[Senate Hearing 112-532]
[From the U.S. Government Publishing Office]
S. Hrg. 112-532
INDUCED SEISMICITY FROM ENERGY TECHNOLOGIES
=======================================================================
HEARING
before the
COMMITTEE ON
ENERGY AND NATURAL RESOURCES
UNITED STATES SENATE
ONE HUNDRED TWELFTH CONGRESS
SECOND SESSION
TO
RECEIVE TESTIMONY ON THE POTENTIAL FOR INDUCED SEISMICITY FROM ENERGY
TECHNOLOIGES, INCLUDING CARBON CAPTURE AND STORAGE, ENHANCED GEOTHERMAL
SYSTEMS, PRODUCTION FROM GAS SHALES, AND ENHANCED OIL RECOVERY
__________
JUNE 19, 2012
Printed for the use of the
Committee on Energy and Natural Resources
_____
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75-820 PDF WASHINGTON : 2012
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COMMITTEE ON ENERGY AND NATURAL RESOURCES
JEFF BINGAMAN, New Mexico, Chairman
RON WYDEN, Oregon LISA MURKOWSKI, Alaska
TIM JOHNSON, South Dakota JOHN BARRASSO, Wyoming
MARY L. LANDRIEU, Louisiana JAMES E. RISCH, Idaho
MARIA CANTWELL, Washington MIKE LEE, Utah
BERNARD SANDERS, Vermont RAND PAUL, Kentucky
DEBBIE STABENOW, Michigan DANIEL COATS, Indiana
MARK UDALL, Colorado ROB PORTMAN, Ohio
JEANNE SHAHEEN, New Hampshire JOHN HOEVEN, North Dakota
AL FRANKEN, Minnesota DEAN HELLER, Nevada
JOE MANCHIN, III, West Virginia BOB CORKER, Tennessee
CHRISTOPHER A. COONS, Delaware
Robert M. Simon, Staff Director
Sam E. Fowler, Chief Counsel
McKie Campbell, Republican Staff Director
Karen K. Billups, Republican Chief Counsel
C O N T E N T S
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STATEMENTS
Page
Bingaman, Hon. Jeff, U.S. Senator From New Mexico................ 1
Hitzman, Murray W., Charles Fogarty, Professor of Economic
Geology, Department of Geology and Geological Engineering,
Colorado School of Mines, Golden, CO........................... 3
Leith, William, Senior Science Advisor for Earthquake and
Geologic Hazards, U.S. Geological Survey Department of the
Interior....................................................... 10
Murkowski, Hon. Lisa, U.S. Senator From Alaska................... 2
Petty, Susan, President and Chief Technology Officer, Alta Rock
Energy, Inc, Seattle, WA....................................... 15
Zoback, Mark D., Benjamin M. Page Professor of Earth Sciences,
Department of Geophysics, Stanford University, Stanford, CA.... 33
APPENDIX
Responses to additional questions................................ 49
INDUCED SEISMICITY FROM ENERGY TECHNOLOGIES
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TUESDAY, JUNE 19, 2012
U.S. Senate,
Committee on Energy and Natural Resources,
Washington, DC.
The committee met, pursuant to notice, at 10:03 a.m. in
room SD-366, Dirksen Senate Office Building, Hon. Jeff
Bingaman, chairman, presiding.
OPENING STATEMENT OF HON. JEFF BINGAMAN, U.S. SENATOR FROM NEW
MEXICO
The Chairman. OK. Why don't we get started? Senator
Murkowski is delayed a very few minutes here, but asked us to
go ahead and proceed.
Welcome everyone to the hearing. This is on the potential
for inducing manmade earthquakes from energy technologies. Many
of the current and next generation energy technologies that are
vital to our country's future require the injection of fluids
like water and carbon dioxide or other mixtures deep into the
Earth's subsurface.
Geothermal energy extraction, geological carbon
sequestration, the injection of waste water from hydraulic
fracturing and enhanced oil recovery all require the injection
and movement of fluids deep underground. Scientists have known
for many decades that one potential side effect of pumping
fluids in or out of the Earth is the creation of small to
medium sized earthquakes. Though only a small number of recent
seismic events here and abroad have been definitely linked to
energy development, public concern has been raised about the
potential for manmade earthquakes after seismic events that
were felt in Arkansas and Oklahoma and Ohio and other places in
the country. Those events in some cases were located near
energy development and waste disposal sites.
In 2010 I asked Secretary Chu to initiate a comprehensive
and independent study by the National Academy of Sciences and
the National Academy of Engineering to examine the possible
scale, scope and consequences of seismicity induced by energy
technologies. In particular, I asked them to focus on the
potential for induced seismicity from enhanced geothermal
systems, production from gas shales, enhanced oil recovery and
carbon capture and storage.
The Academy released their report this past Friday. The
results provide a timely assessment of the potential hazards
and risks of induced seismicity potential posed by these energy
technologies. I want to thank the members of the Study
Committee, the staff of the National Academies and all of those
associated with putting together this important report for
their very hard work.
The National Academy of Science's Committee found that of
all the energy related injection and extraction activities
conducted in the United States only a small percentage have
created earthquakes at levels noticeable to humans. None have
caused significant damage to life or property.
The committee also determined that because hydraulic
fracturing for natural gas development typically involves the
injection of relatively small amounts of fluid into localized
areas. Hydraulic fracturing, itself, rarely triggers
earthquakes large enough to be felt. Activities that inject
greater amounts of fluid over longer periods of time, however,
such as the injection of drilling waste water, pose a greater
risk for causing noticeable earthquakes.
Recent data from USGS suggests that the rate of earthquakes
in the U.S. mid-continent has increased significantly in the
past decade. The locations of these earthquakes are near many
oil and gas extraction operations. As a result have raised
public concern that they are the result of underground
injection of drilling waste water.
The study also indicates that injection and storing--
injecting and storing vast amounts of carbon dioxide in the
subsurface may pose a risk for seismicity that needs to be
better understood and quantified through research.
The discussion we're having today is an important and
timely one. As the National Academy's report indicates risk
from manmade earthquakes associated with energy technologies
has been minimal and provided appropriate proactive measures
are taken, may be effectively managed for the future. I look
forward to hearing more about the topic from our panel of
expert witnesses here.
Let me defer to Senator Murkowski for any comments she has
before I introduce the witnesses.
STATEMENT OF HON. LISA MURKOWSKI, U.S. SENATOR
FROM ALASKA
Senator Murkowski. Thank you, Mr. Chairman and good morning
to all of our witnesses today. I do look forward to your
testimony also.
Over the past year or so I think we've all seen some of the
trade press articles about issues of induced seismicity. While
some of the headlines might look a bit sensational, it did seem
that the true risk in reality is actually quite remote. But as
such it's good to get a reality check from the experts. That's
why you have been invited here today.
The headline on this study from the NAS reads, ``Federal
Research concludes quake risk from drilling low, avoidable.''
This covers geothermal wells, oil and gas wells and waste water
wells. Really the unfortunate thing here is that the headline
associates this report with drilling when drilling is perhaps
not the issue so much as the actual permanent injection of
waste water or carbon into an area where the pressures have
become destabilized and some vibration then occurs.
I think it's good news that most of the seismic activity
under discussion here, even with the hundreds of thousands of
areas energy projects at play, have been quite small and often
barely noticeable to humans. None of this is to say that anyone
should be dismissive of this discussion. I think we all know
that energy development of all sources and in all places does
have attendant risks and impacts. It's not surprising to me to
see that injecting and removing large volumes of fluids and
gases underground might, under some conditions, cause
vibrations to be felt above the ground. The question is whether
that sort of seismicity is avoidable and manageable.
The study that we're looking at seems to indicate the
answer is yes, which is also not surprising. But I'm interested
to hear our other witnesses? views on the study. Since the
study was only released on Friday, I realize that you may have
more to say once you've had more time to actually study it
carefully. But I do look forward to your initial impressions
today.
With that, I thank the Chairman.
The Chairman. Thank you very much.
Let me introduce our witnesses.
First will be Dr. Murray Hitzman, who is a Professor with
Colorado School of Mines. He's also Chairman of the National
Academy's Committee that has prepared this report. So we thank
you again for that heroic effort.
Dr. William Leith is the Senior Science Advisor for
Earthquake and Geologic Hazards with the Geological Survey.
Ms. Susan Petty is President and Chief Technology Officer
with Altarock Energy. Thank you very much for being here.
Dr. Mark Zoback is a Professor at Stanford. He's testified
here before and we welcome him back.
Dr. Hitzman, why don't you go right ahead?
If each of you could take 5 or 6 minutes and tell us the
main points you think we need to try to understand. Then we
will undoubtedly have questions.
STATEMENT OF MURRAY W. HITZMAN, CHARLES FOGARTY PROFESSOR OF
ECONOMIC GEOLOGY, DEPARTMENT OF GEOLOGY AND GEOLOGICAL
ENGINEERING, COLORADO SCHOOL OF MINES, GOLDEN, CO
Mr. Hitzman. Thank you very much.
Chairman Bingaman, Ranking Member Murkowski and members of
the committee, thank you for the invitation to address you.
Although the vast majority of earthquakes that occur in the
world each year have natural causes, some of these earthquakes
and a number of lesser magnitude seismic events are related to
human activities and are called induced seismic events or
induced earthquakes. Since the 1920s we have recognized that
pumping fluids into or out of the Earth has the potential to
cause seismic imbalance that can be felt. Only a very small
fraction of injection and extraction activities at hundreds of
thousands of energy development sites in the U.S. have induced
seismicity at levels that are noticeable to the public.
However, seismic events caused by or likely related to
energy developments have been measured and felt in a number of
States. Although none of these events has resulted in loss of
life or significant structural damage, their effects were felt
by local residents, some of whom also experienced minor
property damage. Anticipating public concern about the
potential for induced seismicity related to energy development,
Chairman, Senator Bingaman, did request from DOE that they
conduct a study of this issue through the National Research
Council.
The committee that wrote the NRC report released last
Friday consisted of 11 experts in various aspects of seismicity
and energy technologies from both academia and industry.
The committee found that induced seismicity associated with
fluid injection or withdrawal associated with energy
development is caused, in most cases, by a change in pore
pressure and/or change in stress in the subsurface in the
presence of faults with specific properties and orientations
and a critical state of stress in the rocks. The factor that
appears to have the most direct consequence in regard to
induced seismicity is the net fluid balance or put more simply,
the total balance of fluid either introduced or taken out from
the subsurface. Additional factors may also influence the way
fluids affect the subsurface.
The committee concluded that while the general mechanisms
that create induced seismic events are well understood. We are
currently unable to accurately predict the magnitude or
occurrence of such events due to the lack of a comprehensive
data on complex natural rocks or systems in the subsurface and
the lack of validated predictive models.
The committee found for the largest induced seismic events
associated with energy projects were those that did not balance
the large volumes of fluids injected into or extracted from the
Earth. We emphasize this is a statistical observation. It
suggests, however, that the net volume of fluid that is
injected and/or extracted may serve as a proxy for the changes
in subsurface stress conditions in pore pressure.
I'm going to briefly discuss the induced seismicity
potential now for each of the energy technologies that was
asked for in the report.
Although it felt induced seismicity has been documented
with the development of geothermal resources, such development
usually attempts to keep a mass balance between fluid volumes
produced and fluids replaced by injection to extend the
longevity of the energy resource. This fluid balance helps to
maintain fairly constant reservoir pressure, close to the
initial preproduction value and aids in reducing the potential
for induced seismicity.
Oil and gas extraction from a reservoir may cause induced
seismic events. These events are rare, relative to the large
number of oil and gas fields around the world and appear to be
related to decrease in pore pressure as fluid has been drawn.
Secondary recovery and enhanced oil recoveries or EOR for
oil and gas production both involve injection of fluids into
the subsurface to push more of the hydrocarbons out of the pore
spaces and to maintain reservoir pressure. Approximately
151,000 injection wells are currently permitted in the U.S.
For a combination of secondary recovery EOR and waste water
disposal with only a very few documented incidents where the
injection caused or is likely related to felt seismic events.
Among the tens of thousands of wells used for enhanced oil
recovery in the U.S. the committee did not find any
documentation in the published literature of felt induced
seismicity.
Shale formations also contain hydrocarbons. The extremely
low permeability of these rocks has trapped the hydrocarbons
and prevented them from migrating from the rock. The low
permeability also prevents the hydrocarbons from easily flowing
into a well bore without production stimulation.
These types of unconventional reservoirs are developed by
drilling rails horizontally through the reservoir rock and
using hydraulic fracturing techniques to create new fractures
in the reservoir to allow us to get the hydrocarbons out. About
35,000 hydraulically fractured shale wells exist in the U.S.
Only one case of felt seismicity in the United States has been
described in which hydraulic fracturing for shale gas
development is suspected but not confirmed. Globally, one case
of felt induced seismicity in Blackpool, England has been
confirmed as being caused by hydraulic fracturing for shale gas
development.
The very low number of felt events relative to the large
number of hydraulically fractured wells for shale gas is likely
due to the short duration of injection of fluids and the
limited fluid volumes used.
In addition to the fluid injection directly related to
energy development, injection wells drilled to dispose of waste
water generated during oil and gas production are very common
in the United States. Tens of thousands of waste water disposal
wells are currently active. Although only a few induced seismic
events have been linked to these disposal wells, the occurrence
of these events has generated considerable public concern.
Examination of these cases suggest casual links between the
injection zones and previously unrecognized faults in the
subsurface. Injection wells are used only for the purpose of
waste water disposal normally do not have a detailed geologic
review performed prior to injection and the data are often not
available to make such a detailed review. Thus the location of
the possible nearby faults is often not a standard part of
citing and drilling these disposal wells. In addition, the
presence of a fault does not necessarily imply an increased
potential for induced seismicity.
The majority of hazardous and non-hazardous waste water
disposal wells do not pose a hazard for induced seismicity.
However, the long term affects of any significant increases in
the number of waste water disposal wells in a particular area
on induced seismicity are unknown.
Carbon capture and sequestration or CCS is also a means of
disposing of fluids in the subsurface. The committee found that
the risk of induced seismicity from CCS is currently difficult
to accurately assess. With only a few small scale commercial
projects overseas and several small demonstration projects
underway in the U.S., there are few data available to evaluate
the induced seismicity potential of this technology.
