A FUEL LIFELINE The energy crunch What is oil …mechanical-fet.weebly.com/uploads/2/7/9/3/27933099/oil...world’s oil supply. > In addition to oil shale, the focus of this review,

OIL SHALE

OIL SHALE: A FUEL LIFELINEThe energy crunchWhat is oil shale?A long historyFrom rock to oilExploding the mythsProjects in the pipeline

Executive summary 2The energy crunch 4What is oil shale? 6A long history 7Past projects 8Where is oil shale found? 10Evaluating oil shale quality 14From rock to oil: 15 How oil shale is extracted and processedEconomic considerations 22Exploding the myths 23Mining: the benefits 29Projects in the pipeline 31Conclusions 36

Appendices I. Other unconventional liquid hydrocarbon fuels 38 •Coaltoliquids 38 •Heavyoil 38 •Oilsands 39 •Gastoliquids 43Comparison table of unconventional fuels 44II.Geographicaldistribution 44III.Glossary&abbreviations 45IV. References 45

CONTENTS

This guide has been produced on behalf of the oil shale industry. It gives an overview of the global energy dilemma, explores the viability of oil shale as an alternative source of fuel, explains the various extraction and processing technologies used and tackles some of the myths surrounding the production of synthetic crude oil (SCO) from oil shale.

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World energy demand> Global energy demand is

predicted to soar by 44% over the next two decades with petroleum still accounting for the biggest share of the world’s energy mix.

> Developing countries are driving demand, accounting for 75% of the expected increase.

> Industry estimates are that global conventional oil reserves will be exhausted in 42 years at current rates of production.

alternative energy sources> Whereas conventional oil

resources are dwindling, the world has plentiful unconventional oil resources that could extend the world’s oil supply.

> In addition to oil shale, the focus of this review, other potential resources include coal-derived liquids, gas to liquids options and heavy oil and tar sands. An overview of these resources and their geographic distribution is contained in appendices at the end of this review.

oil shale> Oil shale is a fine-grained

sedimentary rock that contains a waxy organic substance known as kerogen. When heated, kerogen decomposes to yield oil, gas and carbon.

> High grade oil shale with >10% kerogen can be burned without processing and has been used as a fuel for thousands of years. In Europe, oil was first extracted from oil shale in the early 1300s. Shale oil has been extracted in Europe, North America, Brazil, Australia and New Zealand for

eXecutive summaryWhat haPPens When the oil runs out?

power generation and oil production but in the latter half of the 20th century the industry found it increasingly difficult to compete with a rapid increase in the production of crude oil.

> In recent years, interest in oil shale has revived due to higher oil prices and concern about future supplies from conventional resources.

> Oil shale is widely distributed around the globe. Deposits can be small in size or cover thousands of square kilometres and the oil content varies greatly. The largest known deposit, the Green River Formation in the western US is estimated to contain the equivalent of 1.5 trillion barrels of oil.

Past and Present oPerations> Current producers include China,

Estonia and Brazil. Estonia has been the leading producer, with peak power output attained in 1980 when 31.4 Mt of oil shale were mined. China has now overtaken Estonia and in 2007 it produced 345,000 t of shale oil, most of it for use as fuel oil. In the past there have been various oil shale mining projects in the western US and considerable research and development continues there.

From rock to oil> To date, the extraction of shale

oil from the ground has been principally accomplished by conventional, truck-and-shovel open-pit mining techniques, with the mined product transported to surface retorting facilities for refining into shale oil (synthetic crude oil). However, more recently a range of in situ techniques have been developed by the major oil

companies such as Shell, ExxonMobil and Chevron.

> There are numerous processing methods, each of which has both advantages and disadvantages. The main consideration is the cost of producing a barrel of oil and factors include the amount of energy and water consumed, the ability (of the process) to recycle the waste heat and gases generated and the conversion of the spent shale into a useful and saleable by-product.

evaluating oil shale quality> Oil shale deposits vary widely in

organic content and oil yield, and most commercial grades are in the range 100–200 l/t.

> By-products, including uranium, vanadium and phosphate can add considerable value to oil shale deposits: the ‘waste’ heat generated during retorting can be recycled as a valuable by-product, and spent oil shale is used in a growing number of industrial applications.

eXPloding the myths The mining and processing of oil

shale arouses heated debate and considerable opposition from various environmental lobbies with some concerns justified and others not. Many objections relate to long-established operations using old technology. Key considerations include:

> Water usage> Greenhouse gas emissions> Pollution> Land use and waste management> Energy efficiency

This review addresses these issues and argues that a modern oil shale extraction project should generate an environmental footprint that is neither heavier nor lighter than those generated by secondary and tertiary conventional oil production, as well as other essential industrial activities such as road-building, farming, forestry, urbanisation and tourism.

social and economic beneFits Most surface oil shale projects

now under consideration will use conventional open-pit mining methods, and will provide the same social and economic benefits as other mining and minerals processing projects. These can include the provision of jobs and training for local communities, improved transport and communications, new medical and educational facilities and opportunities to develop local service industries.

Governments benefit from mining projects through increased tax revenues, reduced dependence on mineral imports and foreign currency requirements, as well as reduced unemployment, technology transfer and major foreign investment.

The downstream activities of an oil shale project, namely the refining of the oil shale into synthetic crude, the recycling of ‘waste’ heat and the production of saleable by-products from the spent shale,

all provide valuable additional employment, training and technology transfer.

Projects in the PiPeline A number of new oil shale projects

are in the pipeline, particularly in China, and there also significant projects under way in Jordan and Morocco, both of which possess large resources of oil shale but no significant resources of conventional oil and gas. In Australia, an oil shale project that was suspended a few years ago is being resurrected under new ownership and using a different technology.

economics> In line with the Canadian oil sands

sector where unit cash costs have steadily decreased over the past 20 years, technological developments and economies of scale are resulting in reduced operating costs for oil shale ventures.

> With capital costs of oil shale projects often considerably lower than oil sands projects due to a more amenable environment and better energy integration, some operators claim they will be able to produce shale oil profitably at cash costs of less than $20 a barrel.

> The latest figures quoted for new oil sands projects indicate capital cost figures as high as $120-150,000 per flowing daily barrel. Oil shale ventures, whether using surface retorting or in situ processes, fall into a similar range although figures as low as $80–

100,000/bbl have been quoted for some particularly low-cost environments.

> Conventional oil reserves now costing around $20-25/barrel to replace compared to $2-5/barrel for oil shales, non- conventional sources of oil will become an increasingly attractive financial proposition.

conclusions> Forecasts by the International

Energy Agency and the Energy Information Agency in the US conclude that petroleum will continue to form the largest share of the energy mix for the next 20 years and that conventional oil resources are dwindling.

> Demand however for liquid hydrocarbons is expected to grow strongly, especially in the developing world where China and India are likely to dominate consumption.

> Oil prices will rise strongly and this will make the cost of extracting oil shale increasingly attractive from an economic point of view.

> A constant improvement in processing technologies, quality of operations and international environmental standards (such as the Equator Principles) will make the recovery of oil shale environmentally more acceptable than has been the case to date.

Global conventional oil reserves will be exhausted in 42 years

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In May 2009, in a new forecast to the year 2030, the Energy Information Administration (EIA), the leading energy-forecasting agency for the US Government, has predicted that world production of unconventional oil resources will “quadruple to 13.4 million barrels of oil per day, representing 13% of total global petroleum supplies”. It also predicts that by 2030 renewable energy, like wind and solar power, will be the fastest-growing energy source, making up 11% of global energy supplies, and that China’s electricity generation from coal-fired power plants will triple.

The EIA expects global energy demand to soar by 44% over the next two decades, with petroleum still accounting for the biggest share of the world’s energy mix. The agency acknowledges that the current worldwide economic downturn is dampening world demand for energy in the near term, as manufacturing and consumer demand for goods and services slows. In the longer term, however,

economic recovery is anticipated after 2010, and most nations, it says, should return to trend growth in income and energy demand. Oil prices should also rebound and US crude oil costs are forecast to rise from an average US$61/barrel in 2009, to US$110 in 2015 and US$130 in 2030, the agency says.

develoPing countries drive demandGlobal oil demand is expected to reach 197 million barrels of oil per day (Mbbl/d) over the next two decades, up from 84 Mbbl/d this year, and could account for 32% of world energy supply by 2030.

Almost 75% of the expected increase in global energy demand through 2030 will occur in developing countries, particularly China, India, Russia and Brazil, the agency said. It expects that the Organisation of Petroleum Exporting Countries (OPEC) will continue to provide 40% of the world’s oil supplies during the period.

the energy crunch

Global energy demand is expected to increase by 44% over the next two decades

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ReferenceHigh world oil priceLow world oil price

World oil prices in three price cases (us dollars per barrel)

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The Asia- Pacific region accounted for 87% of the world’s energy consumption growth, and for the third consecutive year, coal accounted for the majority of primary energy consumption growth. Chinese consumption growth slowed for the fifth consecutive year, yet China accounted for nearly three-quarters of global growth. Consumption in the US fell by 2.8%, the largest decline since 1982.

Last year, global oil consumption declined by 0.6%, or by 420,000 bbl/d, the first decline since 1993 and the largest decline since 1982. By contrast, global oil production increased by 0.4%, or by 380,000bbl/d, to 81.8 Mbbl/d.

BP estimates that global proved oil reserves are sufficient to last for only 42 years at current rates of production. The search for viable, alternative sources of energy is becoming increasingly urgent. Oil shale is one such source.

The EIA says its long-term forecast does not reflect any efforts the US may make to cut its greenhouse gas emissions, or an expected new international agreement to curb greenhouse gases. If global climate change laws and policies don’t change, world energy-related CO2 emissions will rise by one-third to 40,000 Mt/y, the agency said.In its 2009 edition of Statistical

Review of World Energy, BP says that primary energy consumption – including oil, natural gas, coal, nuclear and hydro power – grew by 1.4% in 2008, the slowest growth since 2001, and that non-OECD primary energy consumption exceeded OECD consumption for the first time.

We are not good at recognising distant threats, even if their probability is 100%. Society ignoring peak oil is like the people of Pompeii ignoring the rumblings below Vesuvius. James Schlesinger, former US Energy Secretary

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increasing demand for oil (quadrillion btu) LiquidsNatural GasCoalNuclearRenewables

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Historically, oil shale has been referred to by many different names, such as cannel coal, boghead coal, alum shale, stellarite, albertite, kerosene shale, bituminite, gas coal, algal coal, wollongite, schistes bitumineux, torbanite, and kukersite. Some of these names are still used for certain types of oil shale.

It is a fine-grained sedimentary rock containing a waxy organic matter known as kerogen. Oil shale deposits appear to have formed through the burial and compaction of algal swamps by overlying sediments resulting in the conversion of the organic matter to kerogen by a process known as diagenesis. When the oil shale is subjected to sufficient heat the kerogen will decompose to yield oil, gas and residual carbon. The chemical decomposition (pyrolysis) of kerogen begins at a temperature of around 300°C but is most effective at 480°–520°C. Heating is accomplished in retorts.

Recently, attempts have been made to systematically classify the many different types of oil shale on the basis of the depositional environment of the deposit, the petrographic character of the organic matter, and the original organisms from which the organic matter was derived. The composition of oil shale varies considerably — in some deposits, carbonate minerals such as calcite are dominant, in others, detrital minerals such as quartz and clays predominate. The various depositional environments include lakes, shallow seas and lagoons.

Unlike crude oil, oil shale is in abundant supply. The US Geological Survey (USGS) estimates that there are 2.5 to 3 trillion barrels of proven oil shale reserves worldwide – more than double the world’s recoverable crude oil resources.

As the planet’s largest source of untapped liquid hydrocarbons, oil shale can considerably extend the world’s oil supply.

What is oil shale?

There are 3 trillion barrels of proven oil shale reserves worldwide

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It has also been used as a decorative stone. In Britain there are polished ornaments of oil shale dating from the Iron Age and the Greeks and Romans used it in mosaics. Elsewhere, shale oil was used for medical and military purposes, and the Mongols are reported to have tipped their arrows with flaming oil shale.

The first records of oil being extracted from oil shale in Europe date from the early 1300s, and at the end of the 17th Century shale oil was being produced in England from oil shale mined in Shropshire. At that time, oil distilled from oil shale was also being used for streetlights in Modena, Italy.

The first production of oil from oil shale on an industrial scale was developed in France in the 1830s when the chemical decomposition (pyrolysis) of oil shale was achieved by heating oil shale in a retort. In 1850, a Scottish chemist, James Young patented a process to produce lighting oil, lubricating oil and wax from oil shale, and over the next fifty years, shale oil was being extracted in several countries in Europe, as well as in North America, Brazil, Australia and New Zealand. The main focus was on the production of kerosene, lamp oil and paraffin. Thereafter, the industry found it increasingly difficult to compete with the increased production of crude oil.

A revival in oil shale began immediately prior to World War I, partly because of limited access to conventional petroleum resources and partly as a result of increased demand for petroleum brought about by the start of mass production of cars and trucks. Interest in oil shale projects continued until the 1950s and 1960s but producers were finding it increasingly difficult to compete with the growing availability of cheaper petroleum. In recent years, interest in the world’s vast oil shale resources has been renewed because of higher oil prices and the diminishing reserves of conventional oil.

a long history

Because oil shale can be burned without being processed it has been used as a fuel for thousands of years. In the Middle East, ‘rock oil’ was used in Mesopotamia around 3,000 BC as a road construction material and for making architectural adhesives.

