An Assessment of the
Environmental Implications
of Oil and Gas Production:
A Regional Case Study
EPA
Region 8
o
September 2008
Working Draft
SectorStrategies
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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
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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, S02, CO, and HAPs, by State, 2002 (tons) 3-7
Table 3-8. Total Point and Area Emissions of VOCs, NOX, S02, 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
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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
1C Internal combustion
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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
NHa 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
PMio PM with an aerodynamic diameter less than or equal to a nominal 10
micrometers
PM10_PRI Primary PMio
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
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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
SC>2 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
USAGE 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
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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.
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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.l 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 (TCP) 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/market-
oversight/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.
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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 (862),
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. 862 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.
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EXECUTIVE SUMMARY
» In addition to CAA-regulated air pollutants, oil and gas production produces
greenhouse gas (GHG) emissions. Fugitive methane (CH/t) emissions constitute the
largest source of global warming potential-weighted (GWP-weighted) GHG
emissions. CC>2 emissions from process heaters were about 206,000 tons and from
internal combustion (1C) 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 862
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
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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 'Tracing,"
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.
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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.aov/fedrgstr/EPA-WATER/2008/Januarv/Dav-25/w1344.htm
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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,
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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.
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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
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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
GAS RESERVOIR
(SANDSTONEI
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.rockvmountainnews.com
9DTE Energy, Conventional vs. Unconventional Gas Production,
http://www.dteenerav.com/businesses/unconventionalGas.html..
10 Petroleum Technology Alliance Canada, Filling the Gap: Unconventional Gas Technology Roadmap, June 2006.
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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.
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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 (862), carbon dioxide
(CC>2), hazardous air pollutants (HAPs, such as benzene, toluene, ethyl benzenes, and
xylenes), particulate matter (PM), and methane (CH/t).
» 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.
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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.I of Appendix B.
» Appendix E, References, lists references used in this report.
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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
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BACKGROUND
U.S. production.13 The largest expected growth in domestic gas production is expected to
occur within these two states. 14The 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.
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 Lands
16
U.S. Federal Energy Regulatory Commission (FERC), Nature! Gas Markets: Western,, http://www.ferc.gov/market-
pversight/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/fs-
158-02/FS-158-02.pdf
16 U.S. Environmental Protection Agency, Region 8, Mountains and Plains, http://www.epa.gov/region8/tribes/
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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
Gulf Coast
I
I
s
Gulf of Mexico
Rockies
MidContinent
San Juan/ Permian
California/ Other
East/ Midwest
1998 1999 2000 2001 2002 2003 2004 2005 2006
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BACKGROUND
U)
Cl
E
300
250
200
150
Figure 2-3. Active Oil and Gas Rigs in Region 8, 2000—2006
Baker Hughes Monthly Rig Count - Region 8
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
900 -r
0
1998
1999
2000
2001
2002
2003
2004
2005
2006
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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
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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.
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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.ewci.orci/oil and gas/parte.DhD. 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)
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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 air-
related 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.
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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.
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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 SC>2. 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 SC>2 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.
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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 health-
based 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 DOI-
BLM, the U.S. Department of Agriculture (USD A), 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.
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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 NOX and PM, commonly associated with
production operations.
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/.
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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.28 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.
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.aov/oar/visibilitv/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/.
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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 (SOWA);
« 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.
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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 'Tracing" or 'Tracking," 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/auide/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/DrinkinaWaterAtRisk.pdf.
33 Tracking 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.
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» 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/cbmstudv attach uic exec summ.pdf.
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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
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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
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
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). Co-
regulators 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 co-
regulators and the regulated community can
ensure lasting environmental benefits from this
effort.
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.
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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
on rags
VWIs
Triba lands rf mttrest
1 WW states
WRAP ccundes
4
0 17S 36D
7M 1JBO MB
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
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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, 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 cited.
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.ora/nationalwildlife/article.cfm?issuelD=69&articlelD=959.
39 EPA Region 8, Oil & Gas Beneficial Reuse Summary, Region 8 E&P Report.
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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.eom/static//usa/downloads/enerav securitv/pdf/shell final report.pdf
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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.
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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, 862, 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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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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» 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 CC>2 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 CC>2 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. CC>2 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 MS, 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.
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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 CC>2.
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, S02, Nhh, H2S, all
PMs
Air Emissions: ChU
Air Emissions: C02
Produced Water
Drilling Waste
Extrapolated 2002 to 2006 using oil and gas production by state.
Data source: EIA
Extrapolated 2005 to 2006 using oil and gas production and gas processing data
by state.
Data source: EIA
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 2131 1 1 (Drilling Oil and Gas Wells), and NAICS
2131 12 (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
Used Lasser and IHS produced water estimates for 2006.
Extrapolated 2002 to 2006 using API drilling activity data by state.