The existing projects have involved relatively small
injection volumes. CCS differs from the other energy
technologies in that it involves continuous injection of carbon
dioxide fluid at high rates, under pressure, for long periods
of time. It is purposely intended for permanent storage.
There's no fluid withdrawal.
Given that the potential magnitude from induced seismic
event correlates strongly with a fault rupture area. Which in
turn relates to the magnitude of pore pressure change and the
rock volume which exists, the committee determined that large
scale CCS may have the potential for causing significant
induced seismicity.
The committee also investigated governmental responses to
induced seismic events. Responses have been undertaken by a
number of Federal and State agencies in a variety of ways. To
date, Federal and State agencies have dealt with induced
seismic events with different and localized actions.
These actions have been successful, but they've been ad hoc
in nature. With the potential for increased numbers of induced
seismic events due to expanding energy development governmental
agencies and research institutions may not have sufficient
resources to address unexpected events. The committee concluded
that forward looking, interagency cooperation to address
potential induced seismicity is warranted.
Methodologies can be developed for quantitative
probabilistic hazard assessments of induced seismicity risk.
The committee determined that such assessments should be
undertaken before operations begin in areas with a known
history of felt seismicity and updated in response to observed,
potentially induced events. The committee suggested that
practices that consider induced seismicity both before and
during the actual operations of an energy project should be
employed to develop best practices protocols specific to each
of the energy technologies and to site location.
Although induced seismic events have not resulted in loss
of life or major damage to the U.S., their effects have been
felt locally and they raise some concern about additional
seismic activity and its consequences in areas where energy
development is ongoing or planned. Further research is required
to better understand and address the potential risks associated
with induced seismicity.
I'd like to thank the committee for its time and its
interest in this subject. I request the balance of my written
testimony be placed in the record. I certainly look forward to
your questions.
[The prepared statement of Mr. Hitzman follows:]
Prepared Statement of Murray W. Hitzman, Charles Fogarty Professor of
Economic Geology, Department of Geology and Geological Engineering,
Colorado School of Mines, Golden, CO
Chairman Bingaman, Ranking Member Murkowski, and members of the
committee, I would like to thank you for the invitation to address you
on the subject of induced seismicity potential in energy technologies.
My name is Murray Hitzman. I am a professor of geology at the Colorado
School of Mines in Golden, Colorado and served as the chair of the
National Research Council Committee on Induced Seismicity Potential in
Energy Technologies. The Research Council is the operating arm of the
National Academy of Sciences, National Academy of Engineering, and the
Institute of Medicine of the National Academies, chartered by Congress
in 1863 to advise the government on matters of science and technology.
I would like to thank the committee for the invitation to address it on
the subject of induced seismicity potential in energy technologies.
Although the vast majority of earthquakes that occur in the world
each year have natural causes, some of these earthquakes and a number
of lesser magnitude seismic events are related to human activities and
are called ``induced seismic events'' or ``induced earthquakes.''
Induced seismic activity has been attributed to a range of human
activities including the impoundment of large reservoirs behind dams,
controlled explosions related to mining or construction, and
underground nuclear tests. Energy technologies that involve injection
or withdrawal of fluids from the subsurface can also create induced
seismic events that can be measured and felt.
Since the 1920s we have recognized that pumping fluids into or out
of the Earth has the potential to cause seismic events that can be
felt. Only a very small fraction of injection and extraction activities
at hundreds of thousands of energy development sites in the United
States have induced seismicity at levels that are noticeable to the
public. However, seismic events caused by or likely related to energy
development have been measured and felt in Alabama, Arkansas,
California, Colorado, Illinois, Louisiana, Mississippi, Nebraska,
Nevada, New Mexico, Ohio, Oklahoma, and Texas. Although none of these
events resulted in loss of life or significant structural damage, their
effects were felt by local residents, some of whom also experienced
minor property damage. Particularly in areas where natural seismic
activity is uncommon and energy development is ongoing, these induced
seismic events, though small in scale, can be disturbing to the public
and raise concern about increased seismic activity and its potential
consequences.
Anticipating public concern about the potential for induced
seismicity related to energy development, the Chairman of this
Committee, Senator Bingaman, requested that the Department of Energy
conduct a study of this issue through the National Research Council.
The Chairman requested that this study examine the scale, scope, and
consequences of seismicity induced during the injection of fluids
related to energy production. The energy technologies to be considered
included geothermal energy development, oil and gas production,
including enhanced oil recovery and shale gas, and carbon capture and
storage or CCS. The study was also to identify gaps in knowledge and
research needed to advance the understanding of induced seismicity; to
identify gaps in induced seismic hazard assessment methodologies and
the research needed to close those gaps; and to assess options for
interim steps toward best practices with regard to energy development
and induced seismicity potential. The National Research Council (NRC)
released the report Induced Seismicity Potential in Energy Technologies
on June 15.
The committee that wrote this NRC report consisted of eleven
experts in various aspects of seismicity and energy technologies from
academia and industry. The committee examined peer-reviewed literature,
documents produced by federal and state agencies, online databases and
resources, and information requested from and submitted by external
sources. We heard from government and industry representatives. We also
talked with members of the public familiar with the world's largest
geothermal operation at The Geysers at a public meeting in Berkeley,
California. We also spoke to people familiar with shale gas
development, enhanced oil recovery, waste water disposal from energy
development, and CCS at meetings in Dallas, Texas and Irvine,
California. Meetings were also held in Washington, D.C. and Denver,
Colorado to explore induced seismicity in theory and in practice.
This study took place during a period in which a number of small,
felt seismic events occurred that were likely related to fluid
injection for energy development. Because of their recent occurrence,
peer-reviewed publications about most of these events were generally
not available. However, knowing that these events and information about
them would be anticipated in this report, the committee attempted to
identify and seek information from as many sources as possible to gain
a sense of the common factual points involved in each instance, as well
as the remaining, unanswered questions about these cases. Through this
process, the committee has engaged scientists and engineers from
academia, industry, and government because each has credible
information to add to better understanding of induced seismicity.
The committee found that induced seismicity associated with fluid
injection or withdrawal associated with energy development is caused in
most cases by change in pore fluid pressure and/or change in stress in
the subsurface in the presence of faults with specific properties and
orientations and a critical state of stress in the rocks. The factor
that appears to have the most direct consequence in regard to induced
seismicity is the net fluid balance or put more simply, the total
balance of fluid introduced into or removed from the subsurface.
Additional factors may also influence the way fluids affect the
subsurface. The committee concluded that while the general mechanisms
that create induced seismic events are well understood, we are
currently unable to accurately predict the magnitude or occurrence of
such events due to the lack of comprehensive data on complex natural
rock systems and the lack of validated predictive models.
The committee found that the largest induced seismic events
associated with energy projects reported in the technical literature
are associated with projects that did not balance the large volumes of
fluids injected into, or extracted from, the Earth. We emphasize that
this is a statistical observation. It suggests, however, that the net
volume of fluid that is injected and/or extracted may serve as a proxy
for changes in subsurface stress conditions and pore pressure. The
committee recognizes that coupled thermo-mechanical and chemo-
mechanical effects may also play a role in changing subsurface stress
conditions.
I will briefly discuss the potential for induced seismicity with
each of the energy technologies that the committee considered,
beginning with geothermal energy.
Geothermal Energy
The three different types of geothermal energy resources are: (1)
``vapor-dominated'', where primarily steam is contained in the pores or
fractures of hot rock, (2) ``liquid-dominated'', where primarily hot
water is contained in the rock, and (3) ``Enhanced Geothermal Systems''
(EGS), where the resource is hot, dry rock that requires engineered
stimulation to allow fluid movement for commercial development.
Although felt induced seismicity has been documented with all three
types of geothermal resources, geothermal development usually attempts
to keep a mass balance between fluid volumes produced and fluids
replaced by injection to extend the longevity of the energy resource.
This fluid balance helps to maintain fairly constant reservoir
pressure-close to the initial, pre-production value-and aids in
reducing the potential for induced seismicity.
Seismic monitoring at liquid-dominated geothermal fields in the
western United States has demonstrated relatively few occurrences of
felt induced seismicity. However, in vapor or steam dominated
geothermal system at The Geysers in northern California, the large
temperature difference between the injected fluid and the geothermal
reservoir results in significant cooling of the hot subsurface
reservoir rocks. This has resulted in a significant amount of observed
induced seismicity. EGS technology is in the early stages of
development. Many countries including the United States have pilot
projects to test the potential for commercial production. In each case
of active EGS development, at least some, generally minor levels of
felt induced seismicity have been recorded.
Conventional Oil & Gas
Oil and gas extraction from a reservoir may cause induced seismic
events. These events are rare relative to the large number of oil and
gas fields around the world and appear to be related to decrease in
pore pressure as fluid is withdrawn.
Oil or gas reservoirs often reach a point when insufficient
pressure exists to allow sufficient hydrocarbon recovery. Various
technologies, including secondary recovery and tertiary recovery--also
called enhanced oil recovery or EOR--can be used to extract some of the
remaining oil and gas. Secondary recovery and EOR technologies both
involve injection of fluids into the subsurface to push more of the
trapped hydrocarbons out of the pore spaces in the reservoir and to
maintain reservoir pore pressure. Secondary recovery often uses water
injection or ``waterflooding'' and EOR technologies often inject carbon
dioxide. Approximately 151,000 injection wells are currently permitted
in the United States for a combination secondary recovery, EOR, and
waste water disposal with only very few documented incidents where the
injection caused or was likely related to felt seismic events.
Secondary recovery-through waterflooding-has been associated with very
few felt induced seismic events. Among the tens of thousands of wells
used for EOR in the United States, the committee did not find any
documentation in the published literature of felt induced seismicity.
Shale Gas
Shale formations can also contain hydrocarbons-gas and/or oil. The
extremely low permeability of these rocks has trapped the hydrocarbons
and largely prevented them from migrating out of the rock. The low
permeability also prevents the hydrocarbons from easily flowing into a
well bore without production stimulation by the operator. These types
of ``unconventional'' reservoirs are developed by drilling wells
horizontally through the reservoir rock and using hydraulic fracturing
techniques to create new fractures in the reservoir to allow the
hydrocarbons to migrate up the well bore. This process is now commonly
referred to as ``fracking.'' About 35,000 hydraulically fractured shale
gas wells exist in the United States. Only one case of felt seismicity
in the United States has been described in which hydraulic fracturing
for shale gas development is suspected, but not confirmed. Globally
only one case of felt induced seismicity at Blackpool, England has been
confirmed as being caused by hydraulic fracturing for shale gas
development. The very low number of felt events relative to the large
number of hydraulically fractured wells for shale gas is likely due to
the short duration of injection of fluids and the limited fluid volumes
used in a small spatial area.
Waste Water Disposal
In addition to fluid injection directly related to energy
development, injection wells drilled to dispose of waste water
generated during oil and gas production, including during hydraulic
fracturing, are very common in the United States. Tens of thousands of
waste water disposal wells are currently active throughout the country.
Although only a few induced seismic events have been linked to these
disposal wells, the occurrence of these events has generated
considerable public concern. Examination of these cases suggests causal
links between the injection zones and previously unrecognized faults in
the subsurface.
In contrast to wells for EOR which are sited and drilled for
precise injection into well-characterized oil and gas reservoirs,
injection wells used only for the purpose of waste water disposal
normally do not have a detailed geologic review performed prior to
injection and the data are often not available to make such a detailed
review. Thus, the location of possible nearby faults is often not a
standard part of siting and drilling these disposal wells. In addition,
the presence of a fault does not necessarily imply an increased
potential for induced seismicity. This creates challenges for the
evaluation of potential sites for disposal injection wells that will
minimize the possibility for induced seismic activity.
Most waste water disposal wells typically involve injection at
relatively low pressures into large porous aquifers that have high
natural permeability, and are specifically targeted to accommodate
large volumes of fluid. Of the well-documented cases of induced
seismicity related to waste water fluid injection, many are associated
with operations involving large amounts of fluid injection over
significant periods of time. Thus, although a few occurrences of
induced seismic activity associated with waste water injection have
been documented, the majority of the hazardous and nonhazardous waste
water disposal wells do not pose a hazard for induced seismicity.
However, the long-term effects of any significant increases in the
number of waste water disposal wells in particular areas on induced
seismicity are unknown.
Carbon capture and sequestration
Carbon capture and sequestration--or CCS--is also a means of
disposing of fluid in the subsurface. The committee found that the risk
of induced seismicity from CCS is currently difficult to accurately
assess. With only a few small-scale commercial projects overseas and
several small-scale demonstration projects underway in the United
States, there are few data available to evaluate the induced seismicity
potential of this technology. The existing projects have involved very
small injection volumes. CCS differs from other energy technologies in
that it involves continuous injection of carbon dioxide fluid at high
rates under pressure for long periods of time. It is purposely intended
for permanent storage--meaning that there is no fluid withdrawal. Given
that the potential magnitude of an induced seismic event correlates
strongly with the fault rupture area, which in turn relates to the
magnitude of pore pressure change and the rock volume in which it
exists, the committee determined that large-scale CCS may have the
potential for causing significant induced seismicity.
The committee's findings suggest that energy projects with large
net volumes of injected or extracted fluids over long periods of time,
such as long-term waste water disposal wells and CCS, appear to have a
higher potential for larger induced seismic events. The magnitude and
intensity of possible induced events would be dependent upon the
physical conditions in the subsurface-state of stress in the rocks,
presence of existing faults, fault properties, and pore pressure.
The committee also investigated governmental responses to induced
seismic events. Responses have been undertaken by a number of federal
and state agencies in a variety of ways. Four federal agencies-the
Environmental Protection Agency (EPA) the Bureau of Land Management
(BLM), the U.S. Department of Agriculture Forest Service (USFS), and
the U.S. Geological Survey (USGS)-and different state agencies have
regulatory oversight, research roles and/or responsibilities related to
different aspects of the underground injection activities that are
associated with energy technologies. Currently EPA has primary
regulatory responsibility for fluid injection under the Safe Drinking
Water Act. It is important to note that the Safe Drinking Water Act
does not explicitly address induced seismicity.
