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Economies of shale

Economies of shale

Can Colorado afford it?

By Allen Best

The possible production of oil from shale near Rifle raises questions about whether Colorado can afford to sacrifice the water needed to develop it

The Colorado River during spring runoff this year ran full-bodied. It had been a snowy winter at the river’s headwaters in Aspen, Vail and Summit County, among the best in decades. By late May the Colorado was crowding its banks, spilling onto green-grassed low-lying pastures along Interstate 70 as it hurried toward Rifle and then beyond to Grand Junction and into Utah.

The notion of water shortages seems faintly ridiculous in such times of plentitude. It defies the feast of evidence. Yet such water shortages are becoming the major question as Colorado entertains the latest surge in excitement about its vast deposits of oil shale north and west of Rifle. 

That excitement is likely to last as long as oil prices remain above $30 a barrel, a bottom-line benchmark once cited by leaseholder Royal Dutch Shell. With commercial production at least a decade away, the company has since backed away from that number even as a barrel of oil remains near $100.

Much is still unknown. Oil companies remain tentative about extraction methods, electrical demands and even water needs. For that matter, Colorado is unsure how much water remains available for development under interstate compacts governing the Colorado River Basin.

But growing cities fret that even a modest-sized oil shale industry could overstress the demand for water and narrow their options.

“I think there’s going to be a tussle about who gets to develop that last drop of water,” says Dan Birch, deputy general manager of the Colorado River Water Conservation District.

Undisputed is the immensity of hydrocarbons underlying the juniper- and piñon-covered plateaus of northwest Colorado and two adjoining states, Utah and Wyoming. Estimates range up to 2 trillion barrels of oil. Of that, 800 million barrels are recoverable, according to U.S. government estimates. That’s three times more than the proven oil reserves of Saudi Arabia. 

Some 72 percent of oil shale reserves are located below federal land. In 2005, the Bureau of Land Management offered 160-acre tracts in a three-state area for research, development and demonstration purposes. Leases for six of these sites have been awarded, five of them in Colorado. Royal Dutch Shell has three, Chevron and EGL Resources one each. Those companies that demonstrate commercial viability will be authorized to expand operations to 5,100-acre blocks available for 35 years.

At issue is the level of certainty, says Jeremy Boak, from the Colorado School of Mines. “If they expect for the technology to be completely decided upon, they will be waiting for decades,” he says. The technology of oil extraction has evolved now for 140 years. Better, he argues, is to define those areas that need regulation. A top item: water availability.

Congress, in the Energy Policy Act of 2005, ordered a programmatic environmental impact statement for the oil shale lands in the Rocky Mountains — and specified a separate process for commercial leasing of lands to oil companies.

A sticking point is the development of regulations — including the royalty rates — governing commercial production. The disagreement is partisan and local. Last year, U.S. Sen. Ken Salazar (D-Colo.) was able to insert a one-year moratorium on adoption of rules governing commercial leases. U.S. Sen. Wayne Allard (R-Colo.) in May attempted to get the moratorium repealed but lost by one vote. 

“We need the rules and regulations in place first,” Allard told an interviewer. “When the oil companies go to bid on their leases, they need to have some idea what their royalties might be and what their remediation requirements might be.” 

What Democrats really want, he added, is to make gasoline more expensive, to reduce use, and in that way lower emissions of carbon dioxide, a key climate-changing greenhouse gas. Sen. Orrin Hatch (R-Utah) further lashed out at opposition at what he described as Colorado’s ski-resort elites. He singled out Aspen.

Salazar’s position, however, is supported by a very different group: the Front Range Water Users Council. The council includes most major water agencies servicing cities from Fort Collins to Pueblo, plus farm country spreading outward to Kansas and Nebraska. The central worry is that water and oil won’t mix. The organization calls for a go-slower approach until the technology is known. Without that knowledge, informed decisions about commercial leasing, including regulations, cannot be made, said H.J. “Chips” Barry, manager of Denver Water, in a May 14 letter.

In July, Salazar argued that oil shale companies already have potential access to 30,000 acres of public land for research and development, along with 200,000 privately owned oil shale lands in Colorado and Utah. “Let’s put the horse back in front of the cart,” he said.

Royalties cannot be determined until the economics of oil shale are clear, Salazar spokesman Matt Lee-Ashley further explained. Too low, and taxpayers will be shortchanged. Royal Dutch Shell counters that it must know the royalty rates and other factors affecting operation to assess the economic viability of its technology on a commercial scale.

September produced new twists: The Bureau of Land Management issued its final environmental impact statement, potentially opening up 2.4 million acres in Colorado, Wyoming and Utah to commercial leasing. Salazar suggested he was open to a compromise that would allow the leasing to go forward but for any individual state to veto leasing within its borders. But for now, the moratorium remains in place.

