Stanford Geothermal WorkshopFebruary 8-10, 2027

Non-condensable gases (NCGs), mainly CO₂ and H₂S, are commonly co-produced with geothermal fluids and may be vented, treated, or reinjected after gas extraction at geothermal power plants (GPPs). As GPP operators face increasing pressure to reduce greenhouse gas emissions, NCG reinjection is attracting attention not only as an emission-abatement measure but also as a reservoir-management strategy. However, guidance for geothermal NCG reinjection design remains less developed than that for petroleum acid gas injection (AGI), particularly for defining operating envelopes that balance containment, injectivity, corrosion control, and the risk of breakthrough into production wells. This paper synthesizes transferable lessons from petroleum AGI for geothermal NCG reinjection through four field case studies: Zama and Brazeau Nisku Q in Alberta (Canada), Ngā Tamariki (New Zealand), and Hellisheiði/CarbFix2 (Iceland). These cases were selected because they represent the principal operating scenarios relevant to CO₂–H₂S reinjection, including sour-gas disposal and geochemical trapping in petroleum reservoirs, and brine-dissolved NCG reinjection and mineral trapping in geothermal systems. Published field experience, geochemical analyses, numerical simulations, and operational reports were reviewed to compare injection objectives, pressure-temperature-composition control, fluid-phase management, reservoir response, well integrity, monitoring practices, and operational constraints. The comparison indicates that petroleum AGI provides useful design-envelope concepts and operational strategies for geothermal NCG reinjection, but not a direct template, as geothermal applications require significant adaptation. The Zama case highlights containment verification, monitoring, wellbore leakage control, caprock integrity, and breakthrough management. Brazeau Nisku Q illustrates H₂S-rich geochemical trapping and sulfide mineral formation in a petroleum reservoir. Ngā Tamariki emphasizes geothermal-specific constraints, including brine handling, injectivity, scaling, gas return to production wells, and impacts on reservoir performance. Hellisheiði/CarbFix2 demonstrates dissolved CO₂–H₂S injection into basalt, where rapid mineralization can provide durable storage under favorable host-rock conditions. A key distinction between petroleum AGI and geothermal NCG reinjection lies in fluid-phase management. Petroleum AGI commonly injects dehydrated, acid gas-rich streams to limit hydrate formation and free-phase corrosion, whereas geothermal reinjection typically injects NCGs dissolved in brine or condensate to suppress free-gas migration. This approach in geothermal, however, introduces additional challenges related to acidity, scaling, and injectivity. Based on these findings, the study proposes a preliminary design-envelope framework that adapts petroleum AGI principles to geothermal conditions by incorporating constraints associated with gas solubility and breakout, brine chemistry, well integrity, reservoir connectivity, long-term production response, and operating limits in surface facilities.

Topic: Injection

The application of geothermal direct use within Indonesia's thermal bathing industry offers substantial potential for advancing sustainable tourism and empowering local economies. To guarantee environmental sustainability, public safety, and the standardization of facilities, the Indonesian government has instituted the Operational Worthiness Certificate (Sertifikat Laik Operasi, or SLO) requirement for industry operators. As this sector moves toward comprehensive formalization, a critical opportunity arises to streamline the SLO application process and expedite regulatory compliance. Utilizing field data and stakeholder insights gathered from local governments and thermal spring operators across Garut and greater West Java, this study pinpoints crucial areas for procedural improvement and capacity development. Key recommendations involve aligning Central and Regional notification systems within the Online Single Submission (OSS) platform, streamlining Geothermal Situation Map prerequisites for Micro and Small Enterprises (MSEs), and establishing uniform Technical Guidelines (Juknis) to assist local authorities in executing accurate field inspections.Rather than delivering a fully developed software solution, this research proposes a multidisciplinary conceptual framework integrating Geothermal Management, Public Policy, and Information Systems. Initially, we examine the potential of an integrated API architecture—drawing inspiration from local platforms like Subang's SINANAS—to theoretically facilitate seamless data exchange between regional and central permitting databases. This concept demonstrates how enhanced system interoperability can reduce administrative bottlenecks and misrouted permits. Furthermore, informed by an empirical capacity-gap assessment, we outline a standardized field verification methodology calibrated to the existing capabilities of regional governments.To catalyze future progress in the industry, this paper outlines a practical toolkit aimed at assisting both operators and regulators. The core strategic proposals include: (1) a comprehensive Technical Guideline (Juknis) framework that defines minimum field-testing criteria (such as temperature, pH, and H2S levels) and evaluates the integration of Regional Health Laboratories (Labkesda) for equipment validation; (2) the deployment of affordable, standardized Situation Map templates designed to alleviate financial pressures on MSEs; and (3) an intuitive procedural roadmap to guide operators through the existing OSS framework. Supported by conceptual system architecture diagrams, user-journey flowcharts, and capacity-building matrices, this research delivers a strategic roadmap to guide policymakers, support local enterprises, and drive the sustainable expansion of geothermal direct-use applications in Indonesia.

Topic: Direct Use

Enhanced geothermal systems represent the next frontier of geothermal energy, yet reservoir characterization in EGS settings remains challenging due to sparse labels, complex fracture networks, and heterogeneous lithologies. The Utah FORGE site provides a unique, fully open dataset combining drilling records, microseismic catalogs, well logs, and temperature measurements from a purpose-built EGS research site, creating an exceptional opportunity for rigorous machine learning evaluation in a controlled field setting. This study applies and s a suite of machine learning methods to two coupled EGS problems: fracture network characterization from microseismic event clustering and well log signatures and subsurface temperature distribution prediction integrating drilling and geophysical observations. We evaluate classical ensemble methods, physics-informed neural networks that embed heat conduction equations directly into the learning objective, and graph neural networks that represent the fracture network as a structured graph to capture spatial connectivity. Results demonstrate that physics-informed approaches reduce data requirements by over ~ ~40% compared to purely data-driven baselines while maintaining competitive predictive accuracy, a finding with direct operational significance for EGS sites where labeled measurements are expensive. Graph-based fracture representation captures connectivity patterns that conventional feature-engineering approaches miss, improving microseismic cluster characterization. Temperature prediction accuracy is strongly governed by the spatial density of conditioning measurements rather than model complexity, pointing to an optimal data acquisition strategy for future EGS sites. These findings translate into concrete recommendations for EGS site characterization workflows and establish a reproducible on the FORGE dataset that the broader community can build upon as EGS deployment accelerates globally.

Topic: FORGE

Steam–Water Relative Permeability and Two-Phase Flow Properties in Geothermal Reservoirs: Measurements, Models, and Open Questions Reviewed Objectives/Scope: Flashing reservoirs run on steam-water relative permeability, a property measured by a handful of laboratories under conditions most core facilities cannot reach. We review steam-water kr and two-phase flow properties for geothermal systems: the measurement record, phase-transformation effects that make steam-water unlike gas-water, and the model curves simulators quietly default to. Enhanced-system forecasting inherits the gap most directly, its conditions furthest from the data. Methods, Procedures, Process: The steam-water measurement literature is compiled, sparse enough to review nearly completely; phase-change-coupled flow physics is reviewed to explain where steam-water departs from inert-gas analogy. Simulator default practices are examined against the data, and ML property estimation is surveyed briefly. Condition coverage is mapped against enhanced-system envelopes, sizing the extrapolation. Relative-permeability functional forms are compared for their behavior outside measured ranges. Results, Observations, Conclusions: Measured steam-water curves differed from nitrogen-water analogs on the same rocks, with phase transformation reducing apparent interference between phases; defaults borrowed from gas-water practice misstate that. Data cluster in a narrow condition range, and enhanced-system conditions extrapolate beyond all of it. Forecast sensitivity to the kr choice rivaled sensitivity to permeability itself in compiled studies. Functional-form choice dominated extrapolation behavior, curves agreeing where data exist and diverging beyond. Novel/Additive Information: A near-complete audit of a property everything in flashing-reservoir forecasting depends on and almost nobody measures, with measurement gaps ranked by forecast consequence and functional-form choice exposed as a hidden extrapolation policy. The consequence-ranked wish list is scoped for university and national-laboratory capability — a ready agenda for the geothermal research programs now expanding worldwide.

