Enhanced Geothermal Has A Flock Of Black Swans

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Despite being mostly underground, enhanced geothermal systems (EGS) are having a moment in the sun. At its core, EGS involves drilling deep into hot, solid rock formations, artificially creating permeability by fracturing the rock, and circulating fluids to harness and produce power from the Earth’s heat. Unlike conventional geothermal, which relies on naturally occurring reservoirs of hot water or steam, EGS actively creates its reservoirs, significantly expanding geographical potential for geothermal energy.

As a note, this is one in a series of articles on geothermal. The scope of the series is outlined in the introductory piece. If your interest area or concern isn’t reflected in the introductory piece, please leave a comment.

Interest in EGS has recently resurged due to its hypothetical ability to deliver firming, carbon-free energy, essential for comprehensive decarbonization alongside renewables like solar and wind. Additionally, EGS would be uniquely suited to power applications such as data centers requiring constant, stable electricity supplies, if constraints could be overcome. Proponents are also claiming it has the potential to retrofit existing thermal generation infrastructure, prolonging asset life and maximizing infrastructure investments. Achieving commercial viability, however, requires overcoming significant technical and economic hurdles, particularly related to deep drilling.

History & Case Studies

Historically, EGS development began notably in the 1970s with the pioneering Fenton Hill project in New Mexico. Operated by Los Alamos National Laboratory from 1974 to 1995, this early endeavor drilled wells to approximately 3 kilometers depth with reservoir temperatures near 200°C. Although it successfully demonstrated the feasibility of artificial reservoirs, challenges such as reservoir pressure maintenance, water losses, and consistent fluid circulation hindered commercial viability. Still, Fenton Hill’s extensive experimentation provided critical foundational knowledge informing subsequent global efforts.

Europe’s Soultz-sous-Forêts project in France, operational since the mid-1980s, represents a significant milestone in EGS history. Soultz drilled multiple wells up to 5 kilometers deep and achieved sustained electricity generation of around 1.7 MW by 2016. Its long operational history offered valuable insights into reservoir stimulation techniques, operational reliability, and seismic risk management, establishing critical best practices for ongoing and future projects.

Conversely, projects in Basel, Switzerland (2006), and Pohang, South Korea (2017), underscore significant risks associated with induced seismicity. Basel’s hydraulic stimulation activities at 5 kilometers depth resulted in a magnitude 3.4 earthquake, prompting public concern and eventual project termination. Similarly, the Pohang project, involving depths of approximately 4 kilometers, triggered a magnitude 5.5 earthquake, causing notable infrastructure damage and halting further EGS developments in the region. These examples highlight the critical importance of site selection, seismic monitoring, and cautious stimulation practices.

Technological advances over the past decade have revitalized EGS prospects, notably through directional drilling methods adapted from the oil and gas industry. For example, Fervo Energy’s “Project Red” in Nevada (2023) showcases notable advancements in EGS technology. Founded by former oil and gas engineers, Fervo Energy is leveraging techniques originally developed for shale gas extraction, adapting them for geothermal energy.

Project Red received significant backing from major investors, including Breakthrough Energy Ventures and Google, highlighting strong corporate and venture interest. The project used horizontal drilling techniques, paired with advanced multi-zone hydraulic fracturing and real-time fiber-optic sensing technology for precise reservoir monitoring. Challenges included managing high temperatures (around 191°C) and ensuring consistent flow rates and fracture connectivity. Despite these hurdles, Project Red successfully achieved sustained fluid circulation equivalent to approximately 3.5 MW of stable electrical generation. Moving forward, Fervo Energy aims to scale up its approach, further optimize reservoir management, and reduce costs, ultimately proving the commercial feasibility of large-scale EGS deployments.

Technical & Economic Challenges

Despite advancements, deep drilling for EGS remains technically and economically challenging. Typical EGS projects drill to depths of 4–7 kilometers, encountering rock temperatures frequently exceeding 250–350°C. These extreme conditions rapidly degrade critical equipment, such as polycrystalline diamond compact (PDC) bits, which typically lose hardness and durability at temperatures beyond 250°C. The result is frequent bit replacements, significantly increasing drilling time and operational costs. Alternatives include thermally stable diamond-impregnated bits and advanced ceramic or composite drill bit materials currently under research.

High temperatures also severely impact downhole electronics, essential for directional drilling, monitoring, and reservoir management. Traditional electronic systems fail quickly above approximately 175–200°C, necessitating costly protective measures like active cooling or the use of high-temperature-rated electronics and fiber-optic sensors capable of tolerating temperatures exceeding 250°C. Advances in high-temperature electronics and insulation technologies represent crucial areas of research to overcome these limitations.

