Advances In Really Deep Hot Geothermal Energy, But Gigantic Gaps Remain

Originally published on Forbes.com on July 11, 2024

The vision will persist, simply because Superhot Deep Rock offers an unlimited resource spread across the world and within North America.

Superhot Deep Rock is an attractive prospect for the energy transition. It promises a continuous, steady source of energy, unlike wind and solar, and it is widespread. But is there new technology that could access it, and how expensive would it be?

This is not Hot Dry Rock instigated at Los Alamos, New Mexico, in the 1970s, and expanded recently by Fervo Energy’s RED and DOE’s FORGE projects. Superhot Deep Rock is deeper and hotter than Hot Dry Rock, and the resource is even more bountiful.

Geothermal Power Is Stable

The power from solar and wind is not stable, due to obvious daily fluctuations. Three ways to obtain stability are (1) by grid-size battery storage, (2) supplementing solar and wind with geothermal, and (3) nuclear power. Battery storage is proving effective in Australia which leads the world: typical storage times are four hours, but active research is aiming to increase this to eight hours, which will provide stability all through the night.

A geothermal supplement to solar and wind would be ideal, because the earth is a constant supply of heat from deep underground. More on this below. The third way is via nuclear power, but this is expensive. Small Modular Reactors (SMR) have for a decade been endowed by the DOE, but an unexpected price increase has caused communities in Utah to recently reject a sales contract they had signed, so the commercial status of SMRs is uncertain. 

Fervo Energy applications

In a geothermal demonstration supported by Google, Fervo Energy has been producing electricity (3.5 MW) into a Nevada utility, NV Energy, which in turn provides power to a Google data center (data centers require huge amounts of electricity). The Fervo application is two parallel horizontal wells, drilled in hot granite up to 200F, and made to connect by a mesh of hydraulic fractures. A significant advance is the even distribution of fluid flow exiting the injection well and entering the production well. This is necessary for efficient present performance and to offset deadly thermal cooling breakthrough in later years of operation. The system also achieved control of output power to automatically meet the power needs in the utility grid.

Although expensive, the owners predict the cost of power will come down when produced by a full-scale field operation called Cape Station now being built by Fervo Energy, and worth $2 billion. Fervo has drilled 12 of what will eventually become 100 geothermal wells on public lands in western Utah.  Despite cost uncertainty, Southern California Edison have signed contracts for 320 MW (most of the output) of the Cape Station plant in Utah (400 MW), to be completed in 2028. This is enough to power roughly 350,000 homes in Southern California and will be the largest of any geothermal project in the world.

In Figure 1, geothermal activity can be associated with hotspots connected to the mantle. But deeper layers of the crust will be hotter and may serve as targets for enhanced geothermal projects. Oil and gas wells are drilled in the crust.

Enhancements Needed For Superhot Deep Rock 

Fervo Energy has borrowed technology from the shale revolution. Two horizontal wells that are fracked along their lengths to establish a connection, so that water pumped down one well and into the fractures constitutes a heat exchanger. EGS for Enhanced Geothermal Systems is commonly used to describe the process.

In Superhot Deep Rock, further challenging enhancements will be needed. These have been well-documented in a separate article. One is to drill into the superhot rock without melting the drill bit. Second is designing an efficient heat exchanger that allows the heat to be transferred up to the surface. Third is to direct the heat to drive turbines that make electricity. Let’s look at potential progress in these areas.

Drilling Into Superhot Rock.

Examples of deep drilling using conventional equipment are numerous. An early well on the Kola Peninsula at Murmansk in Western Russia was begun in 1989 and took 20 years to reach 40,000 feet or about 7.5 miles. But the well encountered temperatures of 180 C = 356 F that were not expected. The heat killed the drilling equipment and the venture ended. The well was also the source of a persistent rumor that cries of souls damned to hell could be heard before the drilling stopped.

In 1974, the deepest gas well in this report, called the Bertha Rogers, was drilled in the Anadarko basin, in Oklahoma, U.S. At nearly 32,000 feet (6 miles), the well met very high pressure, around 25,000 psi, and a pocket of molten sulfur which destroyed the drill bit. The operation ceased.

The world’s deepest oil well, known as Z-44 Chayvo, is located in Eastern Russia and has been drilled over 40,000 ft (7.5 miles) into the ground. For the operator, Exxon Neftegas, this and other wells are expected to produce a total of 2.3 billion barrels of oil.

To deal with extreme temperatures in Superhot Deep Rock, Quaise Energy has proposed a different drilling method. Conventional drilling would be followed by millimeter wave drilling, a cousin to the microwaves in the kitchen, that has enough energy to melt the rock (Figure 2).

