POWDER RIVER BASIN COALBED

METHANE DEVELOPMENT AND

PRODUCED WATER MANAGEMENT STUDY

U.S. Department of Energy

Office of Fossil Energy

and

National Energy Technology Laboratory 

Strategic Center for Natural Gas

November 2002
DISCLAIMER

This report was prepared as an account of work sponsored by an agency of the United 

States Government. Neither the United States Government nor any agency thereof, 

nor any of their employees, makes any warranty, express or implied, or assumes any 

legal liability or responsibility for the accuracy, completeness, or usefulness of any 

information, apparatus, product, or process disclosed, or represents that its use would 

not infringe privately owned rights. Reference therein to any specific commercial 

product, process, or service by trade name, trademark, manufacturer, or otherwise 

does not necessarily constitute or imply its endorsement, recommendation, or 

favoring by the United States Government or any agency thereof. The views and 

opinions of authors expressed therein do not necessarily state or reflect those of the 

United States Government or any agency thereof.

Cover photos courtesy of Advanced Resources International, Inc., and 

ALL Consulting, 1305 E. 15th Street, Suite 205, Tulsa, OK 74120
Powder River Basin Coalbed Methane Development

and Produced Water Management Study

Prepared for:

U.S. Department of Energy 

Office of Fossil Energy and

National Energy Technology Laboratory

Prepared by:

Advanced Resources International, Inc.

November 2002

DEPARTMENT OF ENERGY 

FOREWORD

The President’s National Energy Policy Plan estimates that over the next 20 years annual natural

gas consumption will increase by 50 percent, from approximately 20 to 31 trillion cubic feet

(Tcf). To meet this growing demand for natural gas, the Plan concludes that we will have to

fully develop, in an environmentally sensitive manner, our nation’s economically recoverable

natural gas resources. 

Natural gas produced from coal, commonly referred to as coalbed methane (CBM), constitutes

7.5 percent of total annual domestic natural gas production. In 2000, about 1.4 Tcf of coalbed

methane was produced in the United States. The Powder River Basin, located in northeastern

Wyoming and southeastern Montana, is the nation’s fastest growing source of coalbed methane. 

In the next 10 years, natural gas development in the Powder River Basin is expected to increase

dramatically. As many as 39,000 additional wells will be drilled with 23,900 of these being on

Federal lands. Because of this increased drilling activity, the Department of the Interior, Bureau

of Land Management (BLM), must prepare Environmental Impact Statements (EIS’s) evaluating

the environmental impacts associated with drilling activities in the region. BLM issued draft

Wyoming and Montana EIS’s for comment in January and February, 2002, and expects to have

both EIS’s completed in February, 2003. In a related matter, the U.S. Environmental Protection

Agency (EPA Region 8) is conducting a study of Best Professional Judgment (BPJ) general

permit requirements for produced water on Native American lands in the region. This study will

be completed in December, 2002.

The BLM EIS’s and the EPA Region 8 BPJ study (and possible follow-on actions) will have a

significant impact on the development of natural gas resources in the Powder River Basin. 

Recognizing this, in April, 2002, the U.S. Department of Energy (DOE), Office of Fossil

Energy, through its National Energy Technology Laboratory, contracted with Advanced

Resources International, Inc. to analyze the basin’s geology and underlying coalbed methane

resources, estimate water production rates associated with coalbed methane development, and

evaluate the costs, feasibility, and impacts of coalbed methane produced water disposal

practices. BLM and EPA cooperated with DOE on this study, realizing that this information

would be useful to them in their efforts to develop environmental policies and procedures that

promote Powder River Basin coalbed methane development while protecting the basin's unique

ecosystem. 

The present study, Powder River Basin Coalbed Methane Development and Produced Water

Management Study, projects that the Powder River Basin contains a considerably larger volume

of coalbed methane resources than previously estimated. There is currently a range of resource
estimates for the Powder River Basin from Federal, State, and industry organizations, varying by

almost a factor of five. For example, DOE, BLM, and the U.S. Geological Survey all have

current estimates for the amount of recoverable coalbed methane in this basin ranging from 8 Tcf

to 39 Tcf. The differences stem from employing alternative methodologies, different geologic

models, and different assumptions. When calculating a quantity as uncertain as undiscovered

recoverable natural gas resources, such differences are to be expected and even encouraged, as

they lead to further scientific investigation and interagency cooperation that increases the state of

knowledge about our Nation’s energy resources. In addition, each source develops its estimates

for different purposes, and this also leads to the use of different approaches. Federal agencies are

working together to refine our understanding of the coal bed methane resources of this Basin, and

we expect, therefore, that estimates of recoverable natural gas resources in the Powder River

Basin will continue to change over time.

In addition, the study projects that recovering these resources will require fewer wells than those

projected in the BLM EIS’s. The study also reveals that the amount of water associated with

coalbed methane production in the Powder River Basin is substantially less than previously

estimated. Nevertheless, the study concludes that development of the basin’s coalbed methane

resources will be significantly impacted by the costs and economic feasibility of produced water

management practices and requirements. The study outlines alternative water disposal options,

clearly identifies their costs, and makes a compelling argument that requiring more costly

methods of produced water management will substantially reduce the amount of economically

recoverable Powder River Basin coalbed methane. 

Review comments on the study by representatives of BLM, EPA, and State officials from

Wyoming and Montana have been overwhelmingly positive. The reviewers expressed their

appreciation for DOE support and indicated data contained in the study will be of great value in

their efforts to promote responsible, environmentally sound development of the Powder River

Basin’s coalbed methane resources. 

The present study is one of a number of studies sponsored by DOE that examine the issues

surrounding coalbed methane development. These include development of best management

practices, electronic mapping of environmental and well data, a CBM primer for the public, a

handbook for the development and review of environmental documents required for CBM

projects, analysis of the options for beneficial use of CBM produced water, and research on

technologies for produced water treatment. DOE believes that CBM produced water represents a

valuable resource in the Powder River Basin and elsewhere in the arid Western U.S., and that it

can be, and is, managed with no significant adverse environmental impacts. Currently, this water

is used for livestock and wildlife watering, irrigation, to maintain stream flows, and in municipal

aquifer recharge. All discharges of this water are permitted and meet State and Federal standards. 

 Additional beneficial uses are being studied. 

For more information about DOE oil and natural gas environmental projects visit the Office of

Fossil Energy website at www.fe.doe.gov/oil_gas/environment or contact Peter Lagiovane at: 

202-586-8116.
ACKNOWLEDGMENTS

This study was conducted by Advanced Resources International, Inc. (ARI), located in

Arlington, Virginia, for the U.S. Department of Energy (DOE) Office of Fossil Energy, located

in Washington, D.C., and the National Energy Technology Laboratory (NETL), with locations in

Morgantown, West Virginia, Pittsburgh, Pennsylvania, and Tulsa, Oklahoma. The principal

investigator at ARI was Vello Kuuskraa. Other ARI staff contributing to this effort included 

A. David Decker, Brian T. Kuck, Greg J. Bank and Joyce A. Frank. The contractor’s effort was

overseen by NETL’s Strategic Center for Natural Gas. The Center’s mission includes strategic

planning and policy support, focused on creating a balanced portfolio of DOE natural gas

research and development initiatives and policy analyses to support more informed government

decision making. The Strategic Center for Natural Gas project manager for this analysis was

John Duda. Other DOE staff contributing to the effort included H. William Hochheiser and

Peter Lagiovane of the Office of Fossil Energy, Office of Natural Gas and Petroleum

Technology, and William Lawson and John Ford of the National Petroleum Technology Office. 

The Department extends its appreciation to those companies operating in the Powder River

Basin, and staff of the Department of the Interior, Environmental Protection Agency, and

Wyoming and Montana State agencies who provided the technical input and assistance that

enabled DOE to improve the scope and quality of the analysis. 

TECHNICAL PREFACE

Coalbed methane resources throughout the entire Powder River Basin were reviewed in this

analysis. The study was conducted at the township level, and as with all assessments conducted

at such a broad level, readers must recognize and understand the limitations and appropriate use

of the results. Raw and derived data provided in this report will not generally apply to any

specific location. The coal geology in the basin is complex, which makes correlation with

individual seams difficult at times. 

Although more than 12,000 wells have been drilled to date, large areas of the Powder River

Basin remain relatively undeveloped. The lack of data obviously introduces uncertainty and

increases variability. Proxies and analogs were used in the analysis out of necessity, though

these were always based on sound reasoning. Future development in the basin will make new

data and interpretations available, which will lead to a more complete description of the coals

and their fluid flow properties, and refined estimates of natural gas and water production rates

and cumulative recoveries. 

Throughout the course of the study, critical data assumptions and relationships regarding gas

content, methane adsorption isotherms, and reservoir pressure were the topics of much

discussion with reviewers. A summary of these discussion topics is provided as an appendix. 

Water influx was not modeled although it is acknowledged that this phenomenon may occur in

some settings.

As with any resource assessment, technical and economic results are the product of the

assumptions and methodology used. In this study, key assumptions as well as cost and price

data, and economic parameters are presented to fully inform readers. Note that many quantities

shown in various tables have been subject to rounding; therefore, aggregation of basic and

intermediate quantities may differ from the values shown.

i

TABLE OF CONTENTS

Page

1.0 STUDY PURPOSE, APPROACH AND FINDINGS . . . . . . . . . . . . . . . . . . . . . . . . . 1-1 

1.1 Purpose of Study . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-1 

1.2 Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-1 

1.3 Partitioning the Powder River Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-4 

1.4 Study Approach . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-9 

1.5 Summary of Findings and Impacts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-13

2.0 GEOLOGIC SETTING AND RESERVOIR PROPERTIES . . . . . . . . . . . . . . . . . . . 2-1 

2.1 Basin Area . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-1 

2.2 Basin Structure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-2 

2.3 Basin Stratigraphy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-3 

2.4 Major Coal Seams . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-6 

2.5 Key Reservoir Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-6 

2.6 Summary of Reservoir Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-15

3.0 COALBED METHANE RESOURCES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-1 

3.1 Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-1 

3.2 Coalbed Methane Resources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-1 

3.3 In-Place and Technically Recoverable PRB CBM Resources, by Partition . . 3-3 

3.4 Estimating Gas and Water Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-8 

4.0 COSTS OF PRB CBM DEVELOPMENT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-1 

4.1 Basic Cost Model . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-1 

4.2 Discussion of CBM Development Capital Costs . . . . . . . . . . . . . . . . . . . . . . . 4-5 

4.3 Discussion of CBM Well O&M Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-9 

5.0 ECONOMICS OF PRB CBM UNDER ALTERNATIVE WATER DISPOSAL

OPTIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-1 

5.1 Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-1 

5.2 Water Disposal Alternatives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-3 

5.3 Costs of Water Disposal Alternatives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-4 

5.4 Discussion of Water Disposal Capital and O&M Costs . . . . . . . . . . . . . . . . . 5-6 

5.5 Detailed Economic Analyses of Water Management Options . . . . . . . . . . . . 5-10

6.0 PRESENTATION OF RESULTS BY BASIN PARTITION . . . . . . . . . . . . . . . . . . . 6-1 

6.1 Partition #1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-1 

6.2 Partition #2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-1 

6.3 Partitions #3 and #12 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-6 

6.4 Partition #4 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-9 

6.5 Partition #5 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-16
ii

TABLE OF CONTENTS

(Continued)

Page

6.6 Partition #6 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-25

6.7 Partition #7 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-33

6.8 Partition #8 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-39

6.9 Partition #9 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-46

6.10 Partition #10 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-46

6.11 Partition #11 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-49

Figures

Figure 1-1. Powder River Basin, Growth of Coalbed Methane Production . . . . . . . . . . . . . . 1-2 

Figure 1-2. Powder River Basin, Growth in CBM Water Production . . . . . . . . . . . . . . . . . . 1-2 

Figure 1-3. CBM Water/Gas Production Ratio . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-3 

Figure 1-4. CBM Water Production Per Well . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-3 

Figure 1-5. Powder River Basin CBM Partitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-5 

Figure 1-6. Extent of CBM Drilling Map, Partition #4, Anderson Coal Seam Wells . . . . . . 1-6 

Figure 1-7. Extent of CBM Drilling Map, Partition #4, Canyon Coal Seam Wells . . . . . . . . 1-7 

Figure 1-8. Extent of CBM Drilling Map, Partition #4, Wyodak Coal Seam Wells . . . . . . . 1-8 

Figure 2-1. Coal Basins of Wyoming . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-1 

Figure 2-2. Center of Powder River Basin Coalbed Methane Activity . . . . . . . . . . . . . . . . . 2-2 

Figure 2-3. Regional Structure and Tectonic Map of the Powder River Basin . . . . . . . . . . . 2-3 

Figure 2-4. Regional Cross Section of the Powder River Basin . . . . . . . . . . . . . . . . . . . . . . . 2-4 

Figure 2-5. Upper Cretaceous and Tertiary Stratigraphic Chart for Powder River Basin . . . 2-4 

Figure 2-6. Coal Bearing Units of the Tongue River Member of the Fort Union 

 Formation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-5 

Figure 2-7. Simplified Representation of Fort Union Coalbeds Near Gillette, in 

 Campbell County, Wyoming . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-7 

Figure 2-8. Sample Log Upper Fort Union Coals in Partition #4 . . . . . . . . . . . . . . . . . . . . . . 2-8 

Figure 2-9. Coal Correlation Diagram for Fort Union and Wasatch Formation,

 Powder River Basin, Wyoming . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-9 

Figure 2-10. Cross-Section Showing Lateral Variation of Coalbeds in the Wyodak

 Coal Zone . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-11

Figure 2-11. Regional Pressure Gradient . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-11

Figure 2-12. Reservoir Pressure Profile Used for PRB Study . . . . . . . . . . . . . . . . . . . . . . . . 2-12

