March 01, 2014

Oil Shale Is Not Shale Oil

Jean Feriancek

In September 2013, oil company Royal Dutch Shell plc announced that it was shutting down its Mahogany oil shale pilot project in western Colorado, after decades of oil shale research. Prior to that, Shell was the biggest player, holding three of the eight federal oil shale Research, Demonstration, and Development (RD&D) leases. Those leases were issued pursuant to Section 369 of the Energy Policy Act of 2005 (EPAct 2005), which sought to encourage research and development of oil shale resources on public lands. Four oil shale RD&D leases remain in effect, held by EGL Resources, Inc.; ExxonMobil Exploration Company; Enefit (which is wholly owned by the government of Estonia, a country that produces most of its electricity from oil shale); and Natural Soda Holdings, Inc. Chevron USA, Inc. relinquished its RD&D lease in 2012.

Implementation of Section 369 of EPAct 2005 represents only the latest of many efforts to develop western oil shale. The first oil shale boom between began almost 100 years ago—between 1915 and 1930—and included everything from mere fraudulent promotions to serious efforts by the U.S. government and energy companies to develop oil shale. Interest in oil shale has waxed and waned in a “boom and bust” cycle ever since then, with renewed interest during times of petroleum shortages and high oil prices. A good project-by-project description of early oil shale development efforts can be found in Paul J. Russell’s 1980 book, History of Western Oil Shale. Portions of the oil shale lands on which early development efforts occurred passed into private ownership through patenting of mining claims that had been located under the mining laws before Congress made oil shale on public lands leasable under the Mineral Leasing Act of 1920, 30 U.S.C. § 241.

It is understandable why developing western oil shale is a tantalizing goal. The Green River Formation in Colorado, Utah, and Wyoming is the largest known concentration of oil shale in the world. More than 70 percent of the formation is on public lands. The U.S. Geological Survey (USGS) estimated a total of 4.285 trillion barrels of oil in-place in the oil shale of the three principal basins of the Green River Formation. The USGS estimated that between 353 billion and 1.146 trillion barrels of the in-place resource have a high potential for development. Birdwell, J. E., Mercier, T. J., Johnson, R. C., and Brownfield, M. E., 2013, In-place Oil Shale Resources Examined by Grade in the Major Basins of the Green River Formation, Colorado, Utah, and Wyoming: U.S. Geological Survey Fact Sheet 2012–3145, 4 p.

The difficulty for energy companies and petroleum researchers historically has been—and still is—to develop a viable, cost-effective technology for recovering shale oil from oil shale and processing it to produce fuels and byproducts. Oil shale is far different from the shales or ‘‘tight’’ formations found in many parts of the United States that contain oil or gas that can be produced by drilling horizontal wells into the shale and hydraulic fracturing. Oil shale is a sedimentary rock such as marlstone containing organic matter called kerogen, rather than oil. Oil shale is a solid rock and must be mined or heated in place to release the kerogen from the rock. For kerogen to be used as an energy source, it needs to be refined and converted to synthetic crude oil. See 73 Fed. Reg. 69,414. Numerous surface processing and in-situ technologies have been tried, some of which have resulted in production of synthetic oil, but at a high cost. It is largely due the technological difficulties associated with development of oil shale that EPAct 2005 provided for the initial issuance of RD&D leases, rather than for leases granting energy companies broader-scale development rights.

Post EPAct 2005 oil shale development efforts have not had smooth sailing. The Bureau of Land Management (BLM) developed regulations for commercial oil shale leasing and regulation oil shale mining operations. The final rule was published in 73 Fed. Reg. 69,414 (Nov. 18, 2008). Shortly thereafter, environmental groups challenged BLM’s regulations in federal district court. Colo. Env’t Coalition v. Salazar, civil action no. 09-00091 (D. Colo.). This suit ultimately was settled, and under the settlement agreement, BLM agreed to propose certain changes to the rules. BLM’s proposed amendments to the oil shale regulations were published in 78 Fed. Reg. 18,547 (Mar. 27, 2013). They toughen the regulations by giving BLM discretion to deny RD&D lessees a right to a commercial lease. They also laid out four royalty options (three of which would leave setting of royalty rate until later stages in the leasing/development process and one that would establish a minimum royalty of 12.5 percent); these would replace a George W. Bush administration royalty plan that began with a 5 percent royalty for the first five lease years, ultimately increasing to 12.5 percent. The revised rules have not been finalized yet. While unlikely to pass in the current regulatory climate, Rep. Doug Lamborn (R-CO) has sponsored legislation (H.R. 1965) that would revoke the Obama administration rule and reinstate Bush administration rules.

