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Features ARCHIVE
August 2005
Vol. 226 No. 8 

Unconventional Resources

Hopes for shale oil are revived

Sometimes called the resource of the future - and it always will be -this rock, with its enormous potential, might be experiencing a comeback in the US in the next few years. But, might and might not, don't they mean the same thing?

Companies, markets and politicians are entering into a well-known cycle, one that is causing them to say that oil shale needs to be looked at anew. Industry and government will need to be convinced that today's $50-plus oil prices will persist long enough to make everyone believe that they are here to stay, or convinced that issues of energy security and peak oil are sufficiently dire. Either way, these will certainly be key drivers, and are two of the reasons for presenting this article.

Government incentives are looming in new US legislation, while the paperwork for experimental leases is being prepared. A unique, long-term in situ experimental process is learning its technical lessons, while a new surface mining method struggles to get its feedstock online. Elsewhere in the world, small- and large-scale pilots and projects continue to operate, and direct use of the greasy rock continues. This article discusses the history, use and current status of this ubiquitous, unusual resource.


Oil shale is a fine-grained sedimentary rock. It contains geothermally immature organic matter, called kerogen, that will yield substantial amounts of refinery input-grade liquid hydrocarbons and combustible gas when destructively distilled. An oil shale deposit having economic potential is generally at, or near, the surface, enabling development by open-cast or conventional underground mining, or by in situ methods.

The geologic age of these rocks ranges from Cambrian to Tertiary. The depositional environments of these shales include freshwater to highly saline lakes, epicontinental marine basins and sub-tidal shelves, as well as the type of limnic and coastal swamps that are commonly associated with coal deposits. But oil shales differ from coal in that they typically contain much larger amounts of inert mineral matter - about 60 to 90% - than coals, which, by definition, contain less than 40% mineral matter. The organic matter of oil shale, which is the source of its hydrocarbon potential, usually has a higher hydrogen/ oxygen ratio than coal and, generally, has less vascular plant material. 1

Much of the organic matter in oil shale is of algal origin, but may also include the remains of animals and land plants, pieces of which can sometimes be identified as to species. For the remaining organic components, there is still some uncertainty concerning its origin, due to the lack of identifiable biologic structures. Such materials might be bacterial in origin or a result of bacterial degradation of algae or other organics.

The mineral component varies as much as the organic component. Some oil shale is composed of carbonates, including calcite, dolomite, and siderite, with lesser amounts of aluminosilicate minerals. 1 Other oil shales are mostly silicates, where quartz, feldspar and clay minerals are dominant. And some deposits contain small, but significant, amounts of sulfide minerals, suggesting a depositional environment that lacked oxygen.

In addition to its hydrocarbon potential, some oil shale deposits contain minerals and metals that can add value, including alum, nahcolite, dawsonite, ammonium sulfate, vanadium, zinc, copper and uranium. The leftover ash from surface processing is sometimes used in cement manufacturing.


A very conservative estimate of the in situ oil shale resource is estimated at 2.9 trillion barrels of oil shale. 1 This figure only includes the known, explored oil shale deposits in 33 countries. If half of this resource can be exploited, it would equal as much oil as has been cumulatively produced worldwide. The US has the lion's share of this shale in both quantity and quality, with some 2.0 trillion barrels. Fig. 1 puts this amount in perspective. The largest known deposit in the world is the Green River oil shale in the western US. It contains an estimated 1.5 trillion in situ US barrels, and is one of the highest quality oil shales in the world.

Fig 1

Fig. 1. Conventional and unconventional resources and reserves. 2

Oil shale has been used continually in various countries for decades, rising and falling, to some extent, with long-term price trends. But even absent high prices or tight oil supplies, countries with limited choices for energy supplies may find it worthwhile to develop their native resources rather than import all of their energy needs, especially when oil shale deposits are easily exploited. Deposits of oil shale are found in many parts of the world. These deposits range from minor accumulations to giant deposits that occupy thousands of square miles and reach thicknesses of 2,000 ft or more.

