Stanford Geothermal WorkshopFebruary 9-11, 2026

Drilling mud is a critical component in geothermal well planning, where environmental sustainability and economic feasibility are key considerations. Conventional additives often come with significant costs and environmental impacts. The commercial calcium carbonate (CaCO₃) is an established weighting/fluid-loss control agent added to the water-based mud (WBM), valued for its thermal stability (maintaining structure and rheological behavior up to 120 °C in HPHT tests), compatibility with barite/bentonite/xanthan systems, and its ability to form thin, low‐permeability filter cakes that reduce fluid invasion. As waste eggshells are composed of ⁓70-95% CaCO₃ (mostly calcite form) and are an abundant agro-industrial waste, this study analyzes and defends the use of waste eggshells (finely ground, less than 125 µm) as a low-cost, sustainable alternative to commercial CaCO₃ in geothermal drilling fluid systems. As part of the methodology, the WBM samples were prepared using standard additives (barite, bentonite, and xanthan gum). Eggshell powder and, for comparison, commercial CaCO₃ were added to the base mud at increasing concentrations (10 g, 20 g, 30 g, and 40 g). Laboratory tests measured mud density, plastic viscosity (PV), yield point (YP), gel strength, pH, resistivity, and filtration characteristics (filtrate volume and filter cake thickness). Results demonstrate that eggshell powder performs comparably to commercial CaCO₃, showing a near-linear increase in mud density and PV correlating with concentration. Eggshell powder effectively enhanced mud stability by promoting optimal (10 min) gel strength and reducing filtrate volume through rapid formation of thin, low-permeability mud cake, matching or exceeding the filtration control achieved by commercial CaCO₃ at equivalent quantities. At intermediate concentrations (20 g), YP and filter cake thickness were optimal, while higher concentrations showed a marginal decrease in YP and filter cake thickness. The pH and resistivity profiles confirmed chemical compatibility and stability within the drilling fluid system. Considering CaCO₃’s established thermal stability (up to 120 °C under HPHT conditions), the similar performance of eggshell powder suggests promising behavior under geothermal conditions. Given its cost advantage and environmental benefits, waste eggshell powder is validated as a viable additive for WBM in geothermal drilling. Its use delivers equivalent fluid-loss control, rheological stability, and mud density performance, while significantly reducing environmental footprint, supporting the UN Sustainable Development Goals.

Topic: Drilling

This study proposes a component-based model of a heating and cooling system comprised of an Aquifer Thermal Energy Storage (ATES) and a heat pump system for a commercial building, developed using Open Modelica. The heating system is divided into the following sub-models: water-to-water heat pump, ATES system, building load, chiller, domestic hot water, and control panel. The present study simulates four operating scenarios under identical loads and boundary conditions in order to evaluate the limits of both constrained and unconstrained aquifer extraction temperatures, as well as different Heat Pump (HP) to district heating energy ratios (60/40% and 90/10%) for heating supply. Across the four scenarios, the ATES supplied between 29–50% of the annual heating load and 41–57% of the annual cooling demand. However, performance proved highly sensitive to the ATES energy extraction/injection ratio. In the unconstrained 60/40% scenario, the imbalance led to an extracted-to-injected ratio of 0.74 and increases of 69% and 21% in the pumped volume per unit of heating and cooling energy, respectively, compared to the 90/10% cases. In contrast, the 90/10% scenarios achieved a balanced operation, with ratios close to 1.27–1.24 only incurring a 3% reduction in the cooling energy injected in the ATES when constraints were applied. The highest Monthly Performance Factors (MPF) were obtained in both 90/10% scenarios, achieving 4 and 55 points for heating and free cooling, considering the HP+ATES boundary level. Free cooling values in the 90/10% scenarios are 10 points higher than both 60/40% scenarios. The results also indicate that over-extracting energy in the ATES while heating is more tolerable than over-injection during cooling for long-term aquifer sustainability and system performance. System-level results further showed that mass flow modulation improved ATES-side heat exchanger effectiveness to values as high as 0.95, improving the quality of the ATES energy and reducing risks of thermal breakthrough. The model also confirmed the value of smart control strategies, and instantaneous Key Performance Indicators (KPIs), including extraction temperature thresholds and switching between free and machine cooling, reducing electricity use and pumping energy. Overall, the study demonstrates that a balanced GSHP–ATES operation with high heat pump participation can significantly reduce district heating reliance, improve efficiency, reduce the risk of thermal breakthrough, and ensure sustainable long-term operation of the ATES.

Topic: Low Temperature

The Great Basin region of the Basin and Range province, which encompasses nearly all of Nevada and parts of Idaho, Oregon, Utah, and California, is a tectonically active region undergoing regional extension and transtension. Active faulting in the Great Basin is a key factor in creating favorable conditions for geothermal activity. The geothermal potential within the region comes with challenges of characterizing the systems, because most of the geothermal resources are blind or hidden with no surface manifestations such as hot springs. This study assesses a potential hidden geothermal system within western Nevada through integration of geological and geophysical data. The study is focused on the Granite Mountain area of Buena Vista Valley in Pershing County, Nevada, where favorable structural settings and other geothermal indicators indicate relatively high potential for hosting a geothermal system. The structural framework of the Granite Mountain-Buena Vista Valley area consists primarily of a system of west-dipping normal faults along the eastern margin of Buena Vista Valley, which includes fault intersections and step-overs (i.e., relay ramps). These structural settings can generate zones of enhanced permeability that may provide favorable pathways for geothermal fluids. Additionally, intersecting gravity gradients and low resistivity anomalies further suggest subsurface structural and hydrothermal features conducive to or indicative of geothermal activity. The combination of these structural and geophysical characteristics suggests that the area may host a hidden geothermal system. By combining multiple datasets, this study aims to identify key structural and geophysical characteristics that define prospective hidden geothermal systems in the Great Basin region. Results from this project will contribute to identifying areas for temperature gradient drilling in the Granite Mountain area and potentially help guide future exploration in the region.

Topic: Geology

Produced water, often co-produced with oil and gas, is typically hot and can serve as a valuable geothermal resource for generating energy to support field operations or supply nearby communities and industries. Like hydrocarbon production, the volumetric rate of produced hot water declines with time, making it essential to understand its decline behavior if it is to be harnessed as a sustainable alternative energy source. In this study, production data from three wells, Anderson 28-33 1-H, Charlie Sorenson 17-8 3TFH, and Ross 7-17H, located in the Mississippian/Devonian Bakken formation (Alger field), spanning August 2009 to August 2025, were analyzed to characterize water-production decline trends. The classical Arps decline models (exponential, hyperbolic, and harmonic) and post-Arps models (LGM, SEPD, PLE, Wang model, Duong model, and VDMA) were first employed to evaluate the decline performance of the produced water. The best-performing Arps and post-Arps models for each well were selected and further compared against an LSTM architecture trained on the same historical dataset. The study results showed that, for historical water production data with very little to no fluctuations, empirical DCA models performed equally well as the data-driven LSTM model. However, in instances where production data is severely noisy due to field operations, the data-driven LSTM outperforms the empirical DCA models, both qualitatively and quantitatively. Despite the improved predictive ability of the LSTM model in capturing non-linear dependencies inherent in field data, compared to empirical decline curve analysis models, the mean predictive errors were within 10 - 15%. This error could be further reduced by integrating variables such as well shut-ins, operational interventions, changes in choke settings, artificial lift adjustments, workover activities, water breakthrough events, reservoir pressure variations, and production constraints into the dataset used for training the LSTM model. Including these factors would enable the LSTM model to better distinguish between transient operational effects and underlying reservoir-driven decline behavior.

Topic: Production Engineering

The Smackover Formation in the southern United States has recently emerged as a promising reservoir for lithium (Li) hosted in subsurface brines, with opportunities for co-production alongside geothermal energy. This study develops a stochastic assessment of lithium and geothermal resource potential in the northern Smackover using publicly available brine chemistry datasets that span both lateral and vertical sampling depths. Variogram analyses quantify spatial continuity, revealing long horizontal correlation ranges (10-40 km) but much shorter vertical ranges (250-1,000 m), which guided an anisotropic inverse distance weighting interpolation of Li concentration. The resulting 3D model delineates subsurface enrichment zones and yields an estimated seven million tonnes of total Li in-place across ~770 km3 of reservoir volume. Incorporating stochastic distributions of porosity, oil–water contact, and extraction efficiency indicates that only ~0.3 million tonnes are realistically recoverable, with recoverability limited primarily by low effective porosity and non-uniform brine saturation. Geothermal potential was evaluated using an analytical enhanced geothermal systems framework that assumes parallel fracture flow and constant heat extraction over a 30-year plant lifetime. Temperature drawdown estimates between 2,300 and 2,600 m depth (12-21°C) were combined with stochastic sampling of seven thermophysical and operational parameters to compute power density. Thermodynamic maxima range from ~8 to 14 W m-2, whereas realistic power densities cluster narrowly between 0.48 and 0.86 W m-2 due to low conversion efficiencies and modest geologic success factors. Together, these results highlight substantial Li endowment but modest geothermal potential and demonstrate the utility of stochastic co-resource assessment for informing future development strategies in the Smackover Formation.

Topic: General

Proppant packs are essential for maintaining fracture conductivity in enhanced geothermal systems (EGS). However, under the EGS high closure stresses and elevated temperatures, the long-term hydraulic performance is strongly affected by particle crushing, resulting in permeability reduction. This study presents a three-dimensional discrete element modeling investigation of proppant pack settlement, particle breakage, and permeability evolution under stress conditions representative of the Utah FORGE geothermal site. Simulations are performed using Particle Flow Code in three dimensions (PFC3D), in which particle fracture is captured through a Fragment Replacement Method (FRM). Breakage is triggered when a stress derived from the maximum contact force exceeds a size-dependent characteristic strength, calibrated using single-particle diametral compression test data. Loading is applied incrementally under oedometric conditions, with breakage events followed by mechanical re-equilibration to mitigate numerical artifacts. Pack-scale void ratio evolution is quantified from volumetric changes associated with particle rearrangement and fragmentation, while permeability evolution is estimated using the Kozeny–Carman relationship. Results show that allowing particle breakage leads to a more compliant macroscopic response, progressive broadening of the particle size distribution, and a sustained reduction in permeability driven by the generation of fines and reorganization of the contact network. Breakage is found to be distributed throughout the pack and governed primarily by internal force-chain evolution rather than boundary effects. These findings highlight the mechanical response to proppant crushing and provide a quantitative framework for evaluating trade-offs between particle size and strength when selecting proppants to maintain fracture conductivity in EGS and unconventional energy reservoirs.

Topic: Enhanced Geothermal Systems

Geothermal wells are by default subjected to thermal cycles that impose demanding loads on the casing strings and cement. Historically, well construction relied on cement to provide annular zonal isolation, structural support, casing protection, and wellbore stability. However, the cement sheath is prone to mechanical failures (e.g., cracking, debonding, strength degradation, etc.) under high cyclic thermal stresses. In addition to violating environmental and safety standards, these failures can lead to inelastic buckling, sustained casing pressure, and cross-flow between communicating formations. This work proposes a novel cementless well construction methodology to overcome the well design and integrity limitations in geothermal environments, specifically. However, the concept can be applied to any type of well application, including oil and gas, CO2 sequestration, enhanced oil recovery (EOR), and/or underground storage wells with thorough well design and planning. The concept proposed in this work utilizes hydraulically-set metal expandable packer (MEP) systems as an alternative to cement for the annular zonal isolation. These packers need to be set at competent formations for a long-lasting metal-to-rock and metal-to-metal seal. This work presents a model with the key design considerations for a successful application using a commercial well design software that also has finite element analysis (FEA) features. In order to eliminate packer failures, certain pre-tension is applied to the strings after each packer set. The concept offers very high potential to achieve maximum well integrity over a longer operational life-of-well, even post-plug and abandonment, neglecting the corrosion damage, which needs further solution development. The metallic packer technology already has a proven track record in the oil and gas wells with back-up cement in place.

Topic: Drilling

Hydrogen production in ultramafic, mafic and metamorphic rocks is limited by geochemical properties of rock and brine. These geochemical properties such as geochemical phases and molar compositions determine the maximum potential production of hydrogen from ultramafic rocks (resources). In this work, we use public geochemical data of ultramafic rocks from PetDB and in-house experiments (Ross et al., 2025) to evaluate variations in hydrogen resources at typical depths in the subsurface.

Topic: Geochemistry

Next-generation geothermal development is undergoing a fundamental transition to access deeper and hotter targets, aiming to maximize and increase energy production per well by orders of magnitude. At ‘superhot’ or ~350 C+ conditions, wells can produce up to ten times more power than conventional geothermal systems, motivating this study to identify additional firm, abundant power generation. This study utilizes reduced-order physical models grounded in analytical foundations quantifying how the interplay of fracture surface area, mass flow rate, and thermal properties dictates long-term project performance. Projects are categorized by development approach: Traditional EGS, Huff-n-Puff EGS, and closed-loop Advanced Geothermal Systems (AGS). These projects are critically assessed through their Connectivity (establishing hydraulic communication), Conductivity (maintaining open flow paths), and Conformance (ensuring uniform sweep). Analysis shows that past failures, such as rapid thermal drawdown or excessive impedance, often stem from a lack of control over one or more of these metrics. Lessons learned from deep and hot geothermal systems are then applied to superhot and superdeep geothermal resource for each next generation geothermal classification. By treating the subsurface as an engineered heat exchanger, we demonstrate that maximizing effective sweep volume is the primary lever to delay thermal breakthrough and achieve sustainable power densities. A novel "drill shallow, fracture deep" concept is introduced to recover heat from superhot formations without drilling superdeep that utilizes dense working fluids to drive fracture propagation downward into deeper, hotter formations. This approach exploits fracture mechanics to access superhot resources while bypassing the technical and economic hurdles of direct deep drilling and completion.

Topic: General

Achieving Net Zero Emissions (NZE) by 2050 will require expanded deployment of geothermal and other low-carbon energy systems capable of providing reliable heat and power. Engineered geological hydrogen generation in ultramafic formations shares strong conceptual and operational similarities with geothermal systems, including fluid circulation, subsurface heat extraction, and surface power conversion. During stimulated geological hydrogen production, hydrogen is co-produced with high-temperature water that transports significant geothermal energy to the surface. This thermal energy is commonly dissipated during surface cooling prior to reinjection, representing a missed opportunity for power generation and increased operational cost. This study investigates the feasibility of integrating a geothermal binary power system with engineered geological hydrogen production to recover waste heat and enable a self-sustaining surface operation. An integrated framework is developed that couples laboratory-scale serpentinization-based hydrogen-generation experiments with field-scale thermal-production forecasting and Organic Rankine Cycle (ORC) modeling. Hydrogen generation rates are scaled to field conditions using fracture-surface-area–based geometric scaling across three reservoir scenarios: low-temperature uncatalyzed, low-temperature catalyzed, and high-temperature catalyzed. A 20-year production lifecycle is simulated, and the co-produced injected fluid is evaluated as the primary heat source for a closed-loop ORC. Results show that low-temperature uncatalyzed systems provide insufficient thermal power, while high-temperature catalyzed systems generate substantial geothermal power but may involve higher capital and operational risks. A low-temperature catalyzed scenario is identified as a marginal yet viable geothermal case, capable of meeting the minimum 3 MW power threshold required for self-sustaining surface operations. Sensitivity analysis demonstrates that reservoir decline management through restimulation is critical for maintaining long-term geothermal power output. These results highlight the potential to repurpose geothermal binary power concepts to improve energy efficiency, thermal recovery, and sustainability in engineered subsurface energy systems.

Topic: General

Enhanced Geothermal System (EGS) target identification requires integration of multimodal geoscientific data to capture thermal state, rock properties, and structural controls across three-dimensional (3D) subsurface volumes. Understanding the non-linear relationships between EGS favorability proxies is essential for targeted data collection and informed prospectivity analysis, yet traditional approaches lack robust mechanisms to reveal these critical interdependencies. This study presents a framework for EGS characterization that combines Self-Organizing Maps (SOM) with depth-resolved statistical validation to distinguish EGS from naturally conventional hydrothermal systems. We developed integrated 3D subsurface models at Utah Frontier Observatory for Research in Geothermal Energy (Utah FORGE) and Roosevelt Hot Springs (RHS) comprising 4.5 million blocks at 100 m resolution, incorporating 11 attributes: P-wave velocity (Vp), S-wave velocity (Vs), Vp/Vs ratio, density inferred from 3D magnetic gravity inversion, temperature, fault density, and five lithology indicators. A 3×3 SOM was trained using a representative subset of the 4.5M valid blocks and then applied to the full block volume to obtain 3D cluster assignments. Component plane analysis revealed systematic correlations: high-temperature domains consistently co-locate with elevated Vp/Vs ratios and intermediate densities, confirming coupling between thermal anomalies, fluid presence, and enhanced permeability. Within the RHS footprint, Cluster C7 represents the dominant high-temperature regime and shows negligible within-cluster sampling bias (Δmean ≈ 0). This supports that the footprint-labeled blocks are representative of the underlying SOM prototype. Depth-resolved statistical validation using dual parametric (Welch's t-test, Hedges’ g) and non-parametric (Mann–Whitney U, Cliff's δ) frameworks quantified system-level contrasts across 500 m depth bins. RHS exhibits very large thermal effect sizes at shallow depths (g greater than 2, |δ| greater than 0.7) reflecting strong convective upflow, while FORGE shows comparable or elevated temperatures below 3000 m depth consistent with deep EGS targeting. This work establishes a reproducible, objective framework for 3D EGS prospectivity assessment that eliminates subjective weighting, delivers quantitative explainability of proxy interdependencies, and provides spatially explicit volumetric delineation of prospect quality. Unlike black-box approaches, the SOM architecture preserves interpretability while handling high-dimensional data, enabling geoscientists to interrogate proxy relationships, validate assignments against domain knowledge, and extract transferable insights. Explainability is provided via SOM component planes (proxy co-variation), cluster prototypes, and depth-binned effect sizes that quantify where and why system contrasts occur. The integrated methodology advances EGS exploration by demonstrating that combined unsupervised learning and rigorous statistical validation can identify subsurface targets in structurally complex basement environments while maintaining full transparency of decision criteria.

Topic: Enhanced Geothermal Systems

Geothermal energy is not only a source of renewable energy but also has a low CO₂ footprint. However, the extraction of heat energy from the geothermal well comes with its challenges. One such challenge is the operation of the isolation tool in the geothermal downhole environment, where temperature and pressure are usually very high. The use of conventional oil and gas packers has limitations when installed in the geothermal well. Therefore, specific isolation tools must be designed to withstand harsh downhole well conditions and ensure long-term durability and integrity. In that respect, packers with metal-to-metal sealing are gaining importance for geothermal operations. However, the manufacturing of metallic packers is not only expensive and time‑consuming, but also very demanding at the design stage. Therefore, it is preferable to develop small-scale prototypes, for which 3D printing can be a valuable tool to address design complexities, enabling rapid iterations and faster optimization. In that regard, Welltec designed a novel retrievable metallic packer and employed 3D printing to produce small-scale prototypes that allowed assembly evaluation and early detection of potential design challenges prior to full-scale manufacturing. This study presents the manufacturing and testing of different 3D designs prototypes that were designed, refined, and evolved based on performance feedback. The packer prototypes were printed using polylactic acid (PLA) and thermoplastic polyurethane (TPU) filaments and tested in a novel flow‑by setup using translucent polyvinyl chloride (PVC) pipe as a wellbore. Vegetable glycerin (VG) mixed with propylene glycol (PV) in liquid form was vaporized to simulate the working fluid while high‑speed video cameras recorded the process. In order to detect the leakage pathways, colored powder spray was utilized, which helps to analyze the fluid bypass and assist in analyzing sealing efficiency during tests. Additionally, differential pressure measurements provided insights into the sealing performance as the design cycle progressed. Overall, rapid prototyping with 3D printing demonstrated that iterative design process and component refinements can improve sealing capability at a small scale, providing critical insights to guide cost‑effective development of field‑scale metallic packers for geothermal applications.

Topic: FORGE

Transport of suspensions and colloids through porous media, involving particle capture and plugging, occurs in various geothermal reservoirs and geothermal power plant processes. Fine particle migration is a critical topic impacting production efficiency in geothermal projects, including permeability impairment in the reservoir, plugging surface infrastructure, reducing heat transfer, and causing abrasiveness and erosion in pumps, valves, and production-injection lines. This study presents an in-depth analysis of this problem by examining drive mechanisms, modeling approaches, experimental studies, and field observations.

Topic: Production Engineering

As the world population increases by the day, so does the energy demand. Along with this phenomenon, global warming is taking its toll on the climate. Therefore, to address these issues, sustainable and green energy production is required, in which geothermal energy plays a crucial role. It is a clean, renewable, and continuous source of energy that remains in operation mode for more than 90% of the time and is not weather-dependent. To ensure the smooth transition of energy from the subsurface to the well head, the well integrity has to be assured. The main component that controls well integrity is the well cement and casing. In a geothermal environment, these barriers are exposed to severe thermal cycling and high-temperature gradients that can induce mechanical stress, create microannuli, and impact long-term material degradation, posing significant risks to well integrity. Therefore, it is important to properly analyze cement properties before placing it in the geothermal well. In that respect, this paper presents the experimental results of the impact of thermal loading on the interfacial bonding strength of the Class G cement, which is the most commonly used cement in the wells. The method utilizes a novel apparatus that incorporates an ISCO pump to quantify the interfacial debonding strength of the cement. The preparation of the cement was according to the API standard, after which it was poured into 2-inch diameter, 6-inch long steel pipes and was cured for 14 days. To simulate the geothermal well condition, the samples were exposed to 5 and 10 thermal cycles loading at 95 °C. In one cycle, there is 1 hour of heating and 3 hours of cooling. From the testing, it was noted that before the debonding of the sample occurs, a leakage of water, termed the “wetting phase,” is observed at a pressure lower than that of the interfacial debonding pressure. It was also observed that cyclic loading had an impact on the debonding strength, which decreased as the number of cycles increased. Hence, it was concluded that the primary mode of failure was caused by shear debonding, which is facilitated by the creation of microannuli at the interface between the casing and the cement, and is exacerbated by thermal loading. Therefore, before cement placement, it should be ensured that the cement debonding strength is sufficient to resist thermal loading and maintain its integrity throughout the project's life. Otherwise, the subsurface fluid can make its way to shallower formations and ultimately reach the surface, which will jeopardize the success of the geothermal project.

Topic: Drilling

The Rico geothermal system in southwestern Colorado represents a promising low- to medium-temperature resource with potential to support a community-scale Thermal Energy Network (TEN). Surface manifestations include three thermal springs from historical artesian mining wells with discharge temperatures ranging from 38–46 °C and flow rates up to 0.95 l/s. However, geothermometry and historical data suggest subsurface temperatures up to 120–140 °C. To evaluate the feasibility of utilizing this resource for direct-use heating, Teverra, with support from Seequent Ltd., developed a preliminary 3D geological model in Leapfrog Energy. This model integrates geological information, mapped fault structures, geophysical datasets, and known hydrothermal features to characterize the subsurface geometry and identify key controls on permeability and fluid flow. Early modeling results indicate a structurally complex but favorable setting for geothermal circulation, with fault networks that may enhance reservoir connectivity and recharge. The ongoing conceptual modeling effort incorporates additional datasets, including spring temperature and geochemistry, historic mining data, resistivity and magnetotelluric surveys, and thermal gradient anomalies, to refine the resource characterization and develop a conceptual model for the geothermal system. This integrated approach will guide future exploration and infrastructure planning, laying the foundation for a resilient, locally sourced geothermal energy solution tailored to Rico’s heating needs. By systematically compiling legacy and newly acquired data into a coherent conceptual framework and 3D resource model, this work establishes a technically defensible pathway toward confirmation drilling, reducing subsurface uncertainty and increasing confidence for subsequent investment and development decisions

Topic: Direct Use

North-Western Himalayas is a promising area for geothermal utilization with more than 400 thermal springs. The Himalayan Geothermal Belt was formed as a result of the collision of the Indian plate with the Eurasian plate, about 50 million years ago. It hosts nearly 150 thermal springs with temperature varying from 47 to 87 degrees Celsius. Although hot spots in Ladakh has a potential to produce geothermal energy, but there has been no progress to harness this energy due to political and financial constraints. The Laddakh is situated in the northern part of the Himalayan belt bordering Tibet (China) hence experiences severe cold during the winter season dipping temperature to minus 15 to 25 degrees Celsius. An effort has been made to demonstrate the use of geothermal energy for space heating at Chumathang near a hot spring source. At present, the city of Leh uses diesel to meet its major power demand for electricity and space heating. It is estimated that diesel generators are generating about 28,000 metric tones of CO2 resulting in greater threat to the Himalayan Glaciers. It is reported that over the last 61 years, the Gangotri glacier has receded by a distance of 1,164 meters. Unlike solar and wind energy, Geothermal energy is available 24x7 and 365 days per year. It emits 80% less greenhouse gases compared to coal and oil. Geothermal energy is independent of adverse weather conditions prevailing in Laddakh region. Initial cost may be high (estimated 40 crore per MW) but will drop over a long period. It is estimated with 90% probability that Geothermal field at Puga could sustain 20 MW power plant at current depth of 250 m. The plant of this capacity at Puga could annually save about 3.5 million litres of diesel costing about 4 million USD apart from saving the environment from toxic gases.

Topic: Direct Use

Characterizing the hydrogeological and mechanical properties of an enhanced geothermal system (EGS) is very important for optimal stimulations, efficient and sustainable heat recovery, and safe operations. However, EGS sites are highly heterogeneous with complex geological structures such as discrete fracture networks (DFNs). Moreover, traditional subsurface characterization approaches require a number of thermal-hydraulic-mechanical (THM) simulations, which poses a significant limit on extensive EGS characterization. In this work, we use a deep generative diffusion model and DFN models to characterize the permeability field of the EGS sites and connectivity between natural and induced DFNs with available observation data sets. The diffusion model, a deep generative model, is used to learn the probability distribution of the permeability field based on conceptual geological models of DFNs. The latent diffusion model is chosen in this work to represent the permeability fields in a significantly smaller dimension than the actual numerical grid dimensions. Ensemble smoother-multiple data assimilation through the latent space is then employed to characterize EGS permeability fields by matching multiple measured data such as temperature, pressure, and production rates. For accurate and fast forward simulations, a surrogate model is constructed using the deep learning framework for THM simulations. Examples with discrete fractured permeability fields and with corresponding continuum-based permeability fields based on the Utah FORGE site, where a recirculation test was performed in the presence of DFNs developed by previous multiple stimulations, are presented to show the performance of our proposed data assimilation framework. After model calibration and validation against recirculation tests at the Utah FORGE site, we will evaluate the effect of a few conceptual models such as near wellbore permeability with DFNs and interaction between natural and induced DFNs for long-term behaviors of heat recovery. SNL is managed and operated by NTESS under DOE NNSA contract DE-NA0003525.

Topic: Modeling

Reported injection surveys in couplet Enhanced Geothermal System (EGS) injection wells show flow rate variations among several fracture-driven interactions (FDIs). Because the reported cases have all created hydraulic fractures in both injection and production wells, there may be production well fractures through which no flow is occurring. The placement of zeolites in production well fractures can serve to characterize the FDI between wells, thereby assessing how efficiently the system recovers heat and energy. The proposed approach involves employing commercially available zeolites with particle diameters ranging from 300 to 500 nm to evaluate both the passage and contact between the circulating fluid and the production well fractures. A doublet well configuration—comprising one injection well and one production well—serves as the assessment scenario. We propose to place zeolites in production well fractures in the expectation that flow through the fractures will carry zeolites to the surface. We propose to detect zeolites through X-ray diffraction (XRD) analysis of samples collected from the production well, leveraging the fact that zeolites are chemically stable and resistant to degradation under high temperature and pressure conditions. In summary, the proposed concept is to assess the contribution of productive fractures to the overall flow, which directly impacts the EGS heat recovery efficiency.

Topic: Tracers

Deep sedimentary basins contain significant geothermal resources for power generation, and these regions often benefit from existing oil and gas infrastructure, subsurface data, an experienced workforce, permitting regulations, and growing power demand. Despite these advantages, field demonstrations and commercial development of the latest styles of Enhanced Geothermal Systems (EGS) have predominantly focused on crystalline basement reservoirs in the western US. In deep sedimentary basins, such as the US Gulf Coast, potential EGS target temperatures (for power generation) are typically located at depths of 4 to 6 kilometers due to modest temperature gradients. Compared to EGS in high-heat flow areas in the western US, these greater target depths result in higher drilling and completions costs, making geothermal power generation less competitive compared to existing natural gas and renewable energy markets. Yet, with novel cost-efficient development and production strategies, geothermal could be attractive for baseload power generation. This study discusses similarities and differences between crystalline basement and deep sedimentary rocks, such as tight sand and shale. What can be done to make EGS at scale in deep sedimentary basins more viable? The study reviews some of the practices of EGS and oil/gas industries and explores whether those are necessary and practically applicable to EGS development in deep sedimentary rocks or if innovative methods or hybrid approaches (e.g., new well configurations, stimulation operations, reactive fracture growth, fluid design, etc.) could enable cost-effective and sustained heat production. The study shows preliminary modeling results from deep sedimentary reservoirs in the US Gulf Coast, which could be good candidates for EGS field pilot tests. The findings, conceptual framework, and proposed recommendations in this study provide a road map for future research and practical implementation of EGS in deep sedimentary basins.

Topic: Enhanced Geothermal Systems

Induced seismicity presents a critical challenge in geothermal reservoir management, as the occurrence of large seismic events raises public safety concerns and affects social acceptance of geothermal operations. Accurate forecasting of induced seismicity provides valuable information for operators and improves understanding of the underlying physical processes. However, physics-based modeling requires detailed knowledge of subsurface properties and intensive computation, while conventional statistical methods struggle to capture the nonlinear relationships between operational parameters and seismicity. In this study, we introduce QuakeCastNet, an interpretable deep learning framework for forecasting induced seismicity, including seismicity rates, the spatiotemporal evolution, and magnitude distribution in geothermal fields, and demonstrate it using data recorded at Utah FORGE and The Geysers. QuakeCastNet combines a modified Temporal Fusion Transformer (TFT) for time-series forecasting with a Graph Neural Network (GNN) for spatial representation learning, enabling joint modeling of complex dependencies across both time and space. The framework integrates heterogeneous datasets—including geological information, historical seismicity catalogs, and injection and production metadata—to predict future seismicity rates and magnitude-frequency distributions within gridded regions of interest. The estimated magnitude distribution provides insights into the probability of larger seismic events in the future to support risk assessment. By coupling explainable AI with data-driven learning, QuakeCastNet demonstrates improved predictive performance and interpretability, advancing our understanding of induced seismicity mechanisms and supporting safer, adaptive reservoir management strategies in geothermal operations.

Topic: Enhanced Geothermal Systems

Data Science has provided geothermal reservoir managers with new avenues for making energy production from this resource more sustainable, accurate, and efficient in recent years. The focus of this Review Paper is to examine recent data science use and development, specifically using machine learning and big data analytics. New AI tools are offering incredible opportunities for field operators to incorporate this technology into their older equipment, ranging from drilling to monitoring. With continuous data generation from geothermal reservoirs, operators can utilize AI to improve decision-making, optimize resource extraction, and improve reservoir monitoring. Due to a large amount of variability in the ranges of permeability, porosity, and fluid distribution traditionally, reservoir characterization and modeling have had a great deal of uncertainty. Machine learning techniques are now being applied to analyze the geological and geophysical data to create the most representative hydrocarbon static model of each reservoir. When machine learning techniques are combined with the ability of traditional reservoir simulation to develop more accurate data driven models, then reservoir engineers will be able to work with more reliable tools for understanding reservoir behavior, history matching, and optimizing the production strategies of those reservoirs. Additionally, by combining big data and numerous datasets (production logs, well tests, or numerical simulation), physics-informed machine learning can be utilized to determine the dynamic behavior and identify the potential unseen risks of geothermal reservoir management. Additionally, the real time monitoring and predictive maintenance of geothermal reservoir operation are two other benefits of data science, where IoT enabled sensors and AI driven models allow operators to continue to monitor key parameters of the operation, where normally the environmental temperature, pressure, stress, and salinity are greater. Anomaly detection, predicting equipment failure, bottleneck detection, program optimization, reducing downtime, extending the life of reservoir infrastructure, and minimizing operational costs, etc., are some examples of how data science can aid in the traditional operation of geothermal reservoirs and improve the overall efficiency of geothermal energy production. The review addresses multiple aspects of the integration of data science and reservoir management strategies, focusing primarily on the geothermal industry. Data science, including AI, machine learning, and big data analytics, can provide the geothermal field operators and researchers with the ability to apply AI capabilities to their daily routines. Some examples of how geothermal energy can be enhanced as part of the renewable energy matrix through data-driven modeling techniques include improving decision-making, enhancing resource management, achieving sustainability goals, and identifying bottlenecks

Topic: Production Engineering

[Bonneville]

A Major Milestone at Newberry, Oregon: Advancing Toward a Superhot Rock EGS Reservoir Alain BONNEVILLE, Sriram VASANTHARAJAN, Patrick BRAND, Jonathan ALCANTAR, Gregory ASHER, Mohamed Idris BEN-FAYED, Wadood EL-RABAA, Romar A. GONZALES LUIS, Gabrijel GRUBAC, Robert SWANSON, Adam KENT, Eric SONNENTHAL, Nori NAKATA, Ahmad GHASSEMI, Geoffrey K. MIBEI, Parker SPRINKLE [Mazama Energy, Inc., USA]

In 2025, Mazama Energy achieved a landmark advancement in geothermal technology by developing the world’s hottest Enhanced Geothermal System (EGS) on the western flank of Newberry Volcano, Oregon. The project began with the workover of the existing 55-29 well (3,008 m deep and 331°C BHT) for use as an injector, followed by the drilling and completion of well 55A-29 to the same depth for use as a producer. After stimulation of both wells, initial circulation and diagnostic testing confirmed strong hydraulic connectivity and stable fluid circulation within the newly engineered reservoir. During this first year of operations, Mazama collected extensive geological, geophysical, and geomechanical datasets. Integration of these data with prior site characterization efforts leads to substantial refinement of the subsurface models, which are presented in this work. These achievements demonstrate the technical feasibility of EGS development in hot crystalline formations of various lithologies and represent a critical milestone toward establishing a Superhot Rock (SHR) EGS reservoir at Newberry Volcano. This effort is part of the Newberry SHR EGS Demonstration Project, a multi-institutional collaboration funded in partnership with the U.S. Department of Energy, paving the way for next-generation geothermal power at unprecedented temperatures.

Topic: Enhanced Geothermal Systems

The processes of electricity production from geothermal resources at Olkaria IAU and Olkaria II Power Plants in Kenya were analysed using exergy analysis method. The objectives of the analysis were to determine the overall second law (Exergy) efficiency of the power plants, pinpoint the locations and quantities of exergy losses and wastes and suggest ways to address them and improve the overall performance of the power plants. Both Olkaria IAU and Olkaria II power plants share steam supply system and have a combined installed capacity of 336MWe from 6 generators In the analysis, the power plants were simplified into sub-systems, each with distinct exergy inflows and outflows and approximated into steady state flow. The theory and mathematical formulations were adapted from the book ‘Exergy methods of thermal plant analysis’ and several online internet publications. Mathematical models for exergy flows were developed and analysed using the Engineering Equation Solver (EES) software to perform the calculations. The degree of thermodynamic perfection (measure of performance) was based on the rational efficiency concept. Few assumptions and simplifications were made. The results showed that Olkaria IAU Power Plant has an overall second law efficiency of 45% and an overall 1st law efficiency of 15% while Olkaria II power plant has an overall second law efficiency of 42% and an overall 1st law efficiency of 14%. It was concluded that the lower performance of Olkaria II is likely as a reult of the aged equipment and recommended that a redevelopment of the plant may be necessary.

