Geothermal energy is arguably one of the best, and one of the most challenging, forms of renewable power available today.
First, the bright side. It’s an abundant, underutilized resource. Geothermal power essentially involves tapping subterranean pools of hot water, pumping it up to the surface and using the heat to make steam. The steam turns a turbine. Meanwhile, the water is sent thousands of feet back down into the earth to get reheated by the planet.
Rocks, water and a hole in the ground are the main ingredients. The Flintstones could almost have done it.
The U.S. has 3 gigawatts' worth of geothermal plants, mostly in Nevada and California, but we could add roughly 40 gigawatts more with known technologies. Technologies like enhanced geothermal — which involve injecting water into dry wells — could add another 100 gigawatts in the U.S. Geothermal wells are also — or soon will be — underway in Italy, Kenya, Turkey, Guatemala, Indonesia and Peru.
Geothermal also creates jobs, does little damage to the environment, and takes up relatively little real estate. The Peppermill Hotel and Casino in Reno gets 1 megawatt of heat from a 4,400-foot-deep well in its parking lot. It replaced four gas-burning water heaters and now saves $2.2 million in gas a year. The well head itself only takes up about one parking space.
“The thermal energy that gets removed is microscopic,” says Paul Thomsen, director of policy and business development at Ormat, which has 600 megawatts of capacity under contract with investor-owned utilities in the U.S.
Unfortunately, finding underground water is far more challenging than you might think. Only around one in ten wells hits a commercially viable hot spot. More often than not, drillers hit dry holes, or pools with water that’s only around 100 degrees: to produce electricity, developers need water at 300 degrees or higher. Promising wells can also peter out quickly.
Drilling a single well can cost $5 million to $8 million and developers may have to drill five or six successful wells before outside investors will jump into a project. Millions of dollars get spent before a single kilowatt gets produced. Developers are literally prospecting for heat.
Technology from the oil and gas industry — seismic mapping tools, better drilling components — could help bring the success rate up to 20 percent, or even 50 percent. Thirty years ago, the oil industry only hit only oil ten percent of the time; now one out of two wells succeeds.
Is geothermal a game changer, or a gamble?
What do you think?
Read more on this topic in a joint effort by General Electric Ecomagination and Greentech Media, and join in on the conversation here.
RENO, Nevada — Reno just might be the greenest little city in the world.
Ormat’s Galena Power Plant at the edge of town provides the city with 100 megawatts of carbon-free electricity, or enough for 20 percent of Reno’s daytime electricity and 50 percent of its nighttime power. Put another way, you could power every home in town with the electricity from the plant.
Pumps pull 6,000 gallons of water a minute out of reservoirs 3,000 feet below the surface. The water, naturally heated by geologic forces to approximately 300 degrees Fahrenheit (150 C), boils a chemical refrigerant contained in sealed loops. The refrigerant, now a gas, cranks a turbine.
But just as important is the quality of power. Unlike solar or wind farms, Galena churns predictable, baseload power 24 hours a day that is relatively easy for the grid to accommodate.
It doesn’t even cover much land: it looks like an ordinary substation with most of the works hidden behind low-rolling hills. Many residents don’t even know it exists. (I grew up in Reno and visit the town regularly, yet had never heard of it.)
Only seven to eight people work at Steamboat full time, but geothermal has a 4.25-job multiplier effect on contractors, pipe suppliers and companies that sell anti-scaling compounds.
“With geothermal, you’re replacing fossil fuels with labor,” says Paul Thomsen, director of policy and business development at Ormat, which has 600 megawatts of capacity under contract with investor-owned utilities in the U.S.
The attractiveness of geothermal is tough to deny. The U.S. has 3 gigawatts' worth of geothermal plants, mostly in Nevada and California, but roughly 38 gigawatts to 40 gigawatts of known reserves that can be developed and harvested with known technologies (that is, not counting concepts like enhanced geothermal that are still under development) exist here, according to says Dan Schochet, executive vice president of Ram Power, a geothermal developer and one of the early champions of geothermal in the U.S.
That would be enough power to supply the West with 10 percent of its power, he said. Approximately 25 percent can be brought on-line over the next decade. Projects are underway or being scrutinized in Arizona, New Mexico, Alaska, Hawaii, Colorado and even Gulf states like Texas and Louisiana.
“One hundred megawatts of geothermal is like 300 megawatts of solar,” said Schochet. “On a macro level, everything is going geothermal’s way.”
The capital costs for geothermal can run from $3.5 to $6 a watt before incentives, he said, depending on transmissions, permitting and geology. But, again, that’s for baseload, constant power, not nameplate capacity.
