Induced Seismicity, Injection Disposal, and Hydraulic Fracturing1
Keith B. Hall
1 East Campus Drive
Baton Rouge, Louisiana 70803
(225) 578-8709 office
(504) 250-2636 cell
keith.hall@law.lsu.edu
I.
Introduction
“Induced seismicity” refers to earthquakes that are triggered by human activity. 2 The subject
has received attention from scientists and engineers for several decades, but the subject began
receiving much more attention in recent years. Events in Oklahoma are one of the reasons.
From 1978 through 2008, Oklahoma averaged 1.6 earthquakes per year with a magnitude of
3.0 or greater. In 2009, however, Oklahoma had 20 earthquakes of such magnitude. In 2013, it had
109. In 2014, it had 584.3 Further, through the first few months of 2015, Oklahoma was on track to
have 941 earthquakes with a magnitude of 3.0 or greater in 2015. Thus, the average number of
magnitude 3.0 or higher earthquakes in Oklahoma increased from fewer than two per year to more
than two per day. Geologists believe that the increase is the result of induced seismicity. Arkansas,
Colorado, Kansas, New Mexico, Ohio, and Texas have also experienced recent seismic events that
may have been induced.
Scientists have identified a variety of human activities that seem to occasionally induce seismic
events, but most of the recent, apparent increase in induced seismicity has been tentatively linked to
certain oil and gas activities – primarily injection disposal of oil and gas production wastes, but
occasionally hydraulic fracturing.
This paper addresses several questions. What is the mechanism by which scientists believe
injection disposal can trigger earthquakes? Does hydraulic fracturing play a role in the recent increase
in seismicity? What are the legal issues associated with induced seismicity?
II.
Induced Seismicity
A. Background
Scientists have long recognized that human activities have the potential to induce seismic
activity.4 As early as the 1920s, they recognized that pumping fluids underground had the potential to
1
This paper is based in part on Induced Seismicity: An Energy Lawyer’s Guide to Legal Issues and the Causes of ManMade Earthquakes, which was presented by the author at the 61st Annual Rocky Mountain Mineral Law Institute in
Anchorage, Alaska on July 16, 2015.
2
The terms “induced seismicity” and “triggered seismicity” are often used interchangeably by seismologists. Other
seismologists use slightly different definitions for the two terms. See, e.g., E. Majer, et al., Protocol for Addressing
Induced Seismicity Associated with Enhanced Geothermal Systems, DOE/EE-0662 at pp. 3, 41, 42 (Jan. 2012) (report for
U.S. Department of Energy).
3
U.S. Geological Survey (hereinafter “USGS”), Graph of the Number of Oklahoma Earthquakes, 1978 to Present,
available at http://earthquake.usgs.gov/earthquakes/states/oklahoma/images/OklahomaEQsBarGraph.png; cf. Oklahoma
Geological Survey, Oklahoma Earthquake Summary Report, Report OF1-2015 at p. 13.
4
National Academy of Sciences (hereinafter, “NAS”), INDUCED SEISMICITY POTENTIAL IN ENERGY
TECHNOLOGIES (2013) at vii.
1
induce earthquakes.5 Over time, scientists have concluded that seismicity can be induced by a variety
of human activities, including mining, the impoundment of water behind dams, the construction of
skyscrapers, fluid withdrawals from the subsurface, fluid injections into the subsurface, and
underground explosions.6
Although a great majority of fluid injection operations do not induce seismicity, there is a clear
consensus amongst scientists that fluid injections occasionally induce seismicity. 7 One of the most
famous examples of induced seismicity occurred near Denver, where injections into a disposal well at
the U.S. military’s Rocky Mountain Arsenal are believed to be responsible for a series of earthquakes
in the 1960s. A scientific paper analyzing those earthquakes contained an illustration that
demonstrated a pronounced correlation between injection rates and the frequency of nearby seismic
events.8 The military eventually halted injections at the site.9
Figure 1: Comparison of injection rates at Rocky Mountain Arsenal and the monthly number of seismic events in the nearby area.
5
Id.
U.S. Environmental Protection Agency, “Minimizing and Managing Potential Impacts of Injection-Induced Seismicity
from Class II Disposal Wells: Practical Approaches” at 7 (draft dated Dec. 24, 2013) at 1; NAS, supra note 2 at 23, 24.
7
Craig Nicholson and Robert L. Wesson, Earthquake Hazard Associated With Deep Well Injection – A Report to the U.S.
Environmental Protection Agency, at VII, USGS Bulletin 1951 (1990) at p. 3.
8
Dale M. Evans, The Denver Area Earthquakes and the Rocky Mountain Arsenal Disposal Well, 3 The Mountain Geologist
23, 27 (1966), available at http://archives.datapages.com/data/rmag/mg/1966/evans.pdf.
9
NAS, supra n. 2 at 28.
6
2
Another famous example of suspected induced seismicity occurred near Rangely, Colorado,
where a company was injecting water as part of a water flood operation for enhanced oil recovery.
After suspicions arose that seismic events in the area might be linked to the water flood operation,
scientists with the USGS persuaded the company to conduct an experiment in which injection rates
were raised and lowered. Scientists monitoring the experiment concluded that their data showed a
correlation between the injection rates and the frequency of seismic activity.10
Figure 2: Comparison of injection pressures and rates of seismic activity in Rangely Field.
The subject of induced seismicity has attracted attention in recent years because of an increase
in seismicity that many people believe has been caused by oil and gas activity.11 The most dramatic
increase has been in Oklahoma, where the average frequency of seismic events with a magnitude 3.0 or
greater increased from fewer than two per year from 1978 through 2008 to more than two per day
10
C.B. Raleigh, et al., An Experiment in Earthquake Control at Rangely, Colorado, 191 Science 1230, 1230 (1976),
available at http://earthquake.usgs.gov/research/induced/pdf/Raleigh-Healy-Bredehoeft-1976-Science-(New-York-NY).pdf.
11
Mark D. Zoback, Managing the Risk Posed by Wastewater Disposal, Earth, 38, 38-9 (Apr. 2012); NAS, supra note 2 at
1.
3
during the first few months of 2015.12 The Oklahoma Geological Survey and U.S. Geological Survey
have each concluded that injection disposal operations are likely the cause of the dramatic increase. 13
Kansas has also seen a significant increase in seismicity. For decades, Kansas had an average
of one recorded earthquake per year.14 In 2014, the state’s geologists recorded 127.15 As of March
2015, Kansas was on track for 248 recorded earthquakes in 2015.16 The Kansas Corporation
Commission, which regulates injection disposal wells in the state, has noted that the counties that have
experienced the majority of the seismic events are counties in which injection disposal volumes have
increased.17
A few other states have also seen notable examples of suspected induced seismicity. For
example, there was a series of earthquakes near Guy, Arkansas that state regulators suspect was
induced by the operation of injection disposal wells.18 Texas also has experienced numerous
earthquakes that are suspected of having been induced by injection disposal wells, including
earthquakes in the Dallas-Fort Worth area.19 Ohio experienced earthquakes near Youngstown in 2011
that are believed to have been induced by injection disposal operations,20 and also experienced seismic
activity near Poland Township in 2014 that may have been induced by hydraulic fracturing.21
Colorado and New Mexico also have experienced earthquakes that are believed to have been induced.
And, in recent years, the United Kingdom,22 as well as the Canadian provinces of Alberta23 and British
Columbia,24 has experienced seismic events that are believed to have been triggered by oil and gas
activities.
12
U.S. Geological Survey (hereinafter “USGS”), Graph of the Number of Oklahoma Earthquakes, 1978 to Present,
available at http://earthquake.usgs.gov/earthquakes/states/oklahoma/images/OklahomaEQsBarGraph.png.
13
USGS and Oklahoma Geological Survey (joint statement), Record Number of Oklahoma Tremors Raises Possibility of
Damaging Earthquakes, available at http://www.okgeosurvey1.gov/media/press/Full_USGSOGS_Statment_05022014.pdf.
14
Kansas Corporation Commission, In the Matter of an Order Reducing Injection Rates into the Arbuckle Formation,
Conservation Division Docket No. 15-CONS-770-CMSC, “Findings of Fact,” para. 4 (03/19/2015), available at
http://estar.kcc.ks.gov/estar/ViewFile.aspx/15-770%20Order.pdf?Id=05630050-78a3-4800-a08b-85202375305a.
15
Id.
16
Id.
17
Id.
18
Arkansas Oil & Gas Commission, “Class II Commercial Disposal Well or Class II Disposal Well Moratorium,” Order
No. 602A-2010-12 (02/08/2011), available at http://www.aogc2.state.ar.us /Hearing%20Orders/2011/Jan/602A-201012.pdf).
19
Matthew J. Hornbach, et al., Causal Factors for Seismicity Near Azle, Texas, Nature Communications (04/21/2015).
20
Ohio Dept. Natural Resources, Preliminary Report on the Northstar 1 Class II Injection Well and the Seismic Events in
the Youngstown, Ohio, Area (March 2012), available at
http://oilandgas.ohiodnr.gov/portals/oilgas/downloads/northstar/reports/northstar-preliminary_report.pdf
21
Robert J. Skoumal, et al., Earthquakes Induced by Hydraulic Fracturing in Poland Township, Ohio Bulletin of the
Seismological Society of America (01/06/2015).
22
C.J. de Pater and S. Baisch, Geomechanical Study of Bowland Shale Seismicity (02/11/2011) at p. 2 of Executive
Summary, available at http://www.cuadrillaresources.com/wp-content/uploads/2012/02/Executive-SummaryGeomechanical-Study-02-11-11.pdf.
23
Alberta Energy Regulator, “AER Bulletin 2015-03,” available at https://www.aer.ca/documents/bulletins/AER-Bulletin2015-03.pdf.
24
B.C. Oil & Gas Commission, “Investigation of Observed Seismicity in the Horn River Basin” (Aug. 2012), available at
https://www.bcogc.ca/node/8046/download.
4
B. How do Human Activities Trigger Earthquakes?
A geologic fault is a fracture in the earth’s subsurface.25 The vast majority of time, the blocks
of earth on opposite sides of a fault do not move relative to one another. The blocks are almost always
pushed by “shear stresses” that could cause the blocks to slide against each other, but the blocks
remain stable because other forces resist movement. Typically, the main force that resists movement is
friction. If, however, shear stresses grow large enough to exceed friction, the blocks can suddenly slip.
An earthquake is a shaking of the ground that is caused by such a sudden slip of a portion of the earth’s
crust at the location of a fault.26
Even when a fault is stable, it may be critically stressed. This means that shear forces are
nearly sufficient to overcome friction and thereby cause slippage at the fault.27 Scientists have
suggested various mechanisms by which human activities can trigger seismic events at critically
stressed faults.28 The two main mechanisms are: (1) increasing pore pressures within subsurface
formations, which has the effect of decreasing friction; and (2) altering the subsurface stresses.
When subsurface injections induce seismicity, the main mechanism responsible for induced
seismicity is an increase in pore pressure within the subsurface formation. The reason that an increase
in pore pressure reduces friction at a fault is a function of the factors that control the amount of friction
created when two surfaces slide along one another. One factor is the amount of force that is pushing
the two surfaces together. A larger force pushing two surfaces together results in more friction. For
example, if you place an empty cardboard box on a hardwood floor, gravity will push the bottom of the
box against the floor. If you push the empty box across the floor, there will be some frictional
resistance, but not very much. If you fill the box with books, gravity will push the book-filled box
against the floor with greater force than when the box was empty. And, if you attempt to slide the
book-filled box across the floor, friction will be greater than before.
When the pressure in the pore spaces along a fault increases, that increased pressure partly
counteracts whatever force is pushing the rocks on opposite sides of the fault together. This reduces
friction in the same way that you could reduce the friction between a cardboard box and a hardwood
floor by removing books from the box. An air hockey table provides an alternative analogy. If the
table’s air jets are turned off and you push the plastic puck, it will move only a short distance because
of friction resistance between the puck and the table. But when the jets are turned on, the upward flow
of air partially counteracts the gravitational forces that push the puck down against the table. The
result is a reduction in friction. And, if you push the puck after the air jets are turned on, the puck will
move further than it did before. In a similar manner, an increase in pore pressure reduces friction,
making it more likely that existing subsurface stresses will cause movement at a fault.