Topic: Enhanced Geothermal Systems

Geothermal Resource Capacity Estimation: Heat-in-Place, Power-Density, and Stochastic Methods Compared, with AI Applications Objectives/Scope: Resource estimates decide drilling budgets, and the estimation methods disagree by design. We compare geothermal capacity-estimation approaches: volumetric heat-in-place with recovery factors, power-density analogs, and stochastic implementations of both, asking what each actually predicts and why early-stage estimates keep running optimistic. Portfolio-level resource reporting inherits the bias, making calibration an industry credibility issue. Methods, Procedures, Process: Method foundations are reviewed with their buried assumptions surfaced, recovery factor above all; estimate-versus-outcome comparisons are compiled wherever developed fields allow the reckoning. Stochastic practice is examined for whether distributions reflect knowledge or convention, and ML-assisted estimation from sparse exploration data is surveyed. Recovery-factor evidence is assembled by system type from outcome comparisons. Cutoff-choice effects are compiled, temperature and depth cutoffs moving estimates quietly. Results, Observations, Conclusions: Recovery factor carried most of the uncertainty and least of the scrutiny; outcome comparisons showed early volumetric estimates biased high, with the bias traceable to recovery-factor and cutoff choices. Power-density methods performed respectably where analog quality was honest. Stochastic ranges published to date have been too narrow more often than too wide. Cutoff choices moved estimates as much as recovery factors in the compiled decompositions. Novel/Additive Information: Capacity-estimation methods are judged against realized drilling outcomes rather than internal logic, with the documented optimism traced to recovery-factor and cutoff choices — two levers of equal weight and unequal scrutiny. The system-type recovery-factor ranges are formatted for direct citation in resource disclosures, giving developers calibrated credibility in a sector whose inflated estimates keep spending it

Topic: Enhanced Geothermal Systems

The analysis compares medium-enthalpy geothermal systems in a direct configuration with hybrid geothermal-solar thermal systems for cooling applications in data centers. Direct geothermal uses resources with temperatures between 90 and 150 °C, providing a steady, stable, and continuously available energy source, although it is limited by the reservoir's own thermal conditions. The integration of solar thermal energy through concentration collectors allows the fluid temperature to rise to values close to 120–200 °C, significantly improving the available energy quality. This thermal boost makes it possible to use double-effect absorption chillers, increases the coefficient of performance (COP), and expands the system's operational flexibility. From an operational standpoint, geothermal provides the base thermal load while the solar resource adds extra energy during periods of high irradiation. Although the solar contribution introduces some daily and seasonal variability, the system's reliability is maintained thanks to the continuous backup from the geothermal source. Plus, using advanced control and automation systems allows optimizing the mix of both energy sources and adapting to changes in demand. In terms of performance, direct geothermal systems usually operate with thermal COPs between 0.6 and 0.75, while hybrid systems can reach values between 0.8 and 1.3. Although adding a solar field increases the initial investment (CAPEX), operating costs stay low because only renewable resources are used and there’s no need for fossil fuels. In conclusion, geothermal–solar hybrid systems represent a highly promising technological alternative for the sustainable cooling of data centers in Costa Rica. Combining the reliability of geothermal energy with the thermal boost capability of solar power allows for increased energy efficiency, reduced levelized cost of cooling (LCOC), and optimized use of available renewable resources, especially in regions with high geothermal and solar potential like Guanacaste.

Topic: Direct Use

Indonesia’s geothermal sector is pivoting from mature high-temperature fields toward vast low-to-medium temperature resources. However, the bankability of these future projects is threatened by power plant construction costs that remain well above global averages. This paper tackles this critical bottleneck by introducing a novel techno-commercial ing methodology that dissects the most capital-heavy project phases: Power Plant Engineering, Procurement, and Construction (EPC) and Steam Above Ground Systems (SAGS). Utilizing escalated global cost datasets from the U.S. and Türkiye, our analysis demonstrates that Indonesia’s CAPEX disparity stems from monopolized turbine markets, high import dependency, and inflated financial "safety margins" in early EPC bids. To counter these drivers, we propose a compounding cost-reduction framework featuring four actionable strategies: (1) utilizing Organic Rankine Cycle (ORC) technologies to break manufacturer monopolies; (2) de-risking execution through pilot testing; (3) replacing EPC safety margins with rigorous, geospatial data-driven Front-End Engineering Design (FEED); and (4) restructuring procurement into Split-EPC contracts to optimize tax exposure. The study translates these multidisciplinary findings into an Integrated Cost Optimization Roadmap, utilizing high-definition visual tools like waterfall charts and contracting visualizations. By bridging theoretical cost-saving measures with practical application, this blueprint offers Indonesian policymakers, operators, and financiers a replicable pathway to drastically reduce development costs and accelerate the nation's energy transition.

Topic: General

Cryogenic cold sources such as liquefied natural gas (LNG), liquid nitrogen, and liquid air contain substantial recoverable physical exergy that is commonly dissipated during regasification or vaporization processes. Thermoelectric generators (TEGs) have emerged as a promising solid-state technology for harvesting this cold energy because of their structural simplicity, scalability, reliability, and absence of moving parts. This review presents a comprehensive analysis of thermoelectric generator applications using cryogenic cold sources, with emphasis on LNG regasification systems, liquid nitrogen recovery systems, and liquid air energy storage applications. The review systematically examines thermoelectric operating principles under cryogenic conditions, material behavior at low temperatures, system configurations, heat transfer mechanisms, and reported electrical performance. Major technical challenges, including cold-side thermal resistance, frosting effects, contact resistance, and low conversion efficiency, are critically discussed. Reported experimental and numerical studies demonstrate that cryogenic thermoelectric systems can achieve electrical power outputs ranging from sub-watt laboratory-scale devices to hundreds-of-watts industrial-scale configurations, although practical efficiencies generally remain limited. The review further evaluates heat exchanger integration strategies, structural optimization approaches, and system-level performance limitations affecting large-scale implementation. Finally, current research gaps and future development directions are identified to support the advancement of efficient and reliable cryogenic thermoelectric energy harvesting technologies.

