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U.S. oil shale: Real, or just a mirage? New processes might turn the mirage of future oil shale development into a viable source of vast quantities of petroleum products F. Jay Schempf Petroleum News Contributing Writer
The federal government is taking another serious look-see at whether U.S. shale oil reserves can be tapped economically and in an environmentally friendly way.
So what’s new? After all, government and industry have searched over more than a century for a way to coax oil economically from the vast U.S. oil shale deposits — the largest in the world — most of which are lodged in a 16,500-square-mile area encompassing the Green River, Uinta and Piceance basins in southwestern Wyoming, northeastern Utah and northwestern Colorado.
It’s also well known that the hydrocarbons in western oil shale reserves are the equivalent of 1.2 to 1.8 trillion barrels of crude oil. Of that, according to U.S. Department of Energy figures, anywhere from 130 billion to 1 trillion barrels ultimately may be recoverable. A trillion barrels is roughly equivalent to all the combined proven conventional oil reserves in the world today. Rock that burns What is oil shale, anyway, this “rock that burns?”
For one thing, it isn’t shale. For another, it doesn’t contain crude oil. Instead, it’s hard, black or dark brown marl that’s richly infused with bituminous material. It was formed eons ago by the simultaneous deposition of silt and organic debris on the sea bottom that once covered the western U.S. As these deposits piled up, heat and pressure transformed them into a stable mixture of inorganic minerals and solidified organic sludge. However, the heat and pressure did not reach high enough levels to form crude oil.
Although solid at ambient temperatures, super-heated oil shale yields a hydrocarbon vapor called kerogen that, when condensed, can be captured and refined into gasoline, diesel and jet fuel. You can dig it The oil shale recovery and kerogen extraction technology that has been most widely employed combines subsurface mining with surface retorting. Producers extract the shale using explosives or draglines at the surface and by burrowing deeper with mining equipment. The chunks of extracted oil shale are broken up and then introduced into retort ovens where, aided by steam, the entrained kerogen and gases are condensed. The next step, refining, cracks the kerogen molecule and adds hydrogen to yield a high-grade synthetic crude oil known as syncrude.
When heated, the oil shale expands much like popcorn, so that even after product removal, the volume may be as large or larger than it was originally. Producers must move this spent material to a proper disposal site and stabilize it — the remnants hold a variety of undesirable mineral compounds that can leach out with rain. What’s more, shale retorts historically have released vile-smelling vapors, some of which may be harmful.
And, of course, producers still have to seal up the excavated area, filling it with soil, reshaping surface contours and then planting it with trees, native grasses, etc. Not viable Even if the mine/report method were to be environmentally friendly, the method has not proved to be financially viable and several attempts at exploiting oil shales in the United States have failed.
In one notable episode, the Middle East oil embargo and several Middle East wars spurred the federal government to create a new shale oil business in the west in the late 1970s. Several companies — confident that oil prices would remain high — placed orders for large mining/retorting operations in the area around the communities of Rifle and Parachute, Colo.. The resulting economic boom burst on May 2, 1982 – a few months into construction – when the biggest shale operator, Exxon Corp., abruptly shut down its Colony mine/retort project near Parachute. The company cited construction cost overruns, but the truth was, crude oil prices had returned to pre-embargo levels. Unocal and Tosco (The Oil Shale Corp.), among others, kept smaller projects on track for a while longer, but by 1991, all Colorado oil shale development had petered out. Rebirth of the industry Currently, however, in virtually the same geographic area, the hint of a quiet, measured rebirth of oil shale exploitation is again being debated in local government offices, civic clubs, cafes and beauty parlors. The difference now is that one company, Shell Exploration and Production, thinks it has extraction technology to develop shale oil efficiently without surface retorts, crushers or landfills. In fact, Shell’s new process leaves a footprint no larger than that of conventional oil field development.
But mindful of the earlier oil shale bust, Shell has done everything possible to forestall any local — or national — perception that another oil shale ‘boom’ is in the offing.
And Shell isn’t flying solo. Several other companies, including ExxonMobil, Chevron and others, still hold large blocks of acreage in all three oil shale states, and have themselves continued their oil shale research. And while Shell is the only major company talking about shale oil extraction these days, a few smaller — much smaller — companies are either retorting shale already or soon plan to do so. New shale bill ‘Hatched’ Meanwhile, the industry says oil shale development needs federal government interest. Such interest already exists — DOE, for example, has conducted oil shale research for decades. What’s more, the U.S. Department of the Interior Bureau of Land Management, which oversees federal shale properties, is now working on a new leasing policy.
And recently, powerful government lawmakers from the three western states with oil shale deposits have seen U.S. oil shale exploitation as a way to stave off perceived crude and products shortfalls and perhaps lower the unprecedented motor fuel price hikes seen in recent months. They also view shale development as a major boon to their states’ economies.
