The moment of truth had come. On my first day in Budapest, armed with a metro pass and two clues, I set off to find the office of Porció Ltd., the geothermal company of Gábor Szita, who had kindly helped to arrange my Hungarian visit and geothermal appointments. (Note: In Hungary, a person’s last name, like Szita, is written before the first name. However, first names will be placed first in this article.) Back home in California, I’d found the location of Gábor’s office impossible to pinpoint — elusive, like some geothermal resources.

The journey took over an hour. But after a metro ride under Pest (clue one), a trolley ride through the woodsy Buda hills (clue two), a short walk going the wrong way and another one retracing my steps (clueless), I found the street sign and then his office, two buildings away and up a short hill. My 6,300-mile trip spanning a continent- and-a-half, plus an ocean, was over. It was time to learn about the thermal waters of Hungary.

The Pannonian Basin once held the huge and shallow Pannonian Sea. The sea covered parts of modern-day Hungary, Slovakia, Poland, Ukraine, Romania, Serbia, Croatia, Slovenia, and Austria. Three to four kilometers of sediments were deposited in the sea when it was at its largest, 5.3 to 2.6 million years ago in the Pliocene Epoch.

Most of the sandy sediments were deposited along the borders of the sea. Today these sediments hold the most significant thermal-water reservoirs in Hungary.(1)

The second major source of Hungarian thermal waters is the limestone strata under the Pannonian Sea, formed from the calcified remains of aquatic organisms. Limestone itself often has little innate porosity, but it is often dissolved by groundwater. Eventually, as happens in Hungary, enlarged fissures form, leading to the development of caves and well-defined underground water courses—typical karst features.(2)

About 80 percent of Hungarian thermal wells extract water from porous late Pannonian sandstone layers, and 20 percent from fragmented carbonate rock (karst) formations.(3)(4)

But how is all this water heated? The answer lies far beneath the Pannonian Basin. Here, a portion of the earth’s crust has been stretched so thinly that heat rising from below infiltrates the basin sediments.(5) “Because of this, the entire basin is characterized by an elevated heat flux (~100 mW/m2) compared to the surrounding regions.” (6)(7)( 8)

In summary, about two-thirds of the Hungarian national territory is underlain by vast thermal reservoirs in sandstone sediments and karst formations. Today much of the surface is covered by rolling plains; only one hill rises above 1015m.

The map at the beginning of the article illustrates the Pre-Cenezoic surface of Hungary. Besides the highly complicated geology, the relief at the surface is highly pronounced.

Through time, the Hungarian people have experienced changes under several rulers — including the Ottomans. But who was the first person ever to bathe in Hungarian thermal waters, and when? No one knows.

The oldest Hungarian archaeological site with evidence of (human?) presence, called Vértesszőlős, is found near a warm spring! Discovered in the 1960s, the site is near Tata (see Map 1). The site was occupied about five times between about 500,000 and 250,000 years ago. The first known traces are of Homo heidelbergensis. Whether these beings are ancestral to humans or not hasn’t been decided.

Thousands of centuries later, thermal bathing played a huge role in Roman life, long before the Romans ruled present-day Hungary. When they came, they brought along their bathing customs — as we know from the many elaborate bath houses built by the Romans at Aquincum — an important Roman city in northern Budapest on the western bank of the Danube.

The waters at Aquincum were cool, but the Romans used hotter waters whenever possible. In fact, the army used thermal waters to care for the horses. Whenever possible after rigorous days on the move, the soldiers led their horses into nearby pools of thermal water to relax and heal.

Dates differ for the years of Roman rule, which probably began between 35 to 9 BC and ended around 409 AD. The Hungarians came later, occupying the Pannonian Basin at the end of the ninth century. Some evidence exists of Hungarians using thermal baths during the Hungarian Kingdom period, between 1000 and 1526 AD —the year the Ottomans conquered Hungary. The Ottomans left Hungary in 1699. They often built Turkish baths near hot springs, and some have been enjoyed from that day to the present.

Over the entire Pannonian Basin, a thermal borehole is found almost every 10 km.(10) In 2019 in Hungary, over 900 active thermal water wells produced about 90 million m3 of thermal water, representing 1023.7 MWt or 10,701 TJ/y.(9) The waters were extracted mainly for bathing and wellness. (for more information, contact Prof. Dr. Rybach at: rybach@ig.erdw.ethz.ch10 or Prof. Dr. Tóth at: toth.aniko@uni-midkolv.hu).(9)

Historically, balneology is the country’s most important geothermal application, with over 250 wells yielding thermal and (sometimes) medicinal waters. These represent a total installed capacity of 249.5 MWt, with an annual use of about 3684 TJ/yr.(9)

Prof. Dr. Tóth wrote, “Most thermal wells in Hungary (40 percent of about 600 wells) are used as spas, their temperature values fall within the 30°-50°C range, and they extract water from the porous Miocene layers found 500-1500 m below the surface. Waters with temperatures above 60°C are recovered from the fissured karst reservoirs in the basement rock. Such wells are found, for example, in Zalakaros (about two hours southwest of Budapest), where the water temperature is 99°C, and in Gyula (see Map 1), where it is 91°C.”(1)

Knowing which minerals are dissolved in the thermal waters is important to many spa patrons who come for their health. The minerals dissolved in Hungarian thermal waters include simple carbonated water, earthy-limey water, alkaline water, chloride water and sodium chloride water, sulfurous water, iodine-bromine water, and radioactive water.(1) Many thermal baths offer bottled thermal waters for sale.

The Budapest area, famous for its thermal springs and spas and outstanding thermal water resources, is one of the main discharge regions of the largest, karstified, carbonate- aquifer system in Hungary. Here, from the second half of the 19th century on, the use of natural springs has been substituted progressively by deep wells. This is because thermal water — from the region where carbonate formations are confined by low-permeability layers of any regional flow system — can be used for geothermal purposes by deep wells.(8)

The springs and wells that supply the famous baths of Budapest discharge mainly from a regional Triassic carbonate rock aquifer system (with karst features). The springs mostly have been replaced by wells. Only a few natural springs are known today; most drain unused into the Danube.(11)

Budapest has 11 major thermal baths, many using thermal water from shallow and deep wells. Springs arise along the Danube fault trending north-south on the western bank of the Danube River — on the Buda side. Calcified caves are found close to the discharge areas of the springs.

The four major baths on the Buda side, from south to north, are St. Gellért, Rudas, Király, and St. Lukács.12 All were built in the Danube fault zone and use thermal waters from shallow wells connected to the fault zone. Water temperatures in the fault zone are hottest to the south and cooler the further north you go. Thus, the southernmost thermal bath of the group, St. Gellért Thermal Baths and Swimming Pool, has the hottest thermal waters.

In 1918, St. Gellért Thermal Baths and Swimming Pool opened its doors. The famous building is beautifully decorated in the Sucessionist, Art Nouveau style — including original, pyro-granitic ornamentation from the famous Zsolnay factory. In the Middle Ages, a hospital stood here.

Eszter Pulay, an Environmental Scientist, led me on a tour through St. Gellért’s rooms and pools. When we finished, we walked north through a tunnel to the spa next door, the Rudas Thermal Baths and Swimming Pool. The tunnel includes observation wells and is used for finding new wells and sources of thermal waters.

Presently, three wells are being used by the St. Gellért Bath and one or two by the Rudas Baths. “The thermal wells, drilled into karst features, are older than the bath buildings themselves,” said Andrea Ligeti, our guide at the Rudas Baths. “The thermal waters were used before construction began.” (For more information, contact Ms. Pulay at: pulay.eszter@spabudapest.hu).

