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CHAPTER THREE

Energy Technologies: How They Work and Their Induced Seismicity Potential

Much of the energy used in the United States comes from fluids pumped out of the ground. Oil and gas have been major energy sources in the country for over 100 years, and new developments in the production of natural gas indicate that it may provide a significant source of energy for the nation during the twenty-first century. Geothermal power has been used to supply energy in the United States for almost as long as oil, although major electricity generation from geothermal energy sources began only in the 1960s at The Geysers in Northern California. A 2006 report on the potential of geothermal energy (MIT, 2006) suggested it could be a major contributor to the nation’s energy supply in the coming decades. Efforts to reduce concentrations of carbon dioxide (CO2) in the atmosphere have spurred development of technologies to capture and store (sequester) CO2. Projects to accomplish carbon capture and storage (CCS) from industrial facilities are currently being piloted in the United States and elsewhere in the world. Underground injection of CO2 has also been commonly used to enhance oil and gas recovery.

This chapter reviews the potential for induced seismicity related to geothermal energy production, conventional oil and gas development (including enhanced oil recovery [EOR]), shale gas development, injection wells related to disposal of wastewater associated with energy extraction, and CCS.

GEOTHERMAL ENERGY

Geothermal energy exists because of the substantial heat in the Earth and the temperature increase with depths below the Earth’s surface. Depending upon the regional geology—including the composition of the rocks in the subsurface and any of the fluids contained in the rocks—the temperature increase with depth (the thermal gradient) may be fairly steep and represent the source of sufficient geothermal energy to allow commercial development for electricity generation. The largest actively producing geothermal field in the United States at The Geysers in Northern California generates approximately 725 megawatts of electricity per year (“megawatts electrical” or MWe). This is enough to power 725,000 homes or a city the size of San Francisco. Currently this geothermal field supplies nearly 60 percent of the average electricity demand of the northern coastal region of California.



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CHAPTER THREE Energy Technologies: How They Work and Their Induced Seismicity Potential Much of the energy used in the United States comes from fluids pumped out of the ground. Oil and gas have been major energy sources in the country for over 100 years, and new developments in the production of natural gas indicate that it may provide a significant source of energy for the nation during the twenty-first century. Geothermal power has been used to supply energy in the United States for almost as long as oil, although major elec­ tricity generation from geothermal energy sources began only in the 1960s at The Geysers in Northern California. A 2006 report on the potential of geothermal energy (MIT, 2006) sug- gested it could be a major contributor to the nation’s energy supply in the coming decades. Efforts to reduce concentrations of carbon dioxide (CO2) in the atmosphere have spurred development of technologies to capture and store (sequester) CO2. Projects to accomplish carbon capture and storage (CCS) from industrial facilities are currently being piloted in the United States and elsewhere in the world. Underground injection of CO2 has also been commonly used to enhance oil and gas recovery. This chapter reviews the potential for induced seismicity related to geothermal ­ nergy e production, conventional oil and gas development (including enhanced oil recovery [EOR]), shale gas development, injection wells related to disposal of wastewater associated with e ­ nergy extraction, and CCS. GEOTHERMAL ENERGY Geothermal energy exists because of the substantial heat in the Earth and the tem- perature increase with depths below the Earth’s surface. Depending upon the regional geology—including the composition of the rocks in the subsurface and any of the fluids contained in the rocks—the temperature increase with depth (the thermal gradient) may be fairly steep and represent the source of sufficient geothermal energy to allow com- mercial development for electricity generation. The largest actively producing geothermal field in the United States at The Geysers in Northern California generates approximately 725 megawatts of electricity per year (“megawatts electrical” or MWe). This is enough to power 725,000 homes or a city the size of San Francisco. Currently this geothermal field supplies nearly 60 percent of the average electricity demand of the northern coastal region of California. 59

