United States

Environmental Protection

Agency

Office of Water

Washington, DC 20460

EPA-820-R-13-009

April 2013

Technical Development 

Document for the 

Coalbed Methane (CBM) 

Extraction Industry
Technical Development Document for the 

Coalbed Methane (CBM) Extraction 

Industry

EPA-820-R-13-009

April 2013

U.S. Environmental Protection Agency

Office of Water (4303T)

Washington, DC 20460
Acknowledgements and Disclaimer

This document was prepared by the Environmental Protection Agency. Neither the United 

States Government nor any of its employees, contractors, subcontractors, or their employees make 

any warrant, expressed or implied, or assume any legal liability or responsibility for any third 

party’s use of or the results of such use of any information, apparatus, product, or process 

discussed in this report, or represents that its use by such party would not infringe on privately 

owned rights.

Questions regarding this document should be directed to:

U.S. EPA Engineering and Analysis Division (4303T)

1200 Pennsylvania Avenue NW

Washington, DC 20460

(202) 566-1000
Table of Contents

i

TABLE OF CONTENTS

Page

SECTION 1 INTRODUCTION............................................................................................................1-1

1.1 References............................................................................................................1-2

SECTION 2 DATA COLLECTION ACTIVITIES...................................................................................2-1

2.1 EPA’s Stakeholder Outreach Program.................................................................2-1

2.2 EPA’s Site Visit Program ....................................................................................2-1

2.3 Questionnaires......................................................................................................2-2

2.4 Existing Data Collection......................................................................................2-2

2.5 References............................................................................................................2-4

SECTION 3 INDUSTRY PROFILE......................................................................................................3-1

3.1 Overview of Coalbed Methane Industry..............................................................3-1

3.2 CBM Production and the Lifespan of CBM Wells..............................................3-1

3.3 Identifying Coal Basins With CBM Development ..............................................3-2

3.4 Gas Production.....................................................................................................3-6

3.5 Water Production and Management.....................................................................3-8

3.6 Produced Water Characteristics.........................................................................3-10

3.7 References..........................................................................................................3-12

SECTION 4 PRODUCED WATER MANAGEMENT AND TREATMENT TECHNOLOGIES........................4-1

4.1 Treatment Technologies.......................................................................................4-1

4.1.1 Settling Ponds..........................................................................................4-1

4.1.2 Chemical Precipitation.............................................................................4-3

4.1.3 Ion Exchange ...........................................................................................4-7

4.1.4 Reverse Osmosis....................................................................................4-11

4.1.5 Other Desalination Technologies...........................................................4-16

4.2 Zero Discharge Management Methods..............................................................4-19

4.2.1 Underground Injection...........................................................................4-20

4.2.2 Evaporation/Infiltration Ponds...............................................................4-24

4.2.3 Land Application ...................................................................................4-26

4.2.4 Livestock or Wildlife Watering .............................................................4-28

4.2.5 Downhole Gas Water Separators...........................................................4-29

4.3 References..........................................................................................................4-32

SECTION 5 PRODUCED WATER MANAGEMENT COSTS ..................................................................5-1

5.1 Identify Discharging Projects and Discharge Volume.........................................5-2

5.2 Determine Costs for New Water Management Method ......................................5-3

5.3 Compute Costs of Operating Ion Exchange or Using Underground 

Injection ...............................................................................................................5-4

5.4 References............................................................................................................5-5
List of Tables

ii

List of Tables

Page

3-1 CBM Basins and Locations, 2008 ................................................................................... 3-3

3-2 CBM Basins With Potential for CBM Gas Development ............................................... 3-5

3-3 Total CBM Gas Production (Million Cubic Feet), 2007–2011 ....................................... 3-7

3-4 Detailed Summary of CBM Gas Production, by Basin in 2008 and 2011 ...................... 3-7

3-5 Produced Water Discharge Practices in Use by Basin..................................................... 3-9

3-6 2008 CBM Production and Produced Water Discharge Volumes for

Discharging Projects...................................................................................................... 3-10

3-7 Produced Water Effluent TDS Concentrations for the Discharging Basins.................. 3-10

3-8 Pollutant Data Summary for Produced Water Discharges............................................. 3-11

4-1 Considerations for Using Settling Ponds at CBM Operations......................................... 4-2

4-2 Capital and O&M Costs for Settling Ponds..................................................................... 4-3

4-3 Common Additive Chemicals and Targeted Pollutants................................................... 4-4

4-4 Considerations for Using Chemical Precipitation at CBM Operations........................... 4-6

4-5 Capital and O&M Costs for Chemical Precipitation ....................................................... 4-6

4-6 Considerations for Using Ion Exchange at CBM Operations.......................................... 4-9

4-7 Summary of Known Ion Exchange Vendors in the CBM Industry................................. 4-9

4-8 Capital and O&M Costs for Ion Exchange .................................................................... 4-10

4-9 Effectiveness of Membrane Filtration Technologies..................................................... 4-12

4-10 Considerations for Using RO at CBM Operations ........................................................ 4-13

4-11 Capital and O&M Costs for RO .................................................................................... 4-14

4-12 Summary of Known RO Technologies Applicable in the CBM Industry..................... 4-15

4-13 Summary of Known Distillation/Evaporation Vendors in the Oil and Gas Industry .... 4-17

4-14 Summary of Underground Injection by Basin............................................................... 4-22

4-15 Considerations for Using Underground Injection at CBM Operations ......................... 4-23

4-16 Capital and O&M Costs for Underground Injection...................................................... 4-24

4-17 Considerations for Using Evaporation/Infiltration Ponds at CBM Operations............. 4-25

4-18 Capital and O&M Costs for Evaporation/ Infiltration Ponds........................................ 4-26

4-19 Considerations for Using Land Application at CBM Operations.................................. 4-27

4-20 Capital and O&M Costs for Land Application.............................................................. 4-27

4-21 Considerations for Using Livestock Watering at CBM Operations .............................. 4-28

4-22 Capital and O&M Costs for Livestock Watering .......................................................... 4-28
List of Tables

List of Tables (Continued) 

Page 

iii

4-23 DGWS Technologies Design Criteria ............................................................................ 4-29

4-24 Considerations for Using DGWS at CBM Operations .................................................. 4-31

4-25 Capital and O&M Costs for DGWS .............................................................................. 4-31
List of Figures

iv

List of Figures

Page

3-1 Generalized Gas and Water Production Curves for CBM Wells..................................... 3-2

3-2 Map of CBM Basins with Location of 98th Meridian...................................................... 3-4

3-3 U.S. Natural Gas Production, 1990–2035........................................................................ 3-8

4-1 pH versus Concentration of Pollutants ............................................................................ 4-5

4-2 Spiral-Wound Membrane Flow Diagram ...................................................................... 4-11

4-3 Schematic of the CDI Treatment Process...................................................................... 4-19

4-4 Schematic of Electrode Regeneration in a CDI Treatment Unit.................................... 4-19
Section 1 –Introduction

1-1 

SECTION 1

INTRODUCTION 

EPA identified the CBM Extraction Industry as a candidate for a preliminary study in the 

Final 2006 Effluent Guidelines Program Plan (71 FR 76644). In response, EPA received 

comments from citizens and environmental advocacy groups on the Final 2006 Effluent 

Guidelines Program Plan requesting development of a regulation for the CBM Extraction 

Industry. In 2007, EPA began a detailed study of the CBM Extraction Industry. EPA gathered 

information by conducting numerous outreach meetings with stakeholders, performing site visits 

to observe produced water treatment technologies, and administering an industry questionnaire to 

gather site-specific data. Section 2 describes the CBM data collection effort in detail. 

EPA published Coalbed Methane Extraction: Detailed Study Report (the CBM detailed 

study report) in December 2010 (U.S. EPA, 2010a). This report contained an initial technical and 

economic industry profile and EPA’s preliminary review of the data collected. Based on this 

preliminary review, EPA announced its plan to develop effluent limitations guidelines and 

standards (ELGs) for the discharge of wastewater from the CBM Extraction Industry in the Final 

2010 Effluent Guidelines Program Plan. EPA listed the following reasons for selecting CBM for 

potential rulemaking:

• CBM is not included in the current applicability of the Oil and Gas Extraction 

Point Source Category (40 CFR Part 435). 

• The industry is discharging high concentrations of total dissolved solids (TDS) 

mainly sodium salts, either sodium chloride (common table salt) or sodium 

carbonate. 

• Treatment technologies for removal of TDS are available. 

• The industry expanded since EPA’s previous review of this industry in 2004 and 

2005 for the 2006 Effluent Guidelines Program Plan (71 FR 76644). 

EPA’s recent findings show that the natural gas industry has changed since EPA 

conducted a detailed study and selected this category for rulemaking. Declining industry 

economics result in the potential for measurable and significant economic impacts, including 

project closures. See the document Economic Analysis for Existing and New Projects in the 

Coalbed Methane Industry for additional details (U.S. EPA, 2013a). 

This document provides a summary of the technical information EPA has collected to 

date on the CBM industry, a snapshot of the CBM operations in 2008 (when EPA collected 

information from the industry) and an update on the industry since EPA’s data collections 

efforts. EPA used the information provided in this document to develop an economic analysis of 

the industry. The economic analysis is described in the document Economic Analysis for Existing 

and New Projects in the Coalbed Methane Industry (U.S. EPA, 2013a). 

EPA’s analysis of the CBM industry is based on data generated or obtained in accordance 

with its Quality Policy and Information Quality Guidelines. EPA’s quality assurance (QA) and 

quality control (QC) activities include the development, approval, and implementation of Quality 

Assurance Project Plans for the use of environmental data generated or collected from all 

sampling and analyses, existing databases, and literature searches, and for the development of 
Section 1 –Introduction

1-2 

any models that use environmental data. Unless otherwise stated within this document, the data 

used and associated data analyses were evaluated as described in these QA documents to ensure 

they are of known and documented quality; meet EPA’s requirements for objectivity, integrity, 

and utility; and are appropriate for the intended use. 

1.1 REFERENCES

1. U.S. EPA. 2010a. Coalbed Methane Extraction: Detailed Study Report. Also available at: 

http://water.epa.gov/scitech/wastetech/guide/cbm_index.cfm. EPA-HQ-OW-2008-0517, 

DCN 09999. 

2. U.S. EPA. 2013a. Economic Analysis for Existing and New Projects in the Coalbed 

Methane Industry. EPA-HQ-OW-2010-00824, DCN CBM00680. 
Section 2 –Data Collection Activities

2-1 

SECTION 2

DATA COLLECTION ACTIVITIES

EPA collected information about the CBM Extraction Industry in three phases: 

• 2007 – Site visit and stakeholder outreach. 

• 2009 – Additional site visits and Screener and Detailed Questionnaires requesting 

information characterizing operations in 2008. 

• 2012 – Supplemental data collection.

With the exception of questionnaire responses, additional documentation is included in 

the following dockets, accessible through http://www.regulations.gov: 

• Preliminary 2008 Effluent Guidelines Program Plan (EPA-HQ-OW-2006-0771).

• Preliminary 2010 Effluent Guidelines Program Plan (EPA-HQ-OW-2008-0517). 

• Final 2010 Effluent Guidelines Program Plan (EPA-HQ-OW-2010-0824). 

Copies of responses to the Screener and Detailed Questionnaire are not available in the 

public docket due to the significant number of CBI claims in the responses. The Summary of 

Coalbed Methane Information Collection Request Confidential Business Information

memorandum discusses the quantity of CBI information in these data sources (U.S. EPA, 2013). 

2.1 EPA’S STAKEHOLDER OUTREACH PROGRAM

EPA conducted extensive outreach during the CBM detailed study to help identify key 

issues and concerns of industry and other stakeholders. The outreach goals included (1) 

collecting information from stakeholders, (2) explaining the purpose of EPA’s planned industry 

survey and the process for approval and implementation of the survey, and (3) identifying and 

resolving issues with survey implementation as early as possible. This outreach helped EPA 

develop the Detailed Questionnaire. EPA incorporated comments and suggestions from industry 

and other stakeholders into the Detailed Questionnaire design. For more information on the 

stakeholder outreach program, see the CBM detailed study report (U.S. EPA, 2010).

2.2 EPA’S SITE VISIT PROGRAM

Between 2007 and 2009, EPA visited six coal basins1 with CBM development in eight 

states. In total, EPA visited 33 CBM operators with a range of CBM operations that demonstrate 

the typical production and water management methods in the basin. During each site visit, EPA 

collected general site information (e.g., location, operator name, field name, produced water 

management practices, and well spacing); information about produced water beneficial use and 

disposal methods; details of produced water treatment; and economic information such as 

descriptions of factors affecting decisions to begin production or shut in (cease production). 

 

1 Coal basins are regions of coal deposits resulting from the accumulation and sedimentation of organic and 

inorganic debris.
Section 2 –Data Collection Activities

2-2 

Information collected during the site visits is available in the public dockets for the 2006 and 

2008 Effluent Guidelines Program Plans. For more information on the site visit program, see 

Coalbed Methane Detailed Study 2007 Data Collection and Outreach (U.S. EPA, 2008). 

2.3 QUESTIONNAIRES

Based on information collected during the site visit and outreach programs, EPA 

identified the primary unit of interest for the CBM Extraction Industry as a project, defined as a 

well, group of wells, lease, group of leases, or recognized unit that is operated as an economic 

unit when making production decisions. A lease is an agreement between the operator and 

mineral rights owner to acquire the rights to hold the property for a period of time, whether or 

not the lease is developed. EPA developed a set of questionnaires (i.e., Screener and Detailed 

Questionnaires) to collect nationally representative data on the CBM Extraction Industry 

including information on basin characteristics, project size (number of wells), and discharge 

methods (i.e., direct or indirect discharge and zero discharge). EPA distributed the Detailed 

Questionnaires to operators who are in charge of day-to-day operations of the CBM projects. For 

more details on the questionnaires, see the CBM detailed study report (U.S. EPA, 2010). The 

questionnaires collected data on CBM operations in 2008. 

As part of this effort, EPA developed survey sample weights to scale project data 

collected in the questionnaires to represent the entire CBM Extraction Industry. The survey 

weights account for the operators who did not receive a Detailed Questionnaire (nonsurveyed) or 

did not respond to the Detailed Questionnaire (nonrespondent). The memorandum Development 

of Final Survey Weights for CBM Analyses (DCN CBM00653) provides a detailed description of 

how survey weights were developed (U.S. EPA, 2012). 

2.4 EXISTING DATA COLLECTION

EPA reviewed existing data sources, including state and federal agency databases, journal 

articles and technical papers, technical references, industry/vendor telephone queries, and vendor 

websites to supplement the Detailed Questionnaire data. EPA identified the following 

information specific to CBM operations in existing data sources:

• General operating conditions (e.g., produced water management, storage, and 

transportation). 

• Produced water constituents and concentrations. 

• Treatment technologies implemented at CBM operations to reduce TDS 

concentrations (e.g., reverse osmosis, ion exchange).

• Current state permitting practices and discharge requirements. 

• Data on CBM operations as of 2010 to update 2008 Detailed Questionnaire data 

collection and determine any changes to the industry.2 2010 was the most recent 

year in which a complete data set was available for most states.

 

2 EPA’s 2010 Data Collection and Methodology Used to Update 2008 Existing Source Analysis memorandum (U.S. 

EPA, 2013c) documents all of the assumptions and calculations used to update the 2008 Detailed Questionnaire data 

to 2010.
Section 2 –Data Collection Activities

2-3 

EPA reviewed the following existing data sources: 

• ALL Consulting3

 documents on CBM, shale gas, and oil and gas produced water 

(2002 through 2011). 

• The Colorado School of Mines (CSM) report An Integrated Framework for 

Treatment and Management of Produced Water (CSM, 2009).

• The National Academy of Sciences report Management and Effects of Produced 

Water in the United States (NAS, 2010). 

• Vendor information on specific treatment technologies. 

• Water treatment references on the use and limitations of general wastewater and 

produced water treatment technologies for produced water. 

• Well data from HPDI, Inc. (a data service company) to identify existing CBM 

wells and coal basins. 

• Information from other federal and state agencies, including: 

- U.S. Department of Energy (DOE) – National Energy Technology 

Laboratory (NETL) research on volume and management of produced 

water, downhole separation, and ion exchange (http://www.netl.doe.gov/). 

- U.S. DOE’s Energy Information Administration (EIA) – information on 

natural gas projections, wellhead prices, and other supplemental 

information used to complete the 2010 analysis of the CBM Extraction 

Industry (http://www.eia.gov/). 

- State permitting agencies – 2008 and 2010 discharge monitoring reports 

(DMRs) from the Alabama Department of Environmental Management 

and the Wyoming Department of Environmental Quality. 

- National Pollutant Discharge Elimination System (NPDES) Permit 

Program – 2008 and 2010 DMRs for the state of Montana (Powder River 

Basin). 

- State oil and gas websites – gas and water production data from the 

following state oil and gas websites, used to evaluate changes in produced 

water volumes and gas production from 2008 to 2010: 

 Colorado (Raton Basin) 

 Wyoming (Powder River and Green River Basins) 

 Pennsylvania (Appalachian Basin) 

 West Virginia (Appalachian Basin)

 

3 ALL Consulting is a professional services firm specializing in energy and water management. They have published 

documents about the CBM industry, CBM best management practices, and produced water management options and 

beneficial use alternatives.
Section 2 –Data Collection Activities

2-4 

 Alabama (Black Warrior and Cahaba Basins)

 Montana (Powder River Basin) 

2.5 REFERENCES

1. CSM (Colorado School of Mines). 2009. An Integrated Framework for Treatment and 

Management of Produced Water: Technical Assessment of Produced Water Treatment 

Technologies. 1st Edition. RPSEA Project 07122-12. EPA-HQ-OW-2008-0517. DCN 

10007. 

2. NAS (National Academy of Science). 2010. Management and Effects of Produced Water 

in the United States. Available online at: 

http://www.nap.edu/catalog.php?record_id=12915. 

3. U.S. EPA. 2008. Coalbed Methane Detailed Study 2007 Data Collection and Outreach. 

EPA-HQ-OW-2006-0771, DCN 05354. 

