Geothermal – can it make up for peak fossil fuels?

Geothermal provides less than half a percent of U.S. electric power.

NREL (2016) recently looked at whether the current 3.8 GWe could be doubled to 7.6 GWe by 2020,  and found that only .784 GWe was likely, with another .856 GWe possible with expedited development (these projects often take 5 years), and another 1.722 GWe if financing could be found and permits given. The report concluded it was unlikely that doubling geothermal electricity capacity could happen by 2020.

There’s not enough geothermal to make a dent in the “imminent liquid fuels crunch (Murphy 2012).

Abundant, potent, or niche? Hmmm. It’s complex. On paper, we have just seen that the Earth’s crust contains abundant thermal energy, with a very long depletion time. But extraction requires a constant effort to drill new holes and share the derived heat. Globally we use 12 TW of energy.  Heat released from all land is 9 TW, but practical utilization is impossible. For one thing, the efficiency with which we can produce electricity dramatically reduces the cap to the 2 TW scale. And for heating just 1 home, you’d need to capture heat from an area 100 meters on a side. Clearly, geothermal energy works well in select locations (geological hotspots). But it’s too puny to provide a significant share of our electricity, and direct thermal use requires substantial underground volumes/areas to mitigate depletion. All this on top of requirements to place lots of tubing infrastructure kilometers deep in the rock (do I hear EROEI whimpering?). And geothermal is certainly not riding to the rescue of the imminent liquid fuels crunch.

Geothermal consumes massive amounts of water & energy

Geothermal plants use a lot of energy to keep the water hot enough to prevent minerals from precipitating out and clogging pipes and heat exchangers. Some were poorly managed and exhausted after running out of water. Maintenance costs are high due to corrosion from corrosive gases and aerosols, etc.

“As with fossil fuel power plants and concentrating solar power, increases in air and water temperatures can reduce the efficiency with which geothermal facilities generate electricity, according to DOE’s 2013 assessment. Geothermal power plants can also withdraw and consume significant quantities of water, according to DOE, making them susceptible to water shortages caused by changes in precipitation or warming temperatures” (USGAO 2014).

94% of all known U.S. geothermal resources are located in California.

Figure 1. Map of United States geothermal regions.

Figure 1. Map of United States geothermal regions.

Source: NREL 2016. United States geothermal total estimated project capacity (in megawatts) by geothermal region (2012-2015). This figure highlights areas that had significant proportions of projects that were either discontinued or postponed: Idaho Batholith (100%), Gulf of California Rift Zone (77%), Alaska (45%), Northwest Basin and Range (47%), the Walker-Lane Transition Zone (44%), and the Northern Basin and Range (36%).

Figure 2. Source: NREL 2016. United States geothermal total estimated project capacity (in megawatts) by geothermal region (2012-2015). This figure highlights areas that had significant proportions of projects that were either discontinued or postponed: Idaho Batholith (100%), Gulf of California Rift Zone (77%), Alaska (45%), Northwest Basin and Range (47%), the Walker-Lane Transition Zone (44%), and the Northern Basin and Range (36%).


Lack of transmission lines strands many geothermal sites

Only a few urban areas in California and other states with geothermal resources (i.e. volcanoes, hot springs, and geysers) are near enough to exploit them.  This is because the cost of adding very long transmission lines to faraway geysers can make a geothermal resource too expensive – they’re already very expensive even when closer to cities.  On top of that, unless the geothermal resource is very large, more of the power is lost over transmission lines than conventional power plants (CEC 2014 page 73).

Getting the financing is hard

The current environment for financing independent power projects is challenging. These challenges include weak corporate profits, changes in corporate direction, and heightened risk aversion. As a result, a number of the financial institutions that were lead underwriters in the past are either pulling out of the market or are taking a lower profile in project financing.

Biomass and geothermal projects are considered riskier than natural gas, solar, and wind projects. This is seen in the lower leverage, higher pricing, and higher DSCRs than for the other generating technologies. The higher level of project risk for biomass and geothermal projects is partly attributed to the technology and fuel sources. Solid fuel power plants require more project infrastructure than do other fuel types. Geothermal projects have inherently uncertain steam supplies as has been seen at the Geysers. Some of the risk also is based on the relatively small number of these projects being developed.

The steadily increasing wheeling access charges the California ISO expects to put in place over the next decade represent a growing, significant cost to renewable developers who find their best renewable resources in locations that are distant from demand.

