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Environmental Issues Surrounding
Shale Gas Production
The U.S. Experience
A Primer
The Subcommittee has been struck by the enormous difference in perception about
the consequences of shale gas activities. Advocates state that fracturing has beenperformed safely without significant incident for over 60 years, although modern shale
gas fracturing of two mile long laterals has only been done for something less than adecade. Opponents point to failures and accidents and other environmental impacts,
but these incidents are typically unrelated to hydraulic fracturing per se and sometimes
lack supporting data about the relationship of shale gas development to incidence andconsequences. An industry response that hydraulic fracturing has been performed
safely for decades rather than engaging the range of issues concerning the public will
not succeed. - U.S. Energy Secretary Steven Chus Shale Gas Advisory Board, InitialReport, August 11, 2011.
Terence H. Thorn
April 2012
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Environmental Issues Surrounding
Shale Gas ProductionA Primer
The shale gas revolution of the last few years has changed the perception of the
natural gas industryandhas dramatically revitalized natural gas exploration and
production while unlocking vast new reserves of natural gas. The increasing cost and
complexity of producing conventional reserves has been countered by new production
techniques that allow access to an abundance of relatively low cost unconventional
reserves.
Shale gas development is receiving a great deal of public scrutiny and the debate over
the environmental impact of this new technology has raised some genuinely important
issues. Environmentalists claim the process could contaminate rivers and aquifers and
pollute the air, while the natural gas companies point out that the fracking method has
been used safely for decades.
Industry, regulators and many members of the environmental community believe that
these concerns can be readily addressed by the employment of best drilling practices,
research and investment in new technologies, and rigorous regulatory oversight. The
challenges for everyone will be to both protect the environment, public health and
safety while realizing the full economic and environmental benefits of expanded shale
gas development.
This paper provides an overview of the major environmental issues surrounding shale
gas development and the regulatory and technical response to identify, prevent and
mitigate these impacts.
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matching a nearly 6% hike in demand. Gas production was bolstered by a nearly 30%
jump in shale play output, according to statistics published in the Energy Information
Administration's (EIA) Annual Energy Review for 2010 (Released October 19, 2011).
Shale gas production accounted 23 percent of U.S. production in 2010 and is forecast
reach 49% of production in 2035 (early release, EIA Annual Energy Outlook 2012,
January 23, 2012).
Shale and tight gas now account for almost two thirds of the daily gas produced in the
United States. In the U.S, there has never been an energy resource that escalated its
market share from essentially zero to 25 percent in just five years. Bentek Energy, LLC
estimates natural gas production in West Virginia and Pennsylvania now averages almost
4 billion cubic feet per day (Bcf/d), more than five times as much as the average from
2004 through 2008 and accounts for over 85% of total Northeastern U.S. natural gasproduction.
Source: U.S. Energy Information Administration, August 2011
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How Much Shale Gas Is There?
A U.S. Geological Report (USGS), released August 25, 2011, estimates that the eight-
State Marcellus Shale region contains some 84 trillion cubic feet of undiscovered,
recoverable natural gas. That amount is far higher than the geological service had
estimated in a 2002 report which estimated 2 trillion cubic feet of gas reserves, but far
below a 2011 estimate by the Energy Information Administration. EIA in January 2011
had estimated 410 trillion cubic feet (tcf) of recoverable gas. The conflicting reportsprompted confusion about the extent of natural gas reserves available in the Marcellus
region.
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The Washington, D.C. based research group Resources For the Future, in an Issue Brief,2
explained that questions about the differences likely lie in a misunderstanding of the
definitions of shale gas resource classifications used by the U.S. Energy Information
Administration (EIA) and USGS. The USGS estimate of 84 trillion cubic feet (tcf)
measures only undiscovered resources outside known fields in the Marcellus. The EIAs
410 tcf estimate of inferred reserves is for known but unproven fields. The two estimates
also differ in their respective analysis of well spacing and estimates of average
production per well.
However, the EIA has said they will adopt the undiscovered resource estimate from the
USG. The new estimate should simply replace the previous estimate of undiscovered
resources and not the current estimate of inferred reserves.
In its early release of the Annual Energy Report for 20123, the EIA said it now thinks
there are about 482 trillion cubic feet of shale gas in the U.S., down from earlier
estimates of 827 trillion cubic feet. The bulk of the downward revision was the result of
changing expectations for the Marcellus to 141 trillion cubic feet. The EIA modified its
estimate based on the USGS latest findings, and on recent well data from the state of
Pennsylvania. Despite the lower estimates, the agencys report noted that shale gas would
continue to have a growing impact on the broader energy market. The share of natural gas
produced by drilling in shale formations is projected to more than double, from 23
percent in 2010 to 49 percent in 2035.
At a hearing before the US Senate Committee on Energy and Natural Resources on
January 31, 2012, EIA Acting Administrator Howard Gruenspecht downplayed the
significance of a 65% reduction in EIA estimates for technically recoverable,
undiscovered resources in the Marcellus shale, noting that as we gain more and more
experience with actual drilling, the numbers will always tend to evolve to total
2Undiscovered Resources and Inferred Reserves, David w. McLaughlin, Issue Brief11-15, October 2011.3
January 23, 2012. http://www.eia.gov/forecasts/aeo/er/
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recoverable resource. He also noted that ultimately resource estimates will not be the
primary driver of US industry activity. It will be lower drilling costs and increased well
productivity, rather than size of the US resource base.
Environmental Concerns
As with any rapidly expanding new technology, several major environmental concerns
have developed over the effects of shale gas development on air and water quality: the
large water requirements and the improper disposal of waste water, the possibility that
underground fracking fluids can migrate into aquifers, and that shale gas operations not
only contribute to poor air quality near drilling operations but significantly add GHG
emissions to the atmosphere.
A. Water Use and Wastewater Disposal
It can take two to five million gallons (7-19 million liters) of water to frack a well, and a
well may be fracked multiple times. Even if some of the water can be recycled, the
process requires a major withdrawal from the aquifer or other water resources. As shale
development continues to grow in the Marcellus, water usage for well fracking could
reach 650 million barrels per year in Pennsylvania, New York and West Virginia,
according to a report done earlier this year for the U.S. Department of Energy and state
authorities. It sounds like a lot until its compared to the other water uses in the three
states. Water used in shale development is a fraction of total water usage for agricultural,
industrial and recreational purposes. In the states In the Marcellus, for example, the total
volume of water needed to meet estimated peak shale gas development would be about
0.65 billion barrels per year, which represents about 0.8 percent of the 85 billion barrels
per year that are currently consumed in the Marcellus basin states. 4
In Texas, Dan Hardin, the resource planning director for the Texas Water Development
4 Arthur, D., Uretsky, M, and Wilson, P., Water Resources and Use for HydraulicFracturing in the Marcellus Shale Region, All Consulting, p. 3.http://www.netl.doe.gov/technologies/oil-gas/publications/ENVreports/FE0000797_WaterResourceIssues.pdf.
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Board, said water use for fracking was not expected to exceed 2 percent of the statewide
total. But drilling can send water use numbers much higher in rural areas. For example,
Dr. Hardin projects that in 2020, more than 40 percent of water demand in La Salle
County, in the Eagle Ford Shale, will go toward fracking. Until recently, no water went
toward fracking there.
Coal and nuclear power plants, in particular, draw many times more water and represent
over 70% of the water used in the three state area. Shale gas producers are quick to point
out that ten times as much water is required to produce the equivalent amount of energy
from coal. Ethanol production, where milled grain is mixed with water and enzymes to
create slurry, can require as much as a thousand times more water to yield the same
amount of energy from natural gas.5
Access to sufficient water is critical to shale gas development, but cumulative effects on
the sources of large water withdrawals must be managed. Industry is making tremendous
progress in managing water withdrawals and learning to treat and use produced water,
reducing the water demands of shale gas drilling.
With each round of fracking, about half of the fracking fluid returns to the surface along
with the gas, via the collection pipes. The returned fracking fluid, now called wastewater
or flowback, is either trucked to water treatment plants that may or may not be designed
to handle fracking chemicals, reinjected into old wells, or stored in large, tarp-lined pits,
where it is allowed to evaporate. The wastewater often contains a high salt level,
dissolved solids, oil, chemicals, and added materials (such as sand or ceramic grains).
