September 2008

Working Draft

An Assessment of the 

Environmental Implications 

of Oil and Gas Production: 

A Regional Case Study 

EPA 

Region 8 

Table of Contents 

Acronyms ....................................................................................................................................................................... iii

Executive Summary.................................................................................................................................................. ES-1

1.0 Introduction ...................................................................................................................................................... 1-1

1.1 Objective ................................................................................................................................................ 1-1

1.2 Approach................................................................................................................................................ 1-1

1.2.1 Framing the Study: Oil and Gas Production in Region 8............................................................ 1-1

1.2.2 Focus of the Report.................................................................................................................... 1-3

1.3 Organization of the Report ..................................................................................................................... 1-5

2.0 Background ...................................................................................................................................................... 2-1

2.1 Importance of Region 8 to Domestic Oil and Gas Production................................................................ 2-1

2.2 Unique Characteristics of Region 8........................................................................................................ 2-2

2.2.1 Oil and Gas Production .............................................................................................................. 2-2

2.2.2 Geological Characteristics.......................................................................................................... 2-5

2.2.3 Other Natural Characteristics ..................................................................................................... 2-6

2.3 Key Policy Issues Associated With Oil and Gas Production .................................................................. 2-7

2.3.1 Air Issues.................................................................................................................................... 2-8

2.3.2 Water Issues............................................................................................................................. 2-13

2.3.3 Land Use Issues....................................................................................................................... 2-18

3.0 Environmental Releases.................................................................................................................................. 3-1

3.1 Data Sources and Assumptions ............................................................................................................. 3-1

3.1.1 2002 Data Sources and Assumptions ........................................................................................ 3-1

3.1.2 2006 Data Development Assumptions ....................................................................................... 3-3

3.2 Estimated Air Emissions: Comparing 2002 Baseline to 2006 Estimates ............................................... 3-5

3.3 Estimated Non-Air Releases (Produced Water and Drilling Waste), 2002 and 2006............................. 3-8

3.3.1 Produced Water Summary ......................................................................................................... 3-9

3.3.2 Produced Water Management and Implications....................................................................... 3-12

3.3.3 Drilling Waste Summary........................................................................................................... 3-12

3.3.4 Drilling Waste Management and Implications .......................................................................... 3-13

4.0 Summary........................................................................................................................................................... 4-1

4.1 Summary of Data Findings..................................................................................................................... 4-1

4.2 Summary of Initiatives to Address Oil and Gas Demand and Environmental Footprint Issues.............. 4-3

4.2.1 Federal Initiatives ....................................................................................................................... 4-4

4.2.2 State Initiatives ........................................................................................................................... 4-5

4.2.3 Regional Initiatives ..................................................................................................................... 4-5

4.2.4 Other Ongoing Analyses and Policy Initiatives........................................................................... 4-5

4.2.5 Voluntary Programs.................................................................................................................... 4-6

Appendix A: Industry Characterization...........................................................................................................................A-1

Appendix B: Pollution Sources in the Oil and Gas Industry ...........................................................................................B-1 

Appendix C: Data Availability and Sources....................................................................................................................C-1 

Appendix D: Air Emissions Sources by Source Category and Equipment Type ...........................................................D-1 

Appendix E: References ................................................................................................................................................E-1 

U.S. Environmental Protection Agency Working Draft – September 2008 i
Table of Tables 

Table 3-1. Methodology to Develop 2006 Data, by Pollutant......................................................................................... 3-4 

Table 3-2. Oil and Gas Criteria Pollutant Emissions Compared to Total Region 8 Criteria Pollutant Emissions, 2002 

(tons).............................................................................................................................................................................. 3-5 

Table 3-3. Criteria Pollutant Emissions by Pollutant, by State, 2002 (tons)................................................................... 3-6 

Table 3-4. Criteria Pollutant Emissions by Pollutant, by State, 2006 (tons)................................................................... 3-6 

Table 3-5. Non-Criteria Pollutant Air Emissions by Pollutant, by State, 2002 (tons) ..................................................... 3-7 

Table 3-6. Non-Criteria Pollutant Air Emissions by Pollutant, by State, 2006 (tons) ..................................................... 3-7 

Table 3-7. Total Point and Area Emissions of VOCs, NOx, SO2, CO, and HAPs, by State, 2002 (tons)....................... 3-7 

Table 3-8. Total Point and Area Emissions of VOCs, NOx, SO2, CO, and HAPs, by State, 2006 (tons)....................... 3-8 

Table 3-9. Produced Water by State, 2002 and 2006 (barrels) ..................................................................................... 3-9 

Table 3-10. Produced Water by Well Type, 2002 (barrels).......................................................................................... 3-10 

Table 3-11. Produced Water by Well Type, 2006 (barrels).......................................................................................... 3-10 

Table 3-12. Characteristics of CBM-Produced Water.................................................................................................. 3-11 

Table 3-13. Drilling Waste by State, 2002 and 2006 (barrels)..................................................................................... 3-13 

Table 4-1. Region 8 Versus National Oil and Gas Air Emissions/ Produced Water/Drilling Waste, 2006 (tons/barrels)4-2 

Table 4-2. Summary of Voluntary Environmental Programs Available to the Oil and Gas Sector.................................... 7 

Table of Figures 

Figure 1-1, Conventional vs. Unconventional Gas Production ...................................................................................... 1-2 

Figure 2-1. EPA Region 8 with Tribal Lands.................................................................................................................. 2-2 

Figure 2-2. Total Dry Gas Production in the Lower 48 by Region, 1998—2005............................................................ 2-3 

Figure 2-3. Active Oil and Gas Rigs in Region 8, 2000—2006...................................................................................... 2-4 

Figure 2-4. Total Crude Oil Production in the Lower 48 by Region, 1998—2005.......................................................... 2-4 

Figure 2-5. Rocky Mountain States’ Oil and Gas Producing Regions ......................................................................... 2-19 

U.S. Environmental Protection Agency Working Draft – September 2008 ii
Acronyms

ACEC Areas of critical environmental concern 

ANL Argonne National Laboratory (DOE) 

APEN Air Pollution Emission Notice 

API American Petroleum Institute 

Bbl Billion barrels 

Bcf Billion cubic feet 

BLM Bureau of Land Management within the U.S. Department of Interior 

BMP Best management practice 

CAA Clean Air Act 

CBM Coal bed methane 

CEM Continuous emissions monitor 

CERR Consolidated Emissions Reporting Rule 

CH4 Methane 

CI Chemical injection 

CO Colorado 

CO Carbon monoxide 

CO2 Carbon dioxide 

COSTIS Colorado Storage Tank Information System 

CWA Clean Water Act 

DART Days Away Restricted or Transferred 

DOE U.S. Department of Energy 

DOI U.S. Department of the Interior 

DOL U.S. Department of Labor 

E&P Exploration and production 

EAC Early action compact 

EDMS Emissions Data Management System 

EIA U.S. Energy Information Administration (DOE) 

ELG Effluent limitations guideline 

EOR Enhanced oil recovery 

EPA U.S. Environmental Protection Agency 

EPAct Energy Policy Act of 2005 

FERC U.S. Federal Energy Regulatory Commission 

FRB U.S. Federal Reserve Board 

FWS U.S. Fish and Wildlife Service (DOI) 

Gal Gallon 

GHG Greenhouse gas 

GPM Gallons per minute 

GWP Global warming potential 

HAP Hazardous air pollutant 

H2S Hydrogen sulfide 

HR U.S. House of Representatives 

HSM Hydrocarbon Supply Model 

IC Internal combustion 

U.S. Environmental Protection Agency Working Draft – September 2008 iii
ICE Internal combustion engine 

IHS IHS Inc. 

Lb Pound 

LDAR Leak detection and repair 

Mcf Thousand cubic feet 

MMscfd Million standard cubic feet per day 

MMcf Million cubic feet 

MT Montana 

NAAQS National Ambient Air Quality Standards 

NAICS North American Industry Classification System 

ND North Dakota 

NPDES National Pollutant Discharge Elimination System 

NEI National Emission Inventory 

NESHAP National Emission Standards for Hazardous Air Pollutants 

NETL National Energy Technology Laboratory (DOE) 

NFA No further action 

NGL Natural gas liquids 

NGO Non-governmental organization 

NH3 Ammonia 

NOx Nitrogen oxides 

NRDC Natural Resources Defense Council 

NSPS New Source Performance Standard 

NWF National Wildlife Federation 

O&G Oil and gas 

OCS Outer Continental Shelf 

OECA Office of Enforcement and Compliance Assurance (EPA) 

OGAP Oil & Gas Accountability Project 

OPEI Office of Policy, Economics, and Innovation (EPA) 

OSHA Occupational Safety and Health Adminstration (DOL) 

OW Office of Water (EPA) 

PAH Polyaromatic hydrocarbon 

Pb Lead 

PM Particulate matter 

PM2.5 PM with an aerodynamic diameter less than or equal to a nominal 2.5 

micrometers 

PM10 PM with an aerodynamic diameter less than or equal to a nominal 10 

micrometers 

PM10_PRI Primary PM10 

PTRCB Petroleum Tank Release Compensation Board 

QA Quality assurance 

RAPP Refuges Annual Performance Plan 

RAQC Regional Air Quality Council 

RCRA Resource Conservation and Recovery Act 

RHR Regional Haze Rule 

RICE Reciprocating internal combustion engine 

RMP Resource Management Plan 

U.S. Environmental Protection Agency Working Draft – September 2008 iv
ROD Record of Decision 

RRC Railroad Commission of Texas 

SAR Sodium adsorption rate 

SCC Source classification code 

SD South Dakota 

SDWA Safe Drinking Water Act 

SGE Special Government Employee 

SIC Standard Industrial Classification 

SIP State Implementation Plan 

SO2 Sulfur dioxide 

SOx Sulfur oxide 

Tcf Trillion cubic feet 

TDS Total dissolved solids 

TIP Tribal Implementation Plan 

UIC Underground injection control 

U.S. United States 

USACE U.S. Army Corps of Engineers 

USDW Underground source of drinking water 

USGS U.S. Geological Survey (DOI) 

UT Utah 

VISTAS Voluntary Innovative Strategies for Today’s Air Standards 

VOC Volatile organic compound 

VPP Voluntary Protection Programs 

VRP Voluntary Remediation Program 

WCI Western Climate Initiative 

WGA Western Governors’ Association 

WDEQ Wyoming Department of Environmental Quality 

WESTAR Western States Air Resources Council 

WRAP Western Regional Air Partnership 

WY Wyoming 

Yr Year 

U.S. Environmental Protection Agency Working Draft – September 2008 v
EXECUTIVE SUMMARY 

Executive Summary 

Oil and gas exploration and production within the Rocky Mountain region is 

experiencing rapid growth. The environmental implications of these and other energy 

production activities are a major area of focus for the U.S. Environmental Protection 

Agency (EPA). Headquartered in Denver, Colorado, the EPA regional office (Region 8) 

partners with other federal agencies, state agencies, and Tribal governments to provide

primary environmental oversight of oil and gas activities in Colorado, Montana, North 

Dakota, South Dakota, Utah, and Wyoming. In addition, EPA’s national partnership with 

the Interstate Oil and Gas Compact Commission (IOGCC) is integral to continued 

communications, coordination, and collaboration regarding environmental oversight of 

oil and gas production. 

The dramatic upsurge in regional oil and gas production in recent years is expected to 

continue. Indeed, various studies predict that the Rocky Mountain region - which 

includes major coal bed methane (CBM), tight gas sands, and shale gas production areas - 

will remain vital to U.S. natural gas production in the decades to come. At the same time, 

many of the region’s oil and gas reserves are located in ecologically sensitive areas, 

raising concerns about the environmental impacts of production. These concerns continue 

to emerge and expand. 

This report is intended to serve as a technical resource for policy makers, environmental 

managers, and other stakeholders focused on oil and gas production. In taking an in-depth 

look at available data on environmental releases from multiple sources, the report 

investigates a number of relevant environmental performance trends and management 

challenges; analyzes current and projected production impact data; offers policy insights 

into current initiatives; and offers examples of environmental stewardship. 

Objectives Summarized 

This report was produced to assist the EPA Office of Policy, Economics, and Innovation 

(OPEI) in assessing environmental impacts associated with oil and gas production in 

Region 8. The report discusses several state, regional, and national policy initiatives 

designed to effect environmentally responsible oil and gas production. In addition, the 

report’s findings are intended to inform current and future agency deliberations regarding 

oil and gas production nationally. 

Through this analysis, the EPA Sector Strategies Program seeks to provide new 

knowledge and insights regarding the environmental releases associated with oil and gas 

production. The report also identifies some of the challenges associated with acquiring 

and analyzing relevant environmental impact data. By focusing on key energy 

development issues and associated production impacts in a strategically important and 

resource-rich region, one that is experiencing unprecedented growth in oil and gas 

activities, we hope to provide valuable environmental management insights and share 

them broadly with policy makers, environmental managers, and other key stakeholders. 

U.S. Environmental Protection Agency Working Draft – September 2008 ES--1 
EXECUTIVE SUMMARY 

Region 8’s Distinctive Oil and Gas Industry Characteristics 

The oil and natural gas resources in Region 8 are distinct from other reserves located in 

the United States. Rich in unconventional natural gas reserves, production in Region 8 is 

increasingly focused on tight gas sands in Colorado and Wyoming (e.g., Washakie 

Basin); large oil shale reserves in western Colorado, northeastern Utah, and southwestern 

Wyoming; shale gas in Montana and North Dakota (e.g., the Bakken Shale); and CBM 

formations such as the Powder River basin in Wyoming and Montana and the Raton 

Basin that stretches from Colorado to New Mexico.1

 Significant natural gas resources are 

steadily gaining increased focus within the region. Representative examples include the 

tight gas sand formations in the Green River Basin of northwestern Wyoming and the 

Piceance Basin of northwestern Colorado. Regional increases in oil and gas production 

are demonstrated by the following statistics: 

• In recent years, gas production has increased the most in Colorado and Wyoming; in 

2005, these two states made up 54 percent of total production in the west and 

comprised 15 percent of total U.S. production.2

 The largest expected growth in gas 

production in the United States is expected to occur within these two states.

3

 

• Oil production does not play as large a role in overall fuel production in Region 8. The 

Rockies represent only about 6 percent of total U.S. oil production,4 and this fraction 

has not changed significantly in recent years. This stagnant crude oil production rate 

can be observed in Chapter 2, Figure 2-4. 

• In terms of new oil wells, the Rockies represent about 13 percent of national activity. 

This fraction has increased from 5 percent in 2000 due to expanding exploration and 

production in Colorado’s Denver Basin and the Uinta Basin of Utah. 

• Potential recoverable resources in Rocky Mountain tight sands are estimated to be 

several hundred trillion cubic feet (TCF) of natural gas, compared to current proved 

reserves of about 190 Tcf for the United States as a whole. The vast size of the tight 

gas sands resource base within the region suggests that extraction activities are likely 

to expand and continue on for decades to come. 

• The Powder River Basin in eastern Wyoming started CBM production in the 1980s, 

gained prominence in the late 1990s, and currently produces about 1 billion cubic feet 

(Bcf) of CBM gas per day (an amount that is greater than 50% of all U.S. CBM 

production). 

• Shale gas exploration and production activities are increasing across the nation, 

including the Bakken shale in Montana and North Dakota. 

 

1

 “Tight gas” refers to natural gas found in usually impermeable and nonporous formations, such as limestone or 

sandstone, which require advanced well stimulation efforts, such as fracturing or acidizing, to optimize resource 

extraction. “Coal bed methane” refers to natural gas trapped in underground coal seams that can be extracted before 

mining the coal (in some cases, the coal seams are very deep or of low quality, in which case CBM is the only 

hydrocarbon extracted from the seam). 

2

 U.S. Federal Energy Regulatory Commission (FERC), Natural Gas Markets: Western, http://www.ferc.gov/marketoversight/mkt-gas/western.asp#prod. 3

 U.S. Department of Energy (DOE), Energy Information Administration (EIA), Natural Gas Pipelines in the Central 

Region, http://www.eia.doe.gov/pub/oil_gas/natural_gas/analysis_publications/ngpipeline/central.html. 4

 Based on 2006 data. 

U.S. Environmental Protection Agency Working Draft – September 2008 ES--2 
EXECUTIVE SUMMARY 

• A recent report by the Rand Corporation estimated that between 500 billion and 1.1 

trillion barrels of oil are technically recoverable from high-grade oil shale deposits 

located in the Green River formation in Colorado, Utah, and Wyoming. Although 

these deposits have yet to be commercially developed. EPA and other government 

agencies are investigating and addressing the relevant environmental and natural 

resource implications of potential oil shale production in Region 8. 

Technical Approach 

Unconventional oil and gas resources generally require more wells, greater energy and

water consumption, and more extensive production operations per unit of gas recovered 

than conventional oil and gas resources, due to factors such as closer well spacing and 

greater well service traffic. Thus, they have the potential for greater environmental 

impacts. Due to these resource characteristics, oil and gas extraction in the Rocky 

Mountain region has a somewhat different environmental footprint than oil and gas 

production in other regions, providing an additional reason for focusing this analysis on 

Region 8. Section 2.2 and Appendix A provide further details on the unique 

characteristics of Region 8 and Section 2.3.2 provides details on produced water from 

CBM. 

• The primary environmental impacts associated with oil and gas production detailed in 

this report are related to three main releases: air emissions, produced water, and 

drilling waste. Concerns about potential groundwater impacts have surfaced with 

respect to individual projects in Region 8; however, reported incidents have not 

proven to be a region-wide trend. Nevertheless, these groundwater incidents and the 

environmental issues they raise may warrant further investigation by EPA and others. 

Using predominantly 2002 baseline data, we estimated 2006 emissions for air and 

water as well as drilling wastes from oil and gas production activities in Region 8. 

• 5The primary air pollutants of interest are nitrogen oxides (NOx), sulfur dioxide (SO2),

and particulate matter (PM) as precursors of regional haze, and NOx and volatile 

organic compounds (VOCs) as precursors of ground level ozone. NOx emissions are 

primarily from production operations and equipment such as engines (both stationary 

and mobile), turbines, and process heaters. VOCs constitute the largest absolute 

component of regulated emissions, primarily fugitive emissions including some 

hazardous air pollutants (HAPs) such as benzene, toluene, ethyl benzenes, and 

xylenes. SO2 emissions are primarily related to combustion in the oil production 

sector. For more information about these air pollutants, please refer to Section 3.2. As 

for the production processes mentioned here, additional details are provided in 

Appendix A, Section A.1. 

• For VOC and HAPs emissions, we found that smaller sources (“area sources,” in the 

data set we relied on) collectively contributed more emissions than larger, “point 

sources”. 

 

5

 Oil spills, although they occur from time to time in oil and gas production, are not addressed in the context of this report 

due to data and other analytical limitations. This report focuses mainly on production impacts that occur within the course 

of normal drilling and resource recovery operations. 

U.S. Environmental Protection Agency Working Draft – September 2008 ES--3 
EXECUTIVE SUMMARY 

• In addition to CAA-regulated air pollutants, oil and gas production produces 

greenhouse gas (GHG) emissions. Fugitive methane (CH4) emissions constitute the 

largest source of global warming potential-weighted (GWP-weighted) GHG 

emissions. CO2 emissions from process heaters were about 206,000 tons and from 

internal combustion (IC) engines (such as compressors) were about 6.4 million tons in 

2006 per our report’s estimate. 

• CBM formations in the Rocky Mountain region initially release large volumes of 

produced water as natural gas is being extracted, which, depending on the water 

quality, can be released to the surface, treated in place, or reinjected. The amount of 

produced water by state is discussed in Section 3.3.1. 

• Unconventional gas extraction tends to produce greater surface disturbances and 

drilling waste in comparison to conventional gas extraction because of tighter well

spacing and the need for fracturing. The amount of drilling waste by state is discussed 

in Section 3.3.2. 

Key Environmental Impact Findings 

This analysis produced the following overarching insights: 

• This analysis showed that emissions from oil and gas production in Region 8 

constitute a sizable share of total U.S. emissions from this sector (ranging from 6 

percent for PM to 30 percent for HAPs; see Chapter 4, Table 4-1), reflecting the 

significance of Region 8 production nationally. As shown in Chapter 3, Table 3-2, 

within the region, oil and gas air emissions are the largest for VOCs, comprising 

over 40 percent of the regional total in 2002. Emissions of NOx, CO, and SO2 

contribute approximately 15 percent, 9 percent, and 4 percent to the regional totals, 

respectively. 

• The report (see Chapter 3, Table 3-7) presents air emissions by major source 

category—point and area—by state. VOCs, NOx, SO2, CO, and HAPs are the only 

pollutants shown, since data are available by type of major source. For VOCs and 

HAPs, the table reveals area sources are a much greater contributor to emissions 

than point sources in Region 8. For NOx and CO emissions, point and area sources 

both contribute significantly to total emissions. The area source fraction is slightly 

larger for NOx and the point source component is larger for CO. NOx and CO 

emissions are primarily from large combustors (point sources) as well as small 

combustors and mobile sources (area sources). 

• PM emissions from the oil and gas industry in Region 8 are negligible, with some data

indicating they are less than 0.1 percent of the regional total. Despite the 

inconsistencies in available particulate data sets, it’s clear that with certain areas not 

meeting current air quality standards and oil and gas production on the rise, these and 

other air quality impacts are growing areas of concern within Region 8 (and 

nationally). 

• Per the report’s estimating methodology for produced water, almost 3 billion barrels of 

water were produced in Region 8 in 2006, with Wyoming contributing approximately 

U.S. Environmental Protection Agency Working Draft – September 2008 ES--4 
EXECUTIVE SUMMARY 

71 percent of total produced water (for both oil and gas) from the region (see Chapter 

3, Table 3-9). Produced water may require water management and treatment or may 

sometimes be clean enough to be used for irrigation and agricultural purposes without 

prior treatment. 

• Developing unconventional natural gas fields often requires fracturing, or “fracing,” 

the target resource by injecting water and chemicals into the formation, which can 

potentially affect groundwater sources. 

• Region 8 also produced more than 46 million barrels of drilling waste in 2006 (see 

Chapter 3, Table 3-13). Directly related to increased rig activity, the largest amount of 

drilling waste was generated in Wyoming, followed by Colorado and Utah. Reuse or 

disposal of drilling waste, along with further disturbance of surface areas due to oil 

and gas production (e.g., through construction of roads and operation of drilling rigs in 

wilderness and undeveloped areas), are highly visible issues involving industry 

stewardship and regulatory oversight. 

• Non-governmental organizations (NGOs), Congressional oversight bodies, and other 

stakeholder groups and citizens have issued studies or scrutinized the environmental 

implications and potential risks of expanding oil and gas production on public lands 

and in general. For example, the Natural Resources Defense Council (NRDC), 

National Wildlife Federation (NWF), and Oil & Gas Accountability Project (OGAP) 

have been leading critics of environmental stewardship within the oil and gas industry. 

Each of these organizations has released reports questioning various oil and gas 

production practices and environmental implications. Section 2.3 provides additional 

details regarding some of these critiques and the issues being raised. 

• The combined, incremental effects of oil and gas production – in combination with 

other human activities – can pose threats to human health and the environment. Under 

the National Environmental Policy Act (NEPA) and associated guidance documents, 

these collective human activities are referred to as cumulative impacts. 

• The oil and gas industry faces a number of issues and operational constraints that 

make it difficult to completely eliminate its environmental footprint. For instance, 

drilling and resource extraction create a number of wastes, such as produced water and 

drilling waste. Wastes that cannot be reused or recycled must be stored or disposed of 

in some manner, increasing the land area affected by oil and gas extraction and raising 

concerns over potential leakage of drilling fluids and other wastes from storage sites. 

In addition, a large increase in production in the oil and gas industry (or any industry) 

is likely to increase air emissions significantly. Installing new technologies and 

controls can reduce the quantity of air emissions per amount of fuel produced but 

cannot eliminate relevant environmental impacts altogether. 

• Although many oil and gas companies have taken steps to reduce the environmental, 

safety, and health impacts of their operations, there are still environmental concerns 

that need to be better understood and addressed. To respond to these concerns, it’s 

important that government, industry, and stakeholders develop a better understanding 

of where current policy and technology mechanisms are inadequate and where further 

controls, commitments, and innovations are needed. 

U.S. Environmental Protection Agency Working Draft – September 2008 ES--5 
EXECUTIVE SUMMARY 

• The environmental management issues raised in this report are magnified by estimates 

that approximately 85 percent of all oil wells and 70 percent of all gas wells nationally 

are marginal wells. Marginal wells are generally defined as those producing at the 

margin of profitability. In addition, they are often owned and operated by smaller 

producers that may lack the technical expertise or resources to maximize potential 

pollution prevention and environmental management opportunities. As noted in 

Section 2.3, these wells are located in mostly rural settings (although urban drilling is 

an emerging trend in some areas of the country). Moreover, the wells are typically 

spread across thousands of operations, with several distinct sources of emissions and 

discharges. Nevertheless, the findings in this report demonstrate that on an aggregate 

basis, the environmental footprint of oil and gas production in Region 8 and other 

producing regions across the United States is growing and deserving of increased 

focus and attention. 

Environmental Policy Issues 

• A number of initiatives have been implemented to address air, water, and land use 

impacts associated with oil and gas production nationally and in Region 8. These 

policies range from the implementation of mandatory emissions limits on oil and gas 

operations (e.g., under the Clean Air Act (CAA), Clean Water Act (CWA), and Safe 

Drinking Water Act (SDWA), state regulations, etc.), to other federal initiatives (e.g., 

Bureau of Land Management (BLM) activities in Region 8 and nationally), to 

voluntary programs and actions. Some of these activities encompass best management 

practices (BMPs) used by industry to reduce environmental releases. 

The following examples highlight just a few of the relevant environmental policy 

decisions and ongoing initiatives shaping oil and gas development in Region 8 and 

elsewhere: 

• The 2004 Pennaco decision compelled BLM to revise Resource Management Plans 

(RMPs) to address cumulative environmental impacts stemming from new CBM 

development proposals and other pending energy projects in the region.6

• BLM and states have been working with western surface land owners to resolve 

differences tied to the stewardship of federal mineral rights (e.g., split estate issues). 

• EPA is conducting a detailed review of the CBM extraction sector to determine if it 

would be appropriate for the agency to initiate a rulemaking to revise, as necessary, 

the effluent limitations guidelines for the Oil and Gas Extraction Point Source 

Category (40 CFR 435) to control pollutants discharged in CBM-produced water.

7

 

• EPA has reviewed and approved innovative CBM waste water treatment residual 

disposal options that allow injection into Class II wells, creating better economic 

scenarios for creating cleaner water for surface discharge or aquifer storage. 

 

6 Energy, Public Lands, and the Environment, Professor Robert B. Keiter, University of Utah S.J. Quinney College of Law, 

September 2008 

7 EPA, Agency Information Collection Activities: Proposed Collection; Comment Request; Coalbed Methane Extraction 

Sector Questionnaire (New), EPA ICR Number 2291.01, OMB Control No. 2040-NEW 

http://www.epa.gov/fedrgstr/EPA-WATER/2008/January/Day-25/w1344.htm

U.S. Environmental Protection Agency Working Draft – September 2008 ES--6 
EXECUTIVE SUMMARY 

• Colorado has implemented more stringent VOC emissions standards in response to the 

state’s rapid increase in oil and gas production-related emissions. 

• Several regional initiatives focusing mainly on air quality have been established in the 

past decade, including the Western Regional Air Partnership (WRAP), Western States 

Air Resources Council (WESTAR), and Western Climate Initiative (WCI). 

There are a number of additional voluntary initiatives underway that can continue to 

grow or be used as models for developing collaborative environmental stewardship 

programs in Region 8. A representative sample includes the following programs: 

• EPA’s Natural Gas STAR program; 

• The Occupational Safety and Health Administration’s (OSHA) Voluntary Protection 

Programs (VPP); 

• The San Juan Voluntary Innovative Strategies for Today’s Air Standards (VISTAS) 

program; 

• The Wyoming Voluntary Remediation Program (VRP); and 

• The Four Corners Air Quality Task Force. 

Each of these programs provides meaningful incentives to program participants, ranging 

from the implicit (such as reduced emissions, increased product sales and profitability) to 

the explicit (such as operational leeway, e.g., reduced monitoring). Voluntary approaches 

such as these encourage improved resource stewardship, environmental protection and 

health and human safety. A summary of these voluntary programs is provided in Chapter 

4, Table 4-2. 

Potential Next Steps 

In spite of the many policy initiatives, program developments, and industry practices that 

are now addressing oil and gas environmental implications, significant environmental 

concerns persist. Such challenges won’t be effectively resolved without enhanced 

communications and the active involvement of government (federal, state, and tribal), 

industry, and stakeholder representatives. Moreover, since production levels are expected 

to continue their rapid ascent across Region 8, EPA continues to investigate and pursue a 

range of policy options in consultation with state partners, Tribal and industry 

representatives, and other key stakeholders. Although a discussion of potential next steps 

are not the focus of this report, specific actions and responses will continue to be 

investigated and pursued by EPA, partner agencies, industry leaders, and other 

stakeholder representatives, as appropriate. 

EPA, state and other government agencies are challenged to keep pace with rapidly 

expanding oil and gas production as well as associated regulatory activities (e.g., 

rulemakings, permitting and inspections). In addition, the high volume of oil and gas 

projects poses unique technical and regulatory challenges for federal and state agencies 

alike. As such, effective regulatory oversight requires open communications, 

U.S. Environmental Protection Agency Working Draft – September 2008 ES--7 
EXECUTIVE SUMMARY 

collaborative partnerships, and constant coordination. Improved environmental 

measurement, stakeholder involvement, and environmental management are integral to 

successful oil and gas production. 

At a national and regional level, EPA is actively reaching out to oil and gas organizations 

to improve understanding, identify drivers and barriers, increase performance, and 

address the environmental implications of oil and gas production. In summary, EPA is 

well positioned to provide greater regulatory certainty and consistency in oil and gas 

oversight through enhanced data collection and analysis, improved information sharing 

and partnerships, and focused compliance assistance and enforcement. 

