## April 2009 U.S. Department of Energy • Office of Fossil Energy N a t i o n a l E n e r g y Te c h n o l o g y L a b o r a t o r y

## DISCLAIMER

This report was prepared as an account of work sponsored by an agency of the United States Government. Neither the United States Government nor any agency thereof, nor any of their employees, makes any warranty, expressed or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe upon privately owned rights. Reference herein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, or favoring by the United States Government or any agency thereof. The views and opinions of author s expressed herein do not necessarily state or reflect those of the United States Government or any agency thereof.

# Modern Shale Gas Development in the United States: 

# A Primer

Work Performed Under DE

- FG26

- 04NT15455

Prepared for U.S. Department of Energy Office of Fossil Energy

and National Energy Technology Laboratory

Prepared by Ground Water Protection Council Oklahoma City, OK 73142 405

- 516

- 4972 www.gwpc.org

and

ALL Consulting Tulsa, OK 74119 918

- 382

- 7581 www.all

- llc.com

April 2009MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER



## ACKNOWLEDGMENTS

This material is based upon work supported by the U.S. Department of Energy, Office of Fossil Energy, National Energy Technology Laboratory (NETL) under Award Number DE

- FG26

- 04NT 15455 . Mr. Robert Vagnetti and Ms. Sandra McSurdy, NETL Project Managers, provided oversight and technical guidance. This study was directed by the Ground Water Protection Council (GWPC) with ALL Consulting serving as lead researcher.

GWPC and ALL Consulting wish to extend their appreciati on to the following federal, state, industry, and educational institutions which helped with numerous data sources, data collection and technology reviews that were critical to the success of this project. Additionally, the extra time and energy that indi viduals provided in reviewing and in broadening our understanding of the issues at hand is respectfully acknowledged.

The authors wish to specifically acknowledge the help and support of the following entities: Arkansas Oil and Gas Commission, Louisiana D epartment of Natural Resources, Michigan Department of Environmental Quality Office of Geological Survey, Montana Board of Oil and Gas Conservation, Montana Department of Natural Resources, New York State Department of Environmental Conservation, Ohio Depa rtment of Natural Resources Division of Mineral Resources Management, Oklahoma Corporation Commission, Pennsylvania Department of Environmental Protection, Railroad Commission of Texas, State of Tennessee, State University of New York at Fredonia, West Vir ginia Department of Environmental Protection , Energy Information Administration, U.S. Environmental Protection Agency, State Review of Oil and Natural Gas Environmental Regulation, Inc. (STRONGER), BP America Production Co., Chesapeake Energy Corp.,
Devon Energy Corp., East Resources, Inc., Fortuna Energy Inc., Independent Petroleum Association of America, Schlumberger Ltd., Universal Well Services Inc., and Weatherford International Ltd.,MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER



## FOREWORD

This Primer on Modern Shale Gas Development in the United States was commissioned through the Ground Water Protection Council (GWPC). It is an effort to provide sound technical information on and additional insight into the relationship between today’s fastest growing, and sometimes controversial, natural gas

r esource development activity, and environmental protection, especially water resource management. The GWPC is the national association of state ground water and underground injection agencies whose mission is to promote the protection and conservation of ground water resources for all beneficial uses. One goal of the GWPC is to provide a forum for stakeholder communication on important current issues to foster development of sound policy and regulation that is based on sound science. This Primer is prese nted in the spirit of furthering that goal.

Water and energy are two of the most basic needs of society. Our use of each vital resource is reliant on and affects the availability of the other. Water is needed to produce energy and energy is necessary to make
water available for use. As our population grows, the demands for both resources will only increase. Smart development of energy resources will identify, consider, and minimize potential impacts to water resources.

Natural gas, particularly shale g as, is an abundant U.S. energy resource that will be vital to meeting future energy demand and to enabling the nation to transition to greater reliance on renewable energy sources.

Shale gas development both requires significant amounts of water and is con ducted in proximity to valuable surface and ground water. Hence, it is important to reconcile the concurrent and related demands for local and regional water resources, whether for drinking water, wildlife habitat, recreation, agriculture, industrial

or o ther uses.

Because shale gas development in the United States is occurring in areas that have not previously experienced oil and gas production, the GWPC has recognized a need for credible, factual information on shale gas resources, technologies for deve loping these resources, the regulatory framework under which development takes place, and the practices used to mitigate potential impacts on the environment and nearby

communities. While the GWPC’s mission primarily concerns water resources, this Primer also addresses non

water issues that may be of interest to citizens, government officials, water supply and use professionals, and other interested parties.

Each state has laws and regulations to ensure the wise use of its natural resources and to protect the

environment. The GWPC has conducted a separate study to summarize state oil and gas program requirements that are designed to protect water resources. These two studies complement one other and together provide a body of information that can serve a s a basis for fact

- based dialogue on how shale gas development can proceed in an environmentally responsible manner under the auspices of state regulatory

programs.
This Shale Gas Primer was intended to be an accurate depiction of current factors and doe s not represent the view of any individual state. Knowledge about shale gas development will continue to evolve. The GWPC welcomes insights that readers may have about the Primer and the relationship of shale gas development to

water resources.

S cott Kel l, President,

Ground Water Protection Council

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- 1 

## EXECUTIVE SUMMARY

Natural gas production from hydrocarbon rich shale formations, known as “shale gas

, ” is one of the most rapidly expanding trends in onshore domestic oil and gas exploration and production today. In some areas, this has included bringing drilling a nd production to regions of the country that have seen little or no activity in the past. New oil and gas developments bring change to the
environmental and socio

- economic landscape, particularly in those areas where gas development is a new activity. Wi th these changes have come questions about the nature of shale gas development, the potential environmental impacts, and the ability of the current regulatory structure to deal with this development. Regulators, policy makers, and the public need an objec tive source of information on which to base answers to these questions and decisions about how to manage the challenges that may accompany shale gas development.

Natural gas plays a key role in meeting U.S. energy demands. Natural gas, coal and oil suppl y about 85% of the nation’s energy, with natural gas supplying about 22% of the total. The percent contribution of natural gas to the U.S. energy supply is expected to remain fairly constant for the next 20 years.

The United States has abundant natural g as resources. The Energy Information Administration estimates that the U.S. has more than 1,744 trillion cubic feet (tcf) of technically recoverable natural gas, including 211 tcf of proved reserves (the discovered, economically recoverable fraction of th e original gas

- in

- place). Technically recoverable unconventional gas (shale gas, tight sands, and coalbed methane) accounts for 60 % of the onshore recoverable resource. At the U.S. production rates for 2007, about 19.3 tcf, the current recoverable resour ce estimate provides enough natural gas to supply the U.S. for the next 90 years. Separate estimates of the shale gas resource extend this supply to 116 years.

Natural gas use is distributed across several sectors of the economy. It is an important energ y source for the industrial, commercial and electrical generation sectors, and also serves a vital role in residential heating. Although forecasts vary in their outlook for future demand for natural gas, they all have one thing in common: natural gas wil l continue to play a significant role in the U.S. energy picture for some time to come.

The lower 48 states have a wide distribution of highly organic shales containing vast resources of natural gas. Already, the fledgling Barnett Shale play in Texas prod uces 6% of all natural gas produced in the lower 48 States. Three factors have come together in recent years to make shale gas production economically viable: 1) advances in horizontal drilling, 2) advances in hydraulic fracturing, and, perhaps most impo rtantly, 3) rapid increases in natural gas prices in the last several years as a result of significant supply and demand pressures. Analysts have estimated that by 2011 most new reserves growth (50% to 60%, or approximately 3 bcf/day) will come from

uncon ventional shale gas reservoirs. The total recoverable gas resources in four new shale gas plays (the Haynesville, Fayetteville, Marcellus, and Woodford) may be over 550 tcf. Total annual production volumes of 3 to 4 tcf may be sustainable for decades. T his potential for production in the known onshore shale basins, coupled with other unconventional gas plays, is predicted to contribute significantly to the U.S.’s domestic energy outlook.MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRI MER

ES

- 2 Shale gas is present across much of the lower 48 States. Exhibit ES

- 1 shows the approximate locations of current producing gas shales and prospective shales. The most active shales to date are
the Barnett Shale

, the Haynesville /Bossier Shale, the Antrim Shale , the Fayetteville Shale, the Marcellus Shale, and the New Albany Shale. Each of these gas shale basins is different and each has a unique set of exploration criteria and operational challenges. Because of these differences, the development of shale gas resources in each of these areas faces potentially unique opportunities

a nd challenges.

The development and production of oil and gas in the U.S., including shale gas, are regulated under a complex set of federal, state, and local laws that address every aspect of exploration and operation. All of the laws, regulations, and permits that apply to conventional oil and gas exploration and production activities also apply to shale gas development. The U.S. Environmental Protection Agency administers most of the federal laws, although development on federally

- owned land is manag ed primarily by the Bureau of Land Management (part of the Department of the Interior) and the U.S. Forest Service (part of the Department of Agriculture). In addition, each state in which oil and gas is produced has one or more regulatory agencies that p ermit wells, including their design, location, spacing, operation, and abandonment, as well as environmental activities and 

### E XHIBIT 

### ES

- 1 : U NITED 

### S TATES 

### S HALE 

### B ASINSMODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRI MER

ES

- 3 discharges, including water management and disposal, waste management and disposal, air emissions, underground injection, wildlife i mpacts, surface disturbance, and worker health and safety. Many of the federal laws are implemented by the states under agreements and plans approved by the appropriate federal agencies.

A series of federal laws governs most environmental aspects of sha le gas development. For example, the Clean Water Act regulates surface discharges of water associated with shale gas drilling and production, as well as storm water runoff from production sites. The Safe Drinking Water Act regulates the underground injec tion of fluids from shale gas activities. The Clean Air Act limits air emissions from engines, gas processing equipment, and other sources associated with drilling and production. The National Environmental Policy Act (NEPA) requires that exploration
and production on federal lands be thoroughly analyzed for environmental impacts. Most of these federal laws have provisions for granting “primacy” to the states (i.e., state agencies implement the programs with federal oversight).

State agencies not only im plement and enforce federal laws; they also have their own sets of state laws to administer. The states have broad powers to regulate, permit, and enforce all shale gas development activities

— the drilling and fracture of the well, production operations, m anagement and disposal of wastes, and abandonment and plugging of the well. State regulation of the environmental practices related to shale gas development, usually with federal oversight, can more effectively address the regional and state

- specific char acter of the activities, compared to one

- size

fits

- all regulation at the federal level. Some of these specific factors include: geology, hydrology, climate, topography, industry characteristics, development history, state legal structures, population den sity, and local economics. State laws often add additional levels of environmental protection and requirements. Also, several states have their own versions of the federal NEPA law, requiring environmental assessments and reviews at the state level and e xtending those reviews beyond federal lands to state and private lands.

A key element in the emergence of shale gas production has been the refinement of cost

- effective horizontal drilling and hydraulic fracturing technologies. These two processes, along with the implementation of protective environmental management practices

, have allowed shale gas development to move into areas that previously would have been inaccessible. Accordingly, it is important to understand the technologies and practices employe d by the industry and their ability to prevent or minimize the potential effects of shale gas development on human health and the environment and on the quality of life in the communities in which shale gas production is located.

Modern shale gas developme nt is a technologically drive n process for the production of natural gas resources. Currently, the drilling and completion of shale gas wells includes both vertical and horizontal wells. In both kinds of wells, casing and cement are installed to protect fresh and treatable water aquifers. The emerging shale gas basins are expected to follow a trend similar to the Barnett Shale play with increasing numbers of horizontal wells as the plays mature. Shale gas operators are increasingly relying on horizontal well completions to optimize recovery and well economics. Horizontal drilling provides more exposure to a formation than does a vertical well. This increase in reservoir exposure creates a number of advantages over vertical wells drilling. Six
to ei ght horizontal wells drilled from only one well pad can access the same reservoir volume as sixteen vertical wells. Using multi

- well pads can also significantly reduce the overall number ofMODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRI MER

ES

- 4 well pads, access roads, pipeline routes, and production facilities required, thus minimizing habitat disturbance, impacts to the public, and the overall environmental footprint.

The other technolog ical key to the economic recovery of shale gas is hydraulic fracturing, which involves the pumping of a fracturing fluid under high pressure into a shale formation to generate fractures or cracks in the target rock formation. This allows the natural gas to flow out of the shale to the well in economic quantities. Ground water is protected during the shale gas fracturing

process by a combination of the casing and cement that is installed when the well is drilled and the thousands of feet of rock between the fracture zone and any fresh or treatable aquifers. For shale gas development, fracture fluids are primarily water based flu ids mixed with additives that help the water to carry sand proppant into the fractures. Water and sand make up over 98 % of the fracture fluid, with the rest consisting of various chemical additives that improve the effectiveness of the fracture job. Each hydraulic fracture treatment is a highly controlled process designed to the specific conditions of the target formation.

The amount of water needed to drill and fracture a horizontal shale gas well generally ranges from about 2 million to 4 million gall ons, depending on the basin and formation characteristics. While these volumes may seem very large, they are small by comparison to some other uses of water, such as agriculture, electric power generation, and municipalities, and generally represent a sma ll percentage of the total water resource use in each shale gas area. Calculations indicate that water use for shale gas development will range from less than 0.1% to 0.8% of total water use by basin. Because the development of shale gas is new in some a reas, these water needs may still challenge supplies and infrastructure. As operators look to develop new shale gas plays, communication with local water planning agencies, state agencies, and regional water basin commissions can help operators and commun ities to coexist and effectively manage local water resources. One key to the successful development of shale gas is the identification of water supplies capable of meeting the needs of a development company for drilling and fracturing water without inter fering with community needs. While a variety of options exist, the conditions of obtaining water are complex and vary by region.

After the drilling and fracturing of the well are completed, water is produced along with the natural gas. Some of this water is returned fracture fluid and some is natural formation water. Regardless of the source, these produced waters that move back t hrough the wellhead with the gas represent a stream that must be managed. States, local governments, and shale gas operators seek to manage produced water in a way that protects surface and ground water resources and, if possible, reduces
future demands f

or fresh water. By pursuing the pollution prevention hierarchy of “Reduce, Re

- use, and Recycle” these groups are examining both traditional and innovative approaches to managing shale gas produced water. This water is currently managed through a variety of mechanisms, including underground injection, treatment and discharge, and recycling. New water treatment technologies and new applications of existing technologies are being developed and used to treat shale gas produced water for reuse in a variety of applications. This allows shale gas

- associated produced water to be viewed as a potential resource in its own right.

Some soils and geologic formations contain low levels of naturally occurring radioactive material (NORM). When NORM is brought to the su rface during shale gas drilling and production operations, it remains in the rock pieces of the drill cuttings, remains in solution with producedMODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRI MER

ES

- 5 water, or, under certain conditions, precipitates out in scales or sludges. The radiation from this
NORM is w eak and cannot penetrate dense materials such as the steel used in pipes and tanks.

Because the general public does not come into contact with gas field equipment for extended periods, there is very little exposure risk from gas field NORM. To protect ga s field workers, OSHA requires employers to evaluate radiation hazards, post caution signs and provide personal protection equipment when radiation doses could exceed regulatory standards. Although regulations vary by state, in general, if NORM concentrat ions are less than regulatory standards, operators are allowed to dispose of the material by methods approved for standard gas field waste. Conversely, if NORM concentrations are above regulatory limits, the material must be disposed of at
a licensed faci lity. These regulations, standards, and practices ensure that shale gas operations present negligible risk to the general public and to workers with respect to potential NORM

exposure.

Although natural gas offers a number of environmental benefits over o ther sources of energy, particularly other fossil fuels, some air emissions commonly occur during exploration and production activities. Emissions may include NO x , volatile organic compounds, particulate matter,
SO 2 , and methane. EPA sets standards, moni tors the ambient air across the U.S., and has an active enforcement program to control air emissions from all sources, including the shale gas industry. Gas field emissions are controlled and minimized through a combination of government regulation
and vo luntary avoidance, minimization, and mitigation strategies.

The primary differences between modern shale gas development and conventional natural gas development are the extensive use s of horizontal drilling and high

- volume hydraulic fracturing.
The use of horizontal drilling has not introduced any new environmental concerns. In fact, the reduced number of horizontal wells needed coupled with the ability to drill multiple wells from a single pad has significantly reduced surface disturbances and associat ed impacts to wildlife, dust , noise, and traffic. Where shale gas development has intersected with urban and industrial settings, regulators and industry have developed special practices to alleviate nuisance impacts, impacts to
sensitive environmental r esources, and interference with existing businesses. Hydraulic fracturing has been a key technology in making shale gas an affordable addition to the Nation’s energy supply, and the technology has proved to be an effective stimulation technique. While so me challenges exist with water availability and water management, innovative regional solutions are emerging that allow shale gas development to continue while ensuring that the water needs of other users are not affected and that surface and ground water quality is protected. Taken together, state and federal requirements along with the technologies and practices developed by industry serve to reduce environmental impacts from shale gas operations.

## THIS PAGE INTENTIONALLY LEFT BLANKi 

## TABLE OF CONTENTS

Table of Contents

................................ ................................ ................................ ................................ .............. i

List of Exhibits

................................ ................................ ................................ ................................ ................ iii

INTRODUCTION

................................ ................................ ................................ ................................ ................ 1

THE IMPORTANCE OF SHALE GAS

................................ ................................ ................................ ............... 3
The Role of Natural Gas in the United States’ Energy Portfolio

................................ ................................ ......... 3 The Advantages of Natural Gas

................................ ................................ ................................ ................................ ......... 5

Natural Gas Basics

................................ ................................ ................................ ................................ ................................ ... 6

Uncon ventional Gas

................................ ................................ ................................ ................................ ................................ 7

The Role of Shale Gas in Unconventional Gas

................................ ................................ ................................ ............ 8 Looking Forward

................................ ................................ ................................ ................................ ................................ .. 10

SHALE GAS DEVELOPMENT IN THE UNITED S TATES

................................ ................................ .......... 13

Shale Gas

– Geology

................................ ................................ ................................ ................................ ............................. 14

Sources of Natural Gas

................................ ................................ ................................ ................................ ....................... 16

Shale Gas in the United States

................................ ................................ ................................ ................................ ........ 16
The Barnett Shale

................................ ................................ ................................ ................................ ............................ 18 The Fayetteville Shale

................................ ................................ ................................ ................................ .................... 19 The Haynesville Shale

................................ ................................ ................................ ................................ ..................... 20

The Marcellus Shale

................................ ................................ ................................ ................................ ........................ 21 The Woodford Shale

................................ ................................ ................................ ................................ ........................ 22

The Antrim Shale

................................ ................................ ................................ ................................ .............................. 23 The New Albany Shale

................................ ................................ ................................ ................................ .................... 24

REGULATORY FRAMEWORK

................................ ................................ ................................ ...................... 25

Federal Environmental Laws Govern ing Shale Gas Development

................................ ................................ . 25 State Regulation

................................ ................................ ................................ ................................ ................................ .... 25 Local Regulation

................................ ................................ ................................ ................................ ................................ ... 27 Regulation of Impacts on Water Quality

................................ ................................ ................................ .................... 29
Clean Water Act

................................ ................................ ................................ ................................ ................................ 29 Safe Drinking Water Act

................................ ................................ ................................ ................................ ............... 32 Oil Pollution Act of 1990

– Spill Prevention Control and Countermeasure

................................ .............. 33 State Regulations and Regional Cooperation

................................ ................................ ................................ ....... 35 Regulation of Impacts on Air Quality

................................ ................................ ................................ .......................... 35
Clean Air Act

................................ ................................ ................................ ................................ ................................ ....... 35 Air Quality Regulations

................................ ................................ ................................ ................................ .................. 36ii

Air Permits

................................ ................................ ................................ ................................ ................................ .......... 36 Regulation of Impacts to Land

................................ ................................ ................................ ................................ ........ 37 Resource Conservation and Recovery Act (RCRA)

................................ ................................ .............................. 37 Endangered Species Act

................................ ................................ ................................ ................................ ................. 38 State Endangered Species Protections

................................ ................................ ................................ .................... 39 Oil and Gas Operations on Public Lands

................................ ................................ ................................ .................... 39
Federal Lands

................................ ................................ ................................ ................................ ................................ .... 39

State Lands

................................ ................................ ................................ ................................ ................................ ......... 40 Other Federal Laws and Requirements that Protect the Environment

................................ ....................... 40 Comprehensive Environmental Response, Compensation, and Liability Act

................................ ........... 40 Emergency Planning and Community Right

- to

- Know Act

................................ ................................ .............. 41 Occupational Safety and Health Act

................................ ................................ ................................ ......................... 42
Summary

................................ ................................ ................................ ................................ ................................ .................. 42

ENVIRONMENTAL CONSIDERATIONS

................................ ................................ ................................ ..... 43

Horizontal Wells

................................ ................................ ................................ ................................ ................................ ... 46 Reducing Surface Disturbance

................................ ................................ ................................ ................................ .... 47 Reducing Wildlife Impacts

................................ ................................ ................................ ................................ ............ 48 Reducing Community Impacts

................................ ................................ ................................ ................................ .... 49 Protecting Groundwater: Ca sing and Cementing Programs

................................ ................................ ......... 51 Hydraulic Fracturing

................................ ................................ ................................ ................................ .......................... 56 Fracture Design

................................ ................................ ................................ ................................ ................................ 56 Fracturing Process

................................ ................................ ................................ ................................ ........................... 58 Fracturing Fluids and Additives

................................ ................................ ................................ ................................ . 61 Water Availability

................................ ................................ ................................ ................................ ................................ 64 Water Management

................................ ................................ ................................ ................................ ............................. 66 Naturally Occurring Radioactive Material (NORM)

................................ ................................ .............................. 70
Air Q uality

................................ ................................ ................................ ................................ ................................ ................ 71 Sources of Air Emissions

................................ ................................ ................................ ................................ ................ 72 Composition of Air Emissions

................................ ................................ ................................ ................................ ...... 72 Technological Controls and Practices

................................ ................................ ................................ ..................... 74
Summary

................................ ................................ ................................ ................................ ................................ .................. 76

Acronyms and Abbreviations

................................ ................................ ................................ .................... 79

DEFINITIONS

................................ ................................ ................................ ................................ .................. 81

ENDNOTES

................................ ................................ ................................ ................................ ...................... 83iii 

## LIST OF E XHIBITS

EXHIBIT

1. United States Energy Consumption by Fuel (2007)

................................ ................................ ......... 3

2. Natural Gas Use by Sector

................................ ................................ ................................ ............................ 4

3. Comparison of Production, Consumption and Import Trends for
Natural Gas in the United States

................................ ................................ ................................ ............... 5

4. Combustion Emissions

................................ ................................ ................................ ................................ .. 5

5. Typical Composition of Natural Gas

................................ ................................ ................................ ........ 6

6. Natural Gas Production by Source

................................ ................................ ................................ ........... 7

7. United States Shale Gas Basins

................................ ................................ ................................ .................. 8

8. United States Unconventional Gas O utlook

................................ ................................ ......................... 9

9. Trends in Shale Gas Production

................................ ................................ ................................ ............. 10

10. Marcellus Shale Outcrop

................................ ................................ ................................ ............................ 1 4

11. Comparison of Data for the Gas Shale s in the United States

................................ ..................... 1 7

12. Stra t igraphy of the Barnett Shale

................................ ................................ ................................ .......... 1 8

13. Barnett Shale in the Fort Worth Basin

................................ ................................ ................................ 1 8

14. Stratigraphy of the Fayetteville Shale

................................ ................................ ................................ . 19

15. Fayetteville Shale in the Arkoma Basin

................................ ................................ .............................. 19

16. Stratigraphy of the H aynesville Shale

................................ ................................ ................................ .. 20

17. Haynesville S hale in the Texas & Louisiana Basin

................................ ................................ ......... 20

18. Stratigraphy of the Marcellus Shale

................................ ................................ ................................ ...... 21

19. Marcellus Shale in the Appalac h ian Basin

................................ ................................ ......................... 21

20. Stratigraphy of the Woodford Shale in the Anadarko Basin

................................ ..................... 22

21. Woodford Shale in the Anadarko Basin

................................ ................................ .............................. 22

22. Stratigraphy of the Antrim Shale

................................ ................................ ................................ ........... 23iv

23. Antrim Shale in the Michigan Basin

................................ ................................ ................................ ...... 23

24. Stratigraphy of the New Albany Shale

................................ ................................ ................................ . 24

25. New Albany Shale in the Illinois Basin

................................ ................................ ................................ 24

26. Oil and Gas Regulatory Agencies in Shale Gas States

................................ ................................ ... 28

27. UIC Class II Primacy Map

................................ ................................ ................................ ........................... 33

28. Process of Shale Gas Development (Duration)

................................ ................................ ............... 44

29. Horizontal and Vertical Well Completions

................................ ................................ ........................ 4 6

30. Casing Zones and Cement Programs

................................ ................................ ................................ .... 5 2

31. Comparison of Target Shale Depth and Base of Treatable Groundwater

........................... 5 4

32. Example Output of a Hydraulic Fracture Simulation Model

................................ .................... 57

33. Mapping of Microseismic Events

................................ ................................ ................................ .......... 57

34. Example of a Single Stage of a Sequenced Hydraulic Fracture Treatment

......................... 5 9

35. Volumetric Composition of a Fracture Fluid

................................ ................................ .................... 6 2

36. Fracturing Fluid Additives, Main Compounds , and Common Uses

................................ ........ 63

37. Estimated Water Needs for Drilling and Fracturing Wells in Select Shale Gas Plays

................................ ................................ ................................ ............................... 6 4

38. Annual Rainfall Map of the United States

................................ ................................ .......................... 67

39. Current Produced Water Management by Shale Gas Basin

................................ ....................... 69

40. VOC Emissions by Source Category

................................ ................................ ................................ ...... 7 2

41. Benzene Emissions by Source

– 1999

................................ ................................ ................................ . 7 3

42. CO Emissions by Source Category

................................ ................................ ................................ ......... 7 3MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

1 

## INTRODUCTION

Natural gas production from hydrocarbon

- rich shale formations, known as “shale gas”, is one of the

most rapidly expanding trends in on shore domestic oil and gas exploration and production today.
I n some areas, this has included bringing drilling and production to regions of the country that have seen little or no activity in the past

. New oil and gas developments bring change s to the
environmental and socio

- economic landscape, particularly in thos e areas where gas development is a new activity. With these changes have come questions about the nature of shale gas development, the potential environmental impacts , and the ability of the current regulatory structure to deal with this development. R eg ulators

, policy makers , and the public need an objective source of information on which to base answers to these questions and decisions about how to manage the challenges that may accompany shale gas development.

This Primer endeavors to provide much of that information. It describes the importance of shale gas in meeting the future energy needs of the United States (U.S.) , including its role in alternative energy strategies and reducing greenhouse gas (GHG) emissions. The Primer provides an overview
of modern shale gas development

, as well as a summary of federal, state, and local regulations applicable to the natural gas production industry, and describes environmental considerations related to shale gas development.

Th e Primer is intended to serve as a technical summary document, including geologic information on the shale gas basins in the U.S. and the methods of shale gas development. By providing an overview of the regulatory framework and the environmental considerations associated wi th shale gas development, it will also help facilitate the minimization and mitigation of adverse environmental impacts. By so doing, the Primer can serve as an instrument to facilitate informed public discussions and to support sound policy

- making decisi ons by government.MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER



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3 

## What I s a Tcf?

Natural gas is generally priced and sold in units of a thousand cubic feet (Mcf, using the Roman numeral for one thousand). Units of a trillion cubic feet (

t cf) are often used to measure large quantities, as in resources or reserves in the ground,

or annual national energy consumption. A t cf is one billion Mcf and is enough natural gas to:

Heat 15 million homes for

one year ; Generate 100 billion
kilowatt

- hours of electricity ; Fuel 12 million natural gas

fired vehicles for one year.



## THE IMP ORTANCE OF SHALE GAS

The Role of Natural Gas in the United States’ Energy Portfolio
Natural gas plays a key role in meeting U.S. energy demands. Natural gas, coal and oil supply about 85% of the nation’s energy, with natural gas supplying about 22% of the total 1 (Exhibit 1 2 ). The percent contribution of natural gas to th e U.S. energy supply is expected to remain fairly constant for the next 20 years.

The United States has abundant natural

gas resources. The Energy Information
Administration (EIA) estimate s that the U.S. has more than 1,74 4 t rillion cubic feet (t cf ) of technically recoverable natural gas, including 211 t cf of prove d reserves (the discovered, economical ly recoverable fraction of the original gas

in

- place) 3

, 4

. Navigant Consulting estimates that technically recoverable unconventional gas (shale gas, tight sands, and coalbed natural gas ) accounts for 60 % of the onshore recoverable resource 5

. At the U.S. production rates for 20 07, about 19.3 tcf , the current recoverable resource estimate provides enough natural gas to supply the U.S. for the next 90 years 6

. Note that historically, estima t es of the size of the total recoverable resource have grown over tim e as knowledge of the resource has improved and recovery technology has advanced. Unconventional gas resources are a prime example of
this trend.

Natural gas use is distributed across several sectors of the economy (Exhibit 2 7 ). It is an important energy source for the industrial , commercial and electrical generation sectors, and also serves a vital role in residential heating 8

. Although forecasts vary in their
outlook for future demand for natural gas, they all have one thing in common: natural gas wil l continue to play a significant role in the U.S. energy picture for
some time to come 9

.
Natural gas, due to its clean

- burning nature and economical availability, has become a very popular fuel for the generation of electricity 10

. In the 1970s
and 80 s, the choice for the majority of electric utility generators was primarily coal or nuclear power; but, due to economic, environmental, technological , and 

### E XHIBIT 

### 1 : U NITED 

### S TATES 

### E NERGY 

### C ONSUMPTION BY 

### F UEL 

### (200 7 )MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

4 Half of the natural gas consumed today is produced from wells drilled within the last 3.5 years. regulatory changes, natural gas has become the fuel of choice for many new power plants. In 2007, natural gas was 39.1 % 11 of electric industry productive capacity.

Natural gas is also the fuel of choice for a wide range of industries. It is a major fuel source for pulp and paper, metals,
chem icals, petroleum refining, and food processing. These five industries alone account for almost three quarters of industrial natural gas use 12 and together employ four million people in the U.S. 13 Natural gas is also a feedstock for a variety of products, i ncluding plastics, chemicals, and fertilizers. For many products, there is no economically viable substitute for natural gas. Industrial use of natural gas accounted for 6.63 tcf of demand in 2007 and is expected to grow to 6.82 tcf by 2030.

However, natural gas is being consumed by the U.S. economy at a rate that exceeds domestic production and the gap is increasing 14

. Half of the natural gas consumed tod ay is produced from wells drilled within the last 3.5 years 15

. Despite possessing a large resource endowment , the U.S. consumes natural gas at a rate requiring rapid replacement of reserves. It is estimated that the gap between demand and domestic supply will grow to nearly 9 tcf by the year 2025 16

. However, it is believed by many that unconventional natural gas resources such as shale gas can significantly
alter that balance.

Exhibit 3 17 shows a comparison of production, consumption, and import trends for natural gas in
the U .S. with demand increasingly exceeding conventional domestic production. Without domestic shale gas and other unconventional gas production

, the gap between demand and domestic production will widen even more, leaving imports to fill t he need. Worldwide consumption of natural gas is also increasing ; therefore the U.S. can anticipate facing an increasingly competitive market for these imports.

This increased reliance on foreign sources of energy could pose at least two problems for the U.S.: 1) i t would serve to decrease our energy security ; and 2) i t could create a multi

- billion dollar outflow to foreign interests, thus making s uch funds unavailable for domestic investment

. 

### E XHIBIT 

### 2 : N ATURAL 

### G AS 

### U SE 

### B Y



### S ECTORMODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

5 

### The Advantages of Natural Gas

In the 1800s and e arly 1900s, natural gas was mainly used to light streetlamps and the
occasional house. However, with a vastly improved
distribution network and advancements in technology, natural gas is now being used
in many ways. One reason for the widespread use of natural gas is its versatility as a fuel. Its high British thermal unit ( B tu ) content

an d a well

- developed infrastructure make it easy to
use in a number of applications.

