# September 2008 W orking Draft 

# An Assessment of the Environmental Implications of Oil and Gas Production: A Regional Case Study

EPA Region 8

### Table of Contents

Acronyms ....................................................................................................................................................................... iii Executive Summary .................................................................................................................................................. ES-1
1.0 Introduction

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

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

............................................................................................................................... ................. 1-1
1.2.1 Framing the Study: Oil and Gas Production in Region 8 ............................................................ 1-1 1.2.2 Focus of the Report .................................................................................................................... 1-3
1.3 Organization of the Report ..................................................................................................................... 1-5
2.0 Background

............................................................................................................................... ....................... 2-1
2.1 Importance of Region 8 to Domestic Oil and Gas Production ................................................................ 2-1
2.2 Unique Characteristics of Region 8 ........................................................................................................ 2-2
2.2.1 Oil and Gas Production .............................................................................................................. 2-2 2.2.2 Geological Characteristics .......................................................................................................... 2-5 2.2.3 Other Natural Characteristics ..................................................................................................... 2-6
2.3 Key Policy Issues Associated With Oil and Gas Production .................................................................. 2-7
2.3.1 Air Issues

............................................................................................................................... ..... 2-8 2.3.2 Water Issues ............................................................................................................................. 2- 13 2.3.3 Land Use Issues ....................................................................................................................... 2-18
3.0 Environmental Releases

............................................................................................................................... ... 3-1
3.1 Data Sources and Assumptions ............................................................................................................. 3-1
3.1.1 2002 Data Sources and Assumptions ........................................................................................ 3-1 3.1.2 2006 Data Development Assumptions ....................................................................................... 3-3
3.2 Estimated Air Emissions: Comparing 2002 Baseline to 2006 Estimates ............................................... 3-5
3.3 Estimated Non-Air Releases (Produced Water and Drilling Waste), 2002 and 2006 ............................. 3-8
3.3.1 Produced Water Summary ......................................................................................................... 3-9 3.3.2 Produced Water Management and Implications ....................................................................... 3-12 3.3.3 Drilling Waste Summary ........................................................................................................... 3-12 3.3.4 Drilling Waste Management and Implications .......................................................................... 3-13
4.0 Summary

............................................................................................................................... ............................ 4-1
4.1 Summary of Data Findings ..................................................................................................................... 4-1
4.2 Summary of Initiatives to Address Oil and Gas Demand and Environmental Footprint Issues .............. 4-3
4.2.1 Federal Initiatives ....................................................................................................................... 4-4 4.2.2 State Initiatives ........................................................................................................................... 4-5 4.2.3 Regional Initiatives ..................................................................................................................... 4-5 4.2.4 Other Ongoing Analyses and Policy Initiatives ........................................................................... 4-5 4.2.5 Voluntary Programs .................................................................................................................... 4-6

Appendix A: Industry Characterization.......................................................................................... .................................A-1 Appendix B: Pollution Sources in the Oil and Gas Industry ...................................................................... .....................B-1 Appendix C: Data Availa bility and Sources...................................................................................... ..............................C-1 Appendix D: Air Emissions Sources by Source Category and Equipment Type ........................................................ ...D-1 Appendix E: References ......................................................................................................... .......................................E-1

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

### Table of Tables

Table 3-1. Methodology to Develop 2006 Data, by Pollutant ......................................................................................... 3-4 Table 3-2. Oil and Gas Criteria Pollut ant 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, NO x , SO 2 , CO, and HAPs, by State, 2002 (tons) ....................... 3-7 Table 3-8. Total Point and Area Emissions of VOCs, NO x , SO 2 , 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 Em issions/ 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 Producti on in the Lower 48 by Region, 1998—2005 .......................................................... 2-4 Figure 2-5. Rocky Mountain Stat es’ Oil and Gas Producing Regions ......................................................................... 2-19

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

## Acronyms

ACEC Areas of critical environmental concern ANL Argonne National Laboratory (DOE) APEN Air Pollution Emission Notice API American Petroleum Institute Bbl Billion barrels Bcf Billion cubic feet BLM Bureau of Land Management within the U.S. Department of Interior BMP Best management practice CAA Clean Air Act CBM Coal bed methane CEM Continuous emissions monitor CERR Consolidated Emissions Reporting Rule CH 4 Methane CI Chemical injection CO Colorado CO Carbon monoxide CO 2 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 En ergy 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 H 2 S Hydrogen sulfide HR U.S. House of Representatives HSM Hydrocarbon Supply Model IC Internal combustion

U.S. Environmental Protection Agency Working Draft – September 2008 iiiICE 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 Indus try 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 T echnology Laboratory (DOE) NFA No further action NGL Natural gas liquids NGO Non-governmental organization NH 3 Ammonia NO x 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, Ec onomics, and Innovation (EPA) OSHA Occupational Safety and Health Adminstration (DOL) OW Office of Water (EPA) PAH Polyaromatic hydrocarbon Pb Lead PM Particulate matter PM 2.5 PM with an aerodynamic diameter less than or equal to a nominal 2.5 micrometers PM 10 PM with an aerodynamic diameter less than or equal to a nominal 10 micrometers PM10_PRI Primary PM 10 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 inte rnal combustion engine RMP Resource Management Plan

U.S. Environmental Protection Agency Working Draft – September 2008 ivROD 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 SO 2 Sulfur dioxide SO x Sulfur oxide Tcf Trillion cubic feet TDS Total dissolved solids TIP Tribal Implementation Plan UIC Underground injection control U.S. United States USACE U.S. Army Corps of Engineers USDW Underground source of drinking water USGS U.S. Geological Survey (DOI) UT Utah VISTAS Voluntary Innovative Strate gies for Today’s Air Standards VOC Volatile organic compound VPP Voluntary Protection Programs VRP Voluntary Remediation Program WCI Western Climate Initiative WGA Western Governors’ Association WDEQ Wyoming Department of Environmental Quality WESTAR Western States Air Resources Council WRAP Western Regional Air Partnership WY Wyoming Yr Year

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


## Executive Summary

Oil and gas exploration and production w ithin the Rocky Mountain region is experiencing rapid growth. The environmenta l implications of thes e and other energy production activities are a majo r area of focus for the U.S. Environmental Protection Agency (EPA). Headquartered in Denver, Co lorado, the EPA regional office (Region 8) partners with other federal agencies, st ate 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 Commi ssion (IOGCC) is integral to continued communications, coordination, a nd collaboration regarding e nvironmental oversight of oil and gas production.

The dramatic upsurge in regional oil and gas production in recent ye ars is expected to continue. Indeed, various studies predic t that the Rocky Mountain region - which includes major coal bed methane (CBM), tig ht 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 ar e located in ecologically sensitive areas, raising concerns about the environmental im pacts of production. These concerns continue to emerge and expand.

This report is intended to serve as a tec hnical resource for policy makers, environmental managers, and other stakeholders focused on oi l 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 environm ental performance trends and management challenges; analyzes current and projected pr oduction impact data; offers policy insights into current initiatives; and offers ex amples of environmental stewardship.

Objectives Summarized

This report was produced to assist the EP A Office of Policy, Economics, and Innovation (OPEI) in assessing environmental impacts a ssociated with oil and gas production in Region 8. The report discusses several state, re gional, 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 ag ency deliberations regarding oil and gas production nationally.

Through this analysis, the EPA Sector Strategies Program seeks to provide new knowledge and insights regarding the environmen tal releases associat ed with oil and gas production. The report also iden tifies some of the challenge s associated with acquiring and analyzing relevant environmental impact data. By focusing on key energy development issues and associated production impacts in a strategi cally important and resource-rich region, one that is experien cing unprecedented growth in oil and gas activities, we hope to provide valuable e nvironmental management insights and share them broadly with policy makers, environmen tal managers, and other key stakeholders.

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

Region 8’s Distinctive Oil and Gas Industry Characteristics

The oil and natural gas resources in Region 8 ar e distinct from other reserves located in the United States. Rich in unconventional natu ral 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, northeaste rn Utah, and southwestern Wyoming; shale gas in Montana and Nort h Dakota (e.g., the Bakken Shale); and CBM formations such as the Powder River basin in Wyoming and Montana and the Raton Basin that stretches from Colorado to New Mexico. 1 Significant natural gas resources are steadily gaining increased focus within the region. Representative examples include the tight gas sand formations in the Green Ri ver Basin of northwestern Wyoming and the Piceance Basin of northwestern Colorado. Regi onal increases in oil and gas production are demonstrated by the following statistics:

• In recent years, gas production has increas ed 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 expect ed 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 per cent 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 re present about 13 percen t of national activity. This fraction has increased from 5 percen t in 2000 due to expanding exploration and production in Colorado’s Denver Basi n and the Uinta Basin of Utah.

• Potential recoverable resources in Rocky Mountain tight sands are estimated to be several hundred trillion cubic f eet (TCF) of natural gas, compared to current proved reserves of about 190 Tcf for the United States as a whole. The vast size of the tight gas sands resource base within the region s uggests that extraction activities are likely to expand and continue on for decades to come.

• The Powder River Basin in eastern Wy oming started CBM production in the 1980s, gained prominence in the late 1990s, and cu rrently 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 acidiz ing, to optimize resource extraction. “Coal bed methane” refers to natural gas trapped in underground coal seams that can be extracted before mining the coal (in some cases, the coal seams are very deep or of low quality, in which case CBM is the only hydrocarbon extracted from the seam).
2 U.S. Federal Energy Regulatory Commission (FERC), Natural Gas Markets: Western

, http://www.ferc.gov/marketoversight/mkt-gas/western.asp#prod

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

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

. 4 Based on 2006 data.

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

• A recent report by the Rand Corporation es timated that between 500 billion and 1.1 trillion barrels of oil are t echnically 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 ge nerally require more wells, greater energy and water consumption, and more extensive produc tion 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 characterist ics, oil and gas extraction in the Rocky Mountain region has a somewhat different environmental f ootprint than oil and gas production in other regions, providing an addi tional reason for focusing this analysis on Region 8. Section 2.2 and Appendix A provi de 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 re leases: air emissions, produced water, and drilling waste. Concerns about potential groundwater impacts have surfaced with respect to individual project s in Region 8; however, reported incidents have not proven to be a region-wide trend. Neverthe less, these groundwate r 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.

• 5 The primary air pollutants of in terest are nitrogen oxides (NO x ), sulfur dioxide (SO 2 )

, and particulate matter (PM) as pr ecursors of regional haze, and NO x and volatile organic compounds (VOCs) as precu rsors of ground level ozone. NO x emissions are primarily from production operations and equipm ent such as engines (both stationary and mobile), turbines, and process heaters. VOCs constitute the largest absolute component of regulated emissions, primar ily fugitive emissions including some hazardous air pollutants (HAPs) such as benzene, toluene, ethyl benzenes, and xylenes. SO 2 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) collect ively contributed more emi ssions 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 focuse s mainly on production impacts that occur within the course of normal drilling and resource recovery operations.

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

• In addition to CAA-regulated air poll utants, oil and gas production produces greenhouse gas (GHG) emissions . Fugitive methane (CH 4 ) emissions constitute the largest source of global warming potential-weighted (GWP-weighted) GHG emissions. CO 2 emissions from process heater s were about 206,000 tons and from internal combustion (IC) engines (such as compressors) were about 6.4 million tons in 2006 per our report’s estimate

.

• CBM formations in the Rocky Mountain region initially releas e 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 conventi onal 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. em issions 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 produc tion 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 NO x , CO, and SO 2 contribute approximately 15 percent, 9 percen t, and 4 percent to the regional totals, respectively.

• The report (see Chapter 3, Table 3-7) pr esents air emissions by major source category—point and ar ea—by state. VOCs, NO x , SO 2 , 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 grea ter contributor to emissions than point sources in Region 8 . For NO x and CO emissions, point and area sources both contribute significantly to total emi ssions. The area source fraction is slightly larger for NO x and the point source component is larger for CO. NO x and CO emissions are primarily from large combus tors (point sources) as well as small combustors and mobile sources (area sources).

• PM emissions from the oil and gas industr y in Region 8 are neg ligible, with some data indicating they are less th an 0.1 percent of the regi onal 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 ar eas of concern within Region 8 (and nationally).

• Per the report’s estimating methodology for produ ced water, almost 3 billion barrels of water were produced in Region 8 in 2006, w ith Wyoming contributing approximately

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

71 percent of total produced wa ter (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 fract uring, or “fracing,” the target resource by inject ing water and chemicals into the formation, which can potentially affect groundwater sources.

• Region 8 also produced more than 46 m illion barrels of drilling waste in 2006 (see Chapter 3, Table 3-13). Directly related to increased rig ac tivity, the largest amount of drilling waste was generated in Wyoming , followed by Colorado and Utah. Reuse or disposal of drilling waste, along with furt her disturbance of surface areas due to oil and gas production (e.g., through co nstruction of roads and oper ation of drilling rigs in wilderness and undeveloped areas), are hi ghly visible issues involving industry stewardship and re gulatory oversight.

• Non-governmental organizations (NGOs), C ongressional oversigh t bodies, and other stakeholder groups and citizens have issued studies or scrutinized the environmental implications and potential risks of expandi ng 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 th e oil and gas industry. Each of these organizations has released reports questioning various oil and gas production practices and environmental imp lications. 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 pos e threats to human health and the environment. Under the National Environmental Policy Act (N EPA) 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 it s environmental footprint. For instance, drilling and resource extraction create a number of wastes, such as produced water and drilling waste. Wastes that canno t be reused or recycled must be stored or disposed of in some manner, increasing the land area aff ected by oil and gas ex traction 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 signi ficantly. 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 ta ken steps to reduce the environmental, safety, and health impacts of their operations, there are still environmental concerns that need to be better un derstood and addressed. To re spond to these concerns, it’s important that government, industry, and stak eholders develop a better understanding of where current policy and technology mechanisms are in adequate and where further controls, commitments, and innovations are needed.

U.S. Environmental Protection Agency Working Draft – September 2008 ES--5EXECUTIVE 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 ge nerally 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 expe rtise or resources to maximize potential pollution prevention and environmental ma nagement 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 c ountry). Moreover, the wells are typically spread across thousands of operations, with several distinct sources of emissions and discharges. Nevertheless, the findings in th is report demonstrate that on an aggregate basis, the environmental f ootprint of oil and gas produc tion in Region 8 and other producing regions across the Un ited States is growing a nd deserving of increased focus and attention.

Environmental Policy Issues

• A number of initiatives have been implem ented 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 an d nationally), to voluntary programs and actions. Some of thes e 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 o il and gas development in Region 8 and elsewhere:

• The 2004 Pennaco decision compelled BLM to revise Resource Management Plans (RMPs) to address cumulative enviro nmental impacts stemming from new CBM development proposals and other pend ing energy projects in the region. 6

• BLM and states have been working with western su rface land owners to resolve differences tied to the stewardship of fede ral 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 init iate a rulemaking to revise, as necessary, the effluent limitations guidelines for the Oil and Gas Extraction Point Source Category (40 CFR 435) to control pollu tants discharged in CBM-produced water

. 7

• EPA has reviewed and approved innovativ e CBM waste water treatment residual disposal options that allow injection in to Class II wells, creating better economic scenarios for creating cleaner wate r for surface discharge or aquifer storage

.

6 Energy, Public Lands, and the Environment , Professor Robert B. Keiter, University of Utah S.J. Quinney College of Law, September 2008
7 EPA, Agency Information Collection Activities: Proposed Collection; Comment Request; Coalbed Methane Extraction Sector Questionnaire (New), EPA ICR Number 2291.01, OMB Control No. 2040-NEW http://www.epa.gov/fedrgstr/EPA-WATER/2008/January/Day-25/w1344.htm

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

• Colorado has implemented more stringent VOC emissions standards in response to the state’s rapid increase in oil a nd gas production-related emissions.

• Several regional initiatives focusing mainly on air quality have been established in the past decade, including the Western Regional Air Partners hip (WRAP), Western States Air Resources Council (WESTAR), and We stern Climate Initiative (WCI).

There are a number of additional voluntary in itiatives underway that can continue to grow or be used as models for developi ng collaborative environmental stewardship programs in Region 8. A representative sa mple includes the following programs:

• EPA’s Natural Gas STAR program;

• The Occupational Safety and Health Admi nistration’s (OSHA) Voluntary Protection Programs (VPP);

• The San Juan Voluntary Innovative Strategi es 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 thes e voluntary programs is provided in Chapter 4, Table 4-2.

Potential Next Steps

In spite of the many policy in itiatives, program developments , and industry practices that are now addressing oil and gas environmenta l implications, significant environmental concerns persist. Such challenges won’t be effectively resolved without enhanced communications and the active i nvolvement of government (fed eral, state, and tribal), industry, and stakeholder repres entatives. Moreover, since pr oduction levels are expected to continue their rapid ascent across Region 8, EPA continues to inve stigate 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 re port, specific actions and re sponses will continue to be investigated and pursued by EPA, partne r agencies, industry leaders, and other stakeholder representati ves, as appropriate.

EPA, state and other government agencies are challenged to keep pace with rapidly expanding oil and gas production as well as associated regulato ry activities (e.g., rulemakings, permitting and inspections). In addition, the high volume of oil and gas projects poses unique technica l and regulatory challenges fo r federal and state agencies alike. As such, effective regulatory oversight requires open communications,

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

collaborative partnerships, and constant coordination. Improved environmental measurement, stakeholder involvement, and e nvironmental 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 grea ter regulatory certainty and consistency in oil and gas oversight through enhanced da ta collection and analysis, improved information sharing and partnerships, and focused compliance assistance and enforcement.

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



## 1.0 Introduction

1.1 Objective

EPA’s Sector Strategies Program, within th e Office of Policy, Economics, and Innovation (OPEI), commissioned this analysis to meet the following objectives:

• Facilitate a genera l understanding of oil and gas production, related environmental releases, and associated environmental implications in EPA Region 8;

• Identify policy issues, program initiatives, and stewardship oppor tunities related to regional oil and gas prod uction, focusing on air, water, and land issues;

• Assess environmental releases to air, water, and land resulting from current and projected oil and gas produc tion in the re gion; and

• Lay the groundwork for future action to reduc e 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 include s Colorado, Montana, North Dakota, South Dakota, Utah, Wyoming, and 27 sovereign trib al 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 numb er of ways. Specifically, Region 8 features extensive unconventional natura l gas resources including tight gas sands, shale gas, and CBM.

Unconventional oil and gas resources are loosel y defined as resources that are generally deeper and / or more difficult to recover th an traditional oil and gas resources that have historically been produced in the United States and el sewhere. In particular, unconventional resources include geologic formations that cont ain oil and gas but require advanced recovery techniques due to tec hnical challenges posed by the physical properties of the reservoir (see figure 1-1).

For example, tight gas formations require th e 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 ma terial 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 s ource. Industry is currently investing in new

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

technologies and approaches to test and u ltimately ensure the co mmercial viability of these unconventional resources.

In terms of the potential size of the o il 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 Dir ector 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 Production 9

Developing, producing, and upgrading oil and gas from unconventional resources tends to be more capital-intensive than conventiona l operations. In gene ral, unconventional oil and gas production tends to involve more surf ace disturbances and wells (due to increases in roads and servicing traffic as well as tig hter well spacing, even wh en advanced drilling techniques are employed). Additionally, unconve ntional 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 combin ed to bring more of these resources to market. Environmental technology improveme nts that are reshaping oil and gas production in Region 8 and nationally include green well completions, vapor recovery

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

9 DTE Energy, Conventional vs. Unconv entional Gas Production, http://www.dteenergy.com/businesses/unconventionalGas.html

,. 10 Petroleum Technology Alliance Canada, Filling the Gap: Unconventional Gas Technology Roadmap, June 2006.

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

units, engine upgrades for non-road vehicles , and closed loop dril ling 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 progr ams is included in Table 4-2.