U.S. Environmental Protection Agency Working Draft – September 2008 ES--8 
INTRODUCTION 

1.0 Introduction 

1.1 Objective 

EPA’s Sector Strategies Program, within the Office of Policy, Economics, and Innovation 

(OPEI), commissioned this analysis to meet the following objectives: 

• Facilitate a general understanding of oil and gas production, related environmental 

releases, and associated environmental implications in EPA Region 8; 

• Identify policy issues, program initiatives, and stewardship opportunities related to 

regional oil and gas production, focusing on air, water, and land issues; 

• Assess environmental releases to air, water, and land resulting from current and 

projected oil and gas production in the region; and 

• Lay the groundwork for future action to reduce environmental impacts associated with 

current and projected production in Region 8 and nationally. 

It is important to note that this report is an analytical document and does not convey 

Agency decisions. The report’s findings are based on the best available production data. 

1.2 Approach 

1.2.1 Framing the Study: Oil and Gas Production in Region 8 

As mentioned previously, Region 8 includes Colorado, Montana, North Dakota, South 

Dakota, Utah, Wyoming, and 27 sovereign tribal nations. The region is rich in natural 

resources, natural gas in particular, but is distinct from traditional U.S. gas producing 

regions, such as the Gulf Coast, in a number of ways. Specifically, Region 8 features 

extensive unconventional natural gas resources including tight gas sands, shale gas, and 

CBM. 

Unconventional oil and gas resources are loosely defined as resources that are generally 

deeper and / or more difficult to recover than traditional oil and gas resources that have 

historically been produced in the United States and elsewhere. In particular, 

unconventional resources include geologic formations that contain oil and gas but require 

advanced recovery techniques due to technical challenges posed by the physical 

properties of the reservoir (see figure 1-1). 

For example, tight gas formations require the gas-bearing formation to be artificially 

fractured and stimulated to allow the gas to flow freely to the wellhead. Unconventional 

resources may also require that extracted material be upgraded to meet relevant fuel 

specifications. For example, oil shale must be heated to release petroleum-like liquids 

that can be turned into fuel. Presently, there are a host of water and energy use, as well as 

associated environmental protection issues, that must be resolved in the years ahead if oil 

shale is going to become a viable energy source. Industry is currently investing in new 

U.S. Environmental Protection Agency Working Draft – September 2008 1-1 
INTRODUCTION 

technologies and approaches to test and ultimately ensure the commercial viability of 

these unconventional resources. 

In terms of the potential size of the oil shale resource residing in Region 8, the 

Department of Interior (DOI) estimates subsurface deposits in Colorado, Utah, and 

Wyoming may be nearly three times the amount of proven petroleum reserves in Saudi 

Arabia. Specifically, according to BLM Director Jim Caswell, oil shale deposits “may 

hold the equivalent of 800 billion barrels of oil – enough to meet U.S. demand for 

imported oil at current levels for 110 years.”8

Figure 1-1, Unconventional vs. Conventional Gas Production9

Developing, producing, and upgrading oil and gas from unconventional resources tends 

to be more capital-intensive than conventional operations. In general, unconventional oil 

and gas production tends to involve more surface disturbances and wells (due to increases 

in roads and servicing traffic as well as tighter well spacing, even when advanced drilling 

techniques are employed). Additionally, unconventional oil and gas production tends to 

involve considerably more energy and water use than conventional extraction 

operations.10

Growing U.S. demand for oil and gas, changing economic conditions, and emerging 

exploration and production expertise have combined to bring more of these resources to 

market. Environmental technology improvements that are reshaping oil and gas 

production in Region 8 and nationally include green well completions, vapor recovery 

 

8

 Rocky Mountain News, Salazar Presses Fight on Oil Shale, September 5, 2008, www.rockymountainnews.com

9

DTE Energy, Conventional vs. Unconventional Gas Production, 

http://www.dteenergy.com/businesses/unconventionalGas.html,. 10 Petroleum Technology Alliance Canada, Filling the Gap: Unconventional Gas Technology Roadmap, June 2006. 

U.S. Environmental Protection Agency Working Draft – September 2008 1-2 
INTRODUCTION 

units, engine upgrades for non-road vehicles, and closed loop drilling fluid systems. 

Many of these technologies and approaches are promoted by initiatives such as the EPA 

Natural Gas STAR Program. A more detailed list of voluntary programs is included in 

Table 4-2. 

In addition to stimulation techniques mentioned previously, the successful extraction of 

natural gas from unconventional resources requires specialized drilling and completion 

techniques. Such approaches tend to generate greater environmental releases than those 

associated with conventional gas producing techniques. For example, unconventional gas 

extraction tends to produce greater surface disturbances as well as large volumes of 

produced water. In the development of tight gas, typically from impermeable and 

nonporous formations, significantly more wells are required to produce the same unit of 

gas that could be produced from conventional formations with less energy use and 

surface disturbances (e.g., fewer wells)11. Although horizontal drilling techniques have 

emerged to connect more reservoir surface to the wellbore, unconventional gas 

development on a cumulative basis appears to be expanding the oil and gas industry’s 

environmental footprint in Region 8. Nevertheless, technology advances are slowing the 

rate of environmental degradation and will be integral to future remedies and control 

strategies. 

In recent years, as natural gas supplies from historic production areas have continued to 

shrink, industry’s focus has shifted toward largely Region 8 and frontier areas (e.g., 

offshore). Oil and gas reserves in Region 8 are often located in environmentally sensitive 

areas, with diverse species, wildlife habitat, forests, and other natural resources. 

Production has increased significantly, especially over the past 5 to 10 years. In the 

future, major contributions to domestic gas supplies are expected to come from 

unconventional sources, resulting in extensive growth in natural gas exploration and 

production. Without the necessary control strategies and stewardship approaches, this 

trend could significantly expand the oil and gas industry’s regional footprint. To assess 

the policy implications of increased oil and gas production in Region 8, this report 

analyzes the sector’s current environmental footprint, identifies environmental issues 

associated with increased oil and gas production, and provides insights about government 

and industry efforts to measure and improve the sector’s environmental performance. 

1.2.2 Focus of the Report 

Sectors Addressed in This Analysis 

This report focuses on oil and gas production, specifically the upstream operations 

associated with the extraction of crude oil and natural gas from wells. It does not include, 

for example, discussions about pipelines or petroleum refineries, and the environmental 

issues and management challenges associated with these energy development activities 

(NOTE: An exception includes the air emissions quantities associated with compressor 

drives that are included in Sections 2.3.1 and 3.1.1.). The report also does not address 

electricity production associated with oil and gas production. 

 

11 National Energy Board, Canada et al Analysis of Horizontal Gas Well in British Columbia, October 2000. 

U.S. Environmental Protection Agency Working Draft – September 2008 1-3 
INTRODUCTION 

Policy Issues 

Several federal, regional, state, and industry initiatives designed to address environmental 

issues in oil and gas production are identified and discussed within the body of this 

report. We reviewed government publications that discuss policies and programs, and we 

collected and analyzed information from non-governmental organizations (NGOs), the oil 

and gas industry, and other stakeholders to augment our discussion of major oil and gas 

production concerns and initiatives. We grouped our findings into three primary 

environmental policy areas—air, water, and land use issues (including waste 

management, e.g., drilling waste)—related to increased production. 

Baseline Environmental Impacts 

We completed a comprehensive review of readily available data to characterize the 

environmental impacts associated with oil and gas production, both on a national basis 

and for Region 8 specifically. Appendix C summarizes our assessment of available data 

sources, data limitations, and data gaps. 

Using the best available industry production and environmental data, which were 

primarily for 2002, we developed estimates for air emissions and non-air releases 

associated with oil and gas extraction in Region 8 for 2006. More detailed information is 

provided in Appendix B. 

• The report addresses the following air emissions: volatile organic compounds (VOCs), 

nitrogen oxides (NOx), carbon monoxide (CO), sulfur dioxide (SO2), carbon dioxide 

(CO2), hazardous air pollutants (HAPs, such as benzene, toluene, ethyl benzenes, and 

xylenes), particulate matter (PM), and methane (CH4). 

• After air emissions, major environmental issues associated with oil and gas extraction 

include produced water—primarily water that occurs naturally in the formation and 

must be disposed of after extraction—and waste from drilling processes, such as 

drilling muds and well-bore cuttings. (NOTE: Data characterizing groundwater 

impacts, specific contaminants and their respective concentrations was not available 

and therefore not in the report.) 

Chapter 3 provides information on these pollutants, including our methodology for 

projecting 2002 and other environmental data to 2006. 

Future Environmental Releases 

To assess the environmental impacts associated with expected future growth in oil and 

gas production in Region 8, we researched and compiled projections for air emissions, 

produced water, and drilling waste in 2018 consistent with WRAP’s 2018 emission 

projection. We describe these projections in some detail in Section C.5 of Appendix C. 

U.S. Environmental Protection Agency Working Draft – September 2008 1-4 
INTRODUCTION 

Next Steps: Opportunities for Environmental Improvement 

This study identifies options for reducing emissions, wastes, and other environmental 

impacts from oil and gas production. We identified these potential steps by reviewing 

current regulatory and voluntary initiatives and placing them within the context of 

emerging supply (e.g., unconventional resources) and environmental control issues. 

1.3 Organization of the Report 

The major remaining sections of this report are organized as follows: 

• Chapter 2, Background, provides an overview of the issues that explain why Region 8 

is vitally important to current and future domestic oil and gas supplies; highlights the 

unique characteristics of Region 8, such as its geology and potential for oil and gas 

production; and introduces relevant policy issues related to increased production. 

• Chapter 3, Environmental Releases, characterizes the environmental releases 

associated with oil and gas production in 2002 and 2006, including air emissions, the 

amount of produced water in the region, and waste impacts and implications. 

• Chapter 4, Conclusions, addresses the sector’s environmental footprint and 

summarizes key environmental issues and related implications of increased oil and gas 

production. This chapter also highlights a number of current policies/programs that are 

helping to reduce the environmental impacts of oil and gas production in Region 8 and 

elsewhere. 

• Appendix A, Industry Characterization, describes the industry in greater detail and 

regional oil and gas production trends. 

• Appendix B, Pollution Sources in the Oil and Gas Industry, characterizes sources of 

air emissions, including greenhouse gases (GHGs), as well as sources of other 

environmental releases. 

• Appendix C, Data Availability and Sources, identifies sources of industry baseline 

data (specifically well and production data, energy use data, and equipment and 

process data) as well as sources of air emissions and other releases. This appendix also 

describes data and methodologies used to provide future projections of air emissions 

and other environmental releases. 

• Appendix D, Air Emissions Sources by Source Category and Equipment Type, 

describes the primary sources of air emissions for each major source category 

identified in Section B.1 of Appendix B. 

• Appendix E, References, lists references used in this report. 

U.S. Environmental Protection Agency Working Draft – September 2008 1-5 
BACKGROUND 

2.0 Background 

2.1 Importance of Region 8 to Domestic Oil and Gas Production 

Oil and gas production has historically been concentrated in a few regions of the United 

States. The Appalachian region was the first oil and gas producing area in the country; 

other early production areas included the Michigan-Illinois Basin and the Mid-Continent 

Oil region, which extends from Nebraska to Texas. Over the years, U.S. production has 

predominantly occurred in the Texas-Louisiana region (including the San Juan and 

Permian Basins), along the Alaskan North Slope, and in the Gulf of Mexico. 

Over the past several years, long-standing reserves have gradually been depleted as 

domestic demand has risen. While conventional production in traditional areas remain 

flat or are in decline, new production has shifted to other areas rich in unconventional 

resources, particularly the Rocky Mountain region (EPA Region 8). In a recent 

presentation by Professor Robert Keiter of the University of Utah’s School of Law, 

relevant policy issues and trends associated with energy development in the 

Intermountain West were captured as follows: 

• “The Western states contain abundant energy resources: coal, natural gas, oil, 

uranium, and hydropower, as well as geothermal, wind, and solar. We have enough 

coal—a 250 year supply—to meet our domestic demands, but coal does not address 

our transportation fuel needs and it raises serious greenhouse gas issues. We have 

substantial natural gas reserves and produce annually about 19 trillion cubic feet, 

leaving a 4 trillion cubic feet annual deficit that is being met primarily by Canada. 

About 11% of our domestic natural gas needs are met from the public lands, and 

another 25% are met from OCS lands. The biggest shortfall is with oil, where we 

import 58% of our needs, and that figure is projected to hit 70% by 2025. We 

presently produce about 5% of our domestic oil needs from the public lands, and 

another 30% from OCS lands. Given the current policy focus on increasing supply, 

the public lands have been targeted for accelerated development. This is reflected 

both in the federal acreage under lease and in the huge jump in wells permitted in 

recent years. About 47.5 million acres of federal land are currently under lease for oil 

and gas development, while exploratory wells are being permitted at a record pace: 

From 2000-2007, the number of drilling permits issued increased more than 250%, 

jumping from 3000 to over 7600 annually. Today, the BLM is rushing to complete 

(RMPs) for each of its energy-rich resource management areas, and the priority in 

each instance has been to [essentially] maximize leasing and exploration.”12

Region 8 has become a major gas-producing area and, as mentioned previously, will be 

an increasingly important source of future domestic gas production. In recent years, gas 

production in Colorado and Wyoming has increased rapidly; in 2005 these two states 

accounted for 54 percent of total production in the west and comprised 15 percent of total 

 

12 Energy, Public Lands, and the Environment, Professor Robert B. Keiter, University of Utah S.J. Quinney College of 

Law, September 2008 

U.S. Environmental Protection Agency Working Draft – September 2008 2-1 
BACKGROUND 

U.S. production.

13 The largest expected growth in domestic gas production is expected to 

occur within these two states. The strategic importance of the resource base within 

Region 8 lies not only in its large, mostly untapped supply of oil and natural gas, but also in 

its abundance of other attributes –vast expanses of forests, abundant and diverse wildlife, 

and several national parks. The region’s natural diversity and large protected areas, where 

many unconventional reserves are located, often produces conflicts as energy production 

continues to expand. Oil and gas regulators play an important role in addressing these 

conflicts and are charged with managing cumulative production impacts across the region. 

14

2.2 Unique Characteristics of Region 8 

2.2.1 Oil and Gas Production 

As shown in Figure 2-1, Region 8 includes Colorado, Montana, North Dakota, South 

Dakota, Utah, Wyoming, and 27 sovereign tribal nations. Region 8 encompasses the area 

generally referred to as the Rocky Mountain oil and gas province. Environmental 

characteristics are discussed further in section 2.2.2 and 2.2.33

. In addition, some 

definitions of the Rocky Mountain region also include northwestern New Mexico, which 

is the primary location of the San Juan Basin (NOTE: Although most of the San Juan 

Basin resides outside of Region 8, parts of it extend into Colorado and Utah as well as 

Arizona which is in Region 9).15 Montana and the Dakotas are part of Region 8 as well, 

these states have some distinct features. Most of Montana has characteristics of the 

Rockies, but the eastern areas of both Montana and North Dakota are part of a separate 

province called the Williston Basin. 

Figure 2-1. EPA Region 8 with Tribal Lands16

 

13 U.S. Federal Energy Regulatory Commission (FERC), Natural Gas Markets: Western,. http://www.ferc.gov/marketoversight/mkt-gas/western.asp#prod 14 U.S. Department of Energy (DOE), Energy Information Administration (EIA), Natural Gas Pipelines in the Central 

Region, http://www.eia.doe.gov/pub/oil_gas/natural_gas/analysis_publications/ngpipeline/central.html. 15 U.S. Department of the Interior (DOI), United States Geological Survey (USGS) considers the San Juan and Raton 

Basins, located partially in northern New Mexico, as part of the Rocky Mountain region; see http://pubs.usgs.gov/fs/fs158-02/FS-158-02.pdf

16 U.S. Environmental Protection Agency, Region 8, Mountains and Plains, http://www.epa.gov/region8/tribes/ 

U.S. Environmental Protection Agency Working Draft – September 2008 2-2 
BACKGROUND 

Most Rocky Mountain oil and gas production is found in Colorado, Utah, and Wyoming, 

and to a lesser extent in Montana, North Dakota, and South Dakota. Although oil 

production is widespread across the region, the Rockies are currently dominated by 

natural gas production activities. Whereas Figure 2-2 shows increasing gas production in 

the Rockies from 1998 to 2005, Figure 2-3 shows increased rig activity in Region 8 from 

2000 to 2006, a fairly reasonable indicator of expanding natural gas production within the 

region. 

Figure 2-2. Total Dry Gas Production in the Lower 48 by Region, 1998—2005

0

1

2

3

4

5

6

1998 1999 2000 2001 2002 2003 2004 2005 2006

Tcf per Year

California/ Other

East/ Midwest

Gulf Coast

Gulf of Mexico

MidContinent

San Juan/ Permian

Rockies

U.S. Environmental Protection Agency Working Draft – September 2008 2-3 
BACKGROUND 

Figure 2-3. Active Oil and Gas Rigs in Region 8, 2000—2006 

Baker Hughes Monthly Rig Count - Region 8

0

50

100

150

200

250

300

Jan-00

Jul-00

Jan-01

Jul-01

Jan-02

Jul-02

Jan-03

Jul-03

Jan-04

Jul-04

Jan-05

Jul-05

Jan-06

Jul-06

Active Rigs

MT

UT

CO

WY

Conventional oil production has declined nationally, and current oil production in Region 

8 is modest when compared to regional natural gas production. Figure 2-4 shows oil 

production levels (in million barrels per year) in the Rockies as essentially constant from 

1998 to 2005. 

Figure 2-4. Total Crude Oil Production in the Lower 48 by Region, 1998—2005 

0

100

200

300

400

500

600

700

800

900

1998 1999 2000 2001 2002 2003 2004 2005 2006

Million Barrels per Year

East/ Midwest

California/ Other

San Juan/ Permian

MidContinent

Rockies

Gulf of Mexico

Gulf Coast

U.S. Environmental Protection Agency Working Draft – September 2008 2-4 
BACKGROUND 

Production activity is concentrated in the Denver Basin of eastern Colorado and the Uinta 

Basin of northeastern Utah. Large oil shale deposits are present in western Colorado, 

northeastern Utah, and southwestern Wyoming, and may be developed in coming 

decades. These deposits were a focal point of earlier industry technology development 

efforts in the 1970s and 1980s. Although energy companies are once again conducting oil 

shale technology research and development (R&D) within the region, the only production 

of note is currently taking place on a pilot scale. Commercial production of oil shale 

appears to be a decade or more away, and various technical, natural resource, and 

environmental issues will need to be addressed in the interim.

2.2.2 Geological Characteristics 

The Rocky Mountain region’s geological characteristics make it very different from other 

oil and gas producing regions. Some of these differences are described below: 

• The Gulf Coast and Gulf of Mexico generally produce oil and gas from high-porosity 

and high-permeability conventional oil and gas reservoirs. The high porosity and 

permeability of these formations generally allow oil and gas to flow freely to 

production wells. In addition, such operations typically involve a relatively small 

number of wells. 

• In contrast, natural gas resources within the Rockies are found primarily in 

unconventional formations. For example, tight gas sands are widely distributed in 

areas such as the Green River Basin of southwestern Wyoming and the Piceance Basin 

of northwestern Colorado. This is natural gas that is now being produced and where 

future extraction operations are likely to be concentrated. Recoverable resources in 

Rocky Mountain tight sands have been assessed to be in multiple hundreds of trillion 

cubic feet (Tcf) of gas, compared to current proved reserves of about 190 Tcf for the 

United States as a whole. The magnitude of the resource means that the current 

expansion in extraction activities is likely to continue for decades. 

The Rocky Mountain region is also the location of two of the most prolific coal bed 

methane (CBM) basins in the world: the San Juan Basin in southwestern Colorado and 

Northwestern New Mexico, and the Powder River Basin in eastern Wyoming. These 

CBM production areas are detailed below: 

• The San Juan Basin produces from the Fruitland coal formation. This formation was 

the initial major area of CBM production in the Rockies. Presently, this CBM 

production area is characterized by large volumes of water that are produced as natural 

gas is extracted (i.e., produced water). Produced water is subsequently re-injected for 

disposal or discharged into surface water, generally after some prior treatment

(although some produced water from CBM formations can be directly discharged into 

surface water). 

• The Powder River Basin in eastern Wyoming initiated CBM production in the 1980s, 

gained prominence in the late 1990s, and currently produces about 1 billion cubic feet 

(Bcf) of natural gas per day. Surface discharge, where permissible, is a much less 

expensive option compared to injection; however, surface water discharge can impact 

U.S. Environmental Protection Agency Working Draft – September 2008 2-5 
BACKGROUND 

surface water quality, contribute to streambed erosion, and / or render agricultural 

soils nonproductive due to high sodium levels. In some instances across Region 8, 

produced water from natural gas extraction (e.g., CBM wells) is clean enough to be 

used for irrigation or watering livestock without treatment; however, it is also common 

to find chemicals in produced water with concentrations that can harm aquatic life and 

crops when discharged. As mentioned previously, EPA is actively investigating these 

issues along with other agency and industry representatives. 

• Efforts to develop CBM natural gas resources elsewhere in the Rockies, including 

central Utah and southwestern Wyoming, are underway and have thus far experienced 

varying degrees of success. 

In 2007, there were approximately 17,000 total producing CBM wells in the Powder 

River Basin and about 150 in southwestern Wyoming. In general, Powder River Basin 

coal bed production is shallower than in other areas, necessitating either conventional 

drilling techniques, which require large numbers of vertical wells across a large surface 

area, or horizontal drilling operations, which enable development of multiple wells from 

a single well pad. The number of wells needed to develop CBM is typically a function of 

depth, water characteristics, number of seams, and other technical factors. 

The unconventional gas resources described in this section all have the following in 

common: a requirement for a greater number of wells (closer, or tighter, well spacing) to 

efficiently recover the gas resource. In spite of advanced drilling techniques that enable 

multiple wells to be drilled from a single well pad, tighter well spacing is the norm with 

unconventional natural gas recovery operations. For example, common practices 

associated with unconventional gas production can result in 8 to 16 times as many wells 

per area of land than would be required for conventional gas recovery17. The impact of 

this greater well density is being mitigated by the use of advanced drilling techniques, 

which allow multiple wells to be drilled from one well pad. However, the net result is still 

a greater number of well sites and surface disturbances than would have occurred in 

conjunction with natural gas production from conventional resources. As a result, the 

growth in CBM and other forms of unconventional gas production are expanding the 

industry’s environmental footprint in Region 8 and in select areas of the country. 

2.2.3 Other Natural Characteristics 

Region 8 is rich in natural resources outside of the vast array of fossil fuels found there. 

The region contains vastly different landscapes—from mountains to plains, canyons, and 

deserts—that are home to a variety of plant and animal species and diverse wildlife 

habitat. More than a third of the acreage in Region 8 is public land owned and managed 

by the U.S. government, including several of the most popular national parks (e.g., 

Yellowstone, Glacier, Badlands, etc.). However, the region is quite arid, and the 

availability and quality of water has historically been limited. Protection of these natural 

assets substantively contributes to many of the policy issues surrounding oil and gas 

production in the region. 

 

17 National Energy Board of Canada, Analysis of Horizontal Gas Well Performance in British Columbia, October, 2000. 

U.S. Environmental Protection Agency Working Draft – September 2008 2-6 
BACKGROUND 

2.3 Key Policy Issues Associated With Oil and Gas Production 

Natural gas development across Region 8 has been the focus of an intense environmental 

debate, and the complex and contentious issues underlying the conflict are likely to 

continue for the foreseeable future. To develop the region’s oil and gas reserves, 

thousands of new wells must be drilled in areas that have not previously seen much 

drilling activity. Region 8 public lands with oil and gas production and potential are 

administered by the BLM. Conflicts often involve energy companies, ranchers, residents, 

and environmentalists; the issues being debated include air and water quality, pollution 

prevention and controls, land management and water rights, wildlife protection, and so 

forth. Increases in population and workforce issues have also fueled concerns over the 

impacts of oil and gas development in areas such as the Roan Plateau in Colorado18, and 

Pinedale, Wyoming19. 

The combined, incremental effects of oil and gas production – in combination with other 

human activities – can pose threats to human health and the environment. Under the 

NEPA statute and associated guidance documents, these collective human activities are 

referred to as cumulative impacts. The following text from an EPA guidance document 

provides additional clarification: 

• “While they may be insignificant by themselves, cumulative impacts accumulate 

over time, from one or more sources, and can result in the degradation of 

important resources. Because federal projects cause or are affected by cumulative 

impacts, this type of impact must be assessed in documents prepared under 

[NEPA] ... the assessment of cumulative impacts in NEPA documents is required 

by Council on Environmental Quality (CEQ) regulations (CEQ, 1987). 

Cumulative impacts, however, are not often fully addressed in NEPA documents 

due to the difficulty in understanding the complexities of these impacts, a lack of 

available information on their consequences, and the desire to limit the scope of 

environmental analysis.”20

BLM has a statutory obligation under NEPA to accurately assess and address reasonably 

foreseeable developments, including current or prospective energy projects that may 

occur within the next several decades (e.g., oil shale development) as the agency 

monitors and oversees such activities in Region 8 and elsewhere. With respect to current 

oil and gas projects, regulators and developers are considering additional mitigation 

measures (e.g., phased development) that are – or may soon be – needed to reduce 

emissions and other environmental impacts consistent with federal and state regulations. 

When oil and gas production occurs, there are other industries and human activities 

producing environmental impacts within a common area. In reviewing proposed oil and 

gas development activities and projected schedules, EPA and other government agencies 

 

18 Environmental Working Group, Who Owns the West? http://www.ewg.org/oil_and_gas/part6.php, accessed August 21, 

2008. 

19 U.S. Environmental Protection Agency, Region 8, Final EPA Comments on Pinedale Anticline, February 2008 20 ‘Consideration of Cumulative Impacts in EPA Review of NEPA Documents.’ U.S. Environmental Protection Agency, 

Office of Federal Activities (2252A) - EPA 315-R-99-002/May 1999 

(http://www.epa.gov/compliance/resources/policies/nepa/cumulative.pdf) 

U.S. Environmental Protection Agency Working Draft – September 2008 2-7 
BACKGROUND 

with oversight responsibilities must consider the cumulative impacts of human activities 

– from energy projects such as coal mining to other forms of development. In addition, 

policy makers must weigh potential mitigation strategies, adaptive management 

approaches (e.g., environmental monitoring, control measures, etc.), or other measures to 

reduce uncertainty and lessen current or potential environmental impacts over time. 

The following discussion summarizes primary policy issues related to oil and gas 

production in the following three categories: air, water, and land use. In addition, we 

summarize industry actions to address environmental issues related to their respective oil 

and gas operations. 

2.3.1 Air Issues 

Under the Clean Air Act (CAA) states have the primary responsibility to address airrelated impacts from energy development. States are required under the Act to maintain - 

or come into attainment with - National Ambient Air Quality Standards (NAAQS) 

through State Implementation Plans (SIPs) or other state mechanisms. Although states 

have the lead, EPA works closely with the states to find solutions to improving air 

quality. The CAA requires EPA to set NAAQS for six common air pollutants (also 

known as "criteria pollutants") which are found all over the United States. They are 

particle pollution (often referred to as particulate matter), ground-level ozone, carbon 

monoxide, sulfur oxides, nitrogen oxides, and lead. These pollutants can cause harm to 

human health and the environment and can lead to property damage. Of the six 

pollutants, particle pollution and ground-level ozone are the most widespread health 

threats. EPA refers to these six as “criteria pollutants” because they are regulated with 

respect to human health-based and/or environmentally-based criteria (i.e., science-based 

guidelines) the agency develops in setting permissible levels. Primary standards are limits 

based on human health criteria whereas secondary standards are thresholds intended to 

prevent environmental and property damage. 

Air emissions associated with oil and gas production can significantly impact air quality 

and impair visibility. Concerns regarding these impacts have expanded in recent years as 

oil and gas production in Region 8 has grown. Air emissions generated during oil and gas 

production, along with emissions from other sources, are regulated by the Clean Air Act 

(CAA) and can be grouped into three categories: 

• Criteria air pollutants (ozone, CO, SO2, PM, and their precursors, including NOx and 

VOCs); 

• Hazardous air pollutants21 (HAPs, primarily fugitive VOC emissions from oil and gas 

production); 

• Haze precursors (which include ozone, NOx, SO2, and particulates); and 

In addition, greenhouse gases (GHGs, which include CO2 and CH4) are generated during 

oil and gas development. EPA issued an advance notice of proposed rulemaking 

(ANPRM) in July 2008 considering possible GHG emission regulation under the Clean 

 

21 EPA is currently required to control 187 HAPs. 

U.S. Environmental Protection Agency Working Draft – September 2008 2-8 
BACKGROUND 

Air Act. Several Rocky Mountain states have developed or are considering mandatory 

GHG emission limits. 

Region 8 has initiated several actions to curb emissions from a number of industrial 

sectors and sources, and oil and gas operations have been at the forefront of these 

regional efforts. Most air policy-related activities relevant to the oil and gas industry in 

Region 8 fall into one of three areas: 

• Regulation of industrial emissions under federal law and implementation of new, more 

stringent state-level programs; 

• Participation in voluntary regional initiatives to reduce emissions; and 

• Industry initiatives to address energy and environmental issues in the region. 

Federal and State Regulation of Air Emissions 

The Clean Air Act is a complex and comprehensive federal law that regulates air 

emissions from all sources, including area, stationary, and mobile sources. Most air 

policy issues related to oil and gas production are determined by the way associated 

operations are regulated under the CAA. Air regulations are implemented and enforced 

by individual states through their State Implementation Plans (SIPs) and through 

permitting activities that draw directly on EPA implementation of the CAA. In addition, 

the BLM is responsible for management and conservation of federal surface lands and 

mineral rights within its purview and controls air emissions from federal lands working in 

cooperation with EPA and other government agencies. 