We have embarked on the beginning of the last days of the age of oil

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oil shaleCredit: Argonne National Laboratory

Brazil, China and Estonia have produced shale oil on a commercial scale for many years (since the 1920s in the case of Estonia), while countries such as Australia, Jordan and Morocco have a number of oil shale projects at the planning stage. There is also considerable interest in the US and several research and demonstration projects are underway in Colorado and Utah.

brazilBrazil possesses one of the world’s largest oil shale resources and development of the country’s oil shale industry began in 1954, with the establishment of the national oil company, Petroleo Brasileiro SA (Petrobras). One of its divisions, Superintendéncia da Industrialização do Xisto (SIX), was charged with the development of the country’s oil shale deposits. Early work concentrated on the Paraíba oil shale, but later focused on the Iratí shale.

A prototype oil shale retort and a 1,600 t/d capacity prototype treatment facility near São Mateus do Sul began operations in 1972. Since then the Petrosix plant has produced in excess of 20 Mbbl of shale oil. The retort burns gas and is the largest pyrolysis reactor in the world.

chinaChina’s Fushun Mining Group (FMG) is reported to have produced 300,000 t of shale oil at its operations in Liaoning Province in 2007, using 180 Fushun-type retorts, each with the capacity to process 100 t/d of oil shale. There were plans to add a further 40 retorts and to add a new 6,000 t/d capacity ATP processor by the end of 2009. Elsewhere, oil shale projects are either going ahead or under consideration in the provinces of Gansu, Guangdong, Heilongjiang and Jilin.

estoniaEstonia has long been a world leader in the mining and processing of oil shales. It operates the world’s two largest thermal power plants fired by oil shale, which generate more than 90% of Estonia’s power supply. The oil shale industry employs around 7,500 people, accounting for about 1% of national employment and 4% of GDP.

Although recognised as early as the 1700s, Estonia’s kukersite deposits were first actively explored during World War I as a result of fuel shortages. Open-pit mining began in 1918 at an annual rate of 1,700 t, and by 1940 annual production had reached 1.7 Mt. After World War II, during the Soviet era, production climbed dramatically, peaking in 1980 when 31.4 Mt of oil shale was mined from eleven open-pit and underground mines.

In 2005, Estonia mined 14.8 Mt of oil shale and produced 345,000 t of shale oil. Of this amount, around 80% was used to fuel pulverised combustion and circulating fluidised beds in power stations. A further 16% was processed into petrochemicals, and the remainder was used to manufacture cement as well as other minor products. However, Estonia badly needs liquid fuels, hence a number of companies intend to convert more of their oil shale to liquid fuel and gas.

The companies mining oil shale in Estonia are Eesti Põlevkivi, Viru Keemia Grupp (VKG), Kiviõli Keemiatööstus and Kunda Nordic Cement. As of 2007, there were six underground and open-pit mines in operation and one new mine in the preparation phase.

The Aidu and Narva open pits, operated by Eesti Põlevkivi, use conventional surface mining techniques, including up to 35 m3 capacity bucket excavators. Blasting is needed to break up both the overburden and the oil shale. Where the overburden is shallow, stripping is accomplished using front-end loaders and hydraulic excavators. The Aidu mine uses bulk extraction of all beds, whereas at Narva and the Põhja-

Past Projects

an estonian oil shale processing plant

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Kiviõli open pit (operated by Kiviõli Keemiatööstus), three seams are mined individually. Underground mines use room-and-pillar extraction methods; longwall mining was abandoned in the 1990s. The largest mine, Estonia, opened in 1972 and is operated by Eesti Põlevkivi.

Estonia’s present open-pit mines will eventually need to be converted to more expensive underground operations as the deeper oil shale is mined.

Such extensive mining activity has inevitably taken its toll on the environment but this is now being redressed. Exhausted open-pit areas are gradually being regenerated through land recultivation and reforestation and environmental studies conducted to ameliorate the environmental degradation of the land affected by oil shale mining.

Three companies in Estonia produce shale oil: VKG Oil (a subsidiary of Viru Keemia Grupp), AS Narva Elektrijaamad (a subsidiary of Eesti Energia) and Kiviõli Keemiatööstus. All three producers have expansion plans and Oil and Gas Journal reports that Eesti Energia intends to build a new shale oil plant and produce up to 0.5 Mt/year of oil for sale by 2010. Its two existing plants produce around 2,500 bbl/d.

united statesThe existence of major oil shale resources in the Green River Formation in Colorado, Utah and Wyoming has been known since the early 1900s and efforts made to commercialise the deposits following the oil price rises in the early 1970s.

In the late 1970s, the US Bureau of Mines opened an experimental mine that included a 723-m-deep shaft with several room-and-pillar entries in the northern part of the Piceance Creek Basin. The site was closed in the late 1980s.

In Utah, three companies spent a total of some $US80 million on a 313 m vertical shaft and haulage incline to access a zone of high-grade oil shale. The Seep Ridge project produced shale oil by a shallow in situ retorting method and several thousand barrels of shale oil were produced. The project was funded by Geokinetics Inc, along with the US Department of Energy.

The Unocal oil shale plant was the last major project to produce shale oil from the Green River Formation. Plant construction began in 1980 and capital investment for constructing the mine, retort, upgrading plant, and other facilities was US$650 million. Unocal produced 657,000 t of shale oil and the average rate of production in the final months of operation was about 875 t/d of shale oil. Operations ceased in 1991.

In recent years, Royal Dutch Shell subsidiary, Shell Oil Co, has experimented with its proprietary in situ conversion process to recover shale oil from the Green River Formation in Colorado, which is estimated to contain the equivalent of 1.5 trillion barrels of oil.

the unocal plant in colorado, usa, produced a total of 657,000 t of oil shale

estonia’s narva oil shale processing plantsetting of estonia’s narva oil shale processing plant

and a total resource estimated at 2.0 billion barrels. The oil shale of the Iratí Formation has the greatest economic potential because of its accessibility, grade, and widespread distribution.

chinaChina’s main oil shale research institution, China University of Petroleum, estimates China’s total oil shale resource at 720 billion tonnes in 80 deposits distributed in 47 oil shale basins. This is equal to 48 billion tonnes of shale oil. Proven reserves are estimated at about 36 billion tonnes.

There are two main resources of oil shale in China: Fushun and Maoming. The Fushun oil shale deposits are located in northeastern China, in Liaoning Province. They are Eocene in age, of lacustrine origin and 48–190 m thick. They are underlain by the Guchengzi Formation, comprising sub-bituminous to bituminous coal, carbonaceous mudstone and shale, and sandstone lenses. The oil shale is exploited as a co-product of coal mining.

In the West open-pit coal mine near the town of Fushun, there are six coal seams as well as a cannel coal 1–15 m thick. (The cannel coal is used for decorative carving, and some of the sub-bituminous coal contains red to yellow gem-quality amber.) Oil shale resources at the West mine are estimated at 260 Mt, of which 235 Mt (90%) is considered mineable. The total oil shale resource at Fushun is estimated at 3,600 Mt. The shale from the West mine averages 7–8% oil (78–89 l/t). The open pit is about 6.6 km long

Oil shale deposits have a global distribution, and can range from Cambrian to Tertiary in age. They can be marine, lacustrine or continental in origin. The smallest deposits are of little or no economic value but the largest can cover thousands of square kilometres in areal extent and be several hundreds of metres in thickness.

In a survey of a selected group of oil shale deposits in 33 countries, the US Geological Survey estimates a total resource of 371 billion tonnes (2.8 trillion barrels) of shale oil and stresses that these estimates could prove very conservative.

The largest and richest known deposit by far is the Green River oil shale in the western US. In Colorado alone, the total resource reaches one trillion barrels, of which one-quarter to perhaps as much as one-third may be recoverable with currently available mining and processing techniques.

Although commonly associated with coal deposits, oil shale differs in several ways in terms of mineral and elemental content. Oil shale can contain much larger amounts of inert mineral matter (60–90% compared with less than 40% for

coal), and the organic matter in oil shale, which is the source of liquid and gaseous hydrocarbons, typically has a higher hydrogen and lower oxygen content than that of lignite and bituminous coal.

The following appraisal of world oil shale resources draws heavily on USGS data and is not exhaustive.

australiaDemonstrated resources total 58,000 Mt, from which some 3,100 Mt of oil (24 billion barrels) could be recovered (Crisp and others, 1987). Those deposits having the best potential for economic development are located in Queensland. They include the Condor, Rundle and Stuart lacustrine deposits, all of Tertiary age.

Elsewhere in Australia, torbanite deposits at Joadja Creek and Glen Davis in New South Wales and tasmanite deposits in Tasmania were mined in the second half of the 1800s and into the early 1900s. The deposits are high grade but the remaining resources are not deemed to be commercially significant. In total, about 4 Mt of oil shale were mined in Australia between 1860 and 1952

brazilAt least nine deposits of oil shale are known in Brazil ranging in age from Devonian to Tertiary. The two more significant deposits include the Tertiary-age lacustrine oil shale in the Paraíba Valley in the State of São Paulo, and the oil shale of the Permian Iratí Formation in southern Brazil. In the Paraíba Valley, drilling has defined reserves of 840 million barrels in two areas covering 86 km2

Where is oil shale Found?

oil shale exploration in colorado, usa

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and 2.0 km wide, and 300 m deep at the west end. In addition, two underground mines lie just east of the open-pit mine.

The Tertiary-age Maoming oil shale deposit in Guangdong Province extends for 50 km, is 10 km wide and 20–25 m thick. Total reserves of oil shale are estimated at 5,000 Mt, of which 860 Mt are in the Jintang mine. The deposit averages 4–12% shale oil, with an average of 6.5%.

estoniaDeposits of kukersite, a marine type of oil shale of Ordovician age, cover an area of more than 50,000 km2 in northern Estonia. The deposits extend eastward into Russia toward St. Petersburg, where they form the so-called Leningrad deposit.

As many as 50 beds of kukersite and kerogen-rich limestone alternating with biomicritic limestone are recognised, and form a sequence 20–30 m thick. Individual beds are typically 10–40 cm thick but can reach 2.4 m. The richest-grade kukersite gives oil yields as high as 320–500 l/t. Proved and probable reserves of kukersite are estimated a 5,940 Mt, and the total resource could be as much as 6,300 Mt.

estimated resourcesBillion barrels shale oil

demonstrated resourcesBillion barrels shale oil

Worldwide oil shale locations

1. usa 21002. australia 1503. russia 1504. jordan 1005. brazil 80

1. usa 5602. china 603. australia 504. jordan 305. brazil 20

estonian oil shale

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israelTwenty marine limestone deposits of Cretaceous age have been identified in Israel containing about 12,000 Mt of oil shale reserves with an average oil yield of 6% by weight, or 60–71 l/t. Thicknesses of the deposits range from 5 m to 400 m.

Some of the deposits can be mined by open-pit methods, and a commercially exploitable bed of phosphate rock, 8–15 m thick, underlies the oil shale in the Mishor Rotem open-pit mine. At the Rotem-Yamin deposit, about 55 t/h of oil shale were burned in a fluidised bed boiler to power a steam turbo-generator in a 25 MW experimental electric power plant operated by PAMA Co. The plant began operation in 1989 but is now closed.

jordanJordan possesses the world’s 4th largest resources of oil shale with 26 known deposits, some of them large and of relatively high-grade. The most important are: Juref ed Darawish, Sultani, Wadi Maghar, Al Lajjun, Attarat Umm Ghudran, Khan ez Zabib, Siwaga, and Wadi Thamad. All eight are in west central Jordan and those drilled most extensively are Al Lajjun, Sultani, and Juref ed Darawish.

All the deposits are of marine origin and range in age from Late Cretaceous to early Tertiary. Most of the deposits are at shallow depth and the beds are generally sub-horizontal. They are overlain by unconsolidated gravel and silt containing some stringers of marlstone and limestone and occasionally basalt. It is estimated that as much as 60% of the oil shale is amenable to open-pit mining.

The oil shales thicken to the north where the Yarmouk deposit appears to extend into Syria. Research indicates that Yarmouk may eventually prove to be an exceptionally large deposit, covering several hundred square kilometres and several hundreds of metres thick.

The oil shales in central Jordan are in a marine chalk-marl unit, underlain by phosphatic limestone and chert. The oil shales are typically brown, gray, or black and weather to a distinctive light bluish-gray.

The moisture content of the oil shale is low (2–5.5% by weight). Calcite, quartz, kaolinite, and apatite make up the major mineral components at Al Lajjun, along with minor amounts of dolomite, feldspar, pyrite, illite, goethite, and gypsum.

The sulphur content of Jordanian oil shale is in the 0.3–4.3% range, although in the Jurf ed Darawish and Sultani deposits it is high, at 8% and 10%, respectively. The metal content of the Jurf el Darawish, Sultani, and Al Lajjun oil shale deposits is relatively high, e.g. Cu 68–115 ppm, Ni 102–167 ppm, Zn 190–649 ppm, Cr 226–431 ppm, and V 101–268 ppm. At El Hasa, the oil shale is underlain by phosphate rock.

moroccoOil shale deposits have been identified at ten localities in Morocco, with the most important deposits being Late Cretaceous marinites. The Timahdit and Tarfaya deposits have been explored most extensively.

Timahdit, located about 250 km southeast of Rabat, underlies an area about 70 km long and 4–10 km wide within a northeast-trending syncline. The thickness of the oil shale is in the 80–170 m range and total reserves are estimated at 18,000 Mt within an area of 196 km2. Oil yields are in the 20–100 l/t range and average 70 l/t.