In addition to stimulation t echniques mentioned previousl y, the successful extraction of natural gas from unconventional resources re quires specialized dr illing and completion techniques. Such approaches te nd to generate greater enviro nmental releases than those associated with conventional gas producing techniques. For example, unconventional gas extraction tends to produce grea ter surface disturbances as well as large volumes of produced water. In the development of ti ght gas, typically from impermeable and nonporous formations, significantly more wells are required to produce the same unit of gas that could be produced from conventi onal 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 o il and gas industry’s environmental footprint in Region 8. Neverthe less, 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 habita t, forests, and other natural resources. Production has increased signifi cantly, especially over the past 5 to 10 years. In the future, major contributions to domestic ga s supplies are expected to come from unconventional sources, resulting in extensiv e growth in natural gas exploration and production. Without the necessary control stra tegies and stewardship approaches, this trend could significantly expand the oil and ga s industry’s regional f ootprint. To assess the policy implications of increased oil a nd gas production in Region 8, this report analyzes the sector’s current environmental footprint, identifies environmental issues associated with increased oil and gas produc tion, and provides insights about government and industry efforts to measur e 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 producti on, specifically the ups tream operations associated with the extraction of crude oil and natural gas from wells. It does not include, for example, discussions about pi pelines or petroleum refineries , and the environmental issues and management challenges associated with these energy development activities ( NOTE : An exception includes the air emissions quantities associated with compressor drives that are included in Sections 2.3.1 and 3.1. 1 .). The report also does not address electricity production associated with oil and gas production.

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

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

Policy Issues

Several federal, regional, stat e, and industry initiatives desi gned to address environmental issues in oil and gas produc tion are identified and discusse d 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 r eadily available data to characterize the environmental impacts associated with o il and gas production, both on a national basis and for Region 8 specifically. Appendix C summ arizes our assessment of available data sources, data limitations, and data gaps.

Using the best available industry produc tion 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 Re gion 8 for 2006. More detailed information is provided in Appendix B

.

• The report addresses the following air emi ssions: volatile organic compounds (VOCs), nitrogen oxides (NO x ), carbon monoxide (CO), sulfur dioxide (SO 2 ), carbon dioxide (CO 2 ), hazardous air pollutants (HAPs, such as benzene, toluene, ethyl benzenes, and xylenes), particulate matter (PM), and methane (CH 4 ).

• 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 re spective 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 e nvironmental 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 a nd compiled projections for air emissions, produced water, and drilling waste in 2018 consistent with WRAP’s 2018 emission projection . We describe these projections in some detail in Section C.5 of Appendix C.

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

Next Steps: Opportunities fo r Environmental Improvement

This study identifies options for reducing em issions, wastes, and other environmental impacts from oil and gas production. We id entified these potentia l steps by reviewing current regulatory and voluntary initiatives and placing them with in the context of emerging supply (e.g., unconventional resource s) and environmental control issues.
1.3 Organization of the Report

The major remaining sections of th is report are organized as follows:

• Chapter 2, Background , provides an overview of the i ssues that explain why Region 8 is vitally important to curre nt and future domestic oil a nd gas supplies; highlights the unique characteristics of Region 8, such as its geology and potential for oil and gas production; and introduces rele vant 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 en vironmental footprint and summarizes key environmental issues and rela ted implications of increased oil and gas production. This chapter also highlights a numbe r 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 th e 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 pr ovide future projections of air emissions and other environmental releases.

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

, describes the primary sources of air emissions for each major source category identified in Section B.1 of Appendix B.

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

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



## 2.0 Background

2.1 Importance of Region 8 to Domestic Oil and Gas Production

Oil and gas production has historically been c oncentrated 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 a nd the Mid-Continent Oil region, which extends from Nebraska to Texas. Over the years, U.S. production has predominantly occurred in the Texas-Loui siana 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 re serves have gradually been depleted as domestic demand has risen. While conventional production in traditional areas remain flat or are in decline, new production has sh ifted to other areas rich in unconventional resources, particularly the Rocky Mount ain 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 en ergy resources: coal, natural gas, oil, uranium, and hydropower, as well as geot hermal, wind, and solar. We have enough coal—a 250 year supply—to meet our domes tic demands, but coal does not address our transportation fuel needs and it rais es serious greenhouse ga s issues. We have substantial natural gas reserves and produ ce annually about 19 trillion cubic feet, leaving a 4 trillion cubic feet annual deficit that is bei ng 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 bi ggest shortfall is w ith 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 domes tic oil needs from the public lands, and another 30% from OCS lands. Given the cu rrent policy focus on increasing supply, the public lands have been targeted for acce lerated 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 fede ral 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 perm its 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 [essentiall y] maximize leasing and exploration.” 12

Region 8 has become a major gas-producing ar ea 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 incr eased rapidly; in 2005 these two states accounted for 54 percent of total production in the west and co mprised 15 percent of total

12 Energy, Public Lands, and the Environment , Professor Robert B. Keiter, University of Utah S.J. Quinney College of Law, September 2008

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

U.S. production

. 13 The largest expected growth in dome stic gas production is expected to occur within these two states

. The strategic importance of the resource base within Region 8 lies not only in its large, mostly untappe d supply of oil and natu ral gas, but also in its abundance of other attributes –vast expanses of forests, abundant and diverse wildlife, and several national parks. The region’s natura l diversity and large protected areas, where many unconventional reserves are located, often produces conflicts as energy production continues to expand. Oil and gas regulators pl ay an important role in addressing these conflicts and are charged with managing cumu lative production impacts across the region. 14

2.2 Unique Characteristics of Region 8

2.2.1 Oil and Gas Production

As shown in Figure 2-1, Region 8 includes Colorado, Montana, North Dakota, South Dakota, Utah, Wyoming, and 27 sovereign tr ibal nations. Region 8 encompasses the area generally referred to as the Rocky Mountai n oil and gas provinc e. Environmental characteristics are discussed further in section 2.2.2 and 2.2.3 3 . In addition, some definitions of the Rocky Mountain region al so include northwester n New Mexico, which is the primary location of the San Juan Basin ( NOTE : Although most of the San Juan Basin resides outside of Regi on 8, parts of it extend into Co lorado 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 ch aracteristics of the Rockies, but the eastern areas of both Montan a and North Dakota are part of a separate province called the Williston Basin.

Figure 2-1. EPA Region 8 with Tribal Lands 16

13 U.S. Federal Energy Regulatory Commission (FERC), Natural Gas Markets: Western

,. http://www.ferc.gov/marketoversight/mkt-gas/western.asp#prod
14 U.S. Department of Energy (DOE), E nergy Information Administration (EIA), Natural Gas Pipelines in the Central Region

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

. 15 U.S. Department of the Interior (DOI), United States Geological Survey (USGS) considers the San Juan and Raton Basins, located partially in northern New Mexico, as part of the Rocky Mountain region; see http://pubs.usgs.gov/fs/fs158-02/FS-158-02.pdf
16 U.S. Environmental Protection Agency, Region 8, Mountains and Plains, http://www.epa.gov/region8/tribes/

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

Most Rocky Mountain oil and gas production is found in Colorado, Utah, and Wyoming, and to a lesser extent in Montana, No rth Dakota, and South Dakota. Although oil production is widespread across the region, the Rockies are curre ntly dominated by natural gas production activities. Whereas Fi gure 2-2 shows increas ing gas production in the Rockies from 1998 to 2005, Figure 2-3 shows increased rig activity in Region 8 from 2000 to 2006, a fairly reasonable indicator of expanding natural gas production within the region.

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

0 1 2 3 4 5 6

1998 1999 2000 2001 2002 2003 2004 2005 2006Tcf per Year

California/ Other

East/ Midwest Gulf Coast

Gulf of Mexico

MidContinent

San Juan/ Permian Rockies

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

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

Baker Hughes Monthly Rig Count - Region 8

0 50 100 150 200 250 300

Jan-00 Jul-00 Jan- 0 1 Jul-01 Jan- 0 2 Jul-02
J a n- 03 Jul-03 Jan- 0 4 Jul-04 Jan-05 Jul-05
J an-06 Jul -0

6Active Rigs MT
UT
CO
WY

Conventional oil production has declined natio nally, and current oil production in Region 8 is modest when compared to regional natural gas production. Figure 2-4 shows oil production levels (in million barrels per year) in the Rockies as essentially constant from 1998 to 2005.

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

0 100 200 300 400 500 600 700 800 900

1998 1999 2000 2001 2002 2003 2004 2005 2006Million Barrels per Year

East/ Midwest California/ Other

San Juan/ Permian

MidContinent

Rockies Gulf of Mexico

Gulf Coast

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

Production activity is concentrated in the De nver Basin of eastern Colorado and the Uinta Basin of northeastern Utah. Large oil shale deposits are present in western Colorado, northeastern Utah, and sout hwestern 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 ener gy companies are once again conducting oil shale technology research a nd development (R&D) within the region, the only production of note is currently taking place on a pilot scale. Commercial pr oduction 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 geol ogical characteristics make it very different from other oil and gas producing regions. Some of th ese differences are described below:

• The Gulf Coast and Gulf of Mexico gene rally produce oil and ga s 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 with in 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 s outhwestern 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 assess ed to be in multiple hundreds of trillion cubic feet (Tcf) of gas, comp ared to current proved rese rves 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 Sa n Juan Basin in southwestern Colorado and Northwestern New Mexico, and the Powder River Basin in eastern Wyoming. These CBM production areas ar e 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). Produ ced water is subsequently re-injected for disposal or discharged into surface water, generally after some prior treatment (although some produced water from CBM forma tions can be directly discharged into surface water).

• The Powder River Basin in eastern Wyom ing initiated CBM production in the 1980s, gained prominence in the late 1990s, and cu rrently produces about 1 billion cubic feet (Bcf) of natural gas per day . Surface discharge, where pe rmissible, is a much less expensive option compared to injection; however, surface water discharge can impact

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

surface water quality, contribute to stream bed erosion, and / or render agricultural soils nonproductive du e to high sodium levels . In some instances across Region 8, produced water from natural gas extracti on (e.g., CBM wells) is clean enough to be used for irrigation or watering livestock w ithout 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 previ ously, EPA is actively investigating these issues along with other agency and industry representatives.

• Efforts to develop CBM natural gas resour ces elsewhere in the Rockies, including central Utah and southwestern Wyoming, ar e 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 ot her areas, necessitating either conventional drilling techniques, which requi re 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 ca n result in 8 to 16 times as many wells per area of land than would be required for conventional gas recovery 17 . 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 di sturbances than would have occurred in conjunction with natural gas production from conventional resources. As a result, the growth in CBM and other forms of unconve ntional 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 re sources outside of the vast a rray of fossil fuels found there. The region contains vastly different lands capes—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.). Howe ver, the region is quite arid, and the availability and quality of wa ter has historically been limited. Protection of these natural assets substantively contributes to many of the policy issues surrounding oil and gas production in the region.

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

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

2.3 Key Policy Issues Associated With Oil and Gas Production

Natural gas development across Region 8 has be en the focus of an intense environmental debate, and the complex and contentious i ssues underlying the c onflict are likely to continue for the foreseeable future. To de velop 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 ga s production and potential are administered by the BLM. Conflicts often invol ve energy companies, ranchers, residents, and environmentalists; the issues being deba ted include air and wa ter quality, pollution prevention and controls, land management a nd water rights, wildlife protection, and so forth. Increases in population and workforce is sues have also fueled concerns over the impacts of oil and gas development in areas such as the Roan Plateau in Colorado 18 , and Pinedale, Wyoming 19

.
The combined, incremental effects of oil and gas production – in combination with other human activities – can pose threats to huma n health and the environment. Under the NEPA statute and associated guidance docum ents, 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 th emselves, cumulative impacts accumulate over time, from one or more sources, and can result in the degradation of important resources. Because federal projec ts cause or are affected by cumulative impacts, this type of impact must be assessed in documents prepared under [NEPA] ... the assessment of cumulative im pacts in NEPA documents is required by Council on Environmental Quality (CEQ) regulations (CEQ, 1987). Cumulative impacts, however, are not ofte n fully addressed in NEPA documents due to the difficulty in understanding the co mplexities 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 activ ities in Region 8 and elsewhere. With respect to current oil and gas projects, regulators and devel opers are considering additional mitigation measures (e.g., phased development) that are – or may soon be – needed to reduce emissions and other environmental impacts consis tent with federal and state regulations.

When oil and gas production o ccurs, there are other indus tries and human activities producing environmental impacts within a co mmon area. In reviewing proposed oil and gas development activities and projected sc hedules, EPA and other government agencies

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

, accessed August 21, 2008.
19 U.S. Environmental Protection Agency, Region 8, Final EPA Comments on Pinedale Anticline, February 2008
20 ‘Consideration of Cumulative Impacts in EPA Review of NEPA Documents.’ U.S. Environmental Protection Agency, Office of Federal Activities (2252A) - EPA 315-R-99-002/May 1999 (http://www.epa.gov/compliance/resour ces/policies/nepa/cumulative.pdf)

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

with oversight respons ibilities must consider the cumu lative 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, contro l measures, etc.), or other measures to reduce uncertainty and lessen current or pot ential environmental impacts over time.

The following discussion summarizes primar y policy issues related to oil and gas production in the following three categories: ai r, water, and land use. In addition, we summarize industry actions to address environmen tal issues related to their respective oil and gas operations.

2.3.1 Air Issues

Under the Clean Air Act (CAA) states have the primary responsibility to address airrelated impacts from energy development. States are required under the Act to maintain - or come into attainment with - Nation al Ambient Air Qualit y 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), gr ound-level ozone, carbon monoxide, sulfur oxides, nitrogen oxides, a nd 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-leve l 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 envir onmentally-based criteria (i.e., science-based guidelines) the agency develops in setting permissible levels . Primary standards are limits based on human health criteria whereas seconda ry standards are thre sholds intended to prevent environmental and property damage

. Air emissions associated with oil and gas pr oduction can significantl y 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 s ources, are regulated by the Clean Air Act (CAA) and can be grouped into three categories:

• Criteria air pollutants (ozone, CO, SO 2 , PM, and their precursors, including NO x and VOCs );

• Hazardous air pollutants 21 (HAPs, primarily fugitive VOC emissions from oil and gas production);

• Haze precursors (which include ozone , NO x , SO 2 , and particulates); and In addition, greenhouse gase s (GHGs, which include CO 2 and CH 4 ) are generated during oil and gas development. EPA issued an advance notice of proposed rulemaking (ANPRM) in July 2008 considering possible GHG emission regulation under the Clean

21 EPA is currently required to control 187 HAPs.

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

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 operati ons have been at the forefront of these regional efforts. Most air policy-related activit ies relevant to the oil and gas industry in Region 8 fall into one of three areas:

• Regulation of industrial emissions under fede ral law and implementation of new, more stringent state-level programs;

• Participation in voluntary regional in itiatives 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 compre hensive federal law that regulates air emissions from all sources, including area, stationary, and mobile sources. Most air policy issues related to oil and gas produc tion are determined by the way associated operations are regulated under the CAA. Air regulations are implemented and enforced by individual states through their Stat e Implementation Plans (SIPs) and through permitting activities that draw directly on EP A implementation of the CAA. In addition, the BLM is responsible for management a nd conservation of federal surface lands and mineral rights within its purvi ew and controls air emissions from federal lands working in cooperation with EPA and other government agencies

. As is the case with air pollu tion regulation throughout the rest of the U.S., states within Region 8 develop and implement regulatory co ntrols 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 emissi ons and other forms of pollution from these

sources

. 22 Several groups have recommended th at the federal government should establish more stringent cont rols on oil and gas production. For example, environmental groups have called for emissions limits and othe r national standards that states can build upon and even exceed should additional controls be deemed necessary.

This section examines regulation and enfor cement concerns under three federally-based standards: the National Ambi ent 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 Qu ality Standards (NAAQS) . Under the CAA, NAAQS establish health-based ambient standards for regulating cr iteria pollutants. States are responsible for demonstrating how they will meet the NAAQS through thei r SIPs. Although most of

22 Environmental groups have questioned government efforts to adequately regulate the oil and gas industry. The Natural Resources Defense Council report, Drilling Down: Protecting Western Communities from the Health and Environmental Effects of Oil and Gas Production , October 2007, http://www.nrdc.org/land/use/down/down.pdf , presents many of these

concerns.

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

Region 8 is in attainment with these sta ndards, 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., exceedence s of 8-hour ozone st andards). In addition, NO x and VOCs from regional oil and gas oper ations 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 emissi ons. 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 atta inment 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 mode rate nonattainment for PM standards and a couple of areas in nonattainment for SO 2 . Montana has released several State Implementation Plans (SIPs) to control fine pa rticulates in certai n areas of the state and is waiting to be redesignated.

• Utah had two areas in nonattainment for SO 2 emissions which are now meeting the standards. Utah has severa l areas still in moderate nona ttainment for PM standards, while Wyoming has one area.

In contrast, North Dakota and S outh Dakota are presently in a ttainment with all relevant NAAQS

. On March 12, 2008, EPA significantly strengthened its NAAQS for ground-level ozone. EPA revised the 8-hour "primary" ozone standa rd, designed to protec t 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 o il and gas development may well be impacted by the new ozone standard. In addition, Sout hwest 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 an d 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 environmenta l requirements and maintain or improve environmental quality with respect to energy projects; 3. Promote energy efficiency and renewable energy; and

23 VOCs are regulated as precursors to ozone.

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

4. Strengthen environmental and energy part nerships with co-regulators and other stakeholders.

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

New Source Performance Standards and Nati onal 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 devel oped 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 e ngines used in oil and gas pr oduction: NSPS for Stationary Spark Ignition Internal Combustion Engines (ICE), and National Emission Standards for Hazardous Air Pollutants (NESHAP) for Reci procating Internal Combustion Engines (RICE). Categories of activities that use thes e types of engines a nd may be subject to regulation include natu ral gas transmission, crude petrol eum and natural gas production, and natural gas liquids producers. Recently promulgated NSPS ru les will regulate NO x , CO, and VOC emissions, whereas the NESHAP regulations will control formaldehyde, CO, or VOC emissions, depending on which em issions 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 a nd operating permits from the appropriate permitting authority, usually the state air agen cy. Permits to constr uct are issued under New Source Review (NSR) for air emissions sources located in NAAQS nonattainment areas, and under Prevention of Significant De terioration (PSD) in NAAQS attainment areas (the program is often collectively refe rred to as PSD/NSR or simply NSR). These air permits ensure that sources of criteria air po llutants do not cause or contribute to violations of the NAAQS. Smaller, “minor” s ources 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 enab le 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 additi on, 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 th e Energy Policy Act of 2005 (EPAct), EPA entered into a Memora ndum of Understanding (MOU) with DOIBLM, the U.S. Department of Agriculture (USDA), and the U.S. Department of the Army. This MOU seeks to focus agency efforts to effectively streamline federal permits. The underlying goal is to enhance efforts to pr ocess oil and gas use authorizations while maintaining environmentally responsible mana gement of federal lands where oil and gas resources are located.

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

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 inve stigating oil and gas i ndustry violations of air quality standards and seek ing to project future emissions from energy development. The study is paying close attention to oil and gas production within the Uinta Basin

, 24 and BLM plans to use the data to determine the best ways of reducing emissions from wells, compressors, storage tanks, and other equipment. For example, BLM may consider incorporating certain technology controls and other permit requirements that would decrease certain air pollutants, such as NO and PM, commonly associated with production operations. x

EPA is also successfully implementing an M OU 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 deve loping the states’ oil and gas resources. Through I OGCC, 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, a nd environmentally responsible ways. In some instances, states and EPA have concurrent ju risdiction relating to a host of oil and gas regulatory efforts. In other instances, the states and EPA have i ndependent authorities that may be complementary when eff ectively coordinated. The EPA-IOGCC MOU focuses federal and state environmental ove rsight 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, increasi ng efficiencies and communication, and enabling the exchange of information and expertise. Lastly, the MOU identifies mutual issues of concern as well as mutually benefi cial joint activities, and creates a permanent means of consultation between EPA and the IOGCC

. Voluntary Regional Initiatives

To improve air quality beyond federal requir ements, a number of regional organizations have been formed in the western states to address air pollution concerns. These organizations include the West ern Regional Air Partnership (WRAP), Western States Air Resources Council (WESTAR), and Western Clim ate Initiative (WCI). Brief descriptions of each are provided below.