“We want to make Reno to geothermal what Texas is to oil,” said Wendy Calvin, a professor of geophysics at the University of Nevada Reno (UNR) and the director of the Great Basin Center for Geophysical Energy.
So what’s the problem? Geothermal developers are essentially mining heat and, like virtually all other mining endeavors, it’s fraught with risk and uncertainty.
In fact, geothermal arguably carries even more risk and uncertainly than mining or oil drilling. Developers, after all, are looking for hot, briny pools of water buried deep in the earth. Water isn’t as easy to detect as oil and the software tools are far more advanced for oil exploration.
“If you are off by 200 feet, you can miss it. That is the nature of these reservoirs. They are much more capricious,” said John Louie, a professor of geophysics at UNR. “There are still a number of dry holes or colder-than-expected [wells]. Drilling risk is still perceived as the highest risk element.”
Only one in ten wells turns out to hits a pool that can produce power, he added.
Temperature is a big issue, too. In Iceland, geyser water clocks in at a steaming 600 degrees, but in the U.S., many of the resources are in the 300-degrees range. Wells that turn up 120-degree water may have little, if any, practical economic value. Production levels off over time, giving some wells a practical lifetime of 15 years.
Forget scouting for bubbling sulfur springs or geysers. Most potential sites these days do not show “surface expressions” of geothermal potential. The task requires mapping, seismological studies, and complicated fluid flow patterns and the optimal conditions can vary from region to region.
The inability to precisely determine the value of a site leads to the next big problem. Namely, money. A single well can cost $5 million to $8 million to drill and a developer may have to drill five to six wells before it can determine whether a given field can produce megawatt-hours' worth of power. While outside investors might ultimately contribute $500 million to a large project, developers generally have to put up their own seed funds.
“You will spend as much as $20 million to $25 million. Certainly, you won’t spend less than $15 million,” said Schochet. "When you come in, you put these funds at risk.”
As a result, geothermal companies function as vertical silos, making equipment for their own projects and serving as a power provider, too. Ormat obtains 75 percent of its revenue from projects it develops and only 25 percent comes from equipment.
"We’d love to have a shift" toward equipment sales, said Thomsen.
The headaches aren’t over yet. Because geothermal plants provide baseline power, utilities generally pay only 8 cents to 10 cents per kilowatt-hour for geothermal power under power purchase agreements, or around two-thirds of the price that solar power providers get, said Thomsen. Hence, one of the signature features of geothermal power actually depresses prices.
Geothermal also gets more expensive as oil prices increase. Why? Developers have to compete for drilling rigs and equipment with Big Oil.
It’s also not an industry with tremendous clout. Only ten major developers exist in the U.S. Geothermal does not qualify for many of the drilling tax credits, like the dry well credit, showered on oil companies. Solar enjoys better credits under the federal system, too.
Near-term solutions could boost power production and reduce risk, as well. Ormat is considering ideas like filling dry holes with water and capping them, effectively creating a man-made well from a literal financial hole. Adding water to existing wells to boost production has already successfully been accomplished at plants like Geysers in California.
Carbon dioxide could even be injected into wells. The heat-carrying capabilities of CO2 aren’t as good, said Thomsen, but it would have the added benefit of carbon capture. Developing nation — particularly those on the seismically active Ring of Fire in the Pacific — would become some of the leading beneficiaries of cheaper, more reliable geothermal exploration because they wouldn’t have to import or burn as much coal or natural gas.
Mapping and seismology also continue to improve. Thirty years ago, the fossil industry only found oil once every ten times. Thanks to better software and extensive research, it has boosted that success rate to 50 percent, says Louie.
At Faulkner 1, a geothermal project in Blue Mountain, the success rate was an unusually high 50 percent.
“We want to find a seismic signature for hot brine. Even if we got to 20 percent, that would halve the risk,” said Louie.
Others, meanwhile, have coined ways to potentially mine revenue from low-temperature reservoirs. The Peppermill Casino gets all of its hot water — one megawatt worth of thermal energy — from a geothermal well in its parking lot.
John Cushman, another UNR professor, has tapped lower temperature resources to grow algae in racetrack ponds in the desert, where temperatures often plunge below the optimal level of 18 degrees Celsius.
Despite the risks, the industry has a pretty good track record. Virtually every geothermal plant today is based on exploration funded by the federal government in the 1970s, noted Schochet. That money didn’t just go to publishing papers.
“We don’t necessarily need a ‘Man on the Moon’ commitment, but we do need a long-term commitment,” said Schochet.
The opportunity in uranium could still be very big, despite the Fukushima furor. Or it could flow away like water.