Another factor that makes natural gas an attractive energy source is its reliability. Eighty

- four percent of the natural gas consumed in the U.S. is produced in the U.S., and ninety

- seven percent of the gas used in this country is produced in North Americ a 18 . Thus, the supply of natural gas is not dependent on unstable foreign countries and the delivery system is less subject to interruption.

A key advantage of natural gas is that it is efficient and clean burning 19

. In fact, of all the fossil fuels, natural gas is by far the cleanest burning. It emits approximately half the carbon dioxide (C O 2 ) of coal along with low levels of other air pollutants 20 . The combustion byproducts of natural gas are mostly CO 2 and water v apor, the same compounds people exhale when breathing. Coal and oil are composed of much more complex organic molecules with greater nitrogen and sulfur content. Their combustion byproducts include large r quantities of CO 2

, nitrogen oxides (NO x ),
sulfur dioxide (SO 2 ) and particulate ash (Exhibit 4 21 ). By comparison, the combustion of natural gas liberates very
small amou nts of SO 2 and NO x , virtually no ash, and lower levels of CO 2 , carbon monoxide ( CO ) , and other hydrocarbons 22

.
Because natural gas emits only half as
much CO 2 as coal and approximately 30%
less than fuel oil

, it is generally considered to be central to energy plans focused on E XHIBIT 3 : C OMPARISON OF P RODUCTION , C ONSUMPTION AND I MPORT T RENDS FOR N ATURAL G AS IN THE U NITED S TATES

E XHIBIT 4 : C OMBUSTION E MISSIONS (P OUNDS / BILLION B TU OF E NERGY I NPUT )

Air Pollutant Combusted Source

Natural Gas Oil Coal

Carbon dioxide (CO 2 ) 117,000 164,000 208,0 00

Carbon monoxide (CO) 40 33 208

Nitrogen oxides (NO x ) 92 448 457

Sulfur dioxide (SO 2 ) 0.6 1,122 2,591
Particulates (PM) 7 .0 84 2,744 Formaldehyde 0.750 0.220 0.221 Mercury (Hg) 0.000 0.007 0.016

Sources: EIA, 1998MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

6 Of all the fossil fuels,

natural gas is by far the cleanest burning. the reduction of GHG emissions 23

. According to the EIA in its report “Emissions of Greenhouse Gases in the United
States 200 6

, ” 8 2.3 % of GHG emissions in the U.S. in 200 6 came from CO 2 as a direct result of fossil fuel combustion 24

. Since CO 2 makes up a large fraction of U.S. GHG emissions

, increasing the role of natural gas in U.S. energy supply relative to other fossil fuels would r esult in
lower GHG emissions.

Although there is rapidly increasing momentum to reduce dependence on fossil fuels in the U.S. and elsewhere, the transition to sustainable renewable energy sources will no doubt require considerable time, effort and investment in order for the se sources to become economical enough

to supply a significant portion of the nation’s energy consumption. Indeed, the EIA estimates that
f ossil fuels (oil, gas, and coal) will supply 82.1 % of the nation’s energy needs in 2030 25

. Since natural gas is the cleanest burning of the fossil fuels, an environmental benefit could be realized by shifting toward proportionately greater reliance on natu ral gas until such time as sources of alternative energy are more efficient, economical, and widely available.

Additionally, the march towards sustainable renewable energy sources

, such as wind and solar

, requires that a supplemental energy source be available when weather conditions and electrical storage capacity prove challenging 26

. Such a backstop energy source must be widely available on
near instantaneous demand. The availability of extensive natural gas transmission and distribution pipeline systems makes natural gas uniquely suitable for this role 27

. Thus, natural gas is an integral facet of moving forward with alternative energy options. With the current emphasis on the potential effects of air emissions on global climate change, air quality, and visibility, cleaner fuels like natural gas are an important part of our nation’s energy future 28

.


### Natural Gas Basics
Natural gas is a combination of hydrocarbon gases consisting primarily of methane (CH 4 ), and lesser percentages of butane, ethane, propane, and other gases 29

, 30

. It is odorless, colorless, and, when ignited, releases a significant amount of

energy 31

. Exhibit 5 32 shows the typical compositional range of natural gas produced in the U.S.

Na tural gas is found in rock formations (reservoirs) beneath the earth’s surface; in some cases it may be associated with oil deposits. Exploration and production companies explore for these 

### E XHIBIT 

### 5 : T YPICAL 

### C OMPOSITION OF 

### N ATURAL 

### G ASMODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

7 deposits by using complex technologies to identify prospective dri lling locations. Once extracted, the natural gas is processed to eliminate other gases, water, sand, and other impurities. Some hydrocarbon gases, such as butane and propane, are captured and separately marketed. Once it has been processed, the cleaned natural gas is distributed through a system of pipelines across
thousands of miles 33

. It is through these pipelines that natural gas is transported to its endpoint for residential, commercial, and industrial use.

Natural gas is measured in either volumetric or energy units. As a gas, it is measured by the volume it displaces at standard temperatures and pressures, usually expressed in cubic feet. Gas companies generally measure natural gas in thousands of cubic f eet (Mcf), millions of cubic feet (MMc f), or billions of cubic feet (b cf), and estimate resources such as original gas

- in

- place in trillions of cubic feet (t cf).

Calculating and tracking natural gas by volume is useful, but it can also be measured as a so urce of

energy. Similar to other forms of energy, natural gas can be computed and presented in British thermal units (Btu). One Btu is the quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit at normal pressur e 34

. There are about 1, 0 00 Btus in one cubic foot of natural gas delivered to the consumer 35

. Natural gas distribution companies typically measure the gas delivered to a residence in 'therms' for billing purposes 36

. A therm is equal to 100,000 Btus

— approxi mately 100 cubic feet

— o f natural gas 37

.


### Unconventional Gas
The U.S. increased its natural gas reserves by 6% from 1970 to 2006 , producing approximately 725

t cf of gas during that period 38

. This increase is primarily a result of advancements in technology

, resulting in an increase in economically recoverable reserves ( reserves becoming proven ) that were previously thought to be

un economic 39

.

In 200 7

, Texas

, Wyoming, and
C olorado were the
states with the greatest additions to proved gas reserves for the year; these
additions were from shale gas, tight sands,
and coalbed methane

, all of which are unconventional gas plays 40

. Similarly, the states of Texas ( 30 %) and Wyoming (12%) had the greatest volume of proved gas 

### E XHIBIT 

### 6: N ATURAL 

### G AS 

### P RODUCTION BY 

### S OURCE ( TCF / YEAR )

S ource: EIA, 2008MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

8 Unconventional production now

accounts for 46% of the total U.S. production. reserves in the U.S. in 200 7

— a gain, both primarily as a result of developing unconventional natural gas plays 41

.

Over all, unconventional natural gas is anticipated to become an ever

- increasing portion of the U.S. prove d reserves, while conventional gas re serves are declining 42

. Over the last decade, production from
unconventional sources has increased almost 65 %, from 5. 4 trillion cubic feet per year (tcf/yr) in
1998 to 8.9 t cf/y r in 2007 (Exhibit 6)

. This means unconventional production now accounts for 46% of the total U.S. production 43

.



### E XHIBIT 

### 7 : U NITED 

### S TATES 

### S HALE 

### G AS 

### B ASINS



### The Role of Shale Gas in Unconventional Gas

The lower 48 s tates have a wide distribution of highly organic shales containing vast resources of natural gas (Exhibit 7 44 ). Already

, the fledgling Barnett Shale play in Texas produces 6 % of all natural gas produced in the lower 48 s tates 45

. Improved drilling and fracturing technolog ies ha ve contributed considerably to the economic potential of shale gas

. This potential for production in Source: ALL Consulting, Modified from USGS & other sourcesMODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

9 Three factors have come together

in recent years to make shale gas production economically viable: 1) advances in horizontal drilling, 2) advances in hydraulic fracturing, and, perhaps most importantly, 3) rapid increases in natural gas prices

. the known onshore shale basins

, coupled with other unconventional gas plays

, is predicted to
contribute significantly to the U.S.’s domestic energy outlook. Exhibit 8 46 shows the projected

c ontribution of shale gas to the overall unconv entional gas production in the U.S. in b cf/day.

Three factors have come together in recent years to make shale gas production economically
viable: 1)
advances in horizontal drilling, 2) adva nces in hydraulic fracturing, and, perhaps most importantly, 3) rapid increases in natural gas prices
in the last several

years as a result of significant supply
and demand

pressures. Advances in the

pre

- existing technologies of directional drilling and h ydraulic fracturing set the stage for today’s horizontal drilling and fracturing techniques, without which many of the unconventional natural gas plays would not be economical. As recently as the late 1990s

, only 40 drilling rigs (6% of total active rigs in the U.S. ) in the U.S. were capable of onshore horizontal drilling; that number grew to 519 rigs (28% of total active rigs in the U.S. ) by May 2008 47

.
It has been suggested that the rapid growth of unconventional natural gas plays has not been captured by recen t resource estimates compiled by the EIA and that, therefore, their resource estimates do not accurately reflect the contribution of shale gas 48

. Since 1998

, annual production has consistently exceeded the EIA’s forecasts of unconventional gas production. A great deal of this increase is attributable to shale gas production, particularly from the Barnett Shale in Texas. The potential for most other shale gas plays in the U.S. is just emerging. Taking this into consideration, Navigant, adding their own an alysis of shale gas resources to other national resource estimates, has estimated that U.S. total natural gas resources (proved plus unprove d technically recoverable) are 1,680 tcf to 2,247 tcf, or 87 to 116 years of production at 2007 U.S. production leve ls

. This compares with EIA’s national 

### E XHIBIT 

### 8: U NITED 

### S TATES 

### U NCONVENTIONAL 

### G AS 

### O UTLOOK 

### ( BCF 

### / DAY 

### )MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

10 Shale gas resource e stimates are likely

to change as new information, additional experience, and advances in technology become available. resource estimate of 1

, 744 tcf, which is within the Navigant

range. Navigant has estimated
that shale gas comprises 28% or more of total estimated technically recoverable gas
resources in the U.S. 49

. Exhibit
9 50 depic ts the daily production (in MMcf/day) from each of the currently active shale gas plays.

As with most resource estimates, especially emerging

resources such as unconventional natural gas

, these estimates are likely to change over time. In addition, there are a variety of organizations making resource and future production estimates for shale gas. These analyses use different assumptions, data, and methodologies. Therefore, one may come across a wide range of numbers for projected shale gas recovery, both nationally and by basin. These shale gas resource estimates are likely to change as new information, additional experience, and advances in technology become available.

Analysts have estimated that by 2011 most new reserves growth (50 % to 60 %, or approximately 3 bcf/ d ay ) will come from unconventional shale gas reservoirs 51

. The total re coverable gas resources
from 4 emerging shale gas plays (the Haynesville, Fayetteville, Marcellus, and Woodford ) may be over 550 t cf 52

. Total annua l production volumes of 3 to 4 t cf may be sustainable for decades. An additio nal benefit of shale gas plays is that many exist in areas previously developed for natural gas production and, therefore, much of the necessary pipeline infrastructure is already in place

. Many of these areas are also proximal to the nation’s population centers thus potentially facilitating transportation to consumers. However, additional pipelines will have to be built to access development in areas that have not seen gas production before 53

. 

### Looking Forward
Considering natural gas’s clean

- burning nature

, the nation’s domestic natural gas resources, and the presence of supporting infrastructure, the development of domestic shale gas reserves will be an important component of the U.S.’s ener gy portfolio for many years. Recent successes in a variety of geologic basins have created the opportunity for shale gas to be a strategic part of the nation’s energy and economic growth 54

. 

### E XHIBIT 

### 9: T RENDS IN 

### S HALE 

### G AS 

### P RODUCTION (MM CF /D AY )MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

11 Recent successes and improvements in a variety of geologic basi ns have created the opportunity for shale gas to be a strategic part of the nation’s energy and economic growth. The Environmental Considerations
section of this Primer describes how improvements in horizontal drilling and hydraulic fracturing technologies have opened the door to the economic recovery of shale gas . It also discusses

a dditional practices that have allowed development of areas that might previously have been
inaccessible due to environmental constraints or restrictions on disturbances in bot h urban and rural settings. By using horizontal drilling, operators have been able to reduce the extent of surface impact commonly associated with multiple vertical wells drilled from multiple well pads; equivalent well coverage can be achieved through dr illing fewer horizontal wells from a single well pad. This can result in a significant reduction in surface disturbances: fewer well pads, fewer roads, reduced traffic, fewer pipelines, and fewer surface facilities. In urban settings

, this can mean
less impact on nearby populations and businesses. In rural settings

, this can mean fewer consequences for wildlife habitat s , agricultural resources, and surface water bodies.

Other practices that are now commonly used for drilling

, particularly in urban sett ings

, include: the use of sound walls and blankets to reduce noise, the use of directional or shielded lighting to reduce nighttime disturbance to nearby residences and businesses, the use of pipelines to transport water resulting in reduced truck traffic , and the use of solar

- powered telemetry devices to monitor gas production resulting in reduced personnel visits to well sites. Such practices are used in specific locations or situations that call for them, and are not appropriate everywhere, but where n eeded, they provide opportunities for safe, environmentally sound development that may not have been possible without them.

These technologies and practices, along with the increasing gas prices of the last few years, have provided the means by which shale gas can be economically recovered. Improvements in reducing the overall footprint and level of disturbance from drilling a nd completion activities have provided the industry with the methods for moving forward with development in new areas that were previously inaccessible

.MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER



## THIS PAGE INTENTIONALLY LEFT BLANKMODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

13 The first producing gas well in the U.S. was completed in 1821 in Devonian

- aged s hale near the town of Fredonia, New York. 

## S HALE GAS DEVELOPMENT IN THE UNITED STATES

Shale formations across the U.S. have been developed to produce natural gas in small b ut continuous volumes since the earliest year s of gas development. The first producing gas well in the
U.S. was completed in 1821 in Devonian

- aged s hale near the town of Fredonia, New York 55 . The natural gas from this first well was used by town residents for lighting 56 . Early supplies of
natural gas were derived from shallow gas wells that were not complicated to drill and from natural gas seeps 57 . The shallow wells and seeps were capable of producing small amounts of natural gas that were used for illuminating city streets and households 58 . These early gas wells played a key part in bringing illumination to
the cities and towns of the eastern U.S. 59

.
Other shale gas wells followed the Fredonia well with the first field

- scale development of shale gas from the Ohio Shale in the Big Sandy Field of Ke ntucky during the 1920 s 60 . The Big Sandy Field has recently experienced a renewed growth and currently is a 3,000

- square

- mile play encompassing
five counties 61 . By the 1930 s, gas from the Antrim Shale in Michigan had experienced moderate development; howev er, it was not until the 198 0 s that development began to expand rapidly to the point that it has now reached nearly 9,000 wells 62 . It was also during the 1980 s that one of the nation’s most active natural gas play s initially kicked off in the area around F ort Worth, Texas 63

. The play was the Barnett Shale

, and its success grabbed the industry’s attention. Large

- scale
h ydraulic fracturing, a process first developed in Texas in the 1950 s, was first used i n the Barnett in 1986; likewise, the first Barnett horizontal well was drilled in 1992 64 . Through continued improvements in the techniques and technology of hydraulic fracturing, development of the Barnett
Shale has accelerated 65 . In the ensuing two decades

, the science of shale gas extraction has matured into a sophisticated process that utilizes horizontal drilling and sequenced

, multi

- stage hydraulic fracturing technologies. As the Barnett Shale play has matured, natural gas producers have been looking to extrapolate the lessons learned in the Barnett t o the other shale gas formations present
across the U.S. and Canada 66

.
In addition to the Barnett Play, a second shale play with greater oil production has also been advancing techniques related to horizontal wells and hydraulic fracturing. The Bakken Shal e of the Williston Basin of Montana and North Dakota has seen a similar growth rate to the Barnet t. The
Bakken is another techni cal play in which the development of this unconventional resource has benefitted from the technological advances in horizontal wells and hydraulic fracturing 67 . In April 2008, the U nited States Geological Survey (U SGS ) released an updated assessment of the
undiscovered technically recoverable reserves for this shale play estimating the re are 3.65 billion
b arrels (bbls) of oil, 1.8 5 t cf of associated natural gas

, and 148 million bbls of natural gas liquids in the play 68

.
The combination of sequenced hydraulic fracture treatments and horizontal well completions has been crucial in facilitating the expansion of shale gas development. Prior to the successful application of these two technologies in the Barnett Shale

, shale gas resources in many basins had been overlooked because production was not viewed as economically feasible 69

. The low natural permeability of shale has been the limi ting factor to the production of shale gas resources becauseMODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

14 it only allows minor volumes of gas to flow naturally to a wellbore 70 . The characteristic of low

matrix permeability represents a key difference between shale and other gas reservoirs. For gas

s hales to be economically produced, the se restrictions must be overcome 71 . The combination of reduced economics and low permeability of gas shale formations historically caused operators to bypass these formations and focus on other resources 72

.


### Shale Gas

– Geology
Shale gas is natural gas produced from shale formations that typically function as both the reservoir and source for the natural gas. In terms of its chemical makeup, shale gas is typically a dry gas primarily composed of methane (90% or more methane), bu t some formations do produce wet gas. The Antrim and New Albany formations have typically produced water and gas 73 . Gas shales are organic

- rich shale formations that were previously regarded only as source rocks and seals for gas accumulating in the strat igraphically

- associated sandstone and carbonate reservoirs of traditional onshore gas development 74 . Shale is a sedimentary rock that is predominantly comprised of consolidated clay

- sized particles. Shales are deposited as mud in low

- energy depositional

e nvironments such as tidal flats and deep water basins where the fine

- grained clay particles fall out of suspension in these quiet waters. During the deposition of these very fine

- grained sediments, there can also be deposition of organic matter in the for m of algae

- , plant

- , and animal

- derived organic debris 75 . The naturally tabular clay grains tend to l ie flat as the sediments accumulate and subsequently become compacted as a result of additional sediment deposition. This results in mud
with thin laminar bed ding that lithif ies ( solidif

ies ) into thinly layered shale rock. The very fine
sheet

- like clay mineral grains and laminated layers of sediment result in a rock that has limited horizontal permeability and extremely limited vertical permeability. Typi cal unfractured shales have matrix permeabilities on the
order of 0.01 to 0.00001 millidarcies 76

. This low permeability means that gas trapped in shale cannot move easily within the rock except over geologic expanses of time (millions of years).

The natural layering and fracturing of shales can be seen in outcrop. Exhibit
10 shows a typical shale outcrop which reveals the natural bedding planes, or layers, of the shale and

near

- vertical natural fractures that can cut across the naturally horizontal bedding planes. Although the vertical fractures shown in this picture are

nat urally occurring, artificial fractures induced by hydraulic fracture stimulation in the deep subsurface
reservoir rock would have a similar

appearance. 

### E XHIBIT 

### 10 : M ARCELLUS 

### S HALE 

### O UTCROP

Source: T. Engelder home pag e

Source: ALL Consulting, 2008MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

15 The low permeability of shale causes it to be classified as an unconventional reservoir for gas (or in

some cases , oil) production. These low permeability, often organic

- rich units are also thought to be the source beds for much of the hydrocarbons produced in these basins 77

. G as reservoirs are classified as conventional or unconventional for the following reasons:

1. Conventional reservoirs

– W ells in conventional gas reservoirs produce from sands and carbonates (limestones and dolomites) that contain the gas in interconnected pore
spaces that allow flow to the wellbore. Much like a kitchen sponge, the gas i n the pores can move from one pore to another through small er pore

- throats that create permeable flow through the reservoir. In conventional natural gas reservoirs, the gas is often sourced from organic

- rich shales proximal to the more porous and permeabl e sandstone or carbonate.

2. Unconventional reservoirs

– W ells in unconventional reservoirs produce from low permeability (tight) formations such as tight sands and carbonates , coal, and shale. In unconventional gas reservoirs, the gas is often sourced from the reservoir rock itself (tight gas sandstone and carbonates are an exception). Because of the low permeability of these formations, it is typically necessary to stimulate the reservoir to cr eate additional permeability. Hydraulic fracturing of a reser voir is the preferred stimulation method for gas shales. Differences between the three basic types of unconventional reservoirs include:

1. Tight Gas

– W ells produce from regional low

- porosity sandstones and carbonate reservoirs. The natural gas is sourced (formed) outside the reservoir and migrates into the reservoir over time (millions of years) 78 . Many of these wells are drilled horizontally and most are hydraulically fractured to enhance production.

2. Coal Bed Natural Gas (CBNG)

– W ells produce from the coal seams which act as source and reservoir of the natural gas 79 . Wells frequently produce water as well as natural gas. Natural gas can be sourced by thermogenic alterations of coal or by biogenic action of indigenous microbes on the coal. There are so me horizontally drilled CBNG wells and some that receive hydraulic fracturing

treatments. However, some CBNG reservoirs are also underground sources of drinking water and as such there are restrictions on hydraulic fracturing. CBNG
wells are most ly shallow as the coal matrix does not have the strength to maintain porosity under the pressure of significant overburden thickness.

3. Shale Gas

– W ells produce from low permeability shale formations that are also the source for the natural gas. The natu ral gas volumes can be stored in a local

macro

- porosity system (fracture porosity) within the shale, or within the micro

pores of the shale 80

, or it can be adsorbed on to minerals or organic matter
within the shale 81 . Wells may be drilled either vertically o r horizontally and most are hydraulically fractured to stimulate production. Shale gas wells can be similar to other conventional and unconventional wells in terms of depth, production rate, and drilling.MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

16 

### Key Gas Resource Terms

Proved Reserves : That portion of
recoverable resources that is demonstrated by actual production or conclusive formation tests to be technically, economically

, and legally producible under existing economic and operating conditions.

Technically Recoverable Res ourc es : The total amount of resource, discovered and undiscovered, that is thought to be recoverable with available technology, regardless of
economics

.
Original Gas

- In

- Place : The entire volume of gas contained in the reservoir, regardless of the ability to produce it. 

### Sources of Natural Gas

Shale gas is both created and stored within the shale bed. Natural gas (methane) is generated from the organic matter that is deposited with and present in the shale matrix.

I n order for a shale to have economic quantities of gas it must be a capable source rock. The potential of a shale formation to contain economic quantities of gas can be evaluated by identifying specific source rock characteristics such as total organic carbon (TOC), thermal maturity, and kerogen analysis. Together, these factors can be used to predict the likelihood of the prospective shale to produce economically viable volumes of natural gas. A number of wells may need to be analyzed in order to sufficiently characterize the potential of a shale formation

, particularly if the geologic basin is large and there are variations in the target shale zone.



### Shale Gas in the United States
Shale gas is present across much of the lower 48
S tates . Exhibit 7 shows the approximate locations of current producing gas sha les and prospective
shales. The most active shales to date are the
Barnett Shale

, the Haynesville /Bossier Shale, the
Antrim Shale , the Fayetteville Shale, the Marcellus Shale, and the New Albany Shale. The following discussion provides a summary of basic information regarding the se shale gas plays

.
Each of these gas shale basins is different and each
has a unique set of exploration criteria and operational challenges. Because of these differences, the development of shale gas
resources in each of these areas faces potential ly unique challenges

. For example

, the Antrim and New Albany Shales are shallower shales that produce significant volumes of formation water unlike most of the other gas shales

. D evelopment of the Fayetteville Shale is occurring in r ural areas
of north central Arkansas

, while development of the Barnett Shale is focused in the area of Forth Worth, Texas

, in an urban and suburban
environment.

As new technologies are developed and refined

, shale gas plays once believed to have limited

e conomic viability are now being re

- evaluated. Exhibit 1 1 summarizes the key characteristics of
the most active shale gas plays across the U.S . This e xhibit supplies data related to the character of
the shale and also provides a means to compare some of the key characteristics that are used to evaluate the different gas shale basins. Note that estimates of the shale gas resource, especially the portion that is technically recoverable, are likely to increase over t ime as new data become available from additional drilling, as experience is gained in producing shale gas, as understanding of the resource characteristics increases, and as recovery technologies improve.MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

17 

### E XHIBIT 

### 1 1 : C OMPARISON OF 

### D ATA FOR THE 

### G AS 

### S HALES IN THE 

### U NITED 

### S TATES

Gas Shale Basin Barnett Fayetteville Haynesville Marcellus Woodford Antrim New Albany
Estimated Basin Area, square miles 5,000 9,000 9,000 95,000 11,000 12,000 43,500

Depth, ft 6, 500

-

8,500 82 1,000

-

7,000 83 10,500

-

13,500 84 4,000

-

8,500 85 6,000

-

11,000 86 600

- 2,200 87 500

- 2,000 88
Net Thickness, ft 100

- 600 89 20

- 200 90 200 91

- 300 92 50

- 200 93 120

- 220 94 70

- 12 0 95 50

- 100 96

Depth to Base of Treatable
Water # , ft ~1200 ~500 97 ~400 ~850 ~400 ~300 ~400

Rock Column Thickness between Top of Pay and Bottom of Treatable
Water , ft 5,300

-

7,300 500

- 6,500 10,100

- 13,100 2,125

- 7650 5,600

- 10,600 300

- 1,900 100

- 1,600

Total Organic Carbon, % 4.5 98 4.0

- 9.8 99 0.5

- 4.0 100 3

- 12 101 1

- 14 102 1

- 20 103 1

- 25 104

Total Porosity,
% 4

- 5 105 2

- 8 106 8

- 9 107 10 108 3

- 9 109 9 110 10

- 14 111

Gas Content, scf/ton 300

-

350 112 60

- 220 113 100

- 330 114 60

- 100 115 200

- 300 116 40

- 100 117 40

- 80 118

Water Production, Barrels water/day N/A N/A N/A N/A N/A 5

- 500 119 5

- 500 120

Well spacing,

a cres 60

- 160 121 80

- 160 40

- 560 122 40

- 160 123 640 124 40

- 160 125 80 126

Original Gas

- In

Place, t cf 127 327 52 717 1,500 23 76 160

Technically Recoverable
Res ources , t cf 128 44 41.6 251 262 11.4 20 19.2

NOTE: Information presented in this table, such as Original Gas

- in

- Place and Technically Recoverable Resources
, is presented for general comparative purposes only. The numbers provided are based on the sources shown and this research did not include a resource evaluation

. Rather, publically available dat a was obtained from a variety of sources and is presented for gen eral characterization and comparison. Resource estimates for any basin may vary greatly depending on individual company experience , data available at the time the estimate was performed, and other factors. Furthermore, these estimates are likely to change as production methods and technol og ies improve.
M cf = thousands of cubic feet of gas

s cf = standard cubic feet of gas

t cf = trillions of cubic feet of gas
# = F or the Depth to base of treatable water data, the data was based on depth data from state oil and gas agencies and state geological survey data. N/A = Data not availableMODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

18 The Barnett Shale

The Barnett Shale is located in the Fort Worth Basin of north

- central Texas. It is a Mississippian

age shale occurr ing at a depth of 6,500 feet to 8,500 feet (Exhibit 1 1 and Exhibit 1 3 131 ) and is bounded by limestone formations above (Marble Falls Limeston e) and below (Chappel Limestone ) ( Exhibit 1 2 )

.

With over 10,000 wells drilled to date, the Barnett Shale is the most prominent shale gas play in the
U.S. 132

. It has been a showcase for modern tight

- reservoir development typical of gas shales in the
U.S. 133 . The development of the Barnett Shale has been a prov ing ground for combining the technologies of horizontal drilling and large

- volume hydraulic fracture treatments. Drilling operations continue expanding the play boundaries outward; at the same time, operations have turned towards infill drilling to increa se the amount of gas recovered 134 . Horizontal well completions in the Barnett are occurring at well spacing ranging from 60 to 160 acres per well ( Exhibit 1 1 ).

The Bar nett Shale covers an area of about 5,000 square miles with an approximate thickness ranging from 100 feet ( ft ) to more than 600 ft ( Exhibit 1 1 ). The original gas

- in

- place estimate for
the Barnett Shale is 327 t cf with estima ted technically recoverable res ources of 44 t cf ( Exhibit 1 1 ). The gas content is the highest among the major shale plays , ranging from 300 s tandard cubic feet per ton (s cf/ton ) to 350 scf/ton of rock ( Exhibit 1 1 ).



### E XHIBIT 

### 1 2 : S TRATIGRAPHY OF THE 

### B ARNETT 

### S HALE Period Group/Unit Permian Leonardian Clear Fork Grp

Wichita Grp Wolfcampian Cisco Grp Pennsylvanian Virgilian Missourian Canyon Grp Desmoinesian Strawn Grp Atokan Bend Grp

Marble Falls Limestone Morrowan Mississippian Chesterian

- Meramecian Barnett Shale

Osagean Chappel

Limestone Ordovician Viola Limestone

Canadian Simpson Grp

Ellenburger Grp

Source: Hayden and Pursell

, 2005 129

AAPG

, 1987 130 

### E XHIBIT 

### 13 : B ARNETT 

### S HALE IN THE 

### F ORT 

### W ORTH 

### B ASIN

Source: ALL Consulting, 2009MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

19 The Fayetteville Shale The Fayetteville Shale is situated in the Arkoma Basin of northern Arkansas a nd eastern Oklahoma

over a depth range of 1,000 ft to 7,000 ft ( Exhibit 1 5 135 and Exhibit 1 1 ). The Fayetteville Shale is a Mississippian

- age shale bound ed by limestone (Pitkin Limestone) above and sandstone (Batesvill e Sandstone) below ( Exhibit 1 4 ).

Development of the Fayetteville began in the early 2000 s as gas companies that had experienced success in the Barnett Shale of the Fort Worth Basin identified parallels between it and the Mississippian

- a ged Fayetteville Sh ale in terms of age and geologic character 136

. Lessons learned from the horizontal drilling and hydraulic fracturing techniques employed in the Barnett, when adapted to development of the Fayetteville Shale, made this play economical 137

. Between 2004 and 2007 the number of gas wells drilled annually in the Fayetteville shale jumped from 13 to more than 600

, and gas production for the shale increased from just over 100 MMcf/yr to approximately
88.85 b cf/yr 138

. With over 1,000 wells in production to date, th e Fayetteville Shale is currently on its way to becoming one of the most active plays in the U.S

. 139

.

The area of the Fayetteville Shale play is nearly double that of the Barnett Shale at 9,000 square miles, with well spacing ranging from 80 to 160 acres per well, and pay zone thickness averaging
between 20 ft and 200 ft ( Exhibit 1 1 ). T he gas content for the Fayetteville Shale has been measured at 60 to 220 scf/ton, which is less than the 300 to 350 scf/ton gas content of the Barnett

. The lower gas content of the Fayetteville, as compared to the Barnett, results in lower estimates of the original gas

- in

- place and technically recover able res ources : 52 tcf and 41.6 t cf respectively ( Exhibit 1 1 ).

E XHIBIT 1 4 : S TRATIGRAPHY OF

THE F AYETTEVILLE S HALE

Period Group/Unit

C ARBONIFEROUS Pennsylvanian Atoka

Bloyd
Hale Prairie

Grove

Cane Hill Mississippian (IMO)

Pitkin

Fayetteville

Batesville

Moorefield

Boone

Source: Hillwood

, 200 7 140 

### E XHIBIT 

### 15 : F AYETTE VILLE 

### S HALE IN THE 

### A RKOMA 

### B ASIN

Source: ALL Consulting, 2009MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

20 The Haynesville Shale The Haynesville Shale (also known as the Haynesville/Bossier) is situated in the North Louisiana Salt Basin in northern Louisiana and eastern Texas with depths rang ing from 10,500 ft to 13,500 ft ( Exhibit 1 7 141 and Exhibit 1 1 ). The Haynesville is an Upper Jurassic

- age shale bound ed by sandstone (Cotton Valley Group) above and limestone (Smackover Formation) below ( Exhibit 1 6 ).

In 2007, after several years of drilling and testing, the Haynesville Shale made headlines as a potentially significant gas reserve, although the full extent of the play will only be known after several more years of development are completed 142

.
The Haynesville Shale covers an area of approximately 9,000 sq uare miles with an average
thickness of 200 ft to 300 ft ( Exhibit 1 1 ). The thickness and areal extent of the Haynesville has
allowed operators to evaluate a wider variety of spacing intervals ranging from 40 to 560 acres per well ( Exhibit 1 1 ). Gas content estimates for the play are 100 scf/ton to 330 scf/ton

. The Haynesville formation has the potential to become a significant shale ga s resource for the U.S. with original gas

- in

- place estimates of 7 17 t cf and technically recoverable res ources e stimated at 25 1 t cf ( Exhibit 1 1 ).



