Geothermal resource

There are three principle categories of geothermal resource. The simplest to exploit is a source of hot underground water (the geothermal reservoir) that either reaches the surface naturally or can be tapped by drilling boreholes. This is the geothermal source upon which all existing commercial geothermal power plants are based.

Where there are no underground water sources, anomalies in the crust can create regions where the rock close to the surface is much hotter than usual. This hot rock can be accessed by drilling and pumping a heat-transfer fluid into the rock, then bringing it back to the surface. The process has been tested but never exploited commercially.

The third, and potentially the richest source of geothermal energy, is the magma itself. The magma contains by far the greatest amount of heat energy, but because of the temperatures and pressures found within it, this is also the most difficult geothermal energy source to exploit.

Estimating the amount of energy in Earth’s crust that could be exploited for power generation is not easy. It has been suggested that there is between 10 and 100 times as much heat energy available for power generation as there is energy recoverable from uranium and thorium in nuclear reactors. Certainly, the resource is enormous, if difficult to access.

Geothermal fields

Geothermal fields are formed when water from Earth’s surface is able to seep through faults and cracks within rock, sometimes to depths of several kilometers, to reach hot regions within the crust. As the water is heated is rises naturally back toward the surface by a process of convection and may appear there again in the form of hot springs, geysers, fumaroles, or hot mud holes. These are particularly common along tectonic plate boundaries.

Sometimes the route of the ascending water is blocked by an impermeable layer of rock. Under these conditions the hot water collects underground within the porous rock beneath the impermeable barrier. This water can reach a much higher temperature than the water that emerges at the surface naturally. Temperatures as high as 350 °C have been found in such reservoirs. This geothermal fluid can be accessed by boring through the impermeable rock. Steam and hot water will then flow upwards through the borehole under pressure and can be used at the surface.

Most of the geothermal fields that are known today have been identified by the presence of hot springs. In the United States, Italy, New Zealand, and many other countries the springs led to prospecting using boreholes drilled deep into the earth to locate the underground reservoirs of hot water and steam that were feeding them. More recently, geological exploration techniques have been used to try and locate underground geothermal fields where no hot springs exist. Sites in Imperial Valley in southern California have been found in this way.

Some geothermal fields produce simply steam, but these are rare. Larderello in Italy and the Geysers in California are the main fields of this type in use today though others exist in Mexico, Indonesia, and Japan. More often the field will produce either a mixture of steam and hot water or hot water alone, often under high pressure. All three can be used to generate electricity.

Deep geothermal reservoirs, as much as 2 km or more below the surface, produce fluid at the highest temperature. Typically, they will produce water with a temperature of 120–350 °C. High-temperature reservoirs of this type are the best for power generation, and the higher the temperature, the more energy can be extracted by a turbine. Shallower reservoirs may be a little as 100 m below the surface. These are cheaper and easier to access but the water they produce is cooler, often less than 150 °C. This can still be used to generate electricity but is more often used for heating.

The fluid emerging from a geothermal reservoir, at a high temperature and usually under high pressure, contains enormous quantities of dissolved minerals such as silica, boric acid, and metallic salts. Quantities of hydrogen sulfide and some carbon dioxide are often present too. The concentrated brine from a geothermal borehole is often corrosive and if allowed to pollute local groundwater sources can become an environmental hazard. This problem can be avoided if the brine is reinjected into the geothermal reservoir after heat has been extracted from it.

Geothermal reservoirs are all of limited extent and contain a finite amount of water and energy. As a consequence, both can become depleted if overexploited. When this happens either the pressure or temperature (or both) of the fluid from the reservoir declines.

In theory, the heat within a subterranean reservoir will continuously be replenished by the heat flow from below. This rate of replenishment may be as high a 1000 MW, though it is usually smaller. In practice, geothermal plants have traditionally extracted the heat faster than it is replenished. Under these circumstances the temperature of the geothermal fluid falls and the practical life of the reservoir is limited.

