Few people on Earth have reached closer to its center than Buzz Speyrer, a drilling engineer with a long career in oil and gas. It’s about 1,800 miles down to the core, smoldering from celestial impacts that date back billions of years and stoked to this day by friction and radioactivity. That heat percolating upwards turns the rock above into a viscous liquid and beyond that into a gelatinous state that geologists call plastic. It’s only within about 100 miles of the surface that rock becomes familiar and hard and drillable.
Right now, Speyrer’s equipment is about 8,500 feet below us, or about 2 percent of the way through that layer, where the heat is already so great that every extra foot, every extra inch, is a hard-won victory. Down there, any liquid you pumped in would become, as Speyrer puts it, hot enough to deep fry a turkey. “Imagine that splashing you,” he says. At that temperature, about 450 degrees Fahrenheit (228 degrees Celsius) his gear can start having problems. Electronics fail. Bearings warp. Hundreds of thousands dollars worth of equipment might go down a borehole, and if it breaks down there, make sure it doesn’t get stuck. In that case, best to just plug that hole, which probably cost millions to drill, tally up your losses, and move on.
Even when things are going well down there, it’s hard to know from up here on the Earth’s surface. “It’s frustrating as hell,” says Joseph Moore, a geologist at the University of Utah, as he watches the halting movements of a 160-foot-tall rig through a trailer window. It’s a cool day in 2022, in a remote western Utah county named Beaver, a breeze whipping off the Mineral Mountains toward hog farms and wind turbines on the valley floor below. The rig looks much like any oil and gas installation dotting the American West. But there are no hydrocarbons in the granite below us, only heat.
Since 2018, Moore has led a $220 million bet by the US Department of Energy (DOE), called FORGE, or the Frontier Observatory for Research in Geothermal Energy, that this heat can be harnessed to produce electricity in most parts of the world. Geothermal energy is today a rare resource, tapped only in places where the crust has cracked a little and heat mingles with groundwater, producing hot springs or geysers that can power electricity-generating turbines. But such watery hot spots are rare. Iceland, straddling two diverging tectonic plates, hits a geological jackpot and produces about a quarter of its electricity that way; in Kenya, volcanism in the Great Rift Valley helps push that figure to more than 40 percent. In the US, it’s just 0.4 percent, almost all of it coming from California and Nevada.
Yet there’s hot rock everywhere, if you drill deep enough. Moore’s project is trying to create an “enhanced” geothermal system, or EGS, by reaching hot, dense rock like granite, cracking it open to form a reservoir, and then pumping in water to soak up heat. The water is then drawn up through a second well, emerging a few hundred degrees hotter than it was before: an artificial hot spring that can drive steam turbines. That design can sound straightforward, plumbing water from point A to point B, but despite a half-century of work, the complexities of engineering and geology have meant no one has managed to make EGS work at practical scale—yet.
Moore is trying to demonstrate it can be done. And in the process, maybe he can get more entrepreneurs and investors as hyped about geothermal as he is. Renewable electricity generation, whether from sun or wind or hot ground, typically offers steady but unremarkable returns once the power starts flowing. That’s fine if your upfront costs are cheap—a requirement wind turbines and solar panels now generally meet. Geothermal happens to require a risky multimillion-dollar drilling project to get started. While clean, dependable power derived from the Earth’s core can complement the on-again, off-again juice from wind and solar, there are safer underground bets for those with the expertise and financing to drill: A geothermal well might take 15 years to pay for itself; a natural gas rig does it in two.
No surprise, then, that there are 2 million active oil and gas wells worldwide, but only 15,000 for geothermal, according to Norwegian energy consultancy Rystad Energy. Nearly all are hydrothermal, relying on those natural sources of hot water. Only a few are EGS. A trio of operating plants in eastern France produce only a trickle of power, having drilled into relatively cool rock. Then there are hotter experiments, like here in Utah and across the border in Nevada, where a Houston startup called Fervo is working to connect two wells of its own, a project that is meant to provide clean power to a Google data center.
Moore believes FORGE can make EGS more attractive by showing it’s possible to go hotter. Every extra degree should mean more energy zapped into the grid and more profit. But drilling hot and hard granite, rather than cooler and softer shale that gas frackers like Speyrer typically split apart, isn’t trivial. Nor is drilling the wide wells required to move large volumes of water for a geothermal plant. Thus, a chicken-and-egg problem: The geothermal industry needs tools and techniques adapted from oil and gas—and in some cases, entirely new ones—but because nobody knows whether EGS will work, they don’t exist yet. Which is where FORGE comes in, playing a role Moore describes as “de-risking” the tools and methods. “Nobody is going to spend that money unless I spend that money,” he says.