Western Regional Air Partnership . Formed in 1997, WRAP 25 is a collaborative and essentially voluntary effort involving stat e and federal agencies for the purpose of providing regional planning, etc. for SIPs seeking to improve visibi lity in western areas, primarily by providing the techni cal 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 succe ssor to the Grand Canyon Visibility Transport

24 Oil and gas development is expected almost to double in Uint a County in the next few years. About 10,000 new wells are either planned or already being dev eloped in the county; almost 6,000 wells are currently in production. See Red Lodge Clearinghouse, BLM moves to reduce air emissions from energy development in Uinta Basin , February 2008, http://rlch.org/content/view/344/62/

. 25 For more information on WRAP, see http://www.wrapair.org/

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

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 cont ributions is the Emissions Forum, which oversees a comprehensive tracking and for ecasting system, called the Emissions Data Management System (EDMS). Policy makers us e EDMS to assess and address air quality issues. For example, EDMS data are used fo r 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 emissi ons trends associated with oil and gas production.

Western States Air Resources Council . Another voluntary gro up 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 di scuss air quality issues in the west. For example, in September 2007, WESTAR hosted a conference focused on oil and gas development issues that highlighted seve ral BMPs to reduce oil and gas production emissions

. Representative BMPs discussed during the conference included installing vapor recovery units on storage tanks, installing fuel recovery systems and static packs to reduce venting at compressor stations, testing for fugitive emissions through leak detection and repair (LDAR), and repairing or replacing pressure safety valves and other equipment or piping where fugitive emissions tend to originate. 28

Western Climate Initiative . The purpose of the WCI is to help participatin g organizations reduce GHG emissions in the west. WCI 29 was formed in February 2007, when the governors of Arizona, California, New Mexi co, 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 Wyom ing 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 stakehol der comments about the potential design and implementation of a regional cap-and-t rade program focused on reducing GHG emissions.

2.3.2 Water Issues

Another major policy challenge related to oi l and gas production involves water sources, competing uses and demands, and associat ed conflicts. Unconventional natural gas resources (e.g., tight sands, shale gas, et c.) generally require higher water use than conventional gas extraction. In addition, CBM formations in the Rocky Mountain region

26 The RHR seeks to improve visibility in 156 national parks and wilderness areas throughout the United States, but located primarily in the west. See http://www.epa.gov/oar/visibility/program.html for additional information on EPA’s Regional Haze Program.
27 For more information on WESTAR, see http://www.westar.org/index.html

. 28 An agenda and presentation materials from the Sept ember 2007 WESTAR conference can be accessed at http://www.westar.org/Docs/Tech%20Confs/Oil-Gas%2007/agenda.doc

. 29 For more information on WCI, see http://www.westernclimateinitiative.org/

.
U.S. Environmental Protection Agency Working Draft – September 2008 2-13BACKGROUND

release large amounts of produced water, whic h is released to th e 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 sc arce regional water resources.

The Powder River Basin produces natural ga s 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 reso urce. 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 relati ve to the volume of water produced by CBM development, producers must find other opt ions. In addition, although deep injection protects surface waters, potential beneficial uses of CBM produced water are sacrificed. The high costs associated with drilling a nd 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 w ithout 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 usag e in the region, as well as evolving federal water policy, only add to th e complexity of the underlying issues and inevitable conflicts that arise. The follo wing discussion addresses these main water issues:

• Water discharges governed by regulations promulgated under the Clean Water Act (CWA) and Safe Water Drinking Act (SDWA);

• State limits on produced water and associated issues (e.g., state water rights); and

• Water contamination from storm water runoff and oil spills.

Federal Water Regulations

Produced water from oil and gas operations is, by volume, the largest waste stream associated with oil and gas production. The content of produced water typically varies depending on the geographic location of the field, the type of hydrocarbons being produced, and other features a ssociated with the geology an d 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 ir rigation or watering liv estock 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 guidelin es under CWA and SDWA, and these issues are discussed in more detail below

.

U.S. Environmental Protection Agency Working Draft – September 2008 2-14BACKGROUND

Clean Water Act . CWA requires EPA to establish na tional, technology-based regulations, known as effluent limitations guidelines (ELGs) , designed to reduce po llutant discharges from categories of industry discharging dire ctly to U.S. waters. These guidelines are implemented through National Pollutant Di scharge Elimination System (NPDES) permits. Effluent guidelines a pply to facilities engaged in field exploration, drilling, and well production in offshore, coastal, and onshor e areas. There are effl uent guidelines for petroleum refining discharges as well, but thes e matters are not examined in this report, which focuses on upstream oil and gas production issues.

Produced water from CBM wells is not cu rrently regulated under federal effluent limitations guidelines developed to address the potentially un ique characteristics of these production operations. With the rapid grow th 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 depth 30 . In 2003, the U.S. Court of Appeals for the Ninth Circuit ruled that water discha rges 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 Circ uit Court of Appeals remand ed to the agency its 2006 rulemaking responding to language in the Energy Policy Act of 2005. Specifically, through this action, the Ninth Circuit Cour t of Appeals has raised questions and uncertainty regarding the extent to which oi l 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) initia ted the aforementioned study of CBM operations. Once the agency’s industry surv ey and study process is complete, EPA may choose to conduct further analyses, take no fu rther action, or initiate a rulemaking to develop new orrevise existing effluent guidelines to include water discharges from these operations. EPA is expected to comple te 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 focu ses on all waters actually or potentially designated for drinking. Environm entalists, health advocates , and the public have called attention to exemptions for the oil and gas industry, incl uding those related to the SDWA

. 32 Nevertheless, with respect to oil and gas production, EPAct significantly amended SDWA in the following fundamental ways:

• First, hydraulic fracturing operations, also referred to as “fracing” or “fracking,” are used to improve gas flow for unconventiona l resources and exempt ed from regulation under SDWA. 33

30 U.S. Environmental Protection Agency, EPA’s Clean Water Act Review of the Coalbed Methane Industrial Sector, June 2007, http://www.epa.gov/guide/304m/2008/cmb-slides.pdf , accessed 08.19.08.
31 The Ninth Circuit Court of Appeals Decision in NRDC v. EPA and its Impact on Storm Water Permitting of Oil & Gas Activities in Pennsylvania Oil & Gas Alert, by Kenneth S. Komoroski

, Michael J.R. Schalk . June 30, 2008, http://www.klgates.com/newsstand/Detail.aspx?publication=4661

, 32 Oil and Gas Accountability Project, Our Drinking Water at Risk: What EPA and the Oil and Gas Industry Don’t Want Us to Know About Hydraulic Fracturing , April 2005, http://www.earthworksaction.org/pubs/DrinkingWaterAtRisk.pdf

. 33 Fracking fluids may contribute to water contamination sinc e they contain hazardous materials such as gels, polymers, biocides, fluid loss agents, thickeners, enzyme breakers, acid breakers, oxidizing agents, friction reducers, and surfactants.

U.S. Environmental Protection Agency Working Draft – September 2008 2-15BACKGROUND

• Second, EPAct calls for voluntary discontinua nce 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 provi sions have stated that they contribute to drinking water contamination. Some environmentalists and legi slators 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 chemical s may be injected underground or spilled during drilling and / or ‘hydrofracing’ operations ... If any of these 65 chemicals were emitted or discharged from an indus trial 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 i nvestigate these issues. However, other stakeholders are raising ques tions about potential groundwater and human health impacts stemming from hydraulic fracturing practices. Cl early, 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 fract uring. EPA released its findings in 2004, concluding there were no confirmed cases of drinking water contamin ation 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, M ontana, and Wyoming, have been delegated the authority to issue discharge permits to control produced wate r, and differing state policies have resulted in some disputes. CBM operations that surface discharge produced water in Colorado typically have to apply for discharg e 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 dr ainage 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 Drin king Water by Hydraulic Fr acturing of Coalbed Methane Reservoirs , EPA 816-R-04-003, 2004, http://www.epa.gov/safewater/uic/pdfs/ cbmstudy_attach_uic_exec_summ.pdf

.
U.S. Environmental Protection Agency Working Draft – September 2008 2-16BACKGROUND

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 pr oduced varying degrees of conflict within Region 8. For example, in 2006, Montana adop ted water quality standards setting new limits on CBM water discharges into severa l water bodies, including the Tongue River, Powder River, and their tributaries. The ri vers 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 Wy oming 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 Mont ana’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. Additi onally, 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 Ri vers, and that litig ation is ongoing.

Tribal Limits

Region 8 has approved four tribes to implemen t Clean Water Act water quality standards. The confederated Salish and Kootenai Tribes of the Flathead Reserv ation 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 regu late certain stormwater discharges containing sediment from oil and gas construc tion sites in the 1990s, EPAct resulted in a policy shift. In 2006, EPA responded to th e 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 disc harges except in very limited instances. EPA’s rulemaking is consistent with EPAc t and encourages voluntary application of BMPs for construction activities associated with oil and gas field activities. The EPA rulemaking also encourages oil and gas pr oduction operations to minimize erosion and control sediment to protect surface water quality. However, as mentioned previously, a federal appellate court deci ded 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 ot her undesirable consequences if they are not contained and subsequently migrate from flowlines, gather ing 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 we re approximately 924

U.S. Environmental Protection Agency Working Draft – September 2008 2-17BACKGROUND

oil and gas industry spills in Co lorado over a 4-year period (2002—2006 ). 36 In addition, over that same period, 20 percen t of all oil and ga s 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 th at can have a deleterious environmental impact. Although this report, as previously mentioned, does not present data and findings relevant to fuel spill impacts, con centrations, and volumes, they are important issues and a focal point for o il and gas regulatory oversight.

2.3.3 Land Use Issues

Co-Regulator Efforts Around Land Use: Oil and Gas Environmental Assessment In1996, Region 8 and U.S. Fish and Wildlife Service (FWS) Region 6 formed a partnership to assess oil and gas waste management issues impacting production and related sites. Originally referred to as the Problem Oil Pit (POP) effort, the name was changed to Oil and GasEnvironmental Assessment (OGEA). Coregulators participating in the effort included state oil and gas agencies and environmental agencies, tribal energy and environmental agencies, BLM, and the U.S. Bureau of Indian Affairs (BIA). Particip ants 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 recommendationsfor future action, and examined how coregulators and the regulated community can ensure lasting environmental benefits from this effort. Oil and gas production in Region 8 contributes to a number of land use issues 37 . 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 indus trial activities;

• Treatment of drilling waste; and

• Separation of surface and mineral rights.

Surface Disturbance . Extraction of unconventional resources such as tight gas and shale gas, which are abundant in Region 8, can cause a greater surface disturbance than production of conventional gas resources. As previously stated, more wells are required to produce unconventional natural gas due primarily to the lower porosity of the formations where the resources reside. However, certain extraction techniques have been

36 Oil and Gas Accountability Project, Colorado Oil and Gas Industry Spills: A Review of COGCC data (June 2002-June 2006)

, http://www.earthworksaction.org/pubs/Spills.pdf

. 37 U.S. Environmental Protection Agency, Report of the Oil and Gas Environmental Assessment (OGEA) Effort 1996- 2002, January 2003.

U.S. Environmental Protection Agency Working Draft – September 2008 2-18BACKGROUND

developed to reduce the total area of surf ace disturbance and partially offset this requirement.

For example, horizontal drilling techniques ar e widely used to access and produce natural gas from such low permeability formations in Region 8 and else where (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 pr actice is another environmental concern. In addition, although not the focus in Region 8 , oil and natural gas production can contribute to land subsiden ce 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, Uta h, Colorado, and 27 tribal nations ( NOTE : The Western Regional Air Partnershi p (WRAP) consists of the si x states of Region 8 plus Washington, Oregon, California, Idaho, New Mexico, Arizona, Nevada, and Alaska .)

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

Impacts on Wildlife . Wilderness areas across Region 8 in creasingly must coexist with oil and gas production. Heavy-duty trucks and roadways used for fuel production and transportation contribute to noi se and air pollution in unde veloped areas. In addition, drilling activities are reportedly impacting wi ldlife habitat and some animal species that reside within these public lands. For exampl e, the Rocky Mountain Front Range ranks in the top 1 percent of U.S. wildlife habitat a nd has a number of native big game animals

U.S. Environmental Protection Agency Working Draft – September 2008 2-19BACKGROUND

that need a large home range to thrive

. 38 Studies have raised con cerns that new roadways and expanding drilling operations disrupt mi gration, habitat, and wintering grounds for certain species. Heavy-duty trucks a nd roadways used for fuel production and transportation contribute to noi se and air pollution. Some environmentalists

cited , residents, wildlife experts, and others resist further o il and gas exploration in Region 8, and surface disturbance and wildlife impacts caused by ro ad development and dr illing operations are among the leading issues

. Treatment of Drilling Waste . Drilling waste is another key issue, and environmental groups and other stakeholders ha ve raised concerns regardin g 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 propert ies and performance of drilling muds and fluids. Such drilling waste accounts for the se cond largest amount of waste derived from oil and gas production (second to produced wate r). Certain methods ha ve been adopted in recent years to reuse and/or reduce drilling wast e as well as to diminish the toxicity of various drilling waste; neve rtheless, benefits have of ten not been realized.

To reduce their drilling footprints, some producers have developed methods to reuse nontoxic drilling waste or treat toxic wast e compounds. For example, certain drilling waste is being processed and converted into a low-cost substitu te for construction aggregate. Another method involves the subst itution 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 system s that eliminate the dumping of waste byproducts into an open pit. This approach can be expensive but has proven effective in reducing drilling waste, associat ed water use, and truck traffi c for shipping wastes offsite to a treatment facility.

Overall, these practices seek to reduce th e 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), a nd 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 spl it estate lands. Split estate lands refer to those lands on which private parties own the surface a nd the federal government owns subsurface minerals. Under U.S. law, the government’s mineral rights supers ede those of private parties. Problems have surfaced with thes e 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 ge nerate royalties (for the U.S. Treasury as well as states).

38 Joel Connelly, National Wildlife Federation, Frontal Assault , Aug/Sep 2004, vol. 42 no. 5, http://www.nwf.org/nationalwildlife/article.cfm?issueID=69&articleID=959

. 39 EPA Region 8, Oil & Gas Beneficial Reuse Summary, Region 8 E&P Report

.
U.S. Environmental Protection Agency Working Draft – September 2008 2-20BACKGROUND

BLM is the principal government agency re sponsible for management and conservation of federal surface lands and mi neral rights. Most of the la nd 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 cri ticized for advancing agency priorities that sup port increased domestic fuel production without adequately addressing competing needs. P ublic disapproval has involved cl aims of decreased efforts in inspection and enforcement, thus harmi ng public lands as well as privately owned surface rights. Opponents of oil and gas pr oduction claim that BLM has supported rapid industry development, thereby enabling eros ion, adverse impacts to water quality and wildlife habitat, and a wide ra nge 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. S uggestions compiled by BLM include educating surface owners and operators of th eir rights, involving surface owners in the land use planning process, and notifying surf ace owners of surf ace-related compliance issues that could affect their property value.

Industry has also acted to address public concer ns regarding environm ental 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 poten tial future directions

. 40 Rocky Mountain residents provided mixed responses re garding 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 expa nd within Region 8, so too do the number of public health concerns surfaced by local re sidents 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 ha ve articulated concerns about exposure to unhealthy ozone levels that have been r ecorded in the Green River Valley. Although public health impacts of oil a nd 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 i ssues 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 highl ights 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 w ithin the context of this report. In short, with a growing worldwide economy that requir es 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 Secu rity: The Shell Final Report

, http://www.shell.com/static//usa/downloads /energy_security/pdf/shell_final_report.pdf

U.S. Environmental Protection Agency Working Draft – September 2008 2-21BACKGROUND

consistent with ones articulated in the 2007 National Petroleum Council report 41 . Clearly, regional efforts to control fossil fuel em issions more effectively—ranging from GHG cap-and-trade programs to carbon capture and sequestration—will be necessary as production and other fossil fuel activities c ontinue 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 a dverse 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 extrac tion within the Rocky Mountain region is occurring . In addition to oil and gas, other fossil fuels, and nuclea r power, increased development of renewable energy sources - such as hydropower, solar, a nd wind resources – in Region 8 is likely. Coupled with an increased focus on energy efficiency and resour ce conservation, the successful development of diverse sources of energy is absolutely essential to U.S. energy security. As such, an open and collaborative effort w ill be required between all parties to provide for better stewardship of oil and gas resour ces—across Region 8 and the nation as a whole

.

41 National Petroleum Council, Facing the Hard Truths About Energy , http://www.npchardtruthsreport.org.

U.S. Environmental Protection Agency Working Draft – September 2008 2-22ENVIRONMENTAL RELEASES



## 3.0 Environmental Releases

3.1 Data Sources and Assumptions

As noted in Section 1.2.2, we ch aracterized the environmental re leases associated with oil and gas production in 2002 and 2006, focusi ng on air emissions as well as produced water and drilling waste. Development of th e 2002 data set is documented in Appendix C; these data were then used with other sour ces 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 mu ch 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 envir onmental 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 info rmation source underpinning our analytical assessment of air em issions associated with oil and gas production in Region 8. The WRAP estimates of air emissions for 2002 42 are well documented and appear to be the best available given the oil and gas produc tion environmental impact data limitations previously referenced. Specifically, air emi ssions data obtained from WRAP include estimates of NO x , SO 2 , VOCs, CO, particulates, ammonia (NH 3 ), and hydrogen sulfide (H 2 S).

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 “maj or” or “minor” for pollutants, based on the potential or permitted air emissions, and it defi nes “area source” as a stationary source of air pollution that is not majo r. WRAP’s categorization of point sources most closely correlates to major sources of air pollution, but could potentially incl ude minor sources as well. Note that WRAP’s categorization of area sources could include certain mobile sources that effectively function as stati onary 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.

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

Other main assumptions for the WRAP 2002 inventory are described below:

• For point sources:

– Original estimates of point source air em issions are based on data collected from states and local agencies (through the Na tional 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 NO x 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 NO x is used for point sources; in other states, the threshold is greater than 2 tons. 43

– The WRAP database is the region’s mo st comprehensive source for criteria pollutant emissions data; however, data for some of the important fields, specifically those pertaining to produc tion and throughput, are not available.

– Not every well or producing f acility will have enough emissions to be classified as a point source. Therefore, the WRAP emissions estimates from smaller stationary sources are grouped toge ther in the area source category.

– Another limitation of our analysis is that production within tribal lands is not captured. Although there were data in th e WRAP database, the relevant state locations were not identified. Due to the relatively modest co ntribution 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 NO x , VOC, and SO 2 emissions from larger sources. As such, not all air pollutants from oil and gas sources are included.

– For NO x and SO 2 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 dehydr ators, gas well completion flaring and venting, and controlled as well as uncontrolled c ondensate tanks.

43 For example, Colorado has by far the greatest number of poi nt 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.

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

• Due to limitations associated with environm ental data from tribal lands previously referenced, area source emissions for produc tion are excluded. Although it is possible that state data would include tribal da ta, there is no confirmation available.

• Regarding CO 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 leas e and plant consumption data, which help to quantify CO 2 emissions. Specifically, natural ga s lease and plan t is recovered natural gas used as fuel for various oil and gas extraction operations and natural gas processing equipment. CO 2 emissions were then calcu lated 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 extrac tion 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 info rmation sources, Lasser, Inc. and IHS, Inc., respectively. Lasser is the oldest U.S. source of oil and gas production data . Similarly, I HS is a global provider of information produc ts and services, providi ng critical insights into oil and gas production, energy, and ot her key industries since 1959. These are privately managed databases, and their inform ation is largely based on data reported by industry to the states for ta xation and royalty purposes. They are widely used by industry and government to characterize oil and ga s 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 disaggreg ate 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 Practic es 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 combina tion 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 an alyzed 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 ga s drilling activities. Re gional estimates for

45 Note: API emission factors from the reference guide ment ioned above are generally believ ed to be the best available.

U.S. Environmental Protection Agency Working Draft – September 2008 3-3ENVIRONMENTAL RELEASES

2006 are based on this extrapolation and augmen ted by production-relate d trends data as well as relevant EIA data sources. However, due to data limitations regarding individual production operations within Region 8, no sp ecific assumptions or calculations were made to capture possible operator adjustments to oil and gas proce sses (e.g., installation of emissions control devices) between 2002 and 2006. In addition, no adjustments were made to incorporate changes in federal a nd 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 investigat e and analyze them, were limited.