Tarfaya, in southwestern Morocco, near the border with Western Sahara, possesses an oil shale resource estimated at 86,000 Mt within an area covering 2,000 km2. The oil shale averages 22 m in thickness and averages 62 l/t.

morocco – shell’s tarfaya project trial mine (1986-88) in 2007

typical oil shale area

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russiaRussia possesses more than 80 oil shale deposits capable of producing tens of billions of tonnes. The Leningrad kukersite deposit near St Petersburg is used as fuel to generate electricity in the Slansky power plant. Elsewhere, there are substantial oil shale deposits amenable to exploitation in the Volga-Pechersk oil shale province, including the Perelyub-Blagodatovsk, Kotsebinsk and Rubezhinsk deposits. Individual beds are up to 2.6 m in thickness but are high in sulphur. Formerly, the oil shale was used to fuel two power plants but operations were halted because of high sulphur emissions. It is reported that in 1995 an oil shale plant at Syzran was processing up to 50,000 t/y of oil shale.

sWedenThe alum shale of Sweden, a unit of black organic-rich marinite, forms a 20–60 m thick horizon laid down in a shallow marine-shelf environment during Cambrian to Lower Ordovician times. Post-depositional tectonic activity, including multiple thrust faulting, has resulted in thicknesses of alum shale of as much as 200 m in some areas. The organic content of alum shale ranges from a few percent to more than 20%, but oil yields are not in proportion to the organic content. For example, at Skåne and Jämtland in west-central Sweden oil yields are nil, although the organic content of the shale is 11–12%. In other areas, oil yields range from 2 to 6%.

syriaOil shales from the Wadi Yarmouk Basin on Syria’s southern border are believed to be part of the large Yarmouk deposit of northern Jordan. The strata comprise marine limestones (marinites) of Late Cretaceous to Palaeogene age. Oil yields, as estimated by the Fischer assay method, are about 7–12%.

thailandThailand possesses lacustrine oil shale deposits of Tertiary age near Mae Sot in Tak Province, and at Li in Lampoon Province. The Department of Mineral Resources has drilled the Mae Sot deposit extensively. The oil shale is a lamosite, has an areal extent of 53 km2 and contains an estimated 18,700 Mt of oil shale, which could yield 916 Mt of shale oil (6.4 billion barrels). Reserves at Li are modest – estimated at 15 Mt of oil shale yielding 50–171 l/t of oil.

turkeyLacustrine oil shale deposits of Paleocene to Eocene age and of late Miocene age are widely distributed in western Anatolia The host rocks are marlstone and claystone. Resource data are sparse as only a few of the deposits have been investigated. On the basis of available data, total resources of in situ shale oil for eight Turkish deposits are estimated at 284 Mt (about 2.0 billion barrels).

united statesWhile oil shale resources in the US could exceed 6 trillion barrels of oil equivalent, most deposits are of insufficient size or grade to be economically viable to exploit.

The U.S. Government owns and manages about 73% of the lands that contain significant oil shale deposits in the western US and federal lands contain about 80% of the known recoverable resources in Colorado, Utah, and Wyoming. Private companies own about 21% of the Piceance Basin in Colorado, 9% of the Uinta Basin in Utah, 24% of the Green River Basin in Wyoming and 10% of the Washakie Basin, also in Wyoming. State governments and localities, and Native American Tribes also own oil shale lands. (Ref: US Department of Energy, Office of Petroleum Reserves.)

Deposits range in age from Precambrian to Tertiary and the two most important are in the Eocene Green River Formation in Colorado, Wyoming and Utah, and in Palaeozoic black shales in the eastern US. In the western US, the lacustrine deposits of the Green River Formation underlie an area of some 65,000 km2 in a number of sedimentary structural basins. In the eastern US, black organic-rich marine shale and associated sediments of Late Devonian/Carboniferous age underlie an area of about 725,000 km2. These shales have been exploited for many years as a source of natural gas, but have also been considered as a potential low-grade resource of shale oil and uranium. The total resource has been estimated by the USGS at 61,000 Mt (423 billion barrels).

Relatively little is known about many of the world’s deposits of oil shale and much exploratory drilling and analytical work needs to be done. Resource evaluation is especially difficult because of the wide variety of analytical units that are used. The grade of a deposit can be expressed in US or Imperial gallons of shale oil per short ton of rock, litres of shale oil per metric tonne (l/t) of rock, barrels of oil, short tons or metric tonnes of shale oil, kilocalories per kilogram (kcal/kg) of oil shale, or gigajoules (GJ) per unit weight of oil shale. In this review, oil shale resources are given in metric tonnes of shale oil and in equivalent US barrels of shale oil. The grade of oil shale is expressed in litres of shale oil per tonne (l/t) of rock.

By-products, including uranium, vanadium, zinc, alumina, phosphate, sodium carbonate minerals, ammonium sulphate, and sulphur can add considerable value to some oil shale deposits. The ‘waste’ heat generated during retorting can be recycled as a valuable by-product, and the spent shale can be used to manufacture cement. Other products that can be made from oil shale include speciality carbon fibres, absorbent carbons, carbon black, bricks, construction and decorative blocks, soil additives, fertilisers, rock wool insulating material, and glass. Most of these applications are in their infancy or at the experimental stage.

determining the gradeOil shale varies widely in organic content and oil yield. Commercial grades, as determined by the yield of shale oil, range from about 100 to 200 litres per tonne (l/t) of rock. A variety of methods have been developed to determine the grade of an oil shale but probably the most commonly used laboratory method to measure the oil yield is the Fischer assay. The method was first developed in Germany and then adapted by the US Bureau of Mines (now part of the United States Geological Survey) for analysing the oil shale of the Green River Formation in the western US.

Today, a standardised Fischer assay method consists of heating a 100-gram sample crushed to – 8 mesh (2.38 mm mesh) screen in a small aluminium retort to 500ºC at a rate of 12ºC per minute. The sample is held at

that temperature for 40 minutes. The distilled vapours of oil, gas, and water are passed through a condenser cooled with ice water into a graduated centrifuge tube. Centrifuging then separates the oil and water. The quantities reported are the weight percentages of shale oil (and its relative density), water, shale residue, and “gas plus loss” by difference. The Fischer assay method does not determine the total available energy in an oil shale, nor does it necessarily indicate the maximum amount of oil that can be produced by a given oil shale. On a commercial scale some retorting methods, such as the Tosco II process, are known to yield in excess of 100% of the yield reported by Fischer assay. At best, the Fischer assay method only approximates the energy potential of an oil shale deposit.

evaluating oil shale quality

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Various technologies have been developed for the thermal treatment of oil shale, some of which are described here. They fall into two categories — those involving traditional mining methods (eg open pit or underground room-and-pillar) and surface processing, and those where heating of the shale takes in place in the ground, known as in situ methods.

the alberta taciuk Process (atP) Was developed in the 1970s by Canadian-based minerals processing engineer William Taciuk of UMATAC Industrial Processes. ATP is based on rotary-kiln technology that incorporates a petroleum refining unit. The distinguishing feature of the ATP is that the drying and pyrolysis of the oil shale (or other feed material) and the combustion, recycling, and cooling of the spent shale or residue, all occur in a single rotating multi-chamber horizontal retort. It also uses fine particles as a feed source.

An advantage of the technology for shale oil extraction is its simple and robust design, energy self-sufficiency, minimal process water requirements, ability to handle fine particles, and high oil yield recovery factors. It is also particularly suited for processing materials with otherwise low oil yields. It allows the mechanical transfer of solids through the machine with no moving parts and achieves improved process efficiencies through solid-to-solid heat transfer.

From rock to oilhoW oil shale is eXtracted and Processed

Numerous shale oil extraction technologies have been developed within the past 100 years. Some are now obsolete and although many have been tested in pilot plants, probably less than ten technologies have been tested at a demonstration scale and only a handful are in commercial use. Better known technologies include Kiviter, Galoter, Fushun, ATP and Petrosix.

Colling Zone Solids

1.Preheat zone

cooling zone

2.retort zone

3.combustion zone

Preheat Steam

Feed

Spent Solids

HydrocarbonVapours

AuxiliaryBurner

CombustionAir

Combusted SolidsHeat Transfer

Evolved Steam

Cooling Zone Solids

Flue Gas

The ATP was originally developed for Alberta’s Athabasca oil-sands industry, which uses large amounts of water and generates high volumes of contaminated oily waste water. The Taciuk process evolved to alleviate this problem and the first pilot plant was constructed in 1977. However, it did not progress to commercialisation to treat oil sands as by the 1980s the scale of operations of the two largest oil sands producers in Alberta, Syncrude and Suncor, had already surpassed the processing capacity that the ATP could provide.

Subsequently, the ATP developers were approached by Australian company, Southern Pacific Petroleum (SPP) with a view to using the technology to recover oil from oil shale in Queensland, specifically the Stuart deposit. A pilot programme proved successful in 1987, with oil yields greater than 85% being achieved. The Stuart 1 project then evolved as part of a joint venture with Suncor Canada. The plant was commissioned in 1999 and continuous operations commenced in 2001. All operations ceased in 2004 when ownership of the project changed. More recently, Jordan Energy and Mining Ltd has elected to use updated and improved ATP technology to develop oil shale deposits in Jordan (p.33).

the Fushun Process Is used only in China and the first commercial-scale plant was built there in 1930. After World War II, shale oil production ceased, but 100 Fushun-type oil shale retorts were

restored in 1949. By 1950, 266 retorts were in operation, each with the capacity for 100–200 t/d of shale oil.

The discovery of the Da Qing oil field in 1960s triggered a decline in shale oil production and Sinopec, a major producer, halted output at the beginning of the 1990s. At the same time, however, the Fushun Oil Shale Retorting Plant, using Fushun process technology, was established as a part of Fushun Mining Group. It started production in 1992 and by 2005 China had became the world’s largest shale-oil producer.

In 1985–86, Sinopec used the Fushun process to test its suitability to treat oil shale from the Al Lajjun deposit in Jordan. The process proved technically viable but the costs were deemed to be too high.

The Fushun process uses a vertical rotary kiln, with outside steel plating lined with inner fire bricks. Each retort exceeds 10 m in height and the inner diameter is about 3 m. Raw oil shale (10–75 mm particle size) is fed in at the top of the retort where it is dried and heated by ascending hot gases. The descending oil shale is heated to around 500°C at which point pyrolysis takes place. Decomposition of the rock produces shale coke (char) and oil vapours and gases. The vapours and gases exit from the top of the retort, whilst the char is burnt in the lower part of the retort to heat gases necessary for pyrolysis. These gases are recirculated.

Retorts are operated in sets and have heat-carrier preparation units and rotating hydro seals designed for the

whole set. Heating furnaces are located next to the retorts and operate in two cycles – combustion and gas heating. Furnaces are heated by passing combustion gases up to 1,000°C.

The Fushun process is relatively cheap and thermal efficiency is high. However, due to the addition of air into the retort, nitrogen dilutes the pyrolysis gas. Also, the excess oxygen in the retort burns out part of the shale oil produced, thereby reducing the shale-oil yield (Fischer assay of about 65%). The process also consumes a high volume of water — some 6–7 barrels per barrel of shale oil produced — and generates great quantities of waste shale. It is not suitable for ores with small particle size and oil content less than 5%.

top: atP oil shale processor under construction at Fmg (october 2008)bottom: Fushun mining group (Fmg) – shale oil storage tanks (october 2008)

new atP / krupp Polysius Processor design (courtesy of jeml)

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Because the capacity of a single retort is limited, the Fushun process is suitable for small-scale retorting plants. Fushun Mining Group’s shale-oil plant has the world’s largest capacity, each of its 180 retorts capable of processing about 4 t/h of oil shale. Due to the inability of the Fushun vertical retorts to handle fine material, a decision was made in 2006 to install one 250 tons/hour ATP retort to treat this material. The ATP is due to come on stream late 2009/early 2010.

the galoter Process (also known as TSK, UTT, or SHC) is an above-ground retorting technology for shale oil extraction that uses fine particles of oil shale heated in a rotating kiln. Hot oil shale ash is used to heat the raw oil shale. The first two Galoter-type retorts were built at Kiviõli, Estonia in 1953 and 1963 (and closed in 1963 and 1981 respectively). The Narva Oil Plant with two Galoter-type retorts was commissioned in 1980.

In this process, crushed oil shale (particle size less than 25 mm in diameter) is passed by belt conveyors to raw oil shale bins from where it is poured into a dryer. Dry oil shale is transported to a mixer chamber where ash is produced by combustion of spent shale in a separate furnace. The resulting hot ash (800°C) is mixed with dried oil shale particles to cause decomposition.

The temperature of decomposition in the Galoter retort is 520°C. The hot flue gas leaving from the cyclone

is introduced to the waste heat boiler and then to the fluidised drier for drying the oil shale feed. Oil vapour is withdrawn and condensed to yield liquid fuel and the non-condensable fraction is considered a medium-energy oil shale gas. The thermal efficiency of the Galoter process is high and technological chemical efficiency accounts for 73–78%. The oil recovery ratio is high — oil yield reaches 85–90 % (Fischer assay), and oil quality is good.

This process creates less pollution than internal combustion technologies, as it uses less water, but it still generates carbon dioxide, as well as carbon disulphide and calcium sulphide.

the kiviter Process Uses an above-ground vertical retort technology and has been used in Estonia since the 1920s. VKG Oil operates several Kiviter retorts and the largest has a processing capacity of 40 t/h of oil shale feedstock. From 1955 until 2003 Kiviter technology was also used to process oil shale in Slansky, Russia.

The vertical Kiviter retort heats coarse oil shale with recycled gases, steam and air. To supply heat, gases (including produced oil shale gas)

and spent residue (char) are burnt within the retort. Raw oil shale is fed into the top of the retort, and is heated by the rising gases, which pass laterally through the descending oil shale causing decomposition of the rock.

Pyrolysis is completed in the lower section of the retort, where the spent shale contacted with more hot gas, steam and air is heated to about 900°C to gasify and burn the residual carbon (char).

