellcompletions and production in both shale gas and coal-bed methane reservoirs. The talk will address certaincommonalities, peculiarities, and challenges of both.Some of the technical aspects will include the impor-

tance of natural fractures and permeability, examples ofcommercial production, and optimizing well stimula-tion. The approaches and learnings from coals andshales may be transferable to newer unconventionalresources.



Implications of Variable Gas Saturation in Coalbed Methane Reservoirs of the Black Warrior Basin

Pashin, JackGeological Survey of AlabamaP.O. Box 869999Tuscaloosa, Alabama [email protected]

AbstractVariable gas saturation in coal of the Black War-

rior basin has significant consequences for productionperformance, and the relationship of gas saturation toisotherm geometry is a critical consideration for devel-opment. Although gas content generally increases withdepth, saturation typically vari‘es greatly among indi-vidual coal seams. Reservoir conditions in the BlackWarrior basin are the product of a complex mix ofstratig 22raphic, structural, hydrogeologic, and petro-logic factors, and these factors have a strong influenceon the mobility and recoverability of coalbed methane.In deep, highly pressured seams that are substantiallyabove Langmuir pressure, the low slope of the isotherm

indicates that even minor undersaturation can necessi-tate prolonged dewatering before the reservoir reachescritical desorption pressure. Where reservoir pressureis relatively low and the slope of the isotherm is rela-tively steep, by contrast, reservoirs that aresignificantly undersaturated with gas can be close tothe critical desorption pressure. Consequently, low res-ervoir pressure in the northern part of the BlackWarrior coalbed methane play favors high gas recoveryfrom all coal seams, whereas recovery from deep,highly pressured coal in the southwestern part of theplay is favored by a combination of high initial gascontent and high Langmuir pressure.



Coal-Bed Natural Gas Production and Gas Content of Pennsylvanian Coal Units in Eastern Kansas

Newell, K. DavidKansas Geological SurveyUniversity of KansasLawrence, Kansas

Carr, Timothy R.Department of Geology and GeographyWest Virginia UniversityMorgantown, West Virginia

AbstractMiddle Pennsylvanian coal units in eastern Kan-

sas produce commercial quantities of coal-bed naturalgas. Annual coal-bed natural gas production in 2008was 49.1 billion cubic feet (Bcf) (13% of state output);cumulative production since 2000 is 165 Bcf. Coalbeds are commonly less than two feet thick and aremostly produced by vertical wells at 80- to 160-acrespacing. Wells usually have comingled gas productionfrom several coal beds. The main producing region is afour-county area (Labette, Montgomery, Neosho, andWilson counties) in southeastern Kansas immediatelynorth of the Oklahoma state line. Most wells are notprolific; their average maximum production rate isapproximately 67 mcf/day, peaking about 14 monthsafter initial production. Decline rates are low, as somecoal-bed natural gas wells have produced 15 years andbeyond. North-northwest–south-southeast trendingproduction fairways can be defined by mapping maxi-mum production rates. These fairways generally

correlate to where coal beds are individually and com-positely thick. The most prolific wells in the thickestcoal units record maximum production rates as great as615 mcf/day.

The median as-received gas content for coals insoutheastern Kansas is 139 scf/ton, with maximum gascontent of approaching 400 scf/ton. Gas content ineast-central and northeastern Kansas coal beds gener-ally runs half that of southeastern Kansas, indicatingeconomics of coal-bed natural gas production areharsher northward. Coals increase in depth westward ata rate of approximately 20 feet per mile. Their gas con-tent commensurately increases by 10 to 20 scf/ton foreach 100 feet of burial. Thin (<4 foot) black shale bedsinterbedded with the coal units may have commercialpotential, for their as-received gas content can be greatas 65 scf/ton, but 20 scf/ton is the median of all shalesamples assayed.


