Significant geothermal energy resources lie a mile or two below our feet
By Steve Blankinship, Associate Editor
The convergence of new technology and changing power industry dynamics often challenge conventional wisdom.
What conventional wisdom sometimes fails to account for is that potential often extends far beyond what the eye can see. Geothermal energy is much more than those brazenly beckoning geysers in Yellowstone National Park. Rather, geysers might be better seen as mere advertisements for the thermal energy that lies a mile or two below our feet; and not just in the Pacific Northwest, but in dozens of states.
The challenge is finding better ways to locate geothermal reservoirs, in much the same way geologists have found better ways to find oil and natural gas. And thanks to new technology that can now use significantly cooler geothermal temperatures than was possible a few decades ago, there may be many more economically viable geothermal sites than once were thought possible.
The 35 MW Sonoma plant is one of 19 facilities owned by Calpine in The Geysers in northern California. Photo courtesy of Calpine
Even without such predictive geology, a new generation of geothermal plants is being built. Trends point to a substantial expansion of geothermal power production. Currently more than 2,800 MW of geothermal baseload power production operates in California, Nevada, Utah and Hawaii. The Geothermal Energy Association (GEA) projects utility-scale power production will soon expand in Alaska, Arizona, Colorado, Idaho, Louisiana, New Mexico, Oregon, Texas, Washington and Wyoming.
Karl Gawell, GEA’s executive director, recently told the Senate Energy and Water Appropriations Subcommittee that geothermal resources could supply more than 30,000 MW of power by 2025, enough to meet 6 percent of today’s total U.S. electricity needs and equal to all of the electricity generated in California, Nevada and Idaho. The U.S. Department of Energy’s Energy Information Agency projects geothermal generation will increase from 13 billion kWh in 2003 to 33 billion kWh in 2025.
A Steamy History
The first geothermal plants in the United States date to the 1920s when they consisted of little more than turbine/generators placed atop geysers in northern California. Known as “flash” geothermal units, these plants captured geothermal fluid in a vessel where it flashed to steam to drive a turbine. Those early plants were small – about 20 kW. And because geothermal fluid is heavily laden with brine and other highly corrosive minerals that quickly take their toll on turbines, flash plants can have high maintenance costs relative to the amount of power they generate.
By 1960, Pacific Gas & Electric had developed about 20 geothermal plants on The Geysers in northern California. At their peak, The Geysers produced about 2,000 MW, which for a time, was enough to supply most of San Francisco’s power needs. But such extensive use drew down the resource. Output diminished as condensation depleted the geothermal wells. Eventually, The Geysers produced around 1,000 MW.
Today The Geysers are owned and operated by independent power producer Calpine Corp. Calpine bought a 5 percent interest in a 20 MW plant at The Geysers in 1989 and has since consolidated ownership of 19 of the 21 facilities representing about 750 MW drawn from 350 active wells. That makes Calpine the world’s largest private producer of geothermal electricity. Calpine continues restoring The Geysers to higher capacity by injecting clean wastewater from local municipalities. A 29-mile-long underground pipeline delivers 8 million gallons of reclaimed water each day. A 41-mile-long underground line being built will deliver another 11 million gallons of reclaimed water a day.
The single most significant improvement since the early days of flash geothermal plants has been the use of binary technology that keeps the geothermal fluid separated from the power block. Fluid from the geothermal reservoir is kept in a separate closed loop to heat a “working” fluid contained in a second closed loop, which is vaporized to turn turbine/generators. Because geothermal water and working fluid are in separate loops, water and steam from the geothermal reservoir never come into contact with the turbine/generator units.
Binary technology resolves several problems associated with flash systems. For one thing, it can operate with cooler water – typically in the range of 225 F to 360 F compared to the 500 F to 600 F range needed for flash plants. Fluid in the geothermal loop heats a “working” fluid in the secondary loop that has a lower boiling point than water. Furthermore, a binary plant design exposes none of the geothermal fluid to the atmosphere, meaning what little pollution is generated by a pure geyser-primarily hydrogen sulfide-is also eliminated. After all, even geothermal plants must meet Clean Air Act emission regulations.
Geothermal power’s last heyday spanned the late 1970s to the early 1980s when the Public Utility Regulatory Policy Act (PURPA) gave non-utility power producers some incentives to develop unconventional power resources. Energy policies spurred several major oil and gas companies to enter the geothermal power business. In hindsight, they were hindered by the idea that size matters most.
“When major players like UniCal were in the business, they were looking for 200 MW flash sites,” says Gawell. “That was part of the mindset in the oil and gas business. They were looking for geysers – big sites with lots of high temperature resources. Those don’t exist any more. But in searching for them, they discovered hundreds of 25 MW sites that today’s binary technology can utilize.”
Sites where extensive groundwork has already confirmed commercial viability are clustered in the western United States. In order of magnitude (from largest to smallest) the states with the most confirmed geothermal potential are California, Nevada, Idaho, Arizona, New Mexico and Utah. Sites now on developers’ radar screens for the nearest-term potential lie one to two miles below the surface. “If you go about three miles down, the entire continental U.S. has a remarkably robust geothermal resource,” says Bruce Green, who is responsible for geothermal-related communications for the U.S. Department of Energy’s National Renewable Energy Laboratory (NREL). “What it lacks in some places is a fluid to move the heat around.”