Topic: Field Studies

Hyperspectral Image Spectroscopy (HIS) has revolutionized the spectral interpretation of minerals by providing non-destructive, high-resolution spectral data for precise mineral identification and mapping. This study explores the application of HIS in determining the wavelength of minimum reflectance, a critical spectral parameter for distinguishing minerals based on their unique absorption features. Wavelength mapping using HIS enhances the accuracy of mineral classification and spatial distribution analysis, making it a valuable tool in geological exploration and remote sensing applications. Compared to traditional analytical techniques such as X-ray Diffraction (XRD) and X-ray Fluorescence (XRF), HIS offers a rapid, large-scale, and non-invasive means of mineral characterization. While XRD is highly precise in identifying crystalline structures and phase compositions, it requires physical samples and extensive laboratory preparation. XRF, on the other hand, is effective in determining elemental compositions but lacks the capability to directly identify mineral phases. In contrast, HIS enables remote, high-throughput mineral discrimination based on spectral signatures, making it particularly advantageous for field-based exploration, planetary studies, and resource assessment. The integration of HIS with XRD and XRF provides a comprehensive approach to mineral characterization, leveraging the spectral mapping capabilities of HIS alongside the structural and elemental insights offered by XRD and XRF. This synergy enhances the accuracy of geological interpretations and supports advanced mineral exploration and environmental studies. This study was focused on the analysis of a lithium pegmatite rock sample and the findings underscore the growing importance of hyperspectral data in complementing conventional mineralogical techniques for more efficient and precise geoscientific analyses. The minerals that were identified from the sample included; Lepidolite, Muscovite, Topaz, Quartz and Albite.

Topic: Geology

Turkey hosts significant geothermal resources due to its unique tectonic setting at the convergence of the African, Eurasian, and Arabian plates. While conventional hydrothermal systems have been successfully developed over the past decades, much of the country’s high-enthalpy potential remains untapped—especially in regions suitable for advanced exploration techniques and Enhanced Geothermal Systems (EGS). This paper presents a comprehensive overview of Turkey’s geothermal landscape, highlighting its geological advantages, current exploration strategies, and sectoral trends. It further outlines the growing investment opportunities fueled by supportive regulatory frameworks, rising energy demand, and a national commitment to renewable energy expansion. By bridging geoscientific insights with private sector dynamics, the study offers a strategic roadmap for investors seeking scalable, long-term geothermal projects in Turkey

Topic: General

Enhanced Geothermal Systems (EGS) rely on hydraulic stimulation to increase permeability in low-permeability rock formations. However, this process often induces microseismicity due to the initiation and propagation of new fractures, as well as slip along pre-existing fractures. Understanding the mechanisms and controlling factors of induced seismicity is essential for optimizing stimulation strategies while ensuring operational safety and maintaining public confidence. The Utah Frontier Observatory for Research in Geothermal Energy (FORGE) provides a unique opportunity for investigating these relationships, offering high-quality datasets with well-characterized subsurface conditions. This study aims to evaluate the influence of key injection parameters, including the rate, duration, and viscosity of injected fluids, on the evolution of microseismicity during and post-stimulation. We develop a series of high-fidelity, hydro-mechanical numerical simulations using XSite, a lattice-based simulator capable of modeling tensile and shear failures in rockmass with complex fracture networks. The simulation domain replicates the 2024 stimulation performed at well 16A(78)-32 at the FORGE site. Discrete Fracture Networks (DFNs) were constructed based on site data, with variations in hydromechanical properties such as the aperture, normal stiffness, and friction coefficient of fractures, informed by laboratory and borehole observations. Each model was calibrated by comparing wellhead pressures and Gutenberg-Richter magnitude-frequency distributions (MFDs) between in situ measurements and numerical predictions. The calibrated models were then employed to quantify the effects of injection rate, total injection volume, and fluid viscosity on the maximum magnitude and MFD of induced seismicity during and after injection. Further analysis will focus on the generation mechanisms of post-injection seismicity and the stress shadowing effects between closely located fracture clusters.

Topic: FORGE

With the development of technology for enhanced geothermal energy, there is a growing potential for its application in dispatchable geothermal energy. Dispatchable energy has the added benefit of optimized economics, with the ramping up of production during high energy demand and high energy prices and reduction of production during low demand and energy prices. As enhanced geothermal systems tend to target granite layers for their reservoir, silica scaling is a growing concern. The injection of cold water in the fractured system causes the silica to precipitate out of solution in the reservoir, decreasing flow and accelerating the thermal drawdown as silica scaling acts as an insulator. This paper evaluates the subsurface effects of the cyclical pressure and temperature changes, that are a result of the nature of dispatchable geothermal energy, and its effect on silica scaling in the reservoir. A non-isothermal reservoir numerical simulator was applied to develop a reservoir model of an enhanced geothermal system in an artificially stimulated granite reservoir. The model evaluates thermal-hydraulic flow, time-dependent heat transport, and geochemical equilibrium calculations for silica solubility. A variety of multiple production-rest cycles are evaluated, as well as waste heat storage to evaluate optimal production scenarios. The simulation results stress the importance of accounting for silica scaling in enhanced geothermal systems, particularly in dispatchable production cases. Optimal operational thresholds are defined for the typical multiple production-rest case, as well as for the waste heat storage case. These thresholds decrease the need for scaling intervention and decrease the production losses associated with the scaling.

Topic: Enhanced Geothermal Systems

Simulating long-term performance of enhanced geothermal systems (EGS) is computationally intensive, limiting the scope of reservoir model calibration and sensitivity analysis. This work introduces a novel reduced-order model, Fast Marching Method-based Simulation (FMM-SIM) to accelerate the geothermal reservoir simulation to make it feasible for real-field applications including Utah FORGE project. The proposed FMM-SIM is a reduced-order modeling approach that transforms 3D fine-scale simulation into a multi-resolution representation using Diffusive Time of Flight (DTOF) which represents the propagation time of the ‘pressure front’ in the reservoir. Our proposed method utilizes a finite-volume Fast Marching Method to efficiently compute DTOF, which then serves as the spatial coordinate for the multi-resolution representation. To ensure accuracy, full 3D resolution is retained near the wellbore and hydraulic fractures, while the remainder of the reservoir is represented by a sequence of 1D grid. The 3D and 1D domains are connected through non-neighbor connections that account for both fluid and heat transmissibility. Whereas conventional reservoir simulations can be computationally intensive to capture complex physics including thermal, compositional and geomechanical effects, FMM-SIM preserves the essential details while reducing high fidelity simulation time by orders of magnitude. We applied the proposed method to both a synthetic model and Utah FORGE model, achieving around 15x speedup in simulation time, allowing each full simulation to finish in about one hour. Using a synthetic model designed after a commercial-scale EGS project, we examined the influence of key parameters in EGS development, including 3C (connectivity, conductivity and conformance), geomechanical effects and well control effects on thermal breakthroughs. Barton-Bandis fracture closure model represents fracture closure and dilation during fluid circulation. We also evaluated intermittent thermal extraction strategies that aim to postpone premature thermal breakthrough. Subsequently, we carried out data assimilation using a multi-objective genetic algorithm to construct a dynamic reservoir model that integrates diverse datasets such as the reference DFN model, the native-state model, DSS measurements, and one month of circulation test data from Utah FORGE project. Integrating the geomechanical module enhanced the accuracy of the history match and indicated that some degree of fracture closure occurred during the circulation period. The calibrated model was then used to test intermittent thermal extraction strategies at the Utah FORGE site, revealing the balance between energy production rate and long term cumulative energy recovery when the production well is periodically shut in. All simulation studies are grounded by accelerated reservoir simulations using FMM-SIM, which enables comprehensive parametric studies and dynamic reservoir modeling. The results demonstrate that FMM-SIM is an effective tool for optimizing geothermal energy extraction through fast and reliable reservoir simulation.

Topic: Reservoir Engineering

Geothermal wells drilled into super-hot rock formations have the potential to generate significant levels of thermal power in closed loop geothermal systems. In addition, a properly designed system of wells can meet target electric power demands even after accounting for conversion losses. The most efficient means of working fluid enthalpy gain is through a network of fractures connecting a pair of injector (cold fluid) and riser (hot fluid) wells, thereby maximising fluid-to-formation contact area. The motivation behind many projects is usually based on the rough estimates of thermal power due to the difference between the well inlet and undisturbed geothermal temperatures. This ignores however the fact that in the vicinity of the fractures, the geothermal temperature declines with time. In addition, the problem is exacerbated when the cold fronts from adjacent fractures coalesce. Larger spacing between fractures to mitigate this effect comes at the expense of fewer fractures in the available space. This study investigates both decline mechanisms and design optimisation strategies to combat them in the aforementioned scenarios. Since the thermal transients cannot be correctly estimated with a pseudo-transient approach, a fully transient model taking into account heat transfer in both the fracture and formation is necessary. Semi-analytical solutions of the energy equation are developed, and it is shown how thermal decline can be managed with a mass flow rate schedule. The results indicate that fracture geometry and resource temperature are by far the most significant contributors to efficient energy generation. Larger spacing between fractures helps arrest thermal decline, but this effect tends to diminish once the spacing is substantially greater than the thermal front progression, or if high mass flow rates cause early coalescing of the cold fronts from adjacent fractures. It is hoped that the results from this study will prove useful in the design of many enhanced and closed loop geothermal systems.

Topic: Enhanced Geothermal Systems

This study assesses the geothermal potential of the Berlin–Brandenburg region, with a particular focus on leveraging existing infrastructure, including legacy hydrocarbon wells and or deep drilling boreholes, for sustainable heat and baseload electricity supply. Two representative areas, Groß Schönebeck site and Lusatia region, serve as examples of a regional strategy that combines technical and economic feasibility with existing regulatory frameworks. Findings highlight the potential of repurposing wells including district heating with multi-layer of reservoir development schemes for low- and medium-enthalpy geothermal applications and seasonal Underground Thermal Energy Storage (UTES). Drawing on the Groß Schönebeck case study, the value of reusing existing wells can be maximized by identifying multiple formations with different geothermal application pathways. The technical aspects should focus on the economic viability of using existing infrastructure to extend the productive life of hydrocarbon, mineral, and water wells, as well as geothermal wells. This would allow for the optimum utilization of formations, depending on their technical and economic suitability in relation to the geothermal utilization technology. In the other hand, the Lusatia case study reveals a successful approach to evaluating UTES potential by identification of geothermal resources (temperature and reservoir locations) combined with an understanding of regional heating demand and existing district heating infrastructure. Critically, the regional energy transition plan leverages government support for geothermal project investment, beginning with exploratory activities like 2D seismic surveys. This study, encompassing a larger regional area, addresses the significant investment costs and exploration risks inherent in geothermal development. While technical assessments and demonstrable demand establish economic viability at the micro-scale, broader implementation of geothermal projects, particularly those utilizing existing infrastructure, requires a robust regulatory framework and supportive local policies. These elements are essential catalysts for attracting investment, streamlining permitting processes, and mitigating initial financial risks, ultimately enabling the widespread adoption of geothermal energy.

Topic: Field Studies

Potential-field geophysical data such as gravity can enhance understanding of geothermal resources at all stages of the resource life cycle, including assessment, exploration, development, and monitoring, and at multiple scales, from the reservoir scale to regional scale. However, to make gravity data useful for geothermal resource characterization, several processing steps are required to isolate the effects of density variations in the Earth’s crust to enable the identification of structural features associated with geothermal resources. Although this process is well-established, standard computational implementations for processing gravity data that are FAIR (Findable, Accessible, Interoperable, and Reproduceable) are still lacking. This paper details ongoing efforts at the U.S. Geological Survey (USGS) to develop a standard set of open-source Python tools for gravity data reduction that align with the FAIR principles. This workflow makes use of existing open-source tools for geophysical data processing with the goal of maximizing opportunities for rapid improvements, interoperability, and adaptability to other types of geophysical data.

Topic: Geophysics

As part of the update to the electric-grade conventional hydrothermal assessment of the Great Basin, USA, Monte Carlo analyses of identified resources within explored regions will be performed to make estimates of discovered resources and associated uncertainty. Analyses use conditional statistics where estimates are conditioned upon a hydrothermal favorability map, allowing for the likelihood that more resources exist in regions of higher hydrothermal favorability. For these analyses, a dataset of identified hydrothermal systems is compiled, and the new compilation is described herein. Recognizing that a single hydrothermal system may be developed with multiple power plants, and that the hydrothermal upflow zone may be several kilometers across with many measurements characterizing a single hydrothermal system, a procedure was developed and employed to create clusters of points (power plants, measurements, etc.) that are associated with a single system, and a new central point was defined as the best estimator of the center of the hydrothermal system. Hydrothermal systems were uniquely identified by grouping electric-grade hydrothermal measurements and operating power plants within a distance of 10 km. Groups that are greater than 10 km apart are assumed to be different electric-grade hydrothermal systems. While 10 km was used as the threshold, most systems were significantly further apart, and most points within groups were typically within 5 km of each other. A well measurement was considered an electric-grade measurement of a hydrothermal system if it had two properties: a measured temperature of greater than 85 °C and evidence of hydrothermal convection. Other points that were added to the dataset are locations of operating powerplants or locations that have been classified as an electric-grade hydrothermal resource by either the U.S Geological Survey (USGS) or the Great Basin Center for Geothermal Energy. After all points are assigned to systems, new points were computed with the goal of identifying the center of the throat of the hydrothermal upflow zone. If operating powerplants exist for a system, then the arithmetic average of all power plant locations is used. Otherwise, if USGS made an estimate, that location is used. In the absence of both powerplants or USGS estimates, the arithmetic average of all electric-grade measurement locations is used. An example is shown of how these newly compiled locations might be ranked for uncertainty analyses, where higher confidence is assumed if measured temperature is higher and there are many supporting measurements indicating an electric-grade resource. In summary, 28 systems have operating power plants, an additional 78 systems are known identified electric-grade hydrothermal resources, and 99 new systems were identified as probable electric-grade systems with varying levels of confidence. These 205 locations are shown as a function of a recent hydrothermal favorability map, conceptually illustrating the conditional statistics that can be used to make estimates of the undiscovered resources of the Great Basin. An accompanying data release provides summaries of developed capacity by system and USGS estimates of likely total capacity and associated uncertainty.

Topic: General

Mapping propped fractures and understanding proppant distribution within fractures is critical for the success of Enhanced Geothermal Systems (EGS) projects. Borehole electromagnetic (EM) measurements offer a promising method to image proppant distribution. Electrically conductive (EC) proppant enhances the EM contrast between propped fractures and the surrounding formations. However, EC proppants are expensive, necessitating their use in small concentrations mixed with normal proppants. Electrically conductive fluids are needed to further increase the EM response. This study investigates the use of carbon black suspensions as an alternative to traditional electrolytes to enhance the electrical conductivity of fracturing fluids while addressing the challenges of salt precipitation and corrosion. In addition, the effect of carbon black on fluid rheology was evaluated under high-pressure and high-temperature conditions to reduce the thermal effect on the fracturing fluid viscosity, to improve proppant transport and distribution within EGS fractures. Laboratory systems were designed to quantify the rheological properties and electrical conductivity of EC proppants and carbon black suspensions at varying concentrations under EGS conditions. Results show that carbon black suspensions can significantly increase the electrical conductivity of fracturing fluids. Low concentrations of CB (≈1 wt%) were tested at varying temperatures up to 200 °C, resulting in a 40% increase in the solution’s viscosity. Using 1% CB increases the electrical conductivity of the solution up to 0.5 s/m at 200 °C and 2000 psi. This study verifies the potential of carbon black suspensions for improving fracture mapping in EGS through borehole EM measurements while mitigating the drawbacks of electrolyte-based solutions and simultaneously improving the fluid viscosity performance under high-temperature geothermal conditions.

Topic: Enhanced Geothermal Systems

Quaise, a geothermal development and drilling company, has broken ground on a high-temperature geothermal power plant in Central Oregon called Project Obsidian. It is sited outside of and adjacent to the southern boundary of the Newberry National Volcanic Monument. The geothermal gradient at the site is believed to be about 100 °C/km on the basis of nearby well temperature logs, and the targeted vertical depth range is about 4.3-4.9 km. The subsurface at this depth is expected to have very low natural permeability. Thereby, the project is expected to be completed by fracturing between wells using modern EGS (enhanced geothermal systems) techniques, rather than as a conventional hydrothermal project. Two reservoirs are planned, with targeted average feedzone temperatures of 315 °C and 365 °C. Each reservoir is to be connected to one injector well and two producer wells, with the wellfield comprising six flowing wells altogether. The injectors have a tie-back design with a 7” outer diameter casing throughout; the producers have a similar casing in the feedzone, stepping up to a 9 5/8” outer diameter casing around 2.5 km TVD to improve the flow characteristics of the more-compressible produced geofluid. The wells are planned to be inclined at 45° in the feedzone, to balance the challenges of directional drilling at high temperatures with the need for significant horizontality with which to connect the wells using vertical fracture planes. The geofluid enthalpy at the producer feedzones is considered as a key unknown, and a finite-element compressible flow model was developed to assess its significance, and its relation to geofluid pressure and phase. This model was used to generate a set of productivity curves, showing that liquid-dominated production and vapor-dominated production represent lower and upper bounds, respectively, for exergetic power at the wellheads. Several plant configurations were considered, including dry steam, flash, cyclopentane-binary, and water-binary. The best-performing cycle showed a strong dependence on the phase of the geofluid at the producer wellheads. Overall, it was found that the proposed system has the potential to deliver at least 50 MWe net from a total of six flowing wells using a binary cycle regardless of the geofluid phase.

Topic: Enhanced Geothermal Systems

Enhanced Geothermal System (EGS) requires uniform fluid flow distribution through its engineered fracture zones for efficient heat extraction and balanced reservoir utilization. Data from the extended circulation test of August 2024 at Utah FORGE, revealed a highly localized flow with over 60% of the injected fluid recovered from the first three fracture zones. Such concentrated flow causes localized thermal stress and pressure spikes, which could result in degradation of fracture conductivity and performance over time. This study employs an analytical model, based on circuit analogies, to assess the effect on flow profile by modifying well orientation and fracture configuration. The base model is calibrated to match flow distribution, zone spacing, and well geometry of 16A(78)-32. Several scenarios for well spacing, with ten and fourteen fracture zones, in parallel and non-parallel (one angled and two angled) well orientations were simulated to identify strategies for improving flow uniformity at Utah FORGE. Fracture flow variation was observed to improve by over 20% with strategic addition of engineered fracture zones. Similarly, the change in well orientation led to increase in flow uniformity by 35%.

Topic: Enhanced Geothermal Systems

The injection well profile from the Fervo Energy commercial doublet well configuration shows considerable flow rate variability among multiple hydraulically fractured stages. Even with uniform flow among the fracture-driven interactions (FDIs), recent work suggests that the heal FDI flow rate will be about 16% greater than the rate at the toe of the downhole engineered heat exchanger (DEHE) under the reported circulation rate. This study assesses what fraction of the maximum recoverable heat the DEHE produces as a thermal recovery factor for DEHE configurations of interest. We define the remaining recoverable heat in a stimulated volume as the energy that can be transferred by reducing its average rock temperature to the final working temperature of the circulating fluid. The model for this study couples models for the flow circulation and heat transfer through the DEHE and the vertical injection and production wells, subject to boundary conditions required for the surface power generation. We define the thermal recovery factor as one minus the time dependent ratio between the original and remaining recoverable heat values, or simply the ratio between the rock temperature change from the original average rock temperature divided by the temperature difference between the original average rock temperature and the lowest plant inlet working fluid temperature for continued plant operation. Sensitivity studies quantify the variation in thermal recovery factors for a DEHE having identical FDI conductivities with variation between maximum and minimum FDI flow rates from less than 1% to 30%. We then quantify the expected thermal recovery factor for the published Fervo Energy injection well profile. This study illustrates the importance of the DEHE design and flow conformance on the thermal recovery efficiency of a DEHE. The thermal recovery factor may be improved by production well or plant workovers that raise the temperature of the produced fluid reaching the power plant inlet and/or enable a lower plant inlet fluid temperature.

Topic: Enhanced Geothermal Systems

Geothermal energy is emerging as a promising sustainable energy resource, particularly with increasing interest in exploiting high-temperature, high-pressure (HTHP) reservoirs. The use of downhole acoustic well logging tools is vital for monitoring casing and cement integrity. However, the development of technology for diagnostics in such extreme conditions remains challenging. Conventional acoustic well logging tools fail to obtain reliable measurements for prolonged periods under the combined effects of high pressure and temperature during exposure to highly corrosive fluids present in geothermal wells. Therefore, there is a need to better ruggedize acoustic logging tools for reliable operation and survival in these harsh conditions. We developed two design approaches to evaluate the passive cooling mechanisms of candidate material composites under HTHP conditions. The first approach focused on thermal energy storage by including layers of Phase Change Materials (PCMs) embedded between silicon aerogel insulation layers. The second method incorporated a vacuum layer enclosed between alternating PCM and silicon aerogel layers. Both designs were evaluated by implementing heat transfer equations in COMSOL Multiphysics under the finite element framework. We employed Fourier’s law and the conservation of energy equation to evaluate thermal resistance and heat flow in both configurations under HTHP condition. Results demonstrated that PCM layers significantly delayed temperature breakthrough by absorbing and storing thermal energy during phase change. Moreover, the hybrid PCM-silicon aerogel configuration significantly outperformed a single aerogel layer supporting enhanced thermal resistance and heat transfer delay at HTHP conditions. The second design with vacuum encapsulated between PCM and aerogel layers displayed the best thermal performance demonstrating the added benefits of controlling latent heat absorption/release. Our designs demonstrate a high potential for passive cooling via thermal energy storage and insulation essential in extended downhole acoustic monitoring of casing and cement integrity.

Topic: Emerging Technology

The thermo-mechanical response of igneous rocks to rapid temperature fluctuations governs both the heat-extraction efficiency in Enhanced Geothermal Systems (EGS) and the permeability development in engineered geological hydrogen systems. This study experimentally investigated the effects of thermal shock on the strength, stiffness, and fracture evolution of granite and ultramafic rocks to establish cross-domain insights into subsurface energy systems. Cylindrical granite and ultramafic specimens were characterized using micro-computed tomography (micro-CT) measurements, then subjected to controlled thermal shock treatments consisting of heating to 200 °C followed by rapid quenching in water at 0 °C or 20 °C to simulate cold-fluid injection into hot geothermal reservoirs. Micro-CT analysis reveals systematic porosity increases following thermal treatment, with heating alone producing minor increases of ~0.07–0.43 percentage points, while rapid quenching results in substantially larger porosity gains of up to ~1.0 percentage point in granite and ~0.8 percentage points in ultramafic samples. These microstructural changes are accompanied by reductions in elastic stiffness, with P- and S-wave velocities decreasing by approximately 5–15% and Young’s modulus decreasing by ~15–40% depending on lithology and quenching severity. Granite exhibits larger relative porosity increases and greater stiffness degradation under thermal shock, whereas ultramafic samples retain higher absolute velocities and moduli, indicating greater resistance to thermally induced damage. Together, the porosity–velocity–modulus response provides experimentally constrained insight into thermally driven fracture evolution and its role in permeability enhancement in enhanced geothermal systems.

Topic: Enhanced Geothermal Systems

[Eppink]

Extending Permeable Fracture Imaging at Newberry to Depth: Added Receiver-Coverage Area and Seismic Velocity Control J. EPPINK, P. MALIN, T. FLURE, F. HOROWITZ, A. MATHEWS, H. ONTIVEROS, A. STROUJKOVA, S. VALENZUELA T. FLEURE, W. MCLAIN, S. PASCHALL, C. SICKING A. T. CHEN, Z. WANG, ANDBONNEVILLE, [Duke University, USA]

In September 2025 we conducted a 3-week, 1,320 seismic ground level receiver, Permeable Fracture Imaging survey at the Newberry geothermal area, Oregon. The aim was to extend a previous, 2023, 982 receiver, PFI survey from ~2.2 km to over 3 km. The extension included adding (1) more receivers to cover a broader area (and hence adding depth) and (2) refining the seismic velocity-depth profile using surface vibroseis, behind casing distributed acoustic sensing (DAS), and a downhole propellant-sourced check shot (hence adding absolute travel time resolution and accuracy). We received support for both the 2023 and 2025 surveys from the Advance Research Project Agency – Energy (ARPA-E), and in 2025, from our industrial partner, Mazama Energy. The PFI method uses hundreds of time-synced seismic recorders to observe episodes of small seismic movements in connected permeability structures – the fluid filled joints, fractures, fracture zones, faults, and fault zone that are geothermal drilling targets. The signals are enhanced by stacking time-distance adjusted seismic signals for a subsurface volume of voxels. The voxel size depends on the density of receivers – roughly 36/km2 in both surveys. The depth penetration of PFI depends on uniform coverage over the target area plus a buffer area, the width of which needs to be ~1 times the depth of the target. In 2023 the area was 27 km2 , yielding a PFI depth of 2.2 km. In 2025, by adding 338 receivers at the same density, the area increased to 37 km2 and PFI depth to more than 3 km. In both cases, the resulting resolution was roughly 30x30x30 m voxels. The spatial accuracy of the PFI method depends on an accurate 3D seismic velocity model. This includes the need to know the varying thicknesses and velocities of near-surface sediments (such adjustments are known in O&G seismic reflection methods as “static corrections”) and the velocity profile all the way down to the bottom of the PFI target. To address this requirement, in the 2025 survey we employed (1) 3-D vibroseis-source profiling recorded into the 1,320-receiver surface net, (2) several ~200 m deep borehole sensors, (3) a 2,736 m long, cemented behind casing, DAS cable and (4) a propellant check shot at 3000 m depth. The vibroseis-to-surface net and ~200 m borehole receivers covered the upper velocity structure. The propellant check shot recorded on the DAS covered the mid and deeper velocity structure. The processing of the resulting terabyte volume of passive and active-source seismic data is currently in progress. We expect a significant improvement in the 2025 survey of PFI depth and location accuracy over what was possible with the 2023 data.

Topic: Emerging Technology

Enhanced Geothermal Systems (EGS) rely on the coupled chemical and mechanical behavior of natural and stimulated fractures to sustain permeability and ensure long-term reservoir stability. At the Utah FORGE site, granitic rocks contain mineral-filled natural fractures whose evolving properties under high-temperature conditions critically influence stimulation performance. This study integrates hydrothermal exposure experiments and micro-scale mechanical characterization to investigate how geochemical alteration modifies the micromechanical behavior of fracture minerals and interfaces, with the objective of deriving fracture-scale constraints relevant to proppant performance in the Utah FORGE reservoir. A representative granitic core sample extracted from a depth of 9,843 ft was subjected to hydrothermal exposure at 250 °C to simulate EGS reservoir conditions. Nanoindentation testing was performed before and after hydrothermal treatment to quantify changes in hardness and elastic modulus, while X-ray diffraction (XRD) and scanning electron microscopy coupled with energy-dispersive spectroscopy (SEM–EDS) were used to characterize mineralogical and microstructural evolution along fracture surfaces. Results indicate that hydrothermal interaction produces spatially heterogeneous chemical and mechanical modification of fracture walls, including the development of aluminosilicate alteration coatings, Fe–Al–rich reaction layers, and localized secondary precipitates. These alterations lead to systematic reductions in hardness and elastic modulus in fracture-proximal domains, while relatively unaltered quartz- and feldspar-rich regions retain higher stiffness and brittleness. Such fracture-scale heterogeneity implies non-uniform proppant–fracture contact conditions and evolving load-transfer behavior under EGS operating conditions. Rather than prescribing specific proppant materials, the results provide mineral- and alteration-dependent mechanical constraints that inform proppant design considerations for Utah FORGE, including resistance to embedment in chemically softened fracture zones, tolerance to variable surface compliance, and mechanical robustness against contact with brittle, quartz-dominated domains. By linking fracture geochemistry and micromechanical evolution, this study establishes a mechanistic basis for evaluating proppant performance in crystalline EGS reservoirs.

Topic: FORGE

Recent field investigations in the Lumut Balai geothermal field, South Sumatra, Indonesia, have identified previously unrecognized geothermal surface manifestations in the southern part of the producing area, within the Tanjung Tiga prospect. These manifestations comprise fumaroles, hot springs, mud pools, and hydrothermally altered grounds, expanding the known extent of surface expressions associated with the system. This study evaluates the geochemical characteristics of the newly identified manifestations to assess their connection to the main geothermal reservoir and to delineate the geothermal upflow zone. Water and gas samples were analyzed for major ion chemistry, and gas composition, complemented by in situ measurements of temperature and pH, following established geothermal geochemical approaches (Giggenbach, 1988; Nicholson, 1993). Results indicate that fumaroles in the Tanjung Tiga prospect area contain higher non-condensable gas (NCG) concentrations than those observed in the currently developed sector, suggesting elevated subsurface temperatures and closer proximity to the upflow zone. Geothermometric calculations, including aqueous and gas geothermometers, estimate reservoir temperatures of approximately 275–300 °C beneath the Tanjung Tiga prospect, consistent with high-temperature upflow conditions (D’Amore and Truesdell, 1985). These integrated geochemical findings refined the conceptual model of the Lumut Balai geothermal system and provide a robust basis for upflow zone delineation and future exploration targeting in the southern sector of the field.

Topic: Geochemistry

The Galleries-to-Calories Geobattery concept explores the use of abandoned coal mine workings for large-scale thermal energy transport and storage. The system involves injecting waste heat from a supercomputing facility into flooded mine galleries, where groundwater flow can store and transport thermal energy for potential recovery in downgradient district heating and cooling applications. To evaluate the feasibility and performance of the Geobattery under geological and operational uncertainty, we developed a suite of stochastic thermo-hydrological (TH) simulations using Monte Carlo sampling of key uncertain parameters (e.g., permeability, porosity, thermal conductivity, specific heat capacity) and operating conditions (e.g., injection rate, injection temperature). Results identified injection rate and temperature as the most influential parameters governing thermal front propagation, while the geometry of the room-and-pillar structure played a critical role in directing the extent and orientation of thermal advancement. Optimal combinations of material properties for maximizing heat recovery were also determined. To address the high computational cost of coupled-process stochastic modeling, we trained a neural network surrogate model on 24,000 physics-based realizations, achieving an R² greater than 0.99 and MAE less than 0.1 for temperature predictions at monitoring locations. This surrogate enabled an additional 100,000 realizations for global sensitivity analysis and probabilistic thermal resource assessment. The integrated stochastic physics–surrogate modeling framework offers a computationally efficient tool for quantifying uncertainty, identifying key drivers, and informing early-stage design decisions for Geobattery systems.

Topic: Modeling

Accurately predicting flow and thermal performance in fractured reservoirs is essential for the development and optimization of enhanced geothermal systems (EGS). Fracture geometry, connectivity, and heterogeneity strongly control reservoir behavior, but these features are high-dimensional and difficult to observe directly, leading to significant uncertainty in flow and thermal predictions. A key challenge is how to efficiently tune fracture networks using limited observations to reduce the prediction uncertainty. In this work, we propose a latent generative modeling framework to parameterize discrete fracture networks (DFNs) with low-dimensional latent variables while preserving fracture geometry and connectivity. The model is trained on ensembles of 2D DFNs and can generate new realizations that are visually and statistically consistent with the training data. We integrate this generative representation with embedded discrete fracture model (EDFM) simulations and apply an ensemble-based data assimilation method for history matching. By assimilating temperature and tracer observations, this framework updates the latent variables and tune fracture networks that better match observed data. We validate the method using a synthetic 2D EGS test case. The posterior results present significant uncertainty reduction in temperature predictions, along with fracture networks that more closely agree with the ‘true’ synthetic fracture networks. This study demonstrates the potential of deep generative modeling for efficient fracture parameterization and uncertainty reduction in geothermal reservoir characterization.

Topic: Modeling

Favorable structural settings (FSS) along Quaternary faults control the location of many higher temperature geothermal systems in the Great Basin region (GBR) of the western USA, which includes most of NV, western UT, southern ID, southeast OR, and eastern CA. They include various fault interaction zones, such as terminations, intersections, step-overs (or relay ramps), and accommodation zones in normal fault systems, as well as pull-aparts and displacement transfer zones in the transtensional western part of the GBR. FSS are commonly critically stressed and characterized by structural complexity, closely-spaced faults, and greater proportions of fault breccia vs. fault gouge, all of which can enhance permeability and thus result in long-term, deeply rooted fluid flow. FSS are critical for vectoring into areas of greater permeability in known geothermal systems and for identifying potential locations of hidden geothermal systems. A major objective of the INGENIOUS project (INnovative Geothermal Exploration through Novel Investigations of Undiscovered Systems) is to generate new geothermal favorability maps for the GBR through compilation and integration of 16 regional geological and geophysical datasets, including FSS. Using available imagery (NAIP, Lidar), geological maps, and geophysical data (mainly gravity), we have identified greater than 1,430 FSS in the GBR. Each FSS was outlined with geologically grounded polygons, which collectively occupy ~7.7% of the study area. Step-overs were the most common accounting for ~40% of FSS followed by fault intersections (26.1%), fault terminations (16.7%), accommodation zones (6.8%), pull-aparts (2.3%), and displacement transfer zones (1.4%). For the 403 known geothermal systems in the GBR, with temperatures ≥37°C, step-overs are again the most common FSS (~27.5%) followed by fault intersections (22.1%), fault terminations (16.6%), accommodation zones (5.7%), displacement transfer zones (3.2%), pull-aparts (2.7%), and major normal faults (2.2%). For 120 systems with documented temperatures ≥120°C, which have been used as training sites for geothermal play fairway analyses, FSS include step-overs (34.2%), fault intersections (26.7%), fault terminations (14.2%), displacement transfer zones (6.7%), accommodation zones (5.8%), pull-aparts (5.0%), and major normal faults (1.7%). The greater than 1,430 FSS, 403 KGS, and 120 training sites in the INGENIOUS study area are all minimums. The number of KGS’s and training sites does not account for an unknown amount of hidden geothermal systems, which probably make up the bulk of geothermal resources in the GBR. Further, the lack of detailed geological (e.g., geological maps) and geophysical (e.g., gravity) datasets greatly limits identification of FSS, especially in the many basins. Notably, many FSS (e.g. fault tips and accommodation zones) are characterized by closely-spaced, relatively minor faults with minimal recent surface ruptures. Further, much of the GBR was inundated by late Pleistocene lakes, and thus faults that have not ruptured in the Holocene are obscured by lake sediments and shoreline features. Detailed gravity surveys are particularly crucial for delineating FSS within and along the margins of basins. Most basins contain multiple FSS, raising the question as to how many independent geothermal systems can such basins host. If such basins contain multiple systems, the geothermal potential of the GBR may be underestimated, especially considering that conductive heat envelopes conducive to EGS development may accompany convective systems. Regional assessments of FSS are therefore imperative for assessing and ultimately unleashing the full geothermal potential of the GBR.

Topic: Geology

The Utah FORGE (Frontier Observatory for Research in Geothermal Energy) project, a U.S. Department of Energy initiative located near Milford, Utah, aims to advance EGS technology. In April 2024, eight new stimulation stages (Stages 3R–10) were conducted in well 16A, following the initial stimulation series (Stages 1–3) in April 2022. Microseismic catalogs and fiber optic data reveal that the fractures stimulated in Stages 3R–6 closely align with that initially generated during Stage 3, suggesting reactivation of existing fractures rather than creation of new fractures in this recent stimulation campaign. To investigate this hypothesis, we adopt a coupled thermo-hydro-mechanical and earthquake (THM+E) simulation workflow to analyze the stimulation activity in well 16(A)78-32, with the primary objective to confirm whether Stages 3R–6 reactivated fractures initially formed in Stage 3. The workflow comprises two sequential modeling steps. Specifically, the first step involves a continuum-based fully coupled THM simulation that incorporates an upscaled permeability field to represent discrete fracture networks. The THM simulation outputs are then post-processed and transferred to an earthquake simulator to model the induced seismic events. Numerical results have illustrated acceptable agreement with the field injection pressure for each stage, when the THM modeling setup includes previously stimulated fracture in the simulation of subsequent stages. Additionally, the full THM+E simulations were conducted, with the purpose to compare the seismic catalog with the field observation. The simulation results have demonstrated a moveout pattern of seismic events away from the injection point through Stages 3–5, showing quantitative similarity to the field observation. Conclusively, these coupled simulation results support the hypothesis that the recent stimulation stages may not generate new fractures, but instead reactivated the same fracture formed in the previous Stage 3 stimulation.

Topic: FORGE

[Finnila]

Identification of Fracture Flow Pathways at Utah FORGE Following Stimulation Activities in 2022 and 2024 Aleta FINNILA [WSP USA, Inc., USA]

A comprehensive update to the Reference Discrete Fracture Network (DFN) model for the Frontier Observatory for Research in Geothermal Energy (FORGE) site near Milford, Utah, has been completed. This revision was informed by the identification of flow pathways between wells 16A(78)-32 and 16B(78)-32 following stimulation activities conducted in 2022 and 2024. Designated as the Utah FORGE 2025 v1 DFN, the revised model includes 131 discrete planar fractures with radius values ranging from 14 to 780 m and 19,544 stochastic fractures located away from well control with radius values ranging from 20 to 149 m. Discrete fractures in the DFN were identified using updated microearthquake data from surface arrays and deep geophones, fracture interpretations from FMI and UBI logs (with aperture estimates when available), K-cluster rock type analysis from various well logs, frac hit data, and core samples. This paper describes the methodology used for mapping fracture pathways in the reservoir. While fracture geometry is detailed in the revised DFN model, hydraulic properties are not assigned. Notably, natural fractures primarily account for the observed stimulated flow in this model, with just a few induced hydraulic fractures added to connect the natural fracture pathways to some well casing perforation intervals.

