Oil & Gas, Geothermal Technology Transfer Not a One-Way Street

Not too many opportunities are capable of pulling someone out of retirement, but the potential and excitement around geothermal energy got Greg Leveille, former CTO for ConocoPhillips, to do just that.

Geothermal is going through a transformation as oil and gas technologies and techniques improve the economics of projects, according to Leveille, now CEO of Tidal Wave Technologies, a consulting company focused on enhanced geothermal systems (EGS).

“Take a look at drilling where the secret sauce has been bringing in modern drilling rigs, rigs with top drives using PDC [polycrystalline diamond compact] bits, physics-based drilling where you tie together all the elements of the rig and the rock,” Leveille said during a session at CERAWeek by S&P Global. “That has reduced the time it takes to drill a geothermal well to about one-tenth of what it was five years ago and the cost to about a third.”

Technologies commonly used in oil and gas—horizontal drilling, longer laterals, more intense completions—are being used for geothermal projects, making it cheaper to drill deep into hot reservoirs to generate power. The so-called transformation of the sector comes amid the search for affordable baseload power to meet growing energy demand.

But it’s not a one-way street when it comes to the technology transfer. The oil and gas sector could also learn from the geothermal sector.

“I do want to make sure that people don’t walk out of this room thinking, well, oil and gas is just going to take over geothermal,” Leveille said. “You kind of get that sense in some of the conversations.”

Dealing with superhot temperatures, fluid geochemistry and moving enormous amounts of water in geothermal systems is a simple equation, he said, but a lot of activity happen in those systems. “When that water picks up elements, you get scaling and corrosion, so there needs to be a cross-fertilization between the two,” Leveille said, “and the degree to which companies are successful at cross-fertilizing will make the difference, I think, between the winners and the ones who don’t do as well.”

Cross-pollination, cross-fertilization

Collaboration between geothermal companies and oil and gas companies is already happening in areas such as fracture geometry, said Trey Lowe, senior vice president and CTO for Devon Energy, which led a $244 million funding round for geothermal company Fervo in 2024.

“We’ve been learning at the same pace that we’re helping at times,” he said. “And it helps us shape how do we think about our assets that we might have in the Permian Basin in a different way.”

There were certain areas where geothermal tossed its traditional ways of thinking and turned to the oil industry for answers, according to Tim Latimer, CEO of Fervo Energy. In some instances, more advanced oil and gas techniques worked; in other instances, they led to setbacks because certain geothermal rules were ignored, he said.

Between 70% and 80% of Fervo’s team came from the oil and gas industry, Latimer said. He admitted the company initially didn’t want to hire people from geothermal but now it realizes the value of the geothermal skillset and cross-pollination between the two industries.

“We’ve started making sure we’re hiring more folks from geothermal as well because certain challenges … around geochemistry are different and more pronounced in the geothermal world, and the work that’s gone into reservoir modeling characterization in geothermal is very strong as well,” Latimer said.

For Fervo, the innovation journey includes lessons on “how do you have the courage to challenge conventional wisdom on certain areas to say, ‘Look, this is a rule of thumb that has been in the geothermal industry for 50 years, but we think we can challenge it and ignore it,’” he said. “And where do you have the humility to say, ‘Actually, the geothermal industry has this figured it out,’ and we’ve got to learn there as well.”

Partnerships, as one might expect, play a key role.

Devon paired some of its subject matter experts (SMEs) with SMEs working on geothermal projects for Fervo, Lowe said. “We’ve seen … the learning going both ways have been incredibly important both for Fervo and for Devon.”

Latimer recalled working on a Helmerich & Payne (H&P) Flex 3 drilling rig when he entered oil and gas as a drilling engineer for BHP in the Eagle Ford. It’s the same type of rig Fervo uses today in its drilling operations. Besides Devon, Fervo’s investors and partners include H&P, Liberty Energy and Mitsubishi Heavy Industries (MHI).

Historically, geothermal projects have presented boutique engineering challenges, according to Latimer. But engineering reservoirs enable more consistent predictions in areas such as pressures, flow rates and reservoir fluids, he said, adding that allows for topside power plant systems to be standardized across multiple projects.

“We’ve already realized working across this partnership with MHI enormous improvements in both the plant efficiency and the plant cost just because you’re starting to chip something from a boutique stick-built one-off solution to something where we can actually batch order numerous turbines in one go and actually devote a lot of engineering resources to it as well,” Latimer said.

Falling costs

Costs for geothermal projects vary, depending on several factors including drilling techniques, depths, flow rates and reservoir conditions such as temperature. Geothermal is already competitive with nuclear, gas and coal generation, according to analysis from Lazard. The firm’s research showed the levelized cost of energy (LCOE) for the carbon-free, baseload power source between $61 and $102 per megawatt hour (MWh). Nuclear power ranged from $141 to $221 with coal between $68 and $166 and gas peakers ranging from $115 to $221.

Solar and wind, though intermittent, have lower LCOE.

Still, there is opportunity to bring geothermal costs down further, including on the drilling and completions side. The sector could see advances similar to those in oil and gas.

“The absolute well cost has kind of plateaued, but we’re now drilling much longer wells, getting more flow rates,” Leveille said. “So, if you kind of look at it on a unit basis, I think there’s still a lot to gain there because the longest well in the world … for geothermal is 5,000 feet. Going longer is going to be very beneficial.”

Going hotter can as well.

Doubling the temperature could increase energy output 4X to 5X, he added, comparing it to efficiency gains with longer laterals in the Permian Basin. Other ways to lower costs include having modular plants and changing well spacing. “I think there’s a lot of opportunities,” Leveille said.

In 2021, the capex needed for a geothermal project was about $30,000 per kilowatt (kW), which is equivalent to about $400 per MWh, Latimer said.

“I don’t care what your green goals are. I don’t care how quickly you want to get a data center online. No one’s going to pay $400 a megawatt hour for power,” he said. Fervo managed to drop costs to $16,000/kW for its three-well pilot EGS project, which Google called Project Red in Nevada in 2023. Costs continued to fall the following year.

Latimer said Fervo believes it is currently around $6,000/kW with its project in Utah as it targets further cost reductions. The company is developing its Cape Geothermal Power Project in southwest Utah, with first electricity expected in 2026. If fully developed, the project could deliver 2 gigawatts of clean power.

“If we get below that $3,000 per kilowatt number, and keep in mind these are long-life assets with limited decline and no fuel costs, we think that [geothermal] becomes the cheapest form of new electricity, period.”