Figure 2-13. Gas Content Isotherm Used for Powder River Coalbed Methane . . . . . . . . . . . 2-13

Figure 2-14. Average Synthesized Adsorption Isotherm for 41 Coal Samples From the 

 PRB, Based on a Compilation of Data From Public and Private Sources . . . . . 2-13

Figure 3-1. Wyodak Coal Seam Time Zero Plot . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-9 

Figure 3-2. Wyodak Type Well History Match . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-10

Figure 3-3. 10-Year Simulation of Gas and Water Production for Wyodak Type Well . . . . 3-11
iii

TABLE OF CONTENTS

(Continued)

Page

Figure 6-1. Partition #1 Base Map . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-2 

Figure 6-2. Partition #2 Base Map . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-3 

Figure 6-3. Canyon Time Zero Plot . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-6 

Figure 6-4. Wyodak Time Zero Plot . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-7 

Figure 6-5. Partition #3 Base Map . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-11

Figure 6-6. Partition #12 Base Map . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-12

Figure 6-7. Big George Time Zero Plot . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-15

Figure 6-8. Big George Partition #3 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-16

Figure 6-9. Partition #4 Base Map . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-18

Figure 6-10. Partition #4 Sample Log . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-20

Figure 6-11. Partition #4 Anderson Wells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-22

Figure 6-12. Anderson Time Zero Plot . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-23

Figure 6-13. Anderson Type Well, Partition #4 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-24

Figure 6-14. Partition #4 Canyon Wells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-26

Figure 6-15. Canyon Time Zero Plot . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-27

Figure 6-16. Canyon Type Well, Partition #4 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-28

Figure 6-17. Partition #4 Wyodak Wells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-29

Figure 6-18. Wyodak Time Zero Plot . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-30

Figure 6-19. Wyodak Type Well, Partition #4 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-32

Figure 6-20. Partition #4 Cook Wells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-33

Figure 6-21. Partition #4 Wall Wells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-35

Figure 6-22. Wall Time Zero Plot . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-36

Figure 6-23. Wall Type Well, Partition #4 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-37

Figure 6-24. Partition #4 Pawnee Wells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-39

Figure 6-25. Partition #4 Cache Wells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-40

Figure 6-26. Partition #5 Base Map . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-42

Figure 6-27. Smith Time Zero Plot . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-45

Figure 6-28. Smith Type Well, Partition #5 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-46

Figure 6-29. Anderson Time Zero Plot . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-48

Figure 6-30. Canyon Time Zero Plot . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-50

Figure 6-31. Big George Coal Seam - Aggregate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-52

Figure 6-32. Big George Coal Seam Well Location and Elevation Map, Partition #5 . . . . . 6-53

Figure 6-33. Big George Time Zero Plot . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-54

Figure 6-34. Big George Type Well Partition #5 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-55

Figure 6-35. Wyodak Time Zero Plot . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-57

Figure 6-36. Partition #6 Base Map . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-61

Figure 6-37. Partition #7 Base Map . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-70

Figure 6-38. Partition #8 Base Map . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-77

Figure 6-39. Anderson Time Zero Plot . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-80

Figure 6-40. Anderson Type Well, Partition #8 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-81
iv

TABLE OF CONTENTS

(Continued)

Page

Figure 6-41. Cook Time Zero Plot . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-83 

Figure 6-42. Cook Type Well, Partition #8 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-84 

Figure 6-43. Wall Time Zero Plot . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-86 

Figure 6-44. Wall Type Well, Partition #8 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-87 

Figure 6-45. Pawnee Time Zero Plot . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-89 

Figure 6-46. Pawnee Type Well, Partition #8 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-90 

Figure 6-47. Partition #9 Base Map . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-93 

Figure 6-48. Partition #10 Base Map . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-94 

Figure 6-49. Dietz Time Zero Plot . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-96 

Figure 6-50. Monarch Time Zero Plot . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-98 

Figure 6-51. Cook-Carney Time Zero Plot . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-100

Figure 6-52. Partition #11 Base Map . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-102

Figure 6-53. Dietz (Anderson) Time Zero Plot . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-103

Figure 6-54. Dietz (Anderson), Partition #11 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-106

Figure 6-55. Monarch (Canyon) Time Zero Plot . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-107

Figure 6-56. Monarch (Canyon), Partition #11 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-109

Figure 6-57. Carney (Cook) Time Zero Plot . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-110

Figure 6-58. Carney (Cook), Partition #11 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-111

Figure A-1. Gas Content Isotherm Used for Powder River Coalbed Methane . . . . . . . . . . A-3 

Figure A-2. Average Synthesized Adsorption Isotherm for 41 Coal Samples From the 

 PRB, Based on a Compilation of Data From Public and Private Sources . . . . A-3 

Figure A-3. Variation in Sorption Capacity with Temperature, Dietz #3 Coal . . . . . . . . . . A-5 

Figure A-4. Comparison of Bustin and Downey Adsorption Iostherm for

 Dietz #3 Coal with Advanced Resources Adsorption Isotherm for PRB Coals A-5 

Figure A-5. Wyodak Time Zero Well Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-7 

Figure A-6. History Match Wyodak Type Well w/Free Gas . . . . . . . . . . . . . . . . . . . . . . . . A-7 

Figure A-7. Reservoir Simulation of Wyodak Type Well w/No Free Gas . . . . . . . . . . . . . . A-8 

Figure A-8. Reservoir Simulation of Wyodak Type Well w/23% Gas Undersaturation . . . A-8 

Figure A-9. Reservoir Simulation of Wyodak Type Well w/66% Gas Undersaturation . . . A-9 

Figure A-10. Big George Time Zero Well Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-10

Figure A-11. History Match Big George Type Well . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-11

Figure A-12. Reservoir Simulation of Big George Type Well w/23% Gas 

 Undersaturation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-12

Tables

Table S-1. Volumes of Economically Recoverable CBM w/Alternative Water

 Disposal Options (Tcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . x 

Table S-2. Summary of Impacts from Using Alternative Water Disposal Methods

 for CBM Produced Water in the PRB . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . xi 

Table 1-1. Reports and Data for Powder River CBM and Water Study . . . . . . . . . . . . . . . . . 1-10
v

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(Continued)

Page

Table 1-2. Electronic Data Sources for Powder River CBM and Water Study . . . . . . . . . . . 1-12

Table 1-3. Economically Recoverable CBM (Tcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-14

Table 1-4. Volumes of Economically Recoverable CBM (Tcf) . . . . . . . . . . . . . . . . . . . . . . . 1-14

Table 1-5. Volumes of CBM Produced Water (Billion Bbls) . . . . . . . . . . . . . . . . . . . . . . . . 1-15

Table 1-6. Loss of Economically Recoverable CBM (Tcf) . . . . . . . . . . . . . . . . . . . . . . . . . . 1-15

Table 1-7. Loss of Mineral Royalties from CBM ($MM) . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-16

Table 1-8. Loss of Well Drilling for CBM (# Wells) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-16

Table 1-9. Loss of Capital Investment for CBM ($MM) . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-17

Table 1-10. Summary of Impacts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-17

Table 2-1. Partition #4 Coal Depth . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-6 

Table 2-2. Coal Thickness for Partition #4 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-10

Table 2-3. Average Data for Partition #4 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-15

Table 2-4. Key Reservoir Properties for Powder River Basin Coals . . . . . . . . . . . . . . . . . . . 2-16

Table 3-1. Gas In-Place for Major PRB Coal Seams (Bcf) . . . . . . . . . . . . . . . . . . . . . . . . . . 3-2 

Table 3-2. Technically Recoverable Resources for Major PRB Coal Seams (Bcf) . . . . . . . . 3-3 

Table 3-3. In-Place and Technically Recoverable CBM, Partitions #1 and #2 . . . . . . . . . . . 3-4 

Table 3-4. In-Place and Technically Recoverable CBM, Partitions #3 and #12 . . . . . . . . . . 3-4 

Table 3-5. In-Place and Technically Recoverable CBM, Partition #4 . . . . . . . . . . . . . . . . . . 3-5 

Table 3-6. In-Place and Technically Recoverable CBM, Partition #5 . . . . . . . . . . . . . . . . . . 3-5 

Table 3-7. In-Place and Technically Recoverable CBM, Partition #6 . . . . . . . . . . . . . . . . . . 3-6 

Table 3-8. In-Place and Technically Recoverable CBM, Partition #7 . . . . . . . . . . . . . . . . . . 3-6 

Table 3-9. In-Place and Technically Recoverable CBM, Partition #8 . . . . . . . . . . . . . . . . . . 3-7 

Table 3-10. In-Place and Technically Recoverable CBM, Partition #9 . . . . . . . . . . . . . . . . . 3-7 

Table 3-11. In-Place and Technically Recoverable CBM, Partition #10 . . . . . . . . . . . . . . . . 3-8 

Table 3-12. Number and Nature of CBM Wells for History Matching . . . . . . . . . . . . . . . . . 3-9 

Table 3-13. Summary Results for PRB Coalbed Methane History Matching . . . . . . . . . . . . 3-10

Table 3-14. Number of CBM Type Wells for Basin Assessment . . . . . . . . . . . . . . . . . . . . . . 3-12

Table 4-1. Capital Costs for PRB CBM Well . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-2 

Table 4-2. O&M Costs for PRB CBM Well . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-3 

Table 4-3. Capital Costs for Alternate Method of Water Disposal . . . . . . . . . . . . . . . . . . . . 4-4 

Table 4-4. Sample Tangible and Intangible Costs for Two PRB CBM Wells . . . . . . . . . . . . 4-6 

Table 4-5. Additional Drilling and Completion Costs for Two PRB CBM Wells . . . . . . . . . 4-7 

Table 4-6. Pump Replacement Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-9 

Table 5-1. Volumes of Economically Recoverable CBM w/Alternative Water 

 Disposal Options . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-2 

Table 5-2. Volumes of Economically Recoverable CBM w/Alternative Water 

 Disposal Options . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-3 

Table 5-3. CBM Water Disposal Alternative Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-4 

Table 5-4. Capital Costs for Disposal Options . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-5 

Table 5-5. Total Estimated Costs for Deep Disposal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-5 

Table 5-6. Total Capital Costs for Active Water Treatment . . . . . . . . . . . . . . . . . . . . . . . . . . 5-9 
vi

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Page

Table 5-7. Annual Operating Costs for Trucking . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-10

Table 5-8. Assumptions for Discounted Cash Flow Analyses . . . . . . . . . . . . . . . . . . . . . . . . 5-10

Table 5-9. Cashflow Model Surface Discharge . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-122 

Table 6-1. Anderson Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-2 

Table 6-2. Canyon Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-3 

Table 6-3. Wyodak Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-4 

Table 6-4. Big George Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-4 

Table 6-5. Cook Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-5 

Table 6-6. Pawnee Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-5 

Table 6-7. In-Place and Technically Recoverable CBM, Partitions #1 and #2 . . . . . . . . . . . 6-6 

Table 6-8. Anderson Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-7 

Table 6-9. Canyon Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-8 

Table 6-10. Big George Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-8 

Table 6-11. Cook Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-9 

Table 6-12. In-Place and Technically Recoverable CBM, Partitions #3 and #12 . . . . . . . . . 6-9 

Table 6-13. Anderson Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-11

Table 6-14. Canyon Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-12

Table 6-15. Wyodak Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-13

Table 6-16. Cook Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-13

Table 6-17. Wall Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-14

Table 6-18. Pawnee Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-15

Table 6-19. Cache Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-16

Table 6-20. In-Place and Technically Recoverable CBM, Partition #4 . . . . . . . . . . . . . . . . . 6-16

Table 6-21. Felix Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-17

Table 6-22. Roland Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-18

Table 6-23. Smith Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-18

Table 6-24. Swartz Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-19

Table 6-25. Anderson Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-20

Table 6-26. Canyon Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-20

Table 6-27. Big George Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-21

Table 6-28. Wyodak Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-22

Table 6-29. Cook Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-23

Table 6-30. Wall Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-23

Table 6-31. Pawnee Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-24

Table 6-32. Cache Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-25

Table 6-33. In-Place and Technically Recoverable CBM, Partition #5 . . . . . . . . . . . . . . . . . 6-25

Table 6-34. Cameron Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-26

Table 6-35. Murry Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-27

Table 6-36. Felix Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-27

Table 6-37. Ucross Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-28
vii

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(Continued)

Page

Table 6-38. Roland Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-28

Table 6-39. Anderson Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-29

Table 6-40. Canyon Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-30

Table 6-41. Big George Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-30

Table 6-42. Cook Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-31

Table 6-43. Wall Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-31

Table 6-44. Pawnee Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-32

Table 6-45. In-Place and Technically Recoverable CBM, Partition #6 . . . . . . . . . . . . . . . . . 6-32

Table 6-46. Wasatch Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-34

Table 6-47. Roland Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-34

Table 6-48. Smith Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-35

Table 6-49. Anderson Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-35

Table 6-50. Canyon Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-36

Table 6-51. Cook Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-37

Table 6-52. Wall Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-37

Table 6-53. Pawnee Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-38

Table 6-54. Cache Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-38

Table 6-55. In-Place and Technically Recoverable CBM, Partition #7 . . . . . . . . . . . . . . . . . 6-39

Table 6-56. Smith Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-40

Table 6-57. Swartz Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-40

Table 6-58. Anderson Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-41

Table 6-59. Canyon Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-42

Table 6-60. Cook Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-42

Table 6-61. Wall Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-43

Table 6-62. Pawnee Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-44

Table 6-63. Cache Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-44

Table 6-64. Oedekoven . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-45

Table 6-65. In-Place and Technically Recoverable CBM, Partition #8 . . . . . . . . . . . . . . . . . 6-45

Table 6-66. Dietz Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-47

Table 6-67. Monarch Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-47

Table 6-68. Carney Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-48

Table 6-69. Pawnee Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-49

Table 6-70. In-Place and Technically Recoverable CBM, Partitions #9 and #10 . . . . . . . . . 6-49

Table 6-71. Dietz #1 Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-50

Table 6-72. Dietz #2 Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-51

Table 6-73. Dietz #3 Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-51

Table 6-74. Monarch Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-52

Table 6-75. Carney Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-53

Table 6-76. In-Place and Technically Recoverable CBM, Partition #11 . . . . . . . . . . . . . . . . 6-53
viii

TABLE OF CONTENTS

(Continued)

Page

Table A-1. Comparison PRB Wyodak Coal and Overseas Low Rank Coal . . . . . . . . . . . . A-2 

Table A-2. Comparison of Gas Production Rates for Wyodak Type Well . . . . . . . . . . . . . A-9 

Table A-3. Wyodak Coal Seam Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-10

Table A-4. Comparison of Gas Production Rates for Big George Type Well . . . . . . . . . . . A-11

Table A-5. Big George Coal Seam Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-12

Table A-6. Reservoir Parameters for Powder River Basin (Fort Union Coals) . . . . . . . . . . A-13

Table A-7. Comparison of 1995 USGS and 2002 ARI Values for Gas Content 

 of PRB Coals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-14
1

Increased potential, however, should not be confused with additional impact. Higher per

well gas recoveries will allow development of the resource using far fewer wells and as a

consequence, with much less disturbance. In fact, this analysis forecasts that several thousand

fewer wells will be needed to develop the CBM resources in the Powder River Basin, compared

to widely-accepted well count estimates. Moreover, prudent resource development is expected to

lead to less water production–billions of barrels less–as compared to the draft EIS estimate.

ix

EXECUTIVE SUMMARY

The Powder River Basin coals contain a considerably larger volume of gas in place than

established by previous studies. The Powder River Coalbed Methane Basin Study identifies

61 Tcf of natural gas in-place. This in-place resource value is significantly larger than

previously reported and confirms that the Powder River Basin (PRB) coalbed methane (CBM)

play has the potential for providing significant additions to future domestic natural gas supplies1

. 