U.S. EPA. 2010. Coalbed Methane Extraction: Detailed Study Report. Also available at: 

http://water.epa.gov/scitech/wastetech/guide/cbm_index.cfm. EPA-HQ-OW-2008-0517, 

DCN 09999. 

4. U.S. EPA. 2012. Development of Final Survey Weights for CBM Analyses. EPA-HQOW-2010-0824, DCN CBM00662. 

5. U.S. EPA. 2013. Summary of Coalbed Methane Information Collection Request 

Confidential Business Information. EPA-HQ-OW-2010-0824, DCN CBM00661. 
Section 3 – Industry Profile

3-1

SECTION 3

INDUSTRY PROFILE

This section describes the CBM Extraction Industry’s gas and water production and 

produced water volumes, characteristics, and management practices.

3.1 OVERVIEW OF COALBED METHANE INDUSTRY

Production of natural gas from coal seams is considered unconventional gas extraction. 

Conventional gas extraction involves extracting natural gas from permeable rock formations 

such as siltstones, sandstones, and carbonates. In contrast, unconventional gas extraction 

involves extracting natural gas from lower-permeability, harder-to-produce formations, such as 

shale plays, coal basins, and tight gas sands. 

The natural gas contained in and removed from coal seams is called coalbed methane or 

CBM (U.S. DOE, 2006). CBM exists in the coal seams in three basic states: as free gas, as gas 

dissolved in the water in coal, and as gas adsorbed on the solid surface of the coal (ALL, 2004). 

CBM extraction requires drilling wells into the coal seams and removing the formation water 

contained in the coal seam to reduce hydrostatic pressure and allow the adsorbed CBM to be 

released from the coal (Wheaton et al., 2006; U.S. DOE, 2006). The water produced during 

CBM extraction is called produced water. Produced water from CBM operations primarily 

consists of formation water, i.e., the water contained within the coal formation; in some cases, it

may include wastewater from drilling activities. The infrastructure for CBM extraction sites 

typically comprises the well pad, gathering system pumps and pipelines, storage tanks, and 

treatment equipment (if treatment occurs).

3.2 CBM PRODUCTION AND THE LIFESPAN OF CBM WELLS

The typical lifespan of a CBM well is between five 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 (De Bruin et al., 2001): 

• An early stage, in which large volumes of formation water 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 formation water pumped from the coal seam decreases. 

• A late stage, in which the amount of gas produced declines and the amount of 

formation water pumped from the coal seam remains low.

Figure 3-1 generalizes the gas and water production curves for CBM wells. 
Section 3 – Industry Profile

3-2

Flow Rate

Time 

Gas

Water

Figure 3-1. Generalized Gas and Water Production Curves for CBM Wells

This production profile is very different from conventional gas or oil production. Most 

conventional gas wells produce relatively little water throughout their lives, although some 

increase in water production might occur as the well ages. Oil wells, or those which produce both 

gas and water, tend to produce little water at first, with production of water rising as the well 

ages. A frequently used model of the production from conventional oil or oil and gas wells 

assumes a constant decline rate for oil with an inverse growth rate in water, achieving a constant 

production of total fluid over time (see, for example, Appendix C in U.S. EPA, 1996). 

3.3 IDENTIFYING COAL BASINS WITH CBM DEVELOPMENT

CBM is produced in a limited number of coal basins located across the United States. The 

gas and water content in the coal vary by hardness of coal or the “rank” of the coal. Coal basins 

in the eastern United States tend to have lower water content and higher gas content (i.e., higher 

rank) than western coal formations. Mid-rank coals contain a good balance of gas and water 

content in the coal seams and are most economical for CBM extraction: thus, CBM development 

has primarily occurred in mid-rank bituminous coals (ALL, 2003). 

Using information from HPDI, Inc. (see Section 2.4), EPA identified the coal basins with 

CBM development as of 2006. The HPDI database included information about CBM production 

in 15 coal basins and was used to develop the distribution list for the Screener and Detailed 

Questionnaires, which collected data on operations in 2008. Table 3-1 lists the 15 CBM basins 

and the number of CBM operators in 2008 within each coal basin based on information from the 

surveys. EPA determined that a total of 251 operators operated 766 projects and over 57,000 
Section 3 – Industry Profile

3-3

CBM wells in 2008 (U.S. EPA, 2010). Figure 3-2 illustrates the coal basins that produced CBM 

in 2008.

CBM development began in the early 1980s. The first area to be developed was the Black 

Warrior Basin in Alabama, followed in the latter part of the 1980s by the San Juan Basin in New 

Mexico and Colorado. For many years, CBM production was limited to these three states 

(Fisher, 2001). Production in the Powder River Basin, primarily located in Wyoming, began in 

earnest in the early 1990s, and the Powder River Basin quickly became a major source of CBM 

by the end of the 1990s (WOGCC, 2010). By 2000, Wyoming was producing 10 percent of all 

CBM; by 2008, production in the state was approaching a third of the total production (EIA, 

2010; U.S. EPA, 2010). According to EIA, CBM production continues to center around these 15 

coal basins in 2009 (EIA, 2013). 

Table 3-1. CBM Basins and Locations, 2008 

Coal Basin States Number of CBM Operators

Anadarko Oklahoma 32

Appalachian Virginia, West Virginia, Pennsylvania 13

Arkla Louisiana 2

Arkoma Oklahoma, Arkansas 41

Black Warrior Alabama 8

Cahaba Alabama 3

Cherokee/Forest City Kansas 36

Greater Green River Wyoming 8

Illinois Illinois, Indiana 2

Permian/Fort Worth Texas 1

Powder River Basin Montana, Wyoming 68

Raton Colorado, New Mexico 5

San Juan New Mexico 55

Uinta-Piceance Utah, Colorado 9

Wind River Wyoming 1

Source: U.S. EPA, 2010. 
Section 3 – Industry Profile

3-4

Source: EIA, 2013. 

Figure 3-2. Map of CBM Basins with Location of 98th Meridian4

In addition to the producing basins listed in Table 3-1, EPA also identified a number of 

other coal basins that have limited or no CBM production. CBM development depends on factors 

including projected amounts of gas and water production, availability of gas and water pipeline 

infrastructure, availability of land, and the difficulty associated with water and gas extraction.

EPA reviewed published information on potential CBM developments. Table 3-2 lists 

basins that were not producing CBM as of 2008 and provides a discussion of the CBM potential 

in each basin. Based on the information available to date, EPA found that a large number of the 

coal basins that had no development in 2008 have limited to no potential for future development.

 

4 The ELGs for the Oil and Gas Extraction Point Source Category (40 CFR Part 435) allow oil and gas wells located 

west of the 98th meridian to be regulated under Subpart E (Agricultural and Wildlife Water Use).
Section 3 – Industry Profile

3-5

Table 3-2. CBM Basins With Potential for CBM Gas Development

Coal Basin State(s) Potential for CBM Development

Some Potential for CBM Development

Black Mesa Arizona There has been large-scale surface coal mining in the area since the 1960s,

but no CBM testing has occurred. The area has easy access to market via 

the recently constructed Questar Southern Trails gas pipeline (ARI, 2010).

Coos Bay Field Oregon • EIA did not identify this field as a significant CBM resource (EIA, 

2007).

• Several wells were drilled in 2005 and 2006, but commercial 

operations have not occurred. Coalbeds are located at depths over 

12,000 feet. Drilling at these depths results in high volumes of 

produced water, with high salt concentration (AAPG, 2005; OPB, 

2011).

Kaiparowits Utah As at Black Mesa, large-scale surface coal mining existed in the area since 

the 1960s but no CBM testing has occurred. The area has easy access to

market via the recently constructed Questar Southern Trails gas pipeline

(ARI, 2010).

Unknown Potential for CBM Development

Alaska North and South 

Central Alaska

CBM content is unknown in most Alaska coal basins. Most of the CBM 

potential exists in the North Slope region; however, the area lacks gas and 

water pipeline infrastructure. Other prospective areas include Central 

Alaska–Nenana and Southern Alaska Cook Inlet. Few pilot studies have 

been implemented, but no commercial production has occurred in Alaska to 

date (NAEG, n.d.; AKCEP, 2012).

Denver Colorado CBM content is unknown in this area. The potential impact of the aquifers 

bordering the formations also hinders CBM development (Bryner, 2002).

North Central 

Coal

North Montana CBM potential has not been studied extensively in this region (ARI, 2010). 

EIA estimates 1.2 trillion cubic feet of recoverable CBM resources in this 

basin (EIA, 2007).

Southwestern 

Coal Region

North Central Texas Coal mining occurs in this region; however, CBM potential has not been 

studied extensively. EIA estimates 6.8 trillion cubic feet of recoverable 

CBM resources in this basin (EIA, 2007).

Limited or No Potential for CBM Development

Big Horn Wyoming

Montana (West of 

Powder River Basin)

Geology limits CBM production. The basin lacks thick, persistent coal in 

most of the region (USGS, 1999).

Deep River Central North 

Carolina

Geology limits CBM production. The fragmented basin geology makes gas 

production uneconomical (BLM, 2008).

Gulf Coast Florida Panhandle to 

Texas Gulf Coast

• Pilot projects have occurred in Louisiana and Texas. In Louisiana, a 

few wells have successfully produced CBM, but there is limited 

knowledge on the production in this region (ARI, 2010).

• Expansion in this basin will be limited because it is heavily populated 

and limited leasable public lands are available. Access to lands where 

CBM reservoirs exist could be a problem. (USGS, 2000).

Hanna Carbon Wyoming Production ceased in 2006 (EIA, 2007).

Henry 

Mountains

Utah Geology limits CBM production. Topography of coal beds is discontinuous, 

which is unfavorable for trapping of CBM (Utah BLM, 2005).
Section 3 – Industry Profile

3-6

Table 3-2. CBM Basins With Potential for CBM Gas Development

Coal Basin State(s) Potential for CBM Development

Michigan Michigan CBM potential has not been studied extensively in this region (ARI, 2010). 

EIA indicates the resources in this basin are minimal (0.01 trillion cubic 

feet) (EIA, 2007).

Pacific Washington Geology limits CBM production. The geologically complex area makes gas 

recovery challenging. Development may also impact existing basalt 

aquifers (U.S. EPA, 2004).

Park Colorado Basin formation favors conventional oil and gas production, which will 

limit CBM production in this area (Sanborn, 1981).

Southwest

Colorado

Southwest Colorado Geology limits CBM production. The topography of coal beds is 

discontinuous, which is unfavorable for trapping of CBM (Utah BLM, 

2005).

Terlingua Field West Texas EIA indicates that the resources in this basin are near zero (EIA, 2007).

Williston North Dakota

Montana

• EIA indicates that this coal basin has 0.6 trillion cubic feet of 

potentially recoverable CBM (EIA, 2007). 

• CBM potential of lignite coals has not been studied extensively, but 

anecdotal evidence from water well drillers suggests CBM exists in 

North Dakota lignite. This basin is primarily a coal mining and shale 

oil and gas area, which will likely limit CBM production. No CBM has 

been identified in this area to date (NAEG, n.d.).

Wyoming 

Overthrust

Western Wyoming • EIA indicates that the CBM in this basin are near zero (EIA, 2007).

• The region primarily focuses on conventional oil and gas production. 

Most of the CBM-producing regions are in the eastern part of the 

Powder River coal region (in Wyodak coal zone), also known as the 

Powder River Basin (WYSGS, 1999).

3.4 GAS PRODUCTION

Table 3-3 summarizes the total gas production from coalbed methane and shale gas wells 

between 2007 and 2011, as published by EIA5

 (EIA, 2013a). Coalbed methane gas production 

peaked in 2008 at about 2 trillion cubic feet. The peak production year also coincides with the 

calendar year that EPA collected CBM Extraction Industry data (see Section 2 for a summary of 

EPA’s data collection activities). From 2008 to 2011, CBM production saw a constant decline

while shale gas production increased. 

Table 3-4 shows a detailed summary of natural gas production, by basin, for 2008 and 

2011 (EIA, 2013b). EIA did not report CBM production for Pennsylvania, West Virginia, and 

Illinois in 2008 or 2011, and did not explain why they did not report production for these states. 

However, EPA’s 2008 Detailed Questionnaire included CBM production and produced water 

discharges for these three states.

Figure 3-3 presents EIA projections for the natural gas market through 2035. EIA 

anticipates the total U.S. gas production to increase from 22 trillion cubic feet in 2010 to 28 

trillion cubic feet in 2035, mainly due to a rapid rise of shale gas production. EIA projects that 

 

5 2011 gas production data were estimated values.
Section 3 – Industry Profile

3-7

CBM production will decline over the next 20 years, with its contribution to total gas production 

falling from about 9 percent of total natural gas production in 2008 to an expected 7 percent by 

2035 (EIA, 2010). 

Table 3-3. Total CBM Gas Production (Million Cubic Feet), 2007–2011 

Industry 2007 2008 2009 2010 2011a

Coalbed Methane Wells 1,999,748 2,022,228 2,010,171 1,916,762 1,779,055

Shale Gas Wells 1,990,145 2,869,960 3,958,315 5,817,122 8,500,983

Source: EIA, 2013a. 

a – Data for 2011 are estimated. 

Table 3-4 Detailed Summary of CBM Gas Production, by Basin in 2008 and 2011

Basin State

Gas Production

(Million Cubic Feet)

2008 2011 Percent Change b

Anadarko, Arkoma Oklahoma, Arkansas 76,860 53,206 -30.8%

Appalachian Pennsylvania, Virginia, 

West Virginia c 101,567 112,219 10.5%

Arkla Louisiana 0 0 0.0%

Black Warrior/Cahaba Alabama 112,222 95,727 -14.7%

Cherokee/Forest City Kansas 44,066 35,924 -18.5%

Illinois Illinois 0 0 0.0%

Green River, Wind River,

Powder River (Wyoming)

Wyoming

563,274 508,739 -9.7%

Powder River (Montana) Montana 14,496 6,691 -53.8%

Permian/Fort Worth Texas 0 0 0.0%

Raton, San Juan, 

Uinta-Piceance

Colorado, New Mexico, 

Utah 1,102,493 961,185 -12.8%

Other Ohio 0 0 0.0%

Total 2,014,978 1,773,691 -12.0%

Source: EIA, 2013b. 

Note: EIA provides detailed state production data. To present the gas production data by basin, EPA consolidated 

state data where necessary. State production data may also represent more than one basin.

b – Data for 2011 are estimated. 

c – EIA indicates zero gas production for Pennsylvania and West Virginia in 2008 and 2011 (EIA, 2013b). 

Therefore, the gas production values for the Appalachian basin in 2008 and 2011 are for Virginia. The Detailed 

Questionnaire included responses for CBM projects operating in Pennsylvania and West Virginia in 2008 and 

included these projects in the summaries using Detailed Questionnaire data.
Section 3 – Industry Profile

3-8

Source: EIA, 2010. 

Figure 3-3. U.S. Natural Gas Production, 1990–2035 

3.5 WATER PRODUCTION AND MANAGEMENT

As discussed in Section 2, CBM operators often group wells together into projects to 

manage, store, treat, and dispose of produced water, a byproduct of CBM gas production. CBM 

operators often combine produced water from multiple wells and occasionally multiple projects 

into a produced water management system (PWMS). In some cases, operators transfer water to 

another operator’s PWMS for management and disposal. 

To dispose produced water, CBM operators currently choose from surface water 

discharge and zero discharge alternatives. Surface water discharge includes direct discharge to 

waters of the United States and indirect discharge through POTWs to surface water. Zero 

discharge includes underground injection, evaporation/infiltration ponds, land application (for 

crop or non-crop production), and livestock or wildlife watering. Section 4 discusses these 

management approaches in detail.
Section 3 – Industry Profile

3-9

Table 3-5 lists the 15 basins that had CBM production in 2008, indicates whether EPA 

classified the basin as discharging or zero-discharging6, and lists the discharge practices used by 

each basin based on results of the screener and Detailed Questionnaire. Operators in seven of 15 

basins reported surface water discharge. Projects in discharging basins may also use zero 

discharge method for produced water disposal. Zero discharge methods used in each basin are 

also noted in Table 3-5. 

Table 3-5. Produced Water Discharge Practices in Use by Basin

Basin Basin Discharge Statusa Zero Discharge Methods Reported

Anadarko Zero Discharge Underground Injection

Appalachian Dischargeb Underground Injection, Land Application, 

Evaporation/Infiltration Pond

Arkla Zero Discharge CBId

Arkoma Zero Discharge Underground Injection

Black Warrior Discharge None

Cahaba Discharge CBId

Cherokee/Forest City Zero Discharge Underground Injection

Greater Green River Discharge CBId

Illinois Discharge CBId

Permian/Ft. Worth Zero Discharge CBId

Powder River Basin (PRB) Discharge Underground Injection, Land Application, Livestock 

Watering, Evaporation/Infiltration Pond

Raton Discharge Underground Injection, Livestock Wateringc

, 

Evaporation/Infiltration Pond

San Juan Zero Discharge Underground Injection, Livestock Wateringc

, 

Evaporation/Infiltration Pond

Uinta-Piceance Zero Discharge Underground Injection, Evaporation/Infiltration Pond

Wind River Zero Discharge CBId

Source: Screener and Detailed Questionnaire. Zero discharge methods listed have at least one project that uses this 

practice.

a – Some discharging basins may also use zero discharge methods as shown in the zero discharge methods column. 

b – Of the discharging basins, only the Appalachian basin had both direct and indirect dischargers. Of the 78 

projects that reported discharging in the Detailed Questionnaires, only four projects in the Appalachian Basin 

reported indirect discharge. All other discharging basins use direct discharge.

c – Zero discharge method was indicated in the screener survey response but cannot be confirmed through the 

Detailed Questionnaire.

d – To protect CBI, specific zero discharge methods could not be presented for basins with few operators. 

Table 3-6 shows the estimated total volume of produced water generated and the 

estimated total volume of water discharged to surface water (directly or indirectly) in 2008 by 

operators in the discharging basins. Overall, operators discharged approximately 30 percent of

the water produced and used zero discharge practices to manage the remaining produced water 

volume. 