Data source: API
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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 newNOx, 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)
Oil and Gas Emissions as
Emissions From Oil Total Region 8 Percentage of Regional
Pollutant and Gas Sector Emissions Emissions
VOCs
NOx
CO
S02
PM
262,953
87,130
37,880
18,385
834
651,580
587,942
413,990
503,041
2,172,255
40.4%
14.8%
9.2%
3.7%
<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
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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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
NOx
CO
S02
PM10_PRI
90,683
45,960
20,720
220
384
5,502
7,761
1,183
227
0
7,805
7,571
798
2,882
0
288
361
11
6
0
36,537
5,108
2,443
1,590
16
122,138
20,369
12,725
13,460
9
262,953
87,130
37,880
18,385
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
NOx
CO
S02
PM10_PRI
115,517
58,546
26,395
281
489
9,596
13,536
2,064
396
0
9,596
9,307
980
3,544
0
302
378
12
6
0
45,472
6,358
3,041
1,978
20
142,383
23,745
14,834
15,691
10
322,865
111,870
47,326
21,895
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 CC>2
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.49 By
comparison, HAP emissions are much smaller and are primarily VOCs.
Table 3-6 shows non-criteria pollutant pollutants, GHGs, and HAPs by state for 2006.
From 2002 to 2006, CC>2 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
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Table 3-5. Non-Criteria Pollutant Air Emissions by Pollutant, by State, 2002 (tons)
Pollutant CO MT ND SD UT WY Total
ChU (C02 equivalent)
CH4
C02
HAPs
3,216,621
153,172
1,644,066
3,781
410,513
19,548
622,154
130
591,147
28,150
265,536
431
37,543
1,788
15,767
15
893,226
42,535
403,571
3,932
5,217,392
248,447
2,240,802
25,450
10,366,442
493,640
5,191,897
33,738
Table 3-6. Non-Criteria Pollutant Air Emissions by Pollutant, by State, 2006 (tons)
Pollutant CO MT ND SD UT WY Total
ChU (C02 equivalent)
ChU
C02
HAPs
3,645,531
173,597
2,130,662
4,817
773,105
36,815
762,281
226
773,699
36,843
273,938
529
39,252
1,869
13,565
15
1,044,258
49,727
566,341
4,893
5,404,241
257,345
3,120,791
29,668
11,680,085
556,195
6,867,579
40,149
Table 3-7 presents air emissions by major source category—point and area—by state.
VOCs, NOX, SC>2, 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
Area
Total
63,423
27,259
90,683
58
5,444
5,502
66
7,740
7,805
0
288
288
576
35,961
36,537
2,691
119,447
122,138
66,814
196,139
262,953
NOx
Point
Area
Total
22,442
23,518
45,960
204
7,557
7,761
2,940
4,631
7,571
0
361
361
1,774
3,335
5,108
5,644
14,725
20,369
33,003
54,126
87,130
S02
Point
Area
Total
102
118
220
2
225
227
2,524
358
2,882
0
6
6
1,573
17
1,590
13,309
150
13,460
17,510
874
18,385
HAPs
Point
Area
Total
2,777
1,004
3,781
1
128
130
0
430
431
0
15
15
52
3,880
3,932
220
25,230
25,450
3,050
30,688
33,738
CO
Point
Area
Total
13,874
6,847
20,720
165
1,018
1,183
761
36
798
0
11
11
1,883
560
2,443
9,179
3,546
12,725
25,862
12,018
37,880
For VOCs and HAPs, the table reveals area sources are a much greater contributor to
emissions than point sources in Region 8. ForNOx 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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are primarily from large combustors (point sources) as well as small combustors and
mobile sources (area sources). On the other hand, SC>2 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, 862, 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
Area
Total
80,793
34,725
115,517
101
9,494
9,596
81
9,515
9,596
0
302
302
717
44,755
45,472
3,137
139,246
142,383
84,829
238,036
322,865
NOx
Point
Area
Total
28,588
29,958
58,546
356
13,180
13,536
3,614
5,693
9,307
0
378
378
2,207
4,150
6,358
6,579
17,166
23,745
41,344
70,526
111,870
S02
Point
Area
Total
130
151
281
3
393
396
3,103
441
3,544
0
6
6
1,958
21
1,978
15,515
175
15,691
20,710
1,186
21,895
HAPs
Point
Area
Total
3,538
1,279
4,817
2
224
226
0
529
529
0
15
15
65
4,828
4,893
256
29,412
29,668
3,861
36,288
40,149
CO
Point
Area
Total
17,673
8,722
26,395
288
1,776
2,064
936
45
980
0
12
12
2,344
697
3,041
10,700
4,134
14,834
31,941
15,385
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
Fugitive emissions are those stemming from unanticipated releases or leaks in production equipment and associated
processes.
Note: Numbers in associated tables in these sections may not add due to rounding.
