Energy Technologies and Induced Seismicity

Murray W. Hitzman, Colorado School of Mines; Donald D. Clarke, Geological Consultant; Emmanuel Detournay, University of Minnesota, CSIRO (Earth Science and Resource Engineering), Australia; James H. Dieterich, University of California; David K. Dillon, David K. Dillon PE, LLC; Elizabeth A. Eide, National Research Council; Sidney J. Green, University of Utah; Robert M. Habiger, Spectraseis; Robin K. McGuire, Lettis Consultants International, Inc.; James K. Mitchell, Virginia Polytechnic Institute and State University; Julie E. Shemeta, MEQ Geo, Inc.; John L. (Bill) Smith, Geothermal Consultant

Figure 1. Sites in the US and Canada with reports of seismicity

Figure 1 Sites in the United States and Canada with documented reports of seismicity caused by or potentially related to human activities, including injection or withdrawal of fluids related to energy development. Other human activities that have caused induced seismic events include the impoundment of water behind dams, planned explosions at mining and construction sites, and underground nuclear tests. These kinds of induced seismic events have been described since at least the 1920s. SOURCE: NRC (2013)

In recent years, small seismic events in a few locations in the United States have been attributed to injection of fluids related to energy development projects. Although only a small number of the many thousands of earthquakes occurring throughout the world each year are related to any kind of human activity (Figure 1), these “induced seismic events” or “induced earthquakes” can occur at levels noticeable to the public and have caused concern about the potential for further induced events as energy development proceeds (NRC, 2013).

The occurrence of these recent induced earthquakes related to fluid injection and withdrawal for energy development encouraged the U.S. Department of Energy in 2010 to ask the National Research Council (NRC) to examine induced seismicity that might occur during geothermal energy production, oil and gas production, carbon capture and storage (CCS), and wastewater injection. The work of the NRC committee resulted in a consensus report that was released in June 2012 (see article Induced Seismicity Potential in Energy Technologies; NRC, 2013).1 The significant points of that report including the physical causes, scale and scope, hazards and risks, steps toward developing protocols and best practices, and gaps in current research are outlined briefly in this contribution. A YouTube video, which describes key elements of the report was also developed by the NRC and is available on the National Academies YouTube channel (Energy Technologies and Manmade Earthquakes video).

In recent years, small seismic events in a few locations in the United States have been attributed to injection of fluids related to energy development projects. Although only a small number of the many thousands of earthquakes occurring throughout the world each year are related to any kind of human activity (Figure 1), these “induced seismic events” or “induced earthquakes” can occur at levels noticeable to the public and have caused concern about the potential for further induced events as energy development proceeds (NRC, 2013).

Figure 2. Injection of fluid inside a porous elastic sphereFigure 2 (a) Injection of a finite volume of fluid inside a porous elastic sphere (gray shaded circle) embedded in a large impermeable elastic body (white shape) generates a pore pressure increase (Δρ) inside the sphere and a stress perturbation inside and outside the sphere, caused by the change in volume (ΔV) of the gray sphere (represented by the dashed line around the original sphere and the arrowheads). (b) If the sphere is removed from its elastic surrounding, it will expand by the amount ΔV* (dashed line around the gray sphere) due to the pore pressure increase, Δρ. (c) When outside of the elastic body, a confining stress Δ σ* needs to be applied to the gray sphere to prevent the volume change caused by the change in pore pressure.

What Causes Induced Seismicity?
Earthquakes are generated when a fault moves or slips. The key elements controlling the initiation of slip on a fault are the normal and shear stresses acting on the fault, which are affected by the pore fluid pressure (or pore pressure). The pore pressure in a rock at depth represents the pressure exerted by the naturally occurring fluids that occupy the voids, faults, and fractures in the rock mass. In principle, faults can be activated if the shear stress (τ) on a fault surpasses its shear resistance. The shear resistance is generally due to friction and is proportional to the difference between the normal stress (σ) acting on the fault, and the pressure (ρ) of the fluid in the fault and the surrounding rock.