Reinjection of the brine after it has passed through the power plant helps maintain the fluid in a reservoir. However, reservoirs such as the Geysers in the United States where fluid exiting the boreholes is steam have proved more difficult to maintain since the steam is generally not returned after use. This has led to a marked decline in the quantity of heat from the Geysers. In an attempt to correct this, waste water from local towns has been reinjected into the reservoir. Some improvement has been noted.

Estimates for the practical lifetime of a geothermal reservoir vary. This is partly because it is extremely difficult to gauge the size of the reservoir. While some may become virtually exhausted over the lifetime of a power plant, around 30 years, others appear able to continue to supply energy for 100 years or more. Better understanding of the nature of the reservoirs and improved management will potentially help maintain them for longer in the future.

Brine-methane reservoirs

In some rare cases the hot brine in an underwater reservoir is found to be saturated with methane too. Such reservoirs normally occur in regions rich in fossil fuel. Where such a reservoir is found it is possible in principle to exploit both the heat in the brine and the dissolved methane gas to generate electricity. The only major reservoirs of this type known today are in the Gulf of Mexico.

Hot dry rock

Underground geothermal reservoirs are relatively rare. More normally hot underground rock is not permeated by water and so there is no medium naturally available to bring the heat energy to the surface.

Where hot rock exists close to the surface, it is possible to create a human-made hydrothermal source, as shown in Figure 12.2. This is accomplished by drilling into the rock and then pumping water down through the borehole that has been created. If water is pumped under sufficiently high pressure it will cause the rock to fracture—the process is similar in concept to fracking to release shale gas—creating faults and cracks through which the liquid can flow. (In fact, underground rock often contains natural faults and fractures through which the water will percolate. This often helps with the fracturing.) If a second borehole is drilled adjacent to the first, then water that has become heated as it has percolated through the rock can be extracted and used to generate electricity.

The first attempt at this hot dry–rock technique was carried out by scientists from the Los Alamos laboratory in New Mexico in 1973. Since then experiments have been carried out in Japan, the United Kingdom, Germany, and France. One such project, part of the European Hot Dry Rock Research Project, is at Soulez-sous-Forets in France. Here boreholes have been drilled to 5 km below the surface and temperatures of 201 °C found. The project is now producing a small amount (around 1.5 MW of generating capacity) of electric power.

Based on pilot schemes such as this, estimates suggest that a commercial hot dry–rock system will need to provide 10–100 MW of generating capacity over at least 20 years to be economical. The technology is still in an early stage of development and it is likely to be 10–15 years before commercial exploitation is possible.

Exploiting the magma

Extracting energy from accessible magma plumes that have formed within Earth’s outer crust is the most difficult way of obtaining geothermal energy, but it is also the most exciting because of the enormous quantities of heat available. A single plume can contain between 100,000 MW-centuries and 300,000 MW-centuries of energy.

Drilling into, or close to, such hot regions is difficult because the equipment can easily fail at the elevated temperatures to which it will be subject. As an additional hazard, if a drill causes a sudden release of pressure, the result can be explosive. Further, ways have yet to be found to tap the heat. Research continues but exploiting magma for power generation is a long-term project with no immediate prospect of exploitation.

Location of geothermal resources

The easiest geothermal resources to exploit are those that can provide water or steam with a temperature above 200 °C. Resources of this type are located almost exclusively along the boundaries between Earth’s crustal plates, in regions where there is significant plate movement. These areas are found around the Pacific Ocean in New Zealand, Japan, Indonesia, the Philippines, the western coasts of North and South America, the central and eastern parts of the Mediterranean, east Africa, the Azores, and Iceland.

Lower-temperature underground reservoirs exist in many other parts of the world and though these contain less energy they can be used to generate electricity too. A project installed in Austria in 2001, for example, generates electricity from 106 °C water, which is also used for district heating. However, these reservoirs can be more difficult to locate in the absence of hot surface springs. Nevertheless, there were around 60 countries using geothermal energy at the beginning of the 21st century for either heating, generating electricity, or both.

