Is Closed-Loop Geothermal The Future of Heat & Power, or Just a Niche Play? – CleanTechnica

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Geothermal energy has long been the quiet workhorse of the clean energy sector—steady, reliable, and utterly unsexy compared to its flashier solar and wind counterparts. It’s also been stubbornly constrained by geography. Traditional geothermal requires naturally occurring underground reservoirs of hot water and steam, which means it’s only viable in regions with active tectonic activity—think Iceland, California, and parts of Indonesia. That limitation has kept it a niche player in the energy mix, despite its promise of 24/7 clean power.

As a note, this is one in a series of articles on geothermal. The scope of the series is outlined in the introductory piece. If your interest area or concern isn’t reflected in the introductory piece, please leave a comment.

Enter closed-loop geothermal, a fundamentally different approach that doesn’t need volcanic hotspots or naturally occurring reservoirs. Instead, it involves drilling sealed wells into hot rock, circulating a working fluid through them to absorb heat, and extracting that energy for direct use or electricity generation. This approach reduces exploration risk, seismicity concerns, and water depletion issues that plague conventional and enhanced geothermal. More importantly, it can theoretically be deployed anywhere, transforming geothermal from a geographically limited resource into a globally scalable one.

Of course, theory and commercial reality are two very different things. Closed-loop geothermal isn’t yet a major player in the energy mix, and despite the recent flurry of investment and pilot projects, it still faces substantial technical and economic hurdles. The big question: will it ever be cost-competitive with other renewables, or is it destined to be a niche solution for district heating with some power generation on the side?

Eavor: The Standard-Bearer of Closed-Loop Geothermal

Among the companies pushing this technology forward, Eavor Technologies is the most visible, best-funded, and furthest along the path to commercialization. The Canadian firm has branded its approach as the Eavor-Loop, a self-contained underground heat exchanger with two vertical wells connected by multiple horizontal laterals, forming a massive radiator-like structure beneath the Earth’s surface. Unlike traditional geothermal, which relies on high-permeability reservoirs to move hot fluids, Eavor’s system extracts heat purely by conduction, using a proprietary sealing technique (Rock-Pipe) to prevent fluid loss and optimize heat transfer.

Eavor built its first pilot, Eavor-Lite, in Alberta in 2019—a two-well system with laterals stretching nearly 2 km in length. The results were encouraging: the loop functioned as designed, operating on a thermosiphon principle that eliminated the need for pumping, and successfully delivering steady thermal output with no decline over four years of operation. More recently, the company drilled Eavor-Deep in New Mexico, proving it could reach ultra-deep (5.5 km) high-temperature rock while maintaining well integrity.

The thermosiphon approach relies on the natural circulation of fluid due to temperature-driven density differences, eliminating the need for mechanical pumps. As the working fluid absorbs heat from deep underground rock, it expands and rises through the well, while cooler, denser fluid sinks to replace it, creating a continuous convective loop. This passive circulation reduces operational energy costs and enhances reliability by minimizing moving parts.

Eavor’s first commercial-scale project, Geretsried in Germany, is now under construction. This 8 MW electrical / 60 MW thermal plant is intended to supply both power and district heating—an economic necessity, given that closed-loop geothermal’s biggest challenge is achieving an attractive levelized cost of electricity (LCOE).

Eavor has consistently marketed its technology as a firm, dispatchable clean energy source, but the reality is that geothermal power production comes with inherent conversion losses. Unlike wind or solar, where nearly all captured energy is converted into electricity, geothermal typically converts only 10-15 percent of the thermal energy into usable power. That means an Eavor-Loop producing 60 MW of heat will only generate around 8 MW of electricity—a crucial factor when evaluating costs.

The projected levelized cost of heat (LCOH) for closed-loop geothermal is around $15 per MWh, making it a competitive option for district heating, particularly in markets with high natural gas prices or carbon pricing. In Europe, where natural gas heating costs typically range between $30 and $60 per MWh, geothermal could offer a lower-cost, stable alternative, especially as carbon taxes increase. In North America, where natural gas heating can be as low as $15 to $25 per MWh, geothermal heat may struggle to gain market share without policy support or long-term pricing stability. Compared to heat pumps, which operate at an effective LCOH of $25 to $50 per MWh depending on electricity costs and climate, closed-loop geothermal could be a more reliable and cost-effective solution in colder regions where heat pump efficiency declines.