Major reasons for the increased PRB coalbed methane resource in-place of 61 Tcf in this Basin

Study are the following:

 • The study included extensive information on the deeper Fort Union coals prevalent in the

basin, it compiled new data on the Wastach coals on the western edge of the basin, and it

included the coals in the Montana portion of the PRB.

 • The study identified the presence of free gas in certain coal formations and established

higher gas content values for PRB coals, both increasing the gas in- place over previous

estimates.

A significant portion of the coalbed methane resource in the Powder River Basin is

technically recoverable. The estimate of 39 Tcf of technically recoverable resources is based

on reservoir modeling and the construction of 142 “type wells” representative of the distribution

in well performance (gas and water production) for 12 distinct coal seams in 12 basin partitions. 

All results include CBM development to date in the basin. The Basin Study’s estimate of

technically recoverable coalbed methane resources for the Powder River updates earlier

estimates by the Potential Gas Committee (2000) of 24 Tcf and by the U.S. Geological Survey

(2002) of 14 Tcf.

The costs and economic feasibility of further developing coalbed methane in the Powder

River Basin will be significantly impacted by produced water management practices and

requirements. The study finds that alternative produced water management options will have a

profound influence on the economic viability of producing coalbed methane from the PRB. The

costs of the alternative water management options in the PRB—assessed using a 15%, before

corporate income tax, internal rate of return (IRR) and a long-term natural gas price (at the

Henry Hub) of $3 per Mcf as the economic threshold criteria—are significant and can make an

otherwise profitable CBM project uneconomic.

The results of the economic analyses are presented on Table S-1 and are further discussed below.
2

Shallow re-injection is considered in a generic sense and evaluated from a theoretical

standpoint. Much uncertainty exists surrounding the real availability of shallow zones with the

required geology and fluid flow properties necessary for long-term successful projects.

x

Table S-1. Volumes of Economically Recoverable CBM 

w/Alternative Water Disposal Options (Tcf)

Economic Conditions

Surface

Discharge Impoundment

Shallow

Reinjection

Active

Treatment

Case 1 (Today)* 1.5 -- -- --

Case 2 (Transition)** 22.4 20.0 18.8 7.1-10.2

Case 3 (Long Term)*** 29.1 27.8 27.1 17.8-21.6

 * Basin differential remains at $1.80 per Mcf.

 ** Basin differential narrows from $1.80 per Mcf in year 1 to $0.80 per Mcf in year 3 and beyond.

*** Basin differential is $0.80 per Mcf.

 • Under today’s volatile natural gas prices and unfavorable Wyoming basin differentials,

only using surface disposal of produced water is economic. And, this low cost water

management option is economic only in selected, highly productive portions of the PRB. 

More costly water disposal options would preclude further economic development of

coalbed methane in the Powder River Basin. A significant portion of the 1.5 Tcf of

economic CBM potential, shown in Table S-1, is already under development, leaving

little opportunity for further economically justified expansion (at today’s conditions and

standard economic criteria) in the Powder River Basin.

 • Assuming a transition toward more normal Wyoming basin price differentials, a significant portion of the basin becomes economic to further develop, with water management

practices of surface discharge, impoundment or shallow re-injection2. Requiring active

treatment of the water (with current reverse osmosis technology) greatly reduces the

economically viable potential for CBM in the PRB. Specifically, instead of 19 to 22 Tcf

of economically recoverable coalbed methane (using one of the first three water management options, shown in Table S-1), only 7 to 10 Tcf of coalbed methane remains economic to develop with a requirement for active water treatment. This represents a loss of

12 Tcf of otherwise economically recoverable natural gas resource from the Powder

River Basin.

 • Taking a long-term outlook on prices and assuming that the Wyoming basin differential

returns to historically more normal values, the economically developable CBM resources

of the PRB range from 27 to 29 Tcf (for the three lower cost water management options). 

Requiring active treatment of water (with current reverse osmosis technology) reduces

the economically viable PRB CBM potential to a range of 18 to 22 Tcf for a loss of 7 to

9 Tcf of otherwise economically recoverable natural gas resource.
xi

The loss of CBM resources, royalties and tax receipts from more stringent CBM produced

water management practices would be substantial. Table S-2 provides a summary of the

potential losses that would occur from requirements to use progressively more stringent water

disposal alternatives. The PRB Study recognizes that, in practice, a combination of water

disposal alternatives would be used. Once the final mix of options is established, the

information in this study can be used to estimate these impacts.

Table S-2. Summary of Impacts from Using Alternative Water Disposal Methods

for CBM Produced Water in the PRB

Water Disposal Method

Loss of CBM

Resource

Loss of CBM

Royalty

Loss of

Production/

Ad Valorem Taxes

(Tcf) ($ million) ($ million)

Surface Discharge -- -- --

Infiltration Impoundment (2.4) ($506) ($362)

Shallow Re-injection (3.6) ($756) ($540)

Reverse Osmosis/w:

• Trucking of Residual (15.3) ($3,184) ($2,272)

• Deep Disposal of Residual (12.2) ($2,547) ($1,810)

Improvements in coalbed methane production technology and water management practices

can help maintain the economic viability of Powder River coalbed methane. The current

volatile natural gas prices and historically high basin differentials place major hurdles on the

economics of Powder River CBM. Further raising the barrier is the recognition that a considerable portion of the shallower, thick coals in the basin have already been drilled, leaving

deeper and thinner coals as the target. Finally, the costs of more stringent water management

practices will further lower the economic viability of this large natural gas resource.
1-1

1.0 STUDY PURPOSE, APPROACH AND FINDINGS

1.1 Purpose of Study

The overall purpose of the Powder River Basin Study is to assist DOE/FE, NETL and NPTO

better understand the energy impacts of the alternative water disposal options being considered

for Powder River Basin coalbed methane. The specific objectives of the study are:

1. Develop a stronger data and analytical base for the geology, resources and CBM potential

of the Powder River Basin.

2. Divide the basin into a series of geologically similar partitions to facilitate the analysis of

well performance and costs.

3. Project CBM and water production rates for a series of typical wells and the distribution

of well performance in each partition.

4. Assemble information on the costs of CBM development and produced water management, including cash flows and economics.

1.2 Background

The Powder River Basin of Wyoming and Montana is the site of the fastest growing domestic

natural gas play—the development of coalbed methane (CBM) from the Wyodak and Big

George fairways. As of the end of 2001:

 • Nearly 12,000 CBM wells have been drilled with 8,177 wells producing.

 • Coalbed methane production is at 823 million cubic feet a day (MMcfd) up from

111 MMcfd just three years earlier, as shown in Figure 1-1.

Along with the growth in CBM production has been the growth in produced water, as part of

dewatering and depressuring the coal formations thus enabling the coals to release their adsorbed

methane. As of the end of 2001, water production was at 1,444,000 barrels per day, up from

229,000 barrels per day at the end of 1998, as shown in Figure 1-2.

Progressive CBM development and dewatering, while increasing total water production, is

leading to lower water to gas ratios and lower average production of water per well:

 • The water to gas production ratio (at the end of 2001) is 1.75 barrels per Mcf, down from

2.88 barrels per Mcf two years ago, as shown in Figure 1-3.

 • Water production per CBM well (at the end of 2001) is 177 barrels per day, down from

396 barrels per day two years ago, as shown in Figure 1-4.
1-2

111

232

544

823

0

100

200

300

400

500

600

700

800

900

12/1998 12/1999 12/2000 12/2001

CBM Production (MMcfd)

Figure 1-1. Powder River Basin, Growth of Coalbed Methane Production

229

667

1,209

1,444

0

200

400

600

800

1000

1200

1400

1600

Water Production (MBbl/d)

12/1998 12/1999 12/2000 12/2001

Figure 1-2. Powder River Basin, Growth in CBM Water Production
1-3

CBM Water/Gas Ratio

(Bbls/Mcf)

0

1

2

3

4

1999 2000 2001

Barrels Water/Mcf Gas

2.88

2.22

1.75

Figure 1-3. CBM Water/Gas Production Ratio

CBM Water Production Per Well

(Bbls/Day)

0

100

200

300

400

1999 2000 2001

Barrels Water/Well/Day

396

268

177

Figure 1-4. CBM Water Production Per Well

For the most part, produced CBM waters are either surface discharged or placed into impoundments providing beneficial use for agriculture, stock watering and grasslands. Should beneficial
1-4

use of produced CBM water be constrained, other (more costly) options would need to be considered, impacting the economics and natural gas resource development in the basin. These

options include: (a) shallow re-injection to conserve the water for future use; (b) pre-treatment

of water with chemicals and reverse osmosis, with deep disposal of the residual concentrate;

and/or, ©) deep re-injection into non-potable water disposal aquifers.

1.3 Partitioning the Powder River Basin

To provide a series of geologically consistent analytic units, the Powder River Basin is divided

into 12 partitions, based on coal depth, development status, and geographic considerations. The

12 basin partitions are shown in Figure 1-5, and consist of the following:

 1. Southern Extension

 2. South Eastern Area

 3. South Central Area

 4. East Central Area

 5. Main Central Area

 6. West Central Area

 7. North Western Area

 8. North Eastern Area

 9. Eastern Montana Area

10. Western Montana Area

11. NW Basin Edge, Wyoming

12. SW Basin Edge, Wyoming

Partition #4, in the east-central portion of the Power River, has seen the most extensive coalbed

methane development, as well as surface mining of coal. Figures 1-6 through 1-8 show the

extent of coalbed methane development (as of the end of 2001) for the Anderson, Canyon and

Wyodak coal seams in Partition #4, and in surrounding townships along the eastern portion of

the PRB.

This study provides the gas in-place, recoverable resources and economics of each of the major