The fault remains stable as long as the magnitude of the shear stress is smaller than the frictional strength, represented by this expression, μ(σ – ρ), where the term (σ – ρ) is the effective stress and μ is the friction coefficient. This condition for triggering slip is called the Coulomb criterion. If the pore pressure on a fault is perturbed either by pumping fluids into or withdrawing fluids from the surrounding rock, slip on the fault could occur (Figure 2). The magnitude of the pore pressure change (Δρ) is proportional to the volume of fluid injected (see also Nicholson and Wesson, 1990).

Although the conditions for initiating slip on a pre-existing fault are well understood and the state of stress and pore pressure throughout much of the Earth’s crust are often not far from the critical conditions for fault slip (Zoback and Zoback, 1980, 1989), reliable estimates of the various quantities in the Coulomb criterion are difficult to make. Similarly, the magnitude of the change in pore pressure that will cause a fault to slip cannot readily be calculated which leads to difficulty in predicting the stability of a fault system.

Scale and Scope of Induced Seismicity for Energy Technologies
Inducing a significant, felt seismic event in association with energy technology development requires (1) an increase or decrease of the pore pressure relative to the pore pressure that existed prior to fluid injection or withdrawal, and (2) a condition such that the change in pore pressure occurs over a region large enough to intersect a fault in a critical state of stress and capable of undergoing slip. The technologies associated with injection and withdrawal of fluids to generate geothermal energy, to produce oil or gas, to dispose of wastewater, and to store carbon dioxide are described briefly in terms of their potential to produce felt seismic events (see also Table 1; NRC, 2013).

Geothermal energy
Three forms of geothermal energy include vapor-dominated, liquid-dominated, and engineered geothermal systems (EGS). The majority of hydrothermal resources are liquid dominated, where primarily hot water is contained in the rock. The Geysers geothermal steam field in northern California is the only vapor-dominated field in the United States and is the most productive geothermal field in the world. EGS, which uses hot, dry rock as the resource, is developed by mechanically fracturing the hot rock and circulating fluids through the new fracture system. The fluid becomes heated and is then pumped to the surface where it can be used to generate electricity. EGS is a relatively new technology and commercial projects do not yet exist in the United States, although some are in development.

In terms of overall fluid balance, geothermal projects generally try to maintain a balance between fluid volumes extracted from the reservoir and fluids injected in order to maintain the energy production from the field. This fluid balance helps to maintain fairly constant reservoir pressure and thus reduce the potential for induced seismicity. 

Seismic monitoring at liquid-dominated geothermal fields in the western United States has demonstrated relatively few occurrences of felt induced seismicity (Table 1). In The Geysers, the large temperature difference between the injected fluid and the subsurface reservoir causes significant cooling of the hot reservoir rocks; cooling causes the rocks to contract and allows the release of local stresses resulting in some felt induced seismicity each year. Because EGS involves fracturing naturally hot dry rock, small earthquakes, generally below the level that can be felt by humans, would be expected to occur during development of EGS fields. The commercial EGS projects in existence around the world monitor this low-level seismicity and have recorded some small events that were felt by local residents.

Table 1: Summary Information about Historic Seismic Eventsa Note that that in several cases the causal relationship between the technology and the event was suspected but not confirmed. Determining whethe r a particular earthquake was caused by human activity is often very difficult. The references for the events in this table and the way in which causality may be determined are discussed in the report. Also important is the fact that the well numbers are those wells in operation today, while the numbers of seismic events that are listed refer to events that have taken place over a total period of decades. bAlthough seismic events M > 2.0 can be felt by some people in the vicinity of the event, events M ≥ 4.0 can be felt by most people and may be accompanied by more significant ground shaking, potentially causing greater public concern.

Oil and gas production
Oil and gas withdrawal. Withdrawal of oil and gas has been linked to felt seismic events at approximately 20 sites in the United States (Table 1; NRC, 2013). These extraction-related events have generally been of M < 4.0 and are rare relative to the very large number of oil and gas fields. The cause of these induced events is generally interpreted to be a net decrease in pore pressure in the reservoir over time if fluids are not re-injected to maintain original pore pressure conditions.