When dry oil shale is crushed and burned directly, its gross heating value ranges from about 500 to 4,000 kcal/kg. 1 By comparison, the heating value of dry, mineral-free basis lignite coal ranges from 3,500 to 4,600 kcal/kg (ASTM, 1966). Fig. 2 shows the annual amount of oil shale mined in six selected countries over a 20-year period. The top five countries mined between 30 and 45 million metric tons of oil shale annually in 1980. This includes shale that is processed for liquid hydrocarbons, as well as direct combustion of the rock itself.

Fig 2

Fig. 2. Annual shale oil mined in eight selected countries, 19802000. 1

Australia mined about 4 million tons of oil shale between 1860 and 1960. This included deposits at Joadja Creek and Glen Davis in New South Wales, and deposits in Tasmania. Glen Davis closed in 1952 and was the last oil shale operation in Australia for nearly 50 years. This shale was used in destructive distillation processes to produce various hydrocarbons, lubricants and fuels, including gasoline. 1

In 1995, SPP/ CPM signed with the Canadian company, Suncor Energy, to develop the Stuart oil shale deposit, located near Gladstone. The project uses the Alberta-Taciuk Processor (ATP) retort technology and had three planned stages, with Stage 3 planned for 85,000 bpd by 2009. Suncor operated the Stuart project, with its Stage I ATP retort technology demonstration plant attaining full production in 2001. The venture had spent $250 million on the project. It produced 4,500 bpd from 6,000 tons per day of oil shale when it was running, cumulatively producing over 1 million bbl of products and a lot of "lessons learned" before being shut down.

The joint venture ran into financial and environmental compliance problems. Also in 2001, Suncor exited the project and sold its interest to SPP. In February, US-based Sandefer Capital Partners formed Queensland Energy Resources (QER) to buy out SPP. Sandefer Capital Partners was already a major investor in SPP, which had been in the hands of receivers.

Brazil began its oil shale industry in 1950 with the establishment of the Oil Shale Industrialization Commission (CIXB). It was set up to study the construction of a plant in the town of Tremembé. In 1954, when Brazil's national oil company, Petrobras, was established, a division of that company, SIX, oversaw oil shale development. Early production focused on the Paraíba Valley northeast of the city of São Paulo. Later efforts concentrated on the Permian Irati formation, a large unit in southern Brazil. A prototype oil shale retort plant, built near Sao Mateus do Sul, began operations in 1972. It had a design capacity of 1,600 tons of oil shale per day. Using a proprietary PetroSix process, a larger version was built in 1991 that was 35 ft in diameter. It produced about 550 tons of "oil" per day. More than 1.5 million tons of shale oil products had been produced through 1998.

China's main oil shale resources are at Fushun, with a small amount (3.5 million tons of yearly) at Maoming. The first commercial production of shale oil began at Fushun in 1930 and at Maoming in 1963. A new retort plant at Fushun began production in 1992. More than 60 Fushun-type retorts, having a capacity of 100 tons of oil shale per day, produce 60,000 tons of shale oil per year. 1,3

Estonia uses about 80% of its oil shale to fuel several electric power plants through direct crushing and then burning it as boiler fuel. The remaining 20% is processed into petrochemicals, cement and other minor products. Full-scale mining began in 1918 with the production of 17,000 tons. By 1940, annual production of oil shale reached 1.7 million tons. 1 Production peaked in 1980 at 31.4 million tons. Mining of oil shale is via several open-pit and underground mines. By 1994, production had decreased to about 14 million tons before recovering to 22 million tons in 1997. Some Estonian oil shale has been an important source of uranium, providing 22.5 tons of the element.

Sweden and Russia have been small producers of oil shale. It is a principal source of uranium in Sweden.