Topic: Emerging Technology

Irregular discharge in multi-feed geothermal wells is commonly attributed to dynamic interactions between feedzones with contrasting pressures and enthalpies, yet quantitative constraints on coupled wellbore--reservoir responses remain limited. This study reconstructs a multi-feed wellbore model for well ULB-01 in the Ulumbu Geothermal Field using a pressure-drop approach calibrated against Pressure Temperature Spinner (PTS) surveys and production-test data. The inferred feedzone boundary conditions are then coupled to a TOUGH2 reservoir simulation to investigate feedzone interaction and wellbore--reservoir response under low wellhead-pressure operation. During a representative cycling interval (10.1--10.5 days), the observed wellhead pressure decreases from 6.8 to 2.7 barg and brine flow declines from 9.2 kg/s to zero, while steam flow remains relatively stable at 5.7--6.3 kg/s. The wellbore simulation captures the broader pressure and steam-rate response but does not fully reproduce the intermittent brine shut-off, indicating that additional transient wellbore or surface-flowline processes may contribute to the observed short-timescale cycling. The coupled TOUGH2--wellbore workflow provides a partial match to measured wellhead pressure, steam mass flow, and produced enthalpy during relatively stable periods, while larger discrepancies remain during transient brine surges and shut-off events. The results suggest that pressure drawdown promotes redistribution of feedzone contributions and cooler liquid inflow at intermediate depth, providing a plausible mechanism for discharge instability. The findings indicate that the coupled workflow is useful for diagnosing feedzone-controlled instability, although resolving intermittent brine shut-off would require a more transient representation of wellbore and surface-flowline processes.

Topic: Reservoir Engineering

Scaling and corrosion remain the most significant operational challenges affecting the efficiency, reliability, and sustainability of geothermal power generation. These processes reduce heat transfer efficiency, impair steam quality, accelerate equipment degradation, increase maintenance costs, and shorten the operational lifespan of geothermal facilities (Nogara & Zarrouk, 2018; Tassew, 2001). Although both phenomena have been widely investigated, they are frequently treated as independent operational problems despite being governed by the same physicochemical evolution of geothermal fluids during production and utilization (Mundhenk et al., 2013). Consequently, limited understanding exists regarding how changes in fluid chemistry within individual process units influence the coupled development of scaling and corrosion throughout a geothermal power plant. This research addresses this knowledge gap by developing an integrated geochemical framework for evaluating the mechanisms controlling scaling and corrosion within the Olkaria I Additional Units (IAU) geothermal power plant, Kenya. Unlike previous studies that primarily emphasize mineral characterization or corrosion assessment independently, this study integrates operational fluid chemistry, steam purity, deposit geochemistry, mineralogical characterization, and process operating conditions to evaluate the evolution of scaling and corrosion across multiple process environments. The framework is designed to identify process-unit-specific geochemical conditions that promote mineral deposition and material degradation, providing a scientific basis for targeted mitigation strategies. Representative deposits were collected from selected process units, including steam scrubbers, condensers, cooling tower basins, and gas extraction systems, where geothermal fluids experience significant physicochemical changes associated with flashing, steam separation, condensation, cooling, and non-condensable gas interactions. Deposit chemistry is being characterized using X-ray fluorescence (XRF), while mineralogical identification is being undertaken using X-ray diffraction (XRD). These datasets are interpreted alongside geothermal fluid chemistry and operational parameters to investigate the relationship between fluid evolution, mineral precipitation, and corrosion processes. Emphasis is placed on steam purity because impurity transport through liquid carryover and vapor-phase contaminants significantly influences deposition and localized corrosion within steam turbines and downstream equipment (Addison & Richardson, 2020; International Association for the Properties of Water and Steam [IAPWS], 2013). Rather than presenting a conventional characterization of geothermal deposits, this research proposes a process-unit-specific methodology for integrating geochemical and operational datasets to improve understanding of the spatial variability of scaling and corrosion within high-enthalpy geothermal systems. The proposed framework is expected to support evidence-based chemical treatment strategies by identifying locations requiring targeted intervention instead of uniform plant-wide chemical dosing. The outcomes are anticipated to contribute toward improved plant reliability, reduced maintenance requirements, enhanced steam quality, and more sustainable operation of geothermal power plants in Kenya and other high-enthalpy geothermal fields.

Topic: Geochemistry

Formation damage constrains geothermal well performance by reducing production or injection capacity through near-wellbore permeability impairment. The problem can occur in both sedimentary and volcanic-hosted reservoirs, but the damage mechanisms and remediation options may be different. This paper discusses the formation damage in geothermal production and reinjection wells hosted in sedimentary and volcanic rocks, with the objective of correlating damage mechanisms and remediation techniques through field case studies. Published measurement data, numerical models, and laboratory experiments from four operational field cases are analyzed: Salak in Indonesia (volcanic-hosted production well), Dieng in Indonesia (volcanic-hosted reinjection well), Beowawe in California (sedimentary-hosted production well), and Szentes in Hungary (sedimentary-hosted reinjection well). The synthesis shows that near-wellbore permeability in sedimentary reservoirs can be impaired by fines migration, clay swelling or detachment, particle plugging, compaction, drilling debris, mineral scaling, and permeability decline driven by changes in flow rate, pressure, temperature, and fluid-rock interaction. Meanwhile, near-wellbore permeability in volcanic-hosted reservoirs can be impaired by silica or carbonate scaling, drilling-fluid invasion, mud and cutting damage, fracture or feed-zone blockage, and alteration-related precipitation. The case studies show that acid stimulation can improve well performance when the acid system and placement method match the damaged material, as illustrated by HF-based acidizing in Salak and Dieng, and HCl-based acidizing for the carbonate interval in Beowawe. However, the Szentes case demonstrates that acid treatment may fail in loose or clay-rich sandstone aquifers, where pump lifting, skin-frac treatment, and mechanical removal of deposited solids can be more suitable. These contrasts indicate that remediation success depends more on mineralogy, damage location, and plugging mechanism than on reservoir type alone. It concludes that geothermal formation damage should be managed through well-performance diagnosis that combines historical drilling review, well testing, fluid chemistry and mineralogy analysis to optimize well stimulation design and results.

Topic: Production Engineering

Conventional geothermal exploration has historically focused on areas with prominent surface manifestations such as hot springs, fumaroles, and hydrothermal alteration. However, many high-temperature geothermal resources remain concealed beneath sedimentary cover or volcanic sequences where surface evidence is limited or absent. These "blind" geothermal systems require integrated multidisciplinary exploration approaches capable of reducing drilling uncertainty. This study presents an integrated exploration workflow combining regional geological interpretation, structural analysis, two-dimensional seismic reflection data, magnetotelluric surveys, gravity and magnetic data, geochemical observations, and three-dimensional subsurface interpretation. Rather than relying on individual datasets, the workflow emphasizes the integration of complementary geoscientific information to identify structurally controlled permeability zones, reservoir compartments, potential heat sources, and optimal exploration drilling targets.

Topic: General

Thermal short-circuiting is one of the key challenges that limit the long-term performance of Enhanced Geothermal Systems (EGS). When a dominant flow path develops by a highly conductive fracture, it reduces the reservoir volume available for heat exchange and causes premature thermal breakthrough. Although near-wellbore flow management has been used to avoid preferential flow path occurrence, controlling permeability away from the wellbore is still challenging, because injected materials need to remain mobile during transport and form a solid flow plug only after it reaches the target location. A laboratory investigation is underway to solve this problem by using microparticles encapsulating reactants within a thin polymer shell. This shell is designed to withstand the lower injection temperatures for a limited time before thermally degrading and releasing diverter-forming reactants at the higher reservoir temperatures, enabling delayed, targeted plug formation away from the wellbore. To deploy this technology in the subsurface at a reservoir scale, it is critical to understand and predict how these microparticles are transported by a viscous carrier fluid in a fracture system before forming diverter plugs and altering the fracture permeability. In this study, we used a Eulerian-Lagrangian approach to numerically simulate multiphase flow within a fracture and the formation of a gel-type diverter plug at a target location. The impact of the factors affecting plugging performance is examined, including carrier fluid properties (viscosity and density), particle properties (particle size, density, and concentration in the mixture), gelation time and stability, fracture geometry, flow rate and boundary condition. Each is varied to evaluate its effect on permeability reduction and plugging effectiveness within the fracture, to identify and optimize the injection conditions that improve the plugging performance. The results of the study will provide the basis for later upscaling to a reservoir model that can assess the field applicability of the technology and the long-term effect on short-circuiting and heat extraction in EGS reservoirs.

