High upfront costs and exploratory uncertainty mean that in 2019 less than 0.9% of the global energy mix came from geothermal energy. In its net-zero report, published this week, the International Energy Agency (IEA) showed that geothermal represented only 15GW of electrical capacity in 2020, compared with 737GW of solar PV capacity. However, experts believe the time and conditions are ripe for change, particularly in the heating sector.
With the right policy support and investment, geothermal use in global renewable heat consumption could rise by more than 40% by 2023, says the IEA. Two-thirds of this growth is forecast in the US and China, where concerns over air pollution are stimulating geothermal district heating developments. However, the technology is also creeping up the agenda in other regions, such as Europe, where heating sectors need to start decarbonising fast if net-zero goals are to be achieved.
“For the last 20 years, we have been trying to clean up electricity,” says Sanjeev Kumar, head of policy at the European Geothermal Energy Council, an industry group. “Half of all energy consumed in Europe is from heat and a quarter is from electricity. There has been a huge policy focus on only a quarter of the problem, while half of the problem has been pushed to the side. We have gone for the low-hanging fruit. Now, virtually every country is starting to look at heat decarbonisation because that is where the problem lies.”
Drilling to new depths
Geothermal energy comes from porous, water-filled rocks beneath the earth’s surface. To produce electricity from geothermal sources, medium-to-high temperatures are needed, but heat production can come from low-to-medium temperatures.
At eight metres below ground, the average surface temperature is around 12°C, sufficient to generate heat for large buildings and individual households. Drill a little deeper and it is possible to generate enough energy to heat larger buildings or areas, such as university campuses.
Deep geothermal involves drilling down to around 2km beneath the surface. On average, the temperature increases by about 25°C for every kilometre of depth.
Historically, geothermal systems were only able to exploit resources where there was sufficient fluid, heat and permeability. However, so-called enhanced geothermal systems (EGS), where fluid is injected into hot rock to create man-made reservoirs, means geothermal energy can now also be extracted from dry, impermeable rock.
With EGS, geothermal energy can work virtually anywhere where there is elevated subsurface heat, says Susan Hamm, director of the Geothermal Technologies Office in the US Department of Energy (DOE). “At depths of 30,000ft (9,144m), you can access high heat consistently just about anywhere.” She admits, however, that such depths remain challenging for modern drilling capabilities.
The DOE recently announced $12m of investment in geothermal energy technologies. While less than 4GW of geothermal energy are installed in the US, with technological improvements, this figure could increase 26-fold by 2050, says Hamm.
The same technological improvements could also facilitate more than 17,500 geothermal district-heating installations nationwide, enabling 28 million US households to access cost-effective heating and cooling solutions. “The further down we can drill cost-effectively, the more heat we can harness,” she says. “EGS is a super exciting area of research.”
District heating systems
There is a long way to go, however. Geothermal, excluding ground-source heat pumps, only meets 0.5% of global heat demand and is the smallest heat source used in buildings, says the IEA.
In the EU, geothermal energy consumption is projected to increase by 270% from 2019–24, says the agency, with district heating a key application. Today, district heating supplies around 12% of total European demand for heat.
One of Europe’s largest geothermal heating plants is under construction in Munich, Germany, and should begin supplying heat this year. Stadtwerke München, the city’s utility, unveiled plans in February 2021 to move 560,000 households from combined heat and power generation to geothermal district heating by 2030, becoming the first German city to have a district heating system completely run off renewable energy sources.
Geothermal heat solutions often face unfair competition from fossil fuels due to tax treatment, electricity grid charges, and investment priorities in certain states. Sanjeev Kumar, European Geothermal Energy Council
“These are the targets we need to be hitting in every city if we want to limit our warming to 1.5°C,” says Kumar.
However, Paul Voss, managing director of Euroheat and Power, a Brussels-based lobby group, warns the situation in Munich is unique. “Munich has better access to geothermal heat than many cities,” he says. “It doesn’t follow that you can replicate the same system everywhere. If it were that easy, we would already be doing it.”
District heat in general, like most renewables, involves a shift from operating expenses to capital expenditure. “The issue is the upfront cost of the network,” says Voss. He is certain this issue can be solved with the right policies, however. “The relative cost depends on public policy – do we have a carbon tax and subsidies to encourage the uptake of green solutions? People aren’t attached to their gas boilers, they just want affordable, reliable and ideally sustainable heat.”
The Nordic countries are a case in point. “District heating is everywhere in the Nordics,” says Voss. “Heat networks supply 98% of the heat in Scandinavian cities because you cannot burn oil and gas for heat anymore. There are rules against it.”
Once the infrastructure is in place, sourcing the geothermal energy for district heating represents another expense, and uncertainty surrounding the size, temperature, pressure and production rate can make it difficult to mobilise the required capital.
Geothermal projects have low operational costs, but the cost of geothermal wells and field development can represent 40% of the total investment figure, says Iceland GeoSurvey, a state-owned consultancy – but technology is catching up. For more than three decades, the oil and gas sector has used 3D seismic technology to identify hydrocarbon reservoirs and such modelling is increasingly being used in the geothermal sector.
The economics of geothermal power plants can also be improved by exploiting their by-products, such as silica or lithium, providing an additional revenue stream. As an integral component of today’s dominant battery technology, demand for lithium has rocketed in the face of rising electrification.
Recent studies show there is potential to extract lithium from geothermal production with a low environmental impact. In Alsace, France, mining company Eramet and electricity and gas distributor Électricité de Strasbourg are testing the extraction of lithium from geothermal brine as part of the European Geothermal Lithium Brine project.
True economic comparisons can only be drawn when energy sources are treated the same, says Kumar. “Geothermal heat solutions often face unfair competition from fossil fuels due to tax treatment, electricity grid charges, and investment priorities in certain states,” he says. Like Voss, he sees policy as the answer.
Policies to reduce the capital risk of geothermal projects can be particularly effective. In the 1980s, Paris created a series of support schemes which pushed gas out and geothermal into the city’s district heating system.
“If geothermal fails to really take off, it will be due to a failure on the part of politics,” says Kumar. He blames poor regulation for the current state of affairs and calls on EU policymakers to launch a European Risk Mitigation Scheme and binding decarbonisation targets for the heating and cooling sector. “With those two things, you lay the foundations for geothermal to take off.”
Rise of the Rift region
East Africa has led developments in this area with a Geothermal Risk Mitigation Facility (GRMF) that has played a “pivotal role” in encouraging public and private sector investment in geothermal power generation, says Tina Nduta, founder of Extractives and Energy Network Africa.
In 2008, the Kenyan government established the Geothermal Development Company to undertake geothermal exploration, leaving the power generation component to electricity producer KenGen. “The government removed the capital risk, enabling investors to come in at a much later stage of the project,” Nduta explains.
Since its inception in April 2012, the GRMF has granted 30 projects a total of $117m, which will have a capacity of 2,800MW when fully developed. Six more projects are due to be given the green light in 2021.
“Policy has helped Kenya become number one in African geothermal,” says Nduta. If Kumar and Voss have their way, the same will help geothermal energy play a bigger role in decarbonising heat in Europe. Combined with the growth forecasts for China and the US, geothermal may yet play a pivotal role in getting the world on track to the IEA’s net-zero emissions scenario.