Prospects and Progress in the Green River Formation Oil Shale, Western United States

Carroll, Alan R.Department of GeoscienceUniversity of Wisconsin1215 W. Dayton St.Madison, Wisconsin [email protected]

Abstract

The Eocene Green River Formation has longbeen believed to contain the world’s largest commercialoil shale deposits, having a recently estimated in situresource of 2 trillion barrels of oil. Most of thisresource lies within the Piceance Creek basin in north-western Colorado, but additional oil shale intervals alsooccur within the Uinta basin in Utah and the greaterGreen River basin in Wyoming. The smaller reportedmagnitude of resources in Utah and Wyoming reflectsthinner stratigraphic intervals but may also be due inpart to more conservative assessment approaches(Utah) or to less complete assessment data (Wyoming).

The Green River Formation represents the depos-its of long-lived lakes that occupied severalintermontane basins within the broken “Laramide”foreland. Oil shale facies consist dominantly of carbon-ate-rich mudstone, having organic enrichment reachingup to 60 gallons of oil per ton (Fischer Assay). Lithofa-cies assemblages record a wide range of depositionalconditions that define three major lake basin types.Under-filled lake basins often contain bedded evapo-rites deposited by hypersaline lakes, and theirstratigraphy is dominated by aggradational lake cycles.Identifiable fossils are typically absent, but mudstonefacies may be highly enriched in organic matter due tohigh algal and cyanobacterial productivity. Balanced-fill lake basins contain lakes of fluctuating salinity thatmay reach brackish or fresh water conditions. Rich oilshale deposits and fish fossils are common, and theirstratigraphy reflects a mix of aggradational and progra-dational geometries. Over-filled lake basins containfresh water lakes, and their stratigraphy is dominatedby shoreline progradation processes. Coal and carbona-ceous shale are common, often associated withmollusks and other freshwater fauna. Oil shale can bepresent but is often of relatively low grade.

Volcanic tuff horizons interbedded with lacus-trine strata have recently helped to establish anextensive chronostratigraphic framework for the GreenRiver Formation. Radioisotopic dating of these tuffs (attemporal resolution of ~100 ky) indicates that theGreen River Formation spanned more than 8 millionyears, from <52 ma to >44 ma. Different lake typesoften occupied adjacent basins at the same time, indi-cating that fill and spill relationships were as importantas climate in determining paleoenvironmental condi-tions and oil shale quality. Major lake-type transitionsappear to have been caused by changes in regionaldrainage organization. For example, expansion of theMahogany oil shale across the Piceance Creek andUinta basins appears to have occurred in response tocapture of a mountain river in central Idaho. This riverflowed into Lake Gosiute in Wyoming, which in turnspilled into Colorado and Utah.

Large-scale commercial production of GreenRiver Formation shale oil depends on resolving twosignificant problems: production costs, and potentialenvironmental impact. Both concerns are currentlybeing addressed through the development of new insitu retort techniques. These techniques involve slowheating of oil shale (to temperatures near 700°F), withthe aim of directly producing relatively high qualitylight oil. In contrast to conventional mining and surfaceretort, asphaltenes and other potentially harmful com-ponents are retained in the subsurface. Requirementsfor process water are also greatly reduced.

At last three distinctly different in situ retortingmethods are being developed for use in the PiceanceCreek basin. The Shell In Situ Conversion (ICP) pro-cess uses vertical heating and production wells, withcontainment by an outer freeze-wall. Heating is accom-plished by an electrical resistance element, and thefreeze-wall is maintained by injection of chemical



refrigerant into an outer ring of wells spaced approxi-mately 8 ft apart. In contrast, ExxonMobil’s methodutilizes horizontal wells and hydraulic fracturing of theoil shale. Heating will be accomplished using a con-ductive proppant material (calcined petroleum coke), to

which an electrical current will be applied. Finally, theAmerican Shale Oil Company (AMSO) plans to useinclined wells, drilled below the stratigraphic level ofPiceance Creek basin evaporite minerals. All threemethods are currently undergoing field tests.