To date, federal and state agencies have dealt with induced seismic
events with different and localized actions. These actions have been
successful but have been ad hoc in nature. With the potential for
increased numbers of induced seismic events due to expanding energy
development, government agencies and research institutions may not have
sufficient resources to address unexpected events. The committee
concluded that forward-looking interagency cooperation to address
potential induced seismicity is warranted.
Methodologies can be developed for quantitative, probabilistic
hazard assessments of induced seismicity risk. The committee determined
that such assessments should be undertaken before operations begin in
areas with a known history of felt seismicity and updated in response
to observed, potentially induced seismicity. The committee suggested
that practices that consider induced seismicity both before and during
the actual operation of an energy project should be employed to develop
a ``best practices'' protocol specific to each energy technology and
site location. The committee's meetings with individuals from Anderson
Springs and Cobb, California, who live with induced seismicity
continuously generated by geothermal energy production at The Geysers
were invaluable in understanding how such a best practices protocol
works.
Although induced seismic events have not resulted in loss of life
or major damage in the United States, their effects have been felt
locally, and they raise some concern about additional seismic activity
and its consequences in areas where energy development is ongoing or
planned. Further research is required to better understand and address
the potential risks associated with induced seismicity.
I would like to thank the committee for its time and interest in
this subject and I look forward to questions.
The Chairman. Thank you very much.
Dr. Leith, go right ahead.
STATEMENT OF WILLIAM LEITH, SENIOR SCIENCE ADVISOR FOR
EARTHQUAKE AND GEOLOGIC HAZARDS, U.S. GEOLOGICAL SURVEY,
DEPARTMENT OF THE INTERIOR
Mr. Leith. Mr. Chairman, members of the committee, thank
you for inviting the USGS to testify at this hearing.
The United States is expanding its use of technologies that
involve the injection and production of fluid at depth. As
detailed in the report released last week by the National
Research Council, the practices employed in these technologies
have the potential to induce earthquakes. I commend this
committee for requesting that such a study be undertaken and
the Department of Energy for commissioning and funding the
study. The NRC panel has done an outstanding job and made a
significant contribution on this important issue.
Since 2011 the central and eastern portions of the U.S.
have experienced a number of moderately strong earthquakes in
areas of historically low seismicity. Of these, only the
earthquake that occurred last August in Central Virginia is
unequivocally a natural tectonic earthquake. In all of the
other cases there arises the possibility that the earthquakes
were induced by waste water disposal.
The disposal of fluids by deep injection is occurring more
frequently in recent years. The occurrence of induced
seismicity associated with fluid disposal from natural gas
production in particular has increased significantly since the
expanded use of hydraulic fracturing. Although there appears to
be very little hazard associated with hydraulic fracturing
itself, the disposal of the waters that are produced with the
gas does appear to be linked to increased earthquake activity.
As evidence, Mr. Chairman, you mentioned recent research by
USGS seismologist Bill Ellsworth and colleagues which has
documented that magnitude 3 and larger earthquakes have
significantly increased in the U.S. midcontinent since the year
2000. Most of this increase in seismicity has occurred in areas
of enhanced hydrocarbon production and hence, increased
disposal of production related fluids.
To understand this phenomena the key research questions
are:
One, what factors distinguish those injection activities
that induced earthquakes from those that do not?
Two, to what extent can the occurrence of earthquakes
triggered by deep fluid injection be influenced by altering the
operational procedures?
Three, can small induced earthquakes trigger much larger
tectonic earthquakes?
Four, what will be the magnitude of the largest induced
earthquake from a specific injection operation?
Five, what is the probability of ground motion from induced
earthquakes reaching a damaging level at a particular
injectionsite?
We're already working collaboratively with the Department
of Energy and EPA on some of these issues in response to the
President's establishment of the Interagency Hydraulic
Fracturing Working Group. The involvement of industry is
welcomed here and may be essential to make progress on some of
these questions. Also any Federal research dollars spent to
minimize the risk of induced seismicity will serve multiple
goals since not only is this research relevant to natural gas
development, geothermal development and carbon sequestration,
but it also addresses several important gaps in our
understanding of the natural earthquake process and fault
behavior.
Currently the precise data on injection volumes, rates and
pressures needed to address these research questions are simply
lacking for many sites of induced seismicity. Data collection
required by underground injection control permits may not be
sufficient to make confident, cause and effect statements about
injection induced earthquakes after the fact. Without more
precise and complete data it will be very difficult to assess
the earthquake hazard potential from the tens of thousands of
UIC wells that are currently in operation.
Looking forward, the Administration has proposed to
significantly increase our efforts on induced seismicity in the
coming Fiscal year as part of a comprehensive initiative to
address potential environmental health and safety issues
associated with hydraulic fracturing. We hope that the Congress
will support that initiative.
Thank you again for the opportunity to testify. I'd be
happy to answer any questions you may have.
[The prepared statement of Mr. Leith follows:]
Prepared Statement of William Leith, Senior Science Advisor for
Earthquake and Geologic Hazards, U.S. Geological Survey, Department of
the Interior
Chairman Bingaman, Ranking Member Murkowski, members of the
committee, thank you for inviting the U.S. Geological Survey (USGS) to
testify at this hearing on induced seismicity. My name is Bill Leith. I
am the Senior Science Advisor for Earthquake and Geologic Hazards at
the U.S. Geological Survey (USGS). The USGS is the science agency for
the Department of the Interior (DOI).
As part of its strategy to meet future energy needs, limit
emissions of greenhouse gases, and safely dispose of wastewater, the
United States is expanding the use of technologies that involve the
injection, and in some cases the associated production, of fluid at
depth. As detailed in the report released last week by the National
Research Council (NRC), Induced Seismicity Potential in Energy
Technologies (hereafter, NRC report), the injection and production
practices employed in these technologies have, to varying degrees, the
potential to introduce earthquake hazards. I would like to commend this
committee for requesting that such a study be undertaken and the
Department of Energy (DOE) for funding the study. The members of the
National Research Council panel who wrote the report have done an
outstanding job and have made a significant and lasting contribution to
the public discourse on this important issue.
The USGS is well positioned to provide solutions for challenging
problems associated with meeting the Nation's future energy needs.
Various new approaches to produce oil and gas and alternative energy
entail deep injection of fluid that can induce earthquakes. The cause
and effect of induced earthquakes pose a number of risks that must be
understood. USGS scientists, along with scientists from the National
Labs and Universities funded by DOE, are already involved in studying a
number of these injection projects, and we possess substantial
expertise in the associated science and technology of mitigating the
effects of induced earthquakes.
I summarize here the research topics that the USGS can address in
order to assist the Nation in meeting its future energy needs through
an improved understanding of induced seismicity that leads to
mitigation of the associated risks.
To put this hazard in perspective, since the beginning of 2011 the
central and eastern portions of the United States have experienced a
number of moderately strong earthquakes in areas of historically low
earthquake hazard. These include earthquakes of magnitude (M) 4.7 in
central Arkansas on February 27, 2011; M5.3 near Trinidad, Colorado on
August 23, 2011; M5.8 in central Virginia also on August 23, 2011; M4.8
in southeastern Texas on October 20, 2011; M5.6 in central Oklahoma on
November 6, 2011; M4.0 in Youngstown, Ohio, on December 31, 2011; and
M4.8 in east Texas on May 17, 2012. Of these, only the central Virginia
earthquake is unequivocally a natural tectonic earthquake. In all of
the other cases, there is scientific evidence to at least raise the
possibility that the earthquakes were induced by wastewater disposal or
other oil-and gas-related activities. Research completed to date
strongly supports the conclusion that the earthquakes in Arkansas,
Colorado and Ohio were induced by wastewater injection. Investigations
into the nature of the Oklahoma and Texas earthquakes are in progress.
The disposal of wastewater from oil and gas production by injection
into deep geologic formations is a process that is being used more
frequently in recent years. The occurrence of induced seismicity
associated with wastewater disposal from natural gas production, in
particular, has increased significantly since the development of
technologies to facilitate production of gas from shale and tight sand
formations. While there appears to be little seismic hazard associated
with the hydraulic fracturing process that prepares the shale for
production (hydrofracturing), the disposal of waters produced with the
gas does appear to be linked to increased seismicity, as was made
evident by the earthquake sequence near the Dallas-Fort Worth airport
in 2008 and 2009. In addition, recent research by USGS seismologist
Bill Ellsworth and colleagues has documented that M3 and larger
earthquakes have significantly increased in the U.S. mid-continent
since 2000, from a long-term average of 21 such earthquakes per year
between 1970 and 2000, to 31 per year during 2000-2008, to 151 per year
since 2008. Most of this increase in seismicity has occurred in areas
of enhanced hydrocarbon production and, hence, increased disposal of
production-related fluids.
Industry has been working to expand the development of
unconventional geothermal resources known as Enhanced Geothermal
Systems (EGS), because of their significant potential to contribute to
the U.S. domestic energy mix. These geothermal resources are widespread
throughout the United States and are areas of high heat flow but low
permeability. To make EGS projects viable, the permeability of geologic
formations must be enhanced by injecting fluid at high pressure into
the low-permeability formations and inducing shear slip on pre-existing
fractures. This process of permeability enhancement generally induces a
large number of very small earthquakes with magnitudes less than 2
(microearthquakes). The microearthquakes provide critical information
on the spatial extent and effectiveness of reservoir creation.
Depending on the circumstances, however, the resulting seismicity can
have serious, unintended consequences, such as project termination, if
any of the induced events are sufficiently large (greater than
magnitude 4) to result in surface damage or disturbance to nearby
residents. As a means to address these issues, the DOE published an
induced seismicity protocol in 2012, which is cited in the NRC study as
``a reasonable initial model for dealing with induced seismicity that
can serve as a template for other energy technologies.''
As emphasized in the NRC report, there is a potential seismic
hazard associated with geologic carbon sequestration projects that
involve the injection of very large quantities of CO2 into
sedimentary basins, some of which are located in or near major urban
centers of the eastern and central United States. Because carbon
dioxide storage requires a high porosity formation of high permeability
that is capped by an impermeable seal (e.g., shale), there are two
important sources of seismic risk. The first type of risk is due to the
possibility of a large magnitude earthquake that causes damage to
structures in the environs of the project. More importantly, there is
the possibility that an induced earthquake rupture would breach the cap
rock allowing the CO2 to escape.
Historically, the USGS has contributed significantly toward
understanding seismicity induced by liquid injection, starting with the
Rocky Mountain Arsenal in the 1960's, where it was first discovered
that liquid waste disposal operations can cause earthquakes. Between
1969 and 1973, the USGS conducted a unique experiment in earthquake
control at the Rangely oil field in western Colorado. This experiment
confirmed the predicted effect of fluid pressure on earthquake activity
and demonstrated how earthquakes can be controlled by regulating the
fluid pressure in a fault zone. The state of the science on the
earthquake hazard related to deep well injection was summarized by the
USGS in 1990, in a review that proposed criteria to assist in
regulating well operations so as to minimize the hazard. This study was
part of a co-operative agreement with EPA and was used to inform site
selection and operating criteria during the development of underground
injection control regulations for Class I Hazardous wells. This 1990
study is the most recent review of this topic but is likely to be
superseded by the new NRC report. With support from our partners, USGS
scientists are currently investigating induced seismicity associated
with brine disposal operations in the Paradox Basin of Colorado and the
Raton Basin coal bed methane field along the Colorado-New Mexico
border. We and our partners, including the DOE, are also investigating
the state of stress, heat flow, and microseismicity within geothermal
reservoirs to evaluate the effectiveness of hydraulic stimulation for
EGS. The combination within USGS of expertise in both energy science
and earthquake science has proven particularly effective in addressing
current issues.
Some of the key questions that arise in connection with fluid
injection and production projects are:
What factors distinguish injection activities that induce
earthquakes from those that do not?
To what extent can the occurrence of earthquakes induced by
deep liquid-injection and production operations be influenced
by altering operational procedures in ways that do not
compromise project objectives?
Can deep liquid-injection operations interact with regional
tectonics to influence the occurrence of natural earthquakes
by, for example, causing them to occur earlier than they might
have otherwise? Similarly, can induced earthquakes trigger much
larger tectonic earthquakes?
What distribution of earthquakes (frequency of occurrence as
a function of magnitude) is likely to result from a specified
injection operation?
What is likely to be the magnitude of the largest induced
earthquake from a specific injection operation?
What is the probability of ground motion from induced
earthquakes reaching a damaging level at a particular site, and
what would be the consequences (e.g., injury and/or structural
damage)?
In the recent NRC report and in workshops sponsored by the DOE, , a
common need has been identified for research to address the science
questions posed above. The USGS, as an independent and unbiased science
organization, can play a major role in studying, assessing, and
providing solutions to these problems. We are already working
collaboratively with DOE and U.S. Environmental Protection Agency on
some of these issues, in response to the President's establishment of
the interagency hydraulic fracturing working group, as well as with the
States.
Although our primary research is directed at natural earthquakes
and hydrogeology, we have in the past assessed the hazards associated
with induced earthquakes due to mining operations, reservoir
impoundment, oil and gas production and fluid injection. Thus, for many
of these items, the research would mostly involve modifying existing
approaches to the specialized requirements of fluid injection-and
production-induced earthquakes.
Addressing these science problems will require a multidisciplinary
approach that includes research in seismology, hydrology, crustal
deformation, laboratory rock mechanics, in situ stress and fracture
permeability, heat transport, fluid flow and other areas of study. The
research activities might potentially include field-scale experiments,
laboratory rock mechanics experiments, and the development and
application of numerical models that simulate the effects of fluid
injection operations on fracturing, fault reactivation and stress
transfer, especially in low-permeability formations. Careful analyses
of published case histories involving seismicity caused by fluid
injection and production operations would be an important component of
a comprehensive research program.
The involvement of industry is welcomed and may be essential to
make progress on many of the key science questions. We see value in
establishing an experimental site, or sites, in cooperation with
industry and other agencies that could further the early work on
induced earthquake triggering that was conducted so long ago at the
Rangely field in Colorado. We note that DOE has in fact proposed a
government-managed test site for EGS in its FY13 budget proposal, at
which such R&D could be conducted in a carefully controlled and
instrumented environment.
While a comprehensive effort is needed, and is called for in the
NRC's recent report, any federal research dollars spent to minimize the
risks of induced seismicity will serve multiple goals. Not only is this
research relevant to shale gas development, geothermal development and
carbon sequestration, but it also addresses several important gaps in
our knowledge of the natural earthquake process and fault behavior.
