Fracking boom lifts hopes for geothermal project at Ore. volcano

No matter what it may sound like, Susan Petty insists she's not trying to frack a volcano.

Petty, the founder and president of the Seattle startup AltaRock Energy Inc., says she is just trying to do for geothermal energy what hydraulic fracturing has done for oil and gas.

About two months from now, the company will pump millions of gallons of water into the ground near the base of an Oregon volcano using Petty's version of a technique that Halliburton Co. first used on a geothermal well in the 1970s.

Its given name? Hydraulic fracturing. Fracking being as controversial as it is, Petty prefers to call it "hydro-shearing."

AltaRock says there are major differences between the two techniques, and Petty has convinced three government agencies that there is no real risk of water contamination, earthquakes or volcanic activity from its project. Now the company must prove to the business world that Petty's patented method can deliver cheap energy.

"It's just like shale gas. Everybody used to say, 'We know there's gas in shale, but we can't get it out and there's just no way to use it,'" she said during an interview. "With geothermal, people were saying, 'We know the rock is hot, but there's just no way to get that heat out of there.' In the early days with shale, people really felt frustrated, but a number of projects persisted."

So has AltaRock, which was formed in 2007 at the peak of a clean energy investment boom.

The company's quarry is the hot rock beneath the Earth's surface, which bakes at temperatures hot enough in many places to spin turbines and make electricity.

Geologists have known about these rock formations for a long time, saying that they could meet much of the world's energy needs if only mankind could engineer its own hot springs to bring the heat to the surface. But to date, it has been little more than a pipe dream, much too expensive to justify the cost beyond a few demonstration projects.

Early in her career, Petty tried to blast open hot rock formations with a mix of pressurized water and sand, imitating the drillers who were cracking open shale to access the oil and gas inside. It didn't work.


So she came up with a technique of her own. It was so tantalizing that AltaRock managed to raise millions of dollars from the Internet titan Google Inc., the closely watched venture capital firm Kleiner Perkins Caufield & Byers and the Department of Energy, all around the time that the company celebrated its first birthday in 2008.

Then the economy crashed, driving down energy prices and stunting the demand for cleaner sources of electricity. The hype around AltaRock had mostly faded by the end of 2009, when drilling problems forced it to scrap tests at the Geysers north of San Francisco (Land Letter, Dec. 17, 2009).

Three years later, AltaRock is just about ready to begin the make-or-break test of its own version of fracking, which has since become a household word as it has enabled America's largest oil and gas drilling boom in decades.

The company has finished setting up seismic sensors on U.S. Forest Service land near the base of Newberry Volcano, a national monument site about 20 miles south of Bend, Ore. The volcano hasn't erupted in 1,300 years and shows no signs of activity today, but the Earth's heat finds its way to the surface in other ways.

Part of the area's allure to visitors comes from the hot springs at Paulina Lake and East Lake, where the water is warm but not too warm for bathing. About 2 miles underground, though, the temperatures climb above 600 degrees Fahrenheit -- about as hot as the Geysers, where a set of power plants in Northern California generate 1,300 megawatts of electricity, more than at any other hot spot on Earth.

AltaRock will inject 24 million gallons of water at roughly 46 degrees Fahrenheit into these hot rocks to build a large network of small cracks. If all goes according to plan, the company will be able to circulate water through the rock and suck it out of newly drilled wells, scalding hot and ready for use in an eventual power plant.

The company is not alone in this endeavor. Just as fracking found an early use as a way to squeeze more oil and gas from wells that were starting to run dry, geothermal developers such as Calpine Corp., Ormat Technologies Inc. and U.S. Geothermal Inc. are looking for ways to make their existing wells more productive and to recoup the cost -- usually $3 million to $10 million per well -- of hitting nothing but dry rock.

Calpine, the largest U.S. producer of geothermal energy, recently used similar fracturing techniques to turn a dry well into a working reservoir beneath the natural steam field at the Geysers. It could allow the company to boost the output of its existing power plant, rather than watch its production slowly decline.