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INDUCED SEISMICITY POTENTIAL IN ENERGY TECHNOLOGIES The most likely regions for commercial development of geothermal power are gener- ally the same regions that have experienced recent volcanism (Figure 3.1). Such areas are concentrated in the western portion of the country. The U.S. Geological Survey (USGS) estimates that the total power output from the hydrothermal (vapor- and liquid-dominated) geothermal resources in the United States can probably be increased to 3,700 MWe per year, and a 50 percent probability exists that it can be increased to about 9,000 MWe per year (Williams et al., 2008). Two recent studies have produced nationwide estimates of the electric power potential that might be achieved by a successful implementation of enhanced geothermal systems (EGS) technology, perhaps contributing 100,000 MWe of electrical power per year (MIT, 2006). More recently the USGS (Williams et al., 2008) has published a mean estimate for potential EGS development on private and accessible public land at The Geysers Coso Geothermal Field Heat Flow (mW/m 2 ) 25-29 30-34 35-39 40-44 45-49 50-54 55-59 60-64 65-69 70-74 75-79 80-84 85-89 90-94 95-99 100-149 150+ FIGURE 3.1  The location of the geothermal provinces in the United States. Within the United States the regions of relatively high thermal gradients, shown in red, exist only in the West. The typical local geologic setting for these high-geothermal-gradient areas is within sedimentary basins located near or intruded by recent volcanics, or within (as part of) the buried volcanic rocks themselves. Only one vapor-dominated reservoir has been developed in the United States (The Geysers); the remainder of the areas in red and orange may host viable liquid-dominated or enhanced geothermal system reservoirs. SOURCE: SMU Geothermal Lab; Blackwell and Richards (2004). 60

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Energy Technologies: How They Work and Their Induced Seismicity Potential 517,800 MWe. This is approximately half of the current installed electric power generating capacity in the United States.1 The three different forms of geothermal resources are recognized: (1) “vapor-­ dominated,” where primarily steam is contained in the pores or fractures of hot rock; (2) “liquid-dominated,” where primarily hot water is contained in the rock; and (3) “hot dry rock,” where the resource is simply hot and currently dry rock that requires an EGS to facilitate development (see Figure 2.1). Vapor- and liquid-dominated systems are collec- tively termed hydrothermal resources. The vast majority of known hydrothermal resources are liquid dominated. The different forms of geothermal resources result in significant differences in the manner ­ in which they are developed and particularly in the manner that liquids are injected to help stimulate energy development. Different injection practices can cause induced seismicity through different processes. The nature of and differences among the induced ­ eismicity that s may result from each of the three geothermal resources are summarized here. Vapor-Dominated Geothermal Resources A limited number of localities in the world exist where the geothermal resources natu- rally occur as steam. Despite their rarity, the two largest geothermal developments of any kind in the world are both vapor-dominated geothermal reservoirs. The Larderello geo­ thermal field in the Apennine Mountains of northern Italy became the first of these and has generated electricity continuously since 1904, except during World War II. However, the most productive geothermal field development in the world is The Geysers (Figure 3.2), located about 75 miles north of San Francisco. The Geysers also has the most historically continuous and well-documented record of seismic activity associated with any energy technology development in the world. The first commercial power plant at The Geysers came online in 1960 with a capacity of 12 MW (Koenig, 1992). Over the next 29 years the installed generation capacity was increased to a total of 2,043 MW through building 28 additional power plant turbine-­ generating units (CDOGGR, 2011). The basic elements of the process to generate elec­ tricity in this type of power plant are illustrated in Figure 3.3. These plants were supplied with steam from 420 production wells, with the steam c ­ apable of flowing up the production wells under its own pressure. The condensed steam not evaporated at the power plant cooling towers was being reinjected into the steam reservoir by using 20 injection wells drilled to similar depths. The area of development had been expanded from the original 3 square miles to about 30 square miles. Because the genera- tion of energy from the field consumes natural steam originally in the reservoir, by 1988 1  See http://www.eia.gov/electricity/capacity. 61