Topic: FORGE

Enhanced Geothermal Systems (EGS) using induced and natural fractures require uniform fluid flow distribution for the most economic power production. An extended circulation test of August 2024 at the Utah FORGE Site between two extended reach wells completed with “Plug and Perf” methods yielded non-uniform flow between the wells in the induced fractures from the first three fracture zones. To overcome the differences in fracture conductivity between wells and wellbore friction that is the root of the non-uniform flow, a low-cost and rapid multistage fracture stimulation technology with cemented casing frac sleeves that also have the ability to regulate flow through the sleeve is being developed and tested with a high temperature tractor to detect and control flow of heat-carrier fluid. This paper reports on the progress of the development of a second-generation sleeve, actuation system, and high temperature tractor, with the goal to provide a uniform injection profile, regardless of the conductivity of fractures between injection and producing wells. Modeling has shown that conformance control may provide a 50% uplift in power generation over a 30-year life as compared to wells without conformance control, for similar costs and with less stress shadowing and a lower seismicity risk.

Topic: Enhanced Geothermal Systems

We conducted high-temperature triaxial direct-shear (TDS) experiments to investigate the coupled thermo–hydro–mechanical–chemical (THMC) processes controlling fracture creation, deformation, permeability evolution, and geochemical reactivity under conditions representative of the Utah FORGE enhanced geothermal system (EGS) reservoir. Rock specimens were collected from the FORGE well 16A(78)-32 and tested at confining pressures of 36.1 MPa, pore pressures of 22 MPa, and temperatures up to 210 ± 15 °C. The experiments enabled in-situ fracture creation, permeability measurements, mechanical characterization, and effluent geochemical sampling and analysis. Results show that shear-induced fracturing can increase bulk permeability by several orders of magnitude, although permeability evolution remains highly sensitive to shear displacement, stress cycling, temperature, and chemical reactions. High-temperature tests generate shear fractures with low fracture dilation angles (3°–7°), substantially smaller than those measured in comparable low-temperature experiments, suggesting a strong thermal control on shear fracture deformation behavior. Geochemical observations indicate rapid mineral dissolution following fracture creation and evidence for secondary mineral precipitation. Together, these results provide critical insights on fracture flow behavior, THMC coupling, and reservoir simulation at the FORGE site. This work also provides detailed documentation of experimental methods and data interpretation, supporting the dataset archived in the Geothermal Data Repository (GDR) (Frash et al., 2023).

Topic: FORGE

We tested an exploratory 152-m geothermal borehole at a site in the United States Army Garrison, West Point, NY, as part of a Department of Energy (DOE) project to assess the site's geothermal potential. The test borehole site is located about 8.8 km southwest of the academic campus in the Hudson Highlands. The geology of these highlands comprises hard metamorphic rocks and shale, with igneous rock intrusions within a complex formation history and folding, as documented by borehole geophysics deployed at the site and cuttings examined during this field effort. A conventional thermal response test (C-TRT) at the site measured the composite thermal conductivity to be 2.82 W m-1 K-1. To explore the vertical variability in the composite C-TRT thermal conductivity result, we also deployed a value-added optical Sensornet Distributed Temperature Sensing (DTS) interrogator to measure the temperature time history along the borehole depth. We instrumented the borehole with two multimode fiberoptic cables: one inside a 3.8-cm-inside-diameter HDPE circulation pipe and another outside the circulation pipe. The results allow evaluation of thermal conductivity with depth and the relationships between those parameters and different rock types and layers in the formation. Our DTS results indicated thermal conductivity values ranging from 1.3 to 3.6 W m-1 K-1, both of which support the variability of thermal properties in metamorphized rocks and the range of values that depend on mineralogical content, dipping beds, faulting, and other features. These distributed results can guide the design of more efficient geothermal energy systems (e.g., optimal depth and spacing).

Topic: Field Studies

Aquifer Thermal Energy Storage (ATES) offers a sustainable, low-carbon heating and cooling solution for the built environment. However, maintaining ATES system efficiency requires careful optimisation of both design and operation, involving computationally expensive numerical simulations of groundwater flow and heat transport in heterogeneous aquifers. Machine Learning (ML) provides a rapid modelling alternative to conventional numerical simulations of complex subsurface flow and transport processes. Here, we introduce the Adaptive Physics Transformer (APT), a transformer-based ML model employing an auto-regressive approach with native support for adaptive meshing. Unlike conventional ML models such as Convolutional Neural Networks (CNNs), Graph Neural Networks (GNNs), or Neural Operators, which require interpolation onto fixed grids, APT seamlessly handles arbitrary gridding schemes that adapt dynamically at each timestep throughout the simulation rollout. The APT model is trained using outputs on adaptive meshes from the open-source Imperial College Finite Element Reservoir Simulator (IC-FERST), a high-order reservoir simulator that employs dynamic unstructured mesh optimisation to enhance solution accuracy and reduce computational costs compared to fixed-grid methods. Consequently, the mesh evolves adaptively between the solution snapshots used during training. High spatial resolution is essential to accurately capture detailed variations in pressure, flow, and temperature fields; adaptive meshing achieves this efficiently by dynamically adjusting mesh resolution where required. The native support of adaptive mesh data in APT eliminates the need for interpolation, reduces potential sources of error, and enables the model to directly learn the underlying physics and transport processes. Our experiments with a synthetic ATES dataset demonstrate that the APT model significantly accelerates simulations, reducing the runtime of a 10-year ATES scenario from tens of hours to mere seconds, while maintaining high accuracy.

Topic: Modeling

Why should we be concerned about geothermal reserves standards? Unlike the petroleum industry, the geothermal industry has no universally recognized set of guidelines, standards, or protocols to guide what are called ‘reserves’ or ‘resources’ in technical evaluations, financial statements and company annual reports. Consistency in reserves and resources classifications (wherein reserves are the commercially viable subset of resources), estimation methodologies, and the related disclosures is needed by geothermal asset teams, investors, regulators, and corporate management teams to geothermal opportunities and clearly communicate the differences using terms that are well defined and understood. In our previous work (Gardner and Faulder 2024), we explored the applicability to the formulation of a classification framework for geothermal resources based on the SPE Petroleum Resources Management System (SPE-PRMS) and proposed an initial geothermal resources management system (GRMS). In this study, we will provide practical examples from certain geothermal projects and interpretations for applying the GRMS based on SPE-PRMS concepts. This work aims to provide case studies to assist geothermal professionals in: 1) determining a geothermal project, 2) classifying resources based on commercial maturity, 3) quantifying and categorizing resources based on technical uncertainty, 4) and designating the development status of resources, all using the same framework. While we recognize that certain situations may arise requiring a departure from the PRMS as a guideline, the PRMS for hydrocarbons provides a good analogy and framework for the establishment of a GRMS and has an important advantage by being familiar and accepted by many energy stakeholders, including many new entrants into the geothermal market space. The adoption and use of the GRMS are strategic to aid in the development and growth of clean and sustainable geothermal energy by promoting consistency, reliability, and transparency in estimates and reporting, which in turn help open the gates for greater geothermal investment.

Topic: General

Wendover Graben in the Great Salt Lake Desert (GSLD), Utah, has been identified as a potential resource of both geothermal energy and lithium (Li+) extraction. Facilities capable of Li+ removal constructed as part of a geothermal power plant could increase Li+ availability and improve costs associated with both geothermal and Li+ extraction. Previous work on Wendover Graben has suggested a high geothermal gradient and reservoir temperature greater than 200°C, facilitated by circulation of hot water through faults from deeper, carbonate and sandstone aquifers (~7000 m thick), through a thin volcanic and tuff layer (100-400 m thick) up to shallower aquifers (~200-1,200 m thick) in the uppermost basin fill. Well data suggests aqueous Li+ concentration below 10 m depth in the basin fill aquifer approximately 17 ppm, and up to 41 ppm in the shallow brine (above 10 m depth). To investigate the potential for combining geothermal energy and Li+ extraction, a series of reactive transport models of Wendover Graben, parameterized using available data in the literature, were constructed in the reactive-transport code PFLOTRAN. Simulation results indicate that Li+ from dissolution of Li-bearing igneous minerals can be transported along with deep, hot water via faults to the basin fill aquifer, facilitating both increased Li+ concentration and precipitation of Li+ bearing clays at shallower depths. These results suggest a potential mechanism by which both increased Li+ concentration and hot ( greater than 200°C) water can be found at depths reasonable for well construction and geothermal power production. This supports the need for additional work to investigate Wendover Graben hydrogeology and mineralogy to improve model parameterization and further determine the location’s suitability for geothermal power production and potential co-extraction of dissolved Li+.

Topic: Modeling

An alternative design in multi-stage hydraulic fracturing for EGS is to create closely-spaced fractures that undergo shear deformation due to their mutual stress shadow. It is shown that by sequentially placing a number of hydraulic fractures close to one another, the induced shear leads to self-propping. The primary motivation for this approach is to avoid proppant use, which is a challenge under high temperature conditions. A few field and laboratory cases are presented to illustrate that fractures in hard granite rocks remain permeable even when they experience high stress conditions. The data shows that if shear deformation can be induced on neighboring hydraulic fractures, it can promote self-propping, lowering the near wellbore pressure drop and providing a permeable pathway between the injection and production wells. This would avoid the challenges associated with proppant availability and potential complications related to proppant transport into the surface facilities.

Topic: FORGE

Microearthquakes (MEQs), also known as microseismic events, are weak seismicity with magnitudes below 3.0 that do not present any risk to nearby communities or infrastructures. Their occurrence is induced and thus inherent to geothermal field operations, playing an important role in monitoring changes in reservoir stress fields. Events typically occur when conditions in pre-existing faults or fracture networks change due to fluid extraction and brine injection, causing stress buildup that eventually reaches a threshold causing rock failure or slippage, releasing stored strain energy as MEQs. Mapping and analyzing the spatial distribution of these events can contribute to the development of injection management strategies especially when integrated with injection tracer test data. The same is also used to confirm the viability of an area as a drilling target. Spatial clustering of MEQs is employed to uncover patterns and trends, ultimately deriving valuable insights related to reservoir structures and dynamics. Currently, conventional methods like grid-based clustering calculate event density within fixed grids and has been proven to be effective in identifying anomalies or dense clusters. However, this approach struggles to distinguish nested clusters or account for the depth component of the events during clustering. To address these limitations, unsupervised machine learning algorithms have gained prominence in identifying significant patterns of arbitrary shapes within large datasets. In this study, the OPTICS (Ordering Points To Identify the Clustering Structure) algorithm, a density-based clustering method, is applied to a 3D spatial dataset of MEQ events from the Tiwi Geothermal Field between 2012 and 2017. This research aims to examine the impact of input parameters on clustering solutions and identify regions of interest for detailed analysis.

Topic: Geophysics

This paper presents the first successful drilling and completion of a twinned geothermal well pair in a 330 °C volcanic reservoir, achieving a step-change in performance and reliability. The project demonstrated precise placement of a new production wellbore (55A-29) within 2 m of its planned trajectory and 90 m of an existing well, enabling a controlled hydraulic connection under extreme conditions. Through system-level integration of optimized BHA design, thermal management, and operational discipline, the campaign reduced on-bottom drilling time by 45% (from 40 to 22 days) and increased the average rate of penetration (ROP) by 150–300% compared to offset wells. Critically, over 120 cumulative circulating hours above 300 °C were achieved with zero downhole motor or MWD failures. The efficiencies achieved indicate that much deeper geothermal wells to access greater than 300 °C resources at other locations can be drilled reliably and economically with conventional tools. The results provide a scalable pathway toward superhot ( greater than 400 °C) geothermal resource development.

Topic: Drilling

The deployment of Enhanced Geothermal Systems (EGS) at reservoir temperatures exceeding 300 °C presents unique technical challenges and opportunities for advancing geothermal energy production through the harnessing of higher enthalpy resources. Building on the successful completion and stimulation of the injector well in Phase I, this paper presents the design, testing, and field implementation of the producer well in the world’s first propped EGS doublet at ultra-high temperature conditions at Newberry Volcano, Oregon. A segmented stimulation strategy with a hybrid fluid design including crosslinked fluids and a hybrid completion in terms of wellbore to reservoir connection was developed for the producer well, incorporating field experience from the injector stimulation, real-time diagnostics and adaptive planning of treatment volumes. The approach integrates distributed temperature sensing (DTS) and distributed acoustic sensing (DAS) via permanent fiber optic installation in the injector well, enabling cross-well monitoring during stimulation of the producer. Nano tracers were deployed in the producer well to provide flow path characterization, while micro seismic activity was monitored using multiple array set ups and fiber inferred DAS data. The Phase II program emphasizes the importance of iterative design, real-time data connection, and advanced stimulation diagnostics to optimize fracture propagation and maximize the probability of hydraulic connection between wells. This work documents the methods, results, and lessons learned from the Phase II completion and stimulation, culminating in the anticipated connection of the wells to enable future circulation and heat harvesting. The findings provide critical insights for the advancement of next-generation EGS technologies at ultra-high temperatures and pave the path to de-risking technologies for superhot rock.

Topic: Enhanced Geothermal Systems

[Gudmundsdottir]

Neural Network–Based Short Term Forecasting of Water Levels in a Low-Temperature Geothermal Field Halldora GUDMUNDSDOTTIR, Roland N. HORNE [Stanford University, USA]

Low-temperature geothermal fields are a critical component of district heating systems in Iceland, where short term fluctuations in heat demand and reservoir conditions can pose operational challenges. In such systems, the ability to reliably predict short term water level behavior in production wells is essential for ensuring secure heat delivery, particularly during periods of extreme weather. This study explores neural network–based time series models for short term prediction of water levels in a low-temperature geothermal reservoir. Using operational data from the Laugaland geothermal field in Iceland, multilayer perceptron (MLP) models are developed to predict water level dynamics based on production and injection rates. Model performance is evaluated under direct and recursive forecasting scenarios, with emphasis on robustness, uncertainty, and operational relevance. The results show that MLP models incorporating lagged inputs and target feedback accurately reproduce short term water level behavior and provide stable predictions across multiple initializations. Recursive predictions reveal increasing uncertainty with longer predictions horizons, and a scenario-based application illustrates how the models can be used to assess the risk of water levels approaching critical pump depth under sustained high-demand conditions. While not intended as a replacement for physics-based reservoir models, the findings suggest that neural network time series models can provide practical and computationally efficient decision support for short term management of low-temperature geothermal district heating systems.

Topic: Modeling

We investigate the growth of a hydro-shearing rupture along an existing fracture where the injection pressure is not controlled to remain below the fracture normal in-situ stress. As a result, hydraulic fracturing of the hydro-sheared fracture occurs (also named hydraulic jacking). We focus on the case of planar three-dimensional circular ruptures, which is geometrically simple yet practically relevant. We demonstrate that two fronts propagate along the existing fracture: a shearing front and an opening front. The latter follows the well-known zero-toughness (viscosity-dominated) solution for a penny-shaped hydraulic fracture, although pore fluid pressure diffuses ahead of the opening front. The shearing front lies ahead of the opening front with an amplification that depends on the stress criticality (in-situ shear stress over initial frictional strength), and the pore-pressure profile resulting from the leakage of fluid ahead of the opening front. Using scaling analysis and fully coupled hydro-mechanical simulations, we show that diffusion ahead of the opening front slowly becomes of order one at large times, with an intensity that mostly depends on the ratio between the characteristic over-pressure for radial fluid flow in the intact fracture and the in-situ normal effective stresses. The extent of the frictional shear rupture ahead of the opening front also depends on stress criticality, defined as the ratio between the initial shear stress and the initial frictional strength of the fracture.

Topic: Enhanced Geothermal Systems

Accurately quantifying porosity in reservoirs is essential for optimizing geothermal resource exploration and subsurface resource evaluation. Conventional predictive methods, such as density porosity models, often have limited accuracy, which can impede effective reservoir characterization. To overcome these limitations, this study leverages advanced machine learning (ML) techniques including AdaBoost, XGBoost, Gradient Boosting, LightGBM (LGBM), and ExtraTrees to predict porosity using well log data. ML offers a powerful alternative by leveraging data-driven approaches to uncover complex, nonlinear relationships between well log responses and porosity. Feature selection techniques, including correlation analysis from heat maps and feature importance are employed to identify well log data relationships. A comprehensive comparative analysis of well log data from two wells in North Dakota demonstrates that the comparative ML-based approach could be utilized to predict porosity effectively. The robustness of the data-driven models is validated through 5-fold cross-validation to confirm its reliability. Additionally, blind testing on a second well further verifies the model’s generalization capability and practical applicability. The results highlight the strong potential of machine learning in enhancing porosity estimation for geothermal reservoirs. By providing more precise and efficient predictions, this ML-driven framework can support better decision-making in geothermal exploration and development, subsurface characterization, reservoir modeling uncertainty, ultimately contributing to more sustainable and cost-effective energy extraction.

Topic: Reservoir Engineering

Data centers are projected to account for up to 12% of total U.S. electricity demand by 2028 according to Lawrence Berkeley National Laboratory, up from 4.4% in 2023. Expanding electricity system infrastructure to reliably serve this rapid data center demand growth is one of the largest near-term challenges that the U.S. electricity system faces. In addition to increasing power demand, rapid data center growth could drastically increase water demand for cooling if evaporative cooling is used. If dry cooling and air-cooled chillers are used to reduce data center water consumption, cooling would drive peak data center demand, which in turn drives the electricity system investments needed to serve that demand. Cold reservoir thermal energy storage (RTES), a form of cold underground thermal energy storage (UTES), can be used to shift data center cooling loads to off-peak hours, reducing electricity system costs while also reducing data center water consumption. Using advanced, open-source power system modeling tools GenX and ReEDS, this paper investigates the impact of RTES for data center cooling on the bulk power system. We estimate the electricity system investment and operational cost savings that RTES could provide and evaluate the impact of RTES system duration on these savings. We find that seasonal RTES could reduce the grid cost of adding data center capacity by 3% to 6% in Virginia. These savings are primarily achieved by reducing cooling demand during net peak load hours, which decreases the firm generation capacity required to meet the planning reserve margin with additional data center load. This firm capacity reduction could be achieved with durations as short as 12 hours in Virginia. These findings suggest that RTES for data center cooling could appreciably lower the power system costs of serving rapidly growing data center load.

Topic: Modeling

Multi-stage hydraulic fracturing is widely used in Enhanced Geothermal Systems (EGS) to create extensive fracture networks, which serve as flow pathways between injector and producer wells. Optimizing well placement requires reliable constraints on fracture geometry, such as height, length, and connectivity, which in EGS remains poorly understood due to limited direct observations. Cross-well distributed fiber-optic strain measurements in offset monitoring wells have proven highly effective for inferring fracture geometry and have reshaped understanding in unconventional reservoirs. In this study, we interpret cross-well fiber data acquired at the FORGE (Frontier Observatory for Research in Geothermal Energy) EGS site and integrate the results with microseismic locations and imaging results to characterize the stimulated fracture geometry. We analyzed cross-well fiber strain data to identify fracture hits in the offset monitoring well. Fracture hits were detected using a multi-attribute approach combining strain rate, strain gradient, and displacement signals. An in-house forward geomechanics model has been used to simulate strain responses under varying conditions. This enables us to interpret the abnormal strain signatures observed in EGS that differ from the typical responses in unconventional reservoirs. We refined our interpretations with microseismic analysis and natural fracture characterization. We have detected 21 fracture hits, which clustered within three depth intervals in the monitoring well—8,771–8,996 ft, 9,432–9,502 ft, and 9,742–9,787 ft—with inferred fracture spacing of ~15–35 ft. Many fractures reopened two to three times during late-stage pumping. On average, newly formed fractures reached the monitoring well after 132 minutes, whereas reopening occurred within 64 minutes. We generated a cross-section view by connecting perforation and fracture-hit location and calculated fracture dip angle, assuming the strike direction coincides with the maximum horizontal stress orientation of 78° relative to the wellbore toe side. The dip angles range from 58° - 102°, with only two fractures dipping toward the toe side. Forward geomechanical modeling using a fracture strike of 78° and dip of 60° reproduces the prominent asymmetric, heart-shaped strain signature observed in Stage 8. The consistency between the local and global dip angles indicates that the hydraulic fracture likely dips 59° from horizontal in stage 8, which is consistent with the conclusion drawn from the in-situ stress analysis. In the cross-sectional view, the inferred fracture propagation direction aligns well with the microseismic event distribution in Stages 3 through 7. However, in Stage 8, the fracture hits occurred first, followed by microseismic activity along a different trajectory. This observation indicates that the hydraulic fracture intersected the 16B well and reactivated a pre-existing natural fracture. The integrated analysis of Stages 8-10 supports the hypothesis that the local Sᵥ is not the principal stress, which explains the hydraulic fracture dipping 59° observed in Stage 8. Our results advance understanding of fracture propagation and geometry in EGS and highlight the value of distributed fiber-optic sensing (DFOS) for geothermal fracture diagnostics. The findings provide key inputs for optimizing injector–producer placement, including both vertical and horizontal well spacing.

Topic: Enhanced Geothermal Systems

Geothermal field development involves complex processes that require multi-disciplinary expertise across domains. Decision-making often demands the integration of geological, geophysical, and reservoir engineering insights, and input from operational teams, drilling engineers, and business units focused on project viability and profitability — all under tight temporal and financial constraints. We present GAIA (Geothermal Analytics and Intelligent Agent), an AI-based system for automation and assistance in geothermal field development. GAIA consists of three core components: GAIA Agent, GAIA Chat, and GAIA DT (Digital Twin), which together constitute an agentic retrieval-augmented generation (RAG) workflow. Specifically, GAIA Agent, powered by a pre-trained large language model (LLM), designs and manages task pipelines by autonomously querying knowledge bases and orchestrating multi-step analyses. GAIA DT encapsulates classical and surrogate physics models, which, combined with built-in domain-specific subroutines and visualization tools, enable predictive modeling of geothermal systems. Lastly, GAIA Chat serves as a web-based interface for users, featuring a ChatGPT-like layout with additional functionalities such as interactive visualizations, parameter controls, and in-context document retrieval. To ensure GAIA’s specialized capability for handling complex geothermal-related tasks, we curated a test set comprising various geothermal-related use cases, and we rigorously and continuously evaluate the system’s performance. GAIA is designed to support a wide range of stakeholders, including operators, researchers, and regulators, by providing actionable insights and tailored analytical workflows suited to their specific needs. With its innovative agentic RAG approach, we envision GAIA as a pioneering step toward intelligent geothermal field development, capable of assisting human experts in decision-making, accelerating project workflows, and ultimately enabling automation of the development process.

Topic: Emerging Technology

The Basin and Range Province of the United States is an area of interest for geothermal power development due to the extended continental crust of the Basin and Range Province providing a tectonic mechanism to bring mantle heat close to the Earth’s surface. In addition, the thick accumulations of highly permeable Cenozoic sedimentary rocks that have accumulated in many of the basins may provide large pore volumes that at depth could be quite warm based on prospective geothermal gradients in some areas. The closed nature of many of the Basin and Range basins ensures that weathering products from igneous rocks (such as lithium and critical minerals) are trapped within the same pore volumes of water. This study examines the Great Salt Lake area (Utah, USA) extending as far west as Wendover for its potential to host stratiform geothermal resources as well as lithium and other critical minerals. Based on mapping by the US Geological Survey, three prospective basins with thick sedimentary accumulations were identified for resource assessment. The Wendover Graben was chosen because of high local geothermal gradients, it hosting active potash brine mining from both shallow and deep brines, lithium presence in produced brines, and local domestic direct use geothermal activity. Two larger basins under the Great Salt Lake were chosen for the presence of geothermal springs in the vicinity, presence of lithium in the Great Salt Lake water, and proximity to a large offtake for geothermal power (Salt Lake City). Preliminary in-place geothermal and lithium resource assessments were developed based on high, medium, and low values for porosity, lithium concentrations, and geothermal gradient. In the mid-case, these suggest approximately 10^10 MWh reservoir thermal energy and 8300 ktonnes of LiCO3-equivalent for the Wendover Graben, and for each of the two basins under Salt Lake approximately 6 x10^10 MWh reservoir thermal energy and 100,000 ktonnes LiCO3-equivalent. Recoverable values are likely lower. Sandia National Laboratories is a multimission laboratory operated by National Technology and Engineering Solutions of Sandia LLC, a wholly owned subsidiary of Honeywell International Inc., for the U.S. Department of Energy's National Nuclear Security Administration. SAND2025-12854C

Topic: Geology

Kyle Haustveit was confirmed as the 16th Assistant Secretary for the U.S. Department of Energy’s Office of Fossil Energy, now the Hydrocarbons and Geothermal Energy Office (HGEO), on September 18, 2025. In this role, Mr. Haustveit oversees HGEO and National Energy Technology Laboratory (NETL) programs, managing a $5 billion research and development portfolio in coal, oil, natural gas, and critical minerals, with the goal of advancing affordable and reliable energy solutions. Prior to joining the Department of Energy, Mr. Haustveit served as a professional petroleum engineer in various technical and leadership roles at Devon Energy. A native of North Dakota, Mr. Haustveit represents a third generation of energy workers, maintaining strong connections to both the energy and agriculture sectors. Throughout his career, he has led teams responsible for developing and commercializing trailblazing diagnostic techniques now utilized globally to optimize hydraulic fracturing and resource development. Subsequently, he directed an Energy Ventures team, focusing on investments in next-generation energy technologies, including geothermal, carbon utilization, lithium extraction, and produced water treatment. Mr. Haustveit holds a petroleum engineering degree from Montana Tech and an MBA in energy from the University of Oklahoma.

Topic: Introduction

It is a well-established concern that uncertainty in effective interwell heat transfer areas introduce significant financial risk. This is true, because heat transfer area and mass flow rates determine transient production well temperatures. Here, a simple method to predict thermal performance that already exists in peer-reviewed literature is presented in a pedagogical fashion. The method utilizes joint pressure-tracer calibration to determine effective heat transfer area. Using a suitable analytical model for heat transfer, one can then readily predict thermal performance. Several case studies are presented, including uncertainty analysis. The results emphasize the necessity of performing both tracer tests and pressure analysis.

Topic: Reservoir Engineering

Closed-loop shallow geothermal systems are one of the key technologies for decarbonizing the residential heating and cooling sector. The primary type of these systems involves vertical borehole heat exchangers (BHEs). During the planning phase, it is essential to find the optimal design for these systems, including the depth and spatial arrangement of the BHEs. In this work, we have developed a novel approach to find the optimal design of BHE fields, taking into account constraints such as temperature limits of the heat carrier fluid. These limits correspond to the regulatory practices applied during the planning phase. The approach uses a finite line source model to simulate temperature changes in the ground in combination with the analytical model of heat transport within the boreholes. Our approach is demonstrated using realistic scenarios and is expected to improve current practice in the planning and design of BHE systems.

Topic: Low Temperature

[Horne1]

Introduction to the 51st Stanford Geothermal Workshop Roland HORNE [Stanford University, USA]

The 2026 Stanford Geothermal Workshop is the 51st time that the workshop has been held. This short overview will describe the background and the recent history of the workshop. The first Stanford Geothermal Workshop was held in December 1975, as the brainchild of Prof. Paul Kruger. Paul Kruger was one of the three founders of the Stanford Geothermal Program, the other two being Prof. Henry J. Ramey, Jr., and Prof. Lou London (Figure 1). In 1975, geothermal energy development was in its infancy in the US, but expanding rapidly as a response to the 1973 Energy Crisis. The Department of Energy was just being formed, out of the ashes of ERDA, the Energy Research and Development Agency. Given the large number of new projects and new researchers turning their expertise to the new field of geothermal energy, Paul Kruger’s concept was for a meeting at which researchers and developers could share their nascent ideas and learn from discussions with others while the projects were still in progress. Stanford Workshop papers were intended to be “work in progress” discussions, rather than completed scientific papers. The Stanford Geothermal Workshop was intended to be a proving ground for testing new ideas. It is called a workshop and not a conference for that reason. The informal style and organization of the Workshop follows this pattern to the present day. The focus on fostering innovative ideas and fruitful discussion is reflected in the “just in time” paper submission and collation process that is used. The Stanford Geothermal Workshop has served as a prototype for several other annual geothermal meetings around the world.

Topic: Introduction

The long-term effectiveness of hydraulic fracturing in geothermal and unconventional reservoirs critically depends on the ability of proppants to maintain open flow pathways under in-situ stress and temperature. This study presents a laboratory-based evaluation of proppant performance using a series of flow-through experiments designed to replicate reservoir-relevant conditions, including elevated confining pressures, high temperatures (up to 250 °C), and continuous fluid flow. Fracture conductivity is commonly used as the key parameter traditionally used in field-scale fracture design, so we report it as the primary measurable indicator of how proppants contribute to maintaining fracture conductivity over extended periods of loading. A suite of proppant-packed fracture analogs was constructed and tested to characterize their mechanical and thermal responses during progressive loading. The experiments captured how fracture conductivity evolves as a function of proppant type (resin coated, low density ceramic, pet coke, & Sand), grain strength, thermal stability, and interactions with the surrounding rock or bounding surfaces. Results show that conductivity degradation varies significantly among proppants: some materials retain permeability even under severe thermo-mechanical conditions, whereas others exhibit substantial loss due to embedment, compaction, thermal softening, or grain crushing. The results contribute to improving proppant selection and fracture-design strategies for high-stress, high-temperature reservoirs, where long-term fracture performance is essential for sustained production

Topic: Enhanced Geothermal Systems

In Enhanced Geothermal Systems (EGS), the placement of producers relative to injectors can play a very important role in controlling fluid flow patterns, fracture connectivity, and overall energy recovery. Improper placement can result in rapid thermal breakthroughs or reduced heat sweep efficiency. This study aims to (1) investigate how the relative angular alignment of the injector-producer pair influences heat recovery, and (2) provide quantitative design strategies for optimizing well placement to enhance long-term geothermal performance. A fully coupled reservoir-fracture-well simulator that models multi-phase flow, geomechanics, and thermal effects is employed to simulate the fluid circulation process and examine fracture propagation in EGS. It simulates the propagation, opening, and closing of propped fractures under the influence of thermo-poro-elastic stress. The geothermal heat recovery was simulated for different well placements. Changes in flow patterns and fracture geometry over time were analyzed, providing insights into fracture dynamics during geothermal recovery and their impact on overall efficiency. Simulation results demonstrate that well spacing and placement strongly influence heat recovery. Although late-time thermal power converges across all cases, cumulative thermal energy increases significantly with production-well elevation. Larger positive angles enhance buoyancy-driven circulation and sustain heat extraction over longer timescales. These findings highlight the trade-offs in fracture utilization and thermal sustainability, underscoring the importance of carefully selecting well placement strategies in EGS.

Topic: Enhanced Geothermal Systems

Huff-puff (cyclic injection/flowback) tests can provide comparatively rapid hydraulic and tracer responses without cross-well testing. In September 2025, we executed a huff-puff diagnostic test at the Utah FORGE well 16B(78)-32 and collected a rich multi-sensor dataset. Fiber optic cable housed in 4.4 cm diameter steel coiled tubing installed in the cased hole provided Rayleigh-based distributed strain sensing (RFS-DSS), together with distributed temperature sensing (DTS) and distributed acoustic sensing (DAS). Three rate steps (2.5, 5.0, 7.5 bpm) produced repeatable DSS responses concentrated near perforated intervals. DSS responses at perforations may be due to changes in temperature, strain, or both. Decoupling thermal and mechanical signatures requires joint analysis of DSS and DTS. In addition, the transfer of both heat and strain through the coiled tubing requires additional consideration. Nevertheless, these tests indicate that it is possible to identify flow exchange during huff-puff tests using an intervention fiber installation in coiled tubing. Quantitative analysis and workflow development are underway.

Topic: FORGE

The Great Basin region of the western United States hosts significant geothermal resources, yet a substantial portion are "hidden" systems lacking surface manifestations. The Argenta Rise study area, within the northeastern Reese River basin of Nevada, was identified as a high-priority hidden prospect through regional play fairway analysis (PFA) due to its favorable structural setting, including a major left step-over between the Argenta Rim and northern Shoshone Range faults. This study, part of the broader INnovative Geothermal Exploration through Novel Investigations Of Undiscovered Systems (INGENIOUS) project, applies detailed geological and geophysical investigations to characterize the hidden geothermal potential at Argenta Rise. Our integrated approach combined geological mapping and structural analysis, geophysical surveys (gravity, magnetics, magnetotellurics, and seismic reflection), a shallow (2-m) temperature survey, and temperature-gradient (TG) drilling. Results confirm the presence of complex, interacting fault systems conducive to fluid flow and identify geophysical anomalies, including low-resistivity zones at ~1.5 km depth, aligned with some of these structures. However, no clear thermal anomalies were detected in the shallow subsurface by the 2-m survey or in ten TG wells drilled to ~244 m depth. This discrepancy highlights the challenge of exploring truly hidden systems, where favorable structural and geophysical indicators are decoupled from shallow thermal signatures. We conclude that the geothermal potential at Argenta Rise remains prospective but unresolved; if present, a potential resource may be localized outside the drilled array, masked by cool aquifers, or confined to a deeper reservoir.

Topic: Field Studies

As enhanced geothermal systems (EGS) continue to gain attention, the ability to engineer and quantify fracture connectivity becomes increasingly important. A critical aspect of this process is understanding proppant placement within fractures, as it directly impacts hydraulic conductivity and guides decisions on (a) where to best intersect fractures for optimal flow paths, or (b) which well completion technique needs to be implemented. Current methods of fracture detection, such as microseismic monitoring or proppant tracers often cannot uniquely resolve proppant distribution far from the borehole, thereby introducing high uncertainty when determining which fracture regions are hydraulically conductive. In this study, we advance the application of triaxial borehole electromagnetic (EM) measurements for detecting and imaging propped fracture geometry in geothermal fields as an alternative/addition to the current fracture detection and appraisal methods to reduce uncertainty. As a preliminary study, we performed numerical simulation of EM measurements in the presence of fractures for both open- and cased-hole completions. Fracture geometries were simulated using ResFrac, providing realistic representations of stimulated areas, and then modeled in COMSOL to evaluate the synthetic triaxial borehole EM response of fractures injected with electrically conductive proppant. Simulation results indicate that borehole instruments with spacings of 100 m, operated at low frequencies (100 Hz), are required to detect the full extent of stimulated fractures. For fracture imaging, a combined strategy is recommended: Long-spacing, low-frequency measurements provide information on the overall extent of proppant-filled fractures, while short-spacing, higher-frequency measurements yield more precise information on fracture locations and type along the borehole. These findings support the development of new inversion methods for imaging the propped fracture geometry, enabling more accurate analysis of fracture connectivity in the field and ultimately improving the ability to ensure robust hydraulic communication between injector and producer wells in EGS.

Topic: Enhanced Geothermal Systems

Commercial geothermal power plants typically operate at thermal to electric conversion efficiencies of ~10-18%, constrained by parasitic loads and system level losses. This work presents a solid-state thermoelectric power generation system that recovers geothermal waste heat by directly converting thermal energy into electricity via the Seebeck effect. Operating without moving parts, the system offers a compact, reliable, and near maintenance free solution that is readily retrofittable to turbine exhausts, separator units, wellhead facilities, and heat rejection stages, where low to medium temperature thermal energy is routinely discharged in geothermal and other industrial processes. A field deployable thermoelectric power cell was designed, fabricated, and experimentally evaluated under laboratory thermal conditions, producing ~228 W from a scaled down 4-module Mk III configuration at a temperature difference of ~71 °C, corresponding to a projected output of ~1.02 kW for a fully populated 16-module stack. Building on this experimentally validated scaling behavior, the upgraded Mk IV architecture is projected to deliver ~10 kW using 16-module at a temperature difference of 220 °C under field conditions, with conversion efficiencies ranging from ~0.83% to 3.88% over the evaluated operating range of 50-225 °C.

