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 authors 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 2009 
MODERN 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-

04NT15455. 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 appreciation 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 individuals 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 Department 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 Department 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 Virginia 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 

resource 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 presented 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 gas, 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 conducted 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 other 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 developing 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 nonwater 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 as 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 does 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. 

Scott Kell, President,

Ground Water Protection Council 
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MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

ES-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 and 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. 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. Regulators, 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. 

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. 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 gas 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 the 

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 resource 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 energy 

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 will 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 produces 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 importantly, 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 

unconventional 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. This 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 PRIMER

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 

and 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 managed 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 permit wells, including 

their design, location, spacing, operation, and abandonment, as well as environmental activities and 

EXHIBIT ES-1: UNITED STATES SHALE BASINS
MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

ES-3

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 states under agreements and plans 

approved by the appropriate federal agencies. 

A series of federal laws governs most environmental aspects of shale 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 injection 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 implement 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, management 

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 character of the activities, compared to one-sizefits-all regulation at the federal level. Some of these specific factors include: geology, hydrology, 

climate, topography, industry characteristics, development history, state legal structures, 

population density, 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 extending 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 employed 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 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. 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 eight 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 of 
MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

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 technological 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 fluids 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 gallons, 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 small 

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 areas, 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 communities 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 interfering 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 through 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 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. 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 surface during shale gas drilling and production 

operations, it remains in the rock pieces of the drill cuttings, remains in solution with produced 
MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

ES-5

water, or, under certain conditions, precipitates out in scales or sludges. The radiation from this 

NORM is weak 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 gas 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 concentrations 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 facility. 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 other sources of energy, 

particularly other fossil fuels, some air emissions commonly occur during exploration and 

production activities. Emissions may include NOx, volatile organic compounds, particulate matter, 

SO2, and methane. EPA sets 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. 

Gas field emissions are controlled and minimized through a combination of government regulation 

and voluntary avoidance, minimization, and mitigation strategies. 

The primary differences between modern shale gas development and conventional natural gas 

development are the extensive uses 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 associated 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 resources, 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 some 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.
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i

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

Unconventional Gas................................................................................................................................................................7

The Role of Shale Gas in Unconventional Gas ............................................................................................................8

Looking Forward ..................................................................................................................................................................10

SHALE GAS DEVELOPMENT IN THE UNITED STATES.......................................................................... 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 Governing 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.................................................................................................................................................. 36
ii

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: Casing 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 Quality................................................................................................................................................................................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 ...................................................................................................................................................... 83
iii

LIST OF EXHIBITS

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 Outlook .........................................................................................9

9. Trends in Shale Gas Production .............................................................................................................10

10. Marcellus Shale Outcrop............................................................................................................................14

11. Comparison of Data for the Gas Shales in the United States .....................................................17

12. Stratigraphy of the Barnett Shale ..........................................................................................................18

13. Barnett Shale in the Fort Worth Basin ................................................................................................18

14. Stratigraphy of the Fayetteville Shale .................................................................................................19

15. Fayetteville Shale in the Arkoma Basin ..............................................................................................19

16. Stratigraphy of the Haynesville Shale..................................................................................................20

17. Haynesville Shale in the Texas & Louisiana Basin.........................................................................20

18. Stratigraphy of the Marcellus Shale......................................................................................................21

19. Marcellus Shale in the Appalachian 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 ...........................................................................................................23
iv

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 ........................................................................................46

30. Casing Zones and Cement Programs....................................................................................................52

31. Comparison of Target Shale Depth and Base of Treatable Groundwater ...........................54

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.........................59

35. Volumetric Composition of a Fracture Fluid ....................................................................................62

36. Fracturing Fluid Additives, Main Compounds, and Common Uses ........................................63 

37. Estimated Water Needs for Drilling and Fracturing Wells in

Select Shale Gas Plays ...............................................................................................................................64

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......................................................................................................72

41. Benzene Emissions by Source – 1999 .................................................................................................73

42. CO Emissions by Source Category.........................................................................................................73
MODERN 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 onshore domestic oil and gas exploration and production today. 

In 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 changes to the 

environmental and socio-economic landscape, particularly in those 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. Regulators, 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. 

The 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 with 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 decisions by government.
MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

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MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

3

What Is 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 (tcf) are often used to 

measure large quantities, as in 

resources or reserves in the ground, 

or annual national energy 

consumption. A tcf 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 gasfired vehicles for one year.

THE IMPORTANCE 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 total1

(Exhibit 12). 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 

gas resources. The Energy Information 

Administration (EIA) 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 the original gasin-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 resource5. At the U.S. 

production rates for 2007, about 19.3 tcf, the current recoverable resource estimate provides 

enough natural gas to supply the U.S. for the next 90 years6. Note that historically, estimates of the 

size of the total recoverable resource have grown over time 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 27). It is an important energy

source for the industrial, commercial and electrical 

generation sectors, and also serves a vital role in 

residential heating8. Although forecasts vary in their 

outlook for future demand for natural gas, they all 

have one thing in common: natural gas will continue 

to play a significant role in the U.S. energy picture for 

some time to come9.

Natural gas, due to its clean-burning nature and 

economical availability, has become a very popular 

fuel for the generation of electricity10. In the 1970s 

and 80s, the choice for the majority of electric utility 

generators was primarily coal or nuclear power; but, 

due to economic, environmental, technological, and 

EXHIBIT 1: UNITED STATES ENERGY 

CONSUMPTION BY FUEL (2007)
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, 

chemicals, petroleum refining, and food 

processing. These five industries alone 

account for almost three quarters of 

industrial natural gas use12 and together 

employ four million people in the U.S.13

Natural gas is also a feedstock for a variety 

of products, including 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 increasing14. Half of the natural gas consumed today is produced from 

wells drilled within the last 3.5 years15. 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 202516. However, it is 

believed by many that unconventional natural 

gas resources such as shale gas can significantly

alter that balance.

Exhibit 317 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 the 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) it would serve to decrease our energy security; and 2) it could create a multi-billion dollar 

outflow to foreign interests, thus making such funds unavailable for domestic investment. 

EXHIBIT 2: NATURAL GAS USE BY 

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

5

The Advantages of 

Natural Gas 

In the 1800s and early 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 (Btu) content

and 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 America18. 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 burning19. In fact, of all the fossil fuels, 

natural gas is by far the cleanest burning. It emits approximately half the carbon dioxide (CO2) of 

coal along with low levels of other air pollutants20. The combustion byproducts of natural gas are 

mostly CO2 and water vapor, 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 larger

quantities of CO2, nitrogen oxides (NOx), 

sulfur dioxide (SO2) and particulate ash 

(Exhibit 421). By comparison, the 

combustion of natural gas liberates very 

small amounts of SO2 and NOx, virtually no 

ash, and lower levels of CO2, carbon 

monoxide (CO), and other hydrocarbons22.

Because natural gas emits only half as 

much CO2 as coal and approximately 30% 

less than fuel oil, it is generally considered 

to be central to energy plans focused on 

EXHIBIT 3: COMPARISON OF PRODUCTION, CONSUMPTION AND 

IMPORT TRENDS FOR NATURAL GAS IN THE UNITED STATES

EXHIBIT 4: COMBUSTION EMISSIONS

(POUNDS/BILLION BTU OF ENERGY INPUT)

Air Pollutant Combusted Source

Natural Gas Oil Coal

Carbon dioxide 

(CO2)

117,000 164,000 208,000

Carbon monoxide 

(CO)

40 33 208

Nitrogen oxides 

(NOx)

92 448 457

Sulfur dioxide (SO2) 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, 1998
MODERN 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 emissions23. According to the EIA in 

its report “Emissions of Greenhouse Gases in the United 

States 2006,” 82.3% of GHG emissions in the U.S. in 2006

came from CO2 as a direct result of fossil fuel combustion24.

Since CO2 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 result 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 these sources to become economical enough 

to supply a significant portion of the nation’s energy consumption. Indeed, the EIA estimates that 

fossil fuels (oil, gas, and coal) will supply 82.1% of the nation’s energy needs in 203025. Since 

natural gas is the cleanest burning of the fossil fuels, an environmental benefit could be realized by 

shifting toward proportionately greater reliance on natural 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 challenging26. 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 role27. 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 future28.

Natural Gas Basics

Natural gas is a combination of hydrocarbon gases consisting primarily of methane (CH4), and

lesser percentages of 

butane, ethane, propane, 

and other gases29,30. It is 

odorless, colorless, and, 

when ignited, releases a 

significant amount of 

energy31. Exhibit 532 shows 

the typical compositional 

range of natural gas 

produced in the U.S.

Natural 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

EXHIBIT 5: TYPICAL COMPOSITION OF NATURAL GAS
MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

7

deposits by using complex technologies to identify prospective drilling 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 miles33. 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 feet (Mcf), millions of cubic feet 

(MMcf), or billions of cubic feet (bcf), and estimate resources such as original gas-in-place in 

trillions of cubic feet (tcf). 