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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
SO
7.5 % increase in produced water in Wyoming from 2002 to 2006. )
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
CO
UT
MT
ND
SD
Total
2,091,105,179
348,255,005
136,296,362
123,397,156
98,537,154
8,108,174
2,805,699,030
2,025,898,781
405,507,349
128,669,683
158,186,310
127,383,733
8,015,208
2,853,661,064
-3%
16%
-6%
28%
29%
-1%
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
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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ENVIRONMENTAL RELEASES
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)
Oil With Gas Gas With Oil
State Oil-Only Wells Gas-Only Wells Wells Wells Total
WY
CO
UT
MT
ND
SD
Total
601,234,810
81,962,976
21,684,832
50,775,321
20,953,673
915,122
777,526,734
569,061,152
158,856,545
31,145,993
16,847,685
3,521
614
775,915,510
853,631,461
102,323,995
79,283,960
55,708,537
74,617,442
5,121,998
1,170,687,393
67,177,756
5,111,489
4,181,577
65,613
2,962,518
2,070,440
81,569,393
2,091,105,179
348,255,005
136,296,362
123,397,156
98,537,154
8,108,174
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)
Oil With Gas Gas With Oil
State Oil-Only Wells Gas-Only Wells Wells Wells Total
CO
MT
ND
SD
UT
WY
Total
47,185,142
56,283,830
26,358,334
616,231
28,124,959
615,254,891
773,823,387
217,006,510
28,076,898
17,382
953
23,725,241
566,049,418
834,876,402
127,734,624
73,443,690
92,659,049
5,597,759
65,148,166
782,635,991
1,147,219,279
13,581,073
381,892
8,348,968
1,800,265
11,671,317
61,958,481
97,741,996
405,507,349
158,186,310
127,383,733
8,015,208
128,669,683
2,025,898,781
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).
Additional information on GHG emissions and produced water issues can be found at:
http://www.beneficialusesummit.com/2008/2008presentations.html
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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 Water
57
Pollutant
Barium
Calcium
Chloride
Iron
Magnesium
Potassium
Sodium
Sulfate
San Juan Basin
Mill Max
0.7
0
0
0
0
0.6
19
0
63
228
2350
228
90
770
7.130
2.300
Pollutant C
Black Warrior
Basin
Mm Max
ND
ND
40
0.1
ND
ND
60
1
ND
ND
36.000
400
ND
ND
21,500
1350
oncenti .ition by B,
Powder River
Basin
Min Max
0.06
^
3
0.03
i
T
89
0.01
7
200
119
11
12
20
800
1.170
«sin (mg/L)
Raton Basin
Min Max
ND
4
15
0.1
1
1
210
1
ND
24
719
•J ^
8
17
991
204
Uinta Basin
Min Mai
ND
ND
2300
ND
ND
ND
ND
ND
ND
ND
14,000
ND
ND
XD
ND
ND
Source: Analysis of Discharge Data for Six Industry Categories {Baitram. 2003).
Min — Minimum.
Max - Maximum.
ND -No data available.
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
U.S. Environmental Protection Agency, Technical Support Document for the 2006 Effluent Guidelines Program Plan,
http ://www. epa. go v/gu ide/304m/2006-TS D-whole.pdf
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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 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). 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.
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ENVIRONMENTAL RELEASES
Table 3-13. Drilling Waste by State, 2002 and 2006 (barrels)
Percent
State 2002 2006 Change
WY
CO
UT
MT
ND
SD
Total
10,834,600
6,138,174
4,533,724
2,741,195
1,484,341
37,451
25,769,484
17,668,762
10,098,340
9,222,269
5,965,305
3,370,840
123,756
46,449,272
63%
65%
103%
118%
127%
230%
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-qas.pdf
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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
ICF International. Beneficial Reuse of Industrial Byproducts in the Gulf Coast Region, prepared for EPA's Sector
Strategies Program, February 2008.
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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-surf ace
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
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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)
Region 8 as
Percentage
Pollutant Regions U.S. Total of U.S. Total
Emissions in Tons
VOCs
NOx
CO
S02
PM
HAPs
CH4
C02
322,865
111,870
47,326
21,895
1,060
40,149
556,195
6,867,579
1,111,445
839,803
273,051
105,227
19,200
134,508
3,841,447
49,706,996
29%
13%
17%
21%
6%
30%
14%
14%
Water and Waste in Barrels
Produced Water
Drilling Waste
2,853,661,064
46,449,272
19,445,269,921
233,887,586
15%
20%
Air pollutants of interest are NOX, SC>2, 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.
"Tapping Into Energy's Fringe: As Companies Drill for 'Unconventional' Natural Gas, Environmental Impacts Mount,"
High Country News. 12/12/05.
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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:
"[Virtually 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
bj 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/.
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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.
Further details on these programs and policies can be found in Chapter 2 of the report.
eeee y g Environmental Protection Agency, EPA's Clean Water Act Review of the Coalbed Methane Industrial Sector,
June 2007, http://www.epa.gov/auide/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/cbmstudv 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, Chapters, Pollution Prevention
Opportunities, http://www.epa.aov/oecaerth/resources/publications/assistance/sectors/notebooks/oilgaspt2.pdf.