Topic: Enhanced Geothermal Systems

Drilling hard, abrasive, and confined formations subjects polycrystalline diamond compact (PDC) cutters to high loads, accelerated wear, and inefficient rock grinding. This study quantifies whether abrasive-water-jet (AWJ) preconditioning immediately ahead of a PDC cutter can reduce cutter loads and mechanical energy demand while increasing rock failure. The scope is limited to completed single-cutter simulations in granite and compares mechanical-only, AWJ-only, and simultaneous hybrid cutting under matched traverse velocities and confinement conditions. The work targets hard-rock drilling applications utilizing current bit architecture. A three-phase LS-DYNA smoothed-particle-hydrodynamics (SPH)/finite-element (FE) framework used a 100×50×20mm granite domain represented by a calibrated Riedel-Hiermaier-Thoma (RHT) material model. Phase 1 simulated mechanical cutting with a rigid single PDC cutter. Phase 2 represented water and 5 wt% iron abrasive using SPH. Phase 3 combined them, positioning a 9.525 mm jet 5 mm ahead of the cutter. Eighteen accepted simulations covered traverse velocities of 1,000, 5,000, and 10,000 mm/s under unconfined and 10 MPa biaxially confined conditions. Matched comparisons used stabilized cutting and axial forces, failed volume per unit travel, and cutter mechanical specific energy (MSE). Mechanical only failed volume remained nearly unchanged across the velocity matrix. In contrast, AWJ only failure was strongly exposure time dependent: increasing traverse velocity from 1,000 to 10,000 mm/s reduced failed volume by 99.76% in unconfined granite and 99.33% under confinement. In all six matched comparisons, hybrid cutting reduced stabilized cutting force by 3.38-18.79% and axial force magnitude by 1.09-17.64%, while increasing failed volume per unit travel by 3.84-65.31%. Cutter MSE decreased by 5.83-51.54% in every hybrid case. The greatest benefits occurred at 1,000 mm/s: failed volume per unit travel increased by 65.31% and 59.46%, and cutter MSE decreased by 51.54% and 49.08%, for unconfined and confined granite, respectively. Confinement had its clearest restrictive effect at this velocity, where AWJ exposure was longest. The consistent force reduction, larger failed zone, and lower cutter MSE demonstrate effective preconditioning, although the benefit diminished rapidly as traverse velocity increased. This study provides a traceable, staged SPH-FEM comparison that separates mechanical cutting and abrasive jet erosion before combining them under identical rock geometry, velocity, and stress conditions. Unlike assessments based on a single force or crater metric, the hybrid response is evaluated using two cutter force components, normalized failed volume, and mechanical energy per failed volume. The resulting dataset quantifies the exposure time dependence of AWJ assistance and demonstrates that a leading abrasive jet can reduce local PDC cutter demand in confined hard rock while enlarging the failed zone.

Topic: Drilling

Reliable assessment of geothermal potential remains challenging because subsurface thermal behavior reflects nonlinear interactions among geological architecture, structural permeability, geophysical signatures, and well conditions, while available observations are spatially heterogeneous and often unevenly sampled. This study develops a generalizable physics informed machine learning framework for predicting geothermal thermal potential, quantifying predictive uncertainty, interpreting the physical controls learned by data driven models, and translating complex model behavior into an analytical screening criterion. A large nationwide geothermal well database from the United States is used as a heterogeneous development and validation test bed, while the framework is formulated using physically defined predictors that can be reconstructed in other geothermal provinces. Exploratory data analysis, spatial statistics, feature engineering, nonlinear relevance analysis, redundancy screening, and spatially stable feature selection are first used to construct a physically consistent predictor space while preventing target leakage and geographic memorization. Strong tabular and neural baselines are compared with a physics informed cross attention architecture that represents geological, structural, geophysical, and well context as interacting information domains. Model selection and hyperparameter optimization are performed using nested spatial cross validation, with geographically separated holdouts used to assess transferability beyond randomly partitioned observations. Predictive reliability is characterized through heteroscedastic uncertainty modeling, deep ensembles, and conformal calibration to distinguish high predicted geothermal potential from high confidence geothermal potential. Model reasoning is investigated using SHAP attribution, SHAP interaction analysis, accumulated local effects, attention based interpretation, and physics consistency tests to identify both individual controls and coupled mechanisms governing predicted thermal conditions. Finally, symbolic regression is applied to stable physical predictors and out of fold model responses to derive a compact geothermal screening index and a locked decision threshold for distinguishing elevated thermal potential. The proposed framework therefore moves beyond black box geothermal prediction toward an uncertainty aware and physically interpretable scientific machine learning approach capable of producing continuous thermal estimates, prospect probabilities, confidence bounds, mechanistic insights, and a transferable analytical screening relationship for regional geothermal exploration.

Topic: Emerging Technology

[Horne]

Introduction to the 52nd Stanford Geothermal Workshop Roland HORNE [Stanford University, USA]

An introduction to the 52nd Stanford Geothermal Workshop.

Topic: Introduction

[Horne1]

Test Paper: A Grand New Concept in Geothermal Roland HORNE, Bob JONES and ZHANG Ziyi [Stanford University, USA]

The deeply hidden fires of the earth Provide a constant source of power and heat, A steady force of planetary worth, Where strength and clean utility will meet. No fickle wind or shifting cloud restrains This steady energy from deep below, A constant current through the metal veins, Where endless streams of boiling waters flow.

Topic: Reservoir Engineering

Supercritical geothermal energy has long been regarded as one of the most promising pathways to transformational renewable power generation; however, despite more than four decades of international drilling efforts, sustained commercial production from confirmed supercritical reservoirs has not yet been achieved. This paper presents the first comprehensive engineering-framework post-mortem analysis of supercritical geothermal wells (T greater than 374°C and/or P greater than 221 bar) drilled worldwide between 1981 and 2026. The dataset comprises 20 entries across six countries-Iceland, Japan, Italy, the United States, Mexico, and Kenya-evaluated using a consistent seven-category failure mode taxonomy (FM-1 to FM-7), including one aggregated entry representing five Los Humeros wellbores with an identical failure profile. For each well, failure mechanisms are systematically examined through quantified operational parameters, root-cause determination, and cross-well pattern analysis to identify recurring engineering limitations. Moving beyond retrospective assessment, the paper proposes four original candidate engineering frameworks intended for independent review and validation by the wider geothermal community: (1) a Deterministic Failure Chain (DFC) describing progressive failure evolution across all basin types; (2) an Axial Compliance Framework (ACF) integrating five coupled thermomechanical mechanisms with the Norton Power Law and Larson-Miller creep rupture criterion to quantify structural survivability; (3) a dual-constraint Thermo-Mechanical and Chemical Survivability Envelope (DCSE) defining simultaneous operating limits for long-term well integrity; and (4) a Basin Risk Index (BRI) providing a structured predictive methodology for assessing technical risk during future supercritical geothermal well planning.

