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Fortune Magazine: Oil shale may finally have its moment

In a dusty corner of northwestern Colorado, an energy of the future is beginning to look like the real thing. Can oil shale work? Fortune’s Jon Birger reports.

By Jon Birger, Fortune senior writer
October 31 2007: 5:43 AM EDT

(Fortune Magazine) — Touring a drilling site on a dusty mountain plateau above Rifle, Colo., Harold Vinegar stops, grins and then announces out of the blue, “I love that smell!”

No, the Royal Dutch Shell chief scientist is not referring to the crisp fragrance of the high desert air or the conifer scent wafting from the nearby stand of evergreens. Rather, it’s the faint, asphalt-like aroma of oil shale – a sedimentary rock rich in kerogen, a fossil fuel that is now the focus of Shell’s single biggest R&D investment.

Vinegar is the energy industry’s leading expert on the complex petroscience of transforming solid oil shale into synthetic crude – a liquid fuel that can be refined into diesel and gasoline. The breakthroughs this 58-year-old physicist has achieved could turn out to be the biggest game changer the American oil industry has seen since crude was discovered near Alaska’s Prudhoe Bay in 1968.

If that sounds like hyperbole, then consider this: Several hundred feet below where Vinegar is strolling lies the Green River Formation, arguably the largest unconventional oil reserve on the planet. (“Unconventional oil” encompasses oil shale, Canadian tar sands, and the extra-heavy oils of Venezuela – essentially, anything that is not just pumped to the surface.)

Spanning some 17,000 square miles across parts of Colorado, Utah and Wyoming, this underground lakebed holds at least 800 billion barrels of recoverable oil. That’s triple the reserves of Saudi Arabia.

The reason you probably haven’t heard about the Green River Formation is that most of the methods tried for turning oil shale into oil have been deeply flawed – economically, environmentally or usually both. Because there have been so many false starts, oil shale tends to get lumped with cold fusion, zero-point energy, and other “miracle” fuels perpetually just over the horizon.

“A lot of other companies have bent their spears trying to do what we’re now doing,” Vinegar says of his 28-year quest to turn oil shale into a commercial energy source. “We’re talking about the Holy Grail.”

Unlike the Grail, though, Shell is convinced that oil shale is no myth and that after years of secret research, it is close to achieving this oil-based alchemy. Shell is not alone in this assessment. “Harold has broken the code,” says oil shale expert Anton Dammer, director of the U.S. Department of Energy’s Office of Naval Petroleum and Oil Shale Reserves.

Vinegar has developed a cutting-edge technology that, according to Shell, will produce large quantities of high-quality oil without ravaging the local environment – and be profitable with prices around $30 a barrel. Now that oil is approaching $90, the odds on Shell’s speculative bet are beginning to look awfully good.

Shell declines to get too specific about how much oil it thinks it can pump at peak production levels, but one DOE study contends that the region can sustain two million barrels a day by 2020 and three million by 2040. Other government estimates have posited an upper range of five million. At that level, Western oil shale would rival the largest oilfields in the world.

Of course, considering the U.S. uses almost 21 million barrels a day and imports about ten million (and rising), even the most optimistic projections do not get the country to the nirvana of “energy independence.” What oil shale could do, though, is reduce the risk premium built into oil prices because energy traders could rest easy knowing that the flow of oil from Colorado or Utah won’t ever be cut off by Venezuelan dictators, Nigerian gunmen or strife in the Middle East. In a broader sense, U.S. energy security lies in diversity of supply, so enhancing domestic sources is appealing.

Oil shale has one other big appeal: It’s not vulnerable to the steep depletion rates that have afflicted other big oilfields. Alaskan oil production is now 775,000 barrels a day, down from its peak of two million in 1988. In contrast, there’s enough oil shale to maintain high production levels for hundreds of years. “Companies just aren’t discovering new Prudhoe Bays anymore,” says Bear Stearns oil analyst Nicole Decker, who thinks Shell has hit on a breakthrough technology. “This could be very significant – certainly bigger, to our knowledge, than any new discoveries that might be available globally.”