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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.
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SUMMARY
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.
U.S. Environmental Protection Agency Working Draft - September 2008 4-6
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SUMMARY
Table 4-2. Summary of Voluntary Environmental Programs Available to the Oil and Gas Sector
Program Four Corners Air Quality
Attributes Natural Gas STAR OSHAVPP San Juan VISTAS Wyoming VRP Task Force
Objectives
Pollutants Under
Purview
Partners
States
Partner Benefits
Program Outreach/
Resources
Identify and promote the
implementation of cost-effective
technologies and practices to reduce
methane emissions
Methane (CH4)
1 1 0+ partners across the four
sectors of the oil and gas industry
(production, processing,
transmission, and distribution); 8
international partners; and 19
endorser organizations
All states, including Region 8 states
• 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
• Technology transfer
workshops for all sectors of
the oil and gas industry
• Annual implementation
workshop
• Technical documents
• Feasibility studies
• Partner challenge study,
identifying opportunities
• 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
Focuses on health and safety
All groups covered by OSHA,
including federal agencies
All states, including Region 8 states
• "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
• "Special Government
Employee" (SGE) program to
extend government resources
and expertise
• Mentoring
• Safety and health management
course
Identify, promote, and implement
cost-effective technologies and
practices to reduce air pollution
affecting northwestern New Mexico
VOCs, CO, NOx, S02, all gases that
affect ozone and haze, and GHGs
Private and public entities:
industries, businesses,
municipalities, organizations and
community groups
New Mexico (but lessons learned
are presumably applicable to
Region 8 and other oil and gas
producing states)
• 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)
• Technology transfer workshops
• Outreach materials
• Assist partners with technology
and practice implementation by
analyzing opportunities, where
applicable
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
All types of land and water
contamination
Not applicable— there are no
partners, perse, but the program is
designed to support owners,
operators, and purchasers of
contaminated sites
Wyoming
• Provides three types of liability
assurances:
1 . Covenants not to sue
2. Certificate of completion
3. No further action (NFA)
letters
• Brownfield assessment
assistance
Various fact sheets
Address air quality issues in the
Four Corners region, increase air
pollution awareness, and consider
options for mitigating air pollution
VOCs, CO, NOx, S02, all gases
that affect ozone and haze, and
GHGs
100+ members (private citizens,
public interest groups, universities,
industry, and federal, state, local
and tribal governments) and 150
interested parties
Arizona, Colorado, New Mexico,
and Utah (i.e., the Four Corners
region)
Reduction in air pollution
• Quarterly meetings
• Workgroup participation
• Outreach material
U.S. Environmental Protection Agency
Working Draft - September 2008
4-7
-------
SUMMARY
Program Four Corners Air Quality
Attributes Natural Gas STAR OSHAVPP San Juan VISTAS Wyoming VRP Task Force
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
• 125 mitigation options
developed by members in 2
years
• Increased air pollution
awareness
• Provided resources to
agencies responsible for air
quality management in the
Four Corners area
U.S. Environmental Protection Agency
Working Draft - September 2008
4-8
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Appendix A: Industry Characterization
A.1 Industry Description
As shown in Table A-l, 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
211111
211112
213111
213112
Oil and Gas Extraction
Crude Petroleum and Natural Gas Extraction
Natural Gas Liquid Extraction
Oil and Gas Drilling
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
1311
S Description
1321
1381
1382
1389
Crude Petroleum and Natural Gas
Natural Gas Liquids
Drilling Oil and Gas Wells
Oil and Gas Field Exploration Services
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.
Figure A-1. Conventional
Oil Formation
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
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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 non-
associated 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
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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
Surface
Depth of deepest area
domestic water well
Surface casing depth:
min. 200 ft., max. 50 ft.
below deepest area
domestic water well
Top of completion zone
Bollorn of completion zone
4.125'sleel pipe
and cement layer*
Surface Casing:
1/2" thick steel pipe
2" Cement
1" Cement
Production Casing: 3/B"
thick steel pipe
Perforations
Production Tubing: 1/4"
thick steel pipe
Plastic Plug
40' Deep Concrete Plug
Production Casing Depth:
200' below compfelion zone
U.S. Environmental Protection Agency
September 2008
A-3
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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 A-
3). 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
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APPENDICES
Figure A-3. Horizontal Drilling
Ellenberger
(Water Bearing Formation)
Viola
(Frac Barrier)
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
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APPENDICES
Figure A-4. Hydraulic Fracturing
Hydraulic fracturing is a means of creating fractures emanating from the well bore in a producing formation to
provide increased flow channels for production. A viscous fluid containing a proppant such as sand is
injected under high pressure until the desired fracturing is achieved. The pressure is then released allowing the
fluid to return to the well. The proppant, however, remains in the fractures preventing them from closing.