Mustafa Pasha built the Rudas Baths during the Ottoman occupation of Hungary in the 16th century. The building has been expanded through the years, and the last renovation ended in 2005. All this time, the original, historical area has remained untouched— including the dome (10 meters in diameter), supported by eight pillars around a lovely, octagonal pool. A drawing hangs nearby of Ottoman bathers using the pool.

Eszter Pulay works at the Király Thermal Baths, located just north of the Rudas Baths. Construction was begun here in 1565 by Arslan, the Turkish Pasha of Buda, and was completed by his successor, Sokoli Mustafa. The Király never has had its own supply of thermal waters. The Ottomans built Király too far away from the thermal wells for this — on purpose. They made sure the thermal baths would be available to them inside the fortress walls during sieges.

At first, redwood pipes were used to channel the waters to Király from what is now called the St. Lukács Thermal Baths and Swimming Pools (just to the north). Today, Király still uses the same thermal waters drawn from the same St. Lukács’ wells.(12)

St. Lukács Thermal Baths and Swimming Pools has a recorded history dating back to the 12th century, when the St. John Knights came to cure the sick. Knights from the orders of Rhodes and Malta followed and built monastery baths.

In the Middle Ages, St. Lukács Baths was the favorite of the Turkish Grand Vizier, Pasha Mustafa. When the City of Buda was recaptured from the Ottomans in 1686, St. Lukács became property of the Treasury. In 1884 Fülöp Palotay purchased the property from the Treasury and began what would become 121 years of remodeling.

“On the Buda side of the Danube River, the carbonate formations with karst features are close to the surface, (as the four thermal baths illustrate),” said Prof. Dr. Mádl-Szőnyi.(8) “On the Pest side, the carbonates form deeper strata and a porous cap rock traps the rising heat in the carbonate. This is why the waters on the Pest side are hotter than on the Buda side.(13) On the Pest side, waters for the thermal baths come from deep wells, not hot springs (For more information, contact Prof. Dr. Mádl-Szőnyi at: szjudit@ludens.elte.hu).

The Széchenyi Thermal Baths and Swimming Pools is the best known thermal bath on the Pest side. Széchenyi extracts 74°C and 77°C thermal waters from two wells drilled 1650 m deep into carbonate rocks in the fault zone. Drillers at the Paskál well entered a 300 meter-long vertical shaft, an amazing karst thermal feature.

Széchenyi’s history began in the 1870s when hot spring wells were drilled near a small bathing structure built at Hero’s Square, near the City Park in Budapest. As patronage grew, the bathing structure was rebuilt on an island in the City Park. Finally, in 1909, construction began on what would be the massive, beautiful building admired in the City Park today.

Some recycled thermal waters from Széchenyi are piped to an artificial lake in the City Park. Others help heat two thirds of the city zoo, lowering the gas bill by one half. Heated areas include the animal enclosures, the pools for tropical animals, and the palm house.(1)

Thermal waters heat many structures in Hungary. In fact, heating greenhouses with thermal waters is the second oldest geothermal application in the country, and very significant. In Hungary, 493 wells produce 11 million m3 of thermal waters used to heat over 70 hectares of greenhouses and 260 hectares of ground-heated polytunnels (tented structures). In the 1960s, Hungary’s oldest and most significant greenhouse network began using thermal waters for heating greenhouses and polytunnels at Árpád Agrár Zrt., in the city of Szentes (see Map 1).(1)

After making a few calls, Gábor Szita spoke with Mr. Sánder Mártin, 91-year-old man who once worked as chief accountant for Árpád — or a prior iteration of the company. Mr. Mártin said a small, state-owned, horticultural research institute in Szentes had used geothermally heated greenhouses a few years before Árpád came. Once Árpád constructed its own greenhouses, it took the lead.

One afternoon Gábor and I drove to Veresegyház, a city of about 20,000 people (see Map 1). Here, thermal waters heat structures built in the city center and on the outskirts. We had appointments to visit a greenhouse and several other buildings that were heated geothermally.

Outside of Veresegyház proper, we passed two large factories run by General Electric — GE Aviation and GE Power — built on eight hectares of land. The plant is heated by a huge geothermal system: three production wells and one injection well, all city-owned. The water temperatures are between 66°C and 72°C. The city has built a double pipeline network, 18 km long, to the site.

We arrived at the greenhouses of Veresi Paradicsom Ltd. on time. This new, innovative, and growing agricultural company was built in Veresegyház at Gábor’s suggestion. The company raises tomatoes in 63,000 m2 of greenhouses heated by geothermal waters piped in from Veresegyház wells. The zero-emissions heating system doesn’t damage the environment; all the waters are cooled, cleaned, and reused.

The company has installed artificial, LED-based, supplementary lighting in the greenhouses — the first in Hungary and maybe the world to do so, according to Tungsram.com. The lighting makes year-round plant growth and sales possible, said Zsolt Márkus, owner and managing director of Veresi.

Company innovations include the tomatoes themselves. Zsolt says Veresi is the first to ever measure the sugar content of tomatoes.

Ripened tomatoes are harvested daily by workers who change their gloves at the end of each row to avoid harming the next one. A bunch of tomatoes is never picked until even the lowest tomato is the right color. Veresi first sold the tomatoes abroad, but today sells about 95 percent of them in Hungary. The company recently received the Innovation Technology Ministerium Award for 2020.

Veresi tomatoes are so well regarded that the chef of Onyx, a two-star restaurant in Budapest, comes to the greenhouses to pick his own. Walking in Budapest the next day, I passed by Onyx. First on the menu — a tomato appetizer (for more information, contact Dr. Márkus at: zsolt.markus@garden-invest.com).

Leaving Veresi with small boxes of cherry tomatoes, we drove to the city center and parked at the Veresegyház hospital, which was geothermally heated. Our appointment was with the city mayor, Mr. Bela Pásztor, who was elected to the office in 1965. On sitting down, I asked Mr. Pásztor for the story of geothermal development in his city. He told us proudly, “Today 81 percent of consumers are connected to our geothermal system.”

He recalled when the first geothermal well was drilled in 1987 to a depth of 1500 m, with temperatures reaching 65°C. The well was tested for over a year to ensure the production was stable. Gábor told me the well’s success even surprised the hydrologist — for drilling is a risky undertaking. A third production well was drilled in 2015, and its production exceeds that of Well 1. Well 3, drilled 1700 m deep with temperatures of 71°C to 72°C, has minor scaling. About 1200 to 1700 m is the average drilling depth for wells in this part of Hungary, but wells drilled in the Triassic limestone are known to reach 2000 and 2800 m.

The mayor said the city’s original goal was to build a thermal bath with geothermal waters, but there wasn’t enough money to pay for the building. Then they heard geothermal waters can heat buildings. A geothermal pipeline network was begun in 1993 for transporting thermal waters to the elementary school. Four years later, the piping network was connected to the music school and the culture house.

“Needing more geothermal waters, we drilled new wells,” he said. “All are successful. Currently we are designing a new production well and a new injection well to supply heat to blocks of buildings, each with 10 to 12 small apartments. The city will own some of the apartments; the others will be privately owned. Today we have about 7,000 detached houses and apartments in the city. About 350 of the apartments are heated solely by geothermal waters.”

In 2008, when Hungarian housing prices dropped, Porció Ltd. (Gábor’s company) built 180 to 190 flats — geothermally heated — in Veresegyház. They were finished around 2014 and all were sold. Their values may have risen over 50 percent in the last 10 years.

