Fervo Energy CEO Tim Latimer didn’t wear his Helmerich & Payne (HP) socks intentionally, but the choice illustrated the growing ties between the geothermal and oil sectors.
“We have a really tight-knit partnership,” Latimer said March 7 during CERAWeek by S&P Global.
Latimer, who leads the Houston-based company’s focus on converting geothermal energy into electricity with enhanced geothermal systems, started his career as an oil and gas drilling engineer in the high-temperature Eagle Ford Shale. He recalled working on a super-spec HP rig with gobs of automation, which wasn’t the case at the time for geothermal drilling.
“We realized actually doing a better job of bridging the gap between the technologies and the oil and gas industry in the geothermal industry could yield huge results,” Latimer said while speaking on a panel alongside executives from Chevron New Energies and GeothermEx, an SLB company. HP is among Fervo’s investors.
The geothermal sector is competing against other forms of renewable energy that must build out massive global supply chains from scratch; however, Fervo and some others in the geothermal field are tapping into the existing oil and gas drilling supply chain to move to market faster.
While the synergies between the two sectors are abundant—utilizing the same or similar rigs to drill horizontal wells, casing tools, imaging equipment and other oilfield services, drilling conditions are different. Geothermal drillers face harder rock, challenging temperatures and more issues with lost circulation, according to Latimer. Still, geothermal is positioned to capitalize on knowledge gained in oil and gas.
Fervo recently released data from a project underway in Utah that cut drilling time using existing technology. It took the company 72 days to drill the project’s first well. That dropped to 59 days with the second well.
“Based off of the metrics that you look at as a drilling engineer from well construction standpoint, from an on-bottom rate of penetration drilling rate standpoint, bit-life standpoint, there’s nothing that prevents us from drilling these wells in a 22- to 25-day period only using existing technology,” Latimer said. “That’s going to make geothermal extraordinarily more cost-effective than it is today. It’s just a matter of coming down that learning curve.”
As new drilling technologies and techniques emerge, the potential for geothermal expands, he added. For geothermal, this also includes incorporating pad drilling.
Partnering with startups
However, the growth of geothermal won’t be solely dependent on what the oil and gas industry brings to the table; it will be leveraging partnerships with startups that have been advancing technology such as advanced closed loop (ACL) geothermal systems, said Barbara Harrison, vice president of offsets and emerging for Chevron New Energies.
Advanced geothermal systems generate power via closed-loop systems where a contained working fluid is circulated within the wells, which brings the heat to the surface without disrupting the reservoir. In conventional geothermal, water or steam is produced from wells and then reinjected after the heat is extracted to keep the system operating for long periods of time.
“We’re going to have to build the scale to drive the costs down to then be able to be fully competitive using either EGS [enhanced geothermal systems] or ACL technology,” Harrison said. The traditional drilling and fracking technology from oil and gas, in partnership with startups pushing the latest technologies, is moving drilling practices to the next level for geothermal, she said.
Chevron Tech Ventures scans the energy landscape looking for early equity investments to support startups and de-risk technology, while Chevron New Energies—working with the Tech Ventures team—focuses on what it will take to drive the technology to commerciality and scale, she explained.
Chevron has invested in Baseload Capital AB, a Sweden-based private investment company focused on development and operation of low-temperature geothermal and heat power assets. The company has also invested in geothermal startup Eavor Technologies.
Investment and production tax credits motivate people to take risks, added Ann Robertson-Tait, president of GeothermEx.
“When you know you have a sweetener in the power price basically from the production tax credit, you will [be] more comfortable and get out there and do something faster,” Robertson-Tait said. The Inflation Reduction Act has “been really amazing in terms of CCS and geothermal, and that is driving people to look to move more quickly into geothermal. Now, is it the only thing? No, absolutely not. All the technology pieces we’ve discussed here are very important, but it is definitely a driver. I think we owe a debt of gratitude to the legislators who decided that that was a good thing to do.”
The U.S. Department of Energy (DOE) is also seeking to lower the cost of EGS by 90% to $45 per megawatt hour by 2035 with its latest Energy Earthshot initiative. The Geothermal Shot plans to address the challenges by accelerating R&D and demonstrations to improve subsurface knowledge. It also seeks to improve well engineering designs.
Path to lower costs
A conference attendee wanted to know if the best path to lower costs were in the subsurface or surface technology or both.
“You can think of geothermal projects as being 50-50 projects, subsurface and surface. Although the surface technology is improving, it’s reached a pretty good level of maturity,” Robertson-Tait said. “We will see innovation in that space, but it will be somewhat incremental. … If you could reduce your drilling costs by half, you’d have reduced your capex by 25%.”
Many drivers in lowering costs for shale oil and gas weren’t necessarily related to drilling performance, but innovation and bringing down associated cost. In mid-2000, for example, the shift from single pads to six-well and 12-well pads helped lower spending on building roads and other related costs.
“You can reduce your road cost by 95% by putting multiple wells on a pad. That’s fascinating,” he said, noting Fervo is planning a six-well pad for the first phase of an upcoming geothermal project. That will lower pipeline costs to connect wells to the plant as well as road and infrastructure costs, while reducing the number of trips taken during the operations and maintenance phase, he said.
“Having better subsurface technology is actually going [to] end up having knock on effects that dramatically reduce your balance of plant costs, even if those technologies have kind of maxed out in terms of what they can do, which I don’t think they have yet,” Latimer said.
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