Waterflooding for enhanced recovery. As of early 2012, approximately 108,000 waterflooding wells were permitted in the United States. Few historical or current wells using waterflooding for enhanced oil or gas recovery in the United States have been associated with felt induced seismic events (Table 1). The relatively low number of felt events associated with these projects is attributed to the fact that operators generally do not exceed pre-production pore pressures, and attempt instead to maintain relative balance between the volumes of fluid injected and extracted from the field.

Figure 3. Schematic diagram of a horizontal wellFigure 3. Schematic diagram of a horizontal well with a 10-stage hydraulic fracture treatment. Upper right inset shows the induced fractures (yellow) created during the hydraulic fracture treatment. The well is fractured in stages from the end of the well (stage 1) to the start of the well (stage 10). The depth to the shale reservoir and the length of the horizontal well vary from area to area; approximate averages for North America are shown. The relative depths of local water wells are shown near the surface. SOURCE: Adapted after Southwestern Energy, used with permission.

Hydraulic fracturing for unconventional hydrocarbon development. Gas and oil from shale reservoirs is often extracted through the combination of horizontal drilling and hydraulic fracturing (Figure 3). Estimates suggest that well over ~35,000 wells drilled for unconventional oil and gas development existed in the United States in 2011 (EPA, 2011).2 As with EGS, low-level seismicity (M<2) is often monitored during hydraulic fracturing as a means to observe the developing fracture geometry. Felt seismicity associated with hydraulic fracturing has been rare with one established case worldwide in Blackpool, England (De Pater and Baisch, 2011) at the time of the publication of the NRC report in 2012. Other possible earthquake sequences in Oklahoma that may be associated with hydraulic fracturing have been discussed in the literature (Nicholson and Wesson, 1990, Holland, 2011, 2013; Kim, 2013). Although hydraulic fracturing does increase pore pressure above the minimum in situ stress, the volumes of fluid injected are generally low and are injected over a short time, and the area affected by the increase in pore pressure is localized, remaining in the near vicinity of the created fracture.

Wastewater Disposal Wells
To manage wastewater generated by geothermal and oil and gas production, injection wells can be drilled to dispose of the water. Tens of thousands of such wastewater disposal wells are currently active in the United States. This total does not include the many thousands of permitted wastewater disposal wells that are no longer in use. Among both currently active and legacy wells, induced seismicity has been documented at approximately 9 sites over the past several decades (Table 1; NRC, 2013). Nonetheless, a few felt events have occurred recently that generated considerable public attention. Examination of seismic activity in both the Dallas-Ft. Worth area of Texas (Frohlich et al., 2010; Frohlich, 2012) and Guy-Greenbrier area of Arkansas (Horton, 2012) has suggested causal links between the injection zones and subsurface faults.

Because most wastewater disposal wells inject fluid at relatively low pressures into large porous and permeable aquifers designed to accommodate large volumes of fluid, the pore pressure in the subsurface for most wastewater wells would not be anticipated to change significantly. However, high volumes of fluid injected over time or fluid volumes injected into an area in proximity of a pre-existing fault can lead to induced seismic events.

Carbon Capture and Storage
Capturing carbon dioxide as a gas, compressing it, and storing it deep underground as a liquid is a technology being developed to reduce carbon dioxide emissions to the atmosphere. At present, only a few small commercial projects globally have attempted to inject and store carbon dioxide for this purpose. In the United States, several pilot projects are in development. Thus, although data to evaluate the induced seismicity potential of this technology are few, carbon capture and storage differs from other energy technologies because the purpose is to inject large volumes of carbon dioxide under high pressure over a long time for permanent storage with no associated fluid withdrawal. The objective is to store the carbon dioxide forever. The large net volumes of carbon dioxide proposed to be stored with this technology may have potential for inducing felt seismic events due to increases in pore pressure over time and the potential that the total volume of the stored carbon dioxide could at some point intersect a fault in a critical state of stress. The possible effects of large-scale carbon capture storage projects require further research (Zoback and Gorelick, 2012).