Talking about the city’s abundant geothermal waters, the mayor said, “We just wanted to use them. Every year our thermal waters replace about 3.5 million cubic meters of natural gas.” When I asked about the risks involved in developing geothermal resources, Mr. Pásztor said, “We have a chance only if we risk.”

Thanking the mayor for his help, we left to see more geothermal projects in Veresegyház. The geothermally heated buildings include the town hall, the post office, the football stadium, and an open-air bath. The municipality determines the price of geothermal energy in Veresegyház, not the state. The local energy source benefits the local community.

Porció Ltd. is a Hungarian company working on geothermal projects. Owned by Gábor Szita, Porció’s business model is to build a geothermal project, operate it successfully, and transfer (sell) it, often to a municipality. If the project doesn’t perform well, a prospective buyer is free to walk away (For more information, contact Dr. Szita at: szitag@mgte.hu).

Another Hungarian geothermal company is NEG Zrt., the National Energy Management Company, whose CEO is István Donázy. NEG Zrt. is controlled by the Hungarian National Asset Management Company, Ltd.

Mr. Donázy said the company’s main goal is to promote energy-conscious operation for its clients, reducing their energy costs. NEG seeks to stimulate, catalyze, and assist legislators with first-hand information, creating a regulatory environment advancing these goals. The company helps the owners of industrial and agricultural infrastructures modernize their energy requirements, increase renewable-energy production, and renovate state and municipal energy use.

The Municipality of Budapest owns the city tram system, where about 600 trams operate every day. The transport company repairs the trams inside a very large building. A current NEG project is to heat the building with geothermal energy instead of natural gas.

To this end, NEG has drilled a geothermal production well and injection well in Budapest. The production well penetrated a hot-water aquifer about 1300 m deep, with waters of about 72°C flowing over 1300 ltr a minute — more than expected. The injection well penetrated a huge karst cavern at a depth of about 1250 m. The thermal waters will be used to heat the tram repair building. These thermal wells are the first ever drilled in Budapest solely for a heating project.

The project began four years ago, and the implementation phase has been underway for two. Originally 6 million kWh of electricity was needed to heat and operate the building each year. The new geothermal heating system will use only 300,000 kWh of electricity every year for operating the pumps and other elements. The geothermal heating system consumes no natural gas and emits no carbon dioxide. (for more information, contact Dr. Donázy at: donazy.istvan@negzrt.hu).

Another Hungarian company, PannErgy, developed Hungary’s largest district heating project in Miskolc (see Map 1). Next the company built the large, direct-use project in Györ (see Map 1). PannErgy also operates two smaller geothermal systems in Szentlőrinc (see Map 1), and Berekfürdő (about two and a half hours east of Budapest). The company recently reported a 20 percent increase in geothermal heat sales for 2019.

Hungary has one geothermal power plant, located in Tura (see Map 1). The electrical production is 2.3 MWe gross and 1.3 MWe net, according to the Mining and Geological Survey of Hungary. This is the first geothermal power plant ever built in the Pannonian Basin.

Gábor Szita believes the future of geothermal in Hungary depends on whether the government policy supports geothermal projects, as did the former government 10 years ago when geothermal development flourished. Then monies were available, the plants ran at high efficiency, and all the equipment worked. The government only has to re- implement the plan.

Moving toward this goal is the Division of Business Development and Communication, in the Mining and Geological Survey of Hungary. The division is headed by Dr. Annamária Nádor, who kindly sent the following information about a new plan for geothermal risk insurance.

She writes, “Hungary is well advanced in introducing a new geothermal risk insurance scheme in 2020. This is well established at the policy level: both the new National Energy Strategy and the National Energy and Climate Plan (both issued in January 2020) explicitly mention the Geothermal Guarantee Fund. The first step is introducing the pilot projects financed by the Swiss-Hungary Cooperation Program with about 14 million CHF of starting capital.

“Experiences from these projects will be used to elaborate further the details of the risk insurance scheme for the future. According to the Hungarian proposal, geothermal projects that apply full injection will be eligible, irrespective of the depth of the research, the petrological nature of the reservoir, and the technology of the exploration and production activities. The planned schemes support project development by tenders, in a phased, ex-post-financed way, by investment risk mitigation, the partial sharing of investment risk, and the introduction of collateral for failure coverage.

“The legal acts about the introduction of this Guarantee Fund are elaborated and presently (in March 2020) under Parliamentary discussion. The concept papers and technical background materials supporting this initiative benefited a great deal from the GeoRISK project and its studies, especially on risk assessment methodologies and the overview and in-depth analyses of the already existing schemes all over Europe.” (For more information, contact Dr. Nádor at: nador.annamaria@mbfsz.gov.hu)

The Hungarian Ministry for Innovation and Technology, established in 2018, coordinates the entire energy sector, including geothermal. In 2018, the ministry established the Energy Innovation Council to offer expert input for a review of the Hungarian Energy Strategy. The council includes several thematic sub-groups. Geothermal energy plays an important role in the sub-group dedicated to renewables.

I interviewed Dr. Péter Kaderják, Minister of State for Energy Affairs and Climate Policy, within the Ministry for Innovation and Technology. He said energy and climate policies contribute over 70 percent of the climate problems. To manage climate issues means using local energy resources and energy efficiency. President Orbán, he said, is very much aware of the climate issues and in favor of the policies alleviating them. Dr. Kaderják’s office offers regulatory and financial help to developers.

The Hungarian Government issues the right to drill geothermal wells and chooses which areas to open for exploration. Those with the highest bids for the licenses enter the market. In 2019, Aspect-TDE Geotherm Kft won the Gádoros area tender for geothermal energy exploration, production, and prospecting.

“At a policy level, the licensing system is stable,” Dr. Kaderják said. “Concessions are for 35 years. To receive a license, a person must demonstrate financial and technical capability. We are far from our full potential in promoting geothermal development, but we are trying to get ahead.” (for more information, contact Dr. Kaderják at: peter.kaderjak@itm.gov.hu)

I want to thank the many kind and generous people who helped me. They include Gábor Szita for the invitation and appointments, the eye-opening trip to Veresegyház, and reviewing the manuscript; Ladislaw Rybach for geological insights and reviewing the manuscript; and Judit Mádl-Szőnyi; Anikó Nóra Tóth; Zsuzsanna Vitai; Kata Takács- Szabó; Eszter Pulay; Andrea Ligeti; István Donázy; Zsolt Márkus; Bela Pásztor; Annamária Nádor; and Péter Kaderjék.