Many environmentalists have severely criticized the handling of wastewater, claiming it
results in toxic waste and surface water contamination. They also argue that fracking
fluids could migrate from the gas-bearing layers, which are over 5,000 feet below the
5 The National Renewable Energy laboratory estimates of water usage during ethanolproduction range from 3 to 4 gallons of water used per gallon of ethanol produced or over400,000 gallons per day for a 50 million per year facility.
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surface, up to water tables often less than 500 feet from the surface and contaminate
drinking supplies. Environmental community documentaries like "Gasland," assert that
hydraulic fracturing has been responsible for water pollution and the presence of methane
in water supplies.
A key problem is the disposal of the fracking fluid. As described in the Vaughn and
Purcell study cited below, fracking chemicals and drilling waste are more hazardous
above ground than several miles underground and pose a more serious environmental
hazard than potential contamination of groundwater from fracking.
In the Southwest U.S., producers reinject the fluid into abandoned wells. States like
Texas have many deep underground injection wells, regulated by the U.S. Environmental
Protection Agency, where companies dispose of the salty and chemical- and mineral-
laden shale wastewater. In the northeast United States there is a shortage of injection
wells for disposal of wastewater and sludge. Some of that waste is being sent to existing
underground waste dumps, leading to the possibility of spills, or being hauled to waste
water treatment plants that may or may not be capable of processing the wastewater.
Since these problems were highlighted, most drilling companies in Pennsylvania have
stopped sending their wastewater through treatment plants that were unable to remove
many of the contaminants before the water was discharged into rivers. State regulators
and drinking water operators are also now testing more regularly for radioactive and
other toxic elements in the drilling wastewater.
B. Groundwater Contamination
Although much of the water used in fracking is collected from the well and processed,
there are concerns that potentially carcinogenic chemicals can sometimes escape and find
their way into drinking water sources. Gasland promoted the idea that shale gas leaking
into drinking supplies allowed tap water to ignite.
Fluids are used to create the fractures in the formation and to carry a propping agent
(typically silica sand), which is deposited in the induced fractures to keep them from
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closing up. Water and sand make up 98 to 99.5 percent of the fluid used in hydraulic
fracturing. In addition, chemical additives are used. The exact formulation varies
depending on the well.6
The chart below taken from Modern Shale Gas Development in the United States: A
Primer (April 2009, U.S. DOE)7 demonstrates the volumetric percentages of additives
that were used for a nine stage hydraulic fracturing treatment of a Fayetteville Shale
horizontal well. Evaluating the relative volumes of the components of a fracturing fluid
reveals the relatively small volume of additives that are present. The additives depicted
on the right side of the pie chart represent less than 0.5% of the total fluid volume.
Overall the concentration of additives in most slickwater fracturing fluids is a relatively
consistent 0.5% to 2% with water making up 98% to 99.5%.
Source: Modern Shale Gas Development in the United States, U.S. DOE, NETL, April 2009.http://www.netl.doe.gov/technologies/oil-gas/publications/epreports/shale_gas_primer_2009.pdf
Typical shale gas deposits are located several thousand feet below the deepest potential
sources of underground drinking water. Further, the low permeability of shale rock and
other intervening formation horizons present additional impediments to the flow of
6 For a list of chemicals used in fracking fluid see http://fracfocus.org/chemical-use/what-chemicals-are-used7
http://fracfocus.org/node/93
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fracking chemicals from target zones upward into aquifers. The likelihood of water
contamination as a consequence of fluids migration up through several thousand feet of
strata is extremely unlikely.
The gas industry asserts there has never been a documented case in the U.S. of
groundwater contamination caused by fracking. In 2011 EPA Administrator Lisa Jackson
told the U.S. Congress that there had been no proven cases where the fracking process
itself has affected water.
However, in their December 2011 draft report Investigation of Ground Water
Contamination near Pavillion Wyoming, EPA reported that its investigation of
groundwater in Pavillion, Wyo., found chemicals consistent with natural gas production
and hydraulic fracturing fluids. 8 EPA began investigating water-quality concerns in
private drinking water wells 3 years ago at the residents requests in the West-Central
Wyoming community, about 20 miles northwest of Riverton. Since that time, EPA said
it has worked with Wyoming state government officials, local residents, and Encana Oil
& Gas (USA) Inc., the gas field's owner, to assess groundwater quality and identify
potential contamination sources. Its Denver regional office released a draft analysis of its
data for public comment and independent scientific review. Encana representatives have
questioned the source of some chemicals found by EPA and believe the preliminaryfindings are conjecture, not fact, and only serve to trigger undue alarm. Others have
questioned the EPA sampling process and have noted this is a very old field and
contamination could have come from surface spills.
The EPA initiated a 45-day comment period that was to have ended Jan. 27, 2012. On
March 29, 2012, EPA extended the public comment period to October 16, 2012.
EPA also plans a peer review by independent scientists that is expected to take 30 days.
On January 31, 2012 EPA posted 622 files related to the investigation at its web site.9
Testifying before Congress on February 1, 2012 James B. Martin, EPAs Region 8
administrator in Denver, told the House Science, Space and Technology Committees
8 http://www.epa.gov/region8/superfund/wy/pavillion/index.html9http://www.epa.gov/region8/superfund/wy/pavillion/docs.html. For the report and other
documentation see http://www.epa.gov/region8/superfund/wy/pavillion/.
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Energy and Environment Subcommittee that the draft report never implied hydraulic
fracturing was unsafe and made clear that the causal link to hydraulic fracturing has not
been demonstrated conclusively, and that our analysis is limited to the particular geologic
conditions in the Pavillion gas field and should not be assumed to apply to fracturing in
other geologic settings. Pavillion is unusual in that commercial natural gas is present at
depths as shallow as 1,100 feet and because there is no cap rock forming a barrier
between the deeper natural gas and shallow intervals. Therefore, over the geologic ages,
this has allowed the upward migration of deeper natural gas to shallow depths. The
agency agreed with Wyoming state regulators on March 8, 2012 to conduct more tests at
a site in Pavillion.
Most agree that more likely candidates as sources of possible water contamination
include improper well design, inadequate surface casing and substandard or improper
cementing, improper handling of surface chemicals, improper design/performance of
holding ponds, and improper storage and disposal of wastes and produced water. More
stringent design standards are being adopted, and more active regulatory oversight is
being exercised. These steps will reduce the incidence of such problems.
A study conducted by the Energy Institute at the University of Texas at Austin (Fact-
based Regulation for Environmental protection in Shale Gas Development, February
2012)), found that many problems attributed to hydraulic fracturing are related to
processes common to all oil and gas drilling operations, such as drilling pipe
inadequately cased in concrete. Many reports of contamination can be traced to above-
ground spills or other mishandling of wastewater produced from shale drilling and not
from hydraulic fracturing. Others cautioned that although the study didnt confirm any
cases of drinking water contamination caused by fracking, that does not mean such
contamination is impossible or that hydraulic fracturing chemicals cant get loose in theenvironment in other ways (such as through spills of produced water).10
Ann Davis Vaughan and David Pursell, ("Frac Attack: Risks, Hype, and Financial Reality
10http://energy.utexas.edu/index.php?option=com_content&view=article&id=151&Itemi
d=160
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of Hydraulic Fracturing in the Shale Plays." Reservoir Research Partners; and Tudor,
Pickering, Holt & Co.), summarize the available studies and information on hydraulic
fracturing and provide an objective look at the debate. The authors confirm that water-
supply contamination from so-called stray gas occurs more often from failures in well
design and construction, breaches in spent hydraulic-fracturing water-containment ponds,
and spills of leftover natural gas liquids used in drilling. In this respect, waste disposal
and safe materials handling are the biggest challenges to producers.
The authors analyze incidents of contamination cited by environmental advocates as
evidence of contamination caused by fracking and conclude that most of those incidents
are either naturally occurring gas in water sands or problems caused by mistakes in well
design -- improper cementing -- not related to fracking.