Calculating and tracking natural gas by volume is useful, but it can also be measured as a source 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 pressure34. There are about 1,000 Btus in one cubic 

foot of natural gas delivered to the consumer35. Natural gas distribution companies typically

measure the gas delivered to a residence in 'therms' for billing purposes36. A therm is equal to 

100,000 Btus—approximately 100 cubic feet—of natural gas37.

Unconventional Gas 

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

tcf of gas during that period38. 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 

uneconomic39.

In 2007, Texas, 

Wyoming, and 

Colorado 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 

plays40. Similarly, the 

states of Texas (30%) 

and Wyoming (12%) 

had the greatest 

volume of proved gas 

EXHIBIT 6: NATURAL GAS PRODUCTION BY SOURCE (TCF/YEAR)

Source: EIA, 2008
MODERN 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 2007—again, both primarily as a 

result of developing unconventional natural gas plays41. 

Overall, unconventional natural gas is anticipated to 

become an ever-increasing portion of the U.S. proved

reserves, while conventional gas reserves are declining42. 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 tcf/yr in 2007 (Exhibit 6). This means unconventional production now accounts for 

46% of the total U.S. production43. 

EXHIBIT 7: UNITED STATES SHALE GAS BASINS

The Role of Shale Gas in Unconventional Gas

The lower 48 states have a wide distribution of highly organic shales containing vast resources of 

natural gas (Exhibit 744). Already, the fledgling Barnett Shale play in Texas produces 6% of all 

natural gas produced in the lower 48 states45. Improved drilling and fracturing technologies have

contributed considerably to the economic potential of shale gas. This potential for production in 

Source: ALL Consulting, Modified from USGS & other sources
MODERN 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 846 shows the projected 

contribution of shale gas to the overall unconventional gas production in the U.S. in bcf/day.

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 

in the last several 

years as a result of 

significant supply 

and demand 

pressures.

Advances in the 

pre-existing technologies of directional drilling and hydraulic 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 200847. 

It has been suggested that the rapid growth of unconventional natural gas plays has not been 

captured by recent resource estimates compiled by the EIA and that, therefore, their resource

estimates do not accurately reflect the contribution of shale gas48. 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 analysis of shale gas 

resources to other national resource estimates, has 

estimated that U.S. total natural gas resources (proved 

plus unproved technically recoverable) are 1,680 tcf to 

2,247 tcf, or 87 to 116 years of production at 2007 U.S. 

production levels. This compares with EIA’s national 

EXHIBIT 8: UNITED STATES UNCONVENTIONAL GAS OUTLOOK (BCF/DAY)
MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

10

Shale gas resource estimates 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 

950 depicts 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/day) will come from unconventional shale gas 

reservoirs51. The total recoverable gas resources

from 4 emerging shale gas plays (the Haynesville, 

Fayetteville, Marcellus, and Woodford) may be over 

550 tcf52. Total annual production volumes of 3 to 4 tcf may be sustainable for decades. An 

additional 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 before53.

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 energy 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 growth54.

EXHIBIT 9: TRENDS IN SHALE GAS PRODUCTION (MMCF/DAY)
MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

11

Recent successes and improvements 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.

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 

additional practices that have allowed development of areas that might previously have been 

inaccessible due to environmental constraints or restrictions on disturbances in both 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 drilling 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 habitats, agricultural resources, and surface water bodies. 

Other practices that are now commonly used for drilling, particularly in urban settings, 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 needed, 

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 and 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

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MODERN 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 shale 

near the town of Fredonia, New York.

SHALE GAS DEVELOPMENT IN THE UNITED STATES

Shale formations across the U.S. have been developed to produce natural gas in small but 

continuous volumes since the earliest years of gas development. The first producing gas well in the 

U.S. was completed in 1821 in Devonian-aged shale near the town of Fredonia, New York55. The 

natural gas from this first well was used by 

town residents for lighting56. Early supplies of 

natural gas were derived from shallow gas 

wells that were not complicated to drill and 

from natural gas seeps57. The shallow wells 

and seeps were capable of producing small amounts of natural gas that were used for illuminating 

city streets and households58. 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 Kentucky during the 1920s

60. The Big Sandy Field has 

recently experienced a renewed growth and currently is a 3,000-square-mile play encompassing 

five counties61. By the 1930s, gas from the Antrim Shale in Michigan had experienced moderate 

development; however, it was not until the 1980s that development began to expand rapidly to the 

point that it has now reached nearly 9,000 wells62. It was also during the 1980s that one of the 

nation’s most active natural gas plays initially kicked off in the area around Fort Worth, Texas63. 

The play was the Barnett Shale, and its success grabbed the industry’s attention. Large-scale 

hydraulic fracturing, a process first developed in Texas in the 1950s, was first used in the Barnett in 

1986; likewise, the first Barnett horizontal well was drilled in 199264. Through continued 

improvements in the techniques and technology of hydraulic fracturing, development of the Barnett 

Shale has accelerated65. 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 to the other shale gas formations present 

across the U.S. and Canada66.

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 Shale of the 

Williston Basin of Montana and North Dakota has seen a similar growth rate to the Barnett. The 

Bakken is another technical play in which the development of this unconventional resource has 

benefitted from the technological advances in horizontal wells and hydraulic fracturing67. In April 

2008, the United States Geological Survey (USGS) released an updated assessment of the 

undiscovered technically recoverable reserves for this shale play estimating there are 3.65 billion 

barrels (bbls) of oil, 1.85 tcf of associated natural gas, and 148 million bbls of natural gas liquids in 

the play68.

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 feasible69. The low natural 

permeability of shale has been the limiting factor to the production of shale gas resources because 
MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

14

it only allows minor volumes of gas to flow naturally to a wellbore70. The characteristic of lowmatrix permeability represents a key difference between shale and other gas reservoirs. For gas 

shales to be economically produced, these restrictions must be overcome71. The combination of 

reduced economics and low permeability of gas shale formations historically caused operators to 

bypass these formations and focus on other resources72. 

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), but some formations do produce wet gas. 

The Antrim and New Albany formations have typically produced water and gas73. Gas shales are 

organic-rich shale formations that were previously regarded only as source rocks and seals for gas 

accumulating in the stratigraphically-associated sandstone and carbonate reservoirs of traditional 

onshore gas development74. Shale is a sedimentary rock that is predominantly comprised of 

consolidated clay-sized particles. Shales are deposited as mud in low-energy depositional 

environments 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 form of algae-, plant-, and animal-derived 

organic debris75. The naturally tabular clay grains tend to lie flat as the sediments accumulate and 

subsequently become compacted as a result of additional sediment deposition. This results in mud 

with thin laminar bedding that lithifies (solidifies) 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. Typical unfractured shales 

have matrix permeabilities on the 

order of 0.01 to 0.00001 millidarcies76. 

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 

naturally occurring, artificial fractures 

induced by hydraulic fracture 

stimulation in the deep subsurface 

reservoir rock would have a similar 

appearance.

EXHIBIT 10: MARCELLUS SHALE OUTCROP 

Source: T. Engelder home page 

Source: ALL Consulting, 2008
MODERN 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 basins77. Gas reservoirs are 

classified as conventional or unconventional for the following reasons:

1. Conventional reservoirs – Wells 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 in the pores 

can move from one pore to another through smaller 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 permeable 

sandstone or carbonate. 

2. Unconventional reservoirs – Wells 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 create 

additional permeability. Hydraulic fracturing of a reservoir is the preferred stimulation 

method for gas shales. Differences between the three basic types of unconventional 

reservoirs include: 

1. Tight Gas – Wells 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) – Wells produce from the coal seams which act as 

source and reservoir of the natural gas79. 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 some 

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 mostly shallow as the coal matrix does not have the strength to 

maintain porosity under the pressure of significant overburden thickness. 

3. Shale Gas – Wells produce from low permeability shale formations that are also 

the source for the natural gas. The natural gas volumes can be stored in a local 

macro-porosity system (fracture porosity) within the shale, or within the micropores of the shale80, or it can be adsorbed onto minerals or organic matter 

within the shale81. Wells may be drilled either vertically or 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 Resources: 

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. 