1. Tóth, A. N., “The Geothermal Atlas of Hungary,” Hungarian Energy and Public Utility Regulatory Authority (2016); 12-13; 33.
2. Duff, P. McL. D., Holmes’ Principles of Physical Geology, Fourth Edition (1993), Chapman & Hall; 387.
3. Liebe, P. , Magyarország Termálvízkészletei (1993), Római Könyvkiadó, Budapest.
4. Fancsik, T., A. Nádor, Geotermikus Feladatok a Magyar Földtani és Geofizikai Intézetben (2012), Kutatás és Innováció a Magyar Geotermiában, Konvferencia, Budapest.
5. Vitai Z. M., Source of Geothermal Energy in Hungary (2019), PowerPoint presentation.
6. Lenkey, L., P. Dővényi, F. Horváth, S. Cloething, Geothermics of the Pannonian Basin and Its Bearing on the Neotectonics EGU Stephan Mueller Special Publication Series, (2002), 3: 29-40.
7. Horváth, F., B. Musitz, A. Balázs, A. Végh, A. Uhrin, A. Nádor, B. Koroknai, N. Pap, T. Tóth, G. Wórum, Evolution of the Pannonian Basin and Its Geothermal Resources, Geothermics, (2002), 53: 29-40.
8. Mádl-Szőnyi, J., M. Virág, F. Zsemle, Potential Maps for the Hydrogeologic Prerequisites of the Installation of Deep Geothermal Doublets and Groundwater Source Heat Pump Systems in Budapest, Hungary, Central European Geology, (2015) 58: 1-2: 114-128.
9. Tóth, A. N., Country Update for Hungary (2020), Proceedings World Geothermal Congress. (To read, wgc2020.us13.list-manage.com , and fill in the author’s name and the title).
10. Rybach, L., Geothermal Potential of Sedimentary Basins, Especially of the Swiss Molasse Basin (2019), Hungarian Geological Society, Vol. 149, 4, pp. 401-414.
11. Eröss, A., Zsemle, F., Pulay, E., Heat Potential Evaluation of Effluent and Used Thermal Waters in Budapest, Hungary, Central European Geology (2015), 58: 1-2: 62- 71.
12. Mupa.hu, Budapest the City of Spas. Accessed June 17, 2020.
13. Mádl-Szőnyi, J., personal communication (2019).

Renewable geothermal energy systems with near- zero carbon emissions generate continuous, reliable, secure, and resilient electric power. Yet, despite being the world’s largest continuous heat supply and the burgeoning demand for clean power, geothermal energy usage has been paradoxically low due to the limitations of legacy hydrothermal technology. Worldwide estimates indicate that only 2% of the Earth’s geothermal resources reside in permeable regions essential to conventional geothermal technologies. Consequently, enormous resources of geothermal energy remain untapped.

Enhanced geothermal systems (EGS) is the main technology devised to create reservoir permeability. EGS attempts to fracture subsurface formations to permit sufficient geo-fluid flow rates through permeable rock layers. Despite progress, EGS is not yet ready for large- scale commercial implementation.

A different approach, closed-loop geothermal (CLG), overcomes permeability issues by circulating a working fluid through a sealed downhole heat exchanger to absorb and transport heat. CLG is a versatile technology that can be implemented in a wide variety of different well pipe configurations using a choice of working fluids (such as water and supercritical CO2 (sCO2)) to optimize site-specific costs and performance.

CLG greatly expands the potential production and consumption of geothermal energy in four fundamental ways: First, closed-loop systems can operate in a much broader range of temperatures and rock compositions, ranging from relatively low temperature sedimentary zones to hot, dry rock formations, than conventional hydrothermal projects. This breadth of viable CLG operating parameters not only increases the number of viable geothermal projects, but also allows the use of high-temperature resources (300°C and above) that dramatically increase power output. Second, closed-loop systems can produce power from previously unproductive geothermal wells and from played out oil and gas wells in hot strata. Third, the baseload and flexible power generation capabilities of CLG can help stabilize the grid with reliable, continuous, sustainable energy, capacity, and ancillary services. Finally, closed-loop geothermal systems can enhance industrial applications, including high-value lithium extraction and hydrogen production, while lowering GHG emissions.

Key environmental advantages of CLG technologies over conventional hydrothermal and EGS include the following:

Air and Water Quality

• Consume little or no process water.
• Reduce problems with saline and corrosive brines inside the system.
• Fewer effluent and waste disposal problems and permitting issues.
• Does not interfere with subsurface water.

Public Safety and Environmental Soundness

• No surface subsidence.
• No waste streams.
• No hazardous chemicals.
• No risk of induced seismicity.

Figure 1 illustrates that conventional hydrothermal and EGS projects depend on large amounts of water traversing highly permeable rock while it collects and transports heat to the surface as brine or steam. The closed “U-Loop” system depicted on the right does not need subsurface permeability because sealed well “pipes” the heat transport fluid through the hot rock and then to the surface for power generation.

A different CLG well configuration consists of a tube-in- tube assembly (an insulated concentric tube), frequently a vacuum insulated tube (VIT), which can be installed into a single well bore. Heat is absorbed via conduction from the rock through the well casing, and then into the working fluid. Figure 2 shows a deep vertical well with the concentric tube configuration circulating sCO2.

Figure 3 illustrates an alternative highly deviated well design, where the well bore kicks-off directionally from the top depth of the geothermal target zone and angles though the target zone temperature gradient or follows a targeted thermal contour to bottom-hole depth.

Technology from the oil and gas industry is essential to the success of CLG. The industry now drills, completes, produces, and maintains gas and oil wells at depths over 9,750 m (32,000 ft) vertically below surface with bottom- hole temperatures above 500°F (260°C) and/or bottom- hole pressures to 30,000 psi (2,069 bar, 207 MPa). The total horizontal length of a single wellbore can be over 6.6 miles (10,667 m). Wells can be drilled in any direction, including multi-lateral wells or U-shaped wells.

GreenFire Energy Inc. conducted a field demonstration of a CLG system at Coso, California, using a DHX to extract heat from an existing but unproductive well. The DHX included the insertion of a VIT string into the well with associated surface equipment as shown in Figure 4. Both water and sCO2 were tested as alternate working fluids.

Although power generation is a direct function of thermal surface area, budget constraints limited the DHX to only 1,000 ft long. Obviously, power generation might increase with a longer well. Figure 5 shows the modeled power potential of a field-scale U-Loop system of increasing lengths installed in an impermeable geothermal resource with a thermal gradient of 240°F (120°C)/km. Although convective heat transfer from water in the resource moving across the well would add substantial power, no convection was assumed in these calculations. The industry continues investigating the potential to multiply heat absorption via well configurations that thermally increase downhole surface area.

Another relevant question is how much more power could be extracted from the Coso KGRA, using CLG wells, by accessing hotter temperatures that geometrically increase power. Considering current limitations on drilling and materials in combination with an acceptable levelized cost of electricity (LCOE), the potential capacity at Coso with intensive CLG development is in the range of 1 to 2 GWe, compared to its current capacity of about 0.145 GWe.

A World Bank study concluded that approximately 22% of all geothermal wells worldwide “fail” due to poor brine production, high non-condensable gases (NCGs), low wellhead pressure, corrosive brine, and insufficient permeability. Remedial well “workovers” often involve additional drilling with high cost and risk.

A better option — CLG well retrofits, such as at Coso — can make unproductive wells generate power with less risk and cost than workovers. This is increasingly attractive as the cost of plugging and abandoning wells escalates. Further, the possibility of fixing new wells that fail with low-cost, closed-loop retrofits effectively mitigates new project risk.

A typical hydrothermal well retrofit solution is illustrated in Figure 6, where a closed-loop, downhole heat exchanger (DHX) is inserted into an existing well. The working fluid circulates from the steam turbine to the bottom of the DHX and extracts heat as it rises in the outer annulus between the well casing and the DHX.

Because the DHX exposes the working fluid to the higher brine temperatures near the bottom of the DHX, the working fluid surfaces at a higher temperature than the produced geothermal brine.

Thousands of abandoned hydrocarbon wells throughout the world could be retrofit to yield geothermal energy under three different scenarios. First, a DHX can be inserted into a defunct oil well to generate power for oilfield operations as an alternative to diesel generators. Second, geothermal heat might be used directly to pump oil. One potential solution comes from the gravity head pump — a downhole pump powered by a thermosiphon created by the heat of the surrounding rock. This avoids the cost of electricity that would otherwise be used for submersible or surface pumps. Third, a CLG system could be inserted into non-productive oil wells to repurpose them for power generation to the grid.

