The Department of Interior's Prototype Leasing Program: Oil from Shale

Although possible for many years, recovery of oil from shale has only recently become economical. Rising prices of crude oil on the world market and concern over the foreign policy implications of the United States' increased reliance of foreign sources has heightened interest in oil shale.

On November 28, 1973, Secretary of the Interior Rogers Morton announced a prototype program for leasing of federal land for shale oil development. The first lease sale took place only six weeks later, January 8, 1974, and subsequent sales will follow each month until the last of the six proposed tracts is leased. Each tract consists of 5,120 acres located in the sheep and cattle grazing country of the Green River Formation of the Rocky Mountains. Two tracts are located in each of three states — Colorado, Utah and Wyoming. The richest deposits are in Colorado and the poorest in Wyoming. The Green River Formation is estimated to contain 600 billion barrels of oil, an amount which could supply the nation's needs at present consumption rates for almost a century. The federal government owns more than 70 percent of the total lands containing oil shale.

Mining Methods Possible

Oil shale can be obtained through open pit mining, underground mining and in situ extraction. The open pit method requires that the earth above the oil bearing material be removed. With the surface method nearly 100 percent of the shale present can be removed. For underground mining approximately 25 percent of the shale must be left standing to support rooms created when the remaining 75 percent of the shale is removed. The farther down the shale deposits are mined the greater the percentage of material that must be left to support the material above. The in situ process uses explosives to fracture the shale underground, creating a space filled with crushed shale. The Occidental Petroleum Company has proposed to use nuclear devices for fracturing and processing. The crushed shale left after conventional fracturing is processed through an underground retorting method; because the shale is not removed from the earth, no residual shale disposal is necessary.

The six tracts proposed each have differing geological characteristics. The Department of Interior, as its Final Impact Statement reflects, expects that as a result, surface mining will be considered most advantageous for one tract, the in situ process for two others, and underground mining for the remaining three. The lease form does not, however, require any particular methods to be used, so that there is no assurance that the program's purpose of testing the feasibility of the three methods will be fulfilled.

Processing Technology

All presently available technology involves heating crushed shale above 900 degrees Fahrenheit. The heated shale releases most of its organic hydrocarbons in the form of vapor, which is then condensed into a highly viscous crude oil. Heating can be accomplished by above ground retorting or underground by the in situ process. The crushed spent shale after retorting occupies a volume 12 percent greater than the raw material in place, creating a disposal problem that represents one of the greatest environmental objections to shale oil production.

With the deep mining method, only an estimated 60 percent of the residual shale could be returned to the vacant spaces underground, and the equipment used to compress the shale into the available underground space requires space in which to operate. Serious question exists as to whether underground water might flow through the horizontal planes created by the empty spaces, diverting normal water seepage and causing leaching of chemicals into nearby water supplies.

With the surface mining method, even if backfilling were done as soon as possible, much land would be required for storage of the removed overburden and the residual spent shale. If simply piled up upon adjoining surface lands, the residual shale may, due to rain and groundwater seepage, leach out salts into the groundwater system. The compressibility of the residue varies; the more loosely packed the shale, the greater is the danger of leached chemicals and also particulate emissions.

Above Ground Processing

With an older method using vertical retorts, crushed shale fed in at the top falls through the retort and is met by a flow of hot gases from below which distills off the oil. This process produces a waste product of inorganic shale with the consistency of volcanic ash. Drawbacks include high SO₂ emissions from the flue exhaust and the low compactibility of the residual shale.

A new method of above ground processing has been developed by the Oil Shale Corporation (TOSCO). With the TOSCO process a mixture of crushed shale and heated ceramic balls is fed into a horizontal rotating vessel. The heat from the ceramic balls distills off the [4 ELR 10032] petroleum vapors from the shale. After discharge the spent shale and cooled balls are screened apart. Residual shale from the TOSCO process consists of very fine grains which can be compacted into a dense mass. Wetting the shale causes a chemical change which cements the mass, sealing it and preventing leaching.

In Situ Processing

As with the above ground methods, the in situ process requires heating of crushed oil shale. The shale is crushed underground by fracturing and is processed in place. The Occidental Petroleum Company has developed a self-combustion technique for underground retorting by which an initial infusion of natural gas is ignited underground. Air is supplied through inlet wells drilled from the ground level. As the gas combusts, the top layers of oil shale release their organic contents, contributing to the burning process. About 5 percent residual carbon is left in the crushed shale. After several hours of burning downward, the incoming air can no longer reach the unburned shale below. The carbon remaining in the upper layers of burned shale becomes the combustion source, maintaining sufficient heat to distill the petroleum from the shale below.

Fracturing and heating can also be accomplished through detonation of small nuclear devices. In past years when nuclear fracturing was proposed to release underground natural gas pockets, there was widespread opposition to this method. Section 14 of the lease form used by the Department of the Interior requires that lessees must, before nuclear devices may be detonated, obtain the Secretary's written approval, which may be granted only after an environmental impact statement pursuant to § 102 of NEPA has been filed.