As is the case with air pollution regulation throughout the rest of the U.S., states within 

Region 8 develop and implement regulatory controls to address oil and gas production 

emissions. Various environmental groups have been critical of the oil and gas industry 

and governmental policy to control air emissions and other forms of pollution from these 

sources.

22 Several groups have recommended that the federal government should 

establish more stringent controls on oil and gas production. For example, environmental 

groups have called for emissions limits and other national standards that states can build 

upon and even exceed should additional controls be deemed necessary. 

This section examines regulation and enforcement concerns under three federally-based 

standards: the National Ambient Air Quality Standards (NAAQS), National Emissions 

Standards for Hazardous Air Pollutants (NESHAP), and New Source Performance 

Standards (NSPS). In addition, state air permitting programs and BLM standards 

implemented in cooperation with EPA programs are also discussed. 

National Ambient Air Quality Standards (NAAQS). Under the CAA, NAAQS establish 

health-based ambient standards for regulating criteria pollutants. States are responsible for 

demonstrating how they will meet the NAAQS through their SIPs. Although most of 

 

22 Environmental groups have questioned government efforts to adequately regulate the oil and gas industry. The Natural 

Resources Defense Council report, Drilling Down: Protecting Western Communities from the Health and Environmental 

Effects of Oil and Gas Production, October 2007, http://www.nrdc.org/land/use/down/down.pdf, presents many of these 

concerns. 

U.S. Environmental Protection Agency Working Draft – September 2008 2-9 
BACKGROUND 

Region 8 is in attainment with these standards, a primary concern involves ground level 

ozone in the Denver Front Range—where substantial oil and gas development is underway 

and nonattainment issues exist (i.e., exceedences of 8-hour ozone standards). In addition, 

NOx and VOCs from regional oil and gas operations are suspected to be substantive 

precursors to ozone nonattainment in Colorado. As part of its response to this growing 

concern, Colorado has taken a number of steps to reduce emissions associated with oil 

and gas production, specifically VOC emissions. In 2004, the Denver metro area entered 

into an early action compact (EAC) with EPA to reduce ozone levels and avoid 

classification of the area as a high-pollution area.23 However, the Denver Front Range 

area was designated as nonattainment for the 8-hour ozone standard in November 2007, 

and at the time of publication the area was expected to submit a new plan to reduce 

ground level ozone. 

Other states in Region 8 that have met attainment standards for ozone, but until recently 

were in nonattainment for other pollutants, are now meeting the NAAQS standards for 

ozone and are waiting to be redesignated: 

• Montana had 10 areas in moderate nonattainment for PM standards and a couple of 

areas in nonattainment for SO2. Montana has released several State Implementation 

Plans (SIPs) to control fine particulates in certain areas of the state and is waiting to be 

redesignated. 

• Utah had two areas in nonattainment for SO2 emissions which are now meeting the 

standards. Utah has several areas still in moderate nonattainment for PM standards, 

while Wyoming has one area. 

In contrast, North Dakota and South Dakota are presently in attainment with all relevant 

NAAQS. 

On March 12, 2008, EPA significantly strengthened its NAAQS for ground-level ozone. 

EPA revised the 8-hour "primary" ozone standard, designed to protect public health, to a 

level of 0.075 parts per million (ppm). The previous standard, set in 1997, was 0.08 ppm. 

Several rural areas in Region 8 with high oil and gas development may well be impacted 

by the new ozone standard. In addition, Southwest Wyoming and the Four Corners area 

(a Region comprising sections of Utah, Colorado, New Mexico, and Arizona) are likely 

to be in nonattainment with the new ozone standard. 

Due to expanding demand for access to Region 8’s extensive fossil fuel and natural 

resources, states in the region collaborated with EPA to develop a Draft Energy Strategy 

(2004), which outlines a number of key goals and objectives that help address air, water, 

and land management issues. Four principal goals underpin the Draft Energy Strategy: 

1. Ensure efficient and timely EPA decisions about energy projects; 

2. Continue to meet federal environmental requirements and maintain or improve 

environmental quality with respect to energy projects; 

3. Promote energy efficiency and renewable energy; and 

 

23 VOCs are regulated as precursors to ozone. 

U.S. Environmental Protection Agency Working Draft – September 2008 2-10 
BACKGROUND 

4. Strengthen environmental and energy partnerships with co-regulators and other 

stakeholders. 

Air-related tasks in the Draft Energy Strategy primarily relate to meeting EPA’s healthbased NAAQS or helping nonattainment areas reach compliance. 

New Source Performance Standards and National Emission Standards for Hazardous Air 

Pollutants (NESHAP). Federal New Source Performance Standards (NSPS) are 

technology-based standards that limit criteria pollutant emissions from specific types of 

equipment. HAPs are also regulated through technology-based limits on specific 

hazardous pollutants. These limits are developed on a process-by-process basis. EPA has 

taken recent actions to control emissions from oil and gas activities by finalizing 

regulations that apply to engines used in oil and gas production: NSPS for Stationary 

Spark Ignition Internal Combustion Engines (ICE), and National Emission Standards for 

Hazardous Air Pollutants (NESHAP) for Reciprocating Internal Combustion Engines 

(RICE). Categories of activities that use these types of engines and may be subject to 

regulation include natural gas transmission, crude petroleum and natural gas production, 

and natural gas liquids producers. Recently promulgated NSPS rules will regulate NOx, 

CO, and VOC emissions, whereas the NESHAP regulations will control formaldehyde, 

CO, or VOC emissions, depending on which emissions are considered appropriate from 

certain engine types. These final rules became effective March 18, 2008. 

State Air Permitting. Major sources of air emissions, such as large compressor stations 

and gas plants, must obtain construction and operating permits from the appropriate 

permitting authority, usually the state air agency. Permits to construct are issued under 

New Source Review (NSR) for air emissions sources located in NAAQS nonattainment 

areas, and under Prevention of Significant Deterioration (PSD) in NAAQS attainment 

areas (the program is often collectively referred to as PSD/NSR or simply NSR). These 

air permits ensure that sources of criteria air pollutants do not cause or contribute to 

violations of the NAAQS. Smaller, “minor” sources of air emissions must usually obtain 

an air permit under a state minor source permitting program. In addition, these permits 

implement site-specific conditions to enable enforcement of the NSPS and NESHAP 

requirements. For tribal lands in Region 8, EPA is presently the permitting authority, 

rather than the individual states. In addition, Region 8 is working on finalizing a federal 

minor source permitting program for tribal lands. Given the large growth in oil and gas 

production and associated oil and gas air emission sources – some of which are located 

on tribal lands – operating these air permitting programs is a significant resource impact 

for both EPA Region 8 and the individual states’ environmental programs. 

Bureau of Land Management (BLM). Following enactment of the Energy Policy Act of 

2005 (EPAct), EPA entered into a Memorandum of Understanding (MOU) with DOIBLM, the U.S. Department of Agriculture (USDA), and the U.S. Department of the 

Army. This MOU seeks to focus agency efforts to effectively streamline federal permits. 

The underlying goal is to enhance efforts to process oil and gas use authorizations while 

maintaining environmentally responsible management of federal lands where oil and gas 

resources are located. 

U.S. Environmental Protection Agency Working Draft – September 2008 2-11 
BACKGROUND 

Since the MOU was established in October 2005, EPA has effectively collaborated with 

BLM and other signatories on various oil and gas permitting and related issues. Presently, 

the BLM field office in Vernal, Utah, is investigating oil and gas industry violations of 

air quality standards and seeking to project future emissions from energy development. 

The study is paying close attention to oil and gas production within the Uinta Basin,

24

and BLM plans to use the data to determine the best ways of reducing emissions from 

wells, compressors, storage tanks, and other equipment. For example, BLM may consider 

incorporating certain technology controls and other permit requirements that would 

decrease certain air pollutants, such as NO and PM, commonly associated with 

production operations. 

x

EPA is also successfully implementing an MOU with the Interstate Oil and Gas Compact 

Commission (IOGCC). The IOGCC is a congressionally chartered organization of 37 oil 

and natural gas producing states responsible for protecting and developing the states’ oil 

and gas resources. Through IOGCC, participating state governors and the agencies, 

programs, and staff within their purview seek to develop, conserve, and protect oil and 

gas resources in efficient, cost-effective, and environmentally responsible ways. In some 

instances, states and EPA have concurrent jurisdiction relating to a host of oil and gas 

regulatory efforts. In other instances, the states and EPA have independent authorities 

that may be complementary when effectively coordinated. The EPA-IOGCC MOU 

focuses federal and state environmental oversight and regulatory activities on oil and 

natural gas exploration and production. In addition, the MOU improves regulatory 

cooperation among the states and the agency by promoting cost-effective environmental 

protection, minimizing duplication, increasing efficiencies and communication, and 

enabling the exchange of information and expertise. Lastly, the MOU identifies mutual 

issues of concern as well as mutually beneficial joint activities, and creates a permanent 

means of consultation between EPA and the IOGCC. 

Voluntary Regional Initiatives 

To improve air quality beyond federal requirements, a number of regional organizations 

have been formed in the western states to address air pollution concerns. These 

organizations include the Western Regional Air Partnership (WRAP), Western States Air 

Resources Council (WESTAR), and Western Climate Initiative (WCI). Brief descriptions 

of each are provided below. 

Western Regional Air Partnership. Formed in 1997, WRAP25 is a collaborative and 

essentially voluntary effort involving state and federal agencies for the purpose of 

providing regional planning, etc. for SIPs seeking to improve visibility in western areas, 

primarily by providing the technical expertise and policy tools needed by states and tribes 

to implement the federal Regional Haze Rule (RHR), designed to protect visibility in 

federal Class I areas. The Rule requires states to set periodic goals for improving 

visibility in these areas. WRAP is the successor to the Grand Canyon Visibility Transport 

 

24 Oil and gas development is expected almost to double in Uinta County in the next few years. About 10,000 new wells 

are either planned or already being developed in the county; almost 6,000 wells are currently in production. See Red 

Lodge Clearinghouse, BLM moves to reduce air emissions from energy development in Uinta Basin, February 2008, 

http://rlch.org/content/view/344/62/. 25 For more information on WRAP, see http://www.wrapair.org/. 

U.S. Environmental Protection Agency Working Draft – September 2008 2-12 
BACKGROUND 

Commission, formed to improve visibility in the Grand Canyon and other park and 

wilderness areas around the Colorado Plateau.26 All Region 8 states and tribes participate 

in WRAP. One of the organization’s key contributions is the Emissions Forum, which 

oversees a comprehensive tracking and forecasting system, called the Emissions Data 

Management System (EDMS). Policy makers use EDMS to assess and address air quality 

issues. For example, EDMS data are used for air quality modeling and help policy makers 

comply with the requirements of EPA’s RHR. In addition, WRAP data are used 

extensively within this report to help EPA, states, and other stakeholders effectively 

characterize current and future air emissions trends associated with oil and gas 

production. 

Western States Air Resources Council. Another voluntary group similar to WRAP is 

WESTAR, which was formed in 1998.

27 Fifteen western states participate in WESTAR, 

including all Region 8 states. Although WESTAR does not track emissions like WRAP 

does, the organization provides a forum to discuss air quality issues in the west. For 

example, in September 2007, WESTAR hosted a conference focused on oil and gas 

development issues that highlighted several BMPs to reduce oil and gas production 

emissions. Representative BMPs discussed during the conference included installing 

vapor recovery units on storage tanks, installing fuel recovery systems and static packs to 

reduce venting at compressor stations, testing for fugitive emissions through leak 

detection and repair (LDAR), and repairing or replacing pressure safety valves and other 

equipment or piping where fugitive emissions tend to originate. 

28

Western Climate Initiative. The purpose of the WCI is to help participating organizations 

reduce GHG emissions in the west. WCI29 was formed in February 2007, when the 

governors of Arizona, California, New Mexico, Oregon, Washington, and the Canadian 

provinces of British Columbia and Manitoba forged an agreement establishing the 

initiative. Since that time, Montana and Utah have also signed on as participants, and 

Alaska, Colorado, Idaho, Nevada, and Wyoming are presently observers of the WCI 

process. In August 2007, WCI set a regional target of reducing GHG emissions to 15 

percent below 2005 levels by 2020. WCI presently features a number of working groups 

and is holding meetings to seek stakeholder comments about the potential design and 

implementation of a regional cap-and-trade program focused on reducing GHG 

emissions. 

2.3.2 Water Issues 

Another major policy challenge related to oil and gas production involves water sources, 

competing uses and demands, and associated conflicts. Unconventional natural gas 

resources (e.g., tight sands, shale gas, etc.) generally require higher water use than 

conventional gas extraction. In addition, CBM formations in the Rocky Mountain region 

 

26 The RHR seeks to improve visibility in 156 national parks and wilderness areas throughout the United States, but 

located primarily in the west. See http://www.epa.gov/oar/visibility/program.html for additional information on EPA’s 

Regional Haze Program. 

27 For more information on WESTAR, see http://www.westar.org/index.html. 28 An agenda and presentation materials from the September 2007 WESTAR conference can be accessed at 

http://www.westar.org/Docs/Tech%20Confs/Oil-Gas%2007/agenda.doc. 29 For more information on WCI, see http://www.westernclimateinitiative.org/. 

U.S. Environmental Protection Agency Working Draft – September 2008 2-13 
BACKGROUND 

release large amounts of produced water, which is released to the surface, treated in 

place, or reinjected into the subsurface depending on a number of variables, including 

water quality, permit limits, availability of injection wells, and so forth. Competing 

energy and agricultural needs, as well as other industrial requirements and population 

growth, are increasing pressure on scarce regional water resources. 

The Powder River Basin produces natural gas from younger, shallower coal beds than 

those in the San Juan Basin. To date, almost all of the produced water has been surface 

discharged rather than injected. The Powder River Basin is located in a predominantly 

arid area, and clean water is a valuable resource. Hence, any suitable produced water is 

used for irrigation and livestock. In addition, several factors have hindered deep injection 

within the basin thus far. For example, if suitable injection zones are too deep or are 

limited in their capacity to accept fluid relative to the volume of water produced by CBM 

development, producers must find other options. In addition, although deep injection 

protects surface waters, potential beneficial uses of CBM produced water are sacrificed. 

The high costs associated with drilling and operating injection wells as dedicated 

facilities tend to impose barriers as well. Nevertheless, there are some shallow zones 

available that could be used for injection purposes if the water from the center of the 

basin is not suitable for surface discharge without prior treatment. Operators may choose 

injection in the future if the cost-benefit calculations and other tradeoffs associated with 

surface discharge without prior treatment are not sufficient. 

In addition, the interplay of states’ rights and water usage in the region, as well as 

evolving federal water policy, only add to the complexity of the underlying issues and 

inevitable conflicts that arise. The following discussion addresses these main water 

issues: 

• Water discharges governed by regulations promulgated under the Clean Water Act 

(CWA) and Safe Water Drinking Act (SDWA); 

• State limits on produced water and associated issues (e.g., state water rights); and 

• Water contamination from storm water runoff and oil spills. 

Federal Water Regulations 

Produced water from oil and gas operations is, by volume, the largest waste stream 

associated with oil and gas production. The content of produced water typically varies 

depending on the geographic location of the field, the type of hydrocarbons being 

produced, and other features associated with the geology and extraction techniques used. 

In some instances across Region 8, produced water from natural gas extraction (e.g., 

CBM wells) is clean enough to be used for irrigation or watering livestock without prior 

treatment; however, it is also common to find chemicals in produced water with 

concentrations that can harm aquatic life and crops when they are discharged or used for 

irrigation, respectively. Thus, produced water discharged from oil and gas production is 

subject to various water permitting guidelines under CWA and SDWA, and these issues 

are discussed in more detail below. 

U.S. Environmental Protection Agency Working Draft – September 2008 2-14 
BACKGROUND 

Clean Water Act. CWA requires EPA to establish national, technology-based regulations, 

known as effluent limitations guidelines (ELGs), designed to reduce pollutant discharges 

from categories of industry discharging directly to U.S. waters. These guidelines are 

implemented through National Pollutant Discharge Elimination System (NPDES) 

permits. Effluent guidelines apply to facilities engaged in field exploration, drilling, and 

well production in offshore, coastal, and onshore areas. There are effluent guidelines for 

petroleum refining discharges as well, but these matters are not examined in this report, 

which focuses on upstream oil and gas production issues. 

Produced water from CBM wells is not currently regulated under federal effluent 

limitations guidelines developed to address the potentially unique characteristics of these 

production operations. With the rapid growth of CBM production within Region 8 and 

other producing regions across the nation, environmental concerns have begun to emerge, 

and EPA is currently studying these issues in depth30. In 2003, the U.S. Court of Appeals 

for the Ninth Circuit ruled that water discharges from CBM wells are a pollutant under 

CWA. However, in a recent court ruling related to the lawsuit Natural Resources Defense 

Council vs. EPA, the Ninth Circuit Court of Appeals remanded to the agency its 2006 

rulemaking responding to language in the Energy Policy Act of 2005. Specifically, 

through this action, the Ninth Circuit Court of Appeals has raised questions and 

uncertainty regarding the extent to which oil and gas exploration and production will be 

exempted from Clean Water Act (CWA) NPDES reporting requirements.31 EPA has 

petitioned the court to rehear the case and the final outcome of these and had yet to be 

determined at the time of this report’s publication. 

In 2007, EPA’s Office of Water (OW) initiated the aforementioned study of CBM 

operations. Once the agency’s industry survey and study process is complete, EPA may 

choose to conduct further analyses, take no further action, or initiate a rulemaking to 

develop new or revise existing effluent guidelines to include water discharges from these 

operations. EPA is expected to complete its CBM study by the end of 2009 or 2010. 

Safe Drinking Water Act. The SDWA was established to protect the quality of drinking 

water in the United States; therefore, it focuses on all waters actually or potentially 

designated for drinking. Environmentalists, health advocates, and the public have called 

attention to exemptions for the oil and gas industry, including those related to the 

SDWA.

32 Nevertheless, with respect to oil and gas production, EPAct significantly 

amended SDWA in the following fundamental ways: 

• First, hydraulic fracturing operations, also referred to as “fracing” or “fracking,” are 

used to improve gas flow for unconventional resources and exempted from regulation 

under SDWA.33 

 

30 U.S. Environmental Protection Agency, EPA’s Clean Water Act Review of the Coalbed Methane Industrial Sector, June 

2007, http://www.epa.gov/guide/304m/2008/cmb-slides.pdf, accessed 08.19.08. 31 The Ninth Circuit Court of Appeals Decision in NRDC v. EPA and its Impact on Storm Water Permitting of Oil & Gas 

Activities in Pennsylvania Oil & Gas Alert, by Kenneth S. Komoroski, Michael J.R. Schalk. June 30, 2008, 

http://www.klgates.com/newsstand/Detail.aspx?publication=4661, 32 Oil and Gas Accountability Project, Our Drinking Water at Risk: What EPA and the Oil and Gas Industry Don’t Want Us 

to Know About Hydraulic Fracturing, April 2005, http://www.earthworksaction.org/pubs/DrinkingWaterAtRisk.pdf. 33 Fracking fluids may contribute to water contamination since they contain hazardous materials such as gels, polymers, 

biocides, fluid loss agents, thickeners, enzyme breakers, acid breakers, oxidizing agents, friction reducers, and surfactants. 

U.S. Environmental Protection Agency Working Draft – September 2008 2-15 
BACKGROUND 

• Second, EPAct calls for voluntary discontinuance of diesel fuel used in fracking 

operations instead of disallowing such use. 

• Last, underground injection in oil and gas operations is defined so EPA has the 

authority to regulate fracking fluids as a possible contaminant to the water supply only 

if diesel fuel additives were used. 

Critics of these statutory provisions have stated that they contribute to drinking water 

contamination. Some environmentalists and legislators are calling for the exemption to be 

removed because of suspected groundwater contamination that may stem from hydraulic 

fracturing. In a recent letter to the Governor of New York, in anticipation of expanding 

shale gas production in the Marcellus shale rock formation, the Environmental Working 

Group and the Endocrine Disruption Exchange (TEDX) made the following assertion: 

“In Colorado, at least 65 chemicals used by natural gas producers are listed as 

hazardous under six (6) major federal laws designed to protect Americans from 

toxic substances. Some of these chemicals may be injected underground or spilled 

during drilling and / or ‘hydrofracing’ operations ... If any of these 65 chemicals 

were emitted or discharged from an industrial facility, reporting to [EPA] would 

be mandatory, and in most cases permits would require strict pollution limits and 

companies would be subject to specific cleanup standards.” 

Presently, per informal communications with EPA regional staff, minimal ground-water 

monitoring activities are being funded to investigate these issues. However, other 

stakeholders are raising questions about potential groundwater and human health impacts 

stemming from hydraulic fracturing practices. Clearly, precise data is needed to allow 

regulators and operators alike to properly assess these issues as they work to prevent 

environmental harm and protect human health and safety.34 Prior to enactment of this 

legislation, EPA assessed the potential for contamination of underground sources of 

drinking water (USDW) by reviewing existing literature on water quality incidents that 

were potentially linked to hydraulic fracturing. EPA released its findings in 2004, 

concluding there were no confirmed cases of drinking water contamination resulting from 

fracturing fluid injection into CBM wells or subsequent underground movement of such 

fracturing fluids.35 

State Limits 

Some Region 8 states, such as Colorado, Montana, and Wyoming, have been delegated 

the authority to issue discharge permits to control produced water, and differing state 

policies have resulted in some disputes. CBM operations that surface discharge produced 

water in Colorado typically have to apply for discharge permits. Wyoming and Montana 

have implemented stringent effluent limits. Wyoming’s discharge limits for CBM 

produced water are determined by the ecological attributes of the drainage area receiving 

such discharges and by the designated use for each drainage. In addition, Wyoming is 

 

34 ‘East Coast Gas Boom Renews Activists' Bid To Kill Drinking Water Act Waiver,’ Inside EPA, 8/14/08 35 EPA, Evaluation of Impacts of Underground Sources of Drinking Water by Hydraulic Fracturing of Coalbed Methane 

Reservoirs, EPA 816-R-04-003, 2004, http://www.epa.gov/safewater/uic/pdfs/cbmstudy_attach_uic_exec_summ.pdf. 

U.S. Environmental Protection Agency Working Draft – September 2008 2-16 
BACKGROUND 

developing general permits that establish limits for the entire watershed. Historically, 

differences between western states regarding discharge limits, permitting, water rights, 

and how these issues are mitigated have produced varying degrees of conflict within 

Region 8. For example, in 2006, Montana adopted water quality standards setting new 

limits on CBM water discharges into several water bodies, including the Tongue River, 

Powder River, and their tributaries. The rivers originate in northern Wyoming, where 

extensive CBM development has occurred, but flow into agricultural areas of Montana. 

While some farmers and conservation groups in Montana and Wyoming support the 2006 

standards because of concerns regarding potential impacts to water quality and flow rates, 

the state of Wyoming joined with several companies and filed lawsuits in state and 

federal court challenging Montana’s new regulatory standards for CBM produced water 

discharges. At the time of publication, the state court had ruled in Montana’s favor and 

that decision is being appealed. Additionally, in early 2008, the U.S. Supreme Court 

agreed to consider a lawsuit between Montana and Wyoming over the shared waters of 

the Tongue, Powder, and Little Powder Rivers, and that litigation is ongoing. 

Tribal Limits 

Region 8 has approved four tribes to implement Clean Water Act water quality standards. 

The confederated Salish and Kootenai Tribes of the Flathead Reservation in Montana and 

the Assiniboine and Sioux Tribes of the Fort Peck Indian Reservation in Montana have 

federally-approved water quality standards. Where EPA has not approved a state or tribe 

to implement federal environmental programs including the CWA, EPA directly 

implements the programs in the tribal lands. 

Stormwater Runoff and Fuel Spills 

• Stormwater Runoff. Inconsistency in the treatment of stormwater runoff at oil and gas 

production operations has raised concerns about the environmental impacts of 

discharges. Although EPA had begun to regulate certain stormwater discharges 

containing sediment from oil and gas construction sites in the 1990s, EPAct resulted in 

a policy shift. In 2006, EPA responded to the new statutory mandate and published a 

rule that exempts construction activities at oil and gas sites from the requirement to 

obtain an NPDES permit for stormwater discharges except in very limited instances. 

EPA’s rulemaking is consistent with EPAct and encourages voluntary application of 

BMPs for construction activities associated with oil and gas field activities. The EPA 

rulemaking also encourages oil and gas production operations to minimize erosion and 

control sediment to protect surface water quality. However, as mentioned previously, a 

federal appellate court decided to remand EPA’s rulemaking exempting construction 

activities at oil and gas facilities from CWA stormwater permitting requirements. The 

final outcome of these court proceedings remains in question. 

• Fuel Spills and Modifications to Regulations. When they occur, fuel spills contribute 

to water contamination, habitat loss, and other undesirable consequences if they are 

not contained and subsequently migrate from flowlines, gathering lines, and / or 

storage vessels. Various studies validate that the amount of spills related to fossil fuel 

production is significant. For example, one report found there were approximately 924 

U.S. Environmental Protection Agency Working Draft – September 2008 2-17 
BACKGROUND 

oil and gas industry spills in Colorado over a 4-year period (2002—2006).36 In 

addition, over that same period, 20 percent of all oil and gas industry spills 

contaminated water to some degree. Spilled products include crude oil/condensate, 

produced water, and “other products” such as hydraulic fracturing fluids, diesel fuel, 

glycol, drilling muds, and other chemicals that can have a deleterious environmental 

impact. Although this report, as previously mentioned, does not present data and 

findings relevant to fuel spill impacts, concentrations, and volumes, they are important 

issues and a focal point for oil and gas regulatory oversight. 

2.3.3 Land Use Issues 

Co-Regulator Efforts Around Land Use: 

Oil and Gas Environmental Assessment

In1996, Region 8 and U.S. Fish and Wildlife 

Service (FWS) Region 6 formed a partnership to 

assess oil and gas waste management issues 

impacting production and related sites. Originally 

referred to as the Problem Oil Pit (POP) effort, 

the name was changed to Oil and Gas 

Environmental Assessment (OGEA). Coregulators participating in the effort included 

state oil and gas agencies and environmental 

agencies, tribal energy and environmental 

agencies, BLM, and the U.S. Bureau of Indian 

Affairs (BIA). Participants focused on threats 

posed by these facilities to surface and ground 

water resources, as well as wetlands. In addition, 

participants focused attention and resources to 

determine where oily waste in open pits posed 

threats to migratory birds and other wildlife and 

to correct problems as they found them. EPA 

OGEA team participants and other Federal, 

State, and Tribal co-regulators pursued several 

activities intended to improve compliance and 

environmental conditions at production sites, 

including commercial waste management 

facilities. As a result of these efforts, in 2003 

EPA developed a report that reviewed the work 

of the team in Region 8, made recommendations 

for future action, and examined how coregulators and the regulated community can 

ensure lasting environmental benefits from this 

effort. 

Oil and gas production in Region 8 

contributes to a number of land use 

issues37. Most land use-related activities 

and criticisms of production operations 

revolve around: 

• Surface disturbances due to drilling, 

and certain drilling techniques used to 

reduce these impacts; 

• Impact of oil and gas operations on 

wildlife due to surface disturbances, 

noise, and other industrial activities; 

• Treatment of drilling waste; and 

• Separation of surface and mineral 

rights. 

Surface Disturbance. Extraction of 

unconventional resources such as tight 

gas and shale gas, which are abundant in 

Region 8, can cause a greater surface 

disturbance than production of 

conventional gas resources. As 

previously stated, more wells are 

required to produce unconventional 

natural gas due primarily to the lower 

porosity of the formations where the 

resources reside. However, certain 

extraction techniques have been 

 

36 Oil and Gas Accountability Project, Colorado Oil and Gas Industry Spills: A Review of COGCC data (June 2002-June 

2006), http://www.earthworksaction.org/pubs/Spills.pdf. 37 U.S. Environmental Protection Agency, Report of the Oil and Gas Environmental Assessment (OGEA) Effort 1996-

2002, January 2003. 

U.S. Environmental Protection Agency Working Draft – September 2008 2-18 
BACKGROUND 

developed to reduce the total area of surface disturbance and partially offset this 

requirement. 

For example, horizontal drilling techniques are widely used to access and produce natural 

gas from such low permeability formations in Region 8 and elsewhere (e.g., shale gas 

production operations such as those common to the Barnett Shale in Region 6). In 

addition, horizontal drilling techniques are now being extensively employed in CBM 

natural gas production. 

Horizontal drilling is used to enable multiple wells to be established from a single well 

pad, thus reducing the overall surface area used for drilling (i.e., well-pad acreage). 

Hydraulic fracturing and disposal of fluids used for this practice is another environmental 

concern. In addition, although not the focus in Region 8, oil and natural gas production 

can contribute to land subsidence over time as evidenced by operations within the Gulf 

Coast and other areas. Figure 2-5 shows the western states’ oil and gas footprint by 

indicating drill rig concentrations and well locations in Region 8 – Montana, North 

Dakota, South Dakota, Wyoming, Utah, Colorado, and 27 tribal nations (NOTE: The 

Western Regional Air Partnership (WRAP) consists of the six states of Region 8 plus 

Washington, Oregon, California, Idaho, New Mexico, Arizona, Nevada, and Alaska.) 

Figure 2-5. Rocky Mountain States’ Oil and Gas Producing Regions 

Impacts on Wildlife. Wilderness areas across Region 8 increasingly must coexist with oil 

and gas production. Heavy-duty trucks and roadways used for fuel production and 

transportation contribute to noise and air pollution in undeveloped areas. In addition, 

drilling activities are reportedly impacting wildlife habitat and some animal species that 

reside within these public lands. For example, the Rocky Mountain Front Range ranks in 

the top 1 percent of U.S. wildlife habitat and has a number of native big game animals 

U.S. Environmental Protection Agency Working Draft – September 2008 2-19 
BACKGROUND 

that need a large home range to thrive.

