Appendix B
Alternative Energy Resources

OIL SHALE

Oil shale is sedimentary rock that is dark brown to black in color and high in organic matter. The organic matter is called kerogen, fossilized insoluble organic material that will yield liquid and gaseous hydrocarbons upon distillation. The kerogen can be converted into petroleum products by distillation. The shale must be heated, typically in a closed vessel (retort), to about 500°C to convert it into petroleum. Fisher assay is the most common method of ranking oil shale in terms of potential oil produced. Oil yields generally vary from 10 to 50 gallons per ton and some oil shale is as high as 65 gal/ton. Shales yielding more than 25 gal/ton are the most attractive and are considered to be potential resources.

Oil shale is generally shallower (<3,000 feet) than the deeper and warmer geologic zones required to form oil. The origins of oil shale can be categorized into three basic groups: terrestrial (organic origins similar to coal-forming swamps), lacustrine (organic origins from fresh or brackish water algae), and marine (organic origins from salt water algae, acri-tarchs, and dinoflagellates).1

Worldwide, the oil shale resource base is believed to contain about 2.6 trillion barrels, of which the vast majority of over 2.1 trillion barrels of oil equivalent, (including eastern and western shales), is located within the United States.2 Due to differences in kerogen type (compared to western shale), eastern oil shale requires different processing. However, with processing technology advances, potential oil yields from eastern shales could someday approach yields from western shales.

1

J.R. Dyni, “Oil Shale Deposits of the U.S.,” Oil Shale Journal, 20:3, 2003.

2

Ibid.



The National Academies | 500 Fifth St. N.W. | Washington, D.C. 20001
Copyright © National Academy of Sciences. All rights reserved.
Terms of Use and Privacy Statement



Below are the first 10 and last 10 pages of uncorrected machine-read text (when available) of this chapter, followed by the top 30 algorithmically extracted key phrases from the chapter as a whole.
Intended to provide our own search engines and external engines with highly rich, chapter-representative searchable text on the opening pages of each chapter. Because it is UNCORRECTED material, please consider the following text as a useful but insufficient proxy for the authoritative book pages.

Do not use for reproduction, copying, pasting, or reading; exclusively for search engines.

OCR for page 347
Appendix B Alternative Energy Resources OIL SHALE Oil shale is sedimentary rock that is dark brown to black in color and high in organic matter. The organic matter is called kerogen, fossilized insoluble organic material that will yield liquid and gaseous hydrocarbons upon distillation. The kerogen can be converted into petroleum products by distillation. The shale must be heated, typically in a closed vessel (retort), to about 500°C to convert it into petroleum. Fisher assay is the most common method of ranking oil shale in terms of potential oil produced. Oil yields generally vary from 10 to 50 gallons per ton and some oil shale is as high as 65 gal/ton. Shales yielding more than 25 gal/ton are the most attractive and are considered to be potential resources. Oil shale is generally shallower (<3,000 feet) than the deeper and warmer geologic zones required to form oil. The origins of oil shale can be catego- rized into three basic groups: terrestrial (organic origins similar to coal-forming swamps), lacustrine (organic origins from fresh or brackish water algae), and marine (organic origins from salt water algae, acri-tarchs, and dinoflagellates). 1 Worldwide, the oil shale resource base is believed to contain about 2.6 trillion barrels, of which the vast majority of over 2.1 trillion barrels of oil equivalent, (including eastern and western shales), is located within the United States.2 Due to differences in kerogen type (compared to western shale), eastern oil shale requires different processing. However, with processing technology advances, potential oil yields from eastern shales could someday approach yields from western shales. 1J.R. Dyni, “Oil Shale Deposits of the U.S.,” Oil Shale Journal, 20:3, 2003. 2Ibid. 