### E XHIBIT 

### 1 6 : S TRATIGRAPHY OF

THE 

### H AYNESVILLE 

### S HALE

Period Group/Unit Cretaceous Navarro

Taylor

Austin Eagle Ford

Tuscaloosa

Washita Fredericksburg

Trinity Group

Nuevo Leon Jurassic Upper Cotton Valley Group

Haynesville Smackover Norphle t
Middle Louann

Lower Werner Triassic Upper Eagle Mills

Source: Johnson et al, 2000 143 

### E XHIBIT 

### 17 : H AYNESVILLE 

### S HALE IN

THE 

### T EXAS 

### & L OUISIANA 

### B ASIN

Source: ALL Consulting, 2009MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

21 The Marcellus Shale The Marcellus Shale is the most expansive shale gas play

, spanning six states in the northeastern
U.S

. ( Exhibit 19 144 ). The estimated depth of production for the Marcellus is between 4,000 ft and 8,500 ft ( Exhibit 1 1 ). The Marcellus Shale is a Middle Devonian

- age shale bound ed by shale (Hamilton Group) above and limestone (Tristates Group) below ( Exhibit 18 ).

Following an increase in gas prices, triggered by the Natural Gas Policy Act (NGPA) of 1978, Devonian shale gas development rose in the early

- to mid

- 1980s in the northeast

, but decreasing gas prices resulted in uneconomical wells and declining production through the 1990s 145

. In 2003, Range Resources Corporation drilled the first economically producing wells into the Marcellus
formatio n in Pennsylvania using horizontal drilling and hydraulic fracturing techniques similar to
those used in the Barnett Shale formation of Texas 146 . Range Resources began producing this
formation in 2005

. A s of September 2008, there were a total of 518 wells permitted in Pennsylvania in the Marcellus shale and 277 of the approved wells had been drilled 147

.
The Marcellus Shale covers an area of 95,000 square miles at an average thickness of 50 ft to 200 ft ( Exhibit 11 ). While the Marcellus is lower in relative g as content at 60 scf/ton to 100 scf/ton, the
much large r area of this play compared to the other shale gas plays results in a higher original gas

in

- place estimate of up to 1,500 tcf ( Exhibit 1 1 ).

At an average well spacing in the Marcellus is 4 0 to 160 acres per well ( Exhibit 1 1 ). The data in
Exhibit 1 1 show technically recoverable res ources for t he formation to be 262 tcf , although much like the Haynesville, the play’s potential estimates are fre quently being revised upward due to its early stage of development.



### E XHIBIT 

### 18 : S TRATIGRAPHY OF THE 

### M ARCELLUS 

### S HALE

Period Group/Unit
Penn Pottsville
Miss Pocono

Devonian Upper Conewango

Conneaut

Canadaway

West Falls Sonyea Genesee

Middle Tully Hamilton

Group Moscow Ludlowville Skaneateles Marcellus Onandaga

Lower Tristates

Helderberg

Source: Arthur et al

, 2008 148 

### E XHIBIT 

### 19 : M ARCELLUS 

### S HALE IN THE 

### A PPALACHIAN 

### B ASIN

Source: ALL Consulting, 2009MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

22 The Woodford Shale

Located in south

- central Oklahoma, the Woodford Shale ranges in depth f rom 6,000 ft to 11,000 ft ( Exhibit 2 1 149 and Exhibit 1 1 ). This formation is a Devonian

- age shale bound ed by limestone (Osage Lime) above and undifferentiated strata below ( Exhibit 2 0 ).

Recent natural gas produc tion in the Woodford Shale began in 2003 and 2004 with vertical well completions only 150

. However, horizontal drilling has been adopted in the Woodford, as in other shale gas plays, due to its success in the Barnett Shale 151

.
The Woodford Shale play encompass es an area of nearly 11,000 square miles ( Exhibit 1 1 ). The Woodford play is in an early stage of development and is occurring at a spacing interval of 640 acres per well ( Exhibit 1 1 ). The average thickness of the Woodford Shale varies from 120 ft to 220 ft across the play ( Exhibit 1 1 ).

Gas content in the Woodford Shale is higher on average
than some of the other shale gas plays at 200 scf/ton to 300 scf/ton ( Exhibit 1 1 ). The original gas

- in

- place
estimate for the Woodford Shale is similar t o the Fayetteville Shale at 23 t cf while the technically
recoverable resources are 11 .4 t cf ( Exhibit 1 1 ). 

### E XHIBIT 

### 2 0 : S TRATIGRAPHY OF THE 

### W OODFORD 

### S HALE

Period Group/Unit Permian Ochoan Cloyd Chief F m Guadalupian White Horse Grp

El Reno Grp
Leonardian Enid Grp

Wolfcampian Chase Grp

Council Grove Grp Admire Grp Penn. Atokan Atoka Grp

Morrowan Morrow Grp Mississippian Chesterian Chester Gr p Meramecian

Miss Lime Meramec Lime Osagean
Osage Lime
Kinderhookian Devonian Woodford Shale Upper

Undifferentiated Middle

Lower

Hunton Grp Haragan Fm Henryhouse Fm

Source: Cardott

, 2007

152
AAPG

, 1983 153 

### E XHIBIT 

### 21 : W OODF ORD 

### S HALE IN THE 

### A NADARKO 

### B ASIN

Source: ALL Consulting, 2009MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

23 The Antrim Shale

The Antrim Shale is located in the upper portion of the lower peninsula of Michigan within the Michigan Basin ( Exhibit 2 3 154 ). This L ate Devonian

- age shale is bounded by shale (Bedford Shale) above and by limestone (Squaw Bay Limestone) below and occurs at dept hs of 600 ft to 2,200 ft which is more typical of CBNG formations than most gas shales ( Exhibit 2 2 and Exhibit 1 1 ).

Aside from the Barnett, the Antrim Shale has been one of the most actively developed shale gas plays with its major expansion taking place i n the late 1980 s 155

.
The Antrim Shale encompasses an area of approximately 1 2 ,000 square miles and is characterized by distinct differences from other gas shales: shallow depth, small stratigraphic thickness with average net pay of 70 ft to 120 ft, and gre ater volumes of produced water in the range of 5 to 500 bbls/day/well 156 ( Exhibit 1 1 ).

The gas content of the Antrim Shale ranges between 40 scf/ton and 100 scf/ton ( Exhibit 11 ). The original gas

- in

- place for the Antrim is estimated at 76 t cf with technically recoverable res ources estimated a t 20 t cf ( Exhibit 11 ). W ell spacing rang es from 40 acres to 160 acres per well

.



### E XHIBIT 

### 2 2 : S TRATIGRAPHY OF THE



### A NTRIM 

### S HALE

Period Formation
Quaternary Pleistocene Glacial Drift

Jurassic Middle Ionia Formation

Pennsylvanian Late Grand River Formation

Early Saginaw Formation

Parma Formation

Mississippian Late Bayport Limestone Michigan Formation

Early Marshall Sandstone

Coldwater Shale Sunbury Shale

Devonian Late Ellsworth Shale Berea Sandstone

Bedford Shale
Upper Member

Antrim Shale Lachine Member Paxton Member Norwood Member Squaw Bay Limestone

Source: Catacosinos et al

, 2000 157 

### E XHIBIT 

### 23 : A NTRIM 

### S HALE IN THE 

### M ICHIGAN 

### B ASIN

Source: ALL Consulting, 2009MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

24 The New Albany Shale The New Albany Shale is located in the Illinois Basin in portions of southeastern Illinois, southwestern Indiana, and northwestern Kentucky 159 ( Exhibit
25 160 ). Similar to the Antrim Shale, the New Albany

occur s at depths between 500 ft and 2,000 ft ( Exhibit
1 1 ) and is a shallower, water

- filled shale with a more
CBNG

- like character than the other gas shales
discussed in this section. The New Albany formation
is a Devonian

- to Mississippian

- age shale bound ed by limestone above (Rockford Limestone) and below (No rth Vernon Limestone) ( Exhibit 24 ).

The New Albany Shale is one of the large st shale gas plays

, encompassing an area of approximately 43,500 square miles with approximately 80

- acre spacing between wells ( Exhibit 11 ). Similar to the Antrim Shale, the New Albany play has a thinner average net pay thickness of 50 ft to 100 ft and has wells which average 5 to 500 bbls of water per day 161 ( Exhibit
11 ). The measured gas content of the New Albany Shale ranges from 40 scf/ton to 80 scf/ton. The original gas

- in

- pl ace for the New Albany formation is
estimated at 160 t cf with technically recoverable

resources estimated at less than 20 t cf ( Exhibit 11 ). 

### E XHIBIT 

### 2 4 : S TRATIGRAPHY OF THE 

### N EW 

### A LBANY 

### S HALE

Period Formation Pennsylvanian Miss ouria n Mattoon

Bond Patoka Desmoinesi
an Shelburn

Dugger Petersburg Linton Staunton Atokan Brazil
Morrow a n Mansfield

Mississippian Chesterian Tobinsport

Branchville Tar Springs Glen Dean Limestone Hardinsburg Haney Limestone Big Clifty Beech Creek Limestone Cypress Elwren Reelsville Limestone Sample Beaver Bend Limestone Bethel Paoli Limestone Ste. Genevieve Ls. Valmeyeran St. Louis Limestone Salem Limestone Harrodsburg Limestone Muldraugh Ramp Creek Edwardsville Spickert Knob

New Providence Sh.

Rockford Ls Coldwater

Sh. Kinderhooki

an

New Albany

Shale Sunbury Sh.

Ellsworth Sh. Devonian Sen ecan Chautauq uan

Antrim Sh. Erian North Vernon

Ls. Transverse

Jeffersonville Ls. Detroit River

Source : Indiana Geological Survey , 1986 158 

### E XHIBIT 

### 25 : N EW 

### A LBANY 

### S HALE IN THE 

### I LLINOIS 

### B ASIN

Source: ALL Consulting, 2009MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

25 By statute, states may adopt their
own standards

; however, these must
be at least as protective as the federal standards they replace , and may even be more p rotective in order to
address local conditions. 

## REGULATORY FRAMEWORK

The development and production of oil and gas in the U.S. , including shale gas, are regulated under a complex set of federal , state, and local laws that address every aspect of exploration and operation. All of the laws, regulations, and permits that apply to conventional oil and gas exploration and production activities also apply to shale gas development. The U.S. Environme ntal Protection Agency (EPA) administers most of the federal laws, although development on federally owned land is managed primarily by the Bureau of Land Management (BLM), which is part of the Department of the Interior

, and the U.S. Forest Service , which is part of the Department of Agriculture. In addition, each state in which oil and gas is produced has one or more regulatory agencies that permit wells, including their design, location, spacing, operation, and abandonment,
as well as environmental acti vities and discharges, including water management and disposal, waste management and disposal, air emissions, underground injection, wildlife impacts, surface disturbance, and worker health and safety. Many of the federal laws are implemented by the state s under agreements and plans approved by the appropriate federal agencies. Those laws and their delegation are discussed below.



### Federal Environmental Laws Governing Shale Gas Development
A series of federal laws govern s most environmental aspects of shale gas development. For example, the Clean Water Act (CWA) regulates surface discharges of water associated with shale gas drilling and production, as well as storm water runoff from production sites. The Safe Drinking
Water Act (SDWA) regulates the underg round injection of fluids from shale gas activities. The
Clean Air Act (CAA) limits air emissions from engines, gas processing equipment, and other sources associated with drilling and production. The National Environmental Policy Act (NEPA) requires
tha t exploration and production on federal lands be thoroughly analyzed for environmental impacts.

However, federal agencies do not have the resources to administer all of these environmental programs for all the oil and gas sites around the country. Also, as explained below, one set of
nation

- wide regu lation s may not always be the most effective way of assuring the desired level of environmental protection. Therefore, most of these f ederal laws have provisions for g ranting “primacy” to the states ( i.e., state agencies implement the programs with federal oversight ) . By statute, states may adopt their own standards ; however, these must be at least as protective as the federal standards they replace , and may even be more protective in order to address local conditions. Once these state programs are approved by the relevant federal agency (usually
the EPA ), the state then has primacy jurisdiction.



### State Regulation
State regulation of the environmental practices related to shale gas development, usually with federal oversight, can more e ffectively add ress the regional and state

- specific character of the activities, compared to one

- size

- fits

- all regulation at the federal level 162 . Some of these specific factors include: geology, hydrology, climate, topography, industry characteristics, development
histo ry, state legal structures, population density, and local economics. The state agencies thatMODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

26 The states have broad powers to regulate, permit, and enforce all
activities

— the drilling and fractur e of the well, production operations,

manag ement and dispos al of wastes,
and aba ndon ment and plugging of
the we l l

. permit these practices and monitor and enforce their laws and regulations may be located in the state Department of Natural Resources (such as in Ohio) or in the Department of Environmental Protection (such as in Pennsylvania). The Texas Railroad Commission regulates oil and gas activity in the nation’s large st oil and gas producing state, home to the Barnett Shale. The names and organizational structures vary, b ut the functions are very similar. Often, multiple agencies are involved, having jurisdiction over different activities and aspects of development.

These state agencies do not only implement and enforce federal laws; they also have their own sets
of state laws to administer. These state laws often add additional levels of environmental protection and requirements. Also, several states have their own versions of the federal NEPA law, requiring environmental assessments and reviews at the state level and e xtending those reviews beyond federal lands to state and private lands.

States have many tools at their disposal to assure that shale gas operations do not adversely impact the environment. The regulation of shale gas drilling and production is a cradle

- to

- grave approach. The states have broad powers to regulate, permit, and enforce all activities

— the drilling and fractur e of the well, production operations, manag ement and dispos al of wastes,
and abandon ment and plugging of the well

. Different states take different approaches to this regu lation and enforcement, but state laws generally give the state oil and gas director or agency the discretion to require whatever is necessary to protect human health and the environment a . In addition to the general protection regulations , most states hav e a general prohibition against pollution from oil and gas drilling and production b

. Most of the state requirements are written into rules or regulations, while some are added to permits on a case

- by

- case basis as a result of environmental review, on

- the

- ground inspections, public comments, or commission hearings.

All s tates require a permit before an operator can drill and operate a gas well. The application for this permit includes all the information about a well ’s location, construction, operation an d
reclamation. Agency staff review s the application for compliance with regulations and to assure adequate environmental safeguards. If necessary, a site inspection will be made before permit approval. Also, most states require operators to post a bond or other financial security when getting a drilling permit to e nsure compliance with state regulations and to make sure that there are funds to properly plug the well once production ceases. Another safeguard is that producers

a An example of this type of provision is the following from Pennsylvania’s statute: “[T]he department shall have the authority to issue such orders as are necessary to aid in the enforcement of the provisions of [the oil and gas] act

. ” (58 P.S. section 601.503.).

b An example of such language can be found in New York’s rules, which state: “Th e drilling, casing and completion program adopted for any well shall be such as to prevent pollution. Pollution of the land and/or of surface or ground fresh water re sulting from exploration or drilling is prohibited.” ( 6 NYCRR Part 554). Another exampl e is the requirement in the rules of the Texas Railroad Commission: “No person conducting activities subject to regulation by the commission may cause or allow pollution o f surface or subsurface water in the state.” (TAC 16.1.3.8).MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

27 generally must notify the state agencies of any significant new activity through a “sundry notice” or a new permit application so that the agency is aware of that activity and can review it c

.
States have implemented voluntary review processes to help ensure that the state programs are as effective as possible. The Ground Water Protection Council (GWPC) has a program to review state implementation of the Underground Injection Control (UIC) pr ogram. In addition to the GWPC UIC review, s tate oil and gas environmental programs other than UIC programs can also be periodically reviewed against a set of guidelines developed by an independent body of state, industry, and environmental stakeholders, known as STRONGER (State Review of Oil and Natural Gas Environmental Regulation , Inc.) 163 . Periodic evaluations of state exploration and production waste management programs have proven useful in improving the effectiveness of those programs and increasing cooperation between federal and state regulatory agencies. To date, 18 states have been reviewed under the state review guidelines , and s everal have been reviewed more than once. The STRONGER program has documented the effectiveness of and improvements i n these state oil and gas environmental programs 164

, 165

. The Interstate Oil and Gas Compact Commission (IOGCC) also completed state reviews using earlier versions of the guidelines prior to the formation of
STRONGER.

The organization of regulatory agencies wi thin the various oil and gas producing states varies considerably. Some states have several agencies that may oversee some facet of oil and gas operations, especially environmental requirements. These agencies may be in various d epartments

or d ivisions w ithin the s tates’ organization s . These various approaches have developed over time within each state, and each state tries to create a structure that best serves its citizenry and all of
the industries that it must oversee. The one constant is that each oil and gas producing state has one agency with primary responsibility for permitting wells and overseeing general operations. While this agency may work with other agencies in the regulatory process, they can serve as a good
source of information about t he various agencies that may have jurisdiction over oil and gas
activities. Exhibit 26 provides a list of the agencies with primary responsibility for oil and gas regulation in each of the sta tes that have or are likely to have shale gas production.



### Local Regulation
In addition to state and federal requirements, additional requirements regarding oil and gas operations may be imposed by other levels of gov ernment in specific locations. Enti ties such as cities, counties, t ribe s, and regional water authorities may each set operational requirements that affect the location and operation of wells or require permits and approvals in addition to those at
the f ed eral or s tate level.

c See, for example, Louisiana Statewide Order 29

- B, section 105, or Texas Administrative Code 16.1.3.5.MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

28 

### E XHIBIT 

### 2 6 : O IL AND 

### G AS 

### R EGULATORY 

### A GENCIES IN 

### S HALE GAS 

### S TATES

State Agency Web Address

Alabama Geological Survey of Alabama, State Oil and

Gas Board http://www.ogb.state.al.us/ogb/ogb.html

Arkansas Arkansas Oil and Gas Commission http://www.aogc.state.ar.us/

Colorado Colorado Department of Natural Resources,

Oil and Gas Conservation Commission http://cogcc.state.co.us/

Illinois Illinois Department of Natural Resources,

Division of Oil and Gas http://dnr.state.il.us/mines/dog/index.htm

Indiana Indiana Department of Natural Resources,

Division of Oil and Gas http://www.in.gov/dnr/dnroil/

Kentucky Kentucky Department for Energy

Development and Independence, Division of Oil and Gas Conservation http://www.dogc.ky.gov/

Louisiana Louisiana Department of Natural Resources,

Office of Conservation http://dnr.louisiana.gov/cons/conserv.ssi

Michigan Michigan Department of Environmental

Quality, Office of Geological Survey http://www.michigan.gov/deq/0,1607,7

- 135

- 3306_28607

--- ,00.html

Mississippi Mississippi State Oil and Gas Board http://www.ogb.state.ms.us/

Montana Montana Department of Natural Resources

and Conservation, Board of Oil and Gas http://bogc.dnrc.mt.gov/default.asp

New Mexico New Mexico Energy, Minerals and Natural

Resources Department, Oil Conservation Division http://www.emnrd.state.nm.us/OCD/

New York New York Department of Environmental

Conservation, Division of Mineral Resources http://www.dec.ny.gov/energy/205.html

North Dakota North Dakota Industrial Commission,

Department of Mineral Resources Oil and Gas
Division https:// www.dmr.nd.gov/oilgas/

Ohio Ohio Department of Natural Resources,

Division of Mineral Resources Management http://www.ohiodnr.com/mineral/default/tabid /10352/Default.aspx

Oklahoma Oklahoma Corporation Commission, Oil and

Gas Conservation Division http://www.occ.state.ok.us/Divisions/OG/neww eb/og.htm

Pennsylvania Pennsylvania Department of Environmental

Protection, Bureau of Oil and Gas Management http://www.dep.state.pa.us/dep/DEPUTATE/MI NRES/OILGAS/oilgas.htm

Tennessee Tennessee Department of Environment and

Conservation, St ate Oil and Gas Board http://www.tennessee.gov/environment/boards /oilandgas.shtml

Texas The Railroad Commission of Texas http://www.rrc.state.tx.us/index.html

West Virginia West Virginia Department of Environmental

Protection, Office of Oil and Gas http://www.wvdep.org/item.cfm?ssid=23MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

29 When operations occur in or near populated areas, local governments may establish ordinances to protect the environment and the general welfare of its citizens. These local ordinances frequently require additional permits for issues such as well placement in flood zones, noise level, set backs from residences or other protected sites, site house

- keeping, and traffic. For example, ordinances may set limits on noise levels that may be generated during both daytime and nighttime operations 166

, 167

, 168

, 169

.
In some cases, regional water

- permitting authorities that have jurisdiction in multiple states have also been established. These federally established authorities have been created to protect the water quality of the entire river basin and to govern uses of the water 170 . Additional approvals and permits may be required for operations in these river basins. For example, the Delaware River
Basin Commission (DRBC) covers parts of New York, Pennsylvania, New Jersey and Delaware 171

. Natural gas operators wishing to withdraw water for consumptive use in this basin must first receive a permit from the DRBC , which has the legal authority to fine violators of the ir rules and regulations.

The variety of laws governing shale gas exploration and production, and the mu ltitude of federal and state agencies that implement them, can sometimes be confusing. Therefore, the following discussion has been organized according to the various environmental media that are affected by these activities, i.e., water, air, and land. The major laws and programs affecting each of these are discussed below. Additional considerations on federal land and unique state requirements are also covered, along with some of the programs that cut across these environmental media.



### Regulation of Imp acts on Water Quality
Potential impacts to water quality are primarily regulated under several federal statutes and the accompanying state programs. The primary federal statutes governing water quality issues related to shale gas development are the Clean Water Act, the Safe Drinking Water Act, and the Oil Pollution
Act. These statutes and their relationship s to shale gas development are discussed below.

Clean Water Act The Clean Water Act (CWA) is the primary federal law in the U.S. governing pollution o f surface water. It was established to protect water quality, and includes regulation of pollutant limits on the discharge of oil

- and gas

- related produced water

. This is conducted through the National Pollut ant Discharge Elimination System (NPDES) pe rmi tting process. Although EPA sets national standards at the federal level, states and tribal governments can acquire primacy for t he NPDES program by meeting EPA’s primacy requirements.

The CWA establishes the basic structure for regulating discharges of pollutants into the waters of
the U.S. and quality standards for surface waters. The basis of the CWA was enacted in 1948 and was called the Federal Water Pollution Control Act; the Act was significant ly reorganized and expanded in 1972. "Clean Water Act " became its common name , with additional amendments
made in 1977 and later

.

Under the CWA, EPA has implemented pollution control programs such as setting wastewater standards for industry. They have also set water quality standards for a variety of contaminants in surface waters.MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

30 The CWA made it unlawful to discharge any pollutant from a point source into the navigable waters
of the U.S. , unless done in accordance with a specific approved permit. The NPDES permit program controls discharges from po int sources that are discrete conveyances

, such as pipes or man

- made ditches. Industrial, municipal, and other facilities such as shale gas production sites or commercial facilities that handle the disposal or treatment of shale gas produced water must ob tain permits if they intend to discharge directly into surface waters 172

, 173

. Large facilities usually have individual NPDES permits. Discharges from some small er facilities may be eligible for inclusion under general permits that authorize a category of dis charges under the CWA within a geographical area. A general permit is not specifically tailored for an individual discharger. Most oil and gas production facilities with related discharges are authorized under general permits because there are typically numerous sites with common discharges in a geographic area.

A state that meets the federal primacy requirements is allowed to set more stringent state

- specific standards for this program. Since individual states can acquire primacy over their respective programs, it is not uncommon to have varying requirements from state to state. This variation can affect how the oil and gas industry manages produced water within a drainage basin located within two or more states, such as the Marcellus shale in the Appa lachian Basin. Effluent limitations serve as the primary mechanism under NPDES permits for controlling discharges of pollutants to receiving waters. Wh en developing effluent limitations for an NPDES permit, a permit writer must consider limits based on both the technology available to control the pollutants (i.e., technology

based effluent standards) and the regulations that protect the water quality sta ndards of the receiving water (i.e., water quality

- based effluent standards).

The intent of technology

- based effluent limits in NPDES permits is to require treatment of effluent concentrations to less than a maximum allowable standard for point source disc harges to the specific surface water body. This is based on available treatment technologies, while allowing the discharger to use any available control technique to meet the limits. For industrial (and other non

municipal) facilities, technology

- based e ff luent limits are derived by : 1) u sing national effluent limitations guidelines and standards established by EPA

, or 2) u sing best professional judgment (BPJ) on a case

- by

- case basis in the absence of national guidelines and standards.

Prior to the granting of a permit, the authorizing agency must consider the potential impact of every proposed surface water discharge on the quality of the receiving water, not just individual discharge s

. If the authorizing agency determines that technology

- based eff luent limits are not sufficient to ensure that water quality standards will be attained in the receiving water, the CWA [ Section 303(b )(1)(c)] and NPDES regulations [40 C ode of Federal Regulations (C FR ) 122.44(d)] require that more stringent limits are imp osed as part of the permit 174

.

EPA establishes e ffluent limitation guidelines (ELGs) and standards for different non

- municipal (i.e., industrial) categories. These guidelines are developed based on the degree of pollutant reduction attainable by an industri al category through the application of pollution control technologies.MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

31 The CWA requires EPA to develop specific effluent guidelines that represent the following:

1. Best conventional technology (BCT) for control of conventional pollutants and applicable to

e xisting dischargers.

2. Best practicable technology (BPT) currently available for control of conventional, toxic and nonconventional pollutants and applicable to existing dischargers.

3. Best available technology (BAT) economically achievable for control of toxi c and nonconventional pollutants and applicable to existing dischargers.

4. New source performance standards (NSPS) for conventional pollutants and applicable to

new sources.
To date, EPA has established guidelines and standards for more than 50 different industrial categories 175

.
The ELGs for Oil and Gas Extraction, which were published in 1979, can be found at 40 CFR Part 435. The onshore subcategory, Subpart C, is applicable to discharge s associated with shale gas development and production 176

.
The CWA also includes a program to control storm water discharges. The 1987 Water Quality Act (WQA) added Section 402(p) to the CWA requiring EPA to develop and implement a storm water permitting pr ogram. EPA developed this program in two phases (Phase I: 1990; Phase II: 1999). Those regulations establish NPDES permit requirements for municipal, industrial, and construction site storm water runoff. The WQA also added Section 402(l)(2) to the CWA specifying that the EPA and states shall not require NPDES permits for uncontaminated storm water discharges from oil and gas exploration, production, processing or treatment operations, or transmission facilities. This exemption applies where the runoff is not contaminated by contact with raw materials or

wastes. EPA had previously interpreted the 402(l)(2) exemption as not applying to construction activities of oil and gas development, such as building roads and pads (i.e., an NPDES permit was require d) 177

.
The Energy Policy Act of 2005 modified the CWA Section 402(l)(2) exemption by defining the excluded oil and gas sector operations to include all oil and gas field activities and operations, including those necessary to prepare a site for drilling and for the movement and placement of drilling equipment. EPA promulgated a rule that implemented this exemption. However, on May 23, 2008, the U.S. Court of Appeals for the Ninth Circuit released a decision vacating the permitting exemption for discharges of sediment from oil and gas construction activities that contribute to
violations of the CWA 178 . The court based its decision on the fact that the new rule exempted runoff contaminated with sediment, while the CWA does not exempt such runoff. As a result of the court's decision, storm water discharges contaminated with sediment resulting in a water quality violation require permit coverage under the NPDES storm water permitting program.

While the EPA storm water permitting rule contains a broad exclusion f or oil and gas sector construction activities, it is important to note that individual states and Indian t ribes may still regulate storm water associated with these activities. EPA has clarified its position that states and

t ribe s may not regulate such st orm water discharges under their CWA authority, but are free to regulate under their own independent authorities. EPA states that “ [ t ] his final rule is not intendedMODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

32 to interfere with the ability of s tates, t ribes, or local governments to regulate any disc harges through a non

- NPDES permit program” 179 . In addition to state and tribal regulation, the industry has a voluntary program of Reasonable and Prudent Practices for Stabilization (RAPPS) of oil and gas construction sites 180 . Producers use RAPPS in order to control erosion and sedimentation associated with storm water runoff from areas disturbed by clearing, grading, and excavating activities related to site preparation.

Safe Drinking Water Act Congress originally passed t he Safe Drinking W ater Act (SDWA) in 1974 to protect public health by regulating the nation's public drinking water supply. The law was amended in 1986 and 1996 and requires many actions to protect drinking water and its sources

, including rivers, lakes, reservoirs, spring s, and ground water wells. SDWA authorizes the U

. S

. EPA to set national health

- based standards for drinking water to protect against both naturally occurring and man

- made contaminants that may be found in drinking water. EPA , states, and municipal water system agencies then work together to make sure that these standards are met 181

.
As one aspect of the protection of drinking water supplies, the SDWA establishes a framework for the Underground Injection Control (UIC) program to prevent the injection of liqu id wastes into underground sources of drinking water (USDWs). The EPA and states implement the UIC program, which sets standards for safe waste injection practices and bans certain types of injection altogether. The UIC Program provides these safeguards so that injection wells do not endanger
USDWs. The first f

ederal UIC regulations were issued in 1980.

EPA currently groups underground injection wells into five classes for regulatory control purposes

, and has a sixth class under consideration

. Each clas s includes wells with similar functions, construction and operating features so that technical requirements can be applied consistently to the class.

1. Class I wells may inject hazardous and nonhazardous fluids (industrial and municipal wastes) into isolated formations beneath the lowermost USDW. Because they may inject hazardous waste, Class I wells are the most strictly regulated and are further regulated und er the Resource Conservation and Recovery Act (RCRA).

2. Class II wells may inject brines and other fluids associated with oil and gas production

.
3. Class III wells may inject fluids associated with solution mining of minerals

.
4. Class IV wells may inject hazard ous or radioactive wastes into or above a USDW and are banned unless specifically authorized under other statutes for ground water remediation.

5. Class V includes all underground injection not included in Classes I

- IV. Generally, most Class V wells inject n onhazardous fluids into or above a USDW and are on

- site disposal systems, such as floor and sink drains which discharge to dry wells, septic systems, leach fields, and drainage wells. Injection practices or wells that are not covered by the UIC Program in clude single family septic systems and cesspools as well as non

- residential septic systems and cesspools serving fewer than 20 persons that inject ONLY sanitary waste water.

6. Class VI has been proposed specifically for the injection of CO 2 for the purpose of sequestration , but has not yet been established.MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

33 M ost injection wells associated with oil and gas production are Class II wells. These wells may be used to inject water and other fluids (e.g., liquid CO 2 ) into oil

- and gas

- bearing zones to enhance recovery, or they may be used to dispose of produced water. The regulation specifically prevents the disposal of waste fluids into USDWs by limiting injection only to formations that are not “underground sources of drinking water.” EPA 's UIC Program is designed to prevent contamination of water supplies by setting minimum requirements for state UIC Programs. The basic premise of the UIC Program is to prevent contamination of USDWs by keeping injected fluids within the intended injection zone. The injected fluids must not endanger, or have the potential to endanger, a current or future public water supply. The UIC requ irements that affect the siting , construction, operation, maintenance, monitoring, testing, and

, finally, closure of injection well s have been established to address these concepts. All injection wells require authorization under general rules or specific permits.

The law was written with the understanding that states are best suited to have primary enforcement authority (primacy) for the UIC Program. In the SDW A, Congress cautioned EPA against a “one

- size

- fits

- all” regulatory scheme, and mandated consideration of local conditions and practices. Section 1421(b)(3)(A) requires that UIC regulations permit or provide consideration of varying geological, hydrological, or historical conditions in different states and in different areas within a state. Section 1425 allows a state to obtain primacy from EPA for oil

- and gas

- related injection wells, without being required to adopt the complete set of applicable federal UIC regulations. The state
must be able to
demonstrate that its existing regulatory program is protecting USDWs as effectively
as the f ederal requirements 182

.

To date, 40 states have obtained primacy for oil and gas injection wells (Class II), although, as shown in
Exhibit 27 not all of
these states have oil and gas production.
The U.S. EPA
administers UIC programs for ten states,
seven of which are oil and g as states, and all other federal jurisdictions and Indian Lands 183 (Exhibit 27 184 ).