These applications share the common challenge of transferring enough enthalpy to be cost effective. Oil and gas wells tend to be at the low end of the acceptable temperature range, and strings must be large enough to provide sufficient fluid flow.

Geothermal systems operate continuously, providing baseload and flexible power required for grid reliability, diversity, and electric grid balancing. In contrast, wind and solar projects cause over-generation when they generate electricity in excess of demand. This oversupply not only causes curtailment of power plants and falling wholesale prices, but also requires substitute and extra backup resources for ramping and generation when wind and solar are unavailable. This leads to relying on battery storage technologies with unproven duty cycles and uncertain lifetimes.

Hydrogen is a highly attractive fuel for power, heat, and transportation. Commercial hydrogen production processes have varying costs and environmental impacts. The predominant process, Steam Methane Reforming (SMR), uses natural gas to produce “Grey Hydrogen” but creates significant CO2. “Blue Hydrogen” production uses natural gas accompanied by Carbon Capture and Sequestration (CCS). Electrolysis of water is a more expensive process that does not directly produce CO2 but requires substantial electricity, which is often generated by fossil fuels. By comparison, “Green Hydrogen” is produced from zero-carbon feedstock utilizing non-carbon-emitting renewable or nuclear energy. Because the cost to produce green hydrogen is more than twice the price of hydrogen produced by SMR, improved technology is required to make green hydrogen cost effective. Today, the price of green hydrogen is more than twice the price of hydrogen produced by SMR.

CLG can reduce the high cost of clean hydrogen while improving safety. Using geothermal energy for hydrogen production is doubly attractive, avoiding the use of natural gas as feedstock and as the energy source. Two types of CLG processes are feasible:

• Downhole reaction methods (DHR) use the well itself as a reaction chamber, providing both heat and pressure to reduce production costs, alternatively.
• Transport high-temperature heat to the surface to reduce the heat/power needed from surface sources to reduce costs.

CLG can provide cost-effective electric power and thermal energy for very pure hydrogen production by electrolysis. Additionally, CLG can precisely create and maintain high pressures for compression and transport. Such a system can alternate between commercial power generation and hydrogen production. When power generation is at a premium, hydrogen production processes can be readily curtailed to allow geothermal plants to maintain baseload operations.

CLG can improve the efficiency of a wide spectrum of hydrogen production methods:

• Alkaline electrolysis
• Solid oxide electrolysis cells
• Proton exchange membranes
• Partial oxidation
• Copper chloride
• Copper chloride method combined with hybrid process of capturing and using exothermic production heat
• Steam reformation
• Auto-thermal reformation
• Liquefaction

Lithium is classified by the Department of the Interior as critical to U.S. national security and the economy. A high percentage of the world’s lithium supply comes from brines, which offer cost advantages, as well as the following:

• Flexibility: Produces either lithium carbonate or lithium hydroxide.
• Efficiency: Up to 90% of the lithium is extracted.
• Speed: Lithium is extracted in hours.
• Purity: Lithium is very pure and highly concentrated.

CLG technology offers a fundamentally different approach to simultaneous power generation and lithium extraction. CLG DHX circulates the working fluid at flow rates that optimize power generation. Meanwhile, mineralized brine annular flow inside the casing is co-produced at rates that optimize lithium extraction. Because the brine well flow transfers heat to the working fluid in the DHX, the two fluid flow rates are calibrated to optimize power production and lithium extraction.

Closed-loop geothermal (CLG) systems can make important contributions toward satisfying worldwide energy and environmental needs. Overall:

• Advanced technologies are essential to supply clean energy and reduce greenhouse gases.
• Electricity is the world’s most versatile form of energy.
• Reliable, renewable, climate resilient, and environmentally preferred geothermal energy provides clean, continuous heat and electric power.

Innovative closed-loop geothermal systems can access previously unavailable, abundant high-energy resources  and deliver secure, sustainable energy at competitive costs.

The shift from fossil energy sources to renewable ones is accelerating worldwide. The new energy system will be characterised by a larger share of intermittent renewables (wind, solar), complemented by other flexible forms of power/heat production. Gas- powered plants can quickly increase or decrease their power output, but the share of natural gas in the mix will most likely decrease during the energy transition.

Therefore, it is clear that variations in energy supply, as well as demand, and the integration of renewable energy sources into the energy infrastructure pose challenges in terms of balancing. Peak shaving and energy storage can help decrease the pressure on the energy infrastructure. Underground Thermal Energy Storage (UTES) stores excess heat during periods of low demand (i.e., summer) and uses it during periods of high demand (i.e., winter). This can be implemented in local or regional heating networks to support the use of surplus heat from industry (e.g., waste incineration plants) and the implementation of renewable heat sources such as bio-Combined Heat and Power (CHP), geothermal, and solar energy. UTES could also be of interest to absorb surpluses from high wind and solar PV production in the electricity grid with the use of heat pumps.

UTES is especially of interest when seasonal dips and peaks in the demand exist, such as in district heating or greenhouses. Conventional storage systems like capacitors, pumped hydro, and batteries are unsuitable for this type of longer-term storage. UTES may provide large-scale storage potential, exceeding 10 GWh. Its costs are competitive, as long as the cost of the heat is low.

Various kinds of UTES exist or are being demonstrated, including Borehole (BTES), Mine (MTES), and Pit Thermal Energy Storage (PTES). This article focuses on High- Temperature Aquifer Thermal Energy Storage (HT-ATES), where hot water is stored in porous, water-bearing layers  in the subsurface. It is different from the well-known LT- ATES (low temperature), which is widely applied in the very shallow subsurface (tens of meters depth, with storage temperatures up to 25°C). Here, buildings are cooled in summer using cold water. The excess heat from the building is then stored in the subsurface and used again in winter for heating the same building, often with the use of a heat pump. Here, the temperature differences are small, and therefore the power is also small. HT-ATES currently uses temperatures up to about 80°C. Higher temperatures are possible, but challenges are posed by legislation, materials, and interference with the use of groundwater.

Figure 1 shows a typical heat demand curve: high during the cold season (in this example, December-March) and low during the warm season (June-September). The high peak demand during the cold period requires a heat supplier with a high capacity. This is typically an installation that is quite expensive to run. During the warm period, on the other hand, this high capacity is not used. For typical low temperature geothermal applications like heating of greenhouses, there is still some demand during the warm period. For city heating in moderate climate regions, the summer demand drops to very low levels, just for hot water use, which deepens the bathtub even more. This requires upfront investments that are higher than necessary for a high-capacity installation. Furthermore, shutting down the heat producer in the summer period increases maintenance needs: for instance, when it concerns a geothermal doublet system, which tends to deteriorate during periods of standstill due to mineral precipitation. Figure 1 illustrates that if the heat production continues between months 4 and 10 at the level of the dotted line, the bathtub is filled.

The excess heat can be reproduced in winter to cover the peak demand. In principle, this makes better use of excess and renewable heat sources and offers opportunities to lower the overall system cost, while providing the same heating services.

Figure 2 shows a schematic diagram of an HT-ATES system. Conventional doublet-type geothermal installations typically have a warm production well and a cold injection well. An HT-ATES system consists, in principle, of two wells that operate in opposite mode: when the cold well is producing, the warm well is injecting, and vice versa.

During the warm season, cold water is produced from the cold well. The water is then heated using a heat exchanger, which receives its energy from the heating source (e.g., geothermal, solar). The heated water is injected into the warm well and stored in the reservoir until the start of the cold season. The stored warm water is reproduced from the same well into which it was injected. Finally, the cooled water is re-injected in the cold well again. Depending on the required capacity of the storage, and the quality and dimensions of the underground reservoir, there may be one or more warm and cold wells. The larger the number of required wells, the higher the investment and operating cost will be. However, economies of scale do apply, and bigger is better. This applies to costs, but also to storage efficiency.