I wish to expand on two of the findings and recommendations in the
NRC report:
The first of these is what I will call the ``data gap'', for which
the report recommends, ``Data related to fluid injection... should be
collected by state and federal regulatory authorities in a common
format and made publicly available (through a coordinating body such as
the USGS).'' Currently, the data on injection volumes, rates and
pressures needed to address many of the research questions above are
simply lacking for many sites of induced seismicity. Permitting
requirements for Underground Injection Control (UIC) wells are defined
under Safe Drinking Water Act regulations, administered by the EPA and
the states. Unless the potential for induced seismicity has been
identified as a local risk prior to issuing a UIC permit, data
collection required under these permits may not be sufficient to make
confident cause-and-effect statements about injection-induced
earthquakes after the fact, making it difficult to provide useful
information to the regulating authorities about whether a particular
disposal operation has or will have increased local earthquake risk.
Without more precise and complete data, it will be very difficult
to assess the hazard potential from the tens of thousands of UIC wells
that are currently in operation and for which their earthquake
potential is unknown. An equal challenge is posed by UIC wells that may
be permitted and become active injectors in the future, particularly if
the permitting agency for the well is not cognizant of the associated
earthquake hazard, or not in communication with parties that would be
sensitive to a change in earthquake risk. For example, how close to an
existing nuclear power plant or a dam is ``too close'' to site a
disposal well permitted for a specified volume and pressure? Whose
responsibility is it to evaluate the risk? Who is responsible for
notifying the parties at risk? Who carries the liability should a
damaging earthquake occur? Getting answers to these questions requires
accurately assessing the induced-earthquake hazard, but at present the
needed statistics are lacking because of the data gap. The NRC report
provides some helpful guidance on how to develop ``best practice''
protocols that could help to close the data gap if implemented The
report cites the recently published DOE IS protocol as an important
step towards establishing a best practices effort.
The NRC report also found: ``To date, the various agencies have
dealt with induced seismic events with different and localized actions.
These efforts to respond to potential induced seismic events have been
successful but have been ad hoc in nature.'' Above in this testimony, I
detailed the large number of induced or potentially induced earthquakes
that have occurred in 2011 and 2012. Further, USGS scientists have also
documented a seven-fold increase since 2008 in the seismicity of the
central U.S., an increase that is largely associated with areas of
wastewater disposal from oil, gas and coal-bed methane production.
Scientifically, USGS has a depth of expertise relevant to understanding
induced seismicity and the increasing demand for better monitoring,
analysis, assessment, and public information. We have also worked
closely with colleagues in academia and the State Geological Surveys,
which have also seen increasing demands.
To meet these increasing demands, we have increased research
efforts within our current budget. Looking forward, the Administration
has proposed to significantly increase our efforts on induced
seismicity in the coming fiscal year, as part of a comprehensive
initiative to address potential environmental, health, and safety
issues associated with hydraulic fracturing, and we hope that the
Congress will support that initiative.
Thank you again for the opportunity to testify and for your
attention to this important matter. I would be happy to answer any
questions you may have.
The Chairman. Thank you very much.
Ms. Petty.
STATEMENT OF SUSAN PETTY, PRESIDENT AND CHIEF TECHNOLOGY
OFFICER, ALTAROCK ENERGY, INC, SEATTLE, WA
Ms. Petty. Thank you, Mr. Chairman and members of the
committee. Good morning.
I really appreciate this opportunity to talk to you about
our experiences with the mitigation of induced seismicity in
the geothermal industry. Over the past few years injection
induced seismicity has become an increasingly important issue
that Earth scientists working in the geothermal, mining,
petroleum and other industries must address. At Altarock Energy
we're in the trenches focused on developing advanced technology
to reduce the cost of enhanced geothermal systems to extend the
ability to use this base load renewable energy source across
the United States.
This resource is so large that recovering even a small
fraction of it could provide electric power and heat sufficient
to supply 10 percent or more of the Nation's need for thousands
of years to come. The MIT study of the future of geothermal
energy in 2007 projected that there is the potential to
generate over 2 million megawatts across the U.S. if only 2
percent of this resource can be recovered. The USGS found that
there is the potential for more than 500,000 megawatts in the
Western United States alone.
In order to develop this vast resource we need a way to
recover the heat by injecting water into a well, have it move
through the hot rock and pick up heat and then be produced
through production wells. To do this, we create a network of
fine fractures that access a large volume of hot rock. Doing
this requires pumping cold water into the ground at relatively
modest pressures and then using the temperature contrast
combined with the pressure to extend existing fractures and
planes of weakness outward from the well.
While this is not new technology, it is technology that is
still in development. Advances are needed to both reduce the
risks associated with the development and to improve economics.
One of the areas of risk is the possibility that seismicity of
concern to people will be induced during the process of
creating the reservoir or operating the EGS project long term.
By looking at our past experiences with injection and induced
seismicity, we can gain a better understanding of how to select
project sites with--and operate the reservoir, so that we can
reduce the risk of problematic induced seismicity. Our
experience with the Newberry EGS Demonstration Projects, I
feel, can help us grasp the issues and the potential solutions
to these issues that will affect any future projects that use
EGS technology.
Injection induced seismicity occurs when the fluid pressure
in a fault or fracture reaches a critical value above which the
friction preventing slip is overcome.
This concept was proposed in 1959.
Inadvertently demonstrated at the Rocky Mountain Arsenal in
1962.
Further tested at the Rangely Oil Field in 1969.
Has been incorporated into continuous injection operations
at Paradox Valley since 1996.
EGS reservoir creation relies upon controlled induced
seismicity to create the high surface area fracture paths
needed for sustainable and economic heat extraction. The
lessons learned from past EGS projects, in particular to
projects along the Rhine Garben in Europe, are being used to
refine the plans for future projects.
It's important to understand that creation of the EGS
reservoir necessarily causes tiny seismic events when the small
fractures slip and slide against one another. We use these tiny
seismic events, as does the oil and gas industry, to map the
fractures as we form them. What we don't want is larger faults
to slip during this process and release enough energy for
people to feel.
The energy released measured by the moment magnitude,
commonly thought of as the Richter scale, is only one aspect of
whether the seismicity will be felt by people or not. The rocks
that the energy passes through and the types of soils near the
surface as well as the structures that sit on those soils all
contribute to whether seismicity is problematic or not.
One of the things we need to do to better communicate about
injection induced seismicity is understand that that
relationship between the magnitude of the event at depth and
what people might potentially feel on the surface, the ground
shaking. It would be better to talk about the risk of ground
shaking than to talk about the risk around a particular
magnitude of event occurring. I might add that the mining
industry has long had regulations regarding ground shaking that
we can maybe look to, to get this kind of experience.
For the Newberry EGS demonstration project we have gone
through a process of both developing an induced seismicity
mitigation protocol for the project activities and also
communicating with the public about the project and the issues
associated with induced seismicity. Three Federal agencies were
involved with the permitting process, the Department of Energy,
the Bureau of Land Management and the Forest Service. Only the
DOE had staff with expertise in induced seismicity to help us
through the process. We had, therefore, to inform and educate
other regulators about the methods used to assess the potential
risks related to induced seismicity and the possibilities for
mitigating those risks.
The most difficult part of the induced seismicity hazards
assessment was commuting the information it contains to the
public. The ability of scientists to explain risk to the
general public is limited by the public's familiarity with that
risk. Using maps and graphics help, but the language we have
for discussing seismicity is difficult for the best of us to
relate to our everyday lives.
One of the interesting aspects of our public outreach
effort is that in this region of tectonic activity with
volcanoes and subduction zones as well as offshore large faults
and fractures, people are much more concerned with potential
for ground water contamination or water use impacts than they
are with induced seismicity. While the Newberry area itself is
very seismically quiet and quite remote from people, Oregonians
are regularly rattled by temblors mostly on offshore faults. So
they are familiar with small, natural seismic events.
On the other hand this is arid area with little water and
little rainfall. Water is of key importance. It's in scarce
supply. The focus by the regulators on induced seismicity took
attention away from the key issue for the public which is
water.
The result of a public outreach on our communication with
regulators, as well as the expert input of the DOE, was a
mitigation protocol that should enable us to both conduct our
project and reduce the risk of felt seismicity. Our effort at
Newberry is far more extensive and in depth. What is required
of operators of waste water disposal wells with the risk, based
on past experience, is far higher than what we have at
Newberry.
What can we take away from our experience with the Newberry
project and with other EGS projects?
Project citing can help us to reduce the risk and also the
concerns of the public about that risk. We need to site
projects away from large populations and dense populations
until we better understand the risks surrounding this
technology.
We need to avoid areas with large faults. How far away do
we need to be from those faults? We don't yet know. That's
something that needs further research.
Existing background data on seismicity is crucial for site
selection and for gathering the information needed for
permitting and operation of these sites.
Public outreach is very important. But communication with
regulators is equally so. Risk assessment results are difficult
to explain to both the public and to regulators. So we need to
select experts to write up and communicate these results, who
have excellent communication skills.
Graphics are needed. But they need to be easy to explain
and understand.
We also need to work with the press to get the message
across. We have to provide data and graphics to reporters to
help them understand the project. I have to say that this has
been one area that has really been very difficult. I think has
resulted in a lot of misunderstanding about what's going on in
this technology.
We also need to identify key local issues. We don't want to
let induced seismicity dominate the discussion if it isn't the
key issue.
Induced seismicity mitigation protocol for all injection
related projects in the energy interest--industry that's
consistent across the technologies would be a useful tool for
both project developers and regulators.
Thank you.
[The prepared statement of Ms. Petty follows:]
Prepared Statement of Susan Petty, President and Chief Technology
Officer, Altatrock Energy, Inc. Seattle, WA
The Chairman. Thank you very much.
Dr. Zoback.
STATEMENT OF MARK D. ZOBACK, BENJAMIN M. PAGE PROFESSOR OF
EARTH SCIENCES, DEPARTMENT OF GEOPHYSICS, STANFORD UNIVERSITY,
STANFORD, CA
Mr. Zoback. Chairman Bingaman, Senator Murkowski and
committee members, thank you for asking me to testify today.
My name is Mark Zoback. I'm a Professor of Geophysics at
Stanford University. My field of expertise is in quantifying
the geologic processes in the Earth that control earthquakes
and hydraulic fracture propagation. I've been doing this
research for over 30 years.
While I was not a member of the NRC Committee chaired by
Professor Hitzman, I did have the opportunity to speak to them
about the issues I'll talk to you about today. Let me say at
the outset, that I'm in full agreement with the principle
findings of their report.
I want to limit my comments today to discussing earthquakes
and energy technologies in 2 specific contexts.
First will be the earthquakes triggered by injection of
waste water. Of course of particular interest has been the
injection of the flow back water coming out from shale gas
wells following hydraulic fracturing.
Second, I want to comment briefly about the potential for
triggered seismicity associated with the large scale carbon
capture and storage or CCS, as it is widely known.
As Dr. Leith pointed out, in 2011 the relatively stable
interior of the U.S. was struck by a surprising number of small
to moderate size, but still widely felt earthquakes. Most of
these events, as he indicated, were the kinds of natural events
that occur from time to time in intra-plate regions. But a
number of the small to moderate earthquakes that did occur in
2011 appeared to be associated with the disposal of waste
water, at least in part related to shale gas production.
Seismic events associated with waste water in 2011 include the
earthquakes near Guy, Arkansas and those near Youngstown, Ohio.
It is understandable that the occurrence of injection
related earthquakes is of concern to the public, the government
and industry alike. I think it is clear that with proper
planning, monitoring and response, the occurrence of small to
moderate earthquakes associated with waste injection can be
reduced and the risks associated with these events effectively
managed.
Five straight forward steps can be taken to reduce the
probability of triggering seismicity whenever we inject fluid
into the subsurface.
First, and as Susan Petty just pointed out, we need to
avoid injection into faults in brittle rock. While this may
seem like a no-brainer, there's not always a sufficient site
characterization prior to approval of an injectionsite. In fact
EPA guidelines does not include the consideration of triggered
seismicity among its requirements.
Second, formations need to be selected that minimize the
pore pressure changes. It is the increase of pore pressure that
is the problem. We can minimize that increase in pore pressure
by careful selection of formations used for injection.
Third, local seismic monitoring arrays should be installed
when there is a potential for triggered seismicity.
Fourth, protocols should be established in advance to
define how operations would be modified if seismicity were to
be triggered.
These kinds of proactive steps, I think, will go a long way
toward making the rare occurrence of these events even more
rare and assure the public that their safety is being
protected.
I'd now like to comment briefly about the potential for
triggered seismicity associated with large scale carbon capture
and storage. My colleague, Steve Gorelick and I, have recently
pointed out that not only would large scale CCS be an extremely
costly endeavor, there is a high probability that earthquakes
will be triggered by injection of the enormous volumes of
CO2 associated with large scale CCS in many regions
currently being considered.
There are 2 issues I want to emphasize in particular.
First, our principle concern is not the probability of
triggering large earthquakes. Large faults are required to
produce large earthquakes. We assume that such faults would be
detected and thus avoided by careful site characterization
studies.
Our concern is that even small to moderate size earthquakes
would threaten the seal integrity of the formations being used
to store the CO2. Studies by other scientists have
shown that a leak rate from an underground CO2
storage reservoir of less than 1 percent per thousand years is
required for CCS to achieve the same climate benefits as
switching to renewable energy sources.
Second, it's important to emphasize that we recognize that
CCS can be a valuable and useful tool for reducing greenhouse
gas emissions in specific situations. Our concern is whether
CCS can be a viable strategy for achieving global greenhouse
gas reductions and appropriate positive effects on climate
change. From a global perspective, if large scale CCS is to
significantly contribute to reducing the accumulation of
greenhouse gases, it must operate at a massive scale on the
order of the volume injected has to be on the order of the 27
billion barrels of oil that are produced each year around the
world. So it's a truly massive undertaking.
Now multiple lines of evidence indicate that pre-existing
faults found in brittle rocks almost everywhere in the Earth's
crust are close to frictional failure. In fact, over time
periods of just a few decades, modern seismic networks have
shown us that earthquakes occur nearly everywhere in
continental interiors.