 

6 If any project in a basin discharges, then EPA classified the basin as “discharge.” If no projects in a basin 

discharge, then EPA classified the basin as “zero discharge.”
Section 3 – Industry Profile

3-10

Table 3-6. 2008 CBM Production and Produced Water Discharge Volumes for

Discharging Projects

Water Production (million bbl) a Discharge Volume (million bbl) b

1,234 371

Source: Detailed Questionnaire. 

a – EPA weighted the Detailed Questionnaire results to reflect the total water produced in the discharging basins 

listed in Table 3-5. 

b – EPA used available DMR data to estimate the total volume discharged to surface water for the Black Warrior, 

Cahaba, Greater Green River, Illinois, and Powder River (MT and WY) basins. DMR data were not available for the 

Appalachian and Raton basins; therefore, EPA used the reported discharge volumes from the Detailed Questionnaire 

and survey weights to estimate total discharge volumes for the basins. 

3.6 PRODUCED WATER CHARACTERISTICS

As discussed in Section 1, one of the reasons EPA selected the CBM Extraction Industry 

for potential rulemaking is the discharge of high concentrations of TDS to surface water. 

Produced water from the CBM industry is characterized by elevated levels of dissolved 

constituents commonly measured as TDS or salinity. The main constituents of TDS in produced 

water are sodium salts, either sodium chloride (common table salt) or sodium carbonate. TDS 

may also include trace elements (e.g., barium and iron). Some produced waters are also 

monitored for the sodium adsorption ratio. This ratio is expressed as a ratio of the sodium 

concentration to the concentration of calcium and magnesium. Table 3-7 shows the average, 

minimum, and maximum TDS concentrations for produced water effluent for the discharging 

basins listed in Table 3-6.

7

Table 3-7. Produced Water Effluent TDS Concentrations for the Discharging Basins

Basin Minimum 

Concentration

Average 

Concentration

Maximum 

Concentration Units

Appalachian 4,480 9,470 14,300 mg/L

Black Warrior / Cahaba a 527 11,800 34,290 mg/L

Green River / Powder River (WY) a 385 621 739 mg/L 

Illinois 7 254 423 mg/L

Powder River (MT) a 603 1,260 1,880 mg/L

Raton 420 1,310 2,650 mg/L

Source: 2008 CBM Detailed Questionnaire and 2008 DMRs. 

a – Estimated based on reported conductivity and the conversion: 1 μS/cm (or 1 μmho/cm) = 0.67 mg/L TDS.

 

7 EPA obtained the produced water concentration information presented in this section from Discharge Monitoring 

Reports (DMR). Therefore, these data reflect available information on CBM discharges to surface water. The tables 

do not include concentration information for CBM produced water that may be handled by other disposal methods 

such as underground injection.
Section 3 – Industry Profile

3-11

CBM produced water generally contains low levels of other constituents, such as oil and 

grease and dissolved organics, that are associated with conventional oil and gas produced water. 

As reported in Wyoming DMRs, other trace pollutants that may be present in produced water 

include potassium, sulfate, bicarbonate, fluoride, ammonia, arsenic, and radionuclides. Pollutant 

concentrations will vary by basin depending on the geology of the underlying coal. Table 3-8

presents the average, minimum, and maximum concentrations for the monitored pollutants 

reported in DMRs for the industry (industry-level concentrations). 

Table 3-8. Pollutant Data Summary for Produced Water Discharges

Pollutant Qualifier Minimum Average Maximum Unit

Alkalinity 75 410 698 mg/L

Ammonia, Total < 0.05 1.43 2.54 mg/L

Arsenic, Total a 0 0.0011 0.0044 mg/L

Barium, Total 0.033 0.038 0.043 mg/L

Bicarbonate a 13 817.3 3190 mg/L

BOD, 5-day < 1 4.93 16.5 mg/L

Boron, Total < 0.05 0.17 0.18 mg/L

Calcium, Total 2.6 14.9 150 mg/L

Chloride, Total 8.4 4,470 18,700 mg/L

Copper, Total < 0.01 0.008 1.2E-6 mg/L

Fluoride, Total 3.24 3.51 3.87 mg/L

Iron, Total < 0.05 0.69 4.88 mg/L

Magnesium, Total 0.6 1.92 7.1 mg/L

Manganese, Total < 0.05 0.10 0.51 mg/L

Nitrogen, Total 0.2 2.13 4.7 mg/L

Oil and Grease < 1 1.88 8.5 mg/L

Phosphorus, Total < 0.01 8.06E-2 0.14 mg/L

Potassium, Total a 2 10.25 19 mg/L

Radium 226 a 0.07 0.47 1 pCi/L

Radium 228 a 0.17 0.53 1.2 pCi/L

Radium 226 + 228 a 0.03 1.48 4.1 pCi/L

Selenium, Total < 0.004 0.004 0.004 mg/L

Sodium, Total 97 513 842 mg/L

Sulfate, Total 15.3 68.0 118 mg/L

TDS 7 5,218 34,300 mg/L

TSS < 4 11.4 60.0 mg/L

Zinc, Total < 0.02 1.46E-02 2.98E-5 mg/L

a – Wyoming is the only state that reported radionuclide (radium 226 and radium 228), arsenic, bicarbonate, and 

potassium concentrations in DMRs. Wyoming projects only report daily maximum values for these pollutants (i.e., 

they do not report average values). Therefore, the minimum, maximum, and average values presented in the table 

are all calculated using the daily maximum values.

Source: 2008 CBM Detailed Questionnaire and 2008 DMRs.
Section 3 – Industry Profile

3-12

3.7 REFERENCES

1. AAPG (American Association of Petroleum Geologists). 2005. Understanding Basalts 

May Be the Key: Pacific Northwest Plays Present a Puzzle. The Explorer. November.

Available online at: http://www.aapg.org/explorer/2005/11nov/pacific_nw.cfm. Accessed 

August 28, 2012. 

2. AKCEP (Alaska Center for Energy and Power). 2012. Coalbed Methane. Alaska Energy 

Wiki. Available online at: http://energy-alaska.wikidot.com/coalbed-methane. Accessed 

August 28, 2012. 

3. ALL (ALL Consulting). 2003. Handbook on Coal Bed Methane Produced Water: 

Management and Beneficial Use Alternatives. Prepared for Ground Water Protection 

Research. Available online at: http://www.allllc.com/publicdownloads/CBM_BU_Screen.pdf. EPA-HQ-OW-2004-0032-2483, DCN 

03451. 

4. ALL. 2004. Coal Bed Methane Primer. Available online at: http://www.allllc.com/publicdownloads/CBMPRIMERFINAL.pdf. 

5. ARI. 2010. Memorandum from Michael Godec, ARI, to James Covington, U.S. EPA. 

April. EPA-HQ-OW-2008-0517, DCN 07346. 

6. BLM (Bureau of Land Management). 2008. North Carolina: Reasonably Foreseeable 

Development Scenario for Fluid Minerals. Available online at: 

http://www.blm.gov/pgdata/etc/medialib/blm/es/jackson_field_office/planning/planning_

pdf_nc_rfds.Par.49259.File.dat/N_Carolina_RFDS_R1.pdf. 

7. Bryner, G. 2002. Coalbed Methane Development in the Intermountain West: Primer. 

University of Colorado, School of Law. Available online at: 

http://www.oilandgasbmps.org/docs/GEN174-CBMConferenceReportNRLC.pdf. 

8. De Bruin, R.H., R.M. Lyman, R.W. Jones, and L.W. Cook. 2001. Coalbed Methane in 

Wyoming Information Pamphlet 7 (revised). Wyoming State Geological Survey. EPAHQ-OW-2004-0032-1904, DCN 03070. 

9. EIA (U.S. Department of Energy, Energy Information Administration). 2007. US 

Coalbed Methane: Past, Present, and Future. Available online at: 

http://www.eia.gov/oil_gas/rpd/cbmusa2.pdf. 

10. EIA, 2010. Annual Energy Outlook 2012. Available online at: 

http://www.eia.gov/forecasts/aeo/pdf/0383(2012).pdf. Accessed August 28, 2012. 

11. EIA. 2013a. Natural Gas Gross Withdrawals and Production, Annual, 2007-2011. 

Available online at: http://www.eia.gov/dnav/ng/ng_prod_sum_dcu_nus_a.htm. Accessed 

March 3, 2013. 
Section 3 – Industry Profile

3-13

12. EIA. 2013b. Natural Gas Gross Withdrawals from Coalbed Wells, 2002-2011. Available 

online at: http://www.eia.gov/dnav/ng/ng_prod_sum_a_epg0_fgc_mmcf_a.htm. 

Accessed March 3, 2013. 

13. Fisher, J.B. 2001. Environmental Issues and Challenges in Coal Bed Methane Production. 

Exponent, Inc. Tulsa, OK. Available online at: 

http://ipec.utulsa.edu/Conf2001/fisher_92.pdf. EPA-HQ-OW-2008-0517, DCN 07229. 

14. Horsley & Witten, Inc. 2001. Draft Evaluation of Impacts to Underground Sources of 

Drinking Water by Hydraulic Fracturing of Coalbed Methane Reservoirs. Prepared for 

the U.S. Environmental Protection Agency. EPA-HQ-OW-2004-0032-2543 (DCN 

03489). 

15. NAEG (Native American Energy Group). n.d. Coal Bed Methane Operations. Available 

online at: 

http://www.nativeamericanenergy.com/index.php?option=com_content&view=article&id

=54&Itemid=152. Accessed September 20, 2012. 

16. OPB (Oregon Public Broadcasting). 2011. Oregon Gas Drilling: Different Challenges 

Between Sandstone and Coal Beds. Oregon Public Broadcasting. July 31. Available 

online at: http://earthfix.opb.org/energy/article/coal-bed-methane-creates-coos-baychallenges/. Accessed August 28, 2012. 

17. Sanborn, A.F. 1981. Potential Petroleum Reserves of Northeastern Utah and 

Northwestern Colorado. In: New Mexico Geological Society. New Mexico Geological 

Society Fall Field Conference Guidebook – 32: Western Slope (Western Colorado and 

Eastern Utah). Available online at: 

http://nmgs.nmt.edu/publications/guidebooks/downloads/32/32_p0255_p0266.pdf. 

Accessed September 20, 2012. 

18. U.S. DOE (Department of Energy). 2006. Future Supply and Emerging Resources – 

Coalbed Natural Gas. EPA-HQ-OW-2004-0032 (DCN 03480). 

19. U.S. EPA (Environmental Protection Agency). 1996. Economic Impact Analysis of Final 

Effluent Limitations Guidelines and Standards for the Coastal Subcategory of the Oil and 

Gas Extraction Point Source Category. Office of Water. EPA-821-R-96-022. Available 

at: http://nepis.epa.gov/. 

20. U.S. EPA. 2004. Evaluation of Impacts to Underground Sources of Drinking Water by 

Hydraulic Fracturing of Coalbed Methane Reservoirs, Attachment 11. Office of 

Groundwater and Drinking Water. Available online at: 

http://water.epa.gov/type/groundwater/uic/class2/hydraulicfracturing/wells_coalbedmetha

nestudy.cfm. 

21. U.S. EPA. 2010. Screener Survey Database (CBI). EPA-HQ-2008-0517 (DCN 07363). 
Section 3 – Industry Profile

3-14

22. USGS (U.S. Geological Survey). 1999. 1999 Resource Assessment of Selected Tertiary 

Coal Beds and Zones in the Northern Rocky Mountains and Great Plains Region. 

Professional Paper 1625-A. Available online at: http://pubs.usgs.gov/pp/p1625a/. 

23. USGS. 2000. Preliminary Gulf Coast Coalbed Methane Exploration Maps: Depth to 

Wilcox, Apparent Wilcox Thickness and Vitrinite Reflectance. Report 2000-113. 

Available online at: http://pubs.usgs.gov/of/2000/ofr-00-0113/downloads/OF00-113.pdf. 

24. Utah BLM (Bureau of Land Management). 2005. Chapter 4: Mineral Occurrence 

Potential and Likelihood of Development of Mineral Resources. In: Mineral Potential 

Report. Utah Department of Interior, Bureau of Land Management. Available online at: 

http://www.blm.gov/pgdata/etc/medialib/blm/ut/richfield_fo/planning/rmp/background_d

ocuments/mineral_potential.Par.97714.File.dat/RichfieldMineralPotentialReport_CH_4.p

df. Accessed August 28, 2012. 

25. Wheaton, J., T. Donato, S. Reddish, and L. Hammer. 2006. 2005 Annual Coalbed 

Methane Regional Ground-Water Monitoring Report: Northern Portion of the Powder 

River Basin. Open-File Report 538. Montana Bureau of Mines and Geology. EPA-HQOW-2008-0517 (DCN 03474). 

26. WOGCC (Wyoming Oil and Gas Conservation Commission). 2010. Wyoming CBM 

Production. Available online at: http://wogcc.state.wy.us/. EPA-HQ-OW-2008-0517 

(DCN 07364). 

27. WYSGS (Wyoming State Geological Survey). 1999. Wyoming Fossil Fuels for the 21st

Century. Available online at: 

http://web.anl.gov/PCS/acsfuel/preprint%20archive/Files/44_1_ANAHEIM_03-

99_0061.pdf. Accessed August, 28, 2012. 
Section 4 – Produced Water Management and Treatment Technologies

4-1 

SECTION 4

PRODUCED WATER MANAGEMENT AND TREATMENT 

TECHNOLOGIES

This section provides information on the management and treatment technologies to 

reduce or eliminate pollutant discharges from CBM extraction operations. EPA identified 

technologies used at CBM operations in 2008 through site visits and the responses to the 

Detailed Questionnaire (see Section 2 for a description of EPA’s data collection efforts). 

Through publicly available information, EPA also identified technologies that have not been 

implemented at CBM operations in 2008 but are potential candidates for treating produced water. 

Section 4.1 describes treatment technologies that can reduce pollutant discharges. Section 4.2

presents information on zero discharge practices that eliminate the discharge of produced water, 

and therefore the discharge of associated pollutants to surface water. 

4.1 TREATMENT TECHNOLOGIES

This section describes technologies to treat produced water prior to discharge. Each 

section describes the technology, discusses factors impacting implementation of the technology 

at CBM operations at a national level, and provides information on the components required for 

developing cost estimates associated with their use. Before discharging produced water, CBM 

operators may treat produced water to reduce concentrations of suspended and dissolved solids. 

As discussed in Section 3.6, produced water contains dissolved cations such as sodium, calcium, 

and magnesium. These constituents are in equilibrium with dissolved anions such as bicarbonate, 

chloride, and sulfate. The concentrations and types of cations and anions present in the produced 

water will depend on the geology of the basin and will impact the treatment types that can be 

used to reduce the dissolved constituents. Ion exchange and reverse osmosis are the only 

treatment technologies reported to be used by CBM operators to reduce TDS concentrations in 

2008. Other treatment technologies capable of TDS removal, such as nanofiltration, capacitative 

deionization, electrodialysis/electrodialysis reversal, and distillation/evaporation, have not yet 

been implemented at full-scale CBM operations and, therefore, are only briefly discussed. 

4.1.1 Settling Ponds

Settling ponds are designed to remove particulates from wastewater using gravity 

sedimentation. They work by allowing water to stagnate or flow very slowly through the pond, 

thereby allowing suspended solids to settle to the bottom of the pond. Large particles settle 

quickly, but smaller suspended particles take longer to settle. For this reason, the suspended 

solids removal rates increase with residence time (i.e., the amount of time that it takes a discrete 

quantity of water to flow through the system) and particle size. 

The size and configuration of settling ponds vary; some ponds operate in series or in 

parallel, while others consist of one large settling pond. Operators size ponds to provide enough 

residence time to reduce the total suspended solids (TSS) levels in the wastewater to a target 

concentration and to allow for a certain lifespan of the pond. 

Some CBM operators have added aeration to settling ponds (i.e., rip-rap, fountains, 

aerators) to enhance gravity settling and to aid in the removal of metals. When certain dissolved 
Section 4 – Produced Water Management and Treatment Technologies

4-2 

FFFF(OOOO)2(ss) = FFFF+2 + 2OOOO−

metals come in contact with oxygen, the metals oxidize and become solid particles in the water. 

These solid particles can then be removed by filtration or flotation. For example, at a neutral pH, 

iron exists as soluble ferrous iron (Fe+2). However, in the presence of oxygen, the soluble ferrous 

iron oxidizes to ferric iron (Fe+3), which can hydrolyze to form insoluble ferric hydroxide 

(Fe(OH)2(s)), as shown in Equation 4-1. 

Equation 4-1 

Insoluble ferric hydroxide will precipitate from solution, thereby removing dissolved iron 

from the influent water. Initiating iron oxidation in produced water involves adjusting the pH to a 

neutral value, if needed, and routing the produced water over rip-rap to enhance the water’s 

contact with air before discharge or by adding aerators to the pond. The use of rip-rap also helps 

in controlling erosion at the influent to or effluent from the pond, where scouring is a problem. 

Implementing Settling Ponds at CBM Operations

The concentration of settleable solids in produced water will affect the design and 

operation of the pond. Higher levels of settleable solids may generate more residuals that require 

disposal, require a longer residence time, or require a larger pond footprint. Settling ponds do not 

target reductions in the concentrations of TDS. 

CBM extraction generates large volumes of produced water at the beginning stages of a 

well and steadily decreases over the lifetime of the well (as discussed in Section 3.2). Settling 

ponds are designed to store the maximum initial volume of produced water generated by a given 

well or group of wells. Pond construction requires a large footprint to construct a pond capable 

of treating the maximum volume of produced water initially coming out of a well or group of 

wells. As the produced water volume declines over time, the settling ponds will likely be closed 

or used for treatment of produced water from a newly producing well or group of wells. The 

latter option may incur a higher cost to operators because, if the new well or group of wells is not 

near the pond, transportation costs will increase.

Table 4-1 lists considerations for using settling ponds at CBM operations. 

Table 4-1. Considerations for Using Settling Ponds at CBM Operations

Consideration Use

Considerations for Use at 

Existing CBM Operations

• Settling ponds do not target reduction of total dissolved solid concentrations.

• Ponds may require increased residence time due to higher levels of settleable 

solids.