The other main mechanism by which human activities can induce seismicity is by altering
subsurface stresses. Human activities can do this by adding weight (such as when water is impounded
behind dams), by withdrawing fluids, or by cooling hot subsurface rocks by injecting water for
recovery of geothermal energy (thereby causing thermal contraction). The magnitude of the change in
stress caused by the human activity may not be large compared to the existing stresses, but if the fault
is critically stressed a small change can sometimes induce seismicity.
25
USGS Earthquake Glossary, available at http://earthquake.usgs.gov/learn/glossary/?term=fault.
Id. at http://earthquake.usgs.gov/learn/glossary/?term=earthquake.
27
NAS, supra n. 2 at 39.
26
28
Ernest L. Majer, et al., Induced Seismicity associated with Enhanced Geothermal Systems, 36 Geothermics
189-90 (2007).
5
III.
Evaluating Whether an Activity is Likely to Induce Seismicity
The likelihood that fluid injections will induce seismicity depends on several factors. Some of
the factors relate to local geology. For example, one relevant factor is the orientation of pre-existing
stress fields relative to the orientation of faults. In order for an injection to induce an earthquake, a
significant component of the pre-existing subsurface stresses probably needs to be pushing parallel to
the direction of a fault (as opposed to perpendicular to it), so that the stresses tends to cause rocks on
either side of the fault to slide along one another (instead of the forces simply pushing push the rocks
into one another). Further, the fault probably needs to be critically stressed, meaning that the preexisting subsurface stresses are nearly sufficient to cause slippage even before the injection occurs.29
Other factors that influence the risk that an injection will induce seismicity relate to injection
rates and the length of time during which injections occur. These factors are relevant because they
influence the amount by which pore pressures will increase and the distance that a “plume” of higher
pressure will spread.30 Finally, in order for an injection to induce seismicity, the injection must be
sufficiently close to the critically-stressed fault (or to a fracture that can serve as a pathway to the
critically stressed fault) for the increases in pore pressure caused by the injection to reach the fault.31
Ultimately, it is impossible to predict definitively whether a particular activity will induce
seismicity,32 but the authors of one scientific paper proposed a ten-factor test to evaluate whether a
proposed injection operation is likely to induce future seismicity.33 The ten factors relate to
background seismicity in the area proposed for the injection operation, the location of faults,
subsurface stresses in the area, and proposed injection practices.34
IV.
Scientists’ Recommendations for Mitigation of Induced Seismicity Risks
Scientists make two basic types of recommendations for mitigating the risk of induced
seismicity.35 The first type relates to the choice of location and formation for the injection disposal.
Given that the dominant method by which injections can induce seismicity is by causing an increase in
pore pressures along critically stressed faults, companies should avoid injecting into such faults.36
To minimize the likelihood of injecting into a critically stressed fault unknowingly, a company
planning a major, new injection disposal operation should evaluate the local geology before beginning
the operation. For example, because past seismicity may indicate the presence of a critically stressed
fault, the company should consider checking whether the area has experienced significant seismicity in
the past. In addition, to minimize increases in pore pressures, the company should attempt to select an
injection zone that is located in a formation with high permeability.
Further, if there is a critically stressed fault in the vicinity, the company should evaluate
whether the planned injection activity could potentially de-stabilize the fault. The evaluation might
include an effort to determine whether there is a potential pathway that would allow the increased pore
29
Majer, supra note 26 at 188; NAS, supra n. 2 at 37, 44-5.
Majer, supra note 26 at 188; NAS, supra n. 2 at 37, 44-5.
31
Majer, supra note 26 at 188; NAS, supra n. 2 at 37, 44-5.
32
NAS, supra note 2 at 1-2; Scott D. Davis and Cliff Frohlich, Did (Or Will) Fluid Injection Cause Earthquakes? –
Criteria for a Rational Assessment, 64 Seismological Research Letters 207, 208 (July-Dec. 1993).
30
33
Davis, supra n. 30 at 211.
Id.
35
NAS, supra n. 2 at 151-64; EPA, supra n.4 at 26-30.
36
Zoback, supra note 9 at 40-1.
34
6
pressures caused by injections to reach the critically stressed fault. If so, the company should choose a
different location for its injection well or take other steps to limit risk, such as restricting injection rates
or pressures. It is important to realize, however, that evaluating whether there are critically stressed
faults sometimes will be difficult because not all faults are mapped and often scientists have relatively
little information about subsurface stresses.
The second recommendation applies once a person has begun injection operations. This
recommendation is to use a so-called “traffic light system.”37 A person using a traffic light system
monitors injection rates and pressures, and perhaps more important, he monitors the surrounding area
for seismic activity. If he does not detect any seismic activity, or he detects only low magnitude
seismic events, he has a “green light” to continue his injection operations as normal.
But if he detects seismic events above a certain magnitude, he gets a “yellow light.” He may
continue operations, but he must take precautions that include some combination of reduced injection
rates, reduced pressures, and increased monitoring for seismicity.
Finally, if he detects seismic events above some higher magnitude than that which triggers a
yellow light (or perhaps if he detects multiple events that individually would trigger only a yellow
light), he gets a “red light” and must cease operations. The cessation might be permanent or for a
specified time or for an indefinite time, such as until subsurface pressures reduce below a certain level
or until a regulator or someone else evaluates whether the observed seismicity was related to injection
operations and whether it is safe to resume injections at the original or some lower rate.
The use of a traffic light system may have originated with a geothermal project in El Salvador38
(geothermal projects often induce seismic events), and the potential utility of such a system is now
well-accepted for geothermal energy projects. For example, the International Energy Agency has
recommended protocols for reducing the risk of induced seismicity associated with geothermal
operations, and one of those protocols is a traffic light system. 39 Further, the U.S. Department of
Energy states that a “’traffic light’ system may be appropriate for many [enhanced geothermal system]
operations.”40 Some scientists have suggested that the traffic light system designed for geothermal
projects be adopted for use in managing risks associated with induced seismicity from injection
disposal operations.
V.
How Often Do Fluid Injections or Withdrawals Induce Seismicity?
Of the millions of earthquakes that occur each year, the vast majority have natural causes.41
Nevertheless, there is a consensus amongst scientists that human activities sometimes cause seismic
events. The estimated frequency at which various fluid injections or withdrawal activities related to
the oil and gas activities induce seismicity is discussed below.42
37
Id. at 42-3; NAS, supra note 2 at 157-8.
38
Julian J. Bommer, et al., Control of hazard due to seismicity induced by a hot fractured rock geothermal project, 83
Engineering Geology 287, 291 (2006).
39
E. Majer, et al., Protocol for Induced Seismicity Associated with Enhanced Geothermal Systems, (2008) at p. 5.
U.S. Dept. Energy, Protocol for Addressing Induced Seismicity Associated with Enhanced Geothermal Systems (Jan.
2012) at p. 23.
41
Id. at 5.
42
Induced seismicity has been associated with fluid injections that are not related to oil and gas activity. For example,
hundreds of seismic events per year are believed to be produced by geothermal energy projects in the United States.
40
7
A. Fluid Withdrawals
There have been a handful of seismic events that scientists believe were caused by the
withdrawal of fluids associated with oil and gas production, but such examples are fairly uncommon.
A National Academy of Sciences report estimated that seismic events have been induced by the fluid
withdrawals associated with oil and gas production at about 20 locations in the U.S.43 This is a
relatively small number given the huge number of oil and gas wells that have been drilled in the United
States.
B. Secondary Recovery
There also are suspected examples of induced seismicity associated with secondary recovery,
but there are relatively few such examples relative to the more than 100,000 wells that have been
permitted for use as injection wells for secondary recovery. A National Academy of Sciences report
concluded that felt seismic events have been induced at about 18 sites in the United States. 44 The
likely reason that injection wells used in secondary recovery projects rarely induce seismicity is that,
during secondary recovery operations, fluids are being injected into and withdrawn from a formation
simultaneously and at approximately the same rate. Thus, the increase in formation pressure is not
very large.
C. Injection Disposal
A variety of industries dispose of fluid wastes by injection into subsurface formations deep
underground that are not useful for any other purposes. These formations typically are far deeper than
formations that contain underground sources of drinking water. The deep formations that are used for
injection disposal often naturally contain water that is extremely salty and which sometimes contains
naturally occurring radioactive materials.
Approximately 30 to 35,000 injection wells in the U.S. are permitted for the disposal of
wastewater generated by oil and gas activities.45 Only a “very small fraction” are suspected of having
induced seismicity.46 Indeed, a report published by the National Academy of Sciences in 2012
estimated that only about nine such wells had been linked to induced seismic events.47 Events during
the past few years likely have increased that number, but even now only a small fraction of injection
wells are suspected of having induced seismic activity. In the last few years, although the number of
injection disposal wells suspected of inducing seismic activity is small, those wells are believed to
have induced a large number of seismic events. Indeed, there have been hundreds of seismic events in
the U.S. in recent years that many geologists suspect were induced by injection disposal, though many
of those events were not strong enough to be felt. The states that have experienced such events include
Oklahoma, Kansas, Arkansas, Texas, Colorado, New Mexico, and Ohio.
D. Hydraulic Fracturing
Notwithstanding some mainstream media headlines, scientists agree that hydraulic fracturing
plays little role in the recent increase in seismicity. Many scientists believe the recent increase is the
result of induced seismicity, rather than being a natural fluctuation in seismic rates, but they uniformly
43
NAS, supra n. 2 at 11.
NAS, supra. n. 2 at 10.
45
Id. at 11; EPA, supra n. 4 at 1.
46
NAS, supra n. 2 at 1, 2.
47
Id. at 11.
44
8
believe that injection disposal is responsible and that hydraulic fracturing is not. The more careful
media sources correctly describe injection disposal, rather than hydraulic fracturing, as being the type
of operation that many scientists believe is responsible for the recent increase in seismic activity, but
even many of the more careful media sources erroneously suggest that the injection disposal wells at
issue are primarily used for disposal of hydraulic fracturing flowback water. Actually, in Oklahoma
(and for the U.S. as a whole), wastewater from hydraulic fracturing operations is a small portion –
significantly under ten percent – of the total volume of water injected into such wells.
The vast majority of the fluid injected into such wells is produced water – water that is
naturally found in many of the formations that contain oil and gas. Whenever a well drilled to such a
formation, the well produces a mixture of oil (or gas) and water, even if the well is not one that has
been hydraulically fractured.48 The water-to-oil and water-to-gas production ratios vary considerably
from one formation to another, but the average water-to-oil ratio nationwide is somewhere in the 7 to
10 range – that is, on average, an oil well may produce 7 to 10 barrels of water for each barrel of oil.49
The average natural gas well produces 97 barrels of water for every million standard cubic feet of
natural gas. Both produced water and hydraulic fracturing wastewater are often sent to the injection
disposal wells used by the oil and gas industry, but the nationwide volume of produce water dwarfs the
nationwide volume of hydraulic fracturing wastewater.50
Thus, neither hydraulic fracturing itself nor the disposal of hydraulic fracturing wastewater
plays a major role in the recent increase in seismicity. Nevertheless, scientists believe that hydraulic
fracturing can induce seismicity, though only in unusual circumstances.51 It is commonly estimated
that more than one million wells have been hydraulically fractured, 52 but there are only about six or so
locations worldwide where evidence suggests that hydraulic fracturing may have induced seismicity.
These include locations in Oklahoma, Ohio, the United Kingdom, and three areas of Canada – one in
Alberta and two in British Columbia. Scientists have suggested that the reason hydraulic fracturing so
seldom triggers seismicity is that hydraulic fracturing operations last only a matter of hours and affect
a smaller volume of rock than do injection disposal operations, which can go on for years and inject
much higher volumes of fluids.53
Readers should note that the count of approximately six locations does not take microseismic
events into account. By definition, hydraulic fracturing involves fracturing of rocks, and such
fracturing generates microseismic events. But such events are not what people typically refer to as
“earthquakes,” even when they are considering earthquakes that are too small in magnitude to be felt.
The microseismicity associated with fracturing typically involves events with magnitudes in the range
of ML -4 to 0, meaning between zero and negative four on the Richter Scale.54 An event in the middle
48
USGS, 6 Facts About Human-Caused Earthquakes, available at http://www.usgs.gov/blogs/features/usgs_top_story/6facts-about-human-caused-earthquakes/.
49
John Veil, U.S. Produced Water Volumes and Management Practices in 2012, available at
http://www.gwpc.org/sites/default/files/Produced%20Water%20Report%202014-GWPC_0.pdf.
