Human-Induced Earthquakes from Deep-Well
Injection: A Brief Overview
Peter Folger
Specialist in Energy and Natural Resources Policy
Mary Tiemann
Specialist in Environmental Policy
January 8, 2015
Congressional Research Service
7-5700
www.crs.gov
R43836

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Human-Induced Earthquakes from Deep-Well Injection: A Brief Overview

Summary
The development of unconventional oil and natural gas resources using horizontal drilling and
hydraulic fracturing (fracking) has created new demand for wastewater disposal wells that inject
waste fluids into deep geologic strata. An increasing concern in the United States is that injection
of these fluids may be responsible for increasing rates of seismic activity. The number of
earthquakes of magnitude 3.0 or greater in the central and eastern United States has increased
dramatically since about 2009, from an average of approximately 20 per year between 1970 and
2000 to over 100 per year in the period 2010-2013. Some of these earthquakes may be felt at the
surface. For example, 20 earthquakes of magnitudes 4.0 to 4.8 have struck central Oklahoma
since 2009. The largest earthquake in Oklahoma history (magnitude 5.6) occurred on November
5, 2011, near Prague, causing damage to several structures nearby. Central and northern
Oklahoma were seismically active regions before the recent increase in the volume of waste fluid
injection through deep wells. However, the recent earthquake swarm does not seem to be due to
typical, random, changes in the rate of seismicity, according to the U.S. Geological Survey.
The relationship between earthquake activity and the timing of injection, the amount and rate of
fluid injected, and other factors are still uncertain and are current research topics. Despite
increasing evidence linking some deep-well disposal activities with human-induced earthquakes,
only a small fraction of the more than 30,000 U.S. wastewater disposal wells appears to be
associated with damaging earthquakes.
The potential for damaging earthquakes caused by hydraulic fracturing itself, as opposed to deep-
well injection of wastewater from oil and gas activities, appears to be much smaller. Hydraulic
fracturing intentionally creates fractures in rocks, and induces microseismicity, mostly of less
than magnitude 1.0, too small to feel or cause damage. In a few cases, however, fracking has led
directly to earthquakes larger than magnitude 2.0, including at sites in Oklahoma, Ohio, England,
and Canada.
The Environmental Protection Agency’s (EPA’s) Underground Injection Control (UIC) program
under the Safe Drinking Water Act (SDWA) regulates the subsurface injection of fluids to prevent
endangerment of drinking water sources. EPA has established regulations for six classes of
injection wells, including Class II wells used for the injection of fluids for enhanced oil and gas
recovery and wastewater disposal. Most oil and gas states administer the UIC Class II program.
The SDWA does not address seismicity, although EPA regulations for certain classes of injection
wells require some evaluation of seismic risk. Such requirements do not apply to Class II wells;
however, EPA has developed a framework for evaluating seismic risk when reviewing Class II
permit applications in states where EPA administers this program. How Congress shapes EPA or
other agency efforts to address and possibly mitigate human-caused earthquakes may be an issue
in the 114th Congress.
In 2011, in response to seismic events in Arkansas and Texas thought to be associated with
wastewater disposal wells, EPA authorized a national UIC technical work group to develop
recommendations to address the risk of Class II disposal-induced seismicity. EPA plans to issue a
document outlining technical recommendations and best practices in early 2015. At the state
level, several states have increased oversight of Class II wells in response to induced seismicity
concerns. In 2014, state oil and gas and groundwater protection agencies established a work
group to discuss Class II disposal wells and recent seismic events occurring in multiple states.
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Contents
Introduction ...................................................................................................................................... 1
Congressional Interest ............................................................................................................... 2
Current Scientific Understanding of Induced Seismicity in the United States ................................ 3
A Historical Example—The Rocky Mountain Arsenal ............................................................. 4
Deep-Well Injection of Oil and Natural Gas Wastewaters ........................................................ 4
Colorado and New Mexico ................................................................................................. 6
Arkansas .............................................................................................................................. 7
Texas.................................................................................................................................... 7
Ohio ..................................................................................................................................... 7
Oklahoma ............................................................................................................................ 8
Hydraulic Fracturing ................................................................................................................. 9
Canada ................................................................................................................................. 9
England ............................................................................................................................. 10
Oklahoma .......................................................................................................................... 10
Ohio ................................................................................................................................... 10
Other Issues ....................................................................................................................... 11
Overview of the Current Regulatory Structure Regarding Induced Seismicity ............................. 11
EPA Regulation of Underground Injection Activities .............................................................. 12
Consideration of Seismicity in EPA UIC Regulations ............................................................. 14
Federal Initiatives to Address Induced Seismicity .................................................................. 16
State Initiatives ........................................................................................................................ 17
Arkansas ............................................................................................................................ 18
Colorado ............................................................................................................................ 18
Ohio ................................................................................................................................... 19
Texas.................................................................................................................................. 20
Conclusion ..................................................................................................................................... 20

Figures
Figure 1. Illustration of the Possible Relationship Between Deep-Well Injection and
Induced Seismicity ....................................................................................................................... 2
Figure 2. Cumulative Number of Magnitude 3.0 or Greater Earthquakes in the Central
and Eastern United States, 1970-2013 .......................................................................................... 5
Figure 3. Oklahoma Earthquakes of M 3.0 or Greater .................................................................... 8
Figure 4. Federally Regulated Underground Injection Wells ........................................................ 13

Tables
Table 1. UIC Program: Classes of Injection Wells and Nationwide Numbers .............................. 14

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Contacts
Author Contact Information........................................................................................................... 21

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Introduction
Human-induced earthquakes, also known as induced seismicity, are an increasing concern in
regions of the United States where the produced fluids and wastewaters from oil and natural gas
activities are being injected into the subsurface through deep disposal wells. The immediate
concern is that injection of these fluids into underground formations may be responsible for
damaging earthquakes in regions that typically do not experience much seismic activity. Induced
seismicity has garnered increased attention because of the rapid development of unconventional
oil and gas resources, in part due to the use of hydraulic fracturing (often referred to as fracking).
It is important to distinguish between seismic activity possibly related to hydraulic fracturing
itself and the possibility of human-induced earthquakes related to injecting fluids down disposal
wells, which may not be located near where wells were fracked.
Human activities have long been known to have induced earthquakes in some instances:
impoundment of reservoirs, surface and underground mining, withdrawal of fluids such as oil and
gas, and injection of fluids into subsurface formations. With the increase in the use of horizontal
drilling and hydraulic fracturing to extract oil and gas from shale, and the concomitant increase in
the amount of fluids that are injected for high-volume hydraulic fracturing and for disposal, there
are several indications of a link between the injected fluids and unusual seismic activity. Figure 1
illustrates conceptually the processes of deep-well injection and the linkage to triggering
earthquakes.
The principal seismic hazard that has emerged from the increased amount of oil and gas activity
in the United States appears to be related to disposal of wastewater using deep-well injection in
some regions of the country. For example, in a May 2, 2014, joint statement between the
Oklahoma Geological Survey and the U.S. Geological Survey (USGS), researchers reported a
50% increase in the rate of earthquakes in Oklahoma since 2013.1 A USGS analysis of the rising
trend suggested that a likely contributing factor was deep-well injection of oil-and-gas-related
wastewater.2 But the relationship between earthquake activity and the timing of injection, the
amount and rate of fluid injected, and other factors are still uncertain and are current research
topics. A 2013 article that reviewed the current understanding of human-caused earthquakes noted
that, of the more than 30,000 wastewater disposal wells classified by the Environmental
Protection Agency (EPA) as Class II,3 only a small fraction appears to be associated with
damaging earthquakes.4
The potential for damaging earthquakes caused by hydraulic fracturing itself, as opposed to deep-
well injection of wastewater from fracking and other oil and natural gas production, appears to be
much smaller. The 2013 review article indicated that the vast majority of wells used for hydraulic
fracturing itself cause microearthquakes—the results of fracturing the rock to extract natural

