Geothermal Energy
Abstract
Geothermal energy is also a very cheap and clean source of energy, but in its current form, it has limitations. There are limited geothermal resources, and the supply may not have the potential to be increased substantially without further technological breakthroughs. Currently, the chief geothermal energy supplies are in the United States, Iceland and the Philippines. These supplies are very small and, apart from the geothermal facilities in Iceland, contribute only a relatively small fraction of the total energy supplies. This could change if deep hot rocks are utilized to capture energy. At present the deep hot rock technologies are not economic. But they represent a very large energy source if technological breakthroughs can be made to capture this energy economically. There are also some environmental issues to be addressed.
Geothermal energy is a rather interesting source of energy. It has a number of similarities to standard fuel-based energy sources such as coal, oil, and natural gas. All of these burn fuel to generate steam, which is then used to drive a steam turbine to generate electricity. In certain locations, there are hot formations close to the surface that already contain hot water or steam under pressure and that can be used to drive the same steam turbines without burning any fuel. This type of energy source is not cheap to develop and operate because wells have to be drilled and produced and steam turbines have to be built and run. Nevertheless, under certain circumstances, it is cost effective to develop geothermal energy.
The word geothermal comes from the Greek words geo (Earth) and therme (heat). Geothermal energy is heat from within the Earth. Most energy sources used on Earth, including fossil fuels, originated in the sun. Geothermal energy is different; it originates in processes occurring within the Earth. This energy can be recovered as steam or hot water and can then be used to heat buildings or to generate electricity. Geothermal energy can be classified as a renewable energy source because the energy is continuously being produced inside the Earth due to the radioactive decay of elements such as uranium, radium, thorium, and potassium. This produces very high temperatures, hot enough to keep much of the interior core of the Earth in a molten state.
Earth actually has a number of different layers. The central core has two layers: a solid iron core and an outer core made of magma, which is melted rock. The next layer is the mantle, which surrounds the core, and is about 1800 miles thick. It is made up of magma and solid rock. The crust is the outermost layer of the Earth, which is 3-5 miles thick under the oceans and 15-35 miles thick on the continents. The Earth’s crust is broken into continental plates, which are constantly in motion. Magma can come close to the Earth’s surface near the edges of these plates. This is where volcanoes and earthquakes occur. The lava that erupts from volcanoes is partly magma. Deep underground, the rocks and water absorb heat energy from this magma. As the water rises to the surface, natural hot springs and geysers occur, such as Old Faithful at Yellowstone National Park (see Figure 11.5). The water in these systems ranges from 400 to 700 °F.
Generally, geothermal energy is recovered by drilling wells into the hot water and steam reservoirs underground and pumping the heated water or steam to the surface. This is then used to heat buildings, such as homes and offices, and to generate electricity. The most active geothermal resources are found along major plate boundaries where earthquakes and volcanoes are concentrated. Much of the geothermal activity in the world occurs along the Ring of Fire, which encircles the Pacific Ocean and runs down the west coast of North and South America, through the coast of Alaska, around the Aleutian Island chain, down the Kamchatka peninsula of Russia, through Japan and the Philippines and down to New Zealand. Iceland, which sits at the conjunction of the North Atlantic Ridge and two continental plates, is also very geologically active. This activity allows a significant portion of its energy to be derived from geothermal and hydroelectric resources.
In Iceland, hot water and steam are recovered from shallow hot spots and this is then used to heat buildings and generate electricity. A city utility, commonly known as a district heating system, produces the hot water and pipes it into buildings to keep people warm through the long cold winters. In the capital city of Reykjavik (population 120,000), hot water is piped from a spring 25 km away, and residents use it not only for heating their houses but also for hot tap water. It is doubtful that the Icelandic community would thrive the way it has without access to this energy source.
Figure 11.1 shows where the potential geothermal resources of the United States are located. Most of the geothermal reservoirs are located in the western states and Hawaii. California generates the most electricity from geothermal energy. The Geysers, a dry steam reservoir north of San Francisco in Northern California, is the largest known dry steam field in the world. It has been producing electricity since 1921 and has been greatly expanded since 1990. Figure 11.1 gives the impression that geothermal resources are widespread and abundant; however, not all of the areas shown in this figure are economic to develop yet because they are much too deep.
The three main categories of utilizing geothermal energy are
(a) Direct use and district heating systems, which use hot water from springs or reservoirs near the surface
(b) Electricity generation power plants, which require water or steam at very high temperatures (300-700 °F) close to the surface. Geothermal power plants are generally built where geothermal reservoirs are located within 6000 ft of the surface
(c) Geothermal heat pumps, which use stable temperatures near the Earth’s surface to control building temperatures above ground. Heat pumps can be used to heat or cool buildings very efficiently, but they generally use water within 1000 ft of the surface.
