Geothermal Drilling: How Oil & Gas Expertise Is Unlocking the Earth's Heat

For most of my career, geothermal was a niche topic at drilling industry conferences — interesting in theory, limited in commercial scale, and generally seen as the domain of volcanically active regions like Iceland, the Philippines, or parts of East Africa. That perception is changing rapidly, and the change is being driven in large part by the transfer of oil and gas drilling expertise into the geothermal sector.

The convergence makes intuitive sense. Oil and gas operators have spent decades developing the tools, techniques, and institutional knowledge required to drill deep, high-pressure, high-temperature wells in complex geology. Geothermal development requires exactly those capabilities — often in more demanding conditions than conventional hydrocarbon wells.

"Enhanced geothermal systems represent a fundamentally different opportunity from conventional geothermal. Done right, they could provide dispatchable baseload power from almost any location with sufficient crustal heat. The drilling challenge is the unlock."

The Technology Transfer Opportunity

The most significant developments in geothermal drilling are happening in enhanced geothermal systems (EGS) and closed-loop geothermal configurations. EGS involves drilling into hot dry rock, creating or stimulating a fracture network, and circulating working fluid through the rock to extract heat. This is not fundamentally different from what hydraulic fracturing operations do in tight formations — the physics of induced fracturing, fluid flow in fractured rock, and wellbore heat transfer are directly applicable.

Directional drilling expertise from oil and gas is enabling multi-lateral geothermal well architectures that dramatically improve heat extraction efficiency. Advanced PDC bits and drilling optimization techniques from shale plays are being adapted to address the exceptionally hard rock typically encountered in geothermal formations. High-temperature MWD and LWD tools, developed for challenging HPHT wells in oil and gas, are now being deployed in geothermal wells where downhole temperatures routinely exceed 200°C.

The Drilling Challenges That Remain Distinctive

While the skills transfer well, geothermal drilling presents specific challenges the oil and gas industry is still working through:

Rock hardness: Granite and other basement rocks are significantly harder than most sedimentary formations. ROP is slow, bit wear is accelerated, and optimizing the drilling program requires adapting parameters tuned for softer formations.

Temperature effects: At temperatures sometimes exceeding 300°C, elastomers in downhole tools degrade, electronics approach operational limits, and drilling fluid formulations require careful design.

Lost circulation: Highly fractured crystalline rock creates severe lost circulation zones difficult to address with conventional LCM materials. Cementing in these conditions requires adapted approaches.

Well completion: Geothermal completions require thermal management across the full well lifecycle, introducing engineering constraints that differ materially from hydrocarbon well design.

The Fervo Energy Model

One of the most watched EGS projects is Fervo Energy's development in Utah and Nevada, which has demonstrated commercially relevant power production using horizontal drilling and multi-stage stimulation adapted directly from oil and gas shale plays. Their collaboration with Google to supply geothermal power to the grid represents a milestone in proving commercial viability.

Fervo's success has attracted significant capital and competitive interest. Baker Hughes and SLB are now actively developing geothermal-specific service lines, recognizing that the technical overlap with their core competencies is substantial.

The Policy and Economics Context

Geothermal has historically struggled with high upfront drilling costs relative to other renewables, despite a significant advantage in capacity factor — plants typically run at 80–90% versus 25–35% for solar and wind. As drilling costs decline through technology improvement and learning curve effects, the economics improve substantially.

U.S. federal support through the DOE's Enhanced Geothermal Shot initiative — targeting a 90% reduction in EGS costs by 2035 — combined with IRA geothermal tax credits, is creating a favorable policy environment for accelerated deployment.

Environmental Considerations and the Seismicity Question

No honest discussion of geothermal development — particularly EGS — is complete without addressing the environmental challenges the technology carries. These are real, they are not uniformly solved, and the industry's credibility depends on engaging with them directly rather than allowing critics to define the conversation.

Induced seismicity is the most significant and the most discussed. EGS relies on hydraulically fracturing hot dry rock — the same basic physics that governs stimulation in unconventional oil and gas. Two cases have defined the regulatory and public perception environment: a project in Basel, Switzerland was shut down in 2006 after stimulation triggered a 3.4 magnitude earthquake felt across the city; in Pohang, South Korea, a 5.5 magnitude earthquake in 2017 was linked to a nearby EGS project and caused significant structural damage. These incidents are not obscure footnotes — they are the reference points regulators and communities reach for when evaluating new EGS proposals. Responsible project development now requires detailed seismic hazard assessment before stimulation, real-time monitoring during operations, and traffic-light protocols that pause or halt operations when thresholds are approached. Fervo's projects in Utah and Nevada have operated under these frameworks, and the absence of significant seismic incidents there is meaningful data — but the risk requires active management, not dismissal.

Geothermal brine management presents a different set of challenges. Produced fluids frequently contain elevated concentrations of silica, heavy metals, boron, and in some systems mercury or arsenic. Surface handling requires containment systems to prevent groundwater contamination, and reinjection is standard practice in modern operations. Closed-loop configurations like the Eavor-Loop address brine management more cleanly by avoiding direct contact between the working fluid and the formation.

Hydrogen sulfide (H₂S) is commonly present in geothermal fluids and must be managed at the surface — toxic at elevated concentrations, detectable by smell at extremely low levels. Scrubbing systems are well-established but add capital cost and operational complexity.

Water consumption is a concern in arid regions where significant geothermal resources are located. Flash steam and dry steam plants consume water in cooling systems; EGS projects require water for the stimulation phase. Closed-loop systems offer a significant advantage, circulating a sealed working fluid without net water consumption after initial fill.