A century of failed hopes
From Rifle the landscape to the northwest is dominated by cliffs, chalky and chiseled, rising 3,000 to 4,000 feet above the Colorado River like an overlong tablecloth ruffling onto the floor. The area on top is the Roan Plateau, a flash point in the nation’s spirited discussion about drilling on public lands. By some definitions, the Roan Plateau extends far to the north, to the White River. Within this plateau are found the world’s richest deposits of oil shale.

The shale-type rocks contain a waxy, rubbery substance called kerogen, the residue of organic matter that accumulated within giant intermountain lakes 40 million to 50 million years ago. It’s not petroleum, because of insufficient pressure and heat, but it’s flammable. Utes called these stones “fire rock.” Lightning can set it on fire. Obviously, oil shale is a poor choice for hearths. Local lore has at least one settler discovering that sad truth at a too-literal house-warming party.

Kerogen is not uncommon around the world. Oil has been produced from the oil shale rocks in the Baltic country of Estonia for nearly a century. Brazil and China also extract oil from kerogen-soaked rocks. But of the world’s estimated 1.8 trillion barrels of potential oil from oil shale, nearly two thirds are in Utah, Wyoming and Colorado.

The first serious attempt to develop oil shale began in 1890. Oil shale chronicler Andrew Gulliford, in his book “Boomtown Blues: Colorado Oil Shale, 1885-1985,” explained that Teddy Roosevelt warned of an impending oil shortage in 1908. That fueled interest, and government surveys from 1914 to 1918 confirmed the richness of the deposits. 

“Is the United States facing a gasoline famine?” National Geographic asked in a 1918 article. “Shall we be required to forgo automobiling except to meet the stern necessities of war and of utilitarian traffic?” No, the magazine said. Oil shale would guarantee America world dominance for decades to come.

Similarly enthusiastic prospectors by 1920 had filed 30,000 claims to 4 million acres in areas near Rifle, Parachute and DeBeque. The shales resisted easy surrender. Not so the underground reservoirs of west Texas. With that Texas-sized boom, Colorado’s oil shale industry went bust.

Interest waxed again during World War II. In 1958, graduate planning students at Cornell University issued detailed plans for a city of 350,000 to accommodate the oil shale extraction. Oil shale development was imperative, the students said, given the U.S. dependence on imported oil.

The warning was prescient. The 1973 Arab oil embargo drove up prices, and in 1980 President Jimmy Carter dangled $20 billion in potential subsidies for oil shale startups. Exxon USA said it needed no help but would invest $5 billion anyway. An entirely new town, Battlement Mesa, resulted.

Even then, however, oil prices were dropping, eventually bottoming out at $10 a barrel in the mid-1980s. By then, Exxon was gone. It had suspended oil shale operations on May 2, 1982. Immediately, 2,000 people lost their jobs. Housing prices from Glenwood Springs to Grand Junction tumbled. Slower was the decline of Colorado Ute, an electrical wholesale supplier that had overbuilt in anticipation of oil shale. It eventually went bankrupt. The bust contributed to the economic and social funk of Denver. Oil shale got a real shiner.

A breakthrough
Oil shale work did not die when Exxon fled in 1982. Unocal continued to produce relatively small amounts of oil for another decade. And in a remote location, miles from the closest paved road, Royal Dutch Shell began tinkering with new technology that, after several increments, is now drawing broad attention.

Shell has a reputation for both its science and its long-term thinking. Supervising its research in Colorado was Harold Vinegar. A physicist with a Ph.D. from Harvard, he was thinking inside a box — an underground box.

Oil shale technology has mostly been premised on extracting the kerogen-rich rock, then heating it to high temperatures, drawing off the oil. A later technique involved fracturing the rock underground, then heating it. The mining process has a massive disposal problem, but both techniques yield a range of hydrocarbons that are difficult to refine.

Sworn to secrecy, Vinegar and his Shell team tested a new proposition. They lowered heating elements into a kerogen-bearing formation close to the surface, and then slowly heated the rock. The results were Shell’s eureka moment.

“I think this is about somebody making a useful discovery just in the nick of time,” said Jeremy Boak of the Colorado School of Mines. “Harold got his first clear bottle of oil just as everybody was folding up their tents, and he said, ‘Well, at least leave me my pup tent.’”

Other extraction methods have used higher temperatures, often of about 900 degrees Fahrenheit. That process yields a heavy substance, which must be trucked away. Vinegar’s method is more like a crockpot. The rock is heated to 650 to 700 degrees. This lower, slower heating process yields a lighter crude oil. This lighter oil — at least in theory — can be shipped out by pipeline. That makes the recovery process more efficient, and hence less expensive.