There have been direct uses of geothermal hot water as an energy source throughout history. Many cultures have used hot mineral springs for bathing, cooking and heating. Many people firmly believe that the hot, mineral-rich waters have beneficial healing powers. After bathing, the most common direct use of geothermal energy is for heating buildings through district heating systems. Hot water near the Earth’s surface can be piped directly into buildings and industries for heat. In addition to building heat and electricity generation, the drying of vegetable and fruit products for storage and later use is another small industrial use of geothermal energy.
Table 11.1 shows the world’s installed geothermal electrical generating capacity, with the United States as the world leader. The world total installed capacity now exceeds 9000 MW (9 GW), which is a very small part of the world’s electricity supply. In 2009, U.S. geothermal power plants produced 15 billion kilowatt-hours (kWh) from the total 3102 MW capacity. This represented a 55% utilization or capacity factor and about 0.4% of the total U.S. electricity supply. In 2009, 5 states had geothermal power plants: California, which had 35 geothermal power plants and produced 85% of U.S. geothermal electricity; Nevada, which had 18 geothermal power plants and produced 11% of U.S. geothermal electricity; and, Hawaii, Idaho, and Utah, which each had one geothermal plant and account for the other 4%.
Table 11.1
Installed Geothermal Capacity (MW)
| 1 | USA | 3102 |
| 2 | Philippines | 1966 |
| 3 | Indonesia | 1189 |
| 4 | Mexico | 958 |
| 5 | Italy | 863 |
| 6 | New Zealand | 769 |
| 7 | Iceland | 575 |
| 8 | Japan | 502 |
| 9 | El Salvador | 204 |
| 10 | Kenya | 167 |
| 11 | Costa Rica | 166 |
| 12 | Nicaragua | 88 |
| 13 | Russia (Kamchatka) | 82 |
| 14 | Turkey | 82 |
| 15 | Papua New Guinea | 56 |
| 16 | Guatemala | 52 |
| 17 | Portugal (The Azores) | 29 |
| 18 | China | 24 |
| 19 | France (Guadeloupe) | 16 |
| 20 | Ethiopia | 7.3 |
Twenty countries including the United States had geothermal power plants in 2008, which generated a total of about 60.4 billion kWh. The Philippines was the second largest geothermal power producer after the United States at 9.8 billion kWh, which equaled about 17% of the country’s total power generation. Geothermal power plants in El Salvador and Iceland produced about 1.4 and 3.8 billion kWh, respectively, which was equal to about 25% of the total power generated in those countries. The other 75% of Iceland’s electricity is generated from hydroelectricity.
There are three basic types of geothermal power plants: dry steam plants, flash steam plants, and binary cycle power plants. A dry steam plant uses steam piped directly from a geothermal reservoir to turn the generator turbines (see Figure 11.2). After the steam passes through the turbines, it is condensed into water and normally reinjected into the reservoir from which it came. This step is usually necessary to maintain the steam supply underground. The largest power plant of this type is The Geysers in California. For many years, The Geysers did not reinject their used water, as is implied in Figure 11.2, because of the process used. This process is discussed in more detail later in the chapter. Now, they are beginning to inject make-up water obtained from other sources.
A flash steam plant uses high-pressure hot water from the Earth and runs it through a flash drum where the pressure is allowed to decrease, which allows some of the hot water to flash into steam at a lower pressure. This steam is then used to drive the steam generator turbines. When the steam cools, it condenses to water and is injected back into the ground to be heated again. The water from the bottom of the flash drum is also added to this steam to be reinjected. The majority of geothermal power plants are flash steam plants, which are illustrated in Figure 11.3.
Binary cycle power plants transfer the heat from geothermal hot water to another liquid such as butane. The heat causes the second liquid to turn to vapor, which is used to drive a generator turbine, as shown in Figure 11.4. This process is used when the hot water does not have a high enough temperature and pressure to use the dry steam or flash steam process.
