&EPA
United States
Environmental Protection
Agency
Coalbed Methane Extraction:
Detailed Study Report
December 2010
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U.S. Environmental Protection Agency
Office of Water (43 03 T)
1200 Pennsylvania Avenue, NW
Washington, DC 20460
EPA-820-R-10-022
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Coalbed Methane Extraction:Detailed Study Report December 2010
CONTENTS
Page
1. EXECUTIVE SUMMARY/INTRODUCTION 1-1
2. DATA COLLECTION ACTIVITIES 2-1
2.1 Stakeholder Outreach 2-1
2.2 Site Visits 2-2
2.3 Data Collection to Identify the Affected Universe 2-3
2.4 EPA CBM Industry Questionnaire 2-3
2.4.1 Screener Questionnaire 2-3
2.4.2 Detailed Questionnaire 2-4
2.5 Collection and Review of Current State and Federal NPDES Regulatory
Requirements 2-5
3. TECHNICAL AND ECONOMIC PROFILE OF THE CBM INDUSTRY 3-1
3.1 CBM Gas Production 3-1
3.1.1 History of Production in the CBM Basins 3-3
3.1.2 CBM Production 3-6
3.1.3 Potential for Development in New CBM Basins 3-7
3.2 Produced Water Characteristics 3-8
3.2.1 Volumes of Produced Water 3-8
3.2.2 Pollutants in Produced Water 3-9
3.3 Management of Produced Water 3-10
3.3.1 Discharge to Surface Water or POTW 3-15
3.3.2 Zero Discharge (with No Beneficial Use) 3-15
3.3.3 Zero Discharge (with Beneficial Use) 3-17
3.4 Treatment Methods 3-18
3.4.1 Aeration 3-18
3.4.2 Sedimentation/Chemical Precipitation 3-19
3.4.3 Reverse Osmosis 3-19
3.4.4 Ion Exchange 3-19
3.4.5 Electrodialysis 3-20
3.4.6 Thermal Distillation 3-20
3.4.7 Multiple Technology Applications 3-20
3.5 Current Economics of CBM Production 3-21
3.5.1 Number of Wells and Projects 3-21
3.5.2 Financial Characteristics of CBM Projects 3-23
3.5.3 Operators of CBM Projects 3-29
3.6 Trends and Projections 3-35
3.6.1 The Present and Future of CBM 3-35
3.6.2 Wellhead Gas Price Projections 3-37
3.6.3 Trends in Costs of Production 3-38
3.6.4 The Future of Existing Basins 3-40
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Coalbed Methane Extraction:Detailed Study Report December 2010
CONTENTS (Continued)
Page
4. ENVIRONMENTAL ASSESSMENT CONSIDERATIONS 4-1
4.1 Documented Impacts From the Direct Discharge of CBM Produced Water 4-2
4.2 Potential Environmental Impacts From the Direct Discharge of CBM
Produced Water 4-5
4.3 Nonsurface Water Environmental Impacts Associated With CBM
Produced Water 4-8
4.3.1 Land Application Impacts 4-8
4.3.2 Impoundment Control Technology Impacts 4-10
4.4 Assertions of No Environmental Impact Caused by CBM Produced Water 4-11
5. REFERENCES 5-1
Appendix A SUMMARY OF PERMITTING PRACTICES AND REQUIREMENTS
11
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Coalbed Methane Extraction:Detailed Study Report December 2010
LIST OF TABLES
Page
1-1 Currently Producing CBM Basins and Locations 1-1
2-1 Site Visit Numbers and Locations 2-3
2-2 Common NPDES Permit Parameters and Limitations 2-6
3-1 Characteristics of Major CBM Basins 3-4
3-2 CBM Production by Basin in 2008 3-6
3-3 Prospective But Nonproducing CBM Resources 3-7
3-4 Volumes of CBM Produced Water Discharged to Surface Waters in the
Discharging Basins (2008) 3-8
3-5 IDS Concentrations in CBM Produced Water by Basin 3-10
3-6 Pollutant Concentrations in CBM Produced Water by Basin 3-10
3-7 CBM Produced Water Management Practices Ob served During Site Vi sits 3-13
3-8 Number of Projects by Produced Water Management Practices Reported 3-14
3-9 UIC Program: Well Classes and Description 3-16
3-10 Wells and Projects by Discharging and Zero Discharge Basins 3-22
3-11 Characteristics of Discharging vs. Zero Discharge Projects 3-23
3-12 2008 Wellhead Prices ($/Mcf) 3-24
3-13 2008 Estimated Gross Revenues ($millions) by Basin, Discharging Basins vs.
Zero Discharge Basins 3-25
3-14 Estimated 2008 Gross Revenues ($millions) by Basin, Discharging Projects vs.
Zero Discharge Projects 3-26
3-15 Assumptions Used in U.S. DOEEIA Cost Models for Four Key CBM Basins 3-28
3-16 Operating Costs and Costs of Equipment Assuming a 10-Well Lease in Four Key
CBM Basins (2008) 3-29
3-17 Number of CBM Operators by Size of Firm 3-30
3-18 Numbers of Operators by Discharge Status and Basin 3-31
3-19 Key Financial Information for Publicly Held CBM Firms (2008) 3-32
iii
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Coalbed Methane Extraction:Detailed Study Report December 2010
LIST OF TABLES (Continued)
Page
3-20 Key Financial Ratios for Public CBM Firms Compared to the OGJ 150 (2008) 3-34
3-21 Average Monthly U.S. Wellhead Price, 2008-2010 3-38
3-22 Summary of Information Important to Future Production Trends in the Major
Discharging Basins 3-40
4-1 Summary of Literature Review Results by Search Category and Type of
Environmental Impact 4-1
4-2 Summary of Documented Impacts From the Direct Discharge of CBM Produced
Water Cited in Peer-Reviewed Literature 4-3
4-3 Scientific Studies Evaluating Potential Environmental Concerns From the Direct
Discharge of CBM Produced Water 4-6
4-4 Scientific Studies Evaluating Nonsurface Water Environmental Concerns
Associated With Land Application of CBM Produced Water 4-9
4-5 Scientific Studies Evaluating Nonsurface Water Environmental Concerns
Associated With Control Technologies for CBM Produced Water 4-11
IV
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Coalbed Methane Extraction:Detailed Study Report December 2010
LIST OF FIGURES
Page
1-1 Locations of Currently Producing CBM Basins 1-2
3-1 Profile of a Typical Western CBM Well With Open Hole Completion (DeBruin,
etal.,2001) 3-2
3-2 Diagram of Potential Path of Produced Water 3-11
3-3 Projections of Natural Gas Consumption and Supply 3-36
3-4 Projections of Shares of Total Gas Production by Type 3-36
3-5 Projections of Natural Gas Wellhead Price 3-37
3-6 Indices for Gas Equipment and Annual Operating Costs and Gas Prices in Real
1976 Dollars 3-39
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Coalbed Methane Extraction:Detailed Study Report
December 2010
1.
EXECUTIVE SUMMARY/INTRODUCTION
This report summarizes the information collected and analyzed by the U.S.
Environmental Protection Agency (EPA) as part of a study of the coalbed methane (CBM)
extraction industry. Currently, CBM discharges are not covered by an Effluent Limitation
Guideline (ELG), but are regulated under Best Professional Judgment (BPJ) permits.
CBM is a form of natural gas that is found in coal seams and is extracted by drilling wells
into the coal seams. Unlike extraction of conventional natural gas, CBM extraction requires the
removal of groundwater to reduce the pressure in the coal seam, which allows CBM to flow to
the surface through the well. This water must be managed and, in several states, is sometimes
permitted for discharge directly or indirectly (via a publicly owned treatment works [POTW]) to
surface waters.
CBM is currently produced in 15 basins1 as shown in Table 1-1 (U.S. EPA, 2010a).
Figure 1-1 illustrates the locations of these basins. The states in which direct or indirect
discharges to surface waters are occurring are Alabama, Colorado, Illinois, Montana,
Pennsylvania, West Virginia, Wyoming, and Virginia.
Table 1-1. Currently Producing CBM Basins and Locations
Basin
Appalachian
Black Warrior
Cahaba
Greater Green River
Powder River Basin (PRB)
Raton
San Juan
Uinta-Piceance
Anadarko
Arkoma
Cherokee/Forest City
Arkla
Permian/Ft. Worth
Illinois
Wind River
States
Virginia a, West Virginia a, Pennsylvania a
Alabama a
Alabama a
Wyoming a
Montana a, Wyoming a
Colorado a, New Mexico
New Mexico
Utah, Colorado
Oklahoma
Oklahoma, Arkansas
Kansas
Louisiana
Texas
Illinois a, Indiana
Wyoming a
a - States that permit CBM produced water discharge to surface water or POTW.
1 Basins are defined as large regions underlain by coalbeds with known CBM resources.
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2010 Coalbed Methane Detailed Study Report
Key
Coalted Methane Basins
25C
500
I
1,000 Miles
Sounce: Energy Information Administration (EIA)
IN
W-4-E
Figure 1-1. Locations of Currently Producing CBM Basins
EPA received comments during the 2005 annual review from citizens and environmental
advocacy groups requesting development of a regulation. In 2005, EPA identified the CBM
extraction industry as a candidate for a preliminary study (U.S. EPA, 2006).
For the 2006 annual review, began EPA collecting data on the number of active basins
producing CBM and their produced water disposal practices. In 2007 EPA began a more detailed
study of the CBM industry. EPA gathered additional information; including conducting
numerous site visits to meet with stakeholders and observe a number of CBM produced water
treatment technologies.
For this detailed study, EPA used a three-pronged approach to collect additional data on
this industry: (1) meetings with stakeholders, (2) site visits, and (3) industry surveys—a national
screener survey and a statistically sampled detailed survey.
EPA developed a technical and economic profile of the industry, which details
information on CBM wastewater discharges, treatment technologies that are available to treat
pollutants associated with CBM discharges (mostly total dissolved solids [IDS]), and the
financial and economic characteristics of the industry.
Using survey responses and other data, EPA evaluated the following: the quality and
quantity of produced water generated from CBM extraction; the available management, storage,
treatment, and disposal options; and the potential environmental impacts of surface discharges.
The findings from this detailed study are described in this report and include:
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Coalbed Methane Extraction:Detailed Study Report December 2010
• Approximately 45 percent of all produced water is discharged to waters of the
United States.
• Various pollutants such as sodium, calcium, and magnesium (used to calculate the
sodium adsorption ratio [SAR]), total suspended solids (TSS), and metals (e.g.,
selenium, chromium) are present in discharges.
• Surface water discharges of produced water can increase stream volume,
streambed erosion, suspended sediment, and salinity.
• Pollutants from CBM discharges may negatively affect fish populations over
time.
• Surface impoundment and land application of produced waters may impact
groundwater from infiltration and the concentration and/or bioaccumulation of
CBM-associated pollutants.
• Advanced water treatment options are being used in the field in some operations
to remove pollutants in produced water.
• Widely practiced zero discharge options may be available depending on well
location.
• Although the recent downturn in the economy has negatively impacted the CBM
industry, projections going forward appear more optimistic, with higher prices for
gas predicted over the longer term.
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Coalbed Methane Extraction:Detailed Study Report December 2010
2. DATA COLLECTION ACTIVITIES
EPA collected and evaluated information from numerous sources to support the
development of the CBM Detailed Study. EPA used this data to develop an industry profile,
characterize the wastewater and identify potential pollution control technologies, review the
potential pollutant load reductions associated with certain treatment technologies, and review
environmental impacts associated with discharges from this industry. This chapter discusses the
following data collection activities:
• Meetings with industry and stakeholders (Section 2.1);
• Site visits, including the site selection process and the information collected
(Section 2.2);
• Data collection to identify the universe of entities for a survey effort (Section 2.3);
• Industry survey activities, including a description of the questionnaires (Section
2.4); and
• Collection and review of National Pollutant Discharge Elimination System
(NPDES) permits (Section 2.5).
Other data examined in this study include information from wastewater treatment
equipment vendors, the U.S. Geological Survey (USGS), and literature and Internet searches on
CBM processes, technologies, wastewaters, pollutants, and regulation. In addition, EPA
considered information provided in public comments during the effluent guidelines planning
process, as well as other contacts with interested stakeholders. EPA also used publicly available
information from the U.S. Department of Energy's (U.S. DOE's) Energy Information
Administration (EIA), various state oil and gas commission websites, Securities and Exchange
Commission (SEC) filings by publicly held firms identified as producing CBM, the Oil & Gas
Journal, and other information as cited in Chapter 3.
2.1 Stakeholder Outreach
For this detailed study, EPA conducted extensive stakeholder outreach in addition to an
expansive site visit program to help identify key issues and concerns of industry and other
stakeholders. The outreach goals for the detailed study included: (1) collecting information from
stakeholders; (2) explaining the purpose for an industry survey and the process for approval and
implementation of the survey; and (3) identifying and resolving issues as early as possible. This
outreach helped facilitate the development of the questionnaire as comments and suggestions
from industry and other stakeholders were incorporated into the survey design.
EPA met with a range of stakeholders (e.g., industry representatives; federal, state, and
tribal representatives; public interest groups and landowners; and water treatment experts) to
obtain the best available information on the industry and its CBM produced water management
practices.
To initiate stakeholder involvement, EPA conducted seven teleconferences and 13
meetings in Washington, D.C. during 2007. Meeting participants included representatives from
EPA and other federal, state, and tribal agencies (e.g., DOE, USGS, the U.S. Forest Service, and
the U.S. Department of Interior); representatives from the affected industry; members of public
interest groups; and CBM treatment experts. EPA posted the briefing slides for the
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Coalbed Methane Extraction:Detailed Study Report December 2010
teleconferences on its project website and drafted and shared meeting minutes with participants
prior to finalizing them; these minutes are available in the public docket. 2
EPA also conducted 23 meetings outside Washington, D.C. in Alabama, West Virginia,
Pennsylvania, Montana, Wyoming, Colorado, New Mexico, and Texas. Meeting participants
included a broad range of stakeholders. These meetings were coordinated with site visits to CBM
operations (see Section 2.2).
The meetings solicited early feedback from participants to facilitate the development of
the first draft of the survey instrument and sample design. They also identified interested
stakeholders for the site visits and meetings outside Washington, D.C. (see below). During these
meetings, EPA provided information on the following topics:
• The EPA regulatory development process;
• An initial review of the CBM sector;
• The CBM Questionnaire; and
• The schedule and next steps.
2.2 Site Visits
EPA visited six CBM basins in eight states to gather data for the CBM Detailed Study
and the questionnaire. In total, EPA visited 33 sites in different locations within these six CBM
basins.
During each site visit, EPA collected general site information (e.g., location, operator
name, field name, pooling arrangements, and well spacing); produced water beneficial use and
disposal methods; treatment methods; and economic information such as descriptions of factors
affecting decisions to begin production or shut in (cease production from) a well or lease.
Information collected during each site visit is documented in a report, which is available in the
public docket (EPA-HQ-OW-2006-0771 and EPA-HQ-OW-2008-0517). Confidential Business
Information (CBI) in these site visit reports has been redacted from the public versions of the
reports in the docket.
Table 2-1 shows the basins in which EPA conducted site visits and the number of
individual visits made.
2See DCNs 5177-5182 and 5184 in the docket (EPA-HQ-OW-2006-0771) for meeting documentation.
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Table 2-1. Site Visit Numbers and Locations
Basin
Appalachian
Black Warrior
Green River
Powder River
Raton
San Juan
States
Virginia, West Virginia, Pennsylvania
Alabama
Wyoming
Montana, Wyoming
Colorado, New Mexico
New Mexico
Total Visits
Number of Visits
6
1
o
J
17
o
5
o
3
33
2.3 Data Collection to Identify the Affected Universe
EPA licensed database information on historic well production from HPDI, Inc.3 (a firm
that compiles information from nearly all of the oil and gas producing states) to get an initial list
of operator names and their associated gas production and number of wells. EPA supplemented
these data with well and production data from Indiana and Illinois, states for which HPDI does
not provide data. EPA also used data from West Virginia and Virginia to identify which wells in
those states were CBM wells, as well as updated information from West Virginia (WVDEP) on
gas production in that state.
EPA compiled the data into a database that provided information on state, basin, operator
name, operator's well name and number, unique well identifier (American Petroleum Institute
[API] number), field, reservoir, and various location and contact information, along with 2006
gas and water production, where available, for all operators of CBM wells in the United States
(ERG, 2008). These data formed the basis for compiling the list of respondents for EPA's survey
efforts, described in the sections below.
2.4 EPA CBM Industry Questionnaire
EPA collected data using two instruments: a screener questionnaire and a detailed
questionnaire. The screener questionnaire focused on identifying CBM projects, which are the
critical business units within the CBM industry that cannot be identified using publicly available
information. A project is defined as a well, group of wells, lease, group of leases, or some other
recognized unit that is operated as an economic unit when making production decisions. The
detailed questionnaire focused on obtaining detailed data at the project level. EPA received
approval for the Coalbed Methane Extraction Sector Survey on February 18, 2009, from the
Office of Management and Budget (OMB Control No. 2040-0279).
2.4.1 Screener Questionnaire
EPA used a screener survey to ensure that it had the appropriate contact information for
CBM operators that were identified in the data collection effort described in Section 0 and to
provide sufficient information to stratify and select a sample of operators and projects for the
detailed questionnaire. Establishments operating in more than one basin and/or state received a
Use of HDPI, Inc. name should not be construed as an endorsement from EPA.
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Coalbed Methane Extraction:Detailed Study Report December 2010
survey for each of the basins and/or states in which they operated. EPA sent the screen er
questionnaire in February 2009 to all CBM operators that had three or more producing CBM
wells in 2006. To reduce respondent burden, EPA completed the screeners for operators
identified with only one or two wells, using public data from states and from contacts with those
operators in basins where surface water discharges are permitted. The screener survey database
was completed in July 2009.
2.4.1.1 Description of the Screener Questionnaire
The screener survey (U.S. EPA, 2010a) requested the following information: verification
that the operator produced CBM in 2008, identification of small businesses and number of
projects operated, and, for each project, information on numbers of wells, gas production, and
produced water management methods.
2.4.1.2 Response, Review, and Follow-up
EPA provided support to recipients in completing the screener surveys through an e-mail
helpline and a toll-free telephone helpline. EPA personnel responded to e-mails and phone calls
to answer questions about the instructions, standard terminology, and procedures for completing
the survey, and respond to requests for guidance on the technical information requested in the
survey. Additional details of how the data were updated to reflect later determinations of out-of-
scope operations and the steps taken to protect CBI when reporting summary data in this report
are presented in a memorandum, which is located in the administrative record (ERG, 2010).
2.4.2 Detailed Questionnaire
EPA began distributing the detailed questionnaire to the representative sample of CBM
projects in late October 2009. The detailed questionnaire collects financial and technical data on
more than 200 CBM projects across the country (Battelle, 2009).
2.4.2.1 Sample Selection
EPA is aware that the economics and environmental impacts of CBM production depend
greatly on the location of CBM development and the surrounding ecosystem. The Agency
considered location of CBM operations during the selection of projects to be surveyed. Using a
sample frame of 773 projects (based on the screener survey responses), EPA selected over 200
CBM projects to receive detailed questionnaires. EPA selected the projects for sampling by
basin, project size (number of wells), and discharge method (i.e., direct or indirect discharge and
zero discharge). Within each sampled stratum, EPA targeted 30 percent of the projects for
sampling.4
Generally, EPA focused on basins where screener respondents reported surface water
discharges (located in the eight states noted in Table 1-1). EPA also focused on emerging zero
discharge basins, which were considered likely to provide information on the types of projects
that might be constructed in basins yet to be developed. These zero discharge basins included
4 Additional details on the sampling process design are documented in an October 19, 2009, memorandum (Battelle,
2009), which is considered CBI because it reveals numbers of projects by basin and state. These totals could be used
to back-calculate numbers of projects reported by respondents requesting that this information be handled as CBI.
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Coalbed Methane Extraction:Detailed Study Report December 2010
Wind River, Arkla, Permian/Fort Worth, and Uinta-Piceance, each of which had relatively few
projects, thereby requiring a census. The only stratified sampling performed was among zero
discharge projects in the Wyoming portion of the Powder River Basin. EPA did not send detailed
questionnaires to projects and operators in established basins that discharge no produced water
directly or indirectly to surface water (Anadarko, Arkoma, and Cherokee/Forest City) because
their well-developed infrastructure was not helpful for modeling conditions in newly emerging
basins. The San Juan basin is a well-developed basin that received questionnaires because EPA
anticipates that the San Juan basin will serve to model the emerging Black Mesa basin.
2.4.2.2 Description
The detailed questionnaire requests both technical and financial and economic data,
including the following information:
• General information on the operator and parent company;
• Produced water volumes, water quality, and treatment, reuse, and disposal
methods;
• Destination of CBM produced water;
• Produced water treatment methods, including system design, operating, and cost
information;
• Environmental impact on receiving waters;
• Pollutant monitoring;
• Firm-level financial information; and
• Project-level financial information.
EPA used data from this survey to calculate the quality and quantity of produced waters
from the CBM industry and determine means of discharge, treatment technology in place, and
geographic location.
2.4.2.3 Questionnaire Response and Review and Follow-up
EPA prepared an electronic version of the detailed questionnaire to minimize operator
burden and improve data quality and operated voicemail and e-mail helplines to support
recipients in completing the questionnaires. Additionally, EPA began conducting follow-up
activities to ensure completeness and accuracy of the questionnaire responses.