1 U.S. Geological Survey/Oklahoma Geological Survey joint statement, “Record Number of Oklahoma Tremors Raises
Possibility of Damaging Earthquakes,” May 2, 2014, http://earthquake.usgs.gov/regional/ceus/products/
newsrelease_05022014.php.
2 Ibid.
3 EPA has established regulations for six classes of injection wells, including Class II wells used for the injection of
fluids for enhanced oil and gas recovery and wastewater disposal. See section on “EPA Regulation of Underground
Injection Activities” for more information.
4 William L. Ellsworth, “Injection-Induced Earthquakes,” Science, vol. 341, July 12, 2013, http://www.sciencemag.org/
content/341/6142/1225942.full. Hereinafter Ellsworth, 2013.
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gas—which are typically too small to be felt or cause damage at the surface. The 2013 review
documented a few cases where fracking itself caused detectable earthquakes felt at the surface,
but these were too small to cause damage.
This report reviews the current scientific understanding of induced seismicity, primarily in the
context of Class II oil and gas wastewater disposal wells. The report also outlines the regulatory
framework for these injection wells, and identifies several federal and state initiatives responding
to recent events of induced seismicity associated with Class II disposal.
Figure 1. Illustration of the Possible Relationship Between Deep-Well Injection and
Induced Seismicity

Source: North Carolina General Assembly, presentation by the Arkansas Oil and Gas Commission, Fayetteville
Shale Overview, for the North Carolina Delegation, slide 33 prepared by Southwestern Energy, November 21, 2013,
http://www.ncleg.net/documentsites/committees/BCCI-6576/2013-2014/5%20-%20Feb.%204.%202014/
Presentations%20and%20Handouts/Arkansas%20Site%20Visit%20Attachments/Att.%205%20-
%20AOGC%20Presentation%2011-21-13%20%283%29.pdf.
Notes: The figure is for illustrative purposes only, and does not depict any specific location or geological
formation.
Congressional Interest
How deep-well injection is linked to induced seismicity, and state and federal efforts to address
that linkage, are of interest to Congress because of the implications to continued development of
unconventional oil and gas resources in the United States. If the current boom in onshore oil and
gas production continues, then deep-well injection of waste fluids is likely to also continue and
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may increase in volume. Also, what Congress, the federal government, and the states do to
address and mitigate possible human-caused earthquakes from deep-well injection of oil and gas-
related fluids may provide some guidance for the injection and sequestration of carbon dioxide.
Carbon dioxide sequestration would involve ongoing, long-term, high-volume, high-pressure
injection via deep wells. Several large-scale injection experiments are currently underway;
however, the relationship between long-term and high-volume carbon dioxide injection and
induced earthquakes is not known.
Current Scientific Understanding of
Induced Seismicity in the United States
Since about the 1920s, it has been known that pumping fluids in and out of the Earth’s subsurface
has the potential to cause earthquakes.5 In addition, a wide range of other human activities have
been known to cause earthquakes, including the filling of large reservoirs, mining, geothermal
energy extraction, and others.6 The mechanics of how human industrial activities may cause
earthquakes are fairly well known: the human perturbation changes the amount of stress in the
earth’s crust, and the forces that prevent faults from slipping become unequal. Once those forces
are out of equilibrium, the fault ceases to be locked, and the fault slips, sending shock waves out
from the fault that potentially reach the surface and are strong enough to be felt or cause damage.
Even knowing that human activities can cause earthquakes, and the mechanics of the process, it is
currently nearly impossible to discriminate between man-made earthquakes and those caused by
natural tectonic forces through the use of modern seismological methods.7 Other lines of evidence
are required to positively link human activities to earthquakes. That linkage is becoming
increasingly well understood in parts of the United States where activities related to oil and gas
extraction—deep-well injection of oil and gas wastewater, and hydraulic fracturing—have
increased significantly in the last few years, particularly in Oklahoma, Texas, Arkansas, Ohio,
Colorado, and several other states.8 Nevertheless, the majority of these activities are not known to
cause earthquakes; most are termed aseismic (i.e., not causing any appreciable seismic activity, at
least for earthquakes greater than magnitude 3).9 (See text box below for a brief description of
earthquake magnitude and intensity.)
Scientists currently have limited capability to predict human-caused earthquakes for a number of
reasons, including uncertainty in knowing the state of stress in the Earth; rudimentary knowledge
of how injected fluids flow underground after injection; poor knowledge of faults that could
potentially slip and cause earthquakes; limited networks of seismometers (instruments used to
measure seismicity) in regions of the country where most oil-and-gas-related activities are
occurring; and difficulty in predicting how large an earthquake will grow once it is triggered.10

5 National Research Council, “Induced Seismicity Potential in Energy Technologies,” 2013, p. vii. Hereinafter referred
to as NRC, 2013.
6 Ellsworth, 2013.
7 Ibid.
8 According to the National Research Council report, seismic events likely related to energy development have been
documented in Alabama, Arkansas, California, Colorado, Illinois, Louisiana, Mississippi, Nebraska, Nevada, Ohio,
Oklahoma, and Texas. NRC, 2013, p. 6.
9 Ibid.
10 William Leith, Senior Science Advisor for Earthquakes and Geologic Hazards, U.S. Geological Survey, “USGS
(continued...)
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Earthquake Magnitude and Intensity11
Earthquake magnitude is a number that characterizes the relative size of an earthquake. It was historical y reported
using the Richter scale. Richter magnitude is calculated from the strongest seismic wave recorded from the
earthquake, and is based on a logarithmic (base 10) scale: for each whole number increase in the Richter scale, the
ground motion increases by 10 times. The amount of energy released per whole number increase, however, goes up
by a factor of 32. The moment magnitude (M) scale is another expression of earthquake size, or energy released during
an earthquake, that roughly corresponds to the Richter magnitude and is used by most seismologists because it more
accurately describes the size of very large earthquakes. Sometimes earthquakes will be reported using qualitative
terms, such as Great or Moderate. Generally, these terms refer to magnitudes as follows: Great (M>8); Major (M>7);
Strong (M>6); Moderate (M>5); Light (M>4); Minor (M>3); and Micro (M<3). This report uses the moment magnitude
scale, which is generally consistent with the Richter scale.12
A Historical Example—The Rocky Mountain Arsenal
Prior to the moment magnitude (M) 5.6 earthquake that occurred on November 6, 2011, in central
Oklahoma (discussed below), an M 4.8 earthquake that struck northeast Denver on August 9,
1967, was generally accepted as the largest recorded human-induced earthquake. The M 4.8
earthquake was part of a series of earthquakes that began within several months of the 1961 start
of deep-well injection of hazardous chemicals produced at the Rocky Mountain Arsenal defense
plant. The earthquakes continued after injection ceased in February 1966.13 The disposal well was
drilled through the flat-lying sedimentary rocks into the underlying older crystalline rocks more
than 12,000 feet deep, and injection rates varied from 2 million gallons per month to as much as
5.5 million gallons per month.14 Earthquake activity declined after 1967, but continued for the
next two decades. Scientists concluded that the injection triggered the earthquakes, and that even
after injection ceased, the migration of the underground pressure front continued for years and
initiated earthquakes along an ancient fault system many miles away from the injection well.15 As
discussed below, the Rocky Mountain Arsenal earthquakes had many similarities to the recent
increased earthquake activity in some deep-well injection activities of the United States,
including, for example, injection near or in underlying crystalline bedrock, activation of fault
systems miles away from the well, and migration of the pressure front away from the point of
injection months or years after injection stopped.
Deep-Well Injection of Oil and Natural Gas Wastewaters
The number of earthquakes of M >3.0 in the central and eastern United States has increased
dramatically since about 2009, from an average of approximately 20 per year between 1970 and
2000 to over 100 per year in the period 2010-2013.16 Figure 2 shows this increase in earthquake

