Geothermal Assisted Power Generation for Thermal Power Plants

By Nigel Bean Chair of Applied Mathematics, School of Mathematics, University of Adelaide & Josephine Varney Ph.D. Candidate, University of Adelaide for Cornerstone

The recent push to reduce carbon emissions from the electricity sector encompasses common, immediately available approaches such as increasing power plant efficiency and increasing the deployment of renewables. The opportunity now exists to accomplish these goals simultaneously through the use of geothermal energy to increase the power output, and decrease the carbon intensity, of thermal power plants. This technology is referred to here as geothermal assisted power generation (GAPG). Basically, GAPG employs hot geothermal fluid to heat the boiler feedwater at a thermal power plant. The steam that would otherwise be taken from the turbines to heat the feedwater is allowed to run through the turbines, thereby generating extra power and increasing plant efficiency. Here we use efficiency to mean “fossil fuel efficiency”, as more power is generated per unit heat (MMBtu) of fossil fuel, because of the addition of the geothermal heat.

Steam rises as a result of the excess heat of a standalone geothermal plant.
GAPG would use geothermal heat more efficiently.

Not only would this technology increase the efficiency of existing thermal power plants, most of which are coal fired, it would also assist the development of the immature technology of utilizing unconventional geothermal resources. As coal-fired power plants rarely exist near conventional (hydrothermal, volcanogenic) geothermal resources, some have drawn the incorrect conclusion that GAPG is of little value or can only be applied in rare cases. However, the development of unconventional (nonhydrothermal, nonvolcanogenic) geothermal resources offers the potential for geothermal energy to be exploited over a much larger geographic range. Therefore, we believe that GAPG should be strongly considered as a means for integrating conventional energy with renewable energy in the most efficient manner possible.


Geothermal energy has been defined as “utilizable heat from the earth”.1 Given that the earth’s temperature increases with depth below the surface, geothermal energy exists everywhere. Further, since it is possible to use geothermal energy to generate power, it has the potential to be a renewable, carbon-free source of baseload electricity. However, while geothermal energy exists everywhere, the cost of extracting this energy does not make it commercially viable everywhere. To be commercially viable a geothermal resource must have sufficient temperature and flowrate that can be accessed relatively simply.

Conventional geothermal resources—characterized by depths of <3000 m, high temperature, and highly permeable rock formations—are generally commercially viable, depending on the regional energy market (see Figure 1). Such resources are usually found in volcanic regions, but the last 40 years have seen growing activity in research and development of the unconventional geothermal resources that exist outside the volcanic regions. To date, only one of these resources, at Landau in Germany, has been shown to be commercially viable. However, given the significant promise of the unconventional geothermal resource, work to develop it continues.

FIGURE 1. Schematic of geothermal resources

The first step is to find geothermal resources with sufficient temperature and at a depth that can be drilled economically. Unconventional geothermal resources with the potential to be used for electricity generation are divided into two types: deep natural reservoirs (DNRs) and enhanced geothermal systems (EGSs).1 DNRs are systems that make use of deep, naturally occurring aquifers with high permeability. EGS resources have little natural permeability, hence these resources must have their permeability increased via stimulation or fracturing.

The most significant unknown in unconventional geothermal systems is the flowrate per well (or well pair). Unconventional geothermal resources are chosen for their heat and their potential permeability. The degree of permeability of a resource is directly linked to its flowrate. However, when there is insufficient natural flowrate, a reservoir’s permeability
can be increased by fracturing. Stimulation technology in a geothermal context is immature, producing “good results some of the time”.1 However, stimulation technology has provided huge productivity improvements in oil and gas wells, so there is hope that similar results will be possible in unconventional geothermal wells. Still, there must be sufficient unconventional geothermal developments to allow stimulation trials/demonstrations to support the development of this technology.

In the near term, the development of unconventional geothermal resources holds significant financial risks, which are largely based on specific geological formations and the need for stimulation. Such risks must be mitigated in some way; from this perspective, GAPG is a major opportunity. Figure 1 shows a simplified means of extracting geothermal energy. Note that actual geothermal developments have many wells, as each producing well can only produce a limited amount of flow. This means that the flow from any geothermal resource increases in a stepwise manner, with each new producing well drilled.