Shale oil vapours and evolving gases are delivered to a condensing system, where condensed shale oil is collected. Non-condensable gases are fed back to the retort. Recycled gas enters the bottom of the retort and cools the spent shale, which then leaves the retort through a water-sealed discharge system.

The Kiviter process uses large amounts of water, which is polluted during processing, and the solid waste residue contains water-soluble toxic substances that leach into the surrounding area.

lurgi-ruhrgas Process Originally invented in the 1940s and further developed in the 1950s for low-temperature liquefaction of lignite (brown coal), the Lurgi-Ruhrgas process is a hot recycled solids technology that processes fine particles (6.3–12.7 mm diameter) and uses spent oil shale (oil shale ash), mixed with sand or other more durable materials as a heat carrier.

The process was used in the late 1940s in Germany for shale oil production and in the late 1960s and early 1970s oil shales from Europe and the Green River Formation in Colorado were tested at the Lurgi pilot plant in Frankfurt. In the US, the technology was

enefit (estonia)

The end-of-the-fossil-hydrocarbons scenario is not a doom-and-gloom picture painted by end-of-the-world prophets but a view of scarcity in the coming years that must be taken seriously Deutsche Bank

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promoted in co-operation with Dravo Corp and the technology was licensed to the Rio Blanco Shale Oil Project for construction of a modular retort in combination with a modified in situ recovery process. However, the plan was terminated.In 1980, Jordan’s Natural Resources Authority commissioned a pre-feasibility study for an oil shale retorting complex using the Lurgi-Ruhrgas process. The study found the technology feasible but the project was never pursued. The technology has the disadvantage that the shale oil vapours that are produced are mixed with shale ash, causing impurities in shale oil.

the Paraho Process Developed in the US in the 1960s, the Paraho process is based partly on a gas combustion retort developed by the US Bureau of Mines. In 1973, Paraho Development Corp, a consortium including Standard Oil of Ohio and a number of other leading US oil producers, launched a test operation on its Anvil Points lease at Rifle, Colorado. A maximum throughput capacity of 263/t/d of raw oil shale was achieved. In March 1976, the consortium tested a modified technology – the Paraho Indirect process. The Anvil Points lease was closed in 1978.

Subsequently, Paraho technology was variously used to produce 100,000 barrels of crude shale oil for the US Navy, tested for use as military transportation fuel, refined and tested as an aviation fuel for the US Airforce and by Cleveland-Cliffs

Iron as a heavy fuel oil in one of its ore carriers. In August 2008, Queensland Energy Resources announced that it would use the Paraho Indirect process for its Stuart Oil Shale Project in Queensland.

The Paraho process can be operated in two different combustion modes: direct and indirect. The direct process involves gas combustion in a vertical shaft retort similar to the Kiviter and Fushun retorts, with crushed raw oil shale fed into the top of the retort through a rotating distributor. The indirect technology is an externally generated hot gas method. The retort is of similar configuration to that used in the direct process but the process gas is burnt in a separate furnace and heat is carried to the retort by using circulation of heated gases. No combustion occurs in the retort.

The main advantages of the Paraho process include simple design, low construction and operating costs and the fact that no water is consumed in the retort — an important consideration for oil

shale extraction in areas where water is scarce.

the PetrosiX Process The Brazilian energy company Petrobras started oil shale processing activities in 1953 by developing its Petrosix technology to extract oil from the Iratí oil shales, a Permian formation in Brazil’s Parana Basin.

The above-ground retorting technology uses externally-generated hot gas for the oil shale pyrolysis. Mined shale is crushed to particles measuring between 12 mm and 75 mm, and these are transported by belt conveyor to a vertical shaft kiln where the shale is heated to about 500°C. The oil shale enters through the top and is heated with reheated recycled gases as it moves down. The kerogen decomposes to yield oil and gas. Spent shale is discharged from the bottom, and oil vapours and gases are discharged through the top.

The oil vapours are cooled to condensate, and shale gases are cleaned to extract light oil. The rest is then sent to the gas treatment unit, where fuel and liquefied petroleum gas (LPG) are produced and sulphur recovered. Part of the cooled retort gas is used as fuel in a tubular heater, part is heated in the heater’s pipes and re-circulated back to the middle of the retort, and part is circulated and enters into the bottom of the retort. There, it cools down the hot shale coke, and is, itself, heated up, ascending into the pyrolysis section for heating the oil shale feed as a supplementary heat source.

crushed raw oil shaleCredit: Argonne National Laboratory

We have run out of good projects. This is not a money issue . . . if these oil companies had fantastic projects they’d be out there developing new fields Matthew Simmons, author of Twilight in the Desert

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A drawback of the process is that the potential heat of fixed carbon contained in the shale coke is not utilised.

Operational since 1992, Petrosix is the world’s largest surface oil shale pyrolysis retort. The vertical shaft kiln is 11 m high and has an inside diameter of 5.5 m. Designed by Cameron Engineers, the retort has an upper pyrolysis section and a lower shale coke cooling section. There is a capacity to treat 6,200 t/d of oil shale and the nominal average daily yield is 3,870 barrels of shale oil, 132 t of oil shale gas, 50 t of liquefied oil shale gas, and 82 t of sulphur. Petrobras operates two Petrosix retorts at São Mateus do Sul and processes 8,500 t/d of oil shale.

In Utah, Oil Shale Exploration Co (OSEC) intends to use the Petrosix process to treat oil shale from the Green River Formation at the White

River mine site in Uintah County. There are plans to produce oil from some 45,000 t of oil shale previously mined at the site.

the tosco ii Process Is an above ground retorting technology developed in the 1960s and 1970s, which uses fine particles of oil shale (less than 13 mm in diameter). These are preheated to about 260°C and mixed with hot 15 mm diameter ceramic balls in a pyrolysis drum (a horizontal rotary kiln). The oil shale temperature is thereby increased to 480–590°C and pyrolysis occurs, with the kerogen decomposing to oil shale gas and oil vapours. The vapours are transferred to a condenser for separation into various fractions.

The spent shale and the ceramic balls are separated in a perforated rotating separation drum (trommel), with the crushed spent shale falling through holes in the trammel and the ceramic balls transferred to a ball heater. Combustible shale gas is burned in the ball heater to reheat the ceramic balls. TOSCO II is a refinement of the Swedish Aspeco process and Tosco Corp purchased the patent rights in 1952. After early development work by Denver Research Institute, a joint venture company, Colony Development, was established in 1964 by Tosco, Standard Oil of

Ohio, and Cleveland Cliffs Iron Co. The aim was to develop the Colony Shale Oil Project and commercialise the TOSCO II technology. A pilot plant designed to handle 1,000 t/d of oil shale operated for several years at Parachute Creek, Colorado but the project was terminated in 1972.

The thermal efficiency of the process is low because the energy of spent shale is not recovered and much of the produced shale gas is consumed by the process itself. Efficiency could be increased by burning char (carbonaceous residue in the spent shale) instead of shale gas as a fuel in the ball heater. Other disadvantages include mechanical complexity, a large number of moving parts and limited lifetime of the ceramic balls. Also, the disposal of spent shale presents environmental problems because of the fine particle size and the contained carbon residue.

in situ conversionIn situ conversion of oil shale requires no conventional mining to extract the shale. Instead, the deposit is heated underground, either by the injection of hot fluids into the formation or by inserting heating units followed by thermal conduction and convection to distribute heat through the formation. Most of the methods are still at the experimental stage but they are seen to offer potential for

spent shale pileCredit: Argonne National Laboratory

recovering oil from deep deposits that cannot be achieved economically by the established ex situ extraction processes. They also offer the possibility of getting to greater depths and recovering oil from deposits that are of too low a grade to be worth exploiting by traditional mining methods. Shell Oil Co has developed the innovative Shell In situ Conversion Process (ICP) whereby a series of underground electrical heating elements are drilled into an oil shale deposit. The target depth zone is typically 300–650 m. The shale is heated slowly over time to 350–370°C and the kerogen decomposes into oil and gas. The process may take two to four years. The products are then pumped to surface using traditional techniques. The product generally comprises one-third gas and two-thirds light oil. The field size for the ICP method is typically about 2.6 km2 and 35–50 holes are drilled per hectare.

The process is currently unproven on a commercial scale, but is regarded by the US Department of Energy as a very promising technology. Confirmation of the technical feasibility of the concept, however, hinges on the resolution of two major technical issues: controlling groundwater during production and preventing subsurface environmental problems, including groundwater impacts.

At its property in Rio Blanco County in Colorado, Shell is conducting a freeze wall test that it hopes to use with the technology and which is designed to serve as a barrier to keep groundwater from subsurface production areas. The freeze wall consists of wells filled with circulated super-chilled fluid. Shell has recently signed a Concession Agreement in Jordan for a twelve year exploration and development program leading to a major ICP shale oil extraction venture.

In American Shale Oil’s CCR process superheated steam is circulated through pipes installed beneath the oil shale horizon from which oil is to be extracted. The system combines horizontal wells, through which steam is passed, and vertical wells, which provide both vertical heat transfer through refluxing of converted shale oil and a means to collect the produced hydrocarbons. Heat is supplied by combustion of natural gas or propane in the initial phase, and oil shale gas by-product at a later stage.

shell icP (in situ conversion Process) pilot plant at rifle, colorado, usa shell icP (in situ conversion Process) pilot plant at rifle, colorado, usa

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Independent Energy Partners’ Geothermic Fuel Cells (GFC) Process involves a high-temperature stack of fuel cells being placed in the oil shale formation. Initially, the cells are fuelled by an external source of natural gas. Subsequently, the process fuels itself using oil shale gas generated by its own waste heat. The formation is fractured by rising fluid pressure in the heated zone. As an alternative, the formation can be pre-fractured to enhance the flow of shale oil between heating and producing wells.

Chevron Corp’s Crush Process, developed in conjunction with Los Alamos National Laboratory, involves fracturing, gas injection and combustion. Conventional drilling methods are used to drill wells and then a series of controlled horizontal fractures are applied within the target area through

which gases rich in CO2 are circulated from well to well. These are then returned to a gas generator for reheating. The shale oil is brought to the surface in conventional vertical oil wells.

Petro Probe has proposed a process involving injecting super-heated air through wells drilled into the oil shale formation. Produced hydrocarbons are transported to the surface in a gaseous state and, after separating the shale oil condensate, the remaining oil shale gas is used to heat the air, which is injected back into the formation along with waste products. This minimises the environmental impact of the process. Similarly, Mountain West Energy’s In situ Vapour Extraction (IVE) process involves the injection of high-temperature gas into the oil shale.

ExxonMobil’s Electrofrac technology uses a series of hydraulic fractures created in the oil shale formation that are injected by an electrically-conductive material such as calcined petroleum coke. The shale oil is then extracted by separate dedicated production wells.

A technology still at the test stage involves horizontal wells that are hydraulically fractured along the vertical axis. The wells are placed in a parallel row with a second horizontal well intersecting them at their toe. This allows opposing electrical charges to be applied at either end. ExxonMobil is considering suitable sites for a field trial.

The concept of radio frequency processing of oil shale was developed at the Illinois Institute of Technology during the late 1970s and subsequently pursued by Lawrence Livermore National Laboratory. The concept was to heat oil shale using vertical electrode arrays and presumes a radio frequency at which the skin depth (the depth at which the alternating current magnitude has fallen to 37% of that at the surface) is many tens of metres, thereby overcoming the thermal diffusion times needed for conductive heating. Microwave heating technologies are based on the same principles as radio-wave heating, although it is believed that radio-wave heating is an improvement because the energy can penetrate farther into the formation.

above: shell in situ conversion Process right: Fushun mining/atP – jeml Photos

In addition to geological factors, including the size and grade of an oil shale deposit, commercial development also depends upon the availability of infrastructure (such as roads, railways, power lines and water), labour and environmental considerations (including existing land usage).

The development of new in situ mining and processing technologies may allow an oil shale operation to go ahead in previously restricted areas without causing damage to the surface or posing problems of air and water pollution.

The availability and price of petroleum will ultimately affect the viability of a large-scale oil shale industry. Today, selected oil shale deposits can be economically mined and processed for shale oil in competition with conventional petroleum. But, as supplies of petroleum inevitably diminish and its cost increases, the use of oil shale for the production of electric power, transportation fuels, petrochemicals, and other industrial products could grow, especially if accompanied by improving technologies to mine and process oil shale.

Also, whereas the economics of heavy oil and oil sands production are well known using existing technologies (see appendix I), the cost estimates for converting oil shale to useable product are less well demonstrated, particularly in light of the development of new processing technologies under development but as yet untested on a commercial scale.

In the past, various attempts to develop oil shale deposits have succeeded only when the cost of producing shale oil is lower than the price of petroleum or its other substitutes. Rand Corp has estimated that the cost of producing shale oil at a hypothetical surface operation in the US (including mining, retorting, upgrading, supporting facilities and spent shale reclamation) would range between US$70 and US$95/barrel (adjusted to 2005 values). Assuming commercial production eventually reaches one billion barrels, the company estimates that costs could gradually reduce to nearer US$30–US$40/barrel.

This downward pressure on unit operating costs as technology developments and scale of operations increase is consistent with the experience of the Canadian oil sands sector where unit cash costs have steadily decreased over the last 20 years from $30–35 to $15–20/bbl at the largest scale and best managed operations.

Royal Dutch Shell calculates that the in situ conversion (ICP) technology that it is developing in Colorado and now in Jordan could be profitable at a crude oil price in excess of US$30/barrel (US$190/m3). There are other operators who claim that their technologies, if scaled up to commercial levels, could produce shale oil profitably even at cash production costs of less than US$20/bbl at crude oil price of less than US$20/barrel ($130/m3).

