Deep Heat: The new technologies taking geothermal energy to the next level

For millennia, humans have tapped into Earth’s internal energy, harnessing hot springs for public baths and underfloor heating, and even powering district heating systems as far back as the 15^th century. Around 100 years ago, the first countries started to develop geothermal power systems, using heat from the planet’s interior to generate electricity. But despite the technology’s relative maturity, less than 20GW of geothermal generating capacity exists today.

The main reason behind this is the highly localised availability of suitable geothermal resources. While countries like Iceland, Indonesia, Kenya and New Zealand have readily available, near-surface volcanic activity that can be accessed for power, most countries simply don’t have suitable geology for geothermal to be economically viable. Even the US – which leads the world with around 2.7GW of installed generation – produces less than half a per cent of its electricity needs from geothermal energy.

Fatih Birol  - Executive Director, IEA

Recent technological breakthroughs are beginning to change the picture, with geothermal developers adopting advanced drilling techniques borrowed from oil and gas. According to a recent report form the International Energy Agency (IEA), these new technologies could see costs for geothermal power fall 80 per cent by 2035 and make it a viable renewable energy source in virtually every corner of the globe.

The IEA claims growth in the sector could attract investment of $1 trillion over the next decade if these technologies are adopted, with costs dropping as low as $50 per MWh. Longer term, the report predicts that geothermal energy could meet 15 per cent of global electricity demand growth between now and 2050 if project costs continue to decline. Furthermore, the skills required to harness this new opportunity are highly transferrable from traditional energy sectors.

“New technologies are opening new horizons for geothermal energy across the globe, offering the possibility of meeting a significant portion of the world’s rapidly growing demand for electricity securely and cleanly,” IEA executive director Fatih Birol said at the time of the report’s publication in late 2024. “What’s more, geothermal is a major opportunity to draw on the technology and expertise of the oil and gas industry. Our analysis shows that the growth of geothermal could generate investment worth $1 trillion by 2035.”

A key determining factor for traditional geothermal power is the permeability of the rock. Suitable geology requires both high temperatures and high permeability, allowing water to percolate through the rock to be continually heated. Even in areas of high volcanic activity, the exact subsurface conditions are rare, and drilling to find them can be a time-consuming and costly process.

“My short form summation of those issues are: geothermal, all the risk and none of the upside of oil and gas,” John Redfern, CEO and president of geothermal energy company Eavor Technologies, told The Engineer.  “It’s got all the same exploration game, all the same reservoir risk, but you end up with a bunch of hot water which you can’t really transfer, and you’ve got to find a local market for it.”

To overcome these limitations, players in the geothermal space have sought to artificially increase the permeability of naturally occurring hydrothermal resources. Known as enhanced geothermal systems (EGS), the technique borrows from the hydraulic fracturing – or fracking – methods widely used in the oil and gas sector. High pressure water is injected into pre-existing fractures to increase the permeability of the rock, creating a much larger hydrothermal resource to tap for energy.

EGS has been around as a concept for several decades but has largely been confined to R&D projects. However, recent advances in drilling techniques have seen an increase in commercial-scale projects and the sector looks to be on the cusp of a boom. 

“Subsurface resources - oil, gas, mining, geothermal - generally take a long lead time, and EGS is experimental,” explained Roland Horne, Professor of Earth Sciences and director of the Geothermal Program at Stanford University.  “About 20 projects have been undertaken, but most have been government research one-off projects, or small commercial operations of a few megawatts. They all moved the ball forward, but incrementally.”

One of the projects aiming for a step-change is Fervo Energy’s 400MW Cape Station geothermal development in southwest Utah. Phase I of the project is set to start delivering in 2026, with full-scale production achieved by 2028. According to Professor Horne, Fervo is deploying EGS at a level not previously seen, using techniques such as horizontal drilling and multi-stage stimulation to maximise the energy potential of the geology.

“Fervo has made a major forward step, not only in the advancement of the technology, but also in the improvement of the economics and the expansion of scale,” he told The Engineer.   “They’ve already drilled 20 horizontal EGS wells, where previous projects only drilled two or three.”

In stark contrast to wind and solar - which are driving the vast majority of renewable energy expansion today - geothermal power can deliver dispatchable baseload electricity around the clock. Once the wells are drilled, output is highly predictable, providing certainty for both project developers and grid operators. What this means in practice is that geothermal can help significantly reduce the overall amount of generation required. “If you have 1,000MW of solar, it only produces eight hours per day,” said Prof Horne. “So you get 8,000MWhr of energy per day. If you have 333MW of geothermal, it also produces 8,000MWhr per day. So overall capacity doesn’t need to be as large.”

EGS has the potential to help geothermal energy scale and deploy in areas where it was previously uneconomic. However, it is still dependent on preexisting hydrothermal resources and geological conditions that can be difficult to locate. Fundamentally, EGS is the same technology as traditional geothermal power, tapping into hydrothermal convection. For geothermal to be rolled out globally, a different approach is required.

Informed by years of experience in the oil and gas sector, Eavor Technologies has developed a ‘closed loop’ approach that relies on conduction from hot rocks rather than convection. Often referred to as advanced geothermal systems (AGS), this method uses a subsurface working fluid - usually water - inside a closed loop of deeply buried pipes that conduct heat from the Earth. In theory, closed loop systems can be located anywhere, according to Eavor’s CEO, John Redfern.  “We started off thinking, why has there never been a single kilowatt of geothermal energy in place as big as Canada?” he told The Engineer.