Topic: General

The mid-to-deep single-well closed-loop geothermal system (CLGS) is considered an important pathway for efficient geothermal energy exploitation. However, under long-distance circulation conditions, significant hydraulic pressure losses in the wellbore result in excessive pumping power consumption, which limits the overall efficiency of the system. Existing studies mainly focus on wellbore structure and heat transfer parameter optimization, while the coupling between working-fluid rheology and deep-well hydraulic losses has not been systematically quantified. This study proposes a non-Newtonian fluid-based drag reduction strategy for geothermal wellbores. The objective is to investigate whether polymer additives can effectively reduce circulation resistance and identify optimal operating conditions for non-Newtonian fluids through multi-parameter optimization, thereby reducing pumping energy consumption. An integrated framework combining experimental characterization, numerical simulation, and optimization is developed. Polymer materials including Hydrolyzed Polyacrylamide (HPAM), Xanthan Gum (XG), Polyethylene Oxide (PEO), and Welan Gum (WG) are used to modify conventional water-based working fluids. Rheological properties are characterized through power-law parameters measured under different concentrations and temperatures. A thermo-hydraulic coupled model of a single-well CLGS is established to simulate heat transfer and pressure loss under deep geothermal conditions. Furthermore, a genetic algorithm (GA) is applied to optimize operating parameters, including circulation flow rate, well depth, and geothermal gradient. Compared with conventional water, non-Newtonian polymer fluids at specific concentrations demonstrate significant drag reduction performance in deep well circulation, with wellbore pressure losses reduced by 63%–75%. The GA optimization identifies optimal operating parameter combinations under different geothermal gradients, further improving the drag reduction performance of various non-Newtonian fluids. The study provides a new fluid regulation strategy for CLGS design and offers theoretical insights and engineering guidance for achieving low-pumping-power and high-efficiency development of mid-to-deep geothermal resources.

Topic: Modeling

Acidic fluids in high-temperature geothermal systems create reservoir and well integrity management challenges beyond corrosion control, because acidity can influence reservoir performance, reinjection strategy, well integrity, and long-term production sustainability. Although many field experiences exist, lessons are often separated between geochemistry, reservoir engineering, and well materials studies, which limit their transfer across projects. This paper synthesizes reservoir and well integrity management lessons from geothermal systems where acidic fluids have affected field development and operation. A comparative review used three field case studies: Rotokawa (New Zealand), Los Humeros (Mexico), and Krafla (Iceland). Published conceptual models, geochemistry and alteration studies, reinjection histories, reservoir monitoring data, and well integrity reports were evaluated to compare acid-fluid origins, operational impacts, mitigation responses, and decision trade-offs. Firstly, the review indicates that acidic-fluid risks are strongly site-specific. At Rotokawa, CO2-rich steam-heated fluids and acid-sulfate conditions in an aquifer above the deep reservoir contributed to severe external casing corrosion in several wells. Early shallow reinjection appears to have helped resaturate and partly neutralize this corrosive aquifer by diluting or displacing acidic fluids and suppressing boiling, but this strategy also created ground uplifting concerns. Later management therefore shifted toward deeper and more peripheral reinjection, which improved pressure support, reduced shallow operational constraints, and helped limit direct cooling returns to the production sector. At Los Humeros, acidic conditions are linked to a complex superhot system involving boiling, phase separation, steam condensation, advanced argillic alteration, meteoric recharge, and possible magmatic contribution. Alteration zoning and surface CO2 monitoring indicate active fluid pathways and reservoir response, showing the value of combining geochemistry, structural interpretation, and reinjection surveillance. At Krafla, IDDP-1 demonstrated the large energy potential of HCl- and HF-bearing superheated steam, but also revealed severe operational limits from acid condensate, silica scaling, casing failure, and high-temperature material degradation. These cases show that acidic geothermal systems should be managed as coupled reservoir and well integrity problems, rather than merely surface facility problems. Effective reservoir and well integrity management requires site-specific fluid characterization, adaptive reinjection planning, corrosion-aware well design, and continuous monitoring from early field development through long-term operation under evolving reservoir and production conditions.

Topic: Reservoir Engineering

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 the Basin and Range province, high-permeability faults linked to deep crystalline basement rocks facilitate upward circulation of hot fluids, yielding gradients far exceeding background levels. GPFA's data-driven approach 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, applying Adaptive Heat Flow/Temperature 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 variable heat flow, thermal conductivity, radiogenic heat production, temperature dependent thermal conductivity 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.

Topic: Enhanced Geothermal Systems

Drilling long inclined/horizontal wells in hard, crystalline rock remains one of the principal economic barriers to next-generation geothermal systems. Downhole Drive Unit (DDU) addresses these chalenges directly – modular, stackable downhole units grip the formation and apply thrust and torque at the bit itself, independent of drillstring weight, under closed-loop control electronics capable of modulating WOB with high frequency. DDU has now completed three sequential field-test phases in 2026 at the NORCE Ullrigg Research and Test Centre in Stavanger, Norway, demonstrating that hydraulically gripping the borehole wall to react weight-on-bit (WOB) and torque directly into the formation is a viable route to overcoming the two dominant barriers to economic hard-rock geothermal drilling: insufficient, poorly controlled WOB delivered through a long, compliant drillstring, and torsional stick-slip dysfunction that caps achievable rate of penetration (ROP). Across the programme, the system delivered up to 32,000 lbf of controlled downhole thrust while the drillstring above continued to rotate, drilled hard Phyllite and operated also in oversized and irregular borehole geometry. The Ullrigg programme progressed from single-unit gripping and drive validation through synchronised dual-unit drilling towards drilling with downhole motor. A phase planned for October 2026, will run a direct side-by-side with and without the system in harder and deeper formation to isolate the performance uplift attributable to the technology, with results available ahead of the workshop. These results speak directly to the drilling economics that constrain deep and enhanced geothermal development. The paper presents the full 2026 Ullrigg field validation dataset, the engineering challenges encountered and resolved between phases, and the outlook for commercial deployment as an enabling technology for cost-effective drilling of deep, hot, hard-rock geothermal wells.

Topic: Drilling

Geothermal Arrays -- networks of large numbers of standard geothermal wells -- open up many opportunities for scaling up clean, cheap, safe, reliable, and abundant baseload electricity.

Topic: Modeling

The present paper is a comprehensive review on induced seismicity in Enhanced Geothermal Systems (EGS) as well as on the related processes. It furthermore describes the monitoring of an injection area for seismic activities and outlines different options for seismic hazard prediction and mitigation in order to handle the risks. An integrated descrption of the mechanisms of induced seismicity (pore pressure increase and thermal stress) and of the criteria for fault reactivation. The monitoring of microearthquakes in the area of injection. The last advances of machine-learning methods for the improvement of the short-term seismic hazard forecast and for the real-time seismic-risk management (so-called “traffic-light control”) of geothermal operations. Results, Observations, Conclusions. Increasing both pore pressure and thermal stress can cause reactivation of faults leading to earthquakes. The related increase in seismic hazard can be managed with an appropriate injection strategy. Short-term seismic hazard forecasts can be improved with the aid of machine learning. However, their accuracy strongly depends on the corresponding monitoring density. This Review provides a fully integrated view of induced seismicity and of associated seismic hazard, for EGS, including management. It also briefly outlines the recent approaches, using machine-learning, of short-term and of real-time seismic hazard and of seismic risk monitoring and management for geothermal projects, and for their on-line real-time on-line seismic risk management (traffic-light control).