C. Methane Emissions
Methane emissions from natural gas extraction, especially shale gas, have been getting a
lot of attention in recent months. A paper by Cornells Robert Howarth (Methane and
the greenhouse-gas footprint of natural gas from shale formations, March 13, 2011,
Climatic Change)11
argues that natural gas from fracking operations can be worse for the
atmosphere than coal because of methane seepage into the atmosphere. The Cornell study
suggests that life cycle greenhouse gas (GHG) emissions from shale gas are 20%-100%
higher than coal on a 20-year timeframe basis. This contradicts a National Technology
Energy Laboratory (NETL) study (Life Cycle Greenhouse Gas Analysis of Natural Gas
Extraction & Delivery in the United States, May 2011) which, on an electricity-generation comparison basis, shows that natural gas base load has 50% lower GHG
emissions than coal on a 20 year timeframe basis.12 Worldwatch Institute and Deutsche
Bank, (Comparing Life-Cycle Greenhouse Gas Emissions from Natural Gas and Coal,
11 http://www.sustainablefuture.cornell.edu/news/attachments/Howarth-EtAl-2011.pdf12DOE/NETL (2010) Life cycle analysis: natural gas combined cycle (NGCC) powerplant, DOE/NETL-403- 110509, p127. http://www.netl.doe.gov/energy-analyses/pubs/NGCC_LCA_Report_093010.pdf
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August 25, 2011) 13 concludes that on average, U.S. natural gas-fired electricity
generation emits 47 percent less GHGs than coal from source to use using the IPCCs
100-year global warming potential (GWP- see 4 below) for methane of 25.
The Howarth paper has been criticized in four areas:
1) First, the data for leakage from well completions and pipelines is very
incomplete and taken from a few isolated cases reported in industry
magazines, and numbers for pipeline leakage from long-distance pipelines in
Russia.
2) The gas-to-coal comparisons are all done on a per energy unit basis and
compare the amount of emissions involved in producing a gigajoule of coal
with the amount involved in producing a gigajoule of gas. Since a gigajoule
of gas produces a far more electricity than a gigajoule of coal (assuming an
electricity conversion efficiency of 60% for natural gas and 30% conversion
efficiency for older coal plants), a per kWh comparison is the correct one.
3) The technological solutions for methane leakage (better well completion
techniques, better pipeline integrity) are relatively inexpensive and exist today
compared to solving the GHG emissions problems of a coal plant (Carbon
Capture and Storage or CCS).
4) Howarth uses 20 year GWPs to compare coal with gas, rather than the 100-
year figure used by the Intergovernmental Panel on Climate Change. GWP is
a relative measure of how much heat a greenhouse gas traps in the atmosphere.
It compares the amount of heat trapped by a certain mass of the gas in
question to the amount of heat trapped by a similar mass of carbon dioxide. A
GWP is expressed as a factor of carbon dioxide (whose GWP is standardized
to 1). For example, the 20 year GWP of methane is 72 which means if the
same weights of methane and carbon dioxide were introduced into the
atmosphere, methane will trap 72 more times heat than the carbon dioxide
over the next twenty years.
13http://www.worldwatch.org/system/files/pdf/Natural_Gas_LCA_Update_082511.pdf
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Although methane is about 21 times more powerful at warming the
atmosphere than carbon dioxide, methane has much shorter lifespan than
CO2- approximately 12 years compared to more than a century for
CO2. Howarth amplified the greenhouse gas footprint of unconventional gas
development by measuring the global warming potential of leaked methane
over a 20-year time frame, rather than the 100 years more commonly. Over a
100-year period the GWP of methane is 25. That choice, critics say, inflates
methanes global warming footprint unnecessarily, allowing the authors to
reach their controversial conclusion that unconventional natural gas
development is worse than burning coal.
In addition to the Worldwatch Institute and NETL studies cited above, a study performed
by researchers at Carnegie Mellon, whose work was funded by the Sierra Club,
concluded that life cycle GHG footprint for shale gas is 20 to 50% lower than that for
coal. Finally a study by IHS Global Energy Research Associates did not calculate relative
GHG footprints, but it noted some of the same problems with the Howarth study. A
second study from Cornell University also concludes that the Horwath study by Howarth
was "seriously flawed," and that shale gas has a GHG footprint that is only one-third to
one-half that of coal. The new study was conducted by L.M. Cathles III and others and
published online in the journal Climatic Change Letters on January 3, 2012.14
Finally a
study from the National Oceanic and Atmospheric Administration's Earth Systems
Research Laboratory (ESRL) in Boulder, Colorado maintains that fields that rely on
fracking tend to leak more methane than fields with conventional wells. The study has
not been released and is currently in press at the Journal of Geophysical Research. The
study is not a life cycle analysis and is a snapshot of emission events in a specific area
and is comparing a localized data point with a national estimate for all wells and
processing plants. For a detailed discussion of this issue and the studies, see Appendix III.
14A commentary on The greenhouse-gas footprint of natural gas in shale formations byR.W. Howarth, R. Santoro, and Anthony Ingraffea, Lawrence M. Cathles III & LarryBrown & Milton Taam & Andrew Hunter.http://www.springerlink.com/content/x001g12t2332462p/
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The full life cycle impact of natural gas production is attracting increased interest as
studies such as Horwaths surface and energy policies include an expanded role for
natural gas. Between its 2010 and 2011 editions of the Inventory, the EPA significantly
revised its methodology for estimating GHG emissions from natural gas systems,
resulting in an estimate of methane emissions from Natural Gas Systems in 2008 that was
120 percent higher than its previous estimate. For the 2011 Inventory, the EPA modified
its treatment of two emissions sources that had not been widely used at the time of the
1996 study, but have since become common: gas well completions and workovers with
hydraulic fracturing. It also significantly modified the estimation methodology for
emissions from gas well cleanups, condensate storage tanks, and centrifugal compressors.
Any sources of so-called greenhouse gases are important and every effort to reducing
those methane emissions should be a priority for the natural gas industry. The Howarth
study is an important reminder that the whole life cycle is what matters, not just the
immediate emissions.
D. Other Air Emissions
Other air quality impacts from shale gas operations also include emissions of carbon
dioxide stripped from the gas, sulphur dioxide and/or hydrogen sulphide from treating
sour water for use as hydraulic fracture fluid, and NOX and other emissions from
compressors, pollution from diesel engines; and ground level ozone. EPA has identified
these emissions as one of the largest sources of air pollution from the energy industry.
DOEs Shale Gas Subcommittee supported rigorous standards for new and existing
sources of methane, air toxics, ozone precursors and other air pollutants from shale gas
operations and cites EPAs July 28, 2011 proposed amendments to oil and gas air
emissions standards as achieving significant benefits in controlling these emissions. The
proposed rules were finalized on April 17, 2012 (see page 22 below). EPA was under a
court-ordered deadline to develop the air-quality rules tied to fracking after being sued by
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environmental groups.
E. Waste Water Injection Causes Minor Earthquakes
A 2.7-magnitude earthquake rocked Ohio on Christmas Eve 2011, followed by a 4.0-
magnitude quake on New Year's Eve. Pumping wastewater from shale gas operations
deep underground was the likely cause of minor earthquakes recorded recently in Ohio,
scientists said. All of the quakes were recorded within a 5-mile radius of a wastewater
injection well run by Northstar Disposal Services. It appears the quakes were triggered by
wastewater from shale gas operations that acted as a lubricant at a fault located about 1
mile underground.
On November 5, an earthquake measuring 5.6 rattled Oklahoma and was felt as far away
as Illinois. Until two years ago Oklahoma typically had about 50 earthquakes a year, but
in 2010, 1,047 quakes shook the state. OGS Austin Holland's August 2011 report,
"Examination of Possibly Induced Seismicity from Hydraulic Fracturing in the Eola Field,
Garvin County, Oklahoma" Oklahoma Geological Survey OF1-2011, studied 43
earthquakes that occurred on January 18, ranging in intensity from 1.0 to 2.8 Md
(milliDarcies.) The report's conclusions state, "Our analysis showed that shortly after
hydraulic fracturing began small earthquakes started occurring, and more than 50 were
identified, of which 43 were large enough to be located."