Drilling operations at such depths also encounter immense pressures, increasing the risk of borehole instability and collapse. Pressure variations can destabilize the borehole, leading to expensive delays and additional casing and cementing requirements. Solutions involve sophisticated borehole stabilization techniques, specialized cement formulations, and casing materials engineered to withstand extreme temperature and pressure conditions. Altogether, these factors significantly elevate project risks and costs, with drilling typically constituting over half the total capital expenditure in EGS projects.

Electricity generation costs from EGS currently range from $0.10–$0.25 per kWh, relatively high compared to solar ($0.03–$0.06/kWh). Yet, substantial cost reductions could occur with improved drilling efficiency and by accessing hotter, deeper resources. At moderate temperatures (~200°C), a typical EGS project may require around 20–40 wells for a 100 MW installation. However, tapping into significantly hotter reservoirs (~400°C) can reduce this requirement, potentially achieving the same output with fewer than 5–10 wells due to higher energy extraction efficiency per well.

Fracking Economies Of Scale Won’t Exist

Shale oil development is a marvel of industrial efficiency. Operators drill multiple horizontal wells from a single pad, allowing them to share everything — roads, power, pipelines, water handling, and on-site storage. It’s the equivalent of building an apartment complex instead of a row of detached houses. Every well drilled from that pad gets cheaper because the fixed costs of infrastructure get spread thinner. A single road services the entire pad. A shared electrical substation powers multiple pumps. A central tank battery collects oil from half a dozen wells. The more wells on a pad, the lower the per-well cost. That’s why shale oil wells, despite long laterals and high-fracturing costs, could still be drilled and completed for $7–$10 million per well and maintain economic breakevens in the $40s per barrel historically. The magic is in the clustering.

EGS operate under fundamentally different constraints than shale oil and gas. Unlike shale wells, which can be tightly clustered on multi-well pads, EGS wells require significantly more spacing — often hundreds of meters to kilometers apart — to prevent thermal interference. If placed too closely, the reservoirs can deplete each other’s heat too quickly, reducing long-term energy output. This means that while some infrastructure can be shared, each EGS well often requires its own access roads, power connections, flowlines, and transmission infrastructure, making economies of scale more challenging compared to shale development. While research continues into optimizing well spacing and potential shared infrastructure models, EGS currently faces higher per-well development costs due to these spatial and logistical constraints.

Every single well is its own mini-project, and that is ruinously expensive. Instead of spreading infrastructure costs over multiple wells, EGS developers have to replicate those costs for every single well. Want to build a power line to your EGS well? Congratulations, you’re paying the full price for that line instead of splitting it across six wells. Need an access road? Same deal. Want to centralize O&M? Good luck. Your wells are scattered across kilometers of terrain, and your technicians are burning hours just getting from site to site.

Drilling costs are worse too. A typical shale oil well might reach 10,000 feet deep, but EGS wells often have to go 15,000 feet or deeper, into hotter, harder rock. That means longer drilling times, more expensive casing, and extreme wear on drill bits. While a Permian Basin shale well can be drilled and fracked for $7–$10 million, an EGS well could cost $15–$25 million—and that’s before you factor in the extra transmission and infrastructure costs that make every dollar go less far.

All of this adds up. Shale oil thrives because it turned drilling into a mass-production, factory-like operation where each new well gets cheaper. EGS, on the other hand, is stuck in a one-off, custom-built model, where every well demands its own infrastructure and expenses. Unless deep drilling costs fall dramatically and infrastructure-sharing innovations emerge, EGS will remain an expensive, high-risk gamble compared to the ruthlessly efficient shale model.

For context, this suggests the first of a kind Fervo site, whose capital and operational costs and costs per MWh haven’t been published yet, might be seeing $0.30-$0.40 per kWh electricity for its 3.5 MW solution after transmission and distribution is added in. Google can afford to pay that for a subset of its data center needs, but no one will be interested in paying that outside of one of demonstrations.

It’s mostly physics which causes these problems, not lack of trying, and in general when physics is the problem, there is no solution.

Black Swans Flock Around Enhanced Geothermal

Bent Flyvbjerg has spent decades warning us about long-tailed risks — those nasty, unpredictable cost explosions that take down entire megaprojects. His thesis is simple: the more complex and bespoke a project is, the more exposed it is to black swans. When you scale something through repetition and standardization — think offshore wind turbines or modular factories — you drive down risk. But when every site is its own special case, like nuclear reactors or high-speed rail, you invite financial catastrophe. This framework is a scalpel that neatly dissects the cost risks in shale oil versus EGS.

