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Chapter 3
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 21st 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 waste water 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 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 (“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 northern coastal region of California.
The most likely regions for commercial development of geothermal power are generally
the same regions that have experienced recent volcanism (Figure 3.1). Such areas are
concentrated in the western portion of the country. The USGS estimates that the total power
51
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52 INDUCED SEISMICITY POTENTIAL IN ENERGY TECHNOLOGIES
output from the hydrothermal (vapor- and liquid-dominated) geothermal resources in the United
States can probably be increased to 3,700 MWe and a 50% probability exists that it can be
increased to about 9,000 MWe (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 System (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 517,800 MWe. This is approximately half of the current installed
electric power generating capacity in the United States (DOE, 2011c).
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).
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 “Enhanced Geothermal System” (EGS) to
facilitate development (Figure 2.1). Vapor- and liquid-dominated systems are collectively termed
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ENERGY TECHNOLOGIES 53
“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 seismicity that
may result from each of the three geothermal resources are summarized below.
Vapor-dominated Geothermal Resources
A limited number of localities in the world exist where the geothermal resources
naturally 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 geothermal
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 (see 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.
Figure 3.3 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.
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54 INDUCED SEISMICITY POTENTIAL IN ENERGY TECHNOLOGIES
The first commercial power plant at the Geysers came on line 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 electricity in this type of power
plant are illustrated in Figure 3.3.
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) that a transformer increases to 230 kv for distribution by a transmission
line. The steam leaving the turbine enters the condenser that contains a network of tubing through 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 non-condensable gasses
usually occur naturally in the steam, those gasses 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 gasses, 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.
These plants were supplied with steam from 420 production wells, with the steam capable
of flowing up the production wells under its own pressure. The condensed steam not evaporated
at the power plant cooling towers was being re-injected 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 generation of energy from the field
consumes natural steam originally in the reservoir, by 1988 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 1 (psi) to levels as low as 175 psi (Barker et
al., 1992). For years the annual injection volumes returned to the geothermal reservoir were less
1
A car tire for a standard, mid-sized automobile is usually inflated to a pressure of about 30-35 psi for comparison.
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ENERGY TECHNOLOGIES 55
than a third of the amount of steam being produced, so the reservoir was drying up. New sources
of water were established by constructing two pipelines that currently deliver about 25 million
gallons of treated waste water 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 began by USGS researchers
(Hamilton and Muffler, 1972) described microseismicity that was observed close to where the
geothermal development operations were taking place. As the area of steam field development
expanded, the areal distribution of seismic events similarly expanded and the number of the
events progressively increased (Figure 3.4).
Figure 3.4 Geysers seismicity maps in 10-year intervals show the expanding distribution of development
as illustrated by the increased numbers of green squares that locate the operating power plants. Source:
Preiss et al. (1996).
With the addition of more seismometers of increased sensitivity distributed throughout
the expanded development area, a clear association became evident between these induced
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 following the start-
up of the first waste water pipeline that more than doubled the injection volume. 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.
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56 INDUCED SEISMICITY POTENTIAL IN ENERGY TECHNOLOGIES
Figure 3.5 The locations of injection wells and the location and depth distribution of seismic events in the
SE 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 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 the seismic events (red dots). Source: Beall et al. (1999).
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 waste water pipelines 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.
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
recorded events of M 1.5* and greater is shown to have increased from almost none in the 1960s to 112
in 1975 and then to as many as 1,384 in 2006 (thick green line). Second, the annual number of
earthquakes of M 3.0 and greater is shown along the bottom of the graph (pale green line). By 1985 25
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ENERGY TECHNOLOGIES 57
such events occurred annually, and that rate of about 2 events of M 3.0 and greater per month has
continued to 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 1 to 3 of these have occurred per year. The
maximum magnitude was a M 4.67 event in May 2006. SOURCE: 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.
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 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 definition of the
Mercalli scale). The one event of Mercalli VII intensity caused an average acceleration of
21.0%g 2 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
communities, county government, federal and state regulatory agencies, the USGS, and the
Lawrence Berkeley National Laboratory in order 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, or dry walls, or tile walls or flooring in these
communities. 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 down-hole 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 CDOGGR, Nevada Commission on Mineral Resources, Imperial irrigation
District, and various operators).
2
“%g” is motion measured as acceleration by an instrument, expressed as a percent of the acceleration of a falling
object due to gravity.
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58 INDUCED SEISMICITY POTENTIAL IN ENERGY TECHNOLOGIES
Table 3.1 Liquid-Dominated Geothermal Fields in the United States with Operating Power Plants.
Area Power cycle Power Average Average Owner/ operator
Plant
Field used plant generation resource
Start capacity (Mwe) temperature
Year (MWe) (degrees F)
California
Imperial Valley
North Brawley 2010 50
Binary 20.9 375 Ormat
East Mesa 1987 105
Binary & Flash 59 306 Ormat
Heber 1985 92
Binary & Dual 75.9 324 to 350 Ormat
Flash
480 to 690
Salton Sea Single, Dual, &
1982 352 314.6 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
W abuska 1987 Binary 2.4 0.8 na H.S. Geothermal
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 1354.0 848.6
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ENERGY TECHNOLOGIES 59
Several different methods are used to generate electricity in liquid-dominated geothermal
systems depending primarily on the temperature of the produced fluids—the Flash Steam Power
Cycle process and the Binary Cycle process being the most common (Figure 3.6).
