Advanced Geothermal (Closed Loop)

Closed-loop geothermal systems ("CLGSs") are an emerging next-generation geothermal technology that circulates a sealed working fluid through deep wellbores to extract subsurface heat via conduction, without requiring natural permeability, reservoir fluids, or hydraulic fracturing. Available in coaxial (tube-in-tube) and U-shaped (multilateral) configurations, CLGSs eliminate the induced seismicity risk, water consumption, and greenhouse gas emissions associated with conventional and enhanced geothermal systems. The technology was demonstrated at field scale by GreenFire Energy at the Coso geothermal field in California (2019–2020) and by Eavor Technologies with the Eavor-Lite™ multilateral closed-loop facility in Alberta, Canada (operating since 2019). Eavor-Lite™ validated the thermosiphon effect, achieved 96.2% uptime, and demonstrated thermodynamic performance within 2% of pre-drill predictions — transforming geothermal from an exploration-dependent resource into a predictable, manufactured energy system. A 2025 study in Nature Communications Earth & Environment estimated CLGS global potential at 9 TWe. However, the technology's reliance on conductive heat transfer limits power output per unit of wellbore, and drilling costs — representing 50–70% of capital expenditure — remain the primary barrier. A comprehensive 2024 multi-laboratory study (White et al.) found that competitive costs for direct heating applications are achievable, but competitive electricity costs require aggressive drilling cost reductions. The near-term commercial pathway is through district heating, with electricity generation expected to follow as drilling technology and costs improve.

Closed-loop geothermal systems ("CLGSs") evolved from decades of research into downhole heat exchangers and wellbore-based energy extraction. The foundational concept — circulating a working fluid through a sealed wellbore to extract subsurface heat without direct contact with reservoir fluids — emerged in the late 1970s when closed-loop designs began to compete with open-loop geothermal systems. In 1980, Horne proposed the downhole coaxial heat exchanger ("DCHE") concept for exploiting medium-deep geothermal resources, establishing the theoretical basis for modern CLGSs. Early experimental work followed in the late 1980s and early 1990s. Morita et al. (1992) conducted DCHE experiments in Hawaii, demonstrating that insulated inner tubing significantly improved heat extraction and that combining a DCHE with an Organic Rankine Cycle ("ORC") power system was technically feasible. In 1993, the first commercial DCHE operation was attempted in Weissbad, Switzerland, though outlet temperatures fell below simulated predictions, revealing challenges with thermal resistance at the cement-casing interface. These early setbacks led to improved understanding of thermal contact resistance and wellbore heat transfer dynamics. Despite these pioneering efforts, the technology was largely set aside during the 1990s and 2000s. The limited heat exchange surface area of a single wellbore constrained power output, and without advances in directional drilling, CLGSs could not compete economically with conventional geothermal or EGS approaches. Interest revived in the 2010s as oil and gas drilling techniques — particularly horizontal and multilateral drilling — became transferable to geothermal applications. GreenFire Energy, founded in 2014, began developing coaxial closed-loop technology (branded "GreenLoop") for retrofitting idle or underperforming hydrothermal wells. With support from the U.S. DOE and the California Energy Commission, GreenFire completed the world's first field-scale demonstration of closed-loop geothermal power at the Coso geothermal field in California in 2019-2020, testing both water and supercritical CO₂ ("sCO₂") as working fluids. The most significant milestone came with Eavor Technologies. The Canadian company began construction of the Eavor-Lite™ demonstration facility near Rocky Mountain House, Alberta in August 2019, completing it by early 2020. Eavor-Lite™ was the world's first multilateral closed-loop geothermal system — a U-tube shaped configuration with two 1.7 km horizontal multilateral wellbores connecting two 2.4 km deep vertical wells. The system validated the thermosiphon effect (passive heat-driven circulation without pumps), achieved 96.2% uptime, and demonstrated thermodynamic performance within 2% of pre-drill predictions. The Eavor-Lite™ project also pioneered the Rock-Pipe™ completion method, which chemically seals the wellbore without steel casing, reducing corrosion risk and extending system lifetime. In its first two years, Eavor-Lite™ produced approximately 11,250 MWh of thermal energy. Building on this success, Eavor partnered with Enex Power Germany in 2020 to develop the first commercial-scale Eavor-Loop™ project in Geretsried, Bavaria — a site where conventional geothermal wells had failed to deliver sufficient flow rates but conditions were well-suited for closed-loop technology. A 2024 working group study involving researchers from U.S. National Laboratories (Pacific Northwest, Sandia, Idaho, and NREL) published a comprehensive numerical investigation in Geothermics, running 2.5 million simulations of CLGS configurations. This landmark study by White et al. (2024) established the publicly accessible GeoCLUSTER web tool for techno-economic analysis and concluded that competitive levelized costs of heat are achievable, though competitive electricity costs require significant drilling cost reductions. In 2025, a Nature Communications Earth & Environment study estimated that CLGSs could provide a global energy potential of 9 TWe — equivalent to roughly 70% of current global electricity production — if fully tapped.