Vinegar has been visiting northwest Colorado since 1979. For most of those years, his friends and co-workers back in Houston, and even his children, had no idea what he was doing there. They would have been even more mystified had they known that this Brooklyn-raised, Harvard-educated Ph.D.- a man who looks about as outdoorsy as Alan Greenspan in hiking boots – spent many of the project’s early days camped out in rough terrain miles from the nearest motel.

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But now the veil of secrecy has lifted. With some 200 Shell (Charts) oil shale patents already filed and approvals needed from Colorado and the U.S. Department of the Interior to proceed with commercial production, Shell knows it has to make the public case for developing the country’s oil shale potential.

So after months of negotiations, Shell and Vinegar agreed to give FORTUNE an exclusive look at a new technology – inelegantly dubbed the In Situ Conversion Process, or ICP – that could vindicate Shell’s 28-year, $200 million (at least) bet on oil shale research.

In a nutshell, ICP works like this: Shell drills 1,800-foot wells and into them inserts heating rods that raise the temperature of the oil shale to 650 degrees Fahrenheit. To keep the oil from escaping into the ground water, the heater wells are ringed by freeze walls created by coolant piped deep into the ground; this freezes the rock and water on the perimeter of the drill site. Eventually the heat begins to transform the kerogen (the fossil fuel embedded in the shale) into oil and natural gas. After the natural gas is separated, the oil is piped to a refinery to be converted into gasoline and other products

In essence, ICP simply accelerates Mother Nature’s handiwork. Fifty million years ago, large swaths of what is now northwest Colorado, northeast Utah, and southeast Wyoming were covered by two great lakes. Algae, leaves and other prehistoric life forms sank to the bottom, leaving behind a thick layer of organic muck. Starved of oxygen, these sediments could not decay, and periodically they would be covered and compacted by sand and other rock deposits. Over millions of years, the pressure exerted by the weight of the rock layers transformed the organic layers into kerogen.

In its purest form, kerogen looks like ordinary black rock. In most parts of the Green River Formation, however, it exists as thin black or dark-gray stripes between lighter-colored layers of limestone or sandstone. Kerogen is an oil precursor. So given a few million more years, those layers would morph into an oozing crude. Of course nobody wants to wait that long, which is why there has been no shortage of attempts over the years to make use of Western oil shale. The Ute Indians called it “fire rock” and burned it for heating. Attempts to commercialize oil shale began in the early 20th century and accelerated during the 1970s Middle East oil crisis, when the Carter administration began pouring big money into synthetic fuels.

Oil from a stone
By Jon Birger, Fortune senior writer
October 31 2007: 5:43 AM EDT

Problem was, the prevailing production process – known as surface retorting – was dirty and inefficient. Federal subsidies masked the problems, encouraging companies to build businesses they never would have created on shareholders’ dimes. When oil prices collapsed, so did the economic rationale for shale oil. The day Exxon left town in 1982, turning some communities into ghost towns, is still remembered in northwestern Colorado as “Black Sunday.”

The basic problem with surface retorting was that shale had to be mined, transported, crushed and then cooked at 1,000 degrees Fahrenheit. Not only were there toxic waste byproducts, but the oil thus produced had to be purified and infused with hydrogen before it could be refined into gasoline and other products. Vinegar may be a physicist by training, but he thinks like an MBA, and to him such a labor- and energy-intensive process reeked of bad economics.

Wouldn’t it be better, he thought, if Shell could extract a liquid that could be pumped and pipelined instead of a solid that had to be mined and trucked? Upon visiting a Shell surface-retorting site for the first time in 1979, he came to a quick, life-changing conclusion: “Wow, we’re going to have to do this in situ.”

The term “in situ” is Latin for “in place.” In an engineering context, it means liquefying the oil shale while it is still underground. That is what Vinegar set out to do. The Eureka moment came in 1981. During a field experiment in Colorado, Vinegar and his colleagues set up camp on a patch of Shell-owned land where the oil shale was close to the surface. Then they drilled seven 20-foot wells within a 36-square-foot zone.

