Despite 800 billion barrel potential, oil shale a hard sell

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Despite 800 billion barrel potential, oil shale a hard sell

Can industry overcome hurdles to tap rich fuel veins in West?

By DAVID IVANOVICH

2008 Houston Chronicle

RIFLE, Colo. — Along the western slope of the Rocky Mountains lies a possible path toward energy independence.

The world's largest deposit of oil shale is hidden here, beneath a landscape dotted by pinyon pines and twisted junipers.

If the oil industry can learn how to extract oil and gas from the oil shale in a cost-effective manner, the United States could lay claim to oil reserves totaling, perhaps, 800 billion barrels — three times Saudi Arabia's.

With oil prices riding high and conventional crude reserves ever more difficult to find and produce, companies including Shell Oil Co., Chevron Corp., Exxon Mobil Corp. and Schlumberger are conducting research on a resource that could forever alter the geopolitics of energy.

But the history of oil shale has been a story of grand plans and locked gates.

And its future is anything but certain. At best production is years away, while upredictable oil markets, growing water demand, sizable electricity needs and climate change all pose potentially huge hurdles.

"We're working on the tough stuff," concedes Rick Mykitta, operations manager for Shell Oil Co.'s Mahogany oil shale research project.

President Bush last month linked oil shale with his oft-repeated calls to open Alaska's Arctic National Wildlife Refuge and more areas offshore to oil and gas drilling, hailing the "extraordinary potential of oil shale."

But Democrats have barred the Bureau of Land Management from leasing any federal land forcommercial-scale oil shale projects.

And whether a nation now focused on boosting use of renewables and lowering dependence on fossil fuels will give oil shale another look remains an open question.

The Utes who populated this part of the West long before there were oil companies described oil shale to settlers as "rock that burns."

Oil shale is not a shale at all, geologists say, but a type of rock called marlstone containing kerogen, an organic material left over from ancient lakes. The trick is to convert the kerogen into usable oil and gas.

Skeptic Randy Udall of nearby Carbondale, Colo., argues that oil shale is but a poor cousin to other fossil fuels, with an energy content per ton less than one-third that of cattle manure and only slightly better than the potato.

But oil shale's allure is understandable. The Green River Formation that sprawls across portions of Colorado, Utah and Wyoming is estimated to hold 500 billion to 1.1 trillion barrels of recoverable shale oil resources, a 2005 Rand Corp. study found.

Experiment collapsed

The Piceance Creek Basin alone here in western Colorado could contain as much oil as all the proven reserves in the world, the Rand study said.

The energy crisis of the 1970s, with the twin oil price shocks sparked by the Arab oil embargo and the Iranian Revolution, prompted a great oil shale boom. Encouraged by incentives from a government-funded entity called the U.S. Synthetic Fuels Corp., oil companies rushed in.

Expectations reached the fantastical.

Exxon hoped to produce 8 million barrels of oil a day from the oil shale by 2010, according to Andrew Gulliford, author of Boomtown Blues: Colorado Oil Shale.

The technology of that time called for mining the oil shale, crushing the material and then cooking it in kilns known as "retorts" to convert the kerogen into oil and gas.

Chevron Corp.'s old Red Point Mine north of De Beque, Colo., is a reminder of those heady days when trucks loaded with oil shale snaked down the cliff side. The rock face around the mine entrance is blackened, evidence of lightning strikes on the exposed oil shale.

The great oil shale experiment came to a crashing halt in the early 1980s with a collapse of world oil prices.

Exxon, after spending more than $1 billion according to a Bureau of Land Management report, shut its oil shale operation. And within a few years, the federal synthetic fuels program had been abolished.

Today, natural gas is the game, as producers employ new drilling techniques that enable them to get at gas trapped in tight sand formations.

But policymakers in Washington never fully abandoned hope of developing the oil shale. A 2004 Energy Department report argued that America's oil shale, together with Canada's Alberta oil sands, could serve as "North America's energy bridge to the future."

In 2005, the Bureau of Land Management launched a program to spur interest in the oil shale, handing out six leases for research and development projects on federal lands, where most of the oil shale is located.

Shell, by nearly all accounts the industry leader in oil shale research, landed three of the leases. The subsequent ban on commercial shale leases doesn't prohibit research activities.

Rather than return to the mining techniques, Shell is experimenting with a plan to heat the oil shale in situ, Latin for in place. Shell officials believe that by slowly heating up the oil shale underground, the company can derive high quality oil suitable for products like jet fuel, as well as natural gas, while also being more environmentally friendly.

On lands near where coyotes scamper across the road, a golden eagle roosts on an electric transmission tower and wild horses graze in the distance, Shell has been tinkering with heating elements contained in metal casing that would be inserted around an oil shale formation.

Udall calls it an "underground toaster oven."

Project would need water

Shell also has been experimenting with a process to create a "freeze wall," a technique used in mining and skyscraper construction, to keep groundwater from migrating in and cooling the heating oil shale.

Any oil shale project in this region would mean new water demands on the Colorado River and its tributaries, vital waterways for much of the western U.S. and northern Mexico.

Mining oil shale requires water to control dust and cool retorts, while an in situ process would need water for cooling, power production and refining, the Rand report noted.

Shell officials say the old retort systems used seven to eight barrels of water per barrel of oil produced, while they expect their method would use about half that. The Rand report pointed to assumptions that oil shale would use about three barrels of water per barrel of shale oil produced.

Shell acknowledges it has long been acquiring water rights in the area.