In 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 

States. Exhibit 7 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. The following 

discussion provides a summary of basic

information regarding these 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 potentially 

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. Development 

of the Fayetteville Shale is occurring in rural 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 

economic viability are now being re-evaluated. Exhibit 11 summarizes the key characteristics of 

the most active shale gas plays across the U.S. This exhibit 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 time 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

EXHIBIT 11: COMPARISON OF DATA FOR THE GAS SHALES IN THE UNITED STATES

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 -

8,50082

1,000 -

7,00083

10,500 -

13,50084

4,000 -

8,50085

6,000 -

11,00086 600 - 2,20087 500 -2,00088

Net Thickness, 

ft 100 - 60089 20 - 20090 20091

- 30092 50 - 20093 120 - 22094 70 - 120

95 50 - 10096

Depth to Base 

of Treatable 

Water#, ft

~1200 ~50097 ~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, % 4.598 4.0 - 9.899 0.5 - 4.0100 3 - 12101 1 - 14102 1 - 20103 1 - 25104

Total Porosity, 

%

4 - 5

105 2 - 8106 8 - 9107 10108 3 - 9109 9110 10 - 14111

Gas Content, 

scf/ton

300 -

350112 60 - 220113 100 - 330114 60 - 100115 200 -300116 40 - 100117 40 - 80118

Water 

Production, 

Barrels 

water/day

N/A N/A N/A N/A N/A 5 - 500119 5 - 500120

Well spacing, 

acres

60 - 160121 80 - 160 40 - 560122 40 - 160123 640124 40 - 160125 80126

Original Gas-InPlace, tcf127 327 52 717 1,500 23 76 160

Technically 

Recoverable 

Resources, 

tcf128

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 data was obtained from a variety of sources and is presented for general 

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 technologies improve.

Mcf = thousands of cubic feet of gas

scf = standard cubic feet of gas

tcf = trillions of cubic feet of gas

# = For 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 available
MODERN 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 Mississippianage shale occurring at a depth of 6,500 feet to 8,500 feet (Exhibit 11 and Exhibit 13131) and is 

bounded by limestone formations above (Marble Falls Limestone) and below (Chappel Limestone) 

(Exhibit 12).

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 proving 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 increase the amount of gas recovered134. Horizontal well 

completions in the Barnett are occurring at well spacing ranging from 60 to 160 acres per well 

(Exhibit 11).

The Barnett 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 11). The original gas-in-place estimate for 

the Barnett Shale is 327 tcf with estimated technically recoverable resources of 44 tcf (Exhibit 11). 

The gas content is the highest among the major shale plays, ranging from 300 standard cubic feet 

per ton (scf/ton) to 350 scf/ton of rock (Exhibit 11). 

EXHIBIT 12: STRATIGRAPHY OF THE 

BARNETT SHALE

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, 2005129

 AAPG, 1987 130

EXHIBIT 13: BARNETT SHALE IN THE FORT 

WORTH BASIN

Source: ALL Consulting, 2009
MODERN 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 and eastern Oklahoma 

over a depth range of 1,000 ft to 7,000 ft (Exhibit 15135 and Exhibit 11). The Fayetteville Shale is a 

Mississippian-age shale bounded by limestone (Pitkin Limestone) above and sandstone (Batesville 

Sandstone) below (Exhibit 14).

Development of the Fayetteville began in the early 2000s as gas companies that had experienced 

success in the Barnett Shale of the Fort Worth Basin identified parallels between it and the 

Mississippian-aged Fayetteville Shale in terms of age and geologic character136. 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 economical137. 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 bcf/yr138. With over 1,000 wells in production to date, the 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 11). The 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 recoverable resources: 52 tcf and 41.6 tcf respectively 

(Exhibit 11).

EXHIBIT 14: STRATIGRAPHY OF 

THE FAYETTEVILLE SHALE

Period Group/Unit

CARBONIFEROUS

Pennsylvanian

Atoka

Bloyd

Hale

Prairie 

Grove

Cane Hill

Mississippian

(IMO)

Pitkin

Fayetteville

Batesville

Moorefield

Boone

Source: Hillwood, 2007140

EXHIBIT 15: FAYETTEVILLE SHALE IN THE 

ARKOMA BASIN

Source: ALL Consulting, 2009
MODERN 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 ranging from 10,500 ft to 13,500 ft 

(Exhibit 17141 and Exhibit 11). The Haynesville is an Upper Jurassic-age shale bounded by 

sandstone (Cotton Valley Group) above and limestone (Smackover Formation) below (Exhibit 16).

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 completed142.

The Haynesville Shale covers an area of approximately 9,000 square miles with an average 

thickness of 200 ft to 300 ft (Exhibit 11). 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 11). 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 gas resource for the U.S. with 

original gas-in-place estimates of 717 tcf and technically recoverable resources estimated at 251 tcf 

(Exhibit 11).

EXHIBIT 16: STRATIGRAPHY OF 

THE HAYNESVILLE SHALE

Period Group/Unit Cretaceous

Navarro

Taylor

Austin

Eagle Ford

Tuscaloosa

Washita

Fredericksburg

Trinity Group

Nuevo Leon

Jurassic

Upper

Cotton Valley Group

Haynesville

Smackover

Norphlet

Middle Louann

Lower Werner

Triassic

Upper Eagle Mills

Source: Johnson et al, 2000143

EXHIBIT 17: HAYNESVILLE SHALE IN 

THE TEXAS & LOUISIANA BASIN

Source: ALL Consulting, 2009
MODERN 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 19144). The estimated depth of production for the Marcellus is between 4,000 ft and 

8,500 ft (Exhibit 11). The Marcellus Shale is a Middle Devonian-age shale bounded 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 1990s145. In 2003, 

Range Resources Corporation drilled the first economically producing wells into the Marcellus 

formation in Pennsylvania using horizontal drilling and hydraulic fracturing techniques similar to 

those used in the Barnett Shale formation of Texas146. Range Resources began producing this 

formation in 2005. As 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 drilled147.

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 gas content at 60 scf/ton to 100 scf/ton, the 

much larger area of this play compared to the other shale gas plays results in a higher original gasin-place estimate of up to 1,500 tcf (Exhibit 11). 

At an average well spacing in the Marcellus is 40 to 160 acres per well (Exhibit 11). The data in 

Exhibit 11 show technically recoverable resources for the formation to be 262 tcf, although much 

like the Haynesville, the play’s potential estimates are frequently being revised upward due to its 

early stage of development.

EXHIBIT 18: STRATIGRAPHY OF THE 

MARCELLUS SHALE

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, 2008148

EXHIBIT 19: MARCELLUS SHALE IN THE 

APPALACHIAN BASIN

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

22

The Woodford Shale

Located in south-central Oklahoma, the Woodford Shale ranges in depth from 6,000 ft to 11,000 ft

(Exhibit 21149 and Exhibit 11). This formation is a Devonian-age shale bounded by limestone 

(Osage Lime) above and undifferentiated strata below (Exhibit 20). 

Recent natural gas production in the Woodford Shale began in 2003 and 2004 with vertical well 

completions only150. However, horizontal drilling has been adopted in the Woodford, as in other 

shale gas plays, due to its success in the Barnett Shale151.

The Woodford Shale play encompasses an area of nearly 11,000 square miles (Exhibit 11). The 

Woodford play is in an early stage of development and is occurring at a spacing interval of 640 

acres per well (Exhibit 11). The average thickness of the Woodford Shale varies from 120 ft to 220 

ft across the play (Exhibit 11). 

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 11). The original gas-in-place 

estimate for the Woodford Shale is similar to the 

Fayetteville Shale at 23 tcf while the technically 

recoverable resources are 11.4 tcf (Exhibit 11).

EXHIBIT 20: STRATIGRAPHY OF THE 

WOODFORD SHALE 

Period Group/Unit

Permian

Ochoan Cloyd Chief Fm

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 Grp

Meramecian

Miss Lime

Meramec Lime

Osagean

Osage Lime

Kinderhookian

Devonian

Woodford Shale

Upper

Middle Undifferentiated

Lower

Hunton 

Grp

Haragan Fm 

Henryhouse 

Fm

Source: Cardott, 2007152

 AAPG, 1983153

EXHIBIT 21: WOODFORD SHALE IN THE 

ANADARKO BASIN

Source: ALL Consulting, 2009
MODERN 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 23154). This Late Devonian-age shale is bounded by shale (Bedford Shale) 

above and by limestone (Squaw Bay Limestone) below and occurs at depths of 600 ft to 2,200 ft 

which is more typical of CBNG formations than most gas shales (Exhibit 22 and Exhibit 11).

Aside from the Barnett, the Antrim Shale has been one of the most actively developed shale gas

plays with its major expansion taking place in the late 1980s

155. 

The Antrim Shale encompasses an area of approximately 12,000 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 greater volumes of produced water in the range of 5 to 500 

bbls/day/well156 (Exhibit 11).

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 tcf with technically recoverable resources

estimated at 20 tcf (Exhibit 11). Well spacing ranges from 40 acres to 160 acres per well.

EXHIBIT 22: STRATIGRAPHY OF THE 

ANTRIM SHALE

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

EXHIBIT 23: ANTRIM SHALE IN THE 

MICHIGAN BASIN

Source: ALL Consulting, 2009
MODERN 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 Kentucky159 (Exhibit 

25160). Similar to the Antrim Shale, the New Albany 

occurs at depths between 500 ft and 2,000 ft (Exhibit 

11) 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 bounded by 

limestone above (Rockford Limestone) and below 

(North Vernon Limestone) (Exhibit 24).