50
In some areas of the eastern United States, where there is less conventional oil and gas production, hydraulic fracturing
wastewater is a large percentage of the water sent to injection disposal wells.
51
Pater, supra n. 20 at p. 2.
52
Thomas E. Kurth, et al., American Law and Jurisprudence on Fracing, 47 Rocky Mtn. Min. L. Found. J. 277 (2010).
53
Zoback, supra note 9 at 40.
54
NAS, supra n. 2 at Appendix I. A magnitude of zero on the Richter Scale does not mean the absence of an earthquake.
The inventor of the Richter Scale assigned a magnitude of zero to the smallest seismic event that he thought could be
detected with the instruments available at that time, even though he no doubt knew that earthquakes too small to be detected
existed. Today’s instruments can detect earthquakes that are smaller in magnitude than the smallest earthquakes that could
9
of that range, a ML -2 microseism of the sort typical in fracturing, produces only 0.001% the amplitude
of ground movement as does a magnitude 3.0 earthquake, which is sometimes cited as being at the
lower end of the magnitude range typically required for an earthquake to be felt, and only about
0.00001% of the ground motion amplitude of a magnitude 5.0 earthquake, the smallest magnitude of
earthquake that typically will cause damages.
VI.
What Harm Could Induced Seismicity Cause? What Harm has it Caused?
The main potential harm from induced seismicity is damage to buildings, and potentially
injuries that result from such damage. To date, a large majority of induced seismic events have been
small in magnitude – often too small to be felt55 – and most have not caused any damages.56 In its
2013 report on induced seismicity, the National Academy of Sciences stated that induced seismic
events had not caused any loss of life or significant structural damage in the U.S., but that such events
had caused minor damages to property.57
An earthquake that occurred near Prague, Oklahoma in 2011 is noteworthy, however. The
Oklahoma Geological Survey concluded that the Prague earthquake likely had natural causes,58 but
some scientists have suggested that the earthquake may have been induced by injection disposal
operations.59 In any event, the earthquake caused substantial damage to numerous homes, even
destroying several according to a Wall Street Journal report, and has sparked litigation.60 Seismic
events in Arkansas and Texas also have sparked litigation by plaintiffs who allege damages and claim
that the earthquakes were triggered by injection disposal wells.
In addition, concern occasionally has been raised about the theoretical possibility that an
earthquake induced by injection operations could breach a confining-layer that prevents upward
migration from a waste-disposal reservoir, and that such a breach could allow contamination of an
underground source of drinking water.61 Further, certain provisions in the new California regulations
suggest that state regulators may be concerned that an induced seismic event might compromise well
integrity, thereby allowing contamination to occur. The EPA is unaware, however, of any groundwater
contamination that has resulted from induced seismicity.62
Some scientists have theorized that the maximum magnitude of a seismic event induced by
injection disposal is limited by the quantity of fluid injected. 63 The reasoning is that the magnitude of
an earthquake is largely a function of the size of the block of earth that slips at a fault and that
subsurface injections are not likely to induce slippage beyond the region affected by the injection, a
be detected in years past. Given that those events are smaller than an event with a magnitude of zero, the smaller seismic
events have a negative Richter Scale magnitude.
55
NAS, supra note 2 at 5.
56
Id. at 31.
57
Id. at 5.
58
Oklahoma Geological Survey, statement dated 3/22/2013 regarding the Prague earthquakes, available at
http://www.ogs.ou.edu/earthquakes/OGS_PragueStatement201303.pdf.
59
Katie M. Keranen, et al., Potentially Induced Earthquakes in Oklahoma, U.S.A.: Links Between Wastewater Injection
and the 2011 M 5.7 Earthquake Sequence, Geology (2013).
60
Miguel Bustillo and Daniel Gilbert, “Energy’s New Risk: Quake Lawsuits,” Wall Street Journal (3/30/2015).
61
Nicholson, supra note 5 at 2.
62
EPA, supra n. 4 at ES-1.
63
A. McGarr, Maximum Magnitude Earthquakes Induced by Fluid Injection, 119 Journal of Geophysical Research: Solid
Earth, 1008 (02/04/2014).
10
region whose size is limited by the volume of fluid injected.64 There have not been any earthquakes
with a magnitude greater than 5.0 for which there is a consensus that the earthquake was induced by
injection of fluids,65 but as noted above, some scientists believe that the Prague, Oklahoma earthquake,
which had a 5.7 magnitude, was induced.
VII.
Regulations
A. Safe Drinking Water Act
There is no federal law whose primary purpose is to reduce the risk that fluid withdrawals or
injections will trigger seismicity. But Part C of the Safe Drinking Water Act (“SDWA”) regulates
subsurface injections for purposes of protecting underground sources of drinking water. The SDWA’s
Underground Injection Control (“UIC”) regulations recognize six classes of UIC wells, with each class
being subject to different regulations. The three classes most relevant to induced seismicity issues are:
Class II, which includes wells in which fluids are injected for enhanced recovery of oil or for the
disposal of produced water, and (as the EPA interprets its SDWA regulations) wells that are
hydraulically fractured using a fluid that contains diesel; 66 Class V, which includes wells in which
fluid is injected for the recovery of geothermal energy; 67 and Class VI, a class designed for wells used
for the injection of carbon dioxide for purposes of carbon sequestration.68
The UIC regulations require that an application for a Class I hazardous waste injection permit
or a Class VI carbon sequestration permit include information regarding seismicity in the area for
which the injection permit is sought.69 The regulations do not require that such information be
included in Class II or Class V permit applications,70 and do not otherwise address seismicity.
Although the Safe Drinking Water Act is a federal statute, the statute includes a provision that
requires the EPA to delegate enforcement authority to state officials if a state applies for such authority
– called “primacy” – and the state demonstrates that it has an underground injection control program
that meets federal standards. About 32 states have primacy. The states with primacy include Texas,
Oklahoma, Louisiana, and New Mexico. Several other states have primacy for certain classes of wells.
A handful of states do not have their own underground injection control program, and in those states,
the EPA enforces the SDWA as to all types of underground injection wells. Because almost all oil and
gas producing states have full primacy or at least have primacy for injection wells relating to the oil
and gas industry, most regulatory responses to induced seismicity concerns have occurred at the state
level. See section VII(C) below and Appendix A for a discussion of state regulatory responses.
B. Federal Lands
The Bureau of Land Management (“BLM”) recently promulgated regulations to govern
hydraulic fracturing on federal and Indian lands.71 In its responses to public comments, BLM noted
64
NAS, supra n. 2 at 50, 56.
Id. at 10-11.
66
40 C.F.R. § 144.6(b). The history of the SDWA’s application or non-application to hydraulic fracturing is somewhat
convoluted. See Keith B. Hall, Regulation of Hydraulic Fracturing Under the Safe Drinking Water Act, 19 Buff. Env. Law
J. 1 (2012).
67
40 C.F.R. § 144.6(e).
68
40 C.F.R. § 144.6(f)
69
40 C.F.R. §§ 146.62(b)(1) and 146.82(a)(3)(v).
70
EPA, supra n. 4 at 3.
71
80 Fed. Reg. 16128 (03/26/2015).
65
11
that several persons had urged the agency to restrict hydraulic fracturing in “areas with seismic
zones.”72 BLM declined to do so, explaining that “research on the phenomena of induced seismicity
from hydraulic fracturing is still ongoing and inconclusive.”73 BLM also stated that the risk of
seismicity can be addressed through the National Environmental Policy Act analysis and that the
agency’s new fracturing rules require applicants for well permits to submit geological information that
could assist in such analyses.74
C. State Regulations
Several states, including Arkansas,75 California,76 Colorado,77 Illinois,78 Kansas,79 Ohio,80
Oklahoma,81 and Texas82 have recently taken steps to address the potential for injection wells to induce
seismicity. Those steps, in the form of statutes, regulations, orders, changes in permitting processes, or
some combination of these, do such things as: require an evaluation of seismicity risks in an area for
which a new injection well permit is sought; require monitoring for seismic events in the vicinity of an
injection well; require more frequent measurement and reporting of injection rates and pressures;
impose moratoria on injections in certain areas or below certain depths; and require a reduction in
injection rates or a cessation of operations if seismic events near the injection site exceed a specified
magnitude or a particular frequency of occurrence. California’s regulation addresses hydraulic
fracturing. The other states’ regulations address injection disposal.
In general, the state regulatory responses are consistent with the two types of recommendations
made by scientists to reduce the risk of induced seismicity: (1) evaluate the induced seismicity risk
before making a decision to locate an injection well in a particular location; and (2) implement a traffic
light system once an injection well is operating. For more discussion of the regulatory actions taken in
individual states, see Appendix A.
D. Canadian Provinces
On February 19, 2015, the Alberta Energy Regulator (“AER”) issued Subsurface Order No. 2,
which requires use of a traffic light system when hydraulic fracturing is to be performed in a particular
72
Id. at 16182
Id.
74
Id.
75
Arkansas Oil & Gas Commission, “Class II Commercial Disposal Well or Class II Disposal Well Moratorium,” Order
No. 602A-2010-12 (02/08/2011), available at http://www.aogc2.state.ar.us /Hearing%20Orders/2011/Jan/602A-201012.pdf); “Request for an Immediate Moratorium on Any New or Additional Class II Commercial Disposal Well or Class II
Disposal Well Permits in Certain Areas,” Order No. 180A-2-2011-07 (08/02/2011), available at:
http://www.aogc2.state.ar.us/Hearing%20Orders/ 2011/July/180A-2-2011-07.pdf
76
14 Cal. Code Reg. § 1785.1
77
Colorado Oil & Gas Conservation Commission, description of Class II regulatory program, available at
http://cogcc.state.co.us/documents/about/TF_Summaries/GovTaskForceSummary_Engineering%20UIC%20Wells.pdf.
78
225 Ill. Comp. Stat. 732/1-96; 62 Ill. Admin. Code 240.796.
79
Kansas Corporation Commission, In the Matter of an Order Reducing Injection Rates into the Arbuckle Formation,
Conservation Division Docket No. 15-CONS-770-CMSC, “Findings of Fact,” para. 13 (03/19/2015), available at
http://estar.kcc.ks.gov/estar/ViewFile.aspx/15-770%20Order.pdf?Id=05630050-78a3-4800-a08b-85202375305a.
80
Ohio Admin. Code § 1501:9-3-06; id. at § 1501:9-3-07(F)-(G).
81
Okla. Reg. No. 24 at p. 1001 (Sept. 12, 2014); See Media Advisory, available at
http://www.occeweb.com/News/2015/ADVISORY%20-%20TRAFFIC%20LIGHT.pdf.
82
16 Tex. Admin. Code §§ 3.9 & 3.46.
73
12
area.83 The requirements include assessing the potential for seismicity of a proposed hydraulic
fracturing operation, conducting monitoring, developing a plan for mitigating any seismicity that is
above a magnitude of 2.0, halting fracturing operations if seismic events of magnitude 4.0 or greater
are detected within 5 km of the well, and refraining from recommencing fracturing (after a mandatory
halt) without AER’s consent.84 The British Columbia Oil & Gas Commission has written certain
provisions relating to induced seismicity into permits and has announced that it plans to incorporate
those requirements into its regulations.85 For further discussion, see Appendix A.
VIII. Litigation
A. Cases
In the last few years, plaintiffs in multiple states (including Oklahoma, Arkansas, and Texas)
have filed actions asserting that induced seismicity relating to oil and gas activity has caused them
harm. Several of the cases have been dismissed on motion of the plaintiffs, or on joint motions of the
parties, from which it is reasonable to conclude that the cases settled. A few cases are pending. None
of the cases have gone to judgment on the merits. A list of the cases that have been filed is attached as
Appendix B. The list notes the court in which the case was filed, the causes of action that the plaintiffs
asserted, and the current disposition of the case.
B. Proving Causation
No matter what legal theory a plaintiff asserts in a lawsuit alleging harm from induced
seismicity, a key issue likely will be causation – whether the defendant’s conduct actually caused an
earthquake. The mere fact that an earthquake occurred is not sufficient to prove that the seismic event
was induced. Although felt earthquakes are rare in many places, natural seismic events that are large
enough to be felt can occur nearly anywhere.86 Expert testimony will be required.