To analyze the power output of any steam turbine, both the first and second laws of thermodynamics must be applied. To illustrate a sample calculation, assume that a geothermal plant is producing hot water at a pressure of 2 MPa and is utilizing a flash steam process as illustrated in Figure 11.3. The steam exits the flash drum as a saturated vapor at the pressure of 2 MPa. It travels through the turbine and exits into the condenser at a pressure of 10 kPa as partially condensed steam and liquid water droplets. The second law of thermodynamics will calculate what the maximum properties of the steam can be at the exit of the turbine. Assume that this calculation gives us a steam quality at the turbine exit of 76%. These numbers allow us to calculate the energy of the steam entering and exiting the turbine. The relevant energy parameter of the steam at each point is called the enthalpy of the steam. Enthalpy includes the internal energy as well as the flow energy of the steam, both of which are a function of its temperature and pressure. Saturated steam at the pressure of 2 MPa has an enthalpy of 2800 kJ/kg and the 76% quality steam at 10 kPa has an enthalpy of 2008 kJ/kg. Consequently, if the entire plant was flashing 100 kg/s of steam from the flash drum, using the first law of thermodynamics the turbine could generate:
Note the low efficiency of this process. Only the flashed steam is being used to generate power in the turbine. Most of the brine (about 75%) being produced by the production well is bypassing the turbine and is being reinjected. Of the steam that is being sent through the turbine to generate electricity, only 28% of its energy is being captured by the turbine. The rest of the energy remains with the low pressure steam, which will also be reinjected back into the ground. The Geysers power plant is more efficient than this because it produces pure steam directly from the ground.
The Geysers Dry Steam Geothermal Power Plant
The largest geothermal system in the world currently in operation is a steam-driven plant in an area called The Geysers, north of San Francisco, California. Despite the name, there are no actual geysers in the area. The energy source is dry steam, not hot water. The area was known for its hot springs (not geysers) at least as far back as 1847 when it was discovered by Bill Elliot who called it “The Geysers.” Soon after this, it was developed as a resort spa. Hot springs like this have been popular throughout history. Bathing in the hot water is a pleasant experience and gives people the impression that it is beneficial to their health and well-being. The resort became a popular holiday destination and thrived for many years.
The first well and power plant at the site were completed in 1921, which generated electricity at the rate of 250 kW. This was a very small power plant and was barely large enough to power the resort, which had been operating continuously since 1852. Deeper wells were drilled in the 1950s, but real development did not occur until the 1970s and 1980s. By 1990, 26 power plants had been built for a capacity of more than 2000 MW.
Because of the rapid development of the area in the 1980s and the technology used, the steam resource has been declining since 1988. Today, owned primarily by Californian utility Calpine and with a total operating capacity of 2000 MW, The Geysers’ facilities still meet nearly 60% of the average electrical demand for California’s North Coast region (from the Golden Gate Bridge north to the Oregon border). The plants at The Geysers use an evaporative water-cooling process to create a vacuum that pulls the steam through the turbine, producing power more efficiently. This process, however, loses 60-80% of the steam to the air without reinjecting it underground. This led to the decline of the volume of steam coming from the underground reservoir and consequently the power that it was able to generate. To recharge the reservoir and to increase the declining steam volume and pressure, various interested partners created the Santa Rosa Geysers Recharge Project. This project involves transporting 11 million gallons per day of treated wastewater from neighboring communities through a 40-mile pipeline and injecting it into the ground to provide make-up water to be converted to steam by the hot rocks below. This part of the project came online in 2003. The city of Santa Rosa plans to further expand this program by increasing the amount of wastewater sent to the Geysers to 20 million gallons per day.
Other Geothermal Applications
Geothermal springs can also be used directly for many varied heating purposes. Hot spring water is used to heat greenhouses, to make dried fish and jerky, for enhancing oil recovery and to heat fish farms and spas. Klamath Falls, Oregon; Boise, Idaho; and Warm Springs, Virginia are a few of the cities in the United States where geothermal spring water has been used to heat homes and buildings for more than a century. In Iceland, virtually every building in the entire country is heated with hot spring water.
Another method of utilizing geothermal energy is via a heat pump. The temperatures just below the Earth’s surface hold nearly constant between 35 and 65 °F, depending on the location. For most areas, this means that soil temperatures are usually warmer than the air in winter and cooler than the air in summer. Geothermal heat pumps use the Earth’s constant temperatures to heat and cool buildings. They transfer heat from the groundwater into buildings in winter and reverse the process in the summer. A heat pump is a kind of reversible refrigerator. A refrigerator uses electrical energy to pump heat from a cold box inside the refrigerator into the warm room outside the refrigerator. A heat pump acts the same way: it pumps heat from the Earth in the wintertime into the house, and in the summer it pumps heat from the house back into the Earth. The U.S. Department of Energy and the EPA have partnered with industry to promote the use of geothermal heat pumps because they can be more efficient than direct heating.