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INDUCED SEISMICITY POTENTIAL IN ENERGY TECHNOLOGIES FIGURE 3.2  Ridgeline Unit 7 and 8 Power Plant (rated at 69 MW) in the left foreground at The Geysers in California. The turbine building, housing the two turbine-generator sets, the operator’s control room, and various plant auxiliaries are on the left. The evaporative cooling tower with steam emanating from the top is on the right of the main complex. The beige pipelines along the roads (with square expansion loops) are the steam pipelines that gather the steam from the production pads and bring it to the plant. A high-voltage transmission line (denoted by lattice towers) is in the middle foreground of the picture. SOURCE: Calpine. the production of steam had started to decline; this decline was marked by a significant decrease in reservoir pressure from an original pressure of about 500 pounds per square inch (psi)2 to levels as low as 175 psi (Barker et al., 1992). For years the annual injection volumes returned to the geothermal reservoir were less than a third of the amount of steam being produced, so the reservoir was drying up. New sources of water were established by con- structing two pipelines that currently deliver about 25 million gallons of treated wastewater a day for injection, increasing the current annual mass replacement to 86 percent compared to 26 percent back in 1988 (CDOGGR, 2011). Early reports of induced seismicity at The Geysers, begun by USGS researchers (­ amilton and Muffler, 1972), described microseismicity that was observed close to where H 2  A car tire for a standard, midsized automobile is usually inflated to a pressure of about 30-35 psi for comparison. 62

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Energy Technologies: How They Work and Their Induced Seismicity Potential Steam Flow Net Plant Output Metering Metering Main Steam Line 13.8 KV 230 KV Auxiliary Steam Line Turbine Generator Transformer Gas Ejector From Steam Cooling Wells Tower Secondary H2S Stretford Condenser Abatement System System Hot Well Condensate Pump Reinjection System Circulating Water Pumps FIGURE 3.3  Elements of the power plant cycle for vapor-dominated geothermal resources. The steam is directed by the main steam line into a turbine that spins the connected generator unit, typically generating electricity at 13.8 kilovolts (kV), which a transformer increases to 230 kV for distribution by a transmis- sion line. The steam leaving the turbine enters the condenser that contains a network of tubing through Figure 3.2.eps which cool water is circulated, facilitating the condensation process. The condensate is then pumped to the cooling tower where it is cooled by evaporation, with the cooled water being in part recirculated by the circulating water pumps back to and through the condenser. Because some noncondensable gases usually occur naturally in the steam, those gases are removed from the condenser by the gas ejector system that creates a partial vacuum by the flow of a small amount of steam delivered by the auxiliary steam line. Those gases, in particular H2S, are chemically processed commonly by a Stretford System before delivery to the cooling tower where they are vented. SOURCE: Adapted from the Northern California Power Agency. the geothermal development operations were taking place. As the area of steam field devel­ opment expanded, the areal distribution of seismic events similarly expanded, and the number of the events progressively increased (Figure 3.4). With the addition of more seismometers of increased sensitivity distributed throughout the expanded development area, a clear association became evident between these ­ nduced i events and the active injection wells and volume of water being injected. Figure 3.5 shows where injection took place in the southeastern part of The Geysers in 1998, the year follow­ ing the startup of the first wastewater pipeline that more than doubled the injection vol- ume. During 1997-1998, 1,599 events of M ≥ 0.6 were recorded, an increase of just over 50 percent compared to the prior 12 months. The history of steam production, water injection, and seismic history at The Geysers since 1965 is shown in Box 3.1. Steam production and therefore electricity generation reached a maximum in 1987, followed by a fairly rapid decline until the wastewater pipelines 63