Some Potential Environmental Hazards

The problem of disposal of spent shale residuals is central to the concern of most environmentalists. Critics of the prototype program point to the lack of knowledge about the amount of leaching of salts from residual shale piles that can be expected, and fear increases in the salinity of available water resources. The influx of personnel to operate the facilities will necessarily alter the now rural areas, with accompanying demands upon local governments for services. Retorting process emissions and construction work will cause degraduation of ambient air quality. Ironically, since shale oil is considered to be a clean low sulfur fuel, the shale oil development will result in massive SO₂ pollution. The environmental impact statement filed by the Department of Interior admits that ambient air quality standards for SO₂ can not be met in the development areas.

Program Objectives

The Department of the Interior has stated that the prototype program is designed to stimulate commercial production of oil from shale while insuring the integrity of the affected areas, and to foster development of methods and technology for the environmentally sound exploitation of the resource. No additional commercial scale leasing will occur until the environmental effects of the prototype program are evaluated.

Several commentators have suggested that the program may not be a research and development program at all. Estimated capital investment for each installation could be as high as 400 million dollars, with a return on the company's investment expected only after 1980. Research on oil shale technology could have been accomplished on a smaller scale than over the 30,000 acres involved in the leasing program. Additional acreage is expected to be provided through permit issuance for transportation and pipeline corridors. Interior has proposed to withdraw 6,560 more acres of public lands to conduct further studies, focusing particularly on the disposal of spent shale.¹

Several of the witnesses before the House Subcommittee on Mines and Mining Hearings on Oil Shale expressed fears that the program would constitute an irreversible commitment regardless of the environmental impact. They suggested that Interior would never decide that the environmental impacts of the program warranted an end to oil shale development, once the oil companies had made a substantial capital investment.

Because the lease terms allow a choice of mining methods, a possibility exists that attractive new technologies, such as the in situ process, may not be commercially demonstrated. The two Wyoming tracts most likely to be developed by the in situ process are the poorest of the six and least likely to receive any bids fromindustry. As was discussed in the opinion of the D.C. Circuit Court of Appeals in Scientists' Institute for Public Information Inc. v. Atomic Energy Commission,² with reference to the AEC's Liquid Metal Fast Breeder Reactor program, research and development programs may, through the commitment of large capital investments, foreclose research into alternative technologies.

Legal Questions Posed by the Program

Lease Provisions

Section 5 of Interior's lease from³ provides for bonus payments to the lessor. Because the Mineral Leasing Act of 1920⁴ restricts annual lease payments to $ .50 per acre, the bonus payments and royalties represent the significant income from the leases. Section 5 grants credits against bonus payment instalments due on the fourth and fifth anniversaries of the lease. The credits are for expenditures prior to the third and fourth anniversaries for development of the leased deposits. This provision places [4 ELR 10033] a premium upon speedy development rather than upon thorough implementation of environmental safeguards. A similar provision in § 7(e)(2) for royalty payments grants credits for development expenditures prior to the tenth anniversary date.

Section 7(d) gives the Secretary of the Interior authority to grant credits to lessees for any extraordinary costs entailed by compliance with environmental regulations, thus requiring the public to pay for environmental costs rather than internalizing them in production costs. The advantage of internalizing all long-term costs is that industry is given an incentive to find less harmful and more sophisticated technologies. Senators Henry Jackson (D-Wash.) and Warren Magnuson (D-Wash.) recently pointed out, in a letter to Secretary Morton, that the lease clause would discourage the development of innovative techniques, such as the in situ process, which could minimize environmental harm caused by oil shale production.

The lease form includes by reference a list of environmental stipulations. Section 11(c) expressly indicates that any breach of the stipulations will constitute a breach of the lease. Unfortunately, not all of the lease terms are so precise. Section 11(b) requires the lessee to "avoid, or where avoidance is impracticable, minimize and, where practicable, repair damage done to the environment…." Nowhere in the lease is the term "impracticable" defined. The language makes clear only that economic considerations dominate.

Successful bidders for the shale tracts must submit a preliminary development plan within 48 hours of notification by the Interior Department that their bid has been accepted. Prior to the third anniversary date of the lease a detailed development plan, including environmental controls and monitoring systems, must be provided to the Mining Supervisor, who has authority to approve or reject the plan. Failure on the part of the lessee to submit a suitable development plan after two notices (two years) may be treated as grounds for termination of the lease. The development plan approval is probably the most significant control upon the lessee's environmentally harmful activities. The Mining Supervisor, an official of the United States Geological Survey, has discretion to approve destruction of objects of historic and scientific interest, useof pesticides and herbicides, disposal of waste water through reinjection or otherwise, and alternation of existing natural waters. The Mining Supervisor also has authority over plans for protection of wildlife and may require modification of the environmental monitoring. Except for minimum periods expressly required by the lease, the Mining Supervisor may at his discretion terminate the monitoring system. Although public hearings are mandatory prior to approval of the development plan, no criteria are specified in the lease to govern approval. The Mining Supervisor is not required to consult either with officials or private persons with greater environmental expertise. No use has been made of the Environmental Protection Agency, the governmental body with the skills most appropriate for making determinations of environmental import.