So in the light of the risk posed to a CO2
repository by even small to moderate sized earthquakes,
formations for suitable large scale injection of CO2
must be well sealed by impermeable overlying strata.
They must be weakly cemented so as to not fail through
brittle faulting.
They must be porous, permeable and laterally extensive to
accommodate large volumes of CO2 with minimal
pressure increases.
Thus the issue is not whether CO2 can be safely
stored at a given site. The issue is whether the capacity
exists for sufficient volumes of CO2 to be stored in
geologic formations for it to have a beneficial effect on
climate change. In this contest--in this context, it must be
recognized that large scale CCS will be an extremely expensive
and risky strategy for achieving significant reductions in
greenhouse gas emissions.
Mr. Chairman, Senator Murkowski, members of the committee,
thank you for the opportunity to speak to you today.
[The prepared statement of Mr. Zoback follows:]
Prepared Statement of Mark D. Zoback, Benjamin M. Page Professor of
Earch Sciences, Department of Geophysics, Stanford University,
Stanford, CA
Chairman Bingaman, Senator Murkowski and members of the committee,
thank you for asking me to testify today. My name is Mark Zoback, I am
a Professor of Geophysics at Stanford University. For your general
information, I last spoke to this committee in October as a member of
the Secretary of Energy's Advisory Board Shale Gas Subcommittee. I also
served on the National Academy of Engineering committee that
investigated the Deepwater Horizon accident. My field of expertise is
in quantifying geologic processes in the earth that control earthquakes
and hydraulic fracture propagation. I have been doing research in these
fields for over 30 years ago. My PhD students and I have been carrying
out a number of collaborative research projects seeking to better
understand these processes in the context of carbon capture and storage
and production from shale gas reservoirs.
While I was not a member of the NRC committee chaired by Professor
Hitzman, I did have the opportunity to speak with the committee about
the issues I'll comment upon today. Let me say at the outset that I am
in full agreement with the principal findings their report.
Today, I will limit my comments to discussing earthquakes and
energy technologies in two specific contexts. First, will be
earthquakes triggered by injection of wastewater. While wastewater can
come from many sources, of particular interest in the past few years
has been the injection of the flow-back water coming out of shale gas
wells following hydraulic fracturing. Second, I want to comment briefly
about the potential for triggered seismicity associated large-scale
carbon capture and storage, or CCS, as it is widely known.
In most cases, if earthquakes are triggered by fluid injection it
is because injecting fluid increases the pore pressure at depth. The
increase in pore pressure reduces the frictional resistance to slip on
pre-existing faults, allowing elastic energy already stored in the rock
to be released in earthquakes. For the cases I will speak about today,
the earthquakes in question would have occurred someday as a natural
geologic process--injection could simply advance their time of
occurrence.
I have provided the committee staff with recently published papers
I've written on these topics to provide more details.
Earthquakes associated with wastewater injection
In 2011 the relatively stable interior of the U.S. was struck by a
surprising number of small-to-moderate, but widely felt earthquakes.
Most of these were natural events, the types of earthquakes that occur
from time to time in all intraplate regions. The magnitude 5.8 that
occurred in northern Virginia on Aug. 23, 2011 that was felt throughout
the northeast and damaged the Washington Monument was one of these
natural events. While the magnitude of this event was unusual for this
part of the world, the Aug. 23rd earthquake occurred in the Central
Virginia seismic zone, an area known for many decades to produce
relatively frequent small earthquakes.
This said, a number of the small-to-moderate earthquakes that
occurred in the interior of the U.S. in 2011 appear to be associated
with the disposal of wastewater, at least in part related to shale gas
production.
Following hydraulic fracturing of shale gas wells, the water that
was injected during hydraulic fracturing is flowed back out of the
well. The amount of water that flows back after fracturing varies from
region to region. It's typical for 25-50% of injected water to flow
back. While the chemicals that comprise the fracturing fluid are
relatively benign, the flow-back water can be contaminated with brine,
metals and potentially dangerous chemicals picked up from the shale and
must be disposed of properly.
Seismic events associated with injection of wastewater in 2011
include the earthquakes near Guy, Ark., where the largest earthquake
was a magnitude-4.7 event on Feb. 27th and the earthquakes that
occurred on Christmas Eve and New Year's Eve near Youngstown, Ohio. The
largest Youngstown event was magnitude 4.0. It is understandable that
the occurrence of injection-related earthquakes is of concern to the
public, government officials and industry alike.
I believe that with proper planning, monitoring and response, the
occurrence of small-to-moderate earthquakes associated with fluid
injection can be reduced and the risks associated with such events
effectively managed. No earthquake triggered by fluid injection has
ever caused serious injury or significant damage. Moreover,
approximately 140,000 Class II wastewater disposal wells have been
operating safely and without incident in the U.S. for many decades.
Five straightforward steps can be taken to reduce the probability
of triggering seismicity whenever we inject fluid into the subsurface.
First, it is important to avoid injection into faults in brittle rock.
While this may seem a ``no-brainer'', there is not always sufficient
site characterization prior to approval of a injection site. Second,
formations should be selected for injection (and injection rates
limited) so as to minimize pore pressure changes. Third, local seismic
monitoring arrays should be installed when there is a potential for
injection to trigger seismicity. Fourth, protocols should be
established in advance to define how operations would be modified if
seismicity were to be triggered. And fifth, operators need to be
prepared to reduce injection rates or abandon injection wells if
triggered seismicity poses any hazard. These five steps provide
regulators and operating companies with a framework for reducing the
risk associated with triggered earthquakes.
In addition, the re-cycling of flow-back water (for use in
subsequent hydraulic fracturing operations) is becoming increasingly
common (especially in the northeastern U.S.). This is a very welcome
development. Re-use of flow-back water avoids potential problems
associated with transport and injection flow-back water or the expense
and difficulty of extensive water treatment operations.
It is important to note that the extremely small microseismic
events occur during hydraulic fracturing operations. These microseismic
events affect a very small volume of rock and release, on average,
about the same amount of energy as a gallon of milk falling off a
kitchen counter. The reason these events are so small is that
pressurization during hydraulic fracturing affects only limited volumes
of rock (typically several hundred meters in extent) and pressurization
typically lasts only a few hours. A few very small earthquakes have
occurred during hydraulic fracturing (such as a magnitude-2.3
earthquake near Blackpool, England, in April 2011), but such events are
extremely rare.
It is important for the public to recognize that the risks posed by
injection of wastewater are extremely low. In addition, the risks can
be minimized further through proper study and planning prior to
injection, careful monitoring in areas where there is a possibility
that seismicity might be triggered, and operators and regulators taking
a proactive response if triggered seismicity was to occur.
Earthquake potential and large-scale carbon storage
I would now like to comment briefly about the potential for
triggered seismicity associated large-scale carbon capture and storage.
My colleague Steve Gorelick and I have recently pointed out that not
only would large-scale CCS be an extremely costly endeavor, there is a
high probability that earthquakes will be triggered by injection of the
enormous volumes CO2 associated with large-scale CCS.
There are two issues I wish to emphasize in particular this
morning. First, our principal concern is not the probability of
triggering large earthquakes. Large faults are required to produce
large earthquakes. We assume that such faults would be detected, and
thus avoided, by careful site characterization studies. Our concern is
that even small-to-moderate size earthquakes would threaten the seal
integrity of the formations being used to store CO2 for long
periods without leakage. Studies by other scientists have shown that a
leak rate from underground CO2 storage reservoirs of less
than 1% per thousand years is required for CCS to achieve the same
climate benefits as switching to renewable energy sources.
Second, it is important to emphasize that we recognize that CCS can
be a valuable and useful tool for reducing greenhouse gas emissions in
specific situations. Our concern is whether CCS can be a viable
strategy for achieving appreciable global greenhouse gas reductions.
From a global perspective, if large-scale CCS is to significantly
contribute to reducing the accumulation of greenhouse gases, it must
operate at a massive scale, on the order of 3.5 billion tonnes of
CO2 per year. This corresponds to a volume roughly
equivalent to the 627 billion barrels of oil currently produced
annually around the world.
Multiple lines of evidence indicate that pre-existing faults found
in brittle rocks almost everywhere in the earth's crust are close to
frictional failure, often in response to small increases in pore
pressure. In fact, over time-periods of just a few decades, modern
seismic networks have shown that earthquakes occur nearly everywhere in
continental interiors. In light of the risk posed to a CO2
repository by even small-to-moderate size earthquakes, formations
suitable for large-scale injection of CO2 must be well-
sealed by impermeable overlaying strata, weakly cemented (so as not to
fail through brittle faulting) and porous, permeable, and laterally
extensive to accommodate large volumes of CO2with minimal
pressure increases.
Thus, the issue is not whether CO2 can be safely stored
at a given site, the issue is whether the capacity exists for
sufficient volumes of CO2 to be stored in geologic
formations for it to have a beneficial affect on climate change. In
this context, it must be recognized that large scale CCS will be an
extremely expensive and risky strategy for achieving significant
reductions in greenhouse gas emissions.
Mr. Chairman, Senator Murkowski and members of the committee, thank
you for the opportunity to speak to you today.
The Chairman. Thank you all very much for the excellent
testimony. Let me start with a few questions.
Dr. Hitzman, I'm trying to get clearly in mind the main
thrust of your conclusions. From what I believe I heard you say
and have read in your report here, the 2 biggest potential
causes of this seismic activity, human causes, would be
injection of waste water which is a significant issue because
there's a lot of it injected.
Second, if in fact we were to pursue carbon capture and
storage at a large scale that also would be significant.
That those 2 types of injection pose a much greater threat
and are a much greater issue, in your mind, then the injection
that is generally referred to as fracking and geothermal
activity as well as I understand it. Is that a reasonable
summary of your----
Mr. Hitzman. That's a very fair statement of what the
report says. Yes.
The Chairman. So you're not as worried about fracking.
You're not as worried about geothermal energy production
activities.
But you are worried about waste water and you are worried
about CCS if it goes to a large scale?
Mr. Hitzman. Correct. It really is volume dependent.
So in geothermal we're trying to balance a reservoir.
In fracking there's very small volume.
But in waste water, most of the waste water disposal wells
are fine. But with vast numbers of them and putting lots and
lots of these wells in, some of them with fairly large volumes,
occasionally there will be an event.
CCS, because it has such very large volumes, as pointed out
by Dr. Zoback, are sort of in a different league. So that
clearly is of concern.
The Chairman. Now as far as I understand, to deal with
the--or to reduce the likelihood that you're going to have
human felt induced seismic activity from waste water injection.
I think your suggestion is that there are some best practices
that can be followed. I guess my question there is, is it clear
that who would have the responsibility or authority to define
those best practices and try to implement them or is this
such--you've got so many agencies and so many different levels
of government involved here that the whole thing is a
hodgepodge?
Mr. Hitzman. The committee actually didn't try to specify
who should do it because, as you say, there are a number of
agencies and different groups involved. But clearly, sort of as
happened with the DOE protocol for EGS. What took place there
was a cooperative venture between several levels of government
with academia, with industry, with local communities try and
come up with best practices.
The committee felt that that was the sort of way moving
forward with the other energy technologies as well.
The Chairman. So the Department of Energy or EPA or
somebody at the Federal level could convene a group of all the
various players in this field and try to come up with some kind
of guidelines. Say this is what we need to be doing in order to
reduce the likelihood of this seismic activity resulting from
waste water injection.
Mr. Hitzman. Yes, absolutely.
The Chairman. Yes.
Now what's your reaction to Dr. Zoback's comment?
He's made a very interesting point here which is basically
that he thinks that, as I understand it, and Dr. Zoback correct
me if I misstate your view here. But your basic view is that in
order for carbon capture and storage to be pursued on the large
scale that it would have to be pursued in order to achieve
significant climate change benefits or, you know, we have real
problems in pursuing it at that scale considering the
likelihood of leakage out of these underground storage
facilities.
Is that a fair summary of--maybe you can state it much
better than that.
Mr. Zoback. I'll try.
When we look at the global greenhouse gas problem, you
know, the real problem is that by mid-century the--if we do
nothing emissions will be twice as much as they are today. So
we'll be adding, you know, something like 15 billion tons of
carbon to the atmosphere per year in 2050. You know, we're
currently at the 7 or 8 billion ton level.
So we have a problem that's on the scale of needing to
reduce emissions by 7 or 8 billion tons of carbon. Now if CCS
is going to be part of that solution at that scale it has been
proposed that it should deal with say, one seventh or one
eighth of the problem.
Can it go along with, you know, enhanced use of renewables?
Can it go along with energy efficiency programs?
Can it go along with fuel switching from coal to natural
gas?
All of which will reduce emissions.
If it's going to be a player at the billion ton level then
we get into a situation where we need 3,500 projects of the
scale of the single operable project that's going on now in the
North Sea. So it's really not the fact that we can't find good
places to put CCS. But for CCS to be part of a global strategy
for stabilizing emissions it's got to operate at this billion
ton of carbon scale which is 3,500 times what we're doing today
at a single site.
The Chairman. OK.
Why don't I defer to Senator Murkowski for her questions
and then Senator Landrieu?
Senator Murkowski. Thank you, Mr. Chairman.
I appreciate the testimony from all the witnesses this
morning. Very interesting. I think that the focus here on CCS
and waste water injection is an interesting one. Perhaps the
results of this study were different than what some imagined
before you began this.
But let me ask the question again, sticking with the CCS. I
mean we've got new EPA rules that essentially ban construction
of new coal fired power plants unless CCS is out there. So a
lot of interest in whether or not we can do this right and/or
if at all.
More specific perhaps to this committee is the work that
we've done to draft the liability protections for CCS
operators. So I guess the question to you, Dr. Hitzman, is with
this information that we know have do you think that it is
perhaps premature or even unwise to provide liability
protection for CCS operators? I mean, can we even do this or do
we need to know more?
Mr. Hitzman. That certainly is outside the scope of what
our committee looked at. We did not look at insurance
whatsoever. So where we can down to is that there is
significant concerns. We thought that DOE should address those
concerns to look at how this technology may play out in the
large scales that Dr. Zoback has talked about.
Senator Murkowski. You--we're talking now about the
increased risk, comparative, when we're talking about
geothermal or fracking as it relates to waste water injection
and CCS. But is it--it's not fair to describe that the risk or
the consequences between waste water injection and CCS are
comparable. Is that correct?