In regions with temperature extremes, ground-source heat pumps are the most energy-efficient heating and cooling systems available. Far more efficient than electric heating and cooling, these systems can pump four times the energy they use in the process. That statement might seem like it violates the first law of thermodynamics, but it does not. This is because a heat pump moves energy from one location to another. For example, it can move the energy required to heat a house from the Earth to the house, but it typically uses only one quarter of the energy gained. The U.S. Department of Energy believes that heat pumps can save a typical home $350 a year in energy costs, with the system often paying for itself in 8-12 years. Tax credits and other incentives can reduce the payback period to 5 years or less.
More than 750,000 ground-source heat pumps supply climate control in U.S. homes and other buildings, with new installations occurring at a rate of about 50,000 per year. Ground-source heat pumps are especially popular in rural areas without access to natural gas pipelines, where homes must use propane or electricity for heating and cooling. Recent government policy initiatives are offering strong incentives for homeowners to install these systems. The 2008 economic stimulus bill—the Emergency Economic Stabilization Act of 2008—includes an 8-year extension (through 2016) of the 30% investment tax credit, with no upper limit in home installations, for Energy Star certified geothermal heat pumps.
Enhanced Geothermal Systems
There is a vast amount of heat energy available from dry rock formations very deep below the surface (4-10 km). Using a set of emerging technologies known as Enhanced Geothermal Systems (EGSs), it may be possible to capture this heat for electricity production on a much larger scale than conventional technologies allow. Geothermal heat occurs everywhere under the surface of the Earth, but the conditions that make water circulate to the surface are found only in a small percentage of the Earth’s land mass. EGS is an approach to capturing the heat in “hot dry rock,” but it is still not commercial, although it does show promise. The hot rock reservoirs, typically at greater depths below the Earth’s surface than conventional sources, are first fracture-stimulated by pumping high-pressure water through them. This opens up pathways for water to flow through the rocks from one well to another. The plants then inject water through the fractured hot rocks, where it heats up, returns to the surface as high pressure steam and powers the steam turbines to generate electricity. After it exits the turbine as cooler low pressure steam, it is condensed into hot water. This water is then reinjected into the reservoir through the injection wells to complete the circulation loop in the same manner as shown in Figures 11.2-11.4. The Department of Energy is collaborating with universities and the geothermal industry in the United States on research to demonstrate the potential of EGS in hot dry rock. Australia, France, Germany, and Japan also have similar research and development programs.
Oil and gas fields already under production represent another large potential source of geothermal energy. In many existing oil and gas reservoirs, a significant amount of high-temperature water is coproduced with the oil and gas. This could be used for the production of electricity whether in a flash system (Figure 11.3) or in a binary system (Figure 11.4). The Rocky Mountain Oilfield Testing Center, located at the Teapot Dome Oilfield in the Powder River Basin in Wyoming, has been investigating the technology to do this.
An MIT study, commissioned by the U.S. Department of Energy in 2006, estimated that the United States has the potential to develop 44 GW of geothermal capacity by 2050 by coproducing electricity, oil and natural gas at oil and gas fields primarily in the southeast and southern Plains states. Further, it would be possible to develop 100 GW of EGS geothermal capacity by 2056. This study projects that such advanced geothermal systems could supply 10% of the U.S. base-load electricity by that year.
These new developments in geothermal energy will be supported by increased levels of federal research and development funding. Under the American Recovery and Investment Act of 2009, $400 million of new funding was allocated to the DOE’s Geothermal Technologies Program. Of this, $90 million is expected to go toward a series of demonstration projects to prove the feasibility of EGS technology. Another $50 million will fund demonstration projects for other new technologies, including coproduction of hot water with oil and gas wells. The remaining funds will go to exploration technologies to expand the deployment of geothermal heat pumps and other uses.
If these resources can be tapped, they offer greatly increased potential for geothermal electricity production capacity. In a recent assessment, the U.S. Geological Survey (USGS) estimated that conventional geothermal sources on private and accessible public lands across 13 western states have the potential capacity to produce 8-73 GW, with a mean estimate of 33 GW. State and federal policies are likely to encourage developers to tap some of this potential in the next few years. The Geothermal Energy Association estimates that 132 projects now under development around the country could provide up to 6 GW of new capacity. As EGS technologies improve and become competitive, even more of the largely untapped geothermal resources could be developed. The USGS study found that hot dry rock resources could provide another 345-727 GW of capacity, with a mean estimate of 517 GW. At a 75% capacity factor, 517 GW could generate 3400 TWh of electricity, which compares to the total 4326 TWh of electricity that was generated in the United States in 2010. If further improvements can be made in EGS technology, this resource would be capable of supplying the majority of U.S. electricity needs.