coal seams in each of these 12 basin partitions.
1-5

Campbell

Johnson

Sheridan

Powder River

9S 44E

8S 44E

7S 47E

9S 46E

6S 47E

9S 45E

8S 45E 8S 46E 8S 47E 8S 50E

9S 47E 9S 50E 9S 53E 9S 

8S 41E

8S 36E

6S 50E

7S 51E

6S 51E

9S 43E

6S 41E

8S 43E

6S 42E 6S 43E

9S 49E

8S 51E

9S 48E

7S 41E 7S 43E 7S 53E

8S 38E

8S 53E

7S 50E

6S 36E

9S 51E 9S 40E

7S 36E

8S 40E

7S 37E 7S 42E

6S 40E

9S 38E 9S 42E

8S 

7S 7S 40E

8S 52E

6S 48E 6S 49E 6S 6S 45E

7S 48E

9S 36E

7S 39E

8S 48E

6S 37E

8S 49E

6S 53E

9S 52E

8S 42E

7S 49E 7S 52E

6S 52E

7S 45E

8S 37E

7S 46E

9S 41E 9S 37E

7S 44E

6S 39E 6S 46E

8S 39E

6S 44E

57N 76W

56N 72W 56N 71W 56N 70W

52N 77W 52N 73W

57N 84W 57N 75W

9S 39E

55N 81W

56N 73W 56N 69W

57N 74W

49N 85W

45N 72W

51N 73W

48N 86W

46N 72W

43N 75W

39N 69W

56N 78W

7S 38E

49N 84W

44N 84W

42N 75W

45N 69W

N 87W

45N 70W

53N 79W

36N 71W

56N 86W

44N 82W

47N 73W

42N 77W

52N 75W

54N 78W

43N 76W

56N 79W

49N 72W

47N 72W

43N 73W

41N 76W

36N 70W

54N 83W

51N 77W

56N 75W

51N 76W

45N 71W

42N 76W

57N 83W

50N 84W

52N 72W

53N 72W

41N 77W

51N 70W

50N 70W

43N 69W

41N 75W 41N 72W

36N 72W

57N 80W

47N 84W

49N 73W 49N 71W

38N 72W

56N 74W

57N 82W

49N 69W

44N 78W

50N 76W

42N 73W

44N 73W

52N 71W

55N 71W

44N 70W

39N 85W

49N 70W

46N 86W

51N 75W

43N 70W

57N 86W

39N 72W

38N 69W

56N 76W

41N 69W

44N 69W

51N 83W

46N 70W

50N 85W

37N 71W

44N 75W

48N 84W

39N 84W

50N 75W

48N 72W

54N 72W

41N 73W

49N 74W

53N 86W

38N 71W

42N 71W

51N 71W

56N 83W 56N 77W

52N 70W

56N 85W

53N 73W

50N 74W

37N 72W

44N 72W

52N 79W

50N 77W

41N 74W

42N 72W

54N 82W

 87W

50N 71W

37N 69W

47N 70W

45N 84W

43N 71W

39N 71W 39N 70W

50N 69W

54N 79W

41N 71W

46N 77W 46N 73W

47N 77W 47N 85W

45N 78W

46N 74W

47N 71W

42N 74W

50N 73W

45N 77W

50N 80W

55N 82W

N 87W

38N 86W

48N 71W

46N 69W

42N 69W

41N 70W

52N 74W

45N 86W

55N 69W

 87W

 87W

45N 74W

44N 71W

45N 82W 45N 76W

52N 76W

42N 84W

53N 85W 53N 84W

46N 78W

37N 85W

55N 72W 55N 70W

42N 85W

N 87W

46N 71W

45N 75W

43N 72W

46N 79W

45N 83W

51N 84W

46N 82W

52N 69W

40N 84W

45N 79W

49N 75W

47N 78W 47N 75W 47N 69W

48N 70W

54N 75W

45N 85W

49N 76W

36N 73W

48N 78W

47N 74W

56N 84W

57N 73W

38N 70W

 87W

49N 77W

52N 86W

51N 69W

38N 85W

53N 69W

43N 74W

48N 69W

44N 81W

N 87W

52N 82W

56N 82W

51N 81W

37N 84W

N 87W

37N 83W 37N 86W

45N 81W

37N 70W

49N 81W

37N 79W

54N 80W

48N 79W

N 87W

54N 77W

53N 70W

52N 85W

49N 83W

42N 70W

57N 77W

49N 82W

54N 73W

50N 82W

37N 78W

47N 79W

55N 84W

51N 82W

87W

48N 73W

46N 81W

54N 74W

55N 83W

42N 83W

57N 71W

37N 81W

49N 86W

50N 81W

55N 85W

39N 77W

52N 83W N 87W

53N 71W

46N 84W

43N 85W

52N 84W

49N 78W

6S 38E

44N 83W

48N 81W

45N 73W

37N 82W

50N 79W

57N 70W

39N 82W

53N 81W

55N 86W

46N 85W

50N 78W

39N 81W 39N 73W

41N 84W 41N 83W

43N 84W

46N 75W

53N 74W

54N 71W

48N 77W

51N 79W

50N 83W

57N 69W

36N 74W

43N 81W

53N 82W

37N 75W 37N 74W

87W

37N 73W

41N 82W

54N 86W 54N 84W

49N 80W

38N 77W 38N 73W

 87W

47N 86W

37N 77W

N 87W 44N 85W

53N 80W

38N 84W

40N 85W

38N 74W

36N 81W

46N 83W

39N 75W

47N 83W

50N 72W

36N 75W

57N 85W

53N 83W

43N 82W

50N 86W

39N 83W

36N 82W

38N 82W

40N 82W

38N 81W

39N 78W

 87W

38N 78W

43N 77W

57N 79W

44N 74W

55N 78W

36N 69W

42N 81W

40N 69W

54N 85W

N 87W

38N 75W

 87W

54N 70W

40N 86W

47N 81W

52N 81W

54N 69W

53N 75W

42N 78W

48N 82W

51N 74W

40N 81W

55N 79W

41N 78W

46N 76W

54N 76W

51N 86W

39N 74W

48N 75W

39N 76W

36N 78W

52N 78W

41N 79W

57N 78W

48N 83W

47N 76W

49N 79W

43N 78W

44N 79W

40N 78W 40N 73W

38N 83W

36N 77W

42N 82W

55N 74W

51N 78W

40N 77W 40N 74W 40N 75W

47N 82W

40N 83W

36N 76W

43N 79W

36N 79W

39N 79W

55N 73W

40N 79W

48N 76W

51N 85W

37N 76W

56N 81W

44N 77W

N 87W

36N 83W

55N 77W

40N 72W

37N 80W

42N 86W

43N 86W

38N 79W

42N 79W

44N 86W

41N 81W

38N 76W

39N 86W

 87W

51N 80W

36N 80W

38N 80W

44N 76W

53N 76W

40N 80W

6N 87W

51N 72W

41N 85W

54N 81W

55N 75W

39N 80W

48N 74W

46N 80W

45N 80W

40N 70W

48N 85W

55N 76W

36N 86W

41N 86W

56N 80W

40N 76W

36N 84W

57N 72W

40N 71W

47N 80W

52N 80W

36N 85W

48N 80W

57N 81W

43N 83W

55N 80W

N 87W

53N 78W

41N 80W

42N 80W

43N 80W

44N 80W

87W 58N 86W

58N 80W 58N 85W

58N 79W 58N 84W 58N 83W 58N 82W 58N 81W 58N 78W 58N 77W 58N 76W 58N 75W 58N 74W 58N 73W 58N 72W 58N 71W 58N 69W 58N 70W

53N 77W

10S 38E

7.5S 40E

10S 43E

7.5S 41E

10S 42E

56 1/2N 69

MT

WY

10 9

11

7 8

6

5

12

4

3

2

1

Campbell

Johnson

Sheridan

Powder River

9S 44E

8S 44E

7S 47E

9S 46E

6S 47E

9S 45E

8S 45E 8S 46E 8S 47E 8S 50E

9S 47E 9S 50E 9S 53E 9S 

8S 41E

8S 36E

6S 50E

7S 51E

6S 51E

9S 43E

6S 41E

8S 43E

6S 42E 6S 43E

9S 49E

8S 51E

9S 48E

7S 41E 7S 43E 7S 53E

8S 38E

8S 53E

7S 50E

6S 36E

9S 51E 9S 40E

7S 36E

8S 40E

7S 37E 7S 42E

6S 40E

9S 38E 9S 42E

8S 

7S 7S 40E

8S 52E

6S 48E 6S 49E 6S 6S 45E

7S 48E

9S 36E

7S 39E

8S 48E

6S 37E

8S 49E

6S 53E

9S 52E

8S 42E

7S 49E 7S 52E

6S 52E

7S 45E

8S 37E

7S 46E

9S 41E 9S 37E

7S 44E

6S 39E 6S 46E

8S 39E

6S 44E

57N 76W

56N 72W 56N 71W 56N 70W

52N 77W 52N 73W

57N 84W 57N 75W

9S 39E

55N 81W

56N 73W 56N 69W

57N 74W

49N 85W

45N 72W

51N 73W

48N 86W

46N 72W

43N 75W

39N 69W

56N 78W

7S 38E

49N 84W

44N 84W

42N 75W

45N 69W

N 87W

45N 70W

53N 79W

36N 71W

56N 86W

44N 82W

47N 73W

42N 77W

52N 75W

54N 78W

43N 76W

56N 79W

49N 72W

47N 72W

43N 73W

41N 76W

36N 70W

54N 83W

51N 77W

56N 75W

51N 76W

45N 71W

42N 76W

57N 83W

50N 84W

52N 72W

53N 72W

41N 77W

51N 70W

50N 70W

43N 69W

41N 75W 41N 72W

36N 72W

57N 80W

47N 84W

49N 73W 49N 71W

38N 72W

56N 74W

57N 82W

49N 69W

44N 78W

50N 76W

42N 73W

44N 73W

52N 71W

55N 71W

44N 70W

39N 85W

49N 70W

46N 86W

51N 75W

43N 70W

57N 86W

39N 72W

38N 69W

56N 76W

41N 69W

44N 69W

51N 83W

46N 70W

50N 85W

37N 71W

44N 75W

48N 84W

39N 84W

50N 75W

48N 72W

54N 72W

41N 73W

49N 74W

53N 86W

38N 71W

42N 71W

51N 71W

56N 83W 56N 77W

52N 70W

56N 85W

53N 73W

50N 74W

37N 72W

44N 72W

52N 79W

50N 77W

41N 74W

42N 72W

54N 82W

 87W

50N 71W

37N 69W

47N 70W

45N 84W

43N 71W

39N 71W 39N 70W

50N 69W

54N 79W

41N 71W

46N 77W 46N 73W

47N 77W 47N 85W

45N 78W

46N 74W

47N 71W

42N 74W

50N 73W

45N 77W

50N 80W

55N 82W

N 87W

38N 86W

48N 71W

46N 69W

42N 69W

41N 70W

52N 74W

45N 86W

55N 69W

 87W

 87W

45N 74W

44N 71W

45N 82W 45N 76W

52N 76W

42N 84W

53N 85W 53N 84W

46N 78W

37N 85W

55N 72W 55N 70W

42N 85W

N 87W

46N 71W

45N 75W

43N 72W

46N 79W

45N 83W

51N 84W

46N 82W

52N 69W

40N 84W

45N 79W

49N 75W

47N 78W 47N 75W 47N 69W

48N 70W

54N 75W

45N 85W

49N 76W

36N 73W

48N 78W

47N 74W

56N 84W

57N 73W

38N 70W

 87W

49N 77W

52N 86W

51N 69W

38N 85W

53N 69W

43N 74W

48N 69W

44N 81W

N 87W

52N 82W

56N 82W

51N 81W

37N 84W

N 87W

37N 83W 37N 86W

45N 81W

37N 70W

49N 81W

37N 79W

54N 80W

48N 79W

N 87W

54N 77W

53N 70W

52N 85W

49N 83W

42N 70W

57N 77W

49N 82W

54N 73W

50N 82W

37N 78W

47N 79W

55N 84W

51N 82W

87W

48N 73W

46N 81W

54N 74W

55N 83W

42N 83W

57N 71W

37N 81W

49N 86W

50N 81W

55N 85W

39N 77W

52N 83W N 87W

53N 71W

46N 84W

43N 85W

52N 84W

49N 78W

6S 38E

44N 83W

48N 81W

45N 73W

37N 82W

50N 79W

57N 70W

39N 82W

53N 81W

55N 86W

46N 85W

50N 78W

39N 81W 39N 73W

41N 84W 41N 83W

43N 84W

46N 75W

53N 74W

54N 71W

48N 77W

51N 79W

50N 83W

57N 69W

36N 74W

43N 81W

53N 82W

37N 75W 37N 74W

87W

37N 73W

41N 82W

54N 86W 54N 84W

49N 80W

38N 77W 38N 73W

 87W

47N 86W

37N 77W

N 87W 44N 85W

53N 80W

38N 84W

40N 85W

38N 74W

36N 81W

46N 83W

39N 75W

47N 83W

50N 72W

36N 75W

57N 85W

53N 83W

43N 82W

50N 86W

39N 83W

36N 82W

38N 82W

40N 82W

38N 81W

39N 78W

 87W

38N 78W

43N 77W

57N 79W

44N 74W

55N 78W

36N 69W

42N 81W

40N 69W

54N 85W

N 87W

38N 75W

 87W

54N 70W

40N 86W

47N 81W

52N 81W

54N 69W

53N 75W

42N 78W

48N 82W

51N 74W

40N 81W

55N 79W

41N 78W

46N 76W

54N 76W

51N 86W

39N 74W

48N 75W

39N 76W

36N 78W

52N 78W

41N 79W

57N 78W

48N 83W

47N 76W

49N 79W

43N 78W

44N 79W

40N 78W 40N 73W

38N 83W

36N 77W

42N 82W

55N 74W

51N 78W

40N 77W 40N 74W 40N 75W

47N 82W

40N 83W

36N 76W

43N 79W

36N 79W

39N 79W

55N 73W

40N 79W

48N 76W

51N 85W

37N 76W

56N 81W

44N 77W

N 87W

36N 83W

55N 77W

40N 72W

37N 80W

42N 86W

43N 86W

38N 79W

42N 79W

44N 86W

41N 81W

38N 76W

39N 86W

 87W

51N 80W

36N 80W

38N 80W

44N 76W

53N 76W

40N 80W

6N 87W

51N 72W

41N 85W

54N 81W

55N 75W

39N 80W

48N 74W

46N 80W

45N 80W

40N 70W

48N 85W

55N 76W

36N 86W

41N 86W

56N 80W

40N 76W

36N 84W

57N 72W

40N 71W

47N 80W

52N 80W

36N 85W

48N 80W

57N 81W

43N 83W

55N 80W

N 87W

53N 78W

41N 80W

42N 80W

43N 80W

44N 80W

87W 58N 86W

58N 80W 58N 85W

58N 79W 58N 84W 58N 83W 58N 82W 58N 81W 58N 78W 58N 77W 58N 76W 58N 75W 58N 74W 58N 73W 58N 72W 58N 71W 58N 69W 58N 70W

53N 77W

10S 38E

7.5S 40E

10S 43E

7.5S 41E

10S 42E

56 1/2N 69

MT

WY

10 9

11

7 8

6

5

12

4

3

2

1

 Figure 1-5. Powder River Basin CBM Partitions.
1-6

Figure 1-6. Extent of CBM Drilling Map, Partition #4, Anderson Coal

Seam Wells
1-7

Figure 1-7. Extent of CBM Drilling Map, Partition #4, Canyon Coal

Seam Wells
1-8

Figure 1-8. Extent of CBM Drilling Map, Partition #4, Wyodak Coal

Seam Wells
1-9

1.4 Study Approach

1.4.1 Coal Resource Data Base

The Basin Study compiled available geologic data on the areal extent and thickness of the major

Fort Union Formation coals in the PRB that met the following criteria:

 • Below 300 feet of depth

 • Thicker than 20 feet

 • Sufficient data exist

For Montana, the depth and coal thickness criteria were relaxed (250 feet of depth and 15 feet of

coal thickness) to more fully capture the coal and CBM resources in this portion of the basin. 