No method exists for conclusively establishing that a particular earthquake was induced, 87 but
scientists have identified several factors that can be considered in evaluating the likelihood that a
seismic event was induced. For example, in one frequently cited paper, two seismologists suggested a
series of seven questions that could be asked in order to evaluate whether fluid injections induced a
particular seismic event. The seven questions explore four issues – the history of seismicity in the
area, whether a temporal correlation exists between a seismic event and the subsurface injection
suspected of inducing the event, whether a spatial correlation exists, and whether the injection
pressures seem sufficient to induce seismicity. A greater number of “yes” answers indicates a greater
likelihood that the seismic event was induced. The questions are:
(1)
(2)
(3)
(4)
Are the seismic events the first known earthquakes of this character in the region?
Is there a clear (temporal) correlation between the earthquakes and the injection?
Are the epicenters of the earthquakes within 5 km of the injection?
Did some of the earthquakes occur at or near the injection depths?
83
Alberta Energy Regulator Subsurface Order No. 2, available at https://www.aer.ca/documents/bulletins/AER-Bulletin2015-07.pdf.
84
Id.
85
B.C. Oil & Gas Commission, “Investigation of Observed Seismicity in the Montney Trend” at pp.18, 19, 21-2 (Dec.
2014), available at https://www.bcogc.ca/node/12291/download.
86
Scott D. Davis and Cliff Frohlich, Did (Or Will) Fluid Injection Cause Earthquakes? – Criteria for a Rational
Assessment, 64 Seismological Research Letters 207, 207 (July-Dec. 1993)
87
NAS, supra note 2 at 31, 32.
13
(5) If the earthquakes did not occur near the injection, are there known geologic structures that
might have channeled flow to the site of the earthquakes?
(6) Are changes in well pressures at well bottoms sufficient to encourage seismicity?
(7) Are changes in fluid pressure at hypocenter locations sufficient to encourage seismicity? 88
Other scientists have used these questions in evaluating whether a seismic event likely was induced. 89
C. Theories of liability
If a plaintiff seeks recovery for harms allegedly caused by induced seismicity, there are several
tort theories that the plaintiff might assert, including negligence, the abnormally dangerous activity
doctrine (a strict liability theory that sometimes is called the “ultrahazardous activity” doctrine),90
nuisance, and trespass. Those four theories have been asserted in most of the recently-filed induced
seismicity cases. 91
1. Negligence
To prevail in a negligence claim, a plaintiff must prove that (a) the defendant owed a duty to the
plaintiff, (b) the defendant breached the duty, (c) the plaintiff incurred damages, and (d) the damages
were proximately caused by the breach.92
The existence or non-existence of a duty is an issue of law to be decided by the court based on
the surrounding circumstances.93 In determining whether a duty existed, the court should consider
such factors as “the risk, foreseeability, and likelihood of injury weighed against the social utility of
the actor's conduct, the magnitude of the burden of guarding against the injury, and the consequences
of placing the burden on the defendant.”94 Of these factors, some courts have suggested that
foreseeability of the risk is “the foremost and dominant consideration.”95 Other courts have stated that
“whether a duty should be imposed in a particular case is essentially one of fairness under
contemporary standards.”96 When a duty exists for purpose of negligence law, the standard of care
88
Davis, supra n. 30 at 208.
E.g., Austin Holland, Examination of Possibly Induced Seismicity from Hydraulic Fracturing in the Eola Field, Garvin
County, Oklahoma, Oklahoma Geological Survey Open-File Report OF1-2011 at pp. 21-2.
89
90
Restatement (Third) of Torts: Liability for Physical and Emotional Harm §§ 20, 24; Restatement (Second) of Torts §§
519-20; Restatement (First) of Torts §§ 519-20.
91
Some plaintiffs also have purported to assert causes of action for “public nuisance” and intentional infliction of emotional
distress. But under the facts alleged and the laws generally governing those causes of action, such claims likely would be
extremely weak in most jurisdictions. William L. Prosser, et al., PROSSER AND KEETON ON TORTS, § 12, pp. 60-5
(5th ed. 1984); Restatement (Second) Torts § 821B & cmts.
92
Shirley v. Glass, 308 P.3d 1, 6 (Kan. 2013); Casebolt v. Cowan, 829 P.2d 352, 356 (Colo. 1992); Greater Houston
Transportation Co. v. Phillips, 801 S.W.2d 523, 525 (Tex. 1990); Sloan v. Owen, 579 P.2d 812, 814 (Okla. 1977);
Restatement (Second) of Torts § 328A.
93
Casebolt v. Cowan, 829 P.2d 352, 356 (Colo. 1992); Greater Houston Transportation Co. v. Phillips, 801 S.W.2d 523,
525 (Tex. 1990); Brown v. C.H. Guernsey and Co., 533 P.2d 1009, 1013 (Okla. App. 1973); see also Shirley v. Glass, 308
P.3d 1, 9 (Kan. 2013); Restatement (Second) of Torts § 328B.
94
Greater Houston Transportation Co. v. Phillips, 801 S.W.2d 523, 525 (Tex. 1990); see also Casebolt v. Cowan, 829 P.2d
352, 356 (Colo. 1992).
95
Greater Houston Transportation Co. v. Phillips, 801 S.W.2d 523, 525 (Tex. 1990). See also Connes v. Mollola Transport
System, Inc., 831 P.2d 1316, 1320 (Colo. 1992) (describing foreseeability as a “prime” factor, though not a controlling
factor).
96
Casebolt v. Cowan, 829 P.2d 352, 356 (Colo. 1992).
14
may be one of reasonable care or it may be a heightened standard – the nature of the standard will be a
question of law.97
If a plaintiff brings a negligence claim based on an earthquake allegedly induced by some type
of oil and gas activity, a defendant might contest the existence of a duty. The contours of such an
argument would depend on a variety of circumstances, including the type of oil and gas activity
alleged to have induced the seismic activity. The parties’ arguments also would depend on the nature
of the duty the plaintiff alleges – for example, is the plaintiff alleging that the defendant had a duty to
use care in choosing the location for its operation? A duty to use care in conducting its operations?
Both?
In support of an assertion that a duty existed, a plaintiff reasonably could argue that, although
the fraction of injection wells that are suspected of induced seismic activity is small, the possibility of
induced seismicity was foreseeable. In support of a contention that no duty existed, a defendant could
argue that the likelihood of an induced seismic event was low, the chances that an induced seismic
event would cause harm was even lower, and the social utility of injection disposal is high. Expert
testimony likely would be critical on such questions as foreseeability, likelihood of harm, and social
utility of the defendant’s conduct.
Assuming the court determined that a duty existed, the plaintiff would need to prove that the
defendant breached its duty. Whether the defendant breached a duty is question to be decided by the
trier of fact, but expert testimony might still be required, just as expert testimony might be needed to
establish the appropriate standard of care in a medical malpractice case. Suppose, for example, that the
plaintiff alleged that the defendant breached a duty to operate an injection disposal well with
reasonable care because the defendant injected fluids at too high a rate. The average juror or judge
would not know what rate of injection is reasonable.
If the defendant breached a duty, the plaintiff also would need to prove that the breach caused
the induced seismicity. Suppose, for example, that the plaintiff’s theory is that the defendant injected
fluids at an unreasonable rapid rate and that this caused an earthquake. Expert testimony will be
essential to proving causation.
Finally, the plaintiff would need to prove that the induced earthquake caused his harm. The
plaintiff might or might not need expert testimony to prove that his alleged damages were caused by
the earthquake, depending on the type of damages alleged. The plaintiff might also need expert
testimony to prove the dollar value of his damages.
2. Strict Liability98
“Strict liability” describes a set of tort liability theories that do not require proof that the
defendant was negligent.99 There are various types of strict liability.100 The theory that is most likely
97
Shirley v. Glass, 308 P.3d 1, 6 (Kan. 2013); Restatement (Second) of Torts § 328B.
Rylands v. Fletcher, L.R. 3 H.L. 330 (1868);
99
The Restatement (Second) of Torts § 519 makes clear that a showing of negligence is not necessary.” It states in part:
“One who carries on an abnormally dangerous activity is subject to liability for harm to the person, land or chattels of
another resulting from the activity, although he has exercised the utmost care to prevent the harm.” See also Restatement
(First) of Torts § 519 (person engaging in ultrahazardous activity generally is liable for any harm caused “although the
utmost care is exercised to prevent the harm”).
“Strict liability” sometimes is called “absolute liability.” For example, Division 3 of the Restatement (First) of Torts is
entitled “Absolute Liability.” In the Restatement (Second) of Torts, Division 3 is entitled “Strict Liability.”
100
For example, products liability is a type of strict liability that is recognized in several jurisdictions.
98
15
to be invoked in an induced seismicity case is a theory that is sometimes called either the
“ultrahazardous activity” doctrine or the “abnormally dangerous” activities doctrine.101
Courts in the U.S. often trace this doctrine to a famous British case, Rylands v. Fletcher, 3 H.L.
330 (1868). In that case, the plaintiff was the operator of a coal mine. The defendant constructed a
water reservoir on nearby land and impounded a large quantity of water there. The land on which the
defendant constructed his reservoir contained five old vertical shafts that were filled with dirt. Those
shafts proceeded vertically downward to old mine works beneath the property, and in turn, those old
mine works were connected via certain subsurface passages to the plaintiff’s coal mine. Water from
the defendant’s reservoir broke through one of the shafts and into the old mine works. From there, the
water flowed to the plaintiff’s mine and flooded it. The House of Lords held that the plaintiff could
recover for his damages even if the defendant had not been negligent.
The Restatement (First) of Torts recognized that a person would be subject to “absolute
liability” (another term for strict liability), even he had not been negligent, if he caused harm by
engaging in an “ultrahazardous activity.”102 Section 520 of the Restatement stated that an activity is an
“ultrahazardous activity” if it is “not a matter of common usage” and it “necessarily involves a risk of
serious harm to the person, land or chattels of others which cannot be eliminated by the exercise of the
utmost care.”103 One of the official comments to Section 520 explained that, “An activity is a matter of
common usage if it is customarily carried on by the great mass of mankind or by many people in the
community.”104 The comment gave driving automobiles as an example of an activity that is of
“common usage.”105
Notably, the same comment notes that driving an automobile is not an ultrahazardous activity
for two reasons – because it is a matter of common usage and because “the risk involved in the careful
operation of a carefully maintained automobile is slight.” This suggests that as long as due care will
substantially eliminates risk, it is not necessary for due care to eliminate all risk whatsoever in order
for an activity to escape classification by section 520 as an activity for which risk “cannot be
eliminated by the exercise of the utmost care.”
The Restatement (Second) of Torts states that a person will have “strict liability” for the harm
he causes by engaging in an “abnormally dangerous” activity.106 The Restatement (Second) states that,
in determining whether an activity is abnormally dangerous, six factors should be considered. 107 When
the six factors are phrased as questions to which an affirmative response weighs in favor of strict
liability, the factors are these:
o
Does the activity involve a high degree of risk of some harm to the person, land or
chattels of others?
o
If the activity causes harm, is it likely that the harm will be great?
101
In the Restatement (First) of Torts, it is called the “ultrahazardous activities” doctrine. See, e.g., Restatement (First)
Torts §§ 519-20; see also La. Civ. Code art. 667. In the Restatement (Second) of Torts §§ 519-20 and Restatement (Third)
of Torts: Liability for Physical and Emotional Harm §§ 20 & 24, “abnormally dangerous” is used.
102
Restatement (First) of Torts § 519.
103
Restatement (First) of Torts § 520.
104
Restatement (First) of Torts § 520 cmt. (e).
105
Id.
106
Restatement (Second) of Torts § 519.
107
Restatement (Second) of Torts § 520.
16
o
Does the activity involve risk that cannot be eliminated even by the exercise of
reasonable care?
o
Is the activity one which is not a matter of common usage?
o
Is the activity inappropriate to the place where it is carried on? and
o
Do dangerous attributes of the activity outweigh its value to the community? 108
The reader should note that not all states recognize this sort of strict liability. For example,
Texas does not recognize the abnormally dangerous activities doctrine.109 Further, although Louisiana
recognizes this sort of strict liability, it restricts the doctrine to cases arising from pile driving and
blasting.110
In states that generally recognize the abnormally dangerous activities doctrine, it is not clear
whether the types of activities that can induce seismicity would be classified as abnormally dangerous.
Case law does not yet seem to have addressed the issue. Expert testimony likely would be important
for helping the court evaluate the factors that determine whether a particular type of activity triggers
the doctrine. Indeed, expert testimony likely would be helpful with respect to each of the factors.
Finally, even if the plaintiff convinces the court that strict liability applies, the plaintiff still will need
to prove that the defendant’s conduct caused the seismic activity that harmed the plaintiff.