Not only do geothermal resources in the United States offer great potential, they can also provide continuous base-load electricity. It is not an intermittent power source like solar and wind power. According to the U.S. National Renewable Energy Laboratory, the capacity factors of geothermal plants (the ratio of the actual electricity generated compared to what would be produced if the plant was running 100% of the time) are comparable with those of coal and nuclear power. The capacity factor of the Geysers Power Plant has averaged 55% recently, but geothermal plants are capable of running at 75-80% capacity. With the combination of both the size of the resource base and its reliability, geothermal energy can play a significant role in the supply of clean renewable electricity; however, that day has not yet come.
The MIT study commissioned by the U.S. Department of Energy in 2006, referred to above, made some specific recommendations for successful EGS projects. In particular, they pointed to the following improvements that would make EGS technology cost competitive:
1. “High flow rates with long path lengths are needed. Natural hydrothermal systems require each production well to produce about 5 MW per well, which requires flow rates ranging from 30 to 100 kg/s (depending on the fluid temperature). At the same time, we need a large heat-exchange area or residence time for water to reheat to production temperatures; this could imply large-pressure drops. Better understanding of successful natural systems (in comparable geological settings) should lead to improved methods of generating artificially EGSs. For instance, the residence time of water injected at Dixie Valley is 3-6 months, and the production wells show little or no cooling due to the aggressive injection program. At Steamboat, though, the residence time for the water is closer to 2 weeks and there is fairly significant cooling.
The well spacing between injectors and producers at Dixie Valley is about 800 m, and there are probably at least two fractures with a somewhat complex connection between the injectors and producers resulting in a long fluid-path length. At the Steamboat hydrothermal site, the distance between producers and injectors is more than 1000 m; however, because there are so many fractures, the transmissivity is so high that there is low residence time for injected fluids. At the East Mesa hydrothermal site, the reservoir is in fractured sandstone and the residence time varies from one part of the field to another. Some injectors perform well in the center of the field, while other injectors are in areas with either high matrix permeability in some zones or fractures that cause cold water to break through faster. The large volume of hot water stored in the porous matrix at East Mesa made it possible to operate the field for a long time before problems with cooling developed.
2. Stimulation is through shearing of pre-existing fractures. In strong crystalline rock, hydraulic properties are determined by the natural fracture system and the stresses on that system. The expectation of scientists planning the early experiments in enhancing geothermal reservoirs was that fracturing would be tensile. While it may be possible to create tensile fractures, it appears to be much more effective to stimulate pre-existing natural fractures and cause them to fail in shear. Understanding the orientation of the stress field is crucial to designing a successful stimulation. Fortunately, in even the most unpromising tectonic settings, many fractures seem to be oriented for shear failure. At Cooper Basin, which is in compression, stimulation of two nearly horizontal pre-existing fracture systems appears to have been successful in creating a connected reservoir of large size. The shearing of natural fractures increases hydraulic apertures and this improvement remains after pressures are reduced. Fortunately, stress fields in strong rocks are anisotropic so the critically aligned natural joints and fractures shear at relatively low overpressures (2-10 MPa).
3. Fractures that are stimulated are those that will take fluid during prestimulation injection. The fractures that are found to be open and capable of receiving fluid during evaluation of the well before stimulation are almost always those that are stimulated and form large-scale connections over a large reservoir volume. This may be because these fractures are connected anyway or because the fractures that are open are those oriented with the current stress state. It is important, therefore, to target areas that will have some pre-existing fractures due to their stress history and the degree of current differential stress. Even in areas with high compressional stresses, such as Cooper Basin in Australia, there are natural, open fractures.
With present technology, connected fractures cannot be created where none exist. It may be possible to initiate new fractures, but it is not known whether these will form large-scale flow paths and connect over large volumes of the reservoir. This means that the fracture spacing in the final reservoir is governed by the initial, natural fracture spacing. The number of fractures in a wellbore that will take fluid is important to assess in each well. The total heat that can be recovered is governed by the fracture spacing because the temperature drops rapidly away from the fracture face that is in contact with the injected cool fluid.
4. There is currently no reliable open-hole packer to isolate some zones for stimulation. This is routine in the oil and gas industry; but in the geothermal industry, high-temperature packers for the open hole are not reliable so we stimulate the entire open interval. Logging shows that the first set of open fractures is the one most improved. If you want to stimulate some zones more than others, or if you want to create new fractures, you will need a good, reliable, high-temperature open-hole packer. Although earlier testing at Soultz (France) using a cement inflatable aluminum packer has been encouraging, more development work remains to be done to improve reliability and increase temperature capability.