Even so, the CBM resources of Montana are only partly defined, as insufficient data existed for

the deeper Knoblock coal zone in this portion of the basin.

A variety of data sources were used by the Basin Study, including data from the USGS,

Wyoming and Montana State offices, private data and supplemental log analysis, as set forth in

Tables 1-1 and 1-2.

The available data were assembled on a township by township basis for each of the major coal

seams in the basin. Special attention was given to assembling new data on the deep coals in the

central portion of the PRB and on the Wasatch coals along the western edge of the PRB.

1.4.2 Projecting Gas and Water Production

The coalbed methane and water production estimates in the Basin Study were developed as

follows:

The geologic model of the PRB (discussed in Chapter 2) provided the key reservoir properties of

coal seam depth, thickness, gas content, and reservoir pressure.

A gas and water production data base (discussed in Chapter 3) of over 8,000 CBM wells in the

PRB was organized by coal seam and by partition and then normalized by time (using “time

zero” plots) to provide a foundation of actual CBM well performance.

History matching of gas and water production (discussed in Chapter 3) from 1,428 PRB CBM

wells, organized into 14 distinct coal-seam and basin-partition sets, was used to establish:

 • Permeability (matrix, fracture)

 • Coal porosity (matrix, fracture)

 • Gas and water saturation 

 • Confirmation of reservoir pressure and gas content
1-10

Table 1-1. Reports and Data for Powder River CBM and Produced Water Management Study

Group File Full Description

USGS BULL 1078 Mapel, W.J., 1959, Geology and coal resources of the Buffalo-Lake de Smet area, Johnson

and Sheridan Counties, Wyoming: U.S. Geological Survey Bulletin 1078, 148 p.

USGS BULL 1917-F Nichols, D.J., and Brown, J.L., 1992, Palynostratigraphy of the Tullock Member (lower

Paleocene) of the Fort Union Formation in the Powder River Basin, Montana and Wyoming:

U.S. Geological Survey Bulletin 1917-F, 35 p., 10 pls.

USGS CI C-119-A. McLellan, M.W., and Biewick, L.H., 1988, Stratigraphic framework of the Paleocene coal beds

in the Broadus 30’ x 60’ quadrangle, Powder River Basin, Montana—Wyoming: U.S.

Geological Survey Coal Investigations Map C-119-A.

USGS CI MAP C-113 Culbertson, W.C., 1987, Diagrams showing proposed correlation and nomenclature of

Eocene and Paleocene coal beds underlying the Birney 30’ x 60’quadrangle, Big Horn,

Rosebud, and Powder River Counties: U.S. Geological Survey Coal Investigations Map

C-113.

USGS CI MAP C-2 Combo, J.X., Holmes, C.N., and Christner, H.R., 1978, Map showing the coal resources of

Montana: U.S. Geological Survey Coal Investigations Map C-2.

WGS CIR 14 Glass, G.B., 1998, Coal resources of the Powder River Basin, in, Guidebook to Coal Geology

of the Powder River Basin: Wyoming Geological Survey Information Circular no. 14, p. 97-

131.

USGS CIR 53 Combo, J.X., Brown, D.M., Pulver, H.F., and Taylor, D.A., 1949, Coal resources of Montana:

U.S. Geological Survey Circular 53, 28 p.

USGS CIR 81 Berryhill, H.L., Jr., Brown, D.M., Brown, A., and Taylor D.A., 1950, Coal resources of

Wyoming: U.S. Geological Survey Circular 81, 78 p.

WGS FIELD GUIDE Culbertson, W.C., and Mapel, W.J., 1976, Coal in the Wasatch Formation, northwest part of

the Powder River Basin near Sheridan, Sheridan County, Wyoming: Wyoming Geological

Association Guidebook 28th Annual Field Conference, p. 193-201.

WGS GUIDEBOOK Mapel, W.J., 1958, Coal in the Powder River Basin: Wyoming Geological Association

Guidebook, 13th Annual Field Conference, p. 218-224.

USGS I-1128 Law, B.E., Barnum, B.E., and Wollenzien, T.P., 1979, Coal bed correlations in the Tongue

River Member of the Fort Union Formation, Monarch, Wyoming, and Decker, Montana, areas:

U.S. Geological Survey Miscellaneous Investigations Series Map I-1128.

USGS I-1959A McLellan, M.W., Biewick, L.H., Molnia, C.L., and Pierce, F.W., 1990, Coal stratigraphy of

northern and central Powder River Basin, Montana and Wyoming: U.S. Geological Survey

Miscellaneous Investigations Series Map I-1959-A.

USGS I-1959-B Pierce, F.W., Johnson, E.A., Molnia, C.L., and Sigleo, W.R., 1990, Coal stratigraphy of the

southeastern Powder River Basin, Wyoming: U.S. Geological Survey Miscellaneous

Investigations Map I-1959-B.

USGS I-1959-C (MAP) Hardie, J.K., 1991, Coal stratigraphy of the southwestern Powder River Basin,Wyoming:

U.S. Geological Survey Miscellaneous Investigations Series Map I-1959-C.

USGS I-1959-D Molnia, Carol L., and Pierce, Frances Wahl, 1992, Cross sections showing coal stratigraphy

of the central Powder River Basin, Wyoming and Montana: U.S. Geological Survey Miscellaneous Investigations Series Map I-1959-D, scale 1:500,000. 

USGS I-2011 Pierce, F.W., and Johnson, E.A., 1991, Stratigraphic cross section showing upper Paleocene

coal-bearing rocks of the Tongue River Member of the Fort Union Formation in the Piney

Canyon NE and Piney Canyon NW quadrangles, Campbell and Weston Counties, southeastern Powder River Basin, Wyoming: U.S. Geological Survey Miscellaneous Investigations

Series Map I-2011.

USGS I-2013 Johnson, E.A., and Pierce, F.W., 1991, Stratigraphic cross section showing upper Paleocene

coal-bearing rocks of the Tongue River Member of the Fort Union Formation in the Coal Bank

Draw and Dugout Creek North quadrangles, Campbell and Weston Counties, southeastern

Powder River Basin, Wyoming: U.S. Geological Survey Miscellaneous Investigations Series

Map I-2013. 
1-11

Table 1-1. Reports and Data for Powder River CBM and Produced Water Management Study

(Continued)

Group File Full Description

USGS ISBN 1-890977-15-2 Roberts, L.N.R., Mercier, T.J., Biewick, L.R.H., and Blake, Dorsey, 1998, A procedure for

producing maps and resource tables of coals assessed during the U.S. Geological Survey's

National Coal Assessment: Fifteenth Annual International Pittsburgh Coal Conference

Proceedings, CD-ROM (ISBN 1-890977-15-2), 4 p.

USGS MF-1779 & MF-1929 Weaver, J.N., and Flores, R.M., 1985, Stratigraphic framework of the upper Fort Union

Formation at the TA Hills, Western Powder River Basin, Wyoming: U.S. Geological Survey

Miscellaneous Field Studies Map, MF1779 & MF-1929.

USGS MF-1127 & MF-1126 Flores, R.M., 1979, Restored stratigraphic cross sections and coal correlations in the Tongue

River member of the Fort Union Formation, Powder River area, Montana: U.S. Geological

Survey, Miscellaneous Field Studies Map MF-1127 & MF-1126.

USGS MF-1796 MF-1796

USGS OF 76-450 OF 76-450

USGS OF 77-283 OF 77-283

USGS OF 77-721 OF 77-721

USGS OF 79-1201 Culbertson, W.C., Kent, B.H., and Mapel, W.J., 1979, Preliminary diagrams showing correlation of coal beds in the Fort Union and Wasatch Formations across the northern Powder River

Basin, northeastern Wyoming and southeastern Montana: U.S. Geological Survey Open-File

Report 79-1201.

USGS OF 82-026 OF 82-026

USGS OF 85-621 Trent, V.A., 1985, Summary of results of the Coal Resource Occurance and Coal Development Potential Mapping Program in Part of the Powder River basin, MT & WY: U.S. Geological Survey Open-file Report 85-621,49 p.,1 pl., 2 fig., 14 tables, Scale 1:1,000,000.

USGS PP 1625-A 1999 Resource Assessment of Selected Tertiary Coal Beds and Zones in the Northern Rocky

Mountains and Great Plains Region.

WGS OF 92-4 Jones, Richard, and Glass G., 1991, Demonstrated reserve base of coal in Wyoming as of

January 1, 1991: Wyoming Geological Survey Open-File Report 92-4.

USGS OF 97-469 Molnia, C.L., Biewick, L.R.H., Blake, Dorsey, Tewalt, S.J., Carter, M.D., and Gaskill, Charlie,

1997, Coal availability in the Hilight quadrangle, Powder River Basin, Wyoming: a prototype

study in a western coal field: U.S. Geological Survey Open-File Report 97-469, 21 p.

WGS RI 35 Ayers, W.B., Jr., 1986, Coal resources of the Tongue River Member of the Fort Union

Formation (Paleocene), Powder River Basin, Wyoming and Montana: Geological Survey of

Wyoming Report of Investigations No. 35, 22 p.

WRD WRIR 85-4305 Daddow, P.B., 1986, Potentiametric-Surface map of the Wyodak-Anderson coal bed, Powder

River Structural Basin, Wyoming, 1973-84: U.S. Department of the Interior, Water Resources

Division, Water Resources Investigation Report 85-4305 (prepared in cooperation with the

Bureau of Land Management).

BLM Bureau of Land Management, 1996, Powder River Basin Coal Production—1995; N. Braz, C.

Gaskill and R. Nelson compilers, U.S. Department of the Interior, Bureau of Land Management, Casper, Wyoming, file D\drawings\wo-map.dwg.

USGS U.S. Geological Survey Global Land Information System-GLIS, 1997, digital spatial data

obtained from http://edcwww.cr.usgs.gov/glis/glis.html.

BLM www.wy.blm.gov/minerals/og/re’s.mgt/resevmgt.html
1-12

Table 1-2. Electronic Data Sources for Powder River CBM and Produced Water

Management Study

 1. Field Conference - Coalbed Methane - Powder River OF01-126

 2. http://greenwood.cr.usgs.gov/energy/coal/OF-97-469.html

 3. http://greenwood.cr.usgs.gov/pub/open-file-reports/ofr-98-0789-a/

 4. http://greenwood.cr.usgs.gov/pub/open-file-reports/ofr-98-0789-b/

 5. http://www.cbmcc.vcn.com/

 6. http://www.prb-eis.org/

 7. US Coal Quality Database

 8. http://www.deq.state.mt.us/coalbedmethane/

 9. http://www.cbmwyo.org

10. http://www.powderriverbasin.org

11. http://energy.cr.usgs.gov/oilgas/cbmethane/

12. http://deq.state.wy.us/

13. http://wogcc.state.wy.us/

14. http://www.wsgsweb.uwyo.edu/

15. http://www.wy.blm.gov/Directory/fo_map/fo_map.html

16. Rick Marvel @WYOGC rmarve@state.wy.us 307-234-7147

17. http://bogc.dnrc.state.mt.us/

Advanced Resources’ COMET3 reservoir simulator, a triple porosity and triple permeability

finite difference model, specifically developed for coalbed methane production and reserve

assessments, was used for history matching and establishing 14 “type wells” reflecting the

geologic and reservoir diversity encountered by PRB coals (discussed in Chapter 3).

The history-matched “type wells” were extended in time (using COMET3) to provide ten year

coalbed methane and water production rates and estimates of ultimate gas and water recovery

(discussed in Chapter 3).

The 14 PRB “type wells” were scaled using actual depth, thickness and gas content to develop

142 individual “type wells” to reflect average, high and low performance for each major coal

seam in each basin partition.
1-13

1.4.3 Basic Cost and Economic Model

The study constructed a Powder River Basin coalbed methane cost and economic model,

CECON (Coalbed Economics), to assess the economic feasibility of developing coalbed methane

in the basin (discussed in Chapter 4). The model includes four components: (1) basic capital

costs; (2) basic operating and maintenance costs; (3) gas transportation and compressions costs;

and (4) other costs.

The economic model incorporates forecasts for future natural gas prices (at the Henry Hub),

current and anticipated Wyoming “basin differentials,” royalties, production taxes, and other

factors that impact CBM costs and economics. The economic model is an industry standard

discounted cash flow (DCF) model that provides both an internal rate of return and the net

present value (NPV) of an investment at various discount rates and at various net gas prices.

1.4.4 Water Management Alternatives

Finally, the Basin Study examined the costs and economic feasibility of four alternatives for

CBM produced water management in the Powder River Basin. These include:

1. Untreated or passively treated produced water, with surface discharge;

2. Infiltration impoundment of the produced water, with enhanced evaporation and/or land

application;

3. Shallow re-injection of the produced water; and

4. Actively treated produced water (with reverse osmosis), with surface discharge of the

treated water and with disposal of the residual concentrate by trucking and/or deep

re-injection.

Deep re-injection of the untreated, relatively high quality CBM produced water would constitute

a loss of a valuable resource and thus was not included among the water disposal alternatives

addressed in this study.

1.5 Summary of Findings and Impacts

1.5.1 The Powder River Basin coals contain a considerably larger volume of gas in place

than established by previous studies. Major reasons for the increased PRB coalbed

methane resource in-place of 61 Tcf are: (1) the study included the deeper Fort Union

coals prevalent in the basin, it compiled new data on the Wastach coals, and it included

Montana coals; and (2) the study identified the presence of free gas in certain coal

formations and established higher gas content values for PRB coals.