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INDUCED SEISMICITY POTENTIAL IN ENERGY TECHNOLOGIES FIGURE 3.4  Geysers seismicity maps in 10-year intervals show the expanding distribution of develop- ment as illustrated by the increased numbers of green squares that indicate the locations of the operating power plants. SOURCE: Preiss et al. (1996). FIGURE 3.5  The locations of injection wells and the location and depth distribution of seismic events in the southeastern part of The Geysers area during 1997-1998. Map on the left shows injection wells in 1998. The middle map shows the total number of recorded seismic events from the period 1997-1998 with the line of cross section (figure on the right). The cross section shows the positions of three geothermal wells with the location at depth of theFigure events (red dots). SOURCE: Beall et al. (1999). seismic 3-5 Bitmapped began deliveries in 1997 and 2003. The annual amount of water injected followed the same trends until new sources of water other than condensate were developed, allowing recent injection to become nearly equal to the annual production levels. The method of injection at The Geysers is unusual because of the extremely low fluid pressures in the deep underlying reservoir. No surface pressure is needed to inject; the water simply falls down the injection well as though through a partial vacuum because the fluid pressures in the reservoir are incapable of supporting a liquid level to the surface. Consequently, without elevated bottom-hole pressures, the primary cause of the induced 64

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Energy Technologies: How They Work and Their Induced Seismicity Potential BOX 3.1 Geysers Annual Steam Production, Water Injection, and Observed Seismicity, 1965-2010 Figure The history of induced seismicity at The Geysers is shown in three forms. First, the number of ­ ecorded events of M 1.5* and greater is shown to have increased from almost none in the 1960s to 112 in r 1975 and then to as many as 1,384 in 2006 (thick green line). Second, the annual number of earthquakes Box 3-1 of M 3.0 and greater is shown along the bottom of the graph (pale green line). By 1985, 25 such events occurred annually, and that rate of about twoBitmapped and greater per month has continued to the events of M 3.0 present. Third, events of M 4.0 and greater are shown near the top (green dots). The first such event occurred in 1972, and more recently about one to three of these have occurred per year. The maximum magnitude was a M 4.67 event in May 2006. SOURCES: Adapted from Smith et al. (2000) and Majer et al. (2007). *Note that this report uses M 2.0 as the general limit below which earthquakes cannot be felt by humans; however, at The Geysers M 1.5 is the lowest magnitude that the USGS can report faithfully year after year. Furthermore, residents in Anderson Springs may feel events as low as M 1.5 because the events are spatially quite close to the community. 65

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INDUCED SEISMICITY POTENTIAL IN ENERGY TECHNOLOGIES seismicity is the fact that the hot subsurface rocks are significantly cooled by the injected water, and the resulting thermal contraction reduces the confining pressures and allows the local stresses to be released by limited movement on fracture surfaces. The two strong motion recording instruments installed in 2003 near the neighboring communities of Anderson Springs and Cobb commonly record moderate shaking, plus about a dozen Mercalli VI (strong shaking) events each year (see also Chapter 1 for a definition of the Mercalli scale). The one event of Mercalli VII intensity caused an average acceleration of 21.0%g3 at Anderson Springs and was related to a M 3.03 seismic event located at a depth of 4,750 feet only 1.2 miles west of the recording instrument. The operators at The Geysers meet regularly with representatives of these two com- munities, county government, federal and state regulatory agencies, the USGS, and the Lawrence Berkeley National Laboratory to discuss the field operations and the recently observed seismicity. Minor damage is occasionally caused by the induced seismicity at The Geysers, generally as cracks to windows, drywalls, or tile walls or flooring in these communi- ties. A system for receiving, reviewing, and approving such damage claims attributed to the local seismicity was established 6 years ago, and the homeowners are reimbursed for their costs to have the home damage repaired. To date these reimbursements for home repairs total $81,000, and this system appears to be resulting in mutually satisfactory relationships. Liquid-Dominated Geothermal Resources In contrast to the development of the vapor-dominated geothermal resources, liquid- dominated resources commonly use downhole pumps in the production wells to deliver the thermal waters to surface facilities. Surface pumping facilities are needed to force the injected waters back down into the reservoir. The liquid-dominated geothermal reservoirs that have been commercially developed to produce electricity in the western United States are listed in Table 3.1 (sources include the California Division of Oil, Gas and Geothermal Resources [CDOGGR], the Nevada Commission on Mineral Resources, the Imperial Irri­ gation District, and various operators). Several different methods are used to generate electricity in liquid-dominated geo- thermal systems depending primarily on the temperature of the produced fluids; the flash steam power cycle process and the binary cycle process are the most common (Figure 3.6). The cause and extent of the induced seismicity related to the development of l ­iquid-dominated geothermal resources are different from those in the vapor-dominated resources (Box 3.2). From the start of operations the amount of fluid produced from a liquid-­ ominated reservoir is almost fully replaced by injection, which prevents a signifi- d 3  “%g” is motion measured as acceleration by an instrument, expressed as a percent of the acceleration of a falling object due to gravity. 66