This simple fact has inspired visions of pipelines from Northwest Colorado the size of that used to ship oil from Alaska’s Prudhoe Bay, which has conveyed up to 2.5 million barrels a day. Cooler heads have warned that such production, if it ever occurs, is likely decades away. Still, the discovery was potentially game-changing.

“When they saw that clear liquid, they knew they had something. And it appears the corporate officers realized they had something because they kept funding the research,” said Boak, who in 2006 resurrected an annual conference at the School of Mines that is devoted to oil shale. Of that investment in oil shale research, Shell will only specify “tens of millions of dollars.”

This research was done in a remote area of the central Piceance Creek Basin, about 90 minutes northwest of Rifle. The nearest towns are Rangely and Meeker, both more than an hour away by challenging roads. It’s a place even now of wild horses and the state’s largest deer herd. The central Piceance Basin also has the richest deposits of oil shale in the world, some bands so thickly stained with dark-colored kerogen that the rock is called mahogany. Here it is 1,000 to 2,000 feet below ground, but in variegated strata. 

Shell estimates that if it extracts hydrocarbons from both richer and poorer zones it can get 1 million to 2 million barrels of oil per acre. In comparison, the United States in 2005 consumed an estimated 2.8 million barrels of oil per day.

First, however, Shell believes it must deal with underground water. These aquifers in the Piceance Basin are enormous. Unlike those underlying metropolitan Denver, this water is brackish, rife with impurities, and expensive to treat. Furthermore, if left in place, it will be very expensive to heat. Shell believes it must create walls around the sites from which the oil will be extracted. 

The novel idea now being tested is whether a wall of ice 15 to 25 feet thick, chilled with coolant to 40 below, can be created around the heated area. The purpose is to isolate the area of hydrocarbon extraction. Also extracted, prior to heating, would be the water. The ice wall would prevent water from other areas from seeping in.

“They see groundwater as the major potential showstopper, which is why they went to the refrigerated wall,” Boak said.

Cooling began last year at a 25-acre research site, also in the Piceance Basin. The freeze-wall test is to continue for three more years. Then yet another test will be necessary: a marriage of the cooling and heating technology. Still, Shell is excited enough about its technology to be using some eyebrow-raising numbers. Several years ago Shell said it could profitably extract the shale if oil prices remain above $30 a barrel. It no longer cites any threshold numbers. 

“There are just too many variables, and with commercial production still 10 to 15 years away, we can’t predict what economic factors will look like then,” said Tracy C. Boyd, communications and sustainability manager for Shell Exploration and Production Co., Unconventional Oil. 

Just how much water will be needed for oil shale production is not known. A 2006 study by the Rand Corp. assumed at least three barrels of water will be needed for every barrel of oil produced. However, that estimate is rooted in research done in the 1970s and 1980s and assumes construction of coal-fired power plants, which require large amounts of water.

Boyd won’t divulge Shell’s estimates, suggesting the figure hasn’t been firmly quantified. But it’s clear that Shell will need less than what Rand estimated, he said. One reason is the electrical generation. Natural gas is a component of the oil shale reserves, and can be used to generate electricity, needing less water to do so.

Yes, water will be needed — and there will likely be the need for additional reservoir storage, he said. But oil shale, “will not dry up the Colorado River Basin, as some have implied.”

Colorado as it used to be
At first blush, Meeker is the sort of town that some people like to call “Colorado as it used to be.” It’s a ranching headquarters, with broad meadows studded with baled and bundled hay only two to three minutes from Main Street. The Meeker Hotel’s prime offering is the suite where Theodore Roosevelt stayed a century ago. The biggest event every year is the start of hunting season.

But changes are all around. Upstream along the White River are the ranches of millionaires and perhaps billionaires. Crews laying natural gas pipelines keep motels booked. And driving to Rifle has become treacherous because of impatient drivers commuting from the new natural gas and oil wells.

“I know we need this oil, but it sure makes you wonder whether it’s worth it,” said David Smith, 77, a rancher and native of Meeker. His grandfather, George Smith, arrived at Meeker even before the Utes were forced to leave. He has heard about oil shale his entire life. This time, he worries it might actually happen. Water is at the core of his concerns.

Smith and a son, also named David, farm 5,000 acres along the White River on the outskirts of Meeker. They grow hay, which feeds cattle. Their water rights are secure, but he can’t say the same for ditches serving other ranches near Meeker. Some of that irrigation water is junior to conditional water rights held by oil companies.

A conditional water right in Colorado is like getting a place in line. You don’t have to actually use it, but every six years you must demonstrate intent to do so. Money spent can be evidence of diligence. That isn’t hard to prove when attorneys are involved.