In the United States, which has 62 - 72% of the world's oil shale resource (see Fig. 3) 2,4 the two most important oil shale deposits are in the Green River formation in Colorado, Wyoming and Utah (see Fig. 4), and the black shales of the eastern US. Minor/ low-grade deposits occur in Nevada, Montana, Alaska, Kansas and other states. By a substantial margin, the oil shales in Colorado have the highest production potential in the US. They also comprise about half (1 trillion bbl) of the total US resource, Fig. 3.

Fig 3

Fig. 3. Comparative resource potential of selected countries. 2

Fig 4

Fig. 4. Green River, Unita, Pisceance and Washakie basins comprise the major deposits of the kerogen-rich Green River formation. For comparison, inset shows barrels of oil equivalent/ acre for various resources. 2

Production history in the US has been extensive and highly dependent on governmental support. It is only highlighted here. It began in the 1900s with small, rudimentary retorts. The oil shale retort kiln in DeBeque, Colorado, in 1918 gave rise to the first oil shale boom in the area. Over 30,000 mining claims were filed before the boom went bust in 1925. The first large-scale governmental effort started with the opening of the Anvil Points mines in 1949 in the Mahogany Ledge. Relatively minor amounts of oils were produced, and the project was abandoned in 1956. In 1955, Union Oil of California began a shale operation near Parachute, Colorado. It produced up to 800 bpd before closing in 1961. Tosco and Sohio, with partner Cleveland-Cliffs, produced 270,000 bbl of liquids from their Colony project facility near Parachute from 1964 - 1972. Two years later, Colony was revived by Unocal's new "Union B" retort process; Shell and Ashland joined the project.

During the 1970s, Shell researched the Piceance Creek in situ steam injection for oil shale and nahcolite. The first of six in situ experiments were begun in 1972 at Logan Wash by Occidental. Oxy's in situ process combined mining and explosive rubblizing to create an underground retort. That same year, Paraho was formed as a consortium of 17 companies. It leased the Anvil Points facility and built a 24 tons/ day pilot plant and 240 tons/ day semi-works plant. The company won a Navy contract to produce 100,000 bbl of shale oil for testing as a military fuel.

In response to the OPEC embargo and energy problems of the 1970s, Congress passed the Energy Security Act, establishing the US Synthetic Fuels Corp. It authorized up to $88 billion for synthetic fuels projects, including oil shale. In 1980, Exxon bought Arco's Colony interest and began Colony II construction, designed for 47,000-bpd production. Also in 1980, Congress approved $14 billion more for synthetic fuels development. That same year, Amoco's Rio Blanco experiment produced 1,900 bbl of in situ oil at its C-a lease. The following year, a second Rio Blanco in-situ demonstration produced 24,400 bbl of shale oil. Construction began in 1981 on Unocal's Long Ridge 50,000-bpd plant. Then, in 1982, the oil price/ demand collapse hit.

Exxon announced that it would close Colony II. The locals called it Black Sunday, as 2,200 workers lost their jobs. During the next five or so years, another 28,000 jobs would be lost as activity wound down. The effect on small Colorado towns that had benefited from the boom was devastating. By 1985, Congress had abolished the Synthetic Liquid Fuels Program after spending $8 billion over 40 years.

In 1987, Paraho reorganized as New Paraho and began production of an asphalt additive called SOMAT. By 1991, Unocal had closed the Long Ridge plant after producing 5 million bbl of liquids and suffering 10 years of operational issues and losses. Doggedly pursuing in situ technology, Shell tested the technique on its Mahogany property; deferring further work due to economics, only to return in 2000 with an expanded in situ, electrical heating technology research plan, which is still ongoing. 5


Brazil, China and Estonia still have appreciable oil shale mining activity. All enjoy governmental support.

In Australia, Greenpeace has been a staunch foe of the Stuart project, objecting to all forms of atmospheric emissions, particularly CO2, with respect to global warming. It is claiming victory. Queensland Energy Resources closed Stage 1 of the Stuart Shale project in July 2004. After further evaluation, in December 2004, QER advised Australian officials that it wished to discontinue the Environmental Impact Statement process for the proposed Stage 2 development. Although it is possible that this project could be resurrected, it is now in a state of deep languishment. There are several other potential oil shale projects whose status is similarly uncertain.