The New Albany Shale is one of the largest 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 day161 (Exhibit 

11). The measured gas content of the New Albany 

Shale ranges from 40 scf/ton to 80 scf/ton. The 

original gas-in-place for the New Albany formation is 

estimated at 160 tcf with technically recoverable 

resources estimated at less than 20 tcf (Exhibit 11).

EXHIBIT 24: STRATIGRAPHY OF THE 

NEW ALBANY SHALE

Period Formation

Pennsylvanian

Miss

ouria

n

Mattoon

Bond

Patoka

Desmoinesi

an

Shelburn

Dugger

Petersburg

Linton

Staunton

Atokan Brazil

Morrowan 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

Senecan

Chautauq

uan

Antrim Sh.

Erian

North Vernon 

Ls. Transverse

Jeffersonville 

Ls. Detroit River

Source: Indiana Geological Survey, 1986158

EXHIBIT 25: NEW ALBANY SHALE IN THE 

ILLINOIS BASIN

Source: ALL Consulting, 2009
MODERN 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 protective 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. Environmental 

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 activities 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 states 

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 governs 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 underground 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 

that 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 regulations may not always be the most effective way of assuring the desired level of 

environmental protection. Therefore, most of these federal laws have provisions for granting 

“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 effectively address the regional and state-specific character of the 

activities, compared to one-size-fits-all regulation at the federal level162. Some of these specific 

factors include: geology, hydrology, climate, topography, industry characteristics, development 

history, state legal structures, population density, and local economics. The state agencies that 
MODERN 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 fracture 

of the well, production operations, 

management and disposal of wastes, 

and abandonment and plugging of 

the well.

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 largest oil and gas producing state, home to the Barnett Shale. The names and 

organizational structures vary, but 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 extending 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 fracture of the well, production 

operations, management and disposal of wastes, 

and abandonment and plugging of the well. 

Different states take different approaches to this regulation 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 environmenta. In addition to the general protection 

regulations, most states have a general prohibition against pollution from oil and gas drilling and 

productionb. 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 states 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 and 

reclamation. Agency staff reviews 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 ensure 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: “The 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 resulting 

from exploration or drilling is prohibited.” (6 NYCRR Part 554). Another example 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 of 

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 itc.

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) program. In addition to the GWPC UIC 

review, state 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 several have been reviewed more than once. The 

STRONGER program has documented the effectiveness of and improvements in these state oil and 

gas environmental programs164,165. 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 within 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 departments 

or divisions within the states’ organizations. 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 the 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 states 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 government in specific locations. Entities such as 

cities, counties, tribes, 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 federal or state 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

EXHIBIT 26: OIL AND GAS REGULATORY AGENCIES IN SHALE GAS STATES

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, State 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=23
MODERN 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 

operations166,167,168,169.

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 water170. 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 Delaware171. 

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 their rules and 

regulations. 

The variety of laws governing shale gas exploration and production, and the multitude 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 Impacts 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 relationships 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 of 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 Pollutant

Discharge Elimination System (NPDES) permitting process. Although EPA sets national standards 

at the federal level, states and tribal governments can acquire primacy for the 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 significantly 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

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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 point 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 obtain permits if 

they intend to discharge directly into surface waters172,173. Large facilities usually have individual 

NPDES permits. Discharges from some smaller facilities may be eligible for inclusion under general 

permits that authorize a category of discharges 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 Appalachian Basin. Effluent limitations serve 

as the primary mechanism under NPDES permits for controlling discharges of pollutants to 

receiving waters. When 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., technologybased effluent standards) and the regulations that protect the water quality standards 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 discharges 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 nonmunicipal) facilities, technology-based effluent limits are derived by: 1) using national effluent 

limitations guidelines and standards established by EPA, or 2) using 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 

discharges. If the authorizing agency determines that technology-based effluent 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 Code of Federal Regulations (CFR) 122.44(d)]

require that more stringent limits are imposed as part of the permit174.

EPA establishes effluent 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 industrial category through the application of pollution control 

technologies.
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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 

existing 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 toxic 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 

categories175.

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 discharges associated with shale gas 

development and production176.

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 program. 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 

required)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 CWA178. 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 for oil and gas sector 

construction activities, it is important to note that individual states and Indian tribes may still 

regulate storm water associated with these activities. EPA has clarified its position that states and 

tribes may not regulate such storm 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 intended 
MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

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to interfere with the ability of states, tribes, or local governments to regulate any discharges 

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 sites180. 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 the Safe Drinking Water 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, 

springs, 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 met181.

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 liquid 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 federal 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 class 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 

under 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 hazardous 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 nonhazardous 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 include 

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 CO2 for the purpose of 

sequestration, but has not yet been established.
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Most 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 CO2) 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 requirements that affect the siting, construction, 

operation, maintenance, monitoring, testing, and, finally, closure of injection wells 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 SDWA, 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 federal 

requirements182.

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 gas states, and all other federal jurisdictions and Indian Lands183 (Exhibit 27184). 

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 

designed to reduce damage to natural resources from oil spills. Congress added Section 311 to the 

EXHIBIT 27: UIC CLASS II PRIMACY MAP

Source: EPA,, 2008
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CWA, which in part authorized the President to issue regulations establishing procedures, methods, 

equipment, and other requirements to prevent discharges of oil from vessels and facilities [Section 

311(j)(1)(c)]. In response to the Exxon Valdez oil spill in Alaska, Congress enacted the OPA in

1990185. 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 waters, 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 measures 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 that 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 waterways186.

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 bbls); and 

3. There must be a reasonable 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 measures are in place, if needed, 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 include 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. 
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In October 2007, EPA proposed amendments to the SPCC rule intended to increase clarity and tailor 

certain requirements to ensure increased compliance. Among other things, these amendments 

would streamline some requirements by allowing the use of a plan template for smaller 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 final187.

State Regulations and Regional Cooperation

In addition to implementing federal statutes for the NPDES, UIC, and storm water programs, states 

and tribes may impose their own requirements to protect their water resources, both surface and 

underground. For example, they establish water quality standards for some or all of their surface 

water. These standards are approved by EPA and become the baseline for CWA permits188. 

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 DRBC190 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 withdrawals and discharge of the water after use. Other river basin 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. They 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 other 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 (CAA). As described below, the Act sets 

national standards for emissions of certain pollutants and requires permits for some industrial 

operations. Greenhouse 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 1990191. The CAA requires EPA to set national 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 exceptions 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 versus unconventional plays, old 
MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

36

versus 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 area. 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 longer193. 

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 project cancellations in light of new standards. 

EPA has established National Emission Standards for Hazardous Air Pollutants (NESHAPs), which 

are nationally uniform standards to control specific 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 larger 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 standard194 and Reciprocating Internal Combustion 

Engine NESHAP195 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 maintenance, testing, monitoring, recordkeeping, 

and reporting requirements196. 

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 that 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—specifying monitoring, record keeping, and 
MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

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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 amendment 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 proposed 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 case 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 human 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 human 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 regulations197. 

In 1978, EPA proposed hazardous waste management standards that included reduced 

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 RCRA198. 

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 energy199. The SWDA Amendments also required EPA to provide a 

report to Congress on these wastes and to make a regulatory determination as to whether 

regulation of these wastes under RCRA Subtitle C was warranted200. 

In 1987, EPA issued a Report to Congress that outlined the 

results of a study on the management, 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 

Subtitle C was not warranted. EPA made this 

determination because it found that other state and 

federal programs could protect human health and the 
MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

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environment more effectively. In lieu of regulation under Subtitle C, EPA implemented a threepronged strategy to ensure that the environmental and programmatic issues were addressed:

1. Improve other federal 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 required201. 

These wastes have remained exempt from Subtitle C regulations, but this does not preclude these 

wastes from control under state regulations or other federal regulations202. The exemption applies 

only to the federal requirements of RCRA Subtitle C. A waste that 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 subject 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 1990203,204.

In 1989, EPA worked with the Interstate Oil and Gas Compact Commission (IOGCC), 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 management 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 state programs reviewed to date 

represent over 90% of the onshore domestic production205. 

Working with the IOGCC, STRONGER has continued to update the guidelines consistent with 

developing environmental and oilfield technologies and practices. Under the state 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 significantly modifying its habitat207. 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 section covers not only federal 

activities but also the issuance of federal 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 

wetlands208. Section 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 (plant 
MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

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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 

when 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 determine 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 

inhabit 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 required209,210. The FWS as 

well as many state fish and game agencies offer services to help operators 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 disturbances during nesting or mating seasons211.

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 considered and an explanation of why they were not taken; and any additional 

measures that the FWS may require212. 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 access213.

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 

have their own requirements for protecting endangered species214.

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 processed215. 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

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Since most shale gas activity in the near 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 varies 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 environment.

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 

health 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 provide 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 Reauthorization 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 the 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 reportable quantity 

(RQ) for that substance [CERCLA Section 103(a)]. The reportable quantity depends on the 

substance released.