2.5 Collection and Review of Current State and Federal NPDES Regulatory
Requirements
This section summarizes the current NPDES permits in key states. As noted in the
executive summary, eight states allow produced water to be directly or indirectly discharged to
surface water. EPA checked with six of these states to see if permits could be obtained for review
and was able to review permits from four of these states'. EPA's review focused on determining
common pollutants.5
5 EPA did not study the permits from Illinois, Pennsylvania, Virginia, and West Virginia in detail for the following
reasons. One direct discharger was identified in Illinois, but this state has very little CBM activity compared to the
other states studied. Pennsylvania permits were not available for review. One indirect discharger was identified in
Virginia, although it is not clear from the screener survey whether the indirect discharge was occurring in Virginia,
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Initially, EPA obtained information on CBM permitting requirements via Internet
searches and discussions with state permitting officials from the six major direct discharging
states: Alabama, Colorado, Montana, Pennsylvania, West Virginia, and Wyoming. The Agency
reviewed general and individual state NPDES permits for CBM produced water discharges in
four states with information on monitoring requirements and discharge limitations. Overall, EPA
determined that states use a combination of general, individual, and watershed-based permits to
regulate CBM discharges to surface waters. Individual permits were issued more frequently than
the other permit types, and Wyoming is the only state actively using watershed-based permits for
CBM discharges.
EPA identified some common discharge and monitoring requirements across the different
permitting programs. The most frequently regulated parameters include pH, chloride, TSS,
Sodium Absorption Ratio (SAR),6 oil and grease, and metals (e.g., iron and manganese). Several
states require continuous monitoring of effluent flow, conductivity, and pH. Three states,
Alabama, Wyoming, and Montana, include receiving stream monitoring requirements in addition
to effluent monitoring. Table 2-2 lists the parameters commonly regulated in CBM produced
water NPDES permits. In addition to those parameters listed in Table 2-2, Alabama, Colorado,
and Wyoming also require whole effluent toxicity (WET) testing of effluent.
Table 2-2. Common NPDES Permit Parameters and Limitations
State
Alabama
Colorado
Montana a
Number
of Active
Permits
24
1 general
permit
covering
about 20
facilities
3
Parameter
Chloride
Oil and Grease
pH
Total Iron
Total Manganese
Chloride
Oil and Grease
pH
TSS
Oil and Grease
pH
SAR
Unit
mg/L
mg/L
s.u.
mg/L
mg/L
mg/L
mg/L
s.u.
mg/L
mg/L
s.u.
Daily
Minimum
NA
NA
6
NA
NA
NA
NA
6.5
NA
NA
6.5
NA
Daily
Maximum
230
15
9
6
4
NA
10
9
NA
10
9
Mar-Oct:
2.6-4.5
Nov-Feb:
6.6-7.5
Monthly
Average
NA
NA
NA
o
6
2
250
NA
NA
30
NA
NA
Mar-Oct:
1.3-3.0
Nov-Feb:
3.3-5.0
West Virginia, or both states, and Virginia has no direct discharges to surface waters. West Virginia direct discharge
permits were not yet active at the time of the study.
6 SAR is the ratio of sodium concentrations to calcium and magnesium concentrations in water. This ratio
characterizes the relative sodicity of water. That is, it measures the relative amount of Na+ ions compared with other
ions in water, which is significant because sodium may affect vegetation and soil characteristics. Section 4 provides
further discussion of the potential impacts from elevated SAR.
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Table 2-2. Common NPDES Permit Parameters and Limitations
State
Wyoming
Number
of Active
Permits
About
800
Parameter
TSS
Total Recoverable Cadmium
Total Recoverable Fluoride
Total Recoverable Iron
Total Recoverable Selenium
Chloride
Dissolved Iron
Dissolved Manganese
pH
SAR
TDS
Unit
mg/L
ug/L
mg/L
mg/L
ug/L
mg/L
ug/L
mg/L
s.u.
mg/L
Daily
Minimum
NA
NA
NA
NA
NA
NA
NA
NA
6.5
NA
NA
Daily
Maximum
30-40
0.48
NA
NA
o
6
50-2000
74-1000
50
9
1-13
SAR < 7.10 x
EC -2.48
300-5000
Monthly
Average
17-25
0.054
0.5
0.6
0.75
NA
NA
NA
NA
NA
NA
a - At the time this report was written, Montana was evaluating how to implement technology-based limits on CBM
discharges.
NA - Not applicable.
Appendix A summarizes the permitting practices and requirements for each of the six
states reviewed.
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3. TECHNICAL AND ECONOMIC PROFILE OF THE CBM INDUSTRY
This profile covers both the technical aspects of CBM extraction and produced water
production and the economic and financial characteristics of the industry. Section 3.1 describes
CBM gas production and also presents the volumes of gas produced. Section 3.2 presents the
volumes and quality of water produced during CBM extraction. Section 3.3 discusses the various
methods for managing produced water and discusses the pollutants in produced water discharges.
Section 3.4 summarizes various treatment technologies that might be used to reduce pollutants,
and Section 3.5 discusses the current economics of the CBM industry, including counts of
operators, numbers of wells, numbers of projects, estimates of revenues generated by those
projects, and the financial conditions of publicly held firms in the industry. Section 3.6 discusses
trends in key factors affecting the future economics of CBM production.
3.1 CBM Gas Production
Coalification, the geologic process that progressively converts plant material to coal,
generates large quantities of natural gas, which are subsequently stored in the coal seams. The
increased pressures from water in the coal seams force the natural gas to adsorb to the coal. The
natural gas consists of approximately 96 percent methane, 3.5 percent nitrogen, and trace
amounts of carbon dioxide (U.S. EPA, 2004a). This natural gas contained in and removed from
the coal seams is called coalbed methane or CBM. (U.S. DOE, 2006)
The amount of available methane in coal varies with coal's hardness (the resistance to
scratching). Level of hardness is known as "rank." The softest coals (peats and lignites) are
associated with high porosity, high water content, and biogenic methane. In higher-rank coals
(bituminous), porosity, water, and biogenic methane production decreases, but the heat
associated with the higher-rank coals breaks down the more complex organics to produce
methane. The highest-rank anthracite coals are associated with low porosity, low water content,
and little methane generation (ALL, 2003). The most sought-after coal formations for CBM
development, therefore, tend to be mid-rank bituminous coals. Coal formations in the eastern
United States tend to be higher-rank, with lower water content than western coal formations.
They also tend to have more methane per ton of coal than western coal formations in the key
basins, but can require fracturing to release the methane because of their low porosity (ALL,
2003).
Extraction of CBM requires drilling and pumping the water from the coal seam, which
reduces the pressure and allows CBM to release from the coal (Wheaton et al., 2006; U.S. DOE,
2006). CBM extraction often produces large amounts of water, as shown in Section 3.2. Methane
and water are piped from individual wells to a metering facility, where the amount of production
is recorded. The methane then flows to a compressor station, where the gas is compressed and
then shipped via pipeline (De Bruin, et al., 2001). The produced water is a by-product of the gas
extraction process, requiring some form of management (i.e., use or disposal).
Well construction for any well drilling operation—including a CBM well—usually
follows one of two basic types: open hole or cased. In open-hole completions, the well is drilled
but no lining material is installed, so any gas can seep out all along the well into the wellbore for
removal to the surface. In cased completions, a lining is installed through all or most of the
wellbore. These casings need to be perforated or slotted to allow gas to enter the wellbore for
removal to the surface. Open-hole completions, which are less expensive than perforated or
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Coalbed Methane Extraction:Detailed Study Report
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slotted completions, are used more often in CBM production than in conventional oil and gas
production, which use open-hole completion only under certain limited circumstances
(NaturalGas.org, 2004). For example, open-hole completion is widely used in Wyoming's
Powder River Basin (PRB) (ALL, 2003). Figure 3-1 shows the profile of a typical western CBM
well using open-hole completion.
Figure 3-1. Profile of a Typical Western CBM Well With Open Hole Completion
(DeBruin, et al., 2001)
Operators drill wells into coal-bearing formations that are often not as deep as those
containing conventional hydrocarbon reserves, particularly in western regions. In the PRB, for
example, some of the methane-bearing formations are shallow, at hundreds to one thousand feet
below land surface, compared to conventional oil and natural gas well depths averaging
approximately 6,000 feet (U.S. DOE, 2005). CBM wells can often be drilled using water well
drilling equipment, rather than rigs designed for conventional hydrocarbon extraction, which are
used to drill several thousands of feet into typical conventional reservoirs (Apache Corporation,
2006).
A CBM well's typical lifespan is between 5 and 15 years, with maximum methane
production often achieved after one to six months of water removal (Horsley & Witten, 2001).
CBM wells go through the following production stages:
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Coalbed Methane Extraction:Detailed Study Report December 2010
• An early stage, in which large volumes of groundwater are pumped from the seam
to reduce the underground pressure and encourage the natural gas to release from
the coal seam;
• A stable stage, in which the amount of natural gas produced from the well
increases as the amount of groundwater pumped from the coal seam decreases;
and
• A late stage, in which the amount of gas produced declines and the amount of
groundwater pumped from the coal seam remains low (De Bruin, et al., 2001).
3.1.1 History of Production in the CBM Basins
Table 3-1 shows the major CBM production basins (including those where no
development has taken place), their locations, typical well depths, and the thickness and depth of
CBM seams. Interest in producing methane gas from coal seams began in the 1970s, but little
development occurred until the early 1980s. In 1983 the Gas Research Institute began a field
study investigating the potential for producing methane gas from coalbed strata (Fisher, 2001).
By the end of that year, 165 wells had been drilled, producing about 6 billion cubic feet (Bcf) of
gas, less than 1 percent of the amount produced in 2008. The first area to be developed was the
Black Warrior Basin in Alabama, followed by the San Juan Basin in New Mexico and Colorado,
which began development in the latter part of the 1980s. For many years, CBM was almost
exclusively produced from these three states (Fisher, 2001). Production in the PRB began in
earnest in the early 1990s, and the PRB quickly became a major source of CBM by the end of the
1990s (Wyoming Oil and Gas Conservation Commission [WOGCC], 2010). Although not
increasing as rapidly since that time, production has risen fairly steadily. By 2000, Wyoming was
producing 10 percent of all CBM; by 2008, production in the state was approaching a third (U.S.
DOE EIA, 2010a; U.S. EPA, 2010a).
The older basins, such as San Juan and Black Warrior, have not seen growth in CBM
production during the 2000s. San Juan production appears to have peaked in 2002, with some
decline since then. Black Warrior production has been level in the 2000s (U.S. DOE EIA,
2010a). The rise in U.S. production over time has been driven primarily by production in
Wyoming, mostly in the PRB. Production in several other basins has also increased over time,
although these basins contribute less to CBM production growth than PRB (U.S. DOE EIA,
2010a). Several additional basins are of interest for future CBM production, although little to no
development is currently underway. Section 3.6.4 discusses the future of CBM production in the
various basins.
3-3
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Table 3-1. Characteristics of Major CBM Basins
Basin
Appalachian (Central)
Appalachian (Northern)
Arkoma
Black Warrior
Cherokee/Forest City
Greater Green River
Illinois
Piceance
Powder River Basin
Location/Area
23,000 square miles in Kentucky,
Tennessee, Virginia, and West Virginia
with greatest potential for development
in a 3,000 square mile area in southwest
Virginia and south central West Virginia
43,700 square miles in Kentucky,
Maryland, Ohio, Pennsylvania, Virginia,
and West Virginia
13,500 square miles in Arkansas and
Oklahoma
• Covers about 23,000 square miles in
Alabama and Mississippi
• Measures approximately 230 miles
east-west and 188 miles north-south
• Cherokee is 26,500 square miles in
Oklahoma, Kansas, and Missouri
• Forest City is 47,000 square miles in
Iowa, Kansas, Missouri, and Nebraska
Comprises five smaller basins in
Wyoming, Colorado, and Utah
Northwestern Kentucky, southeastern
Indiana, and Illinois
7,225 square miles in Northwest
Colorado
25,800 square miles in northeastern
Wyoming and southern Montana
Coalbed Thickness
Variable
Average of 25 feet in Pennsylvania
600 to 2,300 feet
1 to 8 feet
Few inches to 6 feet
Multiple coal seams up to 50 feet thick
Multiple thin coal seams
2,000 feet on west side to 6,500 feet on
east site
Ranges by formation - Wasatch
Formation has thin coals (6 feet or less)
while Fort Union coals, which are below
Wasatch, can be up to 6,200 feet thick
Well Depth or Depth to Target
Coal Seam
1,000 to 2,000 feet
Ranges from surface outcrops to
depths of 2,000 feet with most
occurring at depths of less than
1,000 feet
0 to 4,500 feet
350 to 2,500 feet
Depth to coal in the shallow portion
of Cherokee ranges from surface to
230 feet and up to 1,200 feet in the
deeper portion
Not Readily Available
Most seams are at less than 650
feet; across the basin, all seams are
less than 3,000 feet deep
Depth to methane-bearing
formation is 6,000 feet, which has
hindered development
450 to 6,500 feet
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Table 3-1. Characteristics of Major CBM Basins
Basin
Location/Area
Coalbed Thickness
Well Depth or Depth to Target
Coal Seam
Raton
2,200 square miles in southeastern
Colorado and northeastern New
Mexico
Measures 80 miles north-south and as
much as 50 miles east-west
Vermejo coals are 5 to 35 feet thick and
Raton coal layers are 10 to 140 feet
thick
Not Readily Available
San Juan
Covers an area of about 7,500 square
miles across the Colorado/New
Mexico line in the Four Corners
region.
Measures approximately 100 miles
north-south direction and 90 miles
east-west.
Majority of production is in the
Fruitland Formation. Coals of the
Fruitland Formation range from 20 to
over 40 feet thick
Wells drilled into the Fruitland coal
seam typically range from 600 feet
to 3,500 feet
Uinta
Eastern Utah (small portion in
northwestern Colorado) covering 14,450
square miles
Exploration in Perron Coals and
Blackhawk formation
Depths to coal range from 1,000 to
7,000 feet
Wind River
Central Wyoming east of Powder River
Basin
Potential for development in Upper
Cretaceous Formation with thicknesses
of up to 100 feet and Meeteetse
Formation with thicknesses of less than
20 feet
Not Readily Available
Sources: U.S. EPA, 2004a, U.S. EPA, 2004b; ARI, 2010b; ALL, 2003.
3-5
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3.1.2 CBM Production
CBM production in 2008 totaled nearly 2 trillion cubic feet (Tcf) of gas (U.S. EPA,
2010a),7 when compared to a total of 25.8 Tcf of all forms of natural gas was produced (U.S.
DOE EIA, 201 Ob); CBM composed about 8 percent of all natural gas produced, and is
considered an important ongoing supply of energy by U.S. DOE.
In 2008, according to EPA's screener survey database,8 252 operators managed
approximately 56,000 CBM wells in the United States in 15 basins located in 16 states (U.S.
EPA, 2010a). Table 3-2 identifies all of the currently (as of 2008) producing basins and presents
CBM production by basin.9 More than two-thirds of all CBM produced in 2008 was produced in
the San Juan and Powder River Basins (69 percent). About 88 percent was produced by the five
largest producing basins (San Juan, Powder River, Appalachian, Raton, and Black Warrior). In
the Powder River, Green River, Raton, Black Warrior, Cahaba, Appalachian, and Illinois basins,
some produced water is discharged to surface waters or POTWs. In the remaining basins the only
practice is zero discharge. In 2008, roughly 50 percent of total CBM was produced in basins in
which some surface water discharge is occurring.
By far the largest producing states are Wyoming and New Mexico. Wyoming contains
the largest portions of the PRB and Green River as well as the Wind River Basin. New Mexico
contains most of the San Juan Basin and a portion of the Raton Basin.
Table 3-2. CBM Production by Basin in 2008
Basin
PRB
Green River
Raton
Black Warrior
Cahaba
Appalachian and IL
San Juan
Cherokee/Forest City
State(s)
WY, MT
WY, CO
CO, NM
AL
AL
PA, WV, VA, OH, IN, IL
NM, CO
KS
CBM Production
Total (Bcf)
607
13
129
104
4
144
755
79
Percentage of Total
31%
1%
6%
5%
0%
7%
38%
4%
There are some discrepancies in the screener database from published figures for some basins. Both the screener
and detailed survey ask for production; for the screener survey, operators might have approximated their production;
whereas operators might have provided more exact production figures from the project financial records needed to
complete the detailed survey. Alternatively, some states' production data might be less accurate than the operators'
records; additionally, some wells are classified in some states as confidential wells. It is not certain that published
data contain information on confidential wells. Most state websites indicate that they do not warrant the accuracy of
their data.
8 For information in the screener to be reported without concern that CBI would be revealed, the screener database
was modified to replace CBI data with publicly available data on numbers of wells and gas production. Additionally,
projects identified as out of scope later during implementation of the detailed questionnaire were also removed from
the screener database. The modifications made to the screener database are documented in (ERG, 2010).
9 The Appalachian Basin and Illinois Basin have been combined here, in part, to maintain confidentiality of CBI as
noted in ERG, 2010.
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Table 3-2. CBM Production by Basin in 2008
Basin
Uinta-Piceance
Arkoma
Anadarko
Other
State(s)
CO,UT
OK, AR
OK, AR
LA, TX, WY
Total
CBM Production
Total (Bcf)
65
66
18
3
1,988
Percentage of Total
3%
3%
1%
0%
100%
Source: U.S. EPA, 2010a.
3.1.3 Potential for Development in New CBM Basins
The basins that have been developed to date are those with mid-rank coals (coals with
more energy associated with them and generally more gas than lowest-rank and highest-rank
coals). Additional CBM prospects exist in other areas in the United States that have not yet been
developed. Table 3-3 summarizes prospective but nonproducing CBM resources. Because of the
existing pipeline infrastructure, coal rank, and coal volume, the most likely basin to produce
commercial quantities of CBM over the next 10 years is the Black Mesa Basin (ARI, 2010a).
Table 3-3. Prospective But Nonproducing CBM Resources
Region Name
Location
Estimated Gas in
Place (Tcf)
Status
Alaska—Cook Inlet
Southern
Alaska
136
Located close to existing Kenai LNG facility. One
unsuccessful pilot plant that was built can provide
data for further development.
Alaska—North Slope
Far northern
Alaska
621
No development to date because of remoteness from
markets; not characterized; pipeline planned to
transport natural gas to southern markets could
benefit CBM.
Pacific Northwest
Coal Region
Washington and
Oregon
10
Geologically complex area makes gas recovery
challenging. No conventional gas production in the
region is a positive market factor. Some testing
demonstrated good gas content, permeability, and
gas flow rates.
Black Mesa Basin
Northeastern
Arizona
1-10
Large-scale surface mining in the area since the
1960s but no CBM testing to date. Could access
market via recently constructed Questar Southern
Trails gas pipeline.
Low-Rank Coals in
the Gulf Coast
Florida
panhandle to
Texas Gulf
Coast
1.7-7.9
Gas-rich coals occur below 3,000 feet. Over 400,000
acres have been leased and individual test pilots have
been installed. Exploration is active in north central
Louisiana following 2005 revision of state law to
accommodate CBM. Exploration is also active in
Maverick County in southcentral Texas.
3-7
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Table 3-3. Prospective But Nonproducing CBM Resources
Region Name
Other Low-Rank
Coals
Location
North Dakota,
Northern
Montana,
Michigan
Estimated Gas in
Place (Tcf)
Unknown
Status
Little work done to date to assess the CBM potential
of lignite coals, but anecdotal evidence from water
well drillers suggests CBM exists in North Dakota
lignite.
Source: ARI, 2010a.
3.2 Produced Water Characteristics
EPA evaluated the quality and quantity of produced water generated from CBM
extraction using preliminary data from responses to the detailed survey questionnaires and other
sources. As discussed in Section 3.1, water within the coal seam usually must be removed before
and during CBM production. The quantity and quality of this produced water varies from basin
to basin, and even within the basin itself. The quality of produced water depends, in part, on the
hardness of the coal found within the formation. The quantity of produced water depends on type
of coal and the overall production history of the basin. Basins with a longer production history,
such as the San Juan basin, produce less total water and less water per well than the more
recently developed basins, such as the PRB.
3.2.1 Volumes of Produced Water
Based on preliminary data from the detailed questionnaire responses, EPA estimated that,
in 2008, more than 47 billion gallons of produced water were pumped out of coal seams and
approximately 22 billion gallons of that produced water (or about 45 percent) were discharged to
surface waters. Table 3-4 presents preliminary volumes of produced water discharged (basins
not listed here do not discharge).
Table 3-4. Volumes of CBM Produced Water Discharged to Surface Waters in the
Discharging Basins (2008)
Basin
Appalachian
Black Warrior
Cahaba
Green River
Illinois
Powder River (Montana)
Powder River (Wyoming)
Raton
Total
Volume (million gallons/year) a
32.3
2,454.3
244.0
327.1
113.4
1,266.8
14,622.5
2,515.8
21,543.9
Source: Preliminary detailed questionnaire data (U.S. EPA, 2010b).
a - The volume totals for each basin do not include discharges to POTWs, which are minimal.
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Coalbed Methane Extraction:Detailed Study Report December 2010
3.2.2 Pollutants in Produced Water
CBM produced water is generally characterized by elevated levels of salinity, sodicity,
and trace elements (e.g., barium and iron) (ALL, 2003). Other trace pollutants that may be
present in produced water include potassium, sulfate, bicarbonate, fluoride, ammonia, arsenic,
and radionuclides. The characteristics of the produced water depend on the geography and
location (e.g., naturally occurring elements). All of these parameters can cause adverse
environmental impacts (see Chapter 4) and also affect the potential for beneficial use of
produced water.
Salinity represents the total concentration of dissolved salts in the produced water,
including magnesium, calcium, sodium, and chloride. Salinity can be measured as electrical
conductivity (EC), expressed in deciSiemens per meter (dS/m), as well as total dissolved solids
(TDS). TDS includes any dissolved minerals, salts, metals, cations, or anions in the water. The
salinity of CBM produced water also relates to the measured sodicity value.
Sodicity is excess sodium present in produced water that can deteriorate soil structure
(i.e., swell and disperse clays reducing pore size), which reduces the infiltration of produced
water through the soil. The sodicity of produced water is expressed as the SAR, which is the
ratio of sodium (Na) present in the water to the concentration of calcium (Ca) and magnesium
(Mg) (Equation 3-1).