System Configurations

CLGSs circulate a working fluid through a sealed network of wellbores drilled into hot subsurface rock. The fluid absorbs heat by conduction from the surrounding rock formation and returns to the surface at elevated temperatures for power generation or direct-use heating. Unlike conventional geothermal systems that produce reservoir fluids directly, and unlike Enhanced Geothermal Systems ("EGS") that circulate fluid through artificially fractured rock, CLGSs keep the working fluid entirely contained within sealed piping. There is no fluid exchange with the surrounding geology. The system is best understood as a buried radiator or subsurface heat exchanger. There are two primary configurations in active development:

Coaxial (Tube-in-Tube) A coaxial CLGS uses a single vertical wellbore containing two concentric flow paths: an outer annulus and an insulated inner pipe. Cold working fluid is injected down the outer annulus, where it absorbs heat from the surrounding rock through the outer casing and cement interface. The heated fluid then reverses direction at the bottom of the well and ascends through the insulated inner pipe to the surface. The inner pipe must be thermally insulated — typically using vacuum insulated tubing ("VIT") — to prevent the hot ascending fluid from losing heat back to the cooler descending fluid in the annulus. The thermal conductivity of the VIT (measured as the k-value) is a critical design parameter: lower k-values mean less heat loss and higher production temperatures at the surface. The coaxial design is geometrically simpler than the U-shaped alternative, can be constructed with a single wellbore, and is particularly well-suited for retrofitting existing wells, including abandoned or underperforming oil and gas wells and inactive geothermal wells. GreenFire Energy's GreenLoop™ technology uses this configuration. The company's 2019 demonstration at Coso inserted a tube-in-tube heat exchanger to a depth of approximately 330 meters in an existing inactive geothermal well.

U-Shaped (Multilateral) A U-shaped CLGS comprises two vertical wellbores connected at depth by one or more horizontal (lateral) wellbores, forming a continuous U-tube circuit. Cold working fluid descends one vertical well (the injection well), traverses the hot lateral section(s) at depth, and ascends the second vertical well (the production well) at elevated temperature. The horizontal laterals provide the primary heat exchange surface area. Because the laterals are drilled through hot rock at a relatively constant depth and temperature, they offer a longer residence time for the fluid to absorb heat compared to a vertical-only design. Adding multiple laterals from the same pair of vertical wells — a multilateral configuration — increases the total contact area with hot rock while reducing the flow rate through each individual lateral, which improves per-lateral heat extraction and mitigates the temperature drawdown problem. Eavor Technologies' Eavor-Loop™ is the leading example of this design. The Eavor-Lite™ demonstration facility consists of two 2.4 km deep vertical wells connected by two 1.7 km long multilateral horizontal wellbores drilled within the Rock Creek formation. The laterals were drilled from both surface locations simultaneously using two drilling rigs, with the horizontal wells intersected at depth — a precision drilling achievement adapted from oil and gas directional drilling techniques. Eavor's commercial-scale designs envision systems with significantly more laterals and greater depths to achieve commercially viable power output.