(...continued)
Research into the Causes & Consequences of Injection-Induced Seismicity,” presentation at the U.S. Energy
Association, Oct. 30, 2014, http://www.usea.org/sites/default/files/event-/Leith%20induced%20for%20DOE-
USEA%20Oct14.pdf.
11 For a more general discussion of earthquakes, see CRS Report RL33861, Earthquakes: Risk, Detection, Warning,
and Research, by Peter Folger.
12 U.S. Geological Survey FAQs, at http://earthquake.usgs.gov/learn/faq/; and Magnitude/Intensity Comparison, at
http://earthquake.usgs.gov/learn/topics/mag_vs_int.php.
13 J. H. Healy et al., “The Denver Earthquakes,” Science, vol. 161, no. 3848 (September 27, 1968), pp. 1301-1310.
14 Healy et al., 1968.
15 Ellsworth, 2013.
16 U.S. Geological Survey, “Man-Made Earthquakes Update,” January 17, 2014, http://www.usgs.gov/blogs/features/
usgs_top_story/man-made-earthquakes/.
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frequency as a steep increase in slope of the line of cumulative number of earthquakes starting in
about 2004 but increasing sharply from about 2009, and departing from the relatively unchanging
slope of the average number of earthquakes from 1970 to 2000, depicted as a dashed line.
Figure 2. Cumulative Number of Magnitude 3.0 or Greater Earthquakes in the
Central and Eastern United States, 1970-2013

Source: U.S. Geological Survey, Earthquake Hazards Program, http://earthquake.usgs.gov/research/induced/.
Notes: The dashed line corresponds to the long-term rate of about 20 earthquakes of M 3.0 or greater per
year. A significant increase in the rate of these >M 3.0 earthquakes started around 2009.

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States experiencing higher levels of seismic activity compared to the pre-2005 average include
Arkansas, Colorado, Texas, New Mexico, Ohio, Oklahoma, and Virginia.17 For some of these
states, there is an increasing realization of a potential linkage between deep-well injection of oil
and gas wastewaters and earthquakes, as the number of wells and volume of disposed wastewater
have increased concomitant with increased domestic oil and gas production, particularly since
about 2008 and 2009.18 Several instances of suspected human-induced earthquakes that garnered
media and national attention include:
• October 2008/May 2009—M 2.5-3.3 earthquakes near Dallas-Fort Worth,
Texas;19
• August 2010/February 2011—earthquake swarm in central Arkansas, with M 4.7
earthquake on February 27, 2011, near Greenbrier, Arkansas;20
• August 2011—M 5.3 earthquake in the Raton Basin, northern New
Mexico/southern Colorado;21
• December 2011—M 3.9 earthquake near Youngstown, OH;22 and
• November 2011—M 5.6 earthquake near Prague, OK.23
These examples are summarized below.
Colorado and New Mexico
An investigation of the seismicity in the Raton Basin of northern New Mexico and southern
Colorado concluded that increased seismic activity since August 2001 was associated with deep-
well injection of wastewater related to the production of natural gas from coal-bed methane
fields.24 The study linked the increased seismicity to two high-volume disposal wells that injected
more than seven times as much fluid as the Rocky Mountain Arsenal well in the period leading up
to an August 2011 M 5.3 earthquake in the Raton Basin.

17 Ellsworth, 2013.
18 Ibid.
19 Cliff Frohlich et al., “Dallas-Fort Worth Earthquakes Coincident with Activity Associated with Natural Gas
Production,” The Leading Edge, vol. 29, no. 3 (2010), pp. 270-275.
20 U.S. Geological Survey, Earthquake Hazards Program, “Poster of the 2010-2011 Arkansas Earthquake Swarm,”
http://earthquake.usgs.gov/earthquakes/eqarchives/poster/2011/20110228.php.
21 J. L. Rubinstein, W. L. Ellsworth, and A. McGarr, “The 2001-Present Triggered Seismicity Sequence in the Raton
Basin of Southern Colorado/Northern New Mexico,” talk delivered at the Seismological Society of America Annual
Meeting, Salt Lake City, UT, April 19, 2013, pp. Abstract #13-206.
22 Won-Young Kim, “Induced Seismicity Associated With Fluid Injection Into a Deep Well in Youngstown, Ohio,”
Journal of Geophysical Research—Solid Earth, vol. 118, no. 7 (July 19, 2013), pp. 3506-3518.
23 Danielle F. Sumy et al., “Observations of Static Coulomb Stress Triggering of the November 2011 M 5.7 Oklahoma
Earthquake Sequence,” Journal of Geophysical Research—Solid Earth, vol. 119, no. 3 (March 2014),
http://onlinelibrary.wiley.com/doi/10.1002/2013JB010612/abstract.
24 Rubinstein et al., 2013.
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Arkansas
A study of a 2010-2011 earthquake swarm in central Arkansas noted that the study area
experienced an increase in the number of M 2.5 or greater earthquakes since 2009, when the first
of eight deep-well injection disposal wells became operational.25 The rate of M >2.5 earthquakes
increased from 1 in 2007 to 2 in 2008, 10 in 2009, 54 in 2010, and 157 in 2011, culminating in a
M 4.7 earthquake on February 27, 2011.26 Although the area has a history of seismic activity,
including earthquake swarms in the early 1980s, the study noted that 98% of the earthquakes
during the 2010-2011 swarm occurred within 6 kilometers of one of the waste disposal wells. In
response, the Arkansas Oil and Gas Commission (AOGC) imposed a moratorium on oil and gas
wastewater disposal wells in a 1,150 square-mile area of central Arkansas. Four disposal wells
were shut down following injection of wastewater from the Fayetteville Shale.
Texas
A study of increased seismicity near Dallas-Fort Worth and Cleburne, Texas, identified a possible
linkage between high injection rates of oilfield-related wastewater and earthquakes of M 1.5 or
greater, and found that all 24 of the most reliably located earthquake epicenters occurred within
about 1.5 miles of one or more injection wells.27 The study examined earthquakes occurring
between 2009 and 2011, and noted that it was possible that some of the earthquakes had a natural
origin, but that it was implausible that all were naturally occurring. The investigation showed a
probable linkage between earthquakes and some high-volume injection wells, but also pointed out
that in other regions of the study area there exist similar high-volume injection wells but no
increased seismic activity. The study hypothesized that injection might only trigger earthquakes if
the injected fluids reach suitably oriented nearby faults under regional tectonic stress.
Ohio
A study reported that the Youngstown, Ohio, area, where there were no known past earthquakes,
experienced over 100 small earthquakes between January 2011 and February 2012.28 The largest
among the six felt earthquakes was an M 3.9 event that occurred on December 31, 2011. The
study concluded that the earthquakes, which occurred within the Precambrian crystalline rocks
lying beneath sedimentary rocks, were induced by fluid injection from a deep injection well. The
study noted that the level of seismicity dropped after periods when the injection volumes and
pressures were at their lowest levels, indicating that the earthquakes may have been caused by
pressure buildup and then stopped when the pressure dropped.

