Oil from Stone
The promise and perils of oil shale development


Oil shale is, at the outset, not much to look at. Most of it is dusty gray streaked with sooty black - a rock that is unlikely to find its way into your child's summer rock collection. Much of oil shale country is, to many, equally unappealing: an arid scrubby landscape tens of thousands of adults drive through annually, hoping the car doesn't break down or run out of gas.

However, oil shale holds a lot of promise. There is enough energy contained in these formations to keep our SUVs and energy-intensive lifestyles cruising well into the next century. If this image causes a cacophony of conflicting thoughts, then you can understand the excitement, and the reservations surrounding the oil shale industry today.

"It's a huge, huge resource," exclaims Jeremy Boak, oil shale project manager for the Colorado Energy Research Institute (CERI) housed at Colorado School of Mines.

At current estimates there are roughly three trillion barrels of recoverable oil lying dormant within the world's known oil shale deposits. This equals the total amount of liquid oil known to have existed on our planet, before we even began extracting it. One half of these resources exist within the United States.

The vast majority of the U.S. deposits lie in what is known geologically as the Green River Formation, which sits under 17,000 square miles of Colorado, Utah and Wyoming. Of the one trillion-plus barrels of potential oil streaked throughout these sediments, a moderate estimate promises that at least three quarters, or 800 billion barrels, is recoverable. That's three times the proven oil reserves of Saudi Arabia.

The oil shale is a very dense resource as well. As Dag Nummedal, CERI's director, puts it, "The numbers are just astounding. There is five times the amount of oil per acre in the Piceance Basin [Colorado] as within a rich oil field like Prudhoe Bay." One reason for such potential productivity is the thickness of the oil shale in the Green River Formation. The very best liquid oil reservoirs are 100 to 300 feet thick, whereas much of the oil shale in this area is 1,000 feet thick.

Oil shale has recently become a hot news topic, but Colorado School of Mines has been studying it for years. A longtime senior executive in the industry, Glenn Vawter '60 recalls, "I was on a Mines field trip in the late fifties and Professor Barb [Petroleum Engineering] points across at these cliffs and says, 'Some day this is going to be the salvation of our energy problems in this country.' It caught my attention then, and I've spent the better part of 25 years working on oil shale."

In October of this year Mines hosted its 27th Oil Shale Symposium in partnership with CERI. The event recorded one of its largest turnouts, with more than 330 attendees from 23 states, four Canadian provinces and 20 countries. With such high levels of interest, it doesn't seem to be a question of whether this industry will get off the ground, but when--and most pressing--how.

The first part of the challenge lies here: Oil shale does not actually contain oil. The sooty black streaks that run through these ancient sediments is kerogen, a precursor to liquid oil. To turn it into the real thing, it either needs several million years of geological heat and pressure from nature, or a few years of artificial heat induction arranged by an enterprising corporation.

The second aspect of the challenge is the enormous scale of development required to realize those 800 billion barrels of oil, and many fear that the risks of development at a commercial scale are too high. Impacts on ecosystems, water and, notably, global warming, are primary concerns, and no one feels the heat more than the corporations looking to develop the industry.

Ralph Coates, senior engineer with Combustion Resources, spoke of a news release last June from six environmental groups detailing how one large oil shale plant would produce more carbon emissions than all the coal-generated electricity in Utah, Colorado and Wyoming: "That's obviously a problem for any development of oil shale. The industry has got to satisfy these complaints and concerns with getting the plants permitted," he said.


Adam Brandt, with the Energy and Resources Group at the University of California, Berkeley, states, "By the time an industry gets up and going, there's a fairly good chance that there will be carbon regulation, so any technology that would be developed would need to be amenable to a carbon mitigation effort."

With years of effort, tens of millions of dollars on the line and environmental concerns looming, corporations are moving cautiously--nevertheless, there is excitement in the air from industry representatives. With crude oil prices this high and no relief expected in the foreseeable future, oil shale is economically viable. Additionally, new technologies, and older technologies with new twists, are being applied that could address concerns about carbon emissions and other environmental issues.

Converting kerogen to liquid oil involves a process called retorting--a distillation process in which the oil shale is heated to high temperature (greater than 350° Celsius) to produce hydrocarbons in both gaseous and liquid form. There are two basic strategies for doing this: ex situ and in situ.

In ex situ processing, or above-ground retorting, the shale is mined (either open pit or room-and-pillar), crushed and then heated for an hour or two in an enormous above-ground kiln called a retort. Surface retorts yield a thick tarry product, which is then further refined into transportation grade fuels and other products.

With in situ processing, oil shale deposits are heated where they naturally exist, deep in the ground. The shale is heated for two to four years and the resulting liquid, and gaseous hydrocarbons are pumped up and out. The product is a less viscous, lighter oil that requires far less refining than traditional shale oil to make gasoline, jet fuel and diesel fuel.

As of June 2007, the Department of Energy listed 23 companies developing extraction technologies for oil shale. Here's just a taste of what's being cooked up....

Shell Oil is acknowledged as the leader in the in situ processing field, due to the considerable amount of time and money they have invested, and the creative strategies they have developed. Shell's in situ approach is tackling head on a problem specific to the deepest and richest oil shale resources: free flowing groundwater that, if contaminated, could impact communities far and wide. Shell's answer is to create a "freeze wall" that surrounds the block to be developed, extending hundreds of feet down into the ground. The barrier is created by pumping a refrigerant through plumbing that surrounds the target block. The wall excludes groundwater that would make heating the shale impractical, and protects the surrounding aquifer from contamination. Electric heating elements are inserted into a series of boreholes which cook the kerogen slowly over three to four years, yielding a high quality liquid product condensed from the hydrocarbon vapors created in the formation.

