2_2012-apr_igu environmental issues and shale gas

7/30/2019 2_2012-Apr_IGU Environmental Issues and Shale Gas

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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

2_2012-apr_igu environmental issues and shale gas

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