Hazards and Risk Assessment
Understanding what is meant by hazard and risk related to induced seismicity is critical to any discussion of the options to mitigate the occurrence of felt events and their potential effects. The hazard of induced seismicity takes into account the earthquakes and other physical effects that could be generated by human activities associated with energy technologies involving fluid injection or withdrawal. The risk of induced seismicity considers how induced earthquakes might damage structures. If seismic events occur in areas where no structures exist, there is no risk. 

The types of information and data required to provide robust risk assessments for induced seismicity related to energy development projects include net pore pressures and stresses; information on the presence, orientation, and stresses on faults; data on background seismicity; and statistics about previous induced seismicity and volumes and pressures of fluids injected or extracted. No standard methods currently exist to implement risk assessments for induced seismicity.

Best Practices and Protocols
Quantifying hazard and risk can help establish specific “best practice” protocols for energy project development, which aim to reduce the possibility of a felt seismic event and to mitigate the effects of an event if one should occur. Induced seismicity does not fall squarely in the sole purview of any single government agency and requires cooperation among various local, state, and federal government agencies, as well as operators, researchers, and the general public. In areas that are known to have had felt induced seismicity related to fluid injection or withdrawal, a best practices protocol could be part of the approval process for any new injection permit. In areas where unanticipated felt induced seismicity occurs, existing injection permits in that area could be revised to include a best practices protocol.

Using the Department of Energy protocol for induced seismicity related to EGS (Majer et al., 2012), the report developed a set of parallel and concurrent activities to help manage and mitigate induced seismicity from injection associated with EGS. Viewing a protocol as a set of parallel activities can provide the means to reassess the protocol through time as circumstances of an energy project change and more data become available. Such a protocol might include a “traffic light” control system to respond to the occurrence of induced seismicity and could allow for low levels of seismicity but may add monitoring and mitigation requirements if seismic events increase in magnitude or frequency. A critical part of the implementation of any protocol is the clear, regular, and prompt communication with the public and the appropriate regulatory agencies regarding the purpose of the energy project, the intended operations, and the expected impacts on the local communities and facilities (NRC, 2013). The report also suggested that best practice protocols for induced seismicity be developed for each of the energy technologies analyzed in the report.

Proposed Research Needs
Research in five areas was suggested to address gaps in the present understanding of induced seismicity (NRC, 2013).

(1) Collecting field and laboratory data on active seismic events possibly caused by energy development and on specific aspects of the rock system at energy development sites (for example, on fault and fracture properties and orientations, injection rates, fluid volumes).

(2) Developing instrumentation to measure rock and fluid properties before and during energy development projects.

(3) Hazard and risk assessment for individual energy projects.

(4) Developing models, including codes that link geomechanical models with models for reservoir fluid flow and earthquake simulation.

(5) Conducting research on carbon capture and storage, incorporating data from existing sites where carbon dioxide is injected for enhanced oil recovery, and developing models to estimate the potential magnitude of seismic events induced by the large-scale injection of carbon dioxide for storage.

Summary and Major Findings
Many thousands of wells are currently permitted in the United States for developing geothermal resources, oil and gas production, and wastewater disposal; wells for pilot projects for carbon capture and storage are also being permitted. To date, a few documented incidents have occurred in which a few felt earthquakes occurred and were caused by or likely related to fluid injection or withdrawal for these technologies.

Three major findings emerged from the NRC study:
  • the process of hydraulic fracturing a well as presently implemented for shale gas recovery does not pose a high risk for inducing felt seismic events;
  • injection for disposal of waste water derived from energy technologies into the subsurface does pose some risk for induced seismicity, but very few events have been documented over the past several decades relative to the large number of disposal wells in operation; and
  • CCS, due to the large net volumes of injected fluids, may have potential for inducing larger seismic events.

Induced seismicity associated with fluid injection or withdrawal in energy projects seems to be caused in most cases by a change in pore pressure that contributes to change in stress in the subsurface in the presence of faults with specific properties and orientations and a critical state of stress. Although various factors may influence the way fluids behave in the subsurface, the factor that appears to have the most bearing with regard to inducing seismic events along pre-existing faults is the net fluid balance (total balance of fluid introduced into or removed from the subsurface). A change in the fluid balance may change the pore pressure in the vicinity of an existing fault, potentially causing that fault to slip. Energy technology projects that maintain a balance between the amount of fluid being injected and withdrawn, such as most oil and gas development projects, appear to produce fewer seismic events than projects that do not maintain fluid balance. Steps for assessing the potential for and mitigation of induced seismicity related to energy projects that include fluid injection or withdrawal will involve development of methods for quantitative hazard and risk assessment as well as best practice protocols.