(a)
(b)
Figure 3.6 a and b. (a) The fluids delivered to the surface by the production wells in a Flash Steam
Power Cycle are passed through a flash vessel or separator; the separated steam that flows out of the top
is directed into a power plant where it is used to spin a steam turbine connected to a generator that
produces an electrical output. The spent steam travels through a condenser and the condensate is then
pumped to the cooling tower where the liquids are cooled before some of the fluids are pumped back
inside the condenser and some are combined with the water drained from the bottom of the separator and
sent to the injection wells. (b) The produced fluids for Binary Cycle power plants are first passed through
a heat exchanger to heat a secondary liquid, usually an organic fluid such as isopentane, which vaporizes
(boils) at a lower temperature than does water. That vaporized secondary fluid is then used to spin a
turbine-generator to make electricity. Similarly, that vapor is then condensed and returned directly to the
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60 INDUCED SEISMICITY POTENTIAL IN ENERGY TECHNOLOGIES
heat exchanger to be reheated, revaporized and recycled without any fluid loss. The produced geothermal
water that has passed through the heat exchanger is then delivered to the injection wells. SOURCE: Idaho
National Laboratory.
The cause and extent of the induced seismicity related to the development of liquid-
dominated geothermal resources are different from those in the vapor-dominated resources (see
Box 3.2). From the start of operations the amount of fluid produced from a liquid-dominated
reservoir is almost fully replaced by injection, which prevents a significant decline in reservoir
pressure. The temperature difference between the produced and reinjected waters is also
relatively limited, so less cooling of the reservoir results. Consequently, 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 geothermal 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-dominated
(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 degrees Celsius
(572 degrees F) at depths of 1.5-2 kilometers (~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 therefore generally little if any loss of
pore pressure or fluid temperature, and therefore little if any associated induced seismicity.
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ENERGY TECHNOLOGIES 61
Box 3.2
Induced Seismicity at the Coso Liquid-Dominated Geothermal Field
Locally induced seismicity recorded in the area of the Coso geothermal field development
between 1996 and 2008 in map view (Figure 1, upper figure) and cross-section (Figure 1, lower figure)
shows clustering relative to the location and depth of the geothermal wells shown in blue. The number of
seismic events of magnitude 0.5 and greater is plotted; these events total 10,200.
Figure 1 Seismicity recorded at the Coso geothermal field. SOURCE: Kaven et al. (2011).
The history of geothermal fluid (dominantly water) production, water injection and recent seismic
history at the Coso field from 1977 through 2011 is shown in Figure 2. Starting in 1987, annual
production reached a maximum of 121 billion lbs* in 1990 and had decreased to 68 billion lbs by 2009
while annual injection has declined from a maximum of 80 billion lbs to 27 billion lbs (CDOGGR, 2011).
The relatively low reinjection rate for a liquid-dominated resource is because of cooling tower evaporative
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94 INDUCED SEISMICITY POTENTIAL IN ENERGY TECHNOLOGIES
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 earthquake 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 reports instead the observed limits (to date) of what earthquake magnitudes
have 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.
Figure 3.16. Graph showing maximum induced seismic event magnitude vs. volume of fluid injected into
or extracted from single wells or fields that are documented to have had a seismic event directly attributed
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
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ENERGY TECHNOLOGIES 95
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
represent 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.
(4) These data and the limitations described point toward the great value in collecting
information about well projects and characteristics, including the size of earthquakes 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 amongst the technologies investigated, it does have the highest
annual injected volumes because the projects are designed to run continuously with relatively
large injection volumes. Also, CCS, similar to waste and waste water disposal, involves only net
addition of fluid to a reservoir rather than both injection and extraction that occurs with oil and
gas production and geothermal energy development. This characteristic is represented in the
lower figure in Figure 3.17 by the high net volumes 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.
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96 INDUCED SEISMICITY POTENTIAL IN ENERGY TECHNOLOGIES
Figure 3.17 A comparison showing estimated injected fluid volumes for (1) shale gas hydraulic
fracturing, (2) CCS, (3) Class II waste and waste water 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 one-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 committee 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 4.64 million gallon average per well (the “average fresh water volume for
fracturing” listed for 5 shale projects in King, 2012), estimating 6 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 20% 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
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ENERGY TECHNOLOGIES 97
Norway. Class II disposal well data assume 9,000 barrels per day of waste water injected. The Basel
injection volumes averaged 0.5 million gallons per day for 6 days.
The tens of thousands of Class II water disposal wells located across the United States
have proven to be mostly benign with respect 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 fracturing over the past 5
years means an increased volume of waste water from hydraulic fracturing requiring disposal. If
the number of available Class II waste water disposal wells remains the same, the volume of
injected fluid in each well must increase to accommodate the increased waste water. The long
term effect of this increased volume on 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 including bottom-hole
pressures and time response to different injection regimes.
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