In spite of the limitations, the 2006 estimates help to illustra te 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 th e 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 CO 2
. To develop the CO 2 emissions projections (out to 2006), we us ed industrial production indices (or growth factors) provided by th e Federal Reserve Board (FRB) by relevant North American Industry Classification Sy stem (NAICS) codes. In addition, we augmented these projections with EIA statis tics 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, NO x , CO, SO 2 , NH 3 , H 2 S, all PMs Extrapolated 2002 to 2006 using oil and gas production by state. Data source: EIA

Air Emissions: CH 4 Extrapolated 2005 to 2006 using oil and gas production and gas processing data by state. Data source: EIA Air Emissions: CO 2 Extrapolated 2002 fuel (except natural gas lease and plant) consumption to 2006 using FRB Industrial Production Indices for the following NAICS: NAICS 211111 (Crude Petroleum and Natural Gas Extraction), NAICS 211112 (Natural Gas Liquids Extraction), NAICS 213111 (Drilling Oil and Gas Wells), and NAICS 213112 (Support Activities for Oil and Gas Extr action Operations). Note that FRB data are only at the national level. For natural gas lease and plant, extrapolated 2002 to 2006 using the EIA national estimate of natural gas lease and plant. Data sources: FRB, EIA Produced Water Used Lasser and IHS produced water estimates for 2006. Drilling Waste Extrapolated 2002 to 2006 using API drilling activity data by state. Data source: API

U.S. Environmental Protection Agency Working Draft – September 2008 3-4ENVIRONMENTAL RELEASES

3.2 Estimated Air Emissions: Compar ing 2002 Baseline to 2006 Estimates

Section 3.2 presents air emissions estimat es for 2002 and 2006, respectively, providing insights into the growing signi ficance 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 indus trial categories and s ources within Region 8. From these data, one can see that VOCs 47 from oil and gas production account for nearly 40 percent of total emissions in Region 8. NO x is another significant challenge, as production-related emissions represent almost 15 percent of the regional total.

From 2002 to 2006, regional oil and gas producti on 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 stak eholders are voicing concerns that increasing VOC and NO x emissions from production operations will substantively contribute to expanding ground-le vel ozone and regional haze issues. These concerns have resulted in new regulations to limit NO x and other emissions from oil and gas production sources (e.g., Federal NSPS regulations, Colorado’s new NO x , CO, and VOC regulations for the oil and gas industry).

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

Pollutant Emissions From Oil and Gas Sector Total Region 8 Emissions Oil and Gas Emissions as Percentage of Regional Emissions VOCs 262,953 651,580 40.4% NO x 87,130 587,942 14.8% CO 37,880 413,990 9.2% SO 2 18,385 503,041 3.7% PM 834 2,172,255 <0.1%

Table 3-3 shows total criter ia pollutant emissions from oil and gas production in 2002 grouped by state and pollutant. Wyoming has th e 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 NO x , CO, and SO 2 . The PM emission estimates are not very reliable du e to limited data and va riable 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 availa ble from WRAP are “PM10_PRI ” (PM10 primary emissions, the sum of filterable a nd condensable particulates). Note that particulate emissions were not available for three states: Montana, No rth Dakota, and South Dakota. As discussed in Appendix C, Sections C.2.2 and C.2.3, emissions from sources in these states may be

46 Note: Numbers in associated tables in this section may not add due to rounding.
47 Although EPA does not list VOCs as one of the six criteria pollutants, they are referenced in this section due to their role as a precursor to ozone, a listed criteria pollutant.

U.S. Environmental Protection Agency Working Draft – September 2008 3-5ENVIRONMENTAL RELEASES

too small on an individual basis to be includ ed in the point source category. In addition, the WRAP data collection project initiated in 2005 to expand the criteria pollutant inventory did not include particulates, leaving data gaps for those states

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

Pollutant CO MT ND SD UT WY Total VOCs 90,683 5,502 7,805 288 36,537 122,138 262,953 NO x 45,960 7,761 7,571 361 5,108 20,369 87,130 CO 20,720 1,183 798 11 2,443 12,725 37,880 SO 2 220 227 2,882 6 1,590 13,460 18,385 PM10_PRI 384 0 0 0 16 9 408

Table 3-4 shows total criteria pollutant emissions from production in 2006 increased by 24 percent from the 2002 baseline. Production em issions in Montana increased by almost 75 percent, while emissions in Colorado in creased by almost 28 percent. The fastest growing criteria pollutants are NO x and PM10_PRI, which are projected to increase by 28 percent and 27 percent, respectively, over this 4-year period.

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

Pollutant CO MT ND SD UT WY Total VOCs 115,517 9,596 9,596 302 45,472 142,383 322,865 NO x 58,546 13,536 9,307 378 6,358 23,745 111,870 CO 26,395 2,064 980 12 3,041 14,834 47,326 SO 2 281 396 3,544 6 1,978 15,691 21,895 PM10_PRI 489 0 0 0 20 10 519

Table 3-5 shows non-criteria pollutant po llutants, GHGs, and HAPs by state in 2002. When methane emissions are weighted by their global warming potential (GWP ), 48 CO equivalent methane emissions represent the largest non-criteria po llutant emissions (at over 10 million tons). While these emi ssions are not currently regulated, GHG regulations are being developed within the region, from indivi dual states to the WCI, and some industry companies are taking proactiv e measures to find ways of reducing GHG emissions. In fact, BP America receiv ed the 2007 IOGCC Na tional Environmental Stewardship Award for their project to reduce GHG emissions by challenging the conventional wisdom of standard practices associated with well venting By comparison, HAP emissions are much smaller and are primarily VOCs. 2

. 49

Table 3-6 shows non-criteria pollutant po llutants, GHGs, and HAPs by state for 2006. From 2002 to 2006, CO 2 emissions increased an estimated 32 percent, HAP emissions grew by 19 percent, and CH 4 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, th e only state in Region 8 to do so.

48 GWP is a measure of how much a GHG is expected to contribute to global warm ing. In the case of methane, GWP is approximately 21 times the global warming contribution of CO 2 (whose GWP is, by definiti on, 1) measured over a 100- year timeframe.
49 http://www.iogcc.state.ok.us/iogccs-2007-c hairmans-stewardship-award-winners-are

U.S. Environmental Protection Agency Working Draft – September 2008 3-6ENVIRONMENTAL RELEASES

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

Pollutant CO MT ND SD UT WY Total CH 4 (CO 2 equivalent) 3,216,621 410,513 591,147 37,543 893,226 5,217,392 10,366,442 CH 4 153,172 19,548 28,150 1,788 42,535 248,447 493,640 CO 2 1,644,066 622,154 265,536 15,767 403,571 2,240,802 5,191,897 HAPs 3,781 130 431 15 3,932 25,450 33,738

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

Pollutant CO MT ND SD UT WY Total CH 4 (CO 2 equivalent) 3,645,531 773,105 773,699 39,252 1,044,258 5,404,241 11,680,085 CH 4 173,597 36,815 36,843 1,869 49,727 257,345 556,195 CO 2 2,130,662 762,281 273,938 13,565 566,341 3,120,791 6,867,579 HAPs 4,817 226 529 15 4,893 29,668 40,149

Table 3-7 presents air emissions by majo r source category—point and area—by state. VOCs, NO x , SO 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, NO x , SO 2 , CO, and HAPs, by State, 2002 (tons)

Pollutant/Source CO MT ND SD UT WY Total VOCs Point 63,423 58 66 0 576 2,691 66,814 Area 27,259 5,444 7,740 288 35,961 119,447 196,139 Total 90,683 5,502 7,805 288 36,537 122,138 262,953 NO x Point 22,442 204 2,940 0 1,774 5,644 33,003 Area 23,518 7,557 4,631 361 3,335 14,725 54,126 Total 45,960 7,761 7,571 361 5,108 20,369 87,130 SO 2 Point 102 2 2,524 0 1,573 13,309 17,510 Area 118 225 358 6 17 150 874 Total 220 227 2,882 6 1,590 13,460 18,385 HAPs Point 2,777 1 0 0 52 220 3,050 Area 1,004 128 430 15 3,880 25,230 30,688 Total 3,781 130 431 15 3,932 25,450 33,738 CO Point 13,874 165 761 0 1,883 9,179 25,862 Area 6,847 1,018 36 11 560 3,546 12,018 Total 20,720 1,183 798 11 2,443 12,725 37,880

For VOCs and HAPs, the table reveals area sources are a much greater contributor to emissions than point sources in Region 8 . For NO x and CO emissions, point and area sources contribute significantly to total em issions. The area source fraction is slightly larger for NO x and the point source component is larger for CO. NO x and CO emissions

U.S. Environmental Protection Agency Working Draft – September 2008 3-7ENVIRONMENTAL RELEASES

are primarily from large combustors (point sources) as well as small combustors and mobile sources (area sources ). On the other hand, SO 2 emissions are dominated by large point source combustors. Methane emissions are not shown in Table 3-7, primarily because the exact split betw een 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 sour ce emissions for 2006. For VOCs and HAPs, we estimate point source emissions have grow n faster than area source emissions over the 4-year period. For NO x , SO 2 , and CO, area source emissions increased more than point source emissions.

Table 3-8. Total Point and Area Emissions of VOCs, NO x , SO 2 , CO, and HAPs, by State, 2006 (tons)

Pollutant/Source CO MT ND SD UT WY Total VOCs Point 80,793 101 81 0 717 3,137 84,829 Area 34,725 9,494 9,515 302 44,755 139,246 238,036 Total 115,517 9,596 9,596 302 45,472 142,383 322,865 NO x Point 28,588 356 3,614 0 2,207 6,579 41,344 Area 29,958 13,180 5,693 378 4,150 17,166 70,526 Total 58,546 13,536 9,307 378 6,358 23,745 111,870 SO 2 Point 130 3 3,103 0 1,958 15,515 20,710 Area 151 393 441 6 21 175 1,186 Total 281 396 3,544 6 1,978 15,691 21,895 HAPs Point 3,538 2 0 0 65 256 3,861 Area 1,279 224 529 15 4,828 29,412 36,288 Total 4,817 226 529 15 4,893 29,668 40,149 CO Point 17,673 288 936 0 2,344 10,700 31,941 Area 8,722 1,776 45 12 697 4,134 15,385 Total 26,395 2,064 980 12 3,041 14,834 47,326
3.3 Estimated Non-Air Releases (Pr oduced Water and Drilling Waste), 2002 and 2006

Non-air releases mainly refers to produced water (from oil and ga s 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 a nd implications rega rding drilling waste. 51

50 Fugitive emissions are those stemming from unanticipat ed releases or leaks in production equipment and associated processes. 51 Note: Numbers in associated tables in these sections may not add due to rounding.

U.S. Environmental Protection Agency Working Draft – September 2008 3-8ENVIRONMENTAL RELEASES

3.3.1 Produced Water Summary

Proper management of produced waters is a high priority topic in Region 8 . Tables 3-9, 3-10, and 3-11 show estimates of produced water for Region 8, categorized by state and type of producing well. Table 3-9 shows the amount of produced water from oil and gas extraction activities in the region by state, for 2002 and 2006, from data provided by an industry data aggregation company, Lasser Inc. (Note that data provided on the Wyoming Oil and Gas Conservation Comm ission website differs from the Lasser data, indicating a 7.5 % increase in produced wate r in Wyoming from 2002 to 2006. 52 )

In 2002, almost 3 billion barre ls of produced water were extracted in Region 8, with Wyoming contributing almost 75 percent of to tal produced water. There was only a slight increase of total produced water in the re gion projected from 2002 to 2006 (1.7 percent). Whereas South Dakota, Utah, and Wyoming showed reductions in produced water, Colorado, Montana, and North Dakota show ed increases. The la rgest percentage increases in production (from 2002 to 2006) app ear to have been in North Dakota and Montana.

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

State 2002 2006 Percent Change WY 2,091,105,179 2,025,898,781 -3% CO 348,255,005 405,507,349 16% UT 136,296,362 128,669,683 -6% MT 123,397,156 158,186,310 28% ND 98,537,154 127,383,733 29% SD 8,108,174 8,015,208 -1% Total 2,805,699,030 2,853,661,064 2%

The category “oil with gas wells” (where “asso ciated 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 wa ter in the region. Th ese results are not unexpected, since oil wells typically rel ease more produced water than gas wells (particularly as they mature and produce fe wer 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 ac tivities within the state. From coal to oil and gas production and othe r forms of energy development, Wyoming is one of the nation’s leading providers of dome stic fuels. Most of the water produced from oil wells is re-injected underground. Oil wells often use water injection to stimulate oil production 54 (e.g., “water flooding”), and produced wa ter from these operations is often recycled and re-injected to stimulate further production. In addition, in terms of disposal

52 http://wogcc.state.wy.us/Stat isticsMenu.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 (disso lved 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 comm on approaches to enhanced oil recovery (EOR).

U.S. Environmental Protection Agency Working Draft – September 2008 3-9ENVIRONMENTAL 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)

State Oil-Only Wells Gas-Only Wells Oil With Gas Wells Gas With Oil Wells Total WY 601,234,810 569,061,152 853,631,461 67,177,756 2,091,105,179 CO 81,962,976 158,856,545 102,323,995 5,111,489 348,255,005 UT 21,684,832 31,145,993 79,283,960 4,181,577 136,296,362 MT 50,775,321 16,847,685 55,708,537 65,613 123,397,156 ND 20,953,673 3,521 74,617,442 2,962,518 98,537,154 SD 915,122 614 5,121,998 2,070,440 8,108,174 Total 777,526,734 775,915,510 1,170,687,393 81,569,393 2,805,699,030

Table 3-11 shows produced water by well type, including CBM , for 2006. We estimate that produced water coming from oil wells (oil-only wells and oil with gas wells) declined slightly from 2002 to 2006. During the same period, produced water associated with gas wells (gas-only wells , including CBM wells, and gas with oil wells) appears to have increased, with the largest projected increase coming from gas with oil wells.

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

State Oil-Only Wells Gas-Only Wells Oil With Gas Wells Gas With Oil Wells Total CO 47,185,142 217,006,510 127,734,624 13,581,073 405,507,349 MT 56,283,830 28,076,898 73,443,690 381,892 158,186,310 ND 26,358,334 17,382 92,659,049 8,348,968 127,383,733 SD 616,231 953 5,597,759 1,800,265 8,015,208 UT 28,124,959 23,725,241 65,148,166 11,671,317 128,669,683 WY 615,254,891 566,049,418 782,635,991 61,958,481 2,025,898,781 Total 773,823,387 834,876,402 1,147,219,279 97,741,996 2,853,661,064

Gas-only wells also release produced water, but CBM wells release substantially more produced water than non-CBM wells. The quality and composition of produced CBM water varies widely, as shown in Table 3-12. Ne vertheless, there is si gnificant interest in CBM produced water in Region 8. The main reas on behind the increased attention is that these CBM gas wells often yield high qualit y, and high volumes of, produced water that supports agricultural, ranching, and other uses 56 ( NOTE : Specific data on produced water usage in agricultural purposes (e.g., cen ter-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 Wa ter 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 t hese wells, produced water and other fluids associated with oil and gas extraction (produced water) are reinjected into the same formation. The fluids are mostly salt water (brine). 56 Additional information on GHG emissions and produced water issues can be found at: http://www.beneficialusesummit.com/2008/2008presentations.html

U.S. Environmental Protection Agency Working Draft – September 2008 3-10ENVIRONMENTAL RELEASES

influencing industrial operati ons 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

Primary pollutants commonly found in produc ed 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 evapor ation and infiltrati on. 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 op erations 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 tech nical challenges to re-injection of CBM produced water. For example, the Wyom ing Oil and Gas Cons ervation Commission estimates that across the Powder River Basin, nearly half of the wells drilled for injection cannot accept produced water and that half of the wells that can initially accept produced

57 U.S. Environmental Protection Agency, Technical Support Document for the 2006 Effluent Guidelines Program Plan, http://www.epa.gov/guide/304m/2006-TSD-whole.pdf

U.S. Environmental Protection Agency Working Draft – September 2008 3-11ENVIRONMENTAL RELEASES

water quickly become impaired (from plugging) and thus not a viable option for further injection 58

. 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 wa ter. Nevertheless, produced water is, by volume, the largest waste stre am associated with production. Effective management of produced water—and operator preparations to ensure spill prevention, countermeasures, and control—can present technical chal lenges and impose costs on producers, particularly small businesses. Environmen tal 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 co mmodity. The physical and chemical properties of produced water vary cons iderably depending on the geographic location of the field, the geological form ation 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 floodi ng operations are conducted [to enhance resource recovery], these propertie s 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 chem icals 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). Dri lling fluids include drill cuttings (i.e., rock removed from the formation during drillin g) and drilling muds (i.e., water or oilbased fluids with additives that are pumped down the drilling pipe to offset formation pressure, provide lubrication, and seal o ff 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, ir on sponge, dehydration condensate water, molecular sieve waste, and oily cuttings.

Table 3-13 shows the volume of drilling wa ste (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 l east amount among Region 8 states.

58 EPA-HQ-OW-2006-0771-0970.

59 Argonne National Laboratory, A White Paper Describing Produced Water from Production of Crude Oil, Natural Gas, and Coal Bed Methane , prepared for DOE’s National Energy Technology Laboratory (NETL), January 2004.

U.S. Environmental Protection Agency Working Draft – September 2008 3-12ENVIRONMENTAL RELEASES

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

State 2002 2006 Percent Change WY 10,834,600 17,668,762 63% CO 6,138,174 10,098,340 65% UT 4,533,724 9,222,269 103% MT 2,741,195 5,965,305 118% ND 1,484,341 3,370,840 127% SD 37,451 123,756 230% Total 25,769,484 46,449,272 80%

In 2002, almost 26 million barrels of drilling waste were generated across Region 8. We estimate that drilling waste increased by approximately 80 percent from 2002 to 2006. Although South Dakota is not a major source of drilling waste, it still reported the largest percentage increase of any state in the region, as the 2006 projection has more than tripled the 2002 baseline. In Montana, North Dakota, and Utah, drilling waste more than doubled. Significant growth is projected in Colorado and Wyoming for 2006, as drilling waste increased by more than 60 percent relative to the 2002 baseline.
3.3.4 Drilling Waste Management and Implications

Oil and gas companies have sought to minimize drilling waste and associated environmental impacts in the following ways : recycling and reuse of certain drilling byproducts, employing nontoxic dr illing fluids, and using closed-loop drilling fluid systems to more effectively manage a ssociated wastes. Ne vertheless, 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 spr eading to mitigate some of the industry truck traffic damage, but concerns persist regardi ng associated environmental impacts due to the hydrocarbon content of these byproducts . In many situations, road-spreading applications involving drill cuttings are prohi bited by regulatory agencies. Before drill cuttings can be beneficially reused, thei r salinity and hydrocarbon moisture and clay content must be assessed. Even after sepa ration from other byproducts, cuttings are still coated with mud and, therefor e, 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 cutti ngs are typically exempt from Resource Conservation and Recovery Act (RCRA) hazar dous waste regulations, and this policy does enhance the potential for beneficial reuse 60 . In addition, DOE has funded several projects to test the feasibility of reusing cuttings . It has been 20 years since the RCRA exemption for oil and gas exploration and production was implemented, and many

60 US Environmental Protection Agency, Exemption of Oil and Gas Exploration and Production Wastes from Federal Hazardous Wastes Regulations, October 2002,. http://www.epa.gov/epaoswer/other/oil/oil-gas.pdf

U.S. Environmental Protection Agency Working Draft – September 2008 3-13ENVIRONMENTAL RELEASES

practices and chemicals used have changed duri ng 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 lin ers 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 li ability and other concerns that can inhibit beneficial reuse of drill cuttings. For example, in December 2006, the Railroad Commission of Texas (RRC) revi sed Texas Administrative Code Title 16, Part 1, Chapter 4 and Subchapter B to specify that “a recyclable product is not a waste.” The rule was proposed to mitigate liability concerns of potential end users considering reuse options. 61

61 ICF International. Beneficial Reuse of Industrial Byproducts in the Gulf Coast Region , prepared for EPA’s Sector Strategies Program, February 2008.

