The future of geothermal for reliable clean energy

Historically, access to geothermal energy has hinged on real estate’s famously three most important factors: location, location, and location. Because conventional geothermal power plants require hot, permeable rocks and plenty of underground fluid, use of the technology has been limited mostly to places with recent volcanism, such as Japan, New Zealand, the Philippines, Kenya, El Salvador, Iceland, and the western United States.

Over the past 50 years, however, techniques originally developed for oilfields and adapted for “enhanced geothermal systems” (EGS) have offered the promise of tapping deep reserves of natural heat across a broader swath of the planet.

“There is a lot of excitement about enhanced geothermal energy,” said Roland Horne, a professor of energy science and engineering in the Stanford Doerr School of Sustainability, who convened more than 450 engineers, scientists, and managers from 28 countries earlier this month at the 50th Stanford Geothermal Workshop to exchange ideas and report results from projects around the world. 

To date, nearly all EGS applications have been for research purposes in one-off, small-scale plants, said Horne, who was invited to gather a team of authors to write a review paper for the February 2025 issue of Nature Reviews Clean Technology about EGS and its potential to supply energy at a larger scale. 

Millennia after ancient Romans tapped subterranean heat to warm their buildings, and more than a century after Italy started up the world’s first geothermal power plant, Horne and co-authors note that geothermal today contributes as much as 45% of the electricity supply in some countries, like Kenya. But it still contributes less than half of 1% globally. Solar and wind contribute more than 25 times as much. With EGS, the potential now exists for geothermal to comprise a far greater share of humanity’s energy needs.

Faster drilling reduces costs

Many of the drilling techniques that enabled the shale gas boom of the early 2000s have been adapted to make geothermal work in more regions at lower cost, said Horne. These techniques include horizontal drilling and hydraulic fracturing, or fracking, which involves pumping fluids at high pressure into wells drilled down into and across rock formations thousands of feet underground. The pressure forces open existing fractures in the rock or creates new ones, easing the flow of petroleum or other fluids to the surface. In enhanced geothermal systems, the fluid is just hot water from the natural underground reservoirs. 

Other adapted techniques include drilling multiple wells from a single pad to increase efficiency and reduce costs. Synthetic diamond drill bits, which can effectively chew through hard rock, have also proven critical, making it possible to complete a new geothermal well within a few weeks instead of months. 

“Drilling faster makes an enormous difference to the whole economics of EGS,” said Horne, the Thomas Davies Barrow Professor at Stanford, who also serves on the scientific advisory board of an enhanced geothermal development company co-founded by Stanford alumni Tim Latimer, MS-MBA ’17, and Jack Norbeck, PhD ’16.

Based in part on modeling led by PhD student Mohammad Aljubran, Horne and his co-authors on the review paper estimate the faster drilling rates could make enhanced geothermal systems competitive with average electricity prices across much of the United States by 2027, at approximately $80 per megawatt-hour. 

In California, which currently gets about 5% of its electricity from geothermal, the authors estimate geothermal capacity could increase tenfold with EGS to reach 40 gigawatts by 2045 and replace fossil fuels for baseload power. In this way, EGS would complement the intermittent renewables of wind and solar, adding stability to a decarbonized power grid.

“With EGS, we can meet the load,” said Horne, whose co-authors on the Jan. 31 review paper include Norbeck and former student Mark McClure, MS ’09, PhD ’12, the co-founder and chief executive of a company that markets fracture modeling software to oil, gas, and EGS companies. Additional co-authors include William Ellsworth, an emeritus research professor of geophysics in the Doerr School of Sustainability; Eva Schill, who leads Lawrence Berkeley National Laboratory’s geothermal systems program; and Albert Genter, deputy director general of geothermal at Electricité de Strasbourg, which is involved with commercial development of EGS projects in France. 

Mitigating earthquake risks

As with fracking for oil and gas, fracturing deep rocks to access geothermal reservoirs can trigger earthquakes. 

One obvious way to mitigate risk again hearkens back to location: Simply avoid drilling in places prone to earthquakes. For example, building a site atop the San Andreas Fault that perilously wends through California would be ill advised, Horne said. 

A second approach is monitoring seismicity with a system known as a traffic-light protocol. If a seismic event of a certain magnitude occurs, operators slow down their drilling. Bigger seismic events are treated as red lights that halt all drilling and prompt a review prior to potential restart.

A recently developed strategy for limiting seismicity, Horne said, involves creating many smaller fractures during drilling rather than just one or a few massive fractures. Most earthquakes associated with EGS have occurred when big, human-stimulated fractures are pumped full of fluid and activate faults, which are naturally existing fractures in rock. “A drip-drip-drip instead of a fire hose approach can significantly reduce the risk and size of induced seismicity,” said Horne.

He and his colleagues hope the new study encourages further research and development of EGS as a sustainable and reliable energy source. “EGS could be a game changer for green energy production not just in California but across the U.S. and worldwide,” said Horne. “Safely harnessing Earth’s internal heat could substantially contribute to powering our future.”