1.5.2 A significant portion of the coalbed methane resource in the Powder River Basin is

technically recoverable. The estimate of 39 Tcf of technically recoverable resources is

based on reservoir modeling and the construction of 142 “type wells” representative of

the distribution in well performance (gas and water production) in the basin. This

updates earlier estimates by the Potential Gas Committee (2000) of 24 Tcf and by the

U.S. Geological Survey (2002) of 14 Tcf.
1-14

1.5.3 The costs and economic feasibility of further developing coalbed methane in the

Powder River Basin will be significantly impacted by produced water management

practices and requirements. As shown in Table 1-3, requiring active treatment of water

(such as reverse osmosis) imposes a high cost penalty, and with it, loss of economically

recoverable resources.

Table 1-3. Economically Recoverable CBM (Tcf)

Alternative Water Disposal Options

Economic Cases*

Surface

Discharge Impoundment

Shallow

Reinjection

Active

Treatment

Case 1 (Today)** 1.5 Tcf -- -- --

Case 2 (Transition)*** 22.4 Tcf 20.0 Tcf 18.8 Tcf 7.1-10.2 Tcf

Case 3 (Long Term)**** 29.1 Tcf 27.8 Tcf 27.1 Tcf 17.8-21.6 Tcf

 * Natural gas price (Henry Hub)of $3 (real) per Mcf for life of project.

 ** Basin differential remains at $1.80 per Mcf.

*** Basin differential narrows from $1.80 per Mcf in year 1 to $0.80 per Mcf in year 3 and beyond.

**** Basin differential is $0.80 per Mcf.

The distribution of economically recoverable CBM and estimated water production by mineral

ownership (using Case 2 economic conditions) is provided in Tables 1-4 and 1-5.

Table 1-4. Volumes of Economically Recoverable CBM (Tcf)

Alternative Water Disposal Options

Mineral Ownership

Surface

Discharge Impoundment

Shallow

Reinjection

Active

Treatment

Federal 13.7 Tcf 12.2 Tcf 11.5 Tcf 4.3-6.2 Tcf

State 1.5 Tcf 1.4 Tcf 1.3 Tcf 0.5-0.7 Tcf

Private 7.2 Tcf 6.4 Tcf 6.0 Tcf 2.3-3.3 Tcf

TOTAL 22.4 Tcf 20.0 Tcf 18.8 Tcf 7.1-10.2 Tcf

All mineral ownership results based on a simplified methodology using draft EIS data.
1-15

Table 1-5. Volumes of CBM Produced Water (Billion Bbls)

Alternative Water Disposal Options

Mineral Ownership

Surface

Discharge Impoundment

Shallow

Reinjection

Active

Treatment

Federal 16.6 14.6 13.8 3.7-6.5

State 1.9 1.7 1.6 0.4-0.8

Private 8.7 7.7 7.3 2.0-3.4

TOTAL 27.2* 24.0 22.7 6.1-10.7

*Approximately 5 billion barrels less water than estimated in the WY draft EIS.

1.5.4 More stringent CBM produced water management practices will lead to loss of

recoverable CBM resources for federal, state and local mineral ownership. The loss

of recoverable CBM resources by mineral ownership due to progressively more stringent

CBM produced water management practices (using Case 2 economic conditions) is

provided in Table 1-6.

Table 1-6. Loss of Economically Recoverable CBM (Tcf)

Alternative Water Disposal Options

Mineral Ownership

Surface

Discharge* Impoundment

Shallow

Reinjection

Active

Treatment

Federal (1.5 Tcf) (2.2 Tcf) (7.5-9.4 Tcf)

State (0.1 Tcf) (0.2 Tcf) (0.8-1.0 Tcf)

Private (0.8 Tcf) (1.2 Tcf) (3.9-4.9 Tcf)

TOTAL (2.4 Tcf) (3.6 Tcf) (12.2-15.3 Tcf)

* An estimated 22.4 Tcf of economically recoverable CBM resource is available under Case 2

 economic conditions and surface discharge.

1.5.5 More stringent CBM produced water management practices will reduce royalty

collections and state severance and ad valorem tax receipts. Federal, state and private

royalty payments average about $0.26/Mcf (assuming Case 2 economic conditions). The

aggregate royalty payment losses would range from $506 to $3,184 million depending on

the water management practice required, shown on Table 1-7.
1-16

Table 1-7. Loss of Mineral Royalties from CBM ($MM)

Alternative Water Disposal Options

Mineral Ownership

Surface

Discharge* Impoundment

Shallow

Reinjection

Active

Treatment

Federal ($268) ($401) ($1,349-1,687)

State ($41) ($61) ($207-$258)

Private ($197) ($294) ($991-$1,239)

TOTAL ($506) ($756) ($2,547-$3,184)

* A total of $4,659 million of mineral royalties would be collected under Case 2 economic conditions

 and surface discharge.

State severance and county ad valorem tax receipts average about $0.15/Mcf (assuming

Case 2 economic conditions and 12% (WY) and 9.3% (MT) tax rates). The aggregate tax

receipt losses range from $360 to $2,270 million depending on the water management

practices required.

1.5.6 More stringent CBM produced water management practices will lead to less capital

investment and service work in the Powder River Basin. The loss of CBM well

drilling and capital investment by mineral ownership due to more stringent CBM

produced water management practices (using Case 2 economic conditions) is provided in

Tables 1-8 and 1-9.

Table 1-8. Loss of Well Drilling for CBM (# Wells)

Alternative Water Disposal Options

Mineral Ownership

Surface

Discharge* Impoundment

Shallow

Reinjection

Active

Treatment

Federal (4,041) (6,324) (17,919-21,257)

State (464) (726) (2,056-2,439)

Private (2,120) (3,318) (9,940-11,151)

TOTAL (6,625) (10,368) (29,915-34,847)

* An estimated 46,944 wells would be drilled under Case 2 economic conditions and surface

 discharge. This represents more than 4,000 fewer wells compared to the WY draft EIS well-count 

estimate.
1-17

Table 1-9. Loss of Capital Investment for CBM ($MM)

Alternative Water Disposal Options

Mineral Ownership

Surface

Discharge* Impoundment

Shallow

Reinjection

Active

Treatment

Federal ($455) ($712) ($2,016-$2,391)

State ($52) ($82) ($231-$274)

Private ($238) ($373) ($1,058-$1,255)

TOTAL ($745) ($1,167) ($3,305-$3,920)

* The capital expenditure for PRB CBM is estimated at $5,281 million assuming Case 2 economic

 conditions and surface discharge.

1.5.7 Summary of Impacts. The loss of CBM resources, royalties and tax receipts from

more stringent CBM produced water management practices would be substantial.

Table 1-10 provides a summary of the potential losses that would occur from use of

progressively more stringent water disposal alternatives.

Table 1-10. Summary of Impacts

Water Disposal Method

Loss of CBM

Resource

Loss of CBM

Royalty

Loss of

Production/

Ad Valorem Taxes

(Tcf) ($ million) ($ million)

Surface Discharge -- -- --

Infiltration Impoundment (2.4) ($506) ($362)

Shallow Re-injection (3.6) ($756) ($540)

Reverse Osmosis/w:

• Trucking of Residual (15.3) ($3,184) ($2,272)

• Deep Disposal of Residual (12.2) ($2,547) ($1,810)

1.5.8 Improvements in coalbed methane production technology and water management

practices would help maintain the economic viability of Powder River Basin coalbed

methane. Advanced technology options offer promise for reducing costs and increasing

reserves per well. Conducting assessments of these technology options and supporting

their adaptation to PRB operating conditions would be of high value to basin operators.
2-1

Legend

Subbituminous

Bituminous

Surface Mineable Deposits

Figure 2-1. Coal Basins of Wyoming

2.0 GEOLOGIC SETTING AND RESERVOIR PROPERTIES

2.1 Basin Area

The Powder River Basin is one of a series of coal-bearing basins along the Rocky Mountains,

stretching from northern New Mexico to central Montana, Figure 2-1. The basin covers

approximately 28,500 square miles, with approximately one-half of this area underlain by

producible coals. The basin is bounded on the east by the Black Hills uplift, on the north by the

Miles City arch, on the south by the Laramide Mountains, and on the west by the Big Horn uplift

and Casper arch. 
2-2

Source: Montgomery, 1999.

Figure 2-2. Center of Powder River Basin Coalbed

Methane Activity

The bulk of coalbed methane activity to date has been in the east and central portion of the basin,

around the town of Gillette, in Campbell County, Wyoming, Figure 2-2. To date, nearly 12,000

coalbed methane wells have been drilled in the Powder River Basin, providing a wealth of data

for establishing the geologic setting and characteristics of the Wasatch and Fort Union

Formation low rank coals in this basin.

2.2 Basin Structure

The eastern flank of the Powder River Basin dips gradually at an average of 1.5o

 and is

characterized by occasional normal faulting and folding, Figure 2-3. The basinal axis exists

along the steeper western and southern margins, where the basin terminates against a complex of
2-3

Source: Blackstone (1981, 1988)

Montana

Wyoming

Figure 2-3. Regional Structure and Tectonic Map of the Powder River Basin

basement thrusts and reverse faults, as shown on the generalized cross-section of the Powder

River Basin, Figure 2-4.

2.3 Basin Stratigraphy

The Powder River Basin is filled mainly with thick Tertiary-age marine and fluvial deposits. 

The Tertiary units contain the coal bearing Fort Union and Wasatch formations that are the topic

of this Basin Study, Figure 2-5.
2-4

Source: Montgomery, 1999.

Figure 2-4. Regional Cross Section of the Powder River Basin

Source: Law, Rice and Flores, 1991 SYSTEM SERIES

STRATIGRAPHIC UNIT

Tertiary (Part)

Oligocene Eocene Paleocene

Upper

Cretaceous

(Part)

Lance

Formation (Part)

White River Formation

Wasatch

Formation

FORT UNION

FORMATION

Tongue River Member

Lebo Shale Member

Tullock Member

Figure 2-5. Upper Cretaceous and Tertiary

Stratigraphic Chart for Powder River Basin

The Tongue River Member, consisting of sandstone, conglomerate, siltstone, limestone and coal,

is the principal coal-bearing unit of the Fort Union Formation. The Tongue River Member

contains a large number of distinct coal seams, ranging from a few feet to over 200 feet in

thickness, as shown on Figure 2-6.
2-5

Figure 2-6. Coal Bearing Units of the Tongue River Member of the Fort Union Formation

The Tongue River Member can be further divided into upper and lower units. The Upper

Tongue River unit contains the Smith/Swartz, Anderson (Deitz), Canyon (Monarch), Wyodak

(where the Anderson and Canyon have merged), the Big George and the Cook (Carney) seams. 

The Lower Tongue River unit contains the Wall, Pawnee and Cache seams.
2-6

A series of Wasatch Formation coals exist on the western edge of the basin and include the

Cameron, Felix and Ucross seams. These coals coalesce into a thick coal package at Lake

Desmet.

2.4 Major Coal Seams

The coals are exposed along the eastern edge of the basin where they are surface mined. The

thickest exposed unit of coal along the east-central portion of the basin is the Wyodak seam,

containing several individual coal units. As shown on Figure 2-7, the Wyodak seam splits into

several thinner coal seams, such as the Anderson and Canyon, toward the basin center as well as

to the north and south. Figure 2-8 provides a log of the major coals of the Upper Tongue River

unit in the east-central portion of the basin.

A series of informal names have been assigned to the coals in the Powder River Basin, creating

stratigraphic uncertainty. The Basin Study strives to use a consistent set of coal seam

terminology, following the extensive stratigraphic work by Goolsby, Finley and Associates. The

distribution and correlation of the coals in the Powder River Basin is shown in Figure 2-9, an

east-west cross section of the basin. 

2.5 Key Reservoir Properties

A series of reservoir properties, including depth, coal thickness, gas content, pressure gradient

and gas saturation, were collected and assessed to calculate the gas in-place for each of the major

coals in each of the 12 basin partitions. In addition, data on coal fracture and matrix porosity

was established to calculate the volume of water in-place for each of the coals. Finally, coal

reservoir permeability (for both the cleat system and the coal matrix) was established to calculate

the amounts of recoverable methane and water.

2.5.1 Coal Seam Depth

Coal depth data from completed wells and from previous studies were used to build the coal

depth data base for the Powder River Basin. Information on the depth of individual coal seams

is provided in Chapter 6. Shown below is data on coal depth for basin Partition #4.

Table 2-1. Partition #4 Coal Depth

Coal Seam Avg. Depth (ft)* Depth Range (ft)*

Anderson 450 300-650

Canyon 540 300-800

Wyodak 600 330-750

Cook 790 600-930

Wall 1,020 800-1,250

Pawnee 1,300 1,150-1,500

Cache 1,500 1,150-1,750

* Top of coal
2-7

Source: Modified from Randall (1989)

WASATCH

FT. UNION

WYODAK

ANDERSON

(LOCAL)

CANYON

COOK

(LOCAL)

WALL

U. PAWNEE

L. PAWNEE

CACHE

0 0

15 50

30 100

61 200

122 400

PALEOCENE EOCENE

FELIX

UCROSS

Meters Feet

Figure 2-7. Simplified Representation of Fort Union Coalbeds Near Gillette, in

Campbell County, Wyoming
2-8

Canyon

Anderson

Cook Split

Cook

Not Shown:

Wall

Pawnee

Cache

Figure 2-8. Sample Log - Upper Fort Union Coals in Partition #4
2-9

Source: Law, Rice and Flores, 1991

Figure 2-9. Coal Correlation Diagram for Fort Union and Wasatch Formation, Powder

River Basin, Wyoming

2.5.2 Coal Seam Thickness

Coal seam thickness (net pay) was established for each major coal throughout the basin. Coal

interval data from completed wells, well logs from WOGCC, and coal thickness data from

previous studies (particularly the work by Goolsby, Findley and Associates and the USGS in PP

1625A) were used to build the coal thickness data base for the Powder River Basin (PRB).
2-10

Information on thickness of individual coal seams is provided in Chapter 6. Shown below is data

on coal thickness for basin Partition #4. Figure 2-10 provides a cross section showing the

complexity of coal deposition for the Wyodak group of coals along the eastern portion of the

PRB.