• Ponds may require large footprint to handle maximum produced water flow.

• Also, see considerations for evaporation/infiltration ponds in Table 4-17.

Available in All Basins? Yes. However, settling ponds will not remove TDS.

Currently In Use at CBM 

Operations?

Yes, settling ponds were reported at CBM operations in all of the discharging

basins.
Section 4 – Produced Water Management and Treatment Technologies

4-3 

Components of Costs

Table 4-2 shows operating capital and operating and maintenance (O&M) cost

components for settling ponds.

Table 4-2. Capital and O&M Costs for Settling Ponds 

Cost Use

Capital Costs • Land acquisition or leasing is required for the pond footprint if the operator does 

not own the land adjacent to the wells. The pond footprint is often large to achieve 

the appropriate residence time to meet targeted treatment efficiencies. The 

availability of additional land owned by the operator for a pond will be sitespecific. Alternatively, ponds can be located elsewhere and transportation costs 

must be considered.

• Operators constructing new ponds on undisturbed land will incur costs for 

excavation and mobilization.

• Operators may also need:

- Piping infrastructure to transport the water from the wellhead(s) to the pond.

- Pumps to transport the water, if gravity flow is not possible.

- Liners to contain the produced water or to minimize infiltration into the subsoil 

(e.g., all CBM constructed ponds in Alabama must use liners because the state

does not allow infiltration from ponds.) (CMAA, 2012). 

• Settling ponds may require additional power. If the CBM project does not currently 

have electricity, operators will need to bring infrastructure or generators on site. 

• Operators also incur costs for pond closure at end of life.

O&M Cost Components • Pumps will require electricity.

• Costs will be incurred to transport produced water to the pond by pumps and

pipeline or trucking.

• Ponds can achieve higher removal efficiencies for TSS and other pollutants through 

the addition of chemicals (e.g., pH adjustments, coagulants, flocculants, scale 

inhibitors, biocides).

Other Cost Components Ponds require permits to operate.

Residuals Generated As solids settle, sludge will accumulate at the bottom of the pond and may need 

periodic removal, typically by dredging, and disposal off site. Otherwise, the sludge 

will remain in the pond until closure (ERG, 2007a).

Energy Requirements Pond systems can be designed to use gravity flow, but most need pumps to move 

water from the wellhead to the pond and then from the pond to the final destination. If 

the operator does not already have power on-site for transporting produced water, he 

will need to install power lines or generators.

Personnel Requirements Operators may need to periodically check the system (e.g., ensure that produced water 

flow into and out of the pond is not obstructed, ensure that water levels in the pond are 

appropriate) and perform monitoring required by the discharge permit.

4.1.2 Chemical Precipitation

Chemical precipitation wastewater treatment systems remove dissolved metals and 

suspended solids through the addition of chemicals to the wastewater to alter the physical state of 

targeted pollutant to help settle and remove the solids. The specific chemical(s) used depends 

upon the type of pollutant requiring removal. Operators can precipitate chemicals using the 

following methods: 
Section 4 – Produced Water Management and Treatment Technologies

4-4 

• Adding Chemicals to Enhance Coagulation – The addition of chemical coagulants 

can enhance settling by promoting the growth of larger, heavier particles. 

Polymers can be added to water to bind together particles into larger particles. 

Additional chemicals such as alum (aluminum sulfate, Al2(SO4)3 18H2O) or iron 

salts may be required to change the charge of the particles such that they can 

aggregate and settle. However, the use of these compounds in produced water 

treatment may introduce additional dissolved constituents (i.e., constituents 

present in the chemical additives) that are being targeted for removal from the 

produced water (e.g., iron, sulfate). 

• Adding Chemicals for Precipitation – Chemicals can also be added to convert the 

dissolved pollutants to insoluble forms that can then precipitate, or settle, out of 

solution. For example, Pollutant B (which is soluble in water) is the pollutant 

targeted for removal. Chemical A is added to the solution with dissolved pollutant 

B. A and B react to form a new chemical, AB, which is insoluble; it therefore 

becomes a suspended solid rather than a dissolved solid. The insoluble solids 

precipitate out of the solution; they either settle over time or need to be removed 

by filtration. Chemical precipitation cannot be used for highly soluble ions, such 

as sodium and chloride that are the components of TDS found in produced water. 

Sodium and chloride will remain in solution at all pH levels (Eckenfelder, 2000). 

Table 4-3 shows how different additive chemicals remove different pollutants. 

Table 4-3. Common Additive Chemicals and Targeted Pollutants 

Additive Chemical Targeted Pollutants

Alum Calcium and Magnesium Bicarbonate, Alkalinity, Phosphate, Mercury

Sulfides Arsenic, Cadmium, Selenium, Mercury

Lime (Calcium Hydroxide) Hardness and Total Suspended Solids

Ferric Chloride Alkalinity or Phosphates

Ferric Sulfate Barium

Ferrous Sulfate Barium, Calcium, Calcium Hydroxide

Ferric Hydroxide Mercury, Cadmium

Sources: Metcalf and Eddy, 2003; U.S. EPA, 2000.

One of the underlying principles that dictate chemical precipitation design and operation 

is that a metal’s solubility is a direct result of pH. Each metal is soluble at different pH ranges 

(Metcalf and Eddy, 2003). As a result, chemical precipitation operation involves careful control 

of pH to maximize metals removal. Figure 4-1 shows how pH affects the solubility of different 

metals. The minimum of each curve represents the minimum solubility and optimum pH for 

chemical precipitation. As shown in the figure, the solubility of calcium and magnesium, two of 

the pollutants present in produced water, decrease with increasing pH; however, these pollutants 

do not have minimum solubility points within the typical pH range for this technology. Sodium, 

the dissolved salt commonly targeted for removal in produced water, is not typically removed by 

chemical precipitation.
Section 4 – Produced Water Management and Treatment Technologies

4-5 

Because CBM pollutants have different solubility points, it is not possible to achieve 

maximum removal of all pollutants in a one-step precipitation process. In order to remove all of 

the influent pollutants, multiple stages of precipitation are necessary, using different pH levels 

and additive chemicals (Metcalf and Eddy, 2003). Table 4-3 lists what additive chemicals 

remove different pollutants. 

1.E-11

1.E-08

1.E-05

1.E-02

1.E+01

1.E+04

1.E+07

1.E+10

1.E+13

0 2 4 6 8 10 12 14

Concentration, Log (mg/L)

pH

Calcium (Ca(OH)2) Iron (Fe(OH)2) Iron (Fe(OH)3)

Magnesium (Mg(OH)2) Manganese (Mn(OH)2) Lead (Pb(OH)2)

Source: Means and Hilton, 2004.

Figure 4-1. pH versus Concentration of Pollutants 

Implementing Chemical Precipitation at CBM Operations

Treatment system designers and operators consider the influent water characteristics and 

the desired effluent quality when selecting the appropriate quantity and type of additive 

chemical, including influent wastewater temperature, volume feed rate, pH, and pollutant 

concentrations (Metcalf and Eddy, 2003). Pollutant concentrations in produced water can vary 

over time, requiring ongoing monitoring and operation considerations during chemical addition 

and treatment.

As shown in Table 4-3, the common additives used for precipitation may include 

pollutants that are targeted for removal in produced water (e.g., iron, calcium); therefore, adding 

these chemicals may add dissolved solids to the effluent water. Advanced monitoring systems 
Section 4 – Produced Water Management and Treatment Technologies

4-6 

may be installed to minimize the effects of chemical addition on effluent water (Metcalf and 

Eddy, 2003).

Table 4-4 lists considerations for using chemical precipitation at CBM operations.

Table 4-4. Considerations for Using Chemical Precipitation at CBM Operations

Consideration Use

Considerations for Use at 

Existing CBM Operations

Chemical precipitation does not reduce concentrations of the constituents of TDS 

found in produced water (e.g., sodium, chloride).

Available in All Basins? Yes. However, these treatment systems require appropriate pH and temperature 

controls and pollutant concentrations for efficient treatment to remove soluble 

metals, as shown in Figure 4-1. Sodium and chloride are not removed by chemical 

precipitation.

Currently In Use at CBM 

Operations? 

No; operators may add chemicals to settling ponds to enhance precipitation but 

CBM operators are not using chemical precipitation systems with equalization tanks, 

precipitation tanks, and clarifiers.

Chemical Precipitation Cost Components

Table 4-5 shows capital and O&M cost components for chemical precipitation.

Table 4-5. Capital and O&M Costs for Chemical Precipitation 

Cost Use

Capital Costs • If the operator does not have the land available for the treatment system footprint, he 

will need to acquire additional land. Alternatively, system can be located elsewhere 

and transportation costs must be considered.

• The operator may also need:

- Chemical storage and mixing tanks. 

- Equalization tanks or basins;

- A settling tank (clarifier) or filtration system. 

- Piping infrastructure to transport the water to and from the treatment system.

- Low-pressure pumps for chemical addition. 

- Monitoring equipment to monitor chemical levels and ensure appropriate 

chemical addition.

O&M Cost Components • The treatment system may require additive chemicals.

• Costs will be incurred to transport produced water by pumps and pipeline or trucking.

• The treatment system will require periodic system maintenance, including sludge 

disposal.

Residuals Generated In addition to treated wastewater, chemical precipitation processes produce sludge. The 

quantity and composition of the sludge depends on the pollutants removed and the 

additive chemical used. The sludge produced from chemical precipitation may go 

through further treatment to recover water and concentrate the solids before ultimate 

disposal (e.g., landfill).

Energy Requirements Low-pressure pumps used for chemical addition will need electricity to power them.

Personnel Requirements The treatment system requires personnel to monitor and control the system.
Section 4 – Produced Water Management and Treatment Technologies

4-7 

4.1.3 Ion Exchange

Ion exchange removes charged ions (metals and other dissolved salts) from produced 

water by exchanging them with other charged ions. Ion exchange units use either cation or anion 

resins: cation resins exchange positive ions and anion resins exchange negative ions. Positively 

charged cations such as sodium, magnesium, and calcium are the primary ions in produced water 

targeted for removal. Therefore, cation resins are required for the treatment of produced water.

In CBM ion exchange applications, pretreatment is not a significant concern because of 

the low levels of suspended solids. A representative from Exterran (formerly EMIT), a Powder 

River Basin ion exchange vendor, noted that the Exterran/Higgins LoopTM ion exchange unit has 

a high tolerance for TSS and produced water does not require filtration before treatment with this 

system.

Implementing Ion Exchange at CBM Operations

As discussed previously, produced water contains dissolved cations such as sodium, 

calcium, and magnesium in equilibrium with dissolved anions such as bicarbonate, chloride, and 

sulfate. The concentrations and types of cations and anions present in the produced water will 

depend on the geology of the basin. For example, in the Powder River Basin, the dissolved solids 

consist mostly of sodium bicarbonate, present as sodium ions (Na+

) and bicarbonate ions 

(HCO3

-

). The type of ion exchange resin used will depend on both the pollutants targeted for 

removal and their influent and targeted effluent concentrations.

Equation 4-2 illustrates the ion exchange reaction that takes place to remove sodium from 

produced water with the presence of bicarbonate ions. The resin (R) first exchanges its hydrogen 

ions (H+

) with sodium ions (Na+). After the initial ion exchange reaction, the hydrogen ions (H+) 

are free to react with the bicarbonate (HCO3

-

) ions in solution to form CO2 (Beagle, 2007). After 

ion exchange treatment, the effluent wastewater may require pH adjustment before reuse or 

discharge due to the depletion of bicarbonate (ALL, 2006). Many ion exchange resins use 

sodium as the cation on the resin rather than hydrogen. These resins would not be appropriate for 

removing sodium because they add sodium rather than hydrogen ions to the solution. Therefore, 

ion exchanges systems designed for produced water use hydrogen ions as the cation on the resin. 

Because the treated water will contain more hydrogen ions, the produced water will become 

more acidic (pH will decrease) (NETL, 2011a).

R-H+ + Na+ + HCO3

- → RNa+

H+ + HCO3

- → R-Na+ + H2O + CO2 Equation 4-2

In a paper discussing the application of produced water treatment technologies, Kimball

(2010) noted that, outside the Powder River Basin, ion exchange has limited application due to 

the presence of higher concentrations of mixed salts such as sodium chloride and sodium sulfate. 

Removing TDS in this type of water may require a two-stage process, shown in Equation 4-3 and 

Equation 4-4. In the first step, sodium is removed, similar to the first step of Equation 4-2. The 

hydrogen ions remain in solution rather than reacting with bicarbonate. The second step removes 

the chloride ions using an anion resin. This additional step increases the cost of the ion exchange 

system because both cation and anion exchange units are required. 
Section 4 – Produced Water Management and Treatment Technologies

4-8 

R-H+ + Na+ + Cl-→ RNa+H+ + Cl- Equation 4-3

ROH + H+ + Cl-→ ClR+H2O Equation 4-4

As discussed previously, ion exchange resins designed for sodium ion removal replace 

the sodium ions in the produced water with hydrogen ions from the resin. The increase in 

hydrogen ions decreases the pH of the effluent water. The decrease in pH changes the 

concentrations of the carbonic components of the water (CO2, HCO3

-

, H2CO3), which in turn 

affects the concentrations of calcium and magnesium in the produced water and the overall 

effluent quality. 

As shown in Equation 4-2, the hydrogen ions on the resin used for sodium removal fill 

with sodium ions as the process occurs. The hydrogen ions replace the sodium ions to regenerate 

the resin and to continue produced water treatment. Regeneration requires a strong acid (for 

example, sulfuric acid) to be added over the resin bed. The sodium ions desorb from the resin 

and the hydrogen ions from the acid replace them. The resulting regenerate solution is a highsodium brine solution. Operators rinse the resin with clean water to prepare it for another cycle, 

and collect and dispose of the regeneration solution and rinse water. Resins also require periodic 

disinfection in some cases to prevent biological fouling (ALL, 2006).

Operators may further treat the resulting brine stream before disposal (i.e., crystallization, 

thermal evaporation/distillation). Operators in the Powder River Basin currently using ion 

exchange typically dispose of the brine through underground injection. 

In addition to considerations previously discussed, the following factors are important 

when implementing ion exchange at CBM operations: 

• Influent Water –An Integrated Framework for Treatment and Management of 

Produced Water: Technical Assessment of Produced Water Treatment 

Technologies (CSM 2009) states that ion exchange is effective for produced water 

with TDS between 500 and 7,000 milligrams per liter (mg/L). As shown in Table 

3-7, the average TDS concentration of produced water in the eastern U.S. CBM 

basins may be higher than recommended for use of ion exchange. In addition, 

3,500 mg/L is the upper limit TDS concentration for an ion exchange system used

in the Powder River Basin to remove sodium from sodium bicarbonate produced 

water. 

• Flow Bypass and Blending – Ion exchange can reduce TDS concentrations to less 

than the permit-required discharge concentrations. To reduce costs, operators may 

treat only a portion of their produced water and blend treated and untreated water 

to reach the required effluent concentration. 

Table 4-6 summarizes the considerations for using ion exchange at CBM operations.
Section 4 – Produced Water Management and Treatment Technologies

4-9 

Table 4-6. Considerations for Using Ion Exchange at CBM Operations

Consideration Use

Considerations for Use at 

Existing CBM Operations

• The effectiveness of ion exchange treatment systems depends on the produced 

water TDS concentrations and the TDS constituents (e.g., sodium chloride 

versus sodium bicarbonate). 

- These systems can be operated as a batch or continuous processes (with one 

or multiple treatment trains), allowing for treatment of decreasing volumes 

of water.

• Regeneration waste requires recycling or disposal.

Available in All Basins? No, TDS concentrations may be too high to make ion exchange a viable treatment 

method in most basins.

Currently in Use at CBM 

Operations?

Yes, ion exchange is in use only in the Powder River Basin.

Table 4-7 lists known ion exchange vendors identified by EPA in the CBM Extraction 

Industry. As of 2008, only the Powder River Basin operated ion exchange units for produced 

water. The Ion Exchange Vendors in the CBM Industry memorandum (U.S. EPA, 2013) provides 

additional details for each type of ion exchange unit listed in Table 4-7. In general, the variations 

between each ion exchange system represent different configurations to reduce treatment 

residuals volumes or reduce system downtime for resin regeneration events. Systems are 

specifically designed and operated based on discharge requirements and influent water quality. 

Ion exchange systems are typically capable of removing up to 66 percent of the conductivity in 

influent waters (Kimball, 2010).

Table 4-7. Summary of Known Ion Exchange Vendors in the CBM Industry

Vendor Technology Name Resina CBM Status Basin References

Exterran Water 

Discharge 

Technology, LLC 

(Exterran) and 

Severn Trent 

Services

Higgins LoopTM

continuous ion 

exchange

SAC Deployed at full 

scale. 

Powder 

River

• Dennis, 2005

• Johnston, 2010

Drake Water 

Technologies

Drake 

countercurrent 

process

SAC Deployed at full 

scale.

b

Powder 

River

• ERG, 2007b (site visit)

• Drake, 2011 (vendor call)

• Drake, 2012 (vendor 

email)

Eco-Tec Equipment RecofloTM SAC Deployed at full 

scale. 

Powder 

River

• Eco-Tec, 2008

• Eco-Tec, 2007

• Eco-Tec, 2006

Rohm and Haas Cross-current ion 

exchange process

SAC and 

WAC

Pilot testing. Powder 

River

PG Environmental, 2007a

(site visit)

SET Corp (formerly 

RG Global)

DynIXTM WAC Deployed at full 

scale.