OCR for page 347
 APPENDIx B U.S. oil shales are concentrated in the western United States in the states of Colorado, Utah, and Wyoming, but sizable quantities also exist in the eastern United States. The most economically attractive deposits, containing an estimated 1.5 trillion barrels of oil equivalent, are found in the Green River Formation of Colorado in the Piceance Creek Basin, in Utah in the Uinta Basin, and in Wyoming in the Green River and Washakie Basins. In particular: • Colorado has 1.2 trillion barrels of oil shale resources, and five RD&D projects are currently being reviewed for Environmental Impact Statements (EISs) by the Bureau of Land Management (BLM) under their oil shale RD&D program. Shell has three projects, Chevron/Texaco has one, and EGL has one. The EIS is also under way for commercial leasing in 2007 or 2008. • Utah has substantial oil shale resources and BLM has recently granted one company the right to proceed to a pilot project. The USGS has had an oil shale data compilation project in Utah for the last 2 years. • In the eastern United States, oil shale underlies the Appalachian, Illinois, and Michigan Basins, predominantly in Devonian age deposits covering hundreds of thousands of acres from Illinois to New York to Alabama, and it is estimated that there are 189 billion barrels of oil equivalent in Eastern oil shale. 3 Kentucky has the largest outcrop of oil shale in the eastern United States and also has the largest amount of surface and near-surface oil shale. A two county area in eastern Kentucky was investigated in detail in the 1980s and was estimated to contain 4.4 billion barrels of oil equivalent with 1.3 billion barrels in a stripping ratio of 2.5:1. The extent and characteristics of U.S. western oil shale resources, and particu- larly those in the Green River Formation, are well known and documented.4 More than a quarter million assays have been conducted on core and outcrop samples for the Green River oil shale, and results have shown that the richest zone, known as the Mahogany zone, is located in the Parachute Creek member of the Green River Formation. This zone can be found throughout the formation. A layer of volcanic ash several inches thick, known as the Mahogany marker, lies on top of the Mahogany zone and serves as a convenient stratigraphic event that allows oil shale beds to be correlated over extensive areas. Because of its relatively shallow nature and consistent bedding, the resource richness is well known, giving a high degree of certainty as to resource quality. By assay tech- 3Dyni, op. cit. 4Anton Dammer, Office of the Deputy Assistant Secretary for Petroleum Reserves, Office of Naval Petroleum and Oil Shale Reserves, U.S. Department of Energy Washington, D.C., Strategic Signi��� cance of America�s Oil Shale Resource, Volume II, Oil Shale Resources, Technology and Economics, March 2004, pp. 2-5.

OCR for page 347
 APPENDIx B niques oil yields vary from about 10 gal/ton to 50 gal/ton and, for a few feet in the Mahogany zone, up to about 65 gal/ton. When discussing oil shale resources, it is important to qualify the resource estimates by richness. Of the 1.5 trillion barrels of western oil shale resources, an estimated 418 billion barrels are in deposits that will yield at least 30 gal/ton in zones at least 100 feet thick,5 and there are estimated resources of 750 billion barrels at 25 gal/ton in zones at least 10 feet thick.6 In general, room and pillar mining is likely to be used for resources that outcrop along steep erosions, and horizontal room and pillar mining has been used successfully by Unocal. Deeper and thicker ores will require vertical shaft mining, modified in situ, or true in situ recovery approaches. Because the pay zone is more than 1,500 feet thick in some places, it is conceivable that open pit mining could be applied even with 1,000 feet of overburden. In recent years, Shell has experimented with a novel in situ process that shows promise for recovering oil from rich, thick resources lying beneath several hun- dred to 1,000 feet of overburden. There are locations that could yield in excess of 1 million barrels per acre and require, with minimum surface disturbance, fewer than 23 square miles to produce as much as 15 billion barrels of oil over a 40-year project lifetime. In addition, in the northern Piceance Creek basin, zones of high- grade oil shale also contain rich concentrations of nahcolite and dawsonite—high- value minerals that could be recovered through solution mining. However, oil shale still faces a number of challenges to future development as a resource. Its recovery is still not economically practicable, and uncertain oil price forecasts and a lack of R&D into reducing production costs hamper its economic competitiveness. Both in situ and surface processes are energy intensive, thus while the recovered resources may satisfy one energy demand for liquid fuels, the net balance is much smaller and is an important consideration, particularly in light of efforts to reduce fossil fuel combustion. Current production methods release significantly more greenhouse gases than conventional crude oil production and refining. Retorting also requires large amounts of water and is a potential source of pollutants, and in the case of surface retorting, can also result in land and ecological disturbances. ENHANCED OIL RECOVERY Crude oil production occurs via a series of oil “crops” called primary (1st crop), secondary (2nd crop), and tertiary (3rd crop). Enhanced oil recovery (EOR) is a term often used to describe tertiary recovery, but should be reserved for the more advanced oil production technologies regardless of where the process occurs 5W.J. Culbertson and J.K. Pitman, “Oil Shale,” in United States Mineral Resources, USGS Profes- sional Paper 820, Probst and Pratt, eds., 1973, pp. 497-503. 6J.R. Donnell, “Geology and Oil-Shale Resources of the Green River Formation,” Proceedings, First Symposium on Oil Shale, Colorado School of Mines, pp. 153-163, 1964.