U.S. Environmental Protection Agency Working Draft – September 2008 3-14SUMMARY



## 4.0 Summary

4.1 Summary of Data Findings

As detailed in Chapter 3, air emissions, pr oduced water, and drilli ng waste are the leading environmental concerns associated with oil and gas exploration and production in Region 8 and elsewhere. Land use conflicts also can crea te adversity, delays, and lawsuits. As an example, cultural resource protection and re creational 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 industr ial operations. Envir onmental impacts can arise due to improper management of produced water and drilling waste; accidental hydrocarbon and produced water releases; abandoned or orph aned wells; and emissions from oil and gas exploration, production, a nd storage units. Impacts to ground-surface also result from related activities, such as site clearing; constr uction of roads, tank batteries, brine pits, and pipe lines; and other necessary la nd modifications that produce surface disturbances. As oil and gas companie s 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 throug hout the United States and domestic fuel consumption costs on the ri se, unconventional oil and gas resources are becoming increasingly attractiv e 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 opera tions such as tight gas and CBM require more wells to produce the same volume of gas than conventio nal wells, resulting in more drilling and greater surface disturbances. In addition, extracting natural gas from CBM wells produces significant volumes of produced wate r. Due to these resource characteristics and their associated producti on, oil and gas extraction in the Rocky Mountain region has a somewhat different—and likely greater—envi ronmental footprint than production from conventional operations in other regions. The rapid expansion of oil and gas production activities in recent years, coupled with a bundant proven and projected reserves, suggest that Region 8 will remain strategically importa nt 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—primar ily from tight gas and CBM formations— given its vast resource base. Moreover, despite improvements in drilling technology that shrink the environmental impacts of unconven tional 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 th e 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 4-1SUMMARY

unconventional resource development. A lthough horizontal drilling does reduce the number of well pad locations relative to conventional extr action techniques, these and other operational advances are no t 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 oi l 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 Rock ies. The gas is there. The difficulty is that, as we drill these poorer and poorer qua lity reservoirs, it takes three or four wells today to deliver the same volum e of gas that one conventional well would’ve yielded 10 or 15 or 20 years ago.” 62

In summary, the environmental footprint asso ciated with oil and gas production continues to expand, fueling stakeholder concerns a nd regulatory deliberations regarding the potential pathway forward. As reflected in Table 4-1, this report shows that environmental impacts from oil and gas producti on in Region 8 are si gnificant, with air emissions from regional oil and gas production es timated to comprise 6 percent of PM to 30 percent of HAPs of total U.S. em issions for this sector in 2006.

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

Pollutant Region 8 U.S. Total Region 8 as Percentage of U.S. Total Emissions in Tons VOCs 322,865 1,111,445 29% NO x 111,870 839,803 13% CO 47,326 273,051 17% SO 2 21,895 105,227 21% PM 1,060 19,200 6% HAPs 40,149 134,508 30% CH 4 556,195 3,841,447 14% CO 2 6,867,579 49,706,996 14% Water and Waste in Barrels Produced Water 2,853,661,064 19,445,269,921 15% Drilling Waste 46,449,272 233,887,586 20%

Air pollutants of interest are NO x , SO 2 , and PM as precursors of regional haze, and NO x and VOCs as precursors of ground level ozone. VOC emissions are the largest sources in Region 8, and these polluta nts account for nearly two-thirds (64 percent) of total regional emissions (all sources, not just oil and gas) per th e study’s 2006 projections. NO x emissions are primarily from engines (both st ationary and mobile), turbines, and process heaters. VOCs are primarily fugitive emissions and include some HAPs such as benzene, toluene, ethyl benzenes, and xylenes. SO 2 emissions are primarily related to combustion in the oil production sector.

62 “Tapping Into Energy’s Fringe: As Companies Drill for ‘U nconventional’ Natural Gas, Environmental Impacts Mount,” High Country News , 12/12/05.

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

Lastly, fugitive CH 4 emissions constitute the larg est source of GWP-weighted GHG emissions. Due to its unique unconventi onal resource base and emerging production characteristics, Region 8 c ontributes about 15 percent a nd 20 percent of the total produced water and drilling waste, re spectively, 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 to tal 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 formati ons (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 produc tion, 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 es timated drilling waste, followed by Colorado and Utah. Construction of roads and opera tion of drilling rigs in wilderness and undeveloped areas are other highly visible and often controve rsial aspects of oil and gas production, particularly in pris tine areas. In response to th ese concerns, regulators are attempting to find substantive ways to lessen potential impacts and re duce 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 th e plateau entails the following land use requirements:

“[V]irtually all of the acres of AC ECs would be managed under no surface occupancy stipulations, which means no su rface disturbance is allowed. When the proposed ACECs are taken with the addi tional 17,336 acres stipulated no surface occupancy in the first ROD, more than 50 percent of the planning area would be stipulated no surface occupancy .” 64

4.2 Summary of Initiatives to Address Oil and Gas Demand and Environmental Footprint Issues

A number of environmental management initiatives and industry leadership practices have been developed to try to balance the increasing demand for domestic fuel production with the need to reduce the potential environmental and safety impacts of oil

63 Based on 2006 data.
64 U.S. Bureau of Land Management, First Record of Decision on Roan Plateau Plan , June 8, 200, http://www.blm.gov/rmp/co/roanplateau/

.
U.S. Environmental Protection Agency Working Draft – September 2008 4-3SUMMARY

and gas production. BLM is in the proce ss of focusing the development by requiring federal lease unitization, making operators achi eve interim reclamation standards before further surface disturbance is authorized, and use of appropria te 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 emi ssions). 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 vol untary programs. Lastly, as previously mentioned, concerns regarding actu al 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 representa tive sampling of these efforts (some of which were previously referenced in this report ):

• EPA has recently conducted a number of inves tigations into the im pacts of oil and gas activities on domestic water s upplies. 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 companies 66 . Published in 2004, this study focused on whether the injection of cer tain 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 conduc t a rulemaking to revise the effluent guidelines for the Oil and Gas Extraction Point Source Cate gory (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 reco mmends a number of leadership practices for oil and gas expl oration and production operations

. 69 Examples of suggested practices include using a closed-l oop drilling fluid system, which replaces a reserve pit with storage ta nks; reusing drilling fluids; reducing storm water runoff impacts through the use of sediment traps, containment dikes, and other methods; and reusing or recycling drilling waste.

65 Further details on these programs and policies can be found in Chapter 2 of the report.
6666 U.S. Environmental Protection Agency, EPA’s Clean Water Act Review of the Coalbed Methane Industrial Sector, June 2007, http://www.epa.gov/guide/304m/2008/cmb-slides.pdf , accessed 08.19.08.
67 EPA, Evaluation of Impacts of Underground Sources of Drin king Water by Hydraulic Fr acturing of Coalbed Methane Reservoirs , EPA 816-R-04-003, 2004, http://www.epa.gov/safewater/uic/pdfs/ cbmstudy_attach_uic_exec_summ.pdf

. 68 http://www.epa.gov/fedrgstr/EPA-WATER/2008/January/Day-25/w1344.htm.
69 EPA, OECA, Profile of the Oil and Gas Extraction Industry Sector Notebook, Chapter 5, Pollution Prevention Opportunities

, http://www.epa.gov/oecaerth/resources/publicat ions/assistance/sectors/notebooks/oilgaspt2.pdf

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

• 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 othe r agencies overseeing production. The BLM Colorado State Office is working to improve its interim reclamation standards that would reduce the time needed to restor e 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 activ ities, including o il and gas production.

4.2.2 State Initiatives

In addition to federal activities, there are num erous state initiatives related to curbing the environmental footprint from the oil and ga s industry. The following represents only a partial list of some of the mo re noteworthy state efforts:

• States such as Colorado, Montana, and Wyoming have implemented CBM discharge standards to control and re duce produced water impacts.

• Colorado has implemented more stringent VOC standards, primarily in response to the rapid increase in oil and gas produc tion 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 qua lity and climate initiatives. Colorado, Utah, and Montana have all developed Climate Ac tion 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 he lp meet regional haze requirements;

• WESTAR, which has issued a number of BMPs for oil and gas operations; and

• WCI, which seeks to reduce GHG emissi ons 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 footpr int of oil and gas production (in Region 8 and nationally), Congress, NGOs, and other “watchdog” or ganizations are sc rutinizing industry operations as well as tax and regulatory exemp tions being proposed or currently in place. Regulators are being pressured to implement incremental leasing approaches to reduce both the impacts and pace of expanding o il and gas development (in Region 8 and elsewhere) without sacrifici ng potential oil and gas royaltie s, state revenue streams, employment, and other relevant socio-economic considerations. There is increased focus on wildlife protection zones, and BLM is designa ting select areas as ACECs in its efforts to manage valuable and often vul nerable natural resources more effectively

.

U.S. Environmental Protection Agency Working Draft – September 2008 4-5SUMMARY

U.S. Environmental Protection Agency Working Draft – September 2008 4-6 4.2.5 Voluntary Programs

Many of the aforementioned polic ies 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 consid erations for unconventional development remain favorable, regulators ar e moving to develop and implement policies and programs that will lessen and potentially pr event 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 Admini stration’s (OSHA) Vo luntary 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, ei ther implicitly as reduced emissions and increased product sales or explic itly as operational le eway such as redu ced monitoring, to program participants. Such voluntary approach es encourage stewardship of the resources available to the oil and gas industry, while contributing to envir onmental protection and have been an effective compleme nt to regulatory compliance and enforcement . Table 4-2 provides additional information on each of these programs.SUMMARYTable 4-2. Summary of Voluntary Environmental Programs Available to the Oil and Gas SectorProgramAttributesNatural Gas STAROSHA VPPSan Juan VISTASWyoming VRPFour Corners Air QualityTask ForceObjectivesIdentify and promote theimplementation of cost-effectivetechnologies and practices to reducemethane emissions•Promote effective workplacehealth and safety (in manycases, this translates intoreduced environmental impactas well)•Enable companies to be betterstewards of their operations byprioritizing governmentenforcement resources foroversight of higher riskestablishmentsIdentify, promote, and implementcost-effective technologies andpractices to reduce air pollutionaffecting northwestern New MexicoSet up a process for owners orpotential developers ofcontaminated sites•To determine actions requiredfor remediation quickly•To put contaminated sites backinto productive reuseAddress air quality issues in theFour Corners region, increase airpollution awareness, and consideroptions for mitigating air pollutionPollutants UnderPurviewMethane (CH4)Focuses on health and safetyVOCs, CO, NOx, SO2, all gases thataffect ozone and haze, and GHGsAll types of land and watercontaminationVOCs, CO, NOx, SO2, all gasesthat affect ozone and haze, andGHGsPartners110+ partners across the foursectors of the oil and gas industry(production, processing,transmission, and distribution); 8international partners; and 19endorser organizationsAll groups covered by OSHA,including federal agenciesPrivate and public entities:industries, businesses,municipalities, organizations andcommunity groupsNot applicable—there are nopartners,per se, but the program isdesigned to support owners,operators, and purchasers ofcontaminated sites100+ members (private citizens,public interest groups, universities,industry, and federal, state, localand tribal governments) and 150interested partiesStatesAll states, including Region 8 statesAll states, including Region 8 statesNew Mexico (but lessons learnedare presumably applicable toRegion 8 and other oil and gasproducing states)WyomingArizona, Colorado, New Mexico,and Utah (i.e., the Four Cornersregion)Partner Benefits•Efficient and new technologiessave partners operational costs•Reduction in methane emissions(primarily fugitives)•Additional revenues from savedmethane emissions•Recognition as environmentallysensitive institution•“Star demonstration” sitesevaluated every 12 to 18months•“Merit” sites evaluated every 18to 24 months•“Star” sites evaluated every 3 to5 years•Lower production costs due toefficient technology use•Pollution reduction•Capture more product formarket sale•Recognition from the VISTASprogram as Clean Air Partner(press release, advertisements,articles, and awards)•Provides three types of liabilityassurances:1.Covenants not to sue2.Certificate of completion3.No further action (NFA)letters•Brownfield assessmentassistanceReduction in air pollutionProgram Outreach/Resources•Technology transferworkshops for all sectors ofthe oil and gas industry•Annual implementationworkshop•Technical documents•Feasibility studies•Partner challenge study,identifying opportunities•“Special GovernmentEmployee” (SGE) program toextend government resourcesand expertise•Mentoring•Safety and health managementcourse•Technology transfer workshops•Outreach materials•Assist partnerswith technologyand practice implementation byanalyzing opportunities, whereapplicableVarious fact sheets•Quarterly meetings•Workgroup participation•Outreach materialU.S. Environmental Protection AgencyWorking Draft – September 20084-7U.S. Environmental Protection AgencyWorking Draft – September 20084-8ProgramAttributesNatural Gas STAROSHA VPPSan Juan VISTASWyoming VRPFour Corners Air QualityTask ForceAchievements•Partners have eliminated over575 Bcf of methane emissionssince the program’sestablishment•Methane emissions reductionsof approximately 86 Bcf wereachieved by partners in 2006•Additional revenue of more than$600 million in natural gas saleswas generatedThe Days Away Restricted orTransferred (DART) case rate is52% below industry average foraverage participant worksiteNot ascertainedOver 90 sites have registered withthe program so far•125 mitigation optionsdeveloped by members in 2years•Increased air pollutionawareness•Provided resources toagencies responsible for airquality management in theFour Corners areaSUMMARY

## Appendix A: Industry Characterization

A.1 Industry Description

As shown in Table A-1, the following North American Industrial Classification System (NAICS) codes were included in this anal ysis of oil and gas production issues and associated environmental impacts:

Table A-1. NAICS Codes Addressed in This Analysis

NAICS Description 2111 Oil and Gas Extraction 211111 Crude Petroleum and Natural Gas Extraction 211112 Natural Gas Liquid Extraction 213111 Oil and Gas Drilling 213112 Support Activities for Oil and Gas Operations

In addition, as shown in Table A-2, the followi ng Standard Industria l Classification (SIC) codes were included in this analysis:

Table A-2. SIC Codes Addressed in This Analysis

NAICS Description 1311 Crude Petroleum and Natural Gas 1321 Natural Gas Liquids 1381 Drilling Oil and Gas Wells 1382 Oil and Gas Field Exploration Services 1389 Oil and Gas Field Services, not elsewhere classified

In general, upstream oil and gas industry activities include seismi c and geological data acquisition and interpre tation, leasing and permitting, dril ling activities, workovers and recompletions, and production operations. Workovers and recompletions are operations that work to increase or impr ove recovery of oil and natura l gas from existing wells. As defined here, production operations encompass an array of activities that are needed to gather and process the oil and ga s prior to transport and sale.

Oil is found and extracted from geological formations in which the hydrocarbons are trapped in a porous formation below an impermeable cap rock (Figure A-1). These conventional formations have high permeability, which allows the oil and gas to flow freely to the wellhead. Generall y, one or a small number of wells are adequate to recove r oil and gas from subsurface formations.

Conventional wells typica lly range from 3,500 to 10,000 feet deep, and some are even deeper. In Wyoming, for example, some conventional wells are as much as 24,000

U.S. Environmental Protection Agency Working Draft – September 2008 A-1 Figure A-1. Conventional Oil FormationAPPENDICES

feet deep. Natural gas and water are typical ly trapped in the same formation and are produced along with the oil. Natural gas pr oduced from an oil reservoir is known as “associated gas” and is typically separated from the oil and subse quently processed and then transferred to pipelines for sales a nd 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 concentrati ons of hydrocarbons as well as chemicals associated with drilling pr ocesses. Produced water can be a valuable resource; beneficial uses in clude 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 pr oduction. There are seve ral categories of nonassociated gas:

• Conventional gas is natural gas found in high-permeability formations that allow the hydrocarbons to flow freely to the wellh ead (similar to formations containing conventional oil).

• Tight gas is defined as natural gas producti on from low-permeability, or tight, reservoirs. Such reservoirs have very sm all pore spaces between the sandstone grains, and these characteristics prevent the gas fr om flowing freely to the wellbore. It is generally necessary to stimul ate the pore spaces artificia lly, 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 t ypically 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 e xperiencing rapid growth in production across Region 8 and in other gas producing re gions (e.g., the Barnett Shale in Region 6). Shale is also a low-permeability form ation, and natural gas production requires artificial stimulation (discussed in gr eater detail in Section A.1.1 below).

Relevant oil and gas development activities th at tend to generate the most substantive environmental impacts include field deve lopment 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 th e 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 a nd completing an oil or gas well include: (1) site preparation, (2) casing and cementi ng, (3) drilling, and (4) stimulation and completion.

U.S. Environmental Protection Agency September 2008 A- 2APPENDICES

Site Preparation

Site preparation involves surveying and pe rmitting, 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 cons truction involves constr uction 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 ad jacent reserve pits hold fluids that are used and extracted during drilling operations. Unlike conventional gas extraction, the low permeability of unconventional formations requires more we lls 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 mo st 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 prot ect 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 de pth, progressively smalle r strings of casing are cemented inside the earlier stri ngs. In this manner, portions of the well that have already been drilled are sealed off for safety, we llbore integrity, and pr otection of USDWs.

Figure A-2. Wellbore and Casing

U.S. Environmental Protection Agency September 2008 A- 3APPENDICES

Drilling

Historically, domestic drilling has been domin ated 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 th e rock interface. Drilling fluids or muds are pumped downward via the drill pipe and circulated back to th e surface to remove rock cuttings. In addition, drilling fluids and muds help to control pre ssure ratios from within the wellbore, and the amount of fluid system pressure is typically adjusted by varying th eir relative density. Various types of fluid systems can be use d, including water-based and oil-based muds. The density of the drilling flui d depends on the pressure gradient and other characteristics of the formation being target ed. 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, dril l cuttings have been used as an alternative to gravel in constructio n or cement manufacturing.

In the last 15 years or so, onshore directional and horizonta l drilling have represented a growing percentage of oil a nd gas exploration and producti on activities. Directional drilling allows the operator to use a small surface well pad and dril l outward to access a large portion of the re servoir. 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 fi eld in Wyoming and is planned for future tight gas development in ot her locations (e.g., northwestern Colorado’s Piceance Basin, the Bakken shale fields in Montana and North Dakota; etc.).

In addition, increased targeting of unconventio nal reservoirs in Re gion 8 has resulted in more horizontal drilling activities. Horizontal drilling features techniques that shift the wellbore from a vertical to a horizontal orientation within the target reservoir (Figure A3). The horizontal drilling allows wellbore contact with thousands of feet of reservoir and is generally done in conjunction with well stimulation along the horizontal borehole. Such drilling methods are being used extens ively in shale gas as well as CBM production operations. Horizontal drilling is also used in certain o il production operations (e.g., in the Williston Basin of North Dakota).

In recent years, variants of horizontal drilling have b een developed, and elaborate subsurface drilling patterns ar e 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 Mount ain region as well. Attractive features of these approaches include the potential to improve project economics and to reduce greatly surface disturbances and a ssociated environmental impacts.

U.S. Environmental Protection Agency September 2008 A- 4APPENDICES

Figure A-3. Horizontal Drilling

Stimulation and Completion

After the well has been drille d 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 reservoi rs are subject to stimulatio n 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 subseque ntly 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 fr actures 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, seve ral separate fractures are carried out within the horizontal por tion 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- 5APPENDICES

Figure A-4. Hydraulic Fracturing 1

A.1.2 Gas Production and Processing

Once a well has been stimulated and complete d, natural gas operations move into the production phase. Initial producti on of gas generally begins as natural flow from the wellhead into the gathering system. As a fiel d 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 tr eated prior to introduction into the pipeline system. Heavy liquids such as butane are remove d near the well site as lease condensate. Gas may also contain non-hydrocar bons such as carbon dioxide (CO 2 ), hydrogen sulfide (H 2 S), or nitrogen. Nitrogen and CO 2 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 degr ade the quality of natura l gas being processed. Natural gas is gathered and sent to processing plants for re moval of these constituents. Gas processing plants include combustion units (i nternal combustion (IC) engines and turbines) and chemical process units that produce nitrogen oxides (NO x ), volatile organic compounds

1 U.S. Department of Energy (DOE), Enhanced Oil Recovery (EOR) Research Program.

U.S. Environmental Protection Agency September 2008 A- 6APPENDICES

(VOCs), and particulates. Storage facilities fo r oil and other liquid hydrocarbons may also release fugitive VOC and methane (CH 4 ) emissions.