CERCLA Section 101(14) excludes certain substances from the definition of hazardous substance, 

thus exempting them from CERCLA regulation. These substances include petroleum, meaning 

crude oil or any fraction thereof that is not specifically listed as a hazardous substance, natural 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 reportable quantities; such are not usually present at these sites.
MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

41

However, this 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 

substances is potentially reportable under EPCRA Section 304 if more than an RQ of that substance 

is released216.

Many states have separate requirements regarding hazardous substances. Reporting of releases 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 

governments, tribes, 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 increase 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 officials 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 are 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 available 

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 submitted217, 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 materials 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 operations. Businesses must report 

non-permitted releases—into the atmosphere, surface water, or groundwater—of any listed 
MODERN 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, known 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 authorities 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 (OSHA) 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 health219.

OSHA has developed specific standards to reduce potential safety and health hazards in the oil and 

gas drilling, servicing and storage industry220. 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 comprehensive 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 an array of requirements designed to protect 

human health and the environment 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

Collaborations between industry, 

regulators and the public have 

created innovative environmental 

solutions to problems that at first 

seemed insurmountable.

ENVIRONMENTAL CONSIDERATIONS

As described in the previous 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 the 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 every 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, 

prevention of waste, and protection of the rights of both surface and mineral owners while 

protecting the environment221. 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 drilling and production are properly contained 

and disposed of222. 

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 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.

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 hydraulic fracturing 

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 encountered 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.

One 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 and a host of related concerns. 
MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

44

EXHIBIT 28: PROCESS OF SHALE GAS DEVELOPMENT (DURATION)
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 rights and surface rights are not owned by 

the same party. This 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 rights223. 

In the mid-west and eastern states, where shale gas 

development resources are more prevalent, only 4% of 

the lands are associated with a federal split estate224. 

However, these same areas frequently have privateprivate 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 as a coal company.

A split-estate situation, regardless of its nature, can result in conflicts—especially 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 mineral 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 reclaiming the land when operations are complete225.

Shale gas development within or near existing communities has created challenges for production

companies. New technologies have generally allowed these challenges to be met successfully. In 

some cases, a combination of modern shale gas technologies and the innovative use of BMPs 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 paved and 

natural surface pathways. The drilling 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. Maintaining healthy populations of 

upland hardwood forest habitat was important to the community because such woodlots are rare in 

urban settings. 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. The 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 company was able to produce the shale gas, important 

community resources were protected, and at no point in the process was any portion of the trail 

closed226.
MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

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Both horizontal drilling and hydraulic fracturing are 

established technologies with significant track 

records; horizontal drilling dates back to the 1930s 

and hydraulic fracturing has a history dating back to

the 1950s.

EXHIBIT 29: HORIZONTAL AND VERTICAL WELL COMPLETIONS

Source: John Perez, Copyright ©, 2008

The following discussions describe 

the general process of development 

with emphasis on the horizontal 

drilling 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 prevent 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 29). 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 mature227,228,229. 

The technologies utilized by 

operators to drill shale gas wells 

are similar to the drilling 

techniques that 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 to the 1930s and hydraulic fracturing has a history dating 

back to the 1950s

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 wells231. 

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

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economics232. Exhibit 29 illustrates how horizontal 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 formation233. This increase 

in reservoir exposure creates a number of advantages over vertical wells 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 more235. 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 vertical 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 significantly 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 replace 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 technology will significantly 

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 with vertical versus horizontal wells. The spacing interval for 

vertical wells in the gas shale plays averages 40 acres per well for initial development. The spacing 

Source: ALL Consulting, 2008

Active Drilling Rig in the Barnett Shale Play
MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

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interval for horizontal wells is likely to be approximately 160 acres per well. Therefore, 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. Analysis 

performed in 2008 for the U.S. Department 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 well236. 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. In 

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 highlights 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 phases237. The 

development of shale gas utilizing horizontal wells and multi-well pads 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 significantly 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 

resources. 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 habitats

that are susceptible to 

fragmentation238. 

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 city of Flower Mound, Texas, 

ordinances have been adopted to protect the surface resources and allow for future growth of the 

community without detracting from the land value or sense of community. These ordinances 

Source: WVSORO

Drilling Rig in Rural Upshur County, West Virginia
MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

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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 Pennsylvania, wildlife are further 

protected on state 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 habitats for threatened or endangered 

species239.

When disturbances to wildlife habitat are unavoidable, energy companies mitigate land 

disturbances by implementing land reclamation practices to restore disturbed land to original 

conditions. 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 modern 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., reseeding, land contouring, and re-vegetating) can minimize short and long-term disturbances to 

natural habitats240.

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 nuisance impacts are usually limited to the initial 20- to 30-day drilling and completion 

period242. Along with increases in 

traffic volume, damage to road 

surfaces can occur 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 timing 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. In 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: Parker County Commissioner’s Office

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

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reducing traffic and potential damage to roads243. When these practices are coupled with the 

benefits of multiple directional wells from fewer pads, the number of access roads and associated 

traffic can be further reduced.

In many cases, developers have negotiated to compensate local municipalities for road damage that 

does occur as a result of their 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 enterprises244. The Perryman Group, in their 2007 study of the Barnett Shale 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 taxpayers245. 

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, 

respectively. 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 

plans 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 29). 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 remotely 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 Airport is a 

prime example of how development of urban areas is possible with horizontal wellbores246. 

Source: ALL Consulting, 2008

Shale Gas Activity at Dallas-Fort Worth International Airport
MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

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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.

Changes 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 lighting247. This results in the use of 

BMPs 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, Cleburne, Fort Worth, Joshua and North 

Richland Hills, specific ordinances were developed requiring additional permitting, well set backs 

from properties, day-time and night-time noise limits, and directional lighting248. Directional 

lighting provides illumination of well 

sites for worker safety, directing the light 

downward and shielding the surrounding 

area to prevent illuminating neighboring 

residences, roads or other buildings249. 

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 facilities in both rural and 

urban settings250. These sound barriers 

include developing alternative building 

materials with integral sound absorbing 

properties. 

These “BMPs” are not appropriate for all 

operations and must be applied on a caseby-case basis. In some 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 BMPs have certain benefits 

in certain situations, they 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 multiple layers of protective steel casing and 

Source : Chesapeake Energy Corporation, 2008

Insulation Blankets Used to Deaden Noise from 

Drilling Operations
MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

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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 casing 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 30251). 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 casing252. Exhibit 30

illustrates the casing and cement 

that may be installed in shale gas

wells and highlights how the casing 

can be set to isolate different waterbearing 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 serves as a 

foundation for the well construction 

and prevents caving of surface soils. 

The surface casing is installed to 

seal off potential freshwaterbearing 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 comes in 

contact with the fresh water zone. Intermediate casings, when installed, are used to isolate nonfreshwater-bearing zones from the producing wellbore. Intermediate casing may be necessary 

because of a naturally over-pressured zone or because of a saltwater zone 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 protection 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 isolation of each zone is occurring including ensuring that the casing used 

has sufficient strength, and that the cement has properly bonded to the casing254. 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 specify 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

EXHIBIT 30: CASING ZONES AND CEMENT PROGRAMS
MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

53

wildcat wells and may be modified when field rules are designated. These requirements are

instituted by the state oil and gas agency to provide protection of groundwater resources255. 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 the 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 development 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 

formation 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 for those basins in which there was a possibility of casing 

corrosion257. 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 modern 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 between 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 aquifers258. 

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 aquifer, 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 

contaminate 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. 

It would be exposed to lesser volumes of potentially corrosive water flowing 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, [intermediate 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 USDW259. 

As indicated by the analysis conducted by API and others, the potential for groundwater to be 

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 performed 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 surface. 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 

barriers 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 31 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.

EXHIBIT 31: COMPARISON OF TARGET SHALE DEPTH AND BASE OF TREATABLE GROUNDWATER

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

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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 it could 

never be tapped and produced in usable 

quantities. These sealing strata also act as 

barriers to vertical migration of fluids 

upward toward groundwater 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 pressure260. 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. In 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 development 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 drilling261. 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 York262.

In rural areas, storage 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. Closed-loop drilling allows 

for the re-use of drilling fluids and 

the use of lesser amounts of drilling 

fluids263. Closed-loop drilling 

systems have also been used with 

water-based fluids in 

environmentally sensitive environments in combination with air-rotary drilling techniques264. 

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 state oil and gas agencies have the ability to require operators to vary 

standard practices, the agencies typically do so only when it is necessary to protect the gas 

resources and the environment.

In 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 hydraulic fracturing of wells. 

Source: Compiled from Various Data Sources

Source: ALL Consulting, 2008

Lined Fresh Water Supply Pit from the Marcellus 

Shale Development in Pennsylvania
MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

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Stimulations are optimized to 

ensure that fracture development is 

confined to the target formation.