25 S. Horton, “Disposal of Hydrofracking Waste Fluid by Injection Into Subsurface Aquifers Triggers Earthquake
Swarm in Central Arkansas with Potential for Damaging Earthquake,” Seismological Research Letters, vol. 83, no. 2
(2012), pp. 250-260.
26 U.S. Geological Survey, Earthquake Hazards Program, “Poster of the 2010-2011 Arkansas Earthquake Swarm.”
27 Cliff Frohlich, “Two-Year Survey Comparing Earthquake Activity and Injection-Well Locations in the Barnett
Shale, Texas,” Proceedings of the National Academy of Sciences, vol. 109, no. 35 (August 28, 2012), pp. 13934-13938.
28 Won-Young Kim, “Induced Seismicity Associated With Fluid Injection Into a Deep Well in Youngstown, Ohio,”
Journal of Geophysical Research—Solid Earth, vol. 118, no. 7 (July 19, 2013), pp. 3506-3518.
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Oklahoma
According to the U.S. Geological Survey and the Oklahoma Geological Survey, the rate of
earthquakes in central Oklahoma increased by 50% between October 2013 and May 2014.29 The
number of M 3.0 or greater earthquakes was 145 in the first four months of 2014, which exceeded
the previous record of 109 M 3.0 or greater earthquakes annually set in 2013, and which
continues the trend of increasing seismic activity since about 2009 (Figure 3).30
Figure 3. Oklahoma Earthquakes of M 3.0 or Greater

Source: U.S. Geological Survey, “Record Number of Oklahoma Tremors Raises Possibility of Damaging
Earthquakes,” Updated USGS-Oklahoma Geological Survey Joint Statement on Oklahoma Earthquakes, May 2,
2014, http://earthquake.usgs.gov/contactus/golden/newsrelease_05022014.php. Modified by CRS.
Notes: Figure shows that 145 earthquakes of M 3.0 or greater occurred between January 1, 2014, and May 2,
2014. From 1978 through 2008, the state averaged about two M 3.0 or greater earthquakes per year.
Since 2009, 20 earthquakes of M 4.0 to M 4.8 have struck central Oklahoma. The largest
earthquake in Oklahoma history—M 5.6—occurred on November 5, 2011, near Prague, causing
damage to several structures nearby. Central and northern Oklahoma are seismically active
regions; however, the recent earthquake swarm does not seem to be due to typical, random
changes in the rate of seismicity, according to a USGS statistical analysis.31 The statistical

29 U.S. Geological Survey, “Record Number of Oklahoma Tremors Raises Possibility of Damaging Earthquakes,” Joint
USGS-Oklahoma Geological Survey joint statement, May 2, 2014, http://earthquake.usgs.gov/regional/ceus/products/
newsrelease_05022014.php.
30 Ibid.
31 Ibid.
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analysis suggested that the increased rate of seismicity could be due to deep-well wastewater
injection, and that an M 5.0 foreshock that preceded the M 5.6 earthquake on November 5, 2011,
may have been induced by deep-well injection.32 The M 5.0 event could then have triggered the
subsequent M 5.6 event less than a day later.
The examples above indicate an increasing likelihood that in some instances, deep-well injection
is linked to earthquakes, some greater than M 5.0. A human-induced M 6.0 or greater earthquake
due to deep-well injection has not been observed, although scientists cannot rule out the
possibility that one could occur in the future. However, the great majority of deep injection wells
in the United States (UIC Class II) appear to be aseismic for earthquakes of M 3.0 or more.33
Some observers conclude that most wells permitted for deep-well injection are in geologic
formations that likely have a low risk of failure leading to damaging earthquakes, if the injected
fluids remain in the intended geologic structure.34 The largest earthquakes apparently triggered by
deep-well injection involved faulting that was deeper than the injection interval, suggesting to
some that transmitting pressure from the injection point to deeper zones in basement rocks—
below the sedimentary layers—increases the potential for triggering earthquakes.35
Hydraulic Fracturing
Hydraulic fracturing (often referred to as fracking) is the process of injecting a slurry of water,
chemicals, and sand at high pressure to fracture oil- and gas-bearing rocks in order to provide
permeable pathways to extract hydrocarbons.36 Fracking has been employed with increasing
frequency over the past decade or so to produce oil and natural gas from “unconventional”
formations (e.g., shale)—those geologic strata that contained hydrocarbons but because of natural
impermeability were not exploitable by conventional oil and gas producing methods. Fracking
intentionally propagates fractures in the rocks to improve permeability. Fracking induces
microseismicity, mostly less than M 1.0, too small to feel or cause damage. In some cases,
fracking has led to earthquakes larger than M 2.0, including at sites in Oklahoma, Ohio, England,
and Canada. Hydraulic fracturing is generally thought to present less of a risk than disposal wells
for inducing large earthquakes, because the injections are short-term and add smaller amounts of
fluid into the subsurface compared to most disposal wells.
Canada
Between April 2009 and July 2011, and over a five-day period in December 2011, nearly 40
seismic events were recorded in the Horn River Basin, northeast British Columbia, ranging from
M 2.2 to M 3.8.37 A subsequent investigation indicated that the seismic events were linked to fluid

32 Danielle F. Sumy et al., “Observations of Static Coulomb Stress Triggering of the November 2011 M 5.7 Oklahoma
Earthquake Sequence,” Journal of Geophysical Research—Solid Earth, vol. 119, no. 3 (March 2014).
33 Ellsworth, 2013.
34 Ibid.
35 Ellsworth, 2013.
36 This process has also been used for enhanced geothermal energy development, in which rocks are fractured to create
permeable pathways to circulate fluids at depth. The fluids are heated by the Earth’s natural heat, and then recirculated
to the surface to drive a turbine and generate electricity.
37 BC Oil and Gas Commission, Investigation of Observed Seismicity in the Horn River Basin, August 2012,
http://www.bcogc.ca/node/8046/download.
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injection during hydraulic fracturing activities near pre-existing faults. In contrast to the vast
majority of hydraulic fracturing injection activities, which cause earthquakes not felt at the
surface (e.g., over 8,000 fracking completions in the Horn River Basin without any associated
anomalous seismicity), these anomalous seismic events were felt at the ground surface.
England
In Blackpool, England, hydraulic fracturing injection activities led to a series of small
earthquakes ranging up to M 2.3, between March 28, 2011, and May 28, 2011.38 These seismic
events were not large enough to be felt at the surface, but were strong enough to deform some of
the well casing on the horizontal portion of the production well used for fracking the shale gas-
bearing formation.
Oklahoma
In south-central Oklahoma, hydraulic fracturing injections between January 16, 2011, and
January 22, 2011, induced a series of 116 earthquakes of M 0.6 to M 2.9, according to one
study.39 The study concluded that the lack of similar seismic activity prior to the fracking, and
after fracking ceased, among other factors, linked the fracking activities to the earthquakes. More
recently presented work on the link between hydraulic fracturing and earthquakes in Oklahoma
seems to further strengthen the association between fracking and earthquakes that may rarely
exceed M 3.0 or even M 4.0 in some cases.40 The more recent work in Oklahoma also indicated
that the vast majority of fracking operations did not create anomalous seismicity.
Ohio
Recently published research on a series of small earthquakes in Harrison County, Ohio, indicated
that hydraulic fracturing operations affected a previously unmapped fault in the Precambrian
crystalline rocks lying below the sedimentary rocks that were being hydraulically fractured.41
None of the Harrison County earthquakes exceeded magnitude 2.2, but various lines of evidence
suggested that the fault responsible for the small earthquake was triggered by hydraulic fracturing
operations. Some seismic activity possibly related to fracking in the Marcellus Shale and the
underlying Utica Shale led to changes in how Ohio permits wells.42 The permitting changes