The vertical cross-section of Figure 3 shows the development of the hot plume. At a depth of around 500 m, the in-situ temperature is typically around 20°C to 40°C. A cylindrical volume of hot water will migrate into the reservoir, expelling the cold water initially there. After the first loading-unloading cycles, the amount of reproduced heat is small because the subsurface is heated up (Figure 3). After more cycles, the efficiency can increase to about 70%–80%, but this depends very strongly on local subsurface and surface conditions. Because the density of hot water is less than that of cold water, the hot water will tend to flow to the upper part of the aquifer. This means that when the stored hot water is reproduced, the lower part of the hot wells, at 400 m depth, will start producing cold water before all the stored hot water, concentrated at lower depths, is reproduced. This, combined with the fact that some mixing by heat conduction takes place, means that the efficiency of an HT-ATES can never be 100%.

The Netherlands, one of the pioneering countries of HT- ATES, are home to many thousands of LT-ATES systems. Given its moderate climate with winter temperatures around 0°C, there could be large potential for HT-ATES. The potential can be determined in many ways: theoretical, technical, and economic. The theoretical storage potential can be defined as thermal storage capacity (energy per surface area) and requires subsurface data and surface data (injection and production temperature) as input.

To calculate technical storage potential, one approach is to calculate possible flow rates based on subsurface parameters and technological flow restrictions in order to predict capacities and thermal storage production. When cost parameters are included, the economic potential could be calculated as well, expressed in the levelized cost of energy. The market potential can be determined when surface parameters, like heat sources and demand, and regulatory and spatial planning information is included.

As HT-ATES is not widely developed yet, and many input parameters for calculating technical and economic potential are unknown, another way to approach HT-ATES potential is to define certain (subsurface) criteria and test them with available subsurface data. For the subsurface of the Netherlands, an alternation of unconsolidated sand and clay sediments, the following criteria were considered:

• The typical depth of an HT-ATES system is up to around 500 m. Shallow aquifers (< 50 m below ground level) are considered to be less suitable for HT-ATES, as these are often used for drinking water production. Heating the shallow subsurface should be prevented. Potential leakage zones like faults should, therefore, also be avoided. With increasing depth, the potentially achievable flow rate increases because higher pump pressures can be applied. From ≈800 m, more complex and expensive drilling techniques are required, which will increase the drilling costs significantly. Friction losses increase with increasing depth, thereby decreasing the coefficient of performance (COP).
• It is assumed that HT-ATES wells are technically comparable to LT-ATES wells in unconsolidated layers, meaning that a similar drilling technique and well stimulation process is applied. Given these starting points, a minimum hydraulic conductivity of 5 m/d is advised. The minimum aquifer thickness should be about 15 m.
• The presence of a confining cap layer on top of (and preferably also below) the storage aquifer is a requirement to limit: 1) the impact of buoyancy flow on the recovery efficiency; and 2) the temperature (and associated geochemical) effect on the shallower layers. The clay layer acts as a physical boundary preventing hot water from flowing to shallower aquifers. The advective losses of hot water are restricted to the horizontal dimension when clay layers are present both at the top and the bottom of a storage aquifer, giving a higher recovery efficiency.
• Lithology is an important factor, and medium- to fine- grained sand is generally favored. Very coarse sand usually has high permeabilities and, hence, allows large volumes to be stored with high flow rates, but coarse- grained aquifers are considerably more sensitive to low recovery efficiencies because of a high impact of buoyancy flow. Clay, silt, glauconite, and shell fragments are considered to be unfavorable factors. Depending on the parameters that influence buoyancy flow, maximum hydraulic conductivities should be about 20–50 m/d.
• A low groundwater flow velocity (< 20–30 m/year) is favoured to prevent the hot stored water from drifting away.
• Aquifers holding saline water are favored for storage purposes. Technically, there are limited differences between storage in fresh or saline water, although some findings suggest that storage in salt water is less sensitive to clogging. In case the target aquifer holds fresh water or a fresh-salt water interface, it should be given extra attention. Fresh water is not to be mixed with brackish or saline water; this mainly has to do with the high interests that are associated with fresh water as a resource.

Important boundary conditions for a business case are set by surface conditions. This can be broken down to some simple elements. For HT-ATES systems, a seasonal variation in demand and supply is required. These systems are typically not attractive for regions with a relatively flat demand profile. A high mismatch between seasonal demand and supply is optimal.

The next preferential condition is the presence of a low- cost heat source. This can be waste heat or heat from sources with low marginal production costs, such as geothermal and solar.

The operating temperature of the heating network is very important, as it often determines the temperature difference between the hot and cold wells. This, together with the flow rate, affects the energetic capacity of the storage project. A higher capacity often leads to a lower cost of storage per unit of energy.

Scale is the final preferential condition. From experience with past projects and feasibility studies, the scale should be minimally 5–10 MW(th) and entail 2,500 of full load equivalent running hours per year. This equals approximately 1000 dwellings (for the Netherlands).

Aquifer thermal energy storage could have a bright future in the changing energy system to provide flexibility and security of supply in a world with less fossil fuels. However, it is very important to learn from ongoing projects to bring the concept to full technological and commercial maturity and exploit its benefits. A key aspect to keep in mind is that HT-ATES applications are highly location-specific. An optimal match is found when surface and subsurface conditions are jointly considered.

Over the years, I’ve often heard from geothermal industry players that they would welcome oil and gas engagement in the space; that oil and gas skills and technologies are essential to push geothermal forward, faster; that oil and gas involvement could be a “gamechanger” for the industry. To be clear: I wholeheartedly agree. I’ve made it the focus of my career to help make that happen. However, I have also always had a nagging question in the back of my mind: does the geothermal industry have its eyes wide open about what real and sustained oil and gas engagement in geothermal — geothermal energy at oil and gas scale — would look like? Are we headed for happy marriages or irreconcilable discord between hydrocarbon and geothermal players when this “pivot” into geothermal does occur in the oil and gas industry? And what can the geothermal industry do to help steer the ship in prickly areas like social license in the coming years as oil and gas companies engage? I think we should start a dialog about this quickly before it becomes hindsight. My hope for this piece is to start those conversations.

First, let me reveal my bias. I am, at my core, a climate activist — a tree-hugging environmentalist. I have joked  with my oil and gas friends that if I could have strapped myself to an elk to prevent drilling incursions into the Arctic, I would have. My career can be fairly described as a series of attempts to claw my way onto the deck of the hydrocarbon ship and grab hold of the wheel. My latest quest on this journey is recruitment of the hydrocarbon sailors to the cause of geothermal energy. I want oil and gas to flip the switch and pivot from hydrocarbons to heat, a relatively quick and painless way to solve energy and climate change in one shot. I view the oil and gas industry as the most capable and resourced asset we have on the planet to solve climate change, and with geothermal, they can accomplish that end by leveraging what they already know and do.

Everything I do is colored with the hope that this “pivot” will happen within the next decade. I understand that this proposition has complex implications for the geothermal industry itself. So, back to our topic of discussion.

A primary reason the oil and gas industry has gotten excited about geothermal is that they are increasingly viewing geothermal as globally scalable. This concept is a relatively recent development within operators, occurring over approximately the past year at an accelerating pace, driven by an almost industry-wide realization that the enabling technology developments of the frack boom and offshore HPHT plays could directly apply to make geothermal scalable and profitable.