3. Nuisance
Ownership of land is a bundle of various rights, including an interest in exclusive possession,
which gives an owner the right to exclude others from entry, and also an interest in the use and
enjoyment of the land. 111 Traditionally, two distinct and separate causes of action have arisen to
protect those separate interests.112 “Nuisance” is the cause of action that arose to protect an owner’s
interest in the use and enjoyment of his property.113
To prove a nuisance at common law, a plaintiff must prove that: (1) the defendant acted
intentionally; (2) the defendant’s intentional conduct interferes with the plaintiff’s use and enjoyment
of his property; (3) the interference is substantial; and (4) the interference is unreasonable.114 In
determining whether the interference is unreasonable, the plaintiff’s interest must be balanced against
the social utility of the defendant’s conduct.115
To support a nuisance claim, an interference with the plaintiff’s use and enjoyment of his
property generally must cause “significant harm, of a kind that would be suffered by a normal person
in the community or by property in normal condition and used for a normal purpose.”116 Thus, a slight
108
Restatement (Second) of Torts § 520.
Turner v. Big Lake Oil, 96 S.W.2d 221 (Tex. 1936).
110
La. Civ. Code art. 667.
111
Id. at 218-9.
112
Prosser, supra n. 174 at § 87, p. 622.
113
Adams, 602 N.W.2d at 219.
114
Prosser, supra n. 174 at § 87, pp. 622-3; Crouch v. North Alabama Sand & Gravel, __ So. 3d __ , ___, 2015 WL
1388139 (Ala. 2015); Hendricks v. Stainaker, 380 S.E.2d 198, 200 (W.V. 1989).
115
Hendricks, 380 S.E.2d at 202.
116
Restatement (Second) of Torts § 821F.
109
17
inconvenience or a petty annoyance typically will not support a claim for nuisance.117 Further, if
something causes a significant harm to the plaintiff, but only because the plaintiff is unusually
sensitive, the harm probably will not support a claim for nuisance.118 Moreover, some sources state
that, in order for a plaintiff to prevail on a nuisance claim, it is not sufficient that the defendant acted
intentionally. Instead, it is also necessary that the defendant knew or should have known that his act
would interfere with the plaintiff’s use and enjoyment of property.119
Things that can cause a nuisance include odors,120 dust,121 noise,122 smoke,123 and bright
lights.
Also, vibrations can constitute a nuisance.125 For example, in Sam Warren & Son Stone Co.
v. Gruesser, a Kentucky court found that vibrations caused by diesel engines that the defendant used in
its operations were a nuisance.126 In Transcontinental Gas Pipe Line v. Gault, a court applying
Maryland law found that vibrations from a compressor station constituted a nuisance.127 In Crouch v.
Alabama Sand & Gravel, the plaintiffs alleged that the defendant’s blasting operations caused
vibrations that disturbed their used and enjoyment of their property and caused damages to their
home.128 The trial court granted a summary judgment dismissing the plaintiffs’ claim, but the
Alabama Supreme Court reversed, noting that vibrations can constitute a nuisance under wellestablished state law and that fact issues precluded summary judgment. 129 Under such reasoning, the
shaking caused by an earthquake might support an action in nuisance.
124
A plaintiff can recover damages in nuisance. Also, injunctive relief requiring a cessation of a
defendant’s activities sometimes might be available if the defendant’s activities have caused repeated
incidents of nuisance.130
4. Trespass
Trespass is the cause of action that arose to protect a landowner’s interest in the exclusive
possession of his land.131 Traditionally, an action in trespass required an invasion of the plaintiff’s
land by a person or some tangible thing.132 Accordingly, the projection of light, noise, or vibrations
across property lines traditionally would not support a trespass claim, though they might support a
claim in nuisance.133 Further, although smoke, dust, and even the molecules that transmit odors consist
117
Id. at § 821F cmt. (c).
Id. at § 821F cmt. (d).
119
Prosser, supra note 89.
at § 87, pp. 625.
120
Smith v. Kansas Gas Service, 169 P.3d 1052, 1061 (Kan. 2007); Schneider National Carriers v. Bates, 147 S.W.3d 264,
269 (Tex. 2004); Choctaw, Oklahoma & Gulf Railroad v. Drew, 130 P. 1149, 1151 (Okla. 1913).
121
Schneider National Carriers, 147 S.W.3d at 269.
122
Id.; Choctaw, Oklahoma, 130 P. at 1151.
123
Choctaw, Oklahoma, 130 P. at 1151.
124
Schneider National Carriers, 147 S.W.3d at 269.
125
Colegrove v. Fred A. Newman Co., 2015 WL 627633 (Ohio App. 2015).
126
209 S.W.2d 817 (Ky. 1948).
127
198 F.2d 196 (4th Cir. 1952).
128
__ So. 3d __ , 2015 WL 1388139 (Ala. 2015).
129
Id. at *7.
130
Valasek v. Baer, 401 N.W.2d. 33, 34-5 (Iowa 1987) (nuisance).
131
Adams v. Cleveland-Cliffs Iron, 602 N.W.2d 215, 218 (Mich. App. 1999).
132
Prosser, supra n. 89 at §13, p. 71; Adams, 602 N.W.2d at 219.
133
Prosser, supra n. 89 at §13, p. 71.
118
18
of matter, those things traditionally were not deemed sufficiently tangible to support a trespass
claim.134
Some jurisdictions have retained the traditional requirement that a trespass action be based on
an intrusion by a tangible thing,135 but other jurisdictions have adopted a so-called “modern” theory of
trespass that has eliminated such a requirement.136 In some of the jurisdictions adopting a modern
trespass theory, there still must be a physical intrusion, but the intrusion of small particles that would
not be deemed tangible under the traditional theory will suffice, provided the particles accumulate.137
Other jurisdictions adopting the modern theory of trespass have gone further, allowing trespass claims
to be based on intrusions by a gas that does not accumulate or even on an “invasion” by things that
lack any substance whatsoever, such as light, sound, or vibrations.138
The courts that have adopted the modern theory have also revised the traditional rule relating to
whether a plaintiff must prove actual damages. Under the traditional rule, because a landowner’s
interest in the exclusive possession of his land is breached by any unauthorized intrusion, even an
intrusion that does not cause damages, a landowner can maintain an action for trespass and recover
nominal damages for an unauthorized intrusion that does not cause actual harm.139 But under the
modern theory, a plaintiff cannot prevail in trespass for an invasion by an intangible thing unless he
proves that the invasion caused substantial harm to his property.140
The reason that the courts adopting the modern theory revised the rule relating to damages is a
practical one.141 The traditional rule that no actual damages are required for an action in trespass
works fine if trespass clams must be based on invasions by tangible things, but such a rule raises the
threat of a multitude of lawsuits over petty annoyances if trespass claims can be based on invasions by
intangible things, such as sound, light, and vibrations. Indeed, it is impossible for owners of
neighboring land to occupy or use their land without causing some light, sound, or vibrations to cross
property lines. For example, if a lighted window of your neighbor’s house is visible from your
property, your neighbor is causing light to invade your property.
In a state that follows the traditional rules of trespass, the shaking caused by an earthquake
would not support a trespass claim because the shaking does not involve an intrusion by a tangible
object. In states that follow a modern rule of trespass, such shaking may or may not support a trespass
claim. Some states following a so-called modern theory have extended the conception of trespass to
cover intrusions by dust or small particles that previously would have been deemed “intangible,”
provided that such particles accumulate and cause harm. In such a state, the shaking caused by an
earthquake would not support a trespass claim. But some states adopting a modern theory of trespass
have extended the trespass claim to cover invasions by things wholly lacking in substance, provided
the invasion causes damages to property. In such a state, the shaking caused by an earthquake might
support a trespass claim if the shaking causes damages.
134
Adams, 602 N.W.2d at 219.
Id. at 221; Babb v. Lee County Landfill, 747 S.E.2d 468, 476 (S.C. 2013).
136
Borland v. Sanders Lead Co., 369 So. 2d 523, 529 (Ala. 1979).
137
Id. at 530.
138
Martin v. Reynolds Metals, 342 P.2d 790 (Or. 1959).
139
Adams, 602 N.W.2d at 220.
140
Borland, 369 So. 2d at 530.
141
John Larkin, Inc. v. Marceau, 959 A.2d 551, 555 (Vt. 2008).
135
19
Finally, it is noteworthy that injunctive relief requiring a cessation of a defendant’s activities
sometimes might be available if the activities have caused repeated incidents of trespass.142
IX.
Insurance
Standard homeowner’s policies, commercial building policies, and liability policies exclude
damages for harms caused by earthquakes. But it is possible to obtain earthquake insurance for
damages that an earthquake might cause to a building owned by the insured. Also, some homeowner’s
polices or commercial building polices will cover damages caused by a fire that is itself caused by an
earthquake.
X.
Conclusion
The injection of fluids into the subsurface can trigger earthquakes under certain circumstances.
The vast majority of injection operations, including those associated with the oil and gas industry, do
not trigger earthquakes. But many geologists believe that injection disposal operations associated with
the oil and gas industry are responsible for a recent, dramatic increase in the frequency of earthquakes
in a few areas of the U.S., as well as for isolated seismic incidents elsewhere. Geologists believe that
hydraulic fracturing itself can also induce seismicity on rare occasions, but that it is not responsible for
the recent and dramatic increase in the frequency of seismic events.
Several states have recently addressed concerns about induced seismicity using statutes,
regulations, agency orders, or changes in permitting procedures. Those initiatives do such things as:
require that the potential for induced seismicity in an area be examined during the permitting process;
impose moratoria on injection disposal operations in certain areas or at certain depths; require more
frequent monitoring and reporting of injection rates and pressures; require monitoring for seismic
events in the vicinity of injection operations; and require a reduction in injection rates or a cessation of
injections if seismic events exceeding a specified magnitude or frequency are observed.
Finally, plaintiffs have recently filed litigation in a few states, alleging that they have incurred
harms from induced seismic events. The plaintiffs typically purport to assert causes of action for
negligence, strict liability, nuisance, and trespass. None of those cases have gone to judgment on the
merits yet.
142
Green v. Mutual Steel Co., 108 So. 2d 837, 839 (Ala. 1959) (trespass).
20
Appendix A
Regulations Relevant to Injection-Induced Seismicity
A. Federal regulations
1. Safe Drinking Water Act
There is no federal law whose primary purpose is to reduce the risk that fluid withdrawals or
injections will trigger seismic activity. But Part C of the Safe Drinking Water Act (“SDWA”)
regulates subsurface injections for purposes of protecting underground sources of drinking water
(“USDWs”). To a limited extend, The SDWA’s underground injection control (“UIC”) regulations
have addressed seismicity concerns for purposes of groundwater protection. Federal UIC regulations
recognize six classes of UIC wells, with each class being subject to different regulations.
Class I
Class II
Class III
Class IV
Class V
Class VI
wells used to inject wastes "beneath the lowermost formation containing, within onequarter mile of the well bore, an underground source of drinking water."143
wells in which fluids are injected for: disposal of produced water and certain
wastewater associated with oil and gas production; "enhanced recovery of oil or natural
gas"; storage of liquid hydrocarbons; and (as the EPA interprets its regulations, any
well that is hydraulically fractured using a frac fluid that contains diesel)144
wells are wells associated with certain mining activity145
wells are wells used for injection of wastes into a formation that contains an
underground source of drinking water within one-quarter mile of the well146
wells are injection wells that do not fit into any other category of injection well147
wells for the injection of carbon dioxide for carbon sequestration148
143
40 C.F.R. § 144.6(a)
40 C.F.R. § 144.6(b). For years, the EPA took the position that the SDWA did not apply to hydraulic
fracturing and the Agency’s SDWA regulations did not expressly include hydraulic fracturing in any of the
classes of injection wells. See Keith B. Hall, Regulation of Hydraulic Fracturing Under the Safe Drinking
Water Act, 19 Buff. Env. Law J. 1 (2012) (providing a history of the EPA’s position on whether the Safe
Drinking Water Act applies to hydraulic fracturing). In 2005, the Safe Drinking Water Act was amended to
state that, for purposes of the SDWA, the definition of "underground injection . . . excludes . . . the underground
injection of fluids or propping agents (other than diesel fuels) pursuant to hydraulic fracturing operations related
to oil, gas, or geothermal production activities." That amendment is found at 42 U.S.C. § 300(h)(d)(1). But
after the 2005 amendment, the EPA (which had interpreted its existing regulations as not applying to hydraulic
fracturing) did not go back and amend its regulations to explicitly place hydraulic fracturing into a particular
class of injection wells. Instead, the EPA took no action for several years, and then in 2010 announced that it
interpreted wells that are hydraulically fractured using diesel as falling under Class II. Id. at 25-6.