Topic: Enhanced Geothermal Systems

Repeated stimulation, circulation, and cleanout operations at Utah FORGE have produced a suite of solid mineral scales and corrosion products recovered from the subsurface and surface infrastructure. This study synthesizes mineralogical and textural observations from these scale and corrosion samples collected between 2019 and 2025. These observations are then related to mineral saturation perturbations due to cyclic temperature and composition changes during circulation activities. In addition, we document effective fluid additives for scale and corrosion mitigation used to date at Utah FORGE, and those proposed for future, longer term circulation testing. Scale and corrosion products were characterized by using X-ray diffraction, a scanning electron microscope equipped with an energy-dispersive spectroscopy, and X-ray fluorescence. Mineral scales consist of calcite, siderite, anhydrite, halite, sylvite, and a Fe- and Si-rich expandable smectite group clay. Corrosion products include magnetite, hematite, lepidocrocite, and goethite, as well as boehmite and an Al-bearing phase with structural similarity with greenalite, reflecting both iron and aluminum infrastructure degradation, respectively. Carbonates and anhydrite are expected to deposit from injection waters on heating in the wellbore and/or within the fracture network in the reservoir rocks. Incorporation of CO2 into the fluids in the reservoir lowers pH and somewhat inhibits carbonate deposition. Rapid equilibration with quartz in the reservoir results in the potential for silica scaling on cooling in the production wellbore and topside equipment. After significant scaling issues were encountered in 2024 during stimulation activities, a scale and corrosion mitigation strategy was employed by dosing the injected fluids with additives that has been effective during subsequent cleanout and circulation activities.

Topic: FORGE

Hydrothermal alteration is a common process in active geothermal systems. It can significantly change the physio-chemical properties of the parental rock material. The dissolution and transformation of primary minerals and the formation of hydrothermally altered minerals depends on the prevailing sub-surfaces conditions of a geothermal reservoir. Identification and characterization of the hydrothermal minerals is key to unraveling the predominant sub-surface conditions. In Olkaria, conventional techniques such as binocular and petrographic analysis have been used to identify hydrothermal alteration minerals. However, with introduction of spectroscopy technique in Olkaria, it is imperative to compare hydrothermal alteration minerals identified petrographically with those identified by infrared spectroscopy techniques. Hence, this study compares infrared spectroscopy and petrographic analysis of hydrothermal alteration minerals in OW 205 drilling cutting samples. The study will also include results from binocular observation of the drilling cuttings at the rig site. Binocular analysis was done by visually observing drilling cutting samples using a binocular microscope while petrographic analysis involved first preparing thin section with thickness of about 30 micrometers by mounting drilling cuttings on glass slides. Petrographic studies involved viewing samples in a thin section using a petrographic microscope. On the other hand, spectroscopy analysis was done by first imaging drill cutting sample using short wave infrared (SWIR) camera. Images of the samples were made by passing samples on a translation stage underneath a camera. Minerals such as chlorite, epidote, actinolite, zeolites were positively identified by the two techniques. However, minerals such as chalcedony, prehnite, quartz, and albite were only identified using petrographic analysis. Generally, the integrated use of binocular observations, thin section petrographic analysis, and infrared spectroscopy provide reliable data for hydrothermal alteration characterization in geothermal wells and development of a conceptual model.

Topic: Geology

In geothermal development, localized fluid flow within reservoirs leads to heterogeneous temperature distributions and uncurtains extraction of geothermal resources. This reduces overall heat extraction efficiency and hinders stable steam production. To address issue of localized fluid flow, we propose a novel flow control approach using a thermoresponsive fluid whose properties change with temperature. This functional fluid responds to local temperature of reservoir, promoting uniform flow distribution, homogenizing the temperature field, and enabling stable steam production. A thermoresponsive gel that shows a remarkable increase in hardness upon heating has recently been developed. Its Young’s modulus rises to 1800-fold before and after the transition. At the injection of this functional fluid as slurry to reservoir, the gel remains soft near the low-temperature region around the injection well. In contrast, under higher temperature conditions, the gel hardens. This causes flow paths plugging through bridging and interlocking of solid particles. Consequently, the flow can be redirected toward low-permeability zones. This redirection leads to a more uniform temperature distribution. Such fluid flow control is expected to improve heat extraction efficiency and stabilize steam production. This study experimentally evaluates the feasibility of this idea. To evaluate the plugging performance under different gel hardness states at room and elevated temperatures, we conducted flow tests in an artificial fracture under confining pressure with a slurry containing thermoresponsive gel particles, which particle size satisfied bridging conditions. The slurry was injected into flow model while injection pressure and cumulative discharge were measured. At elevated temperature, an early pressure rise was observed, while at room temperature, the pressure increase was slower. These results indicate that the hardened gel plugged flow paths more rapidly and resisted fluid pressure better than the soft state. In summary, the thermoresponsive gel shows potential for reservoir flow control. Future work will include flow tests involving multiple flow paths with different permeabilities to evaluate the feasibility of fluid flow control.

Topic: Emerging Technology

In 2022, 2024, and 2025, we carried out a DFOS seismic studies in the Kijiyam geothermal field in north-eastern Japan. In 2022and 2024, we installed an optical fiber cable to 2,000 m into the NS and EW strike geothermal boreholes. We operated 24vertical seismic sources around the Kijiyama constructing geothermal plant. In 2024, we also used the N-S and E-W horizontal vibrations at two stations. The DTS temperature was 294ºC at 2,000 m depth. Based on the DAS data and synthetic seismic waveforms, we determined 3D Vp depth distribution in this area. The extract Vp profiles along five boreholes are compared to borehole geology and we confirmed the reasonable fitting. Migrated reflection shows intense reflections from 1 km to 4 km depth. We made 3D composite diagram using Vp, seismic reflection images and lost-circulation, flow-in and flow-out locations along the well trajectories. We obtained anisotropy using the horizontal vibrations. The Vp/Vs for N-S direction was approximately 2.0, in contrast to 1.95 for E-W direction. This suggests the fracture diction is E-W direction down to 1,500m depth. Currently six new boreholes are in drilling state using our 3D Vp and reflection image. We are also conducting the new seismic survey in 2025 using two boreholes for two months continuously. One of new drilling met the fracture zone and circulation loss at one of the seismic reflection zones. We will interpret the geothermal structure in the Kijiyama geothermal field using three years datasets of 2022, 2024 and 2025.

Topic: Geophysics

Maximizing geothermal energy potential will benefit from the ability to drill and produce heat from greater enthalpy resources than are currently utilized. Supercritical geothermal wells ( greater than 373 ˚C and 22 MPa) have the potential to produce 5 to 10 times as much heat as traditional hydrothermal resources. However, attempts at supercritical drilling have in the past encountered near catastrophic issues during drilling and well construction, such as IDDP and Venelle-2, which have prohibited successful utilization. To understand the current limitations in supercritical drilling and well construction, a multi-laboratory collaboration is underway to identify supercritical resources and their downhole chemistries, characterize materials used in their drilling and well constructions, and identify technological and testing gaps of well construction materials for supercritical conditions. An industry and literature review of these resources was conducted to identify 45 wells where bottomhole temperatures exceeded 373 ˚C. These resources are all hydrothermal and have typically been found in volcanically active regions such as Hawaii, Iceland, and Kenya. Most supercritical wells were drilled with conventional methods and materials employed by the geothermal industry, with only a few wells drilled with the intent of reaching supercritical conditions and producing such as Venelle-2, IDDP, and WD-1. Collected data assembled for the project will be made publicly available on the Geothermal Data Repository (GDR) to guide future supercritical drilling efforts and materials R&D. This work was done by Mission Support and Test Services, LLC, Under Contract No. DE-NA0003624 with the U.S. Department of Energy, and the Office of Defense Nuclear Nonproliferation Research and Development.

Topic: Emerging Technology

Abandoned mines are potential and underutilized reservoirs for low-temperature geothermal heat pump systems. We are exploring the potential for a ground-source heat exchange system in the abandoned and flooded Steward Mine in Butte, Montana. This mine is located within the Butte Mining District, within 1000 m of the Berkeley Pit (a large feature within the Butte Area Superfund site). There is a steep groundwater flow gradient from the Steward mineshaft to the Berkeley Pit, creating the potential for vertical flows in the mineshaft as water flows between horizontal drifts and to the pit. Proper design of heat exchangers in the mine shaft and predictions on the possible energy return and sustainability require measurements of the shaft temperatures, water levels, water chemistry, water movement vertically in the shaft and horizontally across the shaft. Using tools typically applied to borehole geophysics, we collected vertically distributed water temperature, conductivity, and pH. In addition, we measured vertical flows in the shaft using a spinner flow meter. We also collected shaft dimensions using SONAR in the flooded sections of the mine. We then attempted to correlate those flows with mine construction records. We found that flow is variable from near zero m/s to around 0.030 m/s and moving downward in the mineshaft starting from near the surface of the water at 150 m below land surface to 396 m below land surface. Variations in flow are likely due to horizontal workings (drifts) that intercept the shaft, creating areas available for flow in the mineshaft.

Topic: Field Studies

We present unique observations and models of hydraulic fracture-fault interactions from the Cape Station EGS project operated by Fervo Energy. We focus on the multi-stage, plug-n-perf stimulation of three horizontal wells near a vertical monitoring well that hosts a downhole pressure gauge. Faults were identified by clustering the microseismicity catalog through unsupervised clustering algorithms. We focus on a fault that intersects multiple horizontal wells and passes closely to the pressure gauge. The initial shear to effective normal stress ratio on the fault is between 0.31 and 0.45; approximately 7 – 18 MPa pressure increase is required to reach criticality for a friction coefficient of 0.6. The pressure gauge recorded two increases of approximately 20 MPa each, interpreted as follows. The first increase occurred during stimulation of the first well and is consistent with fluid leak-off and pressure diffusion away from a nearby hydraulic fracture into the low permeability reservoir. This pressurization of the reservoir brought the fault to a critically stressed state. The leak-off model cannot explain the second, more rapid and larger pressure increase observed during stimulation of the two additional wells, which is more consistent with pressure transmission along a high-permeability fault zone. Seismicity initiated near, but some distance away from where hydraulic fractures intersect the fault. The lack of seismicity close to a minor casing deformation implies that slip occurred aseismically in these regions. We test the hypothesis of pressure transmission along a high permeability fault zone using 3D modeling of fault zone fluid transport. The strong correlations between fault slip, fluid pressure, and well deformation highlight the crucial impact that fault structure and adjacent, permeable damage zones can have on stimulation. Our study demonstrates the importance of pre-existing faults and the potential value of physics-based modeling, integrated with geophysical and geomechanical data, in managing EGS stimulations.

Topic: Enhanced Geothermal Systems

Tracer flow testing is the routine measurement of well output in terms of mass flow and enthalpy in two phase pipelines and is of utmost importance in understanding reservoir performance. This is carried out by injection of exclusively non-radioactive and non-toxic tracers of high chemical and thermal stability- greater than 330oC. High precision multi-phase tracer metering systems with rapid-pulse tracer injection is used as the injection equipment to maximize concentrations at high flow and pressure. Multi-phase sampling separators are used for water-brine and gas-steam sampling. Analysis of samples is carried out by use ultra-specific and sensitive methods which include Gas chromatography and UV-Vis/fluorescence. Interpretation of data is carried out by numerical reservoir simulation services and not just qualitative and quantitative interpretation of results. This kind of tracers are injected in the flow line and sampling is downstream of the injection point. Liquid tracers injected must be conservative- cannot partition significantly to the vapor phase, decay chemically or thermally while in the reservoir for the measurement period. They must also be very detectable at ultra-low concentrations without interference from high concentrations of dissolved minerals in the produced water. Naphthalene sulphonates (NSA) are used for brine phase and Sulphur Hexafluoride (SF6) for gas phase. Interpretation of tracer flow test data is only used quantitatively.

Topic: Tracers

The Utah Frontier Observatory for Research in Geothermal Energy (FORGE) field-scale laboratory was established to advance the development of Enhanced Geothermal System (EGS) resources. This paper aims to predict the mineralogical changes and hydraulic conductivity in the fractured networks using the chemical composition of injected and produced water in wells 16A and 16B during the circulation test conducted between August and September 2024 at the FORGE site. The primary objective is to provide insights into the impact of geochemistry on porosity and flow during the planned long-duration circulation test. A thermal-hydrological-chemical (THC) model was developed using injections and produced water data to explore water-rock interactions and flow in porous and fractured media, using the FALCON (Fracturing And Liquid CONvection) code and The Geochemist’s Workbench. The fracture domain and water chemistry have been updated based on the latest geophysical and geochemical data from the previous circulation tests in August-September 2024. The model's results predicted the mineralogical changes and the net changes in porosity due to water-rock interaction and temperature variations for 6 months to inform the next long-duration circulation test. The geochemical model, calibrated using produced water data from previous tests, predicted the dissolution of quartz and retrograde precipitation of carbonate minerals. In this simulation, production of CO2 has been considered based on the characteristics of produced water and gas samples. The mineralogical changes vary in the fractured network, indicating how fluid transport in the wells influences the movement of precipitated or dissolved minerals along the fractured plane. Model predictions, such as pH, mineral saturations, and concentration of aqueous species were consistent with the produced water chemistry reported during previous circulation tests. The results of this study will aid in planning future long-duration circulation tests and the development of EGS resources for sustainable geothermal production.

Topic: FORGE

Discrete Fracture Network (DFN) models are widely used to evaluate fluid flow and heat transfer in Enhanced Geothermal Systems (EGS). However, the choice of fracture representation introduces a fundamental tradeoff between complexity and computational efficiency. In this study, we compare two DFN approaches applied to the Utah FORGE site: a geologic DFN derived from microseismic data, geomechanical characterization, and borehole observations, and a simplified planar fracture DFN in which fractures are represented as idealized planes connecting injection and production wells. The geologic DFN captures the heterogeneity of natural fracture systems, including variable orientations, lengths, and connectivity. This complexity leads to more realistic predictions of fluid circulation pathways and thermal drawdown, but it comes at the cost of high computational demand. By contrast, the planar fracture DFN sacrifices geologic realism for efficiency, allowing rapid parameter exploration and long-term forecasting. While this simplification enables broader scenario testing, it risks overestimating fracture connectivity and sweep efficiency. Simulation results indicate that fracture connectivity, rather than fracture count or geometry alone, exerts the strongest control on long-term heat recovery. The geologic DFN better represents site-specific variability, while the planar DFN is more practical for sensitivity studies and optimization tasks. This comparison highlights the importance of selecting the appropriate DFN representation based on research objectives, balancing the need for geological accuracy with computational tractability in EGS modeling.

Topic: FORGE

Naturally existing tritium in groundwater was applied as a tracer for dating the age of Chingshui geothermal water. The residence time (or, age) was determined at 15.2 years using the plug-flow model with tritium data. The rate of natural recharge for Chingshui geothermal reservoir can be estimated from the production history from 1981 to 1993. Fluid-in-place can then be calculated from the residence time (or, age) and recharge rate. Alternatively, fluid-in-place can be calculated using the porosity-thickness product obtained from well interference tests. This paper shows that ignoring the effect of fracture compressibility can lead to overestimating the porosity-thickness product and fluid-in-place of Chingshui geothermal reservoir, a stress-sensitive naturally fractured reservoir.

Topic: Reservoir Engineering

The Salak Geothermal Field is currently the largest operating geothermal field in Indonesia and has been continuously operating since 1994, with an installed capacity of 405.4 MWe, comprising of 388.8 MWe flash plant and 16.6 MWe binary plant. As one of the country’s most mature geothermal fields, Salak has drilled more than 115 wells and accumulated an extensive dataset through drilling and reservoir monitoring programs. Leveraging this dataset, Salak’s Earth Science team has updated the static model by incorporating the latest drilling result, monitoring data, new reservoir studies, including new insights from the Naturally Fractured Reservoir (NFR) study. This updated static model served as the foundation for updating the Salak numerical model, with the objective of making the numerical model to have consistent reservoir property distributions. In addition to updating the static property distributions, the dynamic boundary conditions were also revised to align with the updated conceptual model of the field. These improvements made the NFR-based numerical model more effective during the calibration process and demonstrated high calibration quality during the pre-exploitation condition and reservoir response throughout commercial production, including recent major injection strategy change, namely the Salak Injection Realignment Program (SIRP). The quality result from the calibration process indicates that the model is reliable to predict the evolution of key dynamic reservoir parameters observed from surveillance activities during the first few years of the SIRP. Overall, the model update using the NFR-based data has improved the calibration results and enhanced confidence in the model as a reliable predictive tool for evaluating various long-term exploitation strategies, which ultimately improve decision-making quality for Salak’s key strategic projects.

Topic: Modeling

The introduction of New Zealand’s Emissions Trading Scheme (ETS) in 2008, and its extension to geothermal operations in 2010, has driven significant innovation in emissions management, with annual costs to operators around NZ$50M. Historically, non-condensable gases (NCGs) were often released to the atmosphere during power generation. However decarbonisation pressures, including ETS costs, have prompted geothermal operators to adopt new strategies for greenhouse gas abatement. Reinjection of NCGs is now standard practice at many sites to close the emissions loop, but full reinjection is not feasible for all fields due to geological limitations and uncertain long-term impacts on production. Industries such as packaging, food and beverage, agriculture, and manufacturing rely on carbon dioxide—the most abundant NCG—create opportunities for commercial utilisation alongside mitigation. Māori are central to New Zealand’s geothermal sector, holding significant ownership of high-temperature resources, especially in the Taupo Volcanic Zone. Māori trusts and organisations are equity partners in major geothermal projects and actively shape development, investment, and operational strategies, guided by tikanga (customs) and kaitiakitanga (guardianship). As New Zealand advances CO₂ management and decarbonisation, Māori will be key decision makers, with constitutional rights under the Treaty of Waitangi ensuring their consultation and recognition in resource management policy. This paper examines current and future approaches to geothermal emissions utilisation, with a focus on commercial, environmental, mātauranga Māori (Indigenous knowledge), and Te Ao Māori (Māori world views) considerations.

Topic: General

Thermal response tests are essential for determining ground thermal properties required for optimal design of ground heat exchanger systems in shallow geothermal applications. This paper presents a novel Multiple-Input Deep Neural Operator variant for rapid and accurate thermal response test analysis across standard, constant temperature, and oscillatory protocols. The approach directly maps heat injection and fluid temperature time series to soil thermal conductivity, borehole thermal resistance, and (for the oscillatory case) soil volumetric heat capacity, without requiring iterative optimization. Models trained on synthetic samples generated by simulations generalize to six real-world datasets from Canada, Denmark, Japan, and the United States. For two-parameter inversion, mean absolute percentage errors are 4.98% for soil thermal conductivity and 2.75% for borehole thermal resistance. In the three-parameter oscillatory case, errors are 0.58% and 5.79% for the same parameters and 9.33% for soil volumetric heat capacity. The models cut interpretation time to seconds and generalize across different input functions without retraining, making it particularly valuable for rapid site assessment and ground-source heat pump system optimization. Future extensions include noise augmentation and physics-informed training.

Topic: Low Temperature

The UtahForge 2024 EGS stimulation of a 400m horizontal cross-well volume of nominal 100m x 100m cross-section at 2.5km depth in Θ ~ 185oC crystalline crust culminated in well-to-well advective flow V =30 L/s for 30 days at heat energy production Q = ρCΘV ~ 20MWth. Abstracting the 400m cross-well stimulation volume as a thermal energy line-sink of radius R ~ 50m shows that crustal heat conduction recharges the stimulation volume so that the 20Mwth heat energy extraction reduces the crustal heat store temperature by perhaps 10% in ~ 3 to 10 years. Engineering the breakthrough line-sink cross-well advective flow volume requires our immediate and close attention. Accordingly, we note the UtahForge EGS stimulation was planned/executed as a series of hydrofrack-like fluid injections at a dozen plus sites along the 400m well-pair reach. Significant well-to-well flow occurred, however, only when all hydrofrack hardware was drilled out of the stimulation reach and the 400m extent of the injection well was pressurised for flow into the 400m open production well. It follows that the UtahForge EGS cross-well stimulation flow is advective heat transport through an engineered aquifer-like cross-well crustal volume. Eliminated from heat engine consideration are conduction-specific discrete cleavage flow planes. UtahForge cross-well flow involves instead fluid seeping through ambient crust poro-permeability distribution κ(x,y,z) ~ exp(αφ(x,y,z)) controlled by pink-noise porosity φ(x,y,z) at cm-km scales as attested by well-log, well-core, and well-flow data worldwide. While hydrofrack-like stimulation from both the injection and production wells conditioned the cross-well volume, post-stimulation open-hole cross-well advection flow resembles aquifer pump test diffusion between two wellbores. Well-to-well fluid diffusion is given by T [∂2h/∂2r + 1/r ∂h/r] = S ∂h/t + Qδ(r1) - Qδ(r2), free of cumbersome aquifer boundaries. Coefficients T and S function as unit aquifer transmissibility and storativity representing effective permeability and porosity in the EGS stimulation volume. Time-dependent UtahForge well-to-well flow data provide a pump-test-like constraint on the ratio T/S; wellbore-centric Darcy flow constrains the effective transmissivity T. Microseismicity associated with fluid flow in κ(x,y,z) ~ exp(αφ(x,y,z)) media can serve to image/monitor and survey cross-well aquifer flow. Future UtahForge data can provide more comprehensive pump-test-like constraints on the EGS stimulation process

Topic: Enhanced Geothermal Systems

om Engineered Geothermal System (EGS) data acquired by the UtahForge project in 2024, we deconstruct the flow stimulation mechanics into four steps : (i) wellbore-centric fluid flow in/out of the cross-well flow pair; (ii) cross-well flow stimulation of a realistic poro-permeable crust; (iii) advective heat transport in the cross-well heat exchange volume; (iv) conductive heat transport into the cross-well heat exchange volume. Step (i) quantifies the heat energy production Q = ρCTV for fluid volumetric heat capacity ρC, crustal temperature T and wellbore volumetric flow V. Step (ii) quantifies the volumetric flow V ~ 2πr0φv0ℓ for bulk fluid flow φv0 into open wellbore interval of radius r0 and length ℓ. Step (iii) quantifies grain-scale equilibrium solid-fluid heat transfer for ambient crust poro-permeability distribution κ(x,y,z) ~ exp(αφ(x,y,z)) stimulated by EGS pressurisation as given by Peclet number Pe ~ r0φv0/D ~ 10 for thermal diffusivity D = K/ρC ~ 10-6 m2/s and K = thermal conductivity 4W/m/oC. Step (iv) approximates heat extraction as notionally carried by a central advective line-sink of strength Q/ℓ. Step(iii) is attested by microseismic emission first motions recorded by downhole sensors in which poro-permeability increases via increased poro-connectivity parameter α rather than via increased porosity αφ(x,y,z). The step (iv) central line-sink analytic advection-diffusion approximation T(r,r) gives heat reservoir lifetimes τ ~ 3 to 10 years for the UtahForge-scale 100m cross-well offset. Life-times τ treble for 200m cross-well offsets. The scale of heat depletion increases linearly with heat removal rate Q. From the present UtahForge data we can see how upscaling EGS Q requires upscaling cross-well offsets. The close association of EGS microseismicity with κ(x,y,z) ~ exp(αφ(x,y,z)) poro-permeability yields the observational means to survey/monitor the UtahForge EGS system and so quantify the future of EGS.

Topic: Enhanced Geothermal Systems

We present results from a one-week circulation test at the Utah FORGE site following the installation of coiled-tubing deployed fiber optic cables in the 16B producer. A comprehensive suite of diagnostics was applied to evaluate flow pathways and reservoir response. A spinner injection log suggested that injection was limited to three heelward stages, while fiber optic distributed sensing revealed three to four primary inflow zones in the producer. Thermal signatures during pressure buildup indicated possible crossflow behavior and provided evidence for a dominant connection point between the wells. Chemical tracer tests, including a freshwater negative tracer test, inform the circulation volume between the wells. We present efforts to use the tracer data to estimate the effective heat exchange area between the wells. Production efficiency increased steadily from 25% to 65% during the test. Bottomhole pressure and temperature measurements provided supporting constraints on reservoir conditions. Collectively, these diagnostics demonstrate the utility of fiber optics and complementary tools for characterizing fluid circulation and reservoir behavior in enhanced geothermal systems.

Topic: FORGE

Fiber optic cables offer a powerful tool for monitoring enhanced geothermal systems (EGSs), and practical deployment approaches remain under development. We designed, tested, and field-deployed coiled tubing conveyed fiber optic cables to evaluate their feasibility for long-term, retrievable monitoring. The deployment was supported by benchtop strain testing and careful planning of coiled tubing operations. Operational lessons included the importance of circulation contingencies (e.g., burst discs), optimized blowout preventer stack height, and extended coil length at surface to aid in retrieval. Distributed temperature sensing (DTS) measurements provided reliable bottomhole temperature estimates consistent with the bottomhole temperature gauge. Distributed acoustic sensing (DAS) indicated inflow zones and microseismicity. Standard single-mode fiber with RFS-DSS interrogation successfully captured thermal slug responses for production logging. The experimental strain-coupled fiber failed during installation, likely due to thermal expansion effects. Overall, this study demonstrates the feasibility of coiled tubing deployed fiber optics for retrievable monitoring in EGSs.

Topic: Enhanced Geothermal Systems

Interest in geothermal power production has increased substantially over the past five years as technology transfer from the oil and gas industry has driven down the cost of extracting heat from the Earth’s crust, established geothermal industry participants have developed both a better understanding of the nature of geothermal systems and better exploration tools, and the data center building boom has resulted in premium pricing for clean, firm power. While this has generated a modest amount of additional investment in geothermal power projects, further performance improvements are needed for geothermal to secure a significant percentage of the U.S. and international power production markets. That rapid growth in market share could be achieved is suggested by the pace of growth realized over the past twenty-five years from both Canadian Steam Assisted Gravity Drainage (SAGD) oil sands projects and U.S. unconventional reservoirs. These two segments of the oil and gas industry had been technically and economically challenged, but after having received government support in the latter parts of the twentieth century, grew quickly thereafter as operating companies took the lead in driving innovation forward. The growth in U.S. unconventional production to over twenty-five million barrels of oil equivalent per day by YE 2024 is a particularly compelling example for the geothermal industry to learn from. One of the principal factors that enabled this outcome was the transfer of technical knowledge between operators. This was crucial because it allowed companies to learn from each other’s mistakes, difficulties, experiments, and successes, thereby vastly reducing the time and funding required to make progress in driving down development costs and increasing per well production rates. Although much of this sharing of knowledge was at first unintentional, resulting from a pseudo-open-source ecosystem wherein knowledge disseminated mostly through back-channels at a modest pace, the late 2014 collapse in oil prices encouraged companies to recognize that creating formal open-source knowledge sharing structures would benefit not only the industry as a whole but their company in particular. Examples of the types of structures that were put in place include joint operator/government funded hydraulic fracturing test sites, company-to-company and multi-company data trades, publication of cutting-edge technical papers, operator involvement with technology start-ups, and industry-wide adoption of standards for the disclosure of certain types of technical data. While the geothermal community has already embraced some of these methods for sharing technical knowledge and the cost of technology demonstration projects, because the geothermal industry is tiny compared to other better established energy production industries, companies within the geothermal industry would benefit considerably from increasing the amount of knowledge and cost sharing taking place. This would allow established companies to improve their profitability by learning faster than they could on their own, leading to the capture of untold millions of dollars of profit margin that would otherwise be lost. Sharing would also encourage new participants to invest in geothermal power production, which is necessary to encourage the establishment of a service industry capable of supporting rapid growth in power output. It is therefore hoped that geothermal developers ignore those who promote restrictive approaches to managing technical knowledge not directly related to exploration activities (which should be closely guarded) and embrace an open-source paradigm consistent with the reality that for geothermal to scale quickly and economically, it must become one of the lowest cost, most reliable forms of power generation, which is, as the U.S. unconventional industry has demonstrated, a result best achieved by adopting an open-source ethos.

Topic: General

Fracture connectivity optimization and long-term circulation performance are crucial for Enhanced Geothermal Systems (EGS) success. This research assesses various stimulation design choices for a future well, Well 16C(78)-32, at the Utah FORGE location through a numerical sensitivity analysis. This well would be placed to the north of the existing well pair (600 ft at the heel and 280 ft at the toe). The analysis explores the combined impacts of lateral and vertical positioning, stimulation fluid type, and previous stimulation activities. Three trajectory options were examined: elevation alignment with well 16A(78)-32, a mid-level elevation placement between the two wells, and elevation alignment with well 16B(78)-32, all cases offset to the north. Each trajectory was assessed with crosslinked CMHPG and slickwater treatments, with and without considering the 2024 FORGE stimulation history. Simulated fracture hits at wells 16A and 16B were analyzed to assess hydraulic connectivity and fracture extension. The findings reveal that the vertical positioning significantly influences interwell connectivity, with mid-level placement yielding a more balanced and resilient fracture network. Crosslinked CMHPG provides more balanced and durable interwell connectivity under both unstimulated and stimulated stress conditions. Analysis of proppant settlement reveals the significance of wellbore connectivity supported by proppant in maintaining interwell communication during circulation. Continuous propped pathways between wells are crucial for sustaining effective connectivity and reduce reliance on isolated fracture segments. Large treatment designs with crosslinked CMHPG can improve interwell connectivity. Therefore, a robust design option for future EGS development at FORGE involves a mid-level trajectory for well 16C(78)-32 combined with a crosslinked CMHPG stimulation strategy.

Topic: FORGE

High-fidelity geothermal reservoir simulators are essential for forecasting subsurface pressure and temperature distributions but are computationally prohibitive for rapid optimization, history matching, and uncertainty quantification. Surrogate modeling offers a practical alternative by learning simulator input–output mappings and delivering fast predictions that can be embedded in engineering decision loops. In this study, we present a systematic comparison of surrogate models for steady-state geothermal applications, evaluating convolutional encoder–decoder architectures (U-Net), neural operator approaches (FNO, U-FNO, and Fourier-MIONet). Models are assessed using decision-relevant criteria, including predictive accuracy, physics consistency, generalization to unseen geologic heterogeneity, data efficiency, and computational cost. Our results demonstrate that neural operator–based surrogates achieve strong predictive performance from limited training data while reducing inference time by orders of magnitude relative to full-physics simulation. We highlight key trade-offs between surrogate architectures and provide practical guidelines for selecting models that balance fidelity, robustness, and speed in geothermal optimization, history matching, and uncertainty quantification workflows.

Topic: Modeling

Key geothermal resource parameters such as Area, Thickness, and Temperature play an important role in the characterization of resources, the identification of appropriate analogs, and the calculation of resource capacity estimates. There is currently no industry-wide standard for the definition of resource geometry, i.e., resource Area and Thickness, which can result in confusion when communicating such parameters with non-specialists and inconsistent approaches to resource capacity estimations. The definitions presented herein focus on a conceptual model approach to Area and a Thickness parameter rooted in the concept of heat-sweeping in a hypothetical or realized development. In addition to resource parameters such as temperature, area, and thickness, there is the ability to characterize geothermal resources based on Permeability Regime; a resource descrptor that is controlled by geologic setting and that influences parameters such as area, well permeability, feedzone distributions, recovery factors, and post-development cooling trends. Four end-member Permeability Regimes are proposed to describe all naturally-occurring geothermal systems: Discrete, Limited Distributed, Enhanced Distributed, and Stratigraphic, and their relationship to well productivity index values are described herein. This paper outlines an approach to standardize the documentation of key resource characteristics and Permeability Regimes for all geothermal systems, regardless of temperature or geologic setting. A companion paper reviewing the reservoir engineering characteristics of geothermal Permeability Regimes is provided by Murphy and Libbey (2026).

Topic: Geology

On June 3, 2025, an uncapped, shallow (~15- 20 m), abandoned well in the south Reno, Nevada, unexpectedly erupted, shooting boiling water nearly 30 m high, marking the first geyser-like activity at the site in decades. The eruption occurred on the lower sinter terrace in the Steamboat geothermal area, a site known historically for its dramatic surface expressions. Steamboat Springs was once home to some of the largest geysers in the United States, with abundant hot springs and fumaroles active into the early 1900s. Geysering diminished by the mid-20th century. Renewed changes were first noted in 2022, when steaming ground expanded and water began reappearing along fractures; activity has since steadily increased, culminating in the 2025 eruption. In June, our team began documenting changes in the geothermal area through water sampling and geochemical analysis, thermal drone surveys, temperature logging, and mapping of new and evolving features. This work provides a rare opportunity to observe changes in a geothermal system on a human timescale, with implications for both public safety and for understanding and managing the complex interplay of natural variation, commercial demands, and hydrothermal expressions. This study offers critical insights into the dynamic nature of geothermal systems and the factors that can drive their reawakening.

Topic: General

High-temperature reservoir thermal energy storage (RTES) represents a promising approach to storing surplus renewable energy and waste heat in subsurface formations for later recovery, offering a reliable pathway toward enhanced grid stability. To store heat using high-temperature fluid, deep reservoirs with depths greater than 2 km are required for minimal heat loss. However, the mechanism controlling the efficiency of RTES and its value on grid stability remain unclear due to a lack of research and field demonstrations. To reveal this mechanism and achieve optimal heat storage performance for quantifiable grid stability improvement, this study presents an in-depth numerical analysis of the thermal behavior and storage performance of an open-loop RTES system. The effects of critical factors on the system’s performance are analyzed, including the injection temperatures during heat storage and production, injection rates, storage and production schedule. Results show that a higher injection temperature during storage with a lower one during production yields the highest heat recovery. A higher hot fluid injection rate for storage and a lower cold fluid injection rate for production results in the lowest thermal drawdown during production, which is the most beneficial for power generation. To achieve both high production temperature and thermal power, a balanced combination of longer duration storage and production is recommended. Building on these findings, a power system modeling framework based on linearized AC optimal power flow (LPAC) is developed to represent the joint operation of RTES and the power grid. RTES simulation outputs are incorporated as input parameters in the LPAC model, influencing generation dispatch and allowing evaluation of grid stability under stressed operating conditions. Results indicate that RTES, with stronger heat production performance, provide greater grid stability benefits. This framework offers a structured and quantifiable approach to evaluate the operational benefits of RTES, with analysis indicating improvements in grid stability and reliability during stressed conditions.

Topic: Emerging Technology

Closed-loop geothermal systems represent an emerging approach to geothermal energy utilization that operates without the need for sustained external fluid injection. However, their thermal performance is frequently constrained by the limited interfacial area available for heat transfer between the wellbore and the adjacent geological formation. Incorporating a thermally conductive fracture is a potential approach to improving closed-loop systems heat extraction. However, the heat extraction improvement effect of a multi-wing fracture has not been clarified yet. This work introduces an upgraded closed-loop geothermal system (UCGS) featuring a multi-wing fracture filled with thermally conductive proppants and connected to the well bottom, thereby improving heat transfer efficiency in the near-well region. A fully coupled three-dimensional hydrothermal numerical model is developed for the UCGS, on the basis of which a numerical study is conducted to evaluate heat extraction behavior under varying fracture dimensions and geometries. The results demonstrate that incorporating conductive fractures outperforms a conventional closed-loop system in terms of thermal production. Increase in fracture wing length and that in fracture height both lead to heat production improvement. For an identical fracture cross-sectional area, increasing fracture height is more effective in enhancing heat extraction than enlarging fracture thickness. As the number of fracture wings increases, both production temperature and cumulative net heat output increase at diminishing rates. Introducing a multi-wing fracture increases the 10-year cumulative thermal output by up to 19.23%. Results obtained from this study can inform improved design of closed-loop systems in future projects.

Topic: Modeling

Flow channeling is widely recognized as a key mechanism that accelerates thermal drawdown and degrades the long-term performance of enhanced geothermal systems (EGS). In addition to fracture-scale flow channeling, non-uniform flow rate allocation among fractures induced from wellbore-induced pressure loss and thermo-mechanical interactions between fractures can further complicate flow behavior in multi-fracture EGSs. To systematically investigate these coupled effects, we develop field-scale single- and double-fracture EGS models and simulate the fully coupled thermo-hydro-mechanical (THM) processes. Numerical simulations first reveal how injection flow rate governs thermo-mechanical responses and flow channeling within a single fracture. Low injection flow rates lead to localized cooling, strong thermal stress accumulation, and pronounced aperture heterogeneity, resulting in severe flow channeling. In contrast, high injection flow rates generate a broader cooling zone and reduce fracture stiffness over a larger area, producing more spatially distributed aperture evolution and relatively uniform fracture flow, despite faster thermal drawdown. Extending to the double-fracture system, wellbore pressure loss induces persistent asymmetric flow allocation, producing flow behavior in each fracture similar to that in single-fracture cases, while overlapping thermal perturbation zones between closely spaced fractures create strong inter-fracture thermo-mechanical coupling, synchronizing aperture evolution and enhancing flow redistribution.