As part of its ongoing effort to study a variety of potential impacts of U.S. energy
production, United States Geological Survey (USGS) scientists have been investigating
the recent increase in the number of magnitude 3 and greater earthquakes in the
midcontinent of the United States. Beginning in 2001, the average number of earthquakes
occurring per year of magnitude 3 or greater increased significantly, culminating in a six-
fold increase in 2011 over 20th century levels. The scientists then took a closer look at
earthquake rates in regions where energy production activities have changed in recent
years. The lead researcher in the paper15
, Mr. Ellsworth, believes the increased number of
15Are Seismicity Rate Changes In the Midcontinent Natural or Manmade?
ELLSWORTH, W. L. et al, US Geological Survey. April 2012.
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government and state governments have long-established experience regulating the oil
and gas industry.
Working to develop regulations and protocols that will minimize drillings environmental
impact, a common focus of industry and regulators has been the importance of a
continuous improvement in the various aspects of shale gas production that relies on best
practices and is tied to measurement and disclosure.
Those states that have seen a dramatic spike in exploration and production activity have
been quick but deliberate in adjusting their regulations accordingly, and many of the
stated goals of the environmental groups on hydraulic fracturing, such as chemical
disclosure and management of water resources, have been or are being addressed by state
regulation such as the programs taking effect in Texas, Wyoming, Colorado, Oklahoma,
New York and Pennsylvania. Nine states already have disclosure laws for hydraulic
fracturing. But only one stateColoradorequires what the BLM would require: the
names and concentrations of the individual chemicals pumped into each well.
In June 2011, Texas became the first state to require publicdisclosure of chemicals used
in hydraulic fracturing operations. Specifically, in 2011 the Texas legislature passed a
new law (HB 3328) that required chemical ingredients subject to Material Safety Data
Sheets to be posted to a public website. FracFocus.org is specifically referenced. In
addition, information about other ingredients must be provided to the Texas Railroad
Commission and made publicly accessible. Information about the total volume of water
used in fracturing operations must also be publicly filed with the Commission. Louisiana,
New Mexico, Colorado, Arkansas, Wyoming and Oklahoma are developing similar
regulations. The final Texas rule was adopted on December 27, 2011 and went into effect
February 1, 2012 for wells permitted after on or after this date. Colorado's new regulation,
effective April 1, 2012, goes further than most in requiring drillers to disclose all the
chemicals they use in frackingnot just the chemicals considered potentially hazardous.
The American Petroleum Institute (API) has developed a series of shale development
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guidance documents that encompass well integrity and production operations. 16 ).
Historically, API standards have been integrated into state regulatory frameworks. Such
an approach benefits all parties in shale gas production: regulators will have more
complete and accurate information; industry will achieve more efficient operations; and
the public will see continuous, measurable improvement in shale gas activities. The
Interstate Oil and Gas Compact Commission, the Marcellus Shale Coalition, the State
Review of Oil and Natural Gas Environmental Regulation (STRONGER), the
Groundwater Protection Council, and the Intermountain Oil and Gas Project, are all
working to identify best practices.
At the Federal Government level, the U.S. Environmental Protection Agency(EPA)
has begun a new study of hydraulic fracturing at the direction of Congress and is in the
early stages of collecting information on the potential environmental impact of fracking.
The study is a welcomed first step in a scientific analysis of the risks of fracking and in
potentially developing industry best management practices. The agency recently released
a proposed Study Plan that lays out a broad approach to its study of hydraulic fracturing
and the potential impacts on drinking water sources. The initial results will be available at
end of 2012, with a final report due in 2014.
On July 28, 2011, the U.S. Environmental Protection Agency (EPA) announced the
release of a 604-page suite of proposed air emission regulations for oil and gas
production, processing, transmission, and storage. The new rules will leverage
operators ability to capture and sell natural gas that currently escapes into the air,
resulting in more efficient operations while reducing harmful emissions, including
methane leakage, that can impact air quality in surrounding areas and nearby states.
The proposed regulations would make green completions17 mandatory and older pipelines
and processing plants must also be retrofitted with new gear to reduce leaks, something
16 www.api.org/policy/exploration/hydraulicfracturing/index.cfm#guidance17 A green completion is where gas and liquid hydrocarbons are separated from thewastewater using tanks, gas-liquid-sand separator traps, and gas dehydration equipment.If gathering lines are not available to collect the gas, it can be flared.
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that can be easily done for low cost and with existing technology. In fact, many drilling
companies already use green-completion systems. Southwestern Energy Co. and Devon
Energy Corp. say they already use systems to capture methane and other fumes at wells,
the key requirement of a rule that may be issued as early as today. Drilling hasnt slowed
in Colorado or Wyoming where technology to capture emissions has been required by the
state since 2009 and 2010. Of wells drilled in 2011 by eight members of Americas
Natural Gas Alliance, 93 percent used systems to capture stray gas, according to Sara
Banaszak, chief economist with the Washington-based group.
Covered operations and equipment would include completions and recompletions of
hydraulically fractured natural gas wells, compressors, pneumatic controllers, various
storage tanks, and gas processing plants.
The Interstate Natural Gas Association of America, a trade group that represents natural
gas and oil pipeline companies, in an October 11 letter to Assistant Administrator, Office
of Air and radiation, Gina McCarthy, stated that the Environmental Protection Agency
had no defensible reason to include natural gas transmission pipelines in a proposed
emissions rule for the oil and gas industry. The American Petroleum Institute has also
criticized the proposed rule and asked EPA to give businesses more time to review the
rule, which would also cut air pollution from drilling and production activities.
On April 17, 2012, the EPA announced that companies would now have until January 1,
2015 (rather than the 60 days in the original proposal) to begin using "green completion"
equipment that can pare emissions at natural gas wells. It is estimated that 25,000 new
and existing natural gas wells are fractured or re-fractured each year. API President Jack
Gerard had warned in earlier that just 300 sets of the emissions-reducing equipment were
available in the U.S. EPA Assistant Administrator Gina McCarthy said moving back the
deadline will "provide time for industry to order and manufacture enough equipment as
well as train personnel to conduct green completions. During the transition period,
companies can use both green completions and flaring. After Jan. 1, 2015, companies
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cannot only use flaring. 18
On October 19, 2011, the U.S. Environmental Protection Agency unveiled plans to set
national standards for wastewater discharges from natural gas drilling amid growing
concern over water pollution from fracking. The EPA said in a statement that it would
accept comments for new standards over the coming months for shale gas extraction as
well as for gas from underground coal beds. Noting that President Obama has made clear
that natural gas has a central role to play in our energy economy, EPA Administrator Lisa
Jackson said in a statement that we can protect the health of American families and
communities at the same time we ensure access to all of the important resources that
make up our energy economy. The American Petroleum Institute argues that voluntary
industry standards better deal with the produced water from natural gas drilling in that the
industry works with state regulators directly to minimize environmental impact during
the acquisition of water for drilling, water use during fracking operations and treatment
and disposal of water and other fluids recovered after the well is completed. Industry
officials further note that there is no one-size-fits-all approach to managing water at
natural gas sites, because of the wide variations in geology. API has issued its own
guidelines for water management that apply to hydraulic fracturing.
In a November 23, 2011 letter to Earthjustice, EPA stated that it will use the Toxic
Substances Control Act (TSCA) to draft regulations requiring companies to disclose
information regarding "chemical substances and mixtures used in hydraulic fracturing."
Although the EPA has not indicated what information will be subject to disclosure, the
agency stated that it will attempt to avoid duplication of "the well-by-well disclosure
programs already being implemented in several states," and that it anticipates that its
regulations will "focus on providing aggregate pictures of the chemical substances and
mixtures used in hydraulic fracturing."