I mean, you've got a higher risk with CCS?
Mr. Hitzman. It depends on the volumes. So it's volume
related. If we were injecting billions of tons, as Dr. Zoback
discussed, then the risks are probably much greater because
certainly none of our waste water wells are injecting anywhere
near that.
So really it's--think about volume. The more volume
probably the more risk.
Senator Murkowski. You made a statement that, let's see, no
geologic review before injection. This is with the disposal of
the waste water. Is that, perhaps, part of the reason that we
see higher rates of seismic activity is because you don't have
that same geologic study that you have, say for instance, when
you're doing a geothermal well or even fracking?
You've got some pretty serious studies that proceed before
you move forward. Is that perhaps accounting for some of the
difference?
Mr. Hitzman. That's part of it, yes. With any of the CCS
projects going on, with certainly with geothermal, we have a
lot of geologic data before those happen.
For many waste water wells they're relatively low cost
operations. They don't have a lot of citing--site
characterizations done ahead of time.
But it also is important to note that the vast majority of
waste water wells do not have an issue. So we're not, in the
report, we certainly do not suggest requiring that that occur
for all waste water wells.
Senator Murkowski. OK.
Dr. Leith, let me ask you about monitoring. Both the report
and your testimony indicate that we need greater monitoring
activity. In terms of scale do we need to double the monitoring
that we're doing?
What would you suggest in terms of stepped up monitoring
activities here?
Mr. Leith. The USGS, the National Seismic Network, is
capable of routinely locating earthquakes that are around
magnitude 3 and in many areas lower than that. But with that
network we certainly cannot detect the onset of low magnitude
induced earthquakes from an injection operation in most of the
country.
So what we rely upon is learning early about the occurrence
of earthquakes. That typically doesn't happen until they're
felt. It's just going to be above magnitude two somewhere.
Then deploying portable seismometers to go in and assess
what's going on. This is what we did in Arkansas and in
Oklahoma and----
Senator Murkowski. Do you do that just in a few specific
areas or is--are you doing this monitoring across the country?
Mr. Leith. We do not have enough portable systems to deploy
to all of the interesting cases of induced seismicity.
Senator Murkowski. If you have enough portable systems in
these interesting areas, as you put it, what would that
require?
Mr. Leith. We have been so busy with natural earthquakes
for the last few years. Then this increased occurrence of
induced earthquakes has piled onto that demand.
We would need, I would estimate, some hundreds of portable
systems to respond to just the earthquakes that are in the
magnitude 4 and above range. That, of course, doesn't include
the scientist's time, the analyst to evaluate the data and the
researchers to then correlate what's recorded by the
seismometer to determine its relation to the injection
activity, the fluid volumes injected, the pressures and those
sort of things.
Senator Murkowski. Thank you, Mr. Chairman.
The Chairman. Senator Landrieu.
Senator Landrieu. Thank you very much. I have a short
statement for the record.
Senator Landrieu. I want to say I really appreciate the
hearing the chairman and the ranking member have put together.
This is very, very interesting, particularly about the volume
necessary, the 3,500 sites, to take care of the billion tons of
carbon sequestration.
Let me ask you, if you could, Dr. Zoback, to describe these
locations to the best of your ability to those of us that are
trying to get our heads around what such a location might look
like. You said there would need to be 3,500 sites. So we could
pick 100 countries, put 35 in each one.
How--what would a site look like? Describe the one that
exists now so we can get a little better understanding of that.
Mr. Zoback. The project that exists now is a gas field.
It's operating in the North Sea. When they produce the gas it
has a large fraction of CO2 mixed with the methane.
So they have to deal with the CO2.
They separate it from the natural gas. Put the natural gas
into a pipeline. Then they have an injection well in which they
inject the CO2 into a geologic formation, basically
above the gas reservoir. This geologic formation has, what I
consider to be, you know, ideal characteristics.
First, it's very laterally extensive. It's big. So you're
putting the CO2 into a large volume.
Senator Landrieu. It's right near the site itself.
Mr. Zoback. That's exactly right. It's--the well has been
drilled off the same platform that the gas wells were drilled
from.
So the geologic formation, it's called the Utsira
formation. It's a very--it's laterally extensive. It's very
porous and permeable so it's easy for them to get the
CO2 into it. It has this added characteristic that
it's very weak and friable.
It's easy to imagine that if you had a very weak sandstone
and you squeezed on it, well it would just kind of deform
slowly in your hands and, you know, there's no problem. Whereas
a very strong rock, as you squeeze on it, it holds the force
much better. But when it does fail it will fail brittle-ly. You
know, it's like a very small earthquake.
So the Utsira formation is porous, permeable, laterally
extensive and very weak and located where you want it to be.
It's absolutely ideal.
Senator Landrieu. Let me follow that up. Because I was
thinking that it would have to be on countries, on land. But
this could be 3,500 sites in the world in the oceans, on land,
etcetera, etcetera.
So while it sounds like a lot of sites, you know, it's a
big planet. So I think we have to get the scale of this to
understand. But I think it's a very important point that you
raised.
But it's also, I would say in response, while it seems
overwhelming when you first say it. Until you've had a little
bit more information about how many other potentially, really
enormous and very good sites there might be. Before we
completely rule this out we need to have a little bit more, a
lot more, data about that.
Let me ask my other question.
I'm very pleased to hear that fracking is not the problem.
We've heard a lot of problems about fracking. Since my State is
doing a lot of it and think we're contributing to the natural
gas production which is helping clean our atmosphere and
provide the energy that our Nation and the world needs to move
forward. But it's the waste water injections.
So I want to ask a couple of questions.
Is the oil and gas industry, primarily in the United
States, responsible for the majority of waste water wells? Are
there other industries that are injecting waste water? Could
somebody give us some data, if you have it, about that?
Is it primarily the oil and gas industry or is it primarily
other mining or is it petrochemical or agriculture, etcetera,
etcetera?
Mr. Hitzman. There's some data in the NRC report. I don't
have at the top of my head the percentage. But there are a
number of producers of waste water that are disposed in the
subsurface. Oil and gas is one of the major ones in the
country.
Senator Landrieu. But there are other major ones?
Mr. Hitzman. There are other major ones.
Senator Landrieu. Are there any industries that are more
than the oil and gas industry? Does anybody know? You think
there would be----
Mr. Hitzman. I think it probably is the single largest. But
it's probably not super high above.
Senator Landrieu. Above the others.
Mr. Hitzman. Some of the others, yes.
Senator Landrieu. OK.
Those are my questions. Thank you. I'm going to submit the
rest for the record.
The Chairman. Thank you very much.
Let me just try to put a little finer point on Dr. Zoback's
testimony and as least as I understand it just to be clear. As
I understand, your basic point is that you doubt that CCS,
carbon capture and storage, can be a successful strategy for
dealing with the long term effects of climate change. A main
reason you doubt that is because of these small to moderate
sized earthquakes that, not only do you have to have 3,500 of
these projects like the one you've just described to us.
But there are small to moderate size earthquakes that occur
naturally, as I understand it, that will, as you put it,
threaten the seal integrity of the formations that might be
used for the CCS. Is that accurate?
Mr. Zoback. That's exactly our point, Senator.
The Chairman. Yes. Alright.
Is this something you and fellow researcher expert that you
mentioned have concluded on your own? Is this anything that
the--any other group has looked at? Has the National Academy
reviewed that set of recommendations or conclusions?
Mr. Zoback. Basically the conclusions we've recently
written about are essentially identical to the conclusions that
the committee, chaired by Professor Hitzman, came to. So we're
in complete concordance. They basically said----
The Chairman. But their report, the one that we have before
us today doesn't go as far as you're going with your
conclusions about the problems with planning on CCS as a
strategy for long term climate change mitigation.
Mr. Zoback. That's true. They did not go that far. But in
some ways they went further by pointing out the potential for
large earthquakes because of the extremely large volumes to be
injected.
The question there is how good site characterization
studies will be. We took what we thought was an approach by
saying the site characterization will be so comprehensive that,
you know, there will be no big faults. There will be no
probability for a bigger earthquake. But it's the small faults
that you can miss.
So therefore, our statement would have been due to the
large scale, large volumes, there's a high probability of
something happening, probably something small to moderate in
size. Their statement was a bit stronger on the hazard part of
it. They said that in fact there was the potential, perhaps, of
missing some of the bigger faults and a potential for a larger
earthquake occurring.
So philosophically I think we're 100 percent in agreement.
It's a slight change in interpretation about what the hazard
might be.
The Chairman. Dr. Hitzman, let me just ask you.
Did you--does your report deal with the issue of whether or
not small earthquakes or small instances of induced seismicity
might result in natural earthquakes being substantially more
likely in certain areas? For example if you go to a place where
there's a natural known fault and there's a real risk of an
earthquake at some point, could you hasten the time of that
earthquake or increase the likelihood of that natural major
earthquake by doing the type of small injection activity that
we're talking about here?
Mr. Hitzman. That is addressed in the report. The basic
answer is yes that many faults are near a critical state. So if
we perturb them, manmade, we can trigger events. So the answer
is yes.
Is that something we routinely do? No. I mean site
characterization, especially around areas of known faults we do
today.
So I don't see that as a particular large issue.
The Chairman. So as long as we stay away from the known
faults that are naturally there, we pretty much deal with that
problem.
Mr. Hitzman. Right. But what happens is there are faults we
don't know about. That's where, certainly in the waste water
injection, that's where we've had the problems. We found faults
we didn't know existed.
The Chairman. Senator Murkowski.
Senator Murkowski. Thank you, Mr. Chairman.
I want to follow up to the questioning that Senator
Landrieu had about the various types of waste water injection.
It's my understanding that there are 6 different classes of
injection wells.
One is municipal and industrial waste. We've got mineral
solution, mining. We've got other things.
So the question would be whether or not we think that any
of these other well classifications. Whether or not they've
been associated with any additional seismic activity, whether
we've looked at that. Whether it's possible that they could.
Then as a follow on as we see communities expanding and
population going into certain areas, is it possible that we
could see enhanced seismic activity just due to what we're
contributing from the municipal and industrial waste? I don't
know whether it's a significant enough volume or quantity to
make a difference. Have you looked at that?
Mr. Hitzman. Our committee specifically looked at Class Two
wells with energy injection.
Senator Murkowski. OK.
Mr. Hitzman. So we didn't consider the others.
But what I would say is it really makes no difference
whether the fluid is produced by an energy or by another
industry or just simply waste water. It's water being injected
down.
Senator Murkowski. It's the volumes that are the critical
piece.
Mr. Hitzman. Right. Right.
So as we inject more and more volume into the subsurface,
we probably will have more and more potential for seismic
events.
Senator Murkowski. OK. Alright.
Ms. Petty, we've been quiet regarding geothermal here. I am
a huge advocate of geothermal power and the resource itself.
We've got, I think, some considerable opportunities in my
State. We've also got some pretty impressive fault lines that
run up there have had a history of earthquake activity.
We've apparently managed to avoid any major issues. I think
that that's great. But in listening to your testimony you seem
to indicate that the risks associated with geothermal are
perhaps more minimal.
I guess a very generic question is whether or not you think
the benefits then of geothermal outweigh any potential risk
associated.
Ms. Petty. I think that the main aspect of this, as Dr.
Hitzman said, is that in geothermal we want to balance the
injection and production so that we don't have a
disproportionate amount of either. That way the pore pressure
doesn't change. There have been some cases in geothermal fields
where we didn't do that, where we took out more than we put
back in.
In those cases, especially when we started to put more in
we've had increased amounts of seismicity. I think it's that
balancing of injection and production that's kind of inherent
to doing a good job of managing geothermal that makes me feel
that we have less of an issue for potential large scale,
induced seismicity, felt induced seismicity in geothermal.
The cases where we are near large faults, I mean, in fact
there are a number of geothermal fields that are near or
actively injecting into faults. But because they add balance to
the injection and production there hasn't been an issue.
For EGS where we are creating a reservoir, we--a necessity
when we start out, we inject more than we produce because we
don't produce anything until we make the reservoir. That's when
the risk is more clear to us. In that's where we need to have
some kind of mitigation protocol. We have to have good site
characterization, so that we can get that big resource.
Senator Murkowski. It sounds like so much of this is, is we
are learning. That's an important piece to recognize in all of
this as well.
Dr. Zoback, you mention that there are ways that we can
manage the risk. You cited 4 different points.
I mean, one, which is pretty obvious, is avoid the faults.
So we need to know where we are and we need to better
understand our geology. Pay attention to that I would think.
But appreciating that we can manage risk is one thing. Is
there any way to avoid it to the extent that you can tell
people don't worry? We know and we understand what it is that
we have to do to balance this. There should be no cause for
concern.
Are we to that point?
Mr. Zoback. In some cases. For example thorough site
characterization is a basis for assuring the public that you've
done due diligence before you start.
Monitoring with enhanced seismic networks if you think
you're in an area where something might happen. You know,
you're on top of it. That's another issue that should assure
the public.
But something else is happening that should be pointed out
with respect to the shale gas development and waste water
injection problem. That is in the Northeastern U.S. which is,
you know, an area of active development with the Marcellus
shale is being exploited. There are really no good places to
inject the waste water.
So what's happening is that industry has largely started to
recycle the waste water. So the water that comes back from
hydraulic fracturing is now being reused in subsequent
hydraulic fracturing operations. That's beneficial for
everyone.
You use less water. So the water resources are protected.
You basically put the contaminated water, which was
contaminated by its interaction with the shale to begin with.
You put it back into the shale.
So the more you can recycle these flow back waters, the
smaller you make the problem. In the Northeastern U.S. this is
now standard practice. In other areas, if there's difficulty
finding, you know, safe injectionsites, that practice can be
extended to other parts of the country.
Senator Murkowski. We were in West Virginia this weekend
looking at--we were at the Marcellus. They were speaking
exactly to that process of the recycling and how that all plays
into it. Again a recognition that we're learning a little bit
more.
Did you learn anything from this report that you found
surprising?
Mr. Zoback. It was really nice to see that the information
compiled, as it was. I was aware of the general issues, but
they did a terrific job of pulling together information on a
global basis and of course, with the United States getting
particular emphasis.
The other thing I really appreciated out of the report was
that it points to the need for data. So often we're asked,
well, was that earthquake triggered or not. You don't have a
baseline to make an answer to that question.