However, when converting geothermal heat to electricity, the economics become more challenging. The levelized cost of electricity (LCOE) for closed-loop geothermal is estimated at $70 per MWh, significantly higher than wind ($30 to $50 per MWh) and solar PV ($20 to $40 per MWh). This means that while geothermal electricity may remain a niche player unless drilling costs fall dramatically, its strongest economic case lies in direct heat applications for district heating and industrial processes, where it can undercut fossil fuels and complement heat pumps in certain climates.

Eavor’s cost trajectory is similar to early shale gas and solar: expensive at first, with expected reductions over time. However, those cost reductions hinge on significant drilling efficiencies—essentially applying oil and gas drilling techniques to reduce lateral drilling costs below $400 per meter. If that learning curve materializes, Eavor could hit its LCOE target and compete with firm renewables like nuclear and enhanced geothermal systems (EGS). If not, it will remain a high-cost niche solution.

Eavor’s experience with thermal drawdown provides some early indications that their system can maintain stable output, but long-term performance remains an open question. At Eavor-Lite, the system initially produced fluid at around 78°C, but over four years of continuous operation, the outlet temperature stabilized at 50°C. While this suggests a predictable cooling curve, it also highlights the challenge of sustained high-temperature output. The company has modeled thermal replenishment over multi-decade timescales, arguing that wider spacing between laterals and proper flow rate management can mitigate drawdown effects.

However, real-world data beyond a single-digit number of years is still lacking. The Geretsried project in Germany, set to be Eavor’s first commercial-scale deployment, will provide more concrete data, as it involves deeper wells (~5 km) and significantly higher thermal demand. Until larger and longer-running systems confirm sustained output, thermal drawdown remains a key risk that could impact the economics of closed-loop geothermal.

Drilling costs are the make-or-break factor for closed-loop geothermal, and right now, they remain a towering economic hurdle. Scaling up this technology means drilling deeper and extending laterals further into hot rock, but high-temperature drilling is expensive, slow, and fraught with technical challenges. Unlike the oil and gas industry, where horizontal drilling has become routine, geothermal wells face extreme heat, abrasive rock formations, and pressure conditions that wear down drill bits and drive up costs.

Eavor has pinned its hopes on parallel drilling techniques and proprietary lateral well-sealing (Rock-Pipe) technology, arguing that these innovations will streamline construction and cut costs. In theory, Rock-Pipe eliminates the need for traditional casing in the laterals, reducing materials costs and allowing longer wellbores. The question is whether these efficiencies will be enough to bring drilling costs in line with the aggressive price targets needed for commercial viability.

To hit a competitive LCOE of $70 per MWh, Eavor and other closed-loop geothermal developers need to drive down lateral drilling costs below $400 per meter. For context, current oil and gas drilling costs often exceed $1,000 per meter in complex wells, and geothermal adds another layer of difficulty due to heat stress on equipment. If Eavor can achieve its cost reduction targets, its technology might become a viable competitor in niche applications. If not, it remains stuck in the pilot phase, with the economics failing to justify large-scale investment. The Geretsried project in Germany, Eavor’s first commercial-scale plant, will be the proving ground for these cost assumptions. If drilling overruns sink that project’s economics, it could signal that closed-loop geothermal still needs another decade of might-never-arrive cost improvements before it can compete with wind, solar, or even enhanced geothermal systems (EGS) that tap into natural permeability.

Rock-Pipe is the company’s secret sauce for making closed-loop geothermal economically viable, or at least that’s the bet. In conventional oil, gas, and geothermal drilling, wellbores are lined with steel casing to prevent fluid loss and maintain structural integrity. That works fine for vertical wells but becomes prohibitively expensive for the long, winding lateral sections that Eavor needs to maximize heat transfer. Rock-Pipe eliminates the need for conventional casing by chemically sealing the open lateral wellbore with a proprietary formulation, effectively turning the surrounding rock into an impermeable, self-supporting pipe.