18 NRDC documented the savings available from green completions and nine otherpollution control measures in a report calledLeaking Profits (March 2012).http://www.nrdc.org/energy/files/Leaking-Profits-Report.pdf
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The US Department of the Interior ("DOI") has been working on fracturing regulations
for federal lands. The draft rules focuses on the disclosure of chemical identities, well-
bore integrity and management of wastewater disposal. US Sec. of the Interior Ken
Salazar told the US House Natural Resources Committee I February 2012 that regulations
covering hydraulic fracturing on federal lands are necessary, and will be developed after
full consultations with state and Indian tribal governments. Proposals will go through a
full federal rule-making process and possibly could provide a template for national
standards, he suggested. Federal onshore fracking regulations are necessary because 99%
of gas wells now being drilled on public lands use fracking and horizontal drilling. Oil-
and-gas groups, which called the proposals redundant with what many states and industry
itself are already doing and saying they would further impede oil-and-gas development
on federal lands. The U.S. Bureau of Land Management, which is drafting rules for
natural gas production by hydraulic fracturing on federal property, has said it will use
industry standards for cementing. The BLM draft proposed fracking rule has not been
released to the public yet.
The Natural Gas Subcommittee of the U.S. Secretary of Energys Advisory Board
published its 90-day interim report on Improving the Safety and Environmental
Performance of Hydraulic Fracturing. The panel's report pushes several broad themes,
such as "continuous improvement" and "best practices and it offers ideas that could
serve as the underpinnings of legislative or regulatory changes. The seven-member
Natural Gas Subcommittee called for better tracking and more careful disposal of the
waste that comes up from wells, stricter standards on air pollution and greenhouse gases
associated with drilling, and the creation of a federal database so the public can better
monitor drilling operations. While warning that hydraulic fracturing presents real risks to
the air, water and land that must be addressed by energy companies and federal and state
regulators, the report also noted that in the great majority of regions where shale gas is
being produced, large depth separation between drinking water sources and the producing
zone] exists, and there are few, if any, documented examples of such migration.
SEAB issued its second 90-day report on Nov. 10 which reviewed progress made on the
20 recommendations the subcommittee outlined in its Aug. 18 initial report. The new
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report criticizes federal agencies, state governments, industry and public interest groups
for not moving quickly enough on its recommendations of increased regulation on
hydraulic fracturing a critical technology that allow us to access the nations rich shale
gas resources. The SEAB urges more regulatory action on three areas: reducing air
emissions at hydraulic fracturing sites, more disclosure of the chemicals used in hydraulic
fracturing, and reducing the impact of hydraulic fracturing on drinking water and setting
wastes discharge standards. Specific recommendations included:
Improve casing and cementing procedures to isolate the gas-producing zone from
overlaying formations and potable aquifers. Loss of well integrity is simply the
result of poor well completion or poor production-pressure management.
Control the entire lifecycle of the water used from acquisition to disposal. Allwater flows should be tracked and reported quantitatively throughout the process.
Limit water use by controlling vertical fracture growth. Periodic direct
measurement of earth stresses and the micro-seismic monitoring of water and
additive needs will eliminate rogue methane migration and save production
money.
Use multi-well drilling pads to monitor processes and minimize truck traffic and
surplus road construction. The use of mats, catchments, groundwater monitors,
and surface water buffers all standard in the oil industry should be industry
standard in shale gas production as well.
Declare unique and/or sensitive areas off-limits to drilling. There is such an
abundance of natural gas reserves that have come from the fracking revolution
that there is no need to be provocatively drilling beneath protected urban or
wilderness spaces. This recommendation is also one of the most difficult to apply
as the owners of the minerals in such areas have the right to produce those
minerals. Fortunately, with long-reach horizontal drilling, many urban areas can
be developed from remote pad sites with appropriate controls.
Mitigate noise, air and visual pollution. Conversion from diesel to natural gas or
electrical power for equipment fuel is an important first step and can be
substantially accelerated.
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API issued its own 10-page update regarding how industry has responded to the
subcommittees recommendations. API noted that the SEABs draft report outlines
unrealistic expectations and does little to highlight the efforts that industry and regulators
had already made to ensure that these activities are conducted safely. It is unreasonable to
expect that industry and federal, state and local regulators could institute complex new
regulatory programs in three months. The two reports reflected 6 months of deliberations
among a group of industry experts, environmental advocates, academics, and former state
regulators.
Finally, on April 13, 2012, President Obama issued an executive order establishing an
interagency working group to coordinate federal policies to support safe and responsibleUS unconventional natural gas resource development. The order established the working
group and named his domestic policy advisor, Cecilia Munoz, or a designated
representative as its chair. Its members will include deputy-level representatives or the
equivalent from the US Departments of the Interior, Energy, Defense, Agriculture,
Commerce, Health and Human Services, Transportation, and Homeland Security; the US
Environmental Protection Agency; and the White House Council on Environmental
Quality, Office of Management and Budget, National Economic Council, and Office of
Science and Technology Policy. The working group will coordinate agency activities to
ensure they are efficient and effective, and share scientific, environmental, and related
information among the agencies where appropriate. It will make long-term plans and
ensure coordination among federal entities on research, natural resource assessment, and
infrastructure development; promote interagency communication with stakeholders; and
consult with other agencies and offices where appropriate.
Hours after the executive order was issued, DOI, DOE, and EPA announced amemorandum of agreement to coordinate their present and future scientific research and
scientific studies on unconventional oil and gas resource development. They said a
primary goal of this effort will be to identify research topics where collaboration among
the three agencies can be most effectively and efficiently conducted to provide results
and technologies that support sound policy decisions by the agencies responsible for
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ensuring the prudent development of energy sources while promoting safe practices and
human health.
Conclusion
Fracking fluids will get greener, water use will get down, all because the industry,
quite frankly, will do it, must do it, and will feel the public pressure -- not the EPA
pressure -- to do this in a responsible way.- Lisa Jackson, EPA Administrator,
January 2012.
No energy produced, whether in or outside of the United States, is produced without risk
and without some environmental cost. The extraction, processing, and transportation of
natural gas all affect the environment. However, expansion of the supply of natural gas
permits the displacement of more polluting forms of energy.
With the shale gas boom continuing to gather steam, hydraulic fracturing will likely
remain a focus for environmental and citizen groups concerned about the potential
environmental impacts associated with shale gas development. Industry is well aware that
failure to manage some of the attendant impacts surrounding the development of this
resource such as water use and contamination concerns, the public disclosure of
the composition of fracking fluids, and fugitive emissions will seriously hamper efforts to
fully develop this resource.
Working with industry, federal and state regulators and legislators will continue to
monitor developments and develop regulations and protocols that will minimize shale gasdevelopments environmental footprint and any long-term impacts that it might have.
With time, experience, and investment, the technology and practices necessary to
achieve shale gas potential in a safe and environmentally acceptable manner will become
the industry standard. The U.S. experience and technology innovations can then be
carried to the rest of the world.
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Appendix I
The Environmental Issues: Water Use and Waste Water Disposal
With hundreds of wells to be drilled over large shale gas plays, water management
warrants considerable regulatory attention. The very large volumes of water needed to
hydraulically fracture shale gas wells with current technology makes water consumption
a critical issue in shale gas development. And while hydraulic fracturing requires large
amounts of water, the technology of development is evolving rapidly to lessen the
amount. Innovations include closed-loop systems that recycle the same water for
further use.
Anywhere from 10 to 50 percent of the 2-5 million gallons of injected water is returned to
the surface. The flowback fluid can contain chemicals used during the fracturing
operation as well as naturally occurring radioactive, organic and other materials picked
up from the producing formation. Hydraulic fracturing companies use a variety of
complex fluids and additives to provide specific viscosities and desired conductivity for
each well stimulation. Although fracking fluids are more than 99% water and sand, they
also contain a number of chemicals, including some that are toxic at the parts-per-billion
level, such as benzene, antimicrobial agents, and corrosion inhibitors. The federal House
Energy and Commerce Committee released a report in April 2010 that identified 29
chemicals that are either known or possible carcinogens and are subject to EPA
regulation under the Clean Water Act. Oil and gas fracking, however, was exempted from
the act in 2005 by a provision in the Energy Policy Act.
Shale-gas drillers consider the composition of their fracking fluids to be proprietary.
Nonetheless, several states have passed laws to mandate disclosure of the fluid
ingredients. The state legislature in Texas passed a bill in May 2010 that stipulates that
operators disclose several aspects of the operation, including types and volumes of
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the fracking fluid; a list of additives used in the operation, such as acid or biocide;
chemical ingredients contained in the fracking fluid; and concentrations of each chemical
ingredient and the associated chemical families. Shortly thereafter big Marcellus players
such as Chesapeake Energy and Devon Energy began to make the ingredients public.