SAR= , ,xr[Na']r ,, Equation 3-1
Table 3-5 presents available literature data for minimum and maximum produced water
TDS concentrations in 9 of the 15 CBM basins (data were obtained separately for each portion of
the Uinta-Piceance Basin). EPA used these data to estimate average TDS concentrations in each
of the basins where such data were available. When this average might not accurately reflect the
TDS concentrations in produced water basin-wide, EPA substituted other values were used that
were deemed to be more representative. As the table shows, EPA estimates that average TDS
concentrations vary widely, from approximately 1,100 mg/L TDS in the Powder River Basin up
to 86,000 mg/L in the San Juan Basin. For comparison, the recommended TDS limit for potable
(drinking) water is 500 milligrams per liter (mg/L) and 1,000 to 2,000 mg/L (USGS, 2000) for
irrigation and stock ponds.
EPA used preliminary questionnaire discharged flow volumes from Table 3-4 and the
concentration estimates presented in Table 3-5 to calculate approximate TDS discharges from
CBM operations. EPA estimated that approximately 500 million pounds of TDS from CBM
production operations were discharged to surface waters in 2008.10
10 To compute the total TDS discharge, EPA used concentrations from the Black Warrior Basin to estimate the
concentrations for the Cahaba and Illinois basins (data from ALL, 2003).
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Table 3-5. TDS Concentrations in CBM Produced Water by Basin
Basin
Appalachian
Black Warrior
Cahaba
Green River
Illinois
Powder River
Raton
San Juan
Uinta
Piceance
Minimum
(mg/L)
<10,000
<50
<50
ND
<50
244
310
180
6,350
1,000
Maximum
(mg/L)
>10,000
60,000
60,000
>10,000
60,000
8,000
>3,500
171,000
42,700
6,000
Average
(mg/L)
10,000
16,000
16,000
5,000
16,000
1,066
1,905
85,590
24,525
3,500
Average
(Ibs/gal)
0.0835
0.1335
0.1335
0.0417
0.1335
0.0089
0.0159
0.7143
0.2047
0.0292
Source: U.S. EPA 2006, U.S. EPA 2010b.
ND - Not detected.
The available literature also yielded concentration data for other pollutants for five of the
basins (see Table 3-6).
Table 3-6. Pollutant Concentrations in CBM Produced Water by Basin
Pollutant
Barium
Calcium
Chloride
Iron
Magnesium
Potassium
Sodium
Sulfate
Pollutant Concentration by Basin (mg/L)
San Juan Basin
Min
0.7
0
0
0
0
0.6
19
0
Max
63
228
2,350
228
90
770
7,130
2,300
Black Warrior
Basin
Min
NA
NA
40
0.1
NA
NA
60
1
Max
NA
NA
36,000
400
NA
NA
21,500
1,350
Powder River
Basin
Min
0.06
5
3
0.03
1
2
89
0.01
Max
2
200
119
11
52
20
800
1,170
Raton Basin
Min
NA
4
15
0.1
1
1
210
1
Max
NA
24
719
23
8
17
991
204
Uinta Basin
Min
NA
NA
2,300
NA
NA
NA
NA
NA
Max
NA
NA
14,000
NA
NA
NA
NA
NA
Source: U.S. EPA 2006.
Min - Minimum.
Max - Maximum.
NA - No data available.
3.3 Management of Produced Water
CBM well operators use a variety of methods to manage, store, treat, and dispose of
CBM produced water. Figure 3-2 shows the potential path of produced water. As mentioned in
Section 2.4, CBM is usually produced from a project, which is defined as a well, group of wells,
lease, group of leases, or some other recognized unit that is operated as an economic unit when
3-10
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making production decisions. The produced water from the project might be managed using
various storage, treatment, and disposal methods, and each CBM project can use several different
management methods.
All CBM operators need a system gathering and transporting produced water. CBM
produced water from individual wells is often gathered via a pipeline system to transport the
water to a centralized storage system and then to either a treatment system or the final disposal
location. Section 3.4 discusses common treatment methods. The final destination of CBM
produced water may include the following:
• Discharge - Either direct discharge to surface water or indirect discharge to a
POTW (Section 3.3.1);
• Zero discharge (with no beneficial use) - Zero discharge might include
evaporation/infiltration,11 underground injection, or land application with no crop
production (Section 3.3.2); and
• Zero discharge (with beneficial use) - Beneficial use might include land
application, wildlife watering, or other miscellaneous beneficial uses (Section
o o o\
3.3.3).
Produced water from CBM
operations
Storage Ponds
Tanks
Aeration
Filtration
Ion Exchange
Reverse Osmosis
Sedimentation
Discharge
To Surface Water
To POTW
No Treatment or Storage
To Final Disposal Method
Zero Discharge (with no
beneficial use )
Underground Injection
Evaporation /infiltration (with
no surface discharge )
Zero Discharge (with
beneficial use )
Land Application
Livestock Watering
Figure 3-2. Diagram of Potential Path of Produced Water
Operators may contract with a commercial disposal company to manage the wastewater.
Typically, the produced water is stored on site in tanks and later hauled to the third-party
11 CBM operators may also use evaporation/infiltration to reduce the amount of produced water discharged to
surface water.
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Coalbed Methane Extraction:Detailed Study Report December 2010
company. Sections 3.3.1 through 3.3.3 and Section 3.4 discuss the disposal and treatment
methods in more detail.
The produced water management methods used in a particular basin depend on a variety
of factors such as water quantity, water quality, availability of receiving waters, availability of
formations for injection, landowner interests, and state regulations. Table 3-7 lists each basin
included in EPA's site visit program, the typical management and disposal practices in use, the
factors affecting the management practice, and treatment and beneficial use methods observed
during the site visit program.
The screener survey provided EPA with information on which produced water
management practices are used at each project. These management practices are divided into two
major groups: discharging practice (direct discharge to surface waters or indirect discharge to a
POTW) or zero discharge practice (land application, evaporation/infiltration pond, underground
injection, beneficial use, transport to a commercial disposal facility, or no water generated).
The basins in which direct or indirect discharge is practiced are called "discharging
basins" in this profile and include the Powder River, Appalachian, Illinois, Raton, Black Warrior,
Cahaba, and Green River Basins. EPA determined that, in other basins, CBM operators manage
produced water without discharging any portion of it directly or indirectly to surface waters. In
these basins, called "zero discharge basins" in this profile, produced water is managed primarily
by underground injection, trucking to a commercial disposal facility, or collection in ponds for
use by livestock/wildlife (beneficial use) or in evaporation/percolation ponds.
Table 3-8 presents the number of projects using the various produced water management
methods by basin. Note that the numbers reported reflect multiple produced water management
practices at many projects. For example, a project might be reported to use surface water
discharge, evaporation/infiltration ponds, and underground injection. For the purposes of this
profile, such a project is considered a discharging project because at least some produced water
is reported to be discharged to surface waters. Only projects reporting no direct or indirect
discharge are considered zero discharge projects.12
12 Nine CBI "projects" use some type of zero discharge practice; these projects are not reflected in the counts
presented in Table 3-8 to protect potential confidential information. EPA set projects per operator per basin to one
for all operators claiming project information as CBI (see ERG, 2010).
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Table 3-7. CBM Produced Water Management Practices Observed During Site Visits
Basin
Appalachian (Central)
Appalachian (Northern)
Black Warrior Basin
PRB
Raton
San Juan
Management and Disposal
Practices in Use
• Injection
• Land application (with no
crop production)
• Surface discharge
• Injection
• Surface discharge
• Surface discharge
• Injection
• Surface discharge
• Evaporation/infiltration
ponds
• Injection
• Surface discharge
• Injection
• One operator is an indirect
discharger
Factors Affecting
Management Option
• Availability of large
receiving water bodies
• Land application is permitted
under West Virginia general
permit
• Availability of large
receiving water bodies
• Availability of large
receiving water bodies
• Geological formations can
not handle the volumes of
produced water
• High volumes of water with
low salinity
• Availability of formations
for injection
• High salinity of produced
water
• State regulations
Treatment Technologies
Observed During Site Visit
• Sedimentation
• Aeration
• Sedimentation (Pennsylvania
does not allow the use of
chemical coagulants to treat
CBM produced water)
• Operators typically use a
combination of storage
ponds, sedimentation, and
aeration
• Aeration
• Sedimentation
• Ion exchange
• Aerated storage ponds
• Altela thermal distillation
system is used for the
indirect discharger
Beneficial Use Observed
During Site Visit
None observed
None observed
None observed
• Land application
• Livestock watering
• Subsurface drip irrigation
(SDI)
• Small amounts may be used
for dust suppression
• Small amounts may be used
for dust suppression
• Livestock watering
None observed
Source: DCN 05354.
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Table 3-8. Number of Projects by Produced Water Management Practices Reported
Basin
Direct
Discharge
Indirect
Discharge
Land
Application
Underground
Injection
Evaporation/
Infiltration
Pond
Beneficial Use a
Haul to
Commercial
Disposal
No Water
Generated
Discharging Basins
Powder River
Green River
Raton
Black Warrior
Cahaba
Appalachian and 111.
Total, Discharging Basins
% of Projects Reporting
149
o
J
o
J
13
2
8
178
29%
2
0
0
0
0
3
5
1%
29
0
0
0
0
2
31
5%
31
10
o
J
0
1
15
60
10%
145
1
3
1
0
7
157
26%
154
1
1
0
0
0
156
26%
4
2
2
2
1
7
18
3%
4
0
0
0
0
1
5
1%
Zero Discharge Basins
San Juan
Cherokee/Forest City
Uinta-Piceance
Arkoma
Anadarko
Other
Total, Zero Discharge
Basins
% of Projects Reporting
0
0
0
0
0
0
0
0%
0
0
0
0
0
0
0
0%
0
0
0
0
0
0
0
0%
58
25
11
16
14
2
126
28%
2
0
2
0
0
0
4
1%
1
0
0
0
0
0
1
0%
142
3
2
153
6
1
307
69%
2
0
0
2
1
0
5
1%
Source: U.S. EPA, 2010a. Note: Zero discharge practices claimed as CBI are not reported here (see ERG, 2010); counts reflect multiple practices at many
projects.
a - Livestock and wildlife watering.
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Coalbed Methane Extraction:Detailed Study Report December 2010
As Table 3-8 shows, in zero discharge basins, the primary produced water management
practices are underground injection and hauling for commercial disposal. In discharging basins,
in addition to direct and indirect surface water discharge, operators also use zero discharge
methods. In these basins, evaporation/infiltration ponds and beneficial use (livestock and wildlife
watering) are common zero discharge practices; underground injection and hauling are less
common. Land application, another practice that can be considered zero discharge, is relatively
rare and found primarily in the PRB and, as witnessed during site visits, in the Appalachian
basin. Land application under proper circumstances (e.g.., with produced water with low SAR
and other pollutants) can be considered beneficial use (e.g., irrigation). Only 10 projects, located
primarily the Powder River, San Juan, and Arkoma Basins, produced no water in 2008.
3.3.1 Discharge to Surface Water or POTW
Based on screener survey responses, EPA determined that CBM well operators in a
number of basins discharge at least a portion of their produced water directly to surface water.
Screener responses indicated that indirect discharge of produced water is not common; only three
operators with five projects (two in the PRB and three in the Appalachian Basin) discharged
produced water to a POTW in 2008; during site visits, EPA also observed indirect discharges in
basins other than PRB and the Appalachian as listed in Table 3-14. Discharge to surface water is
most prevalent (by volume) in the Black Warrior, Powder River, and Raton Basins. Using
preliminary questionnaire data, EPA estimated that approximately 22 billion gallons of produced
water are discharged annually to surface waters. CBM well operators typically transport
produced water to the discharge location via buried pipelines (i.e., gathering system).
3.3.2 Zero Discharge (with No Beneficial Use)
The following subsections describe zero discharge disposal methods that are not
considered beneficial use.
3.3.2.1 Evaporation/Infiltration Impoundments
Operators use earthen storage impoundments (ponds) to manage the produced water by
allowing the water to evaporate or penetrate into the soil and become groundwater.
Impoundments may also be used for storage or in conjunction with surface water discharge to
control the wastewater flow to the outfall.
The impoundments are typically excavated rectangular pits with sloped sides and
perimeter berms. There are two types of impoundments used for evaporating or infiltrating
produced water: in-channel and off-channel. In-channel ponds are located within an existing
drainage basin, including all perennial, intermittent, and ephemeral defined drainages, lakes,
reservoirs, and wetlands. Off-channel ponds are located in upland areas, outside natural
drainages and alluvial deposits associated with these natural drainages (Pochop et al.,1985).
Many CBM well operators in the PRB manage produced water in impoundments to
minimize or eliminate the amount of wastewater discharging to surface water. Most of the
impoundments in the PRB are off-channel and are designed to contain all CBM produced water
without discharge (Oil & Gas Consulting, 2002).
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Coalbed Methane Extraction:Detailed Study Report December 2010
3.3.2.2 Underground Injection
The Underground Injection Control (UIC) Program, under the Safe Drinking Water Act,
ensures that injection wells do not endanger current and future underground sources of drinking
water (USDW). USDW are defined as aquifers or portions of aquifers that contain less than
10,000 mg/L of TDS and have enough groundwater to supply a public water system. Currently
there are five classes for deep wells used for disposal. EPA defines these classes (listed in Table
3-9) according to the type of fluid and location (U.S. EPA, 2005).
Table 3-9. UIC Program: Well Classes and Description
Well Type
Class I
Class II
Class III
Class IV
Class V
Injection Well Description
Wells used to inject fluids underneath the lowermost formation containing USDW
Wells used to inject nonhazardous fluids associated with oil and natural gas recovery and
storage of liquid hydrocarbons
Wells associated with solution mining (e.g., extraction of uranium, copper, and salts)
Wells used to inject hazardous or radioactive waste into or above USDW
Any injection well that is not contained in Classes I to IV
Source: U.S. EPA, 2005.
The type of injection well CBM operators can use to manage produced water are Class II.
By injecting produced water with high salt content or other contaminants deep underground,
Class II wells prevent surface contamination of soil and water. CBM produced water typically
has lower TDS concentrations than the water in the injection zone. If the well is properly
designed, maintained, and operated, there is little risk of groundwater contamination from
produced water. However, this practice can be limited by the availability of suitable formations
to accept the volumes of water injected (e.g., high-porosity formations located below saline
aquifers to avoid any potential for drinking water contamination). Under federal and state
requirements, the produced water must be injected into the originating formation or into
formations that are similar to those from which it was extracted (Zimpfer et al., 1988).
Operators install Class II wells by either drilling new holes or converting existing wells
such as marginal oil-producing wells, plugged and abandoned wells, and wells that were never
completed (dry holes). Some operational difficulties associated with injecting CBM produced
water include formation plugging and scaling, formation swelling, corrosion, and incompatibility
of injected produced water with receiving formation fluids. In general, these issues can be
avoided or remedied by using engineering and operational applications such as treatment
chemicals (U.S. EPA, 1996).
Pretreatment for injection may include removing iron and manganese by precipitation.
Iron and manganese form oxides upon exposure to air, which may clog the well. Settling tanks
with splash plates aerate the produced water, which oxidize iron and manganese to insoluble
forms that can precipitate in the tank. Biocides may also be added to the produced water prior to
injection to control biological fouling.
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Coalbed Methane Extraction:Detailed Study Report December 2010
3.3.2.3 Land Application (with No Crop Production)
EPA observed the disposal of produced water by land application with no crop
production in West Virginia (Appalachian Basin). In West Virginia, produced water may be
disposed of by land application based on the quality of the water and the land's ability to
assimilate the water. The produced water is land applied such that there is no runoff to surface
water. In West Virginia, water quality parameters that limit land application of CBM water are
chloride content and IDS. Land application may not be feasible for reasons including wet or
frozen conditions or soils with high clay fractions that may impede produced water from
infiltrating into the soil, causing it to run off into nearby streams or rivers. Any conditions
causing limited infiltration preclude land application, and other disposal methods must be used.
3.3.3 Zero Discharge (with Beneficial Use)
The beneficial use of CBM produced water is defined as a use that provides a service to
local communities and ecosystems without resulting in the direct discharge of produced water to
surface waters. Beneficial uses include irrigation of cropland and pastureland without return
flows to drainages and livestock and wildlife watering (Oil & Gas Consulting, 2002).
Water quality and quantity are the primary characteristics of CBM produced water that
determine the potential beneficial use options at a CBM site. For example, concentrations of
certain trace elements such as arsenic, manganese, and zinc can limit the beneficial use options
available due to the elements' potential toxicity to humans and the environment. In addition,
other site-specific constraints such as water rights, permitting regulations, location, and cost may
limit the beneficial use management options available at a given site.
3.3.3.1 Land Application (with Crop Production)
The quality of CBM produced water and the physical and chemical properties of the
irrigated soils determine whether produced water can be used for irrigation. The three primary
water quality considerations of produced water for irrigation applications are salinity, sodicity,
and toxicity (see Section 4.3.1). When CBM produced water is used for irrigation, soil samples
are periodically analyzed to ensure that the application will not cause plugging or dispersal (and
subsequent erosion) of the soil structure. Soil sample analytes include SAR, EC, pH, and soil
moisture (to confirm that water is being absorbed). Complete soil chemistry and hydraulic
properties are also analyzed and reviewed on a periodic basis. Soil amendments (e.g., gypsum)
may be added to improve the physical properties of the soil.
EPA observed subsurface drip irrigation (SDI) systems developed by BeneTerra, LLC, to
beneficially use CBM produced water. BeneTerra currently operates SDI systems in the Powder
River Basin. In Wyoming, SDI systems are permitted under the Wyoming Department of
Environmental Quality's (WYDEQ) UIC program as Class V injection disposal wells.
BeneTerra's SDI system disperses produced water through polyethylene tubing placed
below ground level. BeneTerra contracts with energy companies to design, build, and operate the
SDI systems for a given period of time. Surface and water use agreements are made among all
parties - the CBM operator, landowner, and BeneTerra. BeneTerra agrees to disperse a set
volume of water over a set contract period, works with the landowner to determine the type of
crops that will be grown on the irrigated area, and determines the soil amendments required to
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Coalbed Methane Extraction:Detailed Study Report December 2010
maintain the proper soil chemistry given the type of crop and the produced water quality.
BeneTerra also uses groundwater modeling to predict the subsurface flow of the injected CBM
produced water to ensure that it does not connect with surface waters (U.S. EPA, 2007).
3.3.3.2 Livestock and Wildlife Watering
CBM produced water used for livestock watering is typically stored either in system
reservoirs and stream drainages or in small containment vessels (e.g., tire tanks). Spacing stored
water throughout grazing lands or letting it overflow to a drainage system allows landowners to
distribute water to their livestock in selected locations on ranch lands, which can prevent or
reduce livestock impacts to naturally occurring surface waters.
Similar to livestock watering, CBM produced water can be stored in ponds to provide
additional water sources to support drinking water needs and habitat requirements for local
wildlife. In general, wildlife watering ponds improve the diversity of habitats available, increase
wildlife populations and ranges in the region, and enhance community dynamics in the local
ecosystem (ALL, 2003). In some cases, wildlife watering ponds may also improve the quality of
water available to wildlife and provide habitats for transient populations such as migrating birds
during the winter season.
3.3.3.3 Industrial Uses
Another possible beneficial application of CBM produced water is industrial operations,
such as energy extraction industries, cooling towers, or fire protection. As with all disposal
methods, using produced water in industrial applications depends on the quality of the produced
water and the water quality required for the application. During the site visit program, EPA
observed CBM operations that use produced water for dust suppression during drilling or mining
activities and for equipment washing.
3.4 Treatment Methods
Operators may treat the CBM produced water prior to discharge or other management.
The level of CBM produced water treatment depends on the pollutants present in the water and
the final destination. EPA identified and investigated technologies for treating produced water,
including aeration, chemical precipitation, reverse osmosis, ion exchange, electrodialysis,
thermal distillation, and combination technologies. These technologies reduce or eliminate
pollutants in the produced water, allowing beneficial use or surface water discharge.
3.4.1 Aeration
Aeration is primarily used to precipitate (remove) iron from the wastewater, which
reduces or eliminates stream bed staining and preserves the aesthetic quality of the receiving
stream. The aeration process mixes air and water, typically by injecting air into water, spraying
water into the air, or allowing water to pass over an irregular surface. Pollutants are released
from the water through oxidation, precipitation, or evaporation. CBM well operators may use
spray nozzles, agitators, and bubble diffusers to aerate the water before discharge. Following
sedimentation and chemical precipitation, discharges to surface water typically flow over rip-rap
to aerate the water before it enters the stream bed, which also helps to reduce erosion and further
precipitate pollutants (e.g., iron) from the water.
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Coalbed Methane Extraction:Detailed Study Report December 2010
3.4.2 Sedimentation/Chemical Precipitation
CBM well operators use sedimentation and chemical precipitation to remove suspended
solids. Solids settle to the bottom of sedimentation basin and are removed via an underflow pipe.
Chemical addition is often used to facilitate solids settling (i.e., chemical precipitation).
Sedimentation is not expected to reduce dissolved solids.
This treatment typically occurs prior to discharging the produced water to surface water
or a POTW. Numerous operators use sedimentation to remove iron (typically preceded by some
form of aeration to facilitate iron settling). EPA also received several questionnaire responses
indicating targeted barium removal using chemical precipitation. As discussed in Section 3.3.2,
operators often use storage ponds for evaporation/infiltration, where solids will typically settle to
some extent.
3.4.3 Reverse Osmosis
Reverse osmosis (RO) separates dissolved solids or other constituents from water by
passing the water solution through a semipermeable cellophane-like membrane. RO is a proven
treatment process for removing IDS and other constituents such as arsenic. RO has been used
extensively to convert brackish water/seawater (brine) to drinking water, to reclaim wastewater,
and to recover dissolved salts from various industrial processes.
Although RO membranes can remove dissolved solids, suspended solids need to be
removed in pretreatment steps. A high-quality feed water with reduced TSS levels prevents the
membrane from plugging. In addition, membrane fouling and scaling will increase the required
pressure to maintain a constant flow through the treatment process.
Preliminary responses to the questionnaire indicate RO as the primary desalting
membrane process used in produced water treatment. The high-quality water resulting from the
RO process could be available for many beneficial uses (ALL, 2003).
In addition to RO, nanofiltration is also a high-pressure desalting membrane process.