Region 8 is an arid regio n, 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 produc tion in Region 8. Water disposal may consist of surface discharge with or without treatment, or injection into a porous formation via injection well. Salts ar e among the most common produced water impurities, and the high sodium content of th e brine presents environmental management challenges. Such water quality characteris tics 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 in clude evaporation ponds or processing that reduces the salinity of produced water prior to furt her disposition. For example, with surface discharges throughout the Powder River Basi n 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 developm ent are not challenged by significant water volumes and production that originate in the subsurface (as is gene rally 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 truc k) and subsequently treated, recycled, or disposed of. Such pr ocess 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 na tural reservoir pressure or is pumped to the surface with a pumping unit. At the su rface, 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 hydro carbons. Oil and gas are separated near the wellhead by separator units (i.e., horizontal or vertical cyli ndrical 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 equipmen t. In addition, associated gas may be reinjected into the formation to maintain reservoir pressure. 2

2 Note: Prudhoe Bay, Alaska, production operations often em ploy these approaches to maintain reservoir pressure and augment hydrocarbon flow rates.

U.S. Environmental Protection Agency September 2008 A- 7APPENDICES

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 ta nks in the field area. Prior to pipeline transport, a glycol dehydration unit is used to remove the rema ining water from the oil. After on-site processing, crude oil may be tem porarily 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 c oncentrated in a few regions of the United States based on the location of the geologica l resource. The Appalachian region was the first oil and gas producing ar ea in the country. Other early producing areas included the Michigan-Illinois Basin a nd the Mid-Continent. For many years the predominant producing regions have been the Texas-Loui siana region (including the San Juan and Permian Basins) and the Gulf of Mexico. Howe ver, recent years have seen substantial growth in the Rocky Mountains (Figure A-5).

Figure A-5. Rocky Mountain States Oil and Gas Producing Regions

Region 8 comprises much of what is gene rally called the Rocky Mountain oil and gas province. Some of the Rocky Mountain regi on resides outside Region 8, primarily the San Juan Basin in northwestern New Mexic o. 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- 8APPENDICES

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 pro duction through 2030 and beyond. Conventional oil production has actually been in decline, and oil production is concen trated 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, o il production has vast energy supply implications for the future. Large oil shale deposits are present in western Colorado, northeastern Utah, and southwes tern Wyoming, and may be developed in coming decades. The oil shale deposits were th e focus of a previous industry technology development and pilot project in the 1970s a nd 1980s, but for various technical and other reasons, commercial production never materialized.

The Rocky Mountain region has geological char acteristics that make it very different from other oil and gas producing regions, such as the Gulf Coast. The Gulf Coast and Gulf of Mexico generally produce oil and gas from conventional high-porosity, highpermeability oil and gas reservoirs. High porosit y and permeability mean that the oil and gas in the formation can easily flow into th e production well. Conven tional reservoirs are generally defined as high-porosity formations that contain well-def ined contacts between oil, gas, and water and can be produced us ing standard methods. In contrast, current activity in Region 8 is focuse d on unconventional natural ga s formations, and extracting these resources has significant water use impli cations. To extract the resource from tight gas or shale gas formations successfully, fr actures are opened with pressurized water, requiring water use (which must be recycle d, reused, and/or disposed of) as well as greater surface disturbance from heavy truc ks 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 formati on. Although improvements in drilling technology mean that multiple bores can be drilled fr om 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 ga s and shale gas formations do not contain large volumes of water, pr oduct extraction from these formations does not create significant produced water issues.

Table A-3 shows oil and gas produ ction in Region 8; note that numbers may not add due to rounding. In 2002, the region produ ced 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 natura l gas production occurr ed in Wyoming and Colorado, as these two states represent 86 per cent of total gas produced in the region in 2002. Wyoming produced slightly more than Colorado during th is 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 producti on in the United States. Oil production is dominated by Wyoming and North Dakota. Wyoming accounts for approximately onethird of the total oil production in the region, while North Dakota is next in line at about 19 percent. South Dakota produced the least amou nt of gas and oil among Region 8 states.

U.S. Environmental Protection Agency September 2008 A- 9APPENDICES

Table A-3. Total Oil and Gas Production in Region 8, 2002

State Gas (million cf) Oil (1,000 Bbls) WY 1,776,311 54,872 CO 1,045,365 18,696 UT 292,752 13,767 MT 86,304 16,860 ND 57,783 29,670 SD 32,072 3,061 Region 8 Total 3,290,588 136,928 U.S. Total 18,927,788 2,097,124

Figures A-6 and A-7 illustrate regional gas and oil production tr ends in the lower 48 states from 1998 to 2005. In recent years, natura l gas production has grown by approximately 50 percent in the Rocky Mountain re gion, while it has been flat or declining in most other regions. Oil production in the Rocky Mountain re gion is small compared with other regions and shows no significant growth trend.

Figure A-6. Total Dry Gas Production in the Lower 48 by Region, 1998—2005

0 1 2 3 4 5 6

1998 1999 2000 2001 2002 2003 2004 2005 2006Tcf per Year

California/ Other

East/ Midwest Gulf Coast

Gulf of Mexico

MidContinent

San Juan/ Permian Rockies

U.S. Environmental Protection Agency September 2008 A- 10APPENDICES

Figure A-7. Total Crude Oil Production in the Lower 48 by Region, 1998—2005

0 100 200 300 400 500 600 700 800 900

1998 1999 2000 2001 2002 2003 2004 2005 2006Million Barrels per Year

East/ Midwest California/ Other

San Juan/ Permian

MidContinent

Rockies Gulf of Mexico

Gulf Coast

Undeveloped natural gas resources in the Rock ies are found primarily in tight gas sands. These sands are widely distributed as basi n 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 t housands of feet and present throughout the central portion of major basins. It is this ga s that is now being drilled and will be the focus of future production. Recoverable reso urces 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 s outhwestern Colorado and northwestern New Mexico, and the Powder River Basin in eas tern Wyoming. The San Juan Basin produces from the Fruitland coal formation. This formation was the initia l major area of CBM production in the Rockies and is characteri zed 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 Ju an Basin. To date, almost all of the produced water has been surface discharged, rather th an injected, which can impact surface water

U.S. Environmental Protection Agency September 2008 A- 11APPENDICES

quality and contribute to streambed erosion. 3 Efforts to develop significant CBM elsewhere in the Rockies, including centra l Utah and southwestern Wyoming, have had variable success.

In a recent accounting, there were approximately 17,000 produci ng coal bed wells in the Powder River Basin and about 150 in southw estern Wyoming. Powder River Basin coal beds are shallower than in other areas, nece ssitating drilling a larg e 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 char acteristics, number of seams, and other factors.

Natural gas resource development in the regi on 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 devel opment interests and environmentalists over resource access, water rights, wildlife, and other issues. The growing population of the region has also been a fact or, 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 numb ers 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 to tal number of producing oil and gas wells in 2006. These data highlight the re gion’s rapid growth in extr action activity, particularly for natural gas.

Figure A-8 shows that the Rockies represen ted about 17 percent of total U.S. gas production in 2005, up from 11 percent in 2000. Al most 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 si gnificantly in recent years. Ho wever, this percentage could increase in coming years with the incr eased use of enhanced oil recovery.

3 Not all CBM is associated with large amounts of co-produced water. In Alberta, for exampl e, a coal bed formation that does not produce significant water with the gas is being ex tensively developed.

U.S. Environmental Protection Agency September 2008 A- 12APPENDICES

Figure A-8. Comparison of U.S. and Rockies Gas Production, 2000—2005

0 5 10 15 20 25

2000 2001 2002 2003 2004 2005Tcf per Year

U.S. Rockies

Figure A-9 shows that there were approxi mately 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 domina nce of CBM drilling in Wyoming’s Powder River Basin, which has declined slightly since peaking seve ral years ago. The growth in Rockies activity would be more appare nt if viewed over a longer period.

In terms of new oil wells, the Rockies re present about 13 percen t of national activity. This fraction has increased fr om 5 percent in 2000 due to increased activity, e.g., in Colorado’s Denver Basin and the Uinta Basin of Utah.

Figure A-9. Comparison of U.S. and Rockies Gas Well Completion, 2000—2005

0 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000

2000 2001 2002 2003 2004 2005Number of Wells

U.S. Rockies

U.S. Environmental Protection Agency September 2008 A- 13APPENDICES

Table A-4. Oil and Gas Production and Drilling Activity in the Rockies
Rockies and U.S. Dry Gas Production

Billion Cubic Feet per Year Rockies Rockies U.S. Percent CO UT WY MT Total Total of U.S.

2000 759 226 1,070 67 2,122 19,219 11% 2001 882 288 1,286 73 2,529 19,779 13% 2002 964 286 1,388 77 2,715 19,353 14% 2003 1,142 278 1,456 86 2,962 19,425 15% 2004 1,050 282 1,524 95 2,951 19,168 15% 2005 1,104 308 1,642 100 3,154 18,458 17%

Rockies and U.S. Crude Oil Production

Million Barrels per Year Rockies Rockies U.S. Percent CO UT WY MT Total Total of U.S.

2000 17 14 54 15 100 1,880 5% 2001 16 13 48 16 93 1,915 5% 2002 17 12 46 18 93 1,875 5% 2003 16 12 42 19 89 1,877 5% 2004 18 13 43 22 96 1,819 5% 2005 19 15 45 30 109 1,733 6%

Rockies and U.S. Annual Completed Gas Wells

Rockies Rockies U.S. Percent CO UT WY MT Total Total of U.S.

2000 920 365 4,888 384 6,557 17,126 38% 2001 1,344 484 5,249 318 7,395 21,202 35% 2002 1,270 351 2,942 296 4,859 15,970 30% 2003 1,490 274 2,679 508 4,951 19,482 25% 2004 1,736 301 3,617 435 6,089 23,193 26% 2005 2,496 438 4,356 578 7,868 27,562 29%

Rockies and U.S. Annual Completed Oil Wells

Rockies Rockies U.S. Percent CO UT WY MT Total Total of U.S.

2000 73 84 145 75 377 8,209 5% 2001 34 106 127 163 430 8,934 5% 2002 21 40 90 144 295 6,929 4% 2003 36 117 154 225 532 8,135 7% 2004 312 299 413 287 1,311 11,170 12% 2005 406 355 518 361 1,640 12,734 13%

2006 Producing Oil and Gas Wells Rockies Rockies U.S. Percent CO UT WY MT Total Total of U.S. Gas 19,993 5,012 25,052 4,078 54,135 413,174 13% Oil 7,567 2,401 10,205 5,862 26,035 500,785 5% Total 27,560 7,413 35,257 9,940 80,170 913,959 9%

U.S. Environmental Protection Agency September 2008 A- 14APPENDICES

In 2006, the Rockies had a total of 54,100 producing gas wells and 26,000 producing oil wells, shown in Figure A-10. This represents 13 percent and 5 percent of the U.S. totals, respectively.

Figure A-10. Total U.S. and Rockies Oil and Gas Producing Wells, 2006

0 100 200 300 400 500 600

Gas OilThousands U.S. Rockies

In 2002, a total of almost 22 million feet of wells was drilled in Region 8. Table A-5 shows total footage of wells drilled by st ate; note that numbers may not add due to rounding. Wyoming reported the largest drilli ng 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 th e 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 num ber of wells. On average, the deepest wells are in North Dakota, while Montana has the shallowest wells. Ov erall, the region has an average well depth of 5,848 feet. Table A-5. Footage Drilled by State in Region 8, 2002

State Feet WY 8,531,181 CO 7,055,372 UT 2,698,645 MT 1,803,418 ND 1,413,658 SD 36,360 Total 21,538,634

U.S. Environmental Protection Agency September 2008 A- 15APPENDICES

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 produc tion. 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 w ith oil wells. The remaining wells in the region are oil-only wells, totaling 12,183. Table A-6. Well Data by State for Region 8, 2002

Table A-7. Well Data by Type and State for Region 8, 2002

State Total # of Wells Oil-Only Wells Gas-Only Wells Oil With Gas Wells Gas With Oil Wells
WY 31,600 6,276 13,731 5,225 6,368 CO 22,342 1,763 8,135 4,788 7,656 MT 8,707 2,694 4,633 1,355 25 UT 5,572 467 1,784 1,809 1,512 ND 3,591 914 77 2,452 148 SD 248 69 62 64 53 Total 72,060 12,183 28,422 15,693 15,762

Region 8 also has a substantial number of CBM wells. These are gas-only wells and are, therefore, a subset of the gas-only wells presented above. Table A-8 presents the number of CBM wells in Region 8 by state; note that numbers may not add due to rounding.

CBM wells can be found in all Region 8 states except for North Dakota and South Dakota. Nevertheless, most CBM wells are currently found in Wyoming, representing 71 percent of total CBM wells in Region 8. In addition, 57 percent of the gas-only wells in the region are CBM wells. In Wyoming, the percentage is much higher, 85 percent.

Table A-9 presents 2004 data on natural gas processing plants in Region 8 (2002 data are not available); note that numbers may not a dd due to rounding. Acco rding to these data, Wyoming represents more than half of tota l 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 “oi l with gas well.” Otherwise, it is a “gas with oil well.” State Total # Average Well of Wells Depth (ft) WY 31,600 6,020 CO 22,342 5,856 MT 8,707 3,420 UT 5,572 6,558 ND 3,591 9,013 SD 248 6,660 Total 72,060 5,848

Table A-8. CBM Wells by State for Region 8, 2002

State Gas-Only Wells # of CBM Wells Percent CBM
WY 13,731 11,628 85% CO 8,135 3,680 45% MT 4,633 236 5% UT 1,784 758 42% ND 77 0 0% SD 62 0 0% Total 28,422 16,302 57%

U.S. Environmental Protection Agency September 2008 A- 16APPENDICES

although it has fewer than half the number of plants. Colorado represents the second largest capacity and number of plants. These results are consistent with the production results identifying Colorado and Wyoming as having the largest volume of gas production in Region 8. Table A-9. Total Number and Capacity of Natural Gas Processing Plants in Region 8, 2004

State Capacity (Mcf) Number of Plants WY 6,920 45 CO 2,093 43 UT 970 16 ND 222 8 MT 133 3 SD 0 0 Total 10,338 115

U.S. Environmental Protection Agency September 2008 A- 17APPENDICES

This Page is Intentionally Left Blank.

U.S. Environmental Protection Agency September 2008 A- 18APPENDICES 

## Appendix B: Pollution Sources in the Oil and Gas Industry

The analysis of emissions from oil and ga s 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 re gulated by National Ambient Air Quality Standards (NAAQS), incl uding ground level ozone (the primary component of smog ), carbon monoxide (CO), sulfur dioxide (SO 2 ), and particulate matter (PM). Ozone is not a direct emission but is formed in the atmosphere from nitrogen oxide (NO x ) and volatile organic compounds (VOCs). NO x and VOCs are, therefore, regulated as pr ecursors to ozone. VOCs are either hydrocarbon fugitive emissions or products of fossil fuel combus tion. Most of the othe r emissions are the result of fossil fuel combustion in e ngines, 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, envi ronmental groups, and other affected stakeholders are very concerned about pollutants th at reduce visibility, including NO x , SO 2 , and particulates.

• Greenhouse gases (GHGs): These are gases, including CO 2 and methane (CH 4 ), have climatic warming effects . CO 2 includes CO 2 from combustion of fossil fuels and CO 2 that is removed from ra w natural gas and vented. CH 4 emissions are primarily fugitive emissions from gas system operations. CH 4 has a global warming potential (GWP) 21 times higher than CO 2 . There is increasing in terest in measuring GHG emissions and their impacts in the western states. Arizona, Califor nia, Montana, New Mexico, Oregon, Utah, and Washington a nd have formed the Western Climate Initiative (WCI) to establish and m eet GHG reduction targets. Colorado is establishing its own ta rgets, and other states may follo w suit. In addition, legislative proposals have been introduced in Congress to regulate GHG emissions in the future. EPA issued an advance notice of pro posed 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 inform ation sources, the EP A Sector Strategies Program decided to feature the WRAP air emissi ons 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-1APPENDICES
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 “maj or” or “minor” for pollutants, based on the potential or permitted air emissions, and it defi nes “area source” as a stationary source of air pollution that is not majo r. WRAP’s categorization of point sources most closely correlates to major sources of air pollution, but could potentially incl ude 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 f unction and size of source. For purposes of data categorization in this re port, point sources are large st ationary sources that can be separately measured and tracke d. 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 individuall y. The major point sour ce 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 co mpressors 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 fr om natural gas, incl uding 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 fo r a variety of processes i nvolved 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 compre ssor stations process between 10 and 100 MMscfd of natural gas. These sites are usua lly operated to pre ssurize 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 natu ral gas in the produc tion 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 ar e usually considered point sources, and the other two categories are usua lly included in the area sour ces. Across these four source categories, three basic equipment cate gories contribute to air emissions:

• Internal combustion equipment: Primarily natural ga s-fired engines and combustion turbines used in compressors, generators, and pumping units, or dieselU.S. Environmental Protection Agency Working Draft – September 2008 B-2APPENDICES
fired engines that power generators, trucks, or mobile equipment such as drilling rigs or frac units. Emissions include NO x , PM 10 , PM 2.5 , VOCs, SO x , 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 NO x , PM 10 , PM 2.5 , VOCs, SO x , and CO.

• Storage and separation vessels: Includes a variety of equipment such as separators, storage tanks, pressure and level controllers, glycol de hydrator flash tanks, glycol dehydrator still columns, gas-operated and chemical injection pumps, and oil/water skimmers. These units are a primary source of fugitive VOC emissions, which leak out of tanks, pipes, valves, and fittings or evaporate from exposed liquid surfaces. Wells, gathering pipelines, dehydrators, and separators generate the majority of methane emissions, followed by transmission and storage.

B-1 identifies the emission sources and pollu tants covered in this sector. Table B-2 summarizes the typical range of air pollution sources in th e exploration and production sector along with the source cl assification codes (SCCs) used to categorize the sources and typical emission factors and control effi ciency data; this list was compiled by the Michigan Department of Environmental Qual ity. The emission factors come from EPA’s AP-42 listing of emission factors and other st andard data sources. While these sources do not provide emission rates for sp ecific facilities, they are t ypical values that provide a good first estimate of standard emissions factors and control efficiencies.