Topic: Enhanced Geothermal Systems

FLUID INCLUSION STUDIES OF CASE STUDY OF THE OLKARIA GEOTHERMAL FIELD,KENYA Fluid inclusions are portions of fluids which were trapped in the solid crystals as it grew, or crystallised. Fluids are therefore the samples of the original fluid from which the crystal grew or the latter fluid which bathed the crystal during crystallisation Fluid inclusions can be thought of as the time capsules storing the information about the ancient temperatures, pressures, and fluid composition (Goldstein’s and Reynolds 1994) The study of fluids inclusions is the only direct evidence of the paleo fluids that have circulated at different times through the reservoir rocks providing valuable information about the temperature of mineral formation, pressure of mineral precipitation, composition of the origin of the fluids and mineral precipitation e.g. salinity and later temperature, pressure and fluid composition In Olkaria geothermal field there has not been studies carried out on fluid inclusions, and the highly exploited areas (up flow zones) are slowly diminishing or shrinking, direct studies of the temperatures and pressures using inclusions will help us determine whether the field is cooling or heating up.

Topic: Field Studies

Drilling-induced features identified from borehole image logs provide direct constraints on in-situ stress orientations and serve as a basis for stress magnitude estimation. Classic features such as drilling-induced tensile fractures and borehole breakouts have been extensively documented since the 1980s, predominantly in sedimentary rocks within hydrocarbon reservoirs. More recently, petal-centreline fractures have also been recognised. Their formation has been modelled as functions of stress state, borehole trajectory, rock properties, and drilling fluid parameters. In the high-temperature geothermal wells of the rifted Taupo Volcanic Zone, Aotearoa New Zealand, typical drilling-induced features are commonly observed in borehole image logs. These geothermal systems are hosted in a diverse lithological sequence of silicic to andesitic volcanic and volcaniclastic rocks, as well as metasedimentary basement. Alongside typical features, we also identify a range of non-typical drilling-induced features, which we hypothesise arise from the interaction of drilling with complex rock textures, mechanical anisotropy, natural fractures and veins, fault density, thermal stress, and variations in hydrothermal alteration. Globally, recent studies have modelled these non-typical features on a well-by-well basis to derive stress constraints. With the increasing availability of borehole image data in geothermal environments, we aim to engage the broader geoscience community in recognising and interpreting these non-typical features. They hold promise for refining stress and permeability models—critical for drilling stable and productive geothermal wells. This understanding is vital for optimising conventional geothermal development and advancing next-generation systems such as superhot and Enhanced Geothermal Systems.

Topic: Geology

Fracture Thermal Energy Storage (FTES) stores and recovers heat in low-permeability rock by circulating fluid through hydraulically created fractures that act as transient heat exchangers. We report decimeter-scale laboratory FTES experiments on 25-cm cubic granite and gabbro blocks containing one or three fractures created by hydraulic fracturing. Thermal charge–discharge cycles are performed by circulating hot and cold water between a central injection well and production wells while varying inlet temperature and flow rate, and monitoring inlet/outlet temperatures and the block surface temperature fields. The early-time mean surface warming is approximately linear and scales with injected thermal power (constant flow rate at fixed inlet temperature). The hydraulic response evolves during heating: at constant flow rate, injection pressure increases as the block warms and is higher for higher inlet temperatures, consistent with a temperature-dependent reduction of effective fracture transmissivity. Long injections reach a quasi-steady regime where input thermal power is balanced by boundary heat losses to the laboratory environment; this regime enables estimation of loss power and cumulative lost energy. These measurements constrain key parameters and would enable calibration and validation of a hydrothermal model accounting for the conductive host-rock boundary conditions expected in a field-scale FTES system. It provides quantitative insight into how fracture transmissibility and connectivity affect FTES efficiency.

Topic: General

In recent years Enhanced Geothermal Systems (EGS) have shown increasing viability for meeting the demand of scalable renewable energy. EGS’s have the unique advantage of geographic flexibility while also having massive energy potential, which has the possibility of being much higher than traditional geothermal systems. However, EGS faces challenges, majorly high initial capital expenditures and uncertain economic returns. This study investigates techno-economic feasibilities of EGS. In which we aim to both contribute to a deeper understanding of CO₂-based geothermal enhancement against water-based baseline and support the development and operation in response in asset and ultimately for growing global renewable energy needs. A scenario modeling approach was taken to analyze the impacts of the many technical and economic variables on financial performances. 20 distinct scenarios were designed, the baseline scenario developed is a traditional water based geothermal system by referring the setups in GEOPHIRES’ use case (a baseline from public, GEOPHIRES v2.0) to reflect a realistic commercial scale operation. The following 19 scenarios use CO2 as the working scenarios and are analyzed based on capital investment, operational costs, energy efficiency, and economic performance. Subsequent scenarios introduce modifications such as varying CO2 injection volumes and recovery rates, changes in subsurface storage capacity, system design parameters such as soak time and water-alternating-gas (WAG) ratios. The results indicate that the economic viability of CO₂-based systems is heavily influenced by several key factors. Using CO₂’s thermodynamic properties, such as lower viscosity and higher mobility does improve heat extraction, on the other side, its use greatly affects system costs where the majority of the costs come from CO2 transportation and storage. However, this heavily depends on regional carbon pricing mechanisms and infrastructures for potential asset and applications. Therefore, optimized injection strategies are necessary since they can reduce expenses and enhance energy recovery. In addition, CO₂ injection offers a secondary revenue opportunity through carbon storage credits under the 45Q tax incentive, further improving financial feasibility. Further improvements may come through technological advancements in CO2 handling and compression systems for recycling and reuse. The study concludes that while CO2-based geothermal systems offer distinct advantages, financial success hinges on effective CO2 management, fluid interactions of the stimulation, sweeping, and thermal exchange.

Topic: Enhanced Geothermal Systems

This paper presents a molten-salt closed-loop geothermal system developed primarily for super-hot rock environments, where subsurface temperatures exceed those typically accessible to conventional hydrothermal technologies. By operating at ultra-high temperatures and employing molten salt as both the subsurface heat-transfer fluid and the surface thermal storage medium, the system enables efficient, dispatchable geothermal power generation without formation fluid production or reservoir pressure depletion. The paper focuses on the thermodynamic advantages of super-hot rock operation, engineering strategies for mitigating thermal drawdown, and the role of molten-salt thermal buffering in improving system longevity and project economics. Secondary deployment pathways, including retrofits of existing geothermal wells and selected orphaned oil and gas wells, are discussed as complementary but non-primary applications.

Topic: Emerging Technology

Geothermal energy development faces significant challenges due to subsurface uncertainties, particularly in identifying economically viable plays where elevated temperatures occur at accessible depths. Geothermal Play Fairway Analysis (GPFA) emerges as a powerful risk-reduction framework, adapted from petroleum exploration, to systematically integrate geological, geophysical, and thermal data at basin and play scales. By mapping Common Risk Segment (CRS) and Composite Common Risk Segment (CCRS) elements, GPFA highlights prospects with anomalous heat mechanisms that elevate local geothermal gradients beyond regional norms, enabling high-temperature resources at shallower depths and thereby slashing drilling costs while boosting return on investment (ROI). Anomalous heat mechanisms often drive these localized thermal enhancements. For instance, salt diapirs act as thermal conductors, funneling heat upward and creating hotspots in sedimentary basins. Overpressured zones can advect deeper, hotter fluids toward shallower reservoirs, amplifying gradients through convective heat transfer. In extensional settings like the Basin and Range province, high-permeability faults linked to deep crystalline basement rocks—such as granites or igneous intrusions—facilitate upward circulation of hot fluids, yielding gradients far exceeding background levels. GPFA's data-driven approach, incorporating borehole temperatures, seismic interpretations, and permeability models, identifies these features by quantifying their impact on heat flow, reservoir quality, and fluid pathways. This targeted identification allows operators to prioritize prospects where temperatures suitable for power generation ( greater than 150°C) are achievable at depths under 6 km, reducing capital-intensive deep drilling and enhancing project economics. A critical pitfall in geothermal assessment is the misuse of geothermal gradients for temperature extrapolation. Linear gradients, derived from bottom-hole temperatures (BHT), cannot be reliably extended beyond well control, as they overestimate deeper temperatures. Gradients inherently decrease with depth due to rising thermal conductivity in compacted, less porous rocks—governed by the equation: gradient = heat flow / thermal conductivity. This leads to flawed temperature-depth profiles; for example, a projected 200°C at 3 km might actually yield only 150°C, inflating drilling budgets and jeopardizing projects amid high upfront costs. To mitigate this, GPFA incorporates 1D basin modeling, simulating heat flow from the lithosphere-asthenosphere boundary (at ~1330°C) upward through a stratigraphic column parameterized with lithology-specific thermal conductivities. This physics-based method accurately predicts non-linear gradients, accounting for radiogenic heat production and conductive/convective processes. Case studies from numerous geothermal exploration prospects demonstrate how GPFA, augmented by such modeling, has de-risked plays with anomalous gradients, improving success rates by 20-30% and optimizing ROI through shallower, cost-effective developments. In summary, GPFA not only pinpoints anomalous heat mechanisms for superior play selection but also enforces rigorous gradient modeling to avoid overestimation pitfalls, paving the way for sustainable geothermal expansion.

Topic: Modeling

Much work has been done to further understanding of stimulating hot rock to be able to capture the heat. Davinci has focused on developing a better understanding of a hydrothermal system in high quality reservoir rock that is intensely naturally fractured due to local significant tectonism. We are suggesting a new term for this type of reservoir: Naturally Enhanced Geothermal System (NEGS™). The Imperial Valley of Southern California has been an historical geothermal province exploited by vertical wells drilled to recover heat by either flashing to steam or binary heat transfer methods of electrical generation. Davinci has used gravity, aeromagnetic, and 3D seismic data to supplement previous studies to characterize the direction and intensity of fractures in the pull-apart basin transfer zone between two segments of the San Andreas Fault called the Brawley Seismic Zone. Horizontal drilling to intersect the dominant fracture directions in high permeability reservoir is planned. No additional artificial stimulation is required to achieve high flow rates of high temperature water from these wells. With over 18,000’ of high net to gross fluvial and lacustrine sediments, there is large undeveloped potential in this NEGS™. Since the 1970s, the Imperial Valley of Southern California has been an important geothermal province, with vertical wells historically developed for both flash and binary power generation. DAVINCI EP is re-evaluating this resource through the lens of a new conceptual framework: the Naturally Enhanced Geothermal System (NEGS™) a hydrothermal reservoir in which tectonically induced pervasive fracturing provides permeability comparable to, or possibly exceeding, that achievable through artificial stimulation. Using integrated gravity, aeromagnetic, and 3D seismic datasets, Davinci has delineated a structurally controlled transfer zone within the Brawley Seismic Zone, located between two segments of the San Andreas Fault. The results reveal a dense fracture network with preferred orientations favorable for horizontal wellbore intersection. A pilot horizontal drilling program planned for 2026 will test the NEGS™ model, quantify directional permeability anisotropy, and evaluate sustainable high-temperature flow from producers and injectors without hydraulic stimulation. With more than 18,000 feet of high net-to-gross fluvial and lacustrine sediments and strong convective heat transfer, the Imperial Valley represents a substantial untapped resource base. If validated, the NEGS™ model could enable widespread geothermal development in tectonically fractured sedimentary basins worldwide — expanding access to sustainable, low-impact geothermal energy without reliance on artificial reservoir stimulation.

Topic: Emerging Technology

Seismic and fiber-optic monitoring at the Utah FORGE site during the 2024 stimulation and circulation tests has enabled a refined characterization of the subsurface fracture network. The resulting discrete fracture network (DFN) provides improved constraints on fracture distribution, orientation, and connectivity. This study incorporates this refined DFN to perform a coupled hydro-mechanical analysis of the 2024 hydraulic stimulation using the discrete element method (DEM) based software XSite. To constrain fracture mechanical and hydraulic properties, a systematic sensitivity analysis is first conducted using Stage 1 of the 2022 hydraulic stimulation. Key DFN, hydraulic, and mechanical parameters are varied to identify parameter combinations that best reproduce both the observed injection pressure response and the recorded microseismicity. The sensitivity analysis demonstrates that the system’s response to fluid injection is highly influenced by the DFN realization and that the best match to field measurements is obtained by assuming an initially impermeable DFN with moderate shear strength which generally reproduces the extent of microseismic events and injection pressure history. The calibrated modeling framework is then applied to stimulation Stages 8–10 of the 2024 campaign to assess the influence of DFN geometry and fracture hydraulic behavior on pressure response, fracture activation, and flow path development. The results confirm that an initially strong and impermeable DFN provides a better match to field observations, whereas weak and permeable DFN scenarios overestimate the spatial extent of fracture reactivation due to their diffuse response. While the updated DFN captures aspects of the observed stimulation behavior, particularly shear failure extent, more realistically in Stages 8 and 9, discrepancies remain near Stage 10, indicating missing fracture pathways or uncertainties in local fracture properties. These findings highlight the importance of integrating geophysical data into DFN-based models to enhance their predictive capability and optimize reservoir development strategies in naturally fractured geothermal systems.

Topic: FORGE

The Utah Frontier Observatory for Research in Geothermal Energy (Utah FORGE) is the U.S. Department of Energy’s dedicated field laboratory for advancing enhanced geothermal systems (EGS) technology in low-permeability, high-temperature crystalline rock. Since being awarded the FORGE designation in 2018, Utah FORGE has progressed through multiple development phases focused on site characterization, drilling, stimulation, circulation testing, and open data sharing to reduce the cost and risk of EGS deployment. This presentation provides an update on recent activities and outlines near- and mid-term plans at the Utah FORGE site near Milford, Utah. Major accomplishments to date include significant reductions in drilling time and cost through optimized drilling practices and novel polycrystalline diamond compact (PDC) bit designs, successful drilling and stimulation of highly deviated geothermal wells, demonstration of commercial-scale flow rates and temperatures, and pioneering applications of fiber-optic sensing and advanced microseismic monitoring in high-temperature environments. Utah FORGE has also supported a broad external R&D portfolio, resulting in new tools and technologies for drilling, stimulation, and reservoir monitoring. Current activities focus on Phase 4A circulation testing, including construction and commissioning of surface facilities, extended-duration circulation between existing wells, and comprehensive seismic, thermal, and geochemical monitoring. Results from this testing will guide the placement and design of an additional instrumented well and inform subsequent stimulation and longer-term circulation experiments. Planned work aims to further evaluate reservoir connectivity, thermal sustainability, and operational performance under conditions relevant to commercial EGS development. Collectively, these efforts continue to advance the technical foundation needed to achieve DOE cost and deployment goals for geothermal energy.

Topic: Introduction

Fault geometry exerts a first-order control on geothermal systems by governing stress localization, fracture development, and permeability, yet in complex fault networks or broader shear zones, the relative influence of individual geometric features is often difficult to resolve. In the northern California Coast Ranges, The Geysers geothermal field is commonly interpreted to occur within a releasing stepover, although no single, clearly defined stepover is identified in published studies. To investigate the structural controls on The Geysers and the broader Clear Lake region, a two-dimensional elastic boundary element model is developed to evaluate spatial patterns of dilational strain associated with progressively more complete fault geometries. Model results show that dilation in the region is not controlled by a single structure but instead reflects the combined effects of multiple interacting fault elements. Three primary controls are identified: (1) opposing bends in the regional strike-slip fault system, including a releasing bend along the Maacama fault; (2) the southern fault tip of the Collayomi fault, which generates a prominent dilational lobe beneath the southern Geysers; and (3) a releasing stepover between the Collayomi fault and the Geyser Peak–Mercuryville–Big Sulphur Creek fault system, inferred to collectively behave as a right-lateral shear zone bounding the western margin of The Geysers. Predicted dilational strain magnitudes are sufficient to localize permeability between faults. These results highlight that incorporating complete fault networks and bedrock geological mapping can enhance geothermal assessments and provide a transferable framework for evaluating structurally controlled permeability in tectonically active regions.

Topic: Geology

Advanced testing and verification tools for supercritical geothermal well materials are critical for successful well construction and operation, as they enable the effective selection of appropriate materials. Through reviewing existing methods, published results, and insights into material behavior from public literature and expert interviews, we identified the primary challenges, knowledge gaps, and recommendations for future tools/methods development. Major challenges include replicating high-temperature ( greater than 375 °C) and high-pressure ( greater than 22 MPa) conditions in laboratory environments while accommodating realistic material dimensions and dynamic fluid flow, performing in-situ measurements, and validating newly developed simulation tools. In this review paper, we focus on tools and methods for characterization of fluid chemistry, mechanical degradation, corrosion rates, wellbore hydraulics, and well integrity. Some interesting findings include but not limited to: (1) both experiments and simulations demonstrate that corrosion is more severe in subcritical conditions (around 350 °C) than supercritical conditions; (2) casing materials exhibit pronounced plasticity at high temperatures, whereas rock and cement materials require further investigation due to the complex brittle-to-ductile transition that depends on lithology, chemical composition, and mineralogy; (3) there is a lack of experimental validation of cement mechanical properties and cement stress state at supercritical conditions; and (4) some reported tests, though not originally focused on well materials, can be leveraged for well material assessment—such as strength testing of proppants and rocks, permeability tests on reservoir rocks, fluid chemistry analyses, and hydraulic fracturing experiments. The testing and validation overview highlights the critical research priorities for advancing the understanding and performance of well construction materials in supercritical geothermal environments.

Topic: Drilling

This study presents a data-driven framework for modeling, interpreting, and forecasting heat recovery behavior in hydrothermal and fractured geothermal reservoirs. By combining scientific computing with unsupervised and supervised machine learning, this approach offers a robust methodology for extracting dominant patterns to understand various geothermal systems. Several machine learning techniques were used to provide insights on key geophysical and thermal transport dynamics in low-enthalpy hydrothermal reservoirs. Self-Organizing Maps (SOM) cluster normalized production temperature profiles into four temporal regimes (early, early-intermediate, late-intermediate, and late). Non-negative Matrix Factorization with K-means (NMFK) extracts five latent temperature signatures tied to these regimes. Supervised models (XGBoost, Random Forest, and Deep Neural Networks) are trained on each regime, and interpreted using SHAP analysis to identify the influence of key features such as temperature ratio, thermal Peclet number, fluid expansion, and reservoir geometry on the thermal regimes. Next, the ML workflow is applied to varying fracture network configurations representing enhanced geothermal systems (EGS). Each model incorporates deterministic and stochastic fractures, dynamic well placements, and consistent thermal-fluid-rock properties. Simulation outputs including temperature and pressure data from fracture and matrix zones are processed with NMFK to reveal dominant temporal signatures. These patterns differentiate between fracture-dominated regimes, with early thermal breakthrough, and matrix-buffered regimes characterized by gradual heat conduction. The proposed framework integrates the understandings from dimensionless subsurface transport phenomena, machine learning techniques, and predictive modeling for geothermal reservoir characterization and sustainable energy development.

Topic: Modeling

GEOTHERMAL ARRAYS -- Time to scale the harvesting of geothermal heat for conversion to grid electricity. And not just because geothermal is clean. No, we choose geothermal because it is now emerging firm, abundant, safe, and competitively harvested almost anywhere. How best to scale geothermal? We urge the development of … geothermal arrays. With our Internet mindsets in place, let us not continue toward ever bigger geothermal mainframes. Instead, let us network smaller, standard, competitively-sourced wells into geothermal arrays. While accelerating progress continues at the well level, let us move up to the array level. Let us chat with our AIs about the energy they will need and about how soon to deliver that energy with capacity factors (CFs) approaching 100% and with levelized costs of electricity (LCOE) on a new plateau, less than a cent per kilowatt-hour 1¢/kWh.

Topic: Modeling

Geothermal resource exploration is a key pathway to harnessing renewable energy from the Earth’s heat, offering a sustainable alternative to conventional energy sources as part of the reliable baseload. Enhanced Geothermal Systems (EGS) introduce engineering techniques to improve subsurface reservoirs and extract significant energy from hot, low-permeability rock where traditional systems cannot achieve sufficient performance. By drilling into hot rock and injecting fluids, engineering induced fracture networks that allow working fluids to circulate, transfer heat, and return to the surface to produce energy for increasing demands. Alongside multi-level dataset integration, understanding the geometry and evolution of these fracture and fault networks is critical to optimizing fluid flow, heat recovery, and reservoir sustainability. This work introduces FLOWDASH, an integrated software platform designed to visualize such datasets and analyze fracture networks and associated performance metrics at multiple scales—well-level, segment-level, and stage-level. FlowDash integrates completion and stimulation data, geophysical observations, machine- learning techniques, and economic analysis to support EGS decision-making in an interactive fashion. The platform’s visualization module is designed to present multi-scale reservoir features using interactive well-path schematics, stage-by-stage fracture mapping, temporal seismic event plots, and heat-flow trends. These graphical interfaces allow users to overlay production, seismic, and cost data for rapid interpretation. The software architecture uses a Python-based back end for data handling and computations, coupled with a Tkinter-driven front end that supports real-time updates of charts and diagrams. FlowDash includes a built-in cost- analysis tool that allows users to calculate and compare energy production potential, projected profit, as well as generate visual graphs from these calculations—which users can download such plots directly in various of formats such as images to create customized reports. To characterize the subsurface, the platform processes passive seismic monitoring data and employs up to five unsupervised machine-learning algorithms for micro seismic clustering, b- value quantification, and hydraulic diffusivity analysis. Both hydraulic and natural fractures are delineated to capture reservoir complexity, and the integrated workflow bridges technical teams and decision-makers by combining geophysical interpretation with economic projections. The platform provides an intuitive and centralized environment for interpreting complex datasets, analyses, and results of fracture and fault systems that emerge during EGS operations. The tool enhances reservoir characterization by correlating seismic-derived fracture geometry with production metrics and thermal performance. Early applications of FlowDash have demonstrated its potential to identify high-permeability zones, optimize stimulation designs, improve reservoir-pressure management, and guide decisions on interference- mitigation and re-stimulation planning. FlowDash streamlines workflows for both technical and financial assessments, supporting data-driven strategies for improving reservoir sustainability and energy output. FlowDash unifies geophysical, machine-learning, and economic analyses within a single, intuitive platform to improve geothermal reservoir management. This integrated approach equips engineers, researchers, and stakeholders with actionable insights that enhance efficiency, reliability, and sustainability in geothermal energy production. More datasets and analysis for EGS are still on-going for further insights to support decision making.

Topic: Enhanced Geothermal Systems

As demand for cleaner energy sources grows, geothermal operators must maximize production efficiency from geothermal reservoirs used for power and heat generation. One of the critical challenges shared between geothermal and oil and gas reservoirs is thermal short-circuiting, a phenomenon where cooler injected fluids bypass heat exchange processes by flowing directly to production wells via high-permeability pathways or dominant fractures. This issue, reported in projects such as FORGE and Soultz-sous-Forêts, leads to significantly reduced heat extraction efficiency, as fluid flow distribution within the reservoir is suboptimal. While several techniques have been deployed to address thermal short-circuiting, many have resulted in limited success or even adverse effects on production efficiency. Autonomous Flow control devices (AFCDs) offer a promising solution to these challenges. These tools, already proven in reservoir management for oil and gas wells, can optimize geothermal system efficiency by distributing fluid flow more uniformly, increasing contact between injected fluids and heated rock and enhancing heat absorption. This study explores the potential of autonomous flow control technologies in Enhanced Geothermal Systems (EGS) to address thermal short-circuiting and improve reservoir heat management. For the first time, this paper presents the functionality of autonomous flow control devices, designed to regulate the flow of cold and heated water plus steam, under laboratory conditions. Additionally, results from a comprehensive modelling practice that applies this technology to a geothermal system are discussed. The study simulates multiple possible scenarios which under those cold fluids are injected through an injection well into a naturally fractured and/or hydraulically fractured, high-temperature medium, while heated fluid is subsequently produced via a production well. The impacts of a few uncertain parameters and how the devices mitigate the risk associated with such uncertainties are also addressed. The results highlight that the integration of AFCDs significantly mitigates operational inefficiencies by ensuring uniform fluid distribution, reducing thermal short-circuiting, and maintaining stable reservoir conditions. Furthermore, autonomous flow control devices enable dynamic flow regulation, adapting to changing reservoir conditions in real-time. These advancements lead to delayed cold-water breakthrough for four years while improving thermal recovery by up to 16% and significantly improving economics of the projects. This study illustrates that incorporating AFCDs into geothermal systems represents a significant leap in geothermal reservoir management, offering enhanced heat efficiency, improved sustainability, and greater economic viability for geothermal energy projects. The findings underscore the importance of leveraging advanced flow control technologies to meet the growing global demand for renewable energy.

Topic: Emerging Technology

The Utah Frontier Observatory for Research in Geothermal Energy (FORGE) conducted a 30-day commercial-scale circulation test in August 2024 between wells 16A(78)-32 and 16B(78)-32. During this test, field data were collected, including injection pressure, spinner log measurements of mass flow near each injection perforation, tracer injection and recovery, and mass injection and recovery rates. A discrete fracture network (DFN) of the FORGE site was developed using microseismic data from hydraulic stimulation and circulation tests, core samples, strain gauge measurements, and inferred fracture connectivity derived from flow and pressure responses. In this study, a multi-component thermal-hydraulic simulation of the DFN was calibrated to match the observed field data and used to predict thermal breakthrough behavior. The DFN is modeled as a set of 2D fractures embedded in a 3D domain, with fracture permeabilities dependent on their aperture and flow rate. A linear relationship between mass flow rate and fracture aperture calibrated to the circulation test data is used to parameterize the DFNs based on spinner log data. Using the calibrated parameters, thermal-hydraulic simulations were performed to model a 180-day circulation test and estimate the time to thermal breakthrough.

Topic: FORGE

Geothermal systems occur across diverse geologic settings, and the viability of a conventional development depends not only on elevated temperatures, which are essential, but also on the distribution of permeable rocks and fractures that enable sustained fluid production. Observations and analysis from global analogs reveal characteristic pressure and temperature behaviors that allow reservoirs to be classified by permeability type. This classification enhances early assessments of resource potential and informs exploration and development strategies. The characteristics of four end-member Permeability Regimes are described: Discrete, Limited Distributed, Enhanced Distributed, and Stratigraphic. A companion study, Libbey and Murphy (2026), provides greater detail on the geology and resource parameters of Area and Thickness which characterize these systems as well as detailing a standardized methodology utilizing these characteristics for estimating resource capacity.

Topic: Reservoir Engineering

Thermo-hydro-mechanical-chemical (THMC) flow-through experiments were conducted to evaluate the stability of three proppant systems under Utah FORGE-representative EGS conditions. Quartz sand (FORGE 40/70), Carbolite 40/70, and Kryptosphere LD (40 mesh) were confined between granitoid platens and exposed to 2,000-6,000 psi and 200 °C in deionized water. Mineralogical, chemical, and mechanical responses were assessed using XRD, SEM-EDS, ICP-MS, and API sieve analysis, and compared with earlier thermo-chemical (TC) batch tests in Utah FORGE fluids at 220 °C. XRD shows that both ceramic proppants maintained their crystalline structure under TC and THMC loading, though with amorphous-peak changes. FORGE sand exhibited stronger feldspar-range peak modifications in FORGE fluids than in DI-water THMC tests, confirming the dominant role of fluid chemistry in dissolution pathways. SEM-EDS indicates stress-enhanced surface alteration; mainly Al-Si reactivity on ceramics and Fe removal from FORGE sand, but with limited correspondence between TC and THMC trends. ICP-MS results show that THMC conditions significantly increase dissolution relative to TC tests, with cumulative major-element release (TIRI) lowest for Kryptosphere LD (~2.6×10⁵ ppb), intermediate for FORGE sand (~2.66×10⁵ ppb), and highest for Carbolite (~3.12×10⁵ ppb). Sieve analysis reveals negligible less than 140-mesh fines for the ceramics but ~22 % fines and a high conductivity-weighted breakage index (CWBI ≈ 52-55) for FORGE sand, indicating severe mechanical degradation. A multi-criteria decision framework (AHP) integrating TIRI, CWBI, and price weighted fines most heavily (0.584), followed by price (0.281) and dissolution (0.135). Resulting scores were 0.752 (Carbolite), 0.719 (Kryptosphere LD), and 0.400 (FORGE sand), showing that mechanical integrity is the dominant factor governing performance under geothermal THMC conditions. Ceramic proppants therefore outperform sand despite higher cost. These rankings apply only to the tested materials and selected criteria; future work should incorporate additional performance metrics and expanded proppant classes.

Topic: FORGE

The increasing demand for sustainable energy has intensified interest in geothermal energy, with enhanced geothermal systems (EGS) emerging as a key solution. Hydraulic fracturing, a critical technique in EGS, and continuous injection for reservoir management often induce microseismic events that provide valuable insights into subsurface fracture mechanisms and reservoir properties. This study examines the promising and evolving role of machine learning (ML) in analyzing induced seismicity in geothermal fields, focusing on applications including data acquisition, processing, and interpretation. Specifically, we present four key ML applications: wavefield inpainting for reconstructing missing seismic data, generative artificial intelligence (Gen-AI) for wavefield simulation, transformer-based phase picking for detecting small seismic events, and clustering methods to analyze the spatio-temporal evolution of seismicity. These approaches enhance the efficiency and accuracy of seismic monitoring, offering innovative tools for optimizing geothermal energy extraction. Additionally, the study highlights the importance of pre-processing and data augmentation in addressing challenges such as data scarcity and noise in seismic datasets. Techniques like spectral analysis, attenuation correction, noise injection, and the use of multiple time windows are key to obtaining reasonable results from ML models with limited amounts of data. This research provides insights into ML-aided induced seismicity processing and interpretation for seismic monitoring and reservoir management in geothermal fields, contributing to more efficient and sustainable energy operations while mitigating large induced seismic events.

Topic: Geophysics

High-resolution monitoring of microearthquakes near enhanced geothermal system (EGS) reservoirs is essential for understanding rock-fluid interactions and reservoir evolution during and after stimulation and production. However, the extreme downhole conditions of EGS environments, characterized by high temperatures and pressures, pose significant challenges for conventional seismic and other geophysical sensors. To address this, we are developing a high-temperature, single-level, three-component seismometer based on a 4.5 Hz string-type geophone with a seven-conductor cable. The mechanical and electrical components have been redesigned to enhance durability under conditions up to 260 degree C and 40 MPa. In July 2025, we deployed the sensor at a depth of 2,132 m (176 degree C) in a vertical borehole at the Cape field, Utah, to continuously monitor reservoir activity and seismicity. The sensor has operated successfully since installation, detecting more than 100 times as many earthquakes as the nearby UU.FORK station at 282 m depth. Even compared with borehole distributed acoustic sensing (DAS) data, our instrument recorded approximately 3-5 times more events, demonstrating superior sensitivity and robustness in high-temperature environments.

Topic: Enhanced Geothermal Systems

To meet the growing demand for Enhanced Geothermal Systems (EGS) deployment across the United States, it is essential to expand EGS viability across a wide range of geological settings that differ in lithology, temperature, stress regime, and fluid conditions. A key challenge in scaling EGS is the management of induced seismicity, which directly influences both public perception and long-term operational success. At Lawrence Berkeley National Laboratory (LBNL), we have established and operated seismic monitoring systems across a diverse portfolio of EGS and conventional geothermal sites, including The Geysers, Desert Peak, Brady Hot Springs, Raft River, Newberry, Patua, Cape Modern and Utah FORGE geothermal fields. These networks—ranging from borehole and surface geophones to broadband optical accelerometers—were tailored to site-specific geological and operational conditions, enabling long-term, high-resolution observation of microseismic activity and reservoir behavior. Drawing on more than a decade of multi-site experience, we present the principal lessons learned from field deployments and sustained monitoring. These lessons encompass network design trade-offs between cost, sensitivity, and spatial coverage; the critical role of borehole sensors in lowering magnitude completeness below M0.0; the benefits of robust telemetry and data streaming for real-time analysis; and the importance of calibration, permitting, and noise mitigation. Together, these insights have informed the development of best practices for seismic monitoring in EGS projects and contributed to DOE’s evolving induced seismicity protocols. Finally, we highlight LBNL’s ongoing efforts to ensure open data access through repositories such as NSF SAGE, fostering collaboration and advancing future geothermal research and reservoir management.

Topic: Geophysics

We present the recent effort of the seismic monitoring system at the Newberry Enhanced Geothermal System (EGS) site. The network comprises eight borehole sensors reaching depths of up to 300 m—six legacy 2 Hz geophones (NN07, NN09, NN17, NN19, NN21, NN24) that have been continuously operational since 2012, and two broadband accelerometers (NN18 and NN32) added in 2023 to extend the frequency bandwidth and dynamic range. Data from all sensors are streamed in near real time to the EarthScope Data Management Center (DMC), where they are publicly accessible. Additional regional coverage is provided by nearby stations operated by the University of Washington’s Pacific Northwest Seismic Network (PNSN) and the USGS Cascades Volcano Observatory (CVO). All seismic data are processed in real time using LBNL’s automated detection and analysis pipeline, which identifies, locates, and estimates magnitudes of induced events associated with injection activities at the Newberry site. To enhance spatial and temporal resolution during reservoir stimulation, we also deploy borehole distributed acoustic sensing (DAS) and a surface nodal network consisting of 90 nodes. We analyze seismic signals from two 2025 stimulations (January and August) and compare them with the 2012 and 2014 experiments. Although the 2025 campaigns generated fewer detectable seismic events, the DAS captures coherent P and S wave propagation, which are useful to locate the events. Because the surface stations do not record clear wavefields due to their signal-to-noise ratio, the earthquake size is expected to be much smaller than 2012 and 2014 stimulations.

Topic: Enhanced Geothermal Systems

Fault zones are primary controls on permeability architecture, fluid circulation, and heat extraction in high-enthalpy geothermal systems hosted in volcanic terrains. In the Olkaria East and North-East geothermal fields of Kenya, these zones are characterized by intervals of intense fracturing that are routinely intersected during drilling operations. This study presents a systematic analysis of drilling fluid and circulation returns loss zones recorded in 32 geothermal wells to delineate shallow fault damage zones and assess their spatial distribution, geometry, and structural controls. The loss zones are interpreted as zones of enhanced permeability associated with fault-related fracture networks. Correlation of loss intervals with lithological logs, well trajectories, and regional structural trends shows a strong spatial association between the loss zones and the N-S (Oloolbutot fault & Olkaria fracture), ENE–WSW (Olkaria fault), and NW–SE striking faults and fractures, which constitute the dominant structural fabric of the Olkaria Volcanic Complex. Statistical analysis indicates that 70–75% of all loss zones in the sampled wells occur at depths shallower than 300 m. Loss zone thicknesses range from less than 20 m to greater than 500 m, with the thickest zone at OW-51A having an 800m loss zone. Lateral continuity of loss zones across adjacent wells (e.g., the 742, 731, and 710 well clusters) supports interpretation as coherent fault damage zones rather than isolated fractures. The results demonstrate that drilling loss data provide a cost-effective, high-resolution dataset for characterizing shallow structural permeability and refining fault models in active geothermal field development.

Topic: Geology

Geothermal energy serves as a sustainable and low-carbon alternative that supports the adoption of a diversified and sustainable energy mix. The deep sedimentary basins of North Dakota, particularly within the Mississippian and Devonian formations, possess substantial geothermal potential, making them promising targets for geothermal energy development. Efficient utilization of these geothermal resources requires a robust understanding of the inherent subsurface uncertainties and spatial heterogeneities that influence reservoir performance. This study integrates geostatistical modeling with geothermal reservoir engineering principles to evaluate uncertainty parameters within the geothermal system of the Three Forks formation (Williston basin). Through probabilistic analysis and Monte-Carlo simulation, we quantify the variability and ambiguity of critical subsurface properties within the target formation to improve the reliability of resource assessment and project feasibility within the basin. Field data from the Mississippian and Devonian intervals were analyzed to characterize uncertainties in key parameters that control geothermal energy potential, thereby reducing exploration risks and promoting sustainable development. Uncertainty quantification and probabilistic resource assessment are crucial for informed decision-making and efficient reservoir management. In the case of the Three Forks formation, the arithmetic mean estimates for total geothermal resources, aquifer geothermal resources, and producible geothermal resources were found to be approximately 3.3 × 10¹⁸ J, 1.08× 10¹⁷ J, and 1.02 × 107 J, respectively. These insights provide a quantitative basis for optimizing geothermal energy extraction from the Mississippian–Devonian formations in North Dakota.