The History of US DOE Unconventional Energy Resources in the US, An Archive of References Available for Application to Current Oil Shale and Tar Sand Resources

Mroz, Thomas H.National Energy Technology Laboratory3610 Collins Ferry RoadMorgantown, West Virginia 26507

AbstractThe US Department of Energy (DOE) has partic-

ipated in a large number of energy projects related toall aspects of conventional and unconventional energyresearch over the last four decades. Resourcesaddressed in these projects include secondary and ter-tiary enhanced oil recovery, coal-bed methane, tightsands, oil shale, tar sands, gas shale, gas hydrates anddeep gas. The current projects at the National EnergyTechnology Laboratory include enhanced oil recovery,oil shale and tar sands, deep gas, and gas hydrates. Theinformation presented in this paper is related to the his-

toric projects and the results from case studies,production mechanisms, environmental aspects, andtechnology development producing results that reducedthe costs of locating, evaluating, and producing theseresources in the US, during the last forty years. Theinformation is available through the DOE web site,http://www.netl.doe.gov. Included on the website arelinks to the University of Utah and the Colorado Schoolof Mines for access to further references related specif-ically to oil shale and tar sand research.

http://www.netl.doe.gov


Tight-Gas Sandstone Reservoirs: The 200-Year Path from Unconventional to Conventional Gas Resource and Beyond

Coleman, JamesU.S. Geological SurveyMail Stop 956 National Center12201 Sunrise Valley DriveReston, Virginia. 20192

AbstractThe evolution of tight-gas sandstones from

unconventional to conventional gas reservoirs in theUnited States began with hydrocarbon exploration andproduction from the Appalachian Basin during the first

half of the 19th century, when brines were the preferredproduct, and petroleum was the unconventional andgenerally undesired product. During the next 100 years,rapid development of petroleum extraction and deliverytechnology fed an increase in petroleum demand, suchthat low flow-rate reservoirs were uneconomic andunable to meet the national need. These low-flow ratereservoirs were rejected in favor of high flow-rate res-ervoirs in California, the Midcontinent, and the GulfCoast. Even then, vast amounts of natural gas wereflared off or vented, because no market existed formuch of this produced gas.

With each successful discovery from these areas,the U.S. natural gas supply progressively exceededdemand and pipeline deliverability throughout the first

half of the 20th century. In response to the “energy cri-

sis” of the 1970’s, the Federal government removedprice controls on interstate natural gas in 1978 and cre-ated new tax incentives in 1980 to help offset the costof drilling and producing unconventional gas reser-voirs, including tight-gas sandstones. These decisionshelped spawn a new industry and prompted geoscien-tists to examine the geological conditions that createdand preserved large volumes of natural gas in low-per-meability reservoirs.

Tight-gas sandstone reservoirs exist in a widevariety of settings, ranging from simple one-well accu-mulations to complex montages of multilayered sandbodies requiring thousands of wells to develop. Theymay have a reasonably well-defined geologic limit orappear to have no spatial association with any easilydiscernible mappable geologic phenomena. Under-standing the true nature and future potential of yet-to-be-developed, tight-gas sandstone reservoirs is essen-tial for the nation to supply its annual need for gas for

the 21st century.


Many Technologies Applied to Develop Wattenberg Field, a Giant in Denver’s Backyard

Birmingham, Thomas J.Anadarko Petroleum Corporation

1099 18th St. #1800Denver, Colorado 80202

AbstractSince its discovery in 1970, Wattenberg has been

a prolific oil and gas field in the Rocky Mountainregion. Having 4.2 TCFE produced to-date and esti-mated EURs conservatively projected to exceed 5.5TCFE, Wattenberg ranks as the 8th largest gas field inthe U.S. Production was first established from the Cre-taceous J Sandstone, a pervasive delta-front shorelineand valley fill sequence covering a significant portionof northeast Colorado. In the early 1980’s, commercialproduction from the Cretaceous Codell and Niobraraformations established low-risk multiple pay optionsover the entire field area, which underwent strongexploitation phases during the 1990’s and 2000’s. TheCodell represents marine shelf bar and bar marginsandstone deposits. The Niobrara is represented by adeep water chalk environment of deposition. All pro-ducing units in Wattenberg are classified as tight gasreservoirs, having in situ permeabilities ranging from0.01 to 0.0001 md and requiring hydraulic fracturestimulation to achieve commercial results.