Shale oil thrives because it turns risk into a numbers game. Every well follows the same basic formula: drill down through top cover into not very hard shale, turn horizontal, fracture shale, produce oil. Sure, some wells underperform, some cost more than expected, but on a large enough scale, the surprises average out. Risks are local, limited, and recoverable. If a shale oil well collapses or encounters a bad formation, the operator moves 500 meters over and drills again. Even catastrophic failures, like a casing collapse or an unfracturable formation, are contained at the individual well level. Plus, shale development benefits from mass production learning curves. Every year, drillers get faster, frac designs improve, and costs drop. Over time, surprises become fewer, and the long tail risk shrinks.

Now let’s look at EGS. Every well is an experiment. You’re drilling into extreme depths, in rock that hasn’t been fractured before, in geological conditions that vary wildly from site to site. You might model a reservoir with 100°C heat and good permeability, but the moment you drill, you discover the rock is hotter but impermeable, or the water circulation isn’t working as planned. That’s not a minor cost overrun, that’s a project killer. And because EGS wells need to be widely spaced, there’s no statistical averaging to iron out the risk. If two or three wells fail, your entire project could be dead in the water. Flyvbjerg calls this the “fat tail” problem — the likelihood of a catastrophic overrun is high because each wellsite is its own unique gamble, and failures don’t just nibble at the margins, they swallow entire projects whole.

Infrastructure amplifies this risk. Shale oil pads share infrastructure, so if one well underperforms, the costs are distributed. But in EGS, each well is its own independent cost center, meaning every failure is a full-cost write-off. Worse, EGS wells require long transmission lines and custom power integration, making them far more vulnerable to cascading failures. If your electricity export system depends on a minimum number of producing wells and two fail unexpectedly, the remaining wells might become financially unviable, triggering a domino effect of cost overruns. Shale oil has stop-loss mechanisms—EGS does not.

Then there’s the regulatory and financing angle. Shale oil, love it or hate it, has a mature ecosystem of service providers, financial backers, and well-known risk models. If a company needs $500 million to drill, banks and investors understand the probabilities—they can hedge, they can syndicate risk, and they can adjust based on commodity prices. EGS? It’s a wild card. There’s no mass playbook, no consistent cost model, and every project is bespoke. That means capital is both expensive and risk-averse, making cost overruns even deadlier.

So what does Flyvbjerg’s framework tell us? Shale oil is a high-risk industry that mitigates black swans through volume and standardization. EGS, by contrast, is a high-risk industry that amplifies black swans through site complexity and one-off problem-solving. The long tail is not just bigger in EGS—it’s more lethal. Until EGS finds a way to industrialize its approach, the black swan will keep circling.

Closing Thoughts

Environmental and social impacts also influence EGS acceptance. EGS claims minimal emissions and the potential for big generation in a small foot print. However, seismic risks remain significant. Mitigation strategies, including precise seismic monitoring, adaptive stimulation practices, and transparent community engagement, are vital for building public trust and project acceptance.

Innovative drilling technologies like plasma and millimeter-wave (MMW) drilling are currently under exploration. Plasma drilling, developed by companies such as GA Drilling, employs high-energy plasma jets to fracture rock efficiently without mechanical contact, potentially reducing drilling costs and downtime. Quaise Energy is exploring MMW drilling using high-powered microwave beams generated by gyrotrons, aiming for economical drilling beyond 10 kilometers depth and ultra-high temperatures above 400°C. Although these methods remain early-stage, their successful development could significantly transform EGS economics and feasibility. I’ll spend more time on the advanced drilling systems, but understand that they are first of a kind technologies, and that means more black swans, not fewer.

The idea that coal plants will be repowered with ESG doesn’t pass the sniff test, at least not for decades. A 1,000 MW coal plant typically occupies 1–4 km², with a compact footprint for boilers, turbines, and cooling infrastructure. In contrast, an EGS of the same capacity, even high heat, could require 100–300 km², as widely spaced wells — sometimes kilometers apart — are needed to prevent thermal interference. While coal plants centralize generation, EGS spreads its infrastructure across a vast area, increasing land and transmission costs. Ultra deep holes, up to 20 km, with 500° Celsius+ heats would be required to get a GW of EGS somewhat within the same range as a coal plant, but even then the well heads would be spread over 5-20 km while the coal generators would still be clustered at the center.

Overall, while EGS promises lots of clean, reliable power, realizing its potential will a lot technological innovation, especially in drilling technology and seismic risk management. From what I’ve found so far, we’re a decade or two away from potential scaling, and even then it will remain much more expensive than wind, solar, transmission and storage. Personally, I haven’t found anything to change my opinion that it will remain a relatively minor portion of the energy mix, and I did most of my research before starting the series.