Oil Pollution Act of 1990

– Spill Prevention Control and Countermeasure The CWA and the Oil Pollution Act (OPA) include both regulatory and liability provisions that are desig ned to reduce damage to natural resources from oil spills. Congress added Section 311 to the 

### E XHIBIT 

### 27 : UIC C LASS 

### II P RIMACY 

### M AP

Source: EPA

, , 200 8MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

34 CWA, which in part authorized the President to issue regulations establishing procedures, methods, equipment, and other requirements to prevent discharges of oil from ve ssels and facilities [ Section 311(j)(1)(c) ] . In response to the Exxon Valdez oil spill in Alaska, Congress enacted the OPA in
1990 185

. The OPA amended CWA Section 311 and contains provisions applicable to onshore facilities and operations.

Section 311, as amended by the OPA, provides for spill prevention requirements, spill reporting obligations, and spill response planning. It regulates the prevention of and response to accidental releases of oil and hazardous substances into navigable wat ers, on adjoining shorelines, or affecting natural resources belonging to or managed by the U.S . This authority is primarily carried out through the creation and implementation of facility and response plans. These plans are intended
to establish measure s that will prevent discharge of oil into navigable waters of the U.S. or adjoining
shore

- lines as opposed to response and cleanup after a spill occurs.

A cornerstone of the strategy to prevent oil spills from reaching the nation’s waters is the oil Spill Prevention, Control and Countermeasure ( SPCC ) plan. EPA promulgated regulations to implement this part of the OPA of 1990. These regulations specify that:

1. SPCC Plans must be prepared, certified (by a professional engineer) and implemented by facilities t hat store, process, transfer, distribute, use, drill for , produce, or refine oil;

2. Facilities must establish procedures and methods and install proper equipment to prevent an oil release;

3. Facilities must train personnel to properly respond to an oil spill by conducting drills and training sessions; and,

4. Facilities must also have a plan that outlines steps to contain, clean up and mitigate any effects that an oil spill may have on waterways 186

. Before a facility is subject to the SPCC rule, it must meet three criteria:

1. It must be non

- transportation

- related;

2. It must have an aggregate aboveground storage capacity greater than 1,320 gallons (31.4 bbls ) or a completely buried storage capacity greater than 42,000 gallons (1,000 b bls ); and

3. There must be a reasonab le expectation of a discharge into or upon navigable waters of the
U.S. or adjoining shorelines.

An SPCC Plan is a site

- specific document that describes the measures the facility owner has taken to prevent oil spills, and what measure s are in place

, if nee ded, to contain and clean spills. It includes information about the facility, the oil storage containment, inspections, and a site diagram with locations of tanks (above and below ground) and drainage, and other pertinent details. Prevention
measures inc lude secondary containment around tanks and certain oil

- containing equipment.

The SPCC program is not as applicable to shale gas operations as it is to oil production sites. Shale gas operators may have to prepare plans if they store large amounts of fuel (exceeding the volumes stated above) on site, or if oil

- filled equipment is present, and there is a risk of that oil impacting
waters of the U.S.MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

35 In October 2007, EPA proposed amendments to the SPCC rule intended to increase clarity and t ailor certain requirements to ensure increased compliance. Among other things, these amendments would streamline some requirements by allowing the use of a plan template for small er facilities, extending some deadlines for plan preparation, and exempting some vessels and flow lines from secondary containment requirements. They would also add spill prevention requirements for some oil and gas facilities. These proposed rules have not yet been made final 187

.
State Regulations and Regional Cooperation

In add ition to implementing f ederal statutes for the NPDES, UIC, and storm water programs, states and t ribe s may impose their own requirements to protect their water resources, both surface and underground. For example, they establish water quality standards fo r some or all of their surface water. These standards are approved by EPA and become the baseline for CWA permits 188

.
In addition, some areas have established regional water authorities that regulate water withdrawals and discharges within a river basin. For example, the Susquehanna River Basin
Commission (SRBC) 189 and the DRBC 190 in New York and Pennsylvania require that entities seeking to withdraw water from their river systems first obtain permits. These commissions have authority separate from the states . They have recently directed their attention to the water requirements for drilling and hydraulically fracturing Marcellus Shale gas wells and are updating their requirements
for both water withd rawals and discharge of the water after use . Other river b asin commissions are more advisory in nature, providing water flow and quality information and coordinating river conservation efforts by state agencies and others.

State agencies are the principal organizations for enforcing water quality regulations. Th ey have inspectors, usually located at regional offices throughout the state
, who visit oil and gas well sites to ensure compliance with regulations. When a violation occurs, state enforcement and legal personnel develop the case and order compliance, in many cases also imposing penalties against the violator. Penalties can range from fines to revocation of permits, and even to criminal sanctions in severe cases. Such penalties are usually imposed only after hearings before a board of
commissioners or ot her state body. In addition to fines and penalties, companies that pollute surface or ground water must clean up or remediate the contamination they caused.



### Regulation of Impacts on Air Quality
Air quality impacts are regulated under the Clean Air Act (CA A). As described below, the Act sets national standards for emissions of certain pollutants and requires permits for some industrial operations. Green h ouse Gases are not regulated as such, and are not, therefore, discussed in this
section.

Clean Air Act The CAA is the primary means by which EPA regulates potential emissions that could affect air quality. The U.S. Congress passed the CAA in 1963

, and they have amended it on several occasions since, most recently in 1990 191 . The CAA requires EPA to set nati onal standards to limit levels of certain pollutants. EPA regulates those pollutants by developing human health

- based and/or environmentally and scientifically based criteria for setting permissible levels. Air regulations do not normally include excepti ons for a company’s size, the age of a field, or the type of operation. Typically, the air rules are silent on issues such as conventional v ersus unconventional plays, oldMODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

36 v ersus new fields, and the depth of a well. For the most part, the air emissions, applicable regulations, and associated emissions controls for a shale play are no different than those for any other natural gas operation. There may be differences due to location (some areas of the country have better air quality than others), equipment needs (some shale plays may produce a wetter gas than others), and sulfur content level of the gas

.
Geographic areas that do not meet EPA ’s standards for a given pollutant are designated as

“ nonattainment areas ” 192 . This is the case for the Barnett Shale play, much of which is located in or
near the Dallas

- Fort Worth ozone nonattainment area. As a result, Barnett Shale production activities must often comply with much more stringent regulations than similar operations proposed outside of a nonattainment a rea. As a result of the implementation of the CAA, air quality has improved dramatically across the U.S. during the last few decades and existing regulations should continue to reduce air pollution emissions during the next twenty years or longer 193

.

Air Quality Regulations Like any other U.S. industry, shale gas producers must comply with existing and new air regulations including those resulting from the 1990 CAA Amendments. These rules pose an ongoing challenge to company resources as producers strive to understand and comply with enforcement, fines, public reaction, and possibly even pro ject cancellations in light of new standards.

EPA has established National Emission Standards for Hazardous Air Pollutants (NESHAPs), which are nationally uniform stan dards to control specif ic air emissions. In 2007, EPA implemented a

new standard referred to as the Maximum Achievable Control Technology (MACT) standard for hazardous air pollutants (HAP) that targeted small area sources such as shale gas operations
located in areas near large r populations. These standards limit HAP emissions (primarily benzene) from process vents on glycol dehydration units, storage vessels with flash emissions, and equipment leaks.

Another example of new or amended federal regulations that will have a direct impact on controlling emissions from shale gas operations is the Stationary Spark Ignition Internal Combustion Engine new source performance standard 194 and Reciprocating Internal Combust ion Engine NESHAP 195 rules

, which regulate new and refurbished engines. These rules , passed in 2007, target all internal combustion engines regardless of horsepower rating, location, or fuel (electric engines are not included) and include extensive maintena nce, testing, monitoring, recordkeeping, and reporting requirements 196

.

EPA is not large enough to regulate every air emissions source nationwide, let alone consider the local and regional differences. Therefore, they typically delegate that role to local, state, and tribal agencies. This delegation of authority can include rule implementation, permitting, reporting, and compliance. Any state given such delegation of authority can pass more restrictive rules, but they are prohibited from passing a rule th at is less stringent than its federal counterpart.

Air Permits Air permits are legal documents that facility owners and operators must abide by. The permit specifies what construction is allowed, what emission limits must be met, how the emissions source(s) must be operated, and what conditions

— specify ing monitoring, record keeping, andMODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

37 In 1988, EPA issued a final regulatory determination stating that control of oil and gas exploration and production
wastes under RCRA Subtitle C
was not warranted. reporting requirements

— must be maintained to assure ongoing compliance. Shale gas producers may need air quality permits for a number of emissions sources, including gas compressor engines, glycol dehydrators, and flares.

A company’s permitting responsibility does not end with the issuance of their initial air permit. They must be constantly vigilant that a new regulation, modification, replacement, or process change does not impact their existing permit and require a permit amendmen t or a more stringent permit. Although these permits may differ across the country, they all contain specific conditions designed to ensure state and federal standards are met and to prevent any significant degradation in air quality as a result of a prop osed activity.



### Regulation of Impacts to Land
Impacts to land from shale gas operations include solid waste disposal and surface disturbances that may impact the visual landscape or may affect wildlife habitat . Operations on federal lands are a special ca se with unique requirements that are discussed below.

Resource Conservation and Recovery Act (RCRA) RCRA was passed in 1976 to address the growing problems of the increasing volume of municipal and industrial waste. RCRA established goals for protecting h uman health and the environment, conserving resources, and reducing the amount of waste. RCRA Subtitle C established a federal program to manage hazardous wastes from cradle to grave to ensure that hazardous waste is handled in a manner that protects huma n health and the environment. Subtitle D of the RCRA addresses non

- hazardous solid wastes, including certain hazardous wastes which are exempted from the Subtitle C regulations 197

.

In 1978, EPA proposed hazardous waste management standards that included re duced requirements for some industries, including oil and gas, with large volumes of wastes. EPA determined that these large volume “special wastes” were lower in toxicity than other wastes being regulated as hazardous waste under the RCRA 198

.

In 1980, the Solid Waste Disposal Act (SWDA) amended RCRA to exempt drilling fluids, produced waters, and other wastes associated with exploration, development, and production of crude oil, natural gas and geothermal energy 199 . The SWDA Amendments also required EPA to provide a report to Congress on these wastes and to make a r egulatory d etermination as to whether regulation of these wastes under RCRA Subtitle C was warranted 200

.

In 1987, EPA issued a Report to Congress that outlined the results of a study on the manag ement, volume, and toxicity of wastes generated by the oil, natural gas and geothermal industries. In 1988, EPA issued a final regulatory determination stating that control of oil and gas exploration and production wastes under RCRA
Su btitle C was not war ranted. EPA made this
determination because it found that other state and federal programs could protect human health and theMODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

38 environment more effectively. In lieu of regulation under Subtitle C, EPA implemented a three

pronged strategy to ensure that th e environmental and programmatic issues were addressed:

1. Improve other f ederal programs under existing authorities ;

2. Work with states to improve some programs ; and

3. Work with Congress to develop any additional statutory authorities that may be required 201

.

The se wastes have remained exempt from Subtitle C regulations, but this does not preclude these wastes from control under state regulations or other federal regulations 202 . The exemption applies only to the federal requirements of RCRA Subtitle C. A waste tha t is exempt from Subtitle C regulation might be subject to more stringent or broader state hazardous and non

- hazardous waste regulations and other state and federal program regulations. For example, oil and gas exploration and production wastes may be sub ject to regulation under RCRA Subtitle D, the Clean Air Act, the Clean Water Act, the Safe Drinking Water Act, and /or the Oil Pollution Act of 1990 203

, 204

.

In 1989, EPA worked with the I nterstate Oil and Gas C ompact Commission (I OGCC ) , state regulatory officials, industry representatives, and nationally recognized environmental groups to establish a Council on Regulatory Needs. The purpose of the council was to review existing state oil and gas exploration and production waste managem ent programs and to develop guidelines to describe the elements necessary for an effective state program. This effort was begun by EPA as part of the second prong of the agency’s approach. These groups then worked together with state regulatory agencies to review the state programs, on a voluntary basis, against these guidelines and to make recommendations for improvement. This state review program continues today under the guidance of a non

- profit organization called STRONGER. The s tate programs revie wed to da te represent over 90% of the on shore domestic production 205

.
Working with the IOGCC, STRONGER has continued to update the guidelines consistent with developing environmental and oilfield technologies and practices. Under the s tate review process, state programs have continued to improve, and follow

- up reviews have shown significant improvement where states have successfully implemented the recommendations of the review
committees.

Endangered Species Act The Endangered Species Act (ESA) of 1973 (Pub . L. 93

- 205) protects plants and animals that are listed by the federal government as "endangered" or "threatened" 206 . Sections 7 and 9 are central to regulating oil and gas activities. Section 9 makes it unlawful for anyone to "take" a listed animal,
and this includes significant ly modifying its habitat 207

. This applies to private parties and private land; a landowner is not allowed to harm an endangered animal or its habitat on his or her property.

Section 7 applies not to private parties, but to federal agencies. This s ection covers not only f ederal
activ ities but also the issuance of f ederal permits for private activities, such as Section 404 permits issued by the Corps of Engineers

, to people who want to do construction work in waters or
wetlands 208

. Se ction 7 imposes an affirmative duty on federal agencies to ensure that their actions (including permitting) are not likely to jeopardize the continued existence of a listed species (plantMODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

39 or animal) or result in the destruction or modification of critical habitat. Both Sections 7 and 9 allow “incidental takes” of threatened or endangered species, but only with a permit.

To "take" is to harass, harm, pursue, hunt, shoot, wound, kill

, trap, capture, or collect a plant or
animal of any threatened or endangered species. Harm includes significant habitat modification
whe n it kills or injures a member of a listed species through impairment of essential behavior (e.g., nesting or reproduction).

For any non

- federal industrial activity, the burden is on the owner and/or operator to de termine if an incidental take permit is needed. This is typically accomplished by contacting the U.S. Fish and Wildlife Service (FWS) to determine whether any listed species are present or will potentially
i n habit the project site. A biological survey may be required to determine whether protected species are present on the site and whether a Section 9 permit may be required 209

, 210 . The FWS as well as many state fish and game agencies offer services to help ope rators determine whether a given project is likely to result in a take and whether a permit is required. FWS can also provide technical assistance to help design a project so as to avoid impacts. For example, the project could be designed to minimize dis turbances during nesting or mating seasons 211

.

A Section 9 permit must include a habitat conservation plan (HCP) consisting of: an assessment of impacts; measures that will be undertaken to monitor, minimize and mitigate any impacts;
alternative actions con sidered and an explanation of why they were not taken; and any additional measures that the FWS may require 212

. Mitigation measures, which are actions that reduce or address potential adverse effects of a proposed activity upon species, must be designed to address the specific needs of the species involved and be manageable and enforceable. Mitigation measures

may take many forms, such as preservation (via acquisition or conservation easement) of existing habitat; enhancement or restoration of degraded or former habitat; creation of new habitats; establishment of buffer areas around existing habitats; modifications of land use practices ; and
restrictions on access 213

.
State Endangered Species Protections All fifty states have fish and game/wildlife agencies that work in cooperation with the U. S. FWS district offices with regard to the incidental take permitting process. Many states also have their own endangered and threatened species lists that may include species not on the federal lists , and
ha ve their own requirements for protecting endangered species 214

. 

### Oil and Gas Operations on Public Lands

Federal Lands The U.S. Department of Interior’s Bureau of Land Management (BLM) is responsible for permitting and managing most onshore oil and gas activities on federal lands. The BLM carries out its responsibility to protect the environment throughout the process of oil and gas resource exploration and development on public lands. Resource protection is considered throughout the land use planning process

— when Resource Management Plans (RMPs) are prepared and when an Application for Permit to Drill (APD) is processed 215

. The BLM’s inspection and enforcement and monitoring program is designed to ensure that operators comply with relevant laws and regulations as well as specific stipulations set forth during the permitting process.MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

40 Since most shale gas activity in the nea r future is expected to occur in the eastern U.S. basins, it is not likely that much of this development will occur on federal lands. While there are some federal lands, such as National Parks, National Forests, and military installations, these are much less extensive in the east than in the west. Where shale gas operations do occur on federal lands, BLM has a well established program for managing these activities to protect human health and the
environment.

State Lands

The amount of state

- owned land var ies considerably from state to state and each state manages these lands differently. In most states, leasing of state

- owned minerals occurs through lease auctions. Since states are already set up to manage oil and gas operations within their borders, no special permitting or enforcement systems are required. Some states do have Environmental Policy Acts that require a review of environmental impacts that may result from leasing or operations on state lands or of any state action that may affect the envir onment.


### Other Federal Laws and Requirements that Protect the Environment

Comprehensive Environmental Response, Compensation, and Liability Act The Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), commonly known as Superfund, was enacted by Congress on December 11, 1980. This law created a tax on the chemical and petroleum industries and provided broad federal authority to respond directly to releases or threatened releases of hazardous substances that may endanger public
heal th or the environment. CERCLA established prohibitions and requirements concerning closed
and abandoned hazardous waste sites, provided for liability of persons responsible for releases of hazardous waste at these sites, and established a trust fund to pr ovide for cleanup when no responsible party could be identified. Over five years, $1.6 billion was collected and placed in a trust fund for cleaning up abandoned or uncontrolled hazardous waste sites.

CERCLA was amended by the Superfund Amendments and Re authorization Act (SARA) in 1986. SARA made several changes to the Superfund program that augmented its effectiveness, provided new enforcement authorities, boosted state and citizen involvement, and increased the size of the
trust fund.

In addition to th e provisions for cleaning up hazardous waste sites, CERCLA requires the person in charge of a vessel or facility to immediately notify the National Response Center when there is a release of a hazardous substance in an amount equal to or greater than the r eportable qu antity (RQ) for that substance [CERCLA Section 103(a)] . The reportable quantit y depend s on the
substance released.

CERCLA Section 101(14) excludes certain substances from the definition of hazardous substance, thus exempting them from CERCLA r egulation. These substances include petroleum, meaning crude oil or any fraction thereof that is not specifically listed as a hazardous substance , n atural gas, natural gas liquids, liquefied natural gas, and synthetic gas usable for fuel

. If a release of one of these substances occurs, CERCLA notification is not required. Thus, CERCLA reporting will only apply to shale gas production and processing sites if hazardous substances other than crude oil or natural gas are spilled in reportabl e quantities; such are not usually present at these sites.MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

41 However, t his particular exclusion applies only to CERCLA Section 103(a) reporting requirements ; it does not exempt a facility from the Emergency Planning and Community Right

- to

- Know Act ( EPCRA ) Section 304 reporting requirements. A release of a petroleum product containing certain substance s is potentially reportable under EPCRA Section 304 if more than an RQ of that substance
is released 216

.
Many states have separate requirements regarding hazard ous substances. Reporting of release s of
the materials exempted under CERCLA may be required under state law.

Emergency Planning and Community Right

- to

- Know Act Congress enacted EPCRA in 1986 to establish requirements for federal, state and local

governme nts, t ribe s, and industry regarding emergency planning and "community right

- to

- know" reporting on hazardous and toxic chemicals. The community right

- to

- know provisions of EPCRA are the most relevant part of the law for shale gas producers. They help incr ease the public's knowledge and access to information on chemicals at individual facilities, along with their uses and potential releases into the environment.

Under Sections 311 and 312 of EPCRA, facilities manufacturing, processing, or storing designated hazardous chemicals must make Material Safety Data Sheets (MSDSs)

, describing the properties
and health effects of these chemicals

, available to state and local officials and local fire departments.
Facilities must also provide state and local offic ials and local fire departments with inventories of
all on

- site chemicals for which MSDSs exist. Information about chemical inventories at facilities and MSDSs must be available to the public. Facilities that store over 10,000 pounds of hazardous
chemicals ar e subject to this requirement. Any hazardous chemicals above the threshold stored at shale gas production and processing sites must be reported in this manner.

Section 313 of EPCRA authorizes EPA ’s Toxics Release Inventory (TRI), which is a publicly avail able database that contains information on toxic chemical releases and waste management activities reported annually by certain industries as well as federal facilities. EPA issues a list of industries that must report releases for the database. To date, EPA has not included oil and gas extraction as an industry that must report under TRI. This is not an exemption in the law. Rather it is a decision by EPA that this industry is not a high priority for reporting under TRI. Part of the rationale for this decision is based on the fact that most of the information required under TRI is already reported by producers to state agencies that make it publicly available. Also, TRI reporting from the hundreds of thousands of oil and gas sites would overwhelm the existing EPA reporting system and make it difficult to extract meaningful data from the massive amount of information submitted 217

, 218

.
EPCRA section 304 requires reporting of releases to the environment of certain materials that are subject to this law. As noted in the section above, this requirement would apply to any releases of petroleum products that exceed reporting thresholds, even if those products are exempt from CERCLA reporting. While shale gas production facilities do not normally store the mater ials subject to EPCRA reporting, known as EPCRA "Extremely Hazardous Substances" and CERCLA hazardous substances, a limited number of chemicals used in the hydraulic fracturing process, such as hydrochloric acid, are classified as hazardous under CERCLA. These chemicals may be brought on site for a few days, at most, during fracturing or work

- over operation s

. Businesses must report

non

- permitted releases

— into the atmosphere, surface water, or groundwater

— of any listedMODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

42 A comprehensive set of federal and state laws and programs regulate all aspects of shale gas exploration and production activities. chemical above threshold amounts, kno wn as the "reportable quantity", to federal, state, and local
authorities. Therefore, while every precaution is taken to prevent chemical spills, in the event of an accidental release above the reportable quantity, a report would be made to these authorit ies by the operator.

Occupational Safety and Health Act Under the Occupational Safety and Health Act of 1970, employers are responsible for providing a safe and healthy workplace for their employees. The Occupational Safety and Health Administration (OSH A) promotes the safety and health of America's working men and women by setting and enforcing standards; providing training, outreach and education; establishing partnerships; and encouraging continual process improvement in workplace safety and health 219

.

O SHA has developed specific standards to reduce potential safety and health hazards in the oil and gas drilling, servicing and stor ag e industry 220

. States also have requirements that provide further worker and public safety protections.



### Summary

The U.S. has a long history of actively regulating the oil and gas industry including the shale gas industry. A comprehens ive set of federal and state laws and programs regulate all aspects of shale gas exploration and production activities. Under these programs, federal, state and local agencies
enforce a n array of requirements designed to protect
human health and the envir onment during drilling, production, and abandonment operations. Together, these requirements have reduced environmental risk and adverse impacts to our water, air, and land
nationwide.MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

43 Co llaborations between industry,

regulators and the public have
created inno vative environmental solutions to problems that at first
seemed insurmountable. 

## ENVIRONMENTAL CONSIDERATIONS

As described in the previo us sections, natural gas is an important part of the nation’s energy supply.
As a clean

- burning, affordable and reliable source of energy, natural gas will continue to play a significant role in th e energy supply picture for years to come. Unconventional sources of natural gas have become a major component of that future supply and shale gas is rapidly emerging as a critical part of that resource.

There exists an extensive framework of federal, state, and local requirements designed to manage virtually e very aspect of the natural gas development process. These regulatory efforts are primarily led by state agencies and include such things as ensuring conservation of gas resources, preventi on of w aste, and protecti on of the rights of both surface and miner al owners while protecting the environment 221

. As part of their environmental protection mission, state agencies are responsible for safeguarding public and private water supplies, preserving air quality, addressing safety, and ensuring that wastes from dri lling and production are properly contained and disposed of 222

.
In order to make sound decisions about future shale gas development, it is important to understand the process of drilling and producing shale gas wells (Exhibit 28) and the attendant environmental considerations. A key element in the emergence of shale gas production has been the refinement of

cost

- effective horizontal drilling and hydraulic fracturing technologies. These two processes, along with the implementation of protective BMPs , have allowed shale gas development to move into areas that previously would have been inaccessible. Accordingly, it is important to understand the technologies and practices employed by the industry and their ability to prevent or min imize the potential effects of shale gas development on human health and the environment and on the quality of life in the communities in which shale gas production is located.

Many of the human and environmental considerations associated with shale gas production are common to all oil and gas development. However, the horizontal drilling and hydraul ic f racturing that have become the standard for modern shale gas development bring with them new considerations as well as new ways to reduce impacts. As shale gas development has spread into more densely populated areas, new challenges have been encounte red and new technologies and practices have been developed to meet these challenges. In addition, collaborations between industry, regulators and the public have
created innovative environmental solutions to problems that at first seemed insurmountable.

O ne consideration associated with traditional gas development has been the surface disturbance required for access roads and well pads. As described in greater detail below, horizontal drilling provides a means to significantly reduce surface disturbance a nd a host of related concerns.MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

44 

### E XHIBIT 

### 28: P ROCESS OF 

### S HALE 

### G AS 

### D EVELOPMENT 

### (D URATION 

### )MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

45 It is important to understand that surface owners who do not own minerals rights are still afforded certain protections. Another set of considerations associated with traditional oil and gas development are the conflicts that arise from split estates. In some instances mineral righ ts and surface rights are not owned by the same party . T his is referred to as “split estate” or "severed minerals". The condition of split estate is more prevalent in western states where the federal government owns much of the mineral rights 223

. In the m id

- west and eastern states, where shale gas development resources are more prevalent, only 4% of the lands are associated with a federal split estate 224

. However, these same areas frequently have private

private split estate scenarios where the surface owner differs from the mineral estate owner. In these cases the mineral owner may be another individual or a business enterprise such a s a coal company.

A split

- estate situation , regardless of its nature, can result in conflicts

— e specially in areas where
active mineral resource development is not commonplace. Land

- owners can be surprised to find
that the mineral lease holder is entitled to reasonable use of the land surface even though they do
not own the surface . However, it is important to understand that surface owners who do not own minerals rights are still afforded certain protections

. If the m ineral owner does not own the surface where drilling will occur, a separate agreement may be negotiated (in some states it is required)
with the land owner to ensure that he or she is compensated for the use of the land and to set requirements for reclaimi ng the land when operations are complete 225

.

Shale gas development within or near existing communities has created challe nges for production companies. New technologies have generally allowed these challenges to be met successfully. In some cases, a comb ination of modern shale gas technologies and the innovative use of BMP s has been required to allow development to continue without compromising highly valued community

resources.

In one instance

, Chesapeake Energy Corporation constructed a well pad near a popular Fort Worth community area, known as the Trinity Trail System, to develop natural gas from the Barnett Shale. The Trinity Trail System is located on private land and consists of a 35

- mile network of pav ed and natural surface pathways. The drilli ng pad was constructed approximately 200 feet from one portion of the trail. During the initial planning stages, proposed use of this land for development of natural gas was met with significant opposition by the public. M aintaining healthy populations o f upland hardwood forest habitat was important to the community because such woodlots are rare in urban setting s

. To address the concerns of the community, the company sponsored public meetings and opinion surveys; provided landscape plans; planted trees and shrubs; and enhanced the general area by improving irrigation and lowering maintenance requirements. T he well pad was specifically designed to be as small as possible in order to reduce the well’s footprint. Preventative construction practices were used that helped to preserve many of the existing trees. The construction zone was isolated from view using a 16

- ft barrier fence with sound baffling. This approach benefitted both parties: the compa ny was able to produce the shale gas, important community resources were protected, and a t no point in the process was any portion of the trail
closed 226

.MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

46 Both horizontal drilling and hydraulic fracturing are established technologies with significant track records; horizontal drilling dates back to the 1930s and hydraulic fracturing ha s a history dating back to
the 1950 s. E XHIBIT 29 : H ORIZONTAL AND V ERTICAL W ELL C OMPLETIONS

Source: John Perez, Copyright ©, 2008 The following discussions describe the general process of development with emphasis on the horizontal
d rilling and hydraulic fracturing technologies that are the hallmarks of modern shale gas production.
The section also describes the
environmental considerations that accompany shale gas development and the technologies and practices that are in place to p revent or minimize impacts.



### Horizontal Wells
Modern shale gas development is a technologically driven process for the production of natural gas resources. Currently, the drilling and completion of shale gas wells
includes both vertical and horizontal wells (Exhibit 2 9 ). The emerging sha le gas basins are expected to follow a trend similar to the Barnett Shale play with increasing numbers of horizontal wells as the plays mature 227

, 228

, 229

. The technologies utilized by operators to drill shale gas wells are similar to the drilling techniques tha t have been industry standards for drilling of conventional gas wells. Both horizontal drilling and hydraulic fracturing are established technologies with significant track records; horizontal drilling dates back t o the 1930 s and hydraulic fracturing ha s a history dating
back to the 1950 s 230

. The key difference between a shale gas well and a conventional gas well is the reservoir stimulation (large

- scale hydraulic fracturing) approach performed on shale gas wells 231

.
The evolution of the Barnett Shale play toward favoring horizontal wells resulted from improvements in the technology combined with the economic benefits of the greater reservoir exposure that a horizontal well provides over a vertical well. While both well types may be used to recover the resource, shale gas operators are increasingly relying on horizontal well completions to optimize recovery and wellMODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

47 economics 232

. Exhibit 2 9 illustrates how ho rizontal drilling provides more exposure to a formation
than does a vertical well. For example, in the Marcellus Shale in Pennsylvania, a vertical well may be exposed to as little as 50 ft of formation while a horizontal well may have a lateral wellbore extending in length from 2,000 to 6,000 ft within the 50

- to 300

- ft thick formation 233 . This increase in reservoir exposure creates a number of advantages over vertical well s drilling

.
There are a wide range of factors that influence the choice between a vertical or horizontal well. While vertical wells may require less capital investment on a per well basis, production is often less
economical. A vertical well may cost as much as $800 ,000 (excluding pad and infrastructure) to drill compared to a horizontal well that can cost $2.5 million or more (excluding pad and infrastructure) 234

.
Reducing Surface Disturbance Complete development of a 1

- square mile section could require 16 vertical wells each located on a separate well pad. Alternatively, six to eight
horizontal wells (potentially more) , drilled from only one well pad, could access the same reservoir volume , or even more 235

. The low natural permeability of shale requires vertical wells to be developed at closer spacing intervals than conventional gas reservoirs in order to effectively manage the resource. This can result in initial development of verti cal wells at spacing intervals of 40 acres per well, or less, to efficiently drain the gas resources from the tight shale reservoirs. In addition, horizontal drilling can significant ly reduce the overall number of well pads, access roads, pipeline routes, and production facilities required, thus minimizing habitat fragmentation, impacts to the public, and the overall environmental footprint. Devon Energy Corporation reports that the use of
horizontal wells in the Barnett Shale has allowed the company to r eplace 3 or 4 vertical wells with a single horizontal well. While it is too early to determine the final well spacing that will most efficiently recover the gas resource in all basins, experience to date indicates that the use of horizontal well technolog y will significant ly
decrease the total environmental disturbance

.

Exhibit 11 includes data on well spacing for some of the developing shale gas basins. Using this data it is possible to compare the development of a typical
640

- acre (1 square mile) area w ith vertical versus horizontal wells. The spacing interval for vertical wells in the gas shale plays averag es 40 acres per well for initial development. The spacing Source: ALL Consulting, 2008 Active D rilling R ig in the Barnett Shale P layMODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

48 interval for horizontal wells is likely to be approximately 160 acres per well. Therefor e, a 640

- acre section of land could be developed with a total of 16 vertical wells

, each on its own individual well pad

, or by as few as 4 horizontal wells all drilled from a single multi

- well drilling pad. A nalysis performed in 2008 for the U.S. Departme nt of the Interior estimated that a shallow vertical gas well completed in the Fayetteville Shale in Arkansas would have a 2.0

- acre well pad

, 0.10 miles of road and 0.55 miles of utility corridor

, resulting in a total of 4.8 acres of disturbance per well 236

. The same source identified a horizontal well pad in Arkansas as occupying approximately 3.5 acres plus
roads and utilities

, resulting in a total of 6.9 acres. If multiple horizontal wells are completed from a single well pad it may require the pad to be enlarged slightly. Estimating that this enlargement will
result in a 0.5

- acre increase, the 4

- well horizontal pad with roads and utilities would disturb an
estimated total of 7.4 acres , while the 16 vertical wells would disturb approximately 77 acres. I n this example, 16 vertical wells would disturb more than 10 times the area of 4 horizontal wells to produce the same resource volume. This difference in development footprint when considered in terms of both rural and urban development scenarios highligh ts the desire for operators to move toward horizontal development of gas shale plays.