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 (CCh), 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 (1C) 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 (CH^) 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 re-
injected 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
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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
,;*.- w . -.
• • 'i :-.'• ?
TribflJ lands
^j VfUP states
WRAP counoes
_
4
D 175 3BD
TDD 1JXD
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, high-
permeability 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 one-
third 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
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APPENDICES
Table A-3. Total Oil and Gas Production in Region 8, 2002
WY
CO
UT
MT
ND
SD
Region 8 Total
U.S. Total
1,776,311
1,045,365
292,752
86,304
57,783
32,072
3,290,588
18,927,788
54,872
18,696
13,767
16,860
29,670
3,061
136,928
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
re
3
1998
1999
2000
2001
2002 2003 2004 2005 2006
U.S. Environmental Protection Agency
September 2008
A-10
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APPENDICES
Figure A-7. Total Crude Oil Production in the Lower 48 by Region, 1998—2005
900 -r
1998 1999 2000 2001 2002 2003 2004 2005
2006
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
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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
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APPENDICES
Figure A-8. Comparison of U.S. and Rockies Gas Production, 2000—2005
25
20
8 15
10
2000
2001
2002
2003
2004
2005
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
40,000
35,000
30,000
-------
APPENDICES
Table A-4. Oil and Gas Production and Drilling Activity in the
Rockies and U.S. Dry Gas Production
Billion Cubic Feet per Year
2000
2001
2002
2003
2004
2005
Rockies and
CO
759
882
964
1,142
1,050
1,104
UT
226
288
286
278
282
308
WY
1,070
1,286
1,388
1,456
1,524
1,642
MT
67
73
77
86
95
100
Rockies
Total
2,122
2,529
2,715
2,962
2,951
3,154
U.S.
Total
19,219
19,779
19,353
19,425
19,168
18,458
Rockies
Rockies
Percent
of U.S.
11%
13%
14%
15%
15%
17%
U.S. Crude Oil Production
Million Barrels per Year
2000
2001
2002
2003
2004
2005
Rockies and
2000
2001
2002
2003
2004
2005
Rockies and
2000
2001
2002
2003
2004
2005
CO
17
16
17
16
18
19
UT
14
13
12
12
13
15
WY
54
48
46
42
43
45
MT
15
16
18
19
22
30
Rockies
Total
100
93
93
89
96
109
U.S.
Total
1,880
1,915
1,875
1,877
1,819
1,733
Rockies
Percent
of U.S.
5%
5%
5%
5%
5%
6%
U.S. Annual Completed Gas Wells
CO
920
1,344
1,270
1,490
1,736
2,496
UT
365
484
351
274
301
438
WY
4,888
5,249
2,942
2,679
3,617
4,356
MT
384
318
296
508
435
578
Rockies
Total
6,557
7,395
4,859
4,951
6,089
7,868
U.S.
Total
17,126
21 ,202
15,970
19,482
23,193
27,562
Rockies
Percent
of U.S.
38%
35%
30%
25%
26%
29%
U.S. Annual Completed Oil Wells
CO
73
34
21
36
312
406
2006 Producing Oil and
Gas
Oil
CO
19,993
7,567
UT
84
106
40
117
299
355
Gas Wells
UT
5,012
2,401
WY
145
127
90
154
413
518
WY
25,052
10,205
MT
75
163
144
225
287
361
MT
4,078
5,862
Rockies
Total
377
430
295
532
1,311
1,640
Rockies
Total
54,135
26,035
U.S.
Total
8,209
8,934
6,929
8,135
11,170
12,734
U.S.
Total
413,174
500,785
Rockies
Percent
of U.S.
5%
5%
4%
7%
12%
13%
Rockies
Percent
of U.S.
13%
5%
Total
27,560 7,413 35,257 9,940 80,170 913,959
9%
U.S. Environmental Protection Agency
September 2008
A-14
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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
(A
•c
C
re
o
.n
mn
n
• U.S.
D Rockies
Gas
Oil
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
WY
CO
UT
MT
ND
SD
Total
8,531,181 I
7,055,372
2,698,645
1,803,418
1,413,658
36,360
21,538,634
U.S. Environmental Protection Agency
September 2008
A-15
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APPENDICES
Table A-6. Well Data by State for
Region 8, 2002
State Total # Average Well
of Wells Depth (ft)
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-7. Well Data by Type and State for Region 8, 2002
WY
CO
MT
UT
ND
SD
Total
31,600
22,342
8,707
5,572
3,591
248
72,060
6,020
5,856
3,420
6,558
9,013
6,660
5,848
State Total # Oil-Only Gas-Only Oil With Gas With
of Wells Wells Wells Gas Wells Oil Wells
WY
CO
MT
UT
ND
SD
Total
31,600
22,342
8,707
5,572
3,591
248
72,060
6,276
1,763
2,694
467
914
69
12,183
13,731
8,135
4,633
1,784
77
62
28,422
5,225
4,788
1,355
1,809
2,452
64
15,693
6,368
7,656
25
1,512
148
53
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.