"It's a totally different product than taking fresh rock and running it through an oven for 90 minutes," says Tracy Boyd, Shell's spokesperson. "Short duration retorting yields a very heavy product that has lots of issues to make it usable."

Shell plans to use electricity to heat the shale at a commercial scale, which will likely involve the construction of new power plants, either coal fired or nuclear. "Maybe in the long run we'll have a mix of sources like wind, IGCC (Integrated Gasification Combined Cycle) and who knows what the mix will be. Market factors will likely play a role."

Commercial in situ production is not expected to begin any time soon, with the most ambitious estimates being 2015. Shell is testing its freeze walls: breaching them, measuring effects and developing protocols for possible contingencies. But Boyd is more than optimistic. "Shell has not been researching this since '81 and doing tests in the field since '96 just because we enjoy R&D. We see an opportunity that's too big not to take seriously."

EGL Resources is taking a different tack. "Our in situ approach is different in how the shale is heated," says Glenn Vawter '60, manager of EGL's Oil Shale Division. "We drill down and go horizontally underneath the shale, and use convection (via superheated steam), not just conduction as others are doing. In simplest terms it's like a radiator system you'd have in your house where you are circulating a hot fluid through [pipes]." The heat then radiates upward through the shale. Product is extracted from vertical wells drilled and "spidered" throughout the target deposits above the horizontal heating conduits. The advent of directional drilling, a relatively recent but commonly used technique in conventional oil operations, makes this possible. "You know, 30 years ago when we were trying to do things like this in oil shale, there wasn't nearly the level of technology that there is today," says Vawter.

Energy efficiency is critical. EGL plans to use the natural gas produced in the retorting process (about a third of the product) to heat the shale and then recover the heat from the circulating system in spent blocks for use in the next fresh block of shale. EGL doesn't expect a field test until late in 2009.

Kevin Shurtleff, founder and president of Mountain West Energy, is developing an in situ gas extraction process in which natural gas, heated and pressurized at the surface, is injected into the deposit, heating the shale by convection as the heat rises up through the deposit, "sweeping" hydrocarbon rich vapors to the surface for collection.

"In our process we convert [the hydrocarbons] to a gas, and it stays as a gas, until we bring it back to the surface," says Shurtleff. "If you leave it in the vapor state, you get much better mobility--it flows much more easily out of the reservoir."

For powering the operation, Shurtleff says, "I'm biased against electricity... the problem is you have huge conversion losses so it's always going to cost more energy and produce more pollution than if you use direct heating."

Initially, Mountain West plans to use natural gas (eventually collected on site from the gas fraction of the product) to power their operation. "Ultimately the natural gas we produce we'd prefer to sell, and move to a solar thermal process... that can produce 400° Celsius gas," says Shurtleff, who hopes that eventually such technologies can take him to a zero CO2-emission extraction process.

Surface retorting, the other way to produce shale oil, is already being used commercially for oil shale in Estonia, China and Brazil. At one point a pilot project was launched in Australia before being shut down, in part due to environmental concerns. A similar process is used to extract heavy oil from oil sands in northern Alberta in Canada. Surface retorting is considered the most invasive of extraction methods, due to the mining required, and because existing commercial processes burn the spent shale for fuel, compounding the carbon emissions. For surface retorting to meet anticipated regulatory requirements in the United States, some refinements are being devised.

Combustion Resources is developing a low carbon emission ex situ process. Ralph Coates, senior engineer for the firm, explains, "The main advantage of our [above ground] process, at least theoretically, is we'll heat [the oil shale] with hydrogen as the fuel and avoid putting CO2 as a flue gas. We propose using a similar approach to the FutureGen project: producing the hydrogen by gasifying coal, separating the CO2 that's produced, liquefying it at high pressure and transporting it for either use in secondary oil recovery or underground storage.

FutureGen is the Department of Energy's $1.5 billion initiative to create a coal-based, zero-CO2-emission electricity and hydrogen power plant. "It's a very logical approach for solving the problem of CO2 emissions from coal fired plants," adds Coates.

If oil shale in the Green River Formation ever becomes a meaningful and economically viable source of energy for the nation, it will have to be on a massive scale, which inevitably brings with it substantial regional population growth, necessitating new urban infrastructure. The environmental challenges are also daunting: large quantities of power and water will be required; restoration projects will need to follow in the wake of recovery operations; measures to protect the groundwater may be complex and costly; and extracting the resource without emitting massive quantities of CO2 and other pollutants brings significant challenges and costs. Some argue that such huge capital investments are better spent elsewhere.

"It's not clear to me that it's what we should be doing ahead of increasing efficiency, looking at alternatives and energy conservation, which might limit the need to produce oil shale, at least for the coming decade," says Berkeley's Adam Brandt. "Eventually we might have to use it," he concedes.

Jeremy Boak is pragmatic about environmental concerns and future demand for energy: "Something we are trying to emphasize at CERI is that we've got a huge energy transition going on, and we expect it will take one, two or three generations to complete. In the meantime, any alternatives to fossil fuels will require investment and subsidies which would need to be taken from somewhere. There are plenty of incentives to produce oil and gas, but if you take some of those away, you will lose production. We've got a very careful balancing act ahead of us to make this long-term transition, and we think that making the traditional energy sources more carbon neutral is a really, really important part of that."