Source: ALL Consulting, 2008

A Fracture Stimulation Is Closely Monitored by 

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 purposes265.

Hydraulic Fracturing

The other technological 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 allowing gas to flow more readily toward the wellbore266,267. Hydraulic fracturing 

can be used to overcome natural barriers to the flow of 

fluids (gas or water) to the wellbore. Such barriers 

may include naturally low permeability common in 

shale formations or reduced permeability resulting 

from near wellbore damage during drilling 

activities268.

Hydraulic fracturing involves the pumping of a fracturing fluid into a formation at a calculated, 

predetermined rate and pressure to generate fractures or cracks in the target formation. For shale 

gas development, fracture fluids 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 fractures once the pumping of fluids has stopped. Once the fracture has initiated, additional 

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 length 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 identifying 

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 processes

designed to emplace fracture networks in 

specific rock strata269. A hydraulic 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 dynamics is 

critical to successful stimulations. Hydraulic 

fracturing designs are continually refined to 

optimize fracture networking and maximize 
MODERN 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 operation can 

vary substantially from basin 

to basin and from well to well.

Fracture design can 

incorporate many 

sophisticated and state-of-theart 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 designs270. 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 32)

271. These simulators 

also allow the designers to use the data gathered during a fracture stimulation to evaluate the

success of the fracture job performed. From these data and analyses, engineers can optimize the

design of future fracture stimulations. 

Additional advances in hydraulic fracturing design target analysis of hydraulic fracture treatments 

through technologies such as microseismic fracture mapping (Exhibit 33272) and tilt 

measurements273. 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 through 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

EXHIBIT 33: MAPPING OF MICROSEISMIC EVENTS

EXHIBIT 32: EXAMPLE OUTPUT OF A HYDRAULIC FRACTURE 

STIMULATION MODEL

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

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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 

strata274. Allowing the fractures to extend beyond 

the 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. Having 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 length of a lateral in a single stimulation event275. 

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 stimulated276. 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 substages, with specific additives and proppant concentrations, is injected sequentially. Exhibit 34277

presents an example of the sub-stages of a single-stage hydraulic fracture treatment for a well

completed in the Marcellus Shale278. 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 34 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 

withstand the application of the fracture treatment pressures and pump flow rates. The 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 process279. It should be noted that construction requirements for wells are mandated by 

state oil and gas regulatory agencies to ensure that a well is protective of water resources and is 

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

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EXHIBIT 34: EXAMPLE OF A SINGLE STAGE OF A SEQUENCED HYDRAULIC FRACTURE 

TREATMENT

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 11 20,000 3,000

Prop 12 20,000 3,000

Prop 13 20,000 3,000

Prop 14 10,000 3,000

Prop 15 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., 2008
MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

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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 with 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 network. 

After the pad is pumped, the first proppant sub-stage, combining a large volume of water with fine 

mesh sand is pumped. The next several sub-stagesin 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 

being carried deeper into the developed fractures280. In this example, the 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 proppant, the well and equipment are

flushed with a volume of freshwater sufficient to remove excess proppants from the equipment and 

the wellbore.

Hydraulic fracturing stimulations are overseen continuously by operators and service companies to 

evaluate and document the events of the treatment

process. Every aspect of the fracture stimulation 

process is carefully monitored, from the wellhead 

and downhole 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 Virginia
MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

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also track the volumes of each additive and the water used, and ensure 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.

The staging of multiple fracture treatments along the length of the lateral leg of the horizontal well 

allows the fracturing 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, the 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 monitored manner into the target 

shale formation above fracture pressure281. 

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 treatment 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 purpose282. 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. 

The 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 microorganism growth and to reduce biofouling of the fractures; oxygen scavengers and other stabilizers to prevent corrosion of metal 

pipes; and acids that are used to remove drilling mud damage within the near-wellbore area284. 

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 deposited in the induced fractures. 

Exhibit 35285 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 varies from one geologic basin or formation to another. Evaluating the relative volumes of the 

components of a fracturing fluid reveals the relatively small volume of additives that are present. 

The additives depicted on the right side of the pie chart represent less than 0.5% of the total fluid 

volume. Overall the concentration of additives in most slickwater fracturing fluids is a relatively 

consistent 0.5% to 2% with water making up 98% to 99.5%.
MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

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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 for the volumes for each additive. In classifying fracturing fluids and 

their additives it is important to realize that service 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 concentration 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 Exhibit 35

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 specific application. 

Most industrial 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. 

When used and handled properly, it is safe for workers and near-by residents and provides clean, 

safe drinking water for the community. Although 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 are common chemicals which people regularly encounter in 

everyday life. 

EXHIBIT 35: VOLUMETRIC COMPOSITION OF A 

FRACTURE FLUID 

Source: ALL Consulting based on data from a fracture operation in the Fayetteville 

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

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EXHIBIT 36: FRACTURING FLUID ADDITIVES, MAIN COMPOUNDS, AND COMMON USES.

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 cosmetics, 

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, laxatives, 

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 deicing agent

Surfactant Isopropanol Used to increase the viscosity of 

the fracture fluid

Glass cleaner, antiperspirant, 

and hair color

Note: The specific compounds 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 fracturing of gas shales. 
MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

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Exhibit 36286 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 these compounds. 

Hydrochloric acid (HCl) is the single largest 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 present 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.

Water Availability

The drilling and hydraulic fracturing of a horizontal shale gas well may typically require 2to 4

million gallons of water287, with about 3 million gallons being most common. It should be noted 

that the volume of water needed may vary substantially 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 37288 presents a table of estimated per-well water needs for four shale gas plays 

currently being developed. 

EXHIBIT 37: ESTIMATED WATER NEEDS FOR DRILLING AND FRACTURING WELLS IN 

SELECT SHALE GAS PLAYS

Shale Gas Play

Volume of Drilling 

Water per well

(gal)

Volume of Fracturing 

Water per well

(gal)

Total Volumes of Water 

per well

(gal)

Barnett 

Shale 400,000 2,300,000 2,700,000

Fayetteville 

Shale 60,000* 2,900,000 3,060,000

Haynesville 

Shale 1,000,000 2,700,000 3,700,000

Marcellus 

Shale 80,000* 3,800,000 3,880,000

* Drilling performed with an 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, 2008
MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

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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 38289. 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 resource use in the shale gas 

basins. Calculations indicate that water use 

will range from less than 0.1% to 0.8% by 

basin290. This volume is small in terms of the 

overall surface water budget for an area; 

however, operators need this water when 

drilling activity 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 projected total demand for peak Marcellus Shale 

activity in the same area is 8.4 million gallons per day291. 

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 seasonal flow differences 

allows planning of withdrawals to avoid potential impacts to municipal drinking water supplies or 

to aquatic or riparian communities. In the Fayetteville Shale play of Arkansas, one operator is

constructing a 500-acre-ft impoundment to store 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 available292 (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 

provide portions of this rural area with water for 

fire protection. Also included is monitoring of instream water quality as well as game and nongame fish species in the reach of river 

surrounding the intake. This design provides a 

water recovery system similar in concept to what 

Source: ALL Consulting, 2008

Little Red River, Arkansas
MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

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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. 

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 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.

Because the development of shale gas is new in some 

areas, these water needs may challenge supplies 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 cumulative 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 water 

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 laws293 .

Water Management

After a hydraulic fracture treatment, when the pumping pressure has been relieved from the well, 

the water-based fracturing fluid, mixed with any natural formation water present, begins 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 TDS294 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 volume of produced water may account for less than 30% to more than 70% of the original 

fracture fluid volume295. In some cases, flow back of fracturing fluid in produced water can 

continue for several months after gas production has begun296. 
MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

67

A suite of circumstances explains 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 the 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. Some of these stranded 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 them 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 been 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 vary by geologic basin and specific rock strata. After initial production, produced 

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 

EXHIBIT 38: ANNUAL RAINFALL MAP OF THE UNITED STATES

Source: NRCS
MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

68

report TDS values greater than 400,000 ppm298. The variation in composition 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 regulatory 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 wells 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 every 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 roads299. 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 treatment plants or commercial treatment facilities. The 

availability of municipal or commercial treatment plants may be limited to larger urban areas 

where treatment facilities with sufficient available capacity already exist. As in underground 

injection, transportation to treatment facilities may or may not be practical300. 

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-use301. The practical use of on-site, selfcontained treatment facilities and the treatment methods employed will be dictated 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 could 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 country302. The completion 

and success of such plants no doubt will be closely tied to the successful expansion of production in 

the various shale gas plays.
MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

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EXHIBIT 39: CURRENT PRODUCED WATER MANAGEMENT BY SHALE GAS BASIN.