Size of the resource

Today it is difficult to estimate the size of this energy resource but as survey techniques improve, more accurate data will become available. Based on data available at the beginning of the 21st century, reservoirs located in the United States, for example, might provide 10% of U.S. electricity.

According to figures published by the World Energy Council in its 2010 Survey of Energy Resources the global geothermal generating potential could be between 35 GW and 140 GW, while the technical potential could be 210 GW. However, if hot dry–rock techniques could be exploited, the total potential could be 5–10 times higher than this. A reasonable estimate, again from the World Energy Council, suggests that 8.3% of global electricity generation could be provided by geothermal sources.

Geothermal energy conversion technologies

There are three principle ways that have been developed for converting geothermal energy into electricity. Each is designed to exploit a specific type of geothermal resource. The most straightforward of the three is only feasible when a geothermal reservoir produces high-temperature dry steam alone. Under these circumstances it is possible to use a direct steam power plant, which is analogous to the power train of a steam turbine power station, with the boiler of the plant replaced by the geothermal steam source. Provided the steam exiting the reservoir is of suitable quality, this provides an extremely cheap and effective means of generating electricity.

Most high-temperature geothermal fields produce a mixture of steam and hot brine. This mixture cannot be utilized quite so simply and is most effectively exploited using a configuration called a flash-steam geothermal plant. The flash process converts part of the hot, high-pressure liquid to steam and this steam, together with any steam extracted directly from the borehole, is used to drive a steam turbine.

Where the geothermal resource is of a relatively low temperature a third system called a binary plant is more appropriate. This uses the lower-temperature geothermal fluid to vaporize a second low–boiling point fluid contained in a separate, closed system. The vapor then drives a turbine that turns a generator to produce electricity. Although overall efficiency of such binary systems is low, the availability of a cheap heat source makes the system economical to operate.

Direct steam power plants

Dry steam geothermal reservoirs are extremely rare. Where they exist the steam, with a temperature of 180–350 °C, can be extracted from the reservoir through a borehole and fed directly into a steam turbine (Figure 12.3). Steam from several wells of this type will normally be fed to a single turbine to allow an economically large turbine to be used. The pipes that carry the steam from the well heads to the turbine contain various filters to remove particles of rock and any steam that condenses en route. This is the configuration that was used in the very first geothermal power plant in Larderello, Italy, in 1904.

The steam turbine in a direct steam geothermal plant is usually a standard reaction turbine. Unit size in modern plants is typically between 20 MW and 120 MW. As a result of the relatively low steam temperature and the small size of the turbines, efficiency is generally low at around 30%.

In some cases the steam exiting the turbine may be released directly into the atmosphere. However, the steam usually contains between 2% and 10% of other gases such as carbon dioxide and hydrogen sulfide. Under these circumstances the exhaust from the steam turbine must be condensed to remove the water and then treated to remove any pollutants such as hydrogen sulfide before release into the atmosphere. At the Geysers plant in the United States, the hydrogen sulfide is converted into sulfur as a by-product of the treatment and this sulfur is sold. Condensing the steam also extracts more energy, thereby increasing plant efficiency.

Ideally the geothermal fluid should be returned to the underground reservoir but it is often more economical to release the gas and dispose of the water produced as a result of condensing the steam from the turbine at the surface. Carbon dioxide emissions from such plants could become an issue in the future and, depending on the amounts involved, it may be feasible to capture and either reinject or sequester the carbon dioxide generated from such a plant. In general, however, carbon dioxide emissions are low compared to fossil fuel sources. In the United States, for example, typical emissions from a geothermal plant are equivalent to 91 gCO₂/kWh. For fossil fuel resources the equivalent range of emissions is between 600 gCO₂/kWh and 1000 gCO₂/kWh according to the World Energy Council. Continual removal of underground fluid without replenishment eventually leads to a depletion in the quality of fluid available from the reservoir. At the Geysers geothermal field in southern California, urban waste water has been pumped into the underground reservoir in an attempt to maintain and eventually boost output from the resource.

