The question of “which comes first?” was dominant as oil shale development proponents told a US Senate committee May 15 that regulations need to be developed, and opponents said impacts need to be quantified.
“It seems to me that there should be a way forward that does not involve premature commercial leasing, that protects the interests of the American people and gives them a fair return on their resources, and that addresses concerns of local citizens but still provides industry with the certainty it needs,” Energy and Natural Resources Committee Chairman Jeff Bingaman (D-NM) said.
Pete V. Domenici (R-NM), the committee’s ranking minority member, noted that the 2005 Energy Policy Act (EPACT) contained a provision to facilitate oil shale development. “Unfortunately, last year, without the benefit of full debate and conference as we had in the 2005 energy bill, Congress placed a 1-year moratorium on preparing and publishing the final regulations for a commercial leasing program,” he said.
Committee member Ken Salazar (D-Colo.) said he sought the delay because important provisions dealing with oil shale development, which were part of the 2005 energy bill that the Senate initially approved, were stripped out when the measure went to conference with the House.
Restore orderly process
Salazar said a bill he introduced on May 14 to amend EPACT “would restore an orderly process for the potential development of oil shale and tar sands in Colorado, Utah, and Wyoming and mirror the Senate-passed 2005 energy bill.” It specifically would provide 1 year for federal completion of a programmatic environmental impact statement (P-EIS), an additional 90 days for governors of the affected states to comment, and 1year for a commercial leasing program to be developed once the P-EIS is complete.
S. 3019 also would require the US Bureau of Land Management (BLM) to report to Congress on the research and development program authorized under EPACT to identify available technologies for extracting oil from oil shale, proposed lease terms, and other conditions before any commercial leasing occurs. It also would authorize a National Academy of Science study on oil shale production’s importance to the US, the status of R&D efforts, and probable environmental and socioeconomic impacts. Finally, it would require full compliance with the 1969 National Environmental Policy Act, including a site-specific EIS, before a commercial lease sale and any planned development.
“Colorado already has a huge level of oil and gas development, which is expected to increase twelvefold by 2015. This is why the governor [Bill Ritter Jr., who was a witness] and I want to move forward carefully, particularly in planning something like oil shale development on top of this,” Salazar said during the May 15 hearing.
“I think the disagreement today involves the timing for developing the legal framework for leasing. We believe it should happen only when we know the water needs, the water resource impacts, and the energy needed to produce oil from oil shale,” Ritter told the committee.
Unanswered questions
“I recognize that it could provide significant economic and employment opportunities for Colorado,” Ritter continued, “but we believe we need to answer these unanswered questions. Providing certainty for potential developers is important, but only when we understand the impacts.”
But another witness, C. Stephen Allred, assistant US Interior secretary for lands and minerals management, said EPACT’s existing provision already provides the means for developing an environmentally sound and economically viable oil shale industry to help meet future US energy needs. “Accordingly, I would urge Congress to repeal the current prohibition on finalization of the oil shale regulations,” he said.
He said EPACT Section 369 uses a three-pronged approach. First, it permits oil shale research development and demonstration projects to ensure that technologies can operate in an economically and environmentally acceptable manner before expanding to commercial-size operations. Second, it requires development of the PEIS to identify the most prospective federally-held oil shale areas in Colorado, Utah, and Wyoming. Third, it develops commercial oil shale regulations so companies can make research, development, and demonstration (RD&D) investment decisions now so that optimal processes are developed when the government is ready to move forward on commercial leasing.
“Each of these steps builds upon the other, and each is executed in an open, public process with full consideration and environmental concerns,” Allred said. The moratorium was inserted into the US Department of the Interior’s fiscal 2008 budget as part of the Omnibus Budget Reconciliation Act in December. While it keeps BLM from publishing final regulations, the agency plans this summer to publish proposed regulations, which will lay out a potential framework for possible commercial operations, he continued.
‘May not invest’
“Absent the certainty that final regulations would bring, the commercial oil shale industry may not be willing to invest the necessary dollars for research, and this vast domestic resource will remain untapped at a time when our nation is searching for ways to further its energy security,” Allred warned.