Table 2-2. Coal Thickness for Partition #4

Coal Seam Avg. Thickness (ft) Thickness Range (ft)

Anderson 30 20-50

Canyon 35 20-50

Wyodak 73 70-80

Cook 31 20-50

Wall 27 20-40

Pawnee 27 25-30

Cache 23 20-30

2.5.3 Regional Pressure Gradient

A regional pressure gradient versus depth function for PRB coal seams, Figure 2-11, was

constructed to establish reservoir pressure for each of the coal formations. This was assembled

using:

 • Detailed hydrology data and pressure mapping by the Wyoming BLM,

 • Actual pressure data from basin producers, and 

 • History matching (using COMET3) of the pressure gradient data using long-term (4+

year) gas and water production data in the PRB.

The regional pressure gradient function shows that the shallower coals are significantly

underpressured and approach normal hydrostatic pressures as the coals become deeper,

Figure 2-12.

2.5.4 Gas Content

The Basin Study assembled available gas content data and adsorption isotherms, appropriate for

the low rank coals of the PRB, from the following sources:

 • Past gas content data collected by the BLM and published gas content and isotherm data

by industry and the USGS,

 • Advanced Resources’ own gas content and isotherm data collected for analogous low

rank coals in other basins, and

 • History matching (using COMET3) of alternative isotherms using long-term (4+year) gas

and water production data in the PRB.
2-11

Source: Rice (2000)

Figure 2-10. Cross-Section Showing Lateral Variation of Coalbeds in the Wyodak

Coal Zone

Source: Data from BLM files and CBM operators. Data from water monitor and CBM wells.

Depth to Top of Coal and Original Hydrostatic Pressure

Original Hydrostatic Pressure – psig

Depth to Top of Coal -- feet

0

300

400

500

600

0 400 800 1200

200

100

1600

Y = 0.3405x – 48.265

R2 = 0.901

Figure 2-11. Regional Pressure Gradient
2-12

0

100

200

300

400

500

600

700

800

900

1000

1100

400 600 800 1,000 1,200 1,400 1,600 1,800 2,000 2,200 2,400

Well Depth, ft./ (Pressure Gradient, psia/ft.)

Reservoir Pressure, psia

JAF2002049.XLS

Depth

Pressure

Gradient

(0.260) (0.315) (0.370) (0.435)

Figure 2-12. Reservoir Pressure Profile Used for PRB Study

The best fit coalbed methane isotherm was from actual gas content and isotherm data collected

on an analogous overseas low rank coal basin, Figure 2-13. As a point of comparison, Figure 2-14 provides the average synthesized adsorption isotherm for coal in the PRB assembled

from older data.

2.5.5 Gas Saturation

The nature of early time water and gas production was used to establish whether the PRB coals

were undersaturated, fully saturated or contained free gas in the pore space:

 • A series of fourteen individual coal seams and partition data sets, shown on Table 2-1,

were assembled involving gas and water production data from over 1,400 PRB CBM

wells.

 • History matching (using COMET3) of production data was used to establish the level of

gas saturation and presence of free gas in the coal cleat and matrix system.
2-13

Figure 2-13. Gas Content Isotherm Used for Powder River Coalbed Methane

Figure 2-14. Average Synthesized Adsorption Isotherm for 41 Coal Samples From

the PRB, Based on a Compilation of Data From Public and Private Sources
2-14

Overall, the study established that the coals are fully saturated with methane (at the reduced

reservoir pressure conditions that generally exist in the basin) and that modest amounts of free

gas exist in the matrix porosity and coal cleat (fracture) porosity systems in certain

seam/partition data sets. However, operators report that low gas contents and severe

undersaturation conditions may exist for certain deeper coals in the portions of the basin, south

of Gillette. Collection and analysis of additional gas content data would help define their

potential problem areas and seams in the basin.

Further discussion of the topics of gas content and gas saturation in the Powder River Basin is

provided as Appendix A.

2.5.6 Coal Fracture and Matrix Porosity

History matching of water production was used to estimate the fracture and matrix porosity for

the PRB coals:

1. In general, the coal cleat (fracture) porosity in the coals ranges from 0.1% to 1%,

consistent with other data (The Big George coal in Partition #5 has an apparently higher

than usual fracture porosity).

2. The matrix porosity for these low rank coals varies widely, ranging from 1% to 10%. 

Matrix porosity tends to increase for the deeper coals, such as the Wall, Pawnee, and

Cache.

High coal matrix porosities would support the relatively high water production from otherwise 

thinner (25 to 30 feet) coal seams, such as the Wall. As an alternative explanation, some

investigators have put forward the concept of aquifers in the Fort Union Formation as providing

and supporting the high water production observed from PRB coals.

Some amount of water influx or aquifer leakage from associated sands no doubt exists in some

portions of the basin. However, our assessment is that porosity in these low rank coals is the

primary source of the produced water and that aquifer recharge, if and where it does exist, is

relatively modest for the following reasons:

 • First, high matrix porosity values have been documented for other low rank coals (such

as the overseas low rank coal used for the gas sorption isotherm, discussed above). 

Seidle (2002), in his review of selected coalbed methane pilots, cites a value of 10% for

the porosity of the Wyodak coal at the Rawhide Butte Field of the Powder River Basin. 

Cox (2000), in his assessment of aquifer controls on CBM in the PRB, used 5% for the

Anderson-Wyodak coal.

 • Second, the water production rates in the coalbed methane wells along the maturely

developed eastern portion of the Powder River Basin (such as the Canyon coal wells

Partition #4) have declined to about 20 to 30 barrels per day at the end of 3 years from

about 300 barrels per day during year 1. And, some coal wells in the area have stopped

producing any appreciable water. If aquifer leakage is occurring in this area, it would

have to be low.
2-15

 • Third, the pressure response and gas desorption rates would be considerably different for

water held in coal porosity versus water influx from aquifer leakage. The assessment of

gas production by reservoir simulation tended to support the coal matrix as the primary

source of the produced water, although separating porosity source water from low levels

of aquifer leakage would be difficult to establish.

2.5.7 Coal Permeability

In general, the coal cleat (fracture) permeability of PRB coals is favorable, ranging from 35 to

500 md. Coal matrix permeabilities are considerably lower and variable, ranging from 0.001 to

1.0 md. However, even the lower end of the range for cleat and matrix permeabilities for the

coals in the PRB is sufficient to support reasonable gas recoveries (in 10 years) of 50 to 80+% of

the gas in-place.

2.6 Summary of Reservoir Properties

Table 2-4 provides a summary of the key reservoir properties established from the geologic

study and history matching of 14 sets of coalbed methane data representing the combined well

performance of 1,428 coalbed methane wells in the Powder River Basin. Additional information

on individual coal seam reservoir properties is provided in Chapter 6. 

Shown below is the average derived data on coal seam gas content, pressure, gas saturation and

porosity for basin Partition #4.

Table 2-3. Average Data for Partition #4

Coal

Seam

Gas

Content

Pressure

(Top of

Coal)

Free Gas Saturation Porosity

Fracture Matrix Fracture Matrix

(cf/t) (psi) (%) (%) (%) (%)

Anderson 40 141 8 10 0.2 1.5

Canyon 47 171 7 7 0.4 3.0

Wyodak 54 199 5 10 1.0 6.0

Cook* 67 257 0 1 0.1 2.4

Wall 84 340 0 0 1.0 10.0

Pawnee** 106 460 0 0 0.5 5.0

Cache** 121 558 0 0 0.5 5.0

* Based on extrapolation from history-matched Cook coal seam in Partition #8.

** Based on extrapolation from history-matched Pawnee coal seam in Partition #8.
Seam Part Area # of Wells Depth (Top) (ft) Thickness (ft) Spacing (A/w) Pressure (top) (psi) Gas Content (cf/cf) Gas Content (cf/ton)

Big G 3 T43-44N 74W 38 1,000 67.5 80 335 3.58 86 Anderson 4 T51N 73W 89 500 20.0 80 150 1.79 43 

Wyodak 4 T47-48 R72 159 541 78.0 40 163 2.73 65 Canyon 4 T52-51 R73 172 625 37.5 80 186 2.19 52 Wall 4 T52N 73W 19 800 25.0 80 255 2.82 67 Big G* 5 1 WELL 1 1,260 150.0 80 451 4.33 104 Smith 5 AVG 10 640 30.0 80 197 2.29 55 

Anderson 8 T54 R76-77 261 650 52.5 80 200 1.80 43 

Wall 8 AVG 107 963 30.0 80 300 3.22 77 

Pawnee 8 AVG 19 1,055 33.0 80 358 3.70 89 

Cook 8 T55N 75-76W 134 752 55.0 80 237 2.71 65 

Anderson-Dietz 11 T57N R83-84W 191 650.0 22.5 80 200 2.30 55 Canyon-Monarch 11 T57N R83-84W 147 930.0 20.0 80 306 3.25 78 Cook-Carney 11 T57N R83-84W 65 1,050.0 30.0 80 356 3.68 88 

Smith 5 AVG 10 640 30.0 80 197 2.29 55 

Anderson 4 T51N 73W 89 500 20.0 80 150 1.79 43 Anderson 8 T54 R76-77 261 650 52.5 80 200 1.80 43 Anderson-Dietz 11 T57N R83-84W 191 650 22.5 80 200 2.30 55 Canyon 4 T52-51 R73 172 625 37.5 80 186 2.19 52 Canyon-Monarch 11 T57N R83-84W 147 930 20.0 80 306 3.25 78 Wyodak 4 T47-48 R72 159 541 78.0 40 163 2.73 65 Big G 3 T43-44N 74W 38 1,000 67.5 80 335 3.58 86 Big G* 5 1 WELL 1 1,260 150.0 80 451 4.33 104 

Cook 8 T55N 75-76W 134 752 55.0 80 237 2.71 65 Cook-Carney 11 T57N R83-84W 65 1,050 30.0 80 356 3.68 88 

Wall 4 T52N 73W 19 800 25.0 80 255 2.82 67 Wall 8 AVG 107 963 30.0 80 300 3.22 77 

Pawnee 8 AVG 19 1,055 33.0 80 358 3.70 89 

* (17 wells modeled)

f mfm f m

0.002 0.040 1.00 1.00 35.0 0.002 0.002 0.015 0.92 0.90 225.0 1.000 0.010 0.060 0.95 0.90 500.0 1.000 0.004 0.030 0.93 0.93 200.0 1.000 0.010 0.100 1.00 1.00 100.0 0.100 0.010 0.100 1.00 1.00 250.0 0.001 0.001 0.011 1.00 1.00 45.0 0.010 0.002 0.015 1.00 0.78 175.0 0.001 0.010 0.095 1.00 1.00 42.0 1.000 0.005 0.050 1.00 1.00 125.0 1.000 0.001 0.024 1.00 0.99 50.0 0.100 0.005 0.025 0.98 0.98 450.0 1.000 0.005 0.095 0.98 0.98 275.0 1.000 0.010 0.080 0.99 0.99 150.0 1.000 0.001 0.011 1.00 1.00 45.0 0.010 0.002 0.015 0.92 0.90 225.0 1.000 0.002 0.015 1.00 0.78 175.0 0.001 0.005 0.025 0.98 0.98 450.0 1.000 0.004 0.030 0.93 0.93 200.0 1.000 0.005 0.095 0.98 0.98 275.0 1.000 0.010 0.060 0.95 0.90 500.0 1.000 0.002 0.040 1.00 1.00 35.0 0.002 0.010 0.100 1.00 1.00 250.0 0.001 0.001 0.024 1.00 0.99 50.0 0.100 0.010 0.080 0.99 0.99 150.0 1.000 0.010 0.100 1.00 1.00 100.0 0.100 0.010 0.095 1.00 1.00 42.0 1.000 0.005 0.050 1.00 1.00 125.0 1.000 

Permeability (md) Water Saturation Porosity

Seam Part Area # of Wells Depth (Top) (ft) Thickness (ft) Spacing (A/w) Pressure (top) (psi) Gas Content (cf/cf) Gas Content (cf/ton)

Big G 3 T43-44N 74W 38 1,000 67.5 80 335 3.58 86 Anderson 4 T51N 73W 89 500 20.0 80 150 1.79 43 

Wyodak 4 T47-48 R72 159 541 78.0 40 163 2.73 65 Canyon 4 T52-51 R73 172 625 37.5 80 186 2.19 52 Wall 4 T52N 73W 19 800 25.0 80 255 2.82 67 Big G* 5 1 WELL 1 1,260 150.0 80 451 4.33 104 Smith 5 AVG 10 640 30.0 80 197 2.29 55 

Anderson 8 T54 R76-77 261 650 52.5 80 200 1.80 43 

Wall 8 AVG 107 963 30.0 80 300 3.22 77 

Pawnee 8 AVG 19 1,055 33.0 80 358 3.70 89 

Cook 8 T55N 75-76W 134 752 55.0 80 237 2.71 65 

Anderson-Dietz 11 T57N R83-84W 191 650.0 22.5 80 200 2.30 55 

Canyon-Monarch 11 T57N R83-84W 147 930.0 20.0 80 306 3.25 78 Cook-Carney 11 T57N R83-84W 65 1,050.0 30.0 80 356 3.68 88 

Smith 5 AVG 10 640 30.0 80 197 2.29 55 

Anderson 4 T51N 73W 89 500 20.0 80 150 1.79 43 Anderson 8 T54 R76-77 261 650 52.5 80 200 1.80 43 Anderson-Dietz 11 T57N R83-84W 191 650 22.5 80 200 2.30 55 