Table A-8. CBM Wells
by State for Region 8, 2002
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.
State Gas-Only # of CBM Percent
Wells Wells CBM
WY
CO
MT
UT
ND
SD
Total
13,731
8,135
4,633
1,784
77
62
28,422
11,628
3,680
236
758
0
0
16,302
85%
45%
5%
42%
0%
0%
57%
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."
U.S. Environmental Protection Agency
September 2008
A-16
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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 Number of
(Mcf) Plants
WY
CO
UT
ND
MT
SD
Total
6,920
2,093
970
222
133
0
10,338
45
43
16
8
3
0
115
U.S. Environmental Protection Agency
September 2008
A-17
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APPENDICES
This Page is Intentionally Left Blank.
U.S. Environmental Protection Agency September 2008 A-18
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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 (802), 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 (CH/t),
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
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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 diesel-
U.S. Environmental Protection Agency Working Draft - September 2008 B-2
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APPENDICES
fired engines that power generators, trucks, or mobile equipment such as drilling rigs
or frac units. Emissions include NOX, PMi0, PM2.s, 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, PMi0, PM2.s, 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-l 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
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APPENDICES
Table B-1. Emission Sources and Pollutants for Oil and Gas Production
Source
Category
Pollutant
Emission Unit Large Natural Gas Stand-alone Small
Compressor Processing Production Compressor
Stations Plants Sites Stations &
Wellheads
Internal
Combustion
External
Combustion
Storage and
Separation
Vessels
NOx,
PMio,
PM2.5,
VOCs,
SOx, CO
VOCs
Natural gas-fired
engines
Diesel-fired
engines
Line heaters
Separators
Heat treaters
Glycol
regenerators
Amine
regenerators
Sulfur recovery
units
Combustion flares
Fugitives
Separators
Glycol dehydrator
flash tanks
Glycol dehydrator
regenerator still
columns
Storage tanks
Pressure and level
controllers
Gas operated
pumps & chemical
injection (Cl)
pumps
Oil/water skimmers
y
y
y
y
y
y
y
y
y
y
y
y
y
y
y
y
y
y
y
y
y
y
y
y
y
y
y
y
y
y
y
y
y
y
y
y
y
y
y
y
y
y
y
y
y
y
y
y
y
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
2-02-002-54
Standard "rich burn" engines
May include:
Natural gas process heaters
Natural gas production
compressors
Natural gas production
flares — excluding SO2
Lean burn engines
May include:
Natural gas process heaters
Natural gas production
compressors
Natural gas production
flares — excluding SC>2
CO
NOX
PM-io
PM25
SO2
VOC
CO
NOX
PM10
PM25
SO2
VOC
3.794E3 Ib/mmcf
2.254E3 Ib/mmcf
9.69EO Ib/mmcf
9.69EO Ib/mmcf
6.00E-1 Ib/mmcf
3.02E1 Ib/mmcf
5.68E2 Ib/mmcf
4. 162E3 Ib/mmcf
7.90E-2 Ib/mmcf
7.90E-2 Ib/mmcf
6.00E-1 Ib/mmcf
1.204E2 Ib/mmcf
3-way catalyst
CO - 80%
NOX - 90%
VOCs - 50%
Oxidation catalyst
CO - 80%
VOCs - 50%
Process Heaters (excluding engines noted above)
3-10-004-04
Process heaters
CO
NOX
PM-io
sox
VOC
3.50E1 Ib/mmcf
1.40E2 Ib/mmcf
3.00EO Ib/mmcf
6.00E-1 Ib/mmcf
2.80EO Ib/mmcf
Tank Storage
4-04-003-01
4-04-003-02
Fixed roof tank — breathing
loss
Fixed roof tank — working loss
VOC
VOC
3.6E1 Ib/kgal-yr-
crude oil (storage
capacity)
1.1EOIb/E3gal
crude oil
(throughput)
Vapor recovery
system - 95%
Flare - 95%
Vapor recovery
system - 95%
Flare - 95%
Truck Loading
4-06-001-32
Truck loading
VOC
2.0EO lb/E3 gal
crude oil
Vapor recovery
system - 95%
Gas Dehydrators
3-10-003-21
3-10-003-22
3-10-003-23
Glycol dehydrator — Niagaran
Glycol dehydrator — Prairie du
Chien
Glycol dehydrator — Antrim
VOC
VOC
VOC
9.24E4 Ib/yr-GPM
Glycol
1.94E4 Ib/yr-GPM
Glycol
9.2E1 Ib/yr-GPM
Glycol
Tube and shell
condenser with flash
tank - 90%
Vapor recovery
system - 95%
Flare - 95%
Tube and shell
condenser with flash
tank - 90%
Vapor recovery
system - 95%
Flare - 95%
Vapor recovery
system - 95%
Flare - 95%
Amine Plant
3-06-009-06
Amine plant
SO2
3.76E3 Ib/ton
hydrogen sulfide
Fugitive Emissions (excludes fugitive emissions from crude oil sumps)
3-10-888-01
3-10-888-02
3-10-888-03
Fugitive emissions — light
crude oil
Fugitive emissions — gas
production
Fugitive emissions — gas
plant
VOC
VOC
VOC
1.44E1 Ib/each-yr
valve
3.60EO Ib/each-yr
valve
2.74E1 Ib/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
CC>2 from fossil fuel combustion and CH4 from leaks, venting, and fugitive emissions. As
previously noted, methane has greater global warming effect (or GWP) than CC>2—the
GWP for CH4 is 21 times that of CC>2. 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
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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
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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
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APPENDICES
The database is currently being updated. Table C-l 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 # of Gas Total
Wells Wells
CO
MT
ND
SD
UT
WY
Total
7,567
5,862
3,120
158
2,401
10,205
29,313
19,993
4,078
178
71
5,012
25,052
54,384
27,560
9,940
3,298
229
7,413
35,257
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 # of Gas Total
Wells Wells
CO
MT
ND
SD
UT
WY
Total
4,288
3,765
3,122
75
2,180
10,471
23,901
23,208
5,356
428
129
3,936
23,370
56,427
27,496
9,121
3,550
204
6,116
33,841
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