To increase the efficiency of oil shale retorting, researchers have proposed and tested several co-pyrolysis processes in which other materials such as biomass or peat, or rubber and plastic wastes, are put in the retort, along with the oil shale. For example, an Israeli company, Hom Tov, has developed a process whereby waste bitumen is fed into the retort along with oil shale. The waste bitumen acts as a catalyst, enabling pyrolysis to occur at lower temperatures. Also, modified technologies have been proposed that would combine a fluidised-bed retort with a circulated fluidised-bed furnace for burning the by-products of pyrolysis (char and oil shale gas). This could improve oil yield, increase throughput, and shorten retorting time.

Capital cost intensity for oil shale projects is on a par with those of oil sands ventures but also can be considerably lower, due to locations other than Canada offering lower cost environments.

In 2007, before the global recession, capital cost figures in excess of $150,000 per daily barrel were quoted for new oil sands ventures in Canada and although somewhat lower now due to reduced steel prices and lower wages, are unlikely to be below $100–120,000 per daily barrel.

Oil shale ventures - whether using surface retorting or in situ processing technology - are probably in a similar $100–120,000/per daily barrel range, although references in 2008–09 have quoted figures as low as $80–100,000 per daily barrel for ventures in particularly low cost environments.

economic considerations

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mining in conteXtMining, including oil shale extraction, should be seen in context. All human activity has an impact on the environment — infrastructure, urbanisation, industrialisation, tourism, even leisure activities such as skiing and golf, all do damage. The question that must be asked is: what is an acceptable level of damage for the benefit gained and what remediation steps should be adopted?

Tackling this issue a few years ago from a mining perspective, Bob Horn, a former exploration director for Inco Ltd, cited the Trans-Canada Highway as an example. A federal-provincial system that links all the ten provinces of Canada, the highway was initiated in 1948, opened in 1959 and completed in 1965. At 7,511 km, it is the longest highway in the world and has affected an area of some 1,600 km2. It is an important national asset and an essential part of the infrastructure, providing great social, political and economic benefits to Canadians. It supersedes the great Canadian Pacific and Canadian National rail systems of the 19th and early 20th centuries. But it comes at a cost.

Road accidents on the highway claim hundreds of human lives and in an average year in excess of half a million vertebrate animals are killed as a result of collisions with vehicles. Annual CO2 emissions, based upon average traffic flows at Banff, and weighted average vehicle emissions, total 20 Mt. To put this in context it is the same as the target CO2 emissions for the entire electric power industry of Denmark. Nevertheless, as one of the world’s more responsible nations, Canada has tacitly judged that these impacts are worth the economic and social benefits that the Trans-Canada Highway provides.

Agriculture’s footprint also merits careful scrutiny. Mining and agriculture both produce products that are essential for human survival and both create new wealth rather than recycle the wealth generated by others. Unlike mining, however, the agricultural sector in most countries receives special assistance, such as price support, farm subsidies and tax incentives, partly because of the need to be self-sufficient in food and partly because rural communities in many democratic countries carry a political clout disproportionate to their numbers. Consequently, it is in the self-interest of politicians to look after the farmers.

As Bob Horn points out, agriculture has managed to retain a wholesome image in the public eye, despite ample evidence of the environmental damage it creates. In the 1990s, for example, a World Bank report drew attention to the fact that the intensification of agricultural practices, in particular the growing use of fertilisers and pesticides, and the specialisation and concentration of crop and livestock production, was having an increasing negative impact on water quality. The main agricultural water pollutants are nitrates, phosphorus, and pesticides. Rising nitrate concentrations threaten drinking water quality, and high pesticide use contributes substantially to indirect emissions of toxic substances.

Globally, the gross product value of agricultural land varies widely, from low-intensity grazing to high value cash crops. Based upon published data from the Australian state of Queensland, a region with relatively productive farmland that uses the highest levels of technology, gross annual agricultural product value for crops usually lies within the range A$500–A$2000/ha. Around 4.6 million km2, or 60% of Australia, is used for farming. Of this area, 70% is used for cattle and sheep grazing with a very low density of livestock and consequently low gross product value. High productivity, intensive, cash crop farming occupies about 3% of the country, or just 230,000 km2.

eXPloding the myths

Even assuming that mining’s footprint in Australia occupies 2,000 km2 (twice as big an area as its equivalent in Canada) this is still only 1% of the area used by intensive farming with its agrochemicals. Moreover, Australia’s mineral exports are worth approximately five times as much as its exports of agricultural products.

According to the Canberra-based Australian Bureau of Agricultural and Resource Economics, an Australian Government economic research agency, Australia’s farm export earnings are forecast to increase by 2% to A$32.5 billion in 2009–10, whereas energy and minerals export earnings are estimated to increase by 36% to A$160 billion.

If environmental damage is defined as any change to the natural environment by human activity then the impact of forestry, as well as farming, has been enormous. In Canada, for example, little of the original

native forest remains as a result of these activities, and large parts of the prairie grassland are now used for farming.

By comparison, mining in Canada is comparatively benign. Horn has estimated that over the past 200 years or so, metal mining has destroyed little more than 1,000 km2, including not only mine sites but also land whose proximity to a mine precludes any other use. This area affected by metal mining equates to little more than one third of the area covered by the Trans-Canada Highway. Like it or not, the extraction of mineral resources, along with infrastructure, farming and industrial development, is integral to maintaining modern living standards.

environmental FootPrint claim: “mining harms

the environment” Today, any company seeking

to go ahead with an oil shale project will be obliged to submit a comprehensive environmental impact study to the relevant government authority. Apart from land disturbance and the impact of the project on flora and fauna, the study is likely to consider some or all of the following and to include appropriate provisions:

> the adequacy of water supply:> the contamination of surface

and groundwater by heavy metals;> acid mine drainage;> increased erosion;> greenhouse gas emissions;> emissions of SO2 and other gases;> air pollution caused by

particulates released during processing and transportation of the mined product;

> the displacement and/or resettlement of any communities that might be affected by the project.

Like it or not, the extraction of mineral resources is integral to maintaining modern living standards

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In order to secure a mining permit a company must comply with a plethora of regulations regarding these factors. In addition, it is normal for a company to arrange meetings with local communities and their leaders to explain the implications of the project and to sound out their views and concerns before finalising project proposals with the government and regulatory authorities.

Further, when funding development of a venture, project financing will necessarily come from major banks who have committed not to fund major natural resources projects unless they meet the World Bank/IFC ‘Equator Principles’ – a comprehensive set of environmental and social guidelines.

Despite these often rigorous environmental obligations, however, several environmental groups unequivocally oppose oil shale extraction, with particular concerns about water usage, energy consumption and CO2 emissions.

Water usageclaim: oil shale mining is a WasteFul use oF WaterSurface processing of oil shale uses a net 2–5 barrels of water for every barrel of shale oil produced. In the US, the Bureau of Land Management (BLM) estimated in 2007 that surface mining and retort operations produce 1.5–8.0 gallons of waste water per tonne of processed oil shale.

By contrast, in situ processing, according to one estimate, uses about one-tenth as much water. However, these methods have lower resource recovery factors and their impact on ground water resources needs to be carefully monitored. In arid regions, the availability of sufficient water for an oil shale project will clearly be an important consideration.

On the other hand:> Most surface mining and

retorting facilities can use brackish water or even sea water for cooling and dust suppression, which is not suitable for crops, animals or human consumption without further treatment

> Most oil shale products will have no standing water on their site for example tailings disposal ponds, avoiding negative issues with birds and other wildlife

> Oil shale’s gross water consumption is some three times less than that for oil sands at around 6m3 water per m3 oil produced (whereas oil sands is some 18m3 water per m3 oil produced) although net water use is around the same at 2–4m3 per m3 oil produced, or in the case of the ATP process some 0.4m3 water per barrel shale oil produced

> Modern mine and plant design normally aims for a closed water system with zero discharge and maximum use of recycled water.

> Even in desert areas annual sporadic storm rainfall is considerable and can be captured together with other site rain run-off for use in the process.

Reference

Water Intensity: Typical oil shale/oil sands operationsWater Intensity (m3/bbl)

Oil Shale (ATP)

Oil Sands min

Oil Sands max

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greenhouse gasesclaim: oil shale eXtractiongenerates higher carbonemissions than recovery oF conventional oil Compared with the production of conventional liquid hydrocarbons, oil shale extraction can generate more greenhouse gas emissions. However, as noted previously, a study carried out by German engineering firm DMT GmbH & Co in conjunction with the German testing and accreditation agency TUV Nörd indicated that the likely carbon footprint resulting from CO2 emissions at the Al Lajjun oil shale project in Jordan lies within the range of competing fuel alternatives — slightly higher compared with primary recovery of conventional oil but on a par with secondary and tertiary oil recovery from conventional resources and significantly lower than for coal-to-liquids and on a par with gas-to-liquids operations.

In terms of long-term oil supply, there will be a need to apply more and more secondary and tertiary technologies to enhance recoveries of conventional oil, and this means the environmental performance of companies that are involved in oil shale mining will look increasingly favourable in comparison as their emissions will be constant over the life of the project.

When considering full lifecycle emissions of greenhouse gases associated with a barrel of oil, it should be borne in mind that 80% of emissions come from transport – combustion in cars, trucks, aircraft, ocean-going vessels (tank to wheels) – and only 20% from the actual extraction, processing transportation and refining of oil (well to tank).

Pollutionclaim: oil shale mining releases dangerous gases into the atmosPhereDepending on the technology used and the composition of the oil shale, extraction may lead to the release of sulphur dioxide, hydrogen sulphide and nitrogen oxide emissions. In addition, the thermal processing and extraction process generates substantial quantities of waste material that may include pollutants such as sulphates, heavy metals, and polycyclic aromatic hydrocarbons, some of which are toxic. (In situ conversion processing of oil shale may reduce some of these impacts).

Taking Estonia as an example, an estimated 1,600 Mt of oil shale have been mined over the past 50 years, and although it has to be acknowledged that the oil shale industry played an important role in restoring Estonia’s political and economic independence in the early 1990s, the industry has also been a major source of environmental damage and economic mismanagement.

An area exceeding 45,000 ha (about 1% of Estonian territory) has been damaged by oil shale mining.

Estonia’s oil shale industry dates from the Soviet era when environmental considerations were not to the fore, and although some of the criticisms by environmental campaigners are justified, others need to be qualified. For example, large dumps of fly ash allegedly containing phenol-rich organic

0,2

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0,1

0,3

0,5

0,7

0,4

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Carbon Emissions: Typical oil shale and benchmark operationstCO2/BOE

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phenols are a legacy of its period of Soviet control when all types of oil-processing waste were dumped. This is no longer practiced, and the old dumps have been left on surface rather than used as backfill in the mines so as to avoid any contamination of the groundwater. Industry experts claim that today that much of the waste from the retorts could be free of phenol compounds.

Probably the main criticism levelled by opponents of the oil shale industry is that burning the shale decomposes carbonates as well as hydrocarbons. However, as the detailed studies referred to above indicate, greenhouse gas production from the more advanced technologies are expected to be on a par with secondary recovery of conventional hydrocarbons. In addition, industry supporters argue that these relationships of CO2 production will narrow as industry now uses more advanced combusting technology and around 25% of the included carbonate remains intact.

Furthermore, the nitrogen content in kukersite deposits is very low and an expansion of the industry in Estonia keeping within EU emission guidelines might be possible. The country’s most recent governmental projection is for output to reach 31 Mt by 2015.

land use and Waste managementclaim: oil shale mining requires eXtensive land useAccording to the European Academies Science Advisory Council (EASAC) production of a barrel of shale oil can generate 1.5 tons of spent shale, which occupies approximately 25% greater volume than the original shale. Waste management is taken seriously by the industry and great efforts are being made to identify commercial uses of spent shale, which will not only enhance financial returns but also help address the problem of waste disposal. Spent shale has a variety of uses such as the production of asphalt road surfacing material, low grade building blocks and cement and new applications are being actively explored.

In China, Fushun Mining Group produces in excess of 300,000 t/y of shale oil which is sold as fuel oil, and part of the surplus retort gas with low heating value is used to produce steam and power. Spent shale and shale ash are used to produce cement, with an annual production in excess of 300,000 t.

In Jordan, the potential use of treated solid oil shale by-product to treat aqueous solutions containing several heavy metals has been explored by researchers in the Department of Earth and Environmental Sciences, Yarmouk University. Different experimental approaches including X-ray fluorescence (XRF) were used to explore the feasibility of this material as a cheap adsorbent for the removal of these heavy metals from predetermined solutions. At Jordan’s University of Science and Technology, researchers have demonstrated that oil shale is able to remove appreciable amounts of copper and zinc ions from aqueous solutions.

In many open pit operations, such as Jordan Energy & Mining’s Al Lajjun project in Jordan, unwanted spent shale does not experience the ‘popcorn’ effect of expansion and will simply be returned to the mine and sandwiched between original, stored overburden material before being landscaped to blend in with its desert setting.

energy eFFiciencyclaim: it is not energy eFFicient to Produce energy From oil shale No one would argue that oil shale has a lower energy density than fossil fuels such as coal and crude oil. Typically, oil shale contains one-fifth to one-tenth the energy of crude oil and one-third to one-sixth that of coal. But the inescapable fact is that readily recoverable crude oil supplies are running out and the world needs to find viable “next best” alternatives.

One generally accepted method of measuring the energy efficiency of a material is its EROEI ratio – the Energy Returned On Energy Invested. This is a calculation of the amount of usable energy acquired from a particular energy resource in relation to the amount of energy expended to obtain it. When the EROEI of a resource is equal to or lower than 1, that energy source becomes an ‘energy sink’, and can no longer be used as a primary source of energy.