Yes, oil and gas companies have thought about geothermal before, many a decade or more ago, and declined to engage, labeling the entire prospect as “niche.” Some have ventured — “forayed” as they often say — into geothermal projects, only to divest and wash their hands years later, many as the shale boom took off and the grass started to look greener (somewhat ironically) back in hydrocarbons. There are plenty of folks in my inbox who question the longevity of oil and gas engagement in geothermal, particularly given that this interest now (and only recently) coincides with a drastic downturn.

But this time is different. A convergence of factors makes it different. The enabling technologies and bursts of innovation of the past two decades in the oil and gas industry are one piece. Carbon neutrality commitments with clocks ticking and no clear path to execution is another, combined with increasing global climate activism and associated divestment movements. The sudden demand destruction and oil price crash related to COVID-19 has had the unexpected — and of benefit to geothermal — effect of freeing up a lot of the brainpower needed to consider geothermal problems within oil and gas entities. Major IOC “X” is going to try to avoid laying off their star geophysicists and petroleum engineers in a downturn — so many have repurposed key talent toward the geothermal problem set with exciting and fast-moving results.

Oil and gas industry engagement in geothermal isn’t a quaint proposition. In my view, if it happens, it’s not going to be about applying oil and gas technologies; instead, it will keep things business as usual in the geothermal industry.

Some oil and gas companies have begun to consider what it might look like if they were to drill for geothermal energy at the scale they currently drill for oil and gas. To illustrate, instead of drilling an average of 15 geothermal wells per year in the United States, which is the current paradigm, we would be drilling 20,000. Achieving this level of scale would take time, yes — but once oil and gas gets going on well manufacturing — drill the limit — this could mean break- neck speed compared to the current pace of geothermal development.

Where you sit in the geothermal ecosystem likely defines your level of acceptance or suspicion about this concept of “geothermal anywhere” enabled by the oil and gas industry.

If you are a geothermal startup looking to demonstrate or scale new concepts, oil and gas engagement, strategic partnership, and investment likely looks like a resounding win. Plus, you have an exit and relatively near-term payday. In my current role, I have a good deal of visibility into the startup arena and oil and gas engagement, and the past six months have been exciting and exponentially fast.

Geothermal startups at large are not only engaging with operators at an increasing pace, but they are also showing up on acquisition target lists of these companies as they build their internal geothermal strategies.

But let’s consider for a moment a scenario where, within five years, almost every geothermal startup in our global ecosystem has either been wholly acquired or entered into a strategic partnership with an oil and gas company. Would this be considered a win by the geothermal industry at large? I have concluded personally the answer is yes — as long as the oil and gas companies deploy their newly acquired capabilities to quickly and actively develop geothermal projects — but I also acknowledge that the implications are complex. For example, one major obstacle to cost-effective geothermal development that I’ve heard from consistently geothermal industry players is that they have not had access to the latest drilling technologies and techniques for their projects, largely due to undercapitalization and a resulting lack of engagement by large and highly skilled oil service providers. Given this already constrained tech-transfer situation, what if those same oil service providers came to be majority shareholders in a critical mass of innovative geothermal companies?

If you are engaged on the regulatory side of geothermal project development, an area that is frustrating, unfairly slow, and tedious in parts of the world, the oil and gas lobby throwing in on geothermal might sound like an excellent proposition.

The same goes for folks who are advocates of increased public funding and subsidies for geothermal. Powerful lobbies are more than welcome, right? But powerful lobbies come with heavy baggage, and the oil and gas industry lobby may be, at least to environmentally conscious folks, the least palatable entity of them all in terms of coming together to push for common cause.

Where this trade off will land is an intriguing area of inquiry. Where the really interesting questions arise, in my view, is where we may have true divisions of loyalty, deeply held hard feelings and cultural disagreements between geothermal industry entities and oil and gas suitors. I’m thinking of the publicly traded companies with significant numbers of environmentally minded shareholders and employees, the industry and industry-associated organizations who may not be keen on mixing their hard- earned reputations with the historical baggage that comes with the oil and gas industry, the employees of geothermal industry entities who may have joined the ranks of geothermal in opposition to oil and gas only to find that they may become oil and gas employees in a wave of acquisitions.

Let’s consider the example of a well-established geothermal industry entity. If you are a legacy industry player with significant intellectual property, valuable holdings, an easily replicable business model, and significant institutional knowledge, you may very well also end up on an acquisition target list in the coming years, should oil and gas decide geothermal is their courtship interest. Even if you are public. Again, the differences in scale between the two industries rise to the fore. The world’s largest publicly traded geothermal company has a market cap of about US$3 billion. Oil and gas operators have a combined market cap exceeding US$1 trillion, with several of the largest clocking well in excess of US$100 billion each, even now, in the midst of a severe downturn. For upper-level management of such companies in the geothermal industry, I think it is worth consideration of how such an approach might be received and what strategies could be put in place to make such a transition/acquisition palatable.

Another interesting twist in human dynamics is the seemingly significant and widespread tension (or, at least, the perception of tension) between geothermal and oil and gas folks. The tension is oft described as “arrogance” or “condescension” in reference to the other — interestingly reported similarly by both sides of the aisle. Given this underlying dynamic, would the geothermal industry find the role of “white knight” by oil and gas companies palatable? This question becomes even more interesting if you back out further and consider the question of NGOs and environmental activists, and their willingness to accept the oil and gas industry as “climate saviors” — propelled to this title by a green drilling boom and geothermal’s social license. Exploring how these dynamics may play out in the coming years within the geothermal industry and making a plan within entities to manage them seems to be a worthwhile exercise. It is certainly an area that I spend a good deal of time pondering.

We are headed for a period of fast change in geothermal over the next decade. For some, it will be experienced as a revolution. For others, perhaps it will be perceived as disruption. But how we plan for and navigate this coming decade will determine not only how fast we go in this transition, but how well stakeholders collaborate with one another and how well we become a team. We will need to create an entirely new culture as we merge two industries, defining boundaries, principles, and commonalities as we go on a shared quest for climate change mitigation, access to ubiquitous clean energy, and profit making. A common enemy unites rivals under a common identity, or so the saying goes. How we manage the details and nuance of uniting two industries in a common cause, I believe, will define our success. Let’s set ourselves up to succeed, one conversation at a time.

The use of geothermal energy is on the rise in the United States. Major universities are in the process of developing and building their own geothermal energy plants while legislation is being drafted to help the industry, including tax breaks and allowances for ease of development. All of this is setting the stage to make the geothermal energy industry a powerful source of employment, especially for those in the oil and gas industry who have lost their jobs during the COVID-19 pandemic.

The oil and gas industry has experienced a downturn amid COVID-19 that is set to rival the oil price crash of 2010– 2015, when the industry recorded a loss of 60,000 of its 200,800 jobs. Meanwhile, California has lost nearly 20% of the state’s total clean energy workforce, which is more than 100,000 jobs. The state lost more than three times as many jobs as any other state in the United States. Geothermal can potentially replace all these jobs lost within the next 10 years, but decisive policy support is required to make it happen.

Geothermal energy is seeing increasing interest in regions across the United States for everyone from homeowners, state and local governments, and academic institutions. Cornell University in Ithaca, New York, and West Virginia University (WVU) in Morgantown, West Virginia, are both keen on setting up Deep Direct-Use (DDU) for their campuses.

Cornell University has conducted a two-year feasibility study to completely heat and cool its campus with renewable energy. Several years ago, the university implemented renewable direct-use cooling throughout its campus; now it’s exploring the use of geothermal energy for direct-use to provide 50 MW(th) of base-load heating for the campus. Bioenergy generated from Cornell’s farms and food waste is being evaluated for providing peak heating needed for the approximately 20 extremely cold days that occur yearly.