Flash steam plants

Most high-temperature geothermal reservoirs yield a fluid that is a mixture of steam and liquid brine, both under high pressure (typically up to 10 atm). The steam content, by weight, is typically between 10% and 50%. The simplest method to exploit such a resource is to separate the steam from the liquid and use the steam alone to drive a steam turbine. This would be equivalent to the dry steam plant described earlier. However, using only the steam throws away much of the available energy, particularly where the proportion of steam in the fluid is small.

A more productive alternative is to pass the combined fluid through a valve into a vessel maintained at a lower pressure than the geothermal fluid from the reservoir (Figure 12.4). The sudden reduction in pressure “flashes” a proportion of the hot liquid to steam, creating a larger quantity of steam than was available previously. All this steam can then be separated from the liquid and used to drive a steam turbine. The steam exiting the steam turbine must be treated in exactly the same way as the exhaust from a direct steam geothermal plant to prevent atmospheric pollution. The remaining liquid, which contains high levels of dissolved salts and presents a potential pollution problem, is usually injected back into the geothermal reservoir.

A further refinement to the flash steam plant is called double-flash technology. This involves taking the fluid remaining after the first flash process and releasing it into a second vessel at even lower pressure. Double flashing results in the production of more steam that can be fed to a second, low-pressure turbine or injected into a later stage of the turbine powered by the steam from the first flash. A double-flash plant can product up to 25% more power than a single-flash plant. However, it is more expensive and may not always be cost effective.

Flash technology plants will generally return a much higher percentage of the geothermal fluid—up to 85% for a single-flash plant and somewhat less for a double-flash plant—to the geothermal reservoir. This will include most of the dissolved chemicals contained in the original fluid. However, some reservoir depletion will still take place and without action this is likely to lead to a falloff in output from the reservoir with time. Capacities for flash geothermal power plants are normally between 20 MW and 55 MW.

Binary cycle power plants

Direct steam and flash geothermal power plants utilize geothermal fluid with a temperature between 180 °C to 350 °C. If the fluid is cooler than this, conventional steam technology will normally prove too inefficient to be economically viable. However, energy can still be extracted from the fluid to generate power using a binary cycle power plant. This type of plant has two fluid cycles: the first involves the low-temperature fluid from the geothermal resource and the second is a turbine cycle involving a low–boiling– point fluid (Figure 12.5).

In a binary power plant the geothermal fluid is extracted from the reservoir and immediately passed through a heat exchanger where the heat it contains is used to volatilize a secondary fluid. This secondary fluid is contained within a second, completely closed cycle system. The fluid may be an organic liquid that vaporizes at a relatively low temperature or, in the case of the Kalina cycle,¹ a mixture of water and ammonia.

The vaporized secondary fluid is used to drive a small turbine from which power can be extracted with a generator. Once it has exited the turbine the secondary vapor is condensed and then pumped through the heat exchanger once more. Thus, the cycle is repeated. The geothermal fluid exiting the heat exchanger is, meanwhile, reinjected into the geothermal reservoir. Since 100% of the fluid is returned underground, this type of geothermal power plant has the smallest environmental impact.

Typical binary plant unit size is 1–3 MW, much smaller than for the other types of geothermal technology. However, the small modular units often lend themselves to standardization, reducing production costs. Several units can be placed in parallel to provide a plant with a larger power output.

Although the normal application for binary technology is to exploit a low-temperature geothermal resource, the technology can also be used to generate more power from a flash plant. In this case the fluid left after flashing is passed through a heat exchanger before reinjection, allowing extra energy to be taken to power a small binary unit. Adding a binary unit to a conventional flash plant increases the cost but the resultant hybrid plant will have a larger power output.

Geothermal power and district heating

While high-temperature geothermal resources are suitable for power generation and lower-temperature resources are often exploited for district heating, it is possible to combine the two. This is typical, for example, of geothermal power plants in Iceland where there is high demand for both power and heat.