While Eavor keeps the exact chemistry under wraps, the approach likely involves silicate-based or polymer-enhanced sealants that react with subsurface minerals to form a hardened, low-permeability layer along the wellbore walls. This prevents working fluid loss and mitigates interaction with the surrounding formation, addressing a key challenge in deep geothermal wells. Some experimental studies in oil and gas suggest geopolymer-based sealants—derived from aluminosilicates like fly ash or metakaolin—could serve a similar function, offering high-temperature stability, chemical inertness, and resistance to thermal cycling. Rock-Pipe’s role is critical because any fluid loss in a closed-loop system directly impacts efficiency and increases operational costs. If the seal isn’t perfect, the system risks gradual performance degradation, forcing expensive remediation or re-drilling.

The question is whether Rock-Pipe will hold up under decades of heat stress. In traditional geothermal, scaling and mineral deposition from hot brine can gradually clog production wells, and while Eavor’s system avoids fluid interaction with the formation, any mechanical breakdown of the sealed layer could create pathways for unwanted heat dissipation or fluid leakage. The Eavor-Lite pilot has shown 99.9% sealing integrity over four years, which is promising, but scaling this to deeper, multi-lateral wells—such as in the Geretsried project, where well depths exceed 5 km—will be the real test. If Rock-Pipe holds up, it could be a breakthrough for making deep, long-lateral geothermal wells feasible. If it degrades under high thermal stress, the economics of closed-loop geothermal start looking a lot shakier.

That they are touting supercritical CO2 is a concern. Supercritical CO₂ for power generation is another overhyped, overcomplicated, and unnecessary technology being pushed by the usual crowd that loves complexity for complexity’s sake. The basic idea is to use supercritical CO₂ instead of steam in thermal power plants, promising higher efficiency and smaller turbine sizes. The reality, though, is that this idea has been floating around since 1948, and in 75 years, it still hasn’t made it past a handful of lab prototypes. That’s a giant red flag. If a technology has been tinkered with for decades and still isn’t commercial, it usually means the physics, economics, or both just don’t work.

The technical challenges are severe. Supercritical CO₂ is corrosive, dense, and requires extreme materials to withstand high pressures and temperatures without micropitting or failure. Unlike steam, which power engineers have had 150 years to refine, CO₂ in its supercritical phase creates a whole new set of engineering headaches, from material degradation to unexpected thermal expansion issues. Bolting a novel generation technology onto a novel drilling technology onto a novel bore-sealing technology is multiplying risks, not accelerating success.

The economic sweet spot for Eavor is not electricity but rather district heating and industrial heat applications, where the system’s efficiency and cost structure align more favorably. Those applications can use nearly all of the extracted heat directly, avoiding conversion losses and making full use of the system’s thermal output. Many European district heating networks already operate with supply temperatures between 70 and 120 degrees Celsius, which aligns well with the output of closed-loop geothermal systems. Similarly, industrial processes in food production, textiles, and chemical manufacturing require stable mid-temperature heat, making them ideal customers for a technology that delivers continuous, emission-free thermal energy. In these markets, Eavor can sidestep the efficiency penalty associated with power generation and compete more directly with natural gas heating, particularly in regions where carbon pricing makes fossil fuel alternatives increasingly expensive.

The Other Closed-Loop Contenders

Eavor isn’t alone in this race. Several other companies are pursuing different variations of closed-loop geothermal, each with unique technological approaches and target markets.

GreenFire Energy is advancing its GreenLoop system, a closed-loop geothermal technology designed to repurpose existing geothermal or oil and gas wells. The company has successfully demonstrated the technology in its pilot at Coso, California, where it inserted a coaxial heat exchanger into a 200-degree Celsius well to extract thermal energy. This approach allows it to use  supercritical CO₂ (again) or water as a working fluid, making it an incremental improvement to existing infrastructure rather than a completely new development.