Shale Gas Basin

Water Management 

Technology Availability Comments

Barnett Shale

Class II injection wells303 Commercial and noncommercial

Disposal into the Barnett 

and underlying 

Ellenberger Group304

Recycling305 On-site treatment and 

recycling

For reuse in subsequent 

fracturing jobs 306

Fayetteville Shale

Class II injection wells307 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 jobs309

Haynesville Shale Class II injection wells Commercial and noncommercial

Marcellus Shale

Class II injection wells Commercial and noncommercial

Limited use of Class II 

injection wells310,311

Treatment and discharge

Municipal waste water 

treatment facilities, 

commercial facilities 

reportedly 

contemplated312

Primarily in 

Pennsylvania

Recycling On-site recycling For reuse in subsequent 

fracturing jobs313

Woodford Shale

Class II injection wells Commercial Disposal into multiple 

confining formations314

Land Application

Permit required through 

the Oklahoma 

Corporation 

Commission315

Recycling Non-commercial

Water recycling and 

storage facilities at a 

central location316

Antrim Shale Class II injection wells Commercial and noncommercial

New Albany Shale Class II injection wells Commercial and noncommercial
MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

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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. Recycling or reuse of produced water can decrease 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 right317,318. In one case, Devon Energy Corporation (Devon) is 

currently using water distillation units at centralized locations within the Barnett Shale play to 

treat produced water from hydraulic fracture stimulations319. 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 treatment 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 efficient 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 

technologies are being introduced on a regular basis, and some industry researchers 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 additives 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 reused. Treatment and re-use of produced water could reduce water withdrawal needs as well as the 

need for additional 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 naturally 

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 space 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 average 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 exposure321. 

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 radium226 and radium228322, can be brought to the 

surface in drill cuttings and produced water. Radon222, 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

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When NORM is brought to the surface, it remains in the rock pieces of the drill cuttings, remains in 

solution with produced water, or, under certain conditions, precipitates out in scales or sludges323. 

The radiation from this NORM is weak and cannot penetrate dense materials such as the steel used 

in pipes and tanks324.

The principal concern for NORM in the oil and gas industry is that, over time, it can become 

concentrated in field production equipment325 and as sludge or sediment inside tanks and process 

vessels that have an extended history of contact with formation water326. Because the general 

public does not come into contact with 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 operations327,328. 

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 signs 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 federal worker protections, states have 

regulations that require operators to protect 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 wastesd. Instead, states producing oil and gas are responsible for promulgating 

and administering 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 implemented329. 

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 sites. However, smaller sources 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

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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 fracturing 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 exhaust 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 gas into 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 sets 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 

activities330. These emissions and their sources are discussed below.

As in any construction or industrial activity, NOx are formed when fossil fuel is burned to provide 

power to machinery such as compressor 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 40331). Further, oil 

and natural gas production

contributes only 2% of the 

total benzene emissions in 

the U.S.332, and shale gas 

EXHIBIT 40: VOC EMISSIONS BY SOURCE CATEGORY
MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

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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 and 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 42333 shows that CO emissions from the natural gas industry represent a very small part of 

the total334.

SO2 may form when fossil fuels containing sulfur are burned. Thus, SO2 may be emitted from 

gasoline or diesel powered equipment used at a shale gas production site. However, emissions of 

SO2 are typically very small for shale gas operations compared to coal or oil335.

Ozone (O3) itself is not released directly during natural gas development, but two of its main 

precursors, volatile organic compounds (VOCs) and NOx, may combine with sunlight to form 

ground-level O3 which can 

then be associated with 

exploration and 

production operations.

Hydrogen sulfide (H2S)

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 H2S

is encountered as 

production continues, both 

states and operators are 

well equipped to 

EXHIBIT 42: COEMISSIONS BY SOURCE CATEGORY

EXHIBIT 41: BENZENE EMISSIONS BY SOURCE - 1999
MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

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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 H2S.

The American Petroleum Institute (API) has a Recommended Practice (RP 49) for Drilling and Well 

Servicing Operations Involving H2S336. Producers voluntarily follow this practice to minimize the 

release of and exposure to H2S. In areas where concentrations of H2S may exceed 10 parts per 

million (ppm), producers implement an H2S contingency plan. The plan includes appropriate 

instruction in the use of hydrogen sulfide safety equipment to all personnel present at all hydrogen 

sulfide hazard areas, gas detection where hydrogen sulfide may exist, and appropriate respiratory 

protection for normal and emergency use. 

Methane (CH4) 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, CH4 may be released as a 

fugitive emission from gas processing equipment, especially equipment in high pressure service 

such as pneumatic controls. Producers have strong economic incentives to limit fugitive methane 

emissions to the greatest degree possible in 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 NOx emissions from their engines. One key has 

been the use of catalytic technologies to chemically convert NOx 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 NOx 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 NOx emissions 

standards regardless of engine 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—upgrading 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 activities. 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 emissions338. 

The primary goals of the program are to promote technology transfer and implement cost-effective 

BMPs while reducing CH4 emissions. The program provides information on many practices that not 

only reduce CH4 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

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Some of the most effective and economic technologies promoted by this program include:

1. Identification of high-bleed pneumatic devices (transducers, valves, controllers, etc.) and 

replacement 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 

functions while releasing much smaller 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 are 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 the use of dehydrators. This 

can recover 90 to 99% of the methane that would otherwise be flared or vented into the 

atmosphere339.

4. Performance of green well completions and workovers. These shale gas operations 

typically use portable equipment to process and 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. That captured gas is now retained and sold to market340.

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 advancing the recovery and use of methane as a valuable clean energy source341. 

The program includes the oil and gas sector as a focus area along with coal mines, landfills, and the 

agricultural business. There are approximately 400 program members across the globe 

representing the oil and gas sector342. 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 period343. 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 technologies 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, toluene, ethylbenzene, 

and total xylenes (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 as well as the optimization of
MODERN 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.

As with all operational practices, these BMPs must be applied on a case-by case basis. In some 

cases a given BMP may actually 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 required.

State 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 emission 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 conventional 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 contrary, 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 development 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 fracturing 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 thousands of feet of rock 

between the fracture zone and any fresh or treatable aquifers. The multi-stage hydraulic fracture 

operations used in horizontal wells may 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 continue 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 

occurring radioactive material (NORM) 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 safety
MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

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Although the use of natural 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 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 

voluntary avoidance, minimization, and mitigation strategies. 

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.
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ACRONYMS AND ABBREVIATIONS

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

CH4 Methane

CO Carbon Monoxide

CO2 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 Planning 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

H2S Hydrogen Sulfide

HAP Hazardous Air Pollutant

HCl Hydrochloric acid

IOGCC Interstate 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 Laboratory
MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

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NORM Naturally Occurring Radioactive Material

NOx Nitrogen Oxides

NPDES National Pollution Discharge Elimination System

NYDEC New York State Department of Environmental Conservation

O3 Ozone

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 Reportable Quantity

SARA Superfund Amendments and Reauthorization Act

SCF standard cubic feet

SDWA Safe Drinking Water Act

SO2 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 year
MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

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DEFINITIONS

AIR QUALITY. A measure of the amount of pollutants emitted into the atmosphere and the 

dispersion 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-burning 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 reduce 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 gas well.

CORRIDOR. A strip of land through which one or more existing or potential utilities may be colocated.

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 diameter pipeline that generally connects a well to the initial processing 

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

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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; source 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, breeding space, and living space.

HORIZONTAL DRILLING. A drilling procedure in which the wellbore is drilled vertically to a kickoff 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 underground 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, the 

tract of land, on which a lease has been obtained, where producing wells and production equipment 

are located.

NORM (Naturally Occurring Radioactive Material). Low-level, radioactive material that 

naturally exists in native materials.

ORIGINAL GAS- IN- PLACE The 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). 

PM10 refers to particulate matter having a size diameter of less than 10 millionths of a meter (micrometer) and PM2.5 being less than 2.5 micro-meters in diameter.

PERMEABILITY. A rock’s capacity to transmit a fluid; dependent 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 interconnected. 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 to 
MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

83

address local conditions. Once these state programs are approved by the relevant 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 formation 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, economically, 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 based 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 rights of a given area are 

owned by different persons or entities; also 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 (SO2). A colorless gas formed when sulfur oxidizes, often as a result of burning 

trace amounts of sulfur in fossil fuels.

TECHNICALLY RECOVERABLE RESOURCES 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 pressure 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 danger 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 state, or Indian tribe under the Safe Drinking Water Act 

to ensure that subsurface emplacement of fluids does not endanger underground sources of 

drinking water.

UNDERGROUND SOURCE OF DRINKING WATER (USDW). 40 CFR Section 144.3 An aquifer or its 

portion:

(a) (1) Which supplies any public water system; or

(2) Which contains a sufficient 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 Completion.

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 2008 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/shelltables.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.

17EIA. 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. 

http://www.eia.doe.gov/pub/oil_gas/natural_gas/analysis_publications/natural_gas_1998_issues_trends/pdf/it98.pdf. April 1999.

21 Ibid.

22NaturalGas.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 Projections 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 Producers. Producing 

Today‟s Clean Energy, Ensuring Tomorrow‟s Innovation. http://www.ipams.org/media/docs/Callupdraft10.pdf. Accessed: 

September 2008.