38 Studies have raised concerns that new roadways 

and expanding drilling operations disrupt migration, habitat, and wintering grounds for 

certain species. Heavy-duty trucks and roadways used for fuel production and 

transportation contribute to noise and air pollution. Some environmentalists

cited

, residents, 

wildlife experts, and others resist further oil and gas exploration in Region 8, and surface 

disturbance and wildlife impacts caused by road development and drilling operations are 

among the leading issues . 

Treatment of Drilling Waste. Drilling waste is another key issue, and environmental 

groups and other stakeholders have raised concerns regarding the treatment, storage, and 

disposal or reuse of such production byproducts. Oil and gas production generally 

produces drilling waste that contains mud, rock fragments and cuttings from the wellbore, 

and chemicals added to improve the properties and performance of drilling muds and 

fluids. Such drilling waste accounts for the second largest amount of waste derived from 

oil and gas production (second to produced water). Certain methods have been adopted in 

recent years to reuse and/or reduce drilling waste as well as to diminish the toxicity of 

various drilling waste; nevertheless, benefits have often not been realized. 

To reduce their drilling footprints, some producers have developed methods to reuse 

nontoxic drilling waste or treat toxic waste compounds. For example, certain drilling 

waste is being processed and converted into a low-cost substitute for construction 

aggregate. Another method involves the substitution of nontoxic fluid additives to reduce 

or eliminate the toxicity of such wastes. In addition, some companies have begun to 

implement closed-loop drilling fluid systems that eliminate the dumping of waste 

byproducts into an open pit. This approach can be expensive but has proven effective in 

reducing drilling waste, associated water use, and truck traffic for shipping wastes offsite 

to a treatment facility. 

Overall, these practices seek to reduce the environmental footprint of fossil fuel 

production; however, they also have drawbacks. For example, EPA estimates that only 10 

percent of total drilling waste volumes are either reused or recycled (e.g., as levee fill in 

construction and infrastructure projects), and that current demand for such byproducts in 

other manufacturing sectors is not significant.39 

Land Use Rights. Another issue related to land use deals with how surface and mineral 

rights are distributed under split estate lands. Split estate lands refer to those lands on 

which private parties own the surface and the federal government owns subsurface 

minerals. Under U.S. law, the government’s mineral rights supersede those of private 

parties. Problems have surfaced with these split estate issues, especially as the 

government has increasingly used its rights to advance oil and gas production on public 

lands to meet domestic energy needs and to generate royalties (for the U.S. Treasury as 

well as states). 

 

38 Joel Connelly, National Wildlife Federation, Frontal Assault, Aug/Sep 2004, vol. 42 no. 5, 

http://www.nwf.org/nationalwildlife/article.cfm?issueID=69&articleID=959. 39 EPA Region 8, Oil & Gas Beneficial Reuse Summary, Region 8 E&P Report. 

U.S. Environmental Protection Agency Working Draft – September 2008 2-20 
BACKGROUND 

BLM is the principal government agency responsible for management and conservation 

of federal surface lands and mineral rights. Most of the land managed by BLM is located 

in the western United States, where there are abundant fossil fuel resources. The job of 

balancing resources and uses is challenging, and BLM has been criticized for advancing 

agency priorities that support increased domestic fuel production without adequately 

addressing competing needs. Public disapproval has involved claims of decreased efforts 

in inspection and enforcement, thus harming public lands as well as privately owned 

surface rights. Opponents of oil and gas production claim that BLM has supported rapid 

industry development, thereby enabling erosion, adverse impacts to water quality and 

wildlife habitat, and a wide range of surface disturbances. 

In response to public concerns, BLM has been working diligently with surface owners to 

try to resolve issues involving split estate lands. Suggestions compiled by BLM include 

educating surface owners and operators of their rights, involving surface owners in the 

land use planning process, and notifying surface owners of surface-related compliance 

issues that could affect their property value. 

Industry has also acted to address public concerns regarding environmental issues related 

to its oil and gas operations. For example, Shell Oil sponsored a “national dialogue on 

energy security” and held a number of events around the country in the past few years to 

solicit public opinion on energy issues and potential future directions.

40 Rocky Mountain 

residents provided mixed responses regarding new energy production, and much 

feedback focused on current and potential uses of environmentally friendly technologies 

that provide efficient access to the region’s vast oil and gas resources. 

As oil and gas production continues to expand within Region 8, so too do the number of 

public health concerns surfaced by local residents who feel adversely impacted by 

development activities. Some residents in Garfield County, CO have contacted local 

public health officials about respiratory problems to be investigated and acted upon. 

Similarly, citizen groups in Pinedale, WY have articulated concerns about exposure to 

unhealthy ozone levels that have been recorded in the Green River Valley. Although 

public health impacts of oil and gas activities are outside the scope of this report, these 

issues merit added consideration. EPA and other agencies continue to investigate and, as 

appropriate, respond to these issues in Region 8 and other producing states where similar 

concerns have surfaced. 

2.3.4 Summary of Policy Issues 

Section 2.3 of this report highlights only some of the major policy issues surrounding oil 

and gas operations in Region 8. The issues are too numerous and complicated by 

conflicting interests of the oil and gas industry, impacted residents, and other 

stakeholders to be comprehensively addressed within the context of this report. In short, 

with a growing worldwide economy that requires vast amounts of energy, U.S. and global 

demand for hydrocarbons is not expected to abate any time soon. This finding is 

 

40 Shell Oil Company, A National Dialogue on Energy Security: The Shell Final Report, 

http://www.shell.com/static//usa/downloads/energy_security/pdf/shell_final_report.pdf

U.S. Environmental Protection Agency Working Draft – September 2008 2-21 
BACKGROUND 

consistent with ones articulated in the 2007 National Petroleum Council report41. Clearly, 

regional efforts to control fossil fuel emissions more effectively—ranging from GHG 

cap-and-trade programs to carbon capture and sequestration—will be necessary as 

production and other fossil fuel activities continue to expand. In addition, the genuine 

concerns of affected residents will need to be addressed to resolve current claims, avoid 

increased confrontation between the affected parties, and prevent adverse environmental, 

human health and safety impacts. 

To satisfy domestic demand for energy and with a major push to access and tap into 

reliable energy sources domestically, growth in natural gas production and other forms of 

natural resource extraction within the Rocky Mountain region is occurring. In addition to 

oil and gas, other fossil fuels, and nuclear power, increased development of renewable 

energy sources - such as hydropower, solar, and wind resources – in Region 8 is likely. 

Coupled with an increased focus on energy efficiency and resource conservation, the 

successful development of diverse sources of energy is absolutely essential to U.S. 

energy security. As such, an open and collaborative effort will be required between all 

parties to provide for better stewardship of oil and gas resources—across Region 8 and 

the nation as a whole. 

 

41 National Petroleum Council, Facing the Hard Truths About Energy, http://www.npchardtruthsreport.org. 

U.S. Environmental Protection Agency Working Draft – September 2008 2-22 
ENVIRONMENTAL RELEASES 

3.0 Environmental Releases

3.1 Data Sources and Assumptions 

As noted in Section 1.2.2, we characterized the environmental releases associated with oil 

and gas production in 2002 and 2006, focusing on air emissions as well as produced 

water and drilling waste. Development of the 2002 data set is documented in Appendix 

C; these data were then used with other sources to estimate the same set of environmental 

impacts (i.e., air emissions, produced water, and drilling waste) for 2006. 

In addition, the methodological approach used to estimate 2006 environmental impacts 

helps provide a more current view of the dynamic growth in oil and gas production in 

Region 8 since 2002 (the baseline year for much of the data currently available and 

featured in this report). Sections 3.1.1 and 3.1.2 below summarize key 2002 data sources 

and 2006 extrapolation assumptions. 

3.1.1 2002 Data Sources and Assumptions 

Air Emissions 

Oil and gas production facilities focused on drilling and resource extraction are exempt 

from EPA’s Toxic Release Inventory (TRI) reporting requirements. As such, data 

resources for air emissions (and other environmental impacts) stemming from oil and gas 

production are limited. After researching and evaluating various information sources, the 

EPA Sector Strategies Program decided to profile and analyze the WRAP air emissions 

data. Indeed, the WRAP data set is the principal information source underpinning our 

analytical assessment of air emissions associated with oil and gas production in Region 8. 

The WRAP estimates of air emissions for 200242 are well documented and appear to be 

the best available given the oil and gas production environmental impact data limitations 

previously referenced. Specifically, air emissions data obtained from WRAP include 

estimates of NOx, SO2, VOCs, CO, particulates, ammonia (NH3), and hydrogen sulfide 

(H2S). 

The WRAP defines air emissions sources in a slightly different way than CAA programs 

do. In WRAP terminology, a point source is “a specific source of air pollution” and an 

area source is “many small sources of air pollution in which the contribution of each 

source is relatively small, but combined may be a significant source of air pollution.” The 

CAA categorizes stationary sources as “major” or “minor” for pollutants, based on the 

potential or permitted air emissions, and it defines “area source” as a stationary source of 

air pollution that is not major. WRAP’s categorization of point sources most closely 

correlates to major sources of air pollution, but could potentially include minor sources as 

well. Note that WRAP’s categorization of area sources could include certain mobile 

sources that effectively function as stationary sources, such as drilling rigs. 

 

42 A 2005 update of this data is available in the WRAP document WRAP Area Source Emissions Inventory Projection and 

Control Strategy Evaluation – Phase II, September 2007. 

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ENVIRONMENTAL RELEASES 

Other main assumptions for the WRAP 2002 inventory are described below: 

• For point sources: 

– Original estimates of point source air emissions are based on data collected from 

states and local agencies (through the National Emissions Inventory (NEI), other 

EPA data sets, and other data sources maintained by organizations outside the 

agency). These original estimates of point source air emissions were reviewed and 

revised by WRAP. 

– Point source emissions data used in this analysis account for installed control 

device reductions. Control devices accounted for in the WRAP inventory include 

NOx controls, VOC reduction measures, LDAR systems, and others. 

– The classification of a point source differs from state to state. For example, in 

Colorado, a threshold of 2 tons per year of NOx is used for point sources; in other 

states, the threshold is greater than 2 tons.43 

– The WRAP database is the region’s most comprehensive source for criteria 

pollutant emissions data; however, data for some of the important fields, 

specifically those pertaining to production and throughput, are not available. 

– Not every well or producing facility will have enough emissions to be classified 

as a point source. Therefore, the WRAP emissions estimates from smaller 

stationary sources are grouped together in the area source category. 

– Another limitation of our analysis is that production within tribal lands is not 

captured. Although there were data in the WRAP database, the relevant state 

locations were not identified. Due to the relatively modest contribution of these 

sources to total projected emissions from regional production operations, the 

additional time and resources needed to account for them accurately were not 

expended.44

• For area sources: 

– WRAP area source estimates include only NOx, VOC, and SO2 emissions from 

larger sources. As such, not all air pollutants from oil and gas sources are 

included. 

– For NOx and SO2 estimates, sources were limited to compressor engines, drill 

rigs, and CBM pump engines. 

– For VOC estimates, sources were limited to oil well tanks and pneumatic devices, 

gas well pneumatic devices, gas well dehydrators, gas well completion flaring and 

venting, and controlled as well as uncontrolled condensate tanks. 

 

43 For example, Colorado has by far the greatest number of point sources, most of which are in the natural gas liquid 

extraction facility category. Although Wyoming has large gas production, the sources are defined differently than in 

Colorado, resulting in fewer listed point sources, though the emissions are still captured as area sources. 44 EPA is presently engaged in a rulemaking process focused on New Source Review Minor Permits for air sources on 

tribal lands. 

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ENVIRONMENTAL RELEASES 

• Due to limitations associated with environmental data from tribal lands previously 

referenced, area source emissions for production are excluded. Although it is possible 

that state data would include tribal data, there is no confirmation available. 

• Regarding CO2 emissions, the U.S. Census of Mining (a subset of the U.S. Economic 

Census data set) reports fuel consumption from oil and gas extraction establishments 

in 2002. In addition, the U.S. Department of Energy (DOE) Energy Information 

Administration (EIA) reports natural gas lease and plant consumption data, which help 

to quantify CO2 emissions. Specifically, natural gas lease and plant is recovered 

natural gas used as fuel for various oil and gas extraction operations and natural gas 

processing equipment. CO2 emissions were then calculated by applying standard 

emissions factors to the fuel consumption estimates from the Census and EIA data 

sets, respectively. 

Produced Water 

Although water discharges from oil and gas extraction facilities are reported to EPA, this 

data is not readily available to the public. Primary sources for water data presented in this 

report originate from proprietary industry information sources, Lasser, Inc. and IHS, Inc., 

respectively. Lasser is the oldest U.S. source of oil and gas production data. Similarly, 

IHS is a global provider of information products and services, providing critical insights 

into oil and gas production, energy, and other key industries since 1959. These are 

privately managed databases, and their information is largely based on data reported by 

industry to the states for taxation and royalty purposes. They are widely used by industry 

and government to characterize oil and gas exploration and production activity. The 

Lasser data provide information on the number of wells drilled and amount of oil, gas, 

and water produced. Data extracted from these sources were used to estimate well counts 

and volumes of produced water resulting from production. We used the IHS database to 

identify the CBM wells and to help disaggregate the well data, including produced water, 

by well type. 

Drilling Activities 

Estimates of drilling waste profiled in this report were calculated by using the American 

Petroleum Institute’s (API) Overview of Exploration and Production Waste Volumes and 

Waste Management Practices in the United States. This resource provides emission 

factors that help analysts capture volumes of drilling waste associated with production.45

We used those emission factors in combination with operating data to provide annual 

estimates for 2002 and 2006, respectively. 

3.1.2 2006 Data Development Assumptions 

In developing estimates of environmental impacts of regional oil and gas production in 

2006, we first assembled, developed, and analyzed the 2002 data set. Using the 2002 

baseline, we then extrapolated data and carried the estimates forward to 2006 using 

production-related variables tied to oil and gas drilling activities. Regional estimates for 

 

45 Note: API emission factors from the reference guide mentioned above are generally believed to be the best available. 

U.S. Environmental Protection Agency Working Draft – September 2008 3-3 
ENVIRONMENTAL RELEASES 

2006 are based on this extrapolation and augmented by production-related trends data as 

well as relevant EIA data sources. However, due to data limitations regarding individual 

production operations within Region 8, no specific assumptions or calculations were 

made to capture possible operator adjustments to oil and gas processes (e.g., installation 

of emissions control devices) between 2002 and 2006. In addition, no adjustments were 

made to incorporate changes in federal and state laws and implementing regulations 

affecting air emissions and non-air releases from oil and gas production. We did not 

perform these adjustments, because relevant emissions data, as well as the time and 

staffing resources to investigate and analyze them, were limited. 

In spite of the limitations, the 2006 estimates help to illustrate the potential breadth of 

environmental impacts associated with rapid growth of oil and gas production in the past 

five years. Table 3-1 summarizes how we developed the 2006 data, by pollutant. The 

choice of variables selected depended on the relevance of the source data as well as the 

availability of 2006 state data. For example, state oil and gas production data as well as 

EIA natural gas processing figures were used to calculate all air emissions except CO2. 

To develop the CO2 emissions projections (out to 2006), we used industrial production 

indices (or growth factors) provided by the Federal Reserve Board (FRB) by relevant 

North American Industry Classification System (NAICS) codes. In addition, we 

augmented these projections with EIA statistics reflecting natural gas lease and plant 

consumption for 2006. 

For produced water, we used the 2006 Lasser and IHS data. For drilling waste, we used 

2006 API drilling data to estimate growth in drilling waste from 2002 to 2006. 

Table 3-1. Methodology to Develop 2006 Data, by Pollutant 

Pollutant Methodology 

Air Emissions: VOCs, HAPs, 

NOx, CO, SO2, NH3, H2S, all 

PMs 

Extrapolated 2002 to 2006 using oil and gas production by state. 

Data source: EIA 

Air Emissions: CH4 Extrapolated 2005 to 2006 using oil and gas production and gas processing data 

by state. 

Data source: EIA 

Air Emissions: CO2 Extrapolated 2002 fuel (except natural gas lease and plant) consumption to 2006 

using FRB Industrial Production Indices for the following NAICS: NAICS 211111 

(Crude Petroleum and Natural Gas Extraction), NAICS 211112 (Natural Gas 

Liquids Extraction), NAICS 213111 (Drilling Oil and Gas Wells), and NAICS 

213112 (Support Activities for Oil and Gas Extraction Operations). Note that FRB 

data are only at the national level. 

For natural gas lease and plant, extrapolated 2002 to 2006 using the EIA national 

estimate of natural gas lease and plant. 

Data sources: FRB, EIA 

Produced Water Used Lasser and IHS produced water estimates for 2006. 

Drilling Waste Extrapolated 2002 to 2006 using API drilling activity data by state. 

Data source: API 

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ENVIRONMENTAL RELEASES 

3.2 Estimated Air Emissions: Comparing 2002 Baseline to 2006 Estimates 

Section 3.2 presents air emissions estimates for 2002 and 2006, respectively, providing 

insights into the growing significance of oil and gas production activities in Region 8.46

Table 3-2 compares 2002 criteria pollutant emissions from production as reported by 

WRAP to the total emissions from all industrial categories and sources within Region 8. 

From these data, one can see that VOCs47 from oil and gas production account for nearly 

40 percent of total emissions in Region 8. NOx is another significant challenge, as 

production-related emissions represent almost 15 percent of the regional total. 

From 2002 to 2006, regional oil and gas production increased by about 25 percent, and 

drilling activity expanded by 27 percent (as reflected by regional increases in production 

wells). Given the rapid growth during this period, various stakeholders are voicing 

concerns that increasing VOC and NOx emissions from production operations will 

substantively contribute to expanding ground-level ozone and regional haze issues. These 

concerns have resulted in new regulations to limit NOx and other emissions from oil and 

gas production sources (e.g., Federal NSPS regulations, Colorado’s new NOx, CO, and 

VOC regulations for the oil and gas industry). 

Table 3-2. Oil and Gas Criteria Pollutant Emissions Compared to 

Total Region 8 Criteria Pollutant Emissions, 2002 (tons) 

Pollutant 

Emissions From Oil 

and Gas Sector 

Total Region 8 

Emissions 

Oil and Gas Emissions as 

Percentage of Regional 

Emissions 

VOCs 262,953 651,580 40.4% 

NOx 87,130 587,942 14.8% 

CO 37,880 413,990 9.2% 

SO2 18,385 503,041 3.7% 

PM 834 2,172,255 <0.1% 

Table 3-3 shows total criteria pollutant emissions from oil and gas production in 2002 

grouped by state and pollutant. Wyoming has the greatest air emissions, followed closely 

by Colorado. These two states encompass the most oil and gas production in the region. 

Conversely, South Dakota has the lowest criteria pollutant emissions and the least oil and 

gas production compared to other Region 8 states. The table also shows that VOC 

emissions represent the largest regulated pollutant, followed by NOx, CO, and SO2. The 

PM emission estimates are not very reliable due to limited data and variable definitions of 

the different kinds of PM; however, they are relatively insignificant compared to other 

criteria pollutants common to oil and gas production. 

Particulate emissions available from WRAP are “PM10_PRI” (PM10 primary emissions, 

the sum of filterable and condensable particulates). Note that particulate emissions were 

not available for three states: Montana, North Dakota, and South Dakota. As discussed 

in Appendix C, Sections C.2.2 and C.2.3, emissions from sources in these states may be 

 

46 Note: Numbers in associated tables in this section may not add due to rounding. 47 Although EPA does not list VOCs as one of the six criteria pollutants, they are referenced in this section due to their role 

as a precursor to ozone, a listed criteria pollutant. 

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ENVIRONMENTAL RELEASES 

too small on an individual basis to be included in the point source category. In addition, 

the WRAP data collection project initiated in 2005 to expand the criteria pollutant 

inventory did not include particulates, leaving data gaps for those states. 

Table 3-3. Criteria Pollutant Emissions by Pollutant, by State, 2002 (tons) 

Pollutant CO MT ND SD UT WY Total 

VOCs 90,683 5,502 7,805 288 36,537 122,138 262,953 

NOx 45,960 7,761 7,571 361 5,108 20,369 87,130 

CO 20,720 1,183 798 11 2,443 12,725 37,880 

SO2 220 227 2,882 6 1,590 13,460 18,385 

PM10_PRI 384 0 0 0 16 9 408 

Table 3-4 shows total criteria pollutant emissions from production in 2006 increased by 

24 percent from the 2002 baseline. Production emissions in Montana increased by almost 

75 percent, while emissions in Colorado increased by almost 28 percent. The fastest 

growing criteria pollutants are NOx and PM10_PRI, which are projected to increase by 28 

percent and 27 percent, respectively, over this 4-year period. 

Table 3-4. Criteria Pollutant Emissions by Pollutant, by State, 2006 (tons) 

Pollutant CO MT ND SD UT WY Total 

VOCs 115,517 9,596 9,596 302 45,472 142,383 322,865 

NOx 58,546 13,536 9,307 378 6,358 23,745 111,870 

CO 26,395 2,064 980 12 3,041 14,834 47,326 

SO2 281 396 3,544 6 1,978 15,691 21,895 

PM10_PRI 489 0 0 0 20 10 519 

Table 3-5 shows non-criteria pollutant pollutants, GHGs, and HAPs by state in 2002. 

When methane emissions are weighted by their global warming potential (GWP),48 CO

equivalent methane emissions represent the largest non-criteria pollutant emissions (at 

over 10 million tons). While these emissions are not currently regulated, GHG 

regulations are being developed within the region, from individual states to the WCI, and 

some industry companies are taking proactive measures to find ways of reducing GHG 

emissions. In fact, BP America received the 2007 IOGCC National Environmental 

Stewardship Award for their project to reduce GHG emissions by challenging the 

conventional wisdom of standard practices associated with well venting By 

comparison, HAP emissions are much smaller and are primarily VOCs. 

2

.

49

Table 3-6 shows non-criteria pollutant pollutants, GHGs, and HAPs by state for 2006. 

From 2002 to 2006, CO2 emissions increased an estimated 32 percent, HAP emissions 

grew by 19 percent, and CH4 increased by almost 13 percent. Whereas Utah and 

Wyoming reported the fastest growth in non-criteria pollutant emissions, South Dakota 

exhibited a decline in emissions, the only state in Region 8 to do so. 

 

48 GWP is a measure of how much a GHG is expected to contribute to global warming. In the case of methane, GWP is 

approximately 21 times the global warming contribution of CO2 (whose GWP is, by definition, 1) measured over a 100-

year timeframe. 

49 http://www.iogcc.state.ok.us/iogccs-2007-chairmans-stewardship-award-winners-are 

U.S. Environmental Protection Agency Working Draft – September 2008 3-6 
ENVIRONMENTAL RELEASES 

Table 3-5. Non-Criteria Pollutant Air Emissions by Pollutant, by State, 2002 (tons) 

Pollutant CO MT ND SD UT WY Total 

CH4 (CO2 equivalent) 3,216,621 410,513 591,147 37,543 893,226 5,217,392 10,366,442 

CH4 153,172 19,548 28,150 1,788 42,535 248,447 493,640 

CO2 1,644,066 622,154 265,536 15,767 403,571 2,240,802 5,191,897 

HAPs 3,781 130 431 15 3,932 25,450 33,738 

Table 3-6. Non-Criteria Pollutant Air Emissions by Pollutant, by State, 2006 (tons) 

Pollutant CO MT ND SD UT WY Total 

CH4 (CO2 equivalent) 3,645,531 773,105 773,699 39,252 1,044,258 5,404,241 11,680,085 

CH4 173,597 36,815 36,843 1,869 49,727 257,345 556,195 

CO2 2,130,662 762,281 273,938 13,565 566,341 3,120,791 6,867,579 

HAPs 4,817 226 529 15 4,893 29,668 40,149 

Table 3-7 presents air emissions by major source category—point and area—by state. 

VOCs, NOx, SO2, CO, and HAPs are the only pollutants shown, since data are available 

by type of major source. 

Table 3-7. Total Point and Area Emissions of VOCs, NOx, SO2, CO, and HAPs, by State, 

2002 (tons) 

Pollutant/Source CO MT ND SD UT WY Total 

VOCs 

 Point 63,423 58 66 0 576 2,691 66,814 

 Area 27,259 5,444 7,740 288 35,961 119,447 196,139 

 Total 90,683 5,502 7,805 288 36,537 122,138 262,953 

NOx

 Point 22,442 204 2,940 0 1,774 5,644 33,003 

 Area 23,518 7,557 4,631 361 3,335 14,725 54,126 

 Total 45,960 7,761 7,571 361 5,108 20,369 87,130 

SO2

 Point 102 2 2,524 0 1,573 13,309 17,510 

 Area 118 225 358 6 17 150 874 

 Total 220 227 2,882 6 1,590 13,460 18,385 

HAPs 

 Point 2,777 1 0 0 52 220 3,050 

 Area 1,004 128 430 15 3,880 25,230 30,688 

 Total 3,781 130 431 15 3,932 25,450 33,738 

CO 

 Point 13,874 165 761 0 1,883 9,179 25,862 

 Area 6,847 1,018 36 11 560 3,546 12,018 

 Total 20,720 1,183 798 11 2,443 12,725 37,880 

For VOCs and HAPs, the table reveals area sources are a much greater contributor to 

emissions than point sources in Region 8. For NOx and CO emissions, point and area 

sources contribute significantly to total emissions. The area source fraction is slightly 

larger for NOx and the point source component is larger for CO. NOx and CO emissions 

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ENVIRONMENTAL RELEASES 

are primarily from large combustors (point sources) as well as small combustors and 

mobile sources (area sources). On the other hand, SO2 emissions are dominated by large 

point source combustors. Methane emissions are not shown in Table 3-7, primarily 

because the exact split between area and point sources is not known. However, it is 

generally believed that methane releases are primarily from area sources and are 

considered fugitive emissions.50

Table 3-8 projects the point and area source emissions for 2006. For VOCs and HAPs, 

we estimate point source emissions have grown faster than area source emissions over the 

4-year period. For NOx, SO2, and CO, area source emissions increased more than point 

source emissions. 

Table 3-8. Total Point and Area Emissions of VOCs, NOx, SO2, CO, and HAPs, by State, 

2006 (tons) 

Pollutant/Source CO MT ND SD UT WY Total 

VOCs 

 Point 80,793 101 81 0 717 3,137 84,829 

 Area 34,725 9,494 9,515 302 44,755 139,246 238,036 

 Total 115,517 9,596 9,596 302 45,472 142,383 322,865 

NOx

 Point 28,588 356 3,614 0 2,207 6,579 41,344 

 Area 29,958 13,180 5,693 378 4,150 17,166 70,526 

 Total 58,546 13,536 9,307 378 6,358 23,745 111,870 

SO2

 Point 130 3 3,103 0 1,958 15,515 20,710 

 Area 151 393 441 6 21 175 1,186 

 Total 281 396 3,544 6 1,978 15,691 21,895 

HAPs 

 Point 3,538 2 0 0 65 256 3,861 

 Area 1,279 224 529 15 4,828 29,412 36,288 

 Total 4,817 226 529 15 4,893 29,668 40,149 

CO 

 Point 17,673 288 936 0 2,344 10,700 31,941 

 Area 8,722 1,776 45 12 697 4,134 15,385 

 Total 26,395 2,064 980 12 3,041 14,834 47,326 

3.3 Estimated Non-Air Releases (Produced Water and Drilling Waste), 

2002 and 2006 

Non-air releases mainly refers to produced water (from oil and gas resource extraction) 

and drilling waste (i.e., drilling muds and fluids as well as drill cuttings). Sections 3.3.1 

and 3.3.2 present the data and implications for produced water from 2002 to 2006, while 

Sections 3.3.3 and 3.3.4 present the data and implications regarding drilling waste.51

 

50 Fugitive emissions are those stemming from unanticipated releases or leaks in production equipment and associated 

processes. 

51 Note: Numbers in associated tables in these sections may not add due to rounding. 

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ENVIRONMENTAL RELEASES 

3.3.1 Produced Water Summary 

Proper management of produced waters is a high priority topic in Region 8. Tables 3-9, 

3-10, and 3-11 show estimates of produced water for Region 8, categorized by state and 

type of producing well. Table 3-9 shows the amount of produced water from oil and gas 

extraction activities in the region by state, for 2002 and 2006, from data provided by an 

industry data aggregation company, Lasser Inc. (Note that data provided on the Wyoming 

Oil and Gas Conservation Commission website differs from the Lasser data, indicating a 

7.5 % increase in produced water in Wyoming from 2002 to 2006. 52) 

In 2002, almost 3 billion barrels of produced water were extracted in Region 8, with 

Wyoming contributing almost 75 percent of total produced water. There was only a slight 

increase of total produced water in the region projected from 2002 to 2006 (1.7 percent). 

Whereas South Dakota, Utah, and Wyoming showed reductions in produced water, 

Colorado, Montana, and North Dakota showed increases. The largest percentage 

increases in production (from 2002 to 2006) appear to have been in North Dakota and 

Montana. 

Table 3-9. Produced Water by State, 2002 and 2006 (barrels) 

State 2002 2006 Percent Change 

WY 2,091,105,179 2,025,898,781 -3% 

CO 348,255,005 405,507,349 16% 

UT 136,296,362 128,669,683 -6% 

MT 123,397,156 158,186,310 28% 

ND 98,537,154 127,383,733 29% 

SD 8,108,174 8,015,208 -1% 

Total 2,805,699,030 2,853,661,064 2% 

The category “oil with gas wells” (where “associated gas” is produced) was the largest 

contributor of produced water in Region 8, as shown in Table 3-10.53 Oil-only wells 

released the second largest amount of produced water. Combined, these two well types 

account for 69 percent of total produced water in the region. These results are not 

unexpected, since oil wells typically release more produced water than gas wells 

(particularly as they mature and produce fewer and fewer barrels of oil over time). 

Wyoming is the primary source of produced water in the region for both well types, 

providing further indication of the broad scope of production activities within the state. 