They can be risky to develop since they don’t always work out. In June 1980, Southern California Edison (SCE) began operation of a 10 MW experimental power plant at the Brawley geothermal field, also in Imperial County. However, after a few years of operation further development was ceased due to corrosion, reservoir uncertainties, and the presence of high salinity brines.

Issues with geothermal installations

There are two components to the geothermal resource base: hydrothermal (water heated by Earth) that exists down to a depth of about 3 km, and enhanced geothermal systems (EGS) associated with low-permeability or low-porosity heated rocks at depths down to 10 km.

A National Academy of Sciences concluded that hydrothermal resources are too small to have a major overall impact on total electricity generation in the United States — at best 13 GW of electric power capacity in identified resources (NAS 2009).

The largest geothermal installation in the world is the Geysers in Northern California, occupying 30 square miles. The 15 power plants have a total net generating capacity of about 725 MW of electricity—enough to power 725,000 homes (Heinberg).

  • Geothermal plants often emit hydrogen sulfide, CO2, and toxic sludge containing arsenic, mercury, sulfur, and silica  compounds.
  • Extra land may be needed to dispose of wastes and excess salts
  • groundwater and freshwater can be a limiting force since both hydrothermal and dry rock systems need water
  • Maintenance costs are high because the steam is corrosive and deposits minerals, which clogs pipes and destroys valves.
  • When you extract energy from just about anything it decreases, the same is true for geothermal. So you endlessly need to keep looking for more prospects. For example, the “Geysers” area of Northern California has gone from 2000 MWe to 850 MWe since it was first tapped for power. J. Coleman. 15 Apr 20001. Running out of steam: Geothermal field tapped out as alternative energy source. Associated Press.
  • We need a breakthrough in materials that won’t melt to drill deeply enough to get significant power in non-geothermal areas.
  • You can lose a significant amount of steam because the water you pour down the hole is so hot it fractures rocks and escapes into cracks before it can return up the steam vent. Over time, less and less steam for power generation is produced.
  • If you wanted to tap the heat without any geothermal activity, it becomes energy intensive, because you have to drill much deeper (geothermal sources are already near the surface), the rock below has to be fractured (which it already is in geothermal regions) to release steam, and fracturing and keeping the rock fractured takes far more ongoing energy than the initial drilling.
  • No one has figured out how to do hot dry rock economically – time’s running out.
  • Even if Geodynamics succeeds in scaling their experiments into a real geothermal power plant, it will in huge part be due to the location: “This is the best spot in the world, a geological freak,” Geodynamics managing director Bertus de Graaf told Reuters. “It’s really quite serendipitous, the way the elements — temperature, tectonics, insulating rocks — have come together here.

Although it would be great if we could access the heat 3 to 10 km below the earth, such operations would cool down so much that they’d have to be shut down within 20 to 30 years, and production wells would need to be re-drilled every 4 to 8 years meanwhile.  We don’t know how to do this anyhow.  Despite oil and gas drilling, we don’t have much experience going this deep or know how to enhance heat transfer performance for lower-temperature fluids in power production. Another challenge is to improve reservoir-stimulation techniques so that sufficient connectivity within the fractured rock can be achieved.  France has been trying to make this work for over 2 decades, so don’t hold your breath (NAS 2009).

Geothermal Technology Costs

Geothermal technologies remain viable in California, although they are subject to a number of limitations that are likely to reduce the number of sites developed in California.

Geothermal resource costs are driven largely by the highly variable and significant costs of drilling and well development. These costs are unique to each site and represent a significant risk on the part of the developer. While a successful well may be able to produce electricity at low cost, other wells in the same area may require much more investment in time and resources before they are producing efficiently. Costs for new geothermal plants are projected to increase slightly over the coming years. Limitations of location and drilling are unlikely to see improvement in California, while nationally there are very few geothermal projects under development.