Canyon 4 T52-51 R73 172 625 37.5 80 186 2.19 52 Canyon-Monarch 11 T57N R83-84W 147 930 20.0 80 306 3.25 78 Wyodak 4 T47-48 R72 159 541 78.0 40 163 2.73 65 Big G 3 T43-44N 74W 38 1,000 67.5 80 335 3.58 86 Big G* 5 1 WELL 1 1,260 150.0 80 451 4.33 104 Cook 8 T55N 75-76W 134 752 55.0 80 237 2.71 65 Cook-Carney 11 T57N R83-84W 65 1,050 30.0 80 356 3.68 88 

Wall 4 T52N 73W 19 800 25.0 80 255 2.82 67 Wall 8 AVG 107 963 30.0 80 300 3.22 77 

Pawnee 8 AVG 19 1,055 33.0 80 358 3.70 89 

* (17 wells modeled)

f mfm f m

0.002 0.040 1.00 1.00 35.0 0.002 0.002 0.015 0.92 0.90 225.0 1.000 0.010 0.060 0.95 0.90 500.0 1.000 0.004 0.030 0.93 0.93 200.0 1.000 0.010 0.100 1.00 1.00 100.0 0.100 0.010 0.100 1.00 1.00 250.0 0.001 0.001 0.011 1.00 1.00 45.0 0.010 0.002 0.015 1.00 0.78 175.0 0.001 0.010 0.095 1.00 1.00 42.0 1.000 0.005 0.050 1.00 1.00 125.0 1.000 0.001 0.024 1.00 0.99 50.0 0.100 0.005 0.025 0.98 0.98 450.0 1.000 0.005 0.095 0.98 0.98 275.0 1.000 0.010 0.080 0.99 0.99 150.0 1.000 0.001 0.011 1.00 1.00 45.0 0.010 0.002 0.015 0.92 0.90 225.0 1.000 0.002 0.015 1.00 0.78 175.0 0.001 0.005 0.025 0.98 0.98 450.0 1.000 0.004 0.030 0.93 0.93 200.0 1.000 0.005 0.095 0.98 0.98 275.0 1.000 0.010 0.060 0.95 0.90 500.0 1.000 0.002 0.040 1.00 1.00 35.0 0.002 0.010 0.100 1.00 1.00 250.0 0.001 0.001 0.024 1.00 0.99 50.0 0.100 0.010 0.080 0.99 0.99 150.0 1.000 0.010 0.100 1.00 1.00 100.0 0.100 0.010 0.095 1.00 1.00 42.0 1.000 0.005 0.050 1.00 1.00 125.0 1.000 

Permeability (md) Water Saturation Porosity

2-16

Table 2-4. Key Reservoir Properties for Powder River Basin Coals
3-1

3.0 COALBED METHANE RESOURCES

3.1 Summary

The Powder River Coalbed Methane Basin Study estimates 61 Tcf of natural gas in-place, with

39 Tcf of this gas in-place being technically recoverable. The two reasons for the increased PRB

coalbed methane resource in-place of 61 Tcf in this Basin Study are:

 • Larger Coal Volume Data Base. The study includes extensive information on the deeper

Fort Union coals prevalent in the basin; it compiles new data on the Wasatch coals on the

western edge of the basin; and, it includes the shallower coals in the Montana portion of

the PRB (although insufficient data was available for including the deeper Knoblock coal

zone in the Montana portion of the PRB).

 • Free Gas and Higher Gas Contents. The study identifies the presence of free gas in

certain coal formations and establishes higher inherent gas content values for PRB coals

than used by previous studies, both increasing the gas in-place over previous estimates.

The estimate of technically recoverable resources of 39 Tcf is based on reservoir simulation of

1,428 individual wells assembled into 14 history-matched “time zero” well clusters. These

simulations are used to construct 142 “type wells” representative of the distribution in well

performance (gas and water production) for 12 distinct coal seams in 12 basin partitions.

3.2 Coalbed Methane Resources

3.2.1 Gas In-Place

The distribution of the 61 Tcf of gas in-place ranges widely by basin partition and by coal seam:

 • Basin Partition #5, in the center of the PRB, and where all of the major coal seams are

present at favorable depths, holds over 25 Tcf of gas in-place.

 • The Big George coal seam, that has extensive thickness in the southern and central

portions of the PRB, holds over 14 Tcf of gas in-place, followed by the Canyon coal

seam with nearly 9 Tcf of gas in-place.

Table 3-1 provides the partition and seam level tabulation for the coalbed methane gas in-place

for the major coals in the Powder River Basin. (The Knoblock and other deeper coal seams are

not included in these estimates.)
3-2

Table 3-1. Gas In-Place for Major PRB Coal Seams (Bcf)

Even with the extensive and detailed coal seam and township level mapping of the PRB coals,

considerable uncertainty still remains in these resource estimates.

 • First, only partial data exist on the volumes and location of the deep coals, because few

wells have been drilled in the deeper portions of the basin. (New information would tend

to increase the size of the in-place resource.)

 • Second, localized areas of the basin may have encountered degassing of the coals. While

this regional analysis indicates fully gas-charged coals, localized degassing of coals has

been reported in other CBM basins. (Here, new information would tend to decrease the

size of the in-place resource.)

 • Third, coal seams with thickness of less than 20 feet are excluded from the resource

estimate.

 • Finally, considerable judgement is used in assigning a “name” to a particular coal seam,

particularly where the Wyodak coal splits into sub-seams such as the Anderson and

Canyon, which are major seams on their own. (Here, new information would shift the

volume of resource among the seam, but would not appreciably affect the overall

estimate.)

3.2.2 Technically Recoverable Resources

The distribution of the 39 Tcf of technically recoverable resources is shown on Table 3-2. 

Several insights emerge from the tabulation of data and reservoir simulation-based history

matching of the well performance:
3-3

 • Recovery Efficiency With Depth. Recovery efficiency of the gas in-place does not

decline as severely as conventionally assumed for the deeper coals. Higher coal reservoir

pressure and more favorable gas content tends to partially counter-balance the reduction

in coal permeability. Even so, the technical recovery efficiencies for certain of the

deeper coals still only range from 50 to 60% of the gas in-place.

 • Presence of Free Gas. The upper group of Fort Union coals, including the Anderson,

Canyon and Wyodak, tend to have early gas production due to the presence of free gas

within the coal cleat (fracture) system and in the coal matrix porosity. In addition to

increasing the resource in place, the presence of free gas promotes improved relative

permeability to gas and an earlier peak in gas production.

 • Well Spacing. Where the coals have higher permeability and free gas, wells drilled on 40

to 80 acre spacings produce the bulk of their economically recoverable gas relatively

quickly, in 6 to 7 years.

Table 3-2. Technically Recoverable Resources for Major PRB Coal Seams (Bcf)

3.3 In-Place and Technically Recoverable PRB CBM Resources, by Basin Partition

Tables 3-3 through 3-11 provide additional detail on in-place and technically recoverable PRB

coalbed methane by basin partition. These tables display the areal extent (number of townships),

depth, coal thicknesses, and gas content used to establish the gas in-place for each major coal

seam. The tables also provide estimates of technically recoverable CBM resources by coal seam.
3-4

Table 3-3. In-Place and Technically Recoverable CBM, Partitions #1 and #2

Coal Seam No. Full

Townships

Average

Depth

(ft)*

Average

Thickness

(ft)

Average

Gas

Content

(cf/ton)

Gas in

Place

(Bcf)

Technically

Recoverable

(Bcf)

Anderson 1 450 25 39 40 30

Canyon 2 575 48 51 210 180

Wyodak 5 440 86 42 760 560

Big George 2 863 90 86 550 320

Cook 2 740 30 65 150 120

Pawnee 5 1,336 22 108 470 420

Totals 2,170 1,630

* Top of coal

Table 3-4. In-Place and Technically Recoverable CBM, Partitions #3 and #12

Coal Seam No. Full

Townships

Average

Depth

(ft)*

Average

Thickness

(ft)

Average

Gas Content

(cf/ton)

Gas in

Place

(Bcf)

Technically

Recoverable

(Bcf)

Anderson 1 800 55 70 160 110

Canyon 9 970 43 81 1,260 870

Big George 11 1,280 100 107 6,620 2,910

Cook 2 1,030 30 86 210 170

Totals 8,250 4,060

* Top of coal
3-5

Table 3-5. In-Place and Technically Recoverable CBM, Partition #4

Coal Seam No. Full

Townships

Average

Depth

(ft)*

Average

Thickness

(ft)

Average

Gas Content

(cf/ton)

Gas In 

Place

(Bcf)

Technically

Recoverable

(Bcf)

Anderson 6 450 30 40 400 290

Canyon 12 540 35 47 920 800

Wyodak 6 601 73 54 890 770

Cook 5 790 31 67 450 350

Wall 5 1,020 27 84 440 350

Pawnee 5 1,295 27 106 570 510

Cache 5 1,550 23 121 540 480

Totals 44 4,210 3,550

* To top of coal

Table 3-6. In-Place and Technically Recoverable CBM, Partition #5

Coal Seam No. Full

Townships

Average

Depth

(ft)*

Average

Thickness

(ft)

Average

Gas Content

(cf/ton)

Gas In

Place

(Bcf)

Technically

Recoverable

(Bcf)

Felix 4 530 24 46 180 140

Roland 2 540 25 47 100 80

Smith 18 820 39 70 2,310 1,560

Swartz 2 740 43 63 220 180

Anderson 9 1030 38 86 1,180 830

Canyon 16 1060 39 88 2,320 1,500

Big George 16 1280 97 107 6,760 3,510

Wyodak 2 1000 73 85 250 210

Cook 17 1320 40 109 3,060 1,810

Wall 16 1500 32 120 2,250 1,350

Pawnee 18 1710 41 137 4,000 2,320

Cache 14 2020 32 159 2,700 1,320

Wildcat 1 2190 45 101 180 90

Totals 25,510 14,910

* To top of coal
3-6

Table 3-7. In-Place and Technically Recoverable CBM, Partition #6

Coal Seam No. Full

Townships

Average

Depth

(ft)*

Average

Thickness

(ft)

Average

Gas Content

(cf/ton)

Gas In

Place

(Bcf)

Technically

Recoverable

(Bcf)

Cameron 1 700 20 60 50 40

Felix 1 750 30 63 140 110

Murry 1 800 50 69 80 60

Ucross 3 790 23 66 190 150

Roland 5 1,060 21 86 370 240

Anderson 3 1,220 30 99 370 220

Canyon 8 1,520 30 123 1,090 660

Big George 2 1,670 85 136 930 490

Cook 2 1,860 58 147 690 380

Wall 1 1,630 40 130 200 110

Pawnee 4 2,000 44 158 1,270 620

Wildcat 4 2,640 25 191 760 370

Totals 6,150 3,460

* To top of coal

Table 3-8. In-Place and Technically Recoverable CBM, Partition #7

Coal Seam No. Full

Townships

Average

Depth

(ft)*

Average

Thickness

(ft)

Average

Gas Content

(cf/ton)

Gas In

Place

(Bcf)

Technically

Recoverable

(Bcf)

Wasatch 6 540 25 47 290 230

Roland 3 820 27 70 250 200

Smith 2 1,180 20 96 160 90

Anderson 5 910 21 75 320 230

Canyon 2 1,500 25 120 250 150

Cook 2 2,300 28 178 400 210

Wall 1 2,500 30 186 210 100

Pawnee 1 2,050 40 160 250 140

Cache 3 2,623 30 190 680 330

Totals 2,820 1,680

* To top of coal
3-7

Table 3-9. In-Place and Technically Recoverable CBM, Partition #8

Coal Seam No. Full

Townships

Average

Depth

(ft)*

Average

Thickness

(ft)

Average

Gas Content

(cf/ton)

Gas In 

Place

(Bcf)

Technically

Recoverable

(Bcf)

Smith 8 430 33 38 380 300

Swartz 2 580 21 49 90 70

Anderson 9 600 35 51 750 530

Canyon 19 620 37 54 1,810 1,560

Cook 22 730 39 62 2,280 1,800

Wall 21 960 30 80 1,890 1,230

Pawnee 11 1,060 33 87 1,200 1,070

Cache 4 1,550 27 123 490 290

Oedekoven 2 2,560 20 188 300 170

Totals 9,190 7,020

* To top of coal

Table 3-10. In-Place and Technically Recoverable CBM, Partitions #9 and #10

Coal Seam No. Full

Townships

Average

Depth

(ft)*

Average

Thickness

(ft)

Average

Gas Content

(cf/ton)

Gas in

Place

(Bcf)

Technically

Recoverable

(Bcf)

Deitz 

(Anderson) 2 250 49 25 100 90

Monarch

(Canyon) 7 470 24 41 280 250

Carney

(Cook) 7 650 23 55 380 330

Pawnee 3 1,080 20 88 210 190

Totals 970 860

* Top of coal
3-8

Table 3-11. In-Place and Technically Recoverable CBM, Partitions #11

Coal Seam No. Full

Townships

Average

Depth

(ft)*

Average

Thickness

(ft)

Average

Gas Content

(cf/ton)

Gas in

Place

(Bcf)

Technically

Recoverable

(Bcf)

Deitz #1

(Anderson) 5 910 24 75 510 450

Dietz #2 5 680 24 58 330 290

Dietz #3 6 1,030 22 84 390 340

Monarch

(Canyon) 8 1,070 24 88 640 570

Carney

(Cook) 3 1,030 23 84 220 190

Totals 2,090 1,850

* Top of coal

3.4 Estimating Gas and Water Production

The gas and water production estimates for the study were developed using the following six

steps:

1. Geologic Model. The geologic model (discussed above) provided the key reservoir

properties of coal seam depth, thickness, gas content and reservoir pressure.

2. Well Performance. The gas and water production data base (starting with over 8,000

CBM wells in the PRB) was organized by coal seam and by partition and then

normalized by time (using “time zero” plots) to provide a foundation of actual CBM well

performance. For example, Figure 3-1 provides the “time-zero” plot for “on average”

wells completed in the Wyodak coal seam in a 2-township area of Partition #4. (See

Section 6.4 for further discussion.)

3. History