Reducing Wildlife Impacts Research has documented that activities associated with gas development can affect wildlife and its habitat during the exploration, development, operations, and abandonment phases 237 . The development of shale gas utilizing horizontal wells and multi

- well pa ds not only reduces surface area disturbances by reducing the total number of wells drilled and well pad sites constructed, but also results in fewer roadways and utility corridors. This overall reduction in a project’s footprint
results in significant ly less habitat disturbance while allowing for more operational flexibility. Furthermore, by drilling underneath sensitive areas such as wetlands, areas near streams and
rivers and wilderness habitats, gas can be produced without disturbing some of these

res ources. This ability to
reduce surface disturbance is especially important in certain critical habitats. For example, certain portions of New York (e.g., Catskill Park, the Shawangunk Ridge, the Hudson Highlands and the Poconos) are dominated by
hardwood forests, which are important wildlife habitat s that are susceptible to fragmentation 238

.
In addition, state regulations and, in some cases

, local ordinances include stipulations dictating operational restrictions to provide added protection for wildlife or sensitive resources. In the c ity of Flower Mound, Texas, ordinances have been adopted to protect the surface resources and allow for futu re growth of the community without detract ing from the land value or sense of community. These ordinances Source: WVSORO 

### Drilling Rig in Rural Upshur County, West Virgi niaMODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

49 prevent construction in or near streams or rivers , floodplains and sensitive upland forest to protect wildlife species and their associated habitats.

At the state level, special plans or waivers are required when surface use actions may affect threatened or endangered species. Such waivers must demonstrate that contemplated disturbances will not adversely impact the species in question. In Pennsylva nia, wildlife are further protected on s tate lands ( by the Pennsylvania Game Commission) by using lease agreements that require, whenever feasible, the use of existing timber and maintenance roads to access wells and
avoidance of areas such as wetlands and unique and critical habitat s for threatened or endangered species 239

.

When disturbances to wildlife habitat are unavoidable, energy companies mitigate land disturbances by implementing land reclamation practices to restore disturbed land to original
conditi ons. In general, reclamation practices (or mitigation measures) designed to protect and maintain wildlife will depend on project features, regional characteristics, and the potentially affected species. However, because technologies associated with moder n shale gas development can reduce impacts in the first place, the need for additional protective restoration measures may also be reduced. Regardless of the situation, the timely reclamation of disturbed lands (e.g., re

seeding, land contouring, and re

- v egetating) can minimize short and long

- term disturbances to
natural habitats 240

.
Reducing Community Impacts States, local governments, and industry can work together in the initial planning phase of development to minimize long term effects and to address citizen concerns such as traffic congestion, damage to roads, dust, and noise 241

. The process of shale gas development , especially drilling and hydraulic fracturing

, can create short

- term increases in traffic volume, dust and noise.
These nuisan ce impacts are usually limited to the initial 20

- to 30

- day drilling and completion period 242

. Along with increases in traffic volume, damage to road
surfaces can oc cur if design parameters for traffic volume and weight loads are exceeded. Where these effects are an issue, developers have worked with authorities to adjust work schedules to help alleviate congestion; water unpaved roads to reduce dust; and adjust timi ng of some operations and install special sound barriers to reduce noise for nearby residents. When feasible, developers can also use avoidance practices to help minimize traffic congestion on heavily traveled roads. I n the Barnett Shale play around the Dallas

- Fort Worth International Airport , operators have constructed permanent pipelines to transfer produced water from well sites to disposal facilities

, thereby Source: Par ker County Commissioner’s Office 

### Tanker Trucks in Parker County, TexasMODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

50 reducing traffic and potential damage to roads 243

. When these practices are coupled with the
b enefits of multiple directional wells from fewer pads, the number of access roads and associated
traffic can be further reduced.

I n many cases, developers have negotiated to compensate local municipalities for road damage that
does occur as a result of the ir activities. Alternatively, they may negotiate road maintenance and repair agreements to ensure that damage to roadways are repaired and that the cost is absorbed by the drilling enterprises 244 . The Perryman Group, in their 2007 study of the Barnett Shal e play, noted that although traffic volume is a legitimate concern in the area, developers were effectively addressing the issue through maintenance agreements so that road repairs do not adversely affect local taxpayers 245

.
From a traffic perspective, members of the public or local municipalities often have the ability to limit traffic volume in residential areas by developing restrictions in neighborhood lease agreements or by developing ordinances that prevent road construction in certain areas,

respe ctively. In urban areas these agreements can be used to coordinate local traffic patterns to minimize congestion, control speed limits to address safety concerns

, and specify weight zones to reduce road damage.

With continued advances in technologies, modern developers are afforded a higher level of drilling flexibility than in the past. This provides producers with the ability to adjust their operational pla ns allowing them to access drilling locations that would otherwise be inaccessible. Although drilling circumstances vary by geologic region and well location, in many cases, shale gas plays are being developed with both vertically and horizontally drilled wells (Exhibit 2 9 ). Based on the current development activities of active gas shale basins, horizontal drilling has become the preferred method of drilling in most shale gas plays. Horizontal wells have also been used in many areas of the country to rem otely access natural gas resources beneath existing infrastructure, buildings, environmentally sensitive areas, or other features that would prevent the use of vertical wells. The development of the Barnett Shale near Dallas

- Fort Worth International Airpo rt is a prime example of how development of urban areas is possible with horizontal wellbores 246

.

Source: ALL Consulting , 2008



### Shale Gas Activity at Dallas

- Fort Worth International AirportMODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

51 The purpose of ordinances and best

management practices is to facilitate the development of the natural gas resource while protecting quality of life and
environmental values in the surrounding areas

. C hanges in practices during the drilling and completion of shale gas wells have evolved from the Barnett Shale play near Dallas

- Fort Worth International Airport and other urban areas surrounding the airport. Development practices
there have been altered to suit local ordinances implemented to lessen community impacts and protect environmental resources . These ordinances include detailed setbacks from residences, roadways, churches, and schools, and means to control visual and noise impacts including the required use of directional lighting 247

. This results in the use of
BM Ps for sound barriers and lighting. Typically, drilling operations in rural gas development areas continue around the clock until the well is completed. When these same operations moved into the urban areas around the cities of Arlington, Burleson, Clebu rne, Fort Worth, Joshua and North
Rich land Hills, specific ordinances were developed requiring additional permitting, well set backs from properties, day

- time and night

- time noise limits, and directional lighting 248 . Directional lighting provides illuminati on of well sites for worker safety, directing the light downward and shielding the surrounding area to prevent illuminating neighboring residences, roads or other buildings 249

.
In a similar concept, these drilling rigs are also being outfitted with blanket

- like
enclosures that act as an acoustic barrier to reduce engine noise. Sound deadening technology is a BMP that is also being applied to reduce noises from compressor facilit ies in both rural and urban settings 250 . These sound barriers include developing alternative building materials with integral sound absorbing properties.

T hese “BMPs” are not appropriate for all operations and must be applied on a case

by

- case basis. In s ome cases , a given BMP may actually be counter

- productive. In other cases, a particular BMP may create
other environmental , safety, or operational problems that must be weighed against each other. While BMP s ha ve certain benefits in certain situations, t hey cannot be universally applied or required.

Protecting Groundwater: Casing and Cementing Programs State oil and gas regulatory programs place great emphasis on protecting groundwater. Current well construction requirements consist of installing multipl e layers of protective steel casing and Source : Chesapeake Energy Corporation, 2008 

### Insulation Blankets Used to Deaden Noise from Drilling OperationsMODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

52 cement that are specifically designed and installed to protect fresh water aquifers and to ensure that the producing zone is isolated from overlying formations. During the drilling process, a
conductor and surface c asing string are set in the borehole and cemented in place. In some instances, additional casing strings may be installed; these are known as intermediate casings (Exhibit 30 251 ). After each string of casing is set, and prior to drilling any deeper in the borehole, the casing is cemented to ensure a seal is provided between the casing and formation or between two strings of casing 252 . Exhibit 30 illustrates the casing and cement that may be installed in shale gas wells and highlights how the casing
can be se t to isolate different water

bearing zones from each other. The exhibit shows the multiple strings of casing, layers of cement and the production tubing, which are all important parts of the well completion in preventing
contamination of fresh water zones and assuring that the gas resource does not flow into other, lower pressure zones around the outside of the casing rather than flowing up the well to be produced and sold. 253

.
The conductor casing serve s as a foundation for the well construction and prevent s caving of surface soils. The surface casing is installed to seal off potential freshwater

bearing zones , this isolation is necessary in order to protect aquifers from drilling mud and produced fluids. As a further protection of the fresh water zones, air

- rotary drilling is often used when drilling through this portion of the wellbore interval to ensure that no drilling mud come s in

contac t with the fresh water zone. Intermediate casings

, when installed

, are used to isolate non

freshwater

- bearing zones from the producing wellbore. Intermediate casing may be necessary because of a naturally over

- pressured zone or because of a saltwater zon e located at depth. The borehole area below an intermediate casing may be uncemented until just above the kickoff point for the horizontal leg. This area of wellbore is typically filled with drilling muds.

Each string of casing serves as a layer of prote ction separating the fluids inside and outside of the casing and preventing each from contacting the other. Operators perform a variety of checks to
ensure that the desired isol ation of each zone is occurring including ensuring that the casing used
has su fficient strength, and that the cement has properly bonded to the casing 254 . These checks may include acoustic cement bond logs and pressure testing to ensure the mechanical integrity of casings. Additionally, state oil and gas regulatory agencies often sp ecify the required depth of protective casings and regulate the time that is required for cement to set prior to additional drilling. These requirements are typically based on regional conditions and are established for all 

### E XHIBIT 

### 30: C ASING 

### Z ONES AND 

### C EMENT 

### P ROGRAMSMODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

53 wildcat well s and may be modifi ed when field rules are designated. These requirements are instituted by the state oil and gas agency to provide prot ect ion of groundwater resources 255 . Once the casing strings are run and cemented there could be five or more layers or barriers between the inside of the production tubing and a water

- bearing formation (fresh or salt).

Analysis of the redundant protections provided by casings and cements was presented in a series of reports and papers prepared for the American Petroleum Institute (API) 256 in th e 1980s. These investigations evaluated the level of corrosion that occurred in Class II injection wells. Class II injection wells are used for the routine injection of water associated with oil and gas production. The research resulted in the developme nt of a method of calculating the probability (or risk) that fluids injected into Class II injection wells could result in an impact to a USDW. This research started by evaluating data for oil and gas producing basins to determine if there were natural
fo rmation waters present that were reported to cause corrosion of well casings. The United States was divided into 50 basins, and each basin was ranked by its potential to have a casing leak resulting from such corrosion.

Detailed analysis was performed f or those basins in which there was a possibility of casing
corrosion 257 . Risk probability analysis provided an upper bound for the probability of the fracturing fluids reaching an underground source of drinking water. Based on the values calculated, a mode rn horizontal well completion in which 100% of the USDWs are protected by properly installed surface casings (and for geologic basins with a reasonable likelihood of corrosion), the probability that fluids injected at depth could impact a USDW would be bet ween 2 x
10

- 5 (one well in 200,000) and 2 x 10

- 8 (one well in 200,000,000) if these wells were operated as injection wells. Other studies in the Williston basin found that the upper bound probability of injection water escaping the wellbore and reaching an underground source of drinking water is seven changes in one million well

- years where surface casings cover the drinking water a quifers 258

.
These values do not account for the differences between the operation of a shale gas well and the operation of an injection well. An injection well is constantly injecting fluid under pressure and thus raises the pressure of the receiving aquif er, increasing the chance of a leak or well failure. A production well is reducing the pressure in the producing zone by giving the gas and associated fluid a way out, making it less likely that they will try to find an alternative path that could
contami nate a fresh water zone. Furthermore, a producing gas well would be less likely to experience a casing leak because it is operated at a reduced pressure compared to an injection well

. I t would be exposed to lesser volumes of potentially corrosive water f lowing through the production tubing, and it would only be exposed to the pumping of fluids into the well during
fracture stimulations.

The API study included an analysis of wells that had been in operation for many years when the study was performed in the late 1980s, and does not account for advances that have occurred in equipment and applied technologies and changes to the regulations. As such, a calculation of the probability of any fluids, including hydraulic fracture fluids, reaching a USDW from a gas well would indicate an even lower probability; perhaps by as much as two to three orders of magnitude. The API report came to another important conclusion relative to the probability of the contamination of
a USDW when it stated that:MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

54 ...for injected water to reach a USDW in the 19 identified basins of concern, a number of independent events must occur at the same time and go undetected [emphasis added]. These events include simultaneous leaks in the [production] tubing, production casing, [intermedia te casing,] and the surface casing coupled with the unlikely occurrence of water moving long distances up the borehole past salt water aquifers to reach a USDW 259

.
As indicated by the analysis conducted by API and others, the potential for groundwater to b e impacted by injection is low. It is expected that the probability for treatable groundwater to be impacted by the pumping of fluids during hydraulic fracture treatments of newly installed , deep shale gas wells when a high level of monitoring is being pe rformed would be even less than the 2 x
10

- 8 estimated by API.

In addition to the protections provided by multiple casings and cements, there are natural barriers in the rock strata that act as seals holding the gas in the target formation. Without such seals, gas and oil would naturally migrate to the earth’s surfac e. A fundamental precept of oil and gas geology is that without an effective seal, gas and oil would not accumulate in a reservoir in the first place and so could never be tapped and produced in usable quantities. These sealing strata also act as
barrier s to vertical migration of fluids upward toward useable groundwater zones. Most shale gas wells (outside of those completed in the New Albany and the Antrim) are expected to be drilled at depths greater than 3,000 feet below the land surface (based on the data presented in Exhibit 11 ).
Exhibit 3 1 compares estimated shallowest producible depth of the target (“pay”) shale zone and the maximum base of treatable water. For any fluid present in the producing zone to reach treatable groundwater the fluid must migrate through these overlying zones.



### E XH IBIT 

### 31 : C OMPARISON OF 

### T ARGET 

### S HALE 

### D EPTH AND 

### B ASE OF 

### T REATABLE 

### G ROUNDWATER

Source: Compiled from Various Data SourcesMODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

55 A fundamental precept of oil and gas geology is tha t without an effective seal, gas and oil would not accumulate in a
reservoir in the first place and so it could never be tapped and produced in usable quantities. These sealing strata also act as barriers to vertical migration of fluids upward toward grou ndwater zones. Drilling Fluids and Retention Pits Drilling fluids are a necessary component of the drilling process ; they circulate cuttings (rock chips created as the drill bit advances through rock, much like sawdust) to the
surface to clear the borehole

, they lubricate
and cool the drilling bit, they stabilize the wellbore (preventing cave in), and control downhole fluid pressure 260

. In order to
maintain sufficient volumes of fluids onsite during drilling, operators typically use pits to store make

- up water used as part of the drilling
fluids. Storage pits are not used in every development situation . I n the case of shale gas development, drilling operations have been occurring in both urban and rural locations, requiring
that drilling practices be adapted to facilitate dev elopment in both settings. Drilling with compressed air is becoming an increasingly popular alternative to drilling with fluids due to the increased cost savings from both reduction in mud costs and the shortened drilling times as a result
of air based dr illing 261 . The air, like drilling mud, functions to lubricate, cool the bit, and remove cuttings. Air drilling is generally limited to low pressure formations, such as the
Marcellus shale in New York 262

.

In rural areas, stora g e pits may be
used to hold fresh water for drilling and hydraulic fracturing

. In an urban setting, due to space limitations, steel storage tanks may be used

. Tanks can
also be used in a closed

- loop drilling system. C losed

- loop drilling allows
for the re

- use of drilling fluids and the use of lesser amounts of drilling
fluids 263

. C losed

- loop drilling system s have also been used with

water

- based fluids in environmentally sensitive environments in combination with air

- rota ry drilling techniques 264

. While closed

- loop drilling has been used to address specific situations, the practice is not necessary for every well drilled. As discussed in the previous section, drilling is a regulated practice managed
at the state level

, and while s tate oil and gas agencies have the ability to require operators to vary standard practices

, the agenc ies typically do so only when it is necessary to protect the gas resources and the environment.

I n rural environments, storage pits may be used to hold water

. They are typically excavated containment ponds that , based on the local conditions and regulatory requirements, may be lined.
Pits can also be used to store additional make

- up water for drilling fluids or to store water used in
the hydrau lic fracturing of wells. Source: Compi l ed from Various Data Sources

Source: ALL Consulting, 2008 

### Lined Fresh Water Supply Pit from the Marcellus Shale Development in PennsylvaniaMODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

56 Stimulations are optimized to

ensur e that fracture development is confined to the target formation.

Source: ALL Consulting, 2 008
A Fracture Stimulation Is Closely Monitored b y Many Specialists (Fayetteville Shale

- Arkansas) Water storage pits used to hold water for hydraulic fracturing purposes are typically lined to minimize the loss of water from infiltration (notice the black synthetic liner in the accompanying photograph). Water storage pits are becoming an important tool in the shale gas industry because the drilling and hydraulic fracturing of these wells often requires significant volumes of water as the base fluid for both purposes 265

. 

### Hydraulic Fracturing
The other technolog ical key to the economic recovery of shale gas is hydraulic fracturing. Hydraulic fracturing is a formation stimulation practice used to create additional permeability in a producing
formation

, thus allow ing gas to flow more readily toward the wellbore 266

, 267 . H ydraulic fracturing
can be used to overcome natural barriers to th e flow of fluids (gas or water ) to the wellbore. Such b arriers may include naturally low permeability common in shale formations or reduced permeability resulting from near wellbore damage during drilling
activities 268

.
Hydraulic fracturing involves the pumping of a fracturing fluid into a formation at a calculated, predetermine d rate and pressure to generate fractures or cracks in the target formation. For shale gas development, fracture fl uids are primarily water

- based fluids mixed with additives which help the water to carry sand proppant into the fractures. The sand proppant is needed to “prop” open
the fracture s once the pumping of fluids has stopped. Once the fracture has initiated, a dditional fluids are pumped into the wellbore to continue the development of the fracture and to carry the proppant deeper into the formation. The additional fluids are needed to maintain the downhole pressure necessary to accommodate the increasing lengt h of opened fracture in the formation. Each rock formation has inherent natural variability resulting in different fracture pressures for
different formations. The process of designing hydraulic fracture treatments involves i dentifying properties of the target formation including fracture pressure, and the desired length of fractures. The following discussion addresses some of the processes involved in the design of a hydraulic fracture stimulation of a shale gas
formation.

Fracture Design Modern formation stimulation practices are sophisticated, engineered process es design ed to emplace fracture networks in specific rock strata 269

. A h ydraulic fracture

treatment is a controlled process designed to the specific conditions of the target formation (thickness of shale, rock fracturing characteristics, etc.). Understanding the in

- situ reservoir conditions present and their dyna mics is critical to successful stimulations. Hydraulic fracturing designs are con tinually refined to optimize fracture networking and maximizeMODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

57 gas production

. While the

concepts and general practices are similar, the details of a specific fracture operat ion can vary substantially from basin
to basin and from well to well.

Fracture de sign can incorporate many sophisticated and state

- of

- the

art techniques to accomplish an effective, economic and highly successful fracture
stimulation. Some of these techniques include modeling,
microseismic fracture mapping, and tilt

- meter analysis

.
A computer model can be used to simulate hydraulic fracturing designs 270 . This approach helps maximize effectiveness and economically design a treatment event. The modeling programs allow geologists and engineers to modify the design of a hydraulic fracture treatment and evaluate the height, length

, and orientation of potential fracture development (Exhibit 3 2 ) 271 . These simulators also allow the designers to use the data gathered during a fracture stimulation to evalu ate the success of the fracture job performed. From these data and analyses

, engineers can optim ize the design of future fracture stimulations.

Additional advances in hydraulic fracturing design target analysis of hydraulic fracture treatments through t echnologies such as microseismic fracture mapping (Exhibit 3 3 272 ) and tilt

measurements 273

. These technologies can be used to define
the success and orientation of the fractures created, thus providing the engineers with the ability to manage
the resource thr ough the strategic placement of additional wells, taking advantage of the natural reservoir conditions and expected
fracture results in new wells.

As more formation

- specific data are gathered, service companies and operators can optimize fracture patterns . Operators have strong
economic incentives to ensure that fractures do not propagate beyond Source: Oilfield Service Company , 2008 

### E XHIBIT 

### 3 3 : M APPING OF 

### M ICROSEISMIC 

### E VENTS 

### E XHIBIT 

### 32: E XAMPLE 

### O UTPUT OF A 

### H YDRAULIC 

### F RACTURE



### S TIMULATION 

### M ODEL

Source: Chesapeake, 2008MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

58 Operators have strong economic incentives to ensure that fractures do not propagate beyond the target formation and into adjacent rock

strata. the target formation and into adjacent rock

strata 274 . Allowing the fractures to extend beyond
th e target formation would be a waste of materials, time, and money

. In some cases, fracturing outside o f the target formation could potentially result in the loss of the well and the associated gas resource. Fracture growth outside of the target formation can result in excess water production from bounding strata. Hav ing to pump and handle excess water increases production costs, negatively impacting well economics. This is a particular concern in the Barnett Shale of Texas where the underlying Ellenberger Group limestones are capable of yielding significant formation water.

Fracturing Process Hydraulic fracturing of horizontal shale gas wells is performed in stages. Lateral lengths in
horizontal wells for shale gas development may range from 1,000 feet to more than 5,000 feet. Because of the length of exposed wellbore, it is usually not possible to maintain a downhole pressure sufficient to stimulate the entire leng th of a lateral in a single stimulation event 275

. Because of the lengths of the laterals , hydraulic fracture treatments of horizontal shale gas wells are usually performed by isolating smaller portions of the lateral . The fracturing of each portion of the lateral wellbore is called a stage. Stages are fractured sequentially beginning with the section at the farthest end of the wellbore, moving uphole as each stage of the treatment is completed until the
entire lateral well has been stimulate d 276

. Horizontal wells in the various gas shale basins may be treated using two or more stages to fracture the entire perforated interval of the well. Each stage of
a horizontal well fracture treatment is similar to a fracture treatment for a vertical shale gas well.

For each stage of a fracture treatment, a series of different volumes of fracture fluids, called sub

stages, with specific additives and proppant concentrations, is injected sequentially. Exhibit 3 4 277 presents an example of the sub

- stages of a single

- stage hydraulic fracture treatment for a well completed in the Marcellus Shale 278 . This is a single

- stage treatment typical of what might be performed on a vertical shale well or for each stage of a multi

- stage horizontal well treatment

. The
total volume of the sub

- stages in Exhibit 3 4 is 578,000 gallons. If this were one stage of a four

- stage horizontal well, the entire fracture operation would require approximately four times this amount, or 2.3 million gallons of water.

Before operators or service companies perform a hydraulic fracture treatment of a well (vertical or horizontal), a series of tests is performed . These tests are designed to ensure that the well, well equipment and hydraulic fracturing equipment are in proper working order and will safely
with stand the application of the fracture treatment pressures and pump flow rates . T he tests start with the testing of well casings and cements during the drilling and well construction process

. Testing continues with pressure testing of hydraulic fracturing equipment prior to the fracture treatment process 279

. It should be noted that construction requirements for wells are mandated by state oil and gas regulatory agencies to en sure that a well is protective of water resources and is

s afe for operation.MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

59 

### E XHIBIT 

### 3 4 : E XAMPLE OF A 

### S INGLE 

### S TAGE OF A 

### S EQUENCED 

### H YDRAULIC 

### F RACTURE 

### T REATMENT

Hydraulic Fracture
Treatment Sub

- Stage Volume (gallons) Rate (gal/min)

Diluted Acid ( 15%) 5,000 500

Pad 100,000 3,000

Prop 1 50,000 3,000

Prop 2 50,000 3,000

Prop 3 40,000 3,000

Prop 4 40,000 3,000

Prop 5 40,000 3,000

Prop 6 30,000 3,000

Prop 7 30,000 3,000

Prop 8 20,000 3,000

Prop 9 20,000 3,000

Prop 10 20,000 3,000

Prop 1 1 20,000 3,000

Prop 1 2 20,000 3,000

Prop 1 3 20,000 3,000

Prop 1 4 10,000 3,000

Prop 1 5 10,000 3,000

Flush 13,000 3,000

Notes : Volumes are presented in gallons (42 gals = one barrel, 5,000 gals = ~120 bbls). Rates are expressed in gals/minute, 42 gals/minute = 1 bbl/min, 500 gal/min = ~12 bbls/min.
Flush volumes are based on the total volume of open borehole, therefore as each stage is completed the volume of flush decreases as the volume of borehole is decreased. Total amount of proppant used is approximately 450,000 pounds

Source: Arthur et al.

, 2008MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

60 Every aspect of the fracture stimulation process is carefully
monitored. After the testing of equipment has been completed, the hydraulic fracture treatment process begins

. The sub

- stage sequence is usually initiated with the pumping of an acid treatment. This acid treatment helps to clean the near

- wellbore area which can be “damaged” (pores and pore throats become plugged with drilling mud or casing cement ) as a result of the drilling and well installation process. The next sequence after the acid treatment is a slickwater pad , which is a water

- based fracturing fluid mixed w ith a friction reducing agent . The pad is a volume of fracturing fluid large enough to effectively fill the wellbore and the open formation area

. The slickwater pad helps to facilitate the flow and placement of the proppant further into the fracture netw ork.

After the pad is pumped, the first proppant sub

- stage , combin ing a large volume of water with fine mesh sand is pumped. The next several sub

- stages in the stage increase the volume of fine

- grained proppant while the volume of fluids pumped are decreased incrementally from 50,000 gallons (gals) to 30,000 gals. This fine

- grained proppant is used because the finer particle size is capable of
b eing carried deeper into the developed fractures 280

. In this example, t he fine proppant sub

- stages are followed by eight sub

- stages of a coarser proppant with volumes from 20,000 gals to 10,000 gals. After the completion of the final sub

- stage of coarse pr oppant, the well and equipment are flushed with a volume of freshwater sufficient to remove excess proppants from the equipment and
the wellbore.

H ydraulic fracturing stimulations are overseen continuously by operators and service companies to
evaluate and document the events of the treatment

proces s. Every aspect of the fracture stimulation process is carefully monitored, from the wellhead
and down hole pressures to pumping rates and density of the fracturing fluid slurry . The monitors Source: Chesapeake Energy Corporation, 2008

Hydraulic Fracturing of a Marcellus Shale Well, West VirginiaMODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

61 also track the volumes o f each additive and the water used, and ensur e that equipment is functioning properly. For a 12,000

- bbl (504,000

- gallon) fracture treatment of a vertical shale gas
well there may be between 30 and 35 people on site monitoring the entire stimulation process.

T he staging of multiple fracture treatments along the length of the lateral leg of the horizontal well
allows the fract uring process to be performed in a very controlled manner. By fracturing discrete intervals of the lateral wellbore, the operator is able to make changes to each portion of the completion zone to accommodate site

- specific changes in the formation. These site

- specific variations may include variations in shale thickness, presence or absence of natural fractures, proximity to another wellbore fracture system, and boreholes that are not centered in the
formation

.
Fracturing Fluids and Additives

As described above, t he current practice for hydraulic fracture treatments of shale gas reservoirs is to apply a sequenced pumping event in which millions of gallons of water

- based fracturing fluids mixed with proppant materials are pumped in a controlled and monitore d manner into the target shale formation above fracture pressure 281

.
The fracturing fluids used for gas shale stimulations consist primarily of water but also include a variety of additives

. The number of chemical additives used in a typical fracture treat ment varies depending on the conditions of the specific well being fractured. A typical fracture treatment will use very low concentrations of between 3 and 12 additive chemicals depending on the characteristics of the water and the shale formation being fractured. Each component serves a specific, engineered purpose 282 . The predominant fluids currently being used for fracture treatments in the gas shale plays are water

- based fracturing fluids mixed with friction

- reducing
additives (called slickwater) 283

.

T he addition of friction reducers allows fracturing fluids and proppant to be pumped to the target zone at a higher rate and reduced pressure than if water alone were used . In addition to friction reducers, other additives include : biocides to prevent mic roorganism growth and to reduce bio

fouling of the fractures ; o xygen scavengers and other stabilizers to prevent corrosion of metal pipes ; and acids that are used to remove drilling mud damage within the near

- wellbore area 284

. These fluids are used not only to create the fractures in the formation but also to carry a propping agent (typically silica sand) which is deposit ed in the induced fracture s

.

Exhibit 3 5 285 demonstrates the volumetric percentages of additives that were used for a nine

- stage hydraulic fracturing treatment of a Fayetteville Shale horizontal well. The make

- up of fracturing
fluid var ies from one geologic basin or formation to another. Evaluating the relative volume s 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. O verall the concen t ration of additives in most slickwater fracturing fluids i s a relatively
consistent 0.5% to 2% with water making up 98% to 99.5%

.MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

62 Because the make

- up of each fracturing fluid varies to meet the specific needs of each area

, there is

no one

- size

- fits

- all formula f or the volumes for each additive. In classifying fracturing fluids and their additives it is important to realize that serv ice companies that provide these additives have developed a number of compounds with similar functional properties to be used for the same purpose in different well environments. The difference between additive formulations may be as small as a change in c oncentration of a specific compound

. Although the hydraulic fracturing industry may have a number of compounds that can be used in a hydraulic fracturing fluid, any single fracturing job would only use a few of the available additives. For example, in Ex hibit 3 5 there are 12 additives used, covering the range of possible functions that could be built into a fracturing fluid. It is not uncommon for some fracturing recipes to omit some compound categories if their properties are not required for the specif ic application.

Most ind ustrial processes use chemicals and almost any chemical can be hazardous in large enough quantities or if not handled properly. Even chemicals that go into our food or drinking water can be hazardous. For example, drinking water treatment plants use large quantities of chlorine.
Whe n used and handled properly, it is safe for workers and near

- by residents and provides clean, safe drinking water for the community. A lthough the risk is low, the potential exists for unplanned
releases that could have serious effects on human health and the environment. By the same token, hydraulic fracturing uses a number of chemical additives that could be hazardous, but are safe when properly handled according to requirements and long

- standing industry practices. In addition, many of these additives a re common chemicals which people regularly encounter in everyday life. 

### E XHIBIT 

### 3 5 : V OLUMETRIC 

### C OMPOSITION OF A 

### F RACTURE 

### F LUID

Source: ALL Consulting based on data from a fracture operation in the Fayetteville

Shale, 2008MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

63 

### E XHIBIT 

### 3 6 : F RACTURING 

### F LUID 

### A DDITIVES 

### , M AIN 

### C OMPOUNDS 

### , AND 

### C OMMON 

### U SES



### .
Additive Type Main Compound(s) Purpose Common Use of Main Compound

Diluted Acid (15%) Hydrochloric acid or muriatic acid Help dissolve minerals and initiate cracks in the rock Swimming pool chemical and cleaner

Biocide Glutaraldehyde Eliminates bacteria in the water that produce corrosive byproducts Disinfectant; sterilize medical and dental equipment

Breaker Ammonium persulfate Allows a delayed break down of the gel polymer chains Bleaching agent in detergent and hair cosme tics, manufacture of household plastics

Corrosion Inhibitor N,n

- dimethyl formamide Prevents the corrosion of the pipe Used in pharmaceuticals,

acrylic fibers, plastics

Crosslinker Borate salts Maintains fluid viscosity as temperature increases Laundry detergents, hand soaps, and cosmetics

Friction Reducer Polyacrylamide

Minimizes friction between the fluid and the pipe Water treatment, soil conditioner

Mineral oil Make

- up remover, laxative s, and candy

Gel Guar gum or hydroxyethyl cellulose Thickens the water in order to suspend the sand Cosmetics, toothpaste, sauces, baked goods, ice cream

Iron Control Citric acid Prevents precipitation of metal oxides Food additive, flavoring in

food and beverages; Lemon Juice ~7% Citric Acid

KCl Potassium chloride Creates a brine carrier fluid Low sodium table salt substitute

Oxygen Scavenger Ammonium bisulfite Removes oxygen from the water to protect the pipe from
corrosion Cosmetics, food and beverage processing, water treatment

pH Adjusting Agent Sodium or potassium carbonate Maintains the effectiveness of other components, such as crosslinkers Washing soda, detergents, soap, water softener, glass and
ceramics

Proppant Silica, quartz sand Allows the fractures to remain open so the gas can escape Drinking water filtration, play sand, concrete, brick mortar

Scale Inhibitor Ethylene glycol Prevents scale deposits in the pipe Automotive antifreeze

,

household cleansers, and de

icing agent

Surfactant Isopropanol Used to increase the viscosity of the fracture fluid Glass cleaner, antiperspirant, and hair color

Note: The specific compound s used in a given fracturing operation will vary depending on company preference, source water quality and site

- specific characteristics of the target formation. The compounds shown above are representative of the major compounds used in hydraulic fractur ing of gas shales.MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

64 Exhibit 36 286 provides a summary of the additives, their main compounds , the reason the additive is used in a hydraulic fracturing fluid, and some of the other common uses for the se compounds. Hydrochloric acid (HCl) is the single large st liquid component used in a fracturing fluid aside from water; while the concentration of the acid may vary, a 15% HCl mix is a typical concentration. A 15% HCl mix is composed of 85% water and 15% acid, therefore, the volume of acid is diluted by 85% with water in its stock solution before it is pumped into the formation during a fracturing treatment. Once the entire stage of fracturing fluid has been injected, the total volume of acid in an example fracturing fluid from the Fayetteville shale was 0.123%, which indicates the fluid had been diluted by a factor of 122 times before it is pumped into the formation. The concentration of this acid will only continue to be diluted as it is further dispersed in additional volumes of water that may be pres ent in the subsurface. Furthermore, if this acid comes into contact with carbonate minerals in the subsurface, it would be neutralized by chemical reaction with the carbonate minerals producing water and carbon dioxide as a byproduct of the reaction.