From coal to oil and gas production and other forms of energy development, Wyoming is 

one of the nation’s leading providers of domestic fuels. Most of the water produced from 

oil wells is re-injected underground. Oil wells often use water injection to stimulate oil 

production54 (e.g., “water flooding”), and produced water from these operations is often 

recycled and re-injected to stimulate further production. In addition, in terms of disposal 

 

52 http://wogcc.state.wy.us/StatisticsMenu.cfm?Skip='Y'&oops=49 53 Natural gas is found in two basic forms: associated gas and non-associated gas. Associated gas occurs in crude oil 

reservoirs either as free gas (associated) or as gas in solution with crude oil (dissolved gas). Non-associated gas is not in 

contact with significant quantities of crude oil in the reservoir. 

54 Some wells inject steam or water into the producing formation to promote oil recovery from wells where production has 

slowed. Steam and water flooding are two common approaches to enhanced oil recovery (EOR). 

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options, produced water is re-injected into deep formations via underground injection 

control (UIC) wells.55

Table 3-10. Produced Water by Well Type, 2002 (barrels) 

State Oil-Only Wells Gas-Only Wells 

Oil With Gas 

Wells 

Gas With Oil 

Wells Total 

WY 601,234,810 569,061,152 853,631,461 67,177,756 2,091,105,179 

CO 81,962,976 158,856,545 102,323,995 5,111,489 348,255,005 

UT 21,684,832 31,145,993 79,283,960 4,181,577 136,296,362 

MT 50,775,321 16,847,685 55,708,537 65,613 123,397,156 

ND 20,953,673 3,521 74,617,442 2,962,518 98,537,154 

SD 915,122 614 5,121,998 2,070,440 8,108,174 

Total 777,526,734 775,915,510 1,170,687,393 81,569,393 2,805,699,030 

Table 3-11 shows produced water by well type, including CBM, for 2006. We estimate 

that produced water coming from oil wells (oil-only wells and oil with gas wells) 

declined slightly from 2002 to 2006. During the same period, produced water associated 

with gas wells (gas-only wells, including CBM wells, and gas with oil wells) appears to 

have increased, with the largest projected increase coming from gas with oil wells. 

Table 3-11. Produced Water by Well Type, 2006 (barrels) 

State Oil-Only Wells Gas-Only Wells 

Oil With Gas 

Wells 

Gas With Oil 

Wells Total 

CO 47,185,142 217,006,510 127,734,624 13,581,073 405,507,349 

MT 56,283,830 28,076,898 73,443,690 381,892 158,186,310 

ND 26,358,334 17,382 92,659,049 8,348,968 127,383,733 

SD 616,231 953 5,597,759 1,800,265 8,015,208 

UT 28,124,959 23,725,241 65,148,166 11,671,317 128,669,683 

WY 615,254,891 566,049,418 782,635,991 61,958,481 2,025,898,781 

Total 773,823,387 834,876,402 1,147,219,279 97,741,996 2,853,661,064 

Gas-only wells also release produced water, but CBM wells release substantially more 

produced water than non-CBM wells. The quality and composition of produced CBM 

water varies widely, as shown in Table 3-12. Nevertheless, there is significant interest in 

CBM produced water in Region 8. The main reason behind the increased attention is that 

these CBM gas wells often yield high quality, and high volumes of, produced water that 

supports agricultural, ranching, and other uses56 (NOTE: Specific data on produced 

water usage in agricultural purposes (e.g., center-pivot irrigation) is not available and 

thus could not be analyzed for purposes of this report). 

As noted in Section 2.3.2, EPA’s Office of Water is conducting an in-depth study of the 

CBM sector. The agency is presently surveying oil and gas companies to assess current 

issues and impacts, leadership practices, economic considerations, and other issues 

 

55 Oil and gas UIC wells are classified as Class II wells. In these wells, produced water and other fluids associated with oil 

and gas extraction (produced water) are reinjected into the same formation. The fluids are mostly salt water (brine). 

56 Additional information on GHG emissions and produced water issues can be found at: 

http://www.beneficialusesummit.com/2008/2008presentations.html

U.S. Environmental Protection Agency Working Draft – September 2008 3-10 
ENVIRONMENTAL RELEASES 

influencing industrial operations and associated environmental management practices in 

Region 8 and other U.S. locations with CBM production. 

Table 3-12. Characteristics of CBM-Produced Water57

Primary pollutants commonly found in produced water from CBM operations include 

mineral salts, sodium, and metals such as iron. While produced water extracted from oil 

wells often cannot be safely discharged and is typically re-injected, CBM produced water 

can often have beneficial uses in agriculture (e.g., water for irrigation purposes), ranching 

(e.g., drinking water for livestock), and other applications. Given the fairly high quality 

of some CBM produced water, operators are permitted to discharge produced water into 

streams and rivers, provided this water is of sufficient quality to meet the designated uses 

of the receiving water body or is treated to meet those uses. However, in cases where the 

pollutant concentrations are too high for surface discharge, the produced water may be 

treated, re-injected, or impounded for evaporation and infiltration. These impoundments 

may have hydrologic connections to surface waters. Some operators are able to use CBM 

produced waters containing high concentrations of dissolved inorganics for livestock 

watering or irrigation with proper soil amendments and monitoring. 

In addition, some produced water from CBM operations may be re-injected into deep 

geological formations (where injection zones are available). This is a common practice in 

some CBM basins (e.g. San Juan Basin in Colorado and New Mexico). Other basins 

have geologic conditions that present technical challenges to re-injection of CBM 

produced water. For example, the Wyoming Oil and Gas Conservation Commission 

estimates that across the Powder River Basin, nearly half of the wells drilled for injection 

cannot accept produced water and that half of the wells that can initially accept produced 

 

57 U.S. Environmental Protection Agency, Technical Support Document for the 2006 Effluent Guidelines Program Plan, 

http://www.epa.gov/guide/304m/2006-TSD-whole.pdf

U.S. Environmental Protection Agency Working Draft – September 2008 3-11 
ENVIRONMENTAL RELEASES 

water quickly become impaired (from plugging) and thus not a viable option for further 

injection58. 

3.3.2 Produced Water Management and Implications 

Oil and gas production activities have various implications for water management, from 

storm water management (as construction sites are prepared for eventual exploration and 

production) to management of produced water. Nevertheless, produced water is, by 

volume, the largest waste stream associated with production. Effective management of 

produced water—and operator preparations to ensure spill prevention, countermeasures, 

and control—can present technical challenges and impose costs on producers, 

particularly small businesses. Environmental issues identified with produced water 

management range from potential harm to aquatic life and crops from pollutants or 

chemical constituents that flow into these areas to streambed erosion from produced 

water discharges. A DOE report prepared by the Argonne National Laboratory provides 

the following issue summary: 

“[Produced water] is not a single commodity. The physical and chemical 

properties of produced water vary considerably depending on the geographic 

location of the field, the geological formation with which the produced water has 

been in contact for thousands of years, and the type of hydrocarbon product being 

produced. Produced water properties and volume can even vary throughout the 

lifetime of a reservoir. If water flooding operations are conducted [to enhance 

resource recovery], these properties and volumes may vary even more 

dramatically as additional water is injected into the formation.”59

3.3.3 Drilling Waste Summary 

Oil and gas production yields drilling waste that contains mud, rock fragments, and 

cuttings from the wellbore, as well as chemicals added to improve mud properties. Such 

drilling waste accounts for the second largest amount of waste resulting from oil and gas 

production (second only to produced water). Drilling fluids include drill cuttings (i.e., 

rock removed from the formation during drilling) and drilling muds (i.e., water or oilbased fluids with additives that are pumped down the drilling pipe to offset formation 

pressure, provide lubrication, and seal off the wellbore to avoid contamination and 

remove cuttings). Other associated wastes include oily soil, tank bottoms, workover 

fluids, produced sand, pit and sump waste, pigging waste, iron sponge, dehydration 

condensate water, molecular sieve waste, and oily cuttings. 

Table 3-13 shows the volume of drilling waste (in barrels) by state for 2002 and 2006. 

Whereas Wyoming produced the largest amount of drilling waste, followed by Colorado 

and Utah, South Dakota produced the least amount among Region 8 states. 

 

58 EPA-HQ-OW-2006-0771-0970. 

59 Argonne National Laboratory, A White Paper Describing Produced Water from Production of Crude Oil, Natural Gas, 

and Coal Bed Methane, prepared for DOE’s National Energy Technology Laboratory (NETL), January 2004. 

U.S. Environmental Protection Agency Working Draft – September 2008 3-12 
ENVIRONMENTAL RELEASES 

Table 3-13. Drilling Waste by State, 2002 and 2006 (barrels) 

State 2002 2006 

Percent 

Change 

WY 10,834,600 17,668,762 63% 

CO 6,138,174 10,098,340 65% 

UT 4,533,724 9,222,269 103% 

MT 2,741,195 5,965,305 118% 

ND 1,484,341 3,370,840 127% 

SD 37,451 123,756 230% 

Total 25,769,484 46,449,272 80% 

In 2002, almost 26 million barrels of drilling waste were generated across Region 8. We 

estimate that drilling waste increased by approximately 80 percent from 2002 to 2006. 

Although South Dakota is not a major source of drilling waste, it still reported the largest 

percentage increase of any state in the region, as the 2006 projection has more than 

tripled the 2002 baseline. In Montana, North Dakota, and Utah, drilling waste more than 

doubled. Significant growth is projected in Colorado and Wyoming for 2006, as drilling 

waste increased by more than 60 percent relative to the 2002 baseline. 

3.3.4 Drilling Waste Management and Implications 

Oil and gas companies have sought to minimize drilling waste and associated 

environmental impacts in the following ways: recycling and reuse of certain drilling 

byproducts, employing nontoxic drilling fluids, and using closed-loop drilling fluid 

systems to more effectively manage associated wastes. Nevertheless, various 

environmental groups and other stakeholders continue to express concern over potential 

groundwater contamination from drilling fluids as well as the amount of surface area 

used to treat, store, and dispose of such wastes. 

Drill cuttings have been used for road spreading to mitigate some of the industry truck 

traffic damage, but concerns persist regarding associated environmental impacts due to 

the hydrocarbon content of these byproducts. In many situations, road-spreading 

applications involving drill cuttings are prohibited by regulatory agencies. Before drill 

cuttings can be beneficially reused, their salinity and hydrocarbon moisture and clay 

content must be assessed. Even after separation from other byproducts, cuttings are still 

coated with mud and, therefore, difficult to use for construction. Treatment options and 

combining drill cuttings with other materials can mitigate some of the barriers to reuse. 

Regulatory agencies have initiated efforts to encourage the eventual reuse of drilling 

wastes. At the federal level, drill cuttings are typically exempt from Resource 

Conservation and Recovery Act (RCRA) hazardous waste regulations, and this policy 

does enhance the potential for beneficial reuse60. In addition, DOE has funded several 

projects to test the feasibility of reusing cuttings. It has been 20 years since the RCRA 

exemption for oil and gas exploration and production was implemented, and many 

 

60 US Environmental Protection Agency, Exemption of Oil and Gas Exploration and Production Wastes from Federal 

Hazardous Wastes Regulations, October 2002,. http://www.epa.gov/epaoswer/other/oil/oil-gas.pdf

U.S. Environmental Protection Agency Working Draft – September 2008 3-13 
ENVIRONMENTAL RELEASES 

practices and chemicals used have changed during that time. EPA may need to revisit the 

continued validity of the exemption in light of the advancements in practices. For 

example, more information about ground water contamination as a result of 

advancements developed in the RCRA program may be pertinent. In addition, better 

technology such as synthetic liners and leak detection systems may have become more 

reliable and less costly for operators to install and maintain over the past two decades. 

Outside Region 8, some states are addressing liability and other concerns that can inhibit 

beneficial reuse of drill cuttings. For example, in December 2006, the Railroad 

Commission of Texas (RRC) revised Texas Administrative Code Title 16, Part 1, Chapter 

4 and Subchapter B to specify that “a recyclable product is not a waste.” The rule was 

proposed to mitigate liability concerns of potential end users considering reuse options.61

 

61 ICF International. Beneficial Reuse of Industrial Byproducts in the Gulf Coast Region, prepared for EPA’s Sector 

Strategies Program, February 2008. 

U.S. Environmental Protection Agency Working Draft – September 2008 3-14 
SUMMARY 

4.0 Summary 

4.1 Summary of Data Findings 

As detailed in Chapter 3, air emissions, produced water, and drilling waste are the leading 

environmental concerns associated with oil and gas exploration and production in Region 

8 and elsewhere. Land use conflicts also can create adversity, delays, and lawsuits. As an 

example, cultural resource protection and recreational opportunities on federal lands may 

overlap or compete with private-sector interest in areas of high development potential – 

from oil and gas production to other industrial operations. Environmental impacts can 

arise due to improper management of produced water and drilling waste; accidental 

hydrocarbon and produced water releases; abandoned or orphaned wells; and emissions 

from oil and gas exploration, production, and storage units. Impacts to ground-surface 

also result from related activities, such as site clearing; construction of roads, tank 

batteries, brine pits, and pipelines; and other necessary land modifications that produce 

surface disturbances. As oil and gas companies steadily continue to increase industry’s 

investment in exploration and production in Region 8 and nationally, the need for 

effective environmental management and protection has never been greater. 

With conventional oil and gas production in decline throughout the United States and 

domestic fuel consumption costs on the rise, unconventional oil and gas resources are 

becoming increasingly attractive and profitable to U.S. producers. Representative 

unconventional oil and gas resources found in Region 8 states include CBM, heavy oil, 

oil sands, gas stored in ultra-tight formations (i.e., tight gas or shale gas), and oil shale. 

Converting these fossil fuel resources into energy for consumers via oil and gas 

production has environmental consequences, including increased water use, air 

emissions, drilling waste, surface disturbances, and land and habitat impacts. 

Unconventional natural gas operations such as tight gas and CBM require more wells to 

produce the same volume of gas than conventional wells, resulting in more drilling and 

greater surface disturbances. In addition, extracting natural gas from CBM wells 

produces significant volumes of produced water. Due to these resource characteristics 

and their associated production, oil and gas extraction in the Rocky Mountain region has 

a somewhat different—and likely greater—environmental footprint than production from 

conventional operations in other regions. The rapid expansion of oil and gas production 

activities in recent years, coupled with abundant proven and projected reserves, suggest 

that Region 8 will remain strategically important from an energy security perspective for 

years to come. Although growth in oil and gas production is expected to continue, natural 

gas extraction will dominate the region—primarily from tight gas and CBM formations—

given its vast resource base. Moreover, despite improvements in drilling technology that 

shrink the environmental impacts of unconventional reserves per unit of production, such 

operations still involve a greater degree of surface disturbance and more water production

than conventional gas extraction. 

Such environmental impacts stem from the higher total volume of production in the 

region brought on by tighter well spacing and other operational characteristics of 

U.S. Environmental Protection Agency Working Draft – September 2008 4-1 
SUMMARY 

unconventional resource development. Although horizontal drilling does reduce the 

number of well pad locations relative to conventional extraction techniques, these and 

other operational advances are not sufficient to offset the range of environmental impacts 

associated with unconventional gas production. However, horizontal drilling technology 

can mitigate some of the negative environmental impacts. The following quote from one 

industry executive overseeing oil and gas operations in the Rockies succinctly captures 

some of the tradeoffs associated with unconventional gas production: 

“There are vast volumes of gas in the Rockies. The gas is there. The difficulty is 

that, as we drill these poorer and poorer quality reservoirs, it takes three or four 

wells today to deliver the same volume of gas that one conventional well 

would’ve yielded 10 or 15 or 20 years ago.”62

In summary, the environmental footprint associated with oil and gas production continues 

to expand, fueling stakeholder concerns and regulatory deliberations regarding the 

potential pathway forward. As reflected in Table 4-1, this report shows that 

environmental impacts from oil and gas production in Region 8 are significant, with air 

emissions from regional oil and gas production estimated to comprise 6 percent of PM to 

30 percent of HAPs of total U.S. emissions for this sector in 2006. 

Table 4-1. Region 8 Versus National Oil and Gas Air Emissions/ 

Produced Water/Drilling Waste, 2006 (tons/barrels) 

Pollutant Region 8 U.S. Total 

Region 8 as 

Percentage 

of U.S. Total 

Emissions in Tons 

VOCs 322,865 1,111,445 29% 

NOx 111,870 839,803 13% 

CO 47,326 273,051 17% 

SO2 21,895 105,227 21% 

PM 1,060 19,200 6% 

HAPs 40,149 134,508 30% 

CH4 556,195 3,841,447 14% 

CO2 6,867,579 49,706,996 14% 

Water and Waste in Barrels 

Produced Water 2,853,661,064 19,445,269,921 15% 

Drilling Waste 46,449,272 233,887,586 20% 

Air pollutants of interest are NOx, SO2, and PM as precursors of regional haze, and NOx

and VOCs as precursors of ground level ozone. VOC emissions are the largest sources in 

Region 8, and these pollutants account for nearly two-thirds (64 percent) of total regional 

emissions (all sources, not just oil and gas) per the study’s 2006 projections. NOx

emissions are primarily from engines (both stationary and mobile), turbines, and process 

heaters. VOCs are primarily fugitive emissions and include some HAPs such as benzene, 

toluene, ethyl benzenes, and xylenes. SO2 emissions are primarily related to combustion 

in the oil production sector. 

 

62 “Tapping Into Energy’s Fringe: As Companies Drill for ‘Unconventional’ Natural Gas, Environmental Impacts Mount,” 

High Country News, 12/12/05. 

U.S. Environmental Protection Agency Working Draft – September 2008 4-2 
SUMMARY 

Lastly, fugitive CH4 emissions constitute the largest source of GWP-weighted GHG 

emissions. Due to its unique unconventional resource base and emerging production 

characteristics, Region 8 contributes about 15 percent and 20 percent of the total 

produced water and drilling waste, respectively, to the national total. 

Outside of air emissions, produced water from gas wells is perhaps the most contentious 

environmental management issue confronting regulators and operators alike. Almost 3 

billion barrels of produced water were extracted in Region 8 in 2002 and 2006, with 

Wyoming contributing nearly 70 percent of total produced water (from both oil and gas 

production).63 Although gas production appears to have increased significantly from 

2002 to 2006, produced water volumes have not experienced a similar increase due to 

changes in the mix of producing formations (e.g., CBM formations that yield high 

volumes of produced water versus CBM and tight sand formations that do not). Although 

produced water often has beneficial uses, water management and treatment, when 

necessary, can have negative impacts as well, such as streambed erosion brought on by 

produced water discharges. 

In terms of wastes generated during production, Region 8 produced more than 46 million 

barrels of estimated drilling waste in 2006, an 80 percent increase compared to 2002. 

Wyoming produced the largest amount of estimated drilling waste, followed by Colorado 

and Utah. Construction of roads and operation of drilling rigs in wilderness and 

undeveloped areas are other highly visible and often controversial aspects of oil and gas 

production, particularly in pristine areas. In response to these concerns, regulators are 

attempting to find substantive ways to lessen potential impacts and reduce the industry’s 

footprint in these areas. 

As an example, in 2007, BLM proposed to manage 21,034 acres on top of the Roan 

Plateau in northwestern Colorado as Areas of Critical Environmental Concern (ACECs). 

According to BLM, the second of the agency’s two proposed Records of Decision 

(RODs) governing industry development of the plateau entails the following land use 

requirements: 

“[V]irtually all of the acres of ACECs would be managed under no surface 

occupancy stipulations, which means no surface disturbance is allowed. When the 

proposed ACECs are taken with the additional 17,336 acres stipulated no surface 

occupancy in the first ROD, more than 50 percent of the planning area would be 

stipulated no surface occupancy.”64 

4.2 Summary of Initiatives to Address Oil and Gas Demand and 

Environmental Footprint Issues 

A number of environmental management initiatives and industry leadership practices 

have been developed to try to balance the increasing demand for domestic fuel 

production with the need to reduce the potential environmental and safety impacts of oil 

 

63 Based on 2006 data. 64 U.S. Bureau of Land Management, First Record of Decision on Roan Plateau Plan, June 8, 200, 

http://www.blm.gov/rmp/co/roanplateau/. 

U.S. Environmental Protection Agency Working Draft – September 2008 4-3 
SUMMARY 

and gas production. BLM is in the process of focusing the development by requiring 

federal lease unitization, making operators achieve interim reclamation standards before 

further surface disturbance is authorized, and use of appropriate timing limitations in the 

lease stipulations based on wildlife disturbance thresholds. 

Examples of such activities include, but are not limited to, studies that investigate the 

impacts of certain oil and gas activities and then suggest mitigation practices and 

voluntary approaches for achieving such reductions (e.g., regional working groups 

convened with the goal of reducing air emissions). These policies and practices are 

discussed briefly in the sections below and are grouped according to federal, state, and 

regional initiatives;65 other ongoing analyses; and voluntary programs. Lastly, as 

previously mentioned, concerns regarding actual and potential public health impacts of 

oil and gas production have been raised but are beyond the purview of this study. 

4.2.1 Federal Initiatives 

The federal government has sponsored a number of initiatives related to the oil and gas 

industry. The following listing is a representative sampling of these efforts (some of 

which were previously referenced in this report): 

• EPA has recently conducted a number of investigations into the impacts of oil and gas 

activities on domestic water supplies. As previously mentioned, one such study is part 

of OW’s ongoing investigation into the CBM sector, which resulted in MOUs with 

hydraulic fracturing service companies66. Published in 2004, this study focused on 

whether the injection of certain hydraulic fracturing fluids into CBM wells can 

contaminate USDWs.

67

• EPA is conducting a detailed review of the CBM extraction sector to determine if it 

would be appropriate to conduct a rulemaking to revise the effluent guidelines for the 

Oil and Gas Extraction Point Source Category (40 CFR 435) to control pollutants 

discharged in CBM-produced water.

68

• To raise awareness and provide guidance for managing drilling wastes and other 

environmental impacts from oil and gas production, EPA’s Office of Enforcement and 

Compliance Assurance (OECA) issued Profile of the Oil and Gas Extraction Industry 

Sector Notebook, an important guide that recommends a number of leadership 

practices for oil and gas exploration and production operations.

69 Examples of 

suggested practices include using a closed-loop drilling fluid system, which replaces a 

reserve pit with storage tanks; reusing drilling fluids; reducing storm water runoff 

impacts through the use of sediment traps, containment dikes, and other methods; and 

reusing or recycling drilling waste. 

 

65 Further details on these programs and policies can be found in Chapter 2 of the report. 6666 U.S. Environmental Protection Agency, EPA’s Clean Water Act Review of the Coalbed Methane Industrial Sector, 

June 2007, http://www.epa.gov/guide/304m/2008/cmb-slides.pdf, accessed 08.19.08. 67 EPA, Evaluation of Impacts of Underground Sources of Drinking Water by Hydraulic Fracturing of Coalbed Methane 

Reservoirs, EPA 816-R-04-003, 2004, http://www.epa.gov/safewater/uic/pdfs/cbmstudy_attach_uic_exec_summ.pdf. 68 http://www.epa.gov/fedrgstr/EPA-WATER/2008/January/Day-25/w1344.htm. 69 EPA, OECA, Profile of the Oil and Gas Extraction Industry Sector Notebook, Chapter 5, Pollution Prevention 

Opportunities, http://www.epa.gov/oecaerth/resources/publications/assistance/sectors/notebooks/oilgaspt2.pdf. 

U.S. Environmental Protection Agency Working Draft – September 2008 4-4 
SUMMARY 

• BLM has been working with western surface land owners to resolve numerous issues 

related to federal mineral rights. Such split estate issues remain contentious and are a 

major focal point within BLM and other agencies overseeing production. The BLM 

Colorado State Office is working to improve its interim reclamation standards that 

would reduce the time needed to restore the surface disturbance to minimally 

“healthy” rangeland condition. 

• FWS, through its Refuges Annual Performance Plan (RAPP), is working to protect 

wildlife in Region 8 from various activities, including oil and gas production. 

4.2.2 State Initiatives 

In addition to federal activities, there are numerous state initiatives related to curbing the 

environmental footprint from the oil and gas industry. The following represents only a 

partial list of some of the more noteworthy state efforts: 

• States such as Colorado, Montana, and Wyoming have implemented CBM discharge 

standards to control and reduce produced water impacts. 

• Colorado has implemented more stringent VOC standards, primarily in response to the 

rapid increase in oil and gas production depicted in this report. 

• As noted in Section 2.3.1 and summarized in Section 4.2.3 below, many western states 

participate in a variety of regional air quality and climate initiatives. Colorado, Utah, 

and Montana have all developed Climate Action Plans, and Utah and Montana have 

joined the Western Climate Initiative, a regional effort to reduce GHG emissions. 

4.2.3 Regional Initiatives 

As noted previously, most policy activity concerning air emissions revolves around 

voluntary regional organizations such as the following: 

• WRAP, which tracks emissions to help meet regional haze requirements; 

• WESTAR, which has issued a number of BMPs for oil and gas operations; and 

• WCI, which seeks to reduce GHG emissions in the western United States. 

4.2.4 Other Ongoing Analyses and Policy Initiatives 

Although this report mentions various federal, state, and regional programs designed to 

reduce the environmental footprint of oil and gas production (in Region 8 and nationally), 

Congress, NGOs, and other “watchdog” organizations are scrutinizing industry 

operations as well as tax and regulatory exemptions being proposed or currently in place. 

Regulators are being pressured to implement incremental leasing approaches to reduce 

both the impacts and pace of expanding oil and gas development (in Region 8 and 

elsewhere) without sacrificing potential oil and gas royalties, state revenue streams, 

employment, and other relevant socio-economic considerations. There is increased focus 

on wildlife protection zones, and BLM is designating select areas as ACECs in its efforts 

to manage valuable and often vulnerable natural resources more effectively. 

U.S. Environmental Protection Agency Working Draft – September 2008 4-5 
SUMMARY 

U.S. Environmental Protection Agency Working Draft – September 2008 4-6 

4.2.5 Voluntary Programs 

Many of the aforementioned policies and studies have sought to identify and mitigate the 

effects of oil and gas production on the environment. Expansion of compliance 

monitoring and enforcement action is ongoing, but there are also many opportunities for 

voluntary activities to mitigate environmental impacts for the industry. As conventional 

resources continue to be depleted and market considerations for unconventional 

development remain favorable, regulators are moving to develop and implement policies 

and programs that will lessen and potentially prevent future environmental impacts. The 

following voluntary programs are especially noteworthy and are already having a positive 

influence on industry’s environmental management and approaches: 

• EPA’s Natural Gas STAR program; 

• Occupational Safety and Health Administration’s (OSHA) Voluntary Protection 

Programs (VPP); 

• The San Juan VISTAS program; 

• The Wyoming Voluntary Remediation Program (VRP); and 

• The Four Corners Air Quality Task Force. 

Each of these programs provides incentives, either implicitly as reduced emissions and 

increased product sales or explicitly as operational leeway such as reduced monitoring, to 

program participants. Such voluntary approaches encourage stewardship of the resources 

available to the oil and gas industry, while contributing to environmental protection and 

have been an effective complement to regulatory compliance and enforcement. Table 4-2 

provides additional information on each of these programs. 
SUMMARY 

Table 4-2. Summary of Voluntary Environmental Programs Available to the Oil and Gas Secto

Program 

Attributes Natural Gas STAR OSHA VPP San Juan VISTAS Wyoming VRP 

Objectives Identify and promote the 

implementation of cost-effective technologies and practices to reduce methane emissions 

• Promote effective workplace 

health and safety (in many cases, this translates into reduced environmental impact as well) 

• Enable companies to be better 

stewards of their operations by prioritizing government enforcement resources for oversight of higher risk establishments 

Identify, promote, and implement cost-effective technologies and practices to reduce air pollution affecting northwestern New Mexico 

Set up a process for owners or potential developers of contaminated sites • To determine actions required 

for remediation quickly 

• To put contaminated sites back 

into productive reuse 

Pollutants Under Purview 

Methane (CH4) Focuses on health and safety VOCs, CO, NOx, SO2, all gases that 

affect ozone and haze, and GHGs 

All types of land and water contamination 

Partners 110+ partners across the four 

sectors of the oil and gas industry (production, processing, transmission, and distribution); 8 international partners; and 19 endorser organizations 

All groups covered by OSHA, including federal agencies 

Private and public entities: industries, businesses, municipalities, organizations and community groups 

Not applicable—there are no partners, per se, but the program is designed to support owners, operators, and purchasers of contaminated sites 

States All states, including Region 8 states All states, including Region 8 states New Mexico (but lessons learned 

are presumably applicable to Region 8 and other oil and gas producing states) 

Wyoming 

Partner Benefits • Efficient and new technologies 

save partners operational costs 

• Reduction in methane emissions 

(primarily fugitives) 

• Additional revenues from saved 

methane emissions 

• Recognition as environmentally 

sensitive institution 

• “Star demonstration” sites 

evaluated every 12 to 18 months 

• “Merit” sites evaluated every 18 

to 24 months 

• “Star” sites evaluated every 3 to 

5 years 

• Lower production costs due to 

efficient technology use 

• Pollution reduction 

• Capture more product for 

market sale 

• Recognition from the VISTAS 

program as Clean Air Partner (press release, advertisements, articles, and awards) 

• Provides three types of liability 

assurances: 

1. Covenants not to sue 2. Certificate of completion 3. No further action (NFA) 

letters 

• Brownfield assessment 

assistance 

Program Outreach/ Resources 

• Technology transfer 

workshops for all sectors of the oil and gas industry 

• Annual implementation 

workshop 

• Technical documents • Feasibility studies • Partner challenge study, 

identifying opportunities 

• “Special Government 

Employee” (SGE) program to extend government resources and expertise 

• Mentoring 

• Safety and health management 

course 

• Technology transfer workshops 

• Outreach materials 

• Assist partners with technology 

and practice implementation by analyzing opportunities, where applicable 

Various fact sheets 

U.S. Environmental Protection Agency Working Draft – September 2008 
U.S. Environmental Protection Agency Working Draft – September 2008 

Program 

Attributes Natural Gas STAR OSHA VPP San Juan VISTAS Wyoming VRP 

Achievements • Partners have eliminated over 

575 Bcf of methane emissions since the program’s establishment 

• Methane emissions reductions 

of approximately 86 Bcf were achieved by partners in 2006 

• Additional revenue of more than 

$600 million in natural gas sales was generated 

The Days Away Restricted or Transferred (DART) case rate is 52% below industry average for average participant worksite 

Not ascertained Over 90 sites have registered with 

the program so far 

SUMMARY 

Appendix A: Industry Characterization 

A.1 Industry Description 

As shown in Table A-1, the following North American Industrial Classification System 

(NAICS) codes were included in this analysis of oil and gas production issues and 

associated environmental impacts: 

Table A-1. NAICS Codes Addressed in This Analysis 

NAICS Description 

2111 Oil and Gas Extraction 

211111 Crude Petroleum and Natural Gas Extraction 

211112 Natural Gas Liquid Extraction 

213111 Oil and Gas Drilling 

213112 Support Activities for Oil and Gas Operations 

In addition, as shown in Table A-2, the following Standard Industrial Classification (SIC) 

codes were included in this analysis: 

Table A-2. SIC Codes Addressed in This Analysis 

NAICS Description 

1311 Crude Petroleum and Natural Gas 

1321 Natural Gas Liquids 

1381 Drilling Oil and Gas Wells 

1382 Oil and Gas Field Exploration Services 

1389 Oil and Gas Field Services, not elsewhere classified 

In general, upstream oil and gas industry activities include seismic and geological data 

acquisition and interpretation, leasing and permitting, drilling activities, workovers and 

recompletions, and production operations. Workovers and recompletions are operations 

that work to increase or improve recovery of oil and natural gas from existing wells. As 

defined here, production operations encompass an array of activities that are needed to 

gather and process the oil and gas prior to transport and sale. 