U.S. Environmental Protection Agency Working Draft – September 2008 B-3APPENDICES

Table B-1. Emission Sources and Pollutants for Oil and Gas Production

Source Category Pollutant Emission Unit Large Compressor

Stations Natural Gas Processing

Plants Stand-alone Production Sites Small Compressor Stations & Wellheads Natural gas-fired engines RR R R Internal Combustion Diesel-fired engines R R R R

Line heaters R R R Separators R R Heat treaters R Glycol regenerators R R R R External Combustion NO x , PM 10

, PM 2.5

, VOCs, SO x , CO

Amine regenerators R R

Sulfur recovery units R

Combustion flares R R R Fugitives R R R R Separators R R R Glycol dehydrator flash tanks R R R R

Glycol dehydrator regenerator still columns R R R R

Storage tanks R R R Pressure and level controllers R R R

Gas operated pumps & chemical injection (CI) pumps R R R Storage and Separation Vessels VOCs

Oil/water skimmers R

U.S. Environmental Protection Agency Working Draft – September 2008 B-4APPENDICES

Table B-2. Air Emissions Sources for the Oil and Gas Production Industry

SCC Description Pollutant Emission Factor Control Efficiency Natural Gas Engines 2-02-002-53 Standard “rich burn” engines May include: Natural gas process heaters Natural gas production compressors Natural gas production flares—excluding SO 2 CO NO x PM 10 PM 2.5 SO 2 VOC 3.794E3 lb/mmcf 2.254E3 lb/mmcf 9.69E0 lb/mmcf 9.69E0 lb/mmcf 6.00E-1 lb/mmcf 3.02E1 lb/mmcf 3-way catalyst CO – 80% NO x– 90% VOCs – 50%

2-02-002-54 Lean burn engines May include: Natural gas process heaters Natural gas production compressors Natural gas production flares—excluding SO 2 CO NO x PM 10 PM 2.5 SO 2 VOC 5.68E2 lb/mmcf 4.162E3 lb/mmcf 7.90E-2 lb/mmcf 7.90E-2 lb/mmcf 6.00E-1 lb/mmcf 1.204E2 lb/mmcf Oxidation catalyst CO – 80% VOCs – 50%

Process Heaters (excluding engines noted above) 3-10-004-04 Process heaters CO NO x PM 10 SO x VOC 3.50E1 lb/mmcf 1.40E2 lb/mmcf 3.00E0 lb/mmcf 6.00E-1 lb/mmcf 2.80E0 lb/mmcf Tank Storage 4-04-003-01 Fixed roof tank—breathing loss VOC 3.6E1 lb/kgal-yrcrude oil (storage capacity) Vapor recovery system – 95% Flare – 95% 4-04-003-02 Fixed roof tank—worki ng loss VOC 1.1E0 lb/E3 gal crude oil (throughput) Vapor recovery system – 95% Flare – 95% Truck Loading 4-06-001-32 Truck loading VOC 2.0E0 lb/E3 gal crude oil Vapor recovery system – 95% Gas Dehydrators 3-10-003-21 Glycol dehydrator—Niagaran VOC 9.24E4 lb/yr-GPM Glycol Tube and shell condenser with flash tank – 90% Vapor recovery system – 95% Flare – 95% 3-10-003-22 Glycol dehydrator—Prairie du Chien VOC 1.94E4 lb/yr-GPM Glycol Tube and shell condenser with flash tank – 90% Vapor recovery system – 95% Flare – 95% 3-10-003-23 Glycol dehydrator—Antrim VOC 9.2E1 lb/yr-GPM Glycol Vapor recovery system – 95% Flare – 95% Amine Plant 3-06-009-06 Amine plant SO 2 3.76E3 lb/ton hydrogen sulfide Fugitive Emissions (excludes fugitive emissions from crude oil sumps) 3-10-888-01 Fugitive emissions—light crude oil VOC 1.44E1 lb/each-yr valve 3-10-888-02 Fugitive emissions—gas production VOC 3.60E0 lb/each-yr valve 3-10-888-03 Fugitive emissions—gas plant VOC 2.74E1 lb/each-yr valve

U.S. Environmental Protection Agency Working Draft – September 2008 B-5APPENDICES
In addition to the relatively permanent em ission sources described in this section, emissions are also associated with drilli ng and well stimulation. These emissions are primarily from truck-mounted diesel engine s used to power drilling equipment and hydraulic fracturing equipment used to stim ulate 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 CO 2 from fossil fuel combustion and CH 4 from leaks, venting, and fugitive emissions. As previously noted, methane has greater gl obal warming effect (or GWP) than CO 2 —the GWP for CH 4 is 21 times that of CO 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 CO 2 equivalent emissions.

B.3 Sources of Non-Air Pollution

There are three basic types of non-air polluti on associated with oil and gas extraction:

• Produced water: Consists of water and treatment ch emicals 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 genera ted naturally from petroleum reservoirs or operations using primary and secondary recovery techniques. Chemical compositions of produced wate r can differ substantially between sources and between development and production tech niques. Produced water is us ually stored in tanks for surge capacity and to separate oil from water before dispos al. 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 larg est 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 dow n the drilling pipe to offset formation pressure, provide lubrication, and seal o ff the wellbore to avoid contamination and remove cuttings). This includes synthetic muds and fluids.

• Other associated wastes: Include oily soil, tank botto ms, workover fluids, produced sand, pit and sump waste, pigging waste, ir on 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 se parators, treating vessels, and crude oil stock tanks.

U.S. Environmental Protection Agency Working Draft – September 2008 B-6APPENDICES

– 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 flui ds are expected to contain HAPs. The waste composition data for workover fluids provided by the American Petroleum Institute (API) are mainly based on spen t 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 st ore production fluids. As in tank bottoms, heavy materials settle on the bo ttom of pits or sumps and must be removed. Composition of pit and sump wastes varies between facilities.

– Pigging waste: Produced when pipelines are cl eaned or “pigged.” The waste consists of produced water, condensed wate r, 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-7APPENDICES 

## Appendix C: Data Availability and Sources

The initial task conducted in this analysis was to identi fy 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 se ctor. This assessment was conducted with a primary focus on Region 8 data availability, but also included a broader assessment of general data availa bility for the oil and gas industry.

A baseline characterization of the indust ry’s environmental impacts requires the following information:

• Baseline and benchmarking information for a pa rticular base year, including facility data, oil and gas production, well characterist ics, geology, and depth; energy use; and equipment and process data.

• Emissions data for specific sources and sour ce 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 ta bles 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 informa tion on wells and gas pr ocessing facilities, existing and planned (i.e., t hose applying for permits). State databases of wells are maintained by:

• Colorado Oil and Gas Conserva tion Commission (wells and f acilities 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 Co mmission (wells and gas plants).

In addition, the states’ oil and gas database contains information about wells in tribal lands. ICF International maintains a co mprehensive nationwide database with information on every oil and gas well, incl uding historical pro duction and well depth.

U.S. Environmental Protection Agency September 2008 C-1APPENDICES
The database is currently being updated. Ta ble C-1 shows the curr ent oil and gas well count (without updates) for each state in Region 8 for 2006.

Table C-1. ICF Oil and Gas Well Count by State, 2006

State # of Oil Wells # of Gas Wells Total

CO 7,567 19,993 27,560 MT 5,862 4,078 9,940 ND 3,120 178 3,298 SD 158 71 229 UT 2,401 5,012 7,413 WY 10,205 25,052 35,257 Total 29,313 54,384 83,697

The U.S. Energy Information Administration (EIA) within the U.S. Department of Energy (DOE) also has oil and gas well data, including information from marginal wells, which was developed in connection with th e 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 assessi ng 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 genera lly in line with ICF data.

In other oil and gas produci ng regions, state governments and the Minerals Management Service within the U.S. Department of the In terior (for federal offshore areas) maintain records of oil, gas, and in most cases water production, by “pr operty.” A property is either a single gas or oil well, or in the cas e 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, th ese data can be obtained from Web sites maintained by the state. Also, data aggregat ing 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 produ ction for any geographic area of interest.

Table C-2. EIA Oil and Gas Well Count by State, 2004

State # of Oil Wells # of Gas Wells Total

CO 4,288 23,208 27,496 MT 3,765 5,356 9,121 ND 3,122 428 3,550 SD 75 129 204 UT 2,180 3,936 6,116 WY 10,471 23,370 33,841 Total 23,901 56,427 80,328

5 U.S. PetroSystem, formed in spring 2000, is a cooperative multi-agency program established for creation, maintenance, and sharing of data used in the study of domestic and worldwide oil and gas resources, re serves, 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 fo r shared knowledge gained from cooperation. At present, U.S. PetroSystem member organizations include EIA, NETL, and the U.S. Geological Survey.

U.S. Environmental Protection Agency September 2008 C-2APPENDICES

For our emissions estimates, we used the Lasse r 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 pro cessing every year. Howeve r, 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 databa se 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 indust ry, but only at the national level.

ICF, as part of its 1998 industrial energy cons umption base year work, has estimated total energy consumption for the energy mining i ndustry (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/pro cess 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 equipmen t. These state-level data may be available in some places, but there is substantial variab ility in the availability and usefulness of such data for this type of an alysis. The availability and a pplicability 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 give n complete access to information on the tanks. Also, facilities are not identified by type of busin ess/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 averag e 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 pa rt of the state. Emission levels and control information are included.

U.S. Environmental Protection Agency September 2008 C-3APPENDICES

– 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 Comp ensation 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 pressu re 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 contai ns 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 calcul ating volatile organic compound (VOC) emissions from storage tanks.

– WDEQ developed emissions factors and guidance for calculating various emissions from oil and gas production activ ities as part of its permit process.

C.2 Air Emissions Data

C.2.1 Criteria Air Emissions and Data Sources Considered

Several potential sources of air emissions data were considered for use in this analysis.

National Emissions Inventory

EPA’s National Emissions Inventory (NEI) is intended to be a comprehensive facility and emission unit-specific database covering al l criteria air polluta nts and hazardous air pollutants (HAPs) nationally. In general, NE I is used by states and EPA for air quality modeling and planning purposes, and was de veloped by EPA’s Emission and Inventory Analysis Group in Research Triangle Park, Nort h 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 inte rest for this project (VOCs, sulfur dioxide (SO 2 ), nitrogen oxides (NO x ), and particulate matter (PM ))—and 187 HAPs. In addition, NEI addresses emissions data for all major c ontributors to air pollution, including point, mobile, and nonpoint sources. Emission estima tes are available currently for years 1990 and 1996 through 2002 for cr iteria pollutants and for y ears 1999 through 2002 for HAPs

.

U.S. Environmental Protection Agency September 2008 C-4APPENDICES
The point source emissions are re presented in NEI for individual processes at an industrial facility. NEI is developed using the latest da ta and best availabl e estimation methods, including data from continuous emissions mon itors (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 NONR OAD models. Seasonal and daily records submitted by state, local, and tr ibal agencies are included in NEI, although their emissions are excluded from annual emission summary totals.

Criteria pollutant emissions for NEI are co llected under the Consolidated Emissions Reporting Rule (CERR) (40 CFR Part 51). U nder CERR, states are required to report emissions of SO 2 , VOCs, NO x , carbon monoxide (CO), lead (Pb), PM 10 , PM 2.5 , and ammonia (NH 3 ). Large sources (Type A) are required to report annually, while the other sources (Type B) are required to report ev ery 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 relativ e to the amount of pr oduction underway (and facilities operating), as reflected in Appendix A.

Table C-3. NEI Data on Oil and Gas Production Facilities in Region 8, 2002

State Crude Petroleum and Natural Gas Extraction (SIC 1311) Natural Gas Liquids (SIC 1321) Total

CO 28 6 34 MT 4 1 5 ND 0 0 0 SD 0 0 0 UT 5 3 8 WY 13 5 18 Total 50 15 65

NEI data are based on a combination of me thods, including fac ility reporting, modeling, and estimates. There are generally inconsistencies in how sources of emissions are categorized and emissions estimates are calcula ted. Missing data also ca ll into question the overall reliability of the NEI dataset with respect to o il and gas production facilities currently operating. Areas where experience with NEI has shown data unreliability include:

• A substantial number of data values are mi ssing, 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 a pproximately 1,500 large boilers known to be operational).

• For a given emissions unit, the Source Classi fication Code (SCC) used to classify it may be different than the unit description.

U.S. Environmental Protection Agency September 2008 C-5APPENDICES

• 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 missi ng, 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 fo r 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. An alysis 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 i nventory data from i ndividual states. Some states in Region 8 maintain an air emissi ons inventory, and it is likely that similar inventories would be available in othe r 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 indus try/source and pollutant type (CO, NO x , PM 10 , SO 2 , 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 w ithin the state: CO, NO x , PM 10 and PM 2.5 , SO x , and VOCs. HAP emissions ar e reported for each county in pounds per year, listed by chemical or ch emical class. No data are specified directly for the oil and gas industry. Th e 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 i nventories available for tribal areas, and they are specific to one trib e. The Western Regional Air Partnership (WRAP) has initiated a data assessment for an air emissi ons inventory for tribes, and associated work is ongoing.

U.S. Environmental Protection Agency September 2008 C-6APPENDICES
As shown above, some of the states in Regi on 8 maintain some emission inventories for the oil and gas sector, and others do not. Ther e 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); howeve r, 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 gove rnmental 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 volunt ary 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 ar eas 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 deve lopment 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 a nd forecasts the anticipat ed emissions that will result from current regulatory requireme nts and alternative control strategies.

As part of its air quality pl anning work, WRAP has developed criteria emissions data for two major categories: point or stationary s ources, and area or nonpoint sources. It has also developed data for on-road mobile source s; 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 comple te 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 calculat ed. The approach WRAP used could be replicated, if necessary, to estimat e 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 D ecember 2007. The air emissions data obtained from WRAP included estimates for NO x , SO 2 , VOCs, CO, particulates, NH 3 , and hydrogen sulfide (H 2 S). Details on these data sources are provided below.

U.S. Environmental Protection Agency September 2008 C-7APPENDICES

C.2.2 WRAP Data on Point Sources

WRAP’s point source database c ontains a variety of information for each stationary point source in the region, including all emission po ints on site; stack pa rameters (height, diameter, flow, velocity, temp erature, type); production ra tes (design capacity, maximum nameplate capacity); actual throughp ut fuel parameters (heat c ontent, ash content, sulfur content); SIC code; North American Indus try Classification System (NAICS) code (although not available for all records); location (latitude, longitude); and emission controls. Though the database is the region’s most comprehe nsive source for criteria emissions data, data for some of the importa nt fields, specifically those pertaining to production and throughput, are missing.

Table C-4 shows the number of oil and gas pl ants/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 natu ral gas liquid extracti on facility category. Although Wyoming has high gas production, the s ources 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 presen ted in this report. The tribal land data in the WRAP database is not organized or liste d by state location.. Exam ination 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 Fac ilities in WRAP by State and SIC Code

SIC SIC Description CO MT ND UT SD WY Total
1311 Crude Petroleum and Natural Gas 3,927 149 40 199 0 354 4,669 1321 Natural Gas Liquids 3,491 18 40 93 0 182 3,824 1381 Drilling Oil and Gas Wells 0 0 0 0 0 0 0 1382 Oil and Gas Field Exploration Services 0 0 0 0 0 0 0 1389 Oil and Gas Field Services, not elsewhere classified 41 0 0 0 0 27 68

Total 7,459 167 80 292 0 563 8,561

C.2.3 WRAP Data on Area Sources

WRAP also has an inventory report on area source emissions from oil and gas production for the year 2002. The report, An Emission Inventory of Non-Point Oil and Gas Emissions Sources in the Western Region, was published in December 2005. It includes

U.S. Environmental Protection Agency September 2008 C-8APPENDICES
emissions from tanks, compressors, and engines not included in the point source emissions inventory as part of th e 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 NO x and VOC emissions. Beginning in 2006, WRAP refined the inventory’s “f irst cut” emissions numbers with more precise data on basin-specific activity. It also examined po ssible options for cont rolling the emissions that come from individually small but ubi quitous pieces of field production equipment, including drill rigs, gas compressors, coal bed methane (CBM) pumps, liquid hydrocarbon storage tanks, glyc ol dehydration units, pneumatic instrument controls, and completion flaring and well-venting procedur es. The 2006 effort expa nded the inventory to include SO 2 emissions. This effort was completed in fall 2007. The latest data obtained from WRAP also included CO em issions in the area source in ventory. This latest set of data was used for this analysis.

As the WRAP analysis did not include da ta for area source emissions beyond the four pollutants discussed above (NO x , VOCs, SO 2, and CO), other area source emissions, including PMs, are not included in this an alysis. 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 th is is probably not a large omission.

C.2.4 Hazardous Air Pollutants

WRAP data do not include HAPs, however, th e 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 emissi ons factors provided by WDEQ and WRAP area source assumptions. WD EQ has developed factors that relate emissions factors for HAPs and VOCs for vari ous 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 so urce 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 em issions. 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 em issions factors from WDEQ that were used in the analysis.

Table C-5. HAPs and VOC Emissions Factors by Source

Source Units VOCs HAPs Gas Well Dehydrators lbs/yr/MMCFD 27,485.6 13,695.6 Condensate Tanks Uncontrolled lbs/yr/barrel per day 3,271.0 116.0 Oil Well Tanks lbs/yr/barrel per day 160.00 2.66 Gas Well Completion—Flaring and Venting tons/well 86.0 3.0 Condensate Tanks Controlled lbs/yr/barrel per day 65.740 2.320 Gas Well Pneumatic Devices tons/well 0.200 0.008 Oil Well Pneumatic Devices tons/well 0.100 0.004

U.S. Environmental Protection Agency September 2008 C-9APPENDICES

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 CO 2 emissions. However, the level of detail in the EPA inventory is not sufficient for apportioning emissions to Region 8 sources as readily as fuel consump tion, which can be used to calculate CO 2 emissions directly . The fuel consumption values for 2002 we re taken directly from the 2002 Census of Mining, which reports fuel consumption fo r the following major segments of the oil and gas industry by NAICS:

• NAICS 211111: Crude Petroleum and Natural Gas Extraction;

• NAICS 211112: Natural Ga s 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 Ce nsus 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 th e 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 cons istent 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 CO 2 estimates by end use, in general we used WRAP point source estimates for SO 2 emissions, which are available by SCC. The SCC emissions data are provided by fuel type. The SO 2 emissions by SCC were used to apportion the CO 2 emissions by fuel and SO 2 content. CO 2 emissions were estimated by fuel by SCC. There were instances where the SO 2 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 IC Es. 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 de tailed as for the crit eria pollutants, it provides a general breakdown.

C.2.6 Methane Emissions

Methane emissions are significant in th e 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 CH 4 emissions estimates used in this analysis. The report provides national CH 4 emissions for various sources in the oil and gas production indus try. These national emissions by source were then allocated by st ate, based on appropria te factors for each

U.S. Environmental Protection Agency September 2008 C-10APPENDICES
process, such as gas pro duction, 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 analys is include produced wate r and drilling waste. A database maintained by the industry data aggregation company, Lasser Inc., was used to estimate the amount of produced water resu lting from oil and gas operations in Region 8. The database also includes well-count a nd oil and gas producti on data, which were used for this study. The amount of produced water can be calculat ed using geological data and standard production factors in orde r to estimate future produced water volumes.

Another database, called the IHS database, whic h 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, includi ng 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 roya lty purposes and are widely used by industry and government to characterize e xploration and production activity.

To estimate drilling waste, we first obtained drilling activity information, specifical ly footage data, from the American Petroleum Institu te (API). The amount of waste was calculated based on the data from API and an estimate of the drilling waste f actor (barrels of waste per foot drilled) also from AP I. The drilling waste factors vary by state and are based on the API report, Overview of Exploration and Production Waste Volumes and Waste Management Practic es in the United States (May 2000). Table C-6 shows the drilling waste factors used for each state. Table C-6. Drilling Waste Factors by State

We have not found any real measured data on the other associated wastes. These can be estimated based on industry production factors and drilling data. In 2000, EPA released the analysis, Associated Waste Report: Crude Oil Tank Bottoms and Oily Debris . The information and other data in the report coul d 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 coul d 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 Regi on 8) have guidance on how to calculate VOC emissions from oil tanks. State Bbls/ft CO 0.87 MT 1.52 ND 1.05 SD 1.03 UT 1.68 WY 1.27

U.S. Environmental Protection Agency September 2008 C-11APPENDICES

• The Gas Technology Institute (formerly, Ga s 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 fo r EPA and private clients.

The biggest category of missing data is likel y to be emissions from short-term or intermittent operations, such as drilling a nd well stimulation. It is not clear how significant these are with respect to the overa ll inventory; however, available emission factors can be used to estimate these emi ssions 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 pe nding 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 devel oped their own projec tions 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 ai r emissions projections is WRAP, which developed a detailed forecast of regional ai r emissions for the year 2018 (see Appendix E references). Their projections were based on a projection of th e growth of the oil and gas industry in the region (as provi ded 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 assume d 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 S ources Joint Forum), January 25, 2006.

• Environ Internati onal Corporation, Final Report Oil and Gas Emission Inventories for the Western States (prepared for the Western Gove rnors’ Association), December 27, 2005.

U.S. Environmental Protection Agency September 2008 C-12APPENDICES

• Environ Internati onal Corporation, WRAP Oil & Gas: Part 1: 2002/2005 and 2018 Area Source Emissions Inventory Improvements , May 8, 2007.

• Environ Internati onal 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 re gion, this projection was based on permit data from federal regulators there. It also in cluded proposed or expected new control requirements for engines and process heaters.

As noted, WRAP does not provide projections for HAP and CH 4 emissions. For this study, because of the similarity and relation of emissions sources and factors for VOCs and HAPs, the projection trend in VOC emissi ons was used to estimate HAP emissions, similar to the approach taken for current emissions. For methane emissions, the growth rates in oil and gas producti on in the Rocky Mountain region, as estimated by EIA, were used to extend the 2002 emissions of methane to 2018.