Whether it's a seismic baseline and you're not aware of
what the seismicity was prior to a larger event occurring or
the pore pressure or the stress or the pre-existing faults. In
both the Youngstown and Guy, Arkansas cases scientists have
come forward after the fact and said, oh yeah, there was an
active fault right there that was being injected into. Had that
data been available prior to the injection neither incident
would have occurred.
So, you know, in some ways, as the report illustrates in
case after case we have a good conceptual understanding of what
the issues are but we rarely have the data in order to use that
conceptual understanding to be definitive about, you know,
what's happened and how to prevent things from happening in the
future. So it's a data issue as much as anything else.
Senator Murkowski. Thank you all. I appreciate your
testimony this morning.
Thank you, Mr. Chairman.
The Chairman. Thank you.
Let me ask about a bill. Senator Murkowski referred to one
of the bills that's been reported out of our committee, S. 699,
that provides--it proposes to provide some liability protection
for CCS projects. The idea of that or the general thrust of it
is to say that for the first ten large demonstrations of CCS
there would be some liability protection provided if DOE could
determine that there's adequate measuring and monitoring and
testing to verify that the carbon dioxide that is injected into
the injection zone is not escaping or migrating and is not
endangering underground drinking water sources.
The idea of the legislation and then of course the bill
tries to provide a long term stewardship for these
demonstration projects, these first 10. I guess that I'd ask
Dr. Hitzman. Is there anything in your report or in the work
that your committee did that would tell us whether it makes
sense to proceed with these kinds of large demonstration
projects or to have encouragement to industry to proceed with
these or not?
I mean, is this something that is a waste of effort or is
it something that would make some sense to help us understand
whether or not this is an avenue that's going to be beneficial?
Mr. Hitzman. I think what the report says is that we also
see the potential benefits of doing CCS. But that we really
need to understand it better at the scales that are being
projected. So I'm not sure exactly how large, how many--what
the volume is in these ten demonstration projects over the long
term.
But we recommend that the DOE continue with its research,
probably use some of the research it's doing now and focus it a
little more on this particular issue so it can be better
understood. That right now, we need the data. We can't answer
your question directly.
The Chairman. OK.
Dr. Zoback, did you have thoughts as to whether it makes
sense for the Department of Energy and the Federal Government
to be encouraging some of these large scale demonstration
projects through this kind of legislation or do you think it's
such a non-starter as that we really should look elsewhere to
solve the long term climate change issue.
Mr. Zoback. The paper that we, my colleague and I, just
published on this topic is published as a perspective piece. It
really is our perspective that because of these potential
problems one has to consider this, the strategy of large scale
CCS with these issues in mind. So what we're trying to do--and
by the way, the paper was published yesterday. So there's going
to be a lot of reaction to it without question.
What we're trying to do is just change the dialog and ask
people to consider this question not just in the context of the
scale and the cost which have been raised by many people in the
past. They are very real issues. But also in the context if 10
or 20 years from now one of these moderate sized earthquakes
occur in one of the repositories what is that going to mean for
this strategy that we've, you know, we've embarked on.
So this has to be thought through very carefully. I'm not
familiar with the legislation you referred to. So I'd rather
not comment on it.
But we're just trying to change the dialog and broaden
people's perspective just as the case that triggered seismicity
is not considered in the licensing requirements for a Type Two
waste water injection well. Perhaps it should be, at least in
certain parts of the country. Triggered seismicity should
certainly be a strong consideration as we look at CCS in a
research mode in the future.
The Chairman. But your concern is triggered seismicity. But
you're also--your concern is natural seismicity. You're
basically saying there are natural, small and medium sized
earthquakes that may thwart our ability to use CCS at large
scale to solve climate change problems long term.
Mr. Zoback. That's true, Senator. We're--but by raising the
pore pressure, you know, the probability of something happening
goes up because you are basically advancing the time at which a
natural event would have occurred anyway. So in a given area
natural earthquakes occur but they might be so infrequent that
you would assume that during the lifetime of the repository
there's no possibility of an event occurring.
But by injecting fluid we sort of bring the faults closer
to failure and therefore enhance that probability.
The Chairman. Senator Murkowski, did you have additional
questions?
Thank you all very much. I think this has been very useful.
Again, Dr. Hitzman, thank you for all the work you did on
this report and your entire committee.
That will conclude our hearing.
[Whereupon, at 11:18 a.m. the hearing was adjourned.]
APPENDIX
Responses to Additional Questions
----------
Responses of Murray W. Hitzman to Questions From Senator Bingaman
Question 1. Dr. Zoback has testified that the risk of venting
stored carbon dioxide from small, induced seismic events is a primary
concern and obstacle to the scaling up of CCS technologies to play a
significant role in mitigating global greenhouse gas emissions to the
atmosphere. Do you agree with this assessment?
Answer. The statement of task for the study did not examine include
consideration of the escape of carbon dioxide from CCS projects, thus
we are not in a position to comment on this aspect of induced
seismicity.
Question 2. The NAS study we just heard about indicates that there
have been relatively few induced seismic events that are directly
attributable to the energy technologies considered here. At the same
time, Dr. Leith's testimony shows a sharp increase in the number of
mid-continent earthquakes that USGS has measured over the past decade.
Question 2a. Is there something else going on that could be causing
this trend in earthquakes?
Answer. The data Dr. Leith referred to in his testimony became
available at the end of the NRC study and was not available in a peer-
reviewed form. Hence, we were unable to examine it in detail. There
could be a number of reasons for the seismicity to have apparently
increased. Deep well disposal of waste water associated with energy
development is one possibility. Another is a natural increase in
seismicity. Finally, the apparent increase in number of events could be
due to changes in the monitoring technologies employed over the past
several years.
Question 2b. Is this a measurement issue, or is it just that more
work needs to be done to figure out what caused these earthquakes?
Answer. As noted above, it could be a measurement issue. Certainly
more work is required to better understand these seismic events.
Responses of Murray W. Hitzman to Questions From Senator Murkowski
Question 1. To the extent that wastewater injection wells are
geologically unavailable in certain Eastern US areas, might those areas
bear a correspondingly remote risk of induced seismicity from natural
gas development?
Answer. If the question is if waste water injection wells are not
utilized will the seismic risks be decreased the answer is yes.
However, fluids from energy development will need to be managed in some
manner.
Question 2. The NRC report indicates that the Federal and State
Underground Injection Control (UIC) Programs ``do[es] not address the
issue of seismicity induced by underground injection.'' At the same
time, the current UIC program does require the injection well operator
to perform a site characterization, including identifying the risks
associated with nearby faults if any are located. Furthermore, several
states (including Arkansas, Colorado, Ohio, and West Virginia,) are
currently modifying their UIC Programs to specifically address
seismicity. To this extent, might those state regimes reflect any of
the proposed actions as noted in the report?
Answer. The NRC report states ``the Safe Drinking Water Act . . .
does not specifically address the issue of seismicity induced by
underground injection. (page 106)'' However, individual states have the
authority to promulgate rules above and beyond the requirements of the
SDWA including requirements such as providing additional information
concerning induced seismicity as part of the permitting process. Our
report (page 119) specifically notes the states of Colorado and
Arkansas have adopted additional permitting regulations concerning
induced seismicity in addition to the regulatory framework put forth in
the SDWA. The additional information required by the state of Colorado
closely parallels portions of the ``Hazard Assessment'' protocol
recommended in our report on page 146. Our report also notes on page
106 ``UIC regulations requiring information on locating and describing
faults in the area of a proposed disposal well are concerned with
containment of the injected fluid, not the possibility of induced
seismicity.''
Question 3. The report establishes the ``felt at surface''
threshold as a magnitude 2.0 seismic event. However, USGS documents
state that a magnitude 2.0 to 2.9 is generally not felt, but might be
recorded, while for the general population a magnitude 3.0 to 3.9 is
more likely to be ``felt.'' As also noted, a seismic event typically
does not cause damage until its magnitude falls in the range of 4.0 to
4.9, and the report indicates that the purpose of implementing a risk
management protocol is to prevent the occurrence of damaging events.
Are the report's proposed actions targeted at such a risk management
protocol or do they go further to seek to address any induced
seismicity which might be recorded?
Answer. While seismic events in the 2.0 range are commonly not
felt, particularly if they occur deep within the Earth's crust, the NRC
committee met with residents living in the area of The Geysers where
events in this range are shallow and are routinely felt. Damage from a
seismic event depends on the location of the event relative to the
structures being considered, the construction of such structures, and
their contents. The NRC committee identified magnitude 2.0 since this
is the smallest seismic event that can usually be felt by humans, even
for shallow events caused by humans. The committee certainly is
suggesting a risk protocol that is practical and widely applicable, not
one for events that pose no risk. We would note that we are not
disagreeing with the USGS documents, but feel the difference in wording
has to do with the preciseness of the threshold of what may be felt.
Question 4. Of the corresponding wells drilled for each of the
following energy technologies in the U.S., please provide what
percentage have been proven to induce seismicity:
A) Enhanced oil recovery
B) Wastewater injection wells
C) Geothermal
D) Hydraulic fracturing
Answer. The committee could not find reliable statistics on the
percentage of wells that have, or might have, induced felt seismicity
(greater than M 2.0) for various energy technologies. Developing a
reliable database of the numbers and characteristics of wells, and of
the incidences of induced seismicity, as recommended in our report,
will help with the understanding of the percentages associated with
induced seismicity.
However, based upon the available data from peer-reviewed resources
the committee identified and examined, neither enhanced oil recovery
nor hydraulic fracturing have to date have been proven to have induced
felt seismic events in the United States.
Regarding geothermal energy, although some of the events in our
report's database were clearly caused by injection to generate
geothermal energy (for example at the Geysers and in the Coso
geothermal field), geothermal wells tend to be drilled in areas that
are often seismically active, making `proof' of the tie to fluid
injection difficult.
Our report suggests that felt earthquakes at about 8 locations in
the US over a period of about 40 years have been reasonably proven to
be linked to wastewater injection. We know only the approximate number
of wells today (30,000); some of the older wells that caused felt
events are no longer in operation. An approximate estimate of the
fraction of wastewater wells that have induced felt earthquakes is
therefore 8/30,000, which is about 3/100 of 1%.
Question 5. At the hearing, it was not clear how many of the
various UIC wells of various classes were associated with oil and gas
development (as opposed to municipal waste, etc.). Can you provide the
committee with the breakdown of the various UIC well types and
percentages relative to the total number of wells?
Answer. The committee examined in detail only Class II wells, with
some mention of Class V and Class VI (CCS) wells. The only Class VI
wells currently in operation are those associated with two carbon
sequestration test sites supported by the Department of Energy. Class
II wells, of which there are approximately 151,000 currently permitted
in the United States, are all used for the injection of fluids
associated with oil and gas operations. Of that total of 151,000,
approximately 30,000 (20%) are for waste water disposal (from oil and
gas development), approximately 108,000 (71%) are for secondary oil
and gas recovery (waterflooding), and approximately 13,000 (9%) are
for tertiary recovery (enhanced oil recovery). Class V wells are the
most numerous, accounting for almost 79 percent of the total number of
UIC wells; wells used for fluid injection related to geothermal energy
fall within this well class. However, only 239 wells in the United
States among approximately 400,000-650,000 Class V wells permitted in
the country are for geothermal energy. The committee did not examine
the other kinds of wells (which include storm water drainage wells,
septic system leach fields, etc.) in this study so cannot provide a
breakdown of the numbers of these kinds of wells.
______
Response of Mark D. Zoback to Question From Senator Bingaman
Question 1. Your testimony noted that offshore formations similar
to the one utilized by the Sleipner project in Norway and also depleted
oil and gas reservoirs could potentially be suitable for long-term
storage of high volumes of carbon dioxide. The Department of Energy
indicates there may be as much as 7.5 trillion tons of CO2
storage capacity in offshore formations in the Gulf Coast that are
similar to the Sleipner project in Norway. The most recent estimates
from the National Energy Technology Laboratory indicate that there may
be as much as 20 billion tons of CO2 storage capacity in
depleted oil and gas reservoirs.
Question 1a. Could you please comment on these assessments of
storage capacity and their suitability for the long-term storage of
high volumes of carbon dioxide?
Question 1b. Could you provide an estimate of how much storage is
available in the types of formations that you described as having
suitable characteristics for such long-term storage?
Answer. As we noted in our PNAS paper on the potential of triggered
seismicity associated with CO2 storage, there are a large
number of formations in the Gulf Coast that have appropriate
characteristics for long term CO2 storage. In other words,
they are porous, permeable, weakly-cemented, laterally extensive, have
adequate cap rocks and seals, etc. I am not familiar with the screening
criterion used by the Dept. of Energy in their assessment of 7.5
trillion tons of CO2 storage capacity in these formations.
If their criterion considered all of the characteristics enumerated
above, it should be straightforward to calculate the rates at which
CO2 could be injected without generating excess pore
pressure could accommodate the enormous volumes of CO2
generated in the U.S. each year. Obviously, transport of large
quantities of from thousands of point sources throughout
the U.S. to the Gulf Coast would be a formidable operational challenge.
Nonetheless, utilizing appropriate geologic formations in the Gulf
Coast is a far more attractive strategy than utilization of non-ideal
formations (from the perspective of possible earthquake triggering)
that are located more closely to CO2 sources.
With respect to the National Energy Technology Laboratory's
estimate that 20 billion tons of CO2 could be stored in
depleted oil and gas reservoirs, it is important to recognize that this
does not represent very much capacity. Coal burning power plants in the
U.S. alone generate about 2 billion tons of CO2 each year so
that depleted oil and gas reservoirs could accommodate emissions from
coal burning plants for only 10 years. Another consideration is that
successful long-term storage of CO2 in depleted reservoirs
could be compromised by leakage through the cemented annulus of wells
or via damaged well casings. Both are common occurrences in old wells.
In addition, it is important to assure that oil field operations did
not affect the natural geologic seals of the hydrocarbon reservoir.
There are a variety of mechanisms could compromise the reservoir's seal
such as depletion-induced faulting or hydraulic fracturing, either when
the well was first drilled or during subsequent water flooding
operations.
I have not carried out an assessment of the CO2 storage
capacity of the geologic formations I would classify as being ideal for
sequestration. Thus, I cannot respond to question 1b.