Heat Transfer Mechanism

The fundamental physical distinction between CLGSs and all other geothermal technologies is the heat transfer mechanism. Conventional hydrothermal systems and EGS rely on convective heat transfer — hot reservoir fluids (water or steam) flow through natural or engineered fracture networks, carrying thermal energy to the surface through direct mass transport. This is efficient because the fluid is in direct contact with vast surface areas of hot rock within the fracture network, and convection moves heat much faster than conduction alone.

CLGSs, by contrast, rely predominantly on conductive heat transfer from the rock matrix through the wellbore wall into the circulating working fluid. The working fluid never contacts the reservoir rock directly. Heat must diffuse through the rock formation to the wellbore boundary, then transfer across the cement/casing/pipe interface, and finally into the fluid. This is a slower process governed by the thermal conductivity of the surrounding rock (typically 2–4 W/m·K for common formations), the thermal diffusivity of the rock mass, and the contact area between the wellbore and the formation.

This conduction-limited design has important performance implications. The rock immediately surrounding the wellbore is progressively cooled during operation as heat is extracted. Thermal energy replenishes from the broader rock mass, but this replenishment is governed by the slow rate of thermal diffusion through solid rock. Over time, the cooled zone around the wellbore expands outward, reducing the temperature gradient at the wellbore wall and thereby reducing the rate of heat extraction. This phenomenon — thermal drawdown — means that production temperatures decline over the operational life of the system, particularly at higher flow rates where heat is extracted faster than it can be replenished. This creates a fundamental flow rate vs. temperature tradeoff: higher flow rates extract more total thermal power but at lower fluid temperatures, while lower flow rates produce higher outlet temperatures but less total power. Finding the optimal flow rate for a given well geometry and geothermal gradient is a central challenge in CLGS design.

The White et al. (2024) multi-laboratory study found that in hot dry rock, where no natural fluid convection exists, the performance of CLGSs is entirely conduction-limited. However, in permeable "wet rock" formations (permeability greater than approximately 250 millidarcies), natural groundwater convection in the formation surrounding the wellbore can significantly enhance heat transfer to the CLGS, improving both thermal output and economic viability. This finding suggests that hybrid approaches — where CLGSs are deployed in formations with some natural permeability — may offer a middle path between pure closed-loop and conventional open-loop geothermal.

Wellbore Construction and Sealing

The integrity of the closed-loop seal is essential to CLGS operation. If fluid leaks from the wellbore into the surrounding formation, the system loses both working fluid and pressure, undermining the thermosiphon effect and reducing thermal efficiency. Conversely, if formation fluids enter the loop, they can introduce scaling, corrosion, and unpredictable chemistry.

Conventional geothermal wells use steel casing cemented into the wellbore. However, the lateral sections of multilateral CLGSs present unique challenges: steel casing in long horizontal sections is expensive, vulnerable to corrosion at geothermal temperatures, and difficult to install and cement over kilometer-scale distances. Eavor Technologies developed the Rock-Pipe™ completion method to address this. Rather than casing the lateral wellbores with steel, Rock-Pipe™ applies a chemical sealing compound that reduces the near-wellbore permeability of the rock formation to near-zero levels. In the Eavor-Lite™ demonstration, the in-situ permeability of the Rock Creek formation (estimated at 0.5–50 millidarcies) was reduced to 0.15–0.25 microdarcies after application of the Rock-Pipe™ compound — a reduction of several orders of magnitude. This creates a sealed, casing-free wellbore that is resistant to corrosion and scaling while maintaining the mechanical integrity needed for long-term operation. The elimination of steel casing also removes a significant cost component from the lateral sections, where drilling cost per meter is the dominant economic driver.

The Thermosiphon Effect

In CLGS designs with sufficient depth and temperature differential, the density difference between the cold descending fluid and the hot ascending fluid creates a natural circulation drive — the thermosiphon effect. Cold, dense fluid in the injection wellbore exerts a greater hydrostatic pressure at the bottom of the system than the hot, less dense fluid in the production wellbore. This pressure differential drives fluid circulation through the loop without requiring mechanical pumping, or with significantly reduced pumping requirements.