Microfiltration and ultrafiltration are low-pressure membrane filtration processes that are used to
remove solid particles; these are not considered desalting membranes, but are often used in the
pretreatment steps.
3.4.4 Ion Exchange
In an ion exchange system (IX), wastewater passes through a system that contains a
material (typically a resin) to extract and absorb specific constituents. In a typical setup, a feed
stream passes through a column, which holds the resin. Pollutants absorb onto the resin as the
feed moves through the system. Eventually the resin becomes saturated with the targeted
pollutant requiring regeneration of the resin. A regenerant solution then passes through the
column. For cation resins such as for sodium and metals, the regenerant is an acid, and the
hydrogen ions in the acid remove the absorbed pollutant from the resin. The sodium and metals
concentrations are much higher in the regenerant than in the feed stream. Therefore, the ion-
exchange process separates the sodium from the water and results in a concentrated brine stream
and a treated produced water stream. Because the salt content of the produced water has been
reduced, the treated stream can be discharged to surface waters or beneficially used.
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Coalbed Methane Extraction:Detailed Study Report December 2010
EMIT Water Discharge Technology and LLC Higgins Loop™ - This technology is
currently being used in the PRB and is a continuous countercurrent IX system. The EMIT
process uses a strong acid cation exchange resin, which removes sodium, barium,
calcium, and magnesium ions from the water and exchanges them with hydrogen ions
(ALL, 2006a).
Drake Water Technology Process (Drake Process) - This is a proprietary pilot-scale
technology using an IX system that selectively removes sodium ions from CBM
produced water. The PRB produced water is typically high in sodium (making it the
dominant ion) and low in calcium and magnesium, which can yield high SAR values that
limit beneficial use. Drake has four patents pending and a fifth in preparation that
optimize the design of IX systems to treat PRB produced water. (U.S. EPA, 2009).
3.4.5 Electrodialysis
Similar to RO, electrodialysis (ED) is also considered a desalting membrane (removes
dissolved contaminants) but uses an electrically driven process. Electrodialysis uses alternating
pairs of cation (positively charged) and anion (negatively charged) membranes positioned
between two oppositely charged electrodes. Channeled spacers between the membranes create
parallel flow streams across the membrane surface. Water is pumped into the flow channels;
when voltage is applied, the electrical current causes ions from the water to migrate toward the
oppositely charged electrodes and are restrained in the polarized membranes (Malmrose et al.,
2004).
3.4.6 Thermal Distillation
EPA observed a proprietary thermal distillation process to treat produced water prior to
discharge to a POTW in the San Juan basin. The AltelaRain® system is a transportable and fully
integrated water thermal distillation treatment system for both CBM and conventional produced
water. The system is built and contained in standard 20-foot or 45-foot shipping containers and
transported by truck to individual well sites. The AltelaRain® system concentrates TDS into a
brine waste stream and discharges water with very low TDS concentrations.
3.4.7 Multiple Technology Applications
EPA observed pilot-scale treatment facilities that integrate several treatment technologies
to reduce pollutant concentrations so that water can be beneficially used or discharged. One pilot
plant was run by an operator in conjunction with Sandia National Laboratories and New Mexico
State University. The system used separators, ultrafiltration, and RO to treat produced water
prior to beneficial use.
EPA also observed a pilot plant run by Triwatech, consisting of a portable, pilot treatment
system that included "off-the-shelf equipment as well as proprietary, patent-pending treatment
technologies. This system has been pilot tested for several operators in the San Juan Basin. The
Triwatech pilot plant is located in a portable truck trailer and can be moved to different well
sites. The system is used to determine the optimal treatment configuration for a specific CBM
water quality. Triwatech typically requires about two to four weeks of study to determine an
optimal design for a full-scale system. The final Triwatech process design consists of pre-
treatment, polishing treatment, and post-treatment, which may consist of technologies such as
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Coalbed Methane Extraction:Detailed Study Report December 2010
filtration, sedimentation, nanofiltration, RO, IX, or activated carbon. There are several different
treatment steps that are evaluated during the initial pilot testing, and the final treatment system
comprises a mix of the different types of treatment.
3.5 Current Economics of CBM Production
CBM is a form of natural gas and therefore is included in the accounting of U.S. natural
gas reserves and production. However, because of differences in CBM geological formations and
production characteristics, the economics of CBM production and other natural gas
(conventional gas) or oil production differ, as discussed below.
As noted in Section 3.1, CBM is generally produced from relatively shallow coalbeds.
These coalbeds underlie the surface in broad areas, often covering many hundreds of square
miles. Large amounts of produced water are typically generated initially; over time, the amount
of water produced generally diminishes. In contrast, conventional gas is often contained within
sharply defined geological formations, which can be accessed only from a relatively small area
using deeper wells, typically, than those required for CBM production. Extracting conventional
gas often generates relatively little water at first, but the production of water can increase over
time. These differences in production between conventional gas and CBM lead to a very
different economic profile in terms of production economics and, in some cases, firm economics.
Because produced water management costs are a significant portion of operating costs in either
type of gas production (U.S. DOE EIA, 2010e), CBM projects often begin with high operating
costs that tend to diminish over time, while operating costs for conventional oil and gas often rise
over time.
3.5.1 Number of Wells and Projects
CBM wells are rarely operated as single units responsible for their own production costs,
because operators realize economies of scale in operating several wells together as an economic
unit. Given that CBM production requires numerous wells distributed over the coalbed, operators
tend to include a large number of wells in each economic production unit, or project.
In conventional oil and gas production, where the productive geographic area of an
oil/gas producing formation is typically constrained, an economic production unit is often a
lease. A lease usually comprises a relatively small number of wells ganged to a tank battery. In
the tanks, water is separated and the oil and/or gas is prepared for sale and delivered to the
market by pipeline (oil and gas) or truck (usually only oil). Produced water from that group of
wells is piped to an underground injection well(s) located on the lease or nearby. Alternatively,
the produced water might be trucked to a commercial disposal facility. The costs of produced
water disposal are also shared among the group of wells.
For CBM production, however, the economic production unit can be much larger than a
lease, and the concept of "project" is more applicable. A project can be as small as a single well
or a lease with just a few wells, but it can also be as large as over 1,000 wells. The tendency
toward large projects is due to the wide geographic area in which a coalbed might be located.
Projects in the discharging basins tend to be larger than projects in zero discharge basins.
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December 2010
According to EPA's screener survey,13 a total of about 56,000 CBM wells, organized into
approximately 750 projects, produced gas and/or water in 2008.14 Of these projects, a minority
(approximately 180 projects) discharged some produced water. Table 3-10 and Table 3-11
characterize the numbers of wells and projects reported in the questionnaire. As Table 3-10
shows, most of these wells are located in the PRB (21,000, or 38 percent). The zero discharge
basins have a relatively small number of wells (18,600 or 33 percent) but account for about 50
percent of production, because average production per well is greater in the zero discharge basins
than in the discharging basins. Table 3-11 also presents information on gas produced by
discharging and zero discharge projects in each basin. As the table shows, projects that
discharged at least some produced water to surface waters averaged gas production of 27 million
cubic feet (MMcf) per well and 4.4 Bcf per project in 2008, while those that discharged no
produced water averaged greater gas production per well (45 MMcf) but lower production per
project (2.1 Bcf) than projects discharging to surface waters. The higher per-project production
in discharging basins results from the higher average number of wells per project in the
discharging basins.
Table 3-10. Wells and Projects by Discharging and Zero Discharge Basins
Basin
Number of
Wells
Percentage of
Total Wells
Number of
Projects
Average Wells
per Project
Discharging Basins
PRB
Green River
Raton
Black Warrior
Cahaba
Appalachian/Illinois
Total Wells (Discharging Basins)
21,000
3,700
320
5,200
400
6,200
37,000
38%
7%
1%
9%
1%
11%
66%
220
5
15
15
2
30
280
100
750
25
350
200
200
130
Zero Discharge Basins
San Juan
Uinta-Piceance
Anadarko
Arkoma
Cherokee/Forest City
Other
Total Wells (Zero Discharge Basins)
Total Wells, U.S.
7,000
1,000
2,800
2,400
5,300
80
18,600
56,000
13%
2%
5%
4%
9%
0%
33%
200
15
35
180
40
4
474
750
35
80
80
15
130
20
40
75
Source: U.S. EPA, 2010a.
Note: Unless less than 5, all numbers are rounded to nearest 5, 10, or 100. Totals are independently rounded.
See (ERG, 2010) for how the data presented here were modified to protect CBI.
14 Because wells can produce water before producing gas, screener respondents were asked to report numbers of
wells that were producing either water or gas.
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Coalbed Methane Extraction:Detailed Study Report
December 2010
Table 3-11. Characteristics of Discharging vs. Zero Discharge Projects
Type of Project
Number
of Wells
Number
of
Projects
Gas Produced
(2008) (Bcf)
Wells per
Project
Gas per
Well
(MMcf)
Gas per
Project
(Bcf)
Discharging Projects
PRB
Green River
Raton
Black Warrior
Cahaba
Appalachian and IL
Total Discharging Projects
17,600
80
2,800
5,100
400
3,400
29,300
150
o
J
o
J
15
2
10
180
512
7
99
104
4
80
805
120
30
930
400
200
300
160
29
87
35
20
10
24
27
3.4
2.3
32.8
8.0
1.9
7.3
4.4
Zero Discharge Projects Operating Within Discharging Basins a
PRB
Green River
Raton
Black Warrior
Appalachian and IL
Total Zero Discharge Projects in
Discharging Basins
3,700
250
950
15
2,800
7,700
70
10
2
1
20
100
95
6
30
<1
64
196
50
25
475
15
150
75
26
27
32
28
23
26
1.4
0.6
15.1
0.4
3.4
1.9
Zero Discharge Projects Operating Within Zero Discharge Basins
San Juan
Cherokee/Forest City
Uinta-Piceance
Arkoma
Anadarko
Other
Total Zero Discharge Projects in
Zero Discharge Basins
Total Zero Discharge Projects, All
Basins
Total, U.S.
7,000
5,300
1,000
2,400
2,800
70
18,600
26,200
56,000
200
40
15
180
35
4
470
570
750
755
79
65
66
18
o
J
987
1,183
1,988
35
130
80
15
80
20
40
45
75
107
15
64
28
6
48
53
45
36
3.8
2.0
5.0
0.4
0.5
0.9
2.1
2.1
2.6
Source: U.S. EPA, 2010a.
Note: Most numbers are rounded to nearest 5, 10, 100, or 1,000, unless less than 5. Totals are independently
rounded.
a - A discharging basin is defined as one that has at least one discharging project operating within it. However, zero
discharge projects may also be operational within these basins as well.
3.5.2 Financial Characteristics of CBM Projects
As with any business, CBM project revenues received must cover the costs of production
or it is not economical to produce the project. Additionally, for planned projects not yet
constructed, the estimated operating cash flow over time must be able to cover all of the costs of
the project from inception to end of life. Operating cash flow is revenues to all of the working
interest owners minus their combined share of the costs of production, including produced water
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Coalbed Methane Extraction:Detailed Study Report December 2010
management costs over the assumed production lifetime of the project. The cash flow must be
positive over this time frame and must also cover the projected investment costs (e.g., costs of
preparing the site, drilling the wells, constructing and installing the production (including
produced water management) infrastructure, as well as provide some return to the investors to
cover the cost of capital15 and risk (new oil and gas ventures of any type are risky investments).
If the operating cash flow over the estimated project operating life is not expected to cover the
investment costs with a reasonable return to investors, the project will not be undertaken.
Once a project is constructed and begins operating, it will continue to be operated as long
as cash flow is positive (allowing for possibly a few years of negative cash flow initially as the
coalbed is dewatered and potentially little gas is produced). Thus, key financial characteristics of
existing CBM projects are project revenues and production costs (including produced water
management). The key financial characteristics of new CBM projects include the total
investment costs of the project, as well as the annually occurring revenues and production costs.
3.5.2.1 Project Revenues
Project revenues depend on the amount of gas produced from the project and the price
received for that gas. Using preliminary EPA questionnaire responses, EPA was able to
approximate the average revenues per project that were likely to have been earned, by basin,
using the wellhead price of gas from publicly available sources and production volumes reported
in EPA's screener survey. Wellhead price is the price received by the interest owners at the
wellhead (that is, net of additional gathering, transportation, and other costs which reduce the
price from that seen at the major gas gathering hubs). The U.S. Department of Energy's EIA (US
U.S. DOE EIA 2010c) provides the average wellhead prices for gas in 2008 by state for most oil
and gas producing states.
Table 3-12 presents average wellhead prices received in 2008 in some of the key CBM
basin states. These prices range from a high of $9.65 per thousand cubic feet (Mcf) in Alabama
to a low of $6.94 per Mcf (New Mexico, Colorado). The high wellhead price in Alabama results
in part from the state's proximity to Henry Hub, which is the major gas distribution hub and
pricing point for gas futures in the United States. This hub, which is the intersection of a number
of large pipelines, is located in Louisiana. The higher the transportation cost, the lower the
wellhead price received by the operators. Because transport costs from states located near
Louisiana are much lower than those from the Rocky Mountain area, the average wellhead price
in Texas, Louisiana, and Alabama is much higher than in the Rocky Mountain states.
Table 3-12. 2008 Wellhead Prices ($/Mcf)
Basin
Anadarko
Appalachian a
Illinois
Arkoma
Black Warrior
Wellhead Price ($/Mcf)
$7.96
$7.96
$7.96
$7.96
$9.65
State Wellhead Price Used
OK
U.S.
U.S.
OK
AL
15 For example, borrowing money has a cost, expressed as interest payments.
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Table 3-12. 2008 Wellhead Prices ($/Mcf)
Basin
Cahaba
Cherokee/Forest City
Green River
Arkla
Permian/Ft. Worth
Wind River
Powder River
Raton
San Juan
Uinta-Piceance
Wellhead Price ($/Mcf)
$9.65
$8.40
$6.94
$8.73
$8.51
$6.86
$6.86
$6.94
$6.94
$6.94
State Wellhead Price Used
AL
KS
CO
LA
TX
WY
WY
CO
NM
CO
Source: U.S. DOE EIA, 2010c.
a - Individual prices by state were not available.
EPA multiplied the relevant questionnaire responses for gas production in each basin (see
Table 3-2) and per project (see Table 3-11) by the relevant wellhead price in each basin shown in
Table 3-12. In this way, EPA estimated the total 2008 gross revenues (revenues to all interests)
associated with CBM production nationally, for each basin, and per project in each basin (see
Table 3-13).
Table 3-13. 2008 Estimated Gross Revenues (Smillions) by Basin, Discharging Basins vs.
Zero Discharge Basins
Basin
Gross Revenues/Project
Total Gross Revenues by Basin
Discharging Basins
PRB
Green River
Raton
Black Warrior
Cahaba
Appalachian and IL
Discharging Basins Average/Total
$19
$7
$179
$72
$18
$38
$26
$4,163
$93
$893
$1,006
$36
$1,146
$7,338
Zero Discharge Basins
San Juan
Cherokee/Forest City
Uinta-Piceance
Arkoma
Anadarko
Other
Zero Discharge Basins Average/Total
$26
$17
$35
$3
$4
$6
$15
$5,241
$662
$453
$528
$144
$26
$7,054
Source: EPA estimates (see text).
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In 2008, EPA estimates that total gross revenues for CBM were about $14 billion. Of
these revenues, approximately $7.3 billion (51 percent) was generated in discharging basins and
approximately $7 billion (49 percent) was generated in zero discharge basins. Average revenues
per project over all projects were estimated to be about $21 million. In discharging basins,
average revenues per project were estimated to be about $26 million and in zero discharge
basins, average revenues per project were estimated to be about $15 million.
Note that these estimated revenues are gross revenues that are shared among working
interest operators, royalty owners, and state and local governments. Typical royalty payments
might range from 10 to 20 percent of gross revenues; state and local taxes might consume several
additional percentages. Thus the percentage of revenues received by all working interest
operators (including a 100 percent interest owner) might be less than 80 percent of the gross
project revenues. .
The per-project estimated gross revenues range from $3 million per project in the
Arkoma Basin (where number of wells per project tends to be smaller) up to $179 million per
project in the Green River Basin (where number of wells per project are among the highest).
Table 3-14 presents similar gross revenue information, but identifies the estimated
average gross revenues per project depending on whether the projects are discharging or zero
discharge projects. For discharging projects, the average gross revenues per project in 2008 were
estimated to be about $33 million, whereas for zero discharge projects, the average gross
revenues per project were estimated to be about $15 million. There are more than three times as
many wells, on average, at discharging projects than at zero discharge projects (see Table 3-11),
which explains much of the difference in estimated average revenues per project between
discharging and zero discharge basins and projects. Given that the amount of gas produced per
well at discharging projects tends to be lower on average than the amount of gas produced per
well at zero discharge project (and thus revenues per well are likely to be lower), the size of the
projects is most likely the major factor in this difference (see Table 3-11).
Table 3-14. Estimated 2008 Gross Revenues (Smillions) by Basin, Discharging Projects vs.
Zero Discharge Projects
Basin
Average Gross Revenues/Project
Total Gross Revenues by Basin
Discharging Projects
PRB
Green River
Raton
Black Warrior
Cahaba
Appalachian and IL
Discharging Projects Average/Total
$24
$16
$228
$77
$18
$58
$33
$3,513
$49
$684
$1,002
$36
$636
$5,920
Zero Discharge Projects
PRB
Green River
Raton
$9
$4
$105
$650
$45
$209
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Table 3-14. Estimated 2008 Gross Revenues (Smillions) by Basin, Discharging Projects vs.
Zero Discharge Projects
Basin
Black Warrior
Appalachian and IL
San Juan
Cherokee/Forest City
Uinta-Piceance
Arkoma
Anadarko
Other
Zero Discharge Projects
Average/Total
Average Gross Revenues/Project
$4
$27
$26
$17
$35
$3
$4
$6
$15
Total Gross Revenues by Basin
$4
$510
$5,241
$662
$453
$528
$144
$26
$8,473
Source: EPA estimates (see text).
Note that wellhead prices can be slightly less at CBM projects on average than at
conventional oil and gas leases because CBM projects are sometimes located in areas with less
developed pipeline infrastructure (and therefore greater transportation costs). However, this is
becoming a less important issue. In recent years, several pipelines have been constructed in the
Rocky Mountain area, which has historically been underserved. Two of these pipelines, the
Cheyenne Plains Pipeline and the Rockies Express Pipeline, have substantially increased
transport capacity in Colorado and Wyoming. The Colorado Interstate Pipeline Company's
Cheyenne Plains Pipeline, which was built in 2004 and has the capacity to transport over 730
MMcf per day, transports natural gas from production sites in these states to southwestern
Kansas through an interconnection with Northern Natural Gas and Natural Gas Pipeline
Company of America (U.S. DOE EIA, 2010d). The largest boost to carrying capacity in the
Rockies region, however, was the addition of the Rockies Express Pipeline System, with a 1.8
Bcf/day capacity. The second segment of the pipeline was placed in service in 2007 and was
fully operational in November 2009, becoming the first direct transport from the Rocky
Mountain region to the Midwest and Northeast (KinderMorgan, 2010).
Due to increasing access to pipelines with sufficient capacity, EPA believes the average
wellhead prices used in these estimates reasonably approximate prices received by CBM projects
in 2008 and do not substantially overstate average 2008 revenues reported in this profile of CBM
project finances.
It is, however, important to note that 2008 wellhead gas prices were at an historic high. In
2009, the price of gas dropped substantially. The U.S. average dropped from $7.96 per Mcf to
$3.71 per Mcf, a 53-percent reduction (U.S. DOE EIA, 2010c). Therefore, average revenue per
project in 2009 also are expected to have declined substantially, although the exact declines are
difficult to estimate given expected production declines from existing wells combined with
additions to production from new wells at CBM projects. Section 3.6 discusses wellhead price
trends in more detail.
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3.5.2.2 Project Costs
Balanced against the estimated project revenues are the total investment costs of the
project and gas production costs. Total investment costs include costs to acquire leases, prepare
the site, drill wells, and construct and install production equipment and piping. Gas production
costs include energy and labor costs to extract the gas and produced water management costs,
including treatment and disposal.
EPA's detailed questionnaire data on production costs are not yet available. However,
U.S. DOE EIA (2010e) provides a cost study of four primary CBM basins, including the
Appalachian, Black Warrior, Powder River, and San Juan Basins. In this cost study, EIA
characterizes 10-well leases dewatered by artificial lift (that is, using pumping systems, rather
than natural flow) for each of the four basins. Table 3-15 presents the basic assumptions used in
their costing assumptions for each of these leases (a 10-well lease in these basins is generally
smaller than a typical project, as defined in EPA's surveys, in most cases). As this table shows,
the PRB is modeled as having leases with the shallowest wells, a moderate level of gas
production per well, and the highest produced water production per well among the four basins
investigated. San Juan leases are modeled assuming the deepest wells, highest gas production per
well, and a relatively modest water production per well. Leases in the Appalachian Basin are
assumed to have the least-productive wells. Black Warrior is a moderate case in all categories.
Table 3-15. Assumptions Used in U.S. DOE EIA Cost Models for Four Key CBM Basins
Basin
Appalachian
Black Warrior
PRB
San Juan
Well Depth (ft)
2,000
2,000
1,000
3,000
Dewatering Method
Sucker Rod
Sucker Rod
Submersible
Sucker Rod
Per Well
Gas Production
(Mcf/day)
60
100
100
500
Water Production
(barrels/day)
20
43
300
20
Source: U.S. DOE EIA, 2010e.
Based on these assumptions, U.S. DOE EIA (2010e) estimated two major cost categories
associated with CBM production: equipment costs and operating and maintenance (O&M) costs.