### Wate r Availability The drilling and hydraulic fracturing of a horizontal shale gas well may typically require 2to 4 million gallons of water 287

, with about 3 million gallons being most common

. It should be noted that the volume of water needed may vary substant ially between wells. In addition the volume of water needed per foot of wellbore appears to be decreasing as technologies and methods improve
over time. Exhibit 3 7 288 presents a table of estimated per

- well water needs for four shale gas plays currently bei ng developed.



### E XHIBIT 

### 3 7 : E STIMATED 

### W ATER 

### N EEDS FOR 

### D RILLING AND 

### F RACTURING 

### W ELLS IN 

### S ELECT 

### S HALE 

### G AS 

### P LAY S

Shale Gas Play Volume of Drilling

Water per well (gal) Volume of Fracturing

Water per well (gal) Total Volumes of Water
per w ell (gal)
Barnett Shale 4 0 0,000 2,3 0 0,000 2,7 0 0,000

Fayetteville
Shale 60 ,000* 2,9 0 0,000 3,0 60 ,000

Haynesville
Shale 1, 000 ,000 2,7 0 0,000 3,7 0 0,000

Marcellus
Shale 8 0 ,000* 3, 80 0,000 3,8 8 0 ,000

* Drilling performed with a n air “mist” and /or water

- based or oil

- based muds for deep horizontal well completions. Note: These volumes are approximate and may vary substantially between wells.

Source: ALL Consulting from discussions with various operators , 2008MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

65 This project was developed with input from a local chapter of Trout Unlimited, an active conservation organization in the area, and represents an innovative environmental solution that serves both the community and the gas developer. Water for drilling and hydraulic fracturing of these wells frequently comes from surface water bodies such as rivers and lakes, but can also come from ground water, private water sources, municipal water, and re

- used produced water. Most of the producing shale gas basins occur in areas with moderate to high levels of annual precipitation as shown in Exhibit 3 8 289 . However, even in areas of high precipitation, due to growing populations, other industrial water demands, and seasonal variation in precipitation , it can be difficult to meet the needs of shale gas development and still satisfy regional needs for water.

While the water volumes needed to drill and
stimulate shale gas wells are large, they generally represent a small percentage of the
total water r esource use in the shale gas
basins

. C alculations indicate that water use will range from less than 0.1 % to 0.8 % by
basin 290 . This volume is small in terms of the overall surface water budget for an area; however, operators need this water when drilling ac tivity is occurring

, requiring that the water be procured over a relatively short period of time. Water withdrawals during periods of low stream flow could affect fish and other aquatic life, fishing and other recreational activities, municipal water supplies, and other industries such as power plants. To put shale gas water use in perspective, the consumptive use of fresh water for electrical generation in the Susquehanna River Basin alone is nearly 150 million gallons per day, while the projec ted to tal demand for peak Marcellus S hale activity in the same area is 8.4 million gallons per day 291

.

One alternative that states and operators are pursuing is to make use of seasonal changes in river flow to capture water when surface water flows are greatest. Utilizing s easonal flow differences
allows plan ning of withdrawals to avoid potential impacts to municipal drinking water supplies or to aqu atic or riparian communities. In the Fayetteville Shale play of Arkansas, one operator is

construct ing a 500

- acre

- ft impoundment to s tore water withdrawals from the Little Red River
obtained during periods of high flow (storm events or hydroelectric power generation releases from Greer’s Ferry Dam upstream of the intake) when excess water is available 292 (one acre

- foot is equivalent to the volume of water required to cover one acre with one foot of water)

. The project is limited to 1,550 acre

- ft of water annually. As additional mitigation, the company has
constructed extra pipelines and hydrants to

prov ide portions of this rural area with water for fire protection. Also included is monitoring of in

stream water quality as well as game and non

game fish species in the reach of river surrounding the intake. This design provides a water recovery system si milar in concept to what Source: ALL Consulting, 2008



### Little Red River, ArkansasMODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

66 One key to the successful

development of shale gas is the
id entification of water supplies capable of meeting the needs of a development company for drilling and fracturing water without interfering with community needs. some municipal water facilities use. It will minimize the impact on local water supplies because
surface water withdrawals will be limited to times of excess flow in the Little Red River. This project was developed with input fro m a local chapter of Trout Unlimited, an active conservation organization in the area, and represents an innovative environmental solution that serves both the community and the gas developer

.
Because the development of shale gas is new in some areas, the se water needs may challenge su pplies and
infrastructure

. As operators look to develop new shale gas plays, communication with local water planning agencies can help operators and communities to coexist and effectively manage local

water resources. Understanding local water needs

can help operators develop a water storage or management plan that will meet with acceptance in neighboring communities. Although the water needed for drilling an individual well may represent a small volume over a large area, the withdrawals may have a cumul ative impact to watersheds over the short term. This potential impact can be avoided by working with local water resource managers to develop a plan outlining when and where withdrawals will occur (i.e.

, avoiding headwaters

, tributaries

, small surface wat er bodies , or other sensitive sources ).

In some basins, one key to the successful development of shale gas is the identification of water supplies capable of meeting the needs of a development company for drilling and fracturing water without interfering with community needs. While a variety of options exist, the conditions of obtaining water are complex and vary by region and even within a region such that developers will
also need to understand local water laws 293

.



### Water Management
After a hydraulic fra cture treatment, when the pumping pressure has been relieved from the well,
the water

- based fracturing fluid , mixed with any natural formation water present, begin s to flow back through the well casing to the wellhead. This produced water may also contain dissolved
constituents from the formation itself

. The dissolved constituents are naturally occurring compounds and may vary from one shale play to the next or even by area within a shale play. Initial produced water can vary from fresh ( <5,000 ppm Total Dissolved Solids (TDS)) to varying degrees of saline (5,000 ppm to 100,000 ppm TDS 294 or higher). The majority of fracturing fluid is recovered in a matter of several hours to a couple of weeks. In various basins and shale gas plays,
the v olume of produced water may account for less than 30% to more than 70% of the original
fracture fluid volume 295 . In some cases, flow back of fracturing fluid in produced water can continue for several months after gas production has begun 296

.MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

67 A suite of circumstances explain s the disposition of fracturing fluids that are not recovered through production. However, it is important to understand that unrecovered fluids, if any, will remain contained within the target formations. Some of these fluids will occupy macro

- porosity (typically natural fracture porosity) in the shale formation and some will occupy t he micro

- pore space vacated by the gas that is produced. Also, some of the fracturing fluids remain stranded in fractures within the reservoir rock that heal after fracturing, thus preventing the fluids from flowing back to
the well. S ome of these strand ed fluids may flow back to the well in very small volumes over an extended time span. The longer contact time these fluids have with the formation further alters the chemistry of these fluids through increased dissolution of formation minerals , making the m similar
to the natural formation water . For these reasons it is not possible to unequivocally state that 100% of the fracturing fluids have been recovered or to differentiate flow back water from natural
formation water

.

Natural formation water has be en in contact with the reservoir formation for millions of years and
thus contains minerals native to the reservoir rock. The salinity, TDS, and overall quality of
formation water var y by geologic basin and specific rock strata. After initial production, p roduced water can vary from brackish (5,000 ppm to 35,000 ppm TDS), to saline (35,000 ppm to 50,000 ppm TDS), to supersaturated brine (50,000 ppm to >200,000 ppm TDS) 297

, and some operators



### E XHIBIT 

### 38 : A NNUAL 

### R AINFALL 

### M AP OF THE 

### U NITED 

### S TATES

Source: N

RC SMODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

68 report TDS values greater than 400,000 ppm 298 . T he variation in com position changes primarily with changes in the natural formation water chemistry.

States, local governments, and shale gas operators seek to manage produced water in a way that protects surface and ground water resources and, if possible, reduces future demands for fresh water. By pursuing the pollution prevention hierarchy of “Reduce, Re

- use, and Recycle” these groups are examining both traditional and innovative approaches to managing shale gas produced water. This water is currently managed through a variety of mechanisms, including underground injection, treatment and discharge, and recycling. Exhibit 39 summarizes current produced water management practices for the various shale gas basins, and is compiled from data collected from producers and reg ulatory agencies in these basins.

Underground injection has traditionally been the primary disposal option for oil and gas produced
water. In most settings, this may be the best option for shale gas produced water. This process uses salt water disposal w ells to place the water thousands of feet underground in porous rock formations that are separated from treatable groundwater by multiple layers of impermeable rock thousands of feet thick. Underground injection of the produced water is not possible in ev ery play as suitable injection zones may not be available. Similar to a producing reservoir, there must be a porous and permeable formation capable of receiving injected fluids nearby . If such is not locally available, it may be possible to transport the produced water to a more distant injection site. In well developed urban plays such as the Barnett Shale around the City of Fort Worth, pipelines have been constructed to transport produced water to injection well disposal sites. This minimizes trucking the water and the resultant traffic, exhaust emissions, and wear on local roads 299 . Injection disposal wells are permitted under the federal Safe Drinking Water Act (SDWA), Underground Injection Control (UIC) program (or in the case of state primacy, under equivalent state programs), a stringently permitted and monitored process with many environmental safeguards in place.

Treatment of produced water may be feasible through either self

- contained systems at well sites or fields or municipal waste water treat ment plants or commercial treatment facilities. The availability of municipal or commercial treatment plants may be limited to large r urban areas where treatment facilities with sufficient available capacity already exist. As in underground injection, tr ansportation to treatment facilities may or may not be practical 300

.

Re

- use of fracturing fluids is being evaluated by service companies and operators to determine the degree of treatment and make

- up water necessary for re

- use 301 . The practical use of on

- site, self

contained treatment facilities and the treatment methods employed will be dictate d by flow rate and total water volumes to be treated, constituents and their concentrations requiring removal, treatment objectives and water reuse or discharge requirements. In some cases it would be more practical to treat the water to a quality that co uld be reused for a subsequent hydraulic fracturing job, or other industrial use, rather than treating to discharge to a surface water body or for use as drinking water. At the time this Primer was developed there were plans to construct commercial

waste water treatment facilities specifically designed for the treatment of produced water associated with shale gas development in some locations around the country 302 . The completion and success of such plants no doubt will be closely tied to the successful exp ansion of production in the various shale gas plays.MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

69 

### E XHIBIT 

### 3 9 : C URRENT 

### P RODUCED 

### W ATER 

### M ANAGEMENT BY 

### S HALE 

### G AS 

### B ASIN



### .

Shale Gas Basin Water Management Technology Availability Comments

Barnett Shale Class II injection wells 303 Commercial and non

commercial Disposal into the Barnett and underlying Ellenberger Group 304

Recycling 305 On

- site treatment and recycling For reuse in subsequent fracturing jobs 306

Fayetteville Shale Class II injection wells 307 Non

- commercial Water is transported to two injection wells owned and operated by a single producing
company 308

Recycling On

- site recycling For reuse in subsequent fracturing jobs 309

Haynesville Shale Class II injection wells Commercial and non

commercial

Marcellus Shale Class II injection wells Commercial and non

commercial Limited use of Class II injection wells 310

, 311

Treatment and discharge Municipal waste water treatment facilities, commercial facilities reportedly contemplated 312 Primarily in Pennsylvania

Recycling On

- site recycling For reuse in subsequent fracturing jobs 313

Woodford Shale Class II injection wells Commercial Disposal into multiple confining formations 314

Land Application Permit required through the Oklahoma Corporation Commission 315

Recycling Non

- commercial Water recycling and storage facilities at a central location 316

Antrim Shale Class II injection wells Commercial and non

commercial

New Albany Shale Class II injection wells Commercial and non

commercialMODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

70 New water treatment technologies and new applications of existing technologies are being developed and used to treat shale gas produced water. The treated water can be reused as fracturing make

- up water , irrigation water, and in some cases even drinking water. Recy c ling or re

use of produced water can decre a se water demands and provide additional water resources for drought

- stricken or arid areas . This allows natural gas

- associated produced water to be viewed as a potential resource in its own right 317

, 318

. In one case

, Devon E nergy Corporation (Devon) is currently using water distillation units at centralized locations within the Barnett Shale play to

treat produced water from hydraulic fracture stimulations 319 . As of early 2008, Devon had hydraulically fractured 50 wells using recycled water. Devon reports that the program is still in its testing and development stages. With further development, such specialized tr eatment systems may prove beneficial, particularly in more mature plays such as the Barnett; however, their practicality may be limited in emerging shale gas plays. Current levels of interest in recycling and reuse are high, but new approaches and more ef ficient technologies are needed to make treatment
and re

- use a wide

- spread reality.

While challenges still exist, progress is being made. New technologies and new variations on old
technol og ies are being introduced on a regular basis , and some industry re searchers are pursuing ways to reduce the amount of treatment needed. In early 2009 , studies were underway to determine the minimum quality of water that could successfully be used in hydraulic fracturing. If hydraulic fracturing procedures or fluid addi tives can be developed that will allow use of water with a high TDS content, then more treatment options become viable and more water can be re

used. Treatment and re

- use of produced water could reduce water withdrawal needs as well as the
need for additi onal disposal options. This approach could also help to resolve many of the concerns
associated with these withdrawals.



### Naturally Occurring Radioactive Material (NORM)

Some soils and geologic formations contain low levels of radioactive material. This na turally occurring radioactive material (NORM) emits low levels of radiation, to which everyone is exposed on a daily basis . Radiation from natural sources is also called background radiation. Other sources of background radiation include radiation from s pace and sources that occur naturally in the human body. This background radiation accounts for about 50% of the total exposure for Americans. Most of this background exposure is from radon gas encountered in homes (35% of the total exposure). The avera ge person in the U.S. is exposed to about 360 millirem (mrem) of radiation from natural sources each year (a mrem, or one one

- thousandth of a rem, is a measure of radiation exposure) 320

. The other 50% of exposures for Americans comes primarily from medical sources. Consumer products, industrial, and occupational sources contribute less than 3% of the total exposure 321

.
In addition to the background radiation at the earth’s surface, NORM can also be brought to the surface in the natural gas production process

. When NORM is associated with oil and natural gas production, it begins as small amounts of uranium and thorium within the rock. These elements, along with some of their decay elements, notably radium 226 and radium 228 322 , can be brought to the
surface in drill cuttings and produced water. Radon 222 , a gaseous decay element of radium, can come to the surface along with the shale gas

.MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

71 When NORM is brought to the surface, it remains in the rock pieces of the drill cuttings, remains in solution with produced w ater
, or, under certain conditions, precipitates out in scales or sludges 323

. The radiation from this NORM is weak and cannot penetrate dense materials such as the steel used in pipes and tanks 324

.
The principal concern for NORM in the oil and gas industry i s that, over time, it can become
concentrated in field production equipment 325 and as sludge or sediment inside tanks and process vessels that have an extended history of contact with formation water 326

. Because the general public does not come into contact w ith oilfield equipment for extended periods, there is little exposure risk from oilfield NORM. Studies have shown that exposure risks for workers and the public are low for conventional oil and gas operations 327

, 328

.
If measured NORM levels exceed state regulatory levels or OSHA exposure dose risks (29 CFR 1910.1096), the material is taken to licensed facilities for proper disposal. In all cases, OSHA requires employers to evaluate radiation hazards, post caution sign s and provide personal protection equipment for workers when radiation doses could exceed 5 mrem in one hour or 100 mrem in any five consecutive days. In addition to these f ederal worker protections, s tates have regulations that require operators to prote ct the safety and health of both workers and the public.

Currently there are no existing federal regulations that specifically address the handling and disposal of NORM wastes d

. Instead, states producing oil and gas are responsible for promulgating
and a dministering regulations to control the re

- use and disposal of NORM

- contaminated equipment

, produced water , and oil

- field wastes . Although regulations vary by state, in general, if
NORM concentrations are less than regulatory standards , operators are allowed to dispose of the material by methods approved for standard oilfield waste

. Conversely, if NORM concentrations are above regulatory limits , then the material must be disposed of at a licensed facility.

These regulations, standards , and practices ensure that oil and gas operations present negligible risk to the general public with respect to potential NORM exposure. They also present negligible risk to workers when proper controls are implemented 329

. 

### Air Quality
Many of today’s air quality rules were primarily designed to regulate emissions from single sources
with large volumes of emissions output such as refineries, chemical plants, iron and steel manufacturing facilities, and electrical power generating si tes. However, small er so urces such as individual shale gas well sites are also subject to state and federal regulations. Shale gas exploration and production operations are similar to most other conventional and unconventional natural gas exploration and production operations in terms of their air emissions. However, varying gas composition and the fact that there is little or no associated oil production affects the nature of potential emissions.

d EPA does have drinking water standards for NORM.MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

72 Sources of Air Emissions The exploration and production of shale gas may include a variety of potential air emission sources that change depending on the phase of operation. In the early phases of operation, emissions may come from such sources as drilling rigs whose engines may be fueled by either diesel or natural gas
and from fract uring operations where multiple diesel

- powered pumps are often used to achieve the

necessary pressure. Other sources may include the well completion process, which may involve the venting or flaring of some natural gas

, and vehicular traffic with engine e xhaust and dust from unpaved roads.

Once production has begun, emission sources may include compressors or pumps that may be needed to bring the produced gas up to the surface or up to pipeline pressure. Fugitive emissions such as leaks from pipe connections and associated equipment may also occur. Piping and pumping equipment may include pneumatic instrument systems, which, as part of their normal operations,
release or bleed small amounts of natural ga s in to the atmosphere. Other sources of emissions in this phase of operations include flaring or blow down of gas in non

- routine situations, dehydration units to remove water from the produced gas, and sulfur removal systems that may include flares and/or amine units.

Composition of Air Emissions

EPA set s standards, monitors the ambient air across the U.S., and has an active enforcement program to control air emissions from all sources

, including the shale gas industry. Although natural gas offers a number of environmental benefits over other sources of energy, particularly other fossil fuels, some air emissions commonly occur during exploration and production
activities 330 . These emissions and their sources ar e discussed below.

As in any construction or industrial activity, NO x are formed when fossil fuel is burned to provide power to machinery such as compres sor engines and during flaring operations. In addition, VOCs may be emitted during the dehydration of natural gas. VOC emissions are typically lower in natural gas activities than those associated with oil production because gas production is essentially a closed process from well to pipeline with fewer opportunities for emissions. In addition, emissions of benzene, toluene, ethylbenzene, and xylenes are low simply because these compounds do not
exist in significant quantities in the natural gas

stream. The oil and gas industry in general is a
lesser contributor to air
emissions than numerous other common sources (see
Exhibit 40 331 ). Further, oil and natural gas production contributes only 2% of the
total benzene emissions in the U.S. 332

, and shale gas 

### E XHIBIT 

### 40 : VOC E MISSIONS BY 

### S OURCE 

### C ATEGORYMODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

73 represents a very small subset of this 2%

.
Particulate Matter (PM) may occur from dust or soil entering the air during pad construction, traffic on access roads, and diesel
exhaust from vehicles and engines. In addition, CO may be emitted during flaring a nd from the incomplete combustion of
carbon

- based fuels used in engines. Flaring is seldom necessary with natural gas operations except during short periods of well testing, completions or workovers and

non

- routine situations such as a temporary pipeline closure.
Exhibit 4 2 333 shows that CO emissions from the natural gas industry represent a very small part of
the total 334

.

SO 2 may form when fossil fuels containing sulfur are burned. Thus, SO 2 may be emitted from gasoline or diesel powered equipment used at a shale gas production site. However, emissions of
SO 2 are typically very small for shale gas operations compared to coal or oil 335

.
Ozone (O 3 ) itself is not released directly during natural gas development, but two of its main

precursors, volatile organic compounds ( VOCs ) and NO x , may combine with sunlight to form ground

- level O 3 which can
then be associated with exploration and production operations.

Hydrogen sulfide ( H 2 S )
emissions are not a concern in shale gas production as , based on
discussions with operators from each of the major basins, the shale gas plays developed to date have not produced “sour” gas. If H 2 S is encountered as production continues, both

state s and operators are well equipped to 

### E XHIBIT 

### 42 : CO E MISSIONS BY 

### S OURCE 

### C ATEG ORY 

### E XHIBIT 

### 41: B ENZENE 

### E MISSIONS BY 

### S OURCE



### - 1999MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

74 implement appropriate safety measures. States have well

- established public safety and worker protection requirements in place and operators have access to proven procedures for working with natural gas contaminated with H 2 S

.

The American Petroleum Institute (API) has a Recommended Practice (RP 49) for Dril ling and Well Servicing Operations Involving H 2 S 336 . Producers voluntarily follow this practice to minimize the release of and exposure to H 2 S. In areas where concentrations of H 2 S may exceed 10 parts per million ( ppm ), producers implement an H 2 S contingen cy plan . The plan includes a ppropriate instruction in the use of hydrogen sulfide safety equipment to all personnel present at al l hydrogen sulfide hazard areas, g as detection w here hydrogen sulfide may exist, and a ppropriate respiratory protection for no rmal and emergency use.

Methane ( CH 4 ) is the principal component of natural gas and a known GHG . Although the processing of natural gas is essentially confined from the well to sales, CH 4 may be released as a fugitive emission from gas processing equipment, especially equipment in high pressure service such as pneumatic controls. P roducers have strong economic incentives to limit fugitive methane
emissions to the greatest degree possible i n order to maximize delivery of methane to market. Therefore, they rely on multiple BMPs (e.g., low

- bleed gauges and valves, inspection and maintenance programs, infra

- red (IR) cameras, etc. 337 ) to reduce any potential energy loss.

Another potential source of emissions in natural gas fields are compressor engines. Many gas compressor engines are fueled by natural gas from the lease. Engine manufacturers are constantly improving their technology to reduce the amount of NO x emissions from their engines. One key has been the use of catalytic technologies to chemically convert NO x into inert compounds. The addition of catalytic emissions controls has successfully lowered engine emissions from 20 grams per horsepower hour down to 2 grams of NO x per horsepower hour or less. Also, the addition of
air

- fuel ratio controllers can be used to ensure the continuous low emissions performance of these engines. Recent EPA regulations require new engines to meet more stringent low NO x emissions standards regardless of en gine size or fuel.

Technological Controls and Practices The best way to reduce air pollution is to prevent it from occurring in the first place. Pollution prevention can take many forms

— u pgrading equipment, improving operational practices, reducing

waste through byproduct synergies, improving management practices, and installing emissions controls. Several government programs have been established that encompass avoidance, minimization, and mitigation strategies applicable to exploration and production a ctivities. Some are mandatory regulations, as described in the Regulatory Framework section , while others are voluntary.

An example of the latter is the Natural Gas STAR program, a voluntary partnership between the EPA and the natural gas industry formed in 1995 to find cost

- effective ways to ensure the natural gas industry is doing everything possible to prevent energy losses and to minimize GHG emissions 338

. The primary goals of the program are to promote technology transfer and implement cost

- effective BMPs while reducing CH 4 emissions. The program provides information on many practices that not only reduce CH 4 emissions, but also works to retain greater volumes of natural gas for producers to
sell.MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

75 Some of the most effective and economic technologies promoted by this program include:

1. Identif

ication of high

- bleed pneumatic devices (transducers, valves, controllers, etc.) and replac ement with low

- bleed ones to reduce fugitive product losses. Traditional pneumatic devices control processes by measuring changes in pressure, releasing small quantities of natural gas in the process. Newer devices are now available that perform the same func tions while releasing much small er amounts of gas.

2. Use of IR cameras in the field to visually identify any fugitive hydrocarbon leaks so that they may be rapidly repaired to reduce potential energy losses. These cameras are tuned to the wavelengths that a re reflected by hydrocarbon gases , so that those normally

- invisible gases actually become visible as “smoke” in the camera image, thus allowing companies to quickly detect and repair leaks.

3. Installation of flash tank separators in situations that require t he use of dehydrators. This can recover 90 to 99% of the methane that would otherwise be flared or vented in to the atmosphere 339

.
4. Perform ance of green well completions and workovers. These shale gas operations typically use portable equipment to process an d direct the produced natural gas into tanks or directly into the pipeline rather than the traditional practice of venting or flaring the gas. On average, green completions recover 53% of the natural gas that would otherwise have been flared or vented. T hat captured gas is now retained and sold to market 340

. Many other pollution reduction technologies and practices are described on EPA ’s GasSTAR web site. In 2004, the Methane to Markets Partnership was formed as a voluntary international program aimed at a dvancing the recovery and use of methane as a valuable clean energy source 341

. The program includes the oil and gas sector as a focus area along with coal mines, landfills, and the agricultural business. T here are approximately 400 program members across t he globe representing the oil and gas sector 342 . The collective results of these voluntary programs have been
substantial. Total U.S. methane emissions in 2005 were over 11% lower than emissions in 1990, in spite of economic growth over that same time peri od 343

. EPA expects that these emissions will continue to fall in the future due to expanded industry participation and the ongoing commitment of the participating companies to identify and implement cost

- effective technologies and practices.

Additional tech nologies and practices have been identified that may be used in some settings to
reduce air emissions in shale gas fields. One such practice is the use of natural gas instead of diesel to fuel drilling rigs. Another emission

- reducing practice applicable to some settings is the use of centralized processing facilities ; this reduces vehicle trips, and therefore engine exhaust and dust emissions. Operators have also found that reducing glycol pump rates on dehydration units from their maximum setting to an optimized pump rate will minimize benzene

, t oluene, e thylbenzene,
and t otal x ylenes ( BTEX ) emissions. These units are often operated at a rate (based on at or near maximum throughput) that accommodates the initial, high rate of gas production from a field. However, as production rates decline, the dehydration units can be adjusted to conform to the lower gas throughput and reduce emissions. Other emission

- reducing technologies include the installation of plunger lift systems into shale gas well heads to optimize gas production and reduce methane emissions associated with blowdown operations a s well as the optimiz ation ofMODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

76 compressor and pump sizes to reduce the necessary horsepower and thus the subsequent exhaust
emissions.

A s with all oper ational practices, these BMPs must be applied on a case

- by case basis. In some cases a given BMP may actu ally be counter

- productive . In other cases, a particular BMP may create other environmental or operational problems that must be weighed against each other. While each
BMP has certain benefits in certain situations, it cannot be universally applied or re quired.

S tate and federal requirements along with the technologies and practices developed by industry
serve to limit air emissions from shale gas operations. As described earlier, state and federal requirements ensure that local conditions and other emis sion sources in the area are considered in issuing permits. In addition, advanced technologies and current practices serve to limit air emissions from modern shale gas development.



### Summary
The primary differences between modern shale gas development and c onventional natural gas development are the extensive use of horizontal drilling and multi

- stage hydraulic fracturing. Horizontal drilling allows an area to be developed with substantially fewer wells than would be
needed if vertical wells were used. The overall process of horizontal drilling varies little from conventional drilling, with casing and cementing being used to protect fresh and treatable groundwater. The use of horizontal drilling has not introduced new environmental concerns. On
the contra ry, the reduced number of horizontal wells needed, coupled with multiple wells drilled from a single pad, has significantly reduced surface disturbances and the associated impacts to wildlife and impacts from dust , noise, and traffic. Where shale gas de velopment has intersected with urban and industrial settings, regulators and industry have developed special practices to help reduce community impacts, impacts to sensitive environmental resources, and interference with existing businesses.

Hydraulic fr acturing has been a key technology in making shale gas an affordable addition to the Nation’s energy supply, and the technology has proven to be a safe and effective stimulation technique. Ground water is protected during the shale gas fracturing process by a combination of the casing and cement that is installed when the well is drilled and the thousand s of feet of rock between the fracture zone and any fresh or treatable aquifers. The multi

- stage hydraulic fracture operations used in horizontal wells ma y require 3 to 4 million gallons of water. Since it is a relatively new use in these areas, withdrawals for hydraulic fracturing must be balanced with existing water demands. Once the fracture treatment is completed, most of the fracture water
comes back to the surface and must be managed in a way that conserves and protects water resources. While challenges continue to exist with water availability and water management, innovative regional solutions are emerging that allow shale gas development to conti nue while ensuring that the water needs of other users can be met and that surface and ground water quality is protected.

An additional consideration in shale gas development is the potential for low levels of naturally

occurr ing radioactive material (NOR M) to be brought to the surface. While NORM may be encountered in shale gas operations, there is negligible exposure risk for the general public and there are well established regulatory programs that ensure public and worker safetyMODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

77 Although the use of na tural gas offers a number of environmental benefits over other fossil energy

sources , some air emissions commonly occur during exploration and production activities. EPA sets standards, monitors the ambient air quality across the U.S., and has an active e nforcement program to control air emissions from all sources, including the shale gas industry. Gas field emissions are controlled and minimized through a combination of government regulation and voluntary avoidance, minimization, and mitigation strategie s.

Taken together, state and federal requirements, along with the technologies and practices developed by industry, serve to protect human health and to help reduce environmental impacts from shale gas operations.MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER



## THIS PAGE INTENTIONALLY LEFT BLANKMODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

79 

## ACRONYMS AND ABBREVI ATIONS

API American Petroleum Institute
bbls barrels, petroleum (42 gallons)

bcf billion cubic feet

BLM Bureau of Land Management

BMP Best Management Practices

Btu British thermal units

CAA Clean Air Act

CBNG Coal Bed Natural Gas CEQ Council on Environmental Quality

CFR Code of Federal Regulations

CERCLA Comprehensive Environmental Response, Compensation, and Liability Act

CH 4 Methane

CO Carbon Monoxide

CO 2 Carbon Dioxide

CWA Clean Water Act

DRBC Delaware River Basin Commission

EIA Energy Information Administration

ELG Effluent Limitation Guidelines

EPA Environmental Protection Agency

EPCRA Emergency Plan ning and Community Right

- to

- Know Act

FR Federal Register
ft foot/feet

FWS Fish and Wildlife Service gal gallon

GHG Greenhouse Gases

GWPC Ground Water Protection Council

H 2 S Hydrogen Sulfide

HAP Hazardous Air Pollutant

HCl Hydrochloric acid

IOGCC Intersta te Oil and Gas Compact Commission

IR infra

- red
Mcf thousand cubic feet
MMcf million cubic feet

mrem millirem mrem/yr millirem per year

MSDSs Material Safety Data Sheets

NEPA National Environmental Policy Act

NESHAPs National Emission Standards for Hazardous Air Pollutants

NETL National Energy Technology LaboratoryMODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

80 NORM Naturally Occurring Radioactive Material

NO x Nitrogen Oxides

NPDES National Pollution Discharge Elimination System

NYDEC New York State Department of Environmental Conservation

O 3 O zone
OPA Oil Pollution Act

OSHA Occupational Safety and Health Administration

PM Particulate Matter

ppm parts per million

RAPPS Reasonable and Prudent Practices for Stabilization

RCRA Resource Conservation and Recovery Act

RP Recommended Practice RQ R eportable Quantity

SARA Superfund Amendments and Reauthorization Act

SCF standard cubic feet

SDWA Safe Drinking Water Act

SO 2 Sulfur Dioxide

SPCC Spill Prevention, Control and Countermeasures

SRBC Susquehanna River Basin Commission

STRONGER State Review of Oil and Natural Gas Environmental Regulation, Inc.