The thermosiphon effect is directly analogous to natural convection in a heating system: hot fluid rises because it is less dense, while cool fluid descends because it is denser. The strength of the thermosiphon is proportional to the depth of the system (greater depth means a longer column of fluid contributing to the pressure differential), the temperature difference between the injection and production sides, and the density-temperature relationship of the working fluid. The Eavor-Lite™ project validated this effect operationally, demonstrating that the system could circulate fluid without any mechanical pump, driven entirely by thermosiphon. The site has operated with thermosiphon-driven circulation since commissioning. For commercial-scale facilities, PLC logic will be programmed to modulate the flow rate to match electricity demand, enabling the system to function as a dispatchable, load-following resource.

Working Fluids

The choice of working fluid significantly affects CLGS thermal performance, thermosiphon strength, and surface power conversion efficiency.

Water Water is the most commonly used working fluid due to its high specific heat capacity (approximately 4.2 kJ/kg·K), wide availability, low cost, and well-understood thermodynamic behavior. Water's high heat capacity means it can absorb a large amount of thermal energy per unit mass, making it efficient for heat transport. However, water has limitations at extreme temperatures and pressures: at supercritical conditions (above 374°C and 22.1 MPa), its properties change dramatically, and at lower temperatures its density variation with temperature is moderate, limiting the thermosiphon driving force.

Supercritical CO₂ (sCO₂) Supercritical carbon dioxide has been investigated as an alternative working fluid because of several favorable thermodynamic properties. Near its critical point (31°C, 7.4 MPa), CO₂ exhibits large density changes with temperature, which can produce a stronger thermosiphon effect than water under certain conditions. sCO₂ also has lower viscosity than water, reducing frictional pressure losses in long wellbores. The White et al. (2024) national laboratory study found that sCO₂ can improve power output and economic performance in certain configurations, particularly for U-shaped systems in high-gradient regions where the temperature differential is large enough to exploit CO₂'s favorable density-temperature relationship. GreenFire Energy's Coso demonstration tested both water and sCO₂ in a coaxial configuration, confirming that both fluids are effective for heat extraction. However, sCO₂ introduces additional engineering complexity: it requires hermetic sealing to prevent leaks (CO₂ is a greenhouse gas), specialized materials compatible with carbonic acid corrosion at high temperatures, and a surface power conversion system designed for supercritical fluid conditions.

Other Fluids Researchers have also investigated organic working fluids such as isobutane and n-butane, particularly for integration with Organic Rankine Cycle power plants. These fluids can remain liquid at higher temperatures than water at equivalent pressures, potentially simplifying the surface conversion system. However, they introduce flammability risks, higher costs, and environmental concerns that have limited their adoption in practice. Nalla et al. (2005) studied the impact of working fluid properties on coaxial CLGS performance and concluded that water provides the best overall heat production characteristics for most configurations.

Surface Power Conversion and Direct Use

At the surface, the heated working fluid exiting the production well transfers its thermal energy to either a power conversion system or directly to a heat distribution network. The choice of surface system depends on the fluid temperature, which is determined by the reservoir temperature, well depth, lateral length, flow rate, and insulation quality.

Direct-Use Heating For CLGS producing fluid temperatures in the range of 60–150°C, direct-use heating applications are the most thermally and economically efficient pathway. The hot working fluid passes through a surface heat exchanger, transferring thermal energy to a secondary distribution loop (typically hot water) for district heating, greenhouse heating, aquaculture, industrial process heat, or building HVAC systems. Direct-use applications avoid the significant thermodynamic losses associated with converting heat to electricity and can achieve overall system efficiencies exceeding 90%. The White et al. (2024) study found that competitive levelized costs of heat are achievable with current CLGS technology, particularly in regions with moderate-to-high geothermal gradients, making direct-use heating the most commercially viable near-term application.