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Energy Technologies: How They Work and Their Induced Seismicity Potential cant decline in reservoir pressure. The temperature difference between the produced and r ­einjected waters is also relatively limited, so less cooling of the reservoir results. Conse- quently, if the surface and resulting bottom-hole pressures in the injection wells are limited to be less than that necessary to induce fracturing, little cause exists for the operations to produce significant induced seismicity. Monitoring at many of the liquid-dominated geo- thermal fields has demonstrated a relative lack of induced seismicity. However, as described below, the Coso geothermal field began as a strictly liquid-dominated field and has evolved during extended production to become partly vapor dominated. This evolution has resulted in reduction in fluid replacement and has caused the introduction of induced seismic events. The Coso geothermal field provides a well-documented example of a complex resource area that was liquid dominated before the start of development 25 years ago and that may have evolved, following extensive production, into a resource that is now in part vapor domi- nated (see Box 3.2). Coso near Ridgecrest, in southeast-central California, is in a region of recent volcanism that is also seismically active. The first commercial geothermal power plant began operating in 1987; since 1989 three plants have been in operation with a total generating capacity of 260 MW, with about 85 production and 20 injection wells currently in use (CDOGGR, 2011). The geothermal fluids (dominantly water) are at temperatures in excess of 300°C (572°F) at depths of 1.5-2 km (~0.9-1.2 miles) (Feng and Lees, 1998). The areal coincidence of the local seismicity at Coso with local surface subsidence, identified by using synthetic aperture radar data, suggest that the Coso field operations have caused reservoir cooling and thermal contraction, resulting in induced seismicity (Fialko and Simons, 2000). More recently, Kaven et al. (2011), based in part on their investigation of local changes in seismic velocities (Vp:Vs ratios), attribute the induced seismicity at Coso to decreases in fluid saturation and/or fluid pressure within the active geothermal reservoir. An important issue to emphasize with regard to potential changes in pore pressure at vapor- and liquid-dominated geothermal power plants is the selection of conversion cycle—whether flash cycle or binary cycle (see Figures 3.2 and 3.6). The cycle selection is determined by the temperature and nature (physical state) of the geothermal fluids produced to the surface. Those power-cycle differences are important to explain why evaporative losses are significant at vapor-dominated resource power plants and moderate at flash cycle power plants. Evaporative losses can result in pore pressure and thermal losses that in turn can result in significant or moderate levels of induced seismicity. Equally important is to explain why in the case of binary cycle power plants there are no evaporative losses and generally little if any loss of pore pressure or fluid temperature, and therefore little if any associated induced seismicity. 67