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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.
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- 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 (NET) 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
(862), 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.
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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), PMi0, PM2.s, and
ammonia (NHa). 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 Liquids Total
Natural Gas Extraction (SIC 1321)
(SIC 1311)
CO
MT
ND
SD
UT
WY
Total
28
4
0
0
5
13
50
6
1
0
0
3
5
15
34
5
0
0
8
18
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.
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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,
PMio, 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, PMio 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.
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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.
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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
1321
1381
1382
1389
Crude Petroleum and Natural Gas
Natural Gas Liquids
Drilling Oil and Gas Wells
Oil and Gas Field Exploration Services
Oil and Gas Field Services, not
elsewhere classified
Total
3,927
3,491
0
0
41
7,459
149
18
0
0
0
167
40
40
0
0
0
80
199
93
0
0
0
292
0
0
0
0
0
0
354
182
0
0
27
563
4,669
3,824
0
0
68
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
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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 SC>2 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, SC>2, 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
Condensate Tanks Uncontrolled
Oil Well Tanks
Gas Well Completion— Flaring and Venting
Condensate Tanks Controlled
Gas Well Pneumatic Devices
Oil Well Pneumatic Devices
Ibs/yr/MMCFD
Ibs/yr/barrel per day
Ibs/yr/barrel per day
tons/well
Ibs/yr/barrel per day
tons/well
tons/well
27,485.6
3,271.0
160.00
86.0
65.740
0.200
0.100
13,695.6
116.0
2.66
3.0
2.320
0.008
0.004
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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
CFLt 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
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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.
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.
U.S. Environmental Protection Agency September 2008 C-11
MT
ND
SD
UT
WY
0.87
1.52
1.05
1.03
1.68
1.27
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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.
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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 methaneto 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.
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Appendix D: Air Emissions Sources by Source Category and Equipment
Type
Table D-l describes the primary sources of air emissions for each major source category identified in Section B.I: large compressor
stations, natural gas processing plants, stand-alone production sites, and small compressor stations and wellhead sites.
Table D-1. Sources of Air Emissions by Equipment Type and Source Category
Major Source Internal Combustion Sources External Combustion Sources
Categories NOX, PM™, PM2.5, VOCs, SOX, CO NOX, PM™, PM2.5, VOCs, SOX, CO
Natural Gas-Fired Engines Diesel-Fired Engines Line Heaters Separators HeatTreaters Glycol Regenerator
Large compressor
stations
Natural gas processing
plants
Stand-alone production
sites (intermediate-sized
facilities)
Small compressor
stations and wellheads
Compressors, generators
Compressors (primarily
reciprocating engines),
generators, pumping units
Compressors (primarily
reciprocating engines),
generators, pumping units
Compressors (reciprocating
engines), pumping units
Emergency generators not
used under normal service
Emergency generators not
used under normal service
Emergency generators not
used under normal service
Generators and prime movers
for drilling ops (mechanical
pump power & power
generation); generators for
CBM ops (to power water
pumps, especially in remote
areas)
Maintain temperature of
gas to reduce formation
of natural gas hydrates in
transmission lines
No
Used to heat the fluid
after it takes a pressure
drop through the "choke"
at the wellhead
Used to heat the fluid
after it takes a pressure
drop through the "choke"
at the wellhead
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
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
No
No
No
Used to break
multiphase emulsion of
oil/water/gas in the fluid
No
Used to drive off water
absorbed by the glycol when
the "wet" natural gas was
bubbled through it in a gas
dehydrator
Used to drive off water
absorbed by the glycol when
the "wet" natural gas was
bubbled through it in a
dehydrator
Used to drive off water
absorbed by the glycol when
the "wet" natural gas was
bubbled through it in a
dehydrator
Used to drive off water
absorbed by the glycol when
the "wet" natural gas was
bubbled through it in a
dehydrator
U.S. Environmental Protection Agency
September 2008
D-1
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APPENDICES
External Combustion Sources, Continued Storage and Separation Vessels
NOx, PM™, PM2.5, VOCs, SOX, CO VOCs
Amine Regenerator Sulfur Recovery Unit Combustion Flare Fugitives Separators Glycol Dehydrator Flash
Tank
Large compressor
stations
Natural gas processing
plants
Stand-alone production
sites (intermediate-sized
facilities)
Small compressor stations
and wellheads
No
Used to remove the
entrained pollutants (C02
and hbS) from fluid used in
a "sweetening unit."
