When it comes to geothermal wells, heat is everything.

The higher the temperature the better.

For enhanced geothermal systems (EGS), the key is to assess thermal tolerance, flow rates and produced water temperatures; establish conductivity subsurface; and minimize energy loss as the fluid reaches the surface.

Technical challenges, however, have prevented some geothermal projects from taking off in the past. The Utah Frontier Observatory for Research in Geothermal Energy (FORGE)—the U.S. Department of Energy (DOE)-sponsored international field laboratory managed by the Energy & Geoscience Institute at the University of Utah—is working to change that as it forges public-private partnerships.

Utah FORGE’s partnerships include one with Norway-based RESMAN Energy Technology that specifically aims at tracking fluid movement and assessing connectivity between injection and producer wells at one of its drill sites. The company’s tracer technology, which is typically used in oil and gas reservoirs, was used in April during stimulation and circulation testing to help prove enhanced connectivity between the injection and producer wells in hot dry granite.

“FORGE’s obligation is to de-risk technologies and franchise new technologies in the geothermal industry, and this is how RESMAN came into play. They have sophisticated tracer technology that we particularly need,” John McLennan, the professor who oversaw the testing told Hart Energy. “All of this has to be done at a high temperature, where you have to have a stable … thermal tolerance, and longevity is the critical piece of the action here.”

Time for takeoff

Building and strengthening partnerships to help de-risk technologies is expected to play a vital role in scaling geothermal in the U.S. The nation has a goal of deploying 60 gigawatts of EGS and hydrothermal resources by 2050.

Unlike conventional geothermal, which doesn’t need much engineering to produce power by harnessing heat from naturally-occurring fractures in hot rock, next-generation geothermal energy systems such as EGS use existing oil and gas technologies to harness the Earth’s heat.

“Enhanced geothermal systems have been something that the community has been considering since the 1970s. And there were actually FORGE surrogates in the ‘70s at Fenton Hill, which is near Los Alamos National Laboratory,” McLennan said, calling the Fenton Hill hot dry rock program a pyrrhic victory.

“It was a technical success but an economic failure, and the reason for that largely was drilling technology,” he said.

Eight major wells were drilled and nearly 100 experiments were carried out related to acoustic wave propagation, flow testing, hydraulic fracturing and tracer testing during the Fenton Hill project, which ran from 1971 to 1995, according to the DOE.

While the program ultimately proved heat could be extracted and used for power, its early days were informal and carried out mostly by volunteers who lacked direct geothermal energy experience. Those volunteers later gained expertise and attracted legendary physicist Frank Harlow and federal funding to their efforts, according to an article published by Los Alamos’ National Security Science magazine.

Back then, “there was not the ability to directly drill wells, and the shale industry and directional drilling that spawned that industry has really made a difference now that you can drill and steer horizontal or sub-horizontal wells,” McLennan said. “The hydraulic fracturing technology is almost identical to what was used in the 1980s on some of these geothermal wells. But the drilling, the isolation technologies and the surveillance technologies have made a difference. This is why I think it’ll [geothermal] take off this time.”

Forging bonds

 “What the federal government has provided through FORGE is a platform to test out some of these new technologies and to enthuse vendors such as [RESMAN], entrepreneurs and investors to consider geothermal as something of having real viability, and I think [geothermal’s] getting there,” McLennan said.

It can sometimes be challenging to pioneer new technologies or applications in a commercial environment, especially where operators are also trying to pilot, innovate and explore new things, added Scott LaVoie, chief commercial officer for RESMAN.

“We have to be able to prove that we can bring value and we can deliver results and … FORGE is willing to give us a chance to do that,” LaVoie told Hart. “And then also you get to publish your results,” have honest conversations and share in the industry’s success. That is not something everyone is willing to do as they enter the market.

RESMAN used its chemical tracers, which essentially behave like the target fluid, to gain subsurface data during Utah FORGE’s testing in April. The tracers are uniquely identifiable. LaVoie compared it to an Apple airtag.

“We’re able to trace that water or uniquely tag that water and physically understand the mass transport of how that water is moving into the reservoir between the injector and the producer,” he explained. “And in doing that, you can then optimize your injection, your overall reservoir pattern” and improve reservoir knowledge to help uncover efficiencies. It also helps inform the connected surface area, “which is a big deal because the more surface area you have, the more water is going to be exposed directly to the reservoir heat.”

McLennan added the team wanted to look for fractures that take in the fluids, so a distinct tracer was used in each frac stage. “You want each fracture system to take fluid equally because if all of the fluid tends to go into one fracture system, then you’re going to have thermal depletion …. [and] cool down the reservoir.”

Over two weeks in April, commercial-scale stimulation was conducted on both wells to develop interwell connectivity. The production well was hydraulically fractured in eight stages with multiple tracers used. In all, the experiment used approximately 118,000 bbl of water.

Test results, released in late May, revealed connectivity was established, and hot water was produced during a circulation test following stimulation. Utah FORGE said temperature of the outflow water increased to about 282 F.

Looking ahead

The testing marked the first use of RESMAN tracers for EGS.

RESMAN is considering using its tracer technology for conventional geothermal as well, LaVoie said. It already has employed CO2 tracers as well as tracers used by the oil and gas sector.

“We have eight CO2 projects now that we’ve done all around the world and continue to talk to lots of the projects as they start to develop,” LaVoie said.

Utah FORGE is gearing up to renew its contract with the Energy Department, aiming for its next phase. Not knowing what future contractual obligations may hold, McLennan presumes more drilling may be forthcoming.

“I suspect that there’ll be a new well, drilled hotter and deeper, because temperature is everything in geothermal,” McLennan said. “The higher the temperature, the more efficient your heat production. The well that we stimulated still has half of its real estate available for additional fracs, and so we’ll carry out additional fracs.”

Hopes are that the learnings from the previous drilling campaign will be used to optimize future cluster spacing, injection and other protocols.