OCR for page 347
0 APPENDIx B in the sequence of oil crops. For example, thermally enhanced recovery of tars or heavy oils utilizes advanced technologies for the first or second crops of oil from a given resource. Primary oil recovery is often the least efficient method in terms of the per- cent of original oil in place (OOIP) recovered, unless the reservoir has an active aquifer providing the driving force. Sometimes only 5 or 10 percent of OOIP is produced during primary recovery, especially in the case of low-pressure, shallow reservoirs with only small amounts of internal energy to force the oil out. After primary production has been completed, reservoirs require additional (secondary) energy sources to recover the oil left behind. Secondary oil recovery techniques historically have referred to the injection of gas or water to displace oil and drive it to a production well, and secondary recovery often yields as much as or more oil than primary recovery. Well-designed water floods may recover 20 to 40 percent of the OOIP, depending on oil and reservoir characteristics, leaving “residual oil” amounting to perhaps 50 percent of the OOIP. Theoretically, EOR techniques offer prospects for producing up to 100 per- cent of the residual oil under nearly perfect reservoir conditions; however, practi- cally speaking, the additional recovery is more likely to be similar to the amount of oil recovered during secondary recovery activities. Three major categories of EOR have been found to be commercially successful to varying degrees: • Thermal recovery (e.g., steam injection) introduces heat into the reser- voir to lower the oil's viscosity, thereby improving the oil's ability to flow from the reservoir. Thermal techniques account for over 50 percent of the U.S. EOR production. • Gas injection uses gases such as natural gas, nitrogen, or carbon dioxide to displace additional oil from the reservoir or to dissolve in the oil causing it to expand while simultaneously lowering its viscosity, both of which improve the oil's ability to flow from the reservoir. Gas injection accounts for close to 50 percent of U.S. EOR production. • Chemical injection may be used to enhance the characteristics of the water in a water flood, either to increase the water's viscosity, making it less likely to by-pass reservoir oil and leaving part of the oil behind, or to lower the interfacial tension between the water and the oil, "lubricating" the path for the oil to flow from the reservoir. Chemical techniques account for less than 1 percent of U.S. EOR production. • Other processes, such as microbial EOR, are being researched, but do not currently contribute significantly to oil production. Each of these techniques involves costs that are higher than typical conven- tional secondary recovery methods and involve additional risk because of the sensitivity of the processes to some of the reservoirs' unknown characteristics.