Devon, along with other oil and gas exploration and development companies, had already
voluntarily met state reporting requirements by submitting chemical information through
a website, FracFocus.org, a joint project between the Ground Water Protection Council
and the Interstate Oil and Gas Compact Commission. By April 2011 at least 37
companies had agreed to participate in the project, according to FracFocus. The
legislation in Texas allows operators to submit their chemical information to this site.
Many states, including Pennsylvania, require an analysis to ensure that any proposed
water withdrawals will not harm the watershed by adversely affecting stream flow,
aquatic life, recreational resources or sensitive environments. Until the second half of last
year, Pennsylvania had been the only state to allow most of this wastewater to be
discharged into rivers after only partial treatment.
The 1974 Clean Water Act, among other things, requires EPA to protect underground
sources of drinking water and granted EPA the power to regulate injection
wells. Injection wells are classified into six classes according to the type of fluid they
inject and where the fluid is injected. Class II wells inject fluids associated with oil and
natural gas production operations. Most of the injected fluid is brine that is produced
when oil and gas are extracted from the earth. More than 2 billion gallons of waste,
mostly brine, from oil and gas drilling and production are injected into those wells each
day.19 Nationwide, there are more than 151,000 waste-injection wells, also known as
Class 2 wells.
19http://water.epa.gov/type/groundwater/uic/wells.cfm
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Although the fracking process is essentially the same in the Barnett and Marcellus shales,
the disposal of wastewater generated in fracking differs greatly between the two areas. In
Texas, shale-gas drillers can inject their waste into some of the thousands of Class II oil
and gas waste-injection wells located in and near the Barnett formation. Pennsylvania has
only a handful of Class 2 wells. New York State has no disposal wells. The lack of
injection wells has forced Marcellus shale frackers to find other means for disposing of
the wastewater generated at each well that isnt recycled.
In recent months, though, the industry has boasted big gains in the amount of well
wastewater that is reused, rather than trucked to treatment plants that empty into rivers
and streams. New figures released by Pennsylvania regulators confirm many of those
claims, showing that for the first time, a majority of well wastewater is now being
recycled. At least 65 percent was recycled from July to December 2010 according to state
records. But even with the recycling effort ramping up dramatically, more tainted
wastewater is being shipped to treatment plants providing evidence that recycling gains
are being erased by the continuing expansion in drilling.
Range Resources of Dallas Texas was also the first company in the Marcellus to begin
recycling wastewater. By filtering the water to remove solids that might interfere with
equipment and treating the water with antibacterial agents, the company found it could
get the water clean enough to reuse in fracking. By October 2009, Range was
successfully recycling 100% of its flow back water in its core operating area in
southwestern Pennsylvania (because of the large volumes needed, the company still has
to add fresh water to the mix.) And the company says in the impoundments where it
stores the wastewater until use, it includes bird netting, security and privacy fencing,
solar-powered aeration, liner that is six times thicker than that used in landfills, and
electronic monitoring to notify officials if there is a leak.
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Appendix II
The Environmental Issues: Ground Water Contamination
Perhaps the most publicized environmental risk arises from the possibility that fluids used
in hydraulic fracturing can contaminate drinking water sources.
Much of the water used in fracking is collected from the well and processed, but there are
concerns that potentially carcinogenic chemicals can sometimes escape and find their
way into drinking water sources. Initially the industry itself was of little help by generally
refusing to reveal what was contained in their fracking fluids which reinforced fears that
the natural gas companies were not being honest about potential risks. The movie
Gasland claimed that shale gas leaking into drinking supplies caused tap water to ignite.
The gas industry maintains that there has never been a documented case in the US of
groundwater contamination caused by fracking.
The New York State Department of Environmental Protection, in its 2009 analysis of the
potential impacts of natural gas drilling on the New York City watershed, raised the
possibility that water from hydraulic fracturing could migrate from the gas-bearing layers,
which are 5,000 feet below the surface, up to water tables less than 500 feet from the
surface.
The presence of 4,500 feet of rock above the hydraulic fractured zone makes such an
eventuality unlikely. Typical shale gas deposits are located several thousand feet below
the deepest potential sources of underground drinking water. Fracturing typically takes
place at a depth of 6,000 to 10,000 feet, while fresh water aquifers are typically less than
1,000 feet below the surface. Further, the low permeability of shale rock and other
intervening formation horizons present additional impediments to the flow of fracking
chemicals from target zones upward into aquifers. Consequently, the likelihood of water
contamination as a consequence of fluids migration up through several thousand feet of
strata is extremely unlikely. More likely candidates as sources of possible water
contamination involve surface activities, including improper well design, inadequate
surface casing and substandard or improper cementing, improper handling of surface
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chemicals, improper design/performance of holding ponds, and improper storage and
disposal of wastes and produced water. In the case of drilling through aquifer formations,
by regulation, surface casing is generally required to extend at least 50 to 100 feet below
the deepest potential source of drinking water in order to isolate the aquifer from the
drilling and production process. In many instances, concentric casing sleeves are utilized
to provide additional barriers.
Ann Davis Vaughan and David Pursell, ("Frac Attack: Risks, Hype, and Financial Reality
of Hydraulic Fracturing in the Shale Plays." Reservoir Research Partners; and Tudor,
Pickering, Holt & Co.), show that water-supply contamination from so-called stray gas
occurs more often from failures in well design and construction, breaches in spent
hydraulic-fracturing water-containment ponds, and spills of leftover natural gas liquids
used in drilling than from the hydraulic fracturing process. The Manhattan Institute for
Policy Research in their own report (June 2011) noted that environmental problems that
have arisen in connection with hydraulic fracturing in no way call into question the
soundness of that procedure. In reality, they result from improper drilling and well-casing
technique and defective formulation of cement. Such errors and flaws allow wells to
penetrate shallow gas deposits, permitting the gas within them to escape and enter
groundwater supplies. Marcellus gas resides far below these deposits and any aquifers.
The report goes on to say more stringent design standards should be adopted, and more
active regulatory oversight should be exercised. These steps would reduce the incidence
of such problems.
William Whitsitt, an executive vice president at Devon Energy, in testimony before
Congress said multiple barriers stand between groundwater and fracking. Each wellbore
is surrounded by at least two casings with a layer of cement between them and around the
outside diameter. Further preventing contamination is the layer upon layer of
impenetrable rock that separates the shale from groundwater,
While gas migration has not been shown to result from fracking, the natural gas industry
recognizes that methane migration can occur as a result of ineffective well design and
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insufficient well casings. There have been incidents where methane from producing and
shallow formations have impacted surface and well water supplies due to poor cement
integrity associated with the shallower strings of cemented casings. On Nov. 4, 2009,
Pennsylvanias Department of Environmental Protection released a statement indicating
that well integrity issues led to groundwater contamination associated with natural gas
production activities in Dimock Township, PA: 20
On December 8, 2011, the U.S. Environmental Protection Agency (EPA) issued a draft
report Investigation of Groundwater Contamination Near pavilion Wyoming. Under the
Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA),
residents of Pavillion petitioned EPA, asking the agency to investigate whether
groundwater contamination exists, its extent, and possible sources. Residents had startedcomplaining that their drinking water has turned brown in the mid 1990s, shortly after
existing, nearby gas wells were fracked. The problem got worse in 2004, and for a time,
the gas companies operating in the area trucked in replacement drinking water. This
practice was stopped in more recent years.
Following the petition, EPA began its investigation three years ago. The draft report
indicated that EPA had identified certain constituents in groundwater above the
production zone of the Pavillion natural gas wells that are consistent with some of the
constituents used in natural gas well operations, including the process of hydraulic
fracturing. In its report, EPA claimed that its approach to the investigation best supports
the explanation that inorganic and organic compounds associated with hydraulic
fracturing have contaminated the aquifer at or below the depths used for domestic water
supply in the Pavillion area. EPA did not appear to conclude that there was a definitive
link to a release from the production wells, nor to the constituents found in domestic
wells in shallower parts of the aquifer. EPA also plans a peer review by independentscientists. This may be the very first instance that the EPA has linked the fracking to
water contamination.