High per-capita energy use is considered desirable as it is associated with a high standard of living based on energy-intensive machines and the highest available EROEI energy sources will be exploited first, as they provide the most energy for the least effort. Progressively lower EROEI sources are then used as the higher-quality ones are exhausted.

In the early days of oil consumption, on average it took one barrel of oil to find, extract, and process about 100 barrels of oil (1:100) The ratio has declined steadily over time and in the US only three barrels of oil are now discovered for every barrel used (1:3) By comparison, in Europe and North America the EROEI of wind energy was judged to be about 1:20 (in 2006).

In a 1984 study of various oil shale deposits, the ratio varied between 0.7 and 13.3. Since then, various oil shale projects have EROEI ratios ranging between three and ten, and Royal Dutch Shell has estimated an EROEI of three to four for its in situ conversion process for oil shale development.

Jordan Energy and Mining estimates its EROEI factor at around 5.5 due to the use of residual carbon in the shale as a heat source in the retort and the conversion of waste gases into electrical power.

For a national government it seems clear that EROEI should not be the only consideration when determining energy policy. Energy independence, freedom from pollution and affordability are all other important factors, particularly when considering secondary energy sources. Whereas a primary energy source is not sustainable unless it uses less energy than it creates, this does not apply to secondary energy supplies. In oil shale projects, for example, the use of ‘waste’ heat and gases from the primary energy source to generate electrical power is an important economic consideration.

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social The great majority of oil shale projects now under consideration will use conventional open-pit mining methods, and the same social and economic considerations regarding mineral extraction in general will apply to oil shale projects.

Historically, many of the world’s industrial centres developed because of their proximity to vital natural resources. In Britain, for example, the Industrial Revolution of the 19th Century spawned many of the large northern industrial towns and cities because they were close to ample supplies of water, coal, iron ore and limestone. In Africa, Zambia and Zaire grew wealthy from copper mining and the continent’s largest industrial conurbation, Johannesburg in South Africa, developed as a result of the discovery of gold.

Natural resources, however, are not evenly distributed around the globe and, today, there are no guarantees that deposits of economic value will be discovered close to where they are needed.

Because of this, the mining industry continues to be an important player in bringing vital infrastructure, including roads, railways and power supplies, often along with towns, hospitals and schools, to undeveloped parts of the world. In fact, in some of the poorest

countries, regional communities may be dependent on the medical and educational facilities provided by a private mining company rather than the government of the day.

Currently, infrastructure development in many parts of South America, in countries such as Brazil and Chile, owe much to mining activity and, most recently, plans for major infrastructural developments are accelerating in some of the central Asian republics such as Kazakhstan and Mongolia as a result of mineral development projects. Oil shale projects could well have the same effect.

Even in developed countries, communities in remote areas may be dependent on the mining sector for the provision of vital infrastructure. In the Pilbara iron-mining district of Western Australia, for example, or in northern Canada, where the relatively recent development of diamond mining has been accompanied by road construction and the installation of power lines, which benefit local Inuit communities (not to mention the provision of major job opportunities and training in a region of high unemployment).

mining: the beneFits

road cutting through desert, helping to create infrastructure

… and economicGovernments are major beneficiaries of mining activity in the form of tax revenues, reduced dependence on mineral imports, job creation, technology transfer and training, as well as from major private-sector investment in infrastructure. In Canada, for example, Alberta produced 1.8 Mbbl/d of oil in 2007 (including 1.25 Mbbl from oil sands) and exported about 1.34 Mbbl/d to the US, supplying 13% of the latter’s crude oil imports. The provincial government estimates that every dollar invested in Alberta’s oil sands sector creates nine dollars worth of economic activity, with one-third of that economic value generated outside Alberta. In the period 2000–07, an estimated C$67 billion was invested in oil sands projects in the province, and industry plans are for more than C$100 billion to be invested there during the current decade.

In Jordan, which is highly dependent on imported energy and where the cost of energy-related imports absorbs around 25% of GNP, the government hopes to raise its energy self-provision from 4% to

25% by 2015 and to 39% by 2020. The strategy includes a focus on oil shale as the local energy resource, and a number of companies either have projects underway or under consideration.

Under a draft concession agreement in respect of Jordan Energy and Mining Limited’s Al Lajjun project, the government would receive between 10% and 30% of project revenues in the form of corporate tax and royalty.

Jordan Energy and Mining estimates that its project, which could be in production by 2013, will require an on-site workforce averaging 1,500 personnel over a 30-month construction period, and permanent staff of 570, including senior management, based on a 24-hour, three-shift system. The project, as currently envisaged, would mine 7.5 Mt/y of oil shale and produce 15,000 bbl/d of synthetic crude oil. In addition, ‘waste’ heat and gases would be used to meet the project’s power requirements (60 MW). In addition, approximately 10 MW would be available to the national grid.

Any substantial mining project, once established, will help to encourage and sustain a variety of local service industries and numerous opportunities for local entrepreneurs.

“More important than the deficit, more important than healthcare, more important than anything, we have got to do something about our energy strategy. Because if we keep doing what we’re doing until we’re out of oil . . . it is inconceivable to me that the world won’t be much fuller of resource-based wars of all kinds”Bill Clinton, former US President

local jordanian family

Any substantial mining project will sustain a variety of local service industries

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australiaAustralia’s oil shale deposits are largely located in the eastern one-third of the country (including Queensland, New South Wales, South Australia, Victoria, and Tasmania).

A former mining site at Yarwun, north of Gladstone, which produced 3,700 bbl per day at its peak is now being refurbished by Queensland Energy Resources Inc (QER) to develop the Stuart deposit. QER has chosen Paraho vertical shaft kiln technology as the most appropriate for processing the Stuart oil shale and a decision on its construction will be made late in 2009.

The Paraho process was selected after detailed testing in 2005–07 at a pilot plant near Rifle in Colorado US, belonging to QER’s sister company Shale Tech International. A total of 8,000 t of oil shale from QER’s Queensland deposits was prepared in Australia and shipped to Colorado. The technology was chosen on the basis of mechanical simplicity, a high oil yield, energy efficiency, safety aspects and environmental considerations. QER believes that the thermal extraction process generates typical waste streams that are easily manageable with current emissions control technologies.

Projects in the PiPeline

Australia, Jordan and Morocco all have oil shale projects in the pipeline, and Jordan and Morocco in particular are major energy importers.

Xtract Oil Ltd has oil shale exploration rights over mining tenements in the Julia Creek area of Queensland and in addition to evaluating third party technologies, it has been developing its own proprietary technology for the commercial extraction of liquid hydrocarbon products from oil shale.

chinaFushun Mining Group (FMG) is the principal oil shale company in China, although several coal and oil companies are now diversifying into oil shale extraction. FMG possesses oil shale resources of some 3,600 Mt of which 920 Mt are reported to be exploitable using existing technology. Around 760 Mt of the geological reserves are located in the East open pit and 160 Mt in the West open pit. Current output is from the West pit, and produced as a by-product of coal mining. The oil shale in the East pit has yet to be mined. In 2006, FMG produced 240,000 t of shale oil, and was expected to produce 300,000 t in 2007.

The company’s processing plant possesses 140 retorts in seven units and the facility is designed to process 7.0 Mt/y of oil shale. In addition, FMG is planning to construct an Alberta Taciuk Processor (ATP) facility to treat particulate oil shale, which cannot be processed in a Fushun retort. The 250 t/h ATP processor is being provided by UMATAC Industrial Processes of Canada.

The company also plans another plant capable of producing 400,000t/y of shale oil. On completion of all the projects FMG’s annual production of shale oil should exceed 700,000 t. Production costs are estimated to be the equivalent of US$18.46/barrel, of which mining costs amount to US$0.184, transportation US$4.25, and retorting US$13.84. The shale oil is sold as fuel oil, part of the surplus retort gas with low heating value is used to produce steam and power, and spent shale and shale ash is used to produce cement. Annual cement production is 300,000 t.

China’s largest oil company, PetroChina, established a new department in 2006, specifically responsible for oil shale development, and in August 2008, it commenced construction of an oil shale processing facility in Mudanjiang, Heilongjiang Province. The plant is designed to process 1.2 Mt/y of oil shale per year and produce 100,000 t/y of shale oil.

In Guandong Province, Sinopec subsidiary, Maoming Petrochemical Co. produced oil shale over three decades until the 1990s, using 64 Fushun-type retorts and 48 gas combustion retorts. Annual production reached a maximum of 180,000 t/y of shale oil. Plans are now in place to use the Maoming oil shale in power plants using fluidised bed combustion.

In Shandong Province, Longkow Coal Mining Co, which has been mining brown coal for some 30 years, plans to produce shale oil as a by-product. A 200,000 t/y oil shale processing plant is envisaged utilising Fushun-type retorts. Exploitable reserves are said to be around 100 Mt. In addition, the shale char mixed with particulate oil shale would be burnt in fluidized bed combustion for power generation, with the shale ash utilised to produce building materials.

Jilin Energy & Communication Corp, a subsidiary of China Power Investment Corp, was the first company in China to use oil shale for power generation. The plant, which has three circulating fluidised-bed units with a capacity of 12 MW, began operating in 2006. In 2005, the company proposed construction of a plant with the capacity to produce 200,000 t/y of shale oil at Huadian, along with two fluidised bed combustion units, each with a capacity of 50 MW, and the use of spent shale and shale ash to produce 1.2 Mt/y of cement and other building materials. Petrosix technology would be used in the oil shale plant. The project has the support of the Jilin provincial government.

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Also in Jilin Province, Royal Dutch Shell has established a joint venture with Jilin Guangzheng Mineral Development Co. Ltd to explore and develop oil shale resources. Shell China holds 61% of the shares in the joint venture and Jilin Guangzheng holds 39%. The joint venture plans to use Shell’s In situ Conversion Process.

In other industry developments, a privately-owned company has set up 10 Fushun-type retorts at Wang Qing in Jilin, and produced 15,000 t of shale oil in 2006. There are five other private companies in the province producing around 30,000 t/y of shale oil using Fushun-type retorts.

In Heilongjiang Province, Harbin Gas and Chemical Co plans set up a plant with the capacity to produce 1,000 t/d of shale oil, and Song Ya San Coal Mining Co plans a similar plant. At Mingxin, in Gansu Province, Mingxin Mining Co. is planning to co-produce coal and oil shale. The oil shale oil plant would have the capacity to produce 400,000 t/y of shale oil. Other oil shale projects are being considered in Uromqi (Xinjiang), Yongden (Gansu), and Chanpo (Hainan).

jordan The 26 known oil shale deposits in Jordan contain 40,000–70,000 Mt of oil shale containing more than 5.0 Mt of shale oil. The deposits cover more than 60% of Jordanian territory.

In recent years, there has been a revival of interest in Jordan’s oil shale resources, and several companies are aiming to begin shale-oil extraction and/or to use shale oil as a feed for power generation. The government has said that it is seeking to increase energy self-provision from 4% to 25% by 2015 and to 39% by 2020.

In 2006, the Government of Jordan signed a memorandum of understanding (MoU) with Royal Dutch Shell to test its ICP technology on oil shales in the Azraq and Al-Jafr blocks in central Jordan.

In the same year the government signed an MoU with Eesti Energia of Estonia whereby the latter was granted the exclusive right to examine approximately one-third of the Al Lajjun deposit. The right was subsequently transferred to the Attarat Umm Guhdran oil shale deposit, because the shallow aquifer beneath Al Lajjun provides fresh water to Amman and other municipalities in central Jordan. Eesti Energia presented a feasibility study to the government in April 2008 for the establishment of a shale-oil plant capable of producing 36,000 bbl/d using Galoter processing technology, with a construction start envisaged by 2015.

In November 2006, UK-based Jordan Energy & Mining Ltd (JEML) signed an initial MoU, also in respect of a one-third block of the deposit at Al Lajjun. A comprehensive pre-feasibility study was completed by JEML in May 2007 and presented to Jordan’s Ministry of Energy and Mineral Resources (MEMR) and the Natural Resources Authority (NRA).

Oil shale will play a major role in Jordan’s future“

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The study, which covered geology and resources, mining and processing, shale oil upgrading and power generation, as well as infrastructure considerations, water management and the environment, concluded that the project would be viable using ATP technology. JEML estimates that the project would break even at an oil price of around US$40–US$50/bbl and achieve reasonable returns at oil prices in excess of US$60–US$70/bbl. An independent study commissioned in mid-2007 and undertaken by International Mining Consultants Ltd (IMC) endorsed the JEML findings and paved the way for a full feasibility study which was completed in July 2009. In addition a full Environmental and Social Impact assessment (ESIA) was completed in July 2009 and accepted by the Ministry of Environment. It is hoped to sign a Concession Agreement with MEMR/NRA by end 2009 or early 2010.

In February 2007, a MoU was signed with Petrobras that awards the latter the exclusive right to examine another block of the Attarat Umm Ghudran deposit. Total SA is involved in the project and a feasibility study is due in 2009.

Other companies that have signed MoUs for oil shale extraction in Jordan include Saudi Arabian International Corp for Oil Shale Investment, Jordanian company Aqaba Petroleum, Russian company Inter RAO UES and Abu Dhabi’s National Energy Co.

moroccoMorocco possesses oil shale deposits containing in excess of 50 Mbbl of oil and the government regards the country’s oil shale resource as a strategically located, long-term source of reliable, affordable and secure oil. It believes that the economic viability of oil shale projects is now improving.

Petrobras and Total SA are evaluating a production facility at Timahdit that would use Petrobras’ Petrosix technology, while Irish company San Leon Energy plc has signed a MoU in respect of the Tarfaya oil shale project in southwest Morocco, where the company has been exploring in collaboration with the National Office of Hydrocarbons and Mining (ONHYM) for the past two years.