As the melted rock cools, it might form a solid “casing” that protects the hole made by the system. But from an outsider’s perspective, this appears to be an enormous challenge that will require many years of research to formulate, test, and prove.

An alternate method described in the news release is the particle impact drill. Two-millimeter steel shot bullets are fired from the drill bit at something like 12 million per minute. After blasting the bottom of the hole, the shot is recirculated to the surface and used again.

It has been argued that drilling costs in such harsh conditions will be difficult to surmount.

https://www.eurekalert.org/news-releases/983677

Designing A Heat Exchanger.

In a presentation at GTS NA24 in May of 2024, Trenton Cladouhos of Quaise Energy addressed methods for cold water to pick up heat from hot rock at depth. Three heat exchangers are visualized in Figure 3. More details are provided in a separate article.

The panel on the left shows inlet pipes that are connected to outlet pipes, so that heat-carrying fluid doesn’t directly encounter the heat reservoir. This improves efficiency of the operation and avoids any fluid loss or contamination risk.

This is the method used by Eavor, who recently highlighted its success in Geretsried, Germany. The company plans to use it as a blueprint for a second venture near the town of Weilheim.

By aiming to produce over 70 MW (megawatts) of thermal energy and electrical energy, Eavor is unlocking one strand of geothermal energy’s future.  

The middle panel of Figure 3 is the geometry adopted by Fervo Energy and also the DOE-sponsored Project FORGE. Hydraulic fracturing of wells creates an elongated cloud of fractures. However, the concensus is that the bulk of the fluid moves between the two horizontal wells via dominant linear fractures.

The right panel of Figure 3 refers to Superhot Deep Rock that has been fractured by injection of cold water. The idea is the cold water will cause a myriad of tiny fractures spread over a large volume, and the resulting permeability will be significant enough to allow water/steam to flow from an injection well to a production well.  

There are two analogs that can be compared with this scenario. The first is the former Hot Dry Rock project at Los Alamos, New Mexico that began in the 1970s. The microseismic cloud there looked a lot like the right panel of Figure 3.  The project was a technical but not commercial success. Around the world, other schemes like the HDR project have been tried, and the general view is that they are, at best, commercially borderline. 

One of the reasons for lack of success is there are too few tensile (opening mode) fractures connecting inlet and outlet wells in Hot Dry Rock projects. In other words, a mesh of small shear-induced irregular fractures do not have the conductivity to allow a sufficient flowrate. The shale experience has confirmed this, and shown that high-rate fracking stimulations create more tensile fractures with high conductivity. 

The second analog is coalbed methane (coal seam gas). High-rank coals contain large volumes of adsorbed methane and are intensely fractured (called cleats). But unless the bulk measured permeability lies above 2 md, a vertical well won’t be commercially successful, even though the well has been fracked. A horizontal well is required to encounter much more reservoir to make a well commercial.

How does this carry over to the right panel of Figure 3? First, one may have access to a huge volume of mini-fractures or cleats, but that does not guarantee commercial success in a laterally extensive coalbed methane well, unless the bulk permeability is above 2 md. In Superhot Deep Rock under enormous in-situ stress, a bulk permeability of 2 md seems very unlikely. Second, in Superhot Deep Rock, the ductility (opposite to brittleness) of the rock will tend to squelch the permeability of the cracked volume so much that even long well segments that try to extract heat from the rock will not suffice to make the project commercial.  

Note that we have not considered how to create the fractured volume of Figure 3, the right panel. That may have its own difficulties. Despite challenges, Quaise Energy plans to test the theory at a place where Superhot Deep Rock lies in a shallow zone, such as Newberry volcano in central Oregon (Figure 1).

Making Electricity At The Surface.

In a Superhot Deep Rock, any water that is pumped through the downhole heat exchanger will end up as superheated steam, which can carry 5-10 times as much energy as normal steam. Upgrading turbines to deal with superheated steam may be the least problematic of the three areas.

This summary is incomplete since its based on an outsider’s perspective. A comprehensive review of Superhot Deep Rock technology needs, and especially gaps in current technology, is found in a separate article.

Takeaways.

Existing analogs, such as the Hot Dry Rock of the 1970s and the Shale Revolution of the 2000s, point to a typical time-to-success, meaning commercial success, of around 20 years for Superhot Deep Rock geothermal.  

The vision will persist, simply because Superhot Deep Rock offers an unlimited resource spread across the world and within North America. Only time will tell whether the challenges and their costs are surmountable.