These costs are developed for the assumed 10-well leases in each of the four basins for 2002 and
2006 through 2009 to assist in developing cost indices for CBM production. Table 3-16.
summarizes these cost estimates for 2008 by basin. As the table shows, O&M costs are the
lowest in the Appalachian Basin and highest in the San Juan Basin, while equipment costs are
lowest in the Powder River Basin and highest in the San Juan Basin. U.S. DOE EIA (2010e)
notes that produced water management costs make up a large portion of the estimated operating
costs. Therefore, the high operating costs (as well as high equipment costs) seen in San Juan
Basin are, in part, driven by the costs of the zero discharge management practices used there
(injection, which drives both equipment and operating costs, and commercial disposal), even
though volumes of produced water generated per well are relatively low. The relatively high
operating costs in PRB are likely caused by managing the high volumes of produced water
generated per well. Lower volumes of produced water per well in the Appalachian might help
keep the operating costs in that basin low, while the predominance of surface water discharge in
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December 2010
the Black Warrior Basin might explain the more moderate operating costs estimated by U.S.
DOE EIA in that basin.
Table 3-16. Operating Costs and Costs of Equipment Assuming a 10-Well Lease in Four
Key CBM Basins (2008)
Costs ($2008)
Basin
Appalachian
Black Warrior
PRB
San Juan
Equipment
Producing Equipment
Gathering Lines
Lease Equipment
Total Equipment
$383,700
$218,000
$323,400
$925,100
$426,700
$170,800
$443,100
$1,040,600
$171,000
$237,100
$296,700
$704,800
$868,700
$48,500
$373,500
$1,290,700
Operating and Maintenance
Normal Daily Expense
Surface Maintenance
Subsurface Maintenance
Total O&M
$32,300
$43,800
$11,700
$87,800
$53,000
$40,700
$41,500
$135,200
$48,300
$37,000
$86,600
$171,900
$130,000
$36,800
$46,200
$213,000
Source: U.S. DOE EIA, 2010e. Assumptions used in these cost estimates appear in Table 3-15.
3.5.3 Operators of CBM Projects
3.5.3.1 Numbers, Size, and Discharge Status of CBM Operators
Operators of any type of oil or gas project can be classified as either majors or
independents. Majors are large, vertically integrated firms (i.e., they own production,
distribution, and/or wholesale or retail distribution facilities). Generally, majors have the easily
recognizable names associated with oil and gas production (e.g., Chevron, ConocoPhillips,
Marathon), because these companies often own retail distribution firms. Independents focus
primarily on the upstream activities associated with production. Most CBM operators are
independents, but a few majors are involved in CBM production, including Chevron,
ConocoPhillips, Marathon, EQT Corporation, Suncor Energy, Inc., and Williams Companies.
16
EPA's screener survey indicates that there were 252 operators of CBM projects in the
United States in 2008 (U.S. EPA, 2010a). Operators of CBM projects can be the owners of the
project or contract operators. Owner operators own some portion of the project, known as a
"working interest," which can range from 100 percent to a small fraction of the project. In this
situation, the operator is responsible for a share of the cost, but also receives the an equivalent
share of production and the resulting revenues. As noted earlier, even when an operator owns
100 percent of the working interest, the operator does not own all production (and revenues)
from a project. The nonworking interest owners (also known as owners of passive interests) also
share in the production, but do not share in any of the costs of production. Nonworking interest
Several sources identify majors, but they do not always agree on who is a major. Generally, majors are defined as
large multinational firms with significant ownership of both upstream (production) and downstream (refining,
distribution) assets. For this profile, ERG used Yahoo Finance (2010) and Reuters (2010). DOE also defines majors,
but their definition is more related to size than to integration.
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owners include the mineral rights owners, who receive royalties. Additionally, state and local
taxes on production are usually expressed in terms of a share of production (e.g., severance or ad
valorem taxes), which also reduce the portion of production received by the working interest
owner(s).
Contract operators, on the other hand, share none of the production or costs but are paid
to operate the project for the working interest owners. This situation can happen when, for
example, a working interest owner comprises a group of investors who themselves are not
familiar with the production process. A preliminary investigation of EPA's detailed survey
questionnaire responses indicates that relatively few CBM operators are strictly contract
operators.
Another important distinguishing feature of CBM operators is whether they are small
businesses, as defined by the Small Business Administration (SBA). EPA's screener survey
asked operators to self-identify as small or large businesses, using the SBA definitions of small
business based on the type of business associated with their firm's major source of income at the
highest corporate level (e.g., a parent company). Most of the CBM operators are likely to be in
the oil and gas production or well drilling industries (NAICS 211111 or 213111). Small firms in
these industries must have fewer than 500 employees. For other industries (e.g., oil and gas
support activities [NAICS 213112], which would include contract operators), small firms must
have less than $7 million in revenues (SBA, 2008).
Eight operators claimed that their screener survey responses included confidential
information on the size of the firm (which could not be replaced with public data), which
precludes using their responses in the discussion that follows. Thus, any discussion on size of
firms focuses on 244 operators whose data can be released. According to the screener survey
responses, 194 operators were small businesses and 50 operators were large businesses. Of these
244 operators, the large majority was small operators with zero discharge projects (162 of 244,
or 68 percent). Only 32 small operators operate discharging projects. Table 3-17 summarizes the
numbers of small and large operators and the discharge status of their projects.
Table 3-17. Number of CBM Operators by Size of Firm
Discharge Status
Discharging
Zero Discharge Only
Total a
Large
21
29
50
Small
32
162
194
Total
55
197
252
Source: U.S. EPA, 2010a.
a - The number of large and small operators by discharge status does not add to totals because eight operators are
not included in the business size columns for CBI reasons, although their discharge status is not CBI.
The discharge status of the eight CBI operators can be discussed, and EPA included these
operators in Table 3-18. 1? Two CBI operators operate discharging projects and the other six
operate only zero discharge projects. With these operators added in, 55 of 252 total operators (22
percent) operate discharging projects..
17 Discharge status, even if claimed CBI, is not considered by EPA to be information subject to claims of
confidentiality.
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Table 3-18 provides the numbers of operators by their basin location and discharge status.
Note this table double-counts a number of operators because many operators have projects in
multiple basins, so overall totals for dischargers and nondischargers are not shown.
Table 3-18. Numbers of Operators by Discharge Status and Basin
Basin
PRB
Green River
Raton
Black Warrior
Cahaba
Appalachian and IL
San Juan
Cherokee/Forest City
Uinta-Piceance
Arkoma
Anadarko
Other
Discharging Operators a
35
3
3
7
3
6
0
0
0
0
0
0
Zero Discharge Operators Only
29
5
2
1
0
10
56
36
9
41
32
4
Total
64
8
5
8
3
16
56
36
9
41
32
4
Source: U.S. EPA, 2010a.
a - Operators with at least one project in that basin directly or indirectly discharging at least some produced water to
surface water.
3.5.3.2 Financial Characteristics of Firms Producing CBM
Table 3-19 summarizes key financial data from 2008 for public CBM firms using a
compilation of financial information from nearly all publicly held U.S. oil and gas producing
firms prepared by Oil & Gas Journal (OGJ, 2009). These firms are known as the OGJ 150 and
the data on these firms also provide general financial benchmarks for the oil and gas industry for
comparison to the CBM industry subset. EPA identified those firms among the OGJ 150
operating or owning CBM wells and extracted their financial data. EPA added several additional
foreign-owned or other firms that were not included in the OGJ compilation to Table 3-19 by
extracting financial information from 20-F or 10-K forms available from the SEC. The year 2008
is generally considered to be a better year for the oil and gas industry financially than 2009, due
to higher gas prices realized during 2008 than 2009 (see Section 3.6.2), particularly in the first
half of the year. However, as noted in the OGJ report (OGJ, 2009), despite increases in revenues,
profits slid in the latter half of 2008 as prices and demand fell (OGJ, 2009), heading toward the
low prices seen in 2009.
EPA identified 34 publicly held firms that operate or own firms with CBM projects (and
therefore are parent corporations). A few own more than one CBM operator. Of these 34 firms,
seven are majors, 16 are large independents, and 11 are small independents (small defined by the
SB A). A total of 16 firms are associated with firms that operate discharging projects; 18 are, or
are associated with, firms that operate only zero discharge projects.
Table 3-19 indicates that majors and large independents in both groups (discharging and
zero discharge) generally had positive net income. However, despite the high gas prices in 2008,
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net income results for most small independents were poor. Only four small independents (all
dischargers) in the publicly held group had positive net income in 2008.
Table 3-19. Key Financial Information for Publicly Held CBM Firms (2008)
Firms
Total
Revenues
(Smillions)
Net Income
(Smillions)
Total Assets
(Smillions)
Total Equity
(Smillions)
Total Liabilities
(Smillions)
Firms Owning Discharging Projects
Majors
Chevron U.S. A.
Suncor
The Williams Companies
$273,005
$28,637
$3,121
$23,931
$2,487
$1,260
$161,165
$32,528
$10,286
$86,648
$14,523
NA
$74,517
$18,005
NA
Large Independents
Anadarko
Devon
El Paso
Energen
Fidelity Exploration
Range Resources
XTOa
$15,723
$15,211
$5,363
$1,569
$712
$1,323
$7,695
$3,261
-$2,148
-$823
$322
$122
$346
$1,912
$48,923
$31,908
$23,668
$3,775
$1,793
$5,563
$38,254
$18,795
$17,060
$4,035
$1,913
NA
$2,458
$17,347
$30,128
$14,848
$19,633
$1,862
NA
$3,105
$20,907
Small Independents
Bill Barrett
Belden & Blake
Continental Production
Company
Double Eagle Petroleum
GeoMet
Perm Virginia
$620
$158
$960
$50
$69
$1,221
$108
-$29
$321
$10
-$22
$124
$1,995
$669
$2,216
$172
$37,
$2,997
$1,088
$77
$949
$55
$192
$1,019
$907
$593
$1,267
$117
$185
$1,978
Firms Owning Only Zero Discharge Projects
Majors b
BP America
ConocoPhillips
EQT
Marathon Oil
$367,053
$246,182
$457
$78,569
$21,666
-$16,998
$253
$3,528
$228,238
$142,865
$2,338
$42,686
$92,109
$55,165
NA
$21,409
$136,129
$87,700
NA
$21,277
Large Independents
Chesapeake
CNX
Dominion
Layne Christiansen
Newfield
Noble Energy
Southwestern Energy
St. Mary Land &
Exploration
$11,629
$789
$4,312
$1,008
$2,225
$3,901
$2,312
$1,302
$723
$239
$468
$27
-$373
$1,350
$568
$92
$38,444
$2,125
$11,100
$719
$7,305
$12,384
$4,7608
$2,695
$16,297
$1,385
NA
$456
$3,257
$6,309
$2,508
$1,127
$22,147
$740
NA
$263
$4,048
$6,075
$2,2528
$1,568
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Table 3-19. Key Financial Information for Publicly Held CBM Firms (2008)
Firms
Unit Petroleum
Total
Revenues
(Smillions)
$1,358
Net Income
(Smillions)
$144
Total Assets
(Smillions)
$2,582
Total Equity
(Smillions)
$1,633
Total Liabilities
(Smillions)
$949
Small Independents
Enerjex
Petrohawk
PetroQuest
Rosetta Resources
Warren Resources
$4
$1,095
$314
$501
$109
-$5
-$388
-$97
-$188
-$242
$118
$6,907
$670
$1,154
$287
$1
$3,405
$237
$726
$112
$9
$3,502
$433
$428
$175
Source: OGJ, 2009; GeoMet, 2009; Suncor, 2009, BP, 2009; Reuters, 2010, Yahoo Finance, 2010. One company
was eliminated as a major using corporate websites indicating that they considered themselves independents
(Southwest Energy).
a - XTO was acquired by ExxonMobil in 2010. In 2008, it was considered an independent.
b - Majors were identified using Reuters, 2010, and Yahoo Finance, 2010, along with information on corporate
websites indicating an integration or independent.
NA - Not available.
The magnitude of these losses can be gauged using financial ratios. Financial ratios allow
various financial items to be compared across firms or to be compared to a benchmark, such as
industry averages. They are routinely used by financial analysts, investment firms, and financial
rating organizations to judge firm financial health and to consider investments in the companies
under review. The data available from OGJ are limited, but do allow some assessments of
profitability and debt loads.
EPA compared three key financial ratios for public CBM firms for 2008 to the overall
2008 average ratios (where available) from all public oil and gas firms listed in OGJ (2009). Two
ratios indicate profitability—return on assets (ROA) and net profit margin—and one assesses
debt (debt-to-asset ratio).
ROA is defined as net income divided by assets. It reflects the ability of an investment to
generate income and whether the investment is reasonable given other possible returns on
investments of similar risk. These returns can be compared to returns on the stock market (a
somewhat risky investment) or the percent interest from interest-bearing accounts (relatively
low-risk investments) to determine whether the returns seem good or poor compared to other
possible investments.
Net profit margin is computed as net income divided by revenues. This ratio can indicate
how well a company controls costs, but more importantly, how well a company might weather
an economic downturn. Those firms with net losses or low profit ratios in 2008 were at a greater
risk of continued, deeper losses, or at risk of crossing over into losses in 2009, as gas prices
continued their drop. A "good" profit margin in one industry might not be a "good" profit margin
in another, and profit margins need to be compared to averages for the industry.
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Table 3-20. Key Financial Ratios for Public CBM Firms Compared to the OGJ 150 (2008)
Firm Size
Return on Assets
Net Profit Margin
Net Profit Margin
Among Profitable
Debt to Asset
CBM Operators
Firms With Discharging Projects
Major
Large Independent
Small Independent
13.57%
1.94%
6.07%
9.08%
6.29%
16.62%
9.08%
22.07%
19.73%
47.77%
59.49%
59.90%
Firms With Only Zero Discharge Projects
Major
Large Independent
Small Independent
2.03%
3.94%
-10.18%
1.22%
11.22%
-45.45%
5.70%
13.56%
NA
59.23%
53.57%
50.36%
OGJ 150 a
Major
Large Independent
Small Independent
10.19%
1.27%
-5.77%
6.00%
3.22%
-14.19%
7.63%
14.97%
31.68%
52.51%
57.26%
59.48%
Source: Reuters, 2010; Yahoo Finance, 2010; OGJ, 2009; see Table 3-19.
a - Majors were identified using Reuters, 2010, and Yahoo Finance, 2010, along with information on corporate
websites indicating an integration or independent status in calculating ratios for the OGJ 150. Firms not classified as
majors with assets above $2 billion were used to construct ratios for large independents. The remaining firms were
considered small independents.
NA - Not available
The third ratio, the debt to asset ratio is calculated as total liability divided by total assets.
It measures the ability of companies to take on more debt and whether they could be in difficulty
if creditors began calling in debts. Very high debt-to-asset ratios indicate highly leveraged firms,
which might have trouble finding additional capital or have potential for corporate takeover.
Very low ratios, however, could mean that the firm is not taking advantage of leverage for
growth. Assessing debt-to-asset ratios should take into account how the industry as a whole
operates. Those with much higher debt-to-asset ratios than is typical for the industry might be
less resilient in a downturn, whereas those with much lower ratios, while less likely to fail, might
not be growing as quickly as they could.
Table 3-20 presents these three ratios for the public CBM firms as compared to the Oil &
Gas industry. As the table shows, CBM firms with discharging projects, regardless of size,
generally appear to have higher profit margins (that is, they were more profitable) and better
ROA in 2008 than similar-sized firms that operate only zero discharge projects (except for large
independents). Because of large losses for some firms, which tended to overwhelm the averages,
EPA also calculated profit margins over those firms that reported positive net income. When the
profit margin was calculated only over those firms with positive net income, firms with
discharging projects still appeared to have been more profitable, on average, than similar firms
with zero discharge projects (including large independents). Furthermore, for the most part, firms
with discharging projects had similar to better profitability and ROAs than similar-sized firms
among the OGJ 150. Firms with zero discharge projects (except for large independents) tended,
on average, to perform worse than the OGJ firms on net profit and ROA. These firms with zero
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discharge projects, however, would not be affected by any changes to requirements for managing
produced water from CBM projects.
In terms of debt loads, firms with discharging projects on average had similar debt-to-
asset ratios as the overall OGJ 150, although majors with discharging projects tended to be less
leveraged than average, but not substantially so. A ratio under 50 percent indicates a firm that
uses equity more than debt to fund capital expenditures. Among the firms with zero discharge
projects, the majors were, on average, more leveraged, but the remaining firm sizes tended to
have lower than average debt-to-asset ratios than the OGJ 150. Therefore, on average, the
publicly held CBM firms are not excessively leveraged compared to the overall industry.
3.6 Trends and Projections
This section discusses the future economics of CBM production, including national-level
production trends, wellhead gas price projections, and factors affecting the costs of production
that could change over time, and the potential for the reserves of CBM in the currently developed
basins to be produced in the future. These types of information are critical for determining the
overall economics of a depletable resource such as CBM.
3.6.1 The Present and Future of CBM
U.S. DOE EIA indicates that 2008 was a recent-year peak in domestic production and
consumption of natural gas (including CBM) (U.S. DOE EIA, 2010e). However, in 2009, both
production and consumption of natural gas fell. Production by type of natural gas is not yet
available for 2009, so it is not possible to determine from U.S. DOE EIA data if CBM production
also declined in 2009. However, the Wyoming Oil and Gas Conservation Commission
(WOGCC) data indicate that production of CBM in the Wyoming portion of the PRB (by far the
most productive portion of the basin and a major contributor to total CBM production in the
United States) rose between 2008 and 2009 (WOGCC, 2010). EIA predicts a continuing decline
in both domestic production and consumption of all natural gas for the next several years. By
around 2015, consumption and domestic production will again begin to rise gently, with
production slightly closing the gap with consumption and reducing imports. Figure 3-3 shows
EIA's predictions for the consumption and production of natural gas.
U.S. DOE EIA (2010e) also predicts that CBM production will remain roughly steady
through 2035, despite the overall fall in production of natural gas predicted over the next few
years. In the longer term, however, natural gas production of all types is expected to rise,
contributing to a slight decline in the percentage of natural gas attributable to CBM production.
The largest growth categories of natural gas types are shale gas and conventional natural gas
from Alaska (the result of predicted pipeline construction completion). Shale gas is by far the
largest growth category and by 2035 might be close to total conventional onshore volumes (U.S.
DOE EIA, 2010e). Figure 3-4 presents EIA's predictions for production of natural gas by type.
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Import share of natural gas supply declines as domestic
supply grows
trillion cubic feet
2Q History
25
20 j
Domestic supply
15
10
Projections
Consumption
*s
Net imports 13%
AEO2010 reference case
Updated AEO2009 reference case
1990 1995 2000 2005 2010 2015 2020 2025 2030 2035
Richard Newell, SAIS, December 14, 2009
Source: Annual Energy Outlook 2010 24
Source: U.S. DOE EIA, 2010f.
Figure 3-3. Projections of Natural Gas Consumption and Supply
Shale gas and Alaska production offset declines in supply to
meet consumption growth and lower import needs
trillion cubic feet
25
History
1990 1995 2000 2005 2010 2015 2020 2025 2030 2035
Richard Newell, SAIS, December 14, 2009
Source: Annual Energy Outlook 2010
26
Source: U.S. DOE EIA, 2010f.
Figure 3-4. Projections of Shares of Total Gas Production by Type
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3.6.2 Wellhead Gas Price Projections
Wellhead gas prices reached an historic peak in 2008, averaging $7.96/Mcf in the United
States (for all gas, regardless of origin). In 2009, partly due to the recession, prices fell to the low
point of the decade (averaging $3.71/Mcf). U.S. DOE EIA (2010e) predicts that wellhead prices
will begin to recover in 2010, rising to about $5/Mcf in 2012 and about $5.50/Mcf in 2015.
Prices will reach $6/Mcf in about 2020 (see Figure 3-5).
Natural gas wellhead price is projected to rise from low levels
experienced during 2008-2009 recession
2008 dollars per thousand cubic feet
10 History
Projections
AEO201Q reference case
Updated AEO2009 reference case
0 i , , , , r-
1980 1985 1990 1995 2000 2005 2010 2015 2020 2025 2030 2035
Richard Newell, SAIS, December 14, 2009
Source: Annual Energy Outlook 2010
22
Source: U.S. DOE EIA, 2010e.
Figure 3-5. Projections of Natural Gas Wellhead Price
For 2010, through April, EIA shows a modest increase in the average monthly wellhead
price each month on a year-over-year basis (U.S. DOE EIA, 2010e). Wellhead gas prices usually
rise in the winter and decline in the summer following spikes and troughs in demand. Therefore,
the average wellhead prices for the same month each year (e.g., January 2009 to January 2010)
should be compared to accurately assess any trends. Table 3-21 shows the recent data on average
U.S. wellhead price from 2008 to April 2010. As the table shows, prices in early 2010 are nearly
unchanged at about 70 cents/Mcf higher than they were in the same month in 2009, but still
substantially below the wellhead prices shown for 2008.
Basis differentials must be considered if projections of wellhead price are applied to
individual projects in different parts of the United States. Basis differentials reflect the factors
that make costs to individual projects different from the average U.S. wellhead prices shown in
U.S. DOE data (e.g., transportation cost differences). Some of this differential can be seen in the
differences between the U.S. average wellhead price and the wellhead prices by state shown in
Table 3-12.
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Table 3-21. Average Monthly U.S. Wellhead Price, 2008-2010
Month
January
February
March
April
May
June
July
August
September
October
November
December
2008
$7.16
$7.71
$8.44
$9.04
$10.15
$10.79
$11.32
$8.34
$6.72
$5.50
$4.75
$5.52
2009
$5.15
$4.19
$3.72
$3.43
$3.45
$3.45
$3.43
$3.14
$2.92
$3.60
$3.64
$4.44
2010
$5.14
$4.89
$4.36
$3.92
Difference
2008-2009
($2.01)
($3.52)
($4.72)
($5.61)
($6.70)
($7.34)
($7.89)
($5.20)
($3.80)
($1.90)
($1.11)
($1.08)
% Change
2008-2009
-28.1%
-45.7%
-55.9%
-62.1%
-66.0%
-68.0%
-69.7%
-62.4%
-56.5%
-34.5%
-23.4%
-19.6%
Difference
2009-2010
($0.01)
$0.70
$0.64
$0.49
% Change
2009-2010
-0.2%
16.7%
17.2%
14.3%
Source: U.S. DOE EIA, 2010c.