5. Hydraulic stimulation is most effective in the near-wellbore region. The near-wellbore region experiences the highest pressure drop so stimulation of this region is important. Connectivity in the far field away from the wells is also required to maintain circulation and accomplish heat mining. A variety of techniques, both from the oil and gas industry and from geothermal experience, can be effectively used to improve near-wellbore permeability. Hydraulic stimulation through pumping large volumes of cool fluid over long time periods and acidizing with large volumes of cool fluid and acid (of low concentration) have been most effective. Use of high-viscosity fluids, proppants, and high-rate high-pressure stimulation has been tried with mixed success and may still have potential in some settings, particularly in sedimentary reservoirs with high temperatures. There are, however, limits to the temperature that packers, proppants, and fracturing fluids can withstand. Some of these techniques are impossible or very costly in a geothermal setting.
In crystalline rocks with pre-existing fractures, oil and gas stimulation techniques have failed to result in connection to other fractures and may form short circuits that damage the reservoir. Current efforts to stimulate geothermal wells and EGS wells, in particular, are limited to pumping large volumes of cold water from the wellhead. This means that the fractures that take fluid most readily anyway are stimulated the most. Only a small portion of natural fractures in the wellbore support flow. Because these more open fractures may also be the ones that connect our producers to our injectors, this may not be a disadvantage. There may be a large number of fractures observed in the wellbore; however, an ability to identify and target the best ones for stimulation is limited because of a lack of research.
6. The first well needs to be drilled and stimulated in order to design the entire system. Early efforts to create reservoirs through stimulation relied on drilling two wells that were oriented in such a way that there appeared to be a good chance of connecting them, given the stress fields observed in the wellbore and the regional stress patterns. At Fenton Hill, Rosemanowes, Hijiori, and Ogachi, this method did not yield a connected reservoir. Stress orientation changes with depth, or with the crossing of structural boundaries. The presence of natural fractures already connected (and at least somewhat permeable) makes evaluating the stimulated volume difficult. It seems much easier to drill the first well, then stimulate it to create as large a volume as possible of fractured rock, then drill into what we think is the most likely place, and stimulate again. Because of this, we can design wells as either producers or injectors, whereas it would be better if we could design wells for both production and injection. This emphasis on the first well demands that it be properly sited with respect to the local stress conditions. Careful scientific exploration is needed to characterize the region as to the stress field, pre-existing fractures, rock lithology, etc.
7. Monitoring acoustic emissions is the best tool for understanding the system. Mapping of acoustic events is one of the most important tools for understanding the reservoir. In hydrothermal systems, well tests and tracer tests demonstrate that water is circulating and in contact with large areas of rock. Stimulated fractures can be assessed in the same way, once there are two or more wells in hydraulic connection to allow for circulation tests. The location of acoustic emissions generated during stimulation and circulation can also be mapped with accuracies of around ± 10-30 m. While no one is completely sure what the presence or absence of acoustic emissions means in terms of fluid flow paths or reservoir connectivity, knowledge of the location and intensity of these events is certainly important. This information helps define targets for future wells.
If we drill into a zone that has already been stimulated and shows a large number of acoustic emissions events, it is commonly assumed that the well is connected to the active reservoir. This fact, however, does not always result in a good system for heat extraction. For example, at Soultz, GPK4 was drilled into an area that was within the volume of mapped acoustic emissions. Even after repeated stimulations, it did not produce a connected fracture system between the production and injection wells.
Mapping of acoustic emissions has improved so that we can locate acoustic emissions and determine the focal mechanism for these events more accurately than in the past. As a result, there is a better understanding of the stress field away from the wellbore and how stimulation affects it. Methods for mapping fractures in the borehole have been developed and the upper limit for temperatures at which they can operate is being extended. Ultrasonic borehole televiewers, microresistivity fracture imaging, and wellbore stress tests have all proved very useful in understanding the stress state, nature of existing fractures, and the fluid flow paths (before and after stimulation). Correlating the image logs with high-resolution temperature surveys and with lithology from core and cuttings allows a better determination of which fractures might be productive.
8. Rock-fluid interactions may have a long-term effect on reservoir operation. While studies of the interaction of the reservoir rock with the injected fluid have been made at most of the sites where EGS has been tested, there is still a good deal to learn about how the injected fluid will interact with the rock over the long term. The most conductive fractures often show evidence of fluid flow in earlier geologic time such as hydrothermal alteration and mineral deposition. This is encouraging in that it suggests that the most connected pathways will already have experienced some reaction between water and the rock fracture surface.