Powder 

River

Jangbarwala, 2008

a – SAC – strong-acid cation; WAC – weak-acid cation. 

b – The Drake Water Technologies ion exchange unit was successfully installed at two sites in the Powder River 

Basin. However, in the fall of 2010, the price of gas dropped and made it cost-prohibitive for operators to install 

and/or maintain ion exchange units for treatment of their produced water (Drake, 2012).
Section 4 – Produced Water Management and Treatment Technologies

4-10

Components of Costs

Ion exchange technologies have lower capital and O&M costs than other TDS treatment 

technologies such as reverse osmosis (URS, 2011; ALL, 2011). The capital costs cover tanks, 

pumps, and piping. Vendors estimate that 70 to 80 percent of the operating costs are for the 

regeneration solution and the disposal of the regenerate; only a small portion of the operating 

costs is from purchasing the resin (CSM, 2009; Drake, 2011). Third-party ion exchange vendors 

may offer ion exchange units to CBM operators for a dollar per barrel ($/bbl) operating and 

maintenance cost, which includes everything needed to treat the water to a specified effluent 

concentration, discharge the water, and dispose of residual waste. CBM operators work with ion 

exchange vendors to design a system appropriate for their influent water quality flow and 

targeted effluent. 

Table 4-8 shows operating capital and O&M cost components for ion exchange. 

Table 4-8. Capital and O&M Costs for Ion Exchange 

Cost Use

Capital Costs • If the operator does not have the land available for the treatment system footprint, 

he will need to acquire additional land. Alternatively, skid-mounted units with 

smaller footprints may be useful for produced water because of the finite length of 

time water treatment will be required. 

• The operator may also need:

- Treatment vessels for ion exchange.

- Chemical storage tanks for chemicals used in regeneration and for storing 

brine prior to disposal.

- Equalization tanks to ensure constant flow to the system. 

- Piping infrastructure to transport the water to and from the treatment system.

- Low-pressure pumps. 

• Ion exchange will require additional power. If the CBM project does not currently 

have electricity, operators will need to bring infrastructure or generators on site.

O&M Cost Components • Operators may use biocides to prevent resin fouling.

• Costs will be incurred to transport produced water by pumps and pipeline or 

trucking.

• Resin fouling may occur and will require regeneration using chemicals such as 

hydrochloric or sulfuric acid. The frequency of regeneration will increase with 

increased TDS concentrations. 

• The frequency of resin replacement will depend on the amount of pollutant 

removed and the effectiveness of resin regeneration. The lifespan of the resin will 

vary across CBM operations due to the varying concentrations and volumes of 

produced water treated.

Residuals Generated Operators must remove, neutralize, and dispose of residuals generated by the 

treatment system. Operators typically dispose of the residuals via underground 

injection in the CBM Extraction Industry.

Energy Requirements Various sources indicate that ion exchange alone requires lower energy consumption 

per treated gallon than electrodialysis/electrodialysis reversal, reverse osmosis, or 

evaporation/condensation (URS, 2011; ALL, 2006). Energy requirements typically 

only include electricity for pumps.

Personnel Requirements The treatment system requires personnel to monitor and control flow rates, product 

water quality, and resin regeneration.
Section 4 – Produced Water Management and Treatment Technologies

4-11

4.1.4 Reverse Osmosis

Reverse osmosis (RO) is a well-established membrane treatment process used for 

desalination of seawater and removal of dissolved materials from industrial wastewater. This 

section provides a brief overview of membrane filtration and then focuses on RO, the membrane 

filtration technology that can be used to remove dissolved salts, such as sodium, from produced 

water.

Membrane filtration uses thin film membranes that are semi-permeable, meaning they 

allow water but not dissolved solids to flow through; they are permeable to water, but 

impermeable to dissolved solids. The rate that water passes through the membrane depends on 

the operating pressure, concentration of dissolved materials, and temperature, as well as the 

permeability of the membrane. 

In wastewater treatment applications, membrane filtration separates the feed wastewater 

into two product streams: the permeate, which has passed through the membrane, and the 

concentrate, which has been retained (“rejected”) by the membrane. The percentage of 

membrane system feed that emerges from the system as permeate – i.e., the volume of permeate 

divided by the volume of feed – is known as the water recovery. Figure 4-2 illustrates a typical 

RO system. 

Source: Based on information from Metcalf and Eddy, 2003 and CSM, 2009.

Figure 4-2. Spiral-Wound Membrane Flow Diagram
Section 4 – Produced Water Management and Treatment Technologies

4-12

Membrane filtration technologies include microfiltration, ultrafiltration, nanofiltration, 

and reverse osmosis. Table 4-9 lists general characteristics of membrane filtration technologies 

and the typical constituents removed. As shown in Table 4-9, the differences in the pollutants 

removed by these filtration technologies lie in the pore sizes. As seen in the table, both 

nanofiltration and RO can remove dissolved inorganics. However, the nanofiltration membrane 

is not a complete barrier to dissolved salts. In general, salts that have monovalent ions such as 

sodium chloride or sodium bicarbonate have rejections (removals) of 20 to 80 percent. Salts with 

divalent anions (e.g., magnesium sulfate) have rejections of 90 to 98 percent. Therefore, RO 

membranes are the most effective for removing the TDS found in produced water from CBM 

operations (Dow Chemical, 2011).

Table 4-9. Effectiveness of Membrane Filtration Technologies

Feature Microfiltration Ultrafiltration Nanofiltration Reverse Osmosis

Operating Pressure (psi) 15 75 225 400

Pore Size (nm) >50 2–50 <2 <2

Reject/Concentrate Volume 5–15% 5–15% 10–25% 40–70%

Suspended Solids Removal Excellent Impractical Impractical Impractical

Dissolved Inorganic 

Removal

Not Applicable Not Applicable Good (Depending 

on Salt Species)

Very Good

Energy Requirements Low Medium Medium High

Sources: Metcalf and Eddy, 2003; CSM, 2009; Eckenfelder, 2000.

RO membranes separate constituents based on size and electrostatic charge. They will 

repel most ions (charged particles) and allow neutral molecules like water to pass through. RO 

removes both cations and anions simultaneously. Because salts, such as sodium (Na+

) and 

chloride (Cl-), are ions that are repelled by RO membranes, RO is used for desalination (Metcalf 

and Eddy, 2003). Typical RO membranes reject more than 99 percent of the ions in the produced 

water (CSM, 2009). According to information from CDM, an RO vendor, because RO removes 

both cations and anions simultaneously, it has broader applications than ion exchange for 

treatment of produced water (CDM, 2007). 

The typical design characteristics of membranes result in treatment rates of 8 to 12 

gallons per square foot of membrane per day (Metcalf and Eddy, 2003). To reduce the space 

required by membrane systems, the system design generally configures the membranes as 

spirals, tubes, or multiple layers, as shown in Figure 4-2. With a high-pressure pump, feed water 

is continuously pumped at elevated pressure to the membrane system. Within the membrane 

system, the feed water is split into the permeate and concentrate (i.e., a highly saline, 

concentrated brine). Disposal options for concentrate from produced water treatment include 

deepwell injection and evaporation basins. 

Without proper pretreatment, RO membranes are subject to fouling.8

 Constituents that 

cause fouling include metal hydroxides, colloidal and particulate foulants, precipitates or salts, 

 

8 Fouling occurs when both dissolved and suspended solids deposit onto a membrane surface and degrade its overall 

performance, thereby decreasing permeate quality and water recovery percentage.
Section 4 – Produced Water Management and Treatment Technologies

4-13

organics (e.g., oil), and biologicals (e.g., microbes, bacteria). To prevent scaling and reduce 

membrane fouling, the addition of antiscalants or biocides or TSS removal is required. 

Implementing RO at CBM Operations

Operators consider the following in the design and operation of RO units for produced 

water: 

• Influent Water Quality – RO was optimized for desalination of sea water, which 

typically has a TDS concentration of 35,000 mg/L. RO units are generally only 

able to treat wastewater with TDS concentrations up to about 50,000 mg/L (CSM, 

2009). High water recovery9 (75 to 90 percent) is possible if influent TDS is 

below approximately 25,000 mg/L (ALL, 2011). As shown in Section 3.6, the 

maximum average basin TDS concentration is 12,512 mg/L. 

• Fouling and Scaling – Compounds in produced water can foul membranes, which 

can reduce treatment efficiency and result in high volumes of concentrate. A 

larger concentrate stream can lead to higher disposal costs.

• Membrane Life – Because of potential fouling issues, membranes can last as little 

as one to two years in some cases (Asano, 2007). 

RO systems can be manufactured and installed as portable, skid-mounted units, suitable 

for the generally short time required to treat produced water. Table 4-10 shows considerations 

for using RO in CBM operations. 

Table 4-10. Considerations for Using RO at CBM Operations

Consideration Use

Considerations for Use at 

Existing CBM Operations

• Design variations in RO treatment systems are dependent on the discharge 

requirements and influent water quality.

• Constituents in produced water can foul membranes and pretreatment (e.g., 

filtration, pH adjustment, antiscalant addition) and/or periodic cleaning may be 

required to mitigate scaling.

• Membranes may need frequent replacement because of the common fouling/scaling 

issues (Asano, 2007).

Available in All Basins? Yes, TDS levels in produced water in the discharging basins are within the range that 

is treatable by RO (up to about 50,000 mg/L) (CSM, 2009).

Currently In Use? Yes; RO was reported at CBM operations in the Powder River Basin.

a

a – While some operators reported using RO treatment systems in their responses to the Detailed Questionnaire, 

many of them also noted that the systems did not prove to be economically feasible, and they were forced to shut 

them down. 

 

9 The water recovery percentage is defined as the treated wastewater volume divided by the total influent wastewater 

volume.
Section 4 – Produced Water Management and Treatment Technologies

4-14

Components of Costs

RO vendors note that system costs depend on influent water quality, flow rate, and 

desired effluent quality (Kimball, 2010; Migliavacca, 2011; Alexander, 2011). Table 4-11 shows 

operating capital and O&M cost components for RO systems. 

Table 4-11. Capital and O&M Costs for RO 

Cost Use

Capital Costs • If the operator does not have the land available for the treatment system footprint, he 

will need to acquire additional land. Alternatively, skid-mounted units with smaller 

footprints may be useful for produced water because of the finite length of time water 

treatment will be required. 

• The operator may also need:

- Pretreatment equipment if the influent water does not meet the requirements of 

the RO system.

- Treatment vessels for ion exchange.

- Chemical storage tanks for chemicals used for maintaining the RO system and for

storing brine prior to disposal.

- Equalization tanks to ensure constant flow to the system. 

- Piping infrastructure to transport the water to and from the treatment system.

- High-pressure pumps.

O&M Cost Components • Operators may use chemicals for pretreatment and/or to prevent membrane fouling.

• Costs will be incurred to transport produced water by pumps and pipeline or trucking.

• Membrane fouling may occur and will require replacement.

Residuals Generated The amount of brine requiring disposal will depend on produced water salt 

concentration. According to CDM, brine disposal represents the most expensive 

treatment component due to the cost of trucking, limited number of disposal wells, and 

limited injection capacity (Kimball, 2010).

Energy Requirements RO requires energy to run the pumps required to pressurize the influent. According to 

Siemens, a general rule of thumb is that for every 100 parts per million TDS in the 

influent, one pound of osmostic pressure is required (Siemens, 2011).

Personnel Requirements RO systems operate with minimal onsite operator supervision.

Table 4-12 lists vendors that have developed RO systems for oil and gas wastewater as 

identified by EPA. EPA found only one vendor that had implemented RO at a full-scale CBM 

operation. 
Section 4 – Produced Water Management and Treatment Technologies

4-15

Table 4-12. Summary of Known RO Technologies Applicable in the CBM Industry

Vendors Technology Description Statusa References

Siemens Water

Technologies

Siemens provides standard RO technology in mobile trailers and permanent 

installations that include settling ponds and media filtration for pretreatment.

Deployed at full scale 

(CBM).

Alexander, 2011 (vendor call)

GeoPure and Texas 

A&M

These vendors developed RO technology specifically for treating oilfield 

waters for agricultural and other beneficial use. The system has been tested 

with shale gas flowback water and is currently being applied in multiple 

feasibility studies.

Deployed at shale gas

operations. 

Burnett, 2006

Veolia Water 

Solutionsa

Veolia markets various RO technologies (e.g., MORO, OPUS, ZDD) that are 

designed for different influent TDS concentrations and/or different residual 

generation rates.

Deployed at shale gas

operations. 

Migliavacca, 2011 (vendor call)

Veolia Water Solutions, 2008

Triwatech, LLC Triwatech configures site-specific treatment systems using various treatment 

technologies (including RO). EPA has not identified any full-scale systems to 

date.

Pilot testing (CBM). Malecha, 2006

CDM CDM reports that its RO technology can achieve greater than 98 percent 

recovery of produced water.

Bench testing (CBM). Kimball, 2010

a – EPA did not find information to confirm status of the systems after the referenced date.

b – Veolia offers several different RO technologies, which target different flow rates and influent water quality. 

c – Triwatech did not provide information on the operators that use its RO technology. In 2011, Triwatech LLC was consolidated under the trade name 

Rockwater®.
Section 4 – Produced Water Management and Treatment Technologies

4-16

4.1.5 Other Desalination Technologies

This section provides information on additional technologies, such as distillation and 

electrodialysis, that are capable of removing TDS. With the exception of one distillation 

application, these technologies have not been implemented at CBM operations. 

4.1.5.1 Distillation/Evaporation

Evaporation and distillation technologies separate dissolved salts from wastewater by 

evaporating the water, leaving a concentrated pollutant stream and, in some cases, condensing 

the purified water. These technologies are capable of handling very high influent TDS 

concentrations while creating small volumes of concentrated brine residuals, which require 

disposal. There are many variations of distillation and evaporation technologies, some of which 

require adding heat or mechanical energy to the wastewater to accelerate evaporation, thus using 

more energy. Existing data sources discuss the following types of thermal distillation processes 

used to treat wastewater (ALL, 2006):

• Vapor Compression (VC): Increases the water vapor pressure until it is greater 

than atmospheric pressure by increasing the temperature of the influent 

wastewater.

• Multi-Stage Flash (MSF) and Multi-Effect Distillation (MED): Decreases 

atmospheric pressure and increases water vapor pressure to immediately 

evaporate (“flash”) influent wastewater without heat addition (CSM, 2009).

• Rapid Spray Evaporation (RSE): Increases the rate of evaporation by increasing 

both the surface area of the wastewater and the air movement around the 

wastewater.

• Freeze Thaw Evaporation (FTE): Uses conventional evaporation in combination 

with a cycle of freezing and thawing influent wastewater. These systems are ideal 

for locations with drastic climate changes, where it is most efficient to operate as 

a conventional evaporation system during the warmer months and as a freezethaw evaporation system during the colder months. 

All evaporation/condensation processes result in a concentrated brine stream in addition 

to treated wastewater. Distillation technologies typically have water recovery percentages 

between 60 and 95 percent (CSM, 2009; ALL, 2011). In general, as influent TDS concentrations 

increase, water recovery percentages decrease, resulting in a larger volume of residuals and 

higher disposal costs (URS, 2011). Metcalf and Eddy (2003) suggest that the disposal options for 

concentrated brine generated from thermal distillation units are the same as the disposal options 

for membrane technologies. 

Typical influent TDS concentrations for wastewaters treated with this technology range 

from 60,000 to 80,000 mg/L and effluent concentrations can be less than 10 mg/L (ALL, 2011; 

CSM, 2009). Existing data sources suggest that, unlike other wastewater treatment technologies,

the achievable effluent pollutant concentrations in the treated wastewater are not greatly affected 

by the influent concentrations. 
Section 4 – Produced Water Management and Treatment Technologies

4-17

Distillation is an energy-intensive process. The major energy requirement is for the 

evaporation of the influent wastewater. Produced water at CBM operations is managed at 

ambient temperature. Evaporation costs would vary by climate because colder climates will 

require more energy to evaporate the water. There are minor electricity requirements for running 

low-pressure pumps. 

Table 4-13 summarizes the distillation and evaporation vendors in the oil and gas 

industry identified by EPA. 

Table 4-13. Summary of Known Distillation/Evaporation Vendors in the Oil

and Gas Industry

Vendor Technology Name Status

Source

References

Site 

Visits

Shale Gas 

Vendor 

Calls

Altela AltelaRainSM Deployed at full-scale CBM 

site.

a

X PG

Environmental, 

2007b

212 Resources VACOM MVR System Deployed at shale gas site. X Mertz, 2011

Fountain Quail NOMAD Evaporator Deployed at shale gas sites. X Roman, 2011

INTEVRAS EVRAS Evaporation Deployed at shale gas sites. X Adams, 2011

a – The AltelaRainSM treatment unit was deployed at a full-scale CBM operation, but only treated water from one 

CBM well.

Considerations for using distillation and evaporation technologies include the following 

(URS, 2011): 

• Heat exchange surfaces tend to lose their ability to transfer heat through scaling. 

As the heat exchanger efficiencies decrease, more energy is required to run the 

unit, making the process less cost effective and energy efficient. 

• Pretreatment processes, including media filtration, may need to be added prior to 

thermal distillation unit to remove solids from the influent wastewater stream. 

• The concentrated brine stream generated from distillation and evaporation units 

requires handling and disposal. 

• Distillation and evaporation treatments require a larger capital investment and 

physical footprint than other treatment technologies.

4.1.5.2 Electrodialysis and Electrodialysis Reversal 

Electrodialysis (ED) and electrodialysis reversal (EDR) are separation processes that use 

electric charge and membranes to remove metals and dissolved solids from water. Electrodialysis 

membranes are semi-permeable, meaning they allow ions but not water to pass through. These 

processes are electrically driven and conducted at low pressures; however, they require more 
Section 4 – Produced Water Management and Treatment Technologies

4-18

electricity to operate than most other membrane technologies, which, in comparison, make ED 

and EDR reversal less attractive treatment options (CSM, 2009). 

ED and EDR technologies can treat wastewater with TDS concentrations as high as 

15,000 mg/L and can remove between 50 and 95 percent of salts (ALL, 2011; URS, 2011). ED 

and EDR treatment costs vary depending on the influent wastewater and energy input. Total 

costs are site-specific and depend on the feed water quality. CSM (2009) reports that ED/EDR 

treatment costs increase with increasing influent TDS concentrations (assuming flow stays the 

same). 

EPA did not identify any CBM operators who use ED/EDR technologies.

Advantages of using ED and EDR include the following: 

• Membrane life expectancy is longer for EDR than RO because of the continuous 

polarity reversal and membrane flushing (Asano, 2007). EDR membranes have an 

expected membrane life of eight to 10 years compared to as little as one to two 

years with RO membranes (Hayes, 2004); 

• The reversal and flushing mechanism of EDR needs less maintenance than is 

required with RO (Asano, 2007). 