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TABLE 3.1  Liquid-Dominated Geothermal Fields in the United States with Operating Power Plants 68 Area Plant Power Plant Average Average Resource  Field Start Year Power Cycle Used Capacity (MWe) Generation (MWe) Temperature (°F) Owner/Operator California Imperial Valley   North Brawley 2010 Binary 50 20.9 375 Ormat   East Mesa 1987 Binary & Flash 105 59 306 Ormat  Heber 1985 Binary & Dual 92 75.9 324 to 350 Ormat Flash   Salton Sea 1982 Single, Dual, & 352 314.6 480 to 690 Cal Energy Triple Flash Mojave Desert  Coso 1987 Dual Flash 260 48 480 to 580 TerraGen Mammoth   Casa Diablo 1984 Binary 29 20.9 340 Ormat Power subtotal 888 539.3 Nevada Reno/Fallon  Brady 1992 Dual Flash 26.1 14.8 284 Ormat   Desert Peak 2006 Binary 14 14 370 Ormat   Jersey Valley 2010 Binary 15 Na 330 Ormat   Salt Wells 2009 Binary 28 Na na Enel   San Emidio 1987 Binary 3.6 2.6 275 to 290 U.S. Geothermal   Soda Lake 1987 Binary 26.1 10.4 360 to 390 Magma  Steamboat 1988 Binary & Flash 139.5 105.5 300 Ormat  Stillwater 2009 Binary 47.3 15.9 na Enel  Wabuska 1987 Binary 2.4 0.8 na H.S. Geothermal

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North Central  Beowawe 1985 Dual flash 16.6 14.6 410 TerraGen   Blue Mountain 2009 Binary 49.5 40 375 Nevada Geo   Dixie Valley 1988 Dual flash 67.2 41.2 400 to 480 TerraGen Power subtotal 435.3 259.8 Utah  Roosevelt 1984 Binary & Flash 37 34 510 Pacific Corp  Thermo 2008 Binary 10.0 6.6 250 to 390 Raser Power subtotal 47 40.6 Idaho   Raft River 2008 Binary 13 8.4 275 to 300 U.S. Geothermal Hawai’i   Big Island  Puna 1993 Combined Cycle 30 na 330 Ormat Alaska   Fairbanks area   Chena Hot Springs 2006 Binary 0.73 0.5 165 Chena Energy Power totals 1414.03 848.6 69

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INDUCED SEISMICITY POTENTIAL IN ENERGY TECHNOLOGIES Wastewater disposal FIGURE 3.15  Histograms of maximum magnitudes documented in technical literature caused by or likely related to subsurface energy production globally. Note: Many gas and oil fields undergo extraction of hydrocarbons along with injection of water for secondary recovery, but if the reported total volume of extracted fluids exceeds that of injection, the site is categorized as extraction. Some cases of induced seismicity in the list above do not have reported magnitudes associated with earthquakes, and those cases are not included in the counts used to develop this figure. No induced seismic events have been recognized related to existing CCS projects. SOURCE: See Appendix C. sion (COGCC) (CGS, 2012) in the injection well permitting process. The injection and seismicity in the Raton Basin are under close scrutiny by both the CGS and COGCC. A definitive link to injection has not been established in the Raton Basin seismicity. Enhanced seismic arrays have been installed since 2011 in the area and will continue to be studied in detail by field operators, the Colorado agencies, and the USGS. Numerous geothermal sites report induced seismicity, but the associated maximum magnitudes are generally small, with a maximum reported M 4.6 (at The Geysers site in California). Finally, felt seismic events caused by hydraulic fracturing are small and rare, with only one incident globally of hydraulic fracturing causing induced seismicity less than M 3 (in Blackpool, England; note the description in Appendix J of the seismic event in Eola, Oklahoma). Several authors have observed that the maximum magnitudes of seismic events induced by various causes are related to the dimension or volume of human activity. Figure 3.16 (modified from Figure 3 of Nicol et al., 2011) plots the largest earthquake magnitudes 106