References

BC Oil and Gas Commission. 2012. Investigation of observed seismicity in the Horn River Basin. Available at http://www.bcogc.ca/publications/reports.

De Pater, and De Pater, C.J., and S. Baisch. 2011. Geomechanical Study of Bowland Shale Seismicity - Synthesis Report. Prepared for Cuadrilla Resources. November 2. Available at http://www.cuadrillaresources.com/wp-content/uploads/2012/02/Geomechanical-Study-of-Bowland-Shale-Seismicity_02-11-11.pdf.

Frohlich, C., E. Potter, C. Hayward and B. Stump. 2010. Dallas-Fort Worth earthquakes coincident with activity associated with natural gas production. The Leading Edge 29(3): 270-275.

Frohlich, C. 2012. Two-year survey comparing earthquake activity and injection-well locations in the Barnett Shale, Texas. Proceedings of the National Academy of Sciences, doi: 10.1073/pnas.1207728109, August 6.

Holland, A., 2013. Earthquakes triggered by hydraulic fracturing in south-central Oklahoma. Bulletin of the Seismological Society of America 103(3): 1784-1792.

Holland, A. 2011. Examination of possibly induced seismicity from hydraulic fracturing in the Eola Field, Garvin County, Oklahoma. Oklahoma Geological Survey Open-File Report OF1-2011.

Kim, W.-Y. 2013. Induced seismicity associated with fluid injection into a deep well in Youngstown, Ohio. Journal of Geophysical Research: Solid Earth 118: 3506-3518.

Majer, E.L., J. Nelson, A. Robertson-Tait, J. Savy, and I. Wong. 2012. Protocol for Addressing Induced Seismicity Associated with Enhanced Geothermal Systems. DOE/EE-0662. U.S. Department of Energy. Available at www1.eere.energy.gov/geothermal/pdfs/geothermal_seismicity_protocol_012012.pdf.

Nicholson, C., and R.L. Wesson. 1990. Earthquake hazard associated with deep well injection: A report to the U.S. Environmental Protection Agency. U.S. Geological Survey Bulletin 1951, 74 p.

National Research Council (NRC). 2013. Induced Seismicity Potential in Energy Technologies. Washington, DC: The National Academies Press.

Rubinstein, J. L., W. L. Ellsworth, and A. McGarr. 2013. The 2001–present triggered seismicity sequence in the Raton basin of southern Colorado/Northern New Mexico,” Bulletin of the Seismological Association of America Abstracts 2013 Annual Meeting 155D.

Zoback, M.L., and S.M. Gorelick, 2012. Earthquake triggering and large-scale geologic storage of carbon dioxide. Proceedings of the National Academy of Sciences, doi: 10.1073/pnas.1202473109, June 18.

Zoback, M.L., and M.D. Zoback, 1980. State of stress in the coterminous United States. Journal of Geophysical Research 85(B11): 6113-8156.

Zoback, M.L., and M.D. Zoback, 1989. Tectonic stress field of the continental United States. Geophysical Framework of the Continental United States, eds.

Endnotes

1. Since the June 2012 release of the National Research Council report, additional work related to induced seismicity, including examination of new seismic events caused or potentially related to energy development, has been undertaken by many researchers. The present contribution is confined to the information that was contained in the NRC report. For information about more recent work related to new and recently documented events in Oklahoma, Colorado, and British Columbia, the reader is referred to some recent work by various authors: Holland (2013), BC Oil and Gas Commission (2013), Kim (2013), and Rubinstein et al. (2013).

2. Note that since the publication of the NRC report in June 2012, the count for hydraulically fractured wells in shale formations has increased substantially.

These contributions have not been peer-refereed. They represent solely the view(s) of the author(s) and not necessarily the view of APS.