Karl Gawell, executive director of the Geothermal Energy Association, said those sort of advances will help to lower the risk across the industry.

Today's geothermal power plants all rely on large natural reservoirs of hot water, the biggest and hottest of which have mostly been tapped. If a developer drills down into a new hot spot and doesn't hit much water, it is as if an oil well came up dry.

"It doesn't take too many $10 million dry holes for a company to get very discouraged about geothermal projects," Gawell said.

New challenge

The Obama administration's Department of Energy has bet big on Petty's vision.

Flush with funding from the stimulus package, DOE gave AltaRock a $21.4 million grant to pay for half of the project in Oregon -- more than the geothermal energy program's entire annual budget at the end of the George W. Bush administration.

Doug Hollett, a former Marathon Oil Corp. executive who took over as manager of DOE's geothermal program last September, said there is still room for conventional geothermal power to grow, but the bigger potential rests in hot, dry rock.

If the Oregon project and five other demonstrations go well, he said, it could clear the way for hot rock formations to someday generate 100 or even 500 gigawatts of electricity, which is equivalent to 10 to 50 percent of the U.S. power fleet today.

"That's the game-changer," Hollett said.

The biggest obstacles will be technological, but the controversy surrounding hydraulic fracturing has created a new challenge for AltaRock, which knows firsthand the risk of a public outcry.

As the company was preparing to test its technique near San Francisco, The New York Times published an article that pointed to the tremors caused by a similar project in Basel, Switzerland, and suggested that fracturing rocks at the Geysers might lead to jarring earthquakes. Some locals started to protest the drilling.

Those concerns weren't what caused AltaRock to cancel the project, but the company has had its argument bolstered recently by a National Research Council report that found a relatively small risk from hydraulic fracturing of geothermal wells (Greenwire, June 15).

The questions in Oregon have mostly focused on water contamination, not earthquakes, Petty said. When pressed on the similarity to fracking, she now says that shearing uses lower pressure than fracking, requires fewer chemicals and takes advantage of existing cracks, all of which lessen the risk of harm from the practice.

Petty said the public concern about fracking is overblown, that the risk of contamination comes when irresponsible drillers do a shoddy job of encasing their wells in cement, not from the cracks in rock formations. She said geothermal wells need to be encased in much more cement, and when it comes to AltaRock's project, there are no fossil fuels to leak into groundwater anyway.

"Nothing can explode," she said as she conjured images from the controversial documentary "Gasland," which some people associate -- wrongly, the industry insists -- with fracking. "There can't be any fiery faucets, none of that stuff, because there's no gas."

So far, federal regulators have been inclined to agree. That has not stopped a handful of Oregonians from complaining to the government about AltaRock's plan to "frack a volcano," as the skeptical commenters on Internet message boards put it.

"It perplexes me," said Linda Christian, manager of the project at the Bureau of Land Management, which conducted an environmental study and concluded in April that AltaRock's work would have no significant impact. "No matter how much information you give people, if their minds are made up, their minds are made up."

Aside from that, most of the concerns have been expressed by ranchers and conservation groups worried about AltaRock's water use and the chemicals it plans to inject underground. The Northwest Environmental Defense Center, a student-staffed clinic at the Lewis and Clark Law School in Portland, Ore., stepped in to challenge the go-ahead from BLM.

Andrew Hawley, a staff attorney at the law clinic, said the study of AltaRock's project seemed to simply go through the motions. That is a problem, he said, when a new technology could cause tremors near a volcano.

"We're not actually getting all the information we need to make an informed decision about how we feel about this project and what the potential consequences are," Hawley said.

As with hydraulic fracturing elsewhere, some locals want AltaRock to disclose the chemical formula of the substances that it plans to use in the shearing process. Government officials have reviewed the company's recipe but withheld it from the public, saying that confidentiality is necessary to protect the company's intellectual property.