145
40 C.F.R. § 144.6(c).
146
40 C.F.R. § 144.6(d)
144
147
40 C.F.R. § 144.6(e). The regulations originally only contained five classes of wells, with Class V being the
catch-all category. When a sixth class was added the catch-all category remained as Class V and a new class, for
wells used for carbon sequestration and storage, was added as Class VI.
148
40 C.F.R. § 144.6(f)
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Federal regulations require that an application for a Class I or Class VI injection well include
an analysis of past seismicity in the area for which the injection well is proposed.149 The requirement
appears to be motivated by the possibility that existing seismicity will interfere with containment of the
injected fluids, rather than with the possibility that the injection will induce seismicity.
The
regulations do not require that such an analysis be included in applications for permits for other classes
of UIC wells.
2. Bureau of Land Management
The Bureau of Land Management recently published new regulations to cover hydraulic
fracturing on federal and Indian lands.150 In its responses to public comments, BLM noted that several
public comments had urged the agency to restrict hydraulic fracturing in “area with seismic zones.”151
BLM declined to do so, explaining that “research on the phenomena of induced seismicity from
hydraulic fracturing is still ongoing and inconclusive.”152 BLM went on to state that the risk of
seismicity could be addressed through the National Environmental Policy Act analysis and that the
agency’s new fracturing rule requires applicants for permits to submit geological information that
could assist such an analysis.153
B. State Regulations
1. Arkansas
In Arkansas, oil and gas activity and Class II injection are regulated by the Oil & Gas
Commission. In response to a large number of earthquakes, the Commission issued an order in early
2011, placing a moratorium of approximately six months on the issuance of new Class II injection well
permits for a particular area, based on “circumstantial evidence that recent earthquakes within the
proposed area may be either enhanced or potentially induced by the operation of Class II … wells.”154
The order also required that operators of existing Class II wells within the area begin submitting biweekly reports to the Commission to report the daily injection volumes and the maximum daily
injection pressure.
The Commission’s order also noted that the Arkansas Geological Survey had conducted
studies, and that the Arkansas Geological Survey, as well as the U.S. Geological Survey, and Center
for Earthquake Research and Information would be conducting additional studies, and that later in the
years the Commission would consider information gathered in those studies.
149
40 C.F.R. §§ 146.62(b)(1) and 146.82(a)(3)(v).
150
80 Fed. Reg. 16128 (Mar. 26, 2015).
151
Id. at 16182
Id.
152
153
Id.
154
The order is available on the Arkansas Oil & Gas Commission website at: http://www.aogc2.state.ar.us
/Hearing%20Orders/2011/Jan/602A-2010-12.pdf.
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The Commission considered such information during a meeting in July 2011 and issued an
order placing a “permanent moratorium” on the issuance of new Class II permits in the area covered by
the temporary moratorium issued earlier in the year.155 At the same time, the Commission entered a
separate order that required the closure of the only existing Class II well that was still operating in the
area (the order noted that three other Class II wells in the area had been voluntarily closed by the
operators).156
2. California
A California regulation that went into effect July 1, 2015 requires operators to monitor the
California Integrated Seismic Network from the time they begin hydraulic fracturing of a well until ten
days after they have finished fracturing.157 If an earthquake of magnitude 2.7 or greater is detected
within a distance of five times the “ADSA” or “axial dimensional stimulation area,” which is defined
to mean “the estimated axial dimensions, expressed as maximum length, width, height, and azimuth, of
the area(s) stimulated by a well stimulation treatment,”158 the operator must immediately notify the
Division of Oil, Gas and Geothermal Resources (“DOGGR”).159 The regulations provide that
DOGGR, in consultation with the operator and the California Geological Survey, will evaluate whether
the hydraulic fracturing operation caused the seismic activity, whether there is a pattern of seismic
activity that corresponds to hydraulic fracturing in the area, and whether the mechanical integrity of
any active well within a radius of five times the ADSA has been compromised.160 No further hydraulic
fracturing may be performed in a radius of five times the ADSA until DOGGR has determined that
hydraulic fracturing in the area does not create a heightened risk of seismic activity. 161
3. Colorado
In Colorado, oil and gas activity and Class II injection wells are regulated by the Oil and Gas
Conservation Commission. Starting in September 2011, the Commission began including a seismicity
155
The order is available on the Oil & Gas Commission website at:
http://www.aogc2.state.ar.us/Hearing%20Orders/ 2011/July/180A-2-2011-07.pdf.
156
The order is available on the Oil & Gas Commission website at:
http://www.aogc2.state.ar.us/Hearing%20Orders/2011/July/180A-1-2011-07.pdf.
157
158
14 Cal. Code Reg. § 1785.1(a).
14 Cal. Code Reg. § 1781.
159
14 Cal. Code Reg. § 1785.1(b)(1). Title 14, section 1750 of the California Code of Regulations makes it
clear that section 1785.1’s reference to “Division” means the Division of Oil, Gas, and Geothermal Resources
(“DOGGR”). DOGGR is part of the California Department of Conservation. See Cal. Public Resources Code §
607.
160
14 Cal. Code Reg. § 1785.1(b)(2). If the concern is that the seismic event could have compromised well
integrity, then it would seem that the area within which the integrity of all active wells must be checked should
be an area surrounding the epicenter of the seismic even, but the regulation seems to contemplate a radius
around the well that was hydraulically fractured.
161
14 Cal. Code Reg. § 1785.1(b)(3). In some ways, it would seem that the area covered by the moratorium on
fracturing, pending DOGGR’s determination that fracturing does not create heightened risk of seismic activity,
should be based on area around the hypocenter or epicenter of the seismic event, but the regulation appears to
contemplate an area within a particular radius of the hydraulically fractured well.
A-3
review in its evaluation of applications for new Class II injection well permits.162 As part of that
review, the Commission works with the Colorado Geological Survey, which uses its own geologic
maps, the U.S. Geological Survey earthquake database, and other information to evaluate the potential
for seismicity. If there has been past seismicity in the vicinity of the proposed injection well location,
the Commission requires the permit applicant to use geological data to define the seismicity potential
and the proximity of the site to faults before approving the application.
4. Illinois
In 2013, Illinois enacted legislation directing the Department of Natural Resources to adopt
rules establishing a “traffic light” protocol to address the risk of induced seismicity at Class II injection
wells.163 The legislation states that the rules described such as protocol as one “allowing for low levels
of seismicity while including additional monitoring and mitigation requirements when seismic events
ae of sufficient intensity to result in a concern for public health and safety.” 164 The legislation
specifies that the additional mitigation must “provide for either the scaling back of injection operations
with monitoring for establishment of a potentially safe operation or the immediate cessation of
injection operations.”165
In late 2014, the Illinois DNR adopted regulations to create the required traffic light system. 166
The regulations provide that if the operation of a Class II UIC disposal well is suspected of having
induced seismic activity, the operator must consult with DNR regarding the possibility of installing a
seismic monitoring system and reducing injection rates or pressures.167
In addition, the regulations provide for the issuance of “Yellow Light Alerts” to all operators of
UIC Class II disposal wells located within 6 miles of the epicenter of a seismic event with a magnitude
between 2.0 and 4.0.168 If any operator receives three Yellow Light Alerts within a one-year period,
the operator must immediately reduce injection rates and consult with DNR and the Illinois State
Geological Survey.169 An operator receiving its third Yellow Light Alert within a year must
immediately cease operations if it also has received a Notice of Violation relating to injection rates,
pressure, or mechanical integrity of the same well.170
The operator also must immediately cease
operations if it receives a fifth Yellow Light Alert within a year.171
162
Colorado Oil & Gas Conservation Commission, COGCC Underground Injection and Control and Seismicity
in Colorado, available at http://media.bizj.us/view/img/3037491/inducedseismicityreview.pdf.
163
Public Act 92-22, section 1-96. Section 1-96 is codified is codified at 225 Ill. Comp. Stat. 732/1-96.
164
225 Ill. Comp. Stat. 732/1-96(c).
165
225 Ill. Comp. Stat. 732/1-96(d).
166
38 Ill. Reg. 22052, 22063 (Dec. 1, 2014).
62 Ill. Admin. Code 240.796(c)(3).
167
168
62 Ill. Admin. Code 240.796(b) (defining “Yellow Light Alert”); 62 Ill. Admin. Code 240.796(d).
169
62 Ill. Admin. Code 240.796(d).
170
62 Ill. Admin. Code 240.796(e)(1).
62 Ill. Admin. Code 240.796(e)(3).
171
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DNR issues a “Red Light Alert” to all operators of Class II UIC disposal wells located within
10 miles of the epicenter of an earthquake of magnitude 4.0 or greater. 172 An operator receiving such
an alert must immediately cease operations if it its well is within 6 miles of the earthquake.173 Further,
DNR must order any operator of a Class II injection well to cease operations immediately if conditions
“create imminent danger to the health and safety of the public, or significant damage to property.”174
5. Kansas
In response to an increase in seismic events in Kansas, Governor Sam Brownback established a
task force in to develop a “State Action Plan” to address the issue.175 The task force issued a draft plan
in April 2014,176 and, after accepting public comments on the draft for approximately one month,
submitted a revised draft in September 2014.177 The draft was amended again in January 2015 to
produce a final draft.178
The final draft made certain recommendations. For example, after noting that Kansas currently
relies on two seismic monitors operated by the U.S. Geological Survey, and that those two monitors
are not sufficient to make precisely locate the hypocenters of earthquakes, the Action Plan
recommended that the state fund a permanent network of seismometers. The recommended network
would allow Kansas to detect and locate earthquakes with a magnitude of 1.5 or greater. The Action
Plan also recommended that Kansas fund a portable seismic array that could be deployed to areas
experiencing seismic activity in order to obtain more detailed information regarding seismic events.
Finally, the Action Plan proposed a formula for giving a numerical score to seismic events based on
various criteria, and further proposed that numerical scores above a certain number would prompt
regulators to increase monitoring and evaluate whether other regulatory steps are appropriate for a
particular injection well or area.
In March 2015, the Kansas Corporation Commission issued an order that appears to be based in
part on the Action Plan’s suggestion that regulators require increased monitoring and consider other
regulatory action after the occurrence of any seismic events earn or exceed a specified numerical under
172
62 Ill. Admin. Code 240.796(b) (defining “Red Light Alert”); 62 Ill. Admin. Code 240.796(d).
173
62 Ill. Admin. Code 240.796(e)(4).
174
62 Ill. Admin. Code 240.796(e).
News release entitled “Governor Sam Brownback Names Task Force to Develop State Action Plan for
Induced Seismicity,” available at http://www.governor.ks.gov/media-room/mediareleases/2014/02/17/governor-sam-brownback-names-task-force-to-develop-state-action-plan-for-inducedseismicity.
175
News release entitled “State Task Force on Induced Seismicity Releases Draft State Action Plan” (Apr. 17,
2014) from Induced Seismicity State Task Force, available at
http://kcc.ks.gov/induced_seismicity/release_041714.htm
177
News release entitled “Induced Seismicity Task Force Submits Seismic Action Plan To Governor Sam
Brownback,” dated October 1, 2014 from Induced Seismicity State Task Force, available at
http://kcc.ks.gov/induced_seismicity/release_100114.htm
176
178
Kansas Seismic Action Plan, available at
http://kcc.ks.gov/induced_seismicity/state_of_kansas_seismic_action_plan_9_26_14_v2_1_21_15.pdf.