Multiple generations of technological improve-ments in drilling, petrophysics, and completionpractices have been applied in Wattenberg during fourdecades of field development. Operational and loggingmethods include directional and pad drilling, horizontaldrilling, infill drilling, FMI, CMR, and ECS logging,and new commingling of pay groups. Reservoir meth-ods include advances in hydraulic fracturing, micro-seismic evaluations, petrophysical/saturation modeling,facility automation, subsurface ties to outcrop sections,pressure/volumetric studies, and fault sealing analyses.More recent studies tying outcrops to subsurface sec-tions of isolated shelf sand bodies may providepotential opportunities for new generation plays andincrease current reserve estimates.

In the future, Wattenberg will continue as amajor gas field. Its proximity to the metropolitan corri-dor in eastern Colorado will provide that area with aconvenient low-cost source of energy supply.


Geology of the Piceance Mesaverde Gas Accumulation

Cumella, Stephen P.Bill Barrett Corporation1099 18th Street, Suite 2300Denver, Colorado 80439

AbstractAggressive development of the Mesaverde gas

accumulation in the Piceance Basin over the pastdecade has demonstrated that a commercial gasresource is present in much of the deeper part of thebasin. Unlike tight gas resources in some other basins(e.g., the greater Green River Basin), commercial pro-duction doesn’t appear to be limited to specificfairways or sweet spots. There appears to have been asufficient gas source within in situ coals and underlyingmarine shales to pervasively gas charge up to 3500 ft ofthe Mesaverde. An extensive vertical fracture systemhas resulted from over pressuring from hydrocarbongeneration. Laramide tectonic fractures are also locallyabundant. This fracture system has enabled vertical gasmigration within an otherwise very low permeabilitysystem.

In spite of being one of the oldest areas of tightgas production in the Rocky Mountain region, innova-tions in drilling and completion technology continue toexpand the area of commercial production. Directionaldrilling has allowed over 20 bottom-hole locations tobe accessed from a single surface location, and lateralsreach up to 5000 ft. Microseismic imaging of hydraulicfracture stimulation has helped place bottom-hole loca-tions optimally with regard to highly elliptical drainagepatterns. Large water volume hydraulic fracturing hasdramatically improved estimated ultimate recoveries(EURs) of wells in some areas. Also, unconventionalpay picking has added significant resources that werenot previously developed.


Fracture Diagenesis and Producibility in Tight Gas Sandstones

Laubach, Stephen E.Bureau of Economic GeologyJackson School of GeosciencesThe University of Texas at AustinAustin, Texas 78713-8924, [email protected]

Olson, Jon E.Department of Petroleum & Geosystems EngineeringCockrell School of EngineeringThe University of Texas at Austin1 University Station C0300Austin, Texas 78712, USA

Eichhubl, PeterBureau of Economic GeologyJackson School of GeosciencesThe University of Texas at AustinAustin, Texas 78713-8924, [email protected]

AbstractFractures in tight gas sandstone remain challeng-

ing to characterize or predict accurately. Here werecapitulate recent work on continuity of fractureporosity and its important effect on fluid flow. Naturalcement precipitation (diagenesis) in fractures can pre-serve fluid conduits by propping fractures open orotherwise reducing stress sensitivity of fracture perme-ability. It can also impede fluid flow by reducingeffective fracture length, or occluding porosity. Wereport patterns of natural fracture growth and decaythat are extensively influenced by diagenesis. These

patterns typify many fractured siliciclastic and carbon-ate rocks. We show how appreciation of diageneticeffects can be used to improve accuracy of predictionsof fracture attributes and illustrate implications forfluid-flow simulation. Our results also imply that frac-tures will not tend to close under subsurface loadingconditions in many tectonic settings. Chemical altera-tion and the interactions of diagenetic reactions withrock properties and the in situ stress dictate the locationof open fractured flow conduits.