'What do we do with it now?'

Geothermal is already a small but proven source of renewable power, providing about 0.2 percent of U.S. energy in 2010.

A few more power plants have gone into development over the past several years, partly because Congress let them qualify for the same tax credits as wind farms and DOE offered them loan guarantees. But the tax credits will expire at the end of next year, the loan guarantees are under intense scrutiny on Capitol Hill and the industry needs a major technological leap to meet more than a small fraction of the United States' energy needs, experts say.

The promise lies in hot rock because it is so plentiful. Just ask oil and gas companies. When they drill below the Barnett Shale, a booming natural-gas-filled formation that lies under Dallas, the rock's temperature can reach a few hundred degrees Fahrenheit, more than hot enough to heat homes and provide electricity.

"We've known for decades that this was a hot area," said Maria Richards, head of a geothermal laboratory at Southern Methodist University in Dallas. "But if you drilled down you would just hit dry rock, and up to this point there was nothing that you could do with it. 'OK, great -- we have heat. But what do we do with it now?' The heat's not going to just travel up the borehole."

The answer is deceptively simple: A geothermal company can pipe down its own water. Some researchers think that carbon dioxide, with its special properties, will work even better in some rock formations, especially if the gas becomes cheaper as industrial plants start capturing it to deal with climate change.

Pumping down water is easy enough, but making room in the rock is more difficult. If someone could figure out a cheap and reliable way to form cracks and circulate water through them, geothermal power could suddenly become attractive in vast expanses of the United States, especially in Western states like Oregon, Nevada and Idaho, experts say.

"If you can get hot water to the surface, there's technology that could be installed in months if not weeks," Richards said.

The heat beneath the surface of the continental United States has the technical potential to produce almost 3 million megawatts of power, triple the capacity of the entire U.S. power fleet today, according to an as-yet unpublished analysis that Richards' research group will present later this year at a meeting of the Geothermal Resources Council.

Some people in the geothermal industry refer to this vision as "enhanced geothermal systems," or EGS. To others, the "E" in that acronym stands for "engineered." The field is still searching for its identity and for successes that will bring it to market.

A few demonstration plants are running in France, Australia and England, but research in the United States from the early 1970s to the mid-1990s did not lead to a working power plant.

"There have been a few experiments over the years trying to stimulate wells, and they haven't been terribly successful," said Joseph Moore, a professor of geophysics and engineering at the University of Utah. "What we do know is: If you put cold water into hot rock you get fractures naturally, and that's pretty much where it's been for 10 or 15 years."

Moore, who is working on another EGS demonstration project in Idaho, said he is optimistic about the technology, but it lacks the same deep-pocketed investors that fracking had. Most of the money for EGS research has come from the government and that funding has come and gone as political circumstances have changed.

Petty tried to break that mold by securing much of her company's funding from venture capitalists, who got excited about the technology after Petty co-authored a report in 2007 with experts from the Massachusetts Institute of Technology.

Just a year earlier, the George W. Bush administration had suggested zeroing out funding for DOE's geothermal research program, saying it was a mature industry that no longer needed government help. And then the report came out, saying that new technology would allow geothermal drillers to use far more of the Earth's heat than the fraction of 1 percent they know how to access today.

It marked a turning point for the industry, the Geothermal Energy Association's Gawell said.

"That had been part of our problem: capturing people's imagination," he said. "You sit outside on a hot, sunny day and you can feel the sun baking you. So you say to yourself, 'Look at all that energy. What if we could just capture that?' But with geothermal, it's harder to imagine the massive heat of the earth that we're sitting on.

"It's not that it's not there. It's there. It's huge. And if we work at it, we can develop the technology to tap it."

When fracking failed

The techniques AltaRock will test this year have their roots in a little-known research project that started four decades ago at Los Alamos National Laboratory in New Mexico.