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Energy Technologies: How They Work and Their Induced Seismicity Potential Secondary recovery and waste and wastewater disposal 1,000. FIGURE 3.16  Graph showing maximum induced seismic event magnitude versus volume of fluid injected into or extracted from single wells or fields that are documented to have had a seismic event directly at- tributed to or strongly suggested to be caused by one of the energy technologies. These are global data. Events and associated volumes are identified by technology: red triangles denote geothermal energy with most of the data points representing fields (note that the net fluid volume, injected and withdrawn, at The Geysers is actually close to or below zero; see also Figure 3.17); blue triangles denote injection for secondary recovery or waste injection (such as at the Rocky Mountain Arsenal), almost all of which rep- resent single wells; yellow triangles denote fluid extraction (oil or gas withdrawal; note that no data were available on the amount of fluid that may also have been injected in these fields to facilitate withdrawal); and green triangles denote hydraulic fracturing for shale gas production, both of which represent single wells. Not plotted are data from some projects that do not represent maximum magnitude seismic events for that project. Geothermal, extraction, and injection data modified from Figure 3 of Nicol et al. (2011). Hydraulic fracture data have been added in this study. strongly suggested to be associated with fluid injection or extraction versus the volume of fluid reported for the injection or extraction project. The reported data suggest a correla- tion between the induced earthquake magnitudes and volumes of fluid injected. McGarr et al. (2002) suggested a correlation between maximum induced magnitude and the scale of human activity by plotting the maximum induced magnitude versus the dimension of the human activity (e.g., the maximum dimension of the hydrocarbon activity). Several points are important regarding these apparent correlations between induced magnitude and fluid volume: 107

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INDUCED SEISMICITY POTENTIAL IN ENERGY TECHNOLOGIES 1. Many factors are important in the relationship between human activity and in- duced seismicity: the depth, rate, and net volume of injected or extracted fluids, bottom-hole pressure, permeability of the relevant geologic layers, locations and properties of faults, and crustal stress conditions. These factors, some of which are inter­ ependent, are also described in Chapter 2. For an induced seismic event to d occur, at least two criteria have to be satisfied: (1) the pore pressure change in the reservoir has to exceed a certain critical threshold and (2) a certain net volume of fluid has to be injected (or extracted) to achieve a particular magnitude. The available data suggest, but do not prove, that the net volume of fluid may serve as a proxy for these factors, which indicates what set of conditions will generate small and large earthquakes. Particularly because the other data—bottom-hole pressure, permeability of the relevant geological layers, crustal stress factors, high- resolution well data (full waveform dipole and resistivity and waveform borehole imaging logs), seismic reflection images (two- and three-dimensional surface seis- mic techniques, 3D vertical seismic profiles or cross well seismic data) to reveal the subsurface structure such as the location, orientation, and properties of faults in the area—are not generally available, total volume can be a tool to draw inferences about various technologies. However, a pure causal relationship between the larg- est induced magnitudes and fluid volume should not be assumed. Important also, exceptions occur in those cases where fluids are injected into sites such as depleted oil, gas, or geothermal reservoirs, or at sites where the volume of extracted fluids essentially equals or exceeds the volume injected. In those cases pore pressures may not reach the original levels, or in some cases may not increase at all due to the relative volumes of injection and extraction. These data (specifically for oil and gas withdrawal and geothermal energy) are included in Figure 3.16, but it is noted that these specific data points do not necessarily represent the total (net) fluid (injected and withdrawn) that may be related to the maximum magnitude event. 2. The volumes indicated in Figure 3.16 include both volumes for individual wells in single projects and volumes for fields. The data cannot be used to predict earth- quake magnitudes for an entire region or industry, but rather only to infer what magnitudes might be possible for individual wells or fields. 3. The data in Figure 3.16 are maximum magnitudes associated with fluid injection or extraction and support the requirement, outlined in Chapter 2 and elsewhere in this chapter, that a certain net volume of fluid has to be injected to cause a seismic event of a certain magnitude (or in a similar sense for net fluid withdrawal). The graph does not represent causality, but a condition for an induced seismic event of a certain magnitude to occur. Importantly, the correlation in the figure does not predict what earthquake magnitude will be induced by a specific project, but it reports instead the observed limits (to date) of what earthquake magnitudes have 108