The area of interest covers 6,000 km2 and the project will last for three years with a first test due for completion by the end of 2010. The MoU grants San Leon exclusivity to

the al lajjun site in jordan

oil shale specimenCredit: Argonne National Laboratory

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convert the area into a Licence. The company reports that it has an exclusive agreement with Mountain West Energy of the US to use its proprietary In situ Vapour Extraction (IVE) technology. Laboratory tests in the US using Tarfaya oil shale have yielded 62 l/t of oil, according to the company, and site testing in Morocco is scheduled to begin later this year.

IVE forces heated gas through a central injector well and into a high oil-yielding and fractured oil shale. The oil is then produced from several extraction wells, equidistant from the central injection well. The gases utilised in the process are recycled within a closed system. The technology was tested successfully in Wyoming.

Separately, Petrobras has recently signed an MoU with ONHYM for the Tarfaya oil shale, in an area adjacent to the San Leon ground.

Meanwhile, Xtract Energy (Oil Shale) Morocco SA (XOSM) has signed a MoU with ONHYM to evaluate and possibly develop another oil shale property at Tarfaya.

united statesThe US requires around 20 Mbbl/d of petroleum products and if shale oil were to be used to meet a quarter of that demand, the estimated 800,000 Mbbl of recoverable oil from the Green River Formation would last for more than 400 years.

Interest in US oil shale grew after the 1970s oil price hikes but interest waned when gas prices began to topple. Interest revived in 2003, again as a result of soaring oil prices, and in 2005 George W Bush signed the Energy Policy Act, which officially opened federal lands to oil shale extraction. However, once again, lower oil prices curbed interest, along with environmental concerns and an increasing interest in renewable energy sources.

Shell is currently exploring the feasibility of an innovative in situ conversion process at its research facility in Colorado and in Jordan with which it hopes to recover up to one million barrels of oil per acre. Since research began in 2005 the company has produced some 2,000 barrels of oil shale from a test plot the size of a large garage. It now plans to test key aspects of its method on a larger scale with results due by 2010.

Recoverable oil from the Green River Formation would last for more than 400 years

“”

The principal questions to consider when making the case for oil shale are:

> Will demand for oil increase?> How long will conventional oil

resources last?> Can we manage without oil?> Can oil shale provide a solution? > Is oil shale extraction

economically viable?> Will the environmental footprint

be acceptable?

Despite the current exceptional circumstances in the world economy and the differing views about the depth and extent of the current global recession, there is a consensus that demand for energy over the longer term will grow strongly. Growth will be driven by the developing countries and led by rapid economic expansion in India and China. Together, these two countries account for about one third of the world’s 6.6 billion population.

The EIA has predicted that petroleum will continue to have the largest share of the energy mix for at least the next 20 years and ensuring an adequate supply will be of paramount importance. However, proven reserves of conventional oil are dwindling and at current rates of consumption resources may last for mere decades rather than hundreds of years.

As yet, there are no realistic substitutes for oil in all of its applications, for example in transportation, agriculture and plastics manufacture, and it seems certain that supply shortages and strengthening demand will drive oil prices higher and higher.

However, if modern living standards are to be maintained in the industrialised world and the aspirations of people in the developing world are to be realised, then the global appetite for oil will continue, despite high prices. Greater use of unconventional oil resources becomes more and more attractive, particularly as there are sufficient resources to last for hundreds of years.

The extraction of oil from oil shale will become an increasingly attractive proposition and there are numerous technologies being developed and tested which should make oil shale extraction more environmentally acceptable. There is a problem here, however, regarding public perception. This is because the few long-established commercial oil shale operations such as those in Estonia, and to a lesser extent in China and Brazil, have a bad reputation. The operations are based on technology developed 50 years ago and are perceived and sometimes correctly as dirty and environmentally damaging.

conclusions

global oil uses

transport 50%agriculture 30%industrial 20%

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Oil shale extraction and processing technologies have improved considerably but there are very few commercial-scale operations, as yet, to demonstrate the achievement of modern standards, despite the numerous oil shale projects now under consideration around the globe.

In situ conversion processes offer considerable environmental benefits but may suffer from low resource recovery and potential impact on ground water resources, whereas surface mining and processing of oil shale has also come a long way.

Sceptics should look at developments in other mineral sectors over the past 25 years that have reduced the environmental footprint. For example, the introduction of solvent extraction and electrowinning to treat sulphide ores has obviated the need to smelt sulphide ores.

As already noted (p.23), mineral extraction, including oil shale, should be seen in context with other industries – forestry, farming, tourism, urbanisation and basic infrastructure all carry a heavy environmental footprint. As a basic industry mineral extraction has neither a heavier nor lighter environmental footprint than these other activities and is equally essential.

It seems inescapable that demand for energy will spur greater development of the world’s vast but largely untapped oil shale deposits. Provided the necessary environmental safeguards are in place and the best available technologies are used, oil shale is rapidly developing to be an acceptable solution for maintaining global oil supplies.

As demand for energy continues to increase and supplies of conventional oil dwindle, the “next best” viable alternative energy source must be found. The economic arguments for oil shale look increasingly attractive. With easily accessible crude oil resources running out, the finding cost of conventional oil ($20 – $25 per barrel in 2009) is rising inexorably and is now equivalent to the cash operating cost of some shale oil projects. News that Deutsche Bank is predicting prices of $150 a barrel by 2010 could stimulate even more cautious investors to consider exploration and development of oil shale resources.

For further information, contact:Oil Shale Information CentreTel: +44 (0)1892 509950Email: [email protected]

Technology is great but it can’t find what is not there. In the last five years only one barrel of oil was replaced for every nine usedattributed to L B Magoon Report for the US Geological Survey ”

“

aPPendiX i other unconventional liquid hydrocarbon Fuels ‘Unconventional oil’ resources

can be defined as those resources that cannot be recovered in their natural state through a well by ordinary production methods, or that cannot be pumped without being heated or diluted.

As well as oil shale they include:> coal to liquids > heavy oil > oil sands > gas to liquids

coal to liquids Coal can be converted into liquid

fuels by using either direct or indirect liquefaction technologies. To date, indirect liquefaction has proved to be more successful. It involves the gasification of coal by the introduction of oxygen and steam, and the conversion of the resultant synthetic gas (a mixture of carbon monoxide and hydrogen), into various liquid hydrocarbons. The best-known method is the Fischer-Tropsch process in which catalysts, most commonly iron and cobalt, are used to speed up liquefaction.

The process was first developed in Germany in the 1920s and has been used on a commercial scale in South Africa since 1980. It is still in use there by Sasol to produce most of the country’s diesel fuel requirements.

costsA US Government task force report into unconventional fuels released in 2006 estimated that a domestic coal-to-liquids plant could have capital costs in the range of US$70,000–US$100,000 per daily barrel of oil produced. A 50,000 bbl/d capacity plant could cost between US$3.5 and US$5.0 billion.

outPutIn the same year, a report prepared for the US Department of Energy by US National Coal Council Inc estimated that output could reach 2.6 Mbbl/d by 2025, requiring the consumption of 475 Mt/y of coal. At the time of the estimate, at least eight coal liquefaction projects were under consideration with capacities ranging from 2,000 bbl to 50,000 bbl/d.

heavy oilWhat it isHeavy crude oil (or extra heavy crude oil) is defined as any type of crude oil that does not flow easily. It is called ‘heavy’ because its density or specific gravity is higher than that of light crude oil. Its API gravity is less than 20°, meaning that its relative density is greater than 0.933. Compared with light crude, heavy oil also has high viscosity (resistance to flow) at reservoir temperatures and a significant content of nitrogen, oxygen, sulphur compounds and heavy-metal contaminants.

Heavy oil is similar in content to the residuum after refining light oil. It is found at the margins of geologic basins and is thought to be the residue of formerly light oil. The USGS estimates global resources of technically recoverable heavy oil at some 434 billion barrels.

The largest accumulation is the Orinoco heavy-oil belt in Venezuela, which contains 90% of the world’s extra-heavy oil (API gravity of 10°). Other South American countries possess large resources, and in total the continent possesses 61% of the world’s technically recoverable heavy oil.

aPPendices

tar seeps at tar sands mine

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recoveryThe recovery of heavy and extra-heavy oil almost always requires measures to reduce oil viscosity and the introduction of energy into the reservoir. When super-heated steam is injected into a reservoir, oil viscosity is reduced and reservoir pressure is increased through displacement and partial distillation of the oil. Steam may be injected continuously to form a flood or it may be injected in cycles so wells are used alternately for injection and production. Methods for extraction include cold heavy oil production with sand, steam-assisted gravity drainage, cyclic steam stimulation, vapour extraction and toe-to-heel air injection.

To recover extra-heavy oil, the addition of diluents (gas condensate, natural gas liquids, or light crude) is generally needed so as to enable the oil to be transported by pipeline. Extra-heavy oil must also be chemically upgraded to reduce density and remove contaminants before it can be used as refinery feedstock. In Venezuela, one barrel of diluents is required for every 3–4 barrels of extra-heavy oil produced.

Where it can be FoundGlobal resources of heavy oil are more than twice as large as those of conventional oil resources, and some of the heavy oil fields are at relatively shallow depth (often less than 1,000 m). To some extent this offsets the higher refining costs for heavy oil, and the disadvantages of higher sulphur content and higher viscosity and density. Specialised techniques are being developed for exploration and production of heavy oil, and production is on the increase in several countries.Venezuela is the leading producer and about 25% of its crude output of 2.6 Mbbl/d comes from heavy oil. This percentage is expected to rise as conventional resources decline and heavy oil recovery technologies improve. The World Energy Council believes Venezuela’s heavy oil output will grow to 5.5 Mbbl/d by 2030.

Using existing technology, extraction and refining generates as much as three times the total CO2 emissions compared with conventional oil, mainly because of the extra energy consumed in the extraction process (which may include burning natural gas to heat and pressurise the reservoir to stimulate flow). Better production methods are being sought so as to reduce this environmental impact.

oil sandsWhat they areOil sands (also referred to as tar sands) comprise a mixture of clay, sand, water and a heavy black viscous oil known as bitumen. Oil sands are processed to extract the bitumen, which is then refined into oil. Oil sands are either mined, usually by open-pit techniques, or the oil is extracted in situ by underground heating, with additional upgrading.

Recovery involves extraction and separation systems to separate the bitumen from the clay, sand, and water, plus additional upgrading of bitumen before it can be refined. Because of its high viscosity, the bitumen also requires dilution with lighter hydrocarbons to make it transportable by pipeline.

Where they can be FoundAs much as 2 trillion barrels of the world’s oil resources could be in the form of oil sands, although not all of it is recoverable. Oil sands have a worldwide distribution but the largest deposits are in Canada (Alberta) and Venezuela. There are also large resources in the Middle East, China and the western US.

tar sands processing plant

The Alberta Government calculates that every dollar invested in the oil-sands industry creates about nine dollars worth of economic activity; with one-third of that economic value generated outside Alberta – in Canada, the US and around the world. Furthermore, one in 13 jobs in Alberta is directly related to the energy sector.

eXtraction and ProcessingEfficiencies in mining oil sands have improved considerably in the past 20 years through the introduction of large hydraulic and electrically powered shovels (43 m3 capacity) and 400 t capacity haul trucks to transport the oil sands to treatment facilities.

Initial treatment involves a hot water process to separate the bitumen from sand, water, and minerals, with the resulting slurry piped to an extraction plant where it is agitated. The combination of hot water and agitation releases bitumen from the oil sand, and causes tiny air bubbles to attach to the bitumen droplets. These float to the surface of the separation vessel, where the bitumen is skimmed off.

Only Canada has a large-scale commercial oil sands industry. The Canadian industry is in Alberta and daily production of oil exceeds 1.0 Mbbl. This represents about 40% of Canada’s oil production and output is expanding rapidly.

The oil sands are in three major areas of north-eastern Alberta. The areal extent is about 140,000 km2, and approximately 500 km2 of the land surface has been disturbed by mining. An estimated 173 billion barrels of oil are recoverable using existing technology, of which about 80% of the oil is recoverable by in situ methods and 20% by surface mining.

Further processing removes residual water and solids. The bitumen is then transported and eventually upgraded into synthetic crude oil. It takes approximately 2.0 t of oil sands to produce one barrel of oil. Roughly 75% of the bitumen contained in the oil sand can be recovered. The spent sand and other materials are returned to the mine site, which is eventually reclaimed.

In situ recovery methods are used for oil sands that are too deep to be mined economically by open pit. Techniques include steam injection, solvent injection, and firefloods (where oxygen is injected and part of the resource burned to provide heat). To date, steam injection has been the preferred method. A number of the extraction techniques consume large amounts of water and energy (for heating and pumping).

tar sands open pit mining, alberta, canadaCredit: Suncor Energy Inc.

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the key PlayersCanada’s largest producer, Syncrude Canada Ltd, is based at Fort McMurray, some 440 km north of Edmonton. It operates large open-pit mines, a utilities plant, a bitumen extraction plant and a refinery that produces light, sweet crude oil. Syncrude supplies around 15% of Canada’s petroleum needs. Last year it produced 105.8 Mbbl of crude oil and by 2015 it expects to be extracting 185–200 Mbbl/y of oil.

Aboriginal people make up 9% of the company’s workforce, and Syncrude is the largest industrial employer of Aboriginal people in Canada. One of the largest private sector employers in Alberta, the company employs more than 5,000 people directly and an average of 1,000–1,500 maintenance contractor employees. To date, the company has paid in excess of C$9.0 billion in royalty payments, and federal and provincial taxes, and more than C$1 billion is spent annually on purchased goods, services and salaries.