In Beaver County, his team is testing a bridge plug—a cap, essentially—that will seal off a section of pipe so that water can be forced into surrounding rock with enough force to crack granite. It’s late morning and a dozen water tankers are parked in imposing formation next to the rig. Around lunchtime, they’ll test whether the plug can hold the pressure, and before dinner should fire “the guns”—small explosive charges—to perforate the pipe. Then they’ll push in the water to split the rock in time for a midnight snack—“if everything goes smoothly,” Moore says.
In other words, a pretty standard frack, the technique that has flooded the US with a bounty of natural gas over the past 15 years. But don’t use the f-word too liberally, please—it’s rather taboo in geothermal, even though the industry’s future may depend on the technology. The sensitivity is not just about the association with fossil fuels. Frack in the wrong place, over some hidden fault, and the earth can tremble with damaging intensity.
The team is closely watching data recorded by eight geophones—acoustic detectors that pick up seismic waves—hanging in nearby boreholes. So far, the only clear signal is that it’s really hot down there. A few minutes before the start of the pressure test, John McLennan, a chemical engineer co-managing the frack, arrives in the trailer with bad news about a pair of geophones.
“Both of them have failed,” he says. “Just can’t handle the temperature.”
“I’m too old for this,” Moore replies.
It had been a long few days. It wasn’t supposed to be a 24-hour operation, but here they were, delayed by high winds and malfunctioning equipment, another long day and night ahead. Now he’d lost a pair of crucial ears telling him what was going on beneath the surface.
While the FORGE team preps for the frack, Moore and I drive into the Mineral Mountains to see why geothermal energy has thus far fallen short of its potential. We stop at the perimeter fence of the Blundell Geothermal Plant, which sits a few miles from FORGE, on the eastern edge of a hot zone stretching hundreds of miles west to the Pacific. The appeal of the location is obvious. Near the site, fissures in the rock reveal places where hot water has burbled to the surface, carrying minerals that hardened into rivulets of crystal. A few hundred feet away, sulfurous clouds rise from the soil around a 19th-century shed where cowboys and miners once took hot soaks.
The plant, which is owned by Portland-based electric utility PacifiCorp, was built during a geothermal boom during the 1970s oil crisis. But by the time its turbines began spinning in 1984, energy prices had fallen and the boom was already fading. The vast majority of US plants operating today still date back to the 1980s—a painful fact for a geothermal enthusiast like Moore. His own journey in the industry began around that time, as he transitioned away from an earlier career prospecting for uranium deposits—itself then a waning industry—that had initially brought him to Utah from his native New York City.
He considers Blundell especially underutilized, pointing to turbines that could be upgraded to produce more energy and spots where PacifiCorp could drill more hydrothermal wells. “It’s just risk aversion,” he says. “They say, ‘I can’t see what’s underground, so I’m skeptical about drilling.’” (PacifiCorp did not respond to requests for comment.)
Only a few companies are exploring new hydrothermal locations. One of them is Reno-based Ormat Technologies, which owns and operates more than 20 geothermal plants worldwide. Paul Thomsen, the company’s vice president for business development, tells me how Ormat established its business by purchasing existing plants and updating their turbines to draw more power from the same hot water. More recently, drawing on its experience with everything from drilling to plant operations, it started building new plants.
But it’s tricky to pick winners, even when there’s an obvious hydrothermal resource to exploit. Desert towns in the American West have rebelled against proposals out of concern groundwater will be drained away. And wherever biologists look in hot springs, they have found unique species deserving of protection. Stack that on top of lengthy permitting processes and challenges with connecting new plants to the grid, and options dwindle. Ormat has had recent setbacks at two of its proposed sites, over groundwater near the Nevada site of Burning Man and over the tiny Dixie Valley toad, a species recently listed as endangered.
The challenges of natural hot springs have made creating artificial ones all the more appealing. In 2006, the DOE, along with researchers at MIT, issued a report describing a plan for making geothermal a major contributor to the US grid to help meet climate goals. The flexibility offered by EGS was at the heart of it. Although the depth at which rock gets hot enough varies—shallower out in the American West than on the East Coast, for example—the scientists reckoned it could be reasonable to drill for heat in most places, either to produce electricity or, at lower temperatures, hot water to warm buildings.