Topic: Enhanced Geothermal Systems

This review is intended to give a status report to the field of tracer testing for reservoir characterization of geothermal wells. The main issues are identification of the flow paths, determination of swept-volume and of thermal-breakthrough and the use of machine-learning for improved interpretation of the obtained tracer profiles. We review conservative and reactive tracers as well as flow-path and swept-volume assessment, thermal breakthrough prediction and most recently machine-learning enhanced interpretation of a tracer return to improve our analysis of the connectivity and heat-life of a geothermal reservoir. Tracer testing as a dynamic characterization tool going beyond static models in order to better constrain inter-well-connections as well as thermal breakthrough. In addition, machine learning can be used to improve the interpretation of complex return signals of tracers. But also tracer testing has its limitations. Non-uniqueness of results cannot be solved by tracer testing itself. Additional data is required. the review is of the view that tracer testing is a form of dynamic characterization that can be added to static models, and Machine Learning can be used to interpret the tracer returns in terms of reservoir connectivity and heat lives.

Topic: Tracers

In this review we critically review recent advances of machine-learning in geothermal resource exploration and reservoir management, and assess their current stage of development for favorability, property estimation as well as for process optimization. The review covers supervised learning for favorability and property prediction as well as physics-constrained and hybrid modeling for optimization. The review discriminates between points regarding data-scarcity, validation and transferability to other applications. Data-driven exploration targeting and property prediction for geothermal fields can be supported with ML approaches. However, due to data-scarcity, results are sensitive to the degree of site-specific data incorporation and the corresponding disciplinary validation scope. Results also have limited transferability between sites. A Maturity map for tasks within geothermal applications is presented and it is argued that, in a data-scarce domain such as geothermal resources, the key to durable value from ML is the extent of physics constraints and disciplined validation, rather than the specific ML model used. A maturity map is developed for the application of machine learning in geothermal exploration and reservoir management. The value of machine learning models in geothermal is largely determined by the degree to which they are embedded in physical models and are subject to rigorous validation as opposed to specific model choices.

Topic: Enhanced Geothermal Systems

During exploration drilling campaigns, early predictions of reservoir temperature can improve targeting decisions and help to optimize dynamic campaign decisions. Fully stabilized downhole temperature measurements require months of waiting, but data while drilling, such as from maximum registering thermometers (MRTs), and from early-heat up surveys can be used mid-campaign. Corrections which are proposed based on a systematic review of dozens of drilling examples which can use early data to reliably predict the true reservoir temperature. These methods are particularly critical in small-diameter wells which cannot be reliably flowed. If a flow test is possible, temperatures from flow tests can also provide a highly reliable predicton of reservoir temperature in permeable zones, with appropriate correction.

Topic: Reservoir Engineering

Carbonate-hosted geothermal reservoirs can generate and release CO2 through coupled brine-CO2-rock reactions, particularly where calcite dissolves under high-pressure and high-temperature conditions. These reactions simultaneously govern scaling tendency, corrosion risk, permeability evolution, pore structure, and mechanical response, making CO2-equivalent generation an integrated reservoir problem rather than a purely geochemical one. This study develops new chemical treatments for reducing CO2 emissions from carbonate geothermal systems. Multiple chemical treatments were explored, including the injection of silica additives (silica fume, silica flour) and chelating-agent pre-flushes (EDTA, GLDA), using Red Sea water (RSW) and CO2-rich RSW as base main fluids. This work combined static chemical screening, HPHT disk aging at 70°C, and staged core flooding in dry carbonate cores (10 in length and 1.5 in diameter) at 100°C, 2000 psi confining pressure, 1500 psi backpressure, and 0.5 cm³/min injection flow rate. Phase 1 injected RSW baseline, a chemical slug, and an RSW post-flush; Phase 2 repeated this sequence using CO2-rich RSW as the baseline and post-flush fluid. Effluent was analyzed by ion chromatography and total inorganic carbon (TIC), with CO2-equivalent generation cross-checked against Ca2+/Mg2+ stoichiometry. Pre- and post-flood CT imaging, porosity, pore volume, dry mass, and dynamic elastic properties linked fluid chemistry to rock alteration, while outlet-temperature records were interpreted using local thermal equilibrium (LTE) and non-equilibrium (LTNE) models. Silica fume and silica flour emerged as the most effective mitigation additives. In HPHT screening, 0.1wt% silica fluids did not increase Ca2+/Mg2+ release relative to the base case and maintained near-neutral pH, whereas EDTA produced the strongest carbonate attack. In Phase 1 core flooding, 0.1wt% silica fume lowered cumulative TIC-based CO2-equivalent from 105.20 mg (RSW baseline) to 50.10 mg during the additive stage and 28.13 mg during post-flush; silica flour likewise sustained low CO2-equivalent output. In Phase 2, under CO2-rich RSW, 0.1wt% silica fume reduced the cumulative CO2-equivalent from 357.51 mg to 129.69 mg, and 0.1wt% silica flour reduced it from 248.42 mg to 109.65 mg. By contrast, 5wt% EDTA increased CO2-equivalent from 221.60 mg to 783.33 mg, confirming its role as an active carbonate-dissolving pre-flush rather than a suppressant, while 5wt% GLDA reduced CO2-equivalent from 399.57 mg to 279.30 mg but showed complexation-affected free-ion behavior. Post-flood CT and petrophysical data indicated only limited alteration and no severe sustained plugging across the silica runs, and LTE and LTNE models produced nearly identical outlet-temperature predictions, supporting LTE as an adequate outlet-scale descrption. The obtained results show that CO2-equivalent generation in calcite-dominated geothermal core floods is controlled by the combined effects of CO2-rich brine, carbonate dissolution, sulfate-related ion partitioning, chemical speciation, and thermal stabilization. Silica fume and silica flour reduce net inorganic-carbon release without causing severe flow impairment, while EDTA should be used only cautiously as a short pre-flush requiring metal complexation, and GLDA occupies an intermediate position requiring joint interpretation of TIC, pressure response, and rock-property change. The findings support a reservoir-centered chemical-selection framework for carbonate geothermal systems that weighs scale control against CO2-equivalent generation, injectivity, and rock integrity.

Topic: Reservoir Engineering

Geothermal energy systems generates significant volumes of geothermal brines enriched with dissolved minerals and metals as a by product of power production. These high temperature, saline fluids represent both environmental management challenge and an untapped resource. Properly managed Geothermal brines can support sustainable energy generation while enabling resource recovery, reducing waste and improving overall technoecomic viability of geothermal operations.Thus large volumes of geothermal brines are enriched with dissolved metals and nutrients, creating extreme physiochemical environments characterised by high temperature, salinity and pH. These conditions support extremophylic microorganisms capable of metal tolerance, transformation and bioaccumulation. Harnessing extremophile-driven processes in combination with phytomining approaches, offers a sustainable pathway for recovering valuable and critical metals such as li thium (Li), cesium (Cs), rubidium (Rb), strontium (Sr), manganese (Mn), zinc (Zn), copper (Cu), and i ron (Fe), along with rare earth elements (REEs) present in trace concentrations from Geothermal brines while mitigating environmental impacts.These metals represent a strategic resource for energy storage, electronics, and clean technologies, making geothermal brines an attractive target for bio-based recovery.Overall, extremophile-driven phytomining aligns strongly with circular economy principles and represents a low-carbon pathway for critical metal recovery in future geothermal resource management Keywords: Geothermal energy , Geothermal brines, Phytomining, Extremophile,Sustainable energy resource, Sustainable energy.