Brazil is making high-quality transportation fuels and other oil shale products at a rate of about 3,900 bpd.

In Estonia, over 90% of electricity produced in Estonia is based on oil shale. The country is a net exporter of electricity. Not surprisingly, 90% of the water consumed in Estonia is used in oil shale mining and consumption. And an attendant 97% of air pollution and 86% of total waste come from its power industry as well. 8 In the past few years, the country has installed two, 215-MW energy blocks, now in operation at its Narva Power plants. They are using new, circulation fluidized bed combustion technology, leading to a significant decrease of SO2 and CO2 emissions.

China's production from its Fushun shale oil plant in 2002 was about 90,000 tons of shale oil, wrought from 3 million tons, most of which is sold as fuel oil. 6 There are plans in China to at least double its current oil shale production. A new oil shale plant is under construction, comprising two sets with 40 new retorts that are identical to the existing ones and are planned for startup sometime this year. 7

The US has seen an increase in interest in the oil shales of the Green River formation. As reported in the August 2004 issue of World Oil (pg. 19), a Utah-based, privately held corporation called Oil Tech, Inc., claims to have developed and installed an improved surface retorting process that can produce shale oil for less than $10 to $20 a barrel. A vertical, modular, gravity-flow system that, according to the company website, "includes processes for generating its own water supply and electricity, ensuring uninterrupted production using interchangeable modular pieces." The retort-style prototype was reported to have passed a successful test last year. Exactly what makes the technology unique is not being released. The company is apparently very difficult to contact, so its status is uncertain.

Despite the discontinuation of other in situ experiments in the area, Shell has quietly, yet doggedly, pursued its own in situ experiments. Some 23 years ago, Shell began laboratory and field research on an in-situ oil shale conversion and recovery process. Called the In-situ Conversion Process, or ICP, the company successfully carried out its first small field test in 1996 on its privately owned Mahogany property in Rio Blanco County, Colorado, about 200 mi west of Denver. Since then, Shell has carried out four additional, related field tests at nearby sites. The most recent test was over the past several months and produced more than 1,200 barrels of light oil plus associated gas from a test plot of about one acre using the ICP technology.

The oil shale is heated using electric resistance heaters in boreholes, 500 to 1,000 ft deep, in situ, to around 650°F over several months to three or more years. The process results in the production of about 65 to 70% of the original carbon in place in the subsurface. The carbon that remains in the sub-surface resembles a char, is extremely hydrogen deficient and, if brought to the surface, would require extensive, energy-intensive upgrading and saturation with hydrogen.

The ICP process is energy intensive, as it requires injection of heat into the subsurface. However, for each unit of energy used to generate power to provide heat for the process, about 3.5 units of energy are produced and treated for sales. Electricity is a problem in several ways. One is getting it cheaply. Another is putting it in the ground. The electrodes must be able to take the punishment of high-amperage current for years, or else a costly maintenance program ensues. And cooking hydrocarbons, regardless of where, can cause a lot of carbon buildup. In situ buildup would likely be near or on the wellbore, possibly impeding heat flow.

Wind could be an option for off-grid electricity supply when the project reaches the first commercial threshold, which is forecast in five years. This necessarily means that the wind resource is nearby, but it would introduce the problem of an intermittent power supply. Wind is now competitive with most newly installed power 9 , especially if the 1.8 cent per kWh subsidy applies. Of course, this would amount to US federal subsidies for oil production. On-site coal-fired power could be supplied, but this would ruin some of the environmental "benignity" of the operation, not that it's actually benign.