38 Christopher A. Green, Peter Styles, and Brian J. Baptie, Preese Hall Shale Gas Fracturing, Review &
Recommendations for Induced Seismic Mitigation, April 2012, https://www.gov.uk/government/uploads/system/
uploads/attachment_data/file/15745/5075-preese-hall-shale-gas-fracturing-review.pdf.
39 Austin Holland, “Earthquakes Triggered by Hydraulic Fracturing in South-Central Oklahoma,” Bulletin of the
Seismological Society of America, vol. 103, no. 3 (June 2013), pp. 1784-1792.
40 Austin Holland, “Induced Seismicity ‘Unknown Knowns’: the Role of Stress and Other Difficult to Measure
Parameters of the Subsurface,” Presentation at the U.S. Energy Association Symposium: Subsurface Technology and
Engineering Challenges and R&D Opportunities, Washington, DC, October 30, 2014, http://www.usea.org/event/
subsurface-technology-engineering-challenges-and-rd-opportunities-stress-state-and-induced.
41 Paul A. Friberg, Glenda M. Besana-Ostman, and Ilya Dricker, “Characterization of an Earthquake Sequence
Triggered by Hydraulic Fracturing in Harrison County, Ohio,” Seismological Research Letters, vol. 85, no. 6
(November/December 2014), pp. 1-13.
42 Ohio Department of Natural Resources, Ohio Announces Tougher Permit Conditions for Drilling Activities Near
Faults and Areas of Seismic Activity, April 11, 2014, http://ohiodnr.gov/news/post/ohio-announces-tougher-permit-
conditions-for-drilling-activities-near-faults-and-areas-of-seismic-activity.
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include requirements to install seismic monitoring equipment if drilling will take place within
3 miles of a known fault, or in an area with seismic activity greater than M 2.0. Further, if the
monitors detect a seismic event greater than M 1.0, activities at the site must cease while the
cause is investigated.
Other Issues
One of the major shale gas plays in the United States, the Marcellus Shale, which underlies
western Pennsylvania, and portions of New York, West Virginia, and Ohio, occurs in a region of
relatively low levels of natural seismic activity. Despite thousands of hydraulic fracturing
operations in the past decade or so, only a handful of M 2.0 or greater earthquakes were detected
within the footprint of the Marcellus Shale, as measured by a regional seismographic network.43
The earthquake activity recorded in the Youngstown, OH, region was related to deep-well
injection of waste fluids from the development of Marcellus Shale gas, but was not associated
with hydraulic fracturing of Marcellus Shale in Pennsylvania.44
The linkage between hydraulic fracturing itself and the potential for generating earthquakes large
enough to be felt at the ground surface is an area of active research. It appears to be the case that
hydraulic fracturing operations mostly create microseismic activity—too small to be felt—
associated with fracturing the target formation to release trapped natural gas or oil. However, if
the hydraulic fracturing fluid injection affects a nearby fault, there exists the potential for larger
earthquakes possibly strong enough to be felt at the surface, as was the case in the Horn River
Basin of western Canada.
Overview of the Current Regulatory Structure
Regarding Induced Seismicity
The National Research Council (NRC) estimates that conventional oil and gas production and
hydraulic fracturing, combined, generate more than 800 billion gallons of fluid each year. More
than one-third of this volume is injected for permanent disposal in Class II injection wells.45
Deep-well injection has long been the environmentally preferred option for managing produced
brine and other wastewater associated with oil and gas production poses. However, the
development of unconventional formations using high-volume hydraulic fracturing has
contributed significantly to a growing volume of wastewater requiring disposal. Recent incidents
of seismicity in the vicinity of disposal wells have drawn renewed attention to laws, regulations,
and policies governing wastewater management and have generated various responses at the
federal and state levels. This section of the report reviews the current regulatory framework for
managing underground injection and identifies several federal and state initiatives in response to
concerns surrounding Class II disposal and induced seismicity.

43 Ellsworth, 2013.
44 Ibid.
45 National Research Council, Induced Seismicity Potential in Energy Technologies, Committee on Induced Seismicity
Potential in Energy technologies, National Academy Press, Washington, DC, 2012, p 110.
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EPA Regulation of Underground Injection Activities
The principal law authorizing federal regulation of underground injection activities is the Safe
Drinking Water Act (SDWA) of 1974, as amended.46 The law specifically directs EPA to
promulgate regulations for state underground injection control (UIC) programs to prevent
underground injection that endangers drinking water sources.47 Historically, EPA has not
regulated oil and gas production wells, and as amended in 2005, the SDWA explicitly excludes
the regulation of underground injection of fluids or propping agents (other than diesel fuels)
associated with hydraulic fracturing operations related to oil, gas, and geothermal production
activities.48
The SDWA authorizes states to assume primary enforcement authority (primacy) for the UIC
program for any or all classes of injection wells. EPA must delegate this authority, provided that
the state program meets certain statutory and EPA requirements. If a state’s UIC program plan is
not approved, or if a state chooses not to assume program responsibility, then EPA implements the
UIC program in that state.
For oil-and-gas-related injection operations (such as produced water disposal through Class II
wells), the law allows states to administer the UIC program using state rules rather than following
EPA regulatory requirements, provided a state demonstrates that it has an effective program that
prevents underground injection that endangers drinking water sources.49 Most oil and gas states
have assumed primacy for Class II wells under this provision.
Under the UIC program, EPA, states, and tribes regulate more than 800,000 injection wells. To
implement the UIC program as mandated by the SDWA, EPA has established six classes of
underground injection wells based on categories of materials injected by each class. In addition to
the similarity of fluids injected, each class shares similar construction, injection depth, design,
and operating techniques. The wells within a class are required to meet a set of appropriate
performance criteria for protecting underground sources of drinking water (USDWs).50 Figure 4
provides an illustration of the six well classes established by EPA to implement the UIC program.

46 The Safe Drinking Water Act of 1974 (P.L. 93-523) authorized the UIC program at EPA. UIC provisions are
contained in SDWA Part C, §§1421-1426; 42 U.S.C. §§300h-300h-5.
47 42 U.S.C. §300h(d). SDWA Section 1421.
48 The Energy Policy Act of 2005 (EPAct 2005; P.L. 109-58, §322) amended the definition of “underground injection,”
SDWA§1421(d), to expressly exempt hydraulically fractured oil, gas, or geothermal production wells from the UIC
program unless diesel fuels are used in the fracturing fluid.
49 SDWA Section 1425 requires a state to demonstrate that its UIC program meets the requirements of Section
1421(b)(1)(A) through (D) and represents an effective program (including adequate record keeping and reporting) to
prevent underground injection that endangers underground sources of drinking water. To receive approval under
Section 1425’s optional demonstration provisions, a state program must include permitting, inspection, monitoring, and
record-keeping and reporting requirements.
50 EPA regulations define a USDW to mean an aquifer or part of an aquifer that (a) supplies a public water system, or
contains a sufficient quantity of groundwater to supply a public water system, and currently supplies drinking water for
human consumption, or contains fewer than 10,000 milligrams per liter (mg/L or parts per million) total dissolved
solids; and (b) is not an “exempted aquifer.” 40 C.F.R. 144.3.
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Figure 4. Federally Regulated Underground Injection Wells

Source: U.S. Environmental Protection Agency, Underground Injection Control, Typical Injection Wells.
Class II includes wells used to inject fluids associated with oil and gas production. Class II wells
may be used for three broad purposes: (1) to dispose of brines (salt water) and other fluids
associated with oil and gas production; (2) to store petroleum natural gas; or (3) to inject fluids to
enhance recovery of oil and gas from conventional fields. There are roughly 180,500 Class II
wells across the United States. Based on historical averages, roughly 80% of the Class II wells are
enhanced recovery wells, and 20% are disposal wells (Class IId wells).51
Table 1 provides descriptions of the injection well classes and subcategories and estimated
numbers of wells.

