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

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

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

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

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 gaining attention not only as an emission abatement option, but also as a reservoir management strategy. However, guidance for geothermal NCG reinjection design remains less established than petroleum acid gas injection (AGI) practice, particularly for defining operating envelopes that balance containment, injectivity, corrosion control, and production well breakthrough risks. This paper synthesizes transferable lessons from petroleum AGI for geothermal NCG reinjection using four representative cases: Zama Field and Brazeau Nisku Q in Alberta (Canada), Ngā Tamariki (New Zealand), and Hellisheiði/CarbFix2 (Iceland). These cases were selected because they cover the main operating situations relevant to CO2-H2S reinjection: sour-gas disposal and geochemical trapping in petroleum reservoirs, as well as brine-dissolved NCG reinjection and mineral trapping in geothermal fields. Published field experience, reservoir studies, geochemical analyses, and operational reports were reviewed to compare injection objectives, pressure-temperature-composition control, fluid-phase management, reservoir response, well integrity, monitoring practice, and operational constraints. The comparison shows that petroleum AGI provides design discipline for geothermal NCG reinjection, but not a direct template. Zama 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 reservoir performance feedback. Hellisheiði/CarbFix2 demonstrates dissolved CO2-H2S injection into basalt, where rapid mineralization can provide durable storage under favorable host-rock conditions. A key divergence is moisture treatment strategy: petroleum AGI commonly uses dehydration to limit hydrate formation and free-phase corrosion, whereas geothermal reinjection often uses brine or condensate as a carrier fluid to suppress free-gas migration, while introducing acidity, scaling, and injectivity challenges. The study proposes a preliminary design-envelope framework in which petroleum AGI principles are adapted through geothermal-specific constraints on gas solubility and breakout, brine chemistry, well integrity, reservoir connectivity, and 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

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