Oil is found and extracted from geological formations in which the hydrocarbons are 

trapped in a porous formation below an impermeable cap 

rock (Figure A-1). These conventional formations have 

high permeability, which allows the oil and gas to flow 

freely to the wellhead. Generally, one or a small number of 

wells are adequate to recover oil and gas from subsurface 

formations. 

Conventional wells typically range from 3,500 to 10,000 

feet deep, and some are even deeper. In Wyoming, for 

example, some conventional wells are as much as 24,000 

U.S. Environmental Protection Agency Working Draft – September 2008 A-1 

Figure A-1. Conventional 

Oil Formation 
APPENDICES 

feet deep. Natural gas and water are typically trapped in the same formation and are 

produced along with the oil. Natural gas produced from an oil reservoir is known as 

“associated gas” and is typically separated from the oil and subsequently processed and 

then transferred to pipelines for sales and distribution. Water from the formation is 

known as “produced water” and is disposed of during production, recycled, or reused. 

Water from conventional oil formations often contains concentrations of hydrocarbons as 

well as chemicals associated with drilling processes. Produced water can be a valuable 

resource; beneficial uses include irrigation applications (e.g., water for center pivot 

irrigation), drinking water for livestock, and so forth. 

Non-associated gas, representing the majority of domestic gas production, is natural gas 

that is extracted independently from oil production. There are several categories of nonassociated gas: 

• Conventional gas is natural gas found in high-permeability formations that allow the 

hydrocarbons to flow freely to the wellhead (similar to formations containing 

conventional oil). 

• Tight gas is defined as natural gas production from low-permeability, or tight, 

reservoirs. Such reservoirs have very small pore spaces between the sandstone grains, 

and these characteristics prevent the gas from flowing freely to the wellbore. It is 

generally necessary to stimulate the pore spaces artificially, enabling the gas to flow 

from the formation to the wellhead. 

• Coal bed methane (CBM) is natural gas produced from coal seams and represents a 

substantial—and ever growing—percentage of domestic gas production, especially in 

Region 8. In general, CBM wells are typically only 1,000 to 4,000 feet deep and 

require artificial stimulation to free up and direct the gas to the wellhead. 

• Shale gas is another form of natural gas experiencing rapid growth in production 

across Region 8 and in other gas producing regions (e.g., the Barnett Shale in Region 

6). Shale is also a low-permeability formation, and natural gas production requires 

artificial stimulation (discussed in greater detail in Section A.1.1 below). 

Relevant oil and gas development activities that tend to generate the most substantive 

environmental impacts include field development drilling and subsequent production 

(including gas processing). Development drilling generally involves completion of 

numerous wells, while production operations can impact an area for many years as oil 

and gas continue to be extracted from the subsurface and processed above ground. These 

activities are described below in Sections A.1.1 through A.1.3. 

A.1.1 Drilling and Well Operations 

The major activities involved in drilling and completing an oil or gas well include: (1) 

site preparation, (2) casing and cementing, (3) drilling, and (4) stimulation and 

completion. 

U.S. Environmental Protection Agency September 2008 A- 2 
APPENDICES 

Site Preparation 

Site preparation involves surveying and permitting, road and well pad construction, and 

reserve pit excavation. Surveying is carried out to ensure the proper location and 

boundaries of the well site. Road and pad construction involves construction of an access 

road to the well site as well as grading and leveling of the well pad. A well pad must be 

large enough to accommodate various construction and service company equipment 

(typically several acres), and adjacent reserve pits hold fluids that are used and extracted 

during drilling operations. Unlike conventional gas extraction, the low permeability of 

unconventional formations requires more wells and tighter well spacing to recover 

resident natural gas reserves. Horizontal drilling techniques tend to offset associated 

surface disturbances to some degree by enabling multiple wells to be drilled from a single 

well pad. New road construction and subsequent vehicular traffic (often in ecologically 

sensitive wilderness areas) are perhaps the most visible surface disturbances associated 

with natural gas production in Region 8. 

Casing and Cementing 

Prior to initiating drilling operations, surface conductor casing is constructed. Casing is 

similar to drill pipe, but larger. In addition, casing is designed to be cemented into the 

well to preserve well integrity and protect underground sources of drinking water 

(USDWs) (Figure A-2). Conductor casing of about 20 inches in diameter is first set, and 

as the well is drilled toward its ultimate depth, progressively smaller strings of casing are 

cemented inside the earlier strings. In this manner, portions of the well that have already 

been drilled are sealed off for safety, wellbore integrity, and protection of USDWs. 

Figure A-2. Wellbore and Casing 

U.S. Environmental Protection Agency September 2008 A- 3 
APPENDICES 

Drilling 

Historically, domestic drilling has been dominated by rotary rigs that create vertical 

wellbores. Rotary rigs are powered by diesel engines and use a rotating string of drill pipe 

to turn a drill bit against the rock interface. Drilling fluids or muds are pumped downward 

via the drill pipe and circulated back to the surface to remove rock cuttings. In addition, 

drilling fluids and muds help to control pressure ratios from within the wellbore, and the 

amount of fluid system pressure is typically adjusted by varying their relative density. 

Various types of fluid systems can be used, including water-based and oil-based muds. 

The density of the drilling fluid depends on the pressure gradient and other characteristics 

of the formation being targeted. In some cases, drilling is carried out in a slightly 

underbalanced, or lower pressure, condition to minimize formation damage and improve 

production flow. Drilling muds and well cuttings are gathered in lined surface pits during 

drilling operations. When they are no longer useful, these drilling byproducts are 

removed from the production site and either disposed of (e.g., landfilled) or converted for 

one or more beneficial uses. For example, drill cuttings have been used as an alternative 

to gravel in construction or cement manufacturing. 

In the last 15 years or so, onshore directional and horizontal drilling have represented a 

growing percentage of oil and gas exploration and production activities. Directional 

drilling allows the operator to use a small surface well pad and drill outward to access a 

large portion of the reservoir. Such directional techniques reduce surface disturbances 

and in many cases improve overall project economics. Directional drilling is used 

extensively in areas such as the Jonah-Pinedale tight gas field in Wyoming and is planned 

for future tight gas development in other locations (e.g., northwestern Colorado’s 

Piceance Basin, the Bakken shale fields in Montana and North Dakota; etc.). 

In addition, increased targeting of unconventional reservoirs in Region 8 has resulted in 

more horizontal drilling activities. Horizontal drilling features techniques that shift the 

wellbore from a vertical to a horizontal orientation within the target reservoir (Figure A3). The horizontal drilling allows wellbore contact with thousands of feet of reservoir and 

is generally done in conjunction with well stimulation along the horizontal borehole. 

Such drilling methods are being used extensively in shale gas as well as CBM production 

operations. Horizontal drilling is also used in certain oil production operations (e.g., in 

the Williston Basin of North Dakota). 

In recent years, variants of horizontal drilling have been developed, and elaborate 

subsurface drilling patterns are used to more efficiently tap CBM. These methods, 

including “pinnate drilling,” drill numerous subsurface wellbores parallel to the coal 

seam. Initial pinnate drilling applications have focused on the Appalachian Basin, 

although they have potential in the Rocky Mountain region as well. Attractive features of 

these approaches include the potential to improve project economics and to reduce 

greatly surface disturbances and associated environmental impacts. 

U.S. Environmental Protection Agency September 2008 A- 4 
APPENDICES 

Figure A-3. Horizontal Drilling 

Stimulation and Completion 

After the well has been drilled to total depth, a string of production casing is cemented in. 

This allows the hydrocarbons to be produced while protecting USDWs. The production 

casing also enables the well to be sealed off from the surface if there is a problem. 

Most unconventional gas reservoirs are subject to stimulation operations to improve flow 

to the wellbore. Hydraulic fracturing is the most commonly used method of gas well 

stimulation (Figure A-4). The first aspect of hydraulic fracturing is to perforate the 

production casing with projectiles and subsequently pump a water-based solution into the 

formation through the perforated areas. Water is pumped into the reservoir at pressures 

up to 10,000 pounds per square inch, inducing fractures in the formation. In addition, 

materials such as silica sand are pumped in to prop the fractures open, allowing natural 

gas to flow more freely to the wellbore. 

Tight sand fracturing in the Rocky Mountain region typically involves stimulation of 

many zones in a well with spacing intervals of up to thousands of feet between them. In 

shale formations such as the Barnett Shale in northern Texas, several separate fractures 

are carried out within the horizontal portion of the well. Fracturing is typically 

accomplished with large truck-mounted pumps that are powered by diesel engines. 

U.S. Environmental Protection Agency September 2008 A- 5 
APPENDICES 

Figure A-4. Hydraulic Fracturing1

A.1.2 Gas Production and Processing 

Once a well has been stimulated and completed, natural gas operations move into the 

production phase. Initial production of gas generally begins as natural flow from the 

wellhead into the gathering system. As a field matures, there is a decline in reservoir 

pressure. Natural gas wells flow gas to the surface until abandonment, but in some cases 

gas compression equipment is required to reduce backpressure and increase flow rates. 

In most cases, raw gas streams must be treated prior to introduction into the pipeline 

system. Heavy liquids such as butane are removed near the well site as lease condensate. 

Gas may also contain non-hydrocarbons such as carbon dioxide (CO2), hydrogen sulfide 

(H2S), or nitrogen. Nitrogen and CO2 are inert gases and have the undesirable effect of 

reducing the heating content of the gas. These non-hydrocarbons are removed if they are 

present in sufficient concentrations to degrade the quality of natural gas being processed. 

Natural gas is gathered and sent to processing plants for removal of these constituents. Gas 

processing plants include combustion units (internal combustion (IC) engines and turbines) 

and chemical process units that produce nitrogen oxides (NOx), volatile organic compounds 

 

1

 U.S. Department of Energy (DOE), Enhanced Oil Recovery (EOR) Research Program. 

U.S. Environmental Protection Agency September 2008 A- 6 
APPENDICES 

(VOCs), and particulates. Storage facilities for oil and other liquid hydrocarbons may also 

release fugitive VOC and methane (CH4) emissions. 

Region 8 is an arid region, typically subject to drought. CBM gas production produces 

large volumes of water from the coal bed formation that must generally be pumped out, 

treated, reused, and/or disposed of in some manner. Disposal of produced water is one of 

the other major visible impacts of gas production in Region 8. Water disposal may 

consist of surface discharge with or without treatment, or injection into a porous 

formation via injection well. Salts are among the most common produced water 

impurities, and the high sodium content of the brine presents environmental management 

challenges. Such water quality characteristics determine whether the water can be 

discharged into local rivers and streams, used for irrigation, or must be treated or 

specially disposed of. 

In addition, treatment can include evaporation ponds or processing that reduces the 

salinity of produced water prior to further disposition. For example, with surface 

discharges throughout the Powder River Basin of northeastern Wyoming, operators and 

permitting authorities alike need to ensure recipient streams and rivers are able to 

accommodate variable chemical characteristics and concentrations of produced waters. 

These issues are complex, and considerations include assessing the volume of water 

being produced, the flow rate of streams (i.e., ephemeral or perennial), and the 

compositional characteristics of the water. In some cases, the key environmental issue is 

simply the large volume of produced water that must be effectively managed to prevent 

runoff or erosion problems. 

Generally, tight gas and shale gas development are not challenged by significant water 

volumes and production that originate in the subsurface (as is generally the norm with 

CBM gas production); however, water used in hydraulic fracturing processes must be 

provided for (often transported in and out of production sites by truck) and subsequently 

treated, recycled, or disposed of. Such process water is typically in much smaller 

quantities than produced water from conventional oil and gas formations or natural gas 

production from CBM wells. 

A.1.3 Oil Production and Processing 

Crude oil either flows to the wellhead under natural reservoir pressure or is pumped to 

the surface with a pumping unit. At the surface, production activities yield variable 

quantities of crude oil as well as associated natural gas and formation water. The water is 

generally saline and may also contain hydrocarbons. Oil and gas are separated near the 

wellhead by separator units (i.e., horizontal or vertical cylindrical vessels with baffles 

that provide filtration). The associated gas may be further processed following separation 

to remove liquids and moved offsite by gas pipeline, or some or all of the gas may be 

used on location to power production equipment. In addition, associated gas may be reinjected into the formation to maintain reservoir pressure.2

 

 

2

 Note: Prudhoe Bay, Alaska, production operations often employ these approaches to maintain reservoir pressure and 

augment hydrocarbon flow rates. 

U.S. Environmental Protection Agency September 2008 A- 7 
APPENDICES 

Produced water from formations yielding crude oil is generally corrosive and therefore 

removed prior to product transportation and storage. Water is drained at gathering 

stations and at oil storage tanks in the field area. Prior to pipeline transport, a glycol 

dehydration unit is used to remove the remaining water from the oil. After on-site 

processing, crude oil may be temporarily stored in tanks near the field or transported to a 

bulk storage terminal within the area. The oil is then transported to a refinery by pipeline 

or in some cases by trucking if a suitable pipeline is not available. 

A.2 Regional Oil and Gas Production Trends 

Oil and gas production has historically been concentrated in a few regions of the United 

States based on the location of the geological resource. The Appalachian region was the 

first oil and gas producing area in the country. Other early producing areas included the 

Michigan-Illinois Basin and the Mid-Continent. For many years the predominant 

producing regions have been the Texas-Louisiana region (including the San Juan and 

Permian Basins) and the Gulf of Mexico. However, recent years have seen substantial 

growth in the Rocky Mountains (Figure A-5). 

Figure A-5. Rocky Mountain States Oil and Gas Producing Regions 

Region 8 comprises much of what is generally called the Rocky Mountain oil and gas 

province. Some of the Rocky Mountain region resides outside Region 8, primarily the 

San Juan Basin in northwestern New Mexico. Region 8 also includes Montana and the 

Dakotas. Most of Montana has geological characteristics of the Rocky Mountain oil and 

gas province, but eastern Montana and North Dakota are part of a separate geological 

province called the Williston Basin. 

U.S. Environmental Protection Agency September 2008 A- 8 
APPENDICES 

Presently, oil and gas production is underway in Colorado, Utah, and Wyoming, as well 

as Montana, North Dakota, and South Dakota. However, Region 8 is dominated by 

natural gas production, and oil production is secondary at the moment. The Rocky 

Mountain region is a major gas producing province and is forecast to be even more 

important for future domestic gas production through 2030 and beyond. Conventional oil 

production has actually been in decline, and oil production is concentrated in the Denver 

Basin of eastern Colorado, the Uinta Basin of northeastern Utah, and the Bakken shale 

field of Montana and South Dakota. 

Given the commercial potential of shale oil in the region, oil production has vast energy 

supply implications for the future. Large oil shale deposits are present in western 

Colorado, northeastern Utah, and southwestern Wyoming, and may be developed in 

coming decades. The oil shale deposits were the focus of a previous industry technology 

development and pilot project in the 1970s and 1980s, but for various technical and other 

reasons, commercial production never materialized. 

The Rocky Mountain region has geological characteristics that make it very different 

from other oil and gas producing regions, such as the Gulf Coast. The Gulf Coast and 

Gulf of Mexico generally produce oil and gas from conventional high-porosity, highpermeability oil and gas reservoirs. High porosity and permeability mean that the oil and 

gas in the formation can easily flow into the production well. Conventional reservoirs are 

generally defined as high-porosity formations that contain well-defined contacts between 

oil, gas, and water and can be produced using standard methods. In contrast, current 

activity in Region 8 is focused on unconventional natural gas formations, and extracting 

these resources has significant water use implications. To extract the resource from tight 

gas or shale gas formations successfully, fractures are opened with pressurized water, 

requiring water use (which must be recycled, reused, and/or disposed of) as well as 

greater surface disturbance from heavy trucks and other specialized equipment. As 

fracturing only releases gas within a certain distance of the drill bore, multiple horizontal 

bores must be drilled into the formation. Although improvements in drilling technology 

mean that multiple bores can be drilled from a single well site, unconventional resource 

extraction is generally associated with a higher number of well sites per acre than 

conventional extraction. However, as tight gas and shale gas formations do not contain 

large volumes of water, product extraction from these formations does not create 

significant produced water issues. 

Table A-3 shows oil and gas production in Region 8; note that numbers may not add due to 

rounding. In 2002, the region produced nearly 3.3 trillion cubic feet (Tcf) of natural gas and 

137 million barrels of oil, compared to total U.S. production of almost 19 Tcf of gas and 2 

billion barrels (Bbls) of oil. Most natural gas production occurred in Wyoming and 

Colorado, as these two states represent 86 percent of total gas produced in the region in 

2002. Wyoming produced slightly more than Colorado during this year. Gas production in 

Wyoming and Colorado is increasing rapidly, and these states are expected to be the 

location of most future growth in gas production in the United States. Oil production is 

dominated by Wyoming and North Dakota. Wyoming accounts for approximately onethird of the total oil production in the region, while North Dakota is next in line at about 19 

percent. South Dakota produced the least amount of gas and oil among Region 8 states. 

U.S. Environmental Protection Agency September 2008 A- 9 
APPENDICES 

Table A-3. Total Oil and Gas Production in Region 8, 2002 

State Gas 

(million cf) 

Oil 

(1,000 Bbls) 

WY 1,776,311 54,872 

CO 1,045,365 18,696 

UT 292,752 13,767 

MT 86,304 16,860 

ND 57,783 29,670 

SD 32,072 3,061 

Region 8 Total 3,290,588 136,928 

U.S. Total 18,927,788 2,097,124 

Figures A-6 and A-7 illustrate regional gas and oil production trends in the lower 48 states 

from 1998 to 2005. In recent years, natural gas production has grown by approximately 50 

percent in the Rocky Mountain region, while it has been flat or declining in most other 

regions. Oil production in the Rocky Mountain region is small compared with other regions 

and shows no significant growth trend. 

Figure A-6. Total Dry Gas Production in the Lower 48 by Region, 1998—2005 

0

1

2

3

4

5

6

1998 1999 2000 2001 2002 2003 2004 2005 2006

Tcf per Year

California/ Other

East/ Midwest

Gulf Coast

Gulf of Mexico

MidContinent

San Juan/ Permian

Rockies

U.S. Environmental Protection Agency September 2008 A- 10 
APPENDICES 

Figure A-7. Total Crude Oil Production in the Lower 48 by Region, 1998—2005 

0

100

200

300

400

500

600

700

800

900

1998 1999 2000 2001 2002 2003 2004 2005 2006

Million Barrels per Year

East/ Midwest

California/ Other

San Juan/ Permian

MidContinent

Rockies

Gulf of Mexico

Gulf Coast

Undeveloped natural gas resources in the Rockies are found primarily in tight gas sands. 

These sands are widely distributed as basin center deposits, and accumulations are found 

in areas such as the Green River Basin of southwestern Wyoming and the Piceance Basin 

of northwestern Colorado. They are characterized by enormous amounts of in-place gas 

resources distributed across a depth of thousands of feet and present throughout the 

central portion of major basins. It is this gas that is now being drilled and will be the 

focus of future production. Recoverable resources in Rocky Mountain tight sands have 

been assessed to be in the hundreds of Tcf of gas, compared to current proved reserves of 

about 190 Tcf for the United States as a whole. The magnitude of the resource means that 

the current expansion in extraction activities is likely to continue for decades. 

The Rocky Mountain region is also the location of two of the most prolific CBM basins 

in the world: the San Juan Basin in southwestern Colorado and northwestern New 

Mexico, and the Powder River Basin in eastern Wyoming. The San Juan Basin produces 

from the Fruitland coal formation. This formation was the initial major area of CBM 

production in the Rockies and is characterized by large volumes of water that are 

produced with the gas (produced water), most or all of which is typically re-injected for 

disposal. The Powder River Basin gained prominence for CBM production in the 1980s 

and produces about 1 billion cubic feet (Bcf) per day. This basin produces from younger, 

shallower coal beds than those in the San Juan Basin. To date, almost all of the produced 

water has been surface discharged, rather than injected, which can impact surface water 

U.S. Environmental Protection Agency September 2008 A- 11 
APPENDICES 

quality and contribute to streambed erosion.3 Efforts to develop significant CBM 

elsewhere in the Rockies, including central Utah and southwestern Wyoming, have had 

variable success. 

In a recent accounting, there were approximately 17,000 producing coal bed wells in the 

Powder River Basin and about 150 in southwestern Wyoming. Powder River Basin coal 

beds are shallower than in other areas, necessitating drilling a large number of vertical 

wells across a large area. As mentioned previously, the number of wells needed to 

develop CBM is a function of depth, water characteristics, number of seams, and other 

factors. 

Natural gas resource development in the region has been the focus of an environmental 

debate, because in order to develop the reserves, thousands of new gas wells must be 

drilled in areas that have not seen much drilling activity. Much of the land is administered 

by the U.S. Bureau of Land Management (BLM) and is subject to federal control. This 

has created conflicts between energy development interests and environmentalists over 

resource access, water rights, wildlife, and other issues. The growing population of the 

region has also been a factor, and oil and gas development has become a focus of debate. 

A.2.1 Recent Trends in Rocky Mountain Oil and Gas Production 

Figures A-8 through A-9 and Table A-4 summarize recent trends in Rocky Mountain oil 

and gas industry activity and compare regional activity with total activity across the 

United States; note that numbers in Table A-4 may not add due to rounding. These 

figures and data show trends in total oil and gas production from 2000 to 2005 for new 

oil and gas well completions, as well as the total number of producing oil and gas wells in 

2006. These data highlight the region’s rapid growth in extraction activity, particularly 

for natural gas. 

Figure A-8 shows that the Rockies represented about 17 percent of total U.S. gas 

production in 2005, up from 11 percent in 2000. Almost all of the production increase has 

been in Colorado and Wyoming, where it is primarily due to development of tight gas 

and CBM. The Rockies represent only about 6 percent of total U.S. oil production, and 

this fraction has not changed significantly in recent years. However, this percentage could 

increase in coming years with the increased use of enhanced oil recovery. 

 

3

 Not all CBM is associated with large amounts of co-produced water. In Alberta, for example, a coal bed formation that 

does not produce significant water with the gas is being extensively developed. 

U.S. Environmental Protection Agency September 2008 A- 12 
APPENDICES 

Figure A-8. Comparison of U.S. and Rockies Gas Production, 2000—2005 

0

5

10

15

20

25

2000 2001 2002 2003 2004 2005

Tcf per Year

U.S.

Rockies

Figure A-9 shows that there were approximately 7,900 gas wells completed in the 

Rockies in 2005, representing 29 percent of total U.S. completions. In recent years this 

percentage has declined, from 38 percent in 2000. However, this is somewhat of a 

statistical aberration caused by the dominance of CBM drilling in Wyoming’s Powder 

River Basin, which has declined slightly since peaking several years ago. The growth in 

Rockies activity would be more apparent if viewed over a longer period. 

In terms of new oil wells, the Rockies represent about 13 percent of national activity. 

This fraction has increased from 5 percent in 2000 due to increased activity, e.g., in 

Colorado’s Denver Basin and the Uinta Basin of Utah. 

Figure A-9. Comparison of U.S. and Rockies Gas Well Completion, 2000—2005 

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

2000 2001 2002 2003 2004 2005

Number of Wells

U.S.

Rockies

U.S. Environmental Protection Agency September 2008 A- 13 
APPENDICES 

Table A-4. Oil and Gas Production and Drilling Activity in the Rockies 

Rockies and U.S. Dry Gas Production

Billion Cubic Feet per Year Rockies

Rockies U.S. Percent

CO UT WY MT Total Total of U.S.

2000 759 226 1,070 67 2,122 19,219 11%

2001 882 288 1,286 73 2,529 19,779 13%

2002 964 286 1,388 77 2,715 19,353 14%

2003 1,142 278 1,456 86 2,962 19,425 15%

2004 1,050 282 1,524 95 2,951 19,168 15%

2005 1,104 308 1,642 100 3,154 18,458 17%

Rockies and U.S. Crude Oil Production

Million Barrels per Year Rockies

Rockies U.S. Percent

CO UT WY MT Total Total of U.S.

2000 17 14 54 15 100 1,880 5%

2001 16 13 48 16 93 1,915 5%

2002 17 12 46 18 93 1,875 5%

2003 16 12 42 19 89 1,877 5%

2004 18 13 43 22 96 1,819 5%

2005 19 15 45 30 109 1,733 6%

Rockies and U.S. Annual Completed Gas Wells

Rockies

Rockies U.S. Percent

CO UT WY MT Total Total of U.S.

2000 920 365 4,888 384 6,557 17,126 38%

2001 1,344 484 5,249 318 7,395 21,202 35%

2002 1,270 351 2,942 296 4,859 15,970 30%

2003 1,490 274 2,679 508 4,951 19,482 25%

2004 1,736 301 3,617 435 6,089 23,193 26%

2005 2,496 438 4,356 578 7,868 27,562 29%

Rockies and U.S. Annual Completed Oil Wells

Rockies

Rockies U.S. Percent

CO UT WY MT Total Total of U.S.

2000 73 84 145 75 377 8,209 5%

2001 34 106 127 163 430 8,934 5%

2002 21 40 90 144 295 6,929 4%

2003 36 117 154 225 532 8,135 7%

2004 312 299 413 287 1,311 11,170 12%

2005 406 355 518 361 1,640 12,734 13%

2006 Producing Oil and Gas Wells

Rockies

Rockies U.S. Percent

CO UT WY MT Total Total of U.S.

Gas 19,993 5,012 25,052 4,078 54,135 413,174 13%

Oil 7,567 2,401 10,205 5,862 26,035 500,785 5%

Total 27,560 7,413 35,257 9,940 80,170 913,959 9%

U.S. Environmental Protection Agency September 2008 A- 14 
APPENDICES 

In 2006, the Rockies had a total of 54,100 producing gas wells and 26,000 producing oil 

wells, shown in Figure A-10. This represents 13 percent and 5 percent of the U.S. totals, 

respectively. 

Figure A-10. Total U.S. and Rockies Oil and Gas Producing Wells, 2006 

0

100

200

300

400

500

600

Gas Oil

Thousands

U.S.

Rockies

In 2002, a total of almost 22 million feet of wells was drilled in Region 8. Table A-5 

shows total footage of wells drilled by state; note that numbers may not add due to 

rounding. Wyoming reported the largest drilling footage at 8.5 million feet, followed by 

Colorado, with slightly over 7 million feet. 

In 2002, there were over 72,000 gas and oil wells in 

Region 8. Table A-6 presents data on the total number of 

wells and the average well depth by state; note that 

numbers may not add due to rounding. The number of 

wells is an indicator of the drilling activity and related 

emissions. Deeper wells require longer drilling times 

and produce more drilling waste. Wyoming has the 

greatest number of wells, followed by Colorado. South 

Dakota reports the fewest number of wells. On average, 

the deepest wells are in North Dakota, while Montana 

has the shallowest wells. Overall, the region has an 

average well depth of 5,848 feet. 

Table A-5. Footage Drilled by 

State in Region 8, 2002 

State Feet 

WY 8,531,181 

CO 7,055,372 

UT 2,698,645 

MT 1,803,418 

ND 1,413,658 

SD 36,360 

Total 21,538,634 

U.S. Environmental Protection Agency September 2008 A- 15 
APPENDICES 

In Region 8, the majority of wells are gas wells. As 

shown in Table A-7, over 28,400 wells are gas-only 

wells, accounting for almost 40 percent of total 

wells in the region; note that numbers may not add 

due to rounding. Wyoming accounts for the majority 

of gas-only wells. Table A-7 also presents the 

number of wells producing both oil and gas. The 

“Oil With Gas Wells” data refer to wells that 

produce more oil than gas using a predefined ratio 

between oil and gas production. The “Gas With Oil 

Wells” data refer to wells producing more gas than 

oil, using the same predefined ratio.4

 In 2002, there 

were 15,693 oil with gas wells, and 15,762 gas with oil wells. The remaining wells in the 

region are oil-only wells, totaling 12,183. 

Table A-6. Well Data by State for 

Region 8, 2002 

Table A-7. Well Data by Type and State for Region 8, 2002 

State Total # 

of Wells 

Oil-Only 

Wells 

Gas-Only 

Wells 

Oil With 

Gas Wells 

Gas With 

Oil Wells 

WY 31,600 6,276 13,731 5,225 6,368 

CO 22,342 1,763 8,135 4,788 7,656 

MT 8,707 2,694 4,633 1,355 25 

UT 5,572 467 1,784 1,809 1,512 

ND 3,591 914 77 2,452 148 

SD 248 69 62 64 53 

Total 72,060 12,183 28,422 15,693 15,762 

Region 8 also has a substantial number of CBM wells. These are gas-only wells and are, 

therefore, a subset of the gas-only wells presented above. Table A-8 presents the number 

of CBM wells in Region 8 by state; note 

that numbers may not add due to rounding. 