Western Resource Advocates, a Boulder-based environmental law and policy organization, has tallied at least 750 conditional water rights owned by oil companies, many filed in the 1940s and 1950s. Many are in the Rifle-to-Grand Junction area. As such, they could — when perfected — have higher priority than rights of Denver Water and the Northern Colorado Water Conservancy District for transmountain diversions from the Dillon and Granby areas.

Oil shale companies also have conditional water rights around Meeker. Some of those conditional rights are senior to water diversions from the White River begun in the 1940s to ensure irrigation of hay meadows, Smith says. Less water could mean less hay production, and hence fewer cattle. Ranching always is a game of numbers. At some point, the numbers may not make sense for many ranchers. 

“This will be the nail in the coffin that drives them out,” said Smith, the father of former state legislator Matt Smith of Grand Junction and father-in-law of former Congressman Scott McInnis. In this incremental way, he foresees the end of agriculture and the end of the Meeker he has always known.

Smith hopes for additional reservoir storage, something largely absent in the White River drainage, to hold back flows during spring runoff. But whether there will be water for such reservoirs cuts to the heart of why the oil shale/water story is of statewide interest.

“Whoever thinks this is simply a Western Slope issue is missing the point,” said David M. Abelson, a consultant for Western Resource Advocates.

Colorado has long been uncertain about how much water it has left to develop. Already, it is required to deliver water downstream to Nebraska, Kansas and New Mexico. The only surplus that may remain is on the Western Slope. Estimates have ranged from 150,000 acre-feet to 500,000 acre-feet.

But the drought of 2002 and successive years introduced a jarring prospect to water managers for Front Range cities. Instead of Colorado having undeveloped water, the time came when existing uses — including, potentially, transmountain diversions — would have to be curtailed in Colorado in order to deliver water to downstream states as specified by the 1922 Colorado River Compact. Frames of that pact had assumed droughts, but nothing of the sort that occurred in 2002.

The Colorado Legislature last winter allocated $500,000 for a study that is intended to help resolve the question of how much unallocated water, under normal hydrological conditions, remains. The study is to be completed within one year.

But what if the hydrology in the future is not normal? The Southwest 1,000 years ago had several 30-year droughts. Also problematic is the effect of global warming. The balance of evidence points to reduced streamflows of at least 10 percent to 15 percent in the Southwest. In these cases, could the lower-basin states place a “call” on upper basin states, and what would be the repercussions? Will the cities find themselves standing in line behind oil shale operators when the pail runs dry? Some rights used to fill Dillon Reservoir, for example, are junior to some oil shale rights.

Potential problems vary from drainage to drainage, but the broader story is obvious, says Glenn Porzak, a Boulder-based water attorney who represents Exxon but also Vail Resorts, Coors and other Colorado companies. 

“It’s clear that any oil shale development will use up a significant amount of Colorado’s remaining compact allotment,” he said.

Based in Glenwood Springs, the Colorado River Water Conservation District is completing its own study about impacts of energy development to water supplies. The study is speculative, the agency’s Birch says.

“We are going to have to make some assumptions about how much water the energy industries will need,” he said. “The energy interests aren’t telling us — I think because they don’t know. But we are going to have to make some guesses so we can have some dialogue.”

The River District is “neither an advocate nor an opponent of oil shale. But we want to make sure that if it happens, good water planning happens,” Birch said.

For Louis Meyer, an engineer in Glenwood Springs engaged in Colorado’s water basin roundtable process, the future is more menacing. A big push for oil shale water could mean the end of agriculture in Colorado, he said flatly.

Agriculture won’t disappear tomorrow, nor will oil shale make the United States energy independent anytime soon, if ever. Shell, for example, does not expect to make a decision until about 2015 about whether to proceed with commercial production. Whether it will have the technology is, of course, the multibillion-dollar question. It’s been a century in the making, and so skepticism is justified. 

But then, worldwide oil demand has never been so high and sustained. Do oil and water mix in Colorado? We may very well find out.

Oil shale by the numbers

  • 800 million: Number of estimated barrels of recoverable oil from shale deposits in northwest Colorado, Utah and Wyoming —three times more than the proven oil reserves of Saudi Arabia.
  • 72 percent: Amount of oil reserves located below federal land.
  • 1890: Year the first serious attempt was made to develop oil shale in Colorado.
  • 750: Estimated number of conditional water rights in Colorado owned by oil companies, according to Boulder-based Western Resource Advocates.
  • 3: Barrels of water needed to produce one barrel of oil from oil shale, according to a 2006 Rand Corp. study. The estimate is rooted in research done in the 1970s and 1980s, however, and assumes construction of coal-fired power plants, which require large amounts of water.
Oblique arial view of surface site development on oil shale prototype tract in Rio Blanco County. (Courtesy of U.S. Geological Survey)
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