51 U.S. Environmental Protection Agency, Class II Wells—Oil and Gas Related Injection Wells (Class II),
http://water.epa.gov/type/groundwater/uic/class2/index.cfm, May 9, 2012.
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Table 1. UIC Program: Classes of Injection Wells and Nationwide Numbers
Well Class
Purpose and Uses
Class I
Wel s inject hazardous wastes, industrial non-hazardous liquids, or municipal wastewater beneath
the lowermost underground source of drinking water (USDW). (680 wel s, including 117
hazardous waste wells)
Class II
Wel s inject brines and other fluids associated with oil and gas production, and hydrocarbons for
storage. The wel s inject fluids beneath the lowermost USDW. (>180,000 wel s)
Types of Class II wells:a
•
Enhanced Recovery (ER) Wells: Separate from, but often surrounded by, production
wells, these wells are used to inject produced water (brine), fresh water, steam, polymers,
or carbon dioxide (CO2) into oil-bearing formations to recover additional oil (and
sometimes gas) from production wells. These wells also may be used to maintain reservoir
pressure. Approximately 80% of Class II wells are ER wells.
•
Disposal wells: Produced water and other fluids associated with oil and gas production
(including flowback from hydraulic fracturing operations) are injected into these wells for
permanent disposal. Approximately 20% of Class II wells are disposal (Class IId) wells.
•
Hydrocarbon storage wells: More than 100 Class II wel s are used to inject hydrocarbons
(petroleum and natural gas) into underground formations for storage.
Class III
Class III wells inject fluids associated with solution mining of minerals (e.g., salt and uranium)
beneath the lowermost USDW. (22,131 wel s)
Class IV
Class IV wells inject hazardous or radioactive wastes into or above USDWs. These wells are
banned unless authorized under a federal or state groundwater remediation project. (33 wel s)
Class V
Class V includes all injection wel s not included in Classes I-IV, including experimental wells.
Class V wells often inject non-hazardous fluids into or above USDWs and are typically shallow,
on-site disposal systems (e.g., cesspools and stormwater drainage wells). Some deep Class V wells
(e.g., geothermal energy and aquifer storage wel s) inject below USDWs. (>450,000 wel s)
Class VI
Class VI, established in 2010, includes wells used for the geologic sequestration of carbon
dioxide (CO2). (2 permits approved in 2014)
Source: U.S. Environmental Protection Agency, Underground Injection Control Program, Classes of Wells, and Class II
Wells—Oil and Gas Related Injection Wells (Class II), http://water.epa.gov/type/groundwater/uic/wells.cfm, and UIC
well surveys.
Notes: Regulations for Class I (hazardous waste) and Class VI (CO2 sequestration) wells include evaluation of
seismic risk among requirements to prevent movement of fluids out of the injection zone to protect USDWs.
a. A Class II permit would be required for an oil, gas, or geothermal production well if diesel fuels were to be
used in the hydraulic fracturing fluid.
Consideration of Seismicity in EPA UIC Regulations
The SDWA does not mention seismicity; rather, the law’s UIC provisions authorize EPA to
regulate underground injection to prevent endangerment of underground sources of drinking
water. However, seismicity has the potential to affect drinking water quality through various
means (e.g., by damaging the integrity of a well, or creating new fractures and pathways for fluids
to reach groundwater). EPA UIC regulations include various requirements aimed at protecting
USDWs by ensuring that injected fluids remain in a permitted injection zone. Some of these
measures also could reduce the likelihood of triggering seismic events. For example, injection
pressures for Class II (and other) wells may not exceed a pressure that would initiate or propagate
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fractures in the confining zone adjacent to a USDW.52 As a secondary benefit, limiting injection
pressure can prevent fractures that could act as conduits through which injected fluids could reach
an existing fault.
EPA regulations for two categories of injection wells—Class I hazardous waste disposal wells,
and Class VI wells for geologic sequestration of CO2—specifically address evaluation of
seismicity risks with siting and testing requirements. For Class I wells, EPA regulations include
minimum criteria for siting hazardous waste injection wells, requiring that wells must be limited
to areas that are geologically suitable. The UIC Director (i.e., the delegated state or EPA) is
required to determine geologic suitability based upon an “analysis of the structural and
stratigraphic geology, the hydrogeology, and the seismicity of the region.”53 Testing and
monitoring requirements for Class I wells state that “the Director may require seismicity
monitoring when he has reason to believe that the injection activity may have the capacity to
cause seismic disturbances.”54
For Class VI CO2 sequestration wells, EPA regulations similarly require evaluation of seismicity
risks through siting and testing requirements. In determining whether to grant a permit, the UIC
Director must consider various factors, including potential for seismic activity.
Prior to the issuance of a permit for the construction of a new Class VI well or the conversion of
an existing Class I, Class II, or Class V well to a Class VI well, the owner or operator shall
submit, ... and the Director shall consider ... information on the seismic history including the
presence and depth of seismic sources and a determination that the seismicity would not interfere
with containment.55
EPA regulations for oil and gas wastewater disposal wells (or other Class II wells) do not include
these provisions, or otherwise address seismicity; however, the regulations give discretion to UIC
Directors to include in individual permits additional requirements as needed to protect
underground sources of drinking water.56 Again, for the purpose of protecting drinking water
sources, permits for all Class I, II, and III wells must contain specified operating conditions,
including “a maximum operating pressure calculated to avoid initiating and/or propagating
fractures that would allow fluid movement into a USDW.”57 Regulations for Class I wells further
specify that “injection pressure must be limited such that no fracturing of the injection zone
occurs during operation.”58
Outside of regulations, EPA recently has taken steps to address induced seismicity concerns
associated with Class II disposal wells. For example, EPA Region III now evaluates induced
seismicity risk factors when considering permit applications for Class II wells. (Region III