CBM wells can be found in all Region 8 

states except for North Dakota and South 

Dakota. Nevertheless, most CBM wells are 

currently found in Wyoming, representing 

71 percent of total CBM wells in Region 8. 

In addition, 57 percent of the gas-only 

wells in the region are CBM wells. In 

Wyoming, the percentage is much higher, 

85 percent. 

Table A-9 presents 2004 data on natural gas processing plants in Region 8 (2002 data are 

not available); note that numbers may not add due to rounding. According to these data, 

Wyoming represents more than half of total natural gas processing capacity in the region, 

 

4

 For this study, the predefined ratio is 12.5 gas/oil (Mcf/Bbls). If a well has a ratio less than 12.5, it is classified as “oil with 

gas well.” Otherwise, it is a “gas with oil well.” 

State Total # Average Well 

of Wells Depth (ft) 

WY 31,600 6,020 

CO 22,342 5,856 

MT 8,707 3,420 

UT 5,572 6,558 

ND 3,591 9,013 

SD 248 6,660 

Total 72,060 5,848 

Table A-8. CBM Wells 

by State for Region 8, 2002 

State Gas-Only 

Wells 

# of CBM 

Wells 

Percent 

CBM 

WY 13,731 11,628 85% 

CO 8,135 3,680 45% 

MT 4,633 236 5% 

UT 1,784 758 42% 

ND 77 0 0% 

SD 62 0 0% 

Total 28,422 16,302 57% 

U.S. Environmental Protection Agency September 2008 A- 16 
APPENDICES 

although it has fewer than half the 

number of plants. Colorado represents 

the second largest capacity and number 

of plants. These results are consistent 

with the production results identifying 

Colorado and Wyoming as having the 

largest volume of gas production in 

Region 8. 

Table A-9. Total Number and Capacity of 

Natural Gas Processing Plants in Region 8, 

2004 

State Capacity 

(Mcf) 

Number of 

Plants 

WY 6,920 45 

CO 2,093 43 

UT 970 16 

ND 222 8 

MT 133 3 

SD 0 0 

Total 10,338 115 

U.S. Environmental Protection Agency September 2008 A- 17 
APPENDICES 

This Page is Intentionally Left Blank.

U.S. Environmental Protection Agency September 2008 A- 18 
APPENDICES 

Appendix B: Pollution Sources in the Oil and Gas 

Industry 

The analysis of emissions from oil and gas exploration and production begins with an 

inventory and characterization of the sources of these emissions by medium and type. 

This report addresses several categories of emissions from oil and gas production 

activities. Air emissions include: 

• Criteria air pollutants: These are pollutants that are regulated by National Ambient 

Air Quality Standards (NAAQS), including ground level ozone (the primary 

component of smog), carbon monoxide (CO), sulfur dioxide (SO2), and particulate 

matter (PM). Ozone is not a direct emission but is formed in the atmosphere from 

nitrogen oxide (NOx) and volatile organic compounds (VOCs). NOx and VOCs are, 

therefore, regulated as precursors to ozone. VOCs are either hydrocarbon fugitive 

emissions or products of fossil fuel combustion. Most of the other emissions are the 

result of fossil fuel combustion in engines, turbines, and process heaters. 

• Hazardous air pollutants (HAPs): These primarily include fugitive VOC emissions 

that are classified as HAPs. 

• Haze precursors: Visibility and regional haze are important factors in the Rocky 

Mountains. Regulators, environmental groups, and other affected stakeholders are 

very concerned about pollutants that reduce visibility, including NOx, SO2, and 

particulates. 

• Greenhouse gases (GHGs): These are gases, including CO2 and methane (CH4), 

have climatic warming effects. CO2 includes CO2 from combustion of fossil fuels and 

CO2 that is removed from raw natural gas and vented. CH4 emissions are primarily 

fugitive emissions from gas system operations. CH4 has a global warming potential 

(GWP) 21 times higher than CO2. There is increasing interest in measuring GHG 

emissions and their impacts in the western states. Arizona, California, Montana, New 

Mexico, Oregon, Utah, and Washington and have formed the Western Climate 

Initiative (WCI) to establish and meet GHG reduction targets. Colorado is 

establishing its own targets, and other states may follow suit. In addition, legislative 

proposals have been introduced in Congress to regulate GHG emissions in the future. 

EPA issued an advance notice of proposed rulemaking (ANPRM) in July 2008 

considering possible GHG emission regulation under the Clean Air Act. 

The non-air emissions include produced water and drilling waste. Produced water is one 

of the most significant environmental issues associated with gas production in Region 8. 

B.1 Sources of Air Emissions 

After researching and evaluating various information sources, the EPA Sector Strategies 

Program decided to feature the WRAP air emissions data. As such, it is important to note 

that WRAP defines air emissions sources in a slightly different way than CAA programs 

do. In WRAP terminology, a point source is “a specific source of air pollution” and an 

U.S. Environmental Protection Agency Working Draft – September 2008 B-1 
APPENDICES 

area source is “many small sources of air pollution in which the contribution of each 

source is relatively small, but combined may be a significant source of air pollution.” The 

CAA categorizes stationary sources as “major” or “minor” for pollutants, based on the 

potential or permitted air emissions, and it defines “area source” as a stationary source of 

air pollution that is not major. WRAP’s categorization of point sources most closely 

correlates to major sources of air pollution, but could potentially include minor sources as 

well. Note that WRAP’s categorization of area sources also includes certain mobile 

sources that effectively function as stationary sources, such as drilling rigs. 

The sources of air emissions associated with oil and gas production in Region 8 can be 

categorized into four categories based on function and size of source. For purposes of 

data categorization in this report, point sources are large stationary sources that can be 

separately measured and tracked. Area sources include smaller stationary sources, such as 

small compressors, and certain mobile sources, such as drill rigs and frac units, which are 

tracked as a group rather than individually. The major point source categories include: 

• Large compressor stations (at least 100 million standard cubic feet per day 

(MMscfd) of gas: Used to move natural gas through pipelines. Usually connected to 

interstate gas transmission lines, although they could also be linked with collection 

systems that bring gas from the wells and processing sites to the main transmission 

lines. These stations have very large compressors powered by reciprocating engines 

or combustion turbines that burn gas from the pipeline. 

• Large gas processing plants: Responsible for a variety of processes involved in 

removing liquids, impurities, and inert gases from natural gas, including fractionation, 

sweetening, treatment, dehydration, and compression. Emissions sources include 

internal combustion engines (ICEs) and process heaters. 

• Standalone production sites: Intermediate-sized natural gas processing plants that 

are similarly responsible for a variety of processes involved in removing liquids, 

impurities, and inert gases from natural gas, including fractionation, sweetening, 

treatment, dehydration, and compression. 

• Wellhead sites and small compressor stations: The smallest of the source 

categories, most of the small compressor stations process between 10 and 100 

MMscfd of natural gas. These sites are usually operated to pressurize the natural gas 

so it can be transported in a sale pipeline connected to a large compressor station. 

Wellhead sites include a wellhead and in some sites, a test separator to estimate the 

ratio of oil, water, and natural gas in the production stream. These sites are linked to a 

common production header and are routed to an intermediate site or a commingling 

facility to handle the fluid from multiple well sites more efficiently. 

The first two source categories listed above are usually considered point sources, and the 

other two categories are usually included in the area sources. Across these four source 

categories, three basic equipment categories contribute to air emissions: 

• Internal combustion equipment: Primarily natural gas-fired engines and 

combustion turbines used in compressors, generators, and pumping units, or dieselU.S. Environmental Protection Agency Working Draft – September 2008 B-2 
APPENDICES 

fired engines that power generators, trucks, or mobile equipment such as drilling rigs 

or frac units. Emissions include NOx, PM10, PM2.5, VOCs, SOx, and CO. 

• External combustion equipment: Covers a variety of equipment such as boilers, 

heaters, glycol and amine regenerators, separators, sulfur recovery units, and 

combustion flares. Emissions include NOx, PM10, PM2.5, VOCs, SOx, and CO. 

• Storage and separation vessels: Includes a variety of equipment such as separators, 

storage tanks, pressure and level controllers, glycol dehydrator flash tanks, glycol 

dehydrator still columns, gas-operated and chemical injection pumps, and oil/water 

skimmers. These units are a primary source of fugitive VOC emissions, which leak 

out of tanks, pipes, valves, and fittings or evaporate from exposed liquid surfaces. 

Wells, gathering pipelines, dehydrators, and separators generate the majority of 

methane emissions, followed by transmission and storage. 

B-1 identifies the emission sources and pollutants covered in this sector. Table B-2 

summarizes the typical range of air pollution sources in the exploration and production 

sector along with the source classification codes (SCCs) used to categorize the sources 

and typical emission factors and control efficiency data; this list was compiled by the 

Michigan Department of Environmental Quality. The emission factors come from EPA’s 

AP-42 listing of emission factors and other standard data sources. While these sources do 

not provide emission rates for specific facilities, they are typical values that provide a 

good first estimate of standard emissions factors and control efficiencies. 

U.S. Environmental Protection Agency Working Draft – September 2008 B-3 
APPENDICES 

Table B-1. Emission Sources and Pollutants for Oil and Gas Production 

Source 

Category 

Pollutant Emission Unit Large 

Compressor 

Stations 

Natural Gas 

Processing 

Plants 

Stand-alone 

Production 

Sites 

Small 

Compressor 

Stations & 

Wellheads 

Natural gas-fired 

engines 

Internal RR R R

Combustion 

Diesel-fired 

engines 

R R R R

Line heaters R R R

Separators R R

Heat treaters R

Glycol 

regenerators 

R R R R

External 

Combustion 

NOx, 

PM10, 

PM2.5, 

VOCs, 

SOx, CO 

Amine 

regenerators 

R R

Sulfur recovery 

units 

R

Combustion flares R R R

Fugitives R R R R

Separators R R R

Glycol dehydrator 

flash tanks 

R R R R

Glycol dehydrator 

regenerator still 

columns 

R R R R

Storage tanks R R R

Pressure and level 

controllers 

R R R

Gas operated 

pumps & chemical 

injection (CI) 

pumps 

R R R

Storage and 

Separation 

Vessels 

VOCs 

Oil/water skimmers R

U.S. Environmental Protection Agency Working Draft – September 2008 B-4 
APPENDICES 

Table B-2. Air Emissions Sources for the Oil and Gas Production Industry 

SCC Description Pollutant Emission Factor Control Efficiency 

Natural Gas Engines 

2-02-002-53 Standard “rich burn” engines 

May include: 

Natural gas process heaters 

Natural gas production 

compressors 

Natural gas production 

flares—excluding SO2

CO 

NOx

PM10

PM2.5

SO2

VOC 

3.794E3 lb/mmcf 

2.254E3 lb/mmcf 

9.69E0 lb/mmcf 

9.69E0 lb/mmcf 

6.00E-1 lb/mmcf 

3.02E1 lb/mmcf 

3-way catalyst 

CO – 80% 

NOx – 90% 

VOCs – 50% 

2-02-002-54 Lean burn engines 

May include: 

Natural gas process heaters 

Natural gas production 

compressors 

Natural gas production 

flares—excluding SO2

CO 

NOx

PM10

PM2.5

SO2

VOC 

5.68E2 lb/mmcf 

4.162E3 lb/mmcf 

7.90E-2 lb/mmcf 

7.90E-2 lb/mmcf 

6.00E-1 lb/mmcf 

1.204E2 lb/mmcf 

Oxidation catalyst 

CO – 80% 

VOCs – 50% 

Process Heaters (excluding engines noted above) 

3-10-004-04 Process heaters CO 

NOx

PM10

SOx

VOC 

3.50E1 lb/mmcf 

1.40E2 lb/mmcf 

3.00E0 lb/mmcf 

6.00E-1 lb/mmcf 

2.80E0 lb/mmcf 

Tank Storage 

4-04-003-01 Fixed roof tank—breathing 

loss 

VOC 3.6E1 lb/kgal-yrcrude oil (storage 

capacity) 

Vapor recovery 

system – 95% 

Flare – 95% 

4-04-003-02 Fixed roof tank—working loss VOC 1.1E0 lb/E3 gal 

crude oil 

(throughput) 

Vapor recovery 

system – 95% 

Flare – 95% 

Truck Loading 

4-06-001-32 Truck loading VOC 2.0E0 lb/E3 gal 

crude oil 

Vapor recovery 

system – 95% 

Gas Dehydrators 

3-10-003-21 Glycol dehydrator—Niagaran VOC 9.24E4 lb/yr-GPM 

Glycol 

Tube and shell 

condenser with flash 

tank – 90% 

Vapor recovery 

system – 95% 

Flare – 95% 

3-10-003-22 Glycol dehydrator—Prairie du 

Chien 

VOC 1.94E4 lb/yr-GPM 

Glycol 

Tube and shell 

condenser with flash 

tank – 90% 

Vapor recovery 

system – 95% 

Flare – 95% 

3-10-003-23 Glycol dehydrator—Antrim VOC 9.2E1 lb/yr-GPM 

Glycol 

Vapor recovery 

system – 95% 

Flare – 95% 

Amine Plant 

3-06-009-06 Amine plant SO2 3.76E3 lb/ton 

hydrogen sulfide 

Fugitive Emissions (excludes fugitive emissions from crude oil sumps) 

3-10-888-01 Fugitive emissions—light 

crude oil 

VOC 1.44E1 lb/each-yr 

valve 

3-10-888-02 Fugitive emissions—gas 

production 

VOC 3.60E0 lb/each-yr 

valve 

3-10-888-03 Fugitive emissions—gas 

plant 

VOC 2.74E1 lb/each-yr 

valve 

U.S. Environmental Protection Agency Working Draft – September 2008 B-5 
APPENDICES 

In addition to the relatively permanent emission sources described in this section, 

emissions are also associated with drilling and well stimulation. These emissions are 

primarily from truck-mounted diesel engines used to power drilling equipment and 

hydraulic fracturing equipment used to stimulate gas formations. The equipment is 

typically in one location for days or weeks and would typically be included as part of the 

area source emissions. 

B.2 Sources of Greenhouse Gas Emissions 

The two primary GHGs emitted from oil and gas exploration and production (E&P) are 

CO2 from fossil fuel combustion and CH4 from leaks, venting, and fugitive emissions. As 

previously noted, methane has greater global warming effect (or GWP) than CO2—the 

GWP for CH4 is 21 times that of CO2. The emissions data for methane in this report are 

for the actual tons of methane reported and should be multiplied by 21 to derive the CO2

equivalent emissions. 

B.3 Sources of Non-Air Pollution 

There are three basic types of non-air pollution associated with oil and gas extraction: 

• Produced water: Consists of water and treatment chemicals placed into and extracted 

from the formation containing the gas or oil, and accounts for the majority of oil and 

gas production wastes. Produced water is generated naturally from petroleum reservoirs 

or operations using primary and secondary recovery techniques. Chemical 

compositions of produced water can differ substantially between sources and between 

development and production techniques. Produced water is usually stored in tanks for 

surge capacity and to separate oil from water before disposal. Produced water is also a 

result of coal bed methane (CBM) production, and these gas operations are the primary 

source of produced water currently managed in Region 8. Water quality varies in 

producing basins in both CBM and conventional production. 

• Drilling waste: Contains drilling mud, cuttings from the wellbore, and chemicals 

added to improve mud properties, and account for the second largest amount of waste 

resulting from oil and gas production (after produced water). Drilling fluids include 

drill cuttings (rock removed during drilling) and drilling muds (water or oil-based 

fluids with additives that are pumped down the drilling pipe to offset formation 

pressure, provide lubrication, and seal off the wellbore to avoid contamination and 

remove cuttings). This includes synthetic muds and fluids. 

• Other associated wastes: Include oily soil, tank bottoms, workover fluids, produced 

sand, pit and sump waste, pigging waste, iron sponge, dehydration condensate water, 

molecular sieve waste, and oily cuttings. 

– Oily soil: Contamination of soil with oil usually results from equipment leaks and 

spills. 

– Tank bottoms: Consist of heavy hydrocarbons, sand, clay, and mineral scale that 

deposit in the bottom of the oil and gas separators, treating vessels, and crude oil 

stock tanks. 

U.S. Environmental Protection Agency Working Draft – September 2008 B-6 
APPENDICES 

– Workover fluids: Produced from well control, drilling or milling operations, and 

stimulation and/or cleanup of an oil and gas bearing formation. The fluids coming 

from drilling or milling operations as well as control fluids are usually considered 

produced water. Stimulation or cleanup fluids are expected to contain HAPs. The 

waste composition data for workover fluids provided by the American Petroleum 

Institute (API) are mainly based on spent stimulation fluid samples since these 

data yield conservative HAP emissions estimates. 

– Produced sand: Sand and other formation solids can build up in the wellbore in 

both producing and injection wells, and need to be removed. 

– Pit and sump waste: Production pits are used to store production fluids. As in tank 

bottoms, heavy materials settle on the bottom of pits or sumps and must be 

removed. Composition of pit and sump wastes varies between facilities. 

– Pigging waste: Produced when pipelines are cleaned or “pigged.” The waste 

consists of produced water, condensed water, crude oil, and natural gas liquids. It 

may also contain small amounts of solids, such as paraffin, mineral scale, sand, 

and clay. 

U.S. Environmental Protection Agency Working Draft – September 2008 B-7 
APPENDICES 

Appendix C: Data Availability and Sources 

The initial task conducted in this analysis was to identify and assess the sources of 

environmental and industry data that can be used to characterize and estimate the 

environmental impacts associated with the oil and gas production sector. This assessment 

was conducted with a primary focus on Region 8 data availability, but also included a 

broader assessment of general data availability for the oil and gas industry. 

A baseline characterization of the industry’s environmental impacts requires the 

following information: 

• Baseline and benchmarking information for a particular base year, including facility 

data, oil and gas production, well characteristics, geology, and depth; energy use; and 

equipment and process data. 

• Emissions data for specific sources and source categories. Pollutants to be considered 

depend on what data are available. 

• Oil and gas industry outlook information including: 

– Recent reports on long-term trends of industry; and 

– Expected changes in emissions performance in the industry driven by federal, 

state, and local regulations. 

The following sections list and describe the available data sources found in our 

assessment; note that numbers in the tables may not add due to rounding. 

C.1 Industry Baseline Data 

C.1.1 Baseline Well and Production Data 

All states in Region 8 maintain information on wells and gas processing facilities, 

existing and planned (i.e., those applying for permits). State databases of wells are 

maintained by: 

• Colorado Oil and Gas Conservation Commission (wells and facilities related to oil 

and gas production); 

• Montana Oil and Gas Information System; 

• North Dakota Oil and Gas Division; 

• South Dakota Oil and Gas Section; 

• Utah Division of Oil, Gas and Mining; and 

• Wyoming Oil and Gas Conservation Commission (wells and gas plants). 

In addition, the states’ oil and gas database contains information about wells in tribal 

lands. ICF International maintains a comprehensive nationwide database with 

information on every oil and gas well, including historical production and well depth. 

U.S. Environmental Protection Agency September 2008 C-1 
APPENDICES 

The database is currently being updated. Table C-1 shows the current oil and gas well 

count (without updates) for each state in Region 8 for 2006. 

Table C-1. ICF Oil and Gas Well Count by State, 2006 

State # of Oil 

Wells 

# of Gas 

Wells 

Total 

CO 7,567 19,993 27,560 

MT 5,862 4,078 9,940 

ND 3,120 178 3,298 

SD 158 71 229 

UT 2,401 5,012 7,413 

WY 10,205 25,052 35,257 

Total 29,313 54,384 83,697 

The U.S. Energy Information Administration (EIA) within the U.S. Department of 

Energy (DOE) also has oil and gas well data, including information from marginal wells, 

which was developed in connection with the Distribution of Oil and Gas Wells and 

Production Project, undertaken on behalf of DOE’s National Energy Technology 

Laboratory (NETL) with support from U.S.PetroSystem.5

 The objective of this effort was 

to develop a database for analyses assessing the impact of technological development on 

marginal gas wells. Table C-2 shows EIA’s 2004 data on oil and gas wells for the states 

in Region 8, which is generally in line with ICF data. 

In other oil and gas producing regions, state governments and the Minerals Management 

Service within the U.S. Department of the Interior (for federal offshore areas) maintain 

records of oil, gas, and in most cases water production, by “property.” A property is 

either a single gas or oil well, or in the case of oil, often an oil lease containing one or 

more oil wells. These production records are maintained for tax, conservation, and 

environmental purposes. In some instances, these data can be obtained from Web sites 

maintained by the state. Also, data aggregating companies, such as Lasser Inc., gather 

these data and offer them to the public for a fee. The Lasser data can be used to develop 

statistics for oil, gas, and water production for any geographic area of interest. 

Table C-2. EIA Oil and Gas Well Count by State, 2004 

State # of Oil 

Wells 

# of Gas 

Wells 

Total 

CO 4,288 23,208 27,496 

MT 3,765 5,356 9,121 

ND 3,122 428 3,550 

SD 75 129 204 

UT 2,180 3,936 6,116 

WY 10,471 23,370 33,841 

Total 23,901 56,427 80,328 

 

5

 U.S. PetroSystem, formed in spring 2000, is a cooperative multi-agency program established for creation, maintenance, 

and sharing of data used in the study of domestic and worldwide oil and gas resources, reserves, production, production 

capacity, and associated technologies and economics. Agencies support this work not only for the cost effectiveness and 

efficiency gained from pooling their resources, but also for shared knowledge gained from cooperation. At present, U.S. 

PetroSystem member organizations include EIA, NETL, and the U.S. Geological Survey. 

U.S. Environmental Protection Agency September 2008 C-2 
APPENDICES 

For our emissions estimates, we used the Lasser database to obtain well production data. 

Data and information on natural gas processing plants were obtained from EIA, which 

reports state-level data on natural gas processing every year. However, an inventory of 

natural gas processing plants is not reported yearly. Such an inventory was developed in 

2004 and 1995. The 2004 inventory was used to obtain data on natural gas processing 

plant capacity and number of plants. 

C.1.2 Energy Use Data 

Energy use data can be used to calculate emissions related to energy use or fuel 

combustion. ICF maintains a cogeneration database that includes cogeneration oil and gas 

production facilities. Also, the U.S. Census of Mining (of the Census Bureau) reports fuel 

consumption for the oil and gas industry, but only at the national level. 

ICF, as part of its 1998 industrial energy consumption base year work, has estimated total 

energy consumption for the energy mining industry (includes oil and gas production and 

coal mining) for the region equivalent to Region 8. 

C.1.3 Equipment and Process Data 

An inventory of equipment/process equipment, such as petroleum storage tanks, engines, 

boilers and other pressure vessels, and dehydrators, could be helpful in estimating 

emissions from oil and gas production equipment. These state-level data may be available 

in some places, but there is substantial variability in the availability and usefulness of 

such data for this type of analysis. The availability and applicability of such data in 

Region 8 is as follows: 

• Colorado: 

– The Colorado Storage Tank Information System (COSTIS) is the state’s storage 

tank information database. Although one can access the database for a list of 

facilities, only public employees are given complete access to information on the 

tanks. Also, facilities are not identified by type of business/industry, so extraction 

of oil and gas production facilities will be a time-consuming process. 

– The Regional Air Quality Council (RAQC) has developed (with guidance from 

Colorado’s oil and gas industry) emissions factors for VOC emissions from oil 

and gas production storage tanks. The average emissions factors are fairly close to 

the EPA AP-42 emissions factors. 

– RAQC has a list of facilities with VOC emissions reductions information on 

control technologies. 

– RAQC has an Excel file of glycol dehydrators in the northeastern part of the state. 

Emissions levels and control information are included. 

– RAQC has an Excel file of compressors in the northeastern part of the state. 

Emission levels and control information are included. 

U.S. Environmental Protection Agency September 2008 C-3 
APPENDICES 

– RAQC has an Excel file of condensate tanks in the northeastern part of the state. 

Emission levels and control information are included. 

• Montana: The Petroleum Tank Release Compensation Board (PTRCB) database 

tracks releases (leaks) from petroleum tanks in the state. It is not clear whether all 

petroleum tanks are included in the database. 

• North Dakota: Has no database available to the public. 

• South Dakota: Has no database available to the public.

• Utah: 

– Has a boiler and pressure vessel database. 

– The Department of Environmental Quality maintains files of underground storage 

tanks, but it is probably not useful for this type of analysis. 

• Wyoming: 

– Has a downloadable Excel file that contains facilities with storage tanks. The 

database includes critical information such as type of content, size of tank, etc. 

Nevertheless, this facilities/tanks database does not identify the type of 

industry/business for the facility, thus extraction of oil and gas production 

facilities would be a time-consuming process. 

– The Wyoming Department of Environmental Quality (WDEQ) developed 

emissions factors and guidance for calculating volatile organic compound (VOC) 

emissions from storage tanks. 

– WDEQ developed emissions factors and guidance for calculating various 

emissions from oil and gas production activities as part of its permit process. 

C.2 Air Emissions Data 

C.2.1 Criteria Air Emissions and Data Sources Considered 

Several potential sources of air emissions data were considered for use in this analysis. 

National Emissions Inventory 

EPA’s National Emissions Inventory (NEI) is intended to be a comprehensive facility and 

emission unit-specific database covering all criteria air pollutants and hazardous air 

pollutants (HAPs) nationally. In general, NEI is used by states and EPA for air quality 

modeling and planning purposes, and was developed by EPA’s Emission and Inventory 

Analysis Group in Research Triangle Park, North Carolina. The current base year for air 

emissions data is 2002. NEI nominally contains emission measurements and estimates for 

seven criteria pollutants—including those of interest for this project (VOCs, sulfur dioxide 

(SO2), nitrogen oxides (NOx), and particulate matter (PM))—and 187 HAPs. In addition, 

NEI addresses emissions data for all major contributors to air pollution, including point, 

mobile, and nonpoint sources. Emission estimates are available currently for years 1990 

and 1996 through 2002 for criteria pollutants and for years 1999 through 2002 for HAPs. 

U.S. Environmental Protection Agency September 2008 C-4 
APPENDICES 

The point source emissions are represented in NEI for individual processes at an industrial 

facility. NEI is developed using the latest data and best available estimation methods, 

including data from continuous emissions monitors (CEMs), data collected from all 50 

states and many local and tribal air agencies, and emissions estimates from EPA’s latest 

models, such as the MOBILE and NONROAD models. Seasonal and daily records 

submitted by state, local, and tribal agencies are included in NEI, although their emissions 

are excluded from annual emission summary totals. 

Criteria pollutant emissions for NEI are collected under the Consolidated Emissions 

Reporting Rule (CERR) (40 CFR Part 51). Under CERR, states are required to report 

emissions of SO2, VOCs, NOx, carbon monoxide (CO), lead (Pb), PM10, PM2.5, and 

ammonia (NH3). Large sources (Type A) are required to report annually, while the other 

sources (Type B) are required to report every three years. For the 2002 base year, both 

Type A and Type B were required to report. 

An initial processing of the NEI database for oil and gas production facilities in Region 8 

states shows there are only 65 reporting facilities. Table C-3 summarizes these data by 

Standard Industrial Classification (SIC) code. The overall number of sources for these 

states as reported in NEI is small relative to the amount of production underway (and 

facilities operating), as reflected in Appendix A. 

Table C-3. NEI Data on Oil and Gas Production Facilities in Region 8, 2002 

State Crude Petroleum and 

Natural Gas Extraction 

(SIC 1311) 

Natural Gas Liquids 

(SIC 1321) 

Total 

CO 28 6 34 

MT 4 1 5 

ND 0 0 0 

SD 0 0 0 

UT 5 3 8 

WY 13 5 18 

Total 50 15 65 

NEI data are based on a combination of methods, including facility reporting, modeling, 

and estimates. There are generally inconsistencies in how sources of emissions are 

categorized and emissions estimates are calculated. Missing data also call into question the 

overall reliability of the NEI dataset with respect to oil and gas production facilities 

currently operating. Areas where experience with NEI has shown data unreliability include: 

• A substantial number of data values are missing, especially values for emissions unit 

size and description (e.g., NEI yielded only 672 large boilers in the United States, 

which is substantially lower than the approximately 1,500 large boilers known to be 

operational). 

• For a given emissions unit, the Source Classification Code (SCC) used to classify it 

may be different than the unit description. 

U.S. Environmental Protection Agency September 2008 C-5 
APPENDICES 

• In some cases, the unit of measure used to report emissions is inconsistent with the 

reported capacity of the unit. 

• One NEI equipment record may actually reflect data for multiple pieces of 

equipment. 

• Facility address information may be missing, showing only the town or state rather 

than the facility address. 

• Some emission units have multiple subemission units (called process units) that have 

inconsistent values for certain data fields. 

For these reasons, NEI data may not be the most complete or accurate mechanism for 

determining air emissions associated with the oil and gas industry. Analysis of the data 

for Region 8 described in Appendix A suggested that this would be a concern for the 

sector of interest in this study. 

State Air Emissions Data 

Another possible source of information is inventory data from individual states. Some 

states in Region 8 maintain an air emissions inventory, and it is likely that similar 

inventories would be available in other oil and gas producing states. The state 

information sources in Region 8 include: 

• Colorado: The Colorado Department of Public Health and Environment maintains an 

inventory of emissions by county and industry/source and pollutant type (CO, NOx, 

PM10, SO2, VOC, benzene). The latest available data are for 2004. 

• Montana: Montana links to EPA’s inventory data (NEI, AQD) for its state data. 

• North Dakota: The North Dakota Department of Health maintains an emissions 

inventory for the state. The latest available information is for 2005. 

• South Dakota: No emissions inventory could be found. 