Gawell points to a new generation of geothermal entrepreneurs enabled by state renewable portfolio standards and the federal production tax credit. “We are seeing people who believe they can make money in this business,” he says. “They’re looking at 25 MW projects and building them.”
New Geothermal Projects
According to GEA, 157 MW of geothermal capacity is currently under construction in the United States. That includes three plants in Nevada and one each in California, Idaho and Utah. In addition, GEA counts up to 935 MW at 18 sites across eight states that is currently under development.
Among the most visible developers are Reno, Nev.-based Ormat Technologies and Boise, Ida.-based U.S. Geothermal. Ormat is both a geothermal technology developer and manufacturer. The company is building and supplying equipment for the 10 MW Unit 1 at U.S. Geothermal’s plant near Idaho’s Raft River, which broke ground in July. Unit 1 will draw its heat and water from a 4,500-foot well. Based on the potential at the Raft River site, and verified by DOE testing in the 1970s and ‘80s, the project eventually could produce up to 90 MW from wells as deep as 6,500 feet. Each will costs about $2.5 million to drill. Goldman Sachs provided $34 million in financing for Unit 1. Raft River Unit 1 is expected to go into service in late 2008 or early 2009.
The Richard Burdette plant developed by Ormat near Reno recently went into operation. And U.S. Geothermal has acquired property for a second geothermal project at Neal Hot Springs in eastern Oregon, near the Idaho border.
According to NREL’s Bruce Green, the total development cost of a 25 MW geothermal plant ranges between $60 million to $75 million.
Ormat Vice-President Dan Schochet said his company entered the geothermal business in the early 1980s as an extension of its activities in the heat recovery sector. About 10 years ago, it became a geothermal plant owner and operator. Presently, about 75 percent of its revenue is from power sales. The remainder comes from selling geothermal equipment to third parties developing geothermal and waste recovery plants based on Ormat’s geothermal technology.
“Utilities in the western U.S. want to buy as much geothermal power as they can, says Schochet. “It’s cost effective compared to natural gas combined cycle and it’s clean. Geothermal is baseload.”
Mitsubishi and Balcke-Duerr GmbH are adding two 40 MW flash geothermal units to a plant in Iceland. Photo courtesy of Mitsubishi Heavy Industries
Ormat’s technology is based on the organic Rankine cycle The idea is to offer essentially standardized modules from 200 kW to 20 MW turbine/generators to produce power. There would be about 20 variations of site-specific modifications based upon geothermal fluid conditions to optimize the resource – from temperatures between 200 F to 600 F.
The technology takes the hot water and flashes it off into steam through a simple back pressure turbine. The brine then is put through a binary system which uses excess heat for preheating. All that is achieved with air-cooled condensation. “If you have a water-cooled system and try to use water from the geothermal system for condensate you’ll deplete the resource,” Schochet said. That’s what happened to resource levels at The Geysers in California.
The 30 MW Puna geothermal plant on Hawaii’s big island has operated with Ormat technology since 1993. The plant provides 15 percent of the island’s baseload power using steam on one turbine and binary side heat on the other. Ormat believes the site will support an additional 20 MW. The company operates six other geothermal plants in the U.S. as well as plants in the Philippines, Guatemala, Kenya and Nicaragua. It has sold equipment to plants in New Zealand, Iceland, Germany, Canada, Italy, the Philippines, Japan, China and Portugal.
Fire and Ice
A different kind of geothermal plant went online last July in Chena, Alaska. Producing 200 kW of electricity from 165 F water, the significance of the Chena Hot Springs Geothermal Plant exceeds its modest output. Chena is the lowest temperature geothermal plant to date and represents a leap forward for moderate-temperature geothermal development. Before Chena, the lowest temperature geothermal resource ever developed for commercial power generation was 208 F.
Chena’s power modules were created by United Technologies Corporation (UTC) using components from Carrier’s mass-production waste heat recovery plants. Units are designed to resemble a chiller for quick installation and easy operation, resulting in reductions to upfront installation and long-term maintenance costs. Technology can also be used to generate power from any low temperature waste heat source.
The challenge for moderate temperature small scale geothermal development has been to maintain high turbine efficiency at a cost the allows development of small geothermal fields. UTC, in partnership with DOE’s Geothermal Technologies Program, has been working toward that goal. By applying reverse engineering to mass-produced Carrier chiller components, geothermal plant construction costs can be reduced by taking advantage of the refrigeration industry’s already existing large scale mass production and also allowing modular construction. The first power module arrived at Chena on July 8th and produced power less than a month later.
With abundant geothermal heat lying beneath its frozen surface, Iceland produces 72 percent of its electricity from hydro and geothermal sources. Iceland’s abundant volcanic activity makes it a prime location for flash geothermal plants. Mitsubishi Heavy Industries (MHI), in a consortium with Balcke-Duerr GmbH, is building two 40 MW flash power plants at Reykjavik Energy’s geothermal facility in Hellisheidi. They are the ninth and tenth geothermal plants MHI has provided to the city-owned power provider. Upon completion, Reykjavik Energy’s cumulative geothermal capacity will be 340 MW.