Factors Affecting Future Geothermal Development

California’s relative abundance of geothermal resources in comparison to the rest of the United States does not mean that geothermal power production would be viable or cost-effective everywhere in the state. Developers must consider multiple factors of cost and viability when deciding where to locate new geothermal plants. In turn, these considerations drive the estimates of future costs of new geothermal power plants in California. Considerations for developing geothermal power plants in liquid-dominated resources include (Kagel, 2006):

  • Exploration Costs- Exploration and mapping of the potential geothermal resource is a critical and sometimes costly activity. It effectively defines the characteristics of the geothermal resource.
  • Confirmation Costs-These are costs associated with confirming the energy potential of a resource by drilling production wells and testing their flow rates until about 25 percent of the resource capacity needed by the project is confirmed.
  • Site/Development Costs- Covering all remaining activities that bring a power plant on line, including:   Drilling- The success rate for drilling production wells during site development average 70 percent to 80 percent (Entingh, et al., 2012). The size of the well and the depth to the geothermal reservoir are the most important factors in determining the drilling cost.
  • Project leasing and permitting-Like all power projects, geothermal plants must comply with a series of legislated requirements related to environmental concerns and construction criteria.
  • Piping network- The network of pipes are needed to connect the power plant with production and injection wells. Production wells bring the geothermal fluid (or brine) to the surface to be used for power generation, while injection wells return the used fluid back to the geothermal system to be used again.
  • Power plant design and construction- In designing a power plant, developers must balance size and technology of plant materials with efficiency and cost effectiveness. The power plant design and construction depends on type of plant (binary or flash) as well as the type of cooling cycle used (water or air cooling).
  • Transmission- Includes the costs of constructing new lines, upgrades to existing lines, or new transformers and substations.

Another important factor contributing to overall costs is O&M costs, which consist of all costs incurred during the operational phase of the power plant (Hance, 2005). Operation costs consist of labor; spending for consumable goods, taxes, royalties; and other miscellaneous charges.

Maintenance costs consist of keeping equipment in good working status. In addition, maintaining the steam field, including servicing the production and injection wells (pipelines, roads, and so forth) and make-up well drilling, involves considerable expense.

Development factors are not constant for every geothermal site. Each of the above factors can vary significantly based on specific site characteristics.

Make-up drilling aims to compensate for the natural productivity decline of the project start-up wells by drilling additional production wells. drive costs for geothermal plants (not mentioned directly above since they are highly project specific) are project delays, temperature of the resource, and plant size.

The temperature of the resource is an essential parameter influencing the cost of the power plant equipment. Each power plant is designed to optimize the use of the heat supplied by the geothermal fluid. The size, and thus cost, of various components (for example, heat exchangers) is determined by the temperature of the resource. As the temperature of the resource increases, the efficiency of the power system increases, and the specific cost of equipment decreases as more energy is produced with similar equipment. Since binary systems use lower resource operating temperatures than flash steam systems, binary costs can be expected to be higher. Figure 33 provides estimates for cost variance due to resource temperature. As the figure shows, binary systems range in cost from $2,000/kWh to slightly more than $4,000/kWh, while flash steam systems range from $1,000/kWh to just above $3,000/kWh (Hance, 2005).

Technology Development Considerations

In addition to the cost factors listed in the previous section of the report addressing geothermal binary plants, for some flash plants a corrosive geothermal fluid may require the use of resistive pipes and cement. Adding a titanium liner to protect the casing may significantly increase the cost of the well. This kind of requirement is rare in the United States, found only in the Salton Sea resource in Southern California (Hance, 2005).

Bradley, Robert L., Jr. Geothermal: The Nonrenewable Renewable. National Center for Policy Analysis.

CEC. 2014. Estimated cost of new renewable and fossil generation in California. California Energy Commission.

Hance, C. August 2005. Factors Affecting Costs of Geothermal Power Development, Geothermal Energy Association.

Heinberg, Richard. September 2009. Searching for a Miracle. “Net Energy” Limits & the Fate of Industrial Society. Post Carbon Institute.

Kagel, A. October 2006. A Handbook on the Externalities, Employment, and Economics of Geothermal Energy. Geothermal Energy Association.

Murphy, Tom. 10 Jan 2012. Warm and Fuzzy on Geothermal? Do the Math.

NAS 2009. America’s Energy Future: Technology and Transformation. 2009. National Academy of Sciences, National Research Council, National Academy of Engineering.

NREL. January 2016. Doubling Geothermal Generation Capacity by 2020: A Strategic Analysis.  National Renewable Energy Laboratory.  Technical Report NREL/TP-6A20-64925

USGAO. January 2014. CLIMATE CHANGE Energy Infrastructure Risks and Adaptation Efforts GAO-14-74. United States Government Accountability Office.






This entry was posted in Alternative Energy, Energy, Geothermal and tagged . Bookmark the permalink.

Comments are closed.