• Utah: The statewide inventories of Utah are provided by the Department of 

Environmental Quality. The data are summarized for the following criteria pollutants, 

in tons per year, reporting from point, area, and mobile sources within the state: CO, 

NOx, PM10 and PM2.5, SOx, and VOCs. HAP emissions are reported for each county 

in pounds per year, listed by chemical or chemical class. No data are specified 

directly for the oil and gas industry. The latest available data are for 2005. 

• Wyoming: Wyoming links to EPA’s inventory data (NEI, AQD) for its state data. 

• Native American Tribes: There are only a handful of inventories available for tribal 

areas, and they are specific to one tribe. The Western Regional Air Partnership 

(WRAP) has initiated a data assessment for an air emissions inventory for tribes, and 

associated work is ongoing. 

U.S. Environmental Protection Agency September 2008 C-6 
APPENDICES 

As shown above, some of the states in Region 8 maintain some emission inventories for 

the oil and gas sector, and others do not. There were often insufficient and inconsistent 

data available to rely heavily on these sources for this analysis. 

Toxics Release Inventory 

An additional source of information often used for HAPs and non-air wastes is EPA’s 

Toxics Release Inventory (TRI); however, oil and gas exploration and production 

operations are not required to report to this inventory, and so this data source was not 

used for this report. 

Regional Air Emissions Data 

In oil and gas producing regions, regional governmental partnerships may be a source of 

environmental and industry data. After reviewing the various options available, the primary 

data source used in our assessment of air emissions in Region 8 is provided by WRAP. 

Generally speaking, WRAP is a collaborative effort and voluntary organization of tribal 

governments, state governments, and various federal agencies. Formed in 1997, WRAP 

was organized to succeed and implement the Grand Canyon Visibility Transport 

Commission’s recommendations. WRAP is also implementing regional planning processes 

to improve visibility in all western Class I areas by providing the technical and policy tools 

needed by states and tribes to implement the federal Regional Haze Rule (RHR). Other 

common air quality issues raised by WRAP members may also be addressed. 

The WRAP Emissions Forum oversees development of a comprehensive emissions 

tracking and forecasting system, which can be utilized by WRAP or its member entities. 

It monitors the trends in actual emissions and forecasts the anticipated emissions that will 

result from current regulatory requirements and alternative control strategies. 

As part of its air quality planning work, WRAP has developed criteria emissions data for 

two major categories: point or stationary sources, and area or nonpoint sources. It has 

also developed data for on-road mobile sources; off- or non-road mobile sources; fires; 

windblown dust; and biogenic sources. These data from WRAP’s 2002 inventory were 

determined to be the most accurate and complete source of criteria air emissions data for 

this project, and were, therefore, used for this report. WRAP has extensive documentation 

on how the various emissions were calculated. The approach WRAP used could be 

replicated, if necessary, to estimate emissions for other regions. 

WRAP provided EPA the latest version of its 2002 emissions inventory for all point and 

area sources through database files in December 2007. The air emissions data obtained 

from WRAP included estimates for NOx, SO2, VOCs, CO, particulates, NH3, and 

hydrogen sulfide (H2S). Details on these data sources are provided below. 

U.S. Environmental Protection Agency September 2008 C-7 
APPENDICES 

C.2.2 WRAP Data on Point Sources 

WRAP’s point source database contains a variety of information for each stationary point 

source in the region, including all emission points on site; stack parameters (height, 

diameter, flow, velocity, temperature, type); production rates (design capacity, maximum 

nameplate capacity); actual throughput fuel parameters (heat content, ash content, sulfur 

content); SIC code; North American Industry Classification System (NAICS) code 

(although not available for all records); location (latitude, longitude); and emission 

controls. Though the database is the region’s most comprehensive source for criteria 

emissions data, data for some of the important fields, specifically those pertaining to 

production and throughput, are missing. 

Table C-4 shows the number of oil and gas plants/facilities included in the Point Sources 

Site Report database by state by SIC code. Point sources are the larger stationary 

emissions sources and thus include primarily larger internal combustion engines (ICEs) 

and turbines and processing facilities. Not every well or producing facility will have 

enough emissions to qualify as a point source. The smaller stationary sources are grouped 

together in the area source category. Colorado has by far the greatest number of point 

sources, and most of those are in the natural gas liquid extraction facility category. 

Although Wyoming has high gas production, the sources are defined differently than in 

Colorado, resulting in fewer listed point sources, though the emissions are still captured 

as area sources. 

Also note that no data on tribal land are presented in this report. The tribal land data in 

the WRAP database is not organized or listed by state location.. Examination of a sample 

the tribal land emissions indicated that their contribution was small relative to the 

emissions for Region 8. Due to the small contribution of these sources to the total 

emissions relative to the time that would have been required to evaluate them, they were 

not included in this analysis. 

Table C-4. Number of Oil and Gas Facilities in WRAP by State and SIC Code 

SIC SIC Description CO MT ND UT SD WY Total 

1311 Crude Petroleum and Natural Gas 3,927 149 40 199 0 354 4,669 

1321 Natural Gas Liquids 3,491 18 40 93 0 182 3,824 

1381 Drilling Oil and Gas Wells 0 0 0 0 0 0 0 

1382 Oil and Gas Field Exploration Services 0 0 0 0 0 0 0 

1389 Oil and Gas Field Services, not 

elsewhere classified 

41 0 0 0 0 27 68 

Total 7,459 167 80 292 0 563 8,561 

C.2.3 WRAP Data on Area Sources 

WRAP also has an inventory report on area source emissions from oil and gas production 

for the year 2002. The report, An Emission Inventory of Non-Point Oil and Gas 

Emissions Sources in the Western Region, was published in December 2005. It includes 

U.S. Environmental Protection Agency September 2008 C-8 
APPENDICES 

emissions from tanks, compressors, and engines not included in the point source 

emissions inventory as part of the area source emissions inventory. 

In 2005, WRAP initiated a project to estimate the area source emissions from oil and gas 

field operations for 2002, focusing on NOx and VOC emissions. Beginning in 2006, 

WRAP refined the inventory’s “first cut” emissions numbers with more precise data on 

basin-specific activity. It also examined possible options for controlling the emissions 

that come from individually small but ubiquitous pieces of field production equipment, 

including drill rigs, gas compressors, coal bed methane (CBM) pumps, liquid 

hydrocarbon storage tanks, glycol dehydration units, pneumatic instrument controls, and 

completion flaring and well-venting procedures. The 2006 effort expanded the inventory 

to include SO2 emissions. This effort was completed in fall 2007. The latest data obtained 

from WRAP also included CO emissions in the area source inventory. This latest set of 

data was used for this analysis. 

As the WRAP analysis did not include data for area source emissions beyond the four 

pollutants discussed above (NOx, VOCs, SO2, and CO), other area source emissions, 

including PMs, are not included in this analysis. Also, WRAP did not estimate area 

source emissions data for Native American tribal areas, so such emissions are not 

included in this analysis. Based on available data, the tribal areas are a relatively small 

source of area source emissions, so this is probably not a large omission. 

C.2.4 Hazardous Air Pollutants 

WRAP data do not include HAPs, however, the primary HAPs emissions for this sector 

are fugitive VOCs, which are reported in the WRAP data. Since WRAP does not include 

HAPs data, estimates of HAP emissions were developed using emissions factors provided 

by WDEQ and WRAP area source assumptions. WDEQ has developed factors that relate 

emissions factors for HAPs and VOCs for various emissions sources in the oil and gas 

industry. WRAP has used these factors in its study and analysis for the industry. To be 

consistent with the WRAP point and area source assumptions and the estimates used for 

the other pollutants, the ratio of HAPs over VOC emissions factors, by type of source, 

was applied to the VOC area and point emissions. For point sources, HAP emissions 

were calculated only for glycol dehydrators, which are primary sources of HAPs in the 

industry. Table C-5 shows the HAP and VOC emissions factors from WDEQ that were 

used in the analysis. 

Table C-5. HAPs and VOC Emissions Factors by Source 

Source Units VOCs HAPs 

Gas Well Dehydrators lbs/yr/MMCFD 27,485.6 13,695.6 

Condensate Tanks Uncontrolled lbs/yr/barrel per day 3,271.0 116.0 

Oil Well Tanks lbs/yr/barrel per day 160.00 2.66 

Gas Well Completion—Flaring and Venting tons/well 86.0 3.0 

Condensate Tanks Controlled lbs/yr/barrel per day 65.740 2.320 

Gas Well Pneumatic Devices tons/well 0.200 0.008 

Oil Well Pneumatic Devices tons/well 0.100 0.004 

U.S. Environmental Protection Agency September 2008 C-9 
APPENDICES 

C.2.5 Carbon Dioxide Emissions 

EPA’s report, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990—2005

(April 2007), was considered as a potential data source for CO2 emissions. However, the 

level of detail in the EPA inventory is not sufficient for apportioning emissions to Region 

8 sources as readily as fuel consumption, which can be used to calculate CO2 emissions 

directly. The fuel consumption values for 2002 were taken directly from the 2002 Census 

of Mining, which reports fuel consumption for the following major segments of the oil 

and gas industry by NAICS: 

• NAICS 211111: Crude Petroleum and Natural Gas Extraction; 

• NAICS 211112: Natural Gas Liquid Extraction; 

• NAICS 213111: Drilling Oil and Gas Wells; and 

• NAICS 213112: Support Activities for Oil and Gas Operations. 

There were items in the 2002 Census data that were withheld. In these instances, we made 

best estimates based on available information, including previous Census information and 

data on similar fuels. Also, instead of using the Census estimates on natural gas lease and 

plant (labeled in the Census as “natural gas produced and used in the same plant as fuel” 

and “residue gas produced and used in the same plant as fuel”), we used annual estimates 

from EIA, which we deemed more consistent than the Census estimates. 

The 2002 Census data were only available for the national level, and thus the national 

data needed to be disaggregated by region. To do the regional disaggregation, the number 

of wells was used for the NAICS 211111 and NAICS 213112 segments, drilling footage 

for NAICS 213111, and natural gas processing activity information for the NAICS 

211112 segment. 

To disaggregate CO2 estimates by end use, in general we used WRAP point source 

estimates for SO2 emissions, which are available by SCC. The SCC emissions data are 

provided by fuel type. The SO2 emissions by SCC were used to apportion the CO2

emissions by fuel and SO2 content. CO2 emissions were estimated by fuel by SCC. 

There were instances where the SO2 emissions by SCC information were not available 

(e.g., for NAICS 213111 and NAICS 213112). For these two sub-industries, emissions 

from distillate oil and natural gas were assigned to ICEs. Residual oil was assigned to 

process heat. Emissions from motor gasoline were assigned to off-road transportation. 

While the allocation by process is not as detailed as for the criteria pollutants, it 

provides a general breakdown. 

C.2.6 Methane Emissions 

Methane emissions are significant in the oil and gas industry. EPA’s report, Inventory of 

U.S. Greenhouse Gas Emissions and Sinks: 1990—2005 (April 2007), was used to 

develop the CH4 emissions estimates used in this analysis. The report provides national 

CH4 emissions for various sources in the oil and gas production industry. These national 

emissions by source were then allocated by state, based on appropriate factors for each 

U.S. Environmental Protection Agency September 2008 C-10 
APPENDICES 

process, such as gas production, oil production, pipeline capacity, and gas processing 

quantities. These estimates are all considered area sources. 

C.3 Non-Air Pollution Data 

Other pollution data addressed in this analysis include produced water and drilling waste. 

A database maintained by the industry data aggregation company, Lasser Inc., was used 

to estimate the amount of produced water resulting from oil and gas operations in Region 

8. The database also includes well-count and oil and gas production data, which were 

used for this study. The amount of produced water can be calculated using geological 

data and standard production factors in order to estimate future produced water volumes. 

Another database, called the IHS database, which is another data provider of oil and gas 

production, was used to identify CBM wells. This information was used to help 

disaggregate the well data, including produced water, by well type. 

Well depth data was also estimated from Lasser and IHS information to assist in 

estimating emissions associated with drilling. These databases are based on data reported 

by industry to the states for taxation and royalty purposes and are widely used by industry 

and government to characterize exploration and production activity. 

To estimate drilling waste, we first obtained drilling 

activity information, specifically footage data, from the 

American Petroleum Institute (API). The amount of 

waste was calculated based on the data from API and an 

estimate of the drilling waste factor (barrels of waste per 

foot drilled) also from API. The drilling waste factors 

vary by state and are based on the API report, Overview 

of Exploration and Production Waste Volumes and 

Waste Management Practices in the United States (May 

2000). Table C-6 shows the drilling waste factors used 

for each state. 

Table C-6. Drilling Waste 

Factors by State 

We have not found any real measured data on the other associated wastes. These can be 

estimated based on industry production factors and drilling data. In 2000, EPA released 

the analysis, Associated Waste Report: Crude Oil Tank Bottoms and Oily Debris. The 

information and other data in the report could be used to estimate current associated 

waste levels (crude oil tank bottoms and oily debris). 

C.4 Other Emissions Information Sources 

Other information and data sources that could be useful in similar analyses include: 

• The Houston Advanced Research Center report, VOC Emissions from Oil and 

Condensate Storage Tanks, which provides typical data on these fugitive emissions. 

• Other states (not in Region 8) have guidance on how to calculate VOC emissions 

from oil tanks. 

State Bbls/ft 

CO 0.87 

MT 1.52 

ND 1.05 

SD 1.03 

UT 1.68 

WY 1.27 

U.S. Environmental Protection Agency September 2008 C-11 
APPENDICES 

• The Gas Technology Institute (formerly, Gas Research Institute) has developed 

emission factors for all types of pollutants from glycol dehydrators. The data were 

developed using a variety of sources, including equipment survey data. 

• ICF has developed emission factors for many oil and gas industry operations as part 

of emission inventory work for EPA and private clients. 

The biggest category of missing data is likely to be emissions from short-term or 

intermittent operations, such as drilling and well stimulation. It is not clear how 

significant these are with respect to the overall inventory; however, available emission 

factors can be used to estimate these emissions and determine how important they are. 

C.5 Future Projections 

C.5.1 Industry Outlook 

The following data sources have been found to be potentially useful to project future 

emissions resulting from oil and gas production: 

• States have permit data on pending drilling sites that could be used to do a short-term 

(1—2 year) projection of drilling activity from the base year. 

• Some states (e.g., Colorado) have developed their own projections of long-term 

growth rates. 

• EIA’s Annual Energy Outlook also has projections of natural gas and crude oil 

production by region. 

• ICF could develop projections of future oil and gas production using its Hydrocarbon 

Supply Model (HSM). 

C.5.2 Emissions Projections, 2018 

The primary data source for the criteria air emissions projections is WRAP, which 

developed a detailed forecast of regional air emissions for the year 2018 (see Appendix E 

references). Their projections were based on a projection of the growth of the oil and gas 

industry in the region (as provided in Resource Management Plans (RMPs) of the U.S. 

Bureau of Land Management; where RMPs were not available, EIA regional production 

forecasts were used); changes in applicable regulations; evaluation of the penetration of 

emission control technologies; and assumed retirement of facilities and wells. The 

projections are provided by facility and emissions unit. Documentation of the 

methodology to develop the forecast is provided in several reports: 

• Eastern Research Group, Inc., WRAP Point and Area Source Emissions Projections 

for the 2018 Base Case Inventory, Version 1 (prepared for the Western Governors’ 

Association and WRAP, Stationary Sources Joint Forum), January 25, 2006. 

• Environ International Corporation, Final Report Oil and Gas Emission Inventories 

for the Western States (prepared for the Western Governors’ Association), December 

27, 2005. 

U.S. Environmental Protection Agency September 2008 C-12 
APPENDICES 

• Environ International Corporation, WRAP Oil & Gas: Part 1: 2002/2005 and 2018 

Area Source Emissions Inventory Improvements, May 8, 2007. 

• Environ International Corporation, WRAP Oil & Gas: 2002/2005 and 2018 Area 

Source Controls Evaluation, May 30, 2007. 

WRAP’s assumptions on the growth of the oil and gas industry in Region 8 were based 

on a variety of sources and are provided by county and type of emissions source. The 

data for these growth rates are presented in the Eastern Research Group report noted 

above. Given the detailed analysis embodied in these projections, they were determined 

to be the most credible projections of future criteria emissions for the sector. The two key 

factors are the rate of increased drilling and production and the implementation of new 

emission control regulations for equipment in the sector. While there is continued debate 

about the future growth of drilling in the region, this projection was based on permit data 

from federal regulators there. It also included proposed or expected new control 

requirements for engines and process heaters. 

As noted, WRAP does not provide projections for HAP and CH4 emissions. For this 

study, because of the similarity and relation of emissions sources and factors for VOCs 

and HAPs, the projection trend in VOC emissions was used to estimate HAP emissions, 

similar to the approach taken for current emissions. For methane emissions, the growth 

rates in oil and gas production in the Rocky Mountain region, as estimated by EIA, were 

used to extend the 2002 emissions of methane to 2018. 

For produced water, the projected growth in NOx emissions from drilling rigs by state 

from WRAP was used to extrapolate 2002 produced water levels to 2018. 

U.S. Environmental Protection Agency September 2008 C-13 
APPENDICES 

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APPENDICES 

Appendix D: Air Emissions Sources by Source Category and EqType Table D-1 describes the primary sources of air emissions for each major source category identified in Section B.

stations, natural gas processing plants, stand-alone production sites, and small compressor stations and wellhead 

Table D-1. Sources of Air Emissions by Equipment Type and Source Category 

Internal Combustion Sources External Combustion Sources 

NOx, PM10, PM2.5, VOCs, SOx, CO NOx, PM10, PM2.5, VOCs, SOx, CO 

Major Source Categories 

Natural Gas-Fired Engines Diesel-Fired Engines Line Heaters Separators Heat Treaters 

Large compressor stations 

Compressors, generators Emergency generators not 

used under normal service 

Maintain temperature of gas to reduce formation of natural gas hydrates in transmission lines 

No No 

Natural gas processing plants 

Compressors (primarily reciprocating engines), generators, pumping units 

Emergency generators not used under normal service 

No If no source can accept the 

gas, compression, or combustion flare, vessel will vent to the atmosphere to maintain flow of the liquid to other separators, treatment, and storage vessels 

No 

Stand-alone production sites (intermediate-sized facilities) 

Compressors (primarily reciprocating engines), generators, pumping units 

Emergency generators not used under normal service 

Used to heat the fluid after it takes a pressure drop through the “choke” at the wellhead 

If no source is ready to accept the pressurized gas, compression, or combustion flare, vessel will vent to atmosphere to maintain flow of the liquid to other separators, treatment, and storage vessels 

Used to break multiphase emulsion of oil/water/gas in the fluid 

Small compressor stations and wellheads 

Compressors (reciprocating engines), pumping units 

Generators and prime movers for drilling ops (mechanical pump power & power generation); generators for CBM ops (to power water pumps, especially in remote areas) 

Used to heat the fluid after it takes a pressure drop through the “choke” at the wellhead 

No No 

U.S. Environmental Protection Agency September 2008 
APPENDICES 

External Combustion Sources, Continued Storage and Separation Vess

NOx, PM10, PM2.5, VOCs, SOx, CO VOCs 

Amine Regenerator Sulfur Recovery Unit Combustion Flare Fugitives Separators 

Large compressor stations 

No No Used to destroy natural 

gas and other hydrocarbons during emergency situations (blowdowns, vents, and uncontrolled/unscheduled VOC emissions) 

Leakage of VOCs from a variety of valves, leaks, and exposed process sources 

No 

Natural gas processing plants 

Used to remove the entrained pollutants (CO2

and H2S) from fluid used in 

a “sweetening unit.” Pollutants may be flared, vented directly to atmosphere, or sent to a sulfur recovery unit. 

Used to recover sulfur off the amine regenerator 

Used to destroy natural gas and other hydrocarbons during emergency situations (blowdowns, vents, and uncontrolled/unscheduled VOC emissions) 

Leakage of VOCs from a variety of valves, leaks, and exposed process sources 

If there is no source ready to accept the pressurized gas, compression, or combustion flare, vessel will vent to atmosphere to maintain flow of the liquid to other separators, treatment, and storage vessels 

Stand-alone production sites (intermediate-sized facilities) 

Used to remove the entrained pollutants (CO2

and H2S) from fluid used in 

a “sweetening unit.” Pollutants may be flared, vented directly to atmosphere, or sent to a sulfur recovery unit. 

No Used to destroy natural 

gas and other hydrocarbons during emergency situations (blowdowns, vents and uncontrolled/unscheduled VOC emissions) 

Leakage of VOCs from a variety of valves, leaks, and exposed process sources 

If there is no source ready to accept the pressurized gas, compression, or combustion flare, vessel will vent to atmosphere to maintain flow of the liquid to other separators, treatment, and storage vessels 

Small compressor stations and wellheads 

No No No Leakage of VOCs from a 

variety of valves, leaks, and exposed process sources 

If there is no source ready to accept the pressurized gas, compression, or combustion flare, vessel will vent to atmosphere to maintain flow of the liquid to other separators, treatment, and storage vessels 

U.S. Environmental Protection Agency September 2008 
APPENDICES 

Storage and Separation Vessels, Continued

VOCs 

Glycol Dehydrator Regenerator 

Still Column 

Storage Tanks Pressure and Level Controllers Gas-Operated Pumps and 

Chemical Injection (CI) Pumps 

Large compressor stations Glycol will release the water and 

entrained hydrocarbon under the heat of the regenerator reboiler 

Includes both hydrocarbon and water storage tanks. Salt water storage tanks may be hydrocarbon emissions source as some water separation techniques leave a layer of oil on top of the water. 

Equipment that controls the vessel levels and pressure ranges (could be several hundred controllers at a compressor station). Certain older models vent gas continuously and at a rate of up to 1000 cubic feet per day (cfd). 

Pumps move fluids from one storage vessel to another. CI pumps are used to inject corrosion, scale, and biological inhibitors into flow lines. There can be significant numbers of CI pumps at well sites at the wellhead. 

Natural gas processing plants 

Glycol will release the water and entrained hydrocarbon under the heat of the regenerator reboiler 

Includes both hydrocarbon and water storage tanks. Salt-water storage tanks may be hydrocarbon emissions source as some water separation techniques leave a layer of oil on top of the water. Condensate storage usually controlled with vapor recovery units, though flares may be used as an alternative control. 

Equipment that controls the vessel levels and pressure ranges (could be several hundred controllers at a compressor station). Certain older models vent gas continuously and at a rate of up to 1000 cfd. 

No 

Stand-alone production sites (intermediate-sized facilities) 

Glycol will release the water and entrained hydrocarbon under the heat of the regenerator reboiler 

Includes both hydrocarbon and water storage tanks. Salt water storage tanks may be hydrocarbon emissions source as some water separation techniques leave a layer of oil on top of the water. 

Equipment that controls the vessel levels and pressure ranges (could be several hundred controllers at a compressor station). Certain older models vent gas continuously and at a rate of up to 1000 cfd. 

Pumps move fluids from one storage vessel to another. CI pumps are used to inject corrosion, scale, and biological inhibitors into flow lines. There can be significant numbers of CI pumps at well sites at the wellhead. 

Small compressor stations & wellheads 

Glycol will release the water and entrained hydrocarbon under the heat of the regenerator reboiler 

No No Pumps move fluids from one 

storage vessel to another. CI pumps are used to inject corrosion, scale, and biological inhibitors into flow lines. There can be significant numbers of CI pumps at well sites at the wellhead. 

U.S. Environmental Protection Agency September 2008 
U.S. Environmental Protection Agency September 2008 

NDICES 

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APPE
APPENDICES 

Appendix E: References 

WRAP References: 

Eastern Research Group, Inc., Quality Assurance of the 2002 WRAP Stationary Sources 

Emissions Inventory, Western Governors’ Association and Western Regional Air 

Partnership, Stationary Sources Joint Forum, January 27, 2006. 

Eastern Research Group, Inc., WRAP Point and Area Source Emissions Projections for 

the 2018 Base Case Inventory, Version 1, Western Governors’ Association and Western 

Regional Air Partnership, Stationary Sources Joint Forum, January 25, 2006. 

E.H. Pechan, 2018 SO2 Emissions Evaluation for Non-Utility Sources Final Report, 

Western Governors’ Association, Stationary Sources Joint Forum, October 2006. 

Environ International Corporation, Draft Final Report WRAP Area Source Emissions 

Inventory Projections and Control Strategy Evaluation Phase III, Western Governors’ 

Association, July 2007. 

Environ International Corporation, WRAP Oil & Gas: 2002/2005 and 2018 Area Source 

Controls Evaluation, Western Regional Air Partnership, Stationary Sources Joint Forum 

Working Group, May 30, 2007. 

Environ International Corporation, Oil and Gas Emission Inventories for the Western 

States, January 8, 2007. 

Environ International Corporation, Western States Oil and Gas Emission Inventories, 

Presentation to Four Corners Joint Air Quality Task Force, January 8, 2007. 

Environ International Corporation, WRAP Oil & Gas: Part 1: 2002/2005 and 2018 Area 

Source Emissions Inventory Improvements, Western Regional Air Partnership, Stationary 

Sources Joint Forum Working Group, May 8, 2007. 

Environ International Corporation, Work Plan WRAP Area Source Emissions Inventory 

Projections and Control Strategy Evaluation, Western Governors’ Association, 

November 9, 2006. 

Environ International Corporation, Final Report Oil and Gas Emission Inventories for the 

Western States, Western Governors’ Association, December 27, 2005. 

Western Regional Air Partnership, http://www.wrapair.org/, accessed 2/29/08. 

U.S. Environmental Protection Agency September 2008 E-1 
APPENDICES 

Other (non-WRAP) References: 

American Petroleum Institute, Overview of Exploration and Production Waste Volumes 

and Waste Management Practices in the United States, May 2000. 

American Petroleum Institute, Quarterly Well Completion Report, various editions. 

Argonne National Laboratory, A White Paper Describing Produced Water from 

Production of Crude Oil, Natural Gas, and Coal Bed Methane, U.S. Department of 

Energy, January 2004. 

Canada National Energy Board, Analysis of Horizontal Gas Well Performance in British 

Columbia, British Columbia Ministry of Energy and Mines, Oil and Gas Commission of 

British Columbia, October 2000. 

Colorado Department of Public Health and Environment, Air Quality Control 

Commission, Regulation No. 7, Section XII, 

http://www.cdphe.state.co.us/ap/reg7/o&greg7.pdf, accessed 2/29/08. 

Connelly, Joel, National Wildlife Federation, Frontal Assault, Aug/Sep 2004, vol. 42 no. 

5, http://www.nwf.org/nationalwildlife/article.cfm?issueID=69&articleID=959, accessed 

2/29/08. 

Earth Justice, Notice of Intent to Sue EPA Under the Clean Air Act, Nicholas F. 

Persampieri, July 2008. 

Eastern Research Group, Inc., Preferred and Alternative Methods for Estimating Air 

Emissions from Oil and Gas Field Production and Processing Operations, Emission 

Inventory Improvement Program, Point Source Committee, September 1999. 

Environmental Working Group, Who Owns the West? Oil and Gas Leases: Roan Plateau, 

Colorado, http://www.ewg.org/oil_and_gas/part6.php, accessed 08/21/08.

Federal Reserve Board, Industrial Production and Capacity Utilization, 

http://www.federalreserve.gov/releases/g17/, accessed 2/29/08. 

Four Corners Air Quality Task Force, http://www.nmenv.state.nm.us/aqb/4C/index.html, 

accessed 2/29/08. 

Houston Advanced Research Center, VOC Emissions from Oil and Condensate Storage 

Tanks. 

Hung-Ming Sung, Trinity Consultants, Estimation of HAP Emissions from Oil and Gas 

E&P Operation Wastes Paper No. 368, June 19, 2000. 

ICF International, Beneficial Reuse of Industrial Byproducts in the Gulf Coast Region, 

prepared for EPA’s Sector Strategies Program, February 2008. 

U.S. Environmental Protection Agency September 2008 E-2 
APPENDICES 

ICF Consulting, Overview of Exploration and Production Waste Volumes and Waste 

Management Practices in the United States, American Petroleum Institute, May 2000. 

IHS Inc, U.S. Gas Production Data. 

Independent Petroleum Association of America, Testimony of the Independent Petroleum 

Association of America Before the Committee on Oversight and Government Reform, 

U.S. House of Representatives, Hearing on Oil and Gas Exemptions in Federal 

Environmental Protections, October 31, 2007. 

Lasser, Inc., Lasser Oil and Gas Production Data, March 2008. 

Michigan Department of Environmental Quality, Environmental Science and Services 

Division, Emissions Calculation Fact Sheet Oil and Gas Production Facilities, October 

2006. 

National Academy of Sciences, Oil in the Sea III: Inputs, Fates, and Effects, 2003. 

Natural Resources Defense Council, Drilling Down: Protecting Western Communities 

from the Health and Environmental Effects of Oil and Gas Production, October 2007, 

http://www.nrdc.org/land/use/down/down.pdf, accessed 2/29/08. 

New Mexico Environment Department, San Juan VISTAS, 

http://www.nmenv.state.nm.us/aqb/projects/SJV/, accessed 2/29/08. 

Oil and Gas Accountability Project, Colorado Oil and Gas Industry Spills: A Review of 

COGCC data (June 2002-June 2006), http://www.earthworksaction.org/pubs/Spills.pdf, 

accessed 2/29/08. 

Oil and Gas Accountability Project, Our Drinking Water at Risk: What EPA and the Oil 

and Gas Industry Don’t Want Us to Know About Hydraulic Fracturing, April 2005, 

http://www.earthworksaction.org/pubs/DrinkingWaterAtRisk.pdf, accessed 2/29/08. 

Petroleum Technology Alliance Canada, Filling the Gap: Unconventional Gas 

Technology Roadmap, June 2006

Red Lodge Clearinghouse, BLM moves to reduce air emissions from energy development 

in Uinta Basin, February 2008, http://rlch.org/content/view/344/62/, accessed 2/29/08. 

Rogers, D., G. Fout and W.A. Piper, New Innovative Process Allows Drilling without Pits 

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APPENDICES 

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