According to the study Earth Source Heat: Feasibility of Deep Direct-Use of Geothermal Energy on the Cornell Campus, the university has “already created the sustainable, emissions-free lake source cooling system … we now explore Deep Direct-Use (DDU) as part of a hybrid system: an engineered geothermal system (EGS) for base-load district heating, and biomass combustion for peak demand.”

WVU is also hoping that the use of a DDU will help with heating costs in the long run. As stated in the report Feasibility of Deep Direct Use Geothermal on the WVU Campus-Morgantown, WV, WVU was chosen because of the “optimal and unique combinations of critical factors necessary to develop deep direct use geothermal.”

The planned system to be implemented is unique because it will allow geothermal heat to be used as both a heating and an energy source for absorption cooling, allowing amortization of systems costs within a full 12-month year.

With these feasibility studies completed, it is now possible to put the previous employees of the now idle rigs in the Northeast and Midwest to work — with the oil and gas industry in a lull, geothermal can replace these lost jobs permanently, while building clean energy infrastructure that will benefit the United States for decades to come.

Geothermal Rising is supporting a wide array of legislation to help with the growth of geothermal. Action needs to be taken now due to the severity of the COVID-19 pandemic.

The Moving Forward Act would allow geothermal technologies to access an investment tax credit at a 30% level through January 1, 2028, and all energy credits can elect for direct pay. It would also allow expedited permits for geothermal projects on federal lands, give the Department of the Interior some flexibility on rental rates, and set a goal of no less than 25 GW of wind, solar, and geothermal on federal lands by 2025. It also aims to promote co-production of geothermal energy on oil and gas leases, and allows for non-competitive leases on adjoining lands for geothermal.

The Advancing Geothermal Innovation Leadership Act of 2019 looks to advance geothermal energy resources from direct use to power production. The act is meant to grow geothermal technologies with new research and demonstrate new geothermal capabilities.

The Advanced Geothermal Research and Development Act of 2019 would increase geothermal energy development while lowering the cost of development. The bill would also continue the operation of the Utah-based Frontier Observatory for Research in Geothermal Energy (FORGE) site, as well as create a co-production of geothermal energy and critical minerals initiative.

Another bill, Enhancing Geothermal Production on Federal Lands Act, amends the Geothermal Steam Act of 1970 to facilitate the exploration for geothermal resources on federal lands. It would remove barriers for geothermal activities on federal lands by streamlining the discovery and permitting process.

Geothermal Rising is also supporting two pieces of tax legislation: the Growing Renewable Energy and Efficiency Now (GREEN) Act and the Energy Sector Innovation Credit (H.R.5523).

The renewable resource landscape of California is continuously changing due to several factors, notably the state's success in facilitating expansion in renewable energy, which is mostly solar. The state has continued to advance its clean energy policies with the current objective of decarbonization by 2045, an objective guided in part through the California Public Utilities Commission's (CPUC) Integrated Resource Planning (IRP) process and similar planning processes within the large, publicly-owned utilities. Due to these factors, while geothermal is not the lowest cost resource on a levelized cost basis, it is by far the highest economic value in renewable resources that are operating in California and the surrounding region.(1) Even as we see the contract prices for wind, solar PV, and lithium- ion battery prices decline, geothermal's economic value over the life of long-term purchase agreements remains competitive as California and the region move to higher penetrations of renewable energy.

Ormat tracked how solar PV and geothermal energy market values changed over several years. Stand-alone solar energy on the California grid has grown from just under 500 MW in 2010 to over 25 GW of capacity today. This influx has been leading to progressively lower energy market prices during solar production hours and price spikes during the solar ramp periods. Resources, such as geothermal, that can operate outside the solar production hours have maintained a higher market value compared to solar.

These trends are illustrated in Figure 1 (below) and examine the annual value of a geothermal production profile compared to a sample solar PV production profile taken from a CPUC model from 2012 – 2020 Q1 (January – April).1 At the start of this process, solar energy was worth more than geothermal because it shaved peak energy prices.

However, in the last two to three years, geothermal profiles have been worth around $10/MWh more than a solar profile on average, and commercial forecasts of future energy prices suggest this gap will continue to grow, getting closer to $20/MWh.1 Geothermal's increasing value has persisted into 2020 despite COVID-19 impacts to demand, which decreased solar's value more than geothermal. While the new bulk storage now coming online in California will allow for some energy to be shifted to flatten the “duck curve,” the growing solar energy surpluses will far exceed storage capacity. Hence, forecast models suggest that there will not be much change in this basic pattern for some time.(2)

Another critical factor in the changing value of renewable resources has been the declining RA capacity value of new solar generation. This was predicted in research studies,3 confirmed by the CPUC a few years ago in its RA proceeding, and now its IRP modeling. In California, solar generation has already shaved the annual peak loads and new stand-alone solar no longer provides that benefit. As such, the capacity value of new solar has been adjusted to virtually zero for RA and planning purposes.

Over the past couple of years, this decline in solar capacity value, along with the retirement of older natural gas plants, was reflected in California's bilateral RA capacity prices. These doubled in 2019, reflecting shortages in capacity. This shortage of capacity is why newly-planned solar projects have integrated batteries that enable energy shifting to capture some capacity value. Hybrid resources have not yet proven themselves and are still energy-limited where the storage is charged from the solar field and not the grid.

In contrast, geothermal brings a 90-95% capacity value and a history of reliable operations regardless of the weather. The consistent performance of geothermal as a capacity resource, at all times, is now capturing the attention of buyers across the region.

As the CPUC and California load-serving entities turn to IRPs and other types of long- term analysis to guide procurement and planning decisions, geothermal's multiple values need to be closely examined. California's IRP tools have always selected geothermal at some point in the planning horizon across a range of cost points, even when the model also selects a large amount of solar and storage. The reason geothermal is selected in IRP models is the fact that higher decarbonization targets require the displacement of more and more natural gas-fired and nuclear capacity.

Replacing high-capacity fossil generation in an IRP with renewables results in 1 MW of geothermal displacing 4-5 MW of solar and storage capacity. What we found is that the IRP models build multiple solar plants with storage to displace one geothermal profile. Hence, a simple 1:1 LCOE comparison between these technologies is inadequate. This result is only now starting to be understood by planners; as we look out over the next 20 years, each MW of geothermal procured will require much less solar with storage.

The trends described in this article have been consistent for several years. They suggest that geothermal developers should have confidence that, if more of the resource can be delivered within a reasonable cost range, it will find buyers. A single geothermal project is not competing against the price of a single PV project with storage, but rather the cost of 4 PV projects with storage. It is vital that geothermal developers are helping to tell this story. In addition to stimulating increased geothermal demand across the western United States, these findings should lead to an improved analytical and policy framework for the benefits of geothermal on a global scale.

1. Thomsen P. The Increasing Comparative Value of Geothermal in California– Recent Trends and Forecasts as of Mid-2019. Presentation at: Proceedings World Geothermal Congress; April 26 - May 2, 2020;Reykjavik, Iceland.
2. All prices used for these calculations are downloaded from the CAISO OASIS website. A table comparing geothermal energy value to three different sample solar profiles used for CPUC modeling can be found in Thomsen (2020, 2018a). This profile is one of the ones in the table, updated to 2020.
3. Thomsen P. The Increasing Comparative Value of Geothermal in California–2018 Edition. CD recording: GRC Transactions 2018a;42.