3.6.3 Trends in Costs of Production
A number of trends could affect the costs of production, some long-term, some only
short-term. Each of these types are discussed in the sections below.
3.6.3.1 Short-term Trends
Short-term trends include easing of supply constraints on materials and labor triggered by
low gas prices (there are few demands for drilling rigs, pipe, and operating labor when gas prices
are low), but this is offset by tight credit, such as that experienced in the recent recession. As
prices recover, supply might go down, driving up prices; continuing tight credit could diminish
this short-run price effect, however.
U.S. DOE EIA (2010e) discusses some trends in costs of CBM production over much of
the last decade that provide some insight into potential short-term trends. According to this
source, costs of production (as defined in Section 3.5.2.2), including lease equipment and O&M
costs, have risen steadily. However, these costs fell in 2009 as the plunge in gas prices reduced
demand for lease equipment. Operating costs were also reduced in most areas due to reduced fuel
costs; well-servicing costs also generally fell. The only exception to the reduction in operating
costs was the rising cost of electricity in the Powder River and the Appalachian Basins, which
increased operating costs in these basins in 2009. In the four basins (Appalachian, Black
Warrior, Powder River, and San Juan Basins) studied by U.S. DOE EIA (201 Of), O&M costs
rose overall an average of 8 percent in 2008 and fell by 1 percent in 2009. Equipment costs rose
16 percent and fell 10 percent in 2009.
As seen in the last two years, costs of production tend to rise and fall as gas prices rise
and fall. This relationship between costs and gas price can also be seen in Figure 3-6, which
shows the longer-term relationship between cost and price for conventional gas production (the
same general principal should hold true for CBM). As the figure shows, in years with low gas
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prices, costs tend to be lower, and in years with high prices, costs tend to be higher. Thus,
assuming that credit eases, and given that prices are expected to rise modestly over the next few
years, EPA expects that costs of production might also tend to rise modestly over the short run.
Figure 1. Indices for Gas Equipment and Annual Operating Costs
and Gas Prices in Real 1976 Dollars
150
140
130
70
60 ^ ( H-H ^ :---(---: J, ^ '. :---t-H 4 0
1976 1978 1980 1982 1984 1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008
Source: Energy Information Administration, Office of Oil and Gas
Figure 3-6. Indices for Gas Equipment and Annual Operating Costs and Gas Prices in Real
1976 Dollars
3.6.3.2 Long-term Trends
Key long-term factors affecting costs of production include availability of pipelines to
transport CBM to central distribution hubs, the number of years over which development has
occurred in a region, technology changes, and project-specific trends such as potential decreases
in produced water production over time.
The most important factors for analyzing long-term effects of increased costs of
production due to potential new regulatory requirements are the long-term trends. These long-
term trends, however, tend to move costs in opposite directions. Increased access to pipeline
transportation tends to lower costs of transportation, as demand for pipeline capacity no longer
outstrips its supply. This contributes to a lower basis differential and thereby a higher wellhead
price by which to offset costs.
Years of development in a basin also can affect long-term production costs. As easy-to-
reach coalbeds are tapped, future development relies on producing from deeper coalbeds, thinner
coalbeds (e.g., those that are only a few feet thick), "tighter" coalbeds (those with fewer spaces
that allow gas to escape easily), or coalbeds with lower-rank coals (with less gas), all of which
can be more expensive to produce and/or generate lower revenues. Deeper coalbeds require
deeper wells, taking longer to drill and requiring more piping and often more energy to bring the
gas to the surface. Tighter coalbeds might require special treatment before they are produced
(hydrofracturing—a method of opening up additional cracks in the coal seam to allow gas to
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escape more readily—is an additional expense if tighter coalbeds are to be produced
economically [U.S. EPA, 2004b]).
Also affecting long-term trends in costs are changes in technologies in producing CBM
(e.g., multiseam completions and horizontal drilling), although these changes can have an
uncertain effect on long-term cost trends. These technology changes can increase total costs, but
reduce costs per Mcf of gas produced. Multiseam completions allow several coalbeds at varying
depth to be produced at the same time (U.S. DOE, 2003) or can be used to add CBM to a
conventional oil and gas project when the well passes through a coal seam. Horizontal wells can
be drilled laterally through a coalbed, increasing the length of well in contact with the coalbed
(E&P, 2007). This latter method can allow thin coalbeds, once dismissed as uneconomical, to be
produced. Both of these technologies can be used to produce more gas from one well, potentially
lowering the cost per Mcf to produce the gas.
3.6.4 The Future of Existing Basins
EPA investigated the potential for CBM production in the key discharging basins to
consider the potential for new projects and continued long-term production from existing
projects. Table 3-22 summarizes estimates of the technically recoverable resources within each
of the major discharging basins (except Green River) and presents information on recent well
drilling and production trends and expected future trends. Additionally, it summarizes an
assessment of how accessible the remaining resources are and how accessible the gas is to key
market hubs (ARI, 201 Ob).
In general, the PRB is the discharging basin with the most resource potential, even under
conservative estimates. Adding major pipeline capacity (especially the recent 1.8 Bcf/day
addition) has increased the access of PRB CBM to major markets, increasing the potential for
production. The Appalachian and Raton Basins also show increases in drilling and production
trends, but Black Warrior/Cahaba, the basin with some of the oldest CBM development, might
be at or close to a peak in drilling and production (ARI, 201 Ob).
Table 3-22. Summary of Information Important to Future Production Trends in the
Major Discharging Basins
Basin
PRB
Resource
Potential
-14-52 Tcf
might be
technically
recovered,
mostly in the
Big George
coal horizon
in Wyoming.
Well Drilling
After reaching a
peak of over 3, 500
wells drilled in
2001, drilling has
remained at 2,000-
2,500 wells/year
for the past six
years.
Production
Rapid increase
1997-2000 with
slower growth
2001-2006 as
produced water
issues limited new
drilling. As drilling
resumed,
production
increased again.
Resource Access
43% of CBM
resource underlies
federal lands; 6% of
the CBM resource in
PRB is off limits to
all development;
21% is subject to
federal leasing
restrictions that limit
development during
certain months.
Market Access
In 2000, Cheyenne Hub
began gas transport but
access to markets was
limited by lack of
capacity and
unfavorable basis
differentials. Addition
of Rockies Express
Pipeline has added
substantial capacity.
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Table 3-22. Summary of Information Important to Future Production Trends in the
Major Discharging Basins
Basin
Appala-
chian
Black
Warrior/
Cahaba
Raton
Resource
Potential
-8.4-9.3 Tcf
might be
technically
recoverable
from West
Dunkard and
Pocahontas
formations.
-5.1-7.0+ Tcf
might be
technically
recoverable.
-1.59-8.2 Tcf
might be
technically
recoverable.
Well Drilling
Drilling was
steady 1997 to
2003, rising in
2004 and peaking
in 2006, but
expected to remain
high.
Drilling increased
steadily 1997-
2006, then
declined. Expected
to remain
relatively high.
Drilling increased
steadily 1998-
2007, after which
it has declined.
Production
Rising since 2003,
and should
continue. Activity
mostly in Central
Appalachian Basin.
Remained steady
from 1997-2006.
May not be
sustainable in the
future.
Steady increase
1998-2007; peak
should be
maintained for
foreseeable future.
Resource Access
2% underlies federal
lands; 1% is
inaccessible and 1%
is accessible with
restrictions on
drilling. A small
portion of the
resource underlies
state government
lands.
4% classified federal
lands, 2%
inaccessible to
leasing. Small
portion underlies
state government
lands.
Much CBM
resource underlies
federal lands, some
inaccessible, some
accessible under
development
restrictions.
Market Access
Favorably located near
major pipelines to
northeastern markets;
near Dominion South
Point Hub. Usually a
negligible or slightly
positive basis
differential.
Favorably located near
major pipelines
transporting gas from
Gulf Coast to
northeastern markets.
Pipeline expanded in
2005 from the Raton
Basin into Oklahoma
panhandle, and then
again in 2008 from Las
Animas County area to
the Cheyenne Hub.
Source: ARI, 2010b.
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4.
ENVIRONMENTAL ASSESSMENT CONSIDERATIONS
CBM produced water is released to the environment when it is discharged directly to
surface waters, managed using land application or irrigation, or stored in impoundments or
constructed wetlands. The following sections describe the documented and potential
environmental impacts associated with the discharge of CBM produced water and zero discharge
with beneficial use management options.
EPA conducted a broad, nationwide literature review of environmental impacts from
CBM produced water discharges to identify the impacts discussed in this chapter. EPA identified
and reviewed documents from the following information sources:
Peer-reviewed literature;
State and federal agency reports;
CBM site visit reports;
CBM stakeholder meeting notes;
CBM permits;
Nongovernmental organization (NGO) reports;
Industry publications;
News organization publications; and
University research.
In total, EPA identified over 1,000 documents and performed a detailed review of 452 of these.
EPA selected publicly available peer-reviewed literature as well as state, federal, university, and
news/industry/NGO articles that were publicly available. Table 4-1 summarizes the results of
literature review by search category and type of environmental impact.
Table 4-1. Summary of Literature Review Results by Search Category and Type of
Environmental Impact
Information
Source
Peer-
Reviewed
Literature
State and
Federal
Agency
Reports
CBM Site
Visit Reports
CBM
Stakeholder
Meeting
Notes
Number of
Documents
Identified
46
467
22
41
Number of
Documents
Examined
in Detail
19
116
22
41
Number of
Unique
Documents
That Discussed
Environmental
Impacts
6
38
5
5
Number of Documents by Impact Type a
Documented
1
1
0
0
Potential
o
6
25
2
3
Nonsurface
Water
4
24
2
1
No
Impact
1
8
o
J
3
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Table 4-1. Summary of Literature Review Results by Search Category and Type of
Environmental Impact
Information
Source
NGO, News
and Industry
Publications
University
Research
Total
Number of
Documents
Identified
428
74
1,078
Number of
Documents
Examined
in Detail
195
57
451
Number of
Unique
Documents
That Discussed
Environmental
Impacts
47
23
124
Number of Documents by Impact Type a
Documented
2
2
6
Potential
26
15
74
Nonsurface
Water
34
18
83
No
Impact
2
0
17
a - Note that a document may discuss more than one impact type. Therefore, the sum of the number of documents
by impact type may exceed the number of unique documents identified for a given information source.
4.1 Documented Impacts From the Direct Discharge of CBM Produced Water
EPA defines a documented environmental impact as an impact to stream water quality,
morphology, or aquatic community that resulted from or was contributed to by the direct
discharge of CBM produced water to a receiving stream. EPA's literature review identified only
a limited number of scientific studies documenting the environmental impacts of CBM produced
water discharges on aquatic ecosystems (see Table 4-2). Several authors in the research field
acknowledge that few studies have been conducted to specifically address the effects of CBM
produced water on receiving streams (Davis et al, 2006; MacDonald, 2007; Wang et al, 2007). All
of the identified studies concerned the PRB in Wyoming and Montana and the Black Warrior
Basin in Alabama.
Some of the documented impacts focused on changes to fish species population diversity
due to CBM produced water discharges. Two related papers, Davis et al., 2006, and Davis, 2008,
investigated the impact of CBM discharges on fish assemblages in the PRB. Based on her review
of relevant research and her own research, Davis found conflicting results regarding the impacts
of CBM produced waters on fish. In her master's thesis, Davis observed that CBM produced
waters had some impact on fish assemblages (Davis, 2008). Specifically, she found decreased
abundance of certain fish in streams with elevated bicarbonate. She also found decreasing biotic
integrity18 in streams with increasing conductivity. (Increased conductivity and bicarbonate are
characteristics of some CBM produced waters.) However, the same study found that species
richness and biotic integrity were similar between sites with and without CBM discharges
nearby. Davis also observed a weak relationship or none at all between overall index of biotic
integrity scores and the number or density of CBM wells in a drainage area (Davis, 2008). These
findings suggest that while CBM discharges overall had little effect on the fish present in the
Biotic integrity is the capability to support and maintain a balanced, integrated, adaptive community of organisms
having a species composition, diversity, and functional organization comparable to that of the natural habitat of the
region (Karr, 1981).
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Coalbed Methane Extraction:Detailed Study Report
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receiving streams, elevated bicarbonate or conductivity—which are on average higher in streams
that receive CBM produced water—may negatively affect fish assemblages over time.
Table 4-2. Summary of Documented Impacts From the Direct Discharge of CBM
Produced Water Cited in Peer-Reviewed Literature
Citation
Impact Type
Summary
O'Neiletal., 1991a
(cited in Davis et al.
2006)
Changes in
communities of
aquatic organisms
O'Neil et al. observed changes in fish species abundance and
reproduction in response to water quality alterations resulting from
CBM produced water discharges in the Black Warrior Basin. This
suggests that CBM discharges are altering the aquatic environment
and may cause permanent changes in species assemblages.
Davis, 2008
Changes in
communities of
aquatic organisms
In Davis's comparison of streams in the PRB with and without
CBM development, some results indicated that CBM discharges
were impacting fish assemblages, while others showed no impact.
Impacts tied to CBM produced water discharges included a
correlation of increased conductivity with decreased biotic integrity,
a correlation between decreased abundance of certain fish with an
increase in bicarbonate, and the presence of the salt-tolerant
northern plains killifish only in streams receiving CBM produced
water discharges.
Confluence
Consulting, 2004b
(cited in Confluence
Consulting, 2004a)
Changes in aquatic
organisms and
riparian plant
communities
In a study of the effects of CBM development on fish and water
quality, Confluence Consulting observed elevated levels of
dissolved solids, reduced numbers of sturgeon chub in the Powder
River, and a prevalence of salt-tolerant shrubs.
Vickers, 1990
Changes in
communities of
aquatic organisms
In a study determining the effects of CBM produced water on
surface waters of the Black Warrior Basin in Alabama, researchers
from the University of Alabama observed a decrease of total
macroinvertebrates as the in-stream chloride concentration at Shoal
Creek increased. The decrease in taxa was not completely
dependent upon chloride concentration, but may have been
influenced by in-stream components and subsequent mixtures.
Mount etal., 1992
Changes in
communities of
aquatic organisms
In an in-stream study of surface waters in the Cedar Cove
degasification field, the Geological Survey of Alabama (GS A)
found no significant effects in streams on native invertebrates (acute
toxicity of Ceriodaphnia) at chloride concentrations of 519 mg/L
and below and consistent effects at chloride concentrations of 615
mg/L and above.
O'Neiletal., 1993
Changes in
communities of
aquatic organisms
A GSA study found that environmental effects caused by CBM
water discharges were related to TDS rather than metals or other
constituents. This study concluded that elevated chloride levels in
CBM produced waters from coal seams in Alabama were the main
driver behind deleterious effects on stream conditions. Specifically,
an in-stream limiting chloride concentration of < 565 mg/L had no
significant effect on the community structure of benthic
macroinvertebrates. In contrast, chloride concentrations of > 565
mg/L in produced water always degraded or impaired the benthic
macroinvertebrate community.
In a related review paper, Davis et al., 2006, cited a number of studies performed in the
Black Warrior Basin in Alabama, where fish species diversity and biomass remained unchanged
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following the discharge of CBM produced water (O'Neil et al., 1989, cited in Davis et al., 2006;
O'Neil et al., 1991a, cited in Davis et al., 2006; Shepard et al., 1993, cited in Davis et al., 2006).
However, O'Neil et al., 1991a (cited in Davis et al., 2006) observed water quality alterations
from CBM discharges, resulting in changes in fish species abundance and reproduction that
could cause permanent impacts to communities.
These examples from Davis highlight both the limited number of scientific studies that
have investigated the environmental impacts of CBM produced waters and their conflicting
results. Overall, the data suggest that environmental impacts from CBM produced water
discharges are likely to be site-specific and dependent upon the water quality of the produced
water, type of species present, and the metrics used to evaluate the impacts on aquatic organisms.
Confluence Consulting, 2004b (cited in Confluence Consulting, 2004a) describes a study
of the effects of CBM development on fish and water quality. Sampled sites along the Powder
River with CBM discharges contained elevated dissolved solids concentrations compared to baseline
conditions for the Powder River (USGS, 2006a). Sampling results also showed a rarity of sturgeon
chub, a species of special concern, and encroachment of tamarisk, a salt-tolerant, introduced shrub
that could outcompete the more desirable cottonwoods.
The remaining documented impacts focused on problems with the salinity of CBM
produced water and its impact on aquatic vegetation and macroinvertebrate communities. The
Geological Survey of Alabama (GSA) completed a study in 1993, which documented CBM
produced water data collected during the late 1980s (O'Neil et al., 1993). The study tested
numerous water quality parameters including dissolved oxygen, five-day biochemical oxygen
demand (BODs), TDS, turbidity, bicarbonate, carbonate, alkalinity, silica, metals (e.g., arsenic,
barium, cadmium, chromium, cobalt, iron, lead, manganese, mercury, selenium, silver,
strontium, zinc), calcium, magnesium, sodium, potassium, sulfate, chloride, fluoride, nitrate,
ammonia, and orthophosphate. Dr. Pat O'Neil, GSA, stated that the study found that
environmental effects caused by CBM water discharge were related to TDS rather than metals or
other constituents (U.S. EPA, 2007). Specifically, this study concluded that elevated chloride
levels (above 565 mg/L) in CBM produced waters were the main cause of harmful effects on
stream conditions. Dr. O'Neil noted that only small streams were included in this study, and
postulated that any CBM produced water discharges into large rivers would be diluted, which
may dampen any deleterious effects (U.S. EPA, 2007).
Vickers (1990) describes a study conducted at an Amoco project area by the University
of Alabama, Department of Mineral Engineering and Department of Biology, in 1989. The study
found that, as the in-stream chloride concentration at Shoal Creek increased, total
macroinvertebrate taxa decreased. However, this was not found at the Fox Creek Test Site.
Taxonomic richness (total species) was not affected by chloride in-stream concentrations at
either site. Moreover, the study found that the decrease in total taxa did not completely depend
upon chloride concentration, but may have been influenced by in-stream components and
subsequent mixtures. Mount et al. (1992) describes an in-stream study of surface waters in the
Cedar Cove degasification field conducted by the GSA from 1986 to 1988. Study results found
no significant effects on native invertebrates in streams (acute toxicity of Ceriodaphnid) at
chloride concentrations of 519 mg/L and below, and consistent effects at concentrations of 615
mg/L chloride and above.
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Coalbed Methane Extraction:Detailed Study Report December 2010
One of the limitations of studies conducted in CBM production basins is a lack of
baseline conditions of streams established prior to CBM development and the discharge of
produced water. Without adequate baseline information, the degrees of aquatic impacts are
difficult to ascertain, especially given the seasonal variability of rainfall and consequent stream
flow fluctuations (particularly in arid regions such as the PRB) and the natural occurrence of
many contaminants of concern in produced water (e.g., chlorides and sodium) (Davis, 2008).
4.2 Potential Environmental Impacts From the Direct Discharge of CBM Produced
Water
EPA defines a potential environmental impact as an impact to stream water quality,
morphology, or aquatic community that could potentially result from or be contributed to by the
direct discharge of CBM produced water to a receiving stream. EPA's literature review identified
74 scientific studies, reports, and other sources describing potential environmental impacts from
CBM produced discharges. The primary potential impacts include those to vegetation, water
quality, and organisms due to changes in stream volume, turbidity, salinity, sodicity, SAR, IDS,
specific conductance, toxicity, temperature, and pH. Some of these potential impacts are based
on knowledge or observations of unrelated discharges with similar pollutant levels and the
impacts from those pollutants.
A number of sources expressed concern over the potential for changes in stream water
volume caused by CBM discharges to alter aquatic habitats. A higher receiving water volume
can increase suspended sediment and streambed erosion, which can affect the aquatic organisms
that inhabit these waters (Arthur, 2001; ALL, 2003; Arthur et al., 2001). Erosion can destroy
vegetation within streams (ALL, 2003; Fisher, 2001; Regele and Stark, 2000), impacting aquatic
biota that have particular flow requirements for food, habitat, and reproduction (Rawn-
Schatzinger et al., 2004; Davis et al., 2006; Regele and Stark, 2000). Flow volume changes from
CBM discharges can also increase turbidity, which might help invasive species outcompete
native species under the new flow conditions (Davis et al., 2006; Bonner and Wilde, 2002, cited
in Davis et al., 2006; Gradall and Swenson, 1982, cited in Davis et al., 2006).
Another concern expressed in the literature is the potential for CBM discharges to alter
salinity levels in receiving streams (also discussed with documented impacts in Section 4.1).
Rawn-Schatzinger et al. (2004) suggest that salinity, along with sodicity and toxicity, are the
biggest issues with CBM produced water discharges. Saline discharges from CBM produced
waters can alter plant communities as native species are replaced with salt-tolerant species (Keith
et al., 2003). However, not all locations are impacted equally by such water quality changes. For
example, Stanford and Hauer (2003) noted that because the Tongue River is more dilute than the
Powder River, CBM discharges with high salinity concentrations are more likely to cause
detrimental effects on the Tongue River than the Powder River. Conversely, CBM produced
water discharges can also impact aquatic species by diluting receiving waters with large volumes
of less saline CBM produced water, thus altering the habitat for aquatic species that are
acclimated to more saline waters (Clearwater et al., 2002, cited in MacDonald, 2007).
An elevated SAR value in CBM discharges can also affect aquatic systems (Confluence
Consulting, 2004a; Osborne and Adams, 2005). Other components in CBM produced waters that
are toxic to native plants and animals at elevated concentrations include ammonia, hydrogen
sulfide, bicarbonate, selenium, TDS, chloride, and boron (Fisher, 2001; MacDonald, 2007; Rice
et al., 2000, cited in Davis et al., 2006; ALL, 2003). Depending on species tolerance, impacts to
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aquatic organisms can vary greatly with some species able to acclimate to the new environment
more quickly than others (Davis, 2008; MacDonald, 2007).