52 40 C.F.R. §146.23(a)(1).
53 40 C.F.R. §146.62(b)(1).
54 40 C.F.R. §146.68(f).
55 40 C.F.R. §146.82(a)(3)(v).
56 Relevant provisions for Class II wells are published at 40 C.F.R. §144.12(b) and 40 C.F.R. §144.52(a)(9).
57 U.S. Environmental Protection Agency, Technical Program Overview: Underground Injection Control Regulations,
EPA 816-R-02-005, Revised July 2001, p. 65, http://water.epa.gov/type/groundwater/uic/upload/
2004_5_3_uicv_techguide_uic_tech_overview_uic_regs.pdf.
58 Ibid., p. 66.
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directly implements the UIC program in Pennsylvania and Virginia.)59 In responding to public
comments on a Class II well permit application, the regional office noted the following:
Although EPA must consider appropriate geological data on the injection and confining zone
when permitting Class II wells, the SDWA regulations for Class II wells do not require specific
consideration of seismicity, unlike the SDWA regulations for Class I wells used for the injection
of hazardous waste.... Nevertheless, EPA evaluated factors relevant to seismic activity such as the
existence of any known faults and/or fractures and any history of, or potential for, seismic events
in the areas of the Injection Well as discussed below and addressed more fully in “Region 3
framework for evaluating seismic potential associated with UIC Class II permits, updated
September, 2013.”60
EPA expects that seismic activity is likely to be induced by Class II well injections only when
several conditions are present: “(1) there is a fault in a near-failure state of stress; (2) the fluid
injected has a path of communication to the fault: and (3) the pressure exerted by the fluid is high
enough and lasts long enough to cause movement along the fault line.”61
Federal Initiatives to Address Induced Seismicity
As discussed above, the Safe Drinking Water Act does not directly address seismicity; rather, the
law authorizes EPA to regulate subsurface injections to prevent endangerment of drinking water
sources. In 2011, in response to earthquake events in Arkansas and Texas, EPA asked the
Underground Injection Control National Technical Workgroup to “develop technical
recommendations to inform and enhance strategies for avoiding significant seismicity events
related to Class II disposal wells.” The workgroup specifically was asked to address concerns that
induced seismicity associated with Class II disposal wells could cause injected fluids to move
outside the containment zone and endanger drinking water sources. (EPA has not initiated any
rulemaking to address this issue.)
The UIC workgroup completed a draft report in late 2012.62 EPA plans to release the final report
in early 2015. The final report is expected to include practical tools and best practices to address
injection-induced seismicity: it will not constitute formal agency guidance. EPA requested that the
report contain the following specific elements:
• Comparison of parameters identified as most applicable to induced seismicity
with the technical parameters collected under current regulations.
• Decision-making model/conceptual flow chart to:
• provide strategies for preventing or addressing significant induced seismicity,

59 EPA also directly implements the UIC program for other oil and gas producing states, including Kentucky,
Michigan, and New York.
60 U.S. Environmental Protection Agency Region III, Response to Comments for the Issuance of an Underground
Injection Control (UIC) Permit for Windfall Oil and Gas, Inc., 2013, pp. 3-9, http://www.epa.gov/reg3wapd/pdf/
public_notices/WindfallResponsivenessSummary.pdf.
61 Ibid., p. 4.
62 U.S. Environmental Protection Agency, Minimizing and Managing Potential Impacts of Induced-Seismicity from
Class II Disposal Wells: Practical Approaches, draft report of the Underground Injection Control National Technical
Workgroup, November 27, 2012.
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• identify readily available applicable databases or other information,
• develop site characterization check list, and
• explore applicability of pressure transient testing and/or pressure monitoring
techniques.
• Summary of lessons learned from case studies.
• Recommended measurement or monitoring techniques for higher risk areas.
• Applicability of conclusions to other well classes.
• Define specific areas of research as needed.63
The Department of Energy (DOE) conducts a research program to promote development of the
nation’s geothermal resources, including development of enhanced geothermal systems (EGS).
The development of EGS can enable uneconomic hydrothermal systems to produce geothermal
energy on a large scale. However, the process of injecting fluids to enhance permeability of
hydrothermal systems may trigger a seismic event. In 2012, DOE released an Induced Seismicity
Protocol to mitigate risks associated with the development of these systems.64 Some of the
approaches and mitigation measures included in the DOE protocol may be applicable to issues
posed by Class II disposal wells.
State Initiatives
Several states and state organizations have been assessing the possible relationship between
injection wells and seismic activity. In 2013, the Ground Water Protection Council (GWPC)65
published a white paper on assessing and managing risk of induced seismicity by underground
injection.66 In March 2014, the Interstate Oil and Gas Compact Commission (IOGCC)67 and the
GWPC formed an Induced Seismicity Work Group with state regulatory agencies and geological
surveys to “proactively discuss the possible association between recent seismic events occurring
in multiple states and injection wells.”68

63 Ibid, p. A-1-2. Technical Recommendations to Address the Risk of Class II Disposal Induced Seismicity, Office of
Ground Water and Drinking Water, UIC National Technical Workgroup Project Topic #2011-3, July 2011.
64 Emie Majer, James Nelson, and Ann Roberson-Tait, et al., Protocol for Addressing Induced Seismicity Associated
with Enhanced Geothermal Systems, U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy,
DOE/EE-0662, January 2012, 45 pp., https://www1.eere.energy.gov/geothermal/pdfs/
geothermal_seismicity_protocol_012012.pdf.
65 The Ground Water Protection Council (GWPC) represents state groundwater protection and underground injection
control agencies, http://www.gwpc.org/.
66 Ground Water Protection Council, White Paper Summarizing a Special Session on Induced Seismicity, February
2013, http://www.gwpc.org/sites/default/files/events/white%20paper%20-%20final_0.pdf.
67 The Interstate Oil and Gas Compact Commission is a multi-state agency that “serves as the collective voice of
member governors on oil and gas issues and advocates states’ rights to govern petroleum resources within their
borders.” The commission works with other stakeholders and is chartered to “efficiently maximize oil and natural gas
resources through sound regulatory practices while protecting health, safety and the environment.”
http://iogcc.publishpath.com/.
68 States First Initiative, States Team Up to Assess Risk of Induced Seismicity, April 29, 2014,
http://www.statesfirstinitiative.org.
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Additionally, several states have strengthened requirements for Class II disposal wells in response
to recent seismic events that appear to be injection related. Policy and regulatory developments
adopted or under consideration by several states are outlined briefly below. Typically, these states
have expanded their standard permit application packages to include, for example, requirements
for additional existing geologic information and studies, and stricter operating requirements. Also,
some states have banned the drilling of injection wells in geologic zones of known seismic risk.
Arkansas
In response to the Guy-Greenbrier earthquake swarm associated with injections of wastewater
from shale gas production, the Arkansas Oil and Gas Commission (AOGC) in 2010 imposed a
moratorium on new disposal wells in the vicinity of the increased seismic activity, and required
operators of seven existing wells in the area to provide bi-hourly injection rates and pressures.69
In 2011, the AOGC revised rules governing Class II wells and established a permanent
moratorium zone in the area of a major fault system. The state banned new disposal wells and
required plugging of four existing wells within the zone.70 The rules also require Commission
approval and a public hearing before any Class II wells within specified distances from the
Moratorium Zone Deep Fault or a regional fault can be drilled, deepened, reentered, or
recompleted. Class II wells proposed for disposal above or below the Fayetteville Shale formation
are subject to new siting and spacing requirements, and permit applicants are required to provide
to the state information on the structural geology of an area proposed for a new disposal well. For
existing disposal wells, permit holders must install flow meters and submit injection volume and
pressure information at least daily.71
Colorado
The Colorado Oil and Gas Conservation Commission (COGCC) has identified in existing rules
and policies various requirements that reduce the likelihood of induced seismicity.72 These
safeguards, which are imposed through the permitting process, include setting limits on injection
volume and rate, and requiring that the maximum allowable injection pressure is set below the
fracturing pressure for the injection zone.73 In 2011, COGCC expanded the UIC permit review
process specifically to minimize risk of induced seismicity from oil and gas wastewater disposal.
The changes followed a significant earthquake near wells injecting wastewater produced from a
coalbed methane field. The COGCC now has the Colorado State Geologist (CGS) review permit