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the Plan’s formula. 179 The March 2015 order requires operators of injection disposal wells located in
certain areas to measure daily injection volumes and pressures, and to report each month on the daily
figures for the prior month.180
Further, for disposal wells in those areas, the order reduces the maximum allowable rate of
injection into the Arbuckle formation.181 For example, throughout Sumner and Harper Counties, two
counties that have seen the largest increase in seismic activity, a limit of 25,000 barrels per day will
apply for injections into the Arbuckle formation.182 And in certain areas in those counties, the
maximum allowable injection rate will be reduced in a series of steps that culminates in a maximum
allowable rate of 8,000 barrels of saltwater injection a day, with that ultimate limit going into effect
100 days after issuance of the order.183 In addition, in the area where the most restrictive injection
rates apply, operators generally will be limited to an injection pressure of 250 psi. 184 These operating
restrictions apply both to future disposal wells and existing wells, with the order thus having the effect
of amending existing permits.185
Finally, the order requires operators to measure and report to the Corporation Commission the
true vertical depth of their disposal wells.186 Operators must plug back any wells that have penetrated
beneath the Arbuckle formation in order to confine fluids to that formation.187
6. Ohio
In Ohio, oil and gas activity and Class II injection wells are regulated by the Department of
Natural Resources Division of Oil & Gas Resources. After a series of earthquakes occurred near
Youngstown, Ohio in late 2011, the Department conducted an investigation and ultimately concluded
in a March 2012 report that the earthquakes had likely been caused by operations at a particular
injection disposal facility.188
A few months later, the Department revised its rules regarding injection disposal to address the
threat of induced seismicity. Ohio’s regulation regarding permits for injection disposal was amended
to provide that the Division of Oil & Gas Resources may require that the operator of an existing well
“Order Reducing Saltwater Injection Rates,” available at http://estar.kcc.ks.gov/estar/ViewFile.aspx/15770%20Order.pdf?Id=05630050-78a3-4800-a08b-85202375305a.
179
180
181
Order at para. 13.
See Order at paras. 12, 15.
182
Order at 15.
183
Order at para. 12.
184
Order at para. 12(e).
185
See Order at paras. 12, 15.
186
Order at 16.
187
Order at 17.
An executive summary of a report regarding the earthquakes is available at Ohio DNR’s website at:
http://oilandgas.ohiodnr.gov/portals/oilgas/downloads/northstar/reports/northstar-executive_summary.pdf. A
copy of the full report is on file with Keith B. Hall, co-author of this paper.
188
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conduct certain testing not otherwise required under the regulations. 189 . For example, the Division
may require pressure fall-off testing, investigation of potential faulting within the immediate vicinity of
the proposed site of the injection well, tracer or spinner surveys, and various logs. 190 The Division also
may require the operator to submit a plan for seismic monitoring.191 In addition, the Division may
require that the operator cease operations while the Division is evaluating any of the information that
must be submitted, and may order the plugging of the injection well if the Division deems such action
necessary.192 Finally, the revised regulation gives the Division the authority to “implement graduated
maximum allowable injection pressure requirements based upon data provided.”193
The Department also amended its regulation regarding operation of injection disposal wells.
As amended, the regulation states that all injection wells permitted after the effective date of the
amendment must be “continuously monitored using a method acceptable to the chief” of the
Division.194 The regulation also requires that operators install a device that will automatically shut-off
the injection well if injection pressures exceed the maximum pressure allowed by the permit for that
well.195
7. Oklahoma
In Oklahoma, oil and gas activity and Class II injection wells are regulated by the Corporation
Commission, through the Commission’s Oil & Gas Division. The Commission’s regulations generally
require that operators of injection disposal wells record injection volumes and pressures on a monthly
basis.196 But the Commission amended its regulations in September 2014 to provide that, for injection
into the Arbuckle Formation, the state’s deepest injection formation, operators must monitor and
record injection volumes and pressures on a daily basis, keep the records for at least three years, and
provide the records to the Commission upon request.197
In addition, the Commission announced recently that it has adopted the “traffic light” system
recommended by the National Academy of Sciences.198 In reviewing applications for Class II injection
well permits, its staff now considers such factors as seismicity in the area around the proposed well site
and the proximity of site to faults as part of the Commission’s decision whether the permit should be
granted and, if so, whether any special restrictions should be imposed.
189
190
Ohio Admin. Code 1501:9-3-06(C).
Ohio Admin. Code 1501:9-3-06(C).
191
Ohio Admin. Code 1501:9-3-06(C)(3).
192
Ohio Admin. Code 1501:9-3-06(D)
193
Ohio Admin. Code 1501:9-3-06(E)
Ohio Admin. Code 1501:9-3-07(F).
194
195
Ohio Admin. Code 1501:9-3-07(G).
196
Okla. Admin. Code 165:105-7(b)(3)(A).
197
Okla. Reg. No. 24 at p. 1001 (Sept. 12, 2014).
See statement available at http://www.occeweb.com/SEISMIC%20STATEMENT-a.pdf.
198
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Further, in so-called “areas of interest” or “yellow light” areas, the Commission will require
operators to record injection volumes and pressures daily. Such areas originally were defined to
include all locations within 10 kilometers of the epicenter or an earthquake with a magnitude of 4.0 or
greater.199 In January 2015, the Corporation Commission announced that it had expanded the
definition of “area of interest” to include not only the locations originally included, but to also include:
all locations within 10 kilometers of a “swarm,” which is defined for purpose of the rule as two
earthquakes, at least one of which has a magnitude of at least 3.0, that are located within 0.25 miles of
each other; all locations within 3 miles of a seismically active fault; and all locations within 3 miles of
a stressed fault, whether or not there has been seismic activity. Applications for UIC permits in such
areas are subject to special review and if a permit is granted, it may be granted subject to special
conditions.
In March 2015, the Corporation Commission announced that in areas of interest, each operator
of an injection disposal well would be required to reduce injection rates by 50 percent unless the
operator demonstrated that it was not injecting below the Arbuckle formation. 200 The Commission
explained that disposal below the Arbuckle formation poses increased risk of inducing seismicity
because it puts injected fluid in communication with solid basement rock.201
8. Texas
In Texas, oil and gas activity and Class II injection wells are regulated by the Railroad
Commission. On October 28, 2014, the three members of the Commission unanimously adopted
revisions to Texas’ existing fluid injection regulations in order to address and minimize the risk of
induced seismicity.202 The new rule was published in the Texas Register on November 14, 2014). The
revisions, which became effective November 17, 2014, amend Texas Administrative Code Title 16 §§
3.9 and 3.46 to:
199

provide that any person applying for a permit for a new injection well to dispose of
saltwater or other oil and gas waste must include with his application information from the
U.S. Geological Survey seismic database regarding historical earthquake activity in a 100
square mile area around the proposed injection site (a circle with an area of 100 square
miles would have a radius of approximately 5.64 miles or 9.08 kilometers)203,

expressly state that the Commission staff has the authority to modify, suspend, or terminate
a disposal well permit if scientific data indicates that a disposal well has been determined to
Id.
200
See Media Advisory (from Oklahoma Corporation Commission) , available at
http://www.occeweb.com/News/2015/ADVISORY%20-%20TRAFFIC%20LIGHT.pdf.
201
Id.
202
A press release is available at: http://www.rrc.state.tx.us/all-news/102814b/. A memorandum adopted the
changes, signed by the three Commissioners, appears at: http://www.rrc.state.tx.us/media/24613/adopt-amend-39and3-46-seismic-activity-102814-sig.pdf.
203
The revision is codified at 16 Tex. Admin. Code § 3.9(3)(B) and § 3.46(b)(1)(C)
A-8
be contributing to seismic activity or is likely to be determined to be contributing to seismic
activity204

authorize Commission staff to require operators to report injection volumes and pressures
on a more frequent basis than the annual basis otherwise required if conditions exist that
increase the risk that fluids will not be contained in the “injection interval,”205 and

allow the Commission staff to require that an applicant for a new injection permit submit
information not otherwise required for a permit application, “such as logs, geologic crosssections, pressure front boundary calculations, and/or structure maps to demonstrate that
fluids will be confined” if the location proposed for the well is one where conditions exist
that increase the risk of non-containment.206
An earlier version of the proposed revisions would have required applicants to calculate the boundary
of the pressure front at which pressure would be elevated by five pounds per square inch (psi) (1 psi
equals 6894.76 Pascal’s) after ten years of operation at the maximum injection proposed in the permit
application. The Commission explained that ten years is the typical expected life of an injection
disposal well, that basing calculations on the maximum proposed daily injection rate was conservative,
and that 5 psi was toward the lower end of a 1.4 to 14 psi range recommended by some commentators
for an area for which it would be prudent to require submission of historical earthquake data. But
during the period for public comment on the proposed rules, several persons submitted comments
stating that pressure front calculations are subject to large uncertainties. In response to those
comments, the Commission revised the portion of the proposed rule requiring submission of historical
earthquake data to require that the data be provided for the area within a circle equal to 100 square
miles, centered at the proposed injection well site, instead of the area within the 5 psi, ten-year pressure
front.207
C. Canada
1. Alberta
On February 19, 2015, the Alberta Energy Regulator issued Subsurface Order No. 2, which
requires use of a “traffic light” system when hydraulic fracturing is to be performed in a particular
area.208 Under the order, a company holding a license to drill a well must assess the potential for
seismicity that might be induced by hydraulic fracturing operations before beginning any well
204
205
206
The revision is codified at 16 Tex. Admin. Code § 3.9(6)(A)(vi) and § 3.46(d)(1)(F)
The revision is codified at 16 Tex. Admin. Code § 3.9(11) and § 3.46(f)
The revision is codified at 16 Tex. Admin. Code § 3.9(3)(C) and § 3.46(b)(1)(D)
207
See October 21, 2014 memorandum from Christina Self to Texas Railroad Commissioners, available at:
http://www.rrc.state.tx.us/media/ 24613/adopt-amend-3-9and3-46-seismic-activity-102814-sig.pdf.
208
See Alberta Energy Regulator Subsurface Order No. 2, available at
https://www.aer.ca/documents/bulletins/AER-Bulletin-2015-07.pdf; see also News Release, AER responding to
seismic events in the Fox Creek area (Feb. 19, 2015), available at https://www.aer.ca/about-aer/mediacentre/news-releases/news-release-2015-02-19.
A-9
completion that will include hydraulic fracturing.209 The licensee must conduct monitoring that is
sufficient to detect any seismic event of 2.0 or larger that occurs within 5.0 km of the well. In addition,
the licensee must develop a plan for mitigating any seismicity that is above a magnitude of 2.0, and be
prepared to implement the plan.210
If the licensee detects or becomes aware that someone else has detected a seismic event of
magnitude 2.0 or greater within 5 km, the licensee must immediately notify AER and implement the
traffic light plan for mitigating seismicity. If the licensee detects or becomes aware that someone else
has detected a seismic event of magnitude 4.0 or greater within 5 km of the well, the licensee must
immediately notify AER and immediately halt its fracturing operations. 211 The hydraulic fracturing
operations cannot be resumed without AER’s written consent, and the AER is not allowed to grant its
consent unless the licensee develops and implements a plan that is acceptable to AER to modify
operations so as to eliminate or reduce future seismicity to a magnitude below 4.0.212
The AER issued its Subsurface Order No. 2 after two series of seismic events in the Fox Creek
area of Alberta – one cluster of 18 events in December 2014 that ranged between 2.7 and 3.7 in
magnitude and a set of several events in January 2015 that ranged between 2.4 and 4.4 in magnitude.213
The events were suspected of having been induced by hydraulic fracturing operations.
2. British Columbia
The British Columbia Oil & Gas Commission has written certain provisions relating to induced
seismicity into permits and has announced that it plans to incorporate those requirements into its
regulations.214 These include requirements for increased monitoring and reporting, and a requirement
that operations cease if an earthquake of magnitude 4.0 or greater is detected in the vicinity. 215
209
AER Subsurface Order No. 2.
210
Id.
211
Id.
212
Id.
AER Backgrounder on Seismicity in Alberta (Feb. 19, 2015), available at https://www.aer.ca/aboutaer/media-centre/news-releases/news-release-2015-02-19 (following press release).
213
214
215
B.C. Oil & Gas Commission, supra n. 120 at pp.18, 19, 21-2.
Id. at 21-2.
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Appendix B
Litigation involving Alleged Induced Seismicity or Concerns about Risks of Induced Seismicity
Litigants have raised injection-induced seismicity issues in numerous cases. Plaintiffs have brought suit
seeking damages for harms alleged caused by injection-induced seismicity in Arkansas, Oklahoma, and Texas.
Petitioners have sought review of EPA decisions granting underground injection permits in Michigan and
Pennsylvania. And plaintiffs have brought National Environmental Policy Act claims challenging actions of the
Bureau of Land Management in California and New Mexico. These cases are listed and summarized below.
A. Arkansas
1. 2010-2011 Guy-Greenbriar Earthquake Swarm Victims v. Chesapeake Operating, Inc., No. 23-CV23-14-84, Circuit Court Faulkner County, Judge H.G. Foster.