GAPG is based on the concept of using high-temperature geothermal fluid to heat the boiler feedwater of a thermal power plant. It was first suggested by Khalifa et al. in 19782 as a replacement for low-pressure feedwater heaters (FWHs). In 2002, Bruhn built on Khalifa’s design,3 making it significantly more flexible by allowing GAPG to partially replace any of the low-pressure FWHs. After considering the low-temperature geothermal resources most often available near thermal power plants, in 2010, Buchta focused on very low-temperature geothermal fluids (30–100°C) and considered applying GAPG to only the first low-pressure FWH.4

Of course, geothermal energy is not the only renewable energy source that can be applied to increasing the efficiency of thermal power plants. Hu et al. investigated both geothermal and solar thermal sources for efficiency gains5 and found that the higher temperatures achievable from solar power makes it possible to consider applying heat to the intermediate- and high-pressure FWHs. Then, more recently, Varney and Bean determined the net-power gain for all feasible geothermal flowrates and, further, discussed the flowrate and power limits of GAPG.6

Focused research over many years has generally found that GAPG can be retrofitted to any large thermal power station, although the economics are site-specific. It can be used to fully or partially replace the low-, intermediate-, or high-pressure FWHs; however, it is most likely to be used to replace only the low-pressure FWHs. Depending on the needs of the individual plant, GAPG can increase the power generated (power boosting mode) or it can be run to reduce the amount of fossil fuel consumed (fuel saving mode). The simplest and most flexible implementation was described by Bruhn and is shown in Figure 2.3 In Bruhn’s implementation of GAPG, feedwater is withdrawn upstream of the first low-pressure FWH and is then heated by the geothermal fluid in the geothermal feedwater heater (GFWH). The geothermally heated feedwater is then returned to the feedwater stream via flows ṁG1, ṁG2, ṁG3, and/or ṁG4 (depending on the temperature and flowrate of the geothermal fluid).

FIGURE 2. Schematic of GAPG

Given that geothermal fluids are not clean enough to mix with feedwater, GAPG can only be used to replace closed feed-water heaters (i.e., not the deaerator). In order to cool the extra steam coming through the turbine(s), additional condenser capacity is required, which could be managed by the installation of a new, small condenser.


In our modeling, we retrofitted GAPG to a 500-MW natural-gas-fired, supercritical steam power station, specifically, the Public Service Company of Oklahoma, Riverside Station Unit 1. Although we modeled a gas-fired plant, the analysis could have been applied to a coal-fired power plant and would yield the same results.

One major advantage of GAPG is it’s flexibility: Power can be generated from low geothermal fluid flowrates that otherwise might be of little value in a stand-alone geothermal facility. As these flowrates increase, power generation increases. For example, see Figure 3 which shows the incremental electricity generated as the flowrate of the geothermal fluid is increased. Note that three different temperatures were evaluated (i.e., 150, 175, and 200°C).

FIGURE 3. Geothermal fluid flowrate versus power generation

Using geothermal heat to boost the efficiency of a thermal power plant increases thermal efficiency above stand-alone geothermal plants by 1.7 to 2.9 times, depending on the geothermal fluid temperature.6 However, there is a limit to the amount of geothermal energy that can be utilized through GAPG at any given thermal power plant—once the appropriate FWHs are totally replaced by geothermal feedwater heaters, no further additional power can be produced. To achieve this maximum power limit, a geothermal resource temperature greater than the outlet of the hottest appropriate  FWH (in our modeling the hottest low-pressure FWH was ~160°C) is needed (see Figure 4a). As the geothermal resource temperature increases above ~160°C, the flowrate required to reach this maximum power limit decreases (see Figure 4b). At temperatures less than ~160°C, the maximum power limit cannot be achieved, irrespective of the flowrate (see Figure 4a). Our modeling showed that power could be increased by a maximum of ~6.5% in the modeled 500-MW supercritical plant. To achieve maximum power, a geothermal fluid flowrate of 190–290 kg/s was needed, with lower flowrates for the higher geothermal fluid temperatures and higher flowrates for the lower geothermal fluid temperatures. Despite this maximum power limit, considering the reduced risk to the geothermal developer and the power producer, it is still likely to be worthwhile to take advantage of GAPG.

FIGURE 4. (a) Maximum power output from GAPG; (b) maximum flowrate


Coal-Fired Power Generators

GAPG allows coal-fired power plants to generate more power and reduce their carbon intensity through increased efficiency. Once a geothermal developer brings hot geothermal fluid to the surface, GAPG yields very little risk for the power plant owner. The revenue that can be generated by extra power production will be recognized by the plant operators, as will the capital costs of installing the necessary geothermal feedwater heat exchangers, additional condenser capacity, and extra piping. Hence, power plant operators can decide what they are willing to pay for the hot geothermal fluid in order to make sufficient profits—a site-specific consideration. Finally, if the geothermal fluid stops flowing, for any reason, the power plant can revert to its original operating conditions.

Geothermal Developers

Unquestionably, greater deployment of GAPG has major implications for geothermal developers. GAPG allows them to focus on what they do best, getting hot geothermal fluid from the ground to the surface, and does not require the expertise or capital to produce and sell electricity. Further, the power plant is able to generate up to three times as much power per kilogram of geothermal fluid as a stand-alone geothermal power plant.6 Importantly, GAPG allows the developer to sell whatever hot fluid they are able to get to the surface. This means that they can take small steps—generate some revenue while learning more about the local geothermal resource and enhancing their capability. Later, the flowrate could be increased to further increase the amount of heat provided to the thermal power plant.


