Expectations for Oil Shale Production |
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Background Oil shales are fine-grained sedimentary rocks that contain relatively large amounts of kerogen, which can be converted into liquid and gaseous hydrocarbons (petroleum liquids, natural gas liquids, and methane) by heating the rock, usually in the absence of oxygen, to 650 to 700 degrees Fahrenheit (in situ retorting) or 900 to 950 degrees Fahrenheit (surface retorting) [60]. (“Oil shale” is, strictly speaking, a misnomer in that the rock is not necessarily a shale and contains no crude oil.) The richest U.S. oil shale deposits are located in Northwest Colorado, Northeast Utah, and Southwest Wyoming (Table 10). Currently, those deposits are the focus of petroleum industry research and potential future production. Among the three States, the richest oil shale deposits are on Federal lands in Northwest Colorado. The Colorado deposits start about 1,000 feet under the surface and extend down for as much as another 2,000 feet. Within the oil shale column are rock formations that vary considerably in kerogen content and oil concentration. The entire column ultimately could produce more than 1 million barrels oil equivalent per acre over its productive life. To put that number in context, Canada’s Alberta oil sands deposits are expected to produce about 100,000 barrels per acre. The recoverable oil shale resource base is characterized by oil yield per ton of rock, based on the Fischer assay method [61]. Table 10 summarizes the approximate recoverable oil shale resource within the three States, based on the relative oil concentration in the oil shale rock. In addition to oil, the estimates include natural gas and natural gas liquids, which make up 15 to 40 percent of the total recoverable energy, depending upon the specific shale rock characteristics and the process used to extract the oil and natural gas. The three States contain about 800 billion barrels of recoverable oil in deposits with expected yields of more than 20 to 25 gallons oil equivalent per ton, which are more attractive economically than deposits with lower concentrations of oil. In comparison, on December 31, 2007, U.S. crude oil reserves were 21 billion barrels, or roughly 2.5 percent of the amount potentially recoverable from oil shale deposits in the three States [62]. Oil Shale Production Techniques Liquids and gases can be produced from oil shale rock by either in situ or surface retorting. During the mid-1970s and early 1980s, the petroleum industry focused its efforts primarily on underground mining and surface retorting, which consumes large volumes of water, creates large waste piles of spent shale, and extracts only the richest portion of the oil shale formation. There were also some experiments using a “modified in situ process,” in which rock was mined from the base of the oil shale formation, explosive charges were set in the mined-out area (causing the roof to collapse and fragmenting the rock into smaller masses), and underground fires were set on the rubble to extract natural gas and petroleum liquids. The combustion proved difficult to control, however, and the process produced only low yields of petroleum liquids. Surface subsidence and aquifer contamination were additional issues. The in situ processes now under development raise the temperature of shale formations by using electrical resistance or radio wave heating in wells that are separate from the production wells. Also being considered are “ice walls”—commonly used in construction—both to keep water out of the areas being heated and to keep the petroleum liquids that are produced from contaminating aquifers. The benefits of those methods include uniform heating of the formation; high yields of gas and liquid per ton of rock; production of high-quality liquids that commingle naphtha, distillates, and fuel oil and can be upgraded readily to marketable products; production yields of more than 1 million barrels per acre in some locations; no requirement for disposal and remediation of waste rock; reduced water requirements; scalability, so that additional production can be added readily to an existing project at production costs equal to or less than the cost of the original project; and lower overall production costs. Given these advantages, an in situ process is likely to be used if large-scale production of oil shale is initiated. Although the technical feasibility of in situ retorting has been proved, considerable technological development and testing are needed before any commitment can be made to a large-scale commercial project. EIA estimates that the earliest date for initiating construction of a commercial project is 2017. Thus, with the leasing, planning, permitting, and construction of an in situ oil shale facility likely to require some 5 years, 2023 probably is the earliest initial date for first commercial production. Economic Issues Because no commercial in situ oil shale project has ever been built and operated, the cost of producing oil and natural gas with the technique is highly uncertain. Current estimates of future production costs range from at least $70 to more than $100 per barrel oil equivalent in 2007 dollars. Therefore, future oil shale production will depend on the rate of technological progress and on the levels and volatility of future oil prices. Technology progress rates will determine how quickly the costs of in situ oil shale extraction can be brought down and how quickly natural gas and petroleum liquids can be produced from the process. The in situ retorting techniques currently available require the production zone to be heated for 18 to 24 months before full-scale production can begin. In addition to price levels, the volatility of oil prices is particularly important for a high-cost, capital-intensive project like oil shale production, because price volatility increases the risk that costs will not be recovered over a reasonable period of time. For example, if oil prices are unusually low when production from an oil shale project begins, the project might never see a positive rate of return. Public Policy Issues Development of U.S. oil shale resources also faces a number of public policy issues, including access to Federal lands, regulation of CO2 emissions, water usage and wastewater disposal, and the disturbance and remediation of surface lands. If the petroleum industry were not permitted access to Federal lands in the West, especially in Northwest Colorado, the industry would be excluded from the largest and most economical portion of the U.S. oil shale resource base. In addition, current regulations of the U.S. Bureau of Land Management require that any mineral production activity on leased Federal lands also produce any secondary minerals found in the same deposit. On Federal oil shale lands, deposits of nahcolite (a naturally occurring form of sodium bicarbonate, or baking soda) are intermixed with the oil shales. Relative to oil and other petroleum products, nahcolite is a low-value commodity, and its price would fall even further if its production increased significantly. Thus, co-production of nahcolite could increase the cost of producing oil shale significantly, while providing little revenue in return.
Contact: Philip Budzik/John Cochener
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