Organic Rankine Cycle (ORC) Power Generation For electricity generation from CLGS, an Organic Rankine Cycle is typically employed. Production temperatures from CLGSs are generally in the range of 100–200°C — below the threshold for efficient conventional steam turbine operation but well-suited for ORC systems. An ORC works on the same thermodynamic principle as a conventional steam Rankine cycle but substitutes a low-boiling-point organic working fluid (such as isopentane, isobutane, or R-245fa) for water. The geothermal fluid heats the ORC working fluid in a heat exchanger (the evaporator), causing it to vaporize at a lower temperature than water would. The vapor expands through a turbine to generate electricity, is then condensed, and recycled. ORC systems are commercially mature and widely deployed in binary geothermal power plants worldwide. However, the Carnot efficiency of these systems is inherently limited by the relatively low temperature differential between the heat source and the condenser, resulting in net thermal-to-electric conversion efficiencies typically in the range of 10–15%.

Supercritical CO₂ Power Cycles When sCO₂ is used as both the subsurface working fluid and the surface power cycle fluid, the system can potentially achieve higher conversion efficiencies than ORC at equivalent temperatures. sCO₂ power cycles operate at high pressures and densities, allowing for compact turbomachinery. However, these systems remain at earlier stages of commercial readiness compared to ORC technology.

Hybrid and Cascaded Configurations Some proposed designs use cascaded energy extraction, where high-temperature heat is first used for electricity generation via ORC or sCO₂ cycles, and the remaining lower-temperature heat is then directed to district heating or industrial process heat applications. This cogeneration approach maximizes the total energy utilization from the geothermal resource and improves overall project economics by generating revenue from both electricity and heat sales.

CLGSs offer several structural advantages over both conventional hydrothermal systems and enhanced geothermal systems ("EGS"), the two incumbent approaches to geothermal energy extraction.

Independence from Geology

Conventional geothermal requires the co-location of three geological conditions: high subsurface temperatures, sufficient permeability, and natural fluid (water or steam). EGS relaxes the permeability requirement by using hydraulic fracturing to create artificial pathways but still requires subsurface water and carries exploration risk. CLGSs eliminate all three dependencies. Because the working fluid is entirely contained within sealed wellbores, CLGSs can operate in hot dry rock with no natural permeability or fluid. This makes geothermal energy accessible in geographically common warm sedimentary basins — including regions where oil and gas operations are co-located — rather than being restricted to volcanic hotspots or tectonically active zones.

Elimination of Induced Seismicity Risk

EGS projects have been associated with induced seismicity due to hydraulic fracturing and high-pressure fluid injection into fractured rock formations. The 2006 Basel, Switzerland EGS project was suspended after triggering a magnitude 3.4 earthquake, and public opposition to induced seismicity remains a significant barrier to EGS deployment. CLGSs do not require reservoir stimulation, hydraulic fracturing, or fluid injection into the formation, fundamentally eliminating this risk.

Environmental and Operational Advantages

Because CLGSs are hermetically sealed, they produce no greenhouse gas emissions during operation, no produced brine or solids, no aquifer contamination, and require essentially no water consumption. Conventional and EGS geothermal can emit CO₂ and H₂S dissolved in geothermal fluids and face challenges with scaling, corrosion, and disposal of geothermal brine. The closed-loop design avoids all of these.

Predictability and De-risked Development

Perhaps the most commercially significant innovation is the removal of subsurface exploration risk. Conventional geothermal and EGS projects face large initial uncertainty — even after years of operation, there remains substantial risk of precipitous output decline due to reservoir depletion, cold-water breakthrough, or short-circuiting. The Eavor-Lite™ demonstration showed that closed-loop thermodynamic performance can be predicted accurately prior to drilling, with measured results within 2% of simulated predictions. This transforms geothermal from an exploration-dependent resource into a "manufactured" resource amenable to standardized, repeatable deployment — analogous to the manufacturing scale-up model that drove cost declines in wind and solar.

Dispatchability and Load-Following

CLGSs offer firm, baseload power with the additional capability of load-following. During periods of low demand, the system can reduce production and store thermal energy in the subsurface rock for extraction during peak demand. The Eavor-Lite™ project successfully demonstrated a machine-learning-based load-following algorithm that tracked a solar/wind "duck curve" demand profile, positioning CLGSs as a potential "zero-emitting load-following resource" (ZELFR) — a critical capability for grids with high renewable penetration.