69 U.S. Environmental Protection Agency, Minimizing and Managing Potential Impacts of Induced-Seismicity from
Class II Disposal Wells: Practical Approaches, draft report of the Underground Injection Control National Technical
Workgroup, November 27, 2012, p. 15.
70 Specifically, the rules state: “Unless otherwise approved by the Commission after notice and a hearing, no permit to
drill, deepen, re-enter, recomplete or operate a Class II Disposal or Class II Commercial Disposal Well may be granted
for any Class II or Class II Commercial Disposal wells in any formation within [a prescribed] area (“Moratorium
Zone”). AOGC Rule H-1, Section (s)(2).”
71 Arkansas Oil and Gas Commission: General Rule H – Class II Wells, Rule H-1: Class II Disposal and Class II
Commercial Disposal Well Permit Application Procedures, Section (s).
72 The Colorado Oil and Gas Conservation Commission (COGCC) administers the UIC program in accordance with
EPA regulations. 40 C.F.R. §§144-147.
73 Colorado Oil and Gas Conservation Commission, COGCC Underground Injection Control and Seismicity in
Colorado, January 19, 2011.
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applications to evaluate the area for the proposed well site for seismic activity. The CGS reviews
state geologic maps, the USGS earthquake database, and area-specific information. After
reviewing the geologic history and maps of the area for faults, the CGS may recommend a more
detailed review of subsurface geology or seismic monitoring prior to new drilling. Additionally,
the Division of Water Resources conducts a review of the proposed injection zone.74
In July 2014, the COGGC reported that the commission is working with the Colorado Geological
Survey, USGS researchers, and state universities to establish an induced seismicity advisory
group. Issues for consideration by the advisory group include development of a more
comprehensive statewide seismicity monitoring network and improved guidance for managing
high volume injection.
Ohio
Following the Youngstown earthquakes in 2011 associated with Class II disposal wells, the Ohio
Department of Natural Resources (ODNR) prohibited all drilling into the Precambrian basement
rock and added new permit requirements for Class II disposal wells to improve site assessment
and collection of more comprehensive information. The rules became effective in October 2012,
and are implemented on a well-by-well basis through the permitting process. The supplemental
permit application requirements could include pressure fall-off testing, geological evaluation of
potential faulting, seismic monitoring program (baseline and active injection), minimum
geophysical logging suite, radioactive tracer or spinner survey, and any other tests deemed
necessary by the Division of Oil and Gas Resources Management.75 Before approving a new
Class II disposal well, state officials now review existing geologic data for known faulted areas.
ODNR will also require companies to run a complete suite of geophysical logs on newly drilled
Class II disposal wells. Companies are required to give ODNR a copy of the log suite and where
required, provide analytical interpretation of the logging. For all new Class II permit applications,
ODNR requires installation of monitoring technologies, including a continuous pressure
monitoring system and an automatic shutoff system.76
In 2014, ODNR drafted new rules for construction of horizontal production wells that are to be
hydraulically fractured (i.e., shale oil and gas wells) in response to seismic activity the state
determined had a “probable connection to hydraulic fracturing near a previously unknown
microfault.”77 The draft rules include standards for design, approval, and construction of
horizontal well sites, and would strengthen drilling permit conditions for wells located near faults
or areas linked to previous seismic activity.78

74 Colorado Department of Natural Resources, “COGCC Underground Injection Control and Seismicity in Colorado,”
Colorado Oil and Gas Conservation Commission, January 19, 2011.
75 http://www.aipg.org/Seminars/HFMS14/presentations/Dick_Jeffrey.pdf.
76 https://oilandgas.ohiodnr.gov/portals/oilgas/pdf/YoungstownFAQ.pdf.
77 Ohio Department of Natural Resources, “Ohio Announces Tougher Permit Conditions for Drilling Activities Near
Faults and Areas of Seismic Activity,” press release, April 11, 2014, http://ohiodnr.gov/news/post/ohio-announces-
tougher-permit-conditions-for-drilling-activities-near-faults-and-areas-of-seismic-activity.
78 Ohio Department of Natural Resources, Division of Oil and Gas Resources Management, Draft Rules and Review
(Ch. 1501:9-2-02 OAC), http://oilandgas.ohiodnr.gov/.
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Texas
In November 2014, the Texas Railroad Commission (RRC) published amendments to the state’s
oil and gas rules to incorporate requirements related to seismic events in connection with
wastewater disposal permits, monitoring, and reporting.79 Several of the new requirements are
listed below.80
• Applicants for disposal well permits are required to provide information from the
USGS regarding the locations of any historical seismic events within 100 square
miles of the proposed well site.
• A permit for a Class II disposal well “may be modified, suspended, or terminated
if injection is likely to be or determined to be contributing to seismic activity.”81
• The RRC may require permit applicants to provide additional information (e.g.,
logs, geologic cross-sections, and pressure front boundary calculations) if the
well is to be located in an area where conditions may increase the risk that fluids
will not be confined in the injection interval. (Such conditions may include
complex geology, proximity of the basement rock to the injection interval,
transmissive faults, and/or a history of seismic events using available USGS
information.)
• Operators may be required to conduct more frequent monitoring and reporting of
disposal well injection pressures and rates if certain conditions are present that
could increase the risk that fluids will not be confined to the injection interval.
Although states have taken various actions in response to recent seismic events and wastewater
injection, additional regulatory actions could result from the IOGCC and GWPC Induced
Seismicity Work Group as state regulatory agencies and geological surveys continue to evaluate
this issue.
Conclusion
The scientific understanding of linkages between deep-well injection of waste fluids from oil and
gas production, and from hydraulic fracturing operations, is rapidly evolving. This poses a
challenge to state and federal policy makers who are tasked with making policy, regulatory, and
permitting decisions in a relatively short time frame, concomitant with the evolving scientific
study and understanding, and given public concern over the possibility of damaging earthquakes
from some of the deep disposal wells. Some states have already implemented changes to their
regulatory and permitting requirements, as discussed above. The vast majority of deep-well
injection wells and hydraulic fracturing wells do not appear to be associated with significant
seismic events. Additional geologic studies and reviews adopted by some states should address
some potential risks; however, it is likely that states and possibly the federal government will

79 Railroad Commission of Texas, Ch. 3. Oil and Gas Division, 39 TexRegN8988, November 14, 2014, Texas Register,
amending 16 T.A.C. §3.9, §3.46, http://www.sos.state.tx.us/texreg/pdf/backview/1114/1114adop.pdf.
80 39 TexReg 8996-9005, 16 T.A.C. §3.9.
81 16 T.A.C. §3.9(6)(A)(vi).
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Human-Induced Earthquakes from Deep-Well Injection: A Brief Overview

continue to explore ways to understand and mitigate against the possibility of damaging
earthquakes caused by a small number of wells.
In early 2015, EPA plans to publish a report outlining best practices to address seismic events
associated with oil and gas wastewater injection. Congress may be interested in oversight of
EPA’s UIC program and, more broadly, in federally sponsored research on the relationship
between energy development activities and induced seismicity
Only a small fraction of the more than 30,000 U.S. wastewater disposal wells appears to be
problematic for causing damaging earthquakes. However, such incidents may raise questions as
to whether other energy-related activity—specifically, underground injection for carbon dioxide
sequestration—may present similar risks.

Author Contact Information

Peter Folger
Mary Tiemann
Specialist in Energy and Natural Resources Policy
Specialist in Environmental Policy
pfolger@crs.loc.gov, 7-1517
mtiemann@crs.loc.gov, 7-5937


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