Can Geothermal Energy Be Unlocked Almost Anywhere?
New drilling techniques are pushing geothermal beyond volcanic regions, raising the possibility of reaching usable underground heat across much of the world. The resource is enormous; the challenge is drilling deep enough at a cost that makes it practical.
A few kilometres beneath our feet lies an enormous reservoir of heat. Until now, geothermal power has largely depended on geography: places where hot rock, underground water and permeable formations occur close enough to the surface to exploit economically.
That limitation may be starting to change.
Advances in directional drilling, hydraulic stimulation and high-temperature well construction, many developed by the oil and gas industry, are allowing engineers to pursue hot rock much deeper underground. The International Energy Agency estimates that next-generation geothermal technologies have enough technical potential to satisfy current global electricity demand many times over.
That does not mean humanity has discovered an unlimited source of electricity. The heat exists, but reaching it economically, extracting it reliably and keeping extremely deep wells operating for decades remain major engineering challenges.
The question is increasingly less about whether enough geothermal heat exists and more about whether drilling technology can make enough of it accessible.
Drilling Deeper Changes the Geothermal Map
Earth becomes hotter with depth, although the rate varies substantially by location. Conventional geothermal plants therefore tend to be concentrated in naturally favourable regions such as Iceland, Indonesia, Kenya, Türkiye, Italy and parts of the western United States.
Geothermal currently supplies less than 1% of global energy demand. But the IEA calculates that accessing deeper resources could radically expand where geothermal electricity is possible. Its analysis found that next-generation geothermal has technical electricity-generation potential equivalent to roughly 140 times present global electricity demand. Resources deeper than eight kilometres alone could theoretically provide almost 600 terawatts of geothermal capacity under the assumptions used in the analysis.
Technical potential is not the same as economically recoverable energy. It describes what could theoretically be developed under specified technical and cost assumptions, not what utilities could profitably build today.
Two approaches are attracting particular attention.
Enhanced geothermal systems, or EGS, drill into hot rock that does not naturally contain the combination of fluid and permeability needed for a conventional geothermal reservoir. Engineers create or enhance fractures between wells, allowing water to circulate underground, absorb heat and return to the surface.
Closed-loop systems take another approach. Fluid remains inside sealed underground wells, absorbing heat through the surrounding rock rather than circulating directly through a fractured reservoir.
Both borrow heavily from oil and gas engineering. Horizontal and directional drilling, subsurface imaging, well stimulation and high-temperature well construction are skills already developed at enormous scale by the petroleum industry. The IEA estimates that more than three-quarters of investment requirements for next-generation geothermal overlap with capabilities and expertise found in oil and gas.
Progress is already measurable.
At the U.S. Department of Energy’s Utah FORGE research site, engineers created an EGS reservoir between highly deviated wells and demonstrated circulation through hot, low-permeability rock. DOE says subsequent drilling improvements reduced equivalent “on-bottom” drilling time from about 440 hours to 60 hours. In August 2026, FORGE began an extended circulation test designed to examine how an engineered reservoir performs over a longer period.
The IEA reported in 2026 that drilling rates at FORGE had risen from approximately eight metres per hour in earlier work to nearly 15 metres per hour, with peak rates approaching 26 metres per hour. Commercial developers have reported still higher rates in some projects.
Those improvements matter because drilling and wells can represent the majority of a next-generation geothermal project’s capital cost.
How Deep Could Geothermal Go?
The more ambitious idea is to drill beyond merely hot rock and reach superhot rock.
Researchers generally use the term for geothermal resources above roughly 375°C. At sufficiently high temperature and pressure, water can reach supercritical or near-supercritical conditions, carrying considerably more energy than the fluids used by many conventional geothermal plants.
In principle, that means fewer wells could produce much larger amounts of electricity.
But this is also where today’s technology begins encountering its hardest limits.
Conventional drill bits wear rapidly in extremely hard crystalline rock. Electronics, sensors, seals, drilling fluids and well materials must survive temperatures and pressures far beyond those encountered in many oil and gas wells. Maintaining fractures that allow sufficient fluid flow at extreme depth presents another challenge.
Recent modelling published in Geothermics found that superhot wells above 375°C could potentially produce substantially more power than conventional geothermal wells, but also concluded that achieving more than 30 megawatts of electrical output from a single well would require underground fluid-flow characteristics that have not yet been created in deep superhot rock.
The physics may therefore offer extraordinary potential while the engineering remains unfinished.
Researchers are pursuing better drill bits, improved drilling practices and materials capable of surviving harsher conditions. DOE-backed work using polycrystalline diamond compact bits, for example, is aimed at increasing drilling speed and reducing wear in hard geothermal formations.
Other experimental concepts propose replacing conventional mechanical drilling altogether. Among them are thermal, plasma and directed-energy approaches intended to weaken, melt or vaporize rock. These technologies could eventually become important, but they should be distinguished from the directional drilling and EGS methods already demonstrated underground. Extremely deep commercial power production using such unconventional drilling methods has not yet been established.
Cost remains decisive. The IEA estimates that continued technological improvement and industry learning could reduce next-generation geothermal costs by as much as 80% by 2035, potentially bringing electricity costs toward US$50 per megawatt-hour. That is a projection, not a guaranteed outcome.
Environmental considerations remain as well. EGS stimulation can produce induced seismicity, requiring careful site selection, monitoring and operating controls. Projects also require wells, surface facilities and water-management strategies, while permitting can take years.
The technology nevertheless has an unusual advantage among low-carbon energy sources. Underground heat is available continuously. A geothermal plant does not depend on daylight or wind and can potentially provide electricity around the clock while occupying relatively little surface land.
The resource itself is not the primary obstacle. Earth contains vastly more accessible heat than humanity currently uses, and drilling deeper dramatically increases the number of places where useful temperatures can be reached.
The unresolved question is economic and technological: how much of that heat can be reached, circulated and converted into electricity reliably enough and cheaply enough to compete with other energy sources?
If drilling continues improving, geothermal could gradually stop being an energy resource defined mainly by volcanic geography.
The heat has always been there. What is changing is our ability to reach it.
About the Author Brad Socha is the founder of The Universal Record, focused on sourced, factual global reporting. Coverage includes international news, geopolitics, technology, and major developments.