In 2014, the DOE started looking for a place to serve as a testing ground for repurposing tools from oil and gas, and, four years later, picked Beaver County as the experiment’s home. Soon afterward, the agency calculated that geothermal could satisfy 8.5 percent of US electricity demand by 2050—a 26-fold increase from today. All that was missing was proof that EGS worked.
The Forge well descends straight down for about 6,000 feet (1.8 kilometers), reaching granite about two-thirds of the way there before making a 65 degree turn and going nearly 5,000 feet (1.5 kilometers) farther. Among Moore’s passions, enthusiastically demonstrated with hand motions and napkin diagrams, is the internal “stress field” of the granite that determines how it will crack under pressure.
Understanding that stress field is essential. For an efficient power plant, the cracks must extend far enough for water to move efficiently between the two wells—but not too fast, says Teresa Jordan, a geothermal scientist at Cornell University in New York, where she is leading an EGS project aimed at heating campus buildings with geothermal water. “You want it to take its time, spending a lot of time in contact with rocks that will heat it up,” she says. The cracks must also deliver as much water as possible to the second well—and not into hidden fissures along the way—and also stay hot for years of use. Hot rocks can cool to tepid if cold water pumped in soaks up heat faster than the core’s heat can replenish it. Vanishing water and dwindling heat have played a role in past EGS failures, including in New Mexico in the 1980s and in southern Australia in 2015.
Those risks have sent others looking for different approaches, each with their own tradeoffs. One, a “closed-loop” system, involves running sealed pipes down into the hot rock and then back to the surface, preventing any water from draining away underground. But it has proved tricky to get enough heat into liquid that doesn’t touch hot rocks directly. Or maybe you drill really deep—say, 12 miles down—where temperatures can exceed 1,650 Fahrenheit (900 degrees Celsius), enough for the heat to rise straight to the surface up a single well. But the tools to drill at such depths are still experimental. Others think existing oil and gas wells are the answer, saving on drilling costs and unlocking the industry’s abundant tools for its own wells. But the narrower wells used for extracting fossil fuels aren’t built for pushing the vast volumes of water necessary for a power plant.
EGS proponents argue designs like FORGE strike the right balance, adding enough heat and flexibility over traditional geothermal, while being able to take advantage of oil and gas methods, The newest EGS experiments are enabled by advances in horizontal drilling and better fracking models, says Tim Latimer, CEO of Fervo, which is working with FORGE as it develops its own EGS project in Nevada. He tells me he thinks that the projections energy investors use to estimate geothermal drilling costs—ones that make them hesitant—are 15 years out of date. During the drilling of the first FORGE well, he points out, the team demonstrated it could halve the time using a new, diamond-tipped bit, cutting overall costs by 20 percent.
Around 3 pm, after our walk around the Blundell plant, Moore returns to the drill site and sees McLennan jogging over to greet him. He has good news. First up: The plug has held under pressure. Moore lets out a big breath, hands on hips. “I’m glad that’s over with,” he says. Later, after the guns are fired and water pumped in, a “seismic cloud” of tiny quakes picked up by the remaining geophones, suspended at lesser heat and depth, indicates that the cracks extend about 400 feet from the well—the right distance to connect with the second, future well that will draw newly heated water up to the surface. A third piece of good news is that the seismic cloud couldn’t be felt on the surface.
That’s especially good news to Peter Meier, the CEO of Geo-Energie Suisse, a geothermal energy consortium. He traveled to Utah from Switzerland mostly to listen to the geophones. In 2006, a 3.1 magnitude quake occurred after engineers on a Swiss EGS project attempted to create a water reservoir that was too large and disturbed an unmapped fault, damaging homes nearby in Basel. (A geologist faced criminal negligence charges for his role in the quake, but was later acquitted.) Local governments in Switzerland have been wary of EGS operations since.
In 2017, an even bigger quake triggered by an EGS project in South Korea, which injured 82 people, dimmed the concept’s prospects even further. But Meier believes those earthquakes were due to poor planning on the part of engineers—avoidable, with more careful study of the rocks. He sees FORGE as a chance to rescue the reputation of EGS by demonstrating it working safely. “Until we have a success story it’s a discussion about fracking, because basically, it is fracking,” he says.
This spring, Moore returned to Beaver County to drill well number two. After nearly a year of reviewing the data from the initial frack, he felt confident that the production well, drilled straight through the cloud of cracks from the frack, would succeed in getting water back out. Earlier this month, he was proved right: Nearly 76,000 gallons went down the first hole at a rate of about 210 gallons per minute, and came back out the other end hotter. A full-scale test in 2024 will get the flow rates closer to those required for commercial EGS plants, which should cycle more than a thousand gallons per minute.