The deployment of CLGSs faces interconnected challenges spanning drilling economics, thermal physics, materials science, and regulatory frameworks.

Drilling Cost

Drilling represents the dominant cost driver for CLGSs, potentially accounting for 50–70% of total project capital expenditure. Because CLGSs rely on conductive heat transfer through a limited wellbore surface area, they require deep wells (typically 2–5+ km) and long lateral sections to achieve commercially viable power output. The White et al. (2024) study found that even at an optimistic drilling cost of $500/m — below current NREL cost curves — CLGSs in hot dry rock could not achieve the DOE's target of $45/MWhe by 2035. Their modeling suggested that lateral lengths approaching 100 km may be necessary to reach economically viable electricity costs. The Tangirala & Vilarrasa (2025) study in Nature Communications Engineering reinforced this finding, showing that for reservoir temperatures of 180°C, total revenue from CLGSs failed to recover lifetime costs even with 30 multilateral wellbores. Reducing drilling costs through faster drilling rates, improved bit technology, and manufacturing-style repetition is considered essential for commercial viability.

Conduction-Limited Heat Transfer

The fundamental thermal limitation of CLGSs is their reliance on heat conduction rather than convection. The rock surrounding the wellbore cools progressively during operation, and thermal energy replenishes slowly from the broader rock mass. This leads to production temperature decline over time, particularly at high flow rates. High flow rates cause a steep drop in production temperatures due to rapid cooling of the rock matrix surrounding the wells. Multiple studies show that increasing the number and length of lateral wellbores is the primary mitigation strategy, but this directly compounds the drilling cost challenge. Some researchers have proposed hybrid approaches — injecting thermally conductive materials into the surrounding formation to improve "thermal reach" — but these remain at early research stages.

Vacuum Insulated Tubing Performance

In coaxial CLGS designs, the performance of vacuum insulated tubing (VIT) is critical to prevent heat loss from the hot ascending fluid to the cool descending fluid. Achieving and maintaining low thermal conductivity (k-values) under real-world conditions — including temperature fluctuations, mechanical stress, gas composition in the vacuum space, and manufacturing variability — introduces significant uncertainty. As noted in recent Geothermal Rising Conference proceedings, accurate K-value estimation remains challenging, and inconsistencies in insulation performance across different tubulars persist. Ongoing testing programs are developing improved test benches to measure k-values at multiple temperatures and flow rates.

Material Durability at Depth

Deep CLGS operations expose wellbore materials to high temperatures (potentially 200°C+), high pressures, and thermal cycling over decades-long project lifetimes. Cement degradation, casing corrosion (where used), and thermal fatigue of piping materials are ongoing concerns. Eavor's Rock-Pipe™ technology addresses one aspect by chemically sealing the wellbore without steel casing, but long-term durability data remains limited to the approximately five years of Eavor-Lite™ operation.

Regulatory and Permitting Gaps

Geothermal development — particularly next-generation approaches like CLGSs — often lacks dedicated regulatory frameworks. In many jurisdictions, geothermal projects must navigate permitting processes designed for oil and gas, mining, or water extraction, none of which cleanly fit a closed-loop system that produces no emissions, uses no water, and does not interact with subsurface fluids. Alberta, for example, still lacks specific geothermal and distributed energy regulations, presenting a barrier to commercial deployment in the province despite being home to the Eavor-Lite™ demonstration. Establishing fit-for-purpose regulatory pathways is a precondition for scaling.

Economic Viability: Heat vs. Electricity

A critical distinction in CLGS economics is the difference between heat and electricity applications. The White et al. (2024) study found that competitive levelized costs of heat (LCOH) are achievable with current technology, particularly for district heating applications in regions with moderate-to-high geothermal gradients. However, competitive levelized costs of electricity (LCOE) are not achievable without significant — described as "very aggressive" — reductions in drilling costs. This means that the near-term commercial pathway for CLGSs is likely through direct-use heating applications, with electricity generation becoming viable as drilling technology matures and costs decline.