CAUSES OF ACTION: The plaintiffs purported to assert causes of action for public nuisance, private
nuisance, absolute liability (strict liability), negligence, trespass, deceptive trade practices, and outrage
(emotional distress).
DISPOSITION: An order dated March 21, 2014 dismissed the case with prejudice on plaintiff’s motion
for voluntary dismissal.
2. Sheatsley v. Chesapeake Operating, Inc., No. 4:11-CV-00353, United States District Court for the
Eastern District of Arkansas, Western Division, Judge Leon J. Holmes.
The plaintiffs filed this case as a putative class action in state court in Perry County. The case was
removed to federal court.
CAUSES OF ACTION: The plaintiffs purported to assert causes of action for public nuisance, private
nuisance, absolute liability (strict liability), negligence, and trespass.
DISPOSITION: An order dated July 13, 2011 granted the plaintiff’s motion to dismiss without
prejudice.
3. Hearn v. BHP Billiton Petroleum, No. 4:11-CV-00474, United States District Court for the Eastern
District of Arkansas, Western Division, Judge Leon J. Holmes.
The plaintiffs filed this case as a putative class action in state court in Faulkner County. The case was
removed to federal court. Certain other actions were consolidated with Hearn.
CAUSES OF ACTION: The plaintiffs purported to assert causes of action for public nuisance, private
nuisance, absolute liability (strict liability), negligence, and trespass.
DISPOSITION: An order dated August 29, 2013 dismissed the action with prejudice.
4. Frey v. BHP Billiton Petroleum, No. 4:11-CV-00475, United States District Court for the Eastern
District of Arkansas, Western Division, Judge Leon J. Holmes.
The plaintiffs filed this case as a putative class action in state court in Faulkner County. The case was
removed to federal court. This case originally was consolidated with Hearn v. BHP Billiton Petroleum,
No. 4:11-CV-00474, but then later was de-consolidated from it and consolidated with Mahan v.
Chesapeake Operating, Inc., No. 4:13-CV-0184.
CAUSES OF ACTION: The plaintiffs purported to assert causes of action for public nuisance, private
nuisance, absolute liability (strict liability), negligence, and trespass.
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DISPOSITION: An order dated March 20, 2014 dismissed the case with prejudice on plaintiff’s motion
for voluntary dismissal.
5. Palmer v. BHP Billiton Petroleum, No. 4:11-CV-00476, United States District Court for the Eastern
District of Arkansas, Western Division, Judge Leon J. Holmes.
The plaintiffs originally filed this as a putative class action in state court. The case was removed to
federal court and consolidated with Hearn v. BHP Billiton Petroleum, No. 4:11-CV-00474.
CAUSES OF ACTION: The plaintiffs purported to assert causes of action for public nuisance, private
nuisance, absolute liability (strict liability), negligence, and trespass.
DISPOSITION: An order dated November 18, 2012 granted the Palmer plaintiffs’ motion to dismiss the
case without prejudice.
6. Lane v. BHP Billiton Petroleum, No. 4:11-CV-00477, United States District Court for the Eastern
District of Arkansas, Western Division, Judge Leon J. Holmes
The plaintiffs originally filed this as a putative class action in state court. The case was removed to
federal court and consolidated with Hearn v. BHP Billiton Petroleum, No. 4:11-CV-00474.
CAUSES OF ACTION: The plaintiffs purported to assert causes of action for public nuisance, private
nuisance, absolute liability (strict liability), negligence, and trespass.
DISPOSITION: An order dated November 18, 2012 granted the Lane plaintiffs’ motion to dismiss the
case without prejudice.
7. Miller v. Chesapeake Operating, Inc., No. 4:13-CV-00131, United States District Court for the
Eastern District of Arkansas, Western Division, Judge Leon J. Holmes
CAUSES OF ACTION: The plaintiffs purported to assert causes of action for public nuisance, private
nuisance, absolute liability (strict liability), negligence, trespass, deceptive trade practices, and outrage
(emotional distress).
DISPOSITION:
An order dated March 20, 2014 dismissed the case with prejudice on plaintiff’s
motion for voluntary dismissal.
8. Thomas v. Chesapeake, Operating, Inc., No. 4:13-CV-0184, United States District Court for the
Eastern District of Arkansas, Western Division, Judge Leon J. Holmes
CAUSES OF ACTION: The plaintiffs purported to assert causes of action for public nuisance, private
nuisance, absolute liability (strict liability), negligence, trespass, deceptive trade practices, and outrage
(emotional distress).
DISPOSITION: An order dated March 20, 2014 dismissed the case with prejudice on plaintiff’s motion
for voluntary dismissal.
9. Mahan v. Chesapeake Operating, Inc., No. 4:13-CV-0184, United States District Court for the
Eastern District of Arkansas, Western Division, Judge Leon J. Holmes
CAUSES OF ACTION: The plaintiffs purported to assert causes of action for public nuisance, private
nuisance, absolute liability (strict liability), negligence, trespass, deceptive trade practices, and outrage
(emotional distress).
DISPOSITION: An order dated March 20, 2014 dismissed the case with prejudice on plaintiff’s motion
for voluntary dismissal.
10. Davis v. Chesapeake Operating, Inc., No. 4:14-CV-00081, United States District Court for the
Eastern District of Arkansas, Western Division, Judge Leon J. Holmes
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CAUSES OF ACTION: The plaintiffs purported to assert causes of action for public nuisance, private
nuisance, absolute liability (strict liability), negligence, trespass, deceptive trade practices, and outrage
(emotional distress).
DISPOSITION: An order dated March 20, 2014 dismissed the case with prejudice on plaintiff’s motion
for voluntary dismissal.
B. California
1. Center for Biological Diversity v. Bureau of Land Management, No. 2:15-CV-04378, United States
District for the Central District of California, Western Division, Judge Michael W. Fitzgerald (and
Magistrate Judge John E. McDermott)
CLAIMS: In June 2015, the Center for Biological Diversity brought suit challenging the BLM’s adoption
of a management plan and its approval of an Environmental Impact Statement. The management plan
would allow for the possibility of oil and gas exploration and production on certain federal lands. The
Center for Biological Diversity argues that BLM breached its obligations under the National
Environmental Policy Act by failing to take the required “hard look” at the impact that oil and gas
activities would have on the environment.
DISPOSITION: The case is pending.
C. Michigan
1. In re: Environmental Disposal Systems, 2005 WL 2206804 (EPA Env. App. Bd.)
EPA Region 5 granted two Class I permits for injection disposal of hazardous wastes (a Class I permit is
not for the oil and gas industry). Citizens challenged the permits, in part based on induced seismicity
concerns.
DISPOSITION: The permit challenges were denied.
2. In re: Envotech LP, 1996 WL 66307 (EPA Env. App. Bd.)
EPA Region 5 granted a Class I permit for the underground injection and disposal of hazardous waste (a
Class I permit is not a permit for the oil and gas industry). A citizen challenged the permit, in part based
on induced seismicity concerns.
DISPOSITION: The Environmental Appeals Board rejected the citizen’s induced seismicity arguments,
but remanded the permit to Region 5 for other reasons.
3. In re: West Bay Exploration Co., 2014 WL 3236950 (EPA Env. App. Bd.)
EPA Region 5 granted a Class II permit for an injection disposal well. A citizen challenged the decision
to grant the permit, asserting various grounds, including the possibility that the injection operations would
induce seismic activity.
DISPOSITION: The Environmental Appeals Board rejected the challenge.
D. New Mexico
1. Diné Citizens Against Ruining Our Environment v. Jewell, 1:2015-CV-00209 (D. N.M.), Judge James
O. Browning (and Magistrate Judge Steven C. Yarbrough)
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CLAIMS: Citizens groups brought suit in March 2015, challenging the Bureau of Land Management’s
grant of numerous permits to drill in the Mancos Shale in New Mexico. The groups claim that oil and gas
activity and hydraulic fracturing will cause various harms and that injection disposal could induce
earthquakes. The groups claim that such earthquakes could damage pueblo walls present in the Chaco
Culture National Historic Park. The groups assert that the BLM violated its obligations under the
National Environmental Policy Act by failing to take a “hard look” at environmental impacts and that
BLM’s actions also are inconsistent with the National Historic Preservation Act.
DISPOSITION: The case is pending.
E. Oklahoma
1. Ladra v. New Dominion, LLC, No. CJ-2014-115, District Court for Lincoln County, Judge Cynthia
Ferrell Ashwood
The plaintiff filed suit, alleging that she suffered personal injuries and property damages that were caused
by an earthquake that was induced by operation of an injection disposal well.
CAUSES OF ACTION: The plaintiff purported to assert claims in absolute liability (strict liability) and
negligence.
DISPOSITION: The district court dismissed, holding that the Oklahoma Corporation Commission has
primary jurisdiction to hear a complaint relating to a disposal well for which the Commission has granted
a permit. In a unanimous decision issued on July 2, 2015, the Oklahoma Supreme Court reversed the trial
court’s judgment and ruled that the plaintiff’s case could proceed in court. The Oklahoma Supreme Court
stated that the Corporation Commission has exclusive jurisdiction over the regulation of injection disposal
wells, but that the Commission does not have jurisdiction to hear a private tort claim such as the
plaintiff’s. Accordingly, after passage of the defendants’ time to seek rehearing, or after the denial of a
motion for rehearing if such a motion is filed, the case will return to district court.
2. Cooper v. New Dominion, LLC, No. CJ-2015-24, District Court for Lincoln County, Judge Cynthia
Ferrell Ashwood
The plaintiff filed a putative class action.
CAUSES OF ACTION: The plaintiff purported to assert causes of action for private nuisance, absolute
liability (strict liability), negligence, and trespass.
DISPOSITION: The case currently is under a stay, issued pursuant to the plaintiff’s motion. The plaintiff
sought the stay in order to wait to see how the Oklahoma Supreme Court resolved the district court’s
decision in Ladra that primary jurisdiction was with the Oklahoma Corporation Commission. Now that
the Oklahoma Supreme Court has reversed the district court and held that Ladra can proceed in court, the
stay in Cooper likely will be lifted.
F. Pennsylvania
1. In re: Bear Lake Properties, 2012 WL 2586960 (EPA Env. App. Bd.)
EPA Region 3 issued a permit for a Class II underground injection disposal well. Citizens challenged the
permit on various grounds, including an argument that Region 3 had not properly considered the local
geology and the risk that injection operations would induce seismic activity.
DISPOSITION: The Environmental Appeals Board held that that the citizens “failed to meet their heavy
burden of demonstrating that the Region erred in making its technical and scientific determination
regarding the threat of injection-related seismic activity.” With respect to other issues, the Environmental
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Appeals Board held that Region 3 had not articulated its reasoning in the record. Accordingly, the
Environmental Appeals Board remanded the matter to Region 3 to give it a chance to explain its
reasoning.
2. In re: Stonehaven Energy Mgt., LLC, 2013 WL 7216489 (EPA Env. App. Bd.)
EPA Region 3 issued a permit for a Class II underground injection disposal well. A citizen challenged
the permit, arguing that Region 3 had not properly considered the local geology and the risk that injection
operations would induce seismic activity.
DISPOSITION: The Environmental Appeals Board held that Region 3 had not articulated in the record its
reasoning with respect to geology and seismic risk. Accordingly, the Environmental Appeals Board
remanded the matter to Region 3 to give it a chance to explain its reasoning.
3. In re: Seneca Resources Corp., 2014 WL 2465785 (EPA Env. App. Bd.)
EPA Region 3 granted a permit for a Class II injection disposal well. Three petitioners challenged the
permit. One argument that they raised related to induced seismicity.
DISPOSITION: The Environmental Appeals Board rejected the three petitioners’ challenges – one for
lack of standing, one for lack of specificity, and one for untimeliness.
4. In re: Windfall Oil & Gas, Inc., 2015 WL 3782844 (EPA Env. App. Bd.)
EPA Region 3 issued a permit for a Class II underground injection disposal well. Citizens challenged the
permit on various grounds, including an argument that Region 3 had not properly considered the local
geology and the risk that injection operations would induce seismic activity.
DISPOSITION: The Environmental Appeals Board rejected the challenge in its entirety.
G. Texas
1. Finn v. EOG Resources, Inc., No. C2013-00343, Johnson County District Court, Judge John Neill
CAUSES OF ACTION: The plaintiffs purport to assert causes of action in negligence, nuisance, and strict
liability.
DISPOSITION: The case is pending.
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