They inserted heating rods into six of the holes and positioned the seventh as a production well. “It was a very low-budget operation,” Vinegar chuckles. “The oil would drain into the production well, and every morning we used a fishing pole with a little bailer on the bottom to get it out.”

Most of the oil Vinegar and his colleagues collected was, in his estimation, “gunky.” However, Vinegar noticed that when temperatures in the ground were still comparatively low, the oil recovered was light and pure. “It was almost optically clear, and that fascinated me,” he says. “What was it that allowed us to make this beautiful-quality product early on but not later on?”

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Answering that question took years of lab work, but the company dug in. “Shell continued doing research, even in the 1980s when most everyone else quit,” says Glenn Vawter admiringly. Vawter, a veteran of Exxon’s failed oil shale operation, is now an executive with an oil shale startup, EGL Resources. In 1998 – when the price for West Texas crude crashed to less than $15 a barrel – Shell spent $799 million on R&D; by comparison, the larger Exxon Mobil spent $549 million.

In 2006, Shell spent $855 million on R&D to Exxon (Charts, Fortune 500)’s $733 million. Both Vinegar and Shell Vice President for Unconventional Production John Barry confirm that oil shale is now the biggest piece of the company’s R&D budget, though neither will specify exactly how much has been spent. One source briefed by Shell officials puts the total oil shale R&D investment at north of $200 million.

Shell has long been known for its science. It invented the first semi-submersible offshore drilling rig and pioneered the use of steam flooding to maximize oil well production; it’s also the industry leader in natural-gas-to-liquids (GTL) technology. Much of its research originates at its Bellaire Research Center in Houston, where Vinegar has spent most of his career.

The lab’s most famous alumnus is the late M. King Hubbert, of Hubbert’s Peak fame. Hubbert was the first geologist to understand the mechanics of oilfield depletion and the first to make a reasonably accurate assessment of recoverable oil reserves – initially for the U.S. and later for the world. The founding father of peak-oil theory, Hubbert predicted that U.S. production of conventional oil would peak around 1970 (he was right) and that global oil production would taper off after 2000 (he was wrong, though by how much is the topic of heated debate).

Neither Vinegar nor Barry wants to get drawn into a discussion of peak-oil theory. They simply state that the rapid growth in worldwide oil demand necessitates the development of unconventional oils. (Shell has also invested in biofuels and solar power.)

That said, it’s no coincidence the oil company Hubbert once called home is the one now making the biggest bet on unconventional oil – not only oil shale but GTL and Canadian tar sands too. Jim Spehar, a former Colorado community-relations consultant for Shell, remembers company scientists and executives talking at length about peak oil – and about oil shale as a potential “bridge” between conventional oil and renewable energy – when he worked for Shell in the late 1990s.

“They definitely believed that the conventional stuff being pumped out of the ground was a declining resource,” Spehar says.

Vinegar and the Shell team of chemists, engineers and physicists eventually figured out why the oil they collected early in that 1981 field test was so light and clean and the later samples so dark and dirty. They found that a slower, lower-temperature process – 650 degrees Fahrenheit, versus the 1,000 degrees required in the retorting process – allows more of the hydrogen molecules that are liberated from the kerogen during heating to react with carbon compounds and form a better oil.

This was a crucial discovery, because one of the hallmarks of a light oil – the most valuable kind because it costs less to refine – is its elevated hydrogen content.

Best of all, Shell was able to replicate the lab results in several field tests; the most recent one, in 2005, yielded 1,700 barrels of light oil. In that test, carefully engineered heating rods were inserted several hundred feet into the ground in order to gradually raise the temperature of the oil shale to 650 degrees Fahrenheit. Now Shell had a proven technology that it believed could produce a barrel of oil for $30.