Also, pursuant to EPAct 2005, BLM published a Notice of Availability of the Approved Resource Management Plan Amendments/Record of Decision for Oil Shale and Tar Sands Resources to Address Land Use Allocations in Colorado, Utah, and Wyoming and the Final Programmatic Environmental Impact Statement, 73 Fed. Reg. 72,519 (Nov. 28, 2008). The land use allocations made approximately 1.9 million acres of public lands potentially available for commercial oil shale development. In January 2009, a coalition of environmental organizations brought a lawsuit challenging these land use allocations. Colo. Env’t Coalition v. Salazar, civil action no. 09-00085 (D. Colo.). As part of a settlement agreement in the lawsuit and with a change in administration, the Department of the Interior reconsidered whether the acreage opened in 2008 should remain available for potential future development of oil shale. BLM completed work on a Programmatic Environmental Impact Statement in March 2013, amending ten land use plans in Colorado, Utah, and Wyoming under which the land available for potential development of oil shale was reduced to approximately 678,000 acres. 78 Fed. Reg. 18,547 (Mar. 22, 2013). A coalition of environmental groups, which for the most part appear to be opposed to the allocation of any land for oil shale development, have sued BLM over its revised land use allocation for oil shale development.

Finally, as Shell’s termination of the Mahogany project suggests, proving how oil shale can be developed economically and in environmentally sound manner continues to be a challenge. Shell’s in situ test project involved slow underground heating of oil shale after drilling a circle of wells around it and creating an underground freeze wall barrier between the production area and surrounding groundwater. One potential issue is the large amount of water that may be needed for commercial oil shale development. The Government Accountability Office suggested in a 2010 report that from one barrel to twelve barrels of water per barrel of oil produced may be required for in-situ (underground heating) operations and from two to four barrels of water per barrel of oil produced from mining operations with surface heating. Energy-Water Nexus: A Better and Coordinated Understanding of Water Resources Could Help Mitigate the Impacts of Potential Oil Shale Development, GAO-11-35 (Oct. 29, 2010). Of course, without knowing the technology to be used in developing oil shale, any estimate of water needs for that development is only a guess. Nonetheless, the fact that water is a scarce resource in Colorado, Utah, and Wyoming where the oil shale resource is found potentially could prove to be a difficulty not only for commercial oil shale development but also for competing agricultural and urban water uses in those states.

The large amount of electricity that may be needed for commercial oil shale development is another potential obstacle. While the amount of electricity needed to power commercial oil shale development operations is unknown (again, because the development method is not known), such electricity requirements could stretch available electricity supplies and potentially lead to increases in air pollutants associated with generation of additional electric power. See, e.g., Unconventional Oil and Gas Production: Opportunities and Challenges of Oil Shale Development, Statement of Ann K. Mittal, GAO Director of Natural Resources and Environment, Testimony Before the Subcommittee on Energy and Environment, Committee on Science, Space and Technology, House of Representatives (GAO-12-740T, May 10, 2012).

Development during the past few years of the Bakken, Marcellus, and other reservoirs in various parts of the United States by means of hydraulic fracturing, as well as resulting projections about the vast oil resources existing in those reservoirs, no doubt has dampened the appetite of some energy companies to continue to pour millions of dollars into the less certain goal of developing a cost-effective technology for commercial production of synthetic oil from oil shale. Nonetheless, there still may come a time when technology, oil prices, and the need for additional supplies of oil intersect in a way that makes commercial development of western oil shale viable.

Jean Feriancek

Ms. Feriancek is a partner in the Denver office of Holland & Hart LLP and a member of the editorial board of Natural Resources & Environment.