Stanford Geothermal WorkshopFebruary 8-10, 2027

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

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

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

[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

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

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

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

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

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

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

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