It also knew it could recover a lot more oil than surface retorting did, since the heating rods and wells reach the entire deposit, not just the oil shale close enough to the surface to be mined. There was just one problem: Except for a few small patches of land that it owned, it didn’t have access to the deposits. More than 80 percent of U.S. oil shale is on federal property, including nearly all the most desirable drilling sites. And no mechanism existed for the U.S. Bureau of Land Management to lease this land for oil shale exploration or production.

The Energy Policy Act of 2005 changed that. It required the BLM to set up a process for granting “research development and demonstration leases” to companies seeking to develop oil shale. Under the terms of the RD&D leases, companies whose applications pass muster are given a ten-year lease on 160 acres.

They are then expected to prove the commercial and environmental viability of their process, and if they do, they will be granted a second RD&D lease for an additional 5,100 acres. (Five thousand acres may not sound huge, but Shell believes that the most promising parts of the Green River Formation could yield more than one million barrels per acre using ICP.) Shell applied for and received three RD&D leases; EGL, Chevron (Charts, Fortune 500), and Alabama-based Oil Shale Exploration Co. got one each.

Jeremy Boak, a researcher at the Colorado School of Mines and the organizer of an annual oil shale conference there, believes Shell’s oil shale technology is far ahead of the competition. Indeed, when FORTUNE met last spring with Chevron’s oil shale team and its partners from the Los Alamos National Laboratory, the Chevroners indicated they were still fine-tuning the production process outlined in their lease application.

This involves fracturing the oil shale using explosives or high-pressure carbon dioxide, and then decomposing the kerogen into liquid fuel using supercritical CO2 or other solvents. The idea has not been field-tested yet.

Though there’s no shortage of oil companies now looking to get into oil shale, Vinegar is confident that Shell’s 200 oil shale patents, which cover everything from the composition and spacing of the heating rods to the molecular structure of the light oil ICP creates, will make it difficult for a competitor to come up with a competitive in situ process. (Indeed, there was some griping at the recent School of Mines conference about the breadth of Shell’s patents.) Even so, it will probably be at least 18 months before Shell breaks ground on its first RD&D project and years before the oil hits market. The reason for the delay: another test.

Because there’s no mining and because most of the action occurs underground, ICP is more environmentally benign than surface retorting or even tar sands production in Canada. But one big challenge is preventing the oil from leaching into ground water. Vinegar’s solution was to create an impenetrable “freeze wall” of frozen rock and ice around the perimeter of the heating and production wells.

On a football-field-sized parcel of its own land, Shell is spending an estimated $30 million on a test that involves drilling 150 well bores and filling them with coolant in order to freeze surrounding rock and water to a temperature of minus-60 degrees Fahrenheit. “I do realize,” says Vinegar, “that the whole idea of heating an area [to 650 degrees Fahrenheit] and simultaneously freezing around the circumference to keep the water out sounds almost like science fiction.” Regardless, the freeze wall passed a smaller-scale test in 2004, and Vinegar says everything is proceeding as expected with the latest one.

All this cooling and heating, of course, consumes energy. Can it possibly be worth it? Yes, says Vinegar, who estimates ICP’s ratio of energy produced to energy consumed will range from 3-to-1 to 7-to-1, depending upon the scale of the project. Moreover, the power needed to perform the heating and cooling will be generated entirely from natural gas produced onsite by the ICP process. Shell plans on building its own large power plant and is exploring ways to sequester any CO2 produced.

$90 oil won’t kill the bull
Water is another worry. ICP uses a lot of water, mainly to refine the oil and purify the natural gas. (Shell plans on building a refinery onsite, which is news in itself: It would be the first new refinery built in the U.S. in 30 years.) Shell appears to be on solid legal footing with its water plans, as it owns senior rights for local river water.

And some of the water it intends to utilize will be salinated water pumped from deep aquifers that are not part of the conventional water supply. Nevertheless, the potential for political backlash remains high, given that this is a part of the country where water is scarce and fights over water rights get nasty. “It will certainly be an issue,” says former Rifle mayor David Ling. “There’s an old expression around here: We talk over whiskey and fight over water.”