One noteworthy point raised by a critic of the program is that approval of the Mining Development Plan would appear to be a "major Federal action significantly affecting the quality of the human environment" requiring preparation of an environmental impact statement under § 102(2)(c) of NEPA. Interior's lease form does not require an EIS and in fact the news release announcing Secretary Morton's approval of the Prototype Program expressly states that Interior plans to issue no further environmental statements on any phase of the prototype program. Such an omission seems to invite litigation on the issue.

Public Information and Participation

Opinion by environmental organizations appears uniform on the lack of public involvement in the decision making processes in the program. All feel that some provision should be made for independent evaluation of the program by a recognized organization. The impact statement indicates that a Technical Advisory Board comprised of government personnel nominated by the State Governors will be established. Members of the public would be limited to observing only.

Section 4 of the environmental stipulations requires the lessee to submit annual reports to the Mining Supervisor containing information on the baseline data collected and on the environmental monitoring programs to be made public. These are to be prepared within a year after the final mining development plan has been approved and annually thereafter. Many other records are required to be kept by the lessee concerning development and environmental monitoring but other than those mentioned above, no provision seems to have made for public review. Information is limited to the reports prepared by the industry with no additional supervision or monitoring done by Interior. It appears that the public will be unable to obtain raw data derived from the environmental monitoring systems and will be restricted to review of industry's reports and summaries.

Compliance with Applicable Federal and State Laws

Section 11(a) of the lease form indicates that the lessee must comply with all applicable federal, state and local statutes, regulations and standards. Serious question exists as to whether this will be possible. As mentioned earlier, Interior admits that ambient air quality standards cannot be met for SO₂ levels. Even if ambient air standards are complied with, the program is still subject to the federal policy, upheld by the Supreme Court in Fri v. Sierra Club,⁵ that the Clean Air Act permits no significant deterioration of existing air quality. Colorado state policy is similar. The Federal Water Pollution Control Act⁶ and [4 ELR 10034] the Colorado Water Quality Control Act⁷ Establish federal and state policies of preventing deterioration of water resources; the prototype program may violate their provisions. Several federal statutes, including the Endangered Species Conservation Act,⁸ the Fish and Wildlife Coordination Act,⁹ the Wild Horses and Burros Act¹⁰ and the Bald Eagle Protection Act,¹¹ establish national policy to protect wildlife and endangered species. Bald eagles, wild horses and several endangered species exist on parts of the proposed oil shale lease tracts.

As was evident from the discussion of residual shale, either temporary or permanent disposal sites will be needed. Problems may exist because of the acreage limitation in the Mineral Leasing Act of 1920¹² which grants authority for the entire oil shale program. Section 241(a) prohibits leases in excess of 5,120 acres. The Department of Interior has submitted a proposed revision of the Mineral Leasing Act to Congress that, inter alia, would permit leases of twice the area presently allowed. It is undertermined by what legal authority the Department of Interior can grant large amounts of federal lands for dump sites. Section 10 of Interior's lease form mentions the Public Land Administration Act¹³ in reference to "studies, investigations, and experiments … in connection with the disposal of spent shale." The language of that act would appear dubious authority for Interior's giving lessees permission to dump the vast quantities of shale residuals involved. Special legislation similar to that enacted to permit construction of the Alaskan Pipeline may well be required.

As has become painfully evident, our natural resources are limited. New and innovative methods must be devised to meet the nation's energy needs. Oil shale may prove to be a valuable source of fuel but at present too little research has been done by organizations independent of the oil companies about the possible irreversible consequences a mature oil shale industry may have upon the environment. An adequate research and development effort should ensure testing of all possible methodologies. Considering the seriousness of the shale disposal problem, far greater emphasis should have been placed upon research into the feasiblity of the in situ process. Unfortunately Interior's prototype leasing program, which allows lessees to choose their methods of development, does not assure that data necessary to make informed decisions about the future of a commercial oil shale industry will be provided.

1. 39 Fed. Reg. 832-833. (Jan. 3, 1974).

2. 3 ELR 20525.

3. 38 Fed. Reg. 33189.

4. 30 U.S.C. § 241.

5. 2 ELR 20657.

6. 33 U.S.C. § 1151.

7. CRS 66028-102.

8. 16 U.S.C. § 668aa-cc.

9. 16 U.S.C. § 661-667.

10. 16 U.S.C. § 1331.

11. 16 U.S.C. § 668a-c.

12. 30 U.S.C. § 241.

13. 43 U.S.C. § 1362.