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Energy Technologies: How They Work and Their Induced Seismicity Potential been observed and can be used to infer what might be the size of the largest induced seismic events, if the volume of injected or extracted fluid is known. However, the correlation cannot be used to directly infer hazard or risk associated with various energy technologies. 4. These data and the limitations described point toward the great value in collecting information about well projects and characteristics, including the size of earth- quakes produced (if any). Data are critical to making progress in estimating hazard and risk (see Chapter 5). Another important factor to consider in evaluating the potential for an energy project to induce felt seismic events is the variation in volume from technology to technology, and the variation in net volume over time (Figure 3.17). For example, although CCS does not have the highest daily injection volumes among the technologies investigated, it does have the highest annual injected volumes because the projects are designed to run continu- ously with relatively large injection volumes. Also, CCS, similar to waste and wastewater disposal, involves only net addition of fluid to a reservoir rather than both injection and extraction that occur with oil and gas production and geothermal energy development. This characteristic is represented in the bottom graph in Figure 3.17 by the high net vol- umes of fluid injected for both technologies. Comparatively, the two geothermal cases (The Geysers and the EGS project at Basel) and hydraulic fracturing for shale gas production have negative or low net injection volumes on an annual basis. In the case of The Geysers, the negative net fluid volume is due to the high volumes of fluid extracted; annually, the fluid volume in The Geysers reservoir has actually been declining yearly, despite the high injection volumes. The tens of thousands of Class II water disposal wells located across the United States have proven to be mostly benign with respect to induced seismicity. However, there are clearly troublesome areas that have induced events as large as M 4.7 (Arkansas, 2011; see Horton, 2012) that warrant a closer examination. The dramatic increase in hydraulic fractur- ing over the past 5 years means an increased volume of wastewater from hydraulic fracturing requiring disposal. If the number of available Class II wastewater disposal wells remains the same, the volume of injected fluid in each well must increase to accommodate the increased wastewater. The long-term effect of this increased volume on the potential to induce felt seismic events is unknown but could be of concern. The implication for subsurface storage demonstration sites, for instance for CO2, is that pilot plants that inject small volumes of fluid cannot be expected to represent or bound the induced seismicity that might occur for production plants that will inject much larger volumes. Evaluation of production facilities for large-scale CCS thus requires a complete presentation of the risk of induced seismicity and a comprehensive monitoring plan includ- ing bottom-hole pressures and time response to different injection regimes. 109

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INDUCED SEISMICITY POTENTIAL IN ENERGY TECHNOLOGIES Shale gas well 6 Class II Geysers steam frac stage disposal well field/ave inj well average/day Shale gas frac 15 well Class II Geysers net loss 20% frac water disposal well 5.88E+7 m3 water recovery FIGURE 3.17  A comparison showing estimated injected fluid volumes for (1) shale gas hydraulic fractur- ing, (2) CCS, (3) Class II waste and wastewater disposal wells, (4) The Geysers geothermal steam field for an average injection well, and (5) the Basel EGS project per day (upper graph). The lower graph shows the same information over a 1-year period for each project, with the exception of the Basel EGS project (which operated in total for just 6 days before termination). Data are presented in Appendix L. The com- mittee could not find reliable data per well or per field for hydrocarbon extraction (withdrawal) or for secondary recovery (waterflooding). Hydraulic fracture volumes for shale gas assume a six-stage-per-day program, with a 4.64 million gallon average per well (the “average freshwater volume for fracturing” listed for five shale projects in King, 2012), estimating six hydraulic fracture treatments per day. For the hydraulic yearly volume calculation, an estimate of 15 wells drilled over a project area in the course of a year is made with a 20 percent recovery rate of injected fluid used. The CCS volume shown assumes 1 million tons (~0.9 million metric tonnes) of CO2 injection per year, similar to the Sleipner field offshore Norway. Class II disposal well data assume 9,000 barrels per day of wastewater injected. The Basel injec- tion volumes averaged 0.5 million gallons per day for 6 days. 110

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