Finally, natural-gas fired, on-site power could be used from gas generated in the ICP process, but only later on, after it has achieved a certain momentum. Perhaps all three could be used in some sort of power-sharing scheme, adjusting loads and sources as the project grows in size over time. You can bet that Shell has looked into all of these possibilities and more, and has filed numerous patents. After all, the company has been studying the problem for 23 years.

The production mix generally seen from Colorado oil shale is about two-thirds liquids and one-third natural gas and NGLs, such as propane and butane. On the liquid side, the typical split is about 30% naphtha, 30% jet fuel and 30% diesel, with the remaining 10% being slightly heavier. Because the ICP process is in situ, special care must be taken to keep groundwater away from the process, as its influx would seriously reduce thermal efficiency and potentially pollute groundwater if it migrated. A 10-to-20 ft thick wall of ice serves to contain and separate the produced hydrocarbons from groundwater, Fig. 5.

Fig 5

Fig. 5. Schematic showing principal components of Shell's in situ shale oil process. Blue ice wall surrounds and contains the field.

The ICP process uses about one-tenth as much water as do surface mining methods, which can require several barrels of water for each barrel of shale oil.

The technology has the potential to recover more than 1 million barrels of oil per acre in the richest parts of the Green River formation, or about 10 times the amount possible from conventional mining and retorting. Shell has about 55 research personnel in Colorado, in addition to approximately 100 Houston and Denver-based employees assigned to this project. Much work and expenditure still remain before the ICP process can be deemed commercial. 10

In testimony before the US Congress, Shell was unabashed in asking for governmental support for this project, including removal of lease-size restrictions on 5,120 acres, and pointing out that all of the other oil shale producers worldwide enjoy governmental support. 10 Congress is considering funding for shale oil projects once again, as part of the overall Energy Bill that has been years in the making. That bill could be passed by the time you read this. Meanwhile, the BLM - a federal land management agency that controls over 70% of the richest oil shale land - is going to proceed with experimental leases. These leases were published June 6 in the Federal Register. They call for R&D to demonstrate the commercial feasibility of oil shale extraction within a 10-year period. Once proven commercially viable, a company could then begin the process for commercial operations. Companies have until September 7, 2005, to nominate areas.  WO


1 Dyni, J. R., "Geology and resources of some world oil-shale deposits," Oil Shale, 2003, Vol. 20, No. 3, ISSN 0208-189X, pp. 193-252, Estonian Academy Publishers, 2003, presented at Symposium on Oil Shale in Tallinn, Estonia, Nov. 18 - 21, 2002.

2 Dammer, T., "Strategic significance of America's oil shale resource," presented at 2005 EIA Mid-term Energy Outlook Conference, US Department of Energy, Washington D.C., April 12, 2005.

3 Chilin, Z., "General description of Fushun oil shale retorting factory in China,"Oil Shale, Vol. 13, No. 1, pp. 7 - 11, 1995.

4 World Energy Council, "Survey of energy resources," 2001, Chapt. 3.

5 "Strategic significance of America's oil shale resource, Volume II: Oil shale resources technology and economics," Office of Deputy Assistant Secretary for Petroleum Reserves - Office of Naval Petroleum and Oil Shale Reserves, US Dept. of Energy, Washington, D.C., Table A1, March 2004.

6 Qian, J., Wang, J. and S. Li, "Oil shale development in China,"Oil shale, Vol. 20, No. 3 Special ISSN 0208-189X, pp. 356-359, Estonian Academy Publishers, 2003.

7 Purga, J., Editor's Page, Oil Shale, 2004, Vol. 21, No. 4 ISSN 0208-189X, Estonian Academy Publishers, 2004.

8 Raukas, A., Editor's Page, Oil Shale, 2005, Vol. 22, No. 1 ISSN 0208-189X, p. 3-4, Estonian Academy Publishers, 2005.


10 Testimony of Stephen Mut, CEO, Shell Unconventional Resources Energy, Before The Senate Energy & Natural Resources Committee, Washington, D.C., Relating to potential development of US oil shale resources, April 12, 2005.

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