Syncrude says it has reclaimed over 4,500 ha of land disturbed by oil sands mining, and in 2008 it was the first company in the industry to receive certification from the Alberta Government for a reclaimed area: Gateway Hill, a 104 ha land parcel near Fort McMurray was planted in the early 1980s and comprises an extensive deciduous and coniferous forest interspersed with wetlands.

The project has had major pollution problems, however. In 2005, Syncrude’s Mildred Lake plant was ranked as having the seventh-highest air releases of combined gases (without organic acid compounds) in Canada. The plant is also Canada’s third-largest emitter of greenhouse gases. In the 11 years to 2001, Syncrude reduced CO2 emissions per barrel of oil produced by 23%, and there are plans for further reductions. But absolute emissions may not reduce significantly because of the planned increases in oil production.

The other large oil sands producer in the Athabasca Basin, Suncor Energy Inc, produces around 290,000 bbl/d of oil, and is targeting a daily average of 300,000 bbl for 2009. The company recovers bitumen through conventional truck-and-shovel surface mining and also by in situ techniques (steam injection). The end product, synthetic crude oil, is shipped by underground pipelines to refineries across North America. The company is committed to in situ development as well as expanding its surface mining as part of its goal of producing 550,000 bbl/d of oil by 2013.

Shell Canada Ltd operates the Muskeg River mine, which produces 155,000 bbl/d. There are plans to open a new mine, Jackpine, over the next few years and to raise daily production to some 500,000 bbl.

tar sands mining, alberta, canadaCredit: Suncor Energy Inc.

oil sands economicsHistorically, the cost of extracting oil from bituminous sands has been unprofitable. In mid-2006, the National Energy Board (NEB) of Canada estimated the operating cost of a new mining operation in the Athabasca oil sands at C$9–C$12/bbl, and the cost of an in situ steam-assisted gravity drainage (SAGD) operation (using dual horizontal wells) at C$10–C$14/bbl. By comparison, the operating costs for conventional oil wells range from less than C$1.0/bbl in Iraq and Saudi Arabia, to over C$6.00/bbl in North America.

The NEB estimates that capital costs raise the total cost of production to C$18–C$20/bbl for a new mining operation and C$18–C$22/bbl for a SAGD operation. This does not include the cost of upgrading the crude bitumen to synthetic crude oil, which takes the final costs to C$36–C$40/bbl for a new mining operation. However, exploration costs are very low, and could be a major factor when assessing the economics of drilling in a traditional oil field.

As a result of sharp oil-price increases in recent years the economics have improved dramatically. At a world price of US$50 per barrel, the NEB estimated an integrated mining operation would achieve a rate of return of 16–23%, whereas a SAGD operation would return 16–27%. Oil prices since 2006 have soared and, as a result, capital expenditures in Canada’s oil-sands sector for the period 2006–15 are expected to exceed C$100 billion, twice the amount projected as recently as 2004.

By 2020, the Canadian Association of Petroleum Producers expects Canadian oil sands production to be about 3.3 Mbbl, with Canada’s total oil output running at about 4.1 Mbbl/d.

environmental considerationsIt has been estimated that oil sands mining in Alberta requires 2–4.5 m3 of water to produce 1.0 m3 of synthetic crude oil. Approved oil sands mining operations are currently licensed to divert 359 million m3 from the Athabasca River per year, or more than twice the volume of water required to meet the annual municipal needs of the City of Calgary. Water licence allocations total about 1% of the Athabasca River’s average annual flow, and the provincial government sets strict limits on how much water oil sands companies can remove from the river.

The oil sands industry burns natural gas to heat the bitumen and the process releases CO2. In 2007, the industry used around one billion cubic feet per day of natural gas, equivalent to 40% of Alberta’s total usage. The forecast growth in Alberta’s synthetic oil production threatens Canada’s international commitments to the Kyoto Protocol, whereby it has agreed to reduce its greenhouse gas emissions by 6% by 2012 from 1990 levels. In 2002, Canada’s total greenhouse gas emissions had increased by 24% since 1990, and oil sands production was contributing about 3.4% of Canada’s greenhouse gas emissions. Alberta’s oil sands industry is currently contributing nearer 5%.

A C$2 billion investment has been committed to advance steel-in- the-ground carbon capture and storage (CCS) projects, and is expected to reduce annual emissions by 5.0 Mt by 2015, (the equivalent of taking one million vehicles, or one third of all registered vehicles, off Alberta’s roads). Both the provincial government and the private sector are continuing with efforts to reduce the environmental footprint of oil sands development and to increase economic recoveries.

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A report released in July 2009 by the Alberta Research Institute, claims that Canada’s tar-sands industry is cleaner than previously calculated. CO2 emissions generated by producing oil from Canada’s oil sands are about 10% higher than those generated by competing US crude imports, the report says, whereas earlier studies found greenhouse gases from oil sands were as much as 40% higher. The institute report has used new models to calculate carbon emissions from oil produced in nations such as Saudi Arabia and Venezuela where operational information may not be available. For example, the energy used in injecting water into wells to coax out more oil is included in the new calculation.

Some conservationists and environmental groups are sceptical about the findings, however, claiming that the report compares some of Alberta’s cleanest oil sands operations with some of the dirtiest conventional crude production.

gas to liquids (gtl)What it is‘Gas to Liquids’ is a refinery process to convert natural gas or other gaseous hydrocarbons into longer chain hydrocarbons such as gasoline or diesel fuel. This technology can help countries with large natural gas resources to get more out of them. It can also be used for the economic extraction of gas deposits in locations where it is not economical to build a pipeline. Gas to Liquids plants produce a wide range of products from fuels to lubricants.

Processing methodsThere are two main routes to produce a synthetic petroleum product (syncrude): direct conversion from gas and indirect conversion via synthesis gas (syngas). Methane-rich gases are converted into liquid fuels either via direct conversion or indirectly using syngas as an intermediate.

The direct conversion of methane (typically 85–90% of natural gas) eliminates the cost of producing syngas but involves a high activation energy and is difficult to control. Several direct conversion processes have been developed but none have been commercialised, being economically unattractive.

The Fischer-Tropsch process, developed by two German scientists in the 1920s, is the best-known method of indirect conversion, having been used on a large scale by Germany in World War II. The Mobil, Bergius and Karrick processes are other methods.

main PlayersWorldwide commercial GTL plant capacity is 60,000 barrels per day with plants in South Africa, Malaysia and New Zealand. South Africa’s Sasol is the leading company in the commercialisation of synthetic fuel. Other companies include Shell, Exxon, Statoil, Rentech and Syntroleum.

economic considerationsUnit production costs of GTL fuel will reflect the cost of the feedstock gas, the capital cost of the plants, marketability of by-products such as heat, water and other chemicals (for instance, excess hydrogen, nitrogen or carbon dioxide) and the availability of infrastructure and workforce. However, a US Energy Information Administration (EIA) assessment of a hypothetical GTL project estimated the cost of GTL fuel at almost $25 per barrel. Estimates of the crude oil costs necessary to generate positive economic returns from a GTL project vary widely but typical estimates indicate that oil prices would have to average $70 per barrel on a sustained basis to lead to commitments for large-scale projects.

comParison table oF unconventional Fuels economics environmenttechnology cost oF develoPment caPital cash total co2 Water resource technologies intensity oPeX cost FootPrint usage

Heavy oil medium in place medium medium medium medium low

Oil shale low in place medium medium medium medium medium

Oil sands medium advanced high medium medium medium high

Gas to liquids medium in place high medium high medium low

Coal to liquids medium advanced high high high high medium

aPPendiX iigeograPhical distribution

Heavy Oil & BitumenContaminated Heavy CrudeTight GasOil ShaleGas ShaleCoal Bed Methane

FSU

Venezuela

AUSQueensland

North East China

China

AUSGorgonScott Reef

Kazakhstan

Jordan

Canada

MIDDLE EASTQatarIraqSaudi ArabiaAbu Dhabi

United States

FSU

low, advancedmedium, in placehigh, developing

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aPPendiX iii glossary & abbreviations kukersiteA marine type oil shale of Ordovician age, found in the Baltic Oil Shale Basin in Estonia and northwest Russialamosite Gray, brown to black oil shale deposit of lacustrine origin, with the organic constituent derived from planktonic algaemarinite Gray-black oil shale deposit of marine origin, with chief organic constituents derived from phytoplanktonPyrolysisChemical decomposition of a substance by heatingretortA vessel used to distill volatile materialstorbanite Also known as boghead coal, is a fine-grained black oil shale, of lacustrine origin. It is named after Torbane Hill in ScotlandtasmaniteReddish-brown oil shale of marine origin.

abbreviationsaPiAmerican Petroleum Institutebbl barrel (one barrel = 0.136 t)mbbl/dmillion barrels per dayboebarrels of oil equivalentoPecOrganisation of Petroleum Exporting CountriesusgsUnited States Geological Survey

aPPendiX iv reFerences> BP Statistical Report on

World Energy, 2009> Energy Information

Administration, Energy Demand Forecast to 2030 (May 2009)

> USGS Scientific Investigations Report 2005–5294 by J R Dyni, entitled: Geology and Resources of Some World Oil Shale Deposits

> RAND Corporation Oil Shale Development in the United States Prospects and Policy Issues. J. T. Bartis, T. LaTourrette, L. Dixon, D.J. Peterson and G. Cecchine, MG-414-NETL, 2005.

> Reprint of: United States Geological Survey Scientific Investigations Report 2005–5294 by John R. Dyni

> US Department of Energy, Office of Petroleum Reserves

> Centre for Energy Information, Canada

> Jaan-Mati Punning, Director of the Institute of Ecology at Tallinn University of Educational Sciences, Estonia.

> W Y Abu El Shar, Department of Civil Engineering, Jordan University of Science and Technology, S. H. Gharaibeh and M. M. Al-Kofahi, Department of Earth and Environmental Sciences, Yarmouk University

> Jordan University of Science and Technology, Department of Chemical Engineering, P.O. Box 3030, Irbid 22110, Jordan e-mail: [email protected] Tel.: +962-27095111, ext. 22410 Fax: +962-27095018, JO

> Oil shale processing as a source of aquatic pollution: monitoring of the biologic effects in caged and feral freshwater fish. A Tuvikene, S Huuskonen, K Koponen, O Ritola, U Mauer, and P Lindström-Seppä

> Institute of Zoology and Hydrobiology, University of Tartu, Tartu, Estonia; Limnological Station, Institute of Zoology and Botany, Estonian Agricultural

University, Rannu, Estonia. [email protected]

> Xia H P, 2003, Ecological rehabilitation and the use of grasses to remediate land affected by oil shale mining at Maoming, China, South China Institute of Botany, Guangzhou 510650, People’s Republic of China (Ref; http://ostseis.anl.gov/guide/tarsands/index.cfm)

> Wikipedia> ‘Kimmeridge – The Blackstone-

Oil Shale’, by Ian West, University of Southampton, 2006.

> ‘Shale of the Century’ by Ted Nield, The Geological Society, London, Geoscientist, February 2006.

acknoWledgments– ARGONNE NATIONAL LABORATORY– CITRUS PARTNERS, LONDON. UK– DMT GMBH, ESSEN, GERMANY– ECO CONSULT, AMMAN, JORDAN– ENEFIT (EESTI ENERGIA) LIMITED,

TALLINN, ESTONIA– EXXON MOBIL, HOUSTON,

TEXAS, USA– FUSHUN MINING GROUP,

FUSHUN, CHINA– HATCH LIMITED, TORONTO,

CANADA– IMC GROUP CONSULTING LTD.,

NOTTINGHAM, UK– INTERNATIONAL FINANCE

CORPORATION, WASHINGTON, USA– JORDAN ENERGY AND MINING

LIMITED, LONDON, UK– JORDAN INVESTMENT BOARD,

AMMAN, JORDAN– KRUPP POLYSIUS, BECKUM,

GERMANY– LAHMEYER INTERNATIONAL,

BAD VILBEL, GERMANY– MARSTON, CALGARY, CANADA– MIRABAUD SECURITIES LIMITED,

LONDON. UK– PETROBRAS, SAO MATEUS DO SUL,

BRASIL– PURVIN & GERTZ INC. CALGARY, USA– SHELL BUSINESS DEVELOPMENT

M. E. LIMITED, AMMAN, JORDAN– SUNCOR ENERGY INC., CALGARY,

CANADA– TUV NORD GROUP, ESSEN, GERMANY– UMATAC INDUSTRIAL PROCESSES,

CALGARY, CANADA– UOP LLC, DES PLAINES,

ILLINOIS, USA– VKG (VIRU KEEMIA GRUPP)

TALLINN, ESTONIA

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Developing tomorrow’s energy today

Executive summary 2The energy crunch 4What is oil shale? 6A long history 7Past projects 8Where is oil shale found? 10Evaluating oil shale quality 14From rock to oil: 15 How oil shale is extracted and processedEconomic considerations 22Exploding the myths 23Mining: the benefits 29Projects in the pipeline 31Conclusions 36

Appendices I. Other unconventional liquid hydrocarbon fuels 38 •Coaltoliquids 38 •Heavyoil 38 •Oilsands 39 •Gastoliquids 43Comparison table of non conventional fuels 44II.Geographicaldistribution 44III.Glossary&abbreviations 45IV. References 45

AuthorRoger Ellis BSc C.ENG MIMMMMinerals Industry ConsultantT: +44 (0)1277 354279E: [email protected] EditorMelanie SilverT: +44 (0)1923 212048E: [email protected] DesignSampsonMay T: +44 (0)20 7403 4099E: [email protected]

Oil Shale Information Centre33 St James’s SquareLondon SW1Y 4JSUnited Kingdom T: +44(0) 203 1784511F: +44(0) 203 1784821E: [email protected]

www.oilshale.co.uk