Topic: Geochemistry

The Salton Sea Geothermal Field (SSGF) is characterized by high-temperature, high-salinity brines, a stratified reservoir system with a low-salinity cap above a hypersaline zone, and complex thermodynamic and geochemical behavior. This study presents the development and calibration of a numerical reservoir model focused on the Hudson Ranch area, with the goal of validating prior conceptual and geochemical interpretations (including double-diffusive convection models) through numerical simulation. The model aims to capture the natural-state behavior of the system and provide a framework to evaluate long-term changes associated with both geothermal energy production and critical mineral extraction using new commercial numerical modeling software (Volsung). In recent years, growing interest in lithium and other critical mineral recovery from geothermal brines has emphasized the need to understand how post-extraction reinjection alters reservoir chemistry, pressure, and temperature. This model incorporates mineral depletion and fluid re-equilibration mechanisms to assess the potential reservoir impacts of large-scale lithium extraction. The work supports future feasibility studies by quantifying the thermodynamic and chemical evolution of the system under dual-use scenarios of power generation and mineral recovery. This model provides critical insights for sustainable co-production of energy and minerals from hypersaline geothermal systems.

Topic: Modeling

Underground coal fires (UCFs) represent a severe global environmental and economic challenge, characterized by prolonged combustion, significant greenhouse gas emissions, and substantial coal resource loss. Traditional mitigation methods—such as excavation, inertization, and sealing—often prove inadequate for deep or complex fires and fail to utilize the vast waste heat generated. This review explores the emerging integration of thermoelectric generation (TEG) technology as a sustainable strategy for both controlling UCFs and recovering energy. TEG systems convert waste heat directly into electricity via the Seebeck effect, offering a dual benefit of fire mitigation and power generation. The paper systematically reviews UCF mechanisms, detection techniques, and conventional control strategies before detailing the principles, experimental progress, and field demonstrations of TEG applications in coalfields. Despite promising results from pilot studies—such as field trials in Xinjiang, China—current power outputs remain limited, with laboratory and field systems achieving up to 6.42 W and ~960 W per borehole, respectively. Key challenges include material efficiency, system scalability, and heat extraction optimization. Future prospects hinge on advancing thermoelectric materials, enhancing heat transfer systems, integrating TEG with improved long-term reliability. By transforming UCFs from an environmental liability into an energy asset, TEG technology holds significant potential for sustainable coalfield management and global renewable energy transitions.

Topic: Emerging Technology

Repurposing existing oil and gas infrastructure for geothermal and waste-heat power generation offers a low-capital pathway to expand domestic clean energy production, but it introduces a distinct engineering challenge: operators must remotely monitor and control heat-to-power assets that vary widely in source type, mechanical configuration, and geographic location, often without the benefit of a purpose-built, single-site power plant's centralized instrumentation. This paper presents a unified, vendor-certified SCADA and remote operations architecture developed to address this challenge, and reports field results from its deployment across three structurally different heat-to-power source types. The architecture is built on a Unified Namespace using MQTT Sparkplug B, standardizing data flow and enabling centralized data governance across more than 100,000 monitored points spanning geographically distributed sites. A centralized Unified Control Layer integrates heterogeneous power generation equipment through OPC UA and multi-vendor programmable logic controller connectivity, providing real-time telemetry, alarming, and operator interfaces from a single platform regardless of underlying hardware or physical location. This architecture underlies three deployed projects representing distinct heat-to-power source types. First, a project supported by the U.S. Department of Energy Geothermal Technologies Office, part of the Wells of Opportunity initiative, applies the platform to generate electricity from repurposed oil and gas wells in California San Joaquin Valley, demonstrating the architecture applicability to geothermal energy recovery from existing wellbore infrastructure. Second, a waste heat to power deployment at a natural gas compressor station in Dry Ridge, West Virginia, in partnership with CNX Resources, generates approximately 0.5 MW of zero emission power from compressor exhaust heat, reducing an estimated 1,325 metric tons of CO2 emissions in its initial phase, with a scaling pathway toward approximately 4,000 metric tons of annual reduction. Third, an industrial waste heat to power system at a seafood processing facility in Dutch Harbor, Alaska, operated in partnership with UniSea Inc, generated 67 MWh of electricity during a three week startup phase alone, representing approximately 5,000 gallons of displaced diesel fuel, and now displaces an estimated 3,500 gallons of diesel per week at full operation in a remote, off grid environment. Across all three deployments, the same underlying control architecture supported integration, monitoring, and remote operation without site specific rearchitecting, demonstrating that a standardized, vendor certified SCADA and namespace approach can generalize across geothermal wellbore heat, oilfield adjacent compressor waste heat, and industrial process waste heat. This paper details the technical architecture, integration methodology, and field validated outcomes, and discusses implications for scaling remote heat to power operations across additional repurposed oil and gas assets and off grid or resource constrained sites nationally.

Topic: Emerging Technology

Low-temperature geothermal resources are widely used for heating in Iceland and are more geographically accessible than high-temperature fields, but their low enthalpy limits their suitability for electricity generation. At the same time, Iceland continues to export non-recyclable municipal solid waste (MSW), creating interest in waste-to-energy (WtE) as both a domestic waste-treatment pathway and a stable external heat source. This study evaluates whether externally supplied WtE heat can enhance electricity generation from low-temperature geothermal systems and how the location of heat addition shapes thermodynamic and economic performance. The analysis applies steady-state first- and second-law principles to a baseline single-flash steam (SFS) geothermal plant and two hybrid SFS configurations. In the first hybrid configuration, WtE heat is added to the geothermal brine upstream of the flash separator. In the second, WtE heat is added to the separated steam at the turbine inlet. These integration strategies influence performance in fundamentally different ways: brine-side heating primarily increases steam production, whereas turbine-inlet heating primarily increases the work extracted per unit of steam. The results show that upstream brine heating provides the greatest thermodynamic improvement among the principal SFS cases because it increases the mass of steam available for expansion. However, the economic interpretation is more constrained: improved thermodynamic performance does not necessarily translate into lower Levelized Cost of Electricity (LCOE) when WtE heat is treated as a purchased external input. At the assumed heat price of 15 EUR/MWhth, the cost of external heat becomes the dominant factor governing comparative economic viability. Overall, the analysis demonstrates that geothermal–WtE hybridization can improve electricity generation from low-temperature geothermal resources, but its practical value depends on both the thermodynamic consequences of the chosen integration pathway and the economic cost of external heat.

Topic: Enhanced Geothermal Systems

The development of the geothermal reservoirs involves the processes of heat transfer, fluid flow, rock deformation, and chemical reactions. This review explores the thermo‑hydro‑mechanical‑chemical (THMC) modeling as a way to capture those couplings and assess their impact on injectivity, temperature, scaling, deformation, and reservoir life. Field observations at Soultz‑sous‑Forêts highlight the importance of fracture‑controlled flow and mineral deposition, while the lessons learned from Groß Schönebeck demonstrate that how machine‑learning surrogates could make complex THMC simulations practical for uncertainty analysis and operational planning. AI tools, such as reduced‑order models, neural operators, and physics‑informed network, extend the reach of high‑fidelity simulations, enabling rapid forecasts, sensitivity studies, and digital twins. These surrogates should complement, not replace, process‑based models, with conservation checks and validation that are essential for safe and long‑term use. Together, this integrated workflow makes coupled geothermal modeling more feasible to predict the reservoir performance, sustain the reservoir injectivity, manage the scaling, and safeguard the integrity under complicated subsurface uncertainties.