The last thing Shell wants is a fight with Coloradans. The 2005 energy act set up some guidelines for commercial leasing in addition to the RD&D program. Once Shell completes an environmental-impact report, presumably by 2008 or 2009, the Department of the Interior is expected to consult with the states to gauge whether there’s sufficient support to proceed. Thus far, Colorado Governor Bill Ritter has been cool to the idea without damning it altogether.

In a September letter to a DOE panel exploring ways to expedite oil shale production, Ritter – a Democrat who took office in January – cautioned that “proposed oil shale development overlaps areas with increasing tourism and recreational opportunities. Oil shale leasing on top of this existing network of energy development and changing land uses will put more pressure on an already fragile ecosystem and public temperament.”

Ritter also asserted Colorado’s right to regulate any in-state oil shale projects, though his letter did hint at a possible compromise, one that (surprise, surprise) boils down to money: “Bonus lease payments from federal leases for local government facilities and services [would] help mitigate impacts to local communities and build public acceptance for oil shale developments.”

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At the moment, the greens have been quiet on oil shale, perhaps because ICP is an upgrade over the former method. (Shell says its reclamation methods will restore land to its former appearance.) If you ask environmentalists, they do raise objections. “All the information we have points to industrial oil shale development as an enormous threat to our environment and a huge backward step,” says Amy Mall, a senior policy analyst based in Boulder with the Natural Resources Defense Council.

There is no question that any large-scale oil shale development would dramatically affect the area, and the problem of how to mitigate greenhouse gas emissions has not been solved. That said, opposition to oil shale is nowhere near as loud and organized as the fight to stop drilling in Alaska’s Arctic National Wildlife Refuge. Northwestern Colorado is certainly scenic – high desert plateaus interspersed with lush river valleys – but it’s no ANWR.

Around Rifle (pop. 6,800), people seem at peace with Shell’s oil shale plans, says Ling. There’s already a thriving natural-gas industry in the region, so the idea of digging for oil doesn’t give locals the shivers the way it would in more touristed, populated parts of the state. All that being said, once Shell gets closer to commercial production – Vinegar says it will be no sooner than 2015 – the politics will surely get prickly.

Oil: No longer a heavyweight
Shell insists that it has no beef with Governor Ritter’s desire to proceed slowly. Even so, it’s not leaving anything to chance. Shell has a public relations team devoted to oil shale and, in a shrewd move, the company has hired former U.S. Secretary of the Interior Gale Norton as an in-house lawyer. The stakes are huge. Assuming only $20 in profit for each barrel produced (at today’s inflated oil prices, it would be more like $50), 300,000 barrels per day would add $2.2 billion to Shell’s annual pretax profits. And three million barrels a day would be worth $22 billion.

It could be decades before Shell hits the really big numbers, if it happens at all. The logistics are daunting. It has taken the tar sands industry of Canada almost 30 years to reach its current production of about a million barrels a day (although it could be double that by 2010).

A mature oil shale industry might employ tens of thousands of workers in sparsely populated parts of Colorado, Utah and Wyoming – and that doesn’t include the indirect employment from shop, restaurants and other businesses serving oil companies and their workers. “There’s a real question of how we manage that kind of development,” says Dammer of the DOE.

While it waits for its latest freeze wall to freeze and for the BLM to grind its way toward some sort of commercial leasing program, Shell is exploring other applications for ICP. It is negotiating with Jordan to test it on that country’s oil shale reserves and investigating whether ICP can produce oil from Canadian tar sands – in which Shell also has major investments – more efficiently than current methods.

For his part, Vinegar’s attention is focused squarely on Colorado. “So many Americans have no idea that they’re sitting on a resource several times the size of Saudi Arabia’s,” he says. “The fact is that it’s entirely possible to produce this stuff. Our technology works. There’s no doubt about it.”

– Telis Demos, reporter associate, contributed to this story.

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