Concern about domestic supplies of conventional oil and gas is also prompting some action inside the Washington Beltway to look at supplies from oil shale, oil sands and heavy oil deposits.
On May 19, Utah Republican Senator Orrin Hatch introduced the Oil Shale and Tar Sands Development Act. Hatch and fellow western state lawmakers hope to tack the bill — or at least its main points — on as an amendment to the Senate version of the omnibus energy bill, which its Energy & Natural Resources Committee reported out May 26 to be brought soon to the floor for a vote. The House already has passed its version, and President Bush wants a final bill for his signature by Aug. 1.
The Hatch bill would create a Strategic Fuels Task Force to accelerate and integrate a five-year commercial development of fuels from shale and oil sands. The bill also directs DOI to kick off a comprehensive public lands leasing program (the one BLM already is working on), and calls for a DOE cost-sharing program to demonstrate promising extraction technologies.
Finally, the bill would allow producers immediate expensing of new technology outlays for shale and oil sands development. The bill also suggests sliding-scale federal royalty reductions for initial production.
Backing the Hatch bill are fellow Utah Republican Sen. Bob Bennett, as well as Sens. Wayne Allard, R-Colo., and Ken Salazar, D-Colo., among others.
“Who would have guessed that in just Colorado and Utah, there is more recoverable oil than in the Middle East?” Hatch asked recently. “We just don’t count it among our nation’s oil reserves because it’s not yet being developed commercially.” Shell’s downhole heater Though Shell is loath to say that it has a commercial process, the company is blazing a trail to just the kind of oil shale development Hatch envisages. The company has conducted numerous field tests in Colorado during the last five years that indicate its In-situ Conversion Process, known as ICP, actually works.
With the ICP, the company inserts electric resistance heaters into cased holes in the shale, and then heats the subsurface around each bore hole gradually over a three to four-year period until the surrounding zone reaches a temperature of around 650 F, driving vaporized kerogen into offset producers. This leaves the spent shale, or “char” — heavier hydrocarbons and all those nasty mineral compounds — in the formation.
Testifying at an April 12 Energy & Natural Resource Committee hearing on oil shale potential, Steve Mut, chief executive officer of Shell’s Unconventional Resources unit, said the latest ICP test, performed over several months, produced more than 1,200 barrels of light oil and gas liquids. Some 32 downhole heaters have been placed in wells spaced 10 to 20 feet apart over a five-acre parcel at the company’s 20,000-acre Cathedral Bluffs property in Rio Blanco County, near Rifle, about 200 miles west of Denver.
Heating the shale source rock to release kerogen, said Mut, “…accelerates the natural process of oil and gas maturation by literally tens of millions of years.”
The process produces about 65 percent to 70 percent of the original subsurface “carbon” in place, he noted. The remaining carbon products, if brought to the surface, would require broad, energy intensive upgrading and hydrogen saturation. So, he inferred, these products are best left in place.
The method of keeping the heated shale products from escaping into groundwater flows forms a unique feature of Shell’s ICP process. Mut said that engineers can isolate the ICP-affected underground area by adapting 100 year-old mining and construction technology that freezes groundwater to form an ice barrier or to reduce water flow.
According to Mut, Shell use a refrigeration system, based on the same principle as a residential air conditioner. The system circulates cold fluid through a series of wells, so that ice grows around the wells to connect into a solid ice wall.
The new process uses a lot of electrical energy, said Mut. However, each unit of energy used to generate electricity yields about 3.5 units of energy to be treated and sold, he said, adding that the process compares favorably with steam injection in conventional heavy oil reservoirs.
The ICP produces a different hydrocarbon mix than traditional crude oils — it’s much lighter, with almost no heavy ends, Mut said. However, the process can control product quality by using changes in heating time, temperatures and pressures, he said. Much to be done But don’t bet the farm on the ICP just yet. Mut said that while Shell has spent many millions of dollars on the process and has eliminated a great deal of risk and uncertainty, “much work and expenditure still remain before the ICP process can be commercialized.”
Recent reports, however, say Shell plans to expand ICP research during the next two to three years as a next step toward commercialization, drilling more wells, and taking them deeper. But among other technical needs, the company reportedly is still looking for a heater efficient enough to hold a constant downhole temperature of 600 F for months or years.
Shell officials hope the ICP will be commercial by about 2010, although that may not lead to a major ICP-based project, at least in the U.S.
But while industry observers have long maintained that crude oil prices would have to be at least $40 a barrel to make extracting shale oil profitable, Shell officials say the ICP could make kerogen production profitable at world oil prices of $30 per barrel. With today’s price bouncing around $50, the decision to go ahead seems to be a ‘no-brainer.’
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