Looking at the equipment required for a GAPG development, drilling costs clearly are the largest and most significant portion of the overall capital cost. Of course, drilling costs vary significantly with geology and local drilling market conditions. For example, it is estimated that, on average, a 1.5-km deep well in the U.S. will cost $2.9 million and a 5-km well will cost $10.5 million. However, in Australia, which has a small number of local drilling rigs and had to mobilize some rigs from the U.S., the expected cost for similar wells is $6.6 million and $15.3 million (all estimates are given in U.S. 2014 dollars).1

Further, it is difficult to estimate how many wells are required, because flowrate per well is the other significant unknown in unconventional geothermal developments. The highest flowrate from an unconventional geothermal well has been observed at a site in Landau, Germany, which has a flowrate of 70 kg/s. However, the next highest flowrate per well was recorded at Habanero 1 in Australia, which achieved a maximum flowrate of 40 kg/s. For these reasons, an average cost for a GAPG development cannot accurately be provided. Additionally, as mentioned earlier, stimulation technology, which can potentially increase flowrate, is currently far from certain. Therefore, predicting the total costs to produce a given flowrate at a particular site is currently highly uncertain. However, with knowledge gained through further deployment of GAPG (or other forms of exploration in unconventional geothermal resources) this uncertainty can be reduced.

Although accurate costings cannot be provided, it is fair to say that, in general, unconventional geothermal developments (without the integration offered by GAPG) are not commercially viable yet. Based on drilling costs from the U.S., it is estimated that flowrates in the vicinity of 80–100 kg/s per well are required for commercial viability.1 However, it is clear that GAPG provides up to three times more power than stand-alone unconventional geothermal developments. As much as geothermal energy development is driven by local markets, including renewable portfolio standards, it is important that GAPG be recognized as a renewable energy even though it is integrated with existing thermal power plants.

Although the economics of GAPG will be uncertain until the technology is deployed, it is certain that GAPG is more economical than stand-alone geothermal plants. In addition, as greater experience and improved technology make lower drilling costs and higher flowrates possible, unconventional geothermal developments used for GAPG will become an ideal first step toward making unconventional geothermal energy commercially viable on a broad scale—to the future benefit of both geothermal energy developers and the energy consumers who currently rely on electricity from thermal power plants.


Unconventional geothermal energy is a relatively immature technology, with high capital costs and large risks, but also with enormous potential. Geothermal energy is one of the few renewable energies capable of providing baseload power; further, the size of the unconventional resource is potentially “truly vast”.1 For unconventional geothermal energy to progress it must take small steps and GAPG offers one such step.

Additional opportunities may exist for the application of geothermal energy at conventional power plants in the future. For instance, low-temperature geothermal fluids are characterized by temperatures in the range of the regeneration temperatures of post-combustion amine-based CO2 capture systems. When commercial CCS comes online, GAPG could provide the thermal load needed for CCS, thus allowing the power plant efficiency loss from CCS to be dramatically reduced.

GAPG allows unconventional geothermal developers to concentrate on the geothermal resource, not power conversion. Accordingly, power conversion can be carried out by expert thermal power plant operators, and up to three times as much power can be generated per kilogram of geothermal fluid as can be achieved in a stand-alone geothermal plant. GAPG offers power plant operators a way to increase power production and decrease their carbon footprint at essentially no risk. GAPG is potentially a win-win option for both the geothermal developer and the power plant operator.

This article is republished by permission from  All rights reserved.

The content included in Cornerstone is based on the opinion of the authors, and does not necessarily reflect the views of the World Coal Association or its members.



  1. Australian Renewable Energy Agency. (2014). Looking forward: Barriers, risks and rewards of the Australian Geothermal Sector to 2020 and 2030. Canberra: Commonwealth of Australia.
  2. Khalifa. H.E., DiPippo, R., & Kestin, J. (1978). Geothermal preheating in fossil-fired steam power plants. Proceedings of the 13th Intersociety Energy Conversion Engineering Conference, San Diego, California.
  3. Bruhn, M. (2002). Hybrid geothermal–fossil electricity generation from low enthalpy geothermal resources: geothermal feedwater preheating in conventional power plants. Energy, 27, 329–346.
  4. Buchta J., & Wawszczak, A. (2010). Economical and ecological aspects of renewable energy generation in coal fired power plant supported with geothermal heat. Paper presented at the Fourth IEEE Electrical Power and Energy Conference, 25–27 August, Halifax, Nova Scotia, Canada.
  5. Hu, E., Nathan, G.J., Battye, D., Perignon, G., & Nishimura, A. (2010). An efficient method to generate power from low to medium temperature solar and geothermal resources. Paper presented at Chemeca 2010: Engineering at the Edge, 26–29 September, Adelaide, South Australia.
  6. Varney, J., & Bean, N. (2013). Using geothermal energy to preheat feedwater in a traditional steam power plant. Proceedings of the 38th Workshop on Geothermal Reservoir Engineering, Stanford University, Stanford, California.

The authors can be reached at and

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