Considerations for using ED and EDR include the following: 

• Pretreatment is typically required prior to use and may include scaling control 

(i.e., pH adjustment, addition of an antiscalant), filtration to remove suspended 

solids, and disinfection to prevent biofouling (CSM, 2009). 

• Calcium carbonate and magnesium hydroxide may form a scale inside the unit, 

which can decrease efficiency (URS, 2011). 

• High influent wastewater TDS concentrations (>12,000 mg/L) may make ED and 

EDR treatment technologies cost prohibitive (ASIRC, 2005). 

4.1.5.3 Capacitative Deionization 

Capacitative deionization (CDI) is a developing desalination technology that works by 

adsorbing ions onto high-surface, porous electrodes with a low-voltage electric field. Water 

flows between the electrodes and ions in the water attract to the oppositely charged electrode 

(see Figure 4-3). Unlike ion exchange, where regenerating the resin requires using corrosive 

chemicals, electrodes can be cleaned of the ions they have acquired by simply removing the 

electric field (see Figure 4-4) (CSM, 2009). 
Section 4 – Produced Water Management and Treatment Technologies

4-19

Source: CSM, 2009.

Figure 4-3. Schematic of the CDI Treatment Process

Source: CSM, 2009.

Figure 4-4. Schematic of Electrode Regeneration in a CDI Treatment Unit

CDI has been shown to be cost-competitive with RO, at the pilot scale, in drinking water 

applications for feed water with TDS below 3,000 mg/L. However, capital costs for CDI 

modules become comparatively more expensive than RO at higher TDS levels (CSM, 2009). 

EPA has identified one pilot test of CDI for a conventional gas reservoir and another pilot 

test of CDI for a CBM operation in the Green River Basin of Wyoming (CSM, 2009). In these 

tests, CDI was shown to be less susceptible to fouling and scaling than RO. EPA did not identify

any examples of full-scale deployment of CDI for produced water treatment in the existing 

literature or responses to the CBM Detailed Questionnaire.

4.2 ZERO DISCHARGE MANAGEMENT METHODS

This section discusses produced water management methods capable of eliminating direct 

or indirect discharges to surface water by the operator (zero discharge methods). 
Section 4 – Produced Water Management and Treatment Technologies

4-20

4.2.1 Underground Injection

Underground injection involves pumping produced water into a permeable underground 

formation for storage or disposal. The formation must have adequate permeability and porosity 

to accept the wastewater.

EPA regulates underground injection wells under the Safe Drinking Water Act (SDWA), 

Underground Injection Control (UIC) program by setting minimum federal requirements (40 

CFR 144) to protect underground sources of drinking water from contamination. States, 

territories, and tribes have the option of requesting primacy, or primary enforcement authority, 

from EPA for the injection wells located within their boundaries. To receive primacy, the 

requesting authority must set standards at least as stringent as the federal standards. Currently, 

EPA has delegated primacy to 33 states and three territories and it shares responsibility with 

seven states. EPA has complete control over the UIC programs in the remaining 10 states, and on 

Indian lands (U.S. EPA, 2011b). 

EPA groups underground injection wells into six categories (U.S. EPA, 2011a): 

• Class I industrial and municipal waste. 

• Class II oil and gas production waste. 

• Class III solution mining. 

• Class IV hazardous and radioactive waste (since 1984, only used for disposal of 

wastes from EPA- or state-authorized ground water clean-up action). 

• Class V wastes not covered in Class I through IV or Class VI (e.g., leach fields). 

• Class VI geologic sequestration of carbon dioxide. 

Most wells used for disposal of CBM produced water are UIC Class II wells. In some 

circumstances, CBM produced water has been treated first and then injected into UIC wells that 

have been constructed in undisturbed receiving formations, as has been seen in the Wyoming 

portion of the Powder River Basin. In the CBM Extraction Industry, Class I wells accept 

treatment residuals from ion exchange or reverse osmosis (NETL, 2006). 

Table 4-14 summarizes available information on general underground injection practices 

for Class II wells in the major CBM basins. It presents typical depths at which CBM is produced 

and summary information on UIC regulations in each state. Receiving formations for produced 

water must have sufficient separation from production formations. Considerations for 

implementing underground injection for produced water disposal based on the design and cost 

are discussed below. 

Implementing Underground Injection at CBM Operations

Drilling and completing injection wells in suitable formations requires careful planning. 

During site visits to the Powder River Basin, one state official noted that approximately half of 

the wells drilled for injection cannot accept produced water and half of the wells that initially 

accept produced water quickly become unusable due to limited storage capacity in the receiving 

formation. State officials explained that historically, in the Powder River Basin, disposal of 

produced water by injection has been difficult due to the lack of receptive geologic formations 

(PG Environmental, 2007b). EPA also spoke with officials at the Alabama Department of 
Section 4 – Produced Water Management and Treatment Technologies

4-21

Environmental Management, who expressed similar difficulties with using underground injection 

in Alabama basins (e.g., Black Warrior, Cahaba).

Underground injection wells constructed in undisturbed receiving formations are 

generally sensitive to clogging from even small quantities of suspended solids (e.g., coal fines) 

and biofilm resulting from bacterial growth. For this reason, operators usually treat produced 

water prior to reinjection, typically using low-pressure filtration followed in some cases by 

chlorine disinfection. During site visits, EPA observed CBM operators using filter socks, 

filtration canisters, and hydrocyclone separators for low-pressure filtration (ERG, 2007d; ERG, 

2007e; PG Environmental, 2007c; PG Environmental, 2007a). Residual wastes from these units 

are expected to be generated in low volumes and comprise mainly coal fines. In contrast, 

produced water injected into UIC Class II disposal wells constructed in previously mined coal 

seams generally requires no pretreatment, because there is no risk of clogging in the receiving 

formation (ERG, 2007f). 
Section 4 – Produced Water Management and Treatment Technologies

4-22

Table 4-14. Summary of Underground Injection by Basin

Basin State

Depth of 

Production 

Interval 

(Feet Below 

Ground 

Surface)

State Permitting Requirements 

Applicable to Injectiona

Black Warrior 

and Cahaba

Alabama 350 – <4,100 Alabama has UIC implementation authority over Class II. UIC 

Class I wells are prohibited by state regulation.

Powder River Montana and 

Wyoming

200 – <2,500 • Wyoming has UIC implementation authority over Class II 

wells. 

• Montana has UIC implementation authority over Class II 

wells. In addition to federal requirements, Montana 

requires detailed groundwater quality analyses for Class II 

wells.

Greater Green

River

Wyoming Unknown See Powder River summary.

Central 

Appalachian

West Virginia 

and Virginia

1,500 – 2,500 • West Virginia has UIC implementation authority over 

Class II wells.

• EPA has UIC implementation authority over all injection 

wells in Virginia.

Northern 

Appalachian

Pennsylvania 500 – 2,000 EPA has UIC implementation authority over all injection wells 

in Pennsylvania.

Raton Colorado and 

New Mexico

<500 – <4,100 • Colorado has UIC implementation authority over Class II 

wells.

• New Mexico has UIC implementation authority over Class 

II wells. In New Mexico, state permits are not required for 

Class II wells on federal lands, but injection wells must be 

approved by the Bureau of Land Management (BLM).

Illinois Illinois, 

Indiana, and 

Kentucky

<650 – <3,000 Illinois has UIC implementation authority over all injection 

wells. 

San Juan Colorado and 

New Mexico

550 – 6,500 See Raton summary.

Uinta-Piceance Colorado and 

Utah

• CO – See Raton summary.

• Utah has UIC implementation authority over Class II 

injection wells not on Indian lands (EPA has authority for 

wells on Indian lands). Utah’s regulations are similar to 

federal requirements, although Utah allows Class V wells 

to be permitted on an area basis rather than an individual 

basis.

Sources: Detailed Questionnaire responses; ALL, 2003; COGCC, 2009; ERG, 2007d; ERG, 2007e; ERG, 2007f; 

Illinois EPA, 2012; PG Environmental, 2007c; PG Environmental, 2007a; U.S. EPA, 2004; U.S. EPA, 2011a. 

a EPA has authority for wells on Indian lands.

NA – Not applicable.
Section 4 – Produced Water Management and Treatment Technologies

4-23

One of the most important considerations in managing produced water using 

underground injection is transporting the water to the injection site. Whether water is pumped 

through a pipeline or trucked to the injection site, it is typically transferred from the production 

wells into a tank battery or other water storage area prior to long-distance transportation. During 

site visits, operators who trucked water for disposal consistently indicated that trucking costs 

were the largest component of their reinjection costs. In addition to paying the drivers’ fees, in 

some states operators must also post bonds for road maintenance and contribute to road repairs. 

During EPA’s site visits to the Central Appalachian Basin, one operator noted that the number of 

available water trucks in his area was insufficient to support the operation’s need, and explained 

that reinjection was only economically viable after the operation’s water pipeline was 

constructed (PG Environmental, 2007a; ERG, 2007d; ERG, 2007e; ERG, 2007f). 

Table 4-15 lists considerations for using underground injection at CBM operations. 

Table 4-15. Considerations for Using Underground Injection at CBM Operations

Consideration Use

Considerations for Use at 

Existing CBM Operations

• UIC wells require nearby receiving reservoirs with:

- Sufficient permeability and porosity.

- Sufficient storage capacity for the produced water volume.

- Low reservoir pressure.

- Separation from sources of drinking water and the CBM production 

formation.

- Similar water quality as the produced water.

• High non-water quality and cost impacts may occur if trucking is required to 

transport the water to the UIC well.

• Produced water may require pretreatment (e.g., filtration, disinfection) to control 

clogging or microbial scaling in the geologic formation in which the produced 

water is injected.

Available in All Basins? Although all basins have UIC wells, Alabama and Pennsylvania have limited UIC 

wells and would likely need to truck produced water to another state (ERG, 2012).

Currently In Use at CBM 

Operations?

Yes, in western U.S and West Virginia.

Underground Injection Cost Components

Table 4-16 lists the capital and O&M costs components for underground injection. 

Transportation may be a significant portion of the costs. Section 5 provides information on the 

underground injection costs used in EPA’s initial engineering cost analysis. 
Section 4 – Produced Water Management and Treatment Technologies

4-24

Table 4-16. Capital and O&M Costs for Underground Injection 

Cost Use

Capital Cost Components • The site footprint and therefore, the need for acquiring land, will depend on water 

storage requirements and the injection site. The injection well may not be located 

near the CBM operations.

• Costs vary based on depth and local geology. This management method may 

require road and site construction if the injection site is not located near the 

production wells.

• The operator may also need:

- Pretreatment equipment (e.g., filter socks, chlorine injection).

- Piping infrastructure to transport water to and from the injection site. Some 

sites may transport all water via truck. Sites collecting produced water via haul 

trucks may require more storage than sites receiving water from collection 

piping.

- Pumps.

- Monitoring equipment (e.g., pressure transducers, sampling ports).

• Underground injection requires additional power. If the CBM project does not 

currently have electricity, operators will need to bring infrastructure or generators 

on site.

O&M Cost Components • Operators may use chemicals (e.g., chlorine disinfectant) or filters prior to 

injection.

• If operators select using a truck to haul water to the injection site, they may be 

subject to state law to contribute to road maintenance activities (ERG, 2007e).

• Transportation is a significant component of the costs; therefore, underground 

injection will be expensive in areas without available UIC wells nearby.

• If CBM operators use third parties to inject produced water, they will typically 

pay for disposal based on the produced water volume.a

Other Costs • Injection wells also require permits prior to installing and operating the well.

• Operators must also obtain financial assurance/bonding for road maintenance 

(where applicable) and injection site closure.

Residuals Generated If filtration is required, operators will generate low quantities of coal fines.

Energy Requirements Depending on the pressure of the receiving formation, operators may inject water with 

or without using high-pressure, multi-pump systems.

Personnel Requirements • Underground injection requires personnel to monitor and control injection 

pressure, perform well maintenance activities and periodic inspections, and 

replace filter elements and disinfectant (PG Environmental, 2007a).

• Regulatory agencies typically require quarterly monitoring of produced water.

a – Based on information gathered during EPA’s site visits, CBM operators more commonly own and operate their

own injection wells (ERG, 2007d; ERG, 2007e; ERG, 2007f; PG Environmental, 2007c; PG Environmental, 2007a).

4.2.2 Evaporation/Infiltration Ponds

Evaporation and infiltration ponds are constructed impoundments designed to collect and 

store produced water until it evaporates and/or infiltrates into the water table (ALL, 2003). 

Unlike the settling ponds discussed in Section 4.1.1, evaporation and infiltration ponds do not 

discharge to surface waters, and are therefore considered zero discharge practices. Evaporation 

and infiltration ponds are primarily found in the western U.S. CBM basins, but were also 

reported for projects in the Appalachian basin in the Screener (see Table 3-5). The use of 
Section 4 – Produced Water Management and Treatment Technologies

4-25

evaporation and infiltration ponds in Wyoming is permitted through the Wyoming Department of 

Environmental Quality (WYDEQ). WYDEQ permits evaporation and infiltration ponds via 

WYPDES permits that allow discharge to on-channel reservoirs, which are ponds designed for 

full containment (i.e., evaporation/infiltration ponds) (ERG, 2012). 

Seasonal variations like temperature, wind, and humidity are large factors in the 

efficiency of evaporation or infiltration ponds. Other factors that affect the efficiency of 

evaporation or infiltration ponds include: 

• Landscape, topography, and local water table considerations. 

• Runoff accumulation and associated pond flooding. 

• Vegetation (ALL, 2003).

Implementing Evaporation/Infiltration Ponds at CBM Operations

Table 4-17 lists considerations for using evaporation/infiltration ponds at CBM 

operations. 

Table 4-17. Considerations for Using Evaporation/Infiltration Ponds at CBM Operations

Consideration Use

Considerations for Use at 

Existing CBM Operations 

• Ponds may require large footprint to handle maximum produced water flow.

• The ponds may potentially attract wildlife. Operators may consider covering 

ponds. 

• Pond leakage and saline seepage into the soil may cause environmental harm 

(e.g., contamination of shallow aquifers). 

• There is potential for adverse human health effects (e.g., mosquito breeding 

ground). 

• Water may infiltrate into the water table; therefore, ponds may not be suitable 

for more saline (i.e., high salt) produced water (CSM, 2009; ALL, 2003).

Available in All Basins? No, the technology requires climate suitable for evaporation and soil type suitable 

for infiltration.

Currently In Use at CBM 

Operations?

Yes, in the Appalachian Basin and western United States.

Cost Components

Table 4-18 lists the capital and O&M costs components for evaporation/infiltration 

ponds. 
Section 4 – Produced Water Management and Treatment Technologies

4-26

Table 4-18. Capital and O&M Costs for Evaporation/ Infiltration Ponds

Cost Use

Capital Cost Components • Land acquisition or leasing is required for the pond footprint if the operator does 

not own the land adjacent to the wells. The pond footprint is often large to 

contain the required volume. The availability of additional land owned by the 

operator for a pond will be site-specific.

• Operators constructing new ponds on undisturbed land will incur costs for 

excavation and mobilization.

• Operators may also need:

- Piping infrastructure to transport the water from the wellhead(s) to the pond.

- Pumps to transport the water, if gravity flow is not possible.

- Monitoring equipment, if needed (e.g., groundwater monitoring).

- Aerators to enhance evaporation.

• Evaporation/infiltration ponds may require additional power. If the CBM project 

does not currently have electricity, operators will need to bring infrastructure or 

generators on site if pumps or aerators are needed. 

• Operators also incur costs for pond closure at end of life.

O&M Cost Components The solids at the bottom of the pond may have to be periodically dredged.

Other Cost Components Ponds require permits to operate.

Residuals Generated Settled solids – Solids may or may not need to be removed from the pond. During 

site visits, CBM operators indicated that ponds may require limited or no removal 

of solids, depending on the geometry and removal efficiency of the ponds (ERG, 

2007a).

Energy Requirements Electricity for any pumps may be required.

Personnel Requirements Labor may be required to periodically remove solids from bottom of pond.

4.2.3 Land Application

Managing produced water by land application consists of spreading produced water 

directly on the land or through subsurface irrigation, with or without crop production. Optimal 

land application requires adding produced water at a rate equal to the soil's capacity to accept 

both the volume of and the constituents in produced water without destroying soil integrity, 

creating subsurface soil contamination problems, or causing other adverse environmental 

impacts, which may include water ponding and subsequent runoff. Using land application as a 

disposal method will depend on produced water quality, local land use, water needs, plant status, 

and permitting requirements. For example, in the Powder River Basin, water is a limited resource 

and produced water is being used for crop irrigation. 

As of 2008, CBM operators used land application for the following: 

• Crop production/irrigation. 

• Dust suppression (benefits also include preventing air quality issues and loss of 

surface soils. 

• Disposal without beneficial use (without crop production or dust suppression).
Section 4 – Produced Water Management and Treatment Technologies

4-27

In some cases, CBM operators may land apply produced water without crop production. 

In 2007, EPA visited CDX’s West Virginia operations and observed land application of 

produced water without crop production. CDX’s land application permit specifies the allowable 

chloride and TDS concentrations. Operators must inject produced water underground if it does 

not meet these concentration levels. The produced water flows across a gravel apron to help

disperse the water prior to land application. The water then flows downward through a set of logs 

and hay bales that act as a weir to control water flow. CDX operations are located on the top of a 

mountain making other management methods for produced water impractical (ERG, 2007c).

Implementing Land Application at CBM Operations

Table 4-19 lists considerations for using land application at CBM operations. 

Table 4-19. Considerations for Using Land Application at CBM Operations 

Consideration Use

Considerations for Use at 

Existing CBM Operations

• Land application may not be feasible in areas that have low infiltration rates, 

which may be caused by one or more of the following:

- High clay content in the soil. 

- Wet, supersaturated soil conditions. 

- Frozen soil conditions.

• Produced water with high SAR or TDS concentrations can alter soil properties, 

reducing water infiltration, and/or limiting plant growth.