“The market that has not changed, post-Fukushima, is the emerging market,” said Amir Adnani, President, CEO and Director of Uranium Energy Corp (UEC). “Sixty-two reactors are under construction. That was the number before Japan, and it’s still the number.”
Growth, Adnani added, is unlikely to be stymied by short-lived controversy. “It is in China, it’s in South Korea, it’s in India, it’s in Russia. In those countries, the nuclear industry is a government-run industry.” Such governments remain enthusiastic about nuclear power’s emissions-free scale.
At present, Adnani said, “demand in the U.S. is 55 million pounds per year; on a worldwide basis, it's 175 million pounds per year.” At the same time, “on a worldwide basis, the industry only mines 120 million pounds.”
The balance has been met by stored supplies and materials recovered under a U.S.-Russia weapons recycling agreement that expires in 2013. “In any commodity business, when you consume more than you produce,” Adnani said, “you’re going to end up seeing higher prices for that commodity” and, ultimately, “an expansion of mine production.”
But it may not, according to Christopher Paine, the Nuclear Program Director of the Natural Resources Defense Council (NRDC), be quite as ripe a market as Adnani described. “His basic premise — that there’s going to be this huge shortage of uranium and the price is going to go sky high and he’s going to cash in — is questionable," Paine said. "There is a lot of capacity that’s being constructed in China, but there’s capacity in Europe that looks like it’s going to be coming off-line. There are even reactors in the U.S. that look like they’re going to be shutting down.”
In addition, Paine added, “The bulk of the market is tied up in long-term contracts.” It is dominated by major players such as Cameco, Mestena and Uranium One. UEC may, Paine said, be able to effectively play the spot market, which is about 15 percent to 20 percent of overall demand, but historically low prices have made him dubious about the potential efficacy of this gambit.
Adnani does not share his skepticism. The spot market price is, he pointed out, $56 per pound, well over his present $18-per-pound cash operating expense. He also contended that a lot of contract potential exists after 2013 and as world demand rises with plants in emerging economies coming on-line.
“I am an entrepreneur with a natural resource background,” Adnani said. Six years ago, there was a dramatic proliferation of U.S. companies, perhaps as many as 500, he explained, that aspired to engage in uranium mining. Today, UEC is one of the few left and the only one in production.
It is, Adnani said, “an incredibly small space. But it’s an incredibly important sector for power generation. To me, that’s a unique opportunity.” Much of UEC’s activity is in South Texas, where it is pursuing ore deposits largely identified during oil and gas exploration during the 1970s and 1980s.
One of the keys to UEC’s success is its people, Adnani said. “We have a team of people who have been there, done that. They built 80 percent of the In-Situ Recovery (ISR) projects ever built in the U.S.,” he explained. Plus, he added, “Texas is an incredibly energy-friendly and business-friendly state to operate in.”
UEC’s Palangana ISR project began producing last November. It came pre-permitted with UEC’s purchase of an adjacent plant where mined uranium is processed into yellowcake. The company has not found Texas to be as friendly at its Goliad project site, where the cutting-edge ISR technology has met hard resistance.
“We’re in our fifth year of fighting this,” said Raulie Irwin, Board Member and Chairman of the Uranium Committee of the Goliad County Groundwater Conservation District. “When they started, they didn’t notify anybody in the county. They got a permit from the Railroad Commission, an exploratory permit, and they went out there and started drilling.”
Adnani explained that county permission wasn’t required because the test wells were drilled on leased private property.
"We did get the Railroad Commission to come out and pull an inspection when they were drilling all their holes out there,” Irwin said. “They cited them with 134 violations.”
Both Goliad County and the Conservation District contend that ISR will be ruinous to drought-plagued Goliad’s Evangeline aquifer, the single water source from which all its wells flow.
Adnani explained that UEC had met all environmental and legal obligations for disclosure and had been authorized to mine by Texas Commission on Environmental Quality (TCEQ) geologists and hydrologists. Goliad County brought a battery of distinguished geologists and hydrologists who concluded that ISR would be a threat to the aquifer.
The only thing now between UEC and uranium mining in Goliad County is the Safe Drinking Water Act. It requires that groundwater at mined sites be restored to its pre-mining quality.
Adnani said water samples taken immediately adjacent to uranium sands will inevitably have uranium and radon in them, releasing UEC from the responsibility to restore the water to drinking quality. Goliad County’s position is that their water, even at the sites UEC wants to mine, was clean and being safely used until UEC started exploration drilling. The granting to UEC by EPA of the final permission to proceed will hinge largely on this question.
Numerous uranium market analysts, little concerned with environmental controversies, rate UEC very highly.
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