For produced water, the projected growth in NO x emissions from drilling rigs by state from WRAP was used to extrapol ate 2002 produced water levels to 2018.

U.S. Environmental Protection Agency September 2008 C-13APPE NDICES

U.S. Environmental Protection Agency September 2008 C-14 This Page is Intentionally Left Blank.APPENDICESAppendix D: Air Emissions Sources by Source Category and EquipmentTypeTable D-1 describes the primary sources of air emissionsfor each major source category identified in SectionB.1: large compressorstations, natural gas processing plants, stand-alone production sites,and small compressor stations and wellhead sites.Table D-1. Sources of Air Emissionsby Equipment Type and Source CategoryInternal Combustion SourcesExternal Combustion SourcesNOx, PM10, PM2.5, VOCs, SOx, CONOx, PM10, PM2.5, VOCs, SOx, COMajor SourceCategoriesNatural Gas-Fired EnginesDiesel-Fired EnginesLine HeatersSeparatorsHeat TreatersGlycol RegeneratorLarge compressorstationsCompressors, generatorsEmergency generators notused under normal serviceMaintain temperature ofgas to reduce formationof natural gas hydrates intransmission linesNoNoUsed to drive off waterabsorbed by the glycol whenthe “wet” natural gas wasbubbled through it in a gasdehydratorNatural gas processingplantsCompressors (primarilyreciprocating engines),generators, pumping unitsEmergency generators notused under normal serviceNoIf no source can accept thegas, compression, orcombustion flare, vessel willvent to the atmosphere tomaintain flow of the liquid toother separators, treatment,and storage vesselsNoUsed to drive off waterabsorbed by the glycol whenthe “wet” natural gas wasbubbled through it in adehydratorStand-alone productionsites (intermediate-sizedfacilities)Compressors (primarilyreciprocating engines),generators, pumping unitsEmergency generators notused under normal serviceUsed to heat the fluidafter it takes a pressuredrop through the “choke”at the wellheadIf no source is ready to acceptthe pressurized gas,compression, or combustionflare, vessel will vent toatmosphere to maintain flow ofthe liquid to other separators,treatment, and storage vesselsUsed to breakmultiphase emulsion ofoil/water/gas in the fluidUsed to drive off waterabsorbed by the glycol whenthe “wet” natural gas wasbubbled through it in adehydratorSmall compressorstations and wellheadsCompressors (reciprocatingengines), pumping unitsGenerators and prime moversfor drilling ops (mechanicalpump power & powergeneration); generators forCBM ops (to power waterpumps, especially in remoteareas)Used to heat the fluidafter it takes a pressuredrop through the “choke”at the wellheadNoNoUsed to drive off waterabsorbed by the glycol whenthe “wet” natural gas wasbubbled through it in adehydratorU.S. Environmental Protection AgencySeptember 2008D-1APPENDICESExternal Combustion Sources,ContinuedStorage and Separation VesselsNOx, PM10, PM2.5, VOCs, SOx, COVOCsAmine RegeneratorSulfur Recovery UnitCombustion FlareFugitivesSeparatorsGlycol Dehydrator FlashTankLarge compressorstationsNoNoUsed to destroy naturalgas and otherhydrocarbons duringemergency situations(blowdowns, vents, anduncontrolled/unscheduledVOC emissions)Leakage of VOCs from avariety of valves, leaks,and exposed processsourcesNoA portion of the natural gas isremoved from the triethyleneglycol (TEG) due to pressuredropNatural gas processingplantsUsed to remove theentrained pollutants (CO2and H2S) from fluid used ina “sweetening unit.”Pollutants may be flared,vented directly toatmosphere, or sent to asulfur recovery unit.Used to recover sulfur offthe amine regeneratorUsed to destroy naturalgas and otherhydrocarbons duringemergency situations(blowdowns, vents, anduncontrolled/unscheduledVOC emissions)Leakage of VOCs from avariety of valves, leaks,and exposed processsourcesIf there is no source ready toaccept the pressurized gas,compression, or combustionflare, vessel will vent toatmosphere to maintain flowof the liquid to otherseparators, treatment, andstorage vesselsA portion of the natural gas isremoved from the TEG due topressure dropStand-alone productionsites (intermediate-sizedfacilities)Used to remove theentrained pollutants (CO2and H2S) from fluid used ina “sweetening unit.”Pollutants may be flared,vented directly toatmosphere, or sent to asulfur recovery unit.NoUsed to destroy naturalgas and otherhydrocarbons duringemergency situations(blowdowns, vents anduncontrolled/unscheduledVOC emissions)Leakage of VOCs from avariety of valves, leaks,and exposed processsourcesIf there is no source ready toaccept the pressurized gas,compression, or combustionflare, vessel will vent toatmosphere to maintain flowof the liquid to otherseparators, treatment, andstorage vesselsA portion of the natural gas isremoved from the TEG due topressure dropSmall compressor stationsand wellheadsNoNoNoLeakage of VOCs from avariety of valves, leaks,and exposed processsourcesIf there is no source ready toaccept the pressurized gas,compression, or combustionflare, vessel will vent toatmosphere to maintain flowof the liquid to otherseparators, treatment, andstorage vesselsA portion of the natural gas isremoved from the TEG due topressure dropU.S. Environmental Protection AgencySeptember 2008D-2APPENDICESStorage and Separation Vessels,ContinuedVOCsGlycol Dehydrator RegeneratorStill ColumnStorage TanksPressure and Level ControllersGas-Operated Pumps andChemical Injection (CI) PumpsOil/Water SkimmersLarge compressor stationsGlycol will release the water andentrained hydrocarbon under theheat of the regenerator reboilerIncludes both hydrocarbon andwater storage tanks. Salt waterstorage tanks may be hydrocarbonemissions source as some waterseparation techniques leave alayer of oil on top of the water.Equipment that controls the vessellevels and pressure ranges (couldbe several hundred controllers at acompressor station). Certain oldermodels vent gas continuously andat a rate of up to 1000 cubic feetper day (cfd).Pumps move fluids from onestorage vessel to another. CIpumps are used to injectcorrosion, scale, and biologicalinhibitors into flow lines. There canbe significant numbers of CIpumps at well sites at thewellhead.NoNatural gas processingplantsGlycol will release the water andentrained hydrocarbon under theheat of the regenerator reboilerIncludes both hydrocarbon andwater storage tanks. Salt-waterstorage tanks may be hydrocarbonemissions source as some waterseparation techniques leave alayer of oil on top of the water.Condensate storage usuallycontrolled with vapor recoveryunits, though flares may be usedas an alternative control.Equipment that controls the vessellevels and pressure ranges (couldbe several hundred controllers at acompressor station). Certain oldermodels vent gas continuously andat a rate of up to 1000 cfd.NoNoStand-alone productionsites (intermediate-sizedfacilities)Glycol will release the water andentrained hydrocarbon under theheat of the regenerator reboilerIncludes both hydrocarbon andwater storage tanks. Salt waterstorage tanks may be hydrocarbonemissions source as some waterseparation techniques leave alayer of oil on top of the water.Equipment that controls the vessellevels and pressure ranges (couldbe several hundred controllers at acompressor station). Certain oldermodels vent gas continuously andat a rate of up to 1000 cfd.Pumps move fluids from onestorage vessel to another. CIpumps are used to injectcorrosion, scale, and biologicalinhibitors into flow lines. There canbe significant numbers of CIpumps at well sites at thewellhead.Use of natural gas that is bubbledthrough the produced water torelease additional entrained oil iscommon and often not accountedfor in emissions inventoriesSmall compressor stations& wellheadsGlycol will release the water andentrained hydrocarbon under theheat of the regenerator reboilerNoNoPumps move fluids from onestorage vessel to another. CIpumps are used to injectcorrosion, scale, and biologicalinhibitors into flow lines. There canbe significant numbers of CIpumps at well sites at thewellhead.NoU.S. Environmental Protection AgencySeptember 2008D-3U.S. Environmental Protection AgencySeptember 2008D-4NDICESThis Page is Intentionally Left Blank.APPEAPPENDICES 

## Appendix E: References

WRAP References:

Eastern Research Group, Inc., Quality Assurance of th e 2002 WRAP Stationary Sources Emissions Inventory , Western Governors’ Associat ion and Western Regional Air Partnership, Stationary Sources Joint Forum, January 27, 2006.

Eastern Research Group, Inc., WRAP Point and Area Source Emissions Projections for the 2018 Base Case Inventory, Version 1 , Western Governors’ A ssociation and Western Regional Air Partnership, Stationary Sources Joint Forum, January 25, 2006.

E.H. Pechan, 2018 SO 2 Emissions Evaluation for N on-Utility Sources Final Report

, Western Governors’ Association, Stati onary Sources Joint Forum, October 2006.

Environ Internati onal Corporation, Draft Final Report WRAP Area Source Emissions Inventory Projections and Contro l Strategy Evaluation Phase III , Western Governors’ Association, July 2007.

Environ Internati onal Corporation, WRAP Oil & Gas: 2002/2005 and 2018 Area Source Controls Evaluation , Western Regional Air Partnership, Stationary Sources Joint Forum Working Group, May 30, 2007.

Environ Internati onal Corporation, Oil and Gas Emission Inventories for the Western States , January 8, 2007.

Environ Internati onal Corporation, Western States Oil and Gas Emission Inventories, Presentation to Four Corners Joint Air Quality Task Force , January 8, 2007.

Environ Internati onal Corporation, WRAP Oil & Gas: Part 1: 2002/2005 and 2018 Area Source Emissions Inventory Improvements , Western Regional Air Partnership, Stationary Sources Joint Forum Working Group, May 8, 2007.

Environ Internati onal Corporation, Work Plan WRAP Area Source Emissions Inventory Projections and Control Strategy Evaluation , Western Governors’ Association, November 9, 2006.

Environ Internati onal Corporation, Final Report Oil and Gas Emi ssion Inventories for the Western States , Western Governors’ Association, December 27, 2005.

Western Regional Air Partnership, http://www.wrapair.org/ , accessed 2/29/08.

U.S. Environmental Protection Agency September 2008 E-1APPENDICES
Other (non-WRAP) References:

American Petroleum Institute, Overview of Exploration and Production Waste Volumes and Waste Management Practi ces in the United States , May 2000.

American Petroleum Institute, Quarterly Well Completion Report , various editions.

Argonne National Laboratory, A White Paper Describing Produced Water from Production of Crude Oil, Natural Gas, and Coal Bed Methane , U.S. Department of Energy, January 2004.

Canada National Energy Board, Analysis of Horizontal Gas Well Performance in British Columbia, British Columbia Ministry of Energy and Mines, Oil and Gas Commission of British Columbia, October 2000

. Colorado Department of Public Health and Environment, Air Quality Control Commission, Regulation No. 7, Section XII, http://www.cdphe.state.co.us/ap/reg7/o&greg7.pdf , accessed 2/29/08.

Connelly, Joel, National Wildlife Federation, Frontal Assault , Aug/Sep 2004, vol. 42 no. 5, http://www.nwf.org/nationalwildlife/a rticle.cfm?issueID=69&articleID=959 , accessed 2/29/08.

Earth Justice, Notice of Intent to Sue EPA Under the Clean Air Act, Nicholas F. Persampieri, July 2008

. Eastern Research Group, Inc., Preferred and Alternative Me thods for Estimating Air Emissions from Oil and Gas Field Production and Processing Operations , Emission Inventory Improvement Program, Poin t Source Committee, September 1999.

Environmental Working Group, Who Owns the West? Oil and Gas Leases: Roan Plateau, Colorado, http://www.ewg.org/oil_and_gas/part6.php , accessed 08/21/ 08

. Federal Reserve Board, Industrial Production and Capacity Utilization

, http://www.federalreserve.gov/releases/g17/ , accessed 2/29/08.

Four Corners Air Quality Task Force, http://www.nmenv.state.nm.us/aqb/4C/index.html

, accessed 2/29/08.

Houston Advanced Research Center, VOC Emissions from Oil and Condensate Storage Tanks

. Hung-Ming Sung, Trinity Consultants, Estimation of HAP Emissions from Oil and Gas E&P Operation Wastes Paper No. 368 , June 19, 2000.

ICF International, Beneficial Reuse of Industrial By products in the Gulf Coast Region

, prepared for EPA’s Sector Strategies Program, February 2008.

U.S. Environmental Protection Agency September 2008 E-2APPENDICES
ICF Consulting, Overview of Exploration and Pr oduction Waste Volumes and Waste Management Practices in the United States , American Petroleum Institute, May 2000.

IHS Inc, U.S. Gas Production Data

. Independent Petroleum A ssociation of America, Testimony of the Independent Petroleum Association of America Before the Comm ittee on Oversight and Government Reform

, U.S. House of Representatives, Hearing on Oil and Gas Exemptions in Federal Environmental Protections, October 31, 2007.

Lasser, Inc., Lasser Oil and Gas Production Data, March 2008.

Michigan Department of Environmental Qu ality, Environmental Science and Services Division, Emissions Calculation Fact Sheet Oil and Gas Production Facilities , October 2006.

National Academy of Sciences, Oil in the Sea III: Inputs, Fates, and Effects , 2003.

Natural Resources Defense Council, Drilling Down: Protecting Western Communities from the Health and Environmenta l Effects of Oil and Gas Production , October 2007, http://www.nrdc.org/land/use/down/down.pdf , accessed 2/29/08.

New Mexico Environment Department, San Juan VISTAS, http://www.nmenv.state.nm.us/aqb/projects/SJV/ , accessed 2/29/08.

Oil and Gas Accountability Project, Colorado Oil and Gas Industry Spills: A Review of COGCC data (June 2002-June 2006)

, http://www.earthworksaction.org/pubs/Spills.pdf

, accessed 2/29/08.

Oil and Gas Accountability Project, Our Drinking Water at Risk: What EPA and the Oil and Gas Industry Don’t Want Us to Know About Hydraulic Fracturing , April 2005, http://www.earthworksaction.org /pubs/DrinkingWaterAtRisk.pdf , accessed 2/29/08.

Petroleum Technology Alliance Canada, Filling the Gap: Unconventional Gas Technology Roadmap, June 2006

Red Lodge Clearinghouse, BLM moves to reduce air emissions from energy development in Uinta Basin , February 2008, http://rlch.org/content/view/344/62/ , accessed 2/29/08.

Rogers, D., G. Fout and W.A. Piper, New Innovative Process Allo ws Drilling without Pits in New Mexico , 13 th Annual International Petroleum Environmental Conference, October 17—20, 2006, http://ipec.utulsa.edu/Conf2006/Papers/Piper_5.pdf , accessed 2/29/08.

Russel, James, et al, An Emission Inventory of Non-poi nt Oil and Gas Emissions Sources in the Western Region , May 2006.

U.S. Environmental Protection Agency September 2008 E-3APPENDICES
Shell Oil Company, A National Dialogue on Energy Security: The Shell Final Report

, http://www.shell.com/static//usa/downloads/e nergy_security/pdf/shell_final_report.pdf

, accessed 2/29/08.

U.S. Census Bureau, Crude Petroleum and Natural Gas Extraction: 2002, 2002 Economic Census Mining Industry Series , December 2004.

U.S. Census Bureau, Drilling Oil and Gas Wells: 2002, 2002 Economic Census Mining Industry Series , December 2004.

U.S. Census Bureau, Natural Gas Liquid Extraction: 2002, 2002 Economic Census Mining Industry Series , December 2004.

U.S. Census Bureau, Support Activities for Oil and Gas Operations: 2002, 2002 Economic Census Mining Industry Series , December 2004.

U.S. Congress, Office of Technology Assessment, Managing Industrial Solid Wastes from Manufacturing, Mining, Oil and Gas Production, and Utility Coal Combustion

, March 1992.

U.S. Department of Energy, En ergy Information Administration, Annual Energy Outlook

. U.S. Department of Energy, En ergy Information Administration, Natural Gas Pipelines in the Central Region

, http://www.eia.doe.gov/pub/oil_gas/natural_gas/ analysis_publications /ngpipeline/central. html , accessed 2/29/08.

U.S. Department of Energy, En ergy Information Administration, Natural Gas Processing: The Crucial Link Between Na tural Gas Production and Its Transportation Market , January 2006.

U.S. Department of Energy, Energy Informa tion Administration, various data on oil and gas production.

U.S. Department of Energy, Enhanced Oil Recovery (EOR) Research Program.

U.S. Department of the Interior, U.S. Bureau of Land Management, First Record of Decision on Roan Plateau Plan , June 8, 2007, http://www.blm.gov/rmp/co/roanplateau/

, accessed 3/13/08.

U.S. Department of the Inte rior, U.S. Geological Survey, http://pubs.usgs.gov/fs/fs-158- 02/FS-158-02.pdf , accessed 2/29/08.

U.S. Department of Labor, Occupational Sa fety and Health Admi nistration, Voluntary Protection Programs, http://www.osha.gov/dcsp/vpp/ , accessed 2/29/08.

U.S. Environmental Protection Agency, Associated Waste Report: Crude Oil Tank Bottoms and Oily Debris , 2000.

U.S. Environmental Protection Agency September 2008 E-4APPENDICES
U.S. Environmental Protection Agency, Economic Impact Analysis of Disposal Options for Produced Waters from Coalbed Me thane Operations in EPA Region 8 , September 25, 2001, public meeting, Billings, Montana, http://www.epa.gov/region8/wate r/wastewater/cbm/Agenda010925.pdf , accessed 2/29/08.

U.S. Environmental Protection Agency, EPA’s Clean Water Act Review of the Coalbed Methane (CBM) Industrial Sector , June 2007, http://www.epa.gov/guide/304m/2008/cmbslides.pdf /08.

U.S. Environmental Protection Agency, EPA Coalbed Methane Extraction Sector Questionnaire , January 2008, , accessed 2/29/08.

U.S. Environmental Protection Agency, Evaluation of Impacts of Underground Sources of Drinking Water by Hydraulic Frac turing of Coalbed Methane Reservoirs , EPA 816-R04-003, 2004, , accessed 2/29/08.

U.S. Environmental Protection Agency, Exemption of Oil and Gas Exploration and Production Wastes from Federal Hazardous Waste Regulations, October 2002, , accessed 08/21/08.

U.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005 , April 2007.

U.S. Environmental Protection Agency, Natu ral Gas STAR Program, , accessed 2/29/08.

U.S. Environmental Protection Agency, Oil & Gas Beneficial Reuse Summary, Region 8 Exploration and Production Report

. U.S. Environmental Protection Agency, Office of Enforcement and Compliance Assurance, Profile of the Oil and Ga s Extraction Industry Sect or Notebook, Chapter 5, Pollution Prevention Opportunities

, , accessed 2/29/08.

U.S. Environmental Protection Agency, Regional Haze Program, , accessed 2/29/08.

U.S. Environmental Protection Agency, Region 8, Report of the Oil and Gas Environmental Assessment Effort 1996-2002, January 2003

. U.S. Environmental Protection Agency, Revised Draft Supplemental Environmental Impact Statement for the Pinedale Anticlin e Oil and Gas Exploration and Development Project,http://www.epa.gov/region8/comp liance/nepa/nepadocs/ FinalEPACommentsOnP inedaleAnticline14Feb08.pdf, accessed 08/21/ 08

. U.S. Federal Energy Regulatory Commission, Natural Gas Markets: Western

, , accessed 2/29/08.

U.S. Environmental Protection Agency September 2008 E-5APPENDICES
U.S. House of Representatives, H.R. 6, En ergy Independence and Security Act of 2007, Sec.1502. 7-Year Amortization of Geological and Geophysical Expenditures for Certain Major Integrated Oil Companies.

U.S. Internal Revenue Code of 1986, § 167. Depreciation, , accessed 2/29/08.

Western Climate Initiative, , accessed 2/29/08.

Western States Air Resources Council, , accessed 2/29/08.

Western States Air Resources Council, September 2007, WESTAR conference,

, accessed 2/29/08.

Wyoming Department of Environmen tal Quality, Air Quality Division, Oil and Gas Production Facilities Chapter 6, Section 2 Permitting Guidance , June 2007.

Wyoming Department of Environmental Qu ality, Voluntary Remediation Program, , accessed 2/29/08.

U.S. Environmental Protection Agency September 2008 E-6APPENDICES

This Page is Intentionally Left Blank.

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