Topic: Modeling

An update of progress at Fervo.

Topic: Introduction

Geothermal Energy remains one of the best green sources of energy in Kenya as it currently contributes the single largest energy source at slightly over 40% of all the interconnected grid Energy in Kenya. Other major sources of Energy in Kenya include hydro-electric power, wind, biomass and thermal. KenGen PLC being the leading and largest power generator in the country boasts of not only leading in Hydro-electric power generation but also leads in terms of Geothermal Energy. Its Geothermal Energy generation is close to 800MW thus constitutes about 80% of the Kenya’s geothermal energy. For this geothermal energy to continue being useful and sustainable, prudent reservoir (resource) management is encouraged. KenGen PLC has been generating geothermal power since 1981 in their Olkaria geothermal field. Its generation has increased from the initial 15MW to the current 797MW. This development has been done step wise with rapid expansion being witnessed in the last 10 or so years. This rapid expansion has come with its own technical, social and environmental challenges. However, it is noted that KenGen has initiated a number of strategies in ensuring the sustainability of their geothermal resource. These strategies have included geothermal fluid re-injection (both cold and hot), periodic production wells monitoring and modelling, systematic exploitation of the resource and implementation of innovation ideas that make use of efficient technologies in steam field management and power plant generation. This paper discusses some of these strategies in details and also highlight the current challenges and recommendations. These recommendations are meant to ensure that KenGen continues to sustainably exploit the geothermal resource within its Olkaria licence area without getting into the dangers of long-term degradation.

Topic: Field Studies

Drilling geothermal wells generates significant amounts of metal waste, which contributes to environmental degradation when not properly handled. It is against this backdrop that this proposal is made to recycle metal waste for use in other applications or geothermal drilling operations. This will also take advantage of the idle power associated with geothermal systems. This, when implemented, will generate additional revenue for organizations involved and also greatly improve environmental preservation.

Topic: Production Engineering

Since 2011, a geothermal heat pump (GHP) system has been operating to provide space heating and cooling for the Solar Radiation and Research Laboratory (SRRL) building at the National Laboratory of the Rockies (NLR) in Golden, Colorado. The system consists of 23 vertical boreholes, each extending to a depth of 300 ft (91 m), connected to 11 water-to-air heat pump units and four circulation pumps. Between fiscal years 2023 and 2025, additional power meters and temperature sensors were retrofitted to support detailed system performance assessment and model development. This study presents preliminary monitoring results and the development of an initial numerical model of the borehole heat exchanger field. The model incorporated site-specific geometry, ground thermal properties derived from thermal response tests, and ambient temperatures, and simulated system behavior over a representative operating day in September 2025. Model predictions of outlet temperatures were compared against corresponding field measurements. Results showed that modeling initialized with a simplified linear subsurface temperature gradient presents systematic discrepancies in outlet temperature, whereas incorporating depth-informed borehole temperature measurements for initialization yields substantially improved agreement with observations. The findings highlight the sensitivity of short-term predictive modeling to the representation of initial subsurface thermal conditions and underscore the value of high-resolution field measurements for model calibration and validation. These preliminary results inform ongoing efforts to extend the modeling framework to longer time horizons and to refine monitoring and modeling strategies that support the design and operational optimization of GHP systems in research and commercial buildings.

Topic: Modeling

Kenya Electricity Generating Company operates five major geothermal power plants and fifteen wellhead units with a combined capacity of 799 MW. Within the Olkaria Geothermal Field, Olkaria I Additional Unit (IAU) power plant is located in the East production field. It shares steam gathering and hot reinjection infrastructure with Olkaria II power plant. This interconnection includes common steam lines, separator stations, and reinjection systems, allowing for flexible steam supply, minimal venting, and improved plant availability. Despite these benefits, challenges arise from the shared infrastructure, particularly related to unbalanced mass flow during hot reinjection. The most significant issue occurs when a unit or several units are shut down for maintenance or emergencies, disrupting steam line continuity. Such interruptions reduce brine available for reinjection, causing wells to overheat and pressures to exceed inflow capacity. This imbalance often leads to separator flooding and brine carryover, which can trip units due to high scrubber levels and introduce silica scaling complications. These disruptions compromise reinjection efficiency and plant stability. The effects are amplified by the interconnected nature of the steam field, where a change in one plant’s status directly impacts the other. As such, understanding and managing mass flow distribution is critical for sustainable field performance. This paper examines the implications of hot reinjection challenges on power plant operations with a focus on mass flow imbalance and infrastructure interconnectivity at Olkaria.

Topic: Injection

Silica scaling within geothermal wellhead silencers is a major operational issue that reduces equipment efficiency and increases maintenance costs. During the discharge of geothermal fluids, rapid pressure drops and cooling cause dissolved silica to become supersaturated, leading to the formation of amorphous silica deposits on internal surfaces. This paper examines the mechanisms and conditions that promote silica scaling inside silencers as well as control measures, emphasizing the influence of temperature, pH, and silica concentration. Field observations show that scaling is most severe in zones with high turbulence and abrupt temperature changes. The buildup restricts fluid flow, diminishes silencer performance, and can lead to costly shutdowns. Mitigation strategies such as pH control, fluid re-injection before flashing, and regular mechanical cleaning are discussed. Understanding the kinetics and thermodynamics of silica precipitation in silencers is essential for developing effective scale control methods and improving the reliability of geothermal power systems.

Topic: Production Engineering

Enhanced Geothermal Systems (EGS) were first introduced in the mid-1970s to augment natural hydrothermal production, whose commercial use began roughly a century ago. Yet, despite this long development history and the vast global endowment of accessible geothermal heat, geothermal power has remained a minor contributor to global energy supply. The persistent underperformance of conventional EGS arises from two fundamental technical limitations. First, effective access to subsurface heat is intrinsically limited by hydraulic and thermal short-circuiting. The conventional EGS design, which depends on intersecting perpendicular injection and production wells through an augmented fracture network via hydraulic fracturing, allows the circulating working fluid to flow along the lowest-resistance pathways preferentially. This channeling minimizes contact area with large volumes of hot rock mass and results in premature thermal breakthroughs, drastically reducing the useful life and output of the system. Second, the EGS system suffers from insufficient thermal replenishment within the fracture-stimulated rock volume. Closely spaced, congested fractures restrict the rate at which conductive heat from the surrounding formation can recharge the cooled fracture faces. As a result, EGS reservoirs experience rapid temperature decline and are forced into intermittent operational modes, effectively functioning as costly, low-efficiency thermal storage systems, rather than continuous power sources. Consequently, EGS and related Hot Dry Rock (HDR) and Super-Hot Dry Rock (SHR) approaches have struggled to deliver the sustained, high-capacity power output envisioned decades ago. VegaGeo 3.0’s Hybrid-Semi-Loop System (HSLS) technology, constructed in zero-permeability, plutonic rock, modifies the traditional EGS multiple-well deviated configuration by using a single vertical wellbore trajectory with induced bifurcated propped hydraulic fractures that are co-planar. It maintains full hydraulic communication with the propagation plane of induced fractures. This integrated geometry enables continuous sweeping of the induced fracture surface area, eliminating flow bypass and maximizing hot rock contact. Numerical simulations indicate that VegaGeo 3.0 can sustain high long-term baseload production exceeding 50 MWₜ, demonstrating efficient heat extraction through complete utilization of fracture flow paths. Long-length flow diverters are constructed in the propped fractures, bifurcating them, and causing lengthy heat-collecting fluid flow away from and back to the wellbore, super heating fluids over several hours of exposure to 350 – 750°F rock. Accessing deeper vertical depths within the earth’s upper crust, with heat levels well beyond traditional practice, the reconfigured system fractures are separated laterally by more than 1000 ft, thus allowing high baseload level heat replenishment. Respecting all preferences and advantages for heat extraction from significant depth, the newer method is called the VegaGeo 3.0. This paper presents this novel approach and analysis of simulated performance in deep HDR and SHR. The advanced VegaGeo 3.0 HSLS configuration was evaluated using Computational Fluid Dynamics (CFD) coupled with conjugate heat-transfer (CHT) analysis to predict production temperature and thermal power output under a range of geological, geothermal, and operational conditions. The modeling encompassed variations in rock thermal gradient, fracture geometry, vertical fracture separation, inlet temperature, and circulation rate, allowing a comprehensive assessment of system behavior from early-time transients to long-term steady-state operation. Analytical optimization indicated that a configuration incorporating approximately 15 hydraulically connected co-planar fractures, vertically separated by up to 1,100 ft (~335 m), provides the most practical balance between drilling complexity, reservoir recharge, and sustained heat extraction. Results from both transient and steady-state simulations demonstrate that the VegaGeo 3.0 architecture can achieve 10 to 30× increases in baseload geothermal energy output relative to conventional multi-well EGS systems. Modeled thermal production exceeds 110 MWₜ at initial startup, maintains an average of approximately 50 MWₜ over a 20-year operational period, and does not reach steady-state production of roughly 30 MWₜ until after 25 years of continuous operation. These findings confirm that the VegaGeo 3.0 framework enables unprecedented longevity and capacity in engineered geothermal systems, firmly establishing its potential as a true high-enthalpy baseload geothermal technology.

Topic: Emerging Technology

The economic viability of Enhanced Geothermal Systems (EGS) is fundamentally governed by the balance between thermal energy recovery and the associated costs of subsurface engineering and sustained surface injection. This study conducts a comprehensive numerical investigation to evaluate the thermal performance of a field-scale EGS fluid circulation system. Geologic and well completion data from Fervo’s EGS wells in Milford Valley, Utah is used as an example case. A fully coupled hydro-thermal simulator was employed, integrating reservoir, fracture, and wellbore domains to model long-term fluid circulation involving two injection wells and one production well. Sensitivity analyses were performed to assess the impact of key subsurface and operational parameters, including fracture permeability distribution, proportion and spatial arrangement of active fractures, injection rate, inter-well spacing, and cluster spacing. Simulation results highlight that achieving high energy recovery rates in EGS requires strong inter-well hydraulic connectivity and a uniform distribution of fracture permeability. Furthermore, cluster spacing emerges as a critical design parameter, as it governs the trade-off between effective subsurface thermal sweep and surface injection load. To maximize the heat recovery over time, the cluster spacing, and the injection rate can be optimized for a given well spacing. This relationship between these three operator-controlled variables is explored in detail. It is found that for a given well spacing, the optimum cluster spacing increases with the total injection rate. The overall injection rate must be maintained as high as possible but is limited by the fracture propagation pressure (minimum in-situ stress) and the parasitic energy losses needed to pump the fluid. Under these constraints an optimum cluster spacing can be obtained that will maximize the heat recovery rate. These findings provide valuable insights into optimizing EGS design to maximize net energy output and project profitability.

Topic: Enhanced Geothermal Systems

The long-term performance of Enhanced Geothermal Systems (EGS) depends greatly upon the ability to maintain fracture conductivities long enough to allow for extraction of heat from the deep subsurface at economically viable rates. Hydraulic stimulation is an important tool used to create the conductive pathways required for this purpose. However, in the absence of proppants, hydraulic fractures will close as the in-situ stress increases. Proppant injection is important because proppants are used to create a permanent channel for fluids to flow through the created fractures so that they remain open, and the reservoir will continue to produce. Compared to other conventional oil and gas operations, there are some significant differences in using proppants for geothermal systems. First, the proppant has to maintain its mechanical strength and hydraulic performance at temperatures higher than 200°C. Second, the geochemical environment of geothermal reservoirs can be very aggressive and corrosive, which can cause the proppant to crush, undergo chemical changes and generate fines, all of which result in the progressive reduction of the fracture's ability to conduct fluids. To provide a comprehensive reference for the selection of proppants in geothermal systems, researchers have integrated experimental data from laboratory scale tests with field data and new technologies to provide a full scope of proppant selection criteria. The focus of this study is to evaluate how proppants behave mechanically and chemically when subjected to high temperature conditions that are representative of EGS and super-hot rock (SHR) projects. Combining experimental data with practical field experience will support the decision-making process for selecting proppants to sustain the conductivity of fractures over the life of geothermal energy production. This paper provides an overview of the current knowledge regarding the behavior of proppants under geothermal conditions, emphasizing the major factors contributing to the degradation of the fracture's ability to conduct fluids. Special emphasis has been placed on the development of new methods for testing proppants in SHR environments, where the temperature of the reservoir could be greater than 375°C. Additionally, the study explores the potential for developing technology or operating practices that would extend the time that the fracture's conductivity remains stable in deep geothermal reservoirs.

Topic: Reservoir Engineering

Turkey is among the world's top five countries in installed geothermal capacity and has a history of over four decades of research, exploration and project development. This paper presents a comprehensive overview of the historical development of the industry, its current status and future prospects, demonstrating how geology, technology and policy have combined to transform the industry from early hydrothermal applications in western Anatolia to the present day power generation and direct use applications, and key geothermal regions in the country are reviewed, including the Menderes and Gediz grabens, Tuzla and Kızıldere fields and newly explored regions in Central and Eastern Anatolia. Main factors guiding development strategies are discussed, including reservoir type, fluid chemistry and thermal gradient, while technological developments, including binary cycle power plants, reinjection practices, and approaches to manage scaling and corrosion, supported by domestic R&D and international partnerships, are also reviewed. Furthermore, policy and market aspects are discussed, including feed-in tariffs, exploration licenses and incentives provided by the Renewable Energy Law, and a ing comparison with other global leaders highlights that a vertically integrated geothermal industry is a key advantage in Turkey, but long-term reservoir sustainability, induced seismicity and environmental management remain challenges. Consequently, future opportunities are highlighted in hybrid systems, such as geothermal/solar and geothermal/hydrogen, as well as the expansion of direct use in agriculture and district heating, and the exploration of deeper, higher-enthalpy resources. The paper concludes by discussing research and policy priorities that would support Turkey in consolidating its leadership in geothermal innovation and in progressing toward a sustainable energy transition.

Topic: General

The Utah Frontier Observatory for Research in Geothermal Energy (FORGE) is a U. S. Department of Energy funded, field-scale laboratory dedicated to developing and testing technologies for the commercialization of Enhanced Geothermal Systems (EGS). Past operational hydraulic fracturing activities at Utah FORGE have included stimulations in 2019, 2022, and 2024 and a month-long circulation test in 2024. Each of these activities has been seismically monitored. Seismic monitoring is focused on both implementation of the Traffic Light System and imaging microseismic fractures in the reservoir. Seismic monitoring has evolved from operation to operation with the advent of new tools and advances in seismic processing. For the planned 2026 three-plus month-long circulation test, we propose to integrate data from deep borehole DAS, geophones in three deep boreholes, and data from geophones in three shallow (~300 m) boreholes to generate a real-time catalog. Separately, we will integrate data from the surface and shallow posthole and borehole stations into a machine-learning based algorithm to build an independent catalog. This catalog together with regional seismic monitoring efforts will be used to implement the Utah FORGE Traffic Light System and together with the hydraulic pumping data will be used to test an Adaptive Traffic Light System. We will also deploy a temporary geophone network. The geophone network will build on past temporary geophone experiments and deploy a mix of patches and single element geophones to enhance post-processing efforts.

Topic: FORGE

Direct measurement of deformation in geothermal reservoirs can provide valuable constraints on stimulation and heat extraction processes. It is feasible to characterize deformation with borehole tensor strainmeters, which can measure multiple components of strain at high resolution, but currently available instruments are limited to ambient temperatures. We have developed a tensor strainmeter for geothermal reservoir conditions. It is a thin sleeve containing optical fibers that is clamped around a casing, and we have conducted a suite of experiments to demonstrate performance in the laboratory. One experiment consisted of deploying a sleeve strainmeter on a steel pipe that was subjected to periodic transverse loads while heated to 225–275 °C for nearly six months. The strainmeter measured strain responses of up to 30 µε each time the transverse load was applied. The magnitude at each sensor varied slightly during the experiment, but there was no degradation in performance due to heating. A second experiment evaluated the sleeve strainmeter design at elevated pressure. Two strainmeters were evaluated by monitoring strain while they were attached to a standard oil and gas wellbore casing (5.5-inch API) in a custom vessel that was pressurized up to 5000 psi. The strainmeters were functional during the test and calibration data collected after the pressurization were essentially the same as calibration data prior to pressurization, indicating the effects of high pressure were negligible. Reservoir conditions at Utah FORGE are approximately 230°C and 3700 psi. Our experiments demonstrated strainmeter functionality for extended periods at temperatures and pressures significantly greater than those at the Utah FORGE EGS reservoir. The sleeve architecture can accommodate a variety of optical fiber sensors, including fiber Bragg gratings (FBGs), Distributed Acoustic Sensing (DAS) or interferometric sensors, establishing a flexible platform for high-resolution tensor strain measurements in extreme subsurface environments.

Topic: Emerging Technology

We build an efficient, open-source computational framework for the automated search for the injection and production well placements in hot, fracture-controlled reservoirs that sustainably optimize geothermal energy production. This search is carried out through 3D simulations of groundwater flow and heat transfer. We model the reservoirs as geologically consistent randomly generated 3D discrete fracture networks, where the fractures are approximated by 2D planar manifolds with polygonal boundaries embedded in a 3D porous medium, and the wells are represented by line sources and sinks. The flow and heat transfer in this system is modeled by solving the balance equations for mass, momentum, and energy, where the numerical solver combines the finite element method with semi-implicit time-stepping, algebraic flux correction, and the approximation of the wells via the non-matching approach. To perform the optimization, we use several gradient-free algorithms. We will present our latest results, considering geologically and physically realistic scenarios.

Topic: Reservoir Engineering

The Paipa–Iza geothermal system, located in the Eastern Cordillera of Colombia, is one of the most promising prospects for geothermal development in the country and serves as a reference for the entire Andean region. Its surface hydrothermal manifestations exhibit average temperatures between 65 and 90 °C, placing it within the category of low- to medium-enthalpy systems. Based on previous estimates, its electric potential is between 5 and 10 MWe, making it a potential small-scale solution for electricity generation through binary technologies, as well as for direct uses such as heating, industrial applications, and process integration. This study compiles available geological, geochemical, and geothermal data for Paipa–Iza and compares it to equivalent geothermal fields worldwide, such as Unterhaching (Germany, 3.5 MWe, 122 °C), Copahue (Argentina, 100 MWe, 150 °C), and Berlín (El Salvador, 109 MWe, 280 °C). The comparison shows that Paipa–Iza shares tectonic and surface expression characteristics typical of low-enthalpy systems but exhibits a more limited potential. This analogy, in our view, highlights the need for the application of advanced exploration methods, such as 3D conceptual modeling, magnetotelluric surveys, and coupled hydrothermal simulation, to reduce uncertainty and improve utilization strategies. Beyond its estimated installed capacity, Paipa–Iza provides a natural laboratory for the development of exploration methodologies under low-enthalpy conditions and with limited subsurface data, a typical scenario in Latin America. In this context, the complex is envisioned as a key pilot design project for Colombia, with the potential to contribute to the country’s energy diversification and its transition toward a low-carbon model, while strengthening international scientific cooperation in geothermal research.

Topic: Field Studies

Market demand for geothermal energy is rapidly escalating globally, largely due to the need for 24/7 electrification of power grids as well as policy changes toward decarbonization and GHG (greenhouse gas) reduction. An example feasibility study is presented that focuses on viability for heat and power generation. The study applies a streamlined workflow for evaluating the feasibility of repurposing late-phase or abandoned oil and gas sites for geothermal energy production to a case study in the southern United States. The initial phase of the workflow is Site Screening where Play Fairway Analysis (PFA) is used to down se1ect from five areas of interest to two based on: 1) lowest risk geology; 2) highest potential heat; 3) data rich areas; 4) existing grid connections; and 5) market demand. This initial project phase includes the development of site geomodels consisting of a structural and stratigraphic model, geomechanical model, temperature model, natural fracture assessment, and geochemistry. The initial phase incorporates the conceptual design of optimal well trajectories and stimulation zones to access the target heat source. Steps in the second phase of the study, Pre-Feasibility, were then applied to the two down-selected sites. In the second phase steps 1) fracture data are used to generate numerical Discrete Fracture Network (DFN) models; 2) hydraulic stimulations designs are developed to model hydraulic fracturing of intact rock or Enhanced Geothermal Systems (EGS) and alternatively hydroshearing of preexisting natural fractures; 3) the EGS and DFN models are upscaled to a gridded 3D permeability field; 4) resource potential and production forecasting of heat and minerals is performed using Reservoir Dynamic Modeling including sensitivity scenario testing of model uncertainty space; and 5) a preliminary Economic Analysis is performed which includes surface plant conceptual design, data requirements for the Basis of Design for drilling and completing the wells, drilling engineering design with risk analysis, well design time and cost estimate of DFN/EGS/AGS options, and a preliminary economic assessment for the Levelized Cost of Electricity (LCOE). In the final study phase, Feasibility, further down selection is performed to choose the site with the highest performance capacity and lowest LCOE. The base geomodel, DFN models, and well designs, are used to conduct full-physics 3D multistage EGS stimulation modeling. In this step we simulate coupled thermo-hydro-mechanical behavior of the fracture networks with 1) hydraulic fracture stimulation with no preexisting fracture network, and 2) hydraulic fracture stimulation through preexisting fracture networks to simulate reservoir injection, production and thermal output over 30 years. The results of the full-physics based refined Reservoir Dynamic Modeling is then used to update the techno-economic analyses. This study presents the full link between subsurface characterization and dynamic modeling of natural and induced fracture networks to assess geothermal potential at a prospective site. We show the potential of EGS locating sites in South Texas by drilling to ~5 KM and that their relative LCOE is highly dependent on subsurface conditions. Key findings are 1) production wells must be positioned above stimulated injector to exploit the vertical growth of hydraulic fracture into regions of lower stress magnitude. 2) preexisting natural fracture networks enhance thermal output; 3) well separation has a significant impact on thermal output with respect to hydraulic fracture length distribution (or stimulation zone for natural fracture scenarios) and 4) zonal isolation (flow conformance) significantly improves thermal output for hydraulic fracture cases.

Topic: Modeling

LCOE, IRR, and other techno-economic metrics were computed for a 500 MWe EGS project in 294 scenarios across temperatures ranging from 200–450°C, gradients from 28.3–112°C/km, and 2 drilling and completion cost models representing FOAK (first of a kind) and NOAK (Nth of a kind) approaches. Results indicate that SHR EGS may yield approximately 43% lower LCOE and 246% higher IRR compared to 200°C in NOAK scenarios. The gradient-weighted average SHR IRR (internal rate of return) of 34.5% is 24.5 percentage points greater than the gradient-weighted average Low-Medium IRR of 9.98%, a 246% relative increase. This is primarily driven by the higher enthalpy of SHR fluids, which increases net power production per well up to 520% and thereby reduces the total number of wells required by up to 84%. Furthermore, the analysis indicates that for high geothermal gradients, SHR may yield compelling returns even in present-day FOAK scenarios, with the IRR increasing by 21 percentage points or more compared to lower-temperature EGS.

Topic: Enhanced Geothermal Systems

The goal of this ongoing Department of Energy (DOE)-funded Ormat-GeothermEx Wells of Opportunity Project is to use stimulation techniques, guided by geomechanical modeling and analytical methods, to sequentially stimulate two existing wells with long open-hole sections at two operating fields in Nevada. These stimulations have the potential generation impact of up to several MWs at the Don A. Campbell (DAC) and Jersey Valley (JV) operating geothermal power plants. The subject wells for stimulation are DAC idle well 68-1RD and JV injection well 14-34. This paper describes the results of various tests and data collection activities conducted to understand and characterize the readiness of each well and wellsite for stimulation. For both wells, pressure-temperature-spinner (PTS) logs, geophysical logs and injection test data have been collected to complement extensive reviews of existing well and geothermal resource information. Additionally, laboratory testing has been performed on existing samples of representative core and cuttings to characterize the petrology and mineralogy of the formations of interest for stimulation of both wells. Herein we describe the usefulness of the data collected during BP1 activities for stimulation planning, and how they are used to inform the preparation of static geomechanical models and stimulation effectiveness models for the DAC and JV well sites, and for stimulation planning in general for geothermal wells with low productivity elsewhere. Currently proposed plans for through-tubing stimulation are also described for both wells.

Topic: Field Studies

Efficient thermal management of downhole electronics remains a critical challenge for the deployment of Measurement-While-Drilling (MWD) systems in high temperature geothermal environments. This study evaluates the thermal performance of conventional multilayer polyimide-based printed circuit boards (PCBs) within a modular, multi-stack architecture. Experimental tests were conducted under controlled heating conditions to characterize the temperature response and extract effective thermophysical properties of the PCB material. This data was then used to calibrate conjugate heat transfer simulations of both the PCB and the complete tool assembly. Results show that conventional PCBs exhibit anisotropic heat conduction, with radial thermal conductivities between 20–25 W/m·K, and axial values increasing from 0.3 to 0.6 W/m·K as temperature rises from 60°C to 200°C. Simulations indicate that conventional PCBs can effectively dissipate heat for low-power components ( less than 0.5 W) without excessive temperature rise, supporting their viability for modular MWD configurations. The findings provide valuable insights for designing cost-efficient, thermally reliable electronics suitable for next-generation geothermal drilling systems.

Topic: Drilling

Estimating the potential national build out of emerging geothermal technologies such as enhanced geothermal systems will require understanding state and local regulatory policies and permitting. Water use for enhanced geothermal systems is an outstanding issue, especially for the arid Western United States were elevated subsurface temperatures exist. We have developed an LLM application to gather water rights, availability, and permitting in 98 water districts in Texas. We present the challenges of validating the web-scraped and LLM retrieved information and map this information with the collocated geothermal potential. We have developed an LLM application to gather water rights, availability, and permitting in 98 water districts in Texas. We present the challenges of validating the web-scraped and LLM retrieved information and map this information with the collocated geothermal potential.

Topic: Emerging Technology

Albania is located next to the subduction boundary between the African plate and the Euro-Asiatic one, the basis that allows to have as part of the renewable resources also the geothermal ones, which for the time being are not used at all for their energetical features, but their use is limited only with their health values. The discovery several years ago, of an abyss over a hundred meters deep, having at the bottom, a strong thermal inflow and a vast lake, proofs that there is still much to be done regarding geothermal in Albania. Energetic calculations, technical design, economic analyses and the related calculations are part of this paper.

Topic: Enhanced Geothermal Systems

This study applies supervised machine learning using Extreme Gradient Boosting (XGBoost) with physics-informed formulations to predict fracture intensity (P32) and fracture aperture in deep geothermal reservoirs using drilling and logging-while-drilling data from the Utah FORGE project. To reduce reliance on costly image logs and enable real-time, ahead-of-bit fracture characterization, we apply a depth-based machine learning (ML) prediction strategy that trains the model on shallow-depth data and predicts fracture properties across the remaining well interval. This approach relies on extrapolative, rather than interpolative, predictions and therefore involves a trade-off between prediction accuracy and logging requirements compared to traditional machine learning approaches that depend on full-length wellbore logs. Model performance is evaluated against conventional machine learning approaches, including baseline models without physics-informed formulations, and further compared under scenarios with and without physics-informed features, as well as with or without reduced feature sets. Results show that training the model on approximately 50-60% of the shallow well interval is sufficient to achieve reliable ahead-of-bit predictions of fracture intensity and aperture. Additionally, wavelet-based feature transformations enhance predictive accuracy, and the inclusion of physics-informed formulations further improves performance, particularly in predicting fracture intensity.

Topic: FORGE

Reliable cementing solutions are critical for high-temperature geothermal wells, yet current technologies rely on clinkered Ordinary Portland Cement (OPC) or costly Calcium Aluminate Cement (CAC) systems with limited economic and environmental sustainability. This work presents a distinct, non-clinkered alternative that reconstitutes calcium-silicate binding chemistries relevant to geothermal well cementing from low-cost mineral precursors. A calcium carbonate-silica-olivine system activated under hydrothermal conditions was systematically designed and evaluated to elucidate the roles of precursor composition, activator chemistry, and phase evolution on mechanical performance at 300 °C. Unconfined compressive strength and water-fillable porosity were measured as functions of activator concentration, curing time, and mineral replacement. Sodium metasilicate was found to control early activation kinetics through competitive dissolution of calcium carbonate, olivine and silicate phases, resulting in non-monotonic relationships between strength and porosity. Silica flour acted as a latent silicate source, sustaining binder formation at later ages, while partial replacement of calcium carbonate with olivine provided a rigid structural backbone and a delayed magnesium source, increasing compressive strength to above 2000 psi. Addition of sodium bicarbonate further enhanced sodium availability and phase stability, producing compressive strengths exceeding 3000 psi within 21 days of curing. Crystalline phase analysis revealed that activator selection governs reaction pathways and phase assemblages, with sodium bicarbonate acting as a strong phase-directing agent that accelerates kinetics and shifts calcium-sodium silicate formation from transitional lalondeite to the more stable pectolite phase. Mechanical performance was shown to depend primarily on phase assemblage, crystallinity, and interfacial bonding rather than total porosity alone. The results demonstrate that economically viable, non-clinkered mineral systems can be chemically designed to achieve mechanical performance consistent with geothermal cementing requirements while following fundamentally different pathways from previously explored high-temperature cement alternatives.

Topic: Enhanced Geothermal Systems

Multistage hydraulic fracturing in horizontal wells is a commonly used technique to enhance the permeability of unconventional reservoirs and enhanced geothermal systems (EGS). The U.S. Department of Energy’s FORGE (Frontier Observatory for Geothermal Energy) initiative is an EGS field laboratory in which multistage hydraulic fracturing is applied in horizontal wells with the objective of improving connectivity between injection and production wells. Several fracturing stages have already been carried out with satisfactory results. This paper presents a design and implementation of a new multi fracture stimulation concept for Utah FORGE. In the first section, a new stimulation stage is proposed in well 16A(78)-32 above the previously fractured Stage 9, at a measured depth (MD) of 8950ft. The stage includes three closely spaced clusters (3.5 m spacing), stimulated sequentially for 70, 80, and 90 minutes, respectively. The simulated fractures are oval-shaped and propagate primarily toward well 16B(78)-32, attributed to the prevailing stress gradient. Because of the tight spacing, significant shear deformation develops near the injection point and at fracture tips. This shear deformation is expected to increase fracture conductivity and promote wing-crack development, thereby improving fracture connectivity. Next, a sensitivity analysis is performed by circulating cold water through a three-fracture cluster to identify an optimal cluster spacing. Results indicate that thermal performance improves as fracture spacing increases; however, the injectivity index increases up to a spacing of 4 m and then decreases at 6 m. These findings highlight the need to balance thermal performance with injectivity when selecting the cluster spacing for the proposed stimulation design.

Topic: Enhanced Geothermal Systems

The INovative Geothermal Exploration through Novel Investigations Of Undiscovered Systems (INGENIOUS) project is a United States Department of Energy-funded multi-year project which seeks to identify and characterize blind geothermal systems in the Great Basin region. Geothermal systems in this region are predominantly fault-controlled geothermal plays and most reside in favorable structural settings (e.g. fault intersections, stepovers, etc.). Lund North, UT is the fourth detailed study site selected for the INGENIOUS project and is located along a complex fault-bend and stepover zone of the Lund fault in the southernmost Wah Wah Mountains of Iron County, Utah. Here we present new 2D and 3D modeling results derived from a broad range of geophysical data collected at the Lund North site including airborne magnetic data, ground-based gravity and magnetotelluric (MT) data, paleomagnetic (remanence) directional data, and magnetic susceptibility and density data obtained from hand samples collected in the field. Together these were used in conjunction with existing 1:50,000 scale geologic maps and a 2D seismic line to construct six 2D forward geophysical models across the study region which constrain the subsurface geology and inform potential drilling targets. These six forward models serve as the primary inputs for a 3D geologic model of the Lund North site which further improves our understanding of the subsurface and highlights the structural complexity of the site as well as the relationship between mapped and inferred structures and the 3D resistivity model derived from MT data. Surfaces from the 3D geologic model will be used as constraints for 3D inversion of the gravity and magnetic data collected at Lund North to improve model consistency with the observations and ultimately to inform selection of drilling targets for thermal gradient wells.

Topic: Modeling

Over the past two years, electricity consumption in Egypt has increased from 34.2 GWh to 36.8 GWh, leading to daily power outages of around 3 hours during the summer months. Geothermal energy, a renewable power source stored in subsurface rock and fluids, offers a sustainable solution to Egypt's blackout crisis. This resource has the potential to be a complement to energy sources to address the increased electricity consumption amidst a decline in natural gas production. Despite Egypt's high potential for groundwater available from different aquifers spread across the country, limited research has been conducted on Egypt's geothermal potential. To investigate this potential, a feasibility study was conducted in a selected field. The study workflow started with collecting available data about the Bahga field in Egypt`s Western Desert, including geographic data like its location and extension, and petrophysical data like hydraulic conductivity, porosity, and depth. Bahga field has been previously explored and drilled with more than 12 wells and has a reservoir temperature of 290°F (143°C), making it a promising site for geothermal resource exploitation. Using the available data as an input for the Flexible Geothermal Economics Modeling (FGEM) tool, specifically designed for the techno-economic analysis of flexible geothermal power generation, we evaluated the economic feasibility of the Bahga field in Egypt’s Western Desert. The FGEM utilizes a range of surface and subsurface parameters from each aquifer to estimate key economic indicators, such as the Levelized Cost of Electricity (LCOE). In parallel, we developed and applied an in-house resource power potential and techno-economic analysis methodology, which was directly compared against the FGEM outputs to validate and cross-check the results. The in-house workflow incorporated multiple resource power potential estimation techniques, primarily the Volumetric Method and Power Density Method, with the overlap between both approaches used to enhance confidence in the final estimates. Furthermore, a Monte Carlo Simulation framework was implemented to generate probabilistic forecasts (P10, P50, P90) for both the geothermal resource potential and the associated economic indicators, ensuring a robust representation of uncertainty. The comparative analysis of alternative hydrothermal field development scenarios yielded insightful outcomes. The project demonstrates a P50 internal rate of return (IRR) of approximately 24%, with a levelized cost of electricity (LCOE) ranging from 60 to 330 USD/MWh, depending on the selected field development strategy. The results are highly promising and align with Egypt’s Vision 2050, supporting the nation’s transition toward clean, renewable, and reliable energy sources.

Topic: Field Studies

[Ritz]

Overview of the Swiss Seismological Service’s Efforts to Monitor the July 2025 Test-Stimulation in Haute-Sorne, Switzerland Vanille A. RITZ, Verónica ANTUNES, Paolo BERGAMO, Toni KRAFT, Michèle MARTI, Philippe ROTH, Verena SIMON, Tania TOLEDO, Stefan WIEMER [Swiss Seismological Service at ETH Zürich, Switzerland]

In Switzerland, the subsurface is under the sovereignty of the 26 different cantons, with cantonal authorities in charge of the permitting and regulatory oversight of industrial projects targeting the subsurface. The GEOBEST program ensures that the Swiss Seismological Service can provide seismological expertise and baseline seismic monitoring services to the cantons at no cost, and independently of the operators of geothermal projects. For the EGS pilot project in Haute-Sorne, the republic and canton of Jura receives the support of the Swiss Seismological Service with seismological counseling and risk governance recommendations, as well as the operation of a dedicated seismic network. This seismic network completed in February 2024 consists of seven stations (broadband and strong motion), and was designed to ensure a magnitude of completeness of at least MLhc0.5. The test-stimulation carried out in July 2025 saw 430m³ of water injected at nearly 4km depth with injection rates up to 80L/min. During this period, the Swiss Seismological Service provided 24/7 automatic alarms in a 4 km radius with manual revision within the hour. These alarms fed the magnitude-based traffic light system operated by Geo-Energie Jura, the operator of the Haute-Sorne project.

Topic: Enhanced Geothermal Systems

A reduced-order model for thermal transport through a single hydraulic fracture in hot dry rock is presented, allowing for fully variable flow rates, including flow reversals. This model extends the classical Lauwerier/Gringarten framework, which has served for decades as a reliable, conservative tool for estimating heat harvesting efficiency under the assumption of constant flow. However, modern geothermal strategies – such as Huff-n-Puff methods, thermal storage or variable charging and discharging cycles designed to deliver flexible generation profiles for power-grid demand – require models that accommodate arbitrary, time-dependent flowrates and fracture apertures. The developed model simulates these complex operations by reducing the coupled heat-transport equations into a one-dimensional advection-memory equation. This approach enables the fast design and analysis of injection-backflow tests and evaluation of long-term thermal depletion without the computational burden of full-physics simulators. Crucially, the model accounts for time-dependent fracture apertures, enabling it to simulate the physical ‘breathing’ of fractures caused by pressure fluctuations during charging and discharging. Finally, the applicability of the developed model is validated by first reproducing the test case presented in Juliusson and Horne (2012) and secondly by considering a test case that models Huff-n-Puff operations. The findings highlight that the reduced-order model is efficient, reliable and robust so that it may be used for stochastic or long-term simulations.