That potential demand for water worries rancher David Smith of nearby Meeker, Colo., who relies on water from the White River that he fears will be diverted to the oil shale operations. The oil companies, Smith said, could help ease concerns by sharing in the cost of a water storage project.

"They have not offered to do that," Smith said.

And it would need power

Besides water, Shell's oil shale project would require far more electricity than the existing power grid could supply. That likely means construction of a new power plant. In this part of the country, the most economical way to fire a power plant would be with coal.

But in the next Congress, lawmakers are likely to pass legislation to limit greenhouse emissions, and coal-fired plants are huge emitters of carbon dioxide. That would add to cost, ever oil shale's nemesis.

Shell, according to the 2005 Rand study, had anticipated its process would be competitive with oil prices in the mid-$20-a-barrel range. Oil has been trading recently at more than five times that level.

Oilfield service costs have risen sharply since 2005. Today, Shell spokesman Tracy Boyd would say only that the project would be economical with oil prices at half the current levels.

Shell won't decide whether to go commercial until the middle of the next decade, with production unlikely before 2020.

Competitors are pursuing different approaches. Chevron, working with experts at the Los Alamos National Laboratory and the University of Utah, hopes to avoid the need for so much power by extracting oil and gas through a chemical process. Exxon Mobil is investigating using an electric current to heat the shale, and Schlumberger — with technology developed by Raytheon Co. — is examining using radio waves to heat the rock.

Oil Shale Exploration Co. could beat all these players to the punch. It's considering returning to the mining and retorting method to develop oil shale. The privately held, Utah-based firm announced last month that Brazil's oil company, Petrobras, and Japan's Mitsui & Co. had purchased minority stakes in the venture.

"Whoever cracks the nut is going to be sitting high," said Carroll Campbell, a retired Shell operations supervisor.

Fight over leases

Whatever its technical prospects, oil shale also is caught in the tug of war that long has characterized the energy policy debate on Capitol Hill.

When Republicans were in control of Congress in late 2005, GOP leaders inserted language into the Energy Policy Act of 2005 laying out a timetable for the Bureau of Land Management to craft regulations and begin large-scale commercial leasing of oil shale property.

Last year, with Democrats commanding Capitol Hill, Sen. Ken Salazar, D-Colo., and Randy Udall's brother, Rep. Mark Udall, D-Colo., inserted language in a large spending bill that barred the Bureau of Land Management from moving beyond the research leases to commercial leasing. That moratorium likely will continue at least into the next Congress.

Salazar, in an interview, said he supports looking at oil shale as a possible energy source for the nation. "I just want to do it in the right way." But he contends issues like water needs and other environmental impacts must be understood before leasing acreage for full-scale commercial operations.

Meanwhile, the U.S. is trying to look beyond oil and gas. "Do we really want to add that much more fossil burning to the planet?" asks Steve Smith of The Wilderness Society.

About 25 years ago, the nation turned away from oil shale. The question is whether America will do so again.

http://www.chron.com/disp/story.mpl/front/5885419.html

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http://www.usatoday.com/money/industries/e...aturalgas_N.htm

"But in the Marcellus Shale, Range and other companies hope a different kind of drilling might yield better results — one in which a well is dug straight down to depths of about 6,000 feet or more, before making a right angle to drill horizontally into the shale. That kind of well could cost a company $3 million to build, not counting the cost of leasing the land, Engelder said.

So the multimillion-dollar question is whether that technology can consistently release the gas from the layer of rock hundreds of millions of years old.

Companies began enjoying success with horizontal drilling technology a decade ago in the Barnett Shale, a 5,000-square-mile field in Texas which has produced about 1.2 billion cubic feet of natural gas a day. Forecasts have called for production there to reach 1.7 billion cubic feet, crucial growth considering the United States produces about 85% of its gas supply.

Success in the Barnett emboldened companies to foray into other parts of the country to uncork potentially new reserves, including the much larger Marcellus Shale."

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http://www.wvsoro.org/resources/coal_bed_methane.html

"Horizontal drilling" for Coal Bed Methane is now being pioneered , and mostly here in West Virginia. There are huge Coal Bed Methane projects in the West, but they are virtually all vertical wells. "Horizontal drilling" is done by drilling down a few hundred feet and then out up to 4000 feet horizontally. This can be done drilling from a single well for some distance to a second well. Increasingly two to five specialized wells are be drilled in a cluster, and horizontal well bores are drilled spread out in one or in all directions from that cluster of wells. And each initial horizontal well bore can branch out in more directions. This looks like the veins of a feather and so is called "pinnate" horizontal well drilling. . Because the size of mineral tracts is often much smaller here in West Virginia, going in all four directions may not be that common.

Using horizontal drilling means using fewer wells to get out the Coal Bed Methane. So if the drilling is going to be done anyway, fewer wells means less risk of environmental damage while the vertical wells are being drilled through the groundwater table etc. Horizontal drilling also means that there will be fewer well sites and access roads, which is good for those surface owners where those extra wells would have gone. However, it is worse for the surface owner where the cluster of wells is drilled. There should be extra compensation, and perhaps even new surface owner consent for this surface owner, since this technology and its huge well site were clearly not in the contemplation of the parties when the minerals were separated from the surface. Another issue with horizontal drilling is that it drains the water out faster (limited, but pretty much only limited by the capacity of the pump), so problems with the produced water mentioned above can be exacerbated.

Edited July 13, 2008 by rebeccajo

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http://www.wvsoro.org/resources/Exhibit2UsgsCbmConcerns.pdf

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Drill now, pay less at the pump.

http://www.wvsoro.org/resources/Exhibit2UsgsCbmConcerns.pdf