Los Alamos, the birthplace of the atomic bomb, was starting to branch into other fields besides nuclear weapons when the Middle East oil embargo of the early 1970s sent energy prices soaring. Congress loosened federal purse strings in search of a solution, and researchers at Los Alamos had an idea.

Scientists in the Northeast used their federal dollars to test new ways of tapping the oil and gas in shale formations. The findings from these government-subsidized drilling projects, handed off to the private sector, were turned into a viable business by years of tireless drilling in the Barnett Shale and elsewhere, laying the foundations for today's fracking boom and making some of the drillers into billionaires.

Starting in 1973, the researchers at Los Alamos used their money at Fenton Hill, a parcel of Forest Service land that is now the site of an observatory. When they drilled into the mountain, they hit rock that was more than hot enough for geothermal energy but dry as a bone.

The project was scrapped in 1995, and some of the problems that plagued it have yet to be solved. Hollett, the head of DOE's geothermal program, said the recent boom in unconventional oil and gas is starting to change that.

"The temperatures where we start getting excited are right about the point where traditional oil and gas tools start to fail," he said. The good news for geothermal developers is that "oil and gas increasingly is moving into high-pressure, high-temperature environments, so tools are pushing in that direction."

During the Fenton Hill experiments, Petty was working at the Idaho National Laboratory. Her team was trying to coax more water out of ordinary geothermal reservoirs, just as Calpine, Ormat and U.S. Geothermal are doing today.

Both of the laboratories' projects took the same approach back then: fracking.

"We thought everything would be just like it was in oil and gas," Petty said. "We thought we'd go and use high pressure and break the rock down and use packers the way they do to get multiple fractures."

It turned out that oil and gas techniques did not work. The problem was the very heat that the researchers were trying to exploit.

To unlock the oil and gas in shale formations, drillers often prop open their cracks with sand. In a geothermal well, the sand broke down under high heat, allowing the cracks to close. Petty tried other substances used by oil and gas drillers, such as ceramics and bauxite, but the problem was even worse -- they sometimes dissolved overnight.

It also proved difficult to fracture the rock in more than one place. Oil and gas drillers can fracture a well dozens of times using "packers," which block water from reaching the end of the pipe like a clog in a drain. Petty found out the hard way that the rubber parts in these devices would melt, rendering them useless, or the metal parts would expand and get stuck in the well.

Unable to use packers, the geothermal drillers were only able to fracture a well at one spot. That is the same approach that most still take today, but Petty tried something new.

She decided to use biodegradable plastics called diverters, which can be pumped into a well to clog up the new fractures. Once they're clogged, water can be pumped deeper into a well to fracture it again, as many times as needed, to boost the amount of hot water that an area will produce.

"Wells aren't cheap, and the way to quickly make it cheaper is to stimulate multiple zones," Petty said.

When all the fracturing is done, the cold water slowly heats up and breaks down the diverters, opening the entire network of cracks and allowing the chemicals to be flushed to the surface.

That's the idea, anyway. But over the past few years, Petty learned that her technology wasn't enough.

"With the economy the way it is, renewables aren't in big demand because power's not in big demand and people aren't concerned about global warming and all of that," she said. "It's really a tough time to be trying to do something like this."

So, as AltaRock works on the technology to build new geothermal plants across the country, the company has also shopped its services to the owners of existing plants. It says that the shearing technology could help salvage presently worthless wells or slow the decline of geothermal reservoirs that do not produce as much hot water as they did when they were first drilled.

Working as a geothermal services company may not be as flashy as drilling new wells to draw power from dry rock, but it should pay the bills if big companies see value in Petty's technique. And if the day comes when technology, markets and politics converge to make EGS a cost-effective source of energy, AltaRock would still be around, Petty said.

"People hear that we've had a 50 to 70 percent improvement in the output of wells, and that hits home," she said. "You spend a lot of good money drilling, and if you can find a way to improve it and make it more economic, that's a big boon to an industry."

Click here to read BLM's environmental assessment.

Click here to read BLM's finding of no significant impact.

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