20http://www.portal.state.pa.us/portal/server.pt/community/newsroom/14287?id=2418&ty
peid=1.
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The EPA sampled residential wells, stock wells, shallow monitoring wells, and two
municipal wells. The domestic wells range in depth from approximately 20 feet to nearly
800 feet, and the two municipal wells are 505 and 515 feet deep. The two shallow
monitoring wells were approximately 15 feet deep. According to the EPA Draft Report,
the early phases of the investigation detected the presence of methane and diesel-range
organic chemicals in some of the deeper domestic wells, which prompted EPA to install
two deep monitoring wells in June 2010. Whether the report clearly links groundwater
contamination to drilling or hydraulic fracturing activities has been the source of heated
debate between proponents and opponents of the use of hydraulic fracturing for natural
gas development.
EPA acknowledges that the results are specific to Pavillion. In the release of the draftstudy EPA noted that The draft findings announced today are specific to Pavillion,
where the fracturing is taking place in and below the drinking water aquifer and in close
proximity to drinking water wells production conditions different from those in many
other areas of the country. In this respect the pavilion wells were atypical when
compared to a typical shale gas well
The Pavillion wells were vertical wells (typical shale wells are horizontal).
The Pavillion wells lacked surface casing which means almost all of themlacked protection from leakage at depths from which people draw water (typicalwells have cemented casing down past the deepest water levels).
The Pavillion wells were abnormally shallow with the fractures occurring at 1,200
feet while the water extended to 800 feet (typical shale wells are a mile and a half
underground with thick rock between the well and underground water).
Industry officials pointed out that the EPA announcement didn't focus on those domestic
water wells but two wells drilled somewhat deeper into the aquifer specifically to test for
pollution. They argue that the compounds found in the water could have been brought
about by contamination in their sampling process or construction of their well. The extent
to which EPA may revise its findings in response to public comments and a forthcoming
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external scientific review is unclear and will not be known until the agency finalizes its
report.
A study (Fact-based Regulation for Environmental protection in Shale Gas
Development, February 2012) conducted by the Energy Institute at the University of
Texas at Austin found that many problems attributed to hydraulic fracturing are related to
processes common to all oil and gas drilling operations such as drilling pipe inadequately
cased in concrete. Many reports of contamination can be traced to above ground spills or
other mishandling of wastewater produced from shale drilling and not from hydraulic
fracturing. The institutes research team looked at reports of groundwater contamination
in three shale plays: the Barnett Shale in North Texas; the Marcellus Shale in
Pennsylvania, New York and parts of Appalachia; and the Haynesville Shale in western
Louisiana and northeast Texas. The Environmental Defense Fund, which helped develop
the scope of work and methodology for the study, noted that, although the study didnt
confirm any cases of drinking water contamination caused by fracking, that does not
mean such contamination is impossible or that hydraulic fracturing chemicals cant get
loose in the environment in other ways (such as through spills of produced water).
Scott Anderson of the Environmental Defense Fund in his blog added that the study
shined a light on the fact that there are a number of aspects of natural gas development
that can pose significant environmental risk. And it highlights the fact that there are a
number of ways in which current regulatory oversight is inadequate.
The following conclusions are particularly important:
Many reports of groundwater contamination occur in conventional oil and gas
operations (e.g. failure of well-bore casing and cementing) and are not unique to
hydraulic fracturing.
Surface spills of fracturing fluids appear to pose greater risks to groundwater than
hydraulic fracturing itself.
Blowouts uncontrolled fluid releases during construction and operation are a
rare occurrence, but subsurface blowouts appear to be under-reported.
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The lack of baseline studies makes it difficult to evaluate the long-term,
cumulative effects and risks associated with hydraulic fracturing.
Most state oil and gas regulations were written well before shale gas development
became widespread.
Gaps remain in the regulation of well casing and cementing, water withdrawal
and usage, and waste storage and disposal.
Enforcement capacity is highly variable among the states, particularly when measured by
the ratio of staff to numbers of inspections conducted.
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Appendix III
The Environmental Issues: Air Emissions and GHG
The assumption has been that the increased uses of natural gas can radically reduce the
GHG footprint of the electric power industry. Natural Gas would also play an important
role in expanded end use applications and enabling renewables as the world moved to a
less carbonized energy future.
It is also understood that the extraction, processing, and transportation of natural gas all
affect the environment. Air quality impacts mentioned include emissions of carbon
dioxide stripped from the gas; sulphur dioxide and/or hydrogen sulphide from treating
sour water for use as hydraulic fracture fluid, and NOX and other emissions from
compressors; pollution from diesel engines; and ground level ozone.
However, it is important to remember that the expansion of the supply of natural gas
permits the displacement of more polluting forms of energy. Natural gas is considered
clean because, on combustion, it emits roughly half the carbon dioxide of coal and about
30% that of oil. Estimating the net environmental impacts, therefore, requires comparing
the upstream negative environmental externalities associated with gas development with
the downstream positive externalities created by switching to natural gas. Until recently,
studies estimated that life-cycle emissions from natural gas-fired generation were
significantly less than those from coal-fired generation on a per MMBtu basis.
A study out of Cornell University (Robert W. Howarth, et al ., Methane and the
greenhouse-gas footprint of natural gas from shale formations, Climatic Change, March
13, 2011)21suggests that the rush to develop Americas unconventional gas resources
will likely increase the nations carbon emissions rather than decrease them. According toHowarth, combustion is only one part of the natural gas life cycle. During other parts of
the cycle a lot of methane is lost. It's not that the burning of natural gas itself produces
more greenhouse gases than the burning of coal. Rather, Howarth looked at the total life
21http://www.sustainablefuture.cornell.edu/news/attachments/Howarth-EtAl-2011.pdf
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cycle of shale natural gas production, including the drilling and fracking of wells and the
transport of gas, and found that significant amounts of methane in shale gas production
escape into the atmosphere instead of being captured and used for fuel.
The study suggests that between 3.6% and 7.9% of the methane escape into the
atmosphere. The researchers also include data from a recent study from NASA making
the case that methane can interact with aerosol particles in the atmosphere in a way that
amplifies methane's warming impact, especially in the short-term. In addition, thousands
of trucks are driving every minute of every day to bring fracking fluid to drills and to
remove wastewater. When all is factored in, Howarth and his colleagues conclude the
greenhouse gas footprint of shale gas is likely 20% greater than coal per unit energy, and
may be as much as twice as high.
The study concludes that the production of a unit of shale gas to be more GHG-intensive
than the production of a unit of conventional natural gas. Consequently, if the upstream
emissions associated with shale gas production are not mitigated, a growing share of
shale gas would increase the average life-cycle greenhouse gas footprint of the total U.S.
natural gas supply. According to Howarth, shale gas has a bigger carbon footprint than
coal in the short-term, and is comparable over the long-term. That directly contradicts the
industry position that natural gas has one-half the carbon footprint of coal
To summarize, the Howarth study maintains that:
1) Higher emissions from shale gas are released during hydraulic fracturing.
2) Between 3.6 percent and 7.9 percent of the methane from shale-gas
production escapes to the atmosphere in venting and leaks over the lifetime of
a well;
3) These methane emissions are at least 30 percent more than and perhaps twice
as great as those from conventional gas;
4) Compared to coal, the footprint of shale gas is at least 20 percent greater and
perhaps more than twice as great on the 20-year horizon and is comparable
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when looked at over 100 years.
The Howarth study results are challenged in four areas:
1) First, the data for leakage from well completions and pipelines is very
incomplete and taken from a few isolated cases reported in industry
magazines, and numbers for pipeline leakage from long-distance pipelines in
Russia. Howarth points out that he didnt purposefully avoid certain data.
There just isnt a lot out there. (MIT, Technology Review, April 15, 2001).
2) The gas-to-coal comparisons are all done on a per energy unit basis and
compares the amount of emissions involved in producing a gigajoule of coal
with the amount involved in producing a gigajoule of gas. Since a gigajoule
of gas produces a far more electricity than a gigajoule of coal (assuming an
electricity conversion efficiency of 60% for gas and a 30% conversion
efficiency for older coal plants), a per kWh comparison is the correct one. If
modern gas technology replaces old coal technology as it is retired, switching
from coal to natural gas would dramatically reduce the greenhouse impact of
electricity generation.