• Land application may be inconsistent with permitting requirements, including 

water quality based effluent limits.

Available in All Basins? No; see considerations listed above.

Currently In Use at CBM 

Operations?

Yes, in the Appalachian and Powder River Basins. Operators in the Powder River 

Basin use various irrigation systems for land application.

Land Application Cost Components

Table 4-20 lists the capital and O&M costs components for land application. 

Table 4-20. Capital and O&M Costs for Land Application 

Cost Use

Capital Cost Components Operations may potentially incur the following capital costs:

• Land application equipment (e.g., sprayers). 

• Storage tanks to contain water prior to land application. 

• Pumps and piping to transport water to the land application site. 

• Monitoring equipment, if needed (e.g., groundwater monitoring). 

• Electrical installation (if pumps are used to transport water).

O&M Cost Components • Land application may require soil amendments and sampling and analysis of 

the water and soil at the land application site to prevent damage and sustain the 

land application, depending on the type of land application and the related costs 

for operating land equipment (energy, labor).

• Costs will be incurred to transport produced water by pumps and pipeline or by 

trucking to land application site.
Section 4 – Produced Water Management and Treatment Technologies

4-28

Table 4-20. Capital and O&M Costs for Land Application 

Cost Use

Residuals Generated No residuals are generated.

Energy Requirements Electricity may be required for pumps or land application equipment.

Personnel Requirements Operators require personnel for periodically monitoring the system.

4.2.4 Livestock or Wildlife Watering

In areas of livestock grazing, CBM operators can coordinate with local land owners to 

transfer produced water to ranching areas for livestock watering if the produced water is of good 

enough quality. CBM projects on ranch land have created impoundments or watering stations 

(e.g., tire tanks) for livestock. 

Implementing Livestock Watering at CBM Operations

Table 4-21 lists considerations for using livestock watering as a method of disposing 

produced water. 

Table 4-21. Considerations for Using Livestock Watering at CBM Operations 

Consideration Use

Considerations for Use at 

Existing CBM Operations

• It is applicable only in areas with nearby livestock or wildlife.

• It may not have sufficient livestock for all produced water; therefore, other 

management methods may still be required.

• Use for livestock may be inconsistent with permitting requirements, including 

water quality based effluent limits.

Available in All Basins? No; see limitations listed above.

Currently In Use at CBM 

Operations?

Yes, livestock watering is used in the Powder River Basin.

Livestock Watering Cost Components

Table 4-22 lists the capital and O&M costs components for livestock watering. 

Table 4-22. Capital and O&M Costs for Livestock Watering

Cost Use

Capital Cost Components • Operators may need: 

- Storage containers (e.g., troughs, tire tanks, impoundments) to hold water for 

livestock to drink from and to store excess water prior to livestock watering. 

- Pumps and piping to transport water to the livestock watering site. 

• Livestock may require additional power to pump water to the livestock watering 

site. If the CBM project does not currently have electricity, operators will need 

to bring infrastructure or generators on site.
Section 4 – Produced Water Management and Treatment Technologies

4-29

Table 4-22. Capital and O&M Costs for Livestock Watering

Cost Use

O&M Cost Components • The water may require minimal pretreatment or periodic testing to ensure the 

water quality is suitable for livestock watering. 

• Costs will be incurred to transport produced water by pumps and pipeline or 

trucking to livestock watering site.

Residuals Generated No residuals are generated.

Energy Requirements Pumps will require electricity.

Personnel Requirements Operators need personnel to periodically monitor the system.

4.2.5 Downhole Gas Water Separators

Downhole gas water separation (DGWS) technologies separate methane from formation 

water prior to extracting the gas to the surface. Instead of pumping the formation water to the 

surface, operators inject it into other porous formations either above or below the producing coal 

seam, thus reducing produced water volumes (NETL, 2011b).

EPA did not observe DGWS during the site visit program and operators did not indicate 

using DGWS in 2008 in their Detailed Questionnaire responses. EPA reviewed information on 

DGWS from the DOE’s NETL and a vendor indicating DGWS has been implemented at wells in 

the Powder River Basin. 

Table 4-23 shows four different types of DGWS technologies identified by U.S. DOE 

NETL. These technologies can be installed at the bottom of the gas well based on the produced 

water flowrate and the well depth. Table 4-23 also shows the applicable range of produced water 

flowrates and appropriate well depths for using each DGWS technology (NETL, 2011b).

Table 4-23. DGWS Technologies Design Criteria

DGWS Technology

Produced Water Flow Rate

(Barrels Per Day)

Well Depth

(Feet)

Bypass Tools 25 – 250 6,000 – 8,000

Modified Plunger Rod Pumps 250 – 800 2,000 – 8,000

Electric Submersible Pumps >800 >6,000

Progressive Cavity Pumps NA NA

Source: NETL, 2011b. 

According to a NETL fact sheet, implementing any of these separation devices requires a 

receiving formation with good injectivity10. For CBM applications, there should be good 

separation between the production and receiving formations to ensure that the producing 

formation is depressurized to allow the gas to flow (NETL, 2011b).

 

10 Injectivity is a measurement of the rate and pressure at which fluids can be pumped into a receiving formation 

without fracturing the formation (Schlumberger, 2011).
Section 4 – Produced Water Management and Treatment Technologies

4-30

EPA has identified only one vendor, Big Cat Energy Corp. (Big Cat), providing DGWS 

to the CBM Extraction Industry. Big Cat’s ARIDTM tool has been used only in the Wyoming 

portion of the Powder River Basin, although Big Cat believes their tool would work in other 

areas such as Montana and Alabama. Approximately 12 CBM wells in Wyoming have used the 

ARID system. Big Cat developed the ARID aquifer recharge injection system to reduce the 

volume of produced water requiring disposal. The ARID system uses the existing well bore to 

move the formation water from the producing coal seam to a shallower depleted aquifer with 

water quality similar to the coalbed formation water.

Big Cat has installed the ARID technology on new wells and retrofitted it on existing 

wells. New installations are easier, because the well can be planned in a way that easily 

incorporates the ARID technology. Big Cat estimated that this technology has allowed operators 

to reinject all of the produced water in at least 80 percent of the wells where the technology was 

installed. In one case, limitations of the receiving formation required that some of the produced 

water be pumped to the surface. In other cases, CBM producers have chosen to pump some of 

the water to the surface to meet a surface water need (e.g., livestock watering for a landowner).

Implementing DGWS at CBM Operations

According to Big Cat, the only major logistical issue has been the failure of tool seals 

during installation, which was apparently caused by sharp edges inside the production casing. To 

mitigate this issue, Big Cat instructs operators to run a “scraper” from the interval where the tool 

will be installed to the surface to smooth the inside of the production casing and prevent 

damaging the seal. Big Cat offers seals in a variety of hardness to suit the conditions of the 

production casing. Big Cat recommends that operators replace seals each time they remove the 

tool, for which the operator pays Big Cat. Operators incur additional required operating costs for 

wells that use the ARID tool to periodically monitor the reinjected water and remove the tool 

during well maintenance activities (e.g., workovers).

Clogging of the receiving formation may be an issue if solid particles from the production 

formation or from drilling activities enter the receiving formation. Bacteria that form scale on the 

receiving formation are another source of clogging. To prevent scale formation, Big Cat typically 

tests produced water for scale-forming bacteria prior to tool installation and uses a chlorine drip 

disinfection system as necessary during the initial implementation of the tool (Barritt, 2012). 

The underground injection information previously presented in Section 4.2.1 is also 

relevant to the technical feasibility of DGWS for CBM. As noted above, the success rate of 

DGWS depends on “site-specific properties of the disposal zone at individual wells” (Veil, 

2004). In addition, Big Cat noted that the feasibility of DGWS can only be firmly established by 

a successful pilot study in the basin of interest (Barritt, 2012). 

Table 4-24 lists considerations for using DGWS at CBM operations. 
Section 4 – Produced Water Management and Treatment Technologies

4-31

Table 4-24. Considerations for Using DGWS at CBM Operations 

Consideration Use

Considerations for Use at 

Existing CBM Operations

• DGWS requires suitable geologic formation with sufficient injectivity, storage 

capacity, water quality, and separation from CBM production formations.

Feasibility should be established by a pilot study in the basin of interest.

• Water quality of produced water quality may need to be similar to the water 

quality in the receiving formation.

• The technology requires coordination with local UIC programs. For example, 

one operator noted that UIC programs may require operators to monitor the 

water injected. However, no water is produced to the surface when using 

DGWS. Therefore, if water monitoring is required, operators would need to 

shut in the well periodically to either remove the DGWS tool or install a 

mechanism to bypass the tool so that water could be brought to the surface and 

monitored (Olson, 2012).

• Landowners may want some produced water for land application or livestock 

watering.

• The tool can be installed at the time well is drilled and could handle the 

changes in volume over the life of the well.

Available in All Basins? Unknown; see limitations listed above.

Currently In Use at CBM 

Operations?

Yes, this technology is in use in the Powder River Basin.

DWGS Cost Components

Table 4-25 shows operating capital and O&M costs for DGWS based on information 

collected on the tools used in the Powder River Basin. 

Table 4-25. Capital and O&M Costs for DGWS 

Cost Use

Capital Cost Components • The operator must prepare the well casing prior to installing the ARID tool.

• DGWS ARID tool 

O&M Cost Components • Big Cat recommends replacing the rubber seal on the ARID tool each time it 

is removed (Barritt, 2012).

• The Wyoming Department of Environmental Quality initially required 

quarterly testing of produced water, but they have become more flexible due 

to the logistical issues with collecting samples.

Residuals Generated No residuals are generated.

Energy Requirements The tool may reduce energy requirements at the wellhead because produced water 

does not need to be pumped to the surface.

Personnel Requirements • Operators require personnel to monitor the pressure of the injection 

formation.

• In general, operators need to remove the ARID tool for any downhole well 

maintenance activities (e.g., workovers). Removing and replacing the ARID 

tool results in additional man-hour needs in the field.
Section 4 – Produced Water Management and Treatment Technologies

4-32

4.3 REFERENCES

1. Adams, A. 2011. Telephone Communication Between Andy Adams, Intevras & Layne 

Water Technologies, and Brent Ruminski, Eastern Research Group, Inc. “Intevras 

EVRAS Evaporation Technology.” November. EPA-HQ-OW-2010-0824, DCN 

CBM00671. 

2. Alexander, J. 2011. Telephone Communication Between Jerry Alexander, Siemens and 

Sarah Hays, Eastern Research Group, Inc. “Siemens Reverse Osmosis Technology.” 

September. EPA-HQ-OW-2010-0824, DCN CBM00672. 

3. ALL. 2003. Handbook on Coal Bed Methane Produced Water: Management and 

Beneficial Use Alternatives. Prepared for Ground Water Protection Research. Available 

online at: http://www.all-llc.com/CBM/pdf/CBMBU/CBM%20BU%20Screen.pdf. EPAHQ-OW-2004-0032-2483 (DCN 03451). 

4. ALL. 2006. A Guide to Practical Management of Produced Water from Onshore Oil and 

Gas Operations in the United States. Prepared for U.S. DOE, National Petroleum 

Technology Office. EPA-HQ-OW-2008-0517 (DCN 10000). 

5. ALL. 2011. Shale Gas Produced Water Treatment Catalog. Available online at: 

http://www.all-llc.com/projects/produced_water_tool/page.php?14. 

6. Asano, T. 2007. Water Reuse: An Integrated Approach to Managing the World’s Water 

Resources. McGraw-Hill.

7. ASIRC (Australian Sustainable Industry Research Centre). 2005. Overview of Treatment 

Processes for the Production of Fit for Purpose Water: Desalination and Membrane 

Technologies. Available online at: 

http://www.water.vic.gov.au/__data/assets/pdf_file/0003/5853/Overview_Treatment_Pro

cess_Water_Desalination.pdf. 

8. Barritt, T. 2012. Telephone Communication Between Tim Barritt, Big Cat Energy Corp., 

and Chris Krejci, Eastern Research Group, Inc. “ARID Produced Water Reinjection 

Technology.” January. EPA-HQ-OW-2010-0824, DCN CBM00585. 

9. Beagle, D. 2007. Continuous Countercurrent Ion Exchange Applied to CBM Produced 

Water Treatment in the Powder River Basin of Wyoming and Montana. EPA-HQ-OW2006-0771-0882 (DCN 05158). 

10. Burnett, D. 2006. Advanced Membrane Filtration Technology for Cost Effective 

Recovery of Fresh Water from Oil & Gas Produced Brine. Texas A&M University. EPAHQ-OW-2010-0824, DCN CBM00773. 

11. CMAA (Coalbed Methane Association of Alabama). 2012. Comments on 2010 Effluent 

Guidelines Program Plan. February. EPA-HQ-OW-2008-0517-0853. 

12. COGCC (Colorado Oil and Gas Conservation Commission). 2009. Staff Presentation: 

Coal Bed Methane Production, Raton Basin. EPA-HQ-OW-2010-0824, DCN 

CBM00607. 
Section 4 – Produced Water Management and Treatment Technologies

4-33

13. CDM. 2007. Innovative Produced Water Treatment Process For Coal Bed Methane 

Production. Prepared by Bob Kimball and Ken Klinko. November 7. EPA-HQ-OW2006-0771-0874 (DCN 05149). 

14. CSM (Colorado School of Mines). 2009. An Integrated Framework for Treatment and 

Management of Produced Water: Technical Assessment of Produced Water Treatment 

Technologies. 1st Edition. RPSEA Project 07122-12. EPA-HQ-OW-2008-0517 (DCN 

10007). 

15. Dennis, R. 2005. A Positive Trade-Off. Environmental Protection. July. Available online 

at: http://eponline.com/articles/2005/07/01/a-positive-tradeoff.aspx?admgarea=Features. 

EPA-HQ-OW-2004-0032-0332 (DCN 02226). 

16. Dow Chemical. 2011. Basics of Reverse Osmossis. 

http://www.dowwaterandprocess.com/support_training/literature_manuals/lm_techinfo/b

asics.htm. 

17. Drake, R. 2011. Telephone Communication Between Brent Ruminski, ERG, and Ron 

Drake, Drake Water Technologies. "Drake Water Technologies: IonFlo (Ion Exchange)." 

September. EPA-HQ-OW-2010-0824, DCN CBM00673. 

18. Drake, V. 2012. Email Communication Between Brent Ruminski, ERG, and Vivian 

Drake, Drake Water Technologies. “Drake Process Unit Installation Locations”. January. 

EPA-HQ-OW-2010-0824, DCN CBM00629. 

19. Eckenfelder, W.W. 2000. Industrial Water Pollution Control. 3rd Edition. McGraw-Hill.

20. Eco-Tec. 2006. Short Bed Ion Exchange Technology Produces Ultrapure Water Without 

Using a Mixed Bed. EPA-HQ-OW-2006-0771-1342 (DCN 06160). 

21. Eco-Tec. 2007. Size Does Matter: Evolution of Counter-Current Ion Exchange for 

Industrial Water Treatment. EPA-HQ-OW-2006-0771-1341 (DCN 06159). 

22. Eco-Tec. 2008. Eco-Tec Awarded CBNG Produced Water Treatment System Contract. 

Available online at: http://www.wateronline.com/doc.mvc/Eco-Tec-Awarded-WaterTreatment-Contract-0001. 

23. ERG (Eastern Research Group). 2007a. Site Visit Report for the Howard Treatment 

Facility, Enervest Operating, LLC, Blairsville, PA. EPA-HQ-OW-2006-0771-0996. 

(DCN 05198). 

24. ERG. 2007b. Final Site Visit Report for the Brinkerton Treatment Facility, Great Lakes 

Energy Partners, LLC Mount Pleasant Township, PA. EPA-HQ-OW-2006-0771-0969. 

(DCN 05199). 

25. ERG. 2007c. Final Site Visit Report, Drake Water Technologies, LLC, Gillette, WY 

(Powder River Basin). EPA-HQ-OW-2008-0517-0685. (DCN 10032). 

26. ERG. 2007d. Final Site Visit Report: Penn Virginia Corporation, Central Appalachian 

Basin Coalbed Methane Operations. EPA-HQ-OW-2006-0771-0966. (DCN 05232). 

27. ERG. 2007e. Final Site Visit Report: CNX Gas Company LLC, Upper Appalachian 

Basin Coalbed Methane Operations. EPA-HQ-OW-2006-0771-1047. (DCN 05235). 
Section 4 – Produced Water Management and Treatment Technologies

4-34

28. ERG. 2007f. Final Site Visit Report: CNX Gas Company, LLC, Central Appalachian 

Basin Coalbed Methane Operations. EPA-HQ-OW-2006-0771-0967. (DCN 05233). 

29. ERG. 2012. Coalbed Methane State Phone Calls. Various Dates and Contacts. EPA-HQOW-2010-0824. DCN CBM00678. 

30. Hayes, T. 2004. The Electrodialysis Alternative for Produced Water Management. 

Prepared by Gas Technology Institute. Available online at: 

http://www.netl.doe.gov/technologies/oil-gas/publications/GasTIPS/GasTIPSSummer04.pdf. 

31. Illinois EPA (Environmental Protection Agency). 2012. Underground Injection Control 

Program. Available online at: http://www.epa.state.il.us/land/regulatoryprograms/underground-injection-control.html. Accessed: March 6, 2012. 

32. Jangbarwala. 2008. Custom-Designed Process Treats CBM Produced Water. EPA-HQOW-2006-0771-1338 (DCN 06156). 

33. Johnston. 2010. Summary of EMIT Water Discharge Technology (an Exterran Company) 

held on February 18, 2010. July 27, 2010. EPA-HQ-OW-2008-0517 (DCN 10020). 

34. Kimball, B. 2010. High Recovery Reverse Osmosis for Treatment of Produced Water. 

Camp Dresser & McKee, Inc. Helena, Montana. 71st International Water Conference. 

IWC-10-54. EPA-HQ-OW-2010-0824, DCN CBM00618. 

35. Malecha, S. 2006. Final Report: Coal Bed Methane Produced Water Treatment: Wallace 

Gulch Reverse Osmosis Test. August 4. EPA-HQ-OW-2004-0032-1452 (DCN 02840). 