Fresh rock surfaces will not be protected by a layer of deposited minerals or alteration products. Currently, there is no way to know how much surface water (which cannot be in equilibrium with the reservoir rock) will need to be added to the system over the long term. The longest field tests that have been conducted have seen some evidence for the dissolution of rock and this has led to the development of preferred pathways and short circuits.
Regardless, the produced fluids will need to be cooled through the surface equipment, possibly resulting in precipitation of scale or corrosion (Vuatarez, 2000). Although not analyzed in this study, the use of carbon dioxide (CO2) as the circulating heat transfer fluid in an EGS reservoir has been proposed (Pruess, 2006). Brown (2000) has developed a conceptual model for such a system, based on the Fenton Hill Hot Dry Rock reservoir. The argument is made that supercritical CO2 holds certain thermodynamic advantages over water in EGS applications and could be used to sequester this important greenhouse gas.
9. Pumping the production well to get the high-pressure drops needed for high flow rates without increasing overall reservoir pressure seems to reduce the risk of short circuiting while producing at high rates. High pressures on the injection well during long-term circulation can result in short circuits. Circulating the fluid by injecting at high pressures was found to consume energy while, at the same time, tending to develop shorter pathways through the system from the injector to the producer. High-pressure injection during circulation may also cause the reservoir to continue to extend and grow, which may be useful for the portion of time the field is operating. It may not, however, create fractures that are in active heat exchange, given the system of wells that are in place.
High-pressure injection can also result in fluid losses to those parts of the reservoir that are not accessed by the production wells. By pumping the production wells in conjunction with moderate pressurization of the injection well, however, the circulating fluid is drawn to the producers from throughout the stimulated volume of fractured rock, minimizing fluid loss to the far field.
10. The wells needed to access the stimulated volume can be targeted and drilled into the fractures. While drilling deep wells in hard, crystalline rock may still be fairly expensive, the cost technology has improved dramatically since the first EGS wells were drilled at Fenton Hill. Drill bits have much longer life and better performance, typically lasting as long as 50 h even in deep, high-temperature environments. The rate of penetration achievable in hard, crystalline rock and in high temperature environments is continually increasing, partly due to technology developments with funding from the U.S. government.
As the oil and gas industry drills deeper, and into areas that previously could not be drilled economically, they will encounter higher temperatures and more difficult drilling environments. This will increase the petroleum industry’s demand for geothermal-type drilling. Most geothermal wells need to have fairly large diameters to reduce pressure drop when flow rates are high. Directional control is now done with mud motors, reducing casing wear and allowing better control. Although high temperatures are a challenge for the use of measurement-while-drilling tools for controlling well direction, they did not exist when the first EGS well was drilled. Furthermore, the temperature range of these tools has been extended since they first became available. Mud motors are now being developed that can function not only at high temperatures, but also with aerated fluids.
11. Circulation for extended time periods without temperature drop is possible. Although early stimulated reservoirs were small and long-term circulation tests showed measurable temperature drop, later reservoirs were large enough that no temperature drop could be measured during the extended circulation tests. It is difficult to predict how long the large reservoirs will last because there is not enough measurable temperature change with time to validate the numerical models. Tracer test data can be used for model verification, but in cases where extremely large reservoirs have been created, tracer data may not be adequate for determining the important parameters of heat-exchange area and swept volume.
12. Models are available for characterizing fractures and for managing the reservoir. Numerical simulation can model fluid flow in discrete fractures. It can also model flow with heat exchange in simple to complex fractures, in porous media and in fractured, porous media. Changes in permeability, temperature changes, and pressure changes in fractures can be fit to data to provide predictive methods. Because long-term tests have not been carried out in the larger, commercial-sized reservoirs, it is not yet known whether the models will adequately predict the behavior of such reservoirs. Rock-fluid interactions in porous media or fractured, porous media can also be modeled, but their long-term effects are equally uncertain. Commercial fracture design codes do not take thermal effects into consideration in determining the fracturing outcome. Geothermal codes for fracture stimulation design purposes that do consider thermal or hydraulic effects in fracture growth have not yet been developed.