3) The technological solutions for methane leakage (better well completion
techniques, better pipeline integrity) are relatively inexpensive and are
currently available compared to solving the GHG emissions problems of a
coal plant (CCS).
4) Howarth uses use 20-year global warming potentials (GWPs) to compare coalwith gas, rather than the customary 100 year figures. Methane decays in the
atmosphere in decades while carbon dioxide persists in the atmosphere for
hundreds to thousands of years. If you average the impact of GHG emissions
over 20 years instead of 100, you amplify the relative influence of methane
and the downsides to gas. As noted by Michael Wang, senior scientist on life-
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cycle energy and environmental effects of energy production at Argonne
National Laboratory, Illinois, although methane is more than 70 times more
powerful at heating the atmosphere than carbon dioxide over a 20-year period,
after 100 years it's only 25 times more potent. (Life-cycle emissions for
natural gas generation using new EPA estimates are 47 percent lower than for
coal-based generation when using a GWP of 25).
There is a wealth of information relating to the life cycle emissions of the natural gas
industry. Key ones include:
Timothy J. Skone, National Energy Technology Laboratory (NETL), Life Cycle
Greenhouse Gas Analysis of Natural Gas Extraction & Delivery in the United States,
presentation (Ithaca, NY: 12 May 2011; revised 23 May 2011); Mohan Jiang, et al., Life
cycle greenhouse gas emissions of Marcellus Shale gas, Environmental Research Letters
6 (3), 5 August 2011. Industry Challenges Study that Natural Gas 'Fracking' Adds
Excessively to Greenhouse Effect, Richard Lovett, Nature, April 2011.Five Things to
Know About the Cornell Gas Study, Energy In Depth, May 4, 2011; and Life Cycle
Greenhouse Gas Emissions of Marcellus Shale Gas (Jiang et al, Carnegie Mellon
University, published Environmental Research Letters, August 5, 2011), IHS CERA,
"Mismeasuring Methane - Estimating Greenhouse Gas Emissions from Upstream Natural
Gas Development," August 2011, School of Public Policy, University of Maryland , The
Greenhouse Impact of Unconventional Gas for Electricity Generation, Nathan Hultman,
Dylan Rebois, Michael Scholten4and Christopher Ramig (October 25, 2011), and Cornell
University, A Commentary on The Greenhouse-gas footprint of natural gas in shale
formations by R.W. Howarth, R. Santorio and Anthony Ingtaffea, November 2011.
The NETL study concludes that when used to generate electricity, natural gas
conventional or not results in far less emissions than coal. Using a 100-year global
warming potential and assuming an average power plant, unconventional gas results in
54% less lifecycle greenhouse gas emissions than coal does. Even using a 20-year global
warming potential, as Howarth argues one should, the savings from substituting
unconventional gas for coal are almost 50%. Howarth found a large fraction of produced
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gas from unconventional wells never made it to end users, assumed that all of that gas
was vented as methane, and thus concluded that the global warming impacts were huge.
As the NETL work explains, though, 62% of that gas isnt lost at all its used to power
equipment.
The NETL study acknowledges and explores a range of uncertainties. But it finds
nothing close to the problems that Howarth claims.
The Carnegie Mellon study shows that the development and completion of a typical
Marcellus shale represents an 11% increase in GHG emissions relative to average
domestic gas. It also notes that Marcellus shale has generally lower life cycle GHG
emissions (2050% depending upon plant efficiencies and natural gas emissions
variability)than coal for production of electricity in the absence of any effective carbon
capture and storage processes.
The CERA paper, a private report for ANGA and found on their website, shows that the
Howarth paper grossly overestimates the quantities of methane that are leaking
uncontrolled into the atmosphere at the well site. They note that vented emissions of the
magnitudes estimated by Howarth would be extremely dangerous and subject to ignition.
In response to the new EPA proposed new source performance standards under the Clean
Air Act that would regulate air emissions during the completion phase of hydraulically
fractured gas wells, the CERA report shows that EPA has overstated estimates of gas
vented during well completion operations and are therefore also overstated in terms of
reducing air pollution and emissions of GHG.
The University of Maryland study concludes:
GHG impacts of shale gas areonly 56% that of coal.
Methane has the ability to trap large amounts of infrared radiation relative to CO2,
but it also has a comparatively shorter lifetime in the atmosphere. As a
result, methanes 100 y GWP is much lower than its 20 y GWP.
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Two factors lead to an overall carbon intensity advantage for gas during the
combustion stage. First, gas releases more energy per unit of carbon emitted.
Second, the technology used for combustion of gas is more thermodynamically
efficient than that used for coal, enabling a larger amount of chemical potential
energy in the fuel to be converted to electricity.
Arguments that shale gas is more polluting than coal are largely unjustified.
We have demonstrated that the fugitive emissions from the [shale gas] drilling
process are very likely not substantially higher than for conventional gas.
Evaluated solely on the criterion of GHG emissions from electricity generation,
shale gas is not likely to be substantially more polluting than conventional gas.
The Cathles study from Cornell University also concludes that the Horwath study was
"seriously flawed" and that shale gas has a GHG footprint that is only one-third to one-
half that of coal. The new study was conducted by L.M. Cathles III and others, and
published online in the journal Climatic Change Letters on January 3, 2012. Cathles
maintains that Howarths arguments fail on four critical points:
1) Howarth et al.s high end (7.9%) estimate of methane leakage from well drilling
to gas delivery exceeds a reasonable estimate by about a factor of three and theydocument nothing that indicates that shale wells vent significantly more gas than
conventional wells. This high-end estimate of 7.9% is unreasonably large and
misleading.
2) The data they cite to support their contention that fugitive methane emissions
from unconventional gas production are significantly greater than that from
conventional gas production are actually estimates of gas emissions that were
captured for sale. The authors implicitly assume that capture (or even flaring) is
rare, and that the gas captured in the references they cite is normally vented
directly into the atmosphere. There is nothing in their sources to support this
assumption.
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3) Howarth seems to dismiss the importance of technical improvements on the GHG
footprint of shale gas. He downplays ongoing efforts and the opportunity to
further reduce fugitive gas emissions in the natural gas industry, while at the same
time citing technical improvements in the coal industry.
4) The 20-year time horizon for the GHG comparison of natural gas and coal hides
the critical fact that the lifetime of CO2 in the atmosphere is far longer than that
of methane. A 100-year timeframe at least captures some of the implications of
the shorter lifetime of methane in the atmosphere that are important when
considering swapping gas for coal. The long-term benefits of swapping gas for
coal are completely missed by the 20-year GWP factor.
5) Howarth et al. treat the end use of electricity almost as a footnote and a 20-year
GWP and minimize the efficiency differential between gas and coal by citing a
broad range for each rather than emphasizing the likelihood that efficient gas
plants will replace inefficient coal plants. Had they used a 100-year GWP and
their low-end 3.6% methane leakage rate, shale gas would have about half the
impact of surface coal when used to generate electricity (assuming an electricity
conversion efficiency of 60% for gas and their high 37% conversion efficiency for
coal).
Coal is used almost entirely to generate electricity, so comparison on the basis of
heat content is irrelevant. Gas that is substituted for coal will of necessity be used
to generate electricity since that is coals almost sole use. The appropriate
comparison of gas to coal is thus in terms of electricity generation. If the
comparison is based on the heat content of the fuels, gas becomes twice as bad as
coal from a greenhouse perspective. The appropriate comparison of gas to coal is
thus in terms of electricity generation.
6) Leaking 6% of the gas that will ultimately be produced into the atmosphere
during on-site handling, transmission through pipelines, and delivery appears to
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be far too high and at odds with previous studies. The most recent comprehensive
study (EPA 2011, Table 337, assuming a 2009 U.S. production of natural gas of
24 TCF)22 shows the emission of methane between source and user is ~2.2% of
production. Breaking this down, 1.3% occurs at the well site, 0.73% during
transmission, storage, and distribution, and 0.17% during processing. Howa