The conclusion that Redfern and colleagues reached was that traditional geothermal was simply too risky, with returns on investment that seldom stacked up. To make it a scalable, economic energy source, it needed a paradigm shift. “If you could find a way to take care of those two issues - risk and the lack of big return - then you could have a winner on your hands,” he said. “The way to do it is this rifle shot approach - a closed loop, or AGS system, however you want to call it.”

John Redfern - CEO, Eavor 

The company’s take on the technology is known as Eavor-Loop. Its pilot demonstrator project, Eavor-Lite, has been in operation in Alberta, Canada, since 2019. The project consists of two vertical wells, joined by two multilateral legs at a depth of 2.4km, connected by a pipeline at the surface. According to Redfern, the rationale for the design was to demonstrates all the critical elements of Eavor-Loop at the lowest cost and convince some of the AGS sceptics that the technology was viable.

“You go to a party, what do you do? ‘I’m in geothermal’ - people back away a little bit,” he joked.  “Tell them you’re in closed loop geothermal and even the geothermal people back away. That was seven or eight years ago. We’ve been getting a little more…I won’t say respect, but we’re not shunned so much anymore.”

Having silenced some of these critics with the Canadian demo project, multiple Eavor-Loop systems are now being developed in Germany. The first commercial deployment, at Geretsried in Bavaria, broke ground in 2022. It features twin boreholes drilled to a vertical depth of 4,500m.  From there, the boreholes are diverted horizontally, creating 12 parallel branches in a ‘radiator’ configuration, each branch approximately 3,000-3,500 meters long. Water is then pumped into the system from above, with the network of pipes acting like a giant subsurface heat exchanger.

“We thought ‘what if we didn’t frack’?” Redfern explained.  “What if we didn’t have a reservoir, artificial or otherwise? What if we just built this big radiator? That’s what’s happening in Germany right now. Two rigs side by side, going down four and a half kilometres, splitting each into 12, going several more kilometres out in one direction, joining them all up toe to toe, and creating this loop that has 60, 70, 80, kilometres of wellbore. Will that work? Yeah, that’ll work. And it’ll work incredibly predictably.”

Once fully operational, the Geretsried Eavor-Loop will deliver electrical output of approximately 8.2MW and thermal output of 64MW, providing combined heat and power to the local municipality. While these numbers are relatively modest, the project is acting as a pathfinder for closed loop geothermal and has strong backing from both the German government and the EU, receiving an EU Innovation Fund grant of €91.6 million.  

Additional Eavor-Loop projects are now in development in the German cities of Hanover and Neu-Uln. In both instances, the geothermal energy will primarily be used to decarbonise existing district heating systems that have historically been dependent on Russian gas. Geopolitical events, in combination with the technological advances, have made geothermal increasingly attractive for Germany, with other parts of Europe set to follow.

 “Vladimir Putin and the Russians were great salesmen for us,” said Redfern. “All of a sudden they invaded Ukraine and everyone wanted energy. Not just green, but to be independent. And they’re willing to pay a big premium on it.”

As Europe looks to wean itself off Russia’s gas and North Sea energy production tapers off, geothermal represents a major opportunity for the sector to pivot towards a more sustainable future. Much of the drilling expertise and geological knowledge required in fossil fuel exploration is directly transferable to geothermal. And as new technologies rapidly expand the frontiers where geothermal energy is possible, traditional wells service providers are gearing up for what could be a major new energy boom. 

Aberdeen’s Elemental Energies is one such provider. The well management specialist provides engineering solutions for oil and gas, carbon capture, utilisation and storage (CCUS), decommissioning and geothermal projects. To date, its work in geothermal has been of the more traditional variety, but CEO Mike Adams expects that to change as the sector evolves. Elemental recently teamed up with geothermal drilling services contractor Iceland Drilling on a new joint venture, with both companies anticipating significant growth in the sector.

“They (Iceland Drilling) have an amazing track record of drilling primarily big geothermal projects around the world and have drilled in all the kind of main hot spots for geothermal,” said Adams.  “A really important part of geothermal being effective in the future is taking it away from those hot spot areas, allowing it to be a much more broadly applied technology all across Europe and even the UK and certainly North America as well.”

In terms of transferable skills, Adams believes the oil and gas sector is primed to deliver if geothermal takes off. Aberdeen hosted a geothermal energy conference in February 2025 and there is a growing realisation across the North Sea industry that geothermal represents an opportunity to diversify as well as a pathway to a sustainable future. 

“We know how to get wells in the ground,” said Adams. “We know how to deal with well integrity and well intervention requirements. We know how to build facilities and pipelines and turbines and put these energy systems together. Pound for pound, it’s basically the same process. You’re drilling to 5,000 metres or 4,000 metres, you encounter the same kind of geological challenges.”

However, when it comes to the type of AGS technology that Eavor and others are deploying, there is a step-change in complexity and the level of skills required. Though closed loop drilling was first developed in the oil and gas sector, they are highly specialised techniques. A steep learning curve inevitably awaits much of the energy sector looking to pivot towards next-gen geothermal. “Some of the closed loop technology now is incredibly complex from a drilling perspective,” said Adams. “Some of the closed loop systems, you’re well over 50,000 metres of drilled depth and there’s no hiding from the fact that is an incredibly challenging drilling operation. And you’re trying to connect parallel drilling processes to connect these well bores. It’s established technology. It’s just never been used in that way. And that is really, really complex stuff.”

A big technical challenge, but the potential prize on offer is enormous.

“If we can make those type of systems work…you can drill anywhere,” said Adams.