OCR for page 347
 APPENDIx B As shown in Table B-1, U.S. oil resources are very large. The problem is in recovering them. Discovered and documented resources amount to 582 billion bbls, 482 billion of light oil and about 100 billion of heavy oil. Approximately 208 bil- lion bbls have been developed, leaving 374 billion bbls still in place. Of these 374 billion bbls of oil in place, at least 100 billion bbls are estimated to be producible via EOR. These numbers do not include projected reserves growth (RG), undis- covered resources (UR), residual oil zone resources (ROZ), or oil sands. Beyond this point in the analysis, estimates of future oil recovery are based mostly on statistical analysis. While the statistical bases for the projections are sound and there is a statistically high probability that the projections will be borne out, there are no guarantees. That said, there could very well be another 430 billion bbls of oil produced in the future, including 179 billion bbls from undiscovered resources (UR), 111 billion from RG, and 10 billion from oil/tar sands, plus the 30 billion-bbl correction to the EOR potential from the four additional basins that were evaluated after Table B-1 was created—see note in the table. TABLE B-1 U.S. Original, Developed and Undeveloped Domestic Oil Resources (billion barrels)a Future Recoveryb Original Remaining Oil in Developed Oil in Conventional Technology EORc Place to Date Place Total I. Crude Oil 1 Discovered 582 (194) 374 — 100 100 • Light oil 482 (189) 293 — 80 80 • Heavy Oil 100 (19) 81 — 20 20 2. Undiscovered 360 — 360 119 60 179 3. Reserve Growth 210 — 210 71 40 111 100 100 4. Residual Oil — — Unknown Unknown Zone II. Tar Sands 80 — 80 — 10 10 TOTAL 1,332 (194) 1,124 190 210 400 NOTE: Above estimates do not include the additional resource potential outlined in 10 basin-oriented assessments or recoverable resources from residual oil zones, as discussed in related reports issued by DOE in February 2006. Accounting for these, the future recovery potential from domestic undevel- oped oil resources by applying EOR technology is 240 billion barrels, boosting potentially recover- able resources to 430 billion barrels. aDoes not include oil shale. bTechnically recoverable resources rounded to the nearest 10 billion barrels. cBased on six basin-oriented assessments released by DOE in April 2005. SOURCE: Advanced Resources International. 2006. Undeveloped Domestic Oil Resources: The Foundation for Increasing Oil Production and a Viable Domestic Oil Industry. Prepared for the U.S. Department of Energy, Office of Fossil Energy.

OCR for page 347
 APPENDIx B The potential for enhanced oil recovery in the United States is increasing continuously with advances in technology. Reservoir modeling, especially for CO2-EOR, has become extremely sophisticated with the increased capabilities of modern computers and with the development of advanced computer codes that are better capable of mimicking the physics and chemistry of enhanced oil recovery. Improved drilling and completion techniques are also contributing, providing bet- ter drilling efficiency and improved well control. New sensing devices and com- munication systems provide capability for real time analysis of field operations, including underground flow tracking and simulation, thus enhancing the ability to make intelligent decisions in a timely manner. The synergism of the advanced technologies allow a far better understanding and control of oil reservoirs, reser- voir fluids, and the physics and chemistry of enhanced recovery. CO2-EOR is the “universal” enhanced recovery system, applicable to most reservoirs except the very shallow and the reservoirs with heavier oils, for which thermal technologies are more applicable. DOE recently sponsored a study to determine the CO2-EOR potential for the reservoirs in 10 major U.S. basins (and essentially for the United States, since those basins hold the preponderance of U.S. oil resources). The results of the study are impressive, indicating that as much as 89 billion bbls of oil could be produced by applying modern and forthcoming advanced CO2-EOR technologies. These estimates are based on assumptions that require the application of the very best technologies available, something that is not likely to happen in every case. Even so, the remaining resources offer a large target for CO2-EOR, and even if only a portion of the 89 billion bbl estimate can be recovered, it is very much worth pursuing. There are currently limited sources of low cost CO2 and delivery infra- structure (pipelines) to supply CO2 to the many oil fields in the United States with EOR potential. Coal to liquids and other alternative liquid transportation fuels production facilities are believed to be a key to unlocking the huge potential of U.S. EOR resources. These plants will be distributed across the United States, with many sited proximate to EOR-suited oil fields. CO2 will be a residual product of alternative liquid fuel plants, and capturing the gas for sale will not only create economic value but will also demonstrate environmental stewardship. Thus, it is anticipated that these new liquid fuels manufacturing plants will be a source of low cost CO2 for EOR operations. The United States has limited existing CO2 sources and pipelines currently delivering this strategic EOR gas, and even in these regions, low cost CO2 is in short supply. Many of the basins showing large EOR potential have no existing supplies of CO2. With more than three decades of experience with the process, companies are becoming more comfortable with using CO2-EOR. If the price of oil remains high, there should be considerable incentive for companies to initi- ate new EOR projects, even though past experience has made investors leery of commitments to major projects.