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.

29Chemistry 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.

38BP. 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 Assessment. 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 Williams, 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_production.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.

53CERA. 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 and 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 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.

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 and 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.

67Cohen, 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 Approach 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: Igniting a Hunt for Unconventional Natural Gas Resources.

http://geology.com/research/barnett-shale-gas.shtml. Accessed: September 2008.

73Boyer, 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 and V. Jochen. Schlumberger 

Marketing Communications. October 2005.

75 Davis ,R., Jr. 1992. Depositional Systems: An Introduction to Sedimentology and Stratigraphy. Prentice Hall. 2nd Edition. 

1992.

76 Freeze, R., and J. Cherry. 1979. Groundwater. Prentice Hall. 1979.

77 Nuttal, B.C. 2007. Kentucky Geological 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 Frantz, 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 

Potential 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. Unconventional Challenges. 2008.

84

 Ibid.

85

 Ibid.

86 Navigant Consulting. 2008. North American Natural Gas Supply Assessment. Prepared for American Clean Skies 

Foundation. July 4, 2008.

87 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.

88 Ibid.

89 Ibid.

90 Ibid.

91Boughal, K. 2008. Unconventional Plays Grow in Number After Barnett Shale Blazed the Way. World Oil Magazine. v 229, 

no 8. August 2008.

92Berman, 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 Barnett 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.

100Berman, 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.searchanddiscovery.net/documents/2007/07101nyahay/index.htm. October 1, 2007.

102Cardott, 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.

107Berman, 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 Evaluation. 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. November 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 2008.

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 Skies 

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.

132Railroad Commission of Texas. 2009. Newark, East (Barnett Shale) Field. 

http://www.rrc.state.tx.us/data/fielddata/barnettshale.pdf. Accessed March 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.

137Boughal, 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=NogaNewGISResultsServ&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 Institute. 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 Fracturing 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.

150Cardott, B. 2007. Oklahoma Geological Survey. Overview of Woodford Gas-Shale Play in Oklahoma. 2007.

151Boughal, K. 2008. Unconventional Plays Grow in Number After Barnett Shale Blazed the Way. World Oil Magazine. v 229, 

no 8. August 2008. 

152Cardott, 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. 2005. Pickering Energy Partners, Inc. The Barnett Shale: Visitor‟s Guide to the Hottest Gas Play 

in the US. October 2005.

157Catacosinos, 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.uiuc.edu/maps-datapub/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.

167Richard Hills, Texas, Gas Well Ordinance. Ordinance 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. Regulation 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. Administrative 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 Gas Extraction Point Source Category. 40 CFR Part 435. http://ecfr.gpoaccess.gov/cgi/t/text/textidx?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.

178NRDC v. EPA. 9th 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. Accessed: 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. April 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. January 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.
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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 Program. http://www.epa.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.

191Clean 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 Environmental 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 Ignition 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 Register 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 Volume 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 Geothermal 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 Administration. Electronic Code of Federal Regulations. Wildlife and Fisheries. Endangered 

and Threatened Wildlife and Plants. 50 CFR Part 17. http://ecfr.gpoaccess.gov/cgi/t/text/textidx?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.

208Christman, J., and V. Albrecht. 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 Environmental Documents. October 2004.
MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

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210Construction 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 Species Related Laws, Regulations, 

Policies & Notices. http://www.fws.gov/Endangered/policy/index.html. Accessed: September 2008.

213 Ibid.

214Construction Industry Compliance Assistance (CICA). The 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 Production Operators in Five 

Key States. 1996.

218 IPAA. 2000. Environment & Safety Fact Sheets. IPAA Opposes EPA's Possible Expansion of TRI. 

http://www.ipaa.org/issues/factsheets/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 and Gas Commission. Mission Statement. http://www.aogc.state.ar.us/mission.pdf. Accessed: September 

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.

224Bureau 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.

225Bonner, T., and L. Willer. 2005. National Association of Royalty Owners, Inc (NARO). The New Generation. Royalty 

Management 101: Basics for Beginners and a Refresher Course for Everyone. 25th 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 

Natural 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 Unconventional 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, Pennsylvania Department of Conservation and 

Natural 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 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.

233 Ibid.

234 Marshall Miller & Associates, Inc. Marcellus Shale. Presented to: Fireside Pumpers in Bradford, PA.
MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

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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 Foreseeable Development Scenario for Fluid Minerals: Arkansas. 

Prepared for the Bureau of Land Management Eastern States Jackson Field Office. March 2008.

237Bromley, M. 1985. U.S. Department of Agriculture, Forest Service, Intermountain Research Station. Ogden, Utah. Wildlife 

Management Implications of Petroleum Exploration and Development in Wildland Environments. General Technical Report 

INT-199. 1985.

238Catskill Mountainkeeper. The Marcellus Shale – America's next super giant. http://catskillmountainkeeper.org/node/290. 

Accessed: October 2008.

239 Venesky, T. 2008. State-Owned 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 Interior and United States Department of Agriculture. 2007. Surface Operating Standards 

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. Coal 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 in Select Natural Gas Shale Plays. Presented at the GWPC Annual Meeting. September 2008.

244 Douglas, 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 Parshall, J. 2008. Barnett Shale Showcases Tight-gas Development. 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.

249Chesapeake Energy Corporation. 2008. 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.

252Bellabarba, 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 the Life of the Well. Oilfield Review. Spring 2008.

253Railroad Commission of Texas (RRC). http://www.rrc.state.tx.us/. Accessed: September 2008.

254Bellabarba, 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 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

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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 Company. 1965. 

Mechanism of Drilling Wells with Air as the Drilling Fluid. SPE 1052-MS.

262 Kennedy, 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 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.

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.

269Boyer, 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 Schlumberger. 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. Sixth 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. 

276Chesapeake Energy Corporation. 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..

280Cramer, D. Stimulating Unconventional Reservoirs: Lessons Learned, Successful Practices, Areas for Improvement. SPE 

114172.

281 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..

282 Schlumberger. 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

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284 Schlumberger. PowerSTIM. http://www.slb.com/content/services/stimulation/fracturing/powerstim.asp? Accessed: 

September 2008.

285Compiled 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.

292Chesapeake 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. Chesapeake Energy Corp. Managing 

Water Resource‟s Challenges in Select Natural 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 Willberg, D.M., N. Steinsberger, R. Hoover, R. J. Card, and J. Queen. 1998. 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. Chesapeake 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. Published by the Bureau of Topographic and Geologic Survey, Pennsylvania Department of Conservation and 

Natural Resources.

301Railroad Commission of Texas (RRC). v2008.v Water Use in the Barnett Shale. 

vhttp://www.rrc.state.tx.us/divisions/og/wateruse_barnettshale.html. vUpdated: vJune 30, 2008. vAccessed: vOctober 2008.

302 Personal communication with a variety of producing and service companies operating in shale gas basins. 2008.

303Burnett, 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.

304 Grable, R.C. 2008. Kelly Hart & Hallman, Attorneys at Law. Saltwater Disposal and Other “Hot Issues” in Urban Drilling. 

Safety-Wellbore. Presented at the 19th Annual State Bar of Texas Advanced Real Estate Drafting Course in Dallas. February 29, 

2008.

305Burnett, 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 National Laboratory. Fayetteville Shale Natural Gas: Reducing Environmental Impacts. 

Well Production and Water Management. http://lingo.cast.uark.edu/LINGOPUBLIC/index.htm. Accessed: October 2008.

308 Ibid.

309University 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

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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 Pennsylvania Department of Environmental Protection, Bureau of Oil and Gas Management. 

October 2008.

312 Personal communication with operators and service industry personnel in the Pennsylvania area. October 2008.

313University 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.

314 Personal communication with Tim Baker from Oklahoma Corporation Commission, Oil and Gas Conservation Division. 

October 16, 2008.

315 Ibid.

316 Ibid.

317Burnett, 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 19th Annual State Bar of Texas Advanced Real Estate Drafting Course in Dallas. February 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.html. 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. Environmental 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 American Oilfields A Fact Sheet from the American 

Petroleum Institute. 2004.

326Barnett 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: September 

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. Accessed: September 2008.

332 EPA. Technology 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. Accessed: September 2008.
MODERN SHALE GAS DEVELOPMENT IN THE UNITED STATES: A PRIMER

96

 

334 Ibid.

335 Triplepundit. 2008. Shale Gas: Energy Boon or Environmental Bane, Part One . www.triplepundit.com/pages/shale-gasenergy-boon-or-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. Processing 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/houstonoct26/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/pnmList.aspx?type=oil. 

Accessed: September 2008.

343 Methane to Markets. Methane Partnership Program s. www.epa.gov/methanetomarkets/partnership.htm. Accessed: 

September 2008.
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U.S. Department of Energy

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www.fossil.energy.gov 

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