Iceland’s geothermal reservoirs generally provide a hot brine and energy is extracted from this with a flash plant as described previously. However, after the brine exits the flash plant it still contains a significant amount of heat energy that can be exploited to provide heat for a district heating system. For this, the brine is passed through a series of heat exchangers through the second side of which fresh water is passed and heated. The hot water is then stored in a large tank from which it can be taken to supply the district heating system. The brine, upon exiting these heat exchangers, is reinjected into the reservoir.

Finding and exploiting geothermal sources

The exploitation of geothermal power is often considered to be more risky than development of other renewable resources because of the uncertainty and high costs associated with finding suitable geothermal fields. Initial surveys of geothermal resources are often carried out by national institutions, but for developers, these then need to be backed up with test wells to determine the exact nature of the resource available. Data from Pacific Rim volcanic regions suggests the presence of a single hot spring will provide a 50% change of an exploitable geothermal field. A boiling spring or fumarole increases the probability to 70%.²

Having identified a suitable surface site, prefeasibility studies are likely to cost around $1 million, with a 30% change of failure. Test drilling, usually three wells at up to $2 million per well, has a similar prospect of failure. This risk can be reduced by careful surface study followed by prioritization of the available sites. Such an approach has led to success rates for well drilling in excess of 83% in countries such as Indonesia, Kenya, and New Zealand that have high-temperature resources. However, success rates can be much lower where low-temperature resources are concerned.

Once a usable underground reservoir has been located, its size must be determined. This involves fluid withdrawal over a long period; indeed, it may not be until several years after production has started that a good picture of the resource can be obtained. Careful sizing of the geothermal plant to match the reservoir size will prolong the lifetime of a reservoir. However, this may not be possible if the plant has to be constructed before full data is available and, as noted, the data may not be available anyway until production has started. Oversized plants such as that installed at the Geysers in the United States have led to a premature fall in output, which will have an impact on overall economics.

Cost of geothermal power

In common with many renewable resources, geothermal power generation involves a high capital outlay to establish the facility but extremely low fuel and operating costs. In the case of a geothermal plant there are three initial areas of outlay, prospecting and exploration for the geothermal resource, development of the steam field, and the cost of the power plant itself.

As already noted, the cost of identifying a suitable geothermal reservoir is likely to be several million dollars and may not always be successful. If the resource that is found then turns out to be small this will create a much heavier burden on the project than if the resource is large. Steam field development will depend on plant size and will generally be priced out according to the number of boreholes that are to be drilled. For example, the Hellisheidi geothermal power plant in Iceland, with a generating capacity of 300 MW, has 50 boreholes.

The capital cost of building a power plant to exploit a geothermal resource will depend on the quality of the resource. A good resource will have a temperature above 250 °C and good permeability of the reservoir, so it will provide a good fluid flow. Ideally, it will provide either dry steam or steam and brine, the latter being relatively noncorrosive and with low gas content. For good-quality resources of this type today the lowest cost in the United States is around $2400/kW according to the U.S. Energy Information Administration (EIA). Similar costs in Europe are €3000–4500/kW. The lowest cost will be for a plant of more than 30 MW with smaller plants being relatively more expensive to build.

A poor-quality resource will have a temperature below 150 °C, or it could provide fluid at a higher temperature but with some other defect such as corrosive brine or poor fluid flow. Resources of this type will generally only be capable of supplying heat for a small geothermal plant of less than 5 MW and the capital cost could be up to twice that of a large facility based on a good resource.

Further indirect costs will be incurred, depending on the location and ease of access of the site. These will vary from 5% for an easily accessible site and a local skilled workforce to 60% of the direct cost in remote regions where skilled labor is scarce. All these costs will be part of the initial investment required to construct a plant.

The cost of electricity from the geothermal plant will depend primarily on the capital cost of building the plant and the cost of financing the construction. There is also the potential for an additional cost resulting from a local rent for exploiting the resource but that is rare. European estimates put the levelized cost of geothermal electricity at €40–100/MWh. In the United States the EIA has estimated that the cost of energy from a new geothermal plant entering service in 2017 is $100/MWh. These levelized costs make geothermal power competitive with virtually all other forms of power generation.