SWDA Solid Waste Disposal Act
tcf trillion cubic feet

TDS Total Dissolved Solids
tpy tons per year
TRI Toxics Release Inventory

UIC Underground Injection Control

U.S. United States

U.S.C. United States Code

USDW Underground Source of Drinking Water

USGS United States Geological Survey

VOC Volatile Organic Compound WQA Water Quality Act

yr yearMODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

81 

## DEFINITIONS

AIR QUALITY. A measure of the amount of pollutants emitted into the atmosphere and the
di spersion potential of an area to dilute those pollutants.

AQUIFER. A body of rock that is sufficiently permeable to conduct groundwater and to yield economically significant quantities of water to wells and springs.

BASIN. A closed geologic structure in which the beds dip toward a central location; the youngest rocks are at the center of a basin and are partly or completely ringed by progressively older rocks.

BIOGENIC GAS. Natural gas produced by living organisms or biological processes.

CASING. Steel piping positioned in a wellbore and cemented in place to prevent the soil or rock from caving in. It also serves to isolate fluids, such as water, gas, and oil, from the surrounding geologic formations.

COAL BED METHANE/NATURAL GAS (CBM/CBNG). A clean

- b urning natural gas found deep
inside and around coal seams. The gas has an affinity to coal and is held in place by pressure from groundwater. CBNG is produced by drilling a wellbore into the coal seam(s), pumping out large volumes of groundwater to redu ce the hydrostatic pressure, allowing the gas to dissociate from the
coal and flow to the surface.

COMPLETION

. The activities and methods to prepare a well for production and following drilling. Includes installation of equipment for production from a ga s well.

CORRIDOR. A strip of land through which one or more existing or potential utilities may be co

located.

DISPOSAL WELL. A well which injects produced water into an underground formation for disposal.

DIRECTIONAL DRILLING. The technique of drilling at an angle from a surface location to reach a target formation not located directly underneath the well pad.

DRILL RIG. The mast, draw works, and attendant surface equipment of a drilling or workover unit.

EMISSION. Air pollution discharge into the atmosphere, usually specified by mass per unit time.

ENDANGERED SPECIES. Those species of plants or animals classified by the Secretary of the Interior or the Secretary of Commerce as endangered pursuant to Section 4 of the Endangered Species Act of 1973, as amended. See also Threatened and Endangered Species

.

EXPLORATION. The process of identifying a potential subsurface geologic target formation and the active drilling of a borehole designed to assess the natural gas or oil.

FLOW LINE. A small diamet er pipeline that generally connects a well to the initial processing facility.MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

82 FORMATION (GEOLOGIC). A rock body distinguishable from other rock bodies and useful for mapping or description. Formations may be combined into groups or subdivided into members.

FRACTURING FLUIDS. A mixture of water and additives used to hydraulically induce cracks in the target formation.

GROUND WATER. Subsurface water that is in the zone of saturation ; s ource of water for wells, seepage, and springs

. The top surface of the groundwater is the “water table.”

HABITAT. The area in which a particular species lives. In wildlife management, the major elements of a habitat are considered to be food, water, cover, b reeding space, and living space.

HORIZONTAL DRILLING. A drilling procedure in which the wellbore is drilled vertically to a kick

off depth above the target formation and then angled through a wide 90 degree arc such that the producing portion of the well extends horizontally through the target formation.

HYDRAULIC FRACTURING. Injecting fracturing fluids into the target formation at a force exceeding the parting pressure of the rock thus inducing a network of fractures through which oil or natural gas can flow to the wellbore.

HYDROSTATIC PRESSURE. The pressure exerted by a fluid at rest due to its inherent physical properties and the amount of pressure being exerted on it from outside forces.

INJECTION WELL. A well used to inject fluids into an undergro und formation either for enhanced recovery or disposal.

LEASE

. A legal document that conveys to an operator the right to drill for oil and gas. Also, t he tract of land, on which a lease has been obtained, where producing wells and production equipment

ar e located.

NORM ( Naturally Occurring Radioactive Material ). L ow

- level, radioactive material that naturally exists in native materials.

ORIGINAL GAS

- IN

- PLACE T he entire volume of gas contained in the reservoir, regardless of the ability to produce it.

PARTICULATE MATTER (PM)

. A small particle of solid or liquid matter (e.g., soot, dust, and mist).
PM 10 refers to particulate matter having a size diameter of less than 10 millionths of a meter (micro

meter) and PM 2.5 being less than 2.5 micro

- meters in diameter.

PERMEABILITY. A rock’s capacity to transmit a fluid ; d ependent upon the size and shape of pores and interconnecting pore throats. A rock may have significant porosity (many microscopic pores) but have low permeability if the pores are not inter connected. Permeability may also exist or be enhanced through fractures that connect the pores.

PRIMACY. A right that can be granted to state by the federal government that allows state agencies

to implement programs with federal oversight. Usually, the states develop their own set of regulations. By statute, states may adopt their own standards, however, these must be at least as protective as the federal standards they replace , and may be even more protective in order toMODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

83 address local conditions. Onc e these state programs are approved by the relev ant federal agency (usually the EPA ), the state then has primacy jurisdiction.

PRODUCED WATER. Water produced from oil and gas wells.

PROPPING AGENTS /PROPPANT

. Silica sand or other particles pumped into a f ormation during a hydraulic fracturing operation to keep fractures open and maintain permeability.

PROVED RESERVES That portion of recoverable resources that is demonstrated by actual production or conclusive formation tests to be technically, economicall y, and legally producible under existing economic and operating conditions.

RECLAMATION. Rehabilitation of a disturbed area to make it acceptable for designated uses. This normally involves regrading, replacement of topsoil, re

- vegetation , and other work necessary to
restore it.

SET

- BACK. The distance that must be maintained between a well or other specified equipment and any protected structure or feature.

SHALE GAS. Natural gas produced from low permeability shale formations.

SLICKWATER. A water ba sed fluid mixed with friction reducing agents, commonly potassium
chloride.

SOLID WASTE. Any solid, semi

- solid, liquid, or contained gaseous material that is intended for disposal.

SPLIT ESTATE. Condition that exists when the surface rights and mineral r ights of a given area are owned by different persons or entities ; a lso referred to as “severed estate”.

STIMULATION. Any of several processes used to enhance near wellbore permeability and reservoir permeability.

STIPULATION. A condition or requirement attached to a lease or contract, usually dealing with protection of the environment, or recovery of a mineral.

SULFUR DIOXIDE (SO 2 ). A colorless gas formed when sulfur oxidizes, often as a result of burning
trace amounts of sulfur in fossil fuels.

TECHNIC ALLY RECOVERABLE RES OURCES The total amount of resource, discovered and undiscovered, that is thought to be recoverable with available technology, regardless of economics.

THERMOGENIC GAS. Natural gas that is formed by the combined forces of high pressu re and temperature (both from deep burial within the earth’s crust)

, resulting in the natural cracking of the organic matter in the source rock matrix.

THREATENED AND ENDANGERED SPECIES. Plant or animal species that have been designated as being in dange r of extinction. See also Endangered Species.MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

84 TIGHT GAS. Natural gas trapped in a hardrock, sandstone or limestone formation that is relatively impermeable.

TOTAL DISSOLVED SOLIDS (TDS)

. The dry weight of dissolved material, organic and inorganic, contained in water and usually expressed in parts per million.

UNDERGROUND INJECTION CONTROL PROGRAM (UIC)

. A program administered by the Environmental Protection Agency, primacy s tate, or Indian t ribe under the Safe Drinking Water Act
to ensure that subs urface emplacement of fluids does not endanger underground sources of drinking water.

UNDERGROUND SOURCE OF DRINKING WATER (USDW)

. 40 CFR Section 144.3 A n aquifer or its portion:

(a) (1) Which supplies any public water system; or

(2) Which contains a suf ficient quantity of ground water to supply a public water system;
and

(i) Currently supplies drinking water for human consumption; or

(ii) Contains fewer than 10,000 mg/l total dissolved solids; and

(b) Which is not an exempted aquifer.

WATER QUALITY. The chemical, physical, and biological characteristics of water with respect to its suitability for a particular use.

WATERSHED. All lands which are enclosed by a continuous hydrologic drainage divide and lay upslope from a specified point on a stream.

WELL COMPLETION

. See C ompletion

.

WORKOVER. To perform one or more remedial operations on a producing or injection well to increase production. Deepening, plugging back, pulling, and resetting the liner are examples of workover operations.MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

83 

## ENDNOTES

1 EIA. 2008. Annual Energy Outlook 2 008 with Projections to 2030

. http://www.eia.doe.gov/oiaf/aeo/pdf/0383(2008).pdf . June 2008.

2 Ibid.

3 EIA

. 2007. Annual Energy Review 2007, Tables 4.1 and 4.2

. http://www.eia.doe.gov/emeu/aer/resource.html

. June 2008

.

4 EIA. 2009. U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2007 Annual Report

. http://www.eia.doe.gov/oil_gas/natural_gas/data_publications/crude_oil_natural_gas_reserves/cr.html . February 2009.

5 Navigant Consulting. 2008. North American Natural Gas Supply Assessment . Prepared for American Clean Skies Foundation. July 4, 2008.

6 EIA . 2007. Annual Energy Review 2007, Table 6.1

. http://www.eia.doe.gov/emeu/aer/natgas.html

. June 2008.

7 EIA. 2009. March 2009 Monthly Energy Review, Table 4.3. http://www.eia.doe.gov/emeu/mer/natgas.html

. March 2009.

8 EIA. 2008. Annual Energy Outlook 2008 with Projections to 2030

. http://www.eia.doe.gov/oiaf/aeo/pdf/0383(2008).pdf . June 2008.

9 EIA. 1999. Natural Gas 1998: Issues and Trends

. http://www.eia.doe.gov/pub/oil_gas/natural_gas/analysis_publications/natural_gas_1998_issues_trends/pdf/it98.pdf

. April 1999.

10 NaturalGas.org

. Electrical Generation Using Natural Gas

. http://www.naturalgas.org/overview/uses_eletrical.asp

. Accessed: September 2008.

11 EIA . 2007. Annual Energy Review 2007, Table 8.11b

. http://www.eia.doe.gov/emeu/aer/elect.html . June 2008.

12 EIA

. 2002 Manufacturing Energy Consumption Survey

. http://www.eia.doe.gov/emeu/mecs/mecs2002/data02/shelltabl es.html

. March 2005.

13 U.S. Bureau of Labor Statistics . 2007. Monthly Labor Review, November 2007. http://www.bls.gov/opub/mlr/2007/11/contents.htm

.

14 EIA. Natural Gas Basic Statistics. http://www.eia.doe.gov/basics/quickgas.html

. Accessed: September 2008.

15 Independent Petroleum Association of Mountain States (IPAMS). America’s Independent Natural Gas Producers. Producing Today ‟s Clean Energy, Ensuring Tomorrow‟s Innovation

. http://www.ipams.org/media/docs/Callupdraft10.pdf . Accessed: September 2008.

16 Ambrose, W

. A., E . C. Potter, & R

. Briceno. 2008. An Unconventional Future for Natural Gas in the United States. http://www.geotimes.org/feb08/article.html?id=feature_gas.html . February 2008.

17 EIA. 2008 Natural Gas Summary

. http://tonto.eia.doe.gov/dnav/ng/ng_sum_lsum_dcu_nus_a.htm . Accessed June 2008.

.

18 EIA. 2008. Annual Energy Outlook 2008 with Projections to 2030

. http://www.eia.doe.gov/oiaf/aeo/pdf/0383(2008).pdf

. June 2008.

19 EIA. 2007. International Energy Outlook 2007, Chapter 4: Natural Gas

. http://tonto.eia.doe.gov/FTPROOT/forecasting/0484(2007).pdf

. May 2007.

20 EIA. 1999. Natural Gas 1998: Issues and Trends

. ht tp://www.eia.doe.gov/pub/oil_gas/natural_gas/analysis_publications/natural_gas_1998_issues_trends/pdf/it98.pdf . April 1999.

21 I bid

.

22 NaturalGas.org. 2008. Natural Gas and the Environment

. http://www.naturalgas.org/environment/naturalgas.asp . Accessed: September 2008.

23 American Clean Skies Foundation. Natural Gas Myth vs. Fact

. www.CleanSkies.org . Accessed: September 2008.

24 EIA

. 2008. Greenhouse Gases, Climate Change, and Energy

. http://www.eia.doe.gov/bookshelf/brochures/greenhouse/Chapter1.htm . May 2008.

25 EIA. 2008. Annual Energy Outlook 2008 with Pr ojections to 2030

. http://www.eia.doe.gov/oiaf/aeo/pdf/0383(2008).pdf

. June 2008.MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

84 26 Independent Petroleum Association of Mountain States (IPAMS). America’s Independent Natural Gas Producer s. Producing Today‟s Clean Energy, Ensuring Tomorrow‟s Innovation

. http://www.ipams.org/media/docs/Callupdraft10.pdf . Accessed: September 20 08.

27 Public Lands Advocacy. 2008. Energy Insecurity

. Presentation at Public Lands Advocacy NEPA

- Permitting Seminar/2008 Annual Meeting. http://www.publiclandsadvocacy.org/presentations.htm . June 11, 2008.

28 American Clean Skies Foundation. U.S. Fuel Goals

. www.cleanskies.org . Accessed: September 2008.

29 Chemistry and Technology of Fuels and Oils. 2000. Volume 36, Number 2, pp 82

- 88. March 2000.

30 NaturalGas.org. Overview of Natural Gas . Background. www.naturalgas.org/overview/background.asp . Accessed: September 2008.

31 Ibid.

32 Ibid.

33 EIA. About U.S. Natural Gas Pipelines

– Transporting Natural Gas

. www.eia.doe.gov/pub/oil_gas/natural_gas/analysis_publications/ngpipeline . Accessed: September 2008.

34 EIA. Glossary

. www.eia.doe.gov/glossary/glossary_b.htm . Accessed: September 2008.

35 NaturalGas.org. Overview of Natural Gas. Background. www.naturalgas.org/overview/background.asp

. Accessed: September 2008.

36 Oklahoma Natural Gas Company. 2005. Rate Schedule 701. Compressed Natural Gas Service. Individual Metering. http://www.oneok.com/ong/pdf/rate_schedule/701.pdf . October 4, 2005.

37 NW Natural. Science Facts

. www.nwnatural.com/content_safety.asp?id=297 . Accessed: September 2008.

38 BP. 2008. Statistical Review of World Energy

– 2008. Natural Gas

. http://www.bp.com/subsection.do?categoryId=9023762&contentId=7044550 . Accessed: September 2008.

39 Navigant Consulting. 2008. North American Natural Gas Supply Asse ssment

. Prepared for American Clean Skies Foundation. July 4, 2008.

40 EIA. 2009. U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2007 Annual Report . Available online: http://www.eia.doe.gov/oil_gas/natural_gas/data_publications/crude_oil_natural_gas_reserves/cr.html . Accessed February 2009.

41 Will iams, P. 2008. American Clean Skies. A Vast Ocean of Natural Gas . p 44

- 50. Summer 2008.

42 EIA. 2008. Annual Energy Outlook 2008 with Projections to 2030

. http://www.eia.doe.gov/oiaf/aeo/pdf/0383(2008).pdf

. June 2008.

43 Navigant Consulting. 2008. North American Natural Gas Supply Assessment

. Prepared for American Clean Skies Foundation. July 4, 2008.

44 ALL Consulting modified from USGS and other sources . March 2009.

45 EIA. 2008. Is U.S. Natural Gas Production Increasing ? http://tonto.eia.doe.gov/energy_in_brief/natural_gas_production.cfm

. June 11, 2008.

46 American Clean Skies Foundation. 2008. Natural Gas Planet . Summer 2008

.

47 EIA. 2008. Is U.S. Natural Gas Production Increasing ? http://tonto.eia.doe.gov/energy_in_brief/natural_gas_prod uction.cfm

. June 11, 2008

48 Navigant Consulting. 2008. North American Natural Gas Supply Assessment . Prepared for American Clean Skies Foundation. July 4, 2008.

49 Ibid.

50 Ibid.

51 Ibid.

52 Ibid.

53 CERA

. The Shale Gale: The Implications for North American Natural Gas Pipeline Development. March 2009.MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

85 54 Independent Petroleum Association of Mountain States (IPAMS). America’s Independent Natural Gas Producers. Producing Today‟s Clean Energy, Ensuring Tomorrow‟s Innovation

. http://www.ipams.org/media/docs/Callupdraft10.pdf . Accessed: September 2008.

55 Harper, J. 2008. The Marcellus Shale

– An Old “New” Gas Reservoir in Pennsylvania . v 28, no 1. Published by the Bureau of Topographic and Geologic Survey, Pennsylvania Department of Conservation and Natural Resources. Pennsylvania Geology. Spring 2008.

56 Schlumberger . 2005. Shale Gas White Paper . 05

- OF299. Modified from: J. K., Frantz a nd V. Jochen

. Schlumberger Marketing Communications. October 2005.

57 NY DEC. 1992. Division of Mineral Resources. Final Generic Environmental Impact Statement on the Oil, Gas and Solution Mining Regulatory Program . 1992.

58 Harper, J. 2008. The Marcellus Shale

– An Old “New” Gas Reservo ir in Pennsylvania . v 28, no 1. Published by the Bureau of Topographic and Geologic Survey, Pennsylvania Department of Conservation and Natural Resources. Pennsylvania Geology. Spring 2008.

59 Ibid.

60 Engelder, T., and G. G. Lash. 2008. Marcellus Shale Play‟s Vast Resource Potential Creating Stir in Appalachia

. The American Oil & Gas Reporter. May 2008.

61 Williams, P. 2005. Big Sandy: Kentucky‟s Big Sandy Field Remains a Locus of Exploration Activity, More than 90 years after its Discovery . Oil an d Gas Investor. August 2005.

62 Harrison, W. 2006. Production History and Reservoir Characteristics of the Antrim Shale Gas Play

, Michigan Basin

. Western Michigan University. 2006.

63 Hayden, J., and D. Pursell, D. 2005. Pickering Energy Partners Inc. The Barnett Shale. Visitor‟s Guide to the Hottest Gas Play in the US. October 2005.

64 Ibid.

65 Halliburton Energy Services. 2008. U.S. Shale Gas: An Unconventional Resource

. Unconventional Challenges. 2008.

66 Hayden, J., and D. Pursell, D. 2005. Pickering Energy Partners Inc. The Barnett Shale. Visitor‟s Guide to the Hottest Gas Play in the US. October 2005.

67 Cohen, D. 2008. Energy Bulletin. An Unconventional Play in the Bakken

. April 2008.

68 USGS. Assessment of Undiscovered Oil Resources in the Devonian

- Mississippian Bakken Formation, Williston Basin Province, Montana and North Dakota

. USGS fact sheet 2008

- 3021.

69 Harper, J. 2008. The Marcellus Shale

– An Old “New” Gas Reservoir in Pennsylvania

. v 28, no 1. Published by the Bureau of Topographic and Geologic Survey, Pennsylvania Department of Conservation and Natural Resources. Pennsylvania Geology. Spring 2008.

70 Ameri, S., K. Aminian, J. A. Miller, D. Doricich, and A. B. Yost. A Systematic A pproach for Economic Development of the Devonian Shale Gas Resources

. SPE 14504.

71 Halliburton Energy Services. 2008. U.S. Shale Gas: An Unconventional Resource . Unconventional Challenges. 2008.

72 Airhart, M. Geology.com. The Barnett Shale Gas Boom: I gniting a Hunt for Unconventional Natural Gas Resources. http://geology.com/research/barnett

- shale

- gas.shtml . Accessed: September 2008.

73 Boyer, C., J. Kieschnick, R. Suarez

- Rivera, R. Lewis, and G. Walter. 2006. Schlumberger. Oilfield Review. Producing Gas from Its Source . Autumn 2006.

74 Schlumberger . 2005. Shale Gas White Paper . 05

- OF299. Modified from: J. K., Frantz a nd V. Jochen

. Schlumberger Marketing Communications. Octob er 2005.

75 Davis ,R., Jr. 1992. Depositional Systems: An Introduction to Sedimentology and Stratigraphy

. Prentice Hall. 2 nd Edition. 1992.

76 Freeze, R., and J. Cherry. 1979. Groundwater . Prentice Hall. 1979.

77 Nuttal, B.C. 2007. Kentucky Geologi cal Survey. Predicting Cumulative Production of Devonian Shale Gas Wells from Early Well Performance Data, Appalachian Basin of Eastern Kentucky. September 2007.MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

86 78 NaturalGas.org. Unconventional Natural Gas Resources

. Accessed: September 2008.

79 ALL Consulting and the Montana Board of Oil and Gas Conservation. 2004. Coal Bed Methane Primer: New Source of Natural Gas

– Environmental Implications . Prepared for the U.S. Department of Energy, National Petroleum Technology Office. February 2004.

80 Fra ntz, J.K., and Jochen, V. 2005. Schlumberger. Shale Gas White Paper . 05

- OF299. Schlumberger Marketing Communications. October 2005.

81 Geology.com. Marcellus Shale

- Appalachian Basin Natural Gas Play: New Research Results Surprise Everyone on the Potenti al of this Well

- known Devonian Black Shale

. http://geology.com/articles/marcellus

- shale.shtml

. Accessed: September 2008.

82 Hayden, J., and D. Pursell

. 2005. Pickering Energy Partners

, Inc. The Barnett Shale: Visitor‟s Guide to the Hottest Gas Play in the US . October 2005.

83 Halliburton Energy Services. 2008. U.S. Shale Gas: An Unconventional Resource

. Unc onventional Challenges. 2008.

84 Ibid.

85 Ibid.

86 Navigant Consulting. 2 008. North American Natural Gas Supply Assessment

. Prepared for American Clean Skies Foundation. July 4, 2008.

87 Hayden, J., and D. Pur sell. 2005. Pickering Energy Partners

, Inc. The Barnett Shale: Visitor‟s Guide to the Hottest Gas Play in the US. October 2005.

88 Ibid.

89 Ibid.

90 Ibid.

91 Boughal, K. 2008. Unconventional Plays Grow in Number After Barnett Shale Blazed the Way

. World Oil Magazine. v 229, no 8. August 2008.

92 Berman, A. 2008. The Haynesville Shale Sizzles with the Barnett Cools

. World Oil Magazine. v 229, no 9. September 2008.

93 Drilling Contractor. 2000. Alabama Lawsuit Poses Threat to Hydraulic Fracturing Across U.S. pp 42

- 43. January/February 2000.

94 Haines, L. 2006. Supplement to Oil & Gas Investor. Shale Gas: Activity Builds in the Woodford Shale

. p 17. http://www.oilandgasinvestor.com/pdf/ShaleGas.pdf . January 2006.

95 Hayden, J., and D. Pursell. 2005. Pickering Energy Partners

, Inc. The Bar nett Shale: Visitor‟s Guide to the Hottest Gas Play in the US . October 2005.

96 Ibid.

97 Arkansas Oil and Gas Commission. 2008. Field Rules and Rule B

- 15.

98 Hayden, J., and D. Pursell. 2005 . Pickering Energy Partners

, Inc. The Barnett Shale: Visitor‟s Guide to the Hottest Gas Play in the US. October 2005.

99 Ibid.

100 Berman, A. 2008. The Haynesville Shale Sizzles while the Barnett Cools

. World Oil Magazine. v 229, no 9. September 2008.

101 Nyahay, R., J. Leone, L. Smith, J. Martin, and D. Jarvie. 2007. Update on Regional Assessment of Gas Potential in the Devonian Marcellus and Ordovician Utica Shales of New York. http://www.searchandd iscovery.net/documents/2007/07101nyahay/index.htm . October 1, 2007.

102 Cardott, B. 2004. Oklahoma Geological Survey. Overview of Unconventional Energy Resources of Oklahoma

. http://www.ogs.ou.edu/fossilfuels/coalpdfs/UnconventionalPresentation.pdf . March 9, 2004.

103 Hayden, J., and D. Pursell. 2005. Pickering Energy Partners

, Inc. The Barnett Shale: Visitor‟s Guide to the Hottest Gas Play in the US. October 2005.

104 Ibid.MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

87 105 Ibid.

106 Ibid.

107 Berman, A. 2008. The Haynesville Shale Sizzles while the Barnett Cools

. World Oil Magazine. v 229, no 9. September 2008.

108 Soeder, D.J. 1986. Porosity and Permeability of Eastern Devonian Gas Shale

. SPE Formation Evaluati on. v 3, no 1. January 1, 1986.

109 Vulgamore, T., T. Clawson, C. Pope, S. Wolhart, M. Mayerhofer, S. Machovoe, and C. Waltman. 2007. Applying Hydraulic Fracture Diagnostics to Optimize Stimulations in the Woodford Shale . SPE 110029. 2007.

110 Hayden, J., and D. Pursell. 2005. Pickering Energy Partners

, Inc. The Barnett Shale: Visitor‟s Guide to the Hottest Gas Play in the US. October 2005.

111 Ibid.

112 Ibid.

113 Ibid.

114 Petroleum Listing Services. 2008. Other Players Reporting Haynesville Success . August 15, 2008.

115 Soeder, D.J

. 1986. Porosity and Permeability of Eastern Devonian Gas Shale . SPE Formation Evaluation. v 3, no 1. January 1, 1986.

116 Jochen, V. Schlumberger. 2006. New Technology Needs to Produce Unconventional Gas . Nove mber 29, 2006.

117 Hayden, J., and D. Pursell. 2005. Pickering Energy Partners

, Inc. The Barnett Shale: Visitor‟s Guide to the Hottest Gas Play in the US. October 2005.

118 Ibid.

119 Ibid.

120 Ibid.

121 Ibid.

122 Sumi, L. 2008. Oil and Gas Accountability Project (OGAP). Shale Gas: Focus on the Marcellus Shale

. http://www.earthworksaction.org/pubs/OGAPMarcellusShaleReport

- 6

- 12

- 08.pdf . May 2 008.

123 Ibid.

124 Ibid.

125 Hayden, J., and D. Pursell. 2005. Pickering Energy Partners

, Inc. The Barnett Shale: Visitor‟s Guide to the Hottest Gas Play in the US. October 2005.

126 Ibid.

127 Navigant Consulting. 2008. North American Natural Gas Supply Assessment

. Prepared for American Clean S kies Foundation. July 4, 2008.

128 Ibid.

129 Hayden, J., and D. Pursell. 2005. Pickering Energy Partners

, Inc. The Barnett Shale: Visitor‟s Guide to the Hottest Gas Play in the US. October 2005.

130 AAPG. 1987. Correlation of Stratigraphic Units of North America (CASUNA) Project

. Texas

- Oklahoma Tectonic Region. CSD No. 420, Col 9. 1987.

131 Modified from: Frantz, J.K., and V. Jochen

. 2005. Schlumberger. Shale Gas White Paper . 05

- OF299. Schlumberger Marketing Communications. October 2005.

132 Railroad Commission of Texas

. 2009. Newark, East (Barnett Shale) Field

. http://www.rrc.state.tx.us/data/fielddata/barnettshale.pdf . Accessed Marc h 2009.

133 Parshall, J. 2008. Barnett Shale Showcases Tight

- gas Development

. Journal of Petroleum Technology. September 19, 2008.

134 Halliburton Energy Services. 2008. U.S. Shale Gas: An Unconventional Resource . Unconventional Challenges. 2008.MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

88 135 Modified from: Frantz, J.K., and V. Jochen

. 2005. Schlumberger. Shale Gas White Paper . 05

- OF299. Schlumberger Marketing Communications. October 2005.

136 University of Arkansas. 2008. Projecting the Economic Impact of the Fayetteville Shale Play for 2008

- 2012. Sam M. Walton College of Business. March 2008.

137 Boughal, K. 2008. Unconventional Plays Grow in Number After Barnett Shale Blazed the Way

. World Oil Magazine. v 229

, no 8. August 2008.

138 Ibid.

139 Williams, P. 2008 . American Clean Skies. A Vast Ocean of Natural Gas . p 44

- 50. Summer 2008.

140 Hillwood International Energy. 2007. Fayetteville Shale Power

. Arkansas, USA. http://hillwoodenergy.com/Portals/0/Content/Fayetteville_Shale.pdf

. July 12, 2007.

141 Modified from: Frantz, J.K., and V. Jochen

. 2005. Schlumberger. Shale Gas White Paper . 05

- OF299. Schlumberger Marketing Communications. October 2005.

142 Durham, L. 2008. Louisiana Play a „Company Maker? AAPG Explorer. July 2008.

143 Johnston, J.

, III, P. Heinrich, J. Lovelace, R. McCulloh, and R. Zimmerman. Louisiana Geological Survey. Stratigraphic Charts of Louisiana . Folio series no 8. 2000.

144 Modified from: USGS. Energy Resources Program. National Oil and Gas Assessment. http://certmapper.cr.usgs.gov/noga/broker.jsp?theServlet=NogaNewGIS ResultsServ&theProvince=67&thePage=play

. Accessed: September 2008.

145 West Virginia Geological and Economic Survey. 1997. Enhancement of the Appalachian Basin Devonian Shale Resource Base in the GRI Hydrocarbon Model . Prepared for: Gas Research Institu te. December 1997.

146 Harper, J. 2008. Published by the Bureau of Topographic and Geologic Survey, Pennsylvania Department of Conservation and Natural Resources. Pennsylvania Geology. The Marcellus Shale

– An Old “New” Gas Reservoir in Pennsylvania

. v 28, no 1. Spring 2008.

147 Ibid.

148 Arthur, J.D., B. Bohm, and M. Layne. 2008. ALL Consulting. Hydraulic Fractur ing Considerations for Natural Gas Wells of the Marcellus Shale . Presented at the GWPC Annual Forum in Cincinnati, OH. September 2008.

149 Modified from: Frantz, J.K., and V. Jochen

. 2005. Schlumberger. Shale Gas White Paper . 05

- OF299. Schlumberger Marketing Communications. October 2005.

150 Cardott, B. 2007. Oklahoma Geological Survey. Overview of Woodford Gas

- Shale Play in Oklahoma

. 2007.

151 Boughal, K. 2008. Unconventional Plays Grow in Number After Barnett Shale Blazed the Way . World Oil Magazine. v 229, no 8. August 2008.

152 Cardott, B. 2007. Oklahoma Geological Survey

. Overview of Woodford Gas

- Shale Play in Oklahoma

. 2007.

153 AAPG. 1983. Correlation of Stratigraphic Units of North America (CASUNA) Project. Southwest/Southwest Mid

- Continent Region. CSD No. 360, Col 27. 1983.

154 Modified from: Frantz, J.K., and V. Jochen

. 2005. Schlumberger. Shale Gas White Paper

. 05

- OF299. Schlumberger Marketing Communications. October 2005.

155 Harrison, W. 2006. Production History and Reservoir Characteristics of the Antrim Shale Gas Play, Michigan Basin

. Western Michigan University. 2006.

156 Hayden, J., and D. Pursell . 200 5

. Pickering Energy Partners

, Inc. The Barnett Shale: Visitor‟s Guide to the Hottest Gas Play in the US. October 2005.

157 Catacosinos, P., W. Harrison III, R. Reynolds, D. Westjohn, and M. Wollensak. 2000. Michigan Department of Environmental Quality (DEQ), Geological Survey Division, and Michigan Basin Geological Survey. Stratigraphic Nomenclature for Michigan. 2000.

158 Indiana Geological Survey. Indiana University. General Stratigraphic Column for Paleozoic Rocks in Indiana . Adapted from Shaver, H ., et al. 1986. Indiana Geological Survey Bulletin 59.MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

89 159 Illinois State Geological Survey. GeoNote 1. Mississipian Rocks in Illinois

. http://www.isgs.uiu c.edu/maps

- data

pub/publications/geonotes/pdf

- files/GeoNote1.pdf

.

160 Modified from: Frantz, J.K., and V. Jochen

. 2005. Schlumberger. Shale Gas White Paper . 05

- OF299. Schlumberger Marketing Communications. October 2005.