Part of Moore’s confidence was that he knew he was playing on easy mode. By design, the two wells are too close together to draw up substantial heat for a power plant—the point at this stage was mostly the tools and techniques financed and tested along the way. Prior to the test, Moore was excited to tell me about the new gadgets available for creating the production well, including particle drilling, in which rock is eaten away by shooting small, high-velocity metal balls; a rotary drilling system that they could steer from the surface; and upgraded, more heat resistant geophones.
In the end, all three were less useful than Moore had hoped. The particle drilling and steerable system turned out to be more trouble than they were worth, especially compared with the earlier success of the diamond-tipped bits. The modified geophones still fritzed beyond about 300 degrees Fahrenheit (150 degrees Celsius); Moore says they’ll eventually switch over to heat-proof, fiber optic-based devices. But that’s the point, he says, of “de-risking.” Sometimes it’s helpful to see what breaks.
There are other reasons to feel hopeful. A few days after the FORGE connection, Fervo released results from its own 30-day connection test in Nevada. The result, according to Latimer, is “the most productive enhanced geothermal project ever completed,” producing enough hot water to generate about 3.5 megawatts of electricity. The boreholes were drilled near an existing hydrothermal plant that has room for more capacity, and will produce power by the end of the summer, he says.
“We’ve shown that it works,” Latimer says. “Now the question is how quickly can we bring it down the cost curve.” That includes getting hotter. Fervo’s Nevada wells peaked at 370 degrees Fahrenheit (190 degrees Celsius)—hotter, he points out, than any other horizontal oil and gas well in the US—and hot enough to prove that its own tools can go a bit hotter next time. There are also crucial questions about drilling, he adds: the optimal distance between the wells, the angles, the depth. “It’s not like software where you can iterate quickly,” he says. The industry needs more experiments, more projects, to figure out the most productive combination—each of them bound to be expensive and difficult.
More opportunities to iterate are likely coming. The US Inflation Reduction Act has poured money into green energy infrastructure, adding incentives to geothermal development that put it closer to existing ones available to wind and solar. Meanwhile, the DOE upped its goal for geothermal electricity generation in 2050 by 50 percent, to 90 MW, based in part on improved prospects for EGS technology, and in February announced that it would spend an additional $74 million on pilot EGS demonstrations. None of them are likely to go as hot as FORGE just yet, Moore suspects. “I think we’re going to be looking at temperatures where we know the tools work,” he says. But it’s a start.
Some might try to use that warmth for direct heating, like Jordan’s project at Cornell. Others might drill at the edge of proven hydrothermal areas, where the heat is more accessible. And there are other, creative approaches to maximize revenue. Fervo and others have proposed using their wells as batteries—pumping down water when the grid has excess energy and then bringing it back hot at leaner times to generate power—or building plants alongside power-hungry facilities like data centers or future carbon removal plants, avoiding the challenges of connecting to an overloaded power grid.
Scaling up from there will require much more investment. And the degree to which investors—especially in oil and gas—will pick up the baton remains to be seen. This year, Fervo picked up a $10 million investment from oil and gas company Devon Energy, a pioneer of fracking. Last month, Eavor, a closed-loop geothermal startup, announced BP Ventures had led its latest funding round. “It’s gone from zero to something,” says Henning Bjørvik, who tracks the geothermal industry at Rystad, the energy consultancy. But oil and gas is still as much a competitor—for equipment, expertise, and land—as it is a friend to geothermal, and commitments to clean energy can prove fickle when fossil fuel prices start booming. What investors need to see, Bjørvik says, is that this embryonic industry can scale to hundreds or thousands of plants—with enough potential profit to outweigh the risks of any individual project going south.
The way to do that, Moore believes, is to keep showing how things can get just a little bit hotter. Completing the research at the second FORGE borehole will exhaust its current DOE grant in 2025, but he has applied for new funding to drill wells that are further apart—and, of course, test new tools at ever higher temperatures. By then, he’ll have a new neighbor. The rig for Fervo’s next project is already visible from the FORGE well pad—the start of what’s planned to be a full-scale power plant.
If all goes to plan, it will produce 400 megawatts of energy, Latimer says, enough to power 300,000 homes. It was logical, he says, to drill in the shadow of both FORGE and Blundell. The site has been extensively surveyed and has the grid interconnections to move electricity to Fervo’s initial customers in California. The goal is geothermal energy anywhere. For now, it makes sense to start here.
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