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A series of tight deadlines set forth in the nation's new energy bill will force the U.S. Bureau of Land Management to lease lands in Utah, Colorado and Wyoming for oil-shale and tar sands development within 2 1/2 years.

One of the key provisions for Utah is the language backed by the state's senior U.S. senator, Republican Orrin Hatch, aimed at reviving the U.S. oil shale and tar sands development, which went bust in the 1980s.

In the run-up to the bill's Aug. 1 passage, Hatch said that while it would be years before the oil shale resource could be on the market, the bill would send a message "to everyone, including [the Department of the] Interior, that we're tired of messing around."

Hatch's message actually has been circulating since the beginning of the 20th century. Since then, more than a dozen experiments have yielded millions of barrels of oil from Western shale - and hundreds of headlines predicting earthshaking booms just around the corner - yet none of them was a success.

As some cynical energy experts like to say, oil shale is the energy of the future - and always will be.

James Kohler, BLM solid minerals branch chief in Salt Lake City, doesn't count himself as one of the cynics. There's no question, he says, that Utah's oil shale and tar sands are a large resource.

Eastern Utah, western Colorado and southern Wyoming are believed to have 1.5 trillion barrels of oil trapped in shale and sands. Politicians and other boosters like to compare that resource to the amount of oil in the Middle East, sometimes calling the region the next Saudi Arabia.

But there's a difference between a resource and a reserve, Kohler said. Put simply, "resource" is potential. For a resource to become a reserve, "You have to mine it, process it, get it to market" and sell it at a profit while also protecting the environment, he said.

That goal remains elusive.

The energy bill, signed into law Monday, orders the secretary of the Interior by February to begin developing a federal land leasing program for research and development of oil shale and tar sands resources in Utah, Colorado and Wyoming. Leasing is to commence in late 2007.

Technology, however, will probably continue to lag.

The oil of oil shale actually is kerogen, a waxy hydrocarbon that hasn't undergone the geologic heat and pressure necessary to create petroleum, and the shale is a type of hard sandstone called marl. Until the 1980s, the only known way to extract oil was by heating marl to around 1,000 degrees Fahrenheit. The heavier hydrocarbons that are produced are then further processed into "syncrude" used to make diesel or jet fuel. A ton of rock yields about a barrel of oil, or 42 gallons.

No one is certain at what point that process, called retorting, becomes economically viable. In the 1980s, when oil was around $40 a barrel, equivalent to about $80 a barrel today, retort-style shale extraction failed the profitability test. Exxon Corp. closed its $5 billion Colony II project in western Colorado on May 2, 1982, the infamous "Black Sunday" that busted the oil shale boom, eradicated 10,000 jobs and spurred record numbers of property foreclosures and bankruptcies in Grand Junction and Mesa County.

A year later, other oil companies also abandoned shale projects, triggering prolonged economic problems across the West.

The retort process also requires strip mining. Heating the rock releases significant amount of greenhouse gases and arsenic and requires huge amounts of water, which is in short supply in the Rocky Mountain oil shale region. When the shale is processed, it expands like popcorn, leaving huge amounts of waste rock. The waste rock is extremely alkaline, and runoff would contribute to the salinity of the already over-salty Colorado River.

Two Utah companies are developing variations on the retort process. But it is Shell Exploration and Production's Mahogany Project in-situ (in-ground) conversion process experiment that appears to hold the most promise for oil shale.

The project has been under way for 20 years on 20,000 acres of Shell-owned land in Rio Blanco County, Colo. The experiment involves drilling holes similar to conventional oil and gas bores and inserting large heaters into the ground.

The rock formations are heated to about 700 degrees at depths of 1,000 feet for three or four years, which releases oil and gas from the kerogen. Distilled at the surface, the product is one-third natural gas and two-thirds light oil, which requires less refining than kerogen to be converted to diesel, jet fuel and gasoline.

Shell E&P says the in-ground process, which doesn't require strip mining, is more environmentally friendly and is economical at oil prices in the $25 to $30 a barrel range. Yet the company isn't ready to being large-scale production.

"We're probably five years from making a commercial decision," said Terry O'Connor, Shell E&P vice president of external and regulatory affairs. Even if Shell did proceed, he said, it would be another five years before full production.

As for tar sands, the energy bill requires a leasing program specific to that resource - and Utah is the only state that has it - and encourages a partnership with tar-sands developers in Alberta, Canada.

But water, again, is a problem.

"In Alberta, they use tremendous amounts of water," said Jeff Quick of the Utah Geological Survey.

And the Alberta resource is far superior to those of Utah, Kohler said, as the Canadian tar sands feel like a soft asphalt mix, while Utah's are a hard sandstone from which virtually all moisture has been squeezed out. Mining it would cause a "major land disruption," he said.