Topic: Modeling

It is almost universal in geothermal well cements to include silica in some form, coupled with Class G (dedicated oil-well) cement. The use of silica is to prevent cement strength retrogression at elevated temperatures, and Class G because it is intended for well construction. This design requirement seems be one of the untouchable 'sacred cows' of the industry. The question of 'how strong does the cement actually need to be?' seems to have been largely overlooked. This paper presents calculations and assessments to determine the minimum acceptable cement strengths for geothermal casing cement. It comes to two conclusions - different strengths are required in different parts of the well and, for the vast majority of the cemented sections, the required strength is almost ludicrously low. The learnings from this assessment leads to a new conceptualisation of the role and design requirements of cement in geothermal well construction. This perspective can help future projects to reduce costs and eliminate un-needed logistical issues with no discernible detriment to well quality.

Topic: Drilling

The Tecuamburro–Infiernitos geothermal system combines, a high enthalpy resource with a shallow natural steam cap beneath a low-permeability clay cap, and an adjacent medium enthalpy system requiring artificial lift for a substantial fraction of its wells. Realistic resource assessment (RA) under uncertainty for this combined system depends on two capabilities not covered by standard tools: a reservoir simulator equation of state (EOS) that handles simultaneous CO2 and air non-condensible gas (NCG) species with salt at production-relevant temperatures, and a well-deliverability model that accounts for pump-limited, rather than purely wellhead-pressure-limited, production. For the first, we developed wsace, a custom water–salt–CO2 –air EOS for the Waiwera open-source geothermal simulator. Waiwera’s existing multi-component EOS family covers water+salt+CO2 and water+salt+air separately, via subclasses of a shared water+salt+single-NCG base implementation; neither the base class nor its subclasses support two simultaneous NCG species, which both Tecuamburro/Infiernitos and other target systems (e.g. high-salinity, high-temperature reservoirs such as Salton Sea) require. wsace extends Waiwera’s phase-transition and primary-variable framework to two independent NCG partial pressures. This custom eos allows to model a more realistic atmosphere in which the the CO2 partial pressure ≈ 40 Pa and Air partial pressure ≈ 99 KPa. Validated against a real production-scale Tecuamburro RA case. Reservoir fluid chemistry is further characterized by post-processing Waiwera’s simulated pressure/temperature/composition fields through PHREEQC (Pitzer database, appropriate for high-salinity, high-temperature brine), yielding detailed aqueous speciation at each grid block for water-chemistry evaluation of special important in the natural state calibration. For the second, RA well selection for Infiernitos now uses a two-tier pump-aware deliverability model: a closed-form screening calculation (referenced against pump intake pressure and simulated CO2 partial pressure, rather than surface wellhead pressure) evaluates every candidate block cheaply during the search, and a full pump-curve sizing algorithm combined with a NPSH/gas-breakout-pressure check runs once a well is actually selected, creating a delv type source with a scalar sink pressure instead of an enthalpy table. This replaces a simplified post-hoc power correction with per-well, physically grounded net power reporting and lets the well-selection algorithm itself account for pump feasibility rather than assuming natural flow. Together, these developments let uncertainty-quantified natural-state ensembles propagate through resource assessment for both resources – staged or simultaneously interleaved – with numerically robust multi-phase, multi-NCG chemistry and realistic artificial-lift approach that provides a probabilistic range of power production scenarios for both systems under a sustainable development scheme.

Topic: Modeling

This review focuses on Enhanced Geothermal Systems (EGS) in low-permeability rock, with respect to four areas: (1) stimulating to create engineered permeability for improved reservoir connectivity, (2) fluid circulation for heat extraction and control of hydraulic and thermal short-circuiting, (3) design levers for sustaining a long-term reservoir performance, and (4) techno-economic factors governing the commercial viability. Across these topics, the review brings together research on stimulation methods, fracture creation, coupled thermal–hydraulic modeling, circulation strategies, approaches for limiting hydraulic or thermal bypassing, and the growing use of machine‑learning tools to design and forecast. The economic discussion highlights the parameters that most strongly shape the project outcomes—drilling and completion costs, stimulation requirements, achievable flow rates, produced‑fluid temperatures, thermal decline behavior, reservoir impedance, plant efficiency, operational lifetime, and the financial uncertainties that accompany subsurface development. Long‑term heat extraction depends on establishing a broad, well‑connected network of flow paths that provides sufficient surface area for heat transfer without allowing rapid short‑circuiting or premature cooling. Because the fracture network is created under a specific stress environment and cannot be corrected later, early design choices have lasting consequences for reservoir performance. Economic viability is also tied to subsurface behavior. Higher flow rates and hotter produced fluids generally improve the power generation and lower the levelized cost of energy. However, issues such as high impedance, steep thermal decline, water losses, ineffective stimulation, or elevated drilling costs can challenge a project. Any realistic evaluation must therefore link reservoir performance to capital and operating costs, project duration, financing assumptions, and the uncertainties in long‑term geothermal development. The review concludes by outlining an integrated design framework that covers reservoir creation, circulation management, AI‑supported optimization, and techno‑economic analysis. It emphasizes the role of machine learning to improve the stimulation design, forecast the hydraulic and thermal behavior, identify the emerging short‑circuiting pathways, update the reservoir models with field data, and guide the design choices that would technically and economically resilient under various subsurface uncertainties.

Topic: Enhanced Geothermal Systems

EGS-based geothermal development offers unique solutions to certain challenges facing data center developers in the western US. Data center development is locationally-constrained by existing or planned fiber communication pathways and existing or planned high-voltage grid connections. These two constraints are presenting speed-to-power timeline issues and overall energy supply uncertainty. This two-pronged uncertainty on interconnection actually adds to data center permitting risk, when the public asks for such details in sensitive county meetings, and the developer is unable to clearly articulate on those matters. As a fuel-less and low surface footprint powerplant, EGS geothermal offers data centers solutions to these problems which cannot be matched by classic renewables powerplants (solar, solar) nor modern thermal powerplants (nuclear, gas). Solutions include: a reusable bridge-to-interconnection power supply, no added combustion air emissions permitting risk, and the ability to show the public that the price of new powerplants are being carried by the data center, not utility ratepayers. This paper will dwell on the northern portion of the western states, with Idaho (via Idaho Power Company service area) used specifically as an example.

Topic: Enhanced Geothermal Systems

Recent Play Fairway Analyses of Idahos Snake River Plain produced hydrothermal-based geothermal development heatmaps of attractiveness, built from multi-tiered and expert-weighted data layers associated with heat source, reservoir permeability, and reservoir seal. This hydrothermal geothermal PFA approach was adapted from proven oil & gas PFA philosophies in shale. Our paper presents initial results of producing an EGS geothermal PFA heatmap in Idaho. This is accomplished by re-wiring and inverting certain data layers in the prior PFA work, to better incorporate play conditions for modern EGS project development.

Topic: Enhanced Geothermal Systems