Geothermal is often described as a zero-emission energy source, and compared to fossil fuels the carbon intensity is dramatically lower — but it is not zero. Dissolved gases including CO₂ and methane are released at surface during production. The more precise and defensible claim is that geothermal is a low-carbon dispatchable baseload resource.

The oil and gas industry brings directly relevant experience to managing most of these challenges. Seismicity monitoring and traffic-light protocols are adapted from practices developed for wastewater injection and hydraulic fracturing. Produced water handling, H₂S management, and reinjection design are established competencies in upstream operations. This is one of the less-discussed dimensions of the technology transfer opportunity: it is not just the drilling skills that transfer, but the environmental and operational risk management frameworks as well.

Digital Intelligence as a Geothermal Force Multiplier

The digital transformation of drilling operations — real-time data acquisition, cloud-based analytics platforms, AI-assisted parameter advisory systems, and digital twin modeling — is as relevant to geothermal as it is to conventional oil and gas. In some respects it is more relevant, because the margin for error is narrower: wells are expensive, reservoir access is constrained, and the thermal resources are less forgiving than hydrocarbon accumulations where multiple production mechanisms exist.

Real-time monitoring is the most immediate application. Downhole temperature and pressure profiles, vibration signatures, torque and drag trends, and bit wear indicators are all recoverable in real time with modern MWD/LWD systems. In hard-rock geothermal drilling, where ROP is slow and tool failure is expensive, detecting problems early — an abnormal torque trend, a vibration signature indicating PDC bit damage — and adjusting before a costly failure occurs delivers exactly the same value as in HPHT oil and gas environments.

Digital twin modeling is gaining traction in EGS development because simulating how induced fracture networks develop and connect, how thermal drawdown evolves, and how changes to injection and production rates affect long-term performance requires models continuously updated against live operational data. Fervo, Quaise, and Eavor are all investing in real-time reservoir models updated dynamically as drilling and stimulation data are acquired.

AI-assisted drilling optimization applies directly in the hard-rock environment. Machine learning models trained on historical hard-rock drilling performance — capturing the relationship between WOB, RPM, flow rate, and ROP in specific lithologies — can outperform manual optimization, particularly for teams without deep hard-rock experience.

Remote operations capability creates disproportionate value in geothermal because many resources are in logistically challenging locations — high-altitude, seismically active, or far from established engineering talent pools. Real-time remote drilling supervision reduces the need for continuous on-site technical presence and makes experienced oversight economically viable for projects that could not otherwise afford it.

At WillCo, this is precisely where our digital drilling intelligence capability intersects with the geothermal opportunity. Whether the well targets hydrocarbons or heat, the value of connecting operational data streams to experienced engineering judgment is the same. As geothermal operators scale their programs and look to reduce drilling cost per well, digital intelligence is one of the clearest levers available.

WillCo's Perspective

I follow geothermal closely because it represents one of the clearest examples of how drilling engineering expertise generates value outside conventional oil and gas. The skills, tools, and methodologies we apply in hydrocarbon well construction are directly transferable — and in many ways the geothermal challenge is technically more demanding, which makes it interesting from an engineering standpoint. As the energy transition continues to create new demand for drilling expertise in non-traditional applications, this is an area where experienced drilling consultants can contribute meaningfully.

References

1. DOE Office of Energy Efficiency & Renewable Energy (2025). "Enhanced Geothermal Shot: Progress Report." U.S. Department of Energy.

2. Fervo Energy (2024). "Project Cape: Commercial EGS Results from the Utah FORGE-Adjacent Development." Fervo Energy Technical Report.

3. SPE-215690-MS. "Application of Oil and Gas Directional Drilling Technology to Enhanced Geothermal System Development." SPE, 2024.

4. MIT Energy Initiative (2024). "The Future of Geothermal Energy in the United States." MIT, Cambridge.

5. Baker Hughes (2025). "HPHT Technology Applications in Geothermal: Tools, Fluids, and Bit Design." Baker Hughes Technical Paper.

6. IEA (2025). "Geothermal Power Generation: Technology and Market Report." IEA, Paris.

7. Hart Energy (2025). "Drilling for Heat: Oil Field Know-How Supercharges Geothermal." Hart Energy Publishing.

8. Quaise Energy (2025). "Deep Geothermal Drilling with Directed Energy: Digital Monitoring and Control Requirements." Quaise Technical Report.

9. Eavor Technologies (2025). "Closed-Loop Geothermal Digital Twin: Real-Time Reservoir Simulation Results." Eavor White Paper.

10. SPE-217812-MS. "Machine Learning Applications for Drilling Optimization in Hard Rock Geothermal Formations." SPE, 2025.

11. Rocky Mountain Institute (2025). "Digital Infrastructure for Enhanced Geothermal Systems: Data, Analytics, and Remote Operations." RMI.

12. Majer, E. et al. (2012). "Induced Seismicity Associated with Enhanced Geothermal Systems." Geothermics, 43.

13. Grigoli, F. et al. (2018). "The November 2017 Mw 5.5 Pohang Earthquake: A Possible Case of Induced Seismicity in South Korea." Science, 360(6392).

14. U.S. Geological Survey (2024). "Induced Seismicity and Geothermal Energy Development." USGS Open-File Report.

15. IEA (2025). "Geothermal — Environmental and Social Impacts." IEA Technology Report.