GreenFire is currently at a technology readiness level of 6 to 7, having proven the feasibility of its system but not yet achieving full commercial deployment. Its primary target market includes existing geothermal fields and stranded wells that lack sufficient permeability for traditional geothermal extraction. While the technology has shown promise, its scalability is uncertain, as it depends on the availability of suitable well sites. The next major step for the company is moving beyond pilot projects to a full-scale retrofit deployment.

GreenFire’s GreenLoop system is a single-well coaxial heat exchanger inserted into existing geothermal or oil and gas wells. It circulates a working fluid, allowing it to extract heat even from stranded geothermal resources. Unlike Eavor, GreenFire’s approach is more about incremental improvements to existing infrastructure rather than a complete reinvention.

A key challenge for GreenFire Energy’s closed-loop geothermal approach is scalability, as it is best suited for retrofitting existing geothermal wells rather than developing entirely new fields. Inserting a heat exchanger into underperforming wells allows it to extract thermal energy even from wells that lack sufficient natural permeability for conventional geothermal production. While this approach significantly reduces drilling costs and eliminates the need for finding high-permeability reservoirs, it also limits deployment to locations where wells already exist. This means GreenFire’s addressable market is largely constrained to regions with stranded geothermal resources or aging oil fields, rather than truly global scalability.

Despite this limitation, GreenFire has demonstrated its technology in a successful field pilot at Coso, California, where it installed a closed-loop system inside an idle geothermal well with a bottom-hole temperature of around 200 degrees Celsius. The system circulated water and later supercritical CO₂ as working fluids, proving that heat could be extracted efficiently even in a well that was otherwise unproductive. The next step for GreenFire is moving beyond pilot demonstrations to a full-scale commercial retrofit, where it can validate the system’s long-term performance and economic feasibility. However, without the ability to drill new closed-loop wells at scale, its market remains tied to existing infrastructure rather than a broader push to deploy geothermal anywhere.

Sage Geosystems takes a hybrid approach to closed-loop geothermal, combining subsurface heat extraction with geopressured energy storage, a novel but largely unproven concept at scale. The idea is deceptively simple: inject fluid under high pressure into deep rock formations, temporarily storing both thermal and mechanical energy, then release it later to generate dispatchable power. Unlike traditional geothermal, which passively extracts heat from underground, Sage’s system actively cycles fluid in and out of the formation, leveraging both temperature and pressure gradients. This allows for on-demand energy output, a feature that could make it highly valuable in high-renewable grids where firming capacity is in short supply.

Their first test well in Texas demonstrated a 3 MW energy storage capability, but critical details remain scarce. The pressure levels required for effective storage are likely in the range of hundreds of atmospheres, depending on the permeability and elasticity of the formation. If the system relies on artificial fractures to enhance storage capacity, it edges closer to enhanced geothermal systems (EGS) rather than pure closed-loop, which introduces additional regulatory and operational challenges. The biggest technical unknown is whether repeated pressurization and depressurization cycles will degrade the reservoir’s ability to store energy over time.

While Sage has secured $17 million in funding from Breakthrough Energy Ventures, a sign that investors see promise in its approach, the company has yet to demonstrate continuous geothermal power production at a meaningful scale. Its focus remains on Texas oil and gas fields, leveraging existing drilling expertise and subsurface data to refine its technology. Whether Sage can transition from an interesting niche technology to a commercially viable energy solution will depend on its ability to prove durability, efficiency, and economic competitiveness against more established storage and generation options.

I’ve written before about the fundamental flaws in the idea that fracking the same underground volume over and over is a viable form of energy storage. Sage Geosystems’ approach fits squarely into that category of physics-defying wishful thinking. The problem is simple: underground formations aren’t elastic balloons waiting to store and release energy on demand. When you pressurize fractured rock, you’re not creating a flexible, rechargeable storage system—you’re just temporarily forcing fluid into cracks, hoping they hold pressure long enough to extract useful energy later. But every time you cycle the pressure up and down, you degrade the system, altering the permeability, redistributing stresses, and risking irreversible collapse of the fractures over time.