Responses of Mark D. Zoback to Questions From Senator Murkowski
Question 1. To the extent that wastewater injection wells are
geologically unavailable in certain Eastern US areas, might those areas
bear a correspondingly remote risk of induced seismicity from natural
gas development?
Answer. It is true that there is a remote risk of triggering
seismicity associated with multistage hydraulic fracturing in
horizontal wells, the typical technique used to produce natural gas
from shale formations. Any given hydraulic fracturing operation
involves pressurization of small volumes of rock (typically a few
hundred feet along the length of the wellbore) for short periods of
time (typically about two hours). Hence, the probability of the
pressurization affecting faults that might induce earthquakes large
enough to be felt at the surface is extremely low. I fully agree with
the conclusion of the NRC report that this is the principal reason why
hundreds of thousands of hydraulic fracturing operations to develop gas
from shale in the U.S. have not produced any confirmed cases of
triggered seismicity. Globally, there has only been one confirmed case
in which hydraulic fracturing associated with shale gas development has
triggered one very small earthquakes big enough to be felt at the
surface. Considering the extremely small number of triggered
earthquakes with hundreds of thousands of hydraulic fracturing
operations clearly demonstrates that the risk associated with shale gas
development is extremely low.
Question 2. The NRC report indicates that the Federal and State
Underground Injection Control (UIC) Programs ``do[es] not address the
issue of seismicity induced by underground injection.'' At the same
time, the current UIC program does require the injection well operator
to perform a site characterization, including identifying the risks
associated with nearby faults if any are located. Furthermore, several
states (including Arkansas, Colorado, Ohio, and West Virginia,) are
currently modifying their UIC Programs to specifically address
seismicity. To this extent, might those state regimes reflect any of
the proposed actions as noted in the report?
Answer. It is good to learn that several states are modifying their
UIC Programs to address the potential for triggered seismicity. If this
has been in response to the NRC report, this is indeed a welcome
development.
______
Responses of William Leith to Questions From Senator Bingaman
Question 1. Dr. Zoback has testified that the risk of venting
stored carbon dioxide from small, induced seismic events is a primary
concern and obstacle to the scaling up of CCS technologies to play a
significant role in mitigating global greenhouse gas emissions to the
atmosphere. Do you agree with this assessment?
Answer. Dr. Zoback's study identified the need to carefully study
any prospective CCS projects and to evaluate potential risks associated
with particular projects. We agree that induced earthquakes could be a
significant risk to the efficacy of large-scale CCS and that this
hazard needs to be carefully studied and better understood. Although
injection of CO2 into depleted oil and gas reservoirs (for
example, as used in secondary oil recovery) may pose a low risk for
induced seismicity, such is not the case during injection of
CO2 into normally pressurized, undepleted aquifers. For
injection in undepleted reservoirs, the geologic sequestration of
CO2 is probably not significantly different from other
large-volume liquid-injection projects, such as wastewater disposal at
depth, for which there are numerous case histories involving
earthquakes large enough to be of concern to the public. One of the
early case histories concerned the injection of 625,000 cubic meters of
wastewater at the Rocky Mountain Arsenal (RMA) well in the mid-1960s,
which induced earthquakes of about magnitude 5 and caused damage to
structures in the Denver, CO, area.
Over the next three years, a DOE-sponsored demonstration project in
Decatur, IL, will inject 1 million tons-about 1.4 million cubic meters
of CO2- into an undepleted brine aquifer within the Mt.
Simon sandstone at a depth of about 2 km. Injection at the Decatur well
began in November 2011. Although the induced earthquakes at this site
have been tiny as of July 2012, it is much too early to know what the
seismic response will be as the injection grows; the total planned
volume of injected CO2 at Decatur is more than double what
was injected at the RMA. If the induced earthquake pattern at Decatur
turns out to be similar to that at RMA, then some of the larger induced
earthquakes that would occur at the site could indeed pose threats to
the integrity of the capping seals. It is also possible that high
pressures generated within the Mt. Simon sandstone could be
communicated to ``hidden'' faults within the underlying granite
basement. Although such faults have not been seen in the seismic data
collected at Decatur so far, it is notoriously difficult to image
faults in deep granitic rocks. Thus, a prudent approach would be to
assume that there could be an earthquake risk to nearby communities
during this project.
To assess these seismic hazards, it is necessary to monitor induced
earthquakes at each CCS pilot project with a seismic network designed
to locate events precisely in three dimensions and thereby determine
the exact nature of the seismic source. Microearthquake locations
enabled by such a network would allow us to identify previously unknown
faults within the underlying basement, as well as determine the maximum
likely fault slip associated with these and other faults, including
those located near the sealing formations. Other types of field and
laboratory research will be needed to achieve a comprehensive
understanding of the risk to reservoir seals from earthquake slip in
various geological settings.
Question 2. As USGS considers the amount of available storage for
CCS, is the possibility of leakage from small seismic events something
that is factored in?
Answer. The 2007 Energy Independence and Security Act (Public Law
110-140, section 711) authorized the USGS to conduct a national
assessment of geologic storage resources for carbon dioxide
(CO2). The methodology that was developed for the national
assessment (Brennan and others, 2010, http://pubs.usgs.gov/of/2010/
1127/) addresses the geographical extent, the capacity, injectivity
(permeability), and the risk associated with potential storage
formations. We evaluate the risk of a potential formation by providing
maps of existing well penetrations which, in some cases, may be
potential CO2 leakage pathways (for example well penetration
maps see Covault and others, 2012, http://pubs.usgs.gov/of/2012/1024/a/
). The USGS methodology also incorporates the Environmental Protection
Agency (EPA) guidelines to prevent CO2 leakage to the
surface and CO2 contamination of underground sources of
drinking water (USDW) and overlying aquifers. EPA's guidelines are: (1)
a regional, well defined sealing unit to be present above each storage
assessment unit, and (2) only assessing storage assessment units that
have formation waters that are greater than 10,000 parts per million
total dissolved solids. The risk of induced seismicity associated with
a particular CO2 storage project depends on local storage
reservoir fluid pressure management and CO2 injection rates
and volumes, and is, therefore, an engineering problem that is not
specifically evaluated in the current USGS CO2 storage
assessment efforts. We do, however, note that a potential storage
formation may be located in a region of the country where natural
seismic risks are more likely. We are incorporating a discussion of the
proximity of a potential storage formation to seismically active areas
in the geologic framework reports for each assessed area that will be
published during the coming year.
Question 3. Dr. Zoback's testimony noted that offshore formations
similar to the one utilized by the Sleipner project in Norway and also
depleted oil and gas reservoirs could potentially be suitable for long-
term storage of high volumes of carbon dioxide. The Department of
Energy indicates there may be as much as 7.5 trillion tons of
CO2 storage capacity in offshore formations in the Gulf
Coast that are similar to the Sleipner project in Norway. The most
recent estimates from the National Energy Technology Laboratory
indicate that there may be as much as 20 billion tons of CO2
storage capacity in depleted oil and gas reservoirs.
Question 3a. Could you please comment on these assessments of
storage capacity and their suitability for the long-term storage of
high volumes of carbon dioxide?
Question 3b. Could you provide an estimate of how much storage is
available in the types of formations that Dr. Zoback has described as
having suitable characteristics for such long-term storage?
Answer a. The North American Carbon Storage Atlas (2012, available
at: http://www.netl.doe.gov/technologies/carbon_seq/global/nacap.html),
published jointly by the Department of Energy and representative
agencies from the governments of Canada and Mexico, indicates that
within the Atlantic, Gulf of Mexico, and Pacific offshore regions of
the United States, there is an estimated range of 467 billion to 6.4
trillion metric tons of potential CO2 storage capacity in
saline formations. The North American Storage Atlas also reports that
oil and gas reservoir CO2 storage resources for the United
States (onshore and offshore) are approximately 124 billion metric
tons. In addition, a report by Kuuskraa and others (2011, http://
www.netl.doe.gov/energy-analyses/pubs/storing percent20co2 percent20w
percent20eor_final.pdf), that was prepared for the National Energy
Technology Laboratory, indicates that nearly 20 billion metric tons of
CO2 may be needed to economically produce oil using ``Next
Generation'' enhanced-oil-recovery techniques utilizing a mixture of
naturally occurring CO2 produced from CO2-rich
underground reservoirs and CO2 from anthropogenic sources.
The resource numbers reported by the North American Carbon Storage
Atlas (2012), the Carbon Sequestration Atlas of the United States and
Canada (NETL, 2010, http://www.netl.doe.gov/technologies/carbon_seq/
natcarb/index.html), and Kuuskraa and others (2011) are general
estimates of potential geologic CO2 storage resources in
various regions of North America and the United States.
The USGS is currently working on a comprehensive assessment of
onshore areas and State waters that will identify and evaluate the
Nation's potential CO2 storage resources. Data used in the
previous DOE assessments and data provided by State geological surveys
are being integrated with USGS data to conduct these assessments. The
USGS typically does not assess Federal offshore U.S. resources and
refers to or works with the Bureau of Ocean Energy Management (BOEM)
when evaluating offshore resources. By 2013, the USGS Geologic
CO2 Sequestration Assessment Project will have geologically
characterized and assessed more than 200 potential storage formations
in 37 basins across the United States. This assessment will be the most
comprehensive accounting of the Nation's CO2 storage
potential ever completed, and provide quantitative, probabilistic
estimates of resource storage potential. A summary report is in
preparation that will provide the storage assessment results for the
Nation. In addition, the Geologic CO2 Sequestration Project
is building an assessment methodology and associated engineering
database that can be used for a detailed national assessment of
recoverable hydrocarbon resources associated with CO2
injection and sequestration. USGS assessments are impartial, robust,
statistically sound, and widely cited in the scientific literature and
public media.
Answer b. The USGS assessment of CO2 storage capacities
of onshore areas and State waters of the United States is scheduled to
be completed in 2013. We do not have resource estimates available at
this time. As mentioned in the answer for question 2 above, the risk of
induced seismicity associated with a particular CO2 storage
project depends on local storage reservoir fluid pressure management
and CO2 injection rates and volumes, and is, therefore, a
scientific and engineering problem that is not specifically evaluated
in the current USGS CO2 storage assessment. The scope of
research needed to better predict seismic risk in particular geologic
settings is discussed further in the answer to question 1. In order to
provide resource estimates for formations that are not likely to be
prone to induced seismicity, an additional set of screening geologic
and engineering criteria will need to be developed and applied to the
assessment results generated by the current USGS Geologic
CO2 Sequestration Assessment Project.
Question 4. Is USGS doing, or planning to do work to better
understand the risks of induced seismicity due to large-scale CCS as
indicated in the report? Are there efforts at other agencies or
national labs?
Answer. The USGS is currently proposing to monitor induced
seismicity at one or more DOE-funded CCS pilot projects, and we have
been in contact with the operators of two such projects: one at
Decatur, Illinois, and the other at Kevin Dome, northern Montana.
Although no agreements have been reached so far, the USGS, as an
objective science agency, is in a unique position to provide scientific
knowledge needed to better understand and mitigate the potential
seismic risk associated with CCS. In so doing, it is critical that
these data and analyses be maintained in the public domain, to be
amenable to full scientific peer review and to maintain public trust.
The USGS recently purchased seismic recording equipment sufficient
for a ten-station monitoring network that includes three seismometers
that will record down boreholes about 500 feet deep. In the lower-noise
environment at the bottom of these boreholes, we anticipate that the
magnitude threshold for earthquake detection will be reduced
considerably.
The DOE-funded National Laboratories have conducted earthquake
monitoring at CCS sites in Algeria and Australia, and perhaps other
sites. In addition, the National Laboratories maintain an active and
highly visible program in monitoring induced seismicity associated with
Enhanced Geothermal Systems demonstration projects at several locations
in the United States.
The President's budget request for fiscal year 2013 includes, as
part of the hydraulic fracturing initiative, a proposed $1.1 million
increase to the Earthquake Hazards Program for work assessing the
factors controlling the triggering of earthquakes due to fluid
injection activities, developing a method to forecast the magnitude-
frequency distributions of induced earthquakes including the maximum-
magnitude earthquakes resulting from a specified fluid injection
operation, and accounting in National Seismic Hazard Maps for the
additional hazards due to fluid disposal-induced earthquakes.
Question 5. The NAS study we heard about indicates that there have
been relatively few induced seismic events that are directly
attributable to the energy technologies considered here. At the same
time, your testimony shows a sharp increase in the number of mid-
continent earthquakes that USGS has measured over the past decade.
Question 5a. Is there something else going on that could be causing
this trend in earthquakes?
Question 5b. Is this a measurement issue, or is it just that more
work needs to be done to figure out what caused these earthquakes?
Answer a. USGS believes that the increase in the number of
magnitude 3 and larger earthquakes in the U.S. midcontinent is most
probably caused by increased wastewater injection activities. The
increase is most pronounced in Arkansas, along the Colorado-New Mexico
border, and in Oklahoma. Earthquakes have also been noted in Texas,
Ohio, and West Virginia, where they are otherwise uncommon. Research
published since the NAS report was written demonstrates that the
increase in earthquake activity in Arkansas is due to injection of
wastewater related to shale gas development and production: http://
srl.geoscienceworld.org/content/83/2/250. Studies recently completed by
the USGS show that the earthquakes along the Colorado-New Mexico border
are due to wastewater injection from coal-bed methane production in the
Raton Basin. Studies to identify the underlying cause or causes of the
increase in seismicity in Oklahoma are underway.
Answer b. USGS is certain that the rate change discovered is not a
measurement issue. Three lines of evidence support this conclusion.
First, earthquakes with magnitudes of 3 and above (those used to detect
the rate change) have been uniformly detected through the midcontinent
since the 1970s by the USGS. Second, while improvements in seismic
instrumentation and installation of additional seismic stations have
improved earthquake location accuracy, the algorithms for computing
magnitude have remained unchanged. Third, both the USGS catalog and the
catalog of the Oklahoma Geological Survey independently document the
increase in activity that began in that state in 2009.
To understand the factors that have led to the increased rate of
induced earthquakes in the central and eastern United States, more work
is clearly needed. Site-specific investigations will be required to
identify the underlying causes and improve our understanding so that
the risk of induced earthquakes can be managed in the future.