36. Means, B., and T. Hilton. 2004. Comparison of Three Methods to Measure Acidity of 

Coal-Mine Drainage. 2004. National Meeting of the American Society of Mining and 

Reclamation. EPA-HQ-OW-2006-0771-0142 (DCN 04358). 

37. Mertz, B. 2011. Telephone Communication Between Barry Mertz, 212 Resources 

VACOM Technology, and Brent Ruminski, Eastern Research Group, Inc. “212 

Resources VACOM Technology.” November. 

38. Metcalf and Eddy, Inc. 2003. Wastewater Engineering: Treatment, Disposal, and Reuse. 

McGraw-Hill, Inc. 4th edition. 

39. Migliavacca. 2011. Telephone Communication Between Michele Migliavacca, Veolia 

Water, and Brent Ruminski, Eastern Research Group, Inc. “Veolia Water OPUS and 

MULTIFLO.” November. EPA-HQ-OW-2010-0824, DCN CBM00674. 

40. NETL (National Energy Technology Laboratory). 2006. A Guide to Practical 

Management of Produced Water from Onshore Oil and Gas Operations in the United 

States. Prepared by Interstate Oil and Gas Compact Commission and ALL Consulting. 

Prepared for U.S. DOE NETL. EPA-HQ-OW-2010-0824, DCN CBM00771. 

41. NETL. 2011a. Produced Water Management Technology Descriptions: Fact Sheet – Ion 

Exchange. Available online at: 

http://www.netl.doe.gov/technologies/pwmis/techdesc/ionex/index.html. 
Section 4 – Produced Water Management and Treatment Technologies

4-35

42. NETL. 2011b. Produced Water Management Technology Descriptions: Fact Sheet – 

Downhole Separation. Available online at: 

http://www.netl.doe.gov/technologies/pwmis/techdesc/downsep/index.html. 

43. Olson. 2012. Email from Joe Olson, Williams Production Company to Ahmar Siddiqui, 

U.S. EPA. “Downhole Separation Use with Coalbed Methane Wells.” February 20. 

44. PG Environmental. 2007a. Final Site Visit Report: Anadarko Petroleum Corporation 

Johnson County, WY (Powder River Basin), Coalbed Methane Detailed Study. EPA-HQOW-2006-0771-1002 (DCN 05239). 

45. PG Environmental. 2007b. Final Site Visit Report: St. Mary Land & Exploration 

Company (Formerly Nance Petroleum Corporation) River 1 Project, Sheridan and 

Campbell Counties, WY (Powder River Basin), Coalbed Methane Detailed Study. EPAHQ-OW-2006-0771-0970 (DCN 05236). 

46. PG Environmental. 2007c. Final Site Visit Report: Altela, Inc. Thermal Distillation 

Produced Water Treatment Technology (AltelaRainSM) at the Blackshawl and Moncisco 

Sites Farmington, NM (San Juan Basin), Coalbed Methane Detailed Study. EPA-HQOW-2006-0771-1012 (DCN 05225). 

47. Roman, J. 2011. Telephone Communication Between Jaime Roman, Fountain Quail, and 

Brent Ruminski, Eastern Research Group, Inc. “Fountain Quail NOMAD Evaporator 

Technology.” November.

48. Schlumberger. 2011. Oilfield Glossary – Injectivity Test. Available online at: 

http://www.glossary.oilfield.slb.com/Display.cfm?Term=injectivity%20test. 

49. URS. 2011. Water-Related Issues Associated With Gas Production in the Marcellus 

Shale. Prepared in Support of the Supplemental Generic Environmental Impact Statement 

for Natural Gas Production. Fort Washington, PA. EPA-HQ-OW-2010-0824, DCN 

CBM00772. 

50. U.S. EPA (Environmental Protection Agency). 2000. Wastewater Technology Fact Sheet: 

Chemical Precipitation. EPA-832-F-00-018. 

51. U.S. EPA. 2004. Evaluation of Impacts to Underground Sources of Drinking Water by 

Hydraulic Fracturing of Coalbed Methane Reservoirs. National Study Final Report.

52. U.S. EPA. 2011a. Underground Injection Control Program. Available online at: 

http://water.epa.gov/type/groundwater/uic/index.cfm. 

53. U.S. EPA. 2011b. Aquifer Recharge (AR) and Aquifer Storage & Recovery (ASR). 

Underground Injection Control Program. Available online at: 

http://water.epa.gov/type/groundwater/uic/aquiferrecharge.cfm. 

54. U.S. EPA. 2013. Ion Exchange Vendors in CBM Industry. EPA-HQ-OW-2010-0824, 

DCN CBM00667. 

55. Veil, J.A. 2004. Downhole Separation Technology Performance: Relationship to 

Geologic Conditions. Prepared by Argonne National Laboratory. Prepared for U.S. DOE 

NETL. Available online at: http://www.netl.doe.gov/KMD/cds/disk23/D-
Section 4 – Produced Water Management and Treatment Technologies

4-36

Water%20Management%20Projects/Produced%20Water%5CW-31-109-ENG-38%5CW31-109-Eng-38-DOWS-DGWS-final.pdf. 

56. Veolia Water Solutions. 2008. CeraMem®Ceramic Membrane Technology. Industrial 

Water World Magazine. EPA-HQ-OW-2006-0771-1337 (DCN 06155). 
Section 5 – Produced Water Management Costs

5-1 

SECTION 5

PRODUCED WATER MANAGEMENT COSTS 

In establishing ELGs, EPA identifies a subset of technologies (treatment processes and 

operational/management practices) that are most promising as candidate regulatory options. 

ELGs typically establish numerical limits on the discharge of pollutants to surface waters; EPA 

also establishes technonoloy-based pretreatment standards for dischargers to Publicly Owned 

Treatment Works. These limits and standards are based on the performance of specific 

technologies that constitute the regulatory options. EPA does not require that dischargers use the 

specific technologies that form the basis for the proposed regulatory options. EPA does, 

however, estimate the compliance costs for the industry to meet the numerical limitations and 

standards, including any identified best management practices (BMPs). EPA estimates the 

compliance costs by calculating the costs for operators to implement the technologies that form 

the basis of the proposed regulatory options. For existing sources, compliance costs are 

incremental, meaning they represent the costs operators are expected to incur to revise existing 

operations to match those that form the bases of the regulatory options. For new sources, EPA 

estimates the costs to install such technologies rather than in the technologies that would be 

installed the absence of the rule.

For the CBM Extraction Industry, EPA estimated the costs of implementing certain 

wastewater pollution controls at existing wells. Based on the review of available treatment 

technologies for the industry described in Section 4, EPA included two CBM control 

technologies in this preliminary cost evaluation: ion exchange and underground injection. EPA 

evaluated ion exchange because it is the lowest-cost technology capable of removing TDS from 

produced water. Although ion exchange may not be applicable to all basins, EPA used ion 

exchange costs to provide an initial likely low cost indicator of the economic feasibility of 

implementing a TDS removal technology. As explained in Section 4, other technologies 

identified to remove TDS from produced waters would have higher costs. EPA also evaluated

underground injection because it eliminates all pollutant discharges to surface water and POTWs 

and is currently being used for produced water disposal in all basins except for the Black Warrior 

and Cahaba Basins.

Only projects that discharge some portion of their produced water would possibly incur 

costs under any ELGs. Based on questionnaire/screener responses, EPA estimates that 149 CBM 

projects discharged directly to waters of the U.S. and that 7 projects discharged indirectly in 

200811. Because the number of indirect dischargers is small, for purposes of this analysis, EPA 

developed costs only for those projects that reported discharging any portion of produced water 

directly to surface water in 2008. EPA used the 2008 project-level data for the discharging 

projects along with costs for the two included CBM control technologies to evaluate the potential 

economic impacts associated with an ELG for the industry. The Economic Analysis for Existing 

and New Projects in the Coalbed Methane Industry document presents the results of EPA’s 

economic analysis (U.S. EPA, 2013a). This section describes EPA’s methodology for estimating 

compliance costs for the included technology options. Because most respondents claimed their 

entire response to the Detailed Questionnaire to be CBI, EPA is not providing project-level or 

 

11 EPA calculated the number of projects for the entire CBM industry using the Detailed Questionnaire responses 

and survey weights.
Section 5 – Produced Water Management Costs

5-2 

basin-level computed costs. The following references contain supporting information for the 

analysis described in this section: 

• Summary of Coalbed Methane Information Collection Request Confidential 

Business Information (U.S. EPA, 2013b). 

• Supporting Information for CBM Existing Sources Analysis (U.S. EPA, 2013d).

This section describes the development of the cost estimates using Detailed 

Questionnaire data, which are used in the economic analysis. EPA used the following steps for 

this analysis: 

1. Identify CBM projects that discharged produced water in 2008 (Section 5.1).

2. Develop costs for ion exchange treatment systems to treat produced water prior 

to surface discharge or underground injection as an alternative disposal method 

to surface discharge (Section 5.2). 

3. Calculate the project-level costs associated with ion exchange and underground 

injection (Section 5.3). 

4. Combine the ion exchange and underground injection cost information with 

project-level economic and financial data, gas and water decline rates, and 

projected gas prices to develop an economic assessment of the additional controls. 

(See Economic Analysis for Existing and New Projects in the Coalbed Methane 

Industry). 

5.1 IDENTIFY DISCHARGING PROJECTS AND DISCHARGE VOLUME

Of the 14912 direct discharging projects in the industry, EPA estimated project specific 

engineering costs associated with 74 direct discharging CBM projects. EPA used data from the 

Screener survey responses to identify the total population of direct discharging projects and used 

information from the Detailed Questionnaire responses for the 74 projects to determine the final 

disposal method and the produced water volume disposed of through each method (Questions 

C3-1 and C3-2). EPA scaled the costs estimated for the 74 analyzed projects to the total industry 

population of 149 direct discharging projects using survey weights. The memorandum 

Development of Final Survey Weights for CBM Analyses (DCN CBM00653) provides a detailed 

description of how survey weights were developed (U.S. EPA, 2012). 

For the 74 analyzed projects, operators reported discharging some portion of their 

produced water directly to surface water in 2008; but for 37 of these projects, operators reported 

using at least one other disposal method. 

EPA excluded one of the 74 direct discharging projects from this analysis because the

first (undeveloped) lease in the project was acquired in 2008 as reported in the Detailed 

Questionnaire (Question B3-15). This project was in the first year of production where peak 

water is produced but peak gas flows have not yet been reached. As shown in Figure 3-1, water 

must first be extracted for gas production to begin. As the figure implies, with high costs of 

 

12 The total number of direct dischargers reported in the TDD was calculated using the survey weighted Detailed 

Questionnaire responses.
Section 5 – Produced Water Management Costs

5-3 

water management and relatively low revenues in the first few years, a new project may not yet 

be generating positive earnings. An analysis using a one-year assessment of the ability of a 

project beginning in 2008 to generate positive operating earnings from gas production would 

misrepresent longer-run costs and revenues; therefore, this project was excluded from the 

existing source analysis. 

EPA used the direct discharge volume reported in the Detailed Questionnaire (Question 

C3-2) to estimate costs to retrofit or replace each project’s existing produced water management 

system (PWMS). As mentioned previously, some projects may use zero discharge methods in 

addition to discharging to surface water. EPA did not include the volume disposed of through 

zero discharge practices in this analysis.

EPA identified five CBM projects out of the 74 direct discharging projects that transfer 

their produced water to another CBM operator or project prior to surface water discharge. Two

of the five projects transferred the produced water to another operator’s CBM project and the 

remaining three projects transferred water between projects owned by the same operator. EPA 

assessed costs for new treatment or disposal methods to the operator and project receiving the 

produced water for the volume of water received. The operators receiving water may charge a 

fee to the operators transferring water to offset the cost of treating additional water. The revenues 

offset the overall produced water management system operating costs for the project. EPA 

included any revenues or fees reported in the Detailed Questionnaire in the analysis of these 

projects.

5.2 DETERMINE COSTS FOR NEW WATER MANAGEMENT METHOD

Typically, EPA estimates both operation and maintenance costs and capital costs, which 

are then used to estimate annualized costs for a wastewater management approach. O&M costs 

are typically the largest contributor to the annualized costs. As explained in more detail below, 

for this screening level analysis, EPA only developed O&M costs. As a result, the estimated 

costs are most likely an underestimate of the actual annualized costs. EPA developed O&M 

costs for ion exchange and underground injection in dollars per barrel and used the project 

discharge volume to compute project-level costs for these water management methods. 

Ion Exchange

EPA based costs for ion exchange on the ion exchange system used by operators in the 

Powder River Basin, and publicly available ion exchange cost data. As explained in Section

4.1.3, this system may not be appropriate for TDS levels in CBM produced water in all basins 

evaluated. Nevertheless, EPA applied the ion exchange costs to projects in all basins to 

determine whether the projects are economically capable of implementing a technology with a 

similar or higher cost than ion exchange (e.g., reverse osmosis). 

The cost per barrel reported to operate existing ion exchange units in the Powder River 

basin includes the following costs associated with operating the system: flow 

equalization/storage, bypass piping and pumps, chemicals, electricity, materials, material 

storage, brine disposal, labor, and maintenance. Therefore, the O&M costs incurred by the 

operator represent the full cost of operating the ion exchange system, with the exception of 

transporting the produced water to the system. Although there may be additional capital costs 
Section 5 – Produced Water Management Costs

5-4 

associated with the piping needed to route the water into the new ion exchange unit, EPA 

assumed any changes in the O&M costs associated solely with the produced water transport from 

the aggregation point to the ion exchange unit would be negligible and did not include these 

costs in the analysis. EPA used a cost of $0.50/barrel to implement ion exchange in the economic 

analysis.

For the purpose of its cost estimate, EPA assumed that the ion exchange system would 

receive the entire volume of produced water discharged by each project. Because EPA calculates 

costs for operators incremental to existing practices, EPA did not apply ion exchange costs to 

projects that were operating any type of TDS removal technology (either ion exchange or reverse 

osmosis) in 2008 as reported in the Detailed Questionnaire (Question C3-8, C3-10, C3-12). 

Zero Discharge by Underground Injection

EPA used questionnaire responses for projects that used underground injection as the 

only disposal method to develop an average cost of underground injection by geographic area. 

To protect CBI, EPA developed average underground injection costs for eastern and western 

U.S. basins using costs from the Appalachian and Powder River Basins. EPA assumed that 

basins in similar geographic areas would have similar costs. These average costs represent a 

range of distances between the CBM project and the injection well. EPA used the reported 

produced water gathering and transportation costs and the reported underground injection O&M 

cost to obtain the a total O&M costs for underground injection. 

EPA used the following assumptions: 

• For the Appalachian, Black Warrior, Cahaba, and Illinois Basins: EPA used the 

average underground injection costs for the Appalachian Basin ($4.10/bbl). 

• For the Green River, Powder River, and Raton Basin: EPA used the average 

underground injection costs for the Powder River Basin ($0.54/bbl). 

5.3 COMPUTE COSTS OF OPERATING ION EXCHANGE OR USING UNDERGROUND INJECTION

EPA estimated the additional O&M costs that would be incurred from implementing ion 

exchange or underground injection. EPA did not estimate ion exchange costs for projects that 

already had a TDS removal technology in place (either ion exchange or reverse osmosis) or that 

currently manage their wastewater through any zero discharge alternative including underground 

injection. 

In developing the costs for new water management methods, EPA assigned additional 

cost to the operator to use either ion exchange or underground injection for the portion of water 

discharged to surface water without subtracting any baseline produced water management O&M 

costs. EPA did not subtract baseline costs because for many projects, operators use multiple 

produced water management methods and the additional costs assigned are only for the portion 

of water discharged to surface water. Operators would continue to incur costs for discharge 

methods other than surface water discharge. In addition, regardless of the wastewater 

management method, operators will incur costs to aggregate and store water prior to disposal, so 

they will still incur these O&M costs. The produced water management system costs reported in 
Section 5 – Produced Water Management Costs

5-5 

the Detailed Questionnaire did not breakout subcosts for water aggregation, storage, or the 

various disposal alternatives by disposal method.13

For each project and each wastewater management approach (i.e. ion exchange or 

underground injection), EPA multiplied the produced water volume discharged (bbl/yr) by the 

O&M costs ($/yr) to obtain the projected additional wastewater management costs incurred at 

the project level:

Additional Project-Level Costs Incurred ($/yr)= Project Discharge Volume (bbl/yr) × 

Ion Exchange or Underground Injection O&M ($/bbl) 

EPA used the project-level water management costs in the economic analysis described 

in Economic Analysis for Existing and New Projects in the Coalbed Methane Industry. 

5.4 REFERENCES

1. ERG. 2012. 2012 Shale Gas Water Management Conference Notes. November 27. 

2. U.S. EPA. 2012. Development of Final Survey Weights for CBM Analyses. EPA-HQOW-2010-0824, DCN CBM00653. 

3. U.S. EPA. 2013a. Economic Analysis for Existing and New Projects in the Coalbed 

Methane (CBM) Industry. EPA-HQ-OW-2010-0824, DCN CBM00680. 

4. U.S. EPA. 2013b. Summary of Coalbed Methane Information Collection Request 

Confidential Business Information. EPA-HQ-OW-2010-0824, DCN CBM00661. 

5. U.S. EPA. 2013c. 2010 Data Collection and Methodology Used to Update 2008 Existing 

Source Analysis. EPA-HQ-OW-2010-0824, DCN CBM00665. 

6. U.S. EPA. 2013d. Supporting Information for CBM Existing Source Analysis. EPA-HQOW-2010-0824, DCN CBM00664. 

 

13 For the underground injection management alternative, EPA estimated additional costs for underground injection, 

but did not subtract the ion exchange O&M costs for the projects that had ion exchange installed as of 2008. 

Consequently, for these projects, our calculated undergournd injection may be overestimated. EPA considered an 

alternate calculation method: assuming the projects could convert to undergournd injection disposal with no change 

in costs. This calculation resulted in less than a 10% decrease in the total industry cost. This decrease is unlikely to 

change the overall conclusion described in the Economic Analysis for Existing and New Projects in the Coalbed 

Methane (CBM) Industry.