This isn’t storage in any meaningful sense—it’s an expensive, lossy, and mechanically destructive way to pretend deep rock is a battery. Unlike compressed air storage in salt caverns, which use naturally sealing formations, (albeit low efficiency round trip storage) or pumped hydro, where water is physically stored at elevation, Sage’s concept relies on unpredictable, high-pressure manipulation of rock that wasn’t designed for cycling.

And let’s not forget induced seismicity—every time you alter underground pressure gradients, you risk triggering earthquakes, a problem that has plagued fracking operations across North America. Even if Sage somehow overcomes these fundamental physical challenges, its business model will still run headlong into the reality that grid-scale storage is already dominated by proven, scalable solutions with much lower risks and better efficiencies. Simply put, this isn’t the future of energy storage—it’s just another oil and gas industry fantasy trying to repurpose fracking tech into something palatable for the energy transition.

CeraPhi Energy is betting that old oil and gas wells can be turned into reliable geothermal heat sources, but that assumption runs into a host of technical and economic hurdles that could limit its scalability. Their CeraPhiWell system is a modular heat-extraction setup designed for district heating and industrial processes, meaning it sidesteps the inefficiencies of converting low-temperature heat into electricity. That’s a smart move—direct heat use is the strongest economic case for closed-loop geothermal. But the fundamental question remains: how many old wells actually have enough heat and are located near real heat demand?

Most oil and gas wells simply aren’t drilled deep enough to provide the kind of sustained heat output needed for competitive geothermal energy. In the UK and North Sea, where CeraPhi is focusing, well depths typically range from 2 to 4 kilometers, which might yield fluid temperatures between 50 and 120 degrees Celsius. That’s barely enough for efficient district heating, let alone industrial heat applications that demand sustained high temperatures. Worse, many of these wells were drilled into formations that aren’t particularly thermally conductive, meaning they won’t replenish heat quickly once a closed-loop system starts extracting it. This could lead to rapid temperature declines—a fatal flaw for long-term viability.

Then there’s the issue of location. While there are millions of oil and gas wells globally, only a fraction are situated close enough to cities or industrial heat users to make repurposing viable. In the UK alone, there are around 2,000 decommissioned oil and gas wells, but most of them are in offshore North Sea fields, far from any district heating infrastructure. The same issue applies in North America, where the largest oil and gas fields tend to be in Texas, Alberta, and the Gulf Coast, regions that lack major district heating networks. Industrial users are more dispersed, and while some oil fields are near refineries and chemical plants, there’s little alignment between abandoned wells and large-scale industrial heat demand.

Even if the thermal conditions are favorable and a well is in the right location, there’s the problem of well integrity. Oil and gas wells aren’t designed for multi-decade heat cycling, and many have degraded cement casings, potential leaks, and structural weaknesses after years of extraction. Converting them into geothermal wells isn’t as simple as inserting a closed-loop pipe and calling it a day—it requires expensive well remediation, cementing, and possibly re-drilling sections to ensure longevity. That means the real cost per megawatt of heat may not be much lower than drilling a new, optimized geothermal well, undermining the entire economic premise of repurposing them in the first place.

CeraPhi has launched early pilot projects in the UK and North Sea, but until those demonstrate sustained heat output and cost-effectiveness over multiple years, the business case remains shaky. The company is selling a compelling narrative—turning fossil fuel liabilities into clean energy assets—but whether that narrative holds up against the physics of heat transfer, the economics of well remediation, and the geographic realities of heat demand is still an open question.

Black Swans And Closed Loop Geothermal

Closed-loop geothermal isn’t just facing standard technology commercialization hurdles—it’s riddled with long-tailed risks — black swans — that make scaling up a slow, capital-intensive, and inherently uncertain process. Bent Flyvbjerg’s research on megaproject failures warns about the iron law of project overruns—”over budget, over time, over and over again”—and geothermal drilling checks all the right boxes for cost and timeline blowouts. Unlike wind and solar, which benefit from modularity and predictable, short build times, geothermal requires multi-year development cycles, deep drilling in unpredictable formations, and massive upfront investment with uncertain payback periods. That’s a recipe for risk stacking, where a single bad drilling outcome, thermal depletion, or unexpected well failure can turn a promising project into a financial black hole.