Extending the moratorium “may well have a chilling effect on our efforts to develop this resource in the future,” added Terry O’Connor, vice-president for external and regulatory affairs at Shell Exploration & Production Co.’s unconventional oil division in Denver. The unit in 2006 received three 160-acre federal RD&D leases in Colorado’s Piceance basin, where it plans to perform pilot tests of separate oil shale processes.
Each 160-acre research tract is surrounded by a preference right lease of about 5,000 acres. The lessee will earn the right to expand the surrounding preference right lease if it is able to show it is capable of producing commercial quantities of shale oil from the lease. This would be subject to payment of an undetermined conversion fee, which regulations presumably would establish, O’Connor said.
He acknowledged that Shell also holds three other large oil shale tracts in northeastern Colorado but said the deposits on two of them are better suited to retort technologies, which the company abandoned years ago, while the third, on which it has done small R&D tests, contains easily accessible but noncommercial deposits. Its current research focuses on groundwater protection, and it is conducting tests to determine if freeze wall technology, which the construction industry has used for years, can be used to help extract oil from oil shale using the in situ conversion process (ICP) it has developed.
‘Smartest kind of CCS’
“While we’re aware that this ICP technology has a wide range of environmental benefits, it also requires a lot of energy,” O’Connor said. “We’re looking at a variety of options. Because we’re looking at bringing only the light end out and leaving the heavier portion behind, we expect to practice the smartest kind of carbon capture and sequestration.”
He told the committee that Shell hopes to know by yearend 2009 or early 2010 if its process is effective. “We’re at a point where we need to go into an area where the oil shale is ideally configured to test our ICP technology. We need access to federal land to do that,” he said.
O’Connor conceded that no one fully knows what the impacts of commercial oil shale development would be because it has never occurred. But another witness, Steve Smith, assistant regional director of the Wilderness Society in Denver, said that a 2007 Rand Corp. study for the US Department of Energy found that producing 100,000 b/d from oil shale using the currently most advanced in situ heating retort would require 1.2 Gw of dedicated electricity.
“That equates to construction of a dedicated power plant equal in size to the largest coal-fired power plant now operating in Colorado. Such a plant would cost about $3 billion to build and would consume 5 million tons of coal each year, producing 10 million tons of greenhouse gases. A 500,000 b/d industry, the scale projected by some oil shale enthusiasts, would require five such plants generating 6 Gw of new power, an amount equal to that generated from all of Colorado’s existing coal-fired power plants,” he said in his written testimony.
Smith said that while some of the electricity might be come from gas produced as an in-situ process byproduct, most probably would require using abundant coal supplies in the vicinity. This would prompt additional technological challenges in providing carbon sequestration and controlling particulate air pollution, he indicated.
And then there’s water
Water is an additional problem because the area is arid with relatively low annual rainfall and an existing overcommitment of water supplies and facilities, Smith continued. He said that the Rand report cites an estimate by the Office of Technology Assessment (which went out of business when Republicans took control of Congress in early 1995) that traditional oil shale operations could require 2.1-5.2 bbl of water for each bbl of shale oil product.
“While the new in situ processes may require relatively less water, the Rand report notes that ‘considerable volumes of water may be required for oil and natural gas extraction, postextraction cooling, products upgrading and refining, environmental control systems, and power production,’” he said.
Local water agencies in the area have estimated that a 500,000 b/d oil shale industry would require 25,000 acre ft/year of water, either from new sources or diverted from existing uses, according to Smith. “Such supplies of water adequate for the newer oil shale technologies might not be available and, even if they are, might not remain available in a changing global climate,” he said.
Ritter said Colorado is rapidly approaching its full allocation of Colorado River entitlements and soon will enter a new period of trading and sharing water among different users. “We do not know what the environmental impacts will be on both surface water and groundwater quality due to extraction operations, particularly when considering experimental in situ technologies,” he said.
O’Connor responded that Shell will not proceed unless it can demonstrate that it can produce oil from oil shale without threatening Colorado’s groundwater. “We’ve been able to demonstrate that this process works. The question now is whether it will work in a large commercial project. We need regulations and desperately need them now. It’s not a coincidence that no one has developed oil shale commercially. The regulations have not been there,” he told the committee.