Several studies identified toxicity concerns from CBM produced water constituents
ranging from sodium bicarbonate to pH to metals. Elevated concentrations of and exposure time
to sodium bicarbonate, (a major constituent of CBM produced water in the Tongue and Powder
River drainage basins) decreased fathead minnow survival, increased incidence of lesions and
kidney damage, and may impact freshwater ecosystems by interfering with ion uptake by fish
(USGS, 2006b). Increased water-quality variation from CBM discharges to a receiving stream,
particularly with regard to pH, could potentially cause physiological stress to aquatic organisms
(O'Neil et al., 1991b). In addition, streams receiving produced water tend to have increased
concentrations of metals such as selenium, chromium, cadmium, copper, aluminum, and iron.
Elevated selenium concentrations can potentially bioaccumulate in fish and migratory aquatic
birds, causing effects such as low reproduction, increased mortality, and embryonic deformities
(Ramirez, 2005, citing Ohlendorf et al., 1988). In PRB receiving wetlands, the U.S. Fish and
Wildlife Service (U.S. FWS) measured cadmium and chromium concentrations that exceed the
thresholds considered hazardous to aquatic life (U.S. DOI, 2005). The same study found iron,
manganese, lead, and copper in CBM produced water discharges that were above concentrations
that would impact fish and birds (U.S. DOI, 2005).
A joint study by the Montana Department of Environmental Quality, Montana Fish and
Wildlife, and EPA Region 8 estimated future water quality for streams receiving CBM produced
water discharges in the PRB (Horpestad et al., 2001). To perform their analysis, the researchers
estimated the potential number of new wells in PRB over a 20-year period and used historical
data to estimate typical flow, discharge, conveyance loss, electric conductivity (EC), and SAR
values for surface waters. The modeling results from the analysis suggest that CBM produced
water discharges will significantly alter water quality in five of the seven rivers in the PRB over
a 20-year period. The study concluded that the impacted rivers would likely be rendered
unsuitable for irrigation based on predicted ratios of EC and SAR values in the receiving water,
which exceed the threshold levels for no reduction in infiltration (Horpestad et al., 2001).
Table 4-3. Scientific Studies Evaluating Potential Environmental Concerns From the
Direct Discharge of CBM Produced Water
Citation
Clearwater et al., 2002
(cited in MacDonald.,
2007)
Patzetal., 2004 (cited
in Davis etal., 2006)
Horpestad, 2001 (cited
in Todd, 2006)
Klarich et al., 1980
(cited in Regele and
Stark, 2000)
Impact Type
Changes in water
quality and aquatic
communities
Changes in water
quality
Changes in water
quality
Changes in water
quality
Summary
Changes in volume and salinity of water in receiving streams in the
PRB can impact resident biota by disrupting environmental cues,
which can alter reproduction and normal species behavior.
The pH of CBM produced water may fluctuate due to atmospheric
exposure following discharge to a receiving water in the PRB.
These changes in pH can make downstream impacts difficult to
pinpoint.
In areas with minimal precipitation, such as eastern Montana, salts
from CBM produced water can accumulate in surface waters.
Raising the salinity of southeastern Montana waters above 1,200
micromhos will potentially affect the biological health in streams
receiving produced waters.
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Table 4-3. Scientific Studies Evaluating Potential Environmental Concerns From the
Direct Discharge of CBM Produced Water
Citation
Impact Type
Summary
Forbes etal., 2002, and
Forbes etal, 2001
(cited in MacDonald et
al, 2007)
Changes in water
quality and aquatic
communities
The water quality of CBM produced water and PRB receiving
waters were linked to acute and chronic toxicity effects in
Ceriodaphnia dubia, Daphnia magna, and fathead minnows.
Skaar et al., 2004
(cited in Davis etal.,
2006)
Changes in water
quality and aquatic
communities
Exposure to sodium bicarbonate in reconstituted Tongue and
Powder River water resulted in chronic and acute toxicity and
mortality in fathead minnows.
Skaar et al., 2005
Changes in water
quality and aquatic
communities
Chronic exposure to sodium bicarbonate from simulated Tongue
and Powder River water resulted in gill lesions, gill necrosis, and
kidney damage in fathead minnows.
Ramirez, 2005
Changes in water
quality, aquatic
communities, and
migratory bird
communities
The U.S. FWS (citing Ohlendorf et al., 1988) reported that streams
receiving produced water tend to have increased selenium
concentrations, which can impact fish and migratory aquatic birds
due to bioaccumulation. Birds with increased selenium
concentrations can have low reproduction, increased mortality, and
embryonic deformities. In addition, any prior impoundment of the
produced water before discharge to receiving waters can increase
selenium concentrations even further due to evaporation.
Ramirez, 2005
Changes in water
quality and aquatic
communities
U.S. FWS (citing Eisler, 2000) found that cadmium concentrations
in aquatic invertebrates from some CBM produced water receiving
sites exceeded the 0.1 ug/g "view with caution" level. Chromium in
tiger salamanders at a number of sites ranged from 18.6 to 137 ug/g,
and chromium in fathead minnows ranged from 24.4 to 307 ug/g.
(Chromium concentrations of 4 ug/g or greater are considered
evidence of chromium contamination.)
USGS, 2006b
Changes in water
quality and aquatic
communities
In a laboratory study, the USGS found that increased concentrations
of, and exposure time to, sodium bicarbonate, a major constituent of
CBM produced water in the Tongue and Powder River drainage
basins, decreased fathead minnow survival, increased incidence of
lesions and kidney damage, and interfered with ion uptake by fish.
USDOI, 2005
Changes in water
quality and aquatic
communities
The U.S. FWS measured cadmium concentrations ranging from 6.7
to 9.3 ug/L in wetlands in the PRB that receive CBM produced
waters, exceeding the threshold of 3 ug/L considered hazardous to
aquatic life. Chromium concentrations were typically low, except
for one wetland site where concentrations in fathead minnows
ranged from 24.4 ug/g to 307 ug/g, greatly exceeding the 4 ug/g
threshold considered hazardous.
USDOI, 2005
Changes in water
quality, aquatic
communities, and
bird communities
In a PRB study by U.S. FWS that took place from 2000 to 2002,
concentrations of iron, manganese, lead, and copper in CBM
produced water discharges were above concentrations that would
impact fish and birds.
Jackson and Reddy,
2007
Changes in water
quality and aquatic
communities
Most CBM produced water being discharged at outfalls into the
PRB was considered unsuitable for aquatic life due to aluminum
and copper concentrations greater than the water quality standards
for aquatic life.
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Table 4-3. Scientific Studies Evaluating Potential Environmental Concerns From the
Direct Discharge of CBM Produced Water
Citation
Impact Type
Summary
Mount et al., 1992
Changes in water
quality
The results of a study funded by the Gas Research Institute at the
Cedar Cove degasification field indicated that laboratory toxicity
tests could be used to predict in-stream effects of CBM produced
water. The study reported that the TDS concentration, specifically
the chloride concentration, accounted for most of the toxicity
associated with CBM produced water at the site.
O'Neiletal., 199b
Changes in aquatic
communities
CBM produced water discharges may account for some observed
changes in fish abundance in the receiving waters of the Cedar
Cove degasification field; however, the changes were within the
range of variation observed under natural conditions.
Gore, 2002
Changes in water
quality, aquatic
communities, and
morphology
A study by Columbus State University used model simulations to
evaluate the impact of increased flows from CBM produced water
on aquatic communities. The modeling results determined that all
study locations would lose habitat, impacting and possibly
destroying macroinvertebrates and western silvery minnows and
destabilizing the river ecosystem. Small increases in flow over a
long period of time flushed organisms, decreased organic matter,
changed channel morphology, and increased sedimentation, which
could cause declines in the macroinvertebrate community,
decreasing fish populations and decreasing diversity in the
ecosystem.
4.3 Nonsurface Water Environmental Impacts Associated With CBM Produced Water
EPA defines a nonsurface water environmental impact as an impact caused by CBM
produced water that did not result from the direct discharge of produced water to a receiving
stream. Nonsurface water environmental concerns discussed in the literature can be divided into
two broad categories: (1) environmental impacts caused by the land application (e.g., irrigation
or dust control) of CBM produced water and (2) environmental impacts that resulted from
impounded CBM produced water (e.g., impoundment control technologies, livestock watering
impoundments, and constructed wetlands).
Nonsurface water impacts were the predominant type of environmental impact described
in the literature (see Table 4-1). EPA did not distinguish between documented and potential
nonsurface water impacts. The most prevalent issues cited were groundwater issues, such as
groundwater contamination resulting from both CBM produced water land application and
impoundments, but irrigation and soil toxicity impacts were also frequently discussed.
4.3.1 Land Application Impacts
The land application of CBM produced water for activities such as irrigation and dust
control can cause pollutants in CBM produced water to infiltrate into local groundwater systems.
Pollutants that can infiltrate into groundwater include heavy metals, salts, ions, and organic
material often present in CBM produced water (ALL, 2006b; Fisher, 2001), which can
contaminate drinking water supplies (Veil et al., 2004).
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Elevated SAR and salinity in CBM produced water applied to land can alter the soil
structure of fine-textured soils by causing swelling and dispersion, which decreases pore size and
reduces water infiltration rates (USGS, 2006a; ALL, 2002; ALL, 2003). Reduced soil porosity
increases runoff of rain and irrigation waters, which can decrease the ability of soils to support
plant life (Arthur, 2001; USGS, 2006a). CBM produced waters with elevated salinity can also
decrease air and water permeability in soil. Fine clayey soils, of which the PRB is primarily
composed, are particularly prone to impacts from the saline and high SAR content of CBM
produced water discharges (USGS, 2006a; ALL, 2002).
Even in nonsensitive soils, the increased salinity of CBM discharges can be toxic to
plants and decrease crop yield (Veil et al., 2004; Regele and Stark, 2000). If soil water is too
saline, plants must exert more energy to extract waters from soils, decreasing productivity (ALL,
2003), which can cause plant communities to shift to more salt-tolerant species, decreasing
diversity and altering the ecosystem (Arthur et al., 2001). In one paper, Stanford and Hauer
(2003) observed areas in Montana where land irrigated with CBM produced water contained
very little or no vegetation. In areas with abundant rainfall, salts from CBM produced water can
leach from the soil; however, in more arid regions (e.g., Montana), salts can accumulate with
each application of CBM water (Veil et al., 2004) and render the soil unfit to support vegetation.
In addition to the articles discussed above, EPA identified several published scientific
studies investigating the potential nonsurface water impacts from land application of CBM
produced water (see Table 4-4). These studies primarily focus on groundwater and soil impacts
due to CBM activities.
Table 4-4. Scientific Studies Evaluating Nonsurface Water Environmental Concerns
Associated With Land Application of CBM Produced Water
Citation
Buchanan, 2005
Ganjegunte et al.,
2005
Rice etal., 2002
(cited in Kirkpatrick,
2005)
Robinson, 2002
(cited in Kirkpatrick,
2005)
Todd, 2006
Impact Type
Soil
Soil
Soil
Soil
Soil
Summary
High concentrations of salts and sodium in CBM produced waters pose
a potential risk to soil structure and porosity when used for irrigation.
Finer, more clayey soils exhibited a more significant change in
hydraulic properties when irrigated with CBM produced water than
coarser soils. Irrigation using CBM produced water with high sodium
concentrations increased runoff volumes and decreased infiltration rates.
Irrigation with CBM water can significantly impact certain soil
properties, such as infiltration and conductivity.
CBM waters in the northwest PRB had high SAR and TDS
concentrations. Surface discharge of this water could change soil
permeability.
Repeated wetting and drying cycles from applying CBM produced
water can result in greater SAR levels in soils due to concentration of
ions from evaporating water. The increase in soil SAR values can alter
soil properties (e.g., soil pore size) and decrease the infiltration of water
overtime.
Irrigation with CBM water can have long-term impacts on soil and plant
productivity. Experimental irrigation with CBM produced waters
decreased forage yield, height, and nitrate concentrations of crops.
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Table 4-4. Scientific Studies Evaluating Nonsurface Water Environmental Concerns
Associated With Land Application of CBM Produced Water
Citation
Impact Type
Summary
McBethetal, 2003
Soil
Study results suggest that in arid and semiarid regions, land disposal of
CBM produced waters may cause precipitation of calcium carbonate in
soils, which can decrease infiltration rates and increase runoff and
erosion rates.
Robinson et al., no
date
Soil
A study published by Montana State University and funded by several
conservation districts in the state concluded that CBM produced water
used for irrigation purposes can negatively affect soils. EC, S AR, and
exchangeable sodium percentage (ESP) values were significantly
elevated, with approximately 50% of the resultant values exceeding the
reported thresholds for salt injury to crops (i.e., alfalfa, corn, and
specialty crops) commonly grown in the area and the thresholds for soil
dispersion.
Ramirez, 2005
Soil
The U.S. FWS report on CBM produced water contaminants contends
that irrigation with high-saline produced waters causes salt to
accumulate, which destroys soil structure and inhibits plant uptake of
water. The SAR of produced water is typically 10 to 12 times the level
for soil to support plants.
Ramirez, 2005
Bioaccumulation
In an assessment of CBM contaminants, the U.S. FWS reported that the
land application of CBM produced water with elevated levels of
selenium on marine Cretaceous shales (found in the eastern and western
boundaries of the PRB) can mobilize selenium present in the shale.
Selenium can bioaccumulate in the food chain up to 2,000 times the
level present in water. Bioaccumulation is most likely to occur in areas
with selenium sources, high evaporation rates, and closed containment
reservoirs.
Ramirez, 2005
Groundwater
The U.S. FWS reported that infiltration of CBM produced water can
rapidly contaminate groundwater by leaching salts and trace elements
from the ground in addition to the water's original elevated salt and
trace element concentrations.
4.3.2 Impoundment Control Technology Impacts
Surface impoundment impacts include groundwater impacts due to infiltration, the
concentration or bioaccumulation of pollutants (e.g., salts, heavy metals) due to evaporation, and
the potential creation of new aquatic habitats resulting in the introduction or proliferation of
species in the area (e.g., West Nile Virus vector mosquitoes). In addition to the initial
contamination, evaporation from impoundments can further concentrate pollutants in CBM
produced water, decreasing the quality of water released to the environment through infiltration
or discharge (ALL, 2002). If connected to surface water bodies, impoundment discharges can
also degrade water quality in receiving waters (Roulson, 2007; ALL, 2003).
Impoundments can also create new habitats in CBM production areas (Doherty, 2007),
which can introduce new species or cause the proliferation of species already in the area (Davis
et al., 2006; Doherty, 2007). The proliferation of species such as West Nile virus vector
mosquitoes due to CBM discharge ponds can cause human and wildlife health risks (Doherty,
2007).
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As in impoundments, the salt concentrations in constructed wetlands can increase due to
evaporation, which can impact soils and wetland plant survival (Kirkpatrick, 2005). Elevated salt
concentrations can prevent the vegetation growth on the land once the CBM well is depleted, as
the elevated salinity would prevent all but salt-tolerant plants from reestablishing (Kirkpatrick,
2005).
Table 4-5 lists several published scientific studies identified by EPA that investigate the
potential nonsurface water impacts from control technologies for CBM produced water.
Table 4-5. Scientific Studies Evaluating Nonsurface Water Environmental Concerns
Associated With Control Technologies for CBM Produced Water
Citation
ALL, 2007
Jackson and
Reddy, 2007
Zouetal, 2006
(cited in Doherty,
2007)
Kirkpatrick, 2005
Impact Type
Impoundments,
Groundwater
Impoundments
Impoundments,
Constructed
Wetlands
Constructed
Wetlands
Summary
In a study funded by U.S. DOE's Office of Fossil Energy (Tulsa) and the
Montana Board of Oil and Gas Conservation, ALL used subsurface
hydrogeologic data to investigate the effects of CBM impoundments on
shallow groundwater. In the study, ALL observed a chemical shift in salt
ions present in downgradient bedrock samples over background water
quality.
Researchers from the Department of Renewable Resources at the
University of Wyoming determined that arsenic is soluble and mobile in
semiarid alkaline watersheds with mineral oxides and hydroxides and
increases in concentration in disposal ponds over time.
In a GIS analysis of potential mosquito larval habitats in the PRB, Zou et
al. determined that CBM development increased the habitat available for
West Nile virus vector mosquitoes by 75% from 1999 to 2004.
Some native PRB plants are naturally salinity -tolerant. However, the
elevated salinity and sodicity associated with constructed wetlands for
CBM disposal might prevent even salt-tolerant native species from
reclaiming the area.
4.4 Assertions of No Environmental Impact Caused by CBM Produced Water
EPA identified several articles and documents that included general statements that CBM
produced water discharges were not likely to cause an environmental impact; however, these
statements were not substantiated by rigorous scientific research. EPA also identified several
studies that concluded if the appropriate controls are in place (e.g., certain management practices
or prior soil investigation), there will likely be minimal or no impacts from CBM produced water
discharges.
A number of state and federal documents included statements of no environmental impact
resulting from CBM produced water discharges. The majority of these statements were from
National Environmental Policy Act (NEPA) Final Environmental Impact Statements (FEIS) and
Environmental Assessments (EA) documents from the Bureau of Land Management (BLM); the
remaining no impact claims were from a series of reports written by the BLM on the impacts of
coal activities in the PRB, referred to as the PRB Coal Review. The NEPA documents usually
prefaced statements of no environmental impact with some acknowledgment of the potential for
CBM discharges to cause environmental harm; however, these potential impacts were not
considered serious enough to stop the development of the CBM project and the overall
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Coalbed Methane Extraction:Detailed Study Report December 2010
operations were deemed not to cause any environmental impacts of concern (BLM, 2001, 2003a,
2003b, 2003c, 2004, 2005a). The PRB Coal Report discusses potential environmental impacts,
but also discusses studies by the BLM demonstrating that CBM produced waters have not
impacted the environment. For example, one BLM study concluded that, in Antelope Creek,
Little Powder, Upper Belle Fourche, and Upper Cheyenne subwatersheds, CBM discharges
would have minimal effect on permanent streams (BLM, 2005b). Another noted that as of 2002,
CBM discharges to streams had not impacted surface waters farther than a few miles from the
outfall, and discharges to unlined impoundments had no impact on groundwater or surface water
farther than 25 feet away (BLM, 2006).
The GSA's long-term monitoring offish and benthic communities in Little Hurricane
Creek during controlled discharge of produced water has shown no effect on benthic invertebrate
community structure at chloride concentrations below 600 mg/L. GSA believes this demonstrates
that produced water can be discharged to a surface water without adverse effect if its potential
toxicity is properly assessed and the discharge is managed and monitored accordingly (Mount et
al., 1992).
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5. REFERENCES
1. ALL. 2002. Handbook on Best Management Practices and Mitigation Strategies for Coal
Bed Methane in the Montana Portion of the Powder River Basin. Prepared for: U.S.
Department of Energy, National Petroleum Technology Office, National Energy
Technology Laboratory. Tulsa, OK. EPA-HQ-OW-2008-0517, DCN 05254.
2. ALL. 2003. Handbook on Coal Bed Methane Produced Water: Management and
Beneficial Use Alternatives. Prepared For: Ground Water Protection Research. (July).
Available online at: http://www.all-
llc.com/CBM/pdf/CBMBU/CBM%20BU%20Screen.pdf.EPA-HQ-OW-2004-0032-
2483, DCN 03451.
3. ALL. 2006a. A Guide to Practical Management of Produced Water from Onshore Oil and
Gas Operations in the United States (October). EPA-HQ-OW-2008-0517, DCN 10000.
4. ALL. 2006b. Siting, Design, Construction, and Reclamation Guidebook for CBNG
Impoundments. Prepared for: U.S. Department of Energy, National Petroleum
Technology Office. EPA-HQ-OW-2008-0517, DCN 05399.
5. ALL. 2007. Observed Impacts to Groundwater Resulting from the Operation of CBNG
Impoundments. Paper presented by B. Bohm, J. Arthur,, B.Langhus, and T. Richmond at
the 2007 Annual Ground Water Protection Council Forum (September 17). EPA-HQ-
OW-2008-0517, DCN 07229.
6. Apache Corporation. 2006. Areas with the Largest Increase in Drilling (March).
Available online at:
http://www.apachecorp.com/Expl ore/Explore_Features/20060327/_Report_Areas_with_
the_Largest_Increase_in_Drilling/. EPA-HQ-OW-2004-0032, DCN 03452.
7. ARI. 2010a. Memorandum from Michael Godec, ARI, to James Covington, U.S. EPA.
Review of Prospective but Non-Producing Coalbed Methane Basins (April). EPA-HQ-
OW-2008-0517, DCN 07346.
8. ARI. 201 Ob. Technical/Economic Profiles of Major Producing Coalbed Methane Basins
in the U.S. Prepared for ARI for James Covington, EPA. EPA-HQ-OW-2008-0517, DCN
07347.
9. Arthur, D., 2001. Let's Talk Technical, Montana's CBM EIS Status. Presentation from the
August 29th Montana Petroleum Association's Annual Meeting. EPA-HQ-OW-2008-
0517, DCN 07229.
10. Arthur, J.D., Langhus, B. Epperly, D., Bohm, B., Richmond, T., and Halvorson, J., 2001.
CBM in the Powder River Basin of Montana. Presented at the Ground Water Protection
Council's Annual Forum, Reno, NV. EPA-HQ-OW-2008-0517, DCN 07229.
11. Battelle, 2009. EPA Contract No. EP-05-030, Work Assignment 4-11: Coalbed Methane
(CBM) Study: Final Detailed Questionnaire Sample Design. October 19. EPA-HQ-OW-
2008-0512, DCN 07337.
12. Buchanan, M.M. 2005. Soil Water Flow and Irrigated Soil Water Balance in Response to
Powder River Basin Coalbed Methane Product Water. M.S. Thesis, Montana State
University, Bozeman, MO. EPA-HQ-OW-2008-0517, DCN 07229.
13. BLM. 2001. Final Environmental Impact Statement for the North Jacobs Ranch Coal
Lease Application. WYW146744. Casper Field Office. EPA-HQ-OW-2008-0517, DCN
07229.
14. BLM. 2003a. Final South Powder River Basin Coal Environmental Impact Statement.
Casper Field Office. EPA-HQ-OW-2004-0032-2544.8.
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15. BLM. 2003b. Final Statewide Oil and Gas Environmental Impact Statement and
Proposed Amendment of the Powder River and Billings Resource Management Plans.