Underground drilling is the most obvious risk multiplier. Even in oil and gas, where drilling technology is mature and decades of subsurface data exist, wells still run over budget, take longer than expected, and occasionally just don’t work. Now take that uncertainty and apply it to a new field like closed-loop geothermal, where the industry is trying to push deeper, longer laterals, and novel sealing techniques like Eavor’s Rock-Pipe—all without the benefit of existing large-scale deployments to prove long-term performance. High-temperature formations are brutal on drill bits and equipment, leading to nonlinear cost increases the deeper you go, while subsurface surprises—unfavorable rock conditions, permeability issues, or heat loss pathways—can derail even the most well-planned projects. And once a well is drilled, it’s not always clear that it will maintain heat output over decades, which adds another layer of long-term financial risk.

Then there’s the first-of-a-kind (FOAK) risk—the classic killer of ambitious energy projects. Every new closed-loop geothermal deployment is a high-stakes, multi-year experiment where small failures compound into major financial hits. The Geretsried project in Germany is set to be Eavor’s first true commercial-scale test, but it’s still just one site. Even if it works, scaling geothermal isn’t like building a solar farm—you can’t copy-paste a working design from one geological formation to another and expect identical results. Each deployment is a bespoke project, meaning lessons learned don’t translate into cost reductions as quickly as they do for factory-built renewables. And with project durations stretching from five to ten years from conception to operation, investors have to sit on capital for an uncomfortably long time before seeing any returns. This isn’t a software business—it’s a deeply physical, capital-intensive, and geologically constrained industry with failure points that won’t reveal themselves until years down the line.

Flyvbjerg’s framework tells us that closed-loop geothermal is the perfect candidate for optimism bias—everyone involved underestimates costs, overestimates performance, and assumes risk mitigation strategies will work better than they actually do. The industry is still betting on cost reductions through drilling efficiencies and better heat extraction techniques, but those assumptions rest on uncertain geological conditions, long development timelines, and unproven financial models. The idea of scalable geothermal heat and power is compelling, but it’s fighting against the very nature of deep drilling economics. Without serious breakthroughs in drilling speed, lateral well sealing, and cost predictability, closed-loop geothermal risks getting stuck in the valley of death between promising pilots and scalable deployment—a fate that has sidelined plenty of other energy technologies before it.

Closed Loop Is Just Ground Source Geothermal Heat

At this stage, the grand vision of closed-loop geothermal as a firm, global baseload power source is still aspirational. The technology works, but whether it will ever be cost-competitive with wind, solar, and batteries for electricity generation is an open question, but is unlikely in my opinion.

Where closed-loop geothermal could shine is in district heating, where its steady, predictable output aligns perfectly with seasonal demand, but that’s what ground source geothermal does already. Eavor, CeraPhi, and GreenFire have all targeted municipal heating grids, recognizing that heat delivery is a far better economic proposition than electricity generation. Unlike power plants, which must deal with the inefficiencies of converting moderate-temperature heat into electricity, district heating networks can directly use the geothermal output with minimal losses. In Europe, where heating accounts for a substantial share of energy demand and where gas prices are volatile, these systems could provide a stable, long-term alternative to fossil fuels.

Industrial process heat is another logical application, especially if these firms can economically get to higher heat levels further below the surface than traditional ground source heat facilities. Industries such as food processing, textiles, and chemical manufacturing require consistent high-temperature heat, making them ideal candidates for geothermal integration. Closed-loop geothermal, especially combined with heat pumps to uplift the heat further, could provide direct heat with limited conversion losses, making it an attractive decarbonization tool for industries facing mounting pressure to reduce emissions.

If closed-loop geothermal finds its footing as a district or industrial heating solution first, it might establish a profitable foundation to fund deeper, hotter projects that eventually become competitive in power markets. The ultimate prize is a world where geothermal isn’t constrained to the lucky few countries with volcanoes—but for now, the immediate opportunity lies in heat, not electrons.