161 Hayden, J., and D. Pursell. 2005. Pickering Energy Partners

, Inc

. The Barnett Shale: Visitor‟s Guide to the Hottest Gas Play in the US . October 2005.

162 Interstate Oil and Gas Compact Commission (IOGCC). Issues: States‟ Rights

. http://www.iogcc.state.ok.us/states

- rights

. Accessed: September 2008.

163 State Review of Oil and Natural Gas Regulations (STRONGER). http://www.strongerinc.org

. Accessed: September 2008.

164 STRONGER. List of State Reviews

. http://www.strongerinc.org/reviews/reviews.asp

. Accessed: September 2008.

165 STRONGER. History of STRONGER

- Helping To Make An Experiment Work

. http://www.strongerinc.org/about/history.asp

. Accessed: September 2008.

166 Southlake, Texas, Gas Well Ordinance. Article IV. Gas and Oil Well Drilling and Production

.

167 Richard Hills, Texas, Gas Well Ordinance. Ordin ance No. 996

- 04. September 14, 2004.

168 Haltom City Ordinance No. 0

- 2004

- 026

- 15. November 22, 2004.

169 Fort Worth, Texas, Ordinance No. 16986

- 06

- 2006. June 21, 2006.

170 Susquehanna River Basin Commission. Regula tion of Projects . 18 CFR 801, 806, 807, and 808. http://srbc.net/policies/docs/srbc_regulation_of_projects.PDF

. Effective: February 20, 2007. Accessed: September 2008.

171 Delaware River Basin Commission Basin. Administ rative Manual Part III. Water Quality Regulations. 18 CFR PART 410. http://www.state.nj.us/drbc/regs/WQRegs_071608.pdf

. September 12, 2008.

172 33 U.S.C. section 1251 et. Seq.

173 EPA. Summary of the Clean Water Act

. http://www.epa.gov/lawsregs/laws/cwa.html

. Accessed: September 2008.

174 EPA. Water Quality and Technology

- Based Permitting

. http://cfpub.epa.gov/npdes/generalissues/watertechnology.cfm

. Accessed : September 2008.

175 EPA. Effluent Limitations Guidelines and Standards

. http://cfpub.epa.gov/npdes/techbasedpermitting/effguide.cfm

. Accessed: September 2008.

176 National Archives and Records Administration. Electronic Code of Federal Regulations. Protection of the Environment. Oil and G as Extraction Point Source Category . 40 CFR Part 435. http://ecfr.gpoaccess.gov/cgi/t/text/text

idx?c=ecfr&rgn=div5&view=text& node=40:29.0.1.1.11&idno=40

. Effective : June 12, 2006. Accessed: September 2008.

177 EPA. Final Rule: Amendments to the Storm Water Regulations for Discharges Associated with Oil and Gas Construction Activities

. http://www.epa.gov/npdes/regulations/final_oil_gas_factsheet.pdf

. Effective : June 12, 2006. Accessed: September 2008.

178 NRDC v. EPA

. 9 th Cir. p.5947. 2008.

179 EPA

. Final Rule: Amendments to the Storm Water Regulations for Discharges Associated with Oil and Gas Construction Activities

. http://www.epa.gov/npdes/regulations/final_oil_gas_factsheet.pdf

. Effective June 12, 2006. Acc essed: September 2008.

180 Independent Petroleum Association of America (IPAA). 2004. Guidance Document: Reasonable and Prudent Practices for Stabilization (RAPPS) Of Oil and Gas Construction Sites . Prepared by Horizon Environmental Services, Inc. Apri l 2004.

181 EPA. 2004. Understanding the Safe Drinking Water Act

. EPA 816

- F

- 04

- 030. http://www.epa.gov/safewater/sdwa/30th/factsheets/understand.html

. June 2004.

182 EPA. Drinking Water Academy (DWA). 2003. Introduction to the Underground Injection Control Program

. http://www.epa.gov/safewater/dwa/electronic/presentations/uic/uic.pdf

. Ja nuary 2003.

183 EPA. US EPA's Program to Regulate the Placement of Waste Water and other Fluids Underground

. EPA 816

- F

- 04

- 040. June 2004.MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

90 184 EPA. Underground Injection Control Program

. UIC Program Primacy

. http://www.epa.gov/OGWDW/uic/primacy.html#who

. Accessed: September 2008.

185 EPA. Region 9: Superfund. Oil Pro gram

. http://www.ep a.gov/region09/waste/sfund/oilpp/

. Accessed: September 2008.

186 Ibid.

187 EPA. Spill Prevention, Control, and Countermeasure (SPCC). Proposed Rule Amendments, Information about October 2007 proposed amendments to the SPCC Rule

. http://www.epa.gov/emergencies/content/spcc/index.htm

. Accessed: September 2008.

188 EPA. Water Quality Standards. State, Tribal & Territorial Standards

. http://www.epa.gov/waterscience/standards/wqslibrary/

. Accessed: September 2008.

189 SRBC. http://www.srbc.net/

. Accessed: September 2008.

190 DRBC. http://www.state.nj.us/drbc/

. Accessed: September 2008.

191 Clean Air Act. http://www.epa.gov/air/caa/

. Amended in: 1990. Accessed: September 2008.

192 EPA. The Green Book Nonattainment Areas for Criteria Pollutants

. http://www.epa.gov/oar/oaqps/greenbk/

. Accessed: September 2008.

193 EPA. Air Trends. Basic Information

. http://www.epa.gov /airtrends/sixpoll.html . Accessed: September 2008.

194 Texas Commission on Environmental Quality (TCEQ). Standard of Performance for New Stationary Sources, Spark Ignition Internal Combustion Engines . 40 CFR Part 60, Subpart JJJJ.

195 Texas Commission on E nvironmental Quality (TCEQ). National Emission Standard for Hazardous Air Pollutants for Stationary Reciprocating Internal Combustion Engines . 40 CFR Part 63, Subpart ZZZZ.

196 EPA. 2007. Final Emission Standards of Performance for Stationary Spark Ignit ion Internal Combustion Engines; and Final Air Toxics Standards for Reciprocating Internal Combustion Engines. http://www.epa.gov/ttn/oarpg/t3pfpr.html

. December 20, 2007.

197 EPA. Region2. Solid Waste; RCRA Subtitle D

. http://www.epa.gov/region2/waste/dsummary.htm

. Accessed: September 2008.

198 EPA. 2002. Exemption of Oil and Gas Exploration and Production Wastes from Federal Hazardous Waste Regulations

. http://epa.gov/epawaste/nonhaz/industrial/special/oil/oil

- gas.pdf

. October 2002.

199 Public Law 96

- 482, Sec. 1. Oct. 21, 1980. 94 Stat. 2334.

200 Federal Re gister Volume 58, Number 5. EPA. 1993. Clarification of the Regulatory Determination for Wastes From the Exploration, Development and Production of Crude Oil, Natural Gas and Geothermal Energy . pp 15284

– 15287. March 22, 1993.

201 Federal Register Volu me 53. EPA. 1988. Regulatory Determination for Oil and Gas and Geothermal Exploration, Development and Production Wastes . pp 25447

- 25458. July 6, 1988.

202 EPA. 2002. Exemption of Oil and Gas Exploration and Production Wastes from Federal Hazardous Waste Regulations

. http://epa.gov/epawaste/nonhaz/industrial/special/oil/oil

- gas.pdf

. October 2002.

203 EPA. 53 FR 25447. Regulatory Determination for Oil and Gas and Geother mal Exploration, Development and Production Wastes. http://epa.gov/osw/nonhaz/industrial/special/oil/og88wp.pdf

. Accessed: September 2008.

204 EPA. Laws, Regulations, Guidance and Dockets. Summary of the Oil Pollution Act . 33 U.S.C. Section 2702 et seq. (1990). http://www.epa.gov/lawsregs/laws/opa.html

. Accessed: September 2008.

205 STRONGER. Process Success and Breakdown

. http://www.strongerinc.org/about/success.asp

. Accessed: September 2008.

206 National Archives and Records Administrat ion. Electronic Code of Federal Regulations. Wildlife and Fisheries. Endangere d and Threatened Wildlife and Plants . 50 CFR Part 17. http://ecfr.gpoaccess.gov/cgi/t/text/text

idx?c=ecfr&tpl=/ecfrbrowse/Title50/50cfr17_main _02.tpl

. Accessed: September 2008.

207 Babbitt v. Sweet Home Chapter of Communities for a Great Oregon . 515 U.S. 687. 1995.

208 Christman, J., and V. A lbrecht

. Hunton and Williams

, LLP. http://library.findlaw.com/1999/Jan/1/241467.html

. 1999.

209 ALL Consulting. 2004. Coal Bed Natural Gas Handbook. Resources for the Preparation and Reviews of Project Planning Elements and Envi ronmental Documents. October 2004.MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

91 210 Construction Industry Compliance Assistance (CICA). The CICA Center

. http://www.cicacenter.org/index.cfm

. Accessed: September 2008.

211 Ibid

.

212 U.S. Fish & Wildlife Service (USFS). Endangered Species Program. Endangered Spec ies Related Laws, Regulatio ns, Policies & Notices. http://www.fws.gov/Endangered/policy/index.html

. Accessed: September 2008.

213 Ibid.

214 Construction Industry Compliance Assistance (CICA). Th e CICA Center

. http://www.cicacenter.org/index.cfm

. Accessed: September 2008.

215 ALL Consulting. 2002. Handbook on Best Management Practices and Mitigation Strategies for Coal Bed Methane in the Montana Portion of the Powder River Basin . 2002.

216 EPA. 1998. RCRA: Superfund & EPCRA Hotline Training Module . EPA 540

- R

- 98

- 022. June 1998.

217 IOGCC. 1996. Review of Existing Reporting Requirements for Oil and Gas Exploration and Prod uction Operators in Five Key States . 1996.

218 IPAA. 2000. Environment & Safety Fact Sheets. IPAA Opposes EPA's Possible Expansio n of TRI

. http://www.ipaa.org/issues/factshee ts/environment_safety/tri.asp

. May 2000.

219 U.S. Department of Labor. Occupational Safety & Health Administration. www.osha.gov

. Accessed: September 2008.

220 U.S. Department of Labor. Occupational Safety & Health Administration. Oil and Gas Well Drilling, Servicing and Storage Standards

. http://www.osha.gov/SLTC/oilgaswelldrilling/standards.html

. Accessed: September 2008.

221 Arkansas Oil an d Gas Commission. Mission Statement. http://www.aogc.state.ar.us/mission.pdf

. Accessed: Septe mber 2008.

222 Ohio Department of Natural Resources, Oil and Gas Division. Ohio Revised Code 1509.

223 ALL Consulting. 2004. Coal Bed Natural Gas Handbook. Resources for the Preparation and Reviews of Project Planning Elements and Environmental Documents . October 2004.

224 Bureau of Land Management (BLM). 2006. Scientific Inventory of Onshore Federal Lands‟ Oil and Gas Resources and the Extent and Nature of Restrictions or Impediments to Their Development . Prepared by the U.S. Departments of the Interior, Agriculture, and Energy. 2006.

225 Bonner, T., and L. Willer. 2005. National Association of Royalty Own ers, Inc (NARO). The New Generation. Royalty Management 101: Basics for Beginners and a Refresher Course for Everyone. 25 th Anniversary Convention in Oklahoma City, OK. November 3

- 5, 2005.

226 Lantz, G. 2008 .The Barnett Shale Magazine. Drilling Green Along Trinity Trails . Summer 2008.

227 Harper, J. 2008. The Marcellus Shale

– An Old “New” Gas Reservoir in Pennsylvania . Pennsylvania Geology. v 28, no 1. Spring 2008. Published by the Bureau of Topographic and Geologic Survey, Pennsylvania Department of Conservation and Natu ral Resources.

228 Frantz, J.K., and V. Jochen

. 2005. Schlumberger. Shale Gas White Paper . 05

- OF299. Schlumberger Marketing Communications. October 2005.

229 Halliburton Energy Services. 2008. U.S. Shale Gas: An Un conventional Resource . Unconventional Challenges. 2008.

230 Harper, J. 2008. The Marcellus Shale

– An Old “New” Gas Reservoir in Pennsylvania . Pennsylvania Geology. v 28, no 1. Spring 2008. Published by the Bureau of Topographic and Geologic Survey, P ennsylvania Department of Conservation and Natu ral Resources.

231 Halliburton Energy Services. 2008. U.S. Shale Gas: An Unconventional Resource . Unconventional Challenges. 2008.

232 Harper, J. 2008. The Marcellus Shale

– An Old “New” Gas Reservoir in P ennsylvania . Pennsylvania Geology. v 28, no 1. Spring 2008. Published by the Bureau of Topographic and Geologic Survey, Pennsylvania Department of Conservation and Natu ral Resources.

233 Ibid.

234 Marshall Miller & Ass ociates, Inc. Marcellus Shale

. Presented to: Fireside Pumpers in Bradford, PA.MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

92 235 Parshall, J. 2008. Barnett Shale Showcases Tight

- gas Development . Journal of Petroleum Technology. September 19, 2008.

236 U.S. Department of the Interior. 2008. Reasonably Fore seeable Development Scenario for Fluid Minerals: Arkansas. Prepared for the Bureau of Land Management Eastern States Jackson Field Office. March 2008.

237 Bromley, M. 1985. U.S. Department of Agriculture, Forest Service, Intermountain Research Station. Ogde n, Utah. Wildl ife Management Implications of Petroleum Exploration and Development in Wildland Environments . General Technical Report INT

- 199. 1985.

238 Catskill Mountainkeeper. The Marcellus Shale

– America's next super giant. http://catskillmountainkeeper.org/node/290

. Accessed: October 2008.

239 Venesky, T. 2008. State

- O wned Parcels Eyed for Gas Deposits

. The Times Leader. http://www.timesleader.com/news/hottopics/shale/20080304_01gas_wells_ART.html

. October 14, 2008. Accessed: September 2008.

240 United States Department of the Interi or and United States Department of Agriculture. 2007. Surface Operating Standard s and Guidelines for Oil and Gas Exploration and Development . BLM/WO/ST

- 06/021+3071/REV07. Bureau of Land Management. Denver, Colorado. 2007.

241 ALL Consulting. 2004. Co al Bed Natural Gas Handbook. Resources for the Preparation and Reviews of Project Planning Elements and Environmental Documents. October 2004.

242 The Perryman Group

. 2007. Bounty from Below: The Impact of Developing Natural Gas Resources Associated with the Barnett Shale on Business Activity in Fort Worth and the Surrounding 14

- County Area . May 2007.

243 Satterfield, J., M. Mantell, D. Kathol, F. Hiebert, K. Patterson, and R. Lee

. 2008. Chesapeake Energy Corp. Managing Water Resource‟s Challenges i n Select Natural Gas Shale Plays . Presented at the GWPC Annual Meeting. September 2008.

244 Dou glas, D. Anger over road damage caused by Barnett Shale development. http://www.wfaa.com/sharedcontent/dws/wfaa/latestnews/stories/wfaa080822_lj_douglas.18a895d.html

. Accessed: October 2008.

245 The Perryman Group

. 2007. Bounty from Below: The Impact of Developing Natural Gas Resources Associated with the Barnett Shale on Business Activity in Fort Worth and the Surrounding 14

- County Area . May 2007.

246 P arshall, J. 2008. Barnett Shale Showcases Tight

- gas Developme nt . Journal of Petroleum Technology. September 19, 2008.

247 Various City Ordinances including Arlington ON2006

- 015, Burleson B

- 710, Cleburne Chapter 118, Crowley Chapter 37, Fort Worth ON. 16986

- 06

- 2006, and Richland Hills, ON.996

- 04.

248 Ibid.

249 Chesapeake Energy Corporation. 20 08. Drilling 101 . Presented to the NY DEC. September 2008.

250 ALL Consulting. 2002. Handbook on Best Management Practices and Mitigation Strategies for Coal Bed Methane in the Montana Portion of the Powder River Basin . 2002.

251 ALL Consulting. 2008. Casing and Cement Programs . Horizontal Well Diagram.

252 Bellabarba, M., H. Bulte

- Loyer, B. Froelich, S. Roy

- Delage, R. Van Kuijk, S. Zeroug, D. Guillot, N. Moroni, S. Pastor, and A. Zanchi. 2008. Ensuring Zonal Isolation Beyond th e Life of the Well. Oilfield Review. Spring 2008.

253 Railroad Commission of Texas (RRC). http://www.rrc.state.tx.us/

. Accessed: September 2008.

254 Bellabarba, M., H. Bulte

- Loyer, B. Froelich, S. Roy

- Delage, R. V an Kuijk, S. Zeroug, D. Guillot, N. Moroni, S. Pastor, and A. Zanchi. 2008. Ensuring Zonal Isolation Beyond the Life of the Well. Oilfield Review. Spring 2008.

255 Arkansas Oil and Gas Commission. General Rules and Regulations . Accessed: September 2008.

256 Michie & Associates. 1988. Oil and Gas Water Injection Well Corrosion. Prepared for the American Petroleum Institute. 1988.

257 Ibid.

258 Michie, T.W.

, and C.A. Koch

. Evaluation Of Injection

- Well Risk Management In The Williston Basin, June, 1991.

259 Michie & Associates. 1988. Oil and Gas Water Injection Well Corrosion. Prepared for the American Petroleum Institute. 1988.MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

93 260 Schlumberger. Drilling Fluids: The Many Roles of Drilling Fluids. http://www.seed.slb.com/en/scictr/watch/mud/char.htm

. Accessed: September 2008.

261 Singh,, M. M., Jr. The Pennsylvania State University

. Goodwin, Robert J

. Gulf Research and Development C ompany. 1965. Mechanism of Drilling Wells with Air as the Drilling Fluid. SPE 1052

- MS.

262 Kenn edy, J. Technology Limits Environmental Impact of Drilling . Drilling Contractor. July/August 2000. 33

- 35.

263 Swaco, M. 2006. Reclaim Technology: The system that extends the life of oil

- and synthetic

- base drilling fluids while reducing disposal and environmental costs. Published by M

- I LLC. 2006.

264 Oklahoma Department of Environmental Quality. Pollution Prevention Case Study for Oxy USA, Inc. http://www.deq.state.ok.us/CSDnew/P2/Casestudy/oxyusa~1.htm

. Accessed: September 2008.

265 Harper, J. 2008. The Marcellus Shale

– An Old “New” Gas Reservoir in Pennsylvania

. Pennsylvania Geology. v 28, no 1. Spring 2008. Published by the Bureau of Topographic and Geologic Survey, Pennsylvania Department of Conservation and Natural Resources

..

266 Veatch, R.W., Jr., Z. A. Moschovidis, and C. R. Fast. An Overvie w of Hydraulic Fracturing. Recent Advances in Hydraulic Fracturing, Edited by J.L. Gidley, S.A. Holditch, D.E. Nierode, and R.W. Veatch Jr. Society of Petroleum Engineers, Henry L Doherty Series Monograph. v 12.

267 Jennings, A.R., Jr., and W. G. Darden. 1979. Gas Well Stimulation in the Eastern United States . SPE 7914. 1979.

268 Veatch, R.W., Jr., Z. A. Moschovidis, and C. R. Fast. An Overview of Hydraulic Fracturing. Recent Advances in Hydraulic Fracturing, Edited by J.L. Gidley, S.A. Holditch, D .E. Nierode, and R.W. Veatch Jr. Society of Petroleum Engineers, Henry L Doherty Series Monograph. v 12.

269 Boyer, C., J. Kieschnick, R. Suarez

- Rivera, R. Lewis, and G. Walter. 2006. Schlumberger. Oilfield Review. Producing Gas from Its Source . Pp 36

- 49. Autumn 2006.

270 Meyer & Associates, Inc. User‟s Guide for the Meyer Fracturing Simulators. Sixth Edition.

271 S chlumberger. PowerSTIM

.. http://www.slb.com/content/services/stimulation/fracturing/powerstim.asp ? Accessed: September 2008.

272 Mapping of Microseismic Events Courtesy of : Oilfield Service Company.

273 Meyer & Associates, Inc. User‟s Guide for the Meyer Fracturing Simulators. Six th Edition.

274 Parshall, J. 2008. Barnett Shale Showcases Tight

- gas Development . Journal of Petroleum Technology. September 19, 2008.

275 Overbey, W.K., A.B. Yost, and D.A. Wilkins. 1988. Inducing Multiple Hydraulic Fractures from a Horizontal Wellbore. SPE Paper 18249.

276 Chesapeake Energy Corpor ation. Components of Hydraulic Fracturing , Presented to the NY DEC. October 2008.

277 Arthur, J.D., B. Bohm, and M. Layne. 2008. ALL Consulting. Hydraulic Fracturing Considerations for Natural Gas Wells of the Marcellus Shale . Presented at the GWPC Annual Forum in Cincinnati, OH. September 2008.

278 Ibid.

279 Harper, J. 2008. The Marcellus Shale

– An Old “New” Gas Reservoir in Pennsylvania

. Pennsylvania Geology. v 28, no 1. Spring 2008. Published by the Bureau of Topographic and Geologic Survey, Pennsylvania Department of Conservation and Natural Resources

..

280 Cramer, D. Stimulating Unconventional Reservoirs: Lessons Learned, Successful Practices, Areas for Improvement . SPE 114172.

281 Harper, J. 200 8. The Marcellus Shale

– An Old “New” Gas Reservoir in Pennsylvania

. Pennsylvania Geology. v 28, no 1. Spring 2008. Published by the Bureau of Topographic and Geologic Survey, Pennsylvania Department of Conservation and Natural Resources

..

282 Schlumber ger. Fracturing

. http://www.slb.com/content/services/stimulation/fracturing/index.asp ? Accessed: September 2008.

283 Ketter, A.A., J. L. Daniels, J. R. Heinze, and G. Waters

. A Field Study Optimizing Completion Strategies for Fracture Initiation in Barnett Shale Horizontal Wells . SPE 103232.MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

94 284 Schlumberger. PowerSTIM

. http://www.slb.com/content/services/stimulation/fracturing/powerstim.asp ? Accessed: September 2008.

285 Compiled from Data collected at a Fayetteville Shale Fracture Stimulation by ALL Consulting 2008.

286 Modified from: Arthur, J.D., B. Bohm, and M. Layne

. 2008. ALL Consulting. Hydraulic Fracturing Considerations for Natural Gas Wells of the Marcellus Shale . Presented at the GWPC Annual Forum in Cincinnati, OH. September 2008.

287 Satterfield, J., M. Mantell, D. Kathol, F. Hiebert, K. Patterson, and R. Lee . 2008. Chesapeake Energy Corp. Managing Water Resource‟s Challenges in Select Natural Gas Shale Plays . Presented at the GWPC Annual Meeting. September 2008.

288 Personal conversations with various operators

. September 2008.

289 NRCS. National Water & Climate Center

. http://www.wcc.nrcs.usda.gov/

. Accessed: September 2008.

290 Satterfield, J

, M. Mantell, D. Kathol, F. Hiebert, K. Patterson, and R. Lee. 2008. Chesapeake Energy Corp. Managing Water Resource ‟s Challenges in Select Natural Gas Shale Plays . Presented at the GWPC Annual Meeting. September 2008.

291 Gaudlip, A., L. Paugh ( SPE, Range Resources Appalachia LL ) , and T. Hayes (Gas Technology Institute). Marcellus Shale Water Management Challenges in Pennsylvania . Presented at the SPE Shale Gas Production Conference, November 2008.

292 Chesapeake Energy Corporation. Little Red River Project . Presentation to Trout Unlimited. May 6, 2008.

293 Weston, R.T. 2008. Development of the Marcellus Shale

- Water Resource Challenges. Published by Kirkpatrick & Lockhart Preston Gates Ellis LLP. 2008.

294 Satterfield, J., M. Mantell, D. Kathol, F. Hiebert, K. Patterson, and R. Lee

. . 2008. Chesa peake Energy Corp. Managing Water Resource‟s Challenges in Select Natu ral Gas Shale Plays . Presented at the GWPC Annual Meeting. September 2008.

295 Personal communication with numerous operator and service companies in a variety of shale gas plays.

296 Willb erg, D.M., N. Steinsberger, R. Hoover, R. J. Card, and J. Queen. 19 98. Optimization of Fracture Cleanup Using Flowback Analysis . SPE 39920

- MS. 1998.

297 Satterfield, J., M. Mantell, D. Kathol, F. Hiebert, K. Patterson, and R. Lee. Managing Water Resource‟s Challenges in Select Natural Gas Shale Plays . Chesapeake Energy Corp. Presented at the GWPC Annual Meeting. September 2008.

298 Personal conversations with various operators. March, 2009.

299 Satterfield, J., Mantell, M., Kathol, D., Hiebert, F., Patterson, K., and Lee, R. 2008. Chesa peake Energy Corp. Managing Water Resource‟s Challenges in Select Natural Gas Shale Plays . Presented at the GWPC Annual Meeting. September 2008.

300 Harper, J. 2008. The Marcellus Shale

– An Old “New” Gas Reservoir in Pennsylvania

. Pennsylvania Geology. v 28, no 1. Spring 2008. Publis hed by the Bureau of Topographic and Geologic Survey, Pennsylvania Department of Conservation and Natural Resources

.

301 Railroad Commission of Texas (RRC). v 2008

. v Water Use in the Barnett Shale

. v http://www.rrc.state.tx.us/divisions/og/wateruse_barnettshale.html

. v Updated: v June 30, 2008. v Accessed: v October 2008.

302 Personal communication with a variety of producing and service companies operating in shale gas basins. 2008.

303 Burnett, D.B., and C. J. Vavra. 2006. Global Petroleum Research Institute (GPRI) and Food Protein Research Ce nter. Texas A&M Produced Water Treatment. Desalination of Oilfield Brine. New Resources: Produced Water Desalination . August 2006.

304 Grable, R.C. 2008. Kelly Hart & Hallman, Attorneys at Law. Saltwater Disposal and Other “Hot Issues” in Urban Drilling. Safety

- Wellbore

. Pres ented at the 19th Annual State Bar of Texas Advanced Real Estate Drafting Course in Dallas. February 29, 2008.

305 Burnett, D.B., and C. J. Vavra. 2006. Global Petroleum Research Institute (GPRI) and Food Protein Research Center. Texas A&M Produced Water Treatment. Desalination of Oilfield Brine. New Resources: Produced Water Desalination . August 2006.

306 Ibid.

307 University of Arkansas. Argonne Natio nal Laboratory. Fayetteville Shale Natural Gas: Reducing Environmental Impacts

. Well Production and Wat er Management

. http://lingo.cast.uark.edu/LINGOPUBLIC/index.htm

. Accessed: October 2008.

308 Ibid.

309 University of Arkansas. Argonne National Laboratory. Fayetteville Shale Natural Gas: Reducing Environmental Impacts. Well Production and Water Management

. http://lingo.cast.uark.edu/LINGOPUBLIC/environ/wellprod/index.htm

. Accessed: October 2008.MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

95 310 Darbonne, N. Oil and Gas Investor. Engelder: Marcellus, Mona Lisa Share Structural

- Fracturing Features

. http://www.oilandgasinvestor.com/Headlines/WebJuly/item5298.php

. July 18, 2008.

311 Personal communication with Pe nnsylvania Department of Environmental Protection, Bureau of Oil and Gas Management. October 2008.

312 Personal communication w ith operators and service industry personnel in the Pennsylvania area. October 2008.

313 University of Arkansas. Argonne National Laboratory. Fayetteville Shale Natural Gas: Reducing Environmental Impacts. Well Production and Water Management

. http://lingo.cast.uark.edu/L INGOPUBLIC/environ/wellprod/index.htm

. Accessed: October 2008.

314 Personal communication with Tim Baker from Oklahoma Corporation Commission, Oil and Gas Conservation Division. October 16, 2008.

315 Ibid.

316 Ibid.

317 Burnett, D.B., and C. J. Vavra. 2006. Global Petroleum Research Institute (GPRI) and Food Protein Research Center. Texas A&M Produced Water Treatment

. Desalination of Oilfield Brine. New Resources: Produced Water Desalination . August 2006.

318 Grable, R.C. 2008. Kelly Hart & Hallman, Attorneys at Law. Saltwater Disposal and Other “Hot Issues” in Urban Drilling. Safety

- Wellbore. Presented at the 19t h Annual State Bar of Texas Advanced Real Estate Drafting Course in Dallas. Febr uary 29, 2008.

319 Ewing, J. 2008. Devon Energy Corp. Taking a Proactive Approach to Water Recycling in the Barnett Shale . Presented at the Fort Worth Business Press Barnett Shale Symposium. February 29, 2008.

320 Texas Railroad Commission. NORM

– Naturally Occurring Radioactive Material

. http://www.rrc.state.tx.us/divisions/og/key

- programs/norm.htm l

. Accessed: October 2008.

321 NCRP. 2009. Ioning Radiation Exposure of the Populations of the United States . National Council on Radiation Exposure and Measurements, report No. 160. March, 2009.

322 USGS. 1999. Naturally Occurring Radioactive Materials (NORM) in Produced Water and Oil

- Field Equipment

– An Issue for the Energy Industry . USGS Fact Sheet FS

- 142

- 99. September 1999.

323 Smith, K.P., D. L. Blunt, G. P. Williams, and C. L. Tebes

. 1996. Argonne National Laboratory. Envir onmental Assessment Division. Radiological Dose Assessment Related to Management of Naturally Occurring Radioactive Materials Generated by the Petroleum Industry . September 1996.

324 Ibid.

325 API. 2004. Naturally Occurring Radioactive Material in North Am erican Oilfields A Fact Sheet from the American Petroleum Institute. 2004.

326 Barnett Shale Energy Education Council. Environment. www.bseec.org/index.php/content/facts/environment

. Accessed: September 2008.

327 Ibid.

328 Smith, K.P., D. L. Blunt, G. P. Williams, and C. L. Tebes

. 1996. Argonne National Laboratory. Environmental Assessment Division. Radiological Dose Assessment Related to Management of Naturally Occurring Radioactive Materials Generated by the Petroleum Industry . September 1996.

329 Ibid.

330 NaturalGas.org. Natural Gas and the Environment

. www.naturalgas.org/environment/naturalgas.asp

. Accessed: Sept ember 2008.

331 EPA. Emissions by Category Chart

– Criteria Air Pollutants . Volatile Organic Compounds

- 2001. www.epa.gov/oar/data/emcatbar.html?us~USA~United%20States . Acces sed: September 2008.

332 EPA. Technolo gy Transfer Network: 1999 National

- Scale Air Toxics Assessment. Benzene Emissions 1999

. http://www.epa.gov/ttn/atw/nata1999/99pdfs/benzene.pdf

. Accessed: September 2008.

333 EPA. Emissions by Category Chart

– Criteria Air Pollutants . Carbon Monoxide

– 2001. www.epa.gov/oar/data/emcatbar.html?us~USA~United%20States . A ccessed: September 2008.MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

96 334 Ibid.

335 Triplepundit. 2008. Sha le Gas: Energy Boon or Environmental Bane

, Part One

. www.triplepundit.com/pages/shale

- gas

energy

- boon

- o r

- envir

- 003396.php

. August 11, 2008.

336 American Petroleum Institute (API). 2001. RP 49,

. Recommended Practice for Drilling and Well Servicing Operations Involving Hydrogen Sulfide. 2nd Edition. May 2001. Reaffirmed, March 2007.

337 EPA, 2008. Partner Update: Partner Profile: ConocoPhillips Makes New Commitment to Natural Gas Star

. www.epa.gov/gasstar/pdf/ngspartnerup_spring2007.pdf

. Spring 2008.

338 Ibid.

339 NaturalGas.org. Proce ssing Natural Gas

. www.naturalgas.org/naturalgas/processing_ng.asp

. Accessed: September 2008.

340 EPA. 2005. Reduced Emission Completions (Green Completions )

. www.epa.gov/gasstar/workshops/houston

oct26/green_c.pdf

. October 26, 2005.

341 Methane to Markets. About the Partnership

. www.methanetomarkets.org/about/index.htm

. Accessed: September 2008.

342 Methane to Markets. Oil and Gas Sector Members

. www.methanetomarkets.org/partners/network/pnm List.aspx?type=oil

. Accessed: September 2008.

343 Methane to Mark ets. Methane Partnership Program s

. www.epa.gov/methanetomarkets/partnership.htm

. Accessed: September 2008.

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