Topic: Enhanced Geothermal Systems

The energy geosystems that involve fluid injection into geological formations, such as shale oil and gas and enhanced geothermal systems (EGS), are increasing in number and importance every day. To improve efficiency and ensure the sustainability of these geosystems, one must understand the mechanisms and factors that govern the evolution of the induced fracture network in naturally fractured ultra-low-permeability rock masses. Previous studies have demonstrated that natural fracture characteristics strongly influence both the hydraulic and mechanical responses of such formations. In this study, a combined finite–discrete element method (FDEM) is employed to investigate coupled hydromechanical fracture processes during fluid injection, with particular emphasis on the role of natural fracture (NF) density. The results show that NF density significantly influences near-wellbore fracture initiation behavior, with rock matrix–natural fracture interlocking controlling the breakdown pressure at high NF density relative to homogeneous media. Following fracture initiation, NFs promote pressure dissipation along preferential pathways, thereby increasing the stimulated rock volume and reducing peak pressure within the primary hydraulic fracture. Increasing NF density further amplifies lateral pressure redistribution and distributed fracture opening away from the wellbore, while the hydraulic fracture may cross or deviate, depending on local stress-state redistribution. These findings indicate that increasing NF density modifies both the local near-wellbore stress state and its redistribution along the propagating hydraulic fracture. Understanding these will provide insights into implementing effective strategies for safer, more sustainable fluid injection practices in EGS.

Topic: Enhanced Geothermal Systems

A coupled thermal-hydraulic-mechanical (THM) model has been developed to evaluate the long-term (30-year) performance of the Utah FORGE Enhanced Geothermal System (EGS) concept. The analysis has recently been expanded to a full-scale three-dimensional continuum model around injector and producer wells using the TOUGH-FLAC simulator. Propped-open fractures connecting injection and production wells spaced between 100 and 300 meters apart is represented in the continuum model. To begin, the model was used to simulate the 2024 30-day circulation test at Utah FORGE, which involved water circulation at approximately 26 l/s. This provided a baseline comparison with field data. The simulation was then extended to cover 30 years of continuous heat extraction to assess the long-term influence of coupled THM processes. Results shows that THM effects play a much more significant role over the long term than during the short-term circulation test. Cooling of the rock surrounding the active flowing fractures leads to stress reduction and fracture opening. This suggest that the propped-open fractures may be held open over time, which could enhance heat production efficiency throughout the operational lifespan of the system.

Topic: FORGE

Geothermal energy is a readily dispatchable energy source, unlike intermittent renewable energy such as wind and solar, and represents a vital component of a sustainable energy strategy. In Enhanced Geothermal Systems (EGS), hydraulic stimulation creates new fractures and enhances natural ones, enabling heat extraction from formations with limited inherent permeability and working fluids. Because fluid flow in EGS is largely confined to fractures, characterization of fracture properties using dynamic field data is crucial for reliable performance prediction. We propose a novel and rapid streamline-based inversion framework for fracture characterization in EGS. In this paper, the streamline-based technology, well established in the oil and gas industry, is tailored for EGS applications and introduced for geothermal systems. The proposed framework integrates distributed temperature sensing (DTS) and cluster-level distributed flow rate measurements to calibrate fracture properties. The concept of thermal tracer travel time is utilized to integrate DTS data, while the conventional streamline time of flight is applied to cluster-wise flow rate data. Visualization of thermal tracer travel time provides detailed insight into thermal front propagation behavior and thermal breakthrough time which are key indicators for EGS performance assessment. The streamline-based fracture parameter sensitivities can be computed analytically from a single forward simulation, substantially reducing the computational burden of gradient-based minimization of data misfit during history matching process. The proposed framework is first validated on a synthetic EGS model with DTS and cluster-level production rate measurements. Subsequently, it is applied to the Utah FORGE site using data from a month-long circulation test conducted in August 2024. In both the synthetic and actual field applications, the proposed approach achieved successful history matching through fracture characterization with high computational efficiency. For the Utah FORGE case, the history matching was carried out in approximately one day with 25 iterations and each iteration requiring a single forward simulation. These results demonstrate that streamline-based technology provides a powerful and efficient tool for fracture characterization and visualization of thermal front propagation in EGS.

Topic: Modeling

Indonesia, situated within the geologically active Ring of Fire, is the world's second-largest producer of geothermal energy, a testament to its significant geothermal potential. Streamlining the drilling process for geothermal wells can further bolster Indonesia's geothermal infrastructure, substantially contributing to global climate action in alignment with the sustainable development goals. This paper presents a case study demonstrating the successful integration of innovative hybrid polycrystalline diamond compact (PDC) and roller cone technology, which contributed significantly to reducing drilling days in a West Java geothermal well. This initiative accelerates renewable energy drilling goals and sets a precedent for sustainable development. The challenging igneous lithology of the Darajat field in West Java necessitated innovative solutions. In a remarkable display of collaboration, the geothermal operator and service provider jointly designed and implemented drilling strategies featuring hybrid drill bit technology in the 17 ½-inch section of the well. This strategic approach not only enhanced drilling efficiency and overcame geological complexities but also ensured the economic viability and success of geothermal projects, underscoring the power of collaboration and innovation in our industry. By combining the cutting action capabilities of polycrystalline diamond compact (PDC) and roller cone technologies, the hybrid drill bits have proven to be a game-changer in drilling through challenging and interbedded volcanic formations, significantly boosting drilling performance. The initial application of hybrid drill bit technology in the 17½-inch section contributed to a remarkable result in the Darajat field, setting new s for geothermal drilling performance. The hybrid bit contributed to a superior drilling performance by achieving an average rate of penetration (ROP) of 48.03 ft/hr in one run to target depth, marking a substantial 58% increase in ROP compared to the offset tricone bit. Afterwards, this hybrid bit was rerun to drill the next well and achieved an average ROP of 62.5 ft/hr in one run to target depth, a 106% increase of ROP compared to the offset tricone bit. This successful deployment contributed to extended drilling intervals and significantly reduced drilling time, underscoring the transformative impact of hybrid drill bit technology in geothermal applications. This study sheds light on the collaborative efforts between operators and bit service providers, leading to pioneering advancements in geothermal drilling technology within the challenging igneous formations of the Darajat Field. Integrating hybrid drill bit technology is a testament to innovation and excellence within the geothermal society, offering valuable insights for engineers operating in similar demanding geothermal environments. By enhancing drilling efficiency and reliability, adopting hybrid drill bit technology presents a transformative contribution to advancing geothermal production capabilities.

Topic: Drilling

This paper details the modeling and analysis tracer testing in propped EGS fractures using Utah FORGE tracer data. Two types of tracer tests were conducted at Utah FORGE: stim tracer testing, performed during stimulation with stage-unique tracers mixed with proppant, and flowthrough tracer testing deployed during crossflow and circulation tests. Stim tracer results obtained in 2024, deployed using different compositions (nano- versus chemical tracers) and methodologies, were compared to inform the stim tracer deployment strategy in propped EGS fields. Additionally, a methodology for modeling multicomponent flowthrough tracers in EGS wells is being developed. The stim tracer analysis encompasses various deployment and sampling strategies, including the use of chemical versus nanotracers, different sampling durations, and sampling frequencies. Stim tracer results were analyzed for concentration trends, flow contributions, and tracer recovery returns. Our analysis affirms that simultaneously deploying both nano- and chemical stim tracers helped compare their behavior and effectiveness, as well as establishing a baseline for subsequent analyses. Given that the nanotracer dataset has consistently shown more erratic patterns than chemical tracers, it is recommended to supplement nanotracer stimulation with chemical tracers as a control. Additionally, extending the sampling duration to at least 7 days, ideally longer, would allow capturing the full trend of tracer recovery. The multicomponent tracer model employs tracer dispersion as the governing equation and least-squares fitting with a soft flow-fraction penalty as the objective function. Synthetic datasets were generated to aid in model development. This initial attempt at multicomponent tracer modeling in EGS wells demonstrated promising results, especially when involving a few components. Improvements to the modeling techniques will be explored to enable the model to better handle a larger number of components.

Topic: Tracers

Sub- and supercritical geothermal resources offer significantly higher energy densities compared to hydrothermal systems. Owing to their low viscosity and high enthalpy, supercritical fluids can transport substantially more heat, potentially increasing the energy output per well by up to an order of magnitude. However, accurately identifying and distinguishing these high-temperature resources from traditional hydrothermal systems remains a major exploration and characterization challenge. Joint interpretation of electrical resistivity and gravity data has become standard in hydrothermal exploration, as each method is sensitive to different physical properties—resistivity to fluids and alteration, gravity to density contrasts and structure. Joint inversion can reduce the inherent non-uniqueness of individual methods by enforcing structural or petrophysical links between models. At the Sorik Marapi field (Sumatra), a 3D joint inversion of MT and gravity data, incorporating fault discontinuities, improved delineation of the graben structure. Gravity resolved lateral geometry, while MT provided depth resolution (Soyer et al., 2020). In Los Humeros (Mexico), combining gravity and surface-wave dispersion data led to better-constrained velocity and density models than from separate inversions (Carillo et al., 2024). Nevertheless, some studies opt for so-called cooperative joint inversion approaches, such as cross-gradient or structure-coupled constraints, which offer a flexible alternative (Um et al., 2023). Recent laboratory experiments at temperatures ranging from 25 to about 350°C, electrical conductivity increases because of both increasing surface and electrolytic conduction (Nono et al., 2020). Under supercritical conditions, i.e. temperature from 374°C to 600°C, electrical conductivity strongly decreases due to the evolution of water density and dielectric constant that affect both surface and electrolyte conduction. Apart from amphibolite, crustal rock conductivities at temperatures between 500°C and 700°C lie within the range of dry rock electrical conductivity values. With the aim of identifying geophysical signatures associated with sub- to supercritical temperatures, this study, compares gravity and electric resistivity of the Los Humeros geothermal field. The Los Humeros geothermal field hosts several wells with temperatures that suggest the potential presence of supercritical fluids. While gravity data help delineate key structural features, electrical resistivity is used to characterize thermally relevant zones. Our interpretations are ed against temperature measurements reported by Espinosa-Paredes and García-Gutiérrez (2003).

Topic: Emerging Technology

Despite significant technical challenges (Kibikas et al., 2026), drilling into supercritical fluids offers access to exceptionally high-energy resources, with the potential to deliver up to ten times more power than conventional geothermal wells. In addition to engineering hurdles, the origin and chemical composition of these fluids remain active areas of research. Sub- and supercritical fluids may originate from magmatic degassing or be trapped during the late stages of crystallization of magmatic intrusions. Recent high-temperature flow-through experiments have provided new insights, revealing the chemical and mineralogical transformations associated with supercritical fluid formation during conductive heating and boiling of subcritical geothermal groundwater by magmatic intrusions. These studies suggest that resulting supercritical fluids are typically depleted in major rock-forming elements such as Si, Na, K, Ca, Mg, and Al, but enriched in volatile elements including C, S, and B. As part of the Supercritical Drilling Material Analysis (Kibikas et al., 2026), we have compiled detailed fluid chemistry data from both subcritical and supercritical geothermal wells. With the release of this publicly accessible dataset on the Geothermal Data Repository (GDR, https://gdr.openei.org), we aim to advance our understanding of the characteristics and behavior of fluids across the sub- to supercritical transition. In this study, we examine differences in fluid chemistry across subcritical to supercritical geothermal fields to establish a foundation for further investigations of drilling and completion materials. This integrated approach helps refine conceptual models of supercritical geothermal systems and supports the development of more efficient, targeted drilling strategies, as well as informed selection of well construction materials for future exploration.

Topic: Emerging Technology

Legacy geothermal datasets provide a rich yet underutilized resource for advancing data-driven subsurface exploration. We applied unsupervised machine learning to a digitized U.S. Geological Survey database containing over 1,800 water and 300 gas chemistry samples (1930–2006) from geothermal and hot spring systems across the western United States. The objectives were twofold: (i) to delineate geothermal provinces and fluid sources, and (ii) to identify sites with geochemical conditions conducive to geological hydrogen generation through serpentinization of ultramafic rocks. A multi-stage analysis was performed using k-means, DBSCAN, and Gaussian Mixture Models on standardized chemical, isotopic, and temperature data. Geochemical fingerprinting revealed coherent clusters representing magmatic–volcanic, sedimentary, and deep-circulation systems, providing analogs to productive geothermal fields and flagging unexplored zones. Cluster tagging based on high pH–Mg waters, reducing conditions, and mantle gas indicators (e.g., elevated ³He/⁴He) identified candidate ultramafic settings favorable for H₂ formation and preservation. Hydrochemical–thermal zonation further distinguished high- versus low-enthalpy systems and reconstructed fluid mixing trends within serpentinization-relevant temperature and redox windows. Temporal analyses across seven decades corrected historical biases and improved confidence in H₂ prospectivity screening. This framework illustrates how legacy datasets, when integrated with unsupervised learning, can delineate geothermal provinces, track geochemical evolution, and identify ultramafic terrains for exploration and engineering of hydrogen generation systems. The results highlight the untapped potential of historical data to accelerate sustainable subsurface energy discovery.

Topic: Geochemistry

Next-generation geothermal has the potential to provide reliable, scalable, and clean baseload power globally. However, technological advancements, such as those that enable access to higher-enthalpy resources, are needed for these systems to reach their full potential as a cost-competitive bankable technology. Numerous research groups and industries worldwide are conducting research that can help with the development of higher-enthalpy geothermal systems, but there is no comprehensive overview of where these critical laboratory and modeling capabilities exist. Furthermore, many other research groups and industries possess relevant expertise in related fields that could accelerate the development of higher-enthalpy geothermal but may not realize its applicability to this technology. To address this challenge, we have conducted a first of its kind comprehensive global survey of research relevant to advancing higher-enthalpy geothermal capabilities, focusing on five key technical domains: resource characterization and/or modelling, drilling and well design, monitoring and instrumentation, reservoir creation and management, and surface engineering and power generation. Our survey was first distributed in Spring 2025, and we have begun to catalogue over 120 responses. The detailed survey captures specific equipment capabilities, including their maximum pressure and temperature, numerical modeling tools, and current as well as planned research activities. At the time of paper submission, we are actively collecting and validating survey responses and plan to finalize the development of the directory in mid-2026. The directory will include both a detailed overview of research capabilities by institutions around the world as well as country profiles. The directory will be continuously updated as we receive new survey responses, creating a one-stop shop for global research capabilities for higher-enthalpy geothermal development. It is hoped that this tool will create the conditions for collaboration and knowledge exchange that will accelerate the deployment of higher enthalpy geothermal while creating global visibility into research laboratories and gaps in capabilities. It is also expected that the benefits to higher-enthalpy geothermal development through cost reductions, efficiency gains, and technology improvements will aide in the advancement of lower enthalpy geothermal systems.

Topic: Emerging Technology

Natural rocks in geothermal energy reservoir are heterogeneous and consist of fractures, solid and fluid phases that form complex structures at multiple scales. Explicit incorporation of multiple scales of fractures and heterogeneities into large-scale tightly coupled models is impractical and would cause tremendous computational costs. Therefore, efficient multi-scale and multi-physics strategies are necessary for capturing sub-grid-scale processes and their impacts on macroscopic behavior. In this work, we present a multiscale framework for coupled thermo-mechanical behavior of rocks in geothermal reservoir. The proposed approach allows for separate micro-constitutive laws, which provides an efficient way of capturing both large- and small-scale processes. The performance of the modeling framework in simulation of geothermal energy reservoir is demonstrated through numerical examples.

Topic: Modeling

The three most important factors controlling the performance of enhanced geothermal systems are, (i) the hydraulic conductivity of the fractures, (ii) the connectivity between the injection and production wells, and (iii) the fluid conformance in the injection well. Data obtained at the Forge EGS site and numerical simulations clearly show the importance of these three factors. Good connectivity between the injector and the producer through fractures is essential to EGS success. This inter-well connectivity was measured with both fiber optic data in the producing well and through tracers. DSS (strain) measurements made in the producing well while the frac stages were being pumped in the injection well clearly showed the location and timing of the frac hits in the producing well. Over 48 different frac hits were recorded. To ensure good inter-well connectivity, the producing well was perforated at the location of the major frac-hits. To further improve inter-well connectivity hydraulic fractures were initiated through these perforation clusters in the producing well. Subsequent fluid circulation tests showed excellent connectivity between the injector and producer. Fluid inflow distribution along the producer was monitored by both DTS fiber measurements and tracer data. Both data sets were consistent and showed good inter-well connectivity. Good fluid conformance is essential to avoid thief-fractures from causing early temperature breakthrough and a rapid decline in energy production rate over time. Large sections of the geothermal reservoir can remain undrained when this occurs. Fluid conformance in the producer was measured by DTS and by tracer tests. The results from the tracer test clearly show some preferred corridors of fractures indicating poor conformance in some parts of the wellbore. Ways to minimize this in the future are discussed. Simulations were run to show how this can be achieved in future EGS fracture designs. Good fracture conductivity can be achieved by pumping proppant during the fracture treatment. In the first 3 stages of the fracture treatment of the 16A well at the Forge site, no proppant was pumped. This resulted in very large injection pressures being needed to inject fluid from the injector to the producer. All stages in which proppant was used were able to inject fluid at much lower pressures. The use of proppant results in better conductivity and is essential for maintaining injectivity and minimizing the parasitic energy needed to circulate fluid between the wells. Simulations results clearly show the impact of poor fracture conductivity and conformance on the energy recovery rate. Measuring good connectivity, conductivity and conformance in enhanced geothermal systems is shown to be critical for ensuring high and stable energy production rates.

Topic: Enhanced Geothermal Systems

New Mexico has well-developed petroleum and mineral resources across the state, generating a vast archive of subsurface data through drilling, exploration, and production. With the growing urgency of the energy transition and state-level incentives for renewable energy, geothermal resources are now a priority. The New Mexico Bureau of Geology and Mineral Resources' (NMBGMR) Subsurface Library archives subsurface exploration information from fossil fuels, mining, geothermal, and groundwater resources and serves as an incredible resource for advancing geothermal development. The New Mexico Bureau's Subsurface Library serves as a central repository for a wide variety of subsurface data, including continuous and skeletal core, drill cuttings, physical and digital geophysical and temperature well logs, as well as petrochemical and geochemical analyses, from wells across the state. Subsurface data has already been used extensively in various research projects involving critical mineral, groundwater and oil & gas exploration and emerging low-carbon technologies such as carbon sequestration. Additional information relevant to geothermal exploration resides with partner agencies, and together, these collections represent an excellent resource for geological and engineering insights relevant to geothermal exploration, and for building out a more extensive geothermal database for New Mexico. This paper serves as an update of nearly two decades of new data from new wells and acquisitions, updates to workflows for accessing, integrating, and interpreting these publicly available data sets specific for geothermal exploration and research. Resources covered include the NMBGMR's Subsurface Library and Geothermal database, OCD’s digital hub, and state-level efforts to expand geothermal databases. Case studies—such as updated thermal and heat flow maps of New Mexico and updated subsurface interpretations—demonstrate practical applications of this data repository for identifying and de-risking geothermal exploration opportunities. By synthesizing these resources into a coherent guide, we aim to support developers and researchers in leveraging New Mexico’s extensive subsurface record with recommendations for improving accessibility, identifying gaps, and fostering collaboration to enhance geothermal exploration and development across the state.

Topic: General

Digital twins are increasingly transforming the operation and management of geothermal energy systems by enabling real-time simulation, monitoring, and optimization. This paper presents an open-architecture digital twin framework developed for low-enthalpy deep hydrothermal geothermal plants, designed to support co-simulation and optimization with real-time data streams. The framework integrates physical models, machine learning models, different data streams, and control algorithms to improve operational efficiency and reliability. Through case studies, we demonstrate how the digital twin can be applied to optimize the performance of electrical submersible pumps (ESPs), enhance plant-level operation, and predict potential failures before they occur. In a second case study, we show how large language models (LLMs) can be integrated into the digital twin environment to provide fast and intelligent access to operation and maintenance documentation, reducing response time for troubleshooting and decision support. For the second application, details of the retrieval-augmented generation (RAG) workflow for processing text data will be presented. The open-source nature of the tool lowers adoption barriers and enables broader collaboration across the geothermal sector.

Topic: Emerging Technology

Tracer studies in geothermal fields help quantify injection returns to production and can help predict thermal breakthrough. Often these returns are convoluted with the recycling associated with reinjection and require deconvolution to interpret the single-pass performance. The deconvolution technique discussed in this paper uses the CSTR in Series model, which is a simple model often applied in reactor design engineering for non-ideal residence time distribution analysis. A key advantage of the CSTR in Series model is its simple Laplacian transfer function which provides an analytical solution for impulse disturbances, such as tracer injection, regardless of the number of passes through the system. When applied to a geothermal system, the transfer functions between each injector-producer pair, or a field-average transfer function, can be determined and a temperature forecast can be created by introducing a step-change disruption to the transfer functions. An empirical correlation to re-scale the CSTR time parameter of the transfer function is being evaluated to improve temperature forecasts and better account for heat in place.

Topic: Tracers

A key component of the Utah FORGE field program has been chemical monitoring of flowback and produced fluids. In this regard, the ability to confirm and quantify the presence of gaseous species in circulated fluids dominated by carbon dioxide was first achieved in 2024. However, the effects of carbon dioxide are interpreted to have been present since the earliest phases of reservoir stimulation in April 2022 when flowback waters showed sharp increases in solutes accompanied by significant enrichments in oxygen and hydrogen. The possibility that two-phase conditions had developed in response to boiling was inconsistent with injection pressures that greatly exceeded vapor saturation. Later, when halite was identified along fractures in granitic rocks, it was evident that dissolution of soluble salts was most likely responsible for the increases in total dissolved solutes. The next significant observation followed the completion of 16B(78)-32 in July 2023 when during the first short term circulation test there was evidence of slugging flow and effervescing water indicating gas in the produced fluid. As a result, the flow lines for the Aug-Sept 2024 circulation test were designed to accommodate temporary installation of a mini-separator via which steam and gas could be collected and analyzed. The resulting produced water contained 0.07 to 0.13 wt. % CO2, inducing weak acidification, and the total carbon dioxide production was ~220 metric tons. Monitoring of well waters in 2025 continued to show infiltration of carbon dioxide and isotopic evidence of a deep upper mantle origin. Speculatively and drawing on experience from carbon dioxide injection for enhanced oil recovery and sequestration, carbon dioxide infiltration is linked to the drying out of waters, accounting for the stable isotope trends and salt deposition in fractures. This appears to be an active process that is associated with reservoir development, and one that also occurred naturally in the geologic past.

Topic: Enhanced Geothermal Systems

Well 58-32 was completed in September 2017, providing confirmation of a hot dry granitic rock reservoir at drillable depths that advanced development of the Utah FORGE field laboratory. Apart from small scale injection testing in 2019, the well was used for the temporary deployments of geophone strings and seismic monitoring during drilling and stimulation operations related to the completion of wells 16A(78)-32 and 16B(78)-32. In this early phase of EGS reservoir development through to at least 2022, the water levels in 58-32 were relatively static, and the water composition showed a moderate increase in total dissolved salts compared to the culinary grade water with which it was originally filled. Further compositional evolution occurred by 2024, which is believed to be related to stimulation of stage 9 in 16A(78)-32. The associated sharp pressure rise led to removal of geophones, and at the start of the four-week circulation test in August 2024, vigorous gas bubbling was noticed. The well was shut in, and a flow line was added to sample and monitor fluids safely. When subsequently opened for short periods to acquire samples, a frothy two-phase fluid discharged, and chemical analyses indicated the well water had transformed into a carbon dioxide rich saline solution. Furthermore, connection had been made with the Utah FORGE reservoir, 200 m away. Separately, temperature logs show that the conditions remained unchanged from its original conductive gradient. In this report, an overview of changes in 58-32 fluid chemistry, including results of recent downhole sampling, are described. Provisionally, these data provide clues regarding the character of fluids occupying the periphery of stimulated fractures in the Utah FORGE EGS reservoir.

Topic: Enhanced Geothermal Systems

This study investigates the thermal behavior of an Enhanced Geothermal System (EGS) well during production and wireline intervention, with emphasis on how wellbore heating influences the feasibility and safety of wireline operations. A major challenge is maintaining surface temperatures within limits to ensure compatibility with Pressure Control Equipment (PCE) and wireline systems under high-temperature conditions. A thermal model was developed using real temperature data from Utah 16B(78)-32 well up to 6,000 ft, supplemented by two artificial high-temperature scenarios (bottom-hole temperatures of 250 °C and 300 °C) for depths between 6,000 and 18,000 ft. The axisymmetric model incorporates heat transfer through fluid convection and solid conduction in both axial and radial directions. The simulation consisted of five phases: establishing initial conditions with real and artificial temperature profiles; production at 2,000 gal/min; a one-hour shut-in; tempering with 400 gal/min of 25 °C water for two hours; and a 24-hour wireline operation period, during which surface temperature was targeted to remain below 80 °C to prevent flashing and steam formation with a 20 °C margin. Results reveal significant heat retention in the formation during production, leading to reheating during wireline operations despite prior tempering. For the 250 °C case, proper tempering maintained surface temperatures below 80 °C for 24 hours, enabling safe wireline or coiled tubing work. In contrast, for the 300 °C case, surface temperature rose to 86.2 °C after 24 hours, slightly exceeding the limit. This work underscores the importance of surface temperature control and highlights the need for practical thermal management strategies to ensure safe and efficient geothermal wireline operations. The developed model serves as a predictive tool for assessing thermal behavior under various operational scenarios, supporting proactive planning and minimizing intervention downtime.

Topic: Modeling

Pressure While Drilling (PWD) data was collected on several wells drilled in Nevada, USA in 2025, and was used to calculate injectivity index in real time and to do injection tests. This provided real time injection capacity estimates while saving rig time. This paper will cover (a) a descrption of the PWD technology, (b) a number of examples where comparison between PWD injectivity calculations versus injection test results after the wells were completed, and (c) a brief discussion on future optimization of the approach.

Topic: Drilling

Despite geothermal’s potential abundance and the introduction of multi-well enhanced systems (EGS) 50 years ago, both remain as potential power. Through an innovative reconfiguring of EGS in HDR, this paper presents fundamental refinements and substantive baseload production levels making HDR geothermal highly scalable, even to climate impact levels. One novel application of the reconfigured EGS includes grouping four wells’ early production into single or paired plants, supplying three months, 30 MWe per well seasonal and replenishable energy storage. The paper’s objective is to demonstrate realizable long-term clean energy abundance by use of the innovative Deep Geothermal System, or “DGS” method, as supported by decades of subsystem field experience and by recent simulation-based design, performance evaluation, and optimization. DGS reconfigures the traditionally redundant directional or horizontal drilling of multi-well EGS into one substantially deeper vertical well, thereby accessing 50% higher average heat and maximizing per-MW drilling investment. DGS drilling trajectory is done in a manner that is co-planar with its subsequently induced fracture-reservoir-circuits, enabling full hydraulic communication along the entire well-fracture heights. Long-length flow diverters are constructed horizontally in the fractures, bifurcating them and doubling heat-collecting flow length. The diverters guide flow away and back to the well, superheating fluids over 45 hours’ exposure at depths and heat levels double or more that of traditional practice. Tuning of the co-planar hydraulics, in concert with strategic placement of the diverter, enables full control over reservoir’s hydraulic behavior and heat extraction from some 560 hectares (1380 acres) of total system geothermic rockface having 150oC to 400oC and higher heat. Simulation by Computational Fluid Dynamics (CFD) and conjugate heat transfer analyses predicted well production temperatures and output over various rock thermal gradients, fracture dimensions, separation, inlet temperatures, and flow rates. Analyses also showed high-early per well baseload nearing 120MWt by fully sweeping an optimized count of 15 massive, highly separated reservoirs. Net early well output exceeds 30 MWe, as no parasitic injection or significant cooling loads are required in the vacuum driven DGS surface inlet. Analytical work also revealed a roughly optimal 335-meter reservoir separation enabling high level baseload heat replenishment while balancing the practical aspects of overall installation design, deep well construction, economics, and sustainability. A 15 to 20 MWe range baseload output occurring for some 20 years was also shown prior to entering steady state production. Extension of the analytical work further revealed DGS’ ability to deliver 30 MWe as baseload stored energy delivery on a three-month seasonal basis. Thermal recovery occurring for the balance of the year ranged from 92% to in excess of 98%, depending on well spacing and effective rock volumes. The innovative DGS single well HDR geothermal method is not only novel, but revolutionary. DGS technology obsolesces orders more costly and less productive EGS designs requiring two or more wells per location-output. Geothermal’s promises are shown realizable by the type of work presented in the paper – and in new ways.

Topic: Enhanced Geothermal Systems

There are geothermal systems in the steep slopes around the Shishimuta subsiding zone, which was originated of a caldera volcano. The Otake geothermal field, Japan, is located at the southern margin of the Shishimuta subsiding zone. The geological structure in the Otake geothermal field is characterized by the presence of NW-SE trending fault systems. In August 2025 an earthquake with a magnitude of 4.9 (USGS scale) occurred at the Otake geothermal field. It is the largest event at the field. We made waveform cross correlation and high precision relative relocation of seismicity triggered by the largest event using publicly available seismic data. In Japan, we can effectively use the nation-wide seismic network, seismic station of which are basically deployed in the 20-km mesh. Generally, it is too sparse to analyze fracture structure in geothermal fields. A local volcanic network, however, is working near the Otake field. Therefore, we can make use of the digital waveform data recorded at the seismic station which situated in a few kilometers from the Otake field and study the fracture structure of the field. An empirical Greens function analysis was applied to the largest event of the seismicity, and revealed particular characteristics of the fracture structure in the deeper part of the geothermal reservoir. We developed a kinematic source model for the largest event, The source model as well as accurate hypocenter relocations was effective to image the deep fracture structure of the geothermal reservoir.

Topic: Geophysics

Next-generation geothermal systems are advancing along two primary pathways: Enhanced Geothermal Systems (EGS) which create convective reservoirs via hydraulic fracturing, and Advanced Geothermal Systems (AGS), which extract heat via conduction through closed loops. While EGS offers high energy yields, it carries risks of induced seismicity and geological uncertainty. Conversely, conduction-based closed-loop systems mitigate seismicity, but face challenges related to thermal drawdown (short-circuiting) between proximal laterals and complex well-to-well interceptions. This paper introduces and evaluates the Telluric Radial System (TRS), a hub-and-spoke topology designed to synthesize the massive reservoir contact area of EGS with the low environmental risk of conductive systems. The architecture consists of a large-diameter, insulated central injection hub feeding a distributed network of single-layer, radially oriented production satellites. This configuration is hypothesized to offer superior geometric efficiency by eliminating the vertical thermal interference inherent in stacked parallel loop designs and accessing a larger volume of fresh rock, while consolidating well interception by targeting a stationary vertical hub. Furthermore, the design enables a phased scaling development model, allowing individual satellite radiators to be commissioned sequentially to stage risk and capital deployment. This study presents the conceptual framework and a comparative thermal performance analysis using 3D finite element modeling in OpenGeoSys utilizing parameters modeling the Malm Carbonate formation in Geretsried, Germany. Simulations were normalized for total drilling length to ensure an accurate comparison between radiator topologies. Results demonstrate that the single-layer TRS radiator maintains outlet temperatures 2°C to 5°C higher than equivalent multi-lateral stacked designs over a 30-year operational life, confirming that radial fanning effectively mitigates far-field thermal drawdown despite localized convergence at the hub. The model is further used to explore the system's sensitivity to key design parameters, including radial well spacing and the thermal resistance of the injector's insulation. This work provides a foundational assessment of the TRS as a pathway for developing scalable and dispatchable geothermal assets.

Topic: Modeling

The Ghyben-Herzberg relation is considered the standard model for groundwater hydrology in ocean-island environments. This model is based on simplified assumptions but is still used to provide a basic level of groundwater storage in Hawaiʻi. Over the last 25 years, each and every scientific drilling project on Hawaiʻi Island has revealed complex hydrology, which the standard model does not explain. Scientists encountered surprisingly deep freshwater, warm water, and perched freshwater under a variety of groundwater regimes and hydrostatic pressures. It is hypothesized that Hawaiʻi’s groundwater and geothermal systems are complex, and that more surveying is required to understand the storage of freshwater and prospective geothermal resources across all islands as they age. This study aims to investigate the unique hydrology and prospective resources on the southwest rift zone of East Maui Volcano, more commonly known as Haleakalā. Our survey is located along the southwest rift zone of East Maui Volcano, which is a critically understudied leeward region of East Maui. A large portion of this rift zone is privately owned and classified for agricultural use. East Maui Volcano’s current volcanic state provides an opportunity to examine the distribution and transport of groundwater and residual magmatic heat from more permeable shield-stage aquifers to post shield-stage structures. We conducted a magnetotelluric (MT) survey of 59 stations on and around the rift zone. The resistivity data is inverted to 1D and 3D models to confirm the elevation of the water table and understand the system that is driving groundwater storage. We also have commenced drilling of a cored borehole to confirm and compare the findings from the electromagnetic survey. Drilling to date has been challenging. The goal of this project is to provide an accurate depiction of the extent, source, and temperature of groundwater along an understudied region of Maui. This paper introduces and provides a project status update.

Topic: Geophysics

Delayed induced seismicity remains one of the major challenges for Enhanced Geothermal Systems (EGS), particularly when large earthquakes occur weeks to months after prolonged mitigation efforts. At the Pohang EGS site, a Mw 5.5 earthquake occurred approximately two months after injection stopped, following extended post-injection flowback that recovered less than half of the injected fluid. Although fluid-pressure diffusion has been identified as a dominant mechanism driving this delayed earthquake, the physical reasons why flowback failed to sufficiently depressurize the reservoir remain unclear. Motivated by field observations showing strongly pressure-dependent and largely reversible hydraulic diffusivity within the stimulated fracture zone around the injection well, we investigated the role of pressure-sensitive stimulated fractures in post-injection mitigation failure. We developed a pressure-diffusion model that explicitly incorporates pressure-dependent hydraulic diffusivity and evaluated post-injection pressure evolution under different mitigation strategies. Our results show that rapid flowback in unpropped fractures, as implemented at Pohang, can be ineffective despite generating large reverse pressure gradients toward the well. Rapid depressurization near the well induces fracture closure and a sharp collapse in near-well permeability, transforming stimulated fractures from high-transmissivity conduits into hydraulic barriers. As a result, excess pressure remains trapped away from the well and continues to diffuse toward the fault, producing substantial delayed fault pressurization consistent with the timing of the Mw 5.5 event. Modifying well operation strategies by adjusting the rate of wellhead pressure depressurization alone provides only limited improvement. In contrast, preserving fracture diffusivity through addition of proppant substantially enhances pressure reduction and slows fault pressurization, with rapid flowback combined with proppant providing the most effective mitigation tested in this study. These findings highlight the importance of fracture hydromechanical behavior in post-injection seismic risk mitigation.

Topic: Enhanced Geothermal Systems

As part of the Federal Geothermal Partnerships (FedGeo) initiative, the University of Wisconsin–Madison conducted in situ characterization of the low-temperature geothermal resource at the U.S. Army Garrison Detroit Arsenal to support techno-economic evaluation and borefield optimization. This study employed mud-rotary drilling, geophysical logging, and advanced monitoring techniques—including fiber-optic distributed temperature sensing (FO-DTS)—to assess thermal, physical, and hydrogeological properties along a 152-m test borehole. A conventional thermal response test (TRT) indicated a bulk thermal conductivity of 2.25 W·m⁻¹·K⁻¹, while the acquired FO-DTS data revealed significant variability in heat transfer, identifying high-conductivity formations such as the Birdsong Bay Limestone (67–78 m), Traverse Limestone (78–93 m), and cherty dolomite of the Dundee Group (140–152 m). Drilling performance demonstrated that a 152–168 m borehole can be advanced in a single workday using the mud-rotary drilling method. Completing the drilling in one workday optimizes the installation of the borehole, thus reducing contracting cost. Our testing results suggest that extending the borehole deeper to at least 168 m could increase thermal capacity by approximately 15% compared to a 152-m ground heat exchanger. These findings inform optimal borehole depth, spacing, and layout for geothermal borefields, which represent the most variable and costly component of ground heat exchange systems and thermal energy networks.