Pollutants may be flared,
vented directly to
atmosphere, or sent to a
sulfur recovery unit.
Used to remove the
entrained pollutants (C02
and hbS) from fluid used in
a "sweetening unit."
Pollutants may be flared,
vented directly to
atmosphere, or sent to a
sulfur recovery unit.
No
No
Used to recover sulfur off
the amine regenerator
No
No
Used to destroy natural
gas and other
hydrocarbons during
emergency situations
(blowdowns, vents, and
uncontrolled/unscheduled
VOC emissions)
Used to destroy natural
gas and other
hydrocarbons during
emergency situations
(blowdowns, vents, and
uncontrolled/unscheduled
VOC emissions)
Used to destroy natural
gas and other
hydrocarbons during
emergency situations
(blowdowns, vents and
uncontrolled/unscheduled
VOC emissions)
No
Leakage of VOCs from a
variety of valves, leaks,
and exposed process
sources
Leakage of VOCs from a
variety of valves, leaks,
and exposed process
sources
Leakage of VOCs from a
variety of valves, leaks,
and exposed process
sources
Leakage of VOCs from a
variety of valves, leaks,
and exposed process
sources
No
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
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
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
A portion of the natural gas is
removed from the triethylene
glycol (TEG) due to pressure
drop
A portion of the natural gas is
removed from the TEG due to
pressure drop
A portion of the natural gas is
removed from the TEG due to
pressure drop
A portion of the natural gas is
removed from the TEG due to
pressure drop
U.S. Environmental Protection Agency
September 2008
D-2
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APPENDICES
Large compressor stations
Glycol Dehydrator Regenerator
Still Column
Glycol will release the water and
entrained hydrocarbon under the
heat of the regenerator reboiler
Storage Tanks
Storage and Separation Vessels, Continued
VOCs
Pressure and Level Controllers Gas-Operated Pumps and
Chemical Injection (Cl) Pumps
Oil/Water Skimmers
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. Cl
pumps are used to inject
corrosion, scale, and biological
inhibitors into flow lines. There can
be significant numbers of Cl
pumps at well sites at the
wellhead.
No
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
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. Cl
pumps are used to inject
corrosion, scale, and biological
inhibitors into flow lines. There can
be significant numbers of Cl
pumps at well sites at the
wellhead.
Use of natural gas that is bubbled
through the produced water to
release additional entrained oil is
common and often not accounted
for in emissions inventories
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. Cl
pumps are used to inject
corrosion, scale, and biological
inhibitors into flow lines. There can
be significant numbers of Cl
pumps at well sites at the
wellhead.
No
U.S. Environmental Protection Agency
September 2008
D-3
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APPENDICES
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U.S. Environmental Protection Agency September 2008 D-4
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APPENDICES
Appendix E: References
WRAP References:
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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
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Regional Air Partnership, Stationary Sources Joint Forum, January 25, 2006.
E.H. Pechan, 2018 SO 2 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'
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Environ International Corporation, WRAP Oil & Gas: 2002/2005 and 2018 Area Source
Controls Evaluation, Western Regional Air Partnership, Stationary Sources Joint Forum
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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
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Environ International Corporation, Work Plan WRAP Area Source Emissions Inventory
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Environ International Corporation, Final Report Oil and Gas Emission Inventories for the
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U.S. Environmental Protection Agency September 2008 E-1
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APPENDICES
Other (non-WRAP) References:
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U.S. Environmental Protection Agency September 2008 E-2
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APPENDICES
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U.S. Environmental Protection Agency September 2008 E-3
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APPENDICES
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U.S. Environmental Protection Agency September 2008 E-4
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APPENDICES
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U.S. Environmental Protection Agency September 2008 E-5
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APPENDICES
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U.S. Environmental Protection Agency September 2008 E-6
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APPENDICES
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