In general, if geothermal water temperatures are high enough to generate medium to large capacity plants (20 MW or more), flash cycle is economic and efficient. Although MHI can build both binary and flash cycle units, it generally concentrates on medium and large capacity geothermal projects with flash cycle because they are less expensive to design and build. MHI has resolved corrosion issues in its flash and binary designs by using anti-corrosive material such as stainless steel or titanium. MHI has 2,500 MW of flash cycle plant capacity in Japan, Iceland, the U.S., Mexico, the Philippines, Indonesia, New Zealand, Costa Rica, El Salvador and Kenya.
Geothermal in the Oil Patch
New technology might also enable another form of geothermal energy, taken straight from oil wells. In the 1930s, oil producers routinely flared natural gas, not realizing they had tapped a valuable commodity. Today, oil and gas producers pump billions of barrels of heated water out of production wells and truck it to distant sites for disposal. That currently is potentially wasted energy.
So-called “produced water” or “produced water cut” exists in many U.S oil and gas producing regions. Produced water can range from 200 F to more than 400 F, meaning it could produce geothermal electricity with either binary or flash technology. Electricity could be used on-site to reduce grid power costs and might even generate enough electricity to sell to the grid.
Dr. David Blackwell, professor of geological sciences at Southern Methodist University in Dallas, along with Jeff Tester of MIT completed a year-long evaluation of the potential for engineered geothermal resources for DOE. He is a proponent of geothermal energy from oil and gas wells. “We have hundreds of thousands of wells in Texas with temperatures over 300 F,” says Blackwell, “and lots of gas wells on the Gulf Coast over 400 F.”
Developers try to design wells to minimize water flow because water is costly to dispose of. Blackwell describes how roads northwest and southwest of Dallas are heavy with tanker trucks hauling wastewater from gas wells. In 2002 alone, Texas produced 12 billion barrels of wastewater.
In making his case for how that heated water could be put to better use he cites a test plant at Brazoria near Houston. There, water with a temperature of 300 F produced 1 MW of electricity for five years with no detectable drawdown of the well. The well produced 500 kW from the heat and 500 kW from natural gas encapsulated in the water. In a geopressured resource, natural gas is dissolved in the water. A barrel of geopressured water contains at least 20 to 30 standard cubic feet of natural gas. Estimates suggest that the Brazoria test could have produced 3 MW for 20 years.
“Using conventional technology, the resource would eventually draw down,” says Blackwell. That’s because water is being produced at 5,000 to 10,000 psi, making it difficult to reinject. However, as pressures drop, water conceivably could be reinjected to the same reservoir. At the same time, heat stored in the rock that was not extracted by the initial water production could also be recovered.
A high degree of certainty also exists as to precisely where such resources are in Texas. That’s because they reside in low permeability sandstone reservoirs instead of laying hidden under granite as in most of the western U.S. In Texas alone, Blackwell says the total resource base could support hundreds of thousands of megawatts.
Another plus is that some geopressured areas in Texas are close to urban centers including Houston, which will likely always be transmission constrained. “One reason Texas has so much installed capacity is that oil fields are so energy intensive,” he said. “The thermal energy already below those very fields could provide additional power right where it’s needed.”
To get the power onto the wires, Blackwell envisions several dozen wells clustered together on a relatively small tract with portable geothermal units that could be moved from well to well on a flatbed truck. Such clusters could produce from 10 MW to 50 MW, well within the range considered viable for grid connection. Hot well water could also be delivered up to 30 miles from the source and transported via pipeline, losing only a couple of degrees of heat.
Like other energy sources, the politics of funding further research and development, as well as extending various tax incentives, complicate geothermal development. The Energy Policy Act treated geothermal well and called for additional funding, says NREL’s Bruce Green. Since passage of EPACT in 2005 however, the Bush Administration and the Office of Budget Management have said they want to cut funding and incentives in half because they view geothermal technology as mature and ready to go it alone.
“Congress has passed a $5 million geothermal program and the Senate a $23.5 million program,” says Gawell. DOE continues to push a $5 million program. Gawell says the industry could use up to $60 million to share the cost of new technology and project development.
One challenge comes in identifying resources with a high degree of certainty, and Gawell points to some recent successes. “We had the geothermal resource exploration and development (GRED) program that supported cost-shared drilling in a brand new area. Some projects coming on line tie right back to that GRED funding.” He adds that there remains a great deal of R&D that needs to be done in the power cycle in terms of low temperature power conversion and ways to deal with corrosion. He argues, however, that subsurface technology and resource assessment are the top priorities.
Gawell says that back in the 1920s, the oil industry essentially said “We’re done; there’s nothing more to find,” thinking all the sites in the country they could see had been developed. Modern geophysics and technology allowed additional discoveries.
That may be where the country curently is with geothermal, Gawell says, noting that a 1978 U.S. geological survey reported that 90 percent of U.S. geothermal potential is hidden with no obvious surface manifestations. “We need a better way to find it.”