Miles City and Billings Field Office. EPA-HQ-OW-2008-0517, DCN 07229.
16. BLM. 2003c. Final Environmental Impact Statement for the Pittsburg and Midway Coal
Mining Company Coal Exchange Proposal. WYW148816. Casper Field Office. EPA-
HQ-OW-2008-0517, DCN 07229.
17. BLM. 2004. Environmental Assessment of Bill Barrett Corporation's Modified Cooper
Reservoir Natural Gas Development Project, Natrona County, Wyoming. Casper Field
Office. EPA-HQ-OW-2008-0517, DCN 07229.
18. BLM. 2005a. Duck Creek Federal Coal Bed Natural Gas Project Environmental
Assessment. WY060-05-003. Casper Field Office. EPA-HQ-OW-2008-0517, DCN
07229.
19. BLM. 2005b. Task 3D Report for the Powder River Basin Coal Review Cumulative
Environmental Effects. Casper Field Office and Wyoming State Office. EPA-HQ-OW-
2008-0517, DCN 07229.
20. BLM. 2006. Task IB Report for the Powder River Basin Coal Review Current Water
Resources Conditions. Casper Field Office and Wyoming State Office. EPA-HQ-OW-
2008-0517, DCN 07229.
21. Bonner, T. H., and G.R.Wilde. 2002. Effects of turbidity on prey consumption by prairie
stream fishes. Transactions of the American Fisheries Society 131:1203-1208 (cited in
Davis et al., 2006). EPA-HQ-OW-2008-0517, DCN 07229.
22. BP. 2009. BP, pic., Form 20-F, 2008. EPA-HQ-OW-2008-0517, DCN 07348.
23. Clearwater, S.J., B.A. Morris, and J.S. Meyer, J.S. 2002. A Comparison of Coalbed
Methane Product Water Quality Versus Surface Water Quality in the Powder River Basin
of Wyoming, and An Assessment of the Use of Standard Aquatic Toxicity Testing
Organisms for Evaluating the Potential Effects of Coalbed Methane Product Waters.
Report submitted to Wyoming Department of Environmental Quality. University of
Wyoming, Laramie WY (cited in MacDonald, 2007). EPA-HQ-OW-2008-0517, DCN
07229.
24. Confluence Consulting. 2004a. Annotated Bibliography of the Potential Impacts of Gas
and Oil Exploration and Development on Coldwater Fisheries. Prepared for Trout
Unlimited. EPA-HQ-OW-2008-0517, DCN 07229.
25. Confluence Consulting, Inc. 2004b. Powder River Biological Survey and Implications for
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2008-0517, DCN 07229.
26. Davis, W.N., R.G. Bramblett, and A.V. Zale. 2006. Literature Review and Development
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27. Davis, W.N. 2008. Effects of Coalbed Natural Gas Development on Fish Assemblages in
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28. De Bruin, R.H., R.M. Lyman, R.W. Jones, and L.W. Cook. 2001. Coalbed Methane in
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29. Doherty, M.K. 2007. Mosquito Populations in the Powder River Basin, Wyoming: A
Comparison Of Natural, Agricultural And Effluent Coal Bed Natural Gas Aquatic
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Coalbed Methane Extraction:Detailed Study Report December 2010
Habitats. M.S. Thesis, Montana State University, Bozeman, MO. EPA-HQ-OW-2008-
0517, DCN 07229.
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Coalbed Methane Extraction:Detailed Study Report December 2010
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Coalbed Methane Extraction:Detailed Study Report December 2010
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Coalbed Methane Extraction:Detailed Study Report December 2010
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Coalbed Methane Extraction:Detailed Study Report December 2010
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Coalbed Methane Extraction:Detailed Study Report December 2010
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Coalbed Methane Extraction:Detailed Study Report December 2010
Appendix A
SUMMARY OF PERMITTING PRACTICES AND REQUIREMENTS
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Coalbed Methane Extraction:Detailed Study Report
December 2010
Alabama
The Alabama Department of Environmental Management (ADEM)'s Industrial/Mining
Section began permitting CBM produced water discharges in the mid-1980s and has drafted or
issued 77 individual CBM discharge permits. As of August 2009, there were 24 active CBM
discharge permits in Alabama. ADEM indicated that conductivity and chlorides (both in CBM
produced water and receiving streams) are of the greatest concern (ERG, 2009a). EPA reviewed
the active CBM discharge permits; Table A-l lists the monitored parameters, limits, and
monitoring frequencies that were included in all the permits.
Table A-l. Alabama's Individual Permit Limitations
Parameter
Daily
Minimum
Daily
Maximum
Monthly
Average
Monitoring
Frequency
Flow- and Conductivity-Related Parameters
Flow (mgd)
Conductivity
NA
NA
Monitor
Monitor
Monitor
Monitor
Continuous
Continuous
Metals
Total Iron (mg/L)
Total Manganese (mg/L)
NA
NA
6
4
3
2
Weekly
Weekly
Other Pollutants
BOD (mg/L)
Dissolved Chlorides (mg/L)
Dissolved Oxygen (mg/L)
In-Stream Chlorides (mg/L)
Oil and Grease (mg/L)
pH (s.u.)
NA
NA
5
NA
NA
6
45
Monitor
NA
230
15
9
30
Monitor
NA
NA
NA
NA
Weekly
Weekly
Weekly
Weekly
Weekly
Daily
NA - Not applicable.
Alabama's permits require permittees to continuously measure flow and conductivity and
to use a continuous flow measurement device and an ADEM-approved discharge diffuser to limit
chloride concentrations in the receiving stream. Permittees are required to submit and implement
a Best Management Practices Plan to minimize the potential for accidental discharges of process
liquids or solids.
Permittees must monitor conductivity and use the following correlation between
conductivity and chlorides (chloride [mg/L] = conductivity x 0.287) to determine the amount of
chlorides that can be discharged from the CBM well. Permittees are required to continuously
monitor the conductivity and chloride concentrations both upstream and downstream from each
CBM outfall in both the river and its tributaries. If chloride concentrations exceed 210 mg/L in
the receiving stream or 190 mg/L in its downstream tributaries, permittees must cease
discharging. The permits require monitoring of in-stream dissolved oxygen concentrations
depending on the produced water discharge concentration. Permittees must also perform both 48-
hour acute and short-term chronic WET tests at a minimum of once per quarter. Acute toxicity
tests must result in greater than 90 percent survival; less than 90 percent survival indicates
noncompliance. Chronic toxicity tests must result in greater than 80 percent survival.
A-l
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December 2010
Permittees are also required to monitor any stormwater discharges associated with
construction and operation of their facilities. Monitored parameters for stormwater include flow,
pH, total iron, total manganese, dissolved chlorides, BODs, COD, oil and grease, TSS, and
turbidity. The discharge limit for turbidity is 50 n.t.u. above background levels in the receiving
stream.
Colorado
For the past 10 years, Colorado has regulated all discharges to surface water (from
approximately 20 CBM operations) under a general permit for produced water discharges from
oil-and-gas-producing formations. However, the Colorado Department of Public Health and
Environment (CDPHE) is currently reissuing all CBM permits as individual permits at the end of
their respective permit cycles. CDPHE indicated that sodium is the primary issue of concern with
CBM discharges in Colorado. Other concerns include dewatering of domestic wells, discharge of
high volumes of water into dry creeks, downcutting, erosion, and an increase in sediment
deposition (ERG, 2009b).
Colorado issued a new general permit for produced water discharges from oil-and-gas-
producing formations in September 2009 for those CBM permittees yet to be covered by an
individual permit. The limitations and monitoring requirements therein, effective September
2009, are based on state water quality standards, effluent and watershed limitations, and policies.
Table A-2 lists the permitted parameters, limits, and monitoring frequencies included in
Colorado's general CBM permit.
Table A-2. Colorado's General Permit Limitations
Parameter
Monthly
Average
Weekly
Average
Daily
Maximum
Monitoring
Frequency
Flow- and Conductivity-Related Parameters
SAR
Flow (mgd)
Conductivity (dS/m)
2.5 a
Limit
0.70
NA
NA
NA
NA
Report
NA
Weekly
Continuous
Weekly
Metals
Inorganic Metals (ug/L)
Radium 226+228 (pCi/L)
Site Specific
NA
NA
NA
Site Specific
5
Flow Based
Flow Based
Other Pollutants
Benzene (ug/L)
Chloride (mg/L)
Ethylbenzene (ug/L)
Oil and Grease (mg/L)
Other Nonmetal Inorganic Chemicals
(ug/L)
Other Organic Chemicals (ug/L)
Other Radionuclides (pCi/L)
pH (s.u.)
Sulfate (mg/L)
TDS (mg/L)
NA
250
NA
NA
Site Specific
Site Specific
Site Specific
NA
250
Site Specific
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
Site Specific
NA
Site Specific
10
Site Specific
Site Specific
Site Specific
6.5-9.0
NA
NA
Flow Based
Flow Based
Flow Based
Flow Based
Flow Based
Flow Based
Flow Based
Weekly
Flow Based
Weekly
A-2
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Coalbed Methane Extraction:Detailed Study Report
December 2010
Table A-2. Colorado's General Permit Limitations
Parameter
Temperature (°C)
Toluene (ug/L)
Total Xylene (ug/L)
TSS (mg/L)
Monthly
Average
NA
NA
NA
30
Weekly
Average
9.0-24.2
NA
NA
45
Daily
Maximum
13.0-28.6
Site Specific
Site Specific
NA
Monitoring
Frequency
Flow Based
Flow Based
Flow Based
Weekly
Note: "Flow Based" indicates that monitoring frequency is weekly (over 100,000 gpd), bimonthly (50,001-100,000
gpd) or monthly (less than 50,000 gpd) based on discharge volumes.
a - SAR of 2.5 is acceptable provided EC is 0.70.
NA - Not applicable.
The flow limit in the general permit is based on the design capacity of CBM produced
water treatment process. Many parameters such as TDS, metals, and radionuclides are assigned
on a site-specific basis, based on:
• Water quality standards in specific locations;
• Designed beneficial uses;
• Limitations for discharges to specific watersheds;
• Receiving water characteristics; and
• Produced water quality.
Colorado also requires a chronic WET test in which there can be no statistically
significant differences between control and effluent concentrations.
Montana
The Montana Department of Environmental Quality (MTDEQ) has been issuing
individual CBM permits since the mid-1990s, with the requirement that CBM discharges not be
any more or less pure than the natural conditions of the receiving stream. Currently, there are
three active CBM permits in Montana; however, EPA was able to review only two of them.
Montana only has three operators, two of which do not discharge produced water directly. All
three permits belong to the sole direct discharging operator, and those permits cover hundreds of
wells. EC and SAR are of the biggest concern to Montana because typical surface waters have
high levels of background salts, and increased concentrations of EC and SAR can precipitate the
salt out of the waters. MTDEQ indicated that they are concerned with using CBM produced
water for irrigation, through either the direct beneficial use of CBM waters or the use of surface
waters influenced by upstream CBM discharges, as there is a potential for disaggregation of the
soil. MTDEQ is also concerned about water rights and altered downstream conditions (ERG,
2009c).
Permit parameters found in both of the reviewed individual permits include EC, SAR,
pH, oil and grease, TSS, TDS, total recoverable cadmium, total recoverable selenium, total
recoverable mercury, and total recoverable arsenic. Both permits included summer (March
through October) and winter (November through February) limits for EC and SAR, although the
actual limits differed. Table A-3 lists the permitted parameters, limits, and monitoring
frequencies included in Montana's two reviewed CBM permits.
A-3
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Coalbed Methane Extraction:Detailed Study Report
December 2010
Table A-3. Montana's Individual Permit Limitations and Monitoring Frequencies
Parameter
Daily
Minimum
Daily Maximum
Monthly
Average
Monitoring
Frequency
Flow- and Conductivity-Related Parameters
SAR
Flow (mgd)
Conductivity (uS/cm)
NA
NA
NA
Mar-Oct: 2.6/4.5
Nov-Feb: 6.6/7.5
Apr-Aug: 0
Sep-Mar:0.19-
0.32/NA
Mar-Oct:
964/1,500
Nov-Feb:
1,265/2,500
Mar-Oct:
1.3/3.0
Nov-Feb:
3.3/5.0
NA
Mar-Oct:
480/1,000
Nov-Feb:
631/1,500
Weekly, Monthly
Continuous
Continuous, Monthly
Metals
Dissolved Aluminum (mg/L)
Calcium (mg/L)
Magnesium (mg/L)
Sodium (mg/L)
Total Recoverable Arsenic (mg/L)
Total Recoverable Barium (mg/L)
Total Recoverable Cadmium (mg/L)
Total Recoverable Copper (mg/L)
Total Recoverable Iron (mg/L)
Total Recoverable Lead (mg/L)
Total Recoverable Manganese
(mg/L)
Total Recoverable Mercury (mg/L)
Total Recoverable Radium (pCi/L)
Total Recoverable Selenium (ug/L)
Total Recoverable Zinc (mg/L)
Total Strontium (mg/L)
Other Pollutants
Ammonia (mg/L)
BOD (mg/L)
Nitrite and Nitrate (mg/L)
Oil and Grease (mg/L)
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
Cannot exceed
upstream
concentrations/
NA
NA
0.48/NA
NA
NA
NA
NA
Cannot exceed
upstream
concentrations/
NA
Cannot exceed
upstream
concentrations
3.0
NA
NA
0.26
NA
NA
10
NA
NA
NA
NA
NA
NA
0.054/NA
NA
0.6
NA
NA
NA
NA
0.75
NA
NA
0.13
N/A
NA
NA
Semiannual
Weekly
Weekly
Weekly
Monthly/Semiannual
Semiannual
Monthly/Semiannual
Semiannual
Weekly, Monthly
Semiannual
Semiannual
Monthly/Semiannual
Monthly
Monthly
Semiannual
Semiannual
Weekly, Semiannual
Semiannual
Semiannual
Monthly
A-4
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Coalbed Methane Extraction:Detailed Study Report
December 2010
Table A-3. Montana's Individual Permit Limitations and Monitoring Frequencies
Parameter
pH (s.u.)
TDS (mg/L)
Temperature (°F)
Total Cyanide (mg/L)
Total Kjeldahl Nitrogen (mg/L)
Total Nitrogen (mg/L)
Total Phenols (mg/L)
Total Phosphorus (mg/L)
Total Recoverable Boron (mg/L)
Total Recoverable Fluoride (mg/L)
TSS (mg/L)
Daily
Minimum
6.5
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
Daily Maximum
9.0/8.4
NA
NA
NA
NA
NA
NA
NA
NA
NA
40/30
Monthly
Average
NA
NA
NA
NA
NA
NA
NA
NA
NA
0.5
17/25
Monitoring
Frequency
Continuous,
Weekly/Daily
Weekly, Monthly
Continuous, Weekly
Semiannual
Semiannual
Semiannual
Semiannual
Semiannual
Semiannual
Weekly, Monthly
Monthly/Weekly
NA - Not applicable.
Pennsylvania
CBM development began in Pennsylvania in the 1970s and began increasing in the mid-
1990s, especially in southwestern Pennsylvania. The Pennsylvania Department of Environmental
Protection (PADEP) currently has 12 active CBM individual permits, eight pending permits, and
five permits pending renewal with varying site-specific monitoring and discharge limitations.
EPA, however, was unable to review any of these permits and received all data concerning these
permits via telephone conversations with PADEP staff. PADEP indicated that CBM produced
water is not of good quality and it is most concerned with elevated levels of chlorides and iron in
the water. Pennsylvania currently sets discharge limits for TDS, iron, flow, TSS, oil and grease,
and osmotic pressure and requires monitoring of acidity, alkalinity, and chlorides (ERG, 2009d).
West Virginia
The West Virginia Department of Environmental Protection (WVDEP) has issued two
individual permits for CBM produced water direct discharge to surface waters; however, neither
of the operations has actually discharged produced waters. One operator reported surface water
discharge in the screener survey, and possibly holds a permit, but apparently has not discharged
produced water yet (the operator reported a number of other management practices) (U.S. EPA,
2010a). In West Virginia, CBM operations tend to land apply their produced waters rather than
discharge to surface waters and might occasionally discharge to a POTW (ERG, 2009e). One
operator indicated in the screener survey that indirect discharge is one method they use (U.S.
EPA, 2010a). Land application permits are handled under a general permit by West Virginia's
Office of Oil and Gas. EPA was unable to determine how many land application permits have
been issued to CBM operations, although two operators in EPA's screener survey indicated that
they do practice land application of produced water (U.S. EPA, 2010a).
A-5
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Coalbed Methane Extraction:Detailed Study Report December 2010
Wyoming
The Wyoming Department of Environmental Quality (WYDEQ) began issuing individual
CBM discharge permits in the mid-1990s, with the majority issued within the past 10 years.
WYDEQ has issued approximately 1,000 CBM permits, with approximately 800 current permits.
As these individual CBM permits expire, WYDEQ plans to reissue them as watershed-based
permits because there can be several dozen CBM dischargers in a given watershed (ERG, 2009f).
Currently, WYDEQ has issued about 11 watershed-based permits. Wyoming's watershed-based
permitting program is focusing on areas with increasing or heavy CBM development.
WYDEQ identified IDS, EC, SAR, dissolved iron, total recoverable arsenic, barium,
cadmium, and selenium as constituents of concern and has set permit limits for each of these
constituents. WYDEQ is concerned about stream downcutting and flooding associated with
large-volume discharges, but does not have a regulatory mechanism to control CBM discharge
volumes (ERG, 2009f).
EPA reviewed Wyoming's 11 watershed-based permits and determined that limits varied
by the type of discharge category, of which there are four based on the type of receiving water
body and containment practices:
• Category 1—direct discharges to stream channels with no containment
requirements.
• Category 2—discharges are contained in on-channel reservoirs with regular
overtopping of stream banks due to precipitation allowed.
• Category 3—discharges to on-channel headwater reservoirs or playa lakes with
required containment for the 50-year or 100-year 24-hour storm event.
• Category 4—discharges to constructed off-channel pits. These discharges are not
allowed under the watershed permits and require individual permits.
All watershed-based permits contain identical general language prohibiting the following:
the discharge of floating solids; any visible foam or sheen; discharges that cause erosion,
scouring, or damage to the outfall stream; discharges that cause aesthetic or habitat degradation;
and discharge of toxic substances.
Table A-4 lists Wyoming's watershed-based permit limitations by discharge category. In
addition to the discharge limits and prohibitions, Wyoming has watershed-specific monitoring
requirements including monitoring of steam headcuts, channel stability station monitoring, water
quality station monitoring, WET testing, Category 2 flow monitoring, downstream irrigation
monitoring, and Category 1 stream flow limits.
A-6
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Coalbed Methane Extraction:Detailed Study Report
December 2010
Table A-4. Wyoming's Watershed-Based Permit Limitations by Discharge Category
Parameter
Category 1
Daily
Maximum
Category 2
Daily
Maximum
Category 3
Daily
Maximum
Category 4 a
Daily
Maximum
Measurement
Frequency
Flow- and Conductivity-Related Parameters
SAR
Flow (mgd)
Conductivity
(umohs/cm)
1 -13, SAR <
7.10 xEC-
2.48
0.36-9.70
450-7500
8-10
NA
1330-7500
NA
NA
7500
NA
NA
7500
B i weekly- Annually
Monthly-Annually
B i weekly- Annually
Metals
Dissolved Cadmium
(ug/L)
Dissolved Calcium
(mg/L)
Dissolved Copper
(ug/L)
Dissolved Iron (ug/L)
Dissolved Lead (ug/L)
Dissolved Magnesium
(mg/L)
Dissolved Manganese
(ug/L)
Dissolved Silver (ug/L)
Dissolved Sodium
(mg/L)
Dissolved Zinc (ug/L)
Total Radium 226
(pCi/L)
Total Radium 226 +
Total Radium 228
(pCi/L)
Total Recoverable
Aluminum (ug/L)
Total Recoverable
Arsenic (ug/L)
Total Recoverable
Barium (ug/L)
Total Recoverable
Selenium (ug/L)
0.1-4.0
NA
4-13.2
74-1000
2-4
NA
50
7.5
60-170
80-100
o
J
1-60
490-750
2.4-8.4
360-1800
2-5
0.6-4
NA
10
300-1000
2-4
NA
NA
NA
NA
80-100
NA
5
NA
7-10
1800-2000
5
NA
NA
NA
1000
NA
NA
NA
NA
NA
NA
60
NA
750
150-180
1800
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
60
NA
NA
150
1800
NA
Annually
B i weekly- Annually
Annually
Every 3 mo. -Annually
Annually
B i weekly- Annually
Annually
Annually
B i weekly- Annually
Annually
Annually
Annually
Annually
Annually
Annually
Annually
Other Pollutants
Ammonia (mg/L)
Bicarbonate (mg/L)
Chlorides (mg/L)
Dissolved Boron (ug/L)
Dissolved Fluoride
(ug/L)
0.4-6.8
NA
50-230
NA
2000-4000
NA
NA
150-230
NA
4000
NA
NA
230-2000
NA
2000-4000
NA
NA
230-2000
NA
2000-4000
Weekly-Annually
Monthly-Annually
Monthly-Annually
Annually
Annually
A-7
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Coalbed Methane Extraction:Detailed Study Report
December 2010
Table A-4. Wyoming's Watershed-Based Permit Limitations by Discharge Category
Parameter
pH (s.u.)
Sulfate (mg/L)
TDS (mg/L)
Temperature (°C)
Total Alkalinity (mg/L)
Category 1
Daily
Maximum
6.5-9.0
412-3000
300-5000
NA
NA
Category 2
Daily
Maximum
6.5-9.0
NA
NA
NA
NA
Category 3
Daily
Maximum
6.5-9.0
3000
5000
NA
NA
Category 4 a
Daily
Maximum
6.5-9.0
3000
5000
NA
NA
Measurement
Frequency
Monthly-Annually
B i weekly- Annually
B i weekly- Annually
Monthly-Every 6 mo.
Monthly-Annually
a - Category 4 discharges require an individual permit. Limits are displayed here for comparison purposes.
NA - Not applicable.
A-8
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