13. There are a number of induced seismicity concerns. In EGS tests at the Soultz site, microseismic events generated in the reservoir during stimulation and circulation were large enough to be felt on the surface. Efforts to understand how microearthquakes are produced by stimulation are ongoing, and new practices for controlling the generation of detectable microseismic events are developing. A predictive model that connects reservoir properties and operating parameters such as flow rate, volume injected, and pressure which might affect the generation of detectable microearthquakes is important to realizing the potential of EGS. Such a model has not been quantitatively established.” MIT Report to DOE, “The Future of Geothermal Energy,” 2006.
Environmental Issues
Geothermal energy is not without environmental impact according to the Towler Principle (Chapter 1). So what are those impacts? On the one hand, geothermal power plants do not burn fuel to generate their electricity so their air emissions are very low. They release less than 1% of the carbon dioxide emissions of a fossil fuel plant. Geothermal plants, however, usually emit hydrogen sulfide (also known as “rotten egg gas”) that is often found naturally in steam and hot water underground. This must be captured and converted to elemental sulfur or sulfuric acid or reinjected underground. Some plants also emit trace amounts of arsenic and other harmful metals. Some geothermal plants, such as the one at the Salton Sea reservoir in Southern California, also produce a significant amount of salt that builds up in the pipes and other plant equipment. Initially, the Salton power plant recovered this salt and put it into a landfill, which caused contamination of the groundwater supply. Now, they dissolve the salt in the wastewater and reinject it back into the same formation that produces the hot water via the reinjection process.
If the condensed steam or cooled water is not reinjected, the water in the reservoir underground becomes depleted. This can affect the water table and the groundwater supplies of other users and also results in a depleting geothermal resource. Consider, for example, if there was a proposal to build a geothermal power plant in the Yellowstone National Park adjacent to the Old Faithful geyser (Figure 11.5). This would be a natural place to put a geothermal plant because there is clearly hot water and steam close to the surface that could easily be captured and utilized in a commercial power plant. The result of this, however, would likely be that the Old Faithful geyser would cease to erupt once every hour, as it currently does. When people visit Yellowstone National Park, they come to see Old Faithful. If it ceased to erupt, many people would be upset and some people would not come to visit the National Park at all, despite the many other natural wonders there are to see. Clearly, the environmental impact of a geothermal power plant in Yellowstone National Park would not be acceptable.
The large Geysers project in Northern California suffered from the problem of a depleting water table and declining power output until they began injecting the make-up water to remedy this. Apart from the impacts on other users of the water table, if the geothermal plant does not reinject water, the result is a depleting nonrenewable energy source.
With closed-loop systems, there are minimal emissions and minimal environmental impacts because everything brought to the surface is returned underground. The energy extracted is renewed by ongoing radioactivity in the Earth’s interior. In general, the surface is disturbed by the drilling of wells and deployment of turbines and associated equipment that have a visual impact and other disturbances to the environment. There could be other environmental impacts that are not immediately apparent but, if developed in the proper manner, the overall environmental impact of a geothermal project should be small; but it is not always acceptable. To illustrate this point, the Glass Mountain project in Northern California was an EGS test case which targeted low-permeability, high-temperature rocks just outside the defined hydrothermal boundary of The Geysers geothermal project. The operator, Calpine, was unable to obtain an environmental permit to initiate the project, which led to its cancelation. The Glass Mountain project would have been relatively benign and was located adjacent to an area that was already developed for geothermal activity, but it was still deemed to be unacceptable by the permitting authorities. Calpine then moved the project to its operating plant in an area inside The Geysers boundary where there is low permeability rock and high hydrogen sulfide content and a resulting acidic steam. The new project targeted the stimulation of low-permeability rock on the fringe of their production area to improve the steam quality and to recharge the reservoir while recovering heat energy.
The Future of Geothermal Energy
With current technology, geothermal energy is likely to remain a small player in the United States and the world energy supply. There are only limited areas where geothermal energy can be extracted economically. It does have the potential to play a larger role if EGSs technology can be made cost effective. If this happens, the payoff could result in a cleaner sustainable energy system that is cost competitive. Like hydroelectricity, it is one of the few renewable energy technologies that can supply continuous and reliable base-load power and can be turned up and down as the load changes. The costs for electricity from geothermal facilities are highly variable and generally higher than fossil fuels. The costs, however, are declining and The Geysers geothermal plants have realized a 50% reduction in the price of electricity since 1980. The aim is to open up a large swathe of potential geothermal resources that might be able to produce electricity for about 8 cent/kWh (including a production tax credit), a cost that would be competitive with new conventional fossil fuel-fired power plants. There is also increased potential for the direct use of geothermal resources as a heating source for homes and businesses in many locations. In order to tap into the full potential of geothermal energy, the emerging technologies require further development and cost improvements.