Case Studies Examining the Discovery Sequence and Gas Accumulations in Tight-Gas Sandstones

Coleman, James Attanasi, Emil U.S. Geological SurveyMail Stop 956 National Center12201 Sunrise Valley DriveReston, Virginia. 20192

AbstractAn examination of the geologic characteristics

and discovery history of seven plays, which were origi-nally classified by the U. S. Geological Survey (USGS)in 1995 as continuous-type gas sandstone plays, showsthat these plays have a high degree of similarity withconventional discrete accumulations in terms of reser-voir continuity, sand body geometry, and trappingconfigurations. The general decline in discovery sizewith increasing numbers of discoveries suggests ameans to put limits on volumes of resources assessed inun-drilled areas of a particular play.

Routine time-series analyses of conventionalplays typically show a decline in field discovery size aseach subsequent discovery within the play trend isannounced. If gas accumulations in low-permeabilitysandstone plays occur in trap settings typical of dis-crete conventional accumulations, then modeling of thediscovery sequences within plays may provide an

effective way to constrain regional estimates of remain-ing recoverable resources. At the other extreme, if theplay is regarded as a single homogeneous continuousentity (albeit, with some “sweet spots”), only the playboundary constrains the number of un-drilled sites thatcould contribute to remaining recoverable resources,and there should be no general decrease in discoverysize.

The seven continuous-type gas sandstone playsselected for this study had a sufficient number of obser-vations to test whether discovery size correlates withsequence of discovery. These showed that discoverysize tends to decline with sequence of discovery and inthree of the seven the trend was statistically significant.The discovery size rank and sequence relationship wasfound to be similar to several well known conventionalplays.


Author Index A-1

Author Index

AAttanasi, Emil, 27Ayers, Walter B., 8

BBirmingham, Thomas J., 24Boswell, Ray, 3Boyce, Matthew L., 13

CCarr, Timothy R., 13, 19Carroll, Alan R., 20Chaouche, A., 12Coleman, James, 23, 27Collett, Timothy S., 2, 3Cook, Ann, 3Cumella, Stephen P., 25

DDai, Jianchun, 3DeAngelo, Mike, 7Dufrene, Rebecca, 3

EEastwood, Ray, 9Eichhubl, Peter, 26Ewing, Thomas E., 10

FFrye, Matthew, 3Fulk, Bryant, 11

GGarrity, Christopher P., 11Godfriaux, Paul, 3Guerin, Gilles, 3

HHammes, Ursula, 9Hardage, Bob, 6, 7Holditch, Stephen A., 8

Houseknecht, David W., 11

JJenkins, Creties, 14Johnson, Arthur H., 5Jones, Emrys, 3

LLaubach, Stephen E., 26

MMartin, Bruce J., 10McConnell, Dan, 3Milici, Robert C., 11Mroz, Thomas H., 22Mrozewski, Stefan, 3Murray, Paul, 7

NNewell, K. David, 19

OOlson, Jon E., 26

PPalmer, Ian, 17Pashin, Jack, 18Potter, Eric C., 1

RReed, Robert M., 9Rowe, Harry D., 9

SSava, Diana, 6, 7Scott, Andrew R., 15Shedd, William, 3Shelander, Dianna, 3

TTinker, Scott W., 1

2009 Program and Abstracts - GCSSEPM Home€¦ · shale gas. As a result according to the Potential Gas Committee (June 18, 2009), the nation’s estimated gas reserves have surged

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