Topic: Field Studies

Drilling through hard igneous formations commonly encountered in geothermal wells demands tools and parameters specifically engineered for these conditions. Generic designs optimised for sedimentary or metamorphic rocks typically result in poor drilling efficiency and reduced bit life. This paper presents the design and field performance of a 12.25” polycrystalline diamond compact (PDC) bit optimised for drilling hot, hard and abrasive volcanic tuff, andesite, and rhyolite in the vicinity of Newbury, Oregon. This bit design was also required to maintain strict directional control in aerated mud. The design methodology clearly differentiates between the roles of the primary cutting structure and the trailing support elements to enhance durability in the vibration-rich environment characteristic of igneous drilling. Field results are presented from a run in which the bit drilled 1,952 ft of volcanic rock at an average rate of penetration (ROP) of 46 ft/hr before being pulled in a repairable condition for a BHA change. Post-run analysis validates the design assumptions and identifies opportunities for further optimisation. The paper concludes with key insights and recommends best practices for PDC bit design and selection in geothermal drilling applications.

Topic: Drilling

Drilling simulations under supercritical conditions have been very limited worldwide. In this study, we developed GEOTEMPSC, a thermal-hydraulic simulator capable of modeling drilling behavior under supercritical conditions, by integrating a supercritical calculation module (Cooper and Dooley, 2007) with GEOTEMP2 (Mondy and Duda, 1984). Two reservoir scenarios with distinct pressure–temperature distributions were assumed, and a 5,000 m well, including casing operations, was modeled to evaluate temperature profiles near the wellbore and the cooling effects during drilling. This presentation highlights the simulation methodology and discusses key findings.

Topic: Drilling

This paper presents a modeling framework to evaluate the power generation potential and thermal efficiency of storing solar-gathered heat in porous, permeable sandstone reservoirs at shallow depths (less than 3,000 ft). This process is called Geologic Thermal Energy Storage (GeoTES). Building on the U.S. Department of Energy Solar Energy Technologies Office (SETO) GeoTES Demonstration in Kern County, California, the study integrates proven thermal simulation tools with advanced 3D visualization using Blender. This combined workflow quantifies conductive and convective heat transport, retention dynamics, and recoverable energy over multiple thermal cycles. Results show that loosely consolidated, shallow formations with natural temperatures near 100°F can be economically converted into large-scale solar-charged geologic batteries. Modeled results demonstrate high thermal retention and recoverability, confirming that proven oilfields can be repurposed for dispatchable renewable power generation with near-zero exploration risk. Scaling this concept across the Western San Joaquin Valley could enable more than 100 gigawatts of clean, firm capacity—while introducing the novel idea of subsurface solar heat sequestration as both an energy-storage solution and a potential global cooling mechanism. This project is operated by Premier Resource Management with the following geothermal partners: DOE Geothermal Technologies Office, National Laboratory of the Rockies, Lawrence Berkeley National Laboratory, and Idaho National Laboratory. The GeoTES demonstration was awarded under the Biden Administration and is one of few awards approved by the Trump Administration - representing a bipartisan effort to Unleash GeoTES.

Topic: Emerging Technology

The Utah Frontier Observatory for Research in Geothermal Energy (Utah FORGE) is a field scale laboratory near Milford, Utah designed to help de-risk enhanced geothermal systems (EGS). During EGS operations, pressurized fluids are injected to create a permeable reservoir. This process generates microseismicity. In 2024, stages 3R through 10 of the injection well were stimulated using both proppants and slick water. Microseismicity maps into two main fracture zones. This study establishes a workflow to characterize the internal nature of these fracture zones in order to better understand the risk potential of the fractures and to better inform future activities at the Utah FORGE site. Fractures are identified by clustering microseismic events using an unsupervised machine learning approach called Bayesian Gaussian Mixture Model (BGMM). BGMMs and the more popular K-Means clustering method are both unsupervised clustering algorithms which adjust the defined clusters through numerous iterations until the results converge to a set of output clusters. However, BGMMs diverge from K-Means by inferring the ideal number of clusters to describe the input data, describing such clusters using Gaussians, and probabilistically assigning points to clusters, thus providing generally more robust clustering for data clouds where the clusters may be close together or overlapping, as is the case within the two main fracture zones activated in 2024. One issue with BGMM clustering and other machine learning clustering methods is a dependence on input order. To address this, random sorting of the event catalog is implemented, and the BGMM is run multiple times. After clusters have been identified, Principal Component Analysis is used to fit planes through the identified clusters and determine their degrees of planarity. Calculations are also run to determine the strike, dip, and area of the planes. The results from the multiple runs are assessed to determine the variability in clustering and to characterize the range of potential fracture planes defined by the microseismicity. For stages 3R through 10, we find 23 to 28 overlapping and en-echelon planes roughly in alignment with the SHmax determined from borehole breakouts at Utah FORGE.

Topic: FORGE

This paper presents an updated native state numerical model of the Utah FORGE reservoir, incorporating recent pressure, temperature, and stress data acquired through 2024. The model domain extends 6 km by 6 km laterally and 4.5 km vertically, encompassing the granitic reservoir and overlying sedimentary formations. Mesh refinement has been implemented in the well field region to improve resolution of thermal-hydraulic gradients near injection and production intervals. Temperature calibration incorporates updated thermal gradient measurements from multiple wellbores, with particular attention to convective effects in the fractured granite reservoir. The model demonstrates strong agreement with observed downhole temperature profiles. Pressure boundary conditions have been refined based on recent shut-in pressure measurements and hydraulic monitoring data. In-situ stress parameters have been updated to better represent observed geometrically induced anisotropic stress state and its variation with depth, which is critical for predicting fracture orientation during stimulation operations. Key model parameters including rock thermal conductivity, permeability of both fractures and the surrounding reservoir, and bulk reservoir porosity have been recalibrated using circulation test data from 2024. This updated baseline model provides an improved foundation for simulating enhanced geothermal system development at the Utah FORGE site.

Topic: FORGE

eothermal prospectivity mapping, the identification of areas likely to host commercially viable geothermal resources, is a complex undertaking reliant on integrating diverse datasets ranging from geological and geophysical surveys to geochemical analyses. Subject-matter-driven methods such as traditional Play Fairway Analysis (PFA) are often subjective and time-consuming. This study explores the application and comparative performance of several machine learning (ML) techniques for automated and objective geothermal prospectivity assessment. Specifically, we investigate the efficacy of SmartTensors’ Nonnegative Matrix Factorization (NMFk), Support Vector Machines (SVM), Artificial Neural Networks (ANN), Gradient Boosting Machines (XGBoost), and Diffusion Models (DM) in predicting geothermal potential. The analyses are based on a dataset collected under the USGS/DOE’s GeoDAWN project and various other past research projects in the Great Basin area. We use surface, structural geology, gravity, magnetic, heat flow, and geochemical data attributes. The performance of each model is rigorously evaluated using a series of metrics, as well as through visual inspection of the resulting prospectivity maps. We also analyze feature importance for each model to gain insights into the key geological and geophysical factors influencing geothermal potential. This research contributes to a more robust and efficient methodology for geothermal exploration, potentially reducing exploration costs and accelerating the discovery of new geothermal resources. Our ML methods and tools are designed to be deployed within EnviCloud (https://envitrace.com/#envicloud; https://envitrace.com/saas. Our EnviCloud is a proprietary, comprehensive, cloud-based platform designed to optimize the entire geothermal energy lifecycle, from initial exploration and site assessment to real-time well monitoring and energy output optimization. It is developed to support Software-as-a-Service licenings as well as project consulting work. By leveraging advanced technologies—including cloud/high-performance computing, aritificla intelligence (AI), machine learning (ML), data analytics, and GIS—EnviCloud streamlines geothermal resource utilization and enhances decision making. The platform offers key features such as AI-powered geothermal mapping, thermal gradient analysis, reservoir simulations, near-real-time data analytics, analysis tools for project feasibility. All at a centralized cloud dashboard for mutli-user collaboration. It also includes tools for tracking sustainability metrics and ensuring regulatory compliance, especially related groundwater contamination and induced seismicity. EnviCloud reduces exploration time and maximizes the potential of geothermal resources. It targets a broad audience, including exploration companies, energy providers, investors, regulators, and research institutions, aiming to promote sustainable energy development. Here, we demonstrate EnviCloud's application in processing a wide range of geologic, geothermal, and geophysics datasets related to the Great Basin. Our ML analyses successfully extracted key features relevant to evaluating geothermal prospectivity. We also showcase the platform's ML techniques for the imputation and blind prediction of missing data.

Topic: Modeling

This paper presents an ASTM based thermal conductivity testing program for bare titanium Grade 5 and coated pipe materials intended for high temperature or super-hot rock geothermal drilling and production. Measurements between 120°C and 500°C using two standardized methods provide a consistent dataset of apparent thermal conductivity and thermal resistance under controlled laboratory conditions. The results show that thermal barrier coatings can significantly reduce heat transfer through the drill pipe wall compared with bare titanium and coated titanium and steel, with one advanced coating achieving particularly low conductivity over its qualified temperature range. By comparing the two test methods, the study clarifies when each is best applied using D5470-17R24 as the primary standard for coated systems and E1225-25 as a complementary method for uniformed materials (i.e. bare metals) and high temperatures. The resulting dataset and ing protocol are intended for direct integration into wellbore thermal models and hybrid drill string and production casing / tubing design workflows, enabling more accurate prediction of internal fluid temperatures and supporting strategic placement of titanium, coated titanium, and coated steel sections along the drill string in superhot geothermal wells. This dataset and protocol can effectively support casing and production design processes.

Topic: Drilling

Emission of dissolved non-condensable CO2 is a major contributor to the geothermal carbon footprint of conventional geothermal energy development, and reinjection of CO2 with produced brine is a technique to reduce carbon emission intensities. A previous study has found that the addition of CO2 can significantly reduce the rate of silica precipitation in greywacke (a typical Taupo Volcanic Zone reservoir rock) sand packs. Silica precipitation is responsible for the injectivity decline of conventional geothermal wells. In this study, we propose to leverage neural operators to model geothermal reactive transport. Neural operators are designed to learn the solution operators of partial differential equations (PDEs) by mapping between infinite-dimensional function spaces. Fourier neural operators (FNOs) have good potential to approximate complex PDE systems using the Fourier transform. Meanwhile, the integration of trained neural operator surrogate models into an inversion workflow will significantly speed up the process. In this study, FNO surrogate models are trained to model reactive transport of CO2 reinjection column experiments and to replace a conventional reactive transport numerical solver (PFLOTRAN) in a PESTPP-IES inversion workflow for estimation of geochemical parameters. The trained FNO surrogates can predict the temporal outlet silica concentrations, calcium concentrations, and pH values of the complex reactive transport system with high accuracy (R2 scores up to 0.9998) and superior time efficiency (95.6% faster than PFLOTRAN). With the implementation of FNO surrogates, the time cost of the inversion workflow has reduced by 34.5%, while achieving almost identical results as the workflow with PFLOTRAN. The investigation demonstrated the speedup advantages of implementing FNO surrogates against conventional reactive transport solvers in inverse modeling. The study will be instructive to employ neural operators to model reactive transport and estimate reactive transport parameters in geothermal applications.

Topic: Modeling

Hydraulic fracturing with proppants in enhanced geothermal systems (EGS) improves reservoir permeability, thereby enhancing the efficiency and economic viability of geothermal energy recovery. Accurate fracture diagnostics remain critical for the long-term success of EGS projects. Borehole electromagnetic measurements using electrically-conductive (EC) proppants and fluids provide a promising approach for mapping fractures and proppant distribution. To evaluate the effect of using EC proppants under EGS conditions, we conducted comprehensive measurements of the hydraulic and electrical conductivities of EC proppant-supported fractures under stress and temperature conditions typical of the Utah-FORGE EGS. EC proppants of 30/50-mesh and 40/70-mesh sizes were placed in the space between two Sierra White granite slabs and then subjected to confining stresses up to 10,000 psi and the temperature of 230 °C. Hydraulic conductivity of the EC proppant-supported fracture, defined as the product of fracture permeability and fracture width, was measured under various confining stresses and proppant concentrations. The proppant concentration is defined as the proppant mass per unit fracture-face area. The results revealed non-monotonic dependence of the fracture hydraulic conductivity on the proppant concentration. These findings indicate that significant fracture hydraulic conductivity can be achieved using a partial-monolayer proppant pack in granite fractures, underscoring the potential for reducing material costs. Measurements under dry conditions show that EC proppant-supported fractures exhibit increasing electrical conductivity with confining stress due to enhanced interparticle contacts. It establishes a for electrical conductivity of EC proppant-supported fractures, which serves as a reference for subsequent measurements under brine-saturated conditions. These comprehensive laboratory testing data highlight the potential of using EC proppants in field-scale EGS fracture diagnostics.

Topic: Enhanced Geothermal Systems

Understanding the formation and distribution of hydrothermal alteration minerals is essential for interpreting the thermal evolution, permeability, and fluid–rock interactions in geothermal systems. This study focuses on identifying high-temperature alteration minerals in selected Kenyan geothermal wells using Attenuated Total Reflectance (ATR) Spectroscopy, an advanced form of Fourier Transform Infrared (FTIR) spectroscopy. The method provides a rapid, non-destructive approach for recognizing mineral phases through their diagnostic infrared absorption features. Drill cuttings and core samples collected from different depth intervals and geothermal fields within the Kenyan Rift were analyzed to investigate mineralogical variations associated with increasing temperature and alteration intensity. The ATR spectra revealed prominent vibrational features characteristic of epidote, chlorite, quartz, garnet, and wollastonite, indicating progressive mineral transformations under high-temperature hydrothermal conditions. These spectral interpretations were verified using X-ray Diffraction (XRD) analysis, which confirmed the accuracy of ATR-based mineral identification. Integration of the spectral and mineralogical data delineated distinct alteration zones with depth, reflecting temperature gradients and fluid flow regimes within the geothermal reservoir. The study demonstrates that ATR spectroscopy is a reliable and cost-effective analytical tool that complements traditional methods in geothermal exploration. Its minimal sample preparation, high spectral resolution, and ability to analyze fine-grained mixtures make it suitable for routine characterization of alteration assemblages. These results enhance understanding of the hydrothermal and thermal evolution of Kenyan geothermal systems and provide valuable input for resource evaluation and reservoir development.

Topic: Geology

The U.S. Department of Energy's (DOE) geothermal AI research assistant, AskGDR, has been expanded to better meet the needs of its users and the geothermal industry. Originally the result of integration with the metadata and supporting documents from data submissions to DOE's Geothermal Data Repository (GDR) and a Large Language Model (LLM), AskGDR now includes industry reports, content from DOE's GeoBridge, and the past 9 years of proceedings from the Stanford Geothermal Workshop. The National Laboratory of the Rockies (NLR), in response to user feedback and analysis, has expanded the corpus of knowledge included in AskGDR to better answer the questions asked by users. AskGDR now provides answers to users’ questions about the geothermal industry at large, emerging technologies and trends, and cutting-edge research, while still enabling users to interrogate the deeper aspects of GDR data and the methods used to derive them. This paper outlines the expanded corpus of knowledge input into AskGDR, an analysis of questions asked, the efficacy of recent improvements, and impact and quality of the answers generated.

Topic: Emerging Technology

Deep borehole heat exchangers (DBHEs) present significant computational challenges due to their multi-scale geometry and long operational timescales. We present a GPU-accelerated three-dimensional model that makes well array simulations computationally tractable through an operator splitting strategy tailored to the problem's physics. The method separates vertical diffusion (stabilized explicit Runge–Kutta–Chebyshev), horizontal diffusion (alternating direction implicit), and advection (semi-Lagrangian), achieving near-unconditional stability with high efficiency. We validate against three published models using different numerical approaches, showing excellent to good agreement. The vendor-agnostic Julia implementation enables full three-dimensional simulation of multi-well arrays on a single GPU, opening new possibilities for systematic design optimization and long-term performance assessment of geothermal well systems. The implementation is released as the open-source Julia package GeothermalWells.jl.

Topic: Modeling

Using a semi-analytical solution for the pressure and rate transient response in multifractured enhanced geothermal systems, we developed a mathematical formulation to handle multiple wells with switching between flux control and pressure control for injector and producer. By decoupling well control, we could use a two-step approach to compute the solution effectively. We first solved the pressure and rate transient response with constant rate impulse in each well individually. Then, we combined them together to satisfy flux control and pressure control in each well. With this new semi-analytical solution, we estimated system parameters from inverse modeling for the crossflow tests in the Frisco pad of the Project Cape development, using both injection/production rate and wellhead/downhole pressure. The system parameters in consideration are fracture permeability, fracture area, rock matrix permeability, and initial reservoir pressure. Interestingly, one of the unique aspects of Frisco is that there are multiple injectors and multiple observers operating at the same time and their interactions are dependent on their connectivity through fractures – this is in distinction to the case of Utah FORGE which had only a single injector-producer pair.

Topic: Reservoir Engineering

Geothermal energy stored in hot dry rocks (HDRs) has been characterized as an essential constituent of the global effort to achieve carbon neutrality and combat climate change. Enhanced geothermal system (EGS) is a promising technique to extract geothermal energy from HDRs, but the long-term thermal performance is largely jeopardized by flow/thermal short-circuiting, a phenomenon that most injected fluid concentrates in a few major flow channels and has been widely reported in field EGS practices. To understand the underlying physical and chemical mechanisms of flow short-circuiting, we first perform a comprehensive literature review to summarize the main causes of flow short-circuiting. Based on previous studies, we develop a thermo-hydro-mechanical-chemical (THMC) coupled model to simulate the complex physical and chemical processes associated with heat extraction from EGS reservoirs. With the model, we comprehensively quantify the effect of fluid pressure, poroelastic process, thermoelastic process and water-rock reactions on fracture aperture evolution, as well as the corresponding influences on fracture flow channeling behavior and long-term thermal performance. Specifically, we reveal various positive and negative feedback loops between THMC processes and fracture flow channeling. According to the model results, we further discuss potential techniques for flow channeling mitigation that can be employed in field applications to improve heat extraction efficiency from EGS reservoirs.

Topic: Enhanced Geothermal Systems

This study evaluates the techno-economic feasibility of a deep direct-use geothermal system in Grimes County, Texas. The system consists of a doublet system, including an injector and a producer. Fluid is extracted from the subsurface for heat utilization at surface facilities and is reinjected as cooled fluid. A numerical model is developed to simulate the performance of the doublet system. The simulation time is 30 years for analyzing long-term behavior. A deep formation - the Austin Chalk, with formation top ranges from 13,000 ft (3,962 m) to 15,500 ft (4,724 m) of true vertical depth (TVD) - is selected as the reservoir formation due to the favorable sealability of the Midway and Taylor shales above. The permeable layer is sandwiched between low-permeable formations. The reservoir is assumed to be brackish water, without any hydrocarbons. Techno-economic analysis is conducted to assess economic feasibility. The sensitivity of formation characteristics such as porosity and permeability can also be modeled to examine the reservoir impact on energy production. The results of the reservoir simulation evaluate the dynamic performance of the direct-use geothermal system. Produced temperature profile, changes in reservoir pressure over time, and the amount of energy stored are simulated. Techno-economic analysis incorporates simulation results to assess the economic indicators, such as the levelized cost of energy. Additionally, the evaluation considers both technical and economic performance to provide a comprehensive assessment.

Topic: Reservoir Engineering

Enhanced Geothermal Systems (EGS) rely on efficient heat transfer between circulating fluids and hot rock through engineered fracture networks. Reservoir thermal properties—particularly thermal conductivity and specific heat capacity—play a critical role in production temperature, thermal power output, and fracture spacing. These thermal properties are commonly assumed to be homogeneous, yet laboratory measurements from Utah FORGE core and cuttings reveal substantial spatial and temperature-dependent heterogeneity. Core and cutting analyses show that thermal conductivity can vary by up to 67% along depth, largely driven by mineralogical differences, especially quartz content. In addition, thermal conductivity decreases while specific heat capacity increases with increasing temperature, leading to reduced thermal diffusivity at reservoir conditions. This study integrates laboratory measurements with numerical simulations to quantify the influence of thermal property heterogeneity on EGS performance. Numerical simulation results of both single-fracture and multi-fracture doublet systems demonstrate that a 50% increase in thermal conductivity combined with a 20% increase in heat capacity can increase produced thermal power by approximately 11%. In heterogeneous reservoirs, the presence of a 130 m high thermal property layer enhances thermal power output by 3.6%. Furthermore, reduced thermal diffusivity at elevated temperatures decreases the fracture spacing required to maintain thermal independence, lowering fracture spacing from approximately 100 m to 85 m for a 30-year project lifespan. These results highlight the importance of incorporating realistic thermal property heterogeneity into EGS design and performance assessments.

Topic: Enhanced Geothermal Systems

Thermo-hydraulic modeling of fluid flow and heat extraction in porous media is widely used in enhanced geothermal systems (EGS), often incorporating discrete fracture networks to represent complex fracture geometries. In these models, the elevated permeability near fractures is typically governed by aperture width – a key parameter for matching field observations. However, many existing approaches do not fully couple fracture opening and closure with mechanical responses to high-pressure fluid injection, potentially limiting their predictive accuracy. To address this, we focus on a single dominant fracture at the Utah FORGE site and develop a coupled thermo-hydro-mechanical (THM) model using a discontinuous Galerkin method integrated with a cohesive zone model to explicitly capture fracture deformation during injection. This formulation allows fracture aperture to evolve dynamically in response to thermal stresses and fluid pressure, enabling more realistic predictions of permeability evolution. By reducing the computational domain to a few hundred meters and focusing on a single fracture, we strike a balance between physical fidelity and computational feasibility. The model is further coupled with an optimization algorithm to calibrate key parameters against observed data. We compare the results with those from a purely thermo-hydraulic model using a prescribed aperture distribution – such as an elliptical profile with sigmoid decay – to evaluate whether geomechanical coupling improves predictive performance. The findings provide insights into the role of mechanical feedback in EGS performance and offer a valuable tool for the design and optimization of stimulate strategies.

Topic: Modeling

The first utility-led retrofit geothermal energy network (GEN) system in the US was built in Framingham, MA by Eversource in 2024. The system was designed to provide heating and cooling energy to 36 nearby buildings through a single ambient loop connecting three geothermal borefields. Although GEN systems are estimated to have a lifetime of 50 years, these systems may suffer from efficiency reductions due to subsurface thermal drifts after multiple years of operation, especially when the heating and cooling loads are not balanced. To ensure that the GEN system is operating in an optimal and sustainable manner, a ground temperature monitoring system based on distributed fiber optic sensing (DFOS) technique was designed and installed at the Framingham GEN system. Fiber optic cables were inserted in 14 (out of 90) boreholes among the three borefields to measure both the temperature distribution along the depth and its variation with time. This study focuses on ground temperature data collected from the Normandy Lot borefield of the GEN system during its first 16 months of operation. Measured borehole temperatures ranged from a summer maximum of 21 °C to a winter minimum of 9 °C, relative to an average initial ground temperature of 12 °C, indicating a substantially greater net heat injection during the summer period. Difference in borehole temperature responses were observed and can be attributed to multiple factors, including borehole position, pipe flow rate, drilling deviation, and grouting quality. Thermal interaction occurred within the top 50 meters of the subsurface and turns significant when temperature reaches extrema during the ground heating and cooling phases. Below 50 meters, thermal interactions were found negligible. As system continues to operate under imbalanced heating and cooling loads, the thermal interaction zone is expected to expend to greater depths, highlighting the importance of long-term subsurface temperature monitoring for maintaining GEN system performance and sustainability. Eventually, the recorded ground temperature data will be used to improve understanding of subsurface thermal response to building energy loads, validate the GEN system design, and optimize the system operation strategy.

Topic: Field Studies

South-central South Dakota exhibits elevated heat flow (up to 130 mW/m²) and steep geothermal gradients (greater than 100 °C/km), indicating substantial geothermal potential. Nevertheless, the region remains underexplored; past development has been largely confined to small direct-use systems (e.g., hot-water heating). In our previous work (Ye et al., 2025), we compiled the most comprehensive dataset to date, nearly 3,000 borehole temperature measurements, to reconstruct higher-resolution geothermal-gradient maps, and then performed preliminary techno-economic analysis (TEA) of direct-use applications in two shallow aquifers. These results are encouraging and point to considerable opportunities for geothermal development in South Dakota. In this paper, we further evaluate the technical feasibility and economic viability of the deployment of enhanced geothermal systems (EGS) within the deep crystalline basement using a doublet well configuration with approximately 100 m injection-production spacing. Thermal transport analysis shows that realistic fracture apertures enable rapid heat transfer, allowing produced fluid temperatures to approach reservoir conditions at depths of ~3 km, and deeper. A grid-based techno-economic assessment quantifies the levelized cost of electricity (LCOE), net present value (NPV), and internal rate of return (IRR) under varying production flow rates and Investment Tax Credit (ITC) levels. The TEA results suggest that EGS in South-Central South Dakota are technically viable and hold considerable long-term potential, but their near-term economic success remains sensitive to reservoir performance and the presence of policy incentives. This study aims to provide a first-hand perspective on the techno-economic viability of geothermal energy development in South Dakota and highlights key parameters affecting its future development.

Topic: Enhanced Geothermal Systems

This study presents a deep learning framework, Thermal-Hydraulic-Mechanical Embed-to-Control-and-Observe (THM-E2CO), designed for high-fidelity reduced-order modeling of geothermal reservoirs governed by tightly coupled poro-thermo-elastic processes. The architecture extends the E2CO paradigm to address the complex nonlinear interactions between heat transfer, fluid flow, and rock deformation. Unlike static surrogate models, this framework is specifically engineered to predict and capture the temporal evolution of porosity and permeability as they respond to thermal drawdown and mechanical loading within the reservoir. The THM-E2CO architecture integrates a 3D convolutional encoder-decoder to compress and reconstruct full field pressure and temperature distributions while preserving critical thermal-hydraulic-mechanical couplings. A nonlinear latent-state transition network models the temporal evolution of the reservoir under varying operational controls. Crucially, the model is trained to observe the feedback loops where temperature gradients and pore pressure fluctuations drive mechanical deformation, subsequently altering the flow properties of the rock matrix. The learning process is regularized through a composite loss function that enforces data reconstruction fidelity, latent consistency, and conservation of mass and energy, ensuring physical plausibility across the coupled domains. Using CMG STARS as the high-fidelity simulator, a diverse ensemble of training data was generated via CMOST-driven variations in injection rates and producer bottom hole pressures. The dataset comprises over 1,000 simulations spanning a 30-year production period, featuring a six-well configuration. This wide operational space allows the model to learn robust coupled behavior and the nonlinear degradation or enhancement of reservoir transmissibility over time. The novelty of this work lies in the framework’s ability to explicitly capture the poro-thermo-elastic response of the reservoir, providing a rapid alternative to computationally expensive geomechanical solvers. By embedding the physics of stress-dependent permeability into the latent space, the model achieves high-fidelity reproduction of full physics simulations with computational accelerations exceeding 30,000 times. This development provides a scalable foundation for the prediction of rapid geothermal performance, uncertainty quantification, and real time optimization under complex geomechanical conditions.

Topic: Modeling

Early-stage geothermal exploration in Canada is challenged by remote terrain, harsh climate, limited infrastructure, and sparse subsurface data coverage, particularly in northern and underexplored regions. To address these challenges, this study develops a satellite-based remote sensing framework that quantifies geothermal heat flux contributions to land surface temperature (LST) derived from thermal infrared imagery. The method exploits the contrasting spatial–temporal characteristics of solar radiation and geothermal heat input to separate temporally invariant geothermal signals from time-dependent solar effects using a physics-based iterative decomposition workflow. The approach is applied across three contrasting geological settings in Canada, including the Mount Meager Volcanic Complex in British Columbia, a fault-controlled geothermal system near Burwash Landing in Yukon, and a carbonate-dominated Arctic environment on Cornwallis Island, Nunavut. Results demonstrate that the extracted geothermal-related LST anomalies form coherent spatial patterns consistent with geological controls across volcanic, structural, and Arctic settings. This remote sensing–driven framework provides an effective and transferable tool for early-stage geothermal target screening, significantly reducing exploration uncertainty in data-scarce and logistically challenging regions of Canada and beyond.

Topic: Emerging Technology

Accurate ground motion prediction is essential for assessing the potential impact of induced seismicity during fluid injection in enhanced geothermal systems (EGS). Building on our maximum magnitude (Mmax) forecasting framework, we integrated Mmax predictions with ground-motion prediction equations (GMPEs) to evaluate spatial and temporal variations in seismic hazard at the Utah FORGE site. The approach combined the predicted Mmax values with GMPEs that account for local geological and site effects, including shallow time-averaged shear-wave velocity (Vs30) and epicentral distance. By dynamically linking source-level forecasts to site-level motion estimates, the model provided updated predictions of Peak Ground Acceleration (PGA) and Peak Ground Velocity (PGV) at nearby population centers and infrastructure nodes. Preliminary results from the 2022 and 2024 FORGE stimulations indicated that incorporating evolving Mmax forecasts improved the reliability of PGA and PGV estimates under changing injection and post-injection conditions. This integrated framework provides a pathway to real-time, data-informed seismic hazard assessment in EGS operations, enhancing risk mitigation and supporting the refinement of traffic-light protocols.

Topic: Enhanced Geothermal Systems

Reinjection of cold fluid is essential for sustaining deep geothermal systems but inevitably perturbs the reservoir stress state through coupled thermo-hydro-mechanical (THM) processes, triggering microseismicity. A critical challenge in reservoir management is distinguishing between hydraulic and thermal triggering mechanisms, which tend to exhibit distinct spatiotemporal characteristics. In this study, we investigate the spatiotemporal evolution of induced microseismicity using a fully coupled 2D THM model in conjunction with the discrete fracture network (DFN) approach. By comparing isothermal and non-isothermal injection scenarios, we isolate the specific contributions of poroelastic pressure diffusion and thermoelastic contraction to fracture slip. We find that while pressure perturbations propagate rapidly and induce diffuse, widespread seismicity at early times, the dominant triggering mechanism progressively shifts toward thermoelastic stressing. Analysis of Coulomb failure stress changes (ΔCFS) reveals that cooling-induced instability forms a localized band that co-migrates with the advancing thermal front. Unlike the pressure front, which quickly decouples from the microseismic cloud, the late-time seismic front aligns closely with the cold domain. These findings demonstrate that induced microseismicity is not merely a hydraulic byproduct but can serve as a reliable tracer for cold-front migration, offering a potential tool for forecasting thermal breakthrough in fractured reservoirs.

Topic: Enhanced Geothermal Systems

Accurate microseismic locations are essential for developing and monitoring enhanced geothermal systems (EGS). Joint use of downhole geophones and distributed acoustic sensing (DAS) can boost detection and location performance, but conventional picking-based workflows perform sub-optimally on DAS data because individual channels are noisy. In addition, DAS’s unidirectional measurements cause blind spots that depend on acquisition geometry and source location, focal mechanism, and subsurface structure. We compare a traditional, picking-based locator with a picking-free source-imaging workflow that jointly exploits P- and S-wave phases on DAS and geophones. The source-imaging method applies an STA/LTA transform to enhance P-wave coherence and mitigate blind spots due to DAS directivity. Our analysis clarifies the strengths and downsides of each approach and shows that combining them improves catalog completeness and location accuracy and resolution, with specific benefits for real-time detection of shear onset and runaway slip. These results inform real-time monitoring, risk assessment, and stimulation planning in EGS operations.

Topic: FORGE

Thermal short-circuiting significantly undermines the long-term productivity and economic sustainability of Enhanced Geothermal Systems (EGS). This research examines the synergistic physical mechanisms—thermal edge effects, non-isothermal wellbore flow, and thermal destressing—that drive this phenomenon using a coupled Thermo-Hydro-Mechanical-Wellbore (THM-W) framework. The model reveals that an initially uniform reservoir eventually develops preferential flow channels through a self-reinforcing feedback loop. This evolution begins with wellbore friction and thermal edge effects, which induce rock contraction and cooling near central fractures. By the 28-year mark, thermo-mechanical opening becomes the primary flow regulator; central fracture apertures expand from 5 mm to over 7 mm, while permeability escalates from 5×10-11 m2 to 4.06×10-8 m2. This high-conductance path captures a disproportionate 30% of injected fluid, triggering premature thermal breakthrough. Furthermore, while proppants enhance hydraulic conductivity, they also expedite thermal decline. These findings offer a quantitative evaluation of the mechanisms precipitating thermal short-circuiting, providing essential insights for the development of future engineering interventions and mitigation strategies.

Topic: Enhanced Geothermal Systems

The global transition to sustainable energy demands innovative technologies that enhance the efficiency and scalability of renewable resource utilization. Subsurface stimulation offers a promising pathway to accelerate heat exchange in geothermal reservoirs. However, conventional hydraulic fracturing technology remains constrained by packer leakage, flow short-circuiting, and limited fracture surface area. To address these challenges, dynamic fracturing using pulsed power has been proposed to enable more efficient, controllable, and sustainable stimulation of subsurface resource extraction. Pulsed power fracturing experiments have been reported in the literature, but the conversion efficiency of electrical energy into mechanical energy that drives rock fracture, especially in multiple pulses scenarios, remains insufficiently understood due to the dynamic nature of the process in microseconds. Moreover, because rocks are naturally fluid-infiltrated, the coupled interaction between fracture propagation and fluid flow has yet to be systematically analyzed and compared with pure solid descrption. To address these challenges, this study introduces a three-dimensional dynamic continuum modeling framework that fully couples the phase-field fracture method with fluid flow and evolving hydro-mechanical properties. Using empirical relationships extracted from existing literature, we capture the fracturing dynamics on the microsecond timescale, representing the pulse power as a time-dependent, depth-varying mechanical pressure applied on the borehole boundary. The implementation is validated against laboratory experiments on both dry and fluid-saturated rock samples. Finally, we evaluate the governing factors controlling fracture surface enhancement and energy conversion efficiency. We assess the complete energy budget under multiple pulsing conditions. The findings provide insights into the fundamentals of pulsed power fracturing, reveal energy partitioning mechanisms, and identify key factors to improve efficiency and scalability to field applications.

Topic: Modeling

Geothermal exploration in structurally controlled systems requires careful assessment of well placement relative to permeable fault zones and associated upflows. This study investigates multiple drilling scenarios that reflect different locations of temperature gradient holes (TGH) with respect to a fault-hosted hydrothermal reservoir and its upflow plume. Using a combination of conceptual models and field data, we compare thermal profiles from wells that (1) completely miss the reservoir, (2) encounter distal upflow from the heat source, (3) intersect the isothermal reservoir, and (4) capture shallow or proximal upflow at varying locations. We also evaluate these scenarios under different fault dip angles and rock thermal conductivities. The comparative analysis highlights diagnostic temperature-depth trends, including shallow isothermal zones, steep conductive gradients, and deep upflow signals. By integrating field observations with modeled profiles, we demonstrate how variations in well location influence both the apparent subsurface temperature structure and the inferred reservoir potential. These findings provide practical guidance for geothermal exploration strategies, emphasizing the importance of structural context, hydrothermal upflow geometry, and well trajectory when targeting economically viable resources.

Topic: Modeling

Unpropped fracture segments—often referred to as arch regions or residual openings—play a critical yet underexplored role in subsurface flow dynamics. While conventional hydraulic fracturing models focus primarily on propped zones, emerging evidence suggests that even low conductivity unpropped regions can significantly influence fluid transport and energy recovery. This study presents a numerical investigation into the impact of unpropped channel conductivity on perforation placement optimization and thermal performance in Enhanced Geothermal Systems (EGS). Using a custom in-house simulator, we model a series of fracture configurations with varying unpropped channel heights and permeability contrasts. Results demonstrate that the presence and geometry of unpropped channels alter flow pathways and temperature evolution at the production well over time. Comparative analysis against homogeneous fracture models reveals substantial deviations in system behavior, underscoring the importance of incorporating conductivity heterogeneity into design and simulation workflows. This work bridges a critical gap in current modeling practices by quantifying the operational significance of unpropped fracture zones. It offers a foundation for more accurate perforating and doublet strategies leading to improved EGS system efficiency, while opening avenues for future integration with real-time monitoring and adaptive control technologies.

Topic: Enhanced Geothermal Systems