The most popular approaches to saving the planet from our addiction to oil borrow energy from wind, waves, plants, or the sun. Now, a less obvious source has emerged as a feasible alternative. Structures the size of small power plants could be used to tap into a hidden store of underground energy, drawing fluid up through narrow holes several kilometers deep. And that fluid wouldn’t be oil but plain old water.
In January, an MIT-led panel of scientists, economic experts, and engineers released The Future of Geothermal Energy, a federally funded 372-page report calling for a national effort to exploit the heat of subterranean rock. The authors, led by MIT chemical-engineering professor Jefferson Tester, PhD ‘71, contend that given technological developments and recent successes abroad, geothermal could provide a significant amount of energy in the coming decades.
Geothermal systems extract energy from water exposed to hot rock deep beneath the earth’s surface. Tester says that an R&D investment of less than $1 billion would make geothermal economically viable–and, by 2050, capable of supplying at least 100 gigawatts of electricity, or 10 percent of today’s entire U.S. generating capacity. Better yet, geothermal uses relatively unobtrusive surface equipment, produces almost no emissions, draws on a renewable energy supply, and has a very limited environmental impact.
Tester doesn’t think the government’s current interest in geothermal is just part of an alternative-energy fad, nor does he think it will fade if gas prices drop. “Things are different now,” he says. “There are more reasons why we should evolve to a new energy system. Part of it is security-related, part of it is environmental, but part of it is just the recognition that a lot of folks in the U.S. are dependent on low-cost energy, and we’re too dependent right now on a few sources.”
Today, 50 U.S. geothermal plants are using steam or hot water from the earth’s crust to crank out almost three gigawatts of electricity. But these sites, located in California, Hawaii, Utah, and Nevada, are blessed with ideal conditions: the hot rock is relatively close to the surface, so it’s accessible without drilling very deep; there are plenty of natural cracks in the rock; and there’s an abundant supply of water already flowing through those cracks–in most cases carrying steam to the surface naturally. Unfortunately, there are not enough such sites in the United States to satiate much of our appetite for energy.
For this reason, the geothermal report focuses on a technology called enhanced or engineered geothermal systems (EGS), which doesn’t require ideal subsurface conditions. The specifics vary by site, but installing an EGS plant typically involves drilling a 10- to 12-inch-wide, three- to four-kilometer-deep hole, expanding existing fractures in the rock at the bottom of the hole by pumping down water under high pressure, and drilling a second hole into those fractures. (The holes are thousands of feet apart at depth but can be quite close on the surface.) Water pumped down one hole courses through the gaps in the rock, heats up, and flows back to the surface through the second hole. Finally, a plant harvests the heat and circulates the cooled water back down into the cracks. Theoretically, EGS could work anywhere, even in the middle of Boston. You’d just have to drill deeper–perhaps seven kilometers or more. “There’s hot rock everywhere,” says Chad Augustine, a PhD candidate in Tester’s lab and an associate member of the EGS panel. “It’s just a matter of how much it costs to do it, how deep you have to go to get it.”
Economic viability–not whether the engineering works–has been the big question with EGS. Can it compete on price with oil, or even solar and wind? The geothermal report points to promising projects like one at an Australian site called Cooper Basin, where engineers tapped into 250 ºC granitic rock four kilometers below ground. Past projects, including one at Fenton Hill, NM, that Tester was involved with for more than 20 years, proved that EGS is technically feasible. But at Cooper Basin, the hot water rushed up to the surface at an impressively high rate of production, achieving one-third to one-half of the flow capacity at which EGS could compete with other energy sources–a major step forward.
Successes like Cooper Basin are attributable to new technology that takes much of the guesswork out of siting and building EGS plants. When engineers pump down water to expand the cracks in the rock, they can map the spreading fractures with tools widely used in the oil industry. Seismometers record vibrations, and simulation software generates a map of the new cracks. The map helps engineers pick the best spot for the second hole–the spot amid those veins of fractures that will yield the best flow from one hole’s pipe to the next. Such tools are “a very crucial thing for us to make this whole process feasible and economically viable,” says MIT geophysics professor M. Nafi Toksöz, a report coauthor.
Drilling is one of the biggest costs associated with building a geothermal plant, but that’s a problem Augustine and Tester are addressing. Conventional drill bits wear down and must be replaced frequently. That can sideline drill rigs–which are rented on a daily basis–for the better part of a day, Augustine says. While deep-pocketed oil companies can afford expensive delays, the prospect of absorbing extra costs makes would-be EGS investors wary. One alternative is a different kind of drilling, called thermal spallation, which replaces the drill bit with a jet flame. The rock is heated to about 500 ºC, at which point it begins to spall, or chip off in tiny chunks. “If you put the right amount of heat on the right type of rock,” Augustine says, “it’ll just fly away.”
In Tester’s basement lab, Augustine is experimenting with this flamethrower technique in an apparatus that he built to simulate the extremes of temperature (upwards of 2,000 ºC) and pressure at the bottom of a borehole. Working under such conditions isn’t for the faint of heart; he jokes that he encased the rig in two layers of bulletproof material to appease his lab mates. But Augustine’s research could make EGS installation much cheaper. With thermal spallation, there are no bits to wear out, and thus no delays while they’re replaced. It’s also more efficient; other researchers’ work suggests that the technique may be more than twice as fast as normal drilling.
The process of exploring and drilling a site poses a few potential environmental risks, but the report deems them manageable. For example, coauthor Ronald DiPippo, a mechanical engineer and author of Geothermal Power Plants, says expanding the fractures could induce tremors registering two or three on the Richter scale–something people living nearby should be aware of but would have no cause to fear. MIT chemical engineer Elisabeth Drake ‘58, ScD ‘66, led the drafting of the report’s section on the environmental impact of EGS. “Once the facility is operational,” she says, “the impacts are small compared with other energy technologies.”
Although geothermal alone won’t meet our energy needs in the coming decades, a relatively small investment in EGS research and development over 15 years would easily pay off. Tester says investing $800 million to $1 billion–less than the cost of one new clean coal-burning power plant–could make EGS an economically viable energy source. And as part of a portfolio of energy alternatives, it could substantially decrease our dependence on fossil fuels. “If we think about what made America strong over its history, it has largely been a diversity of the ideas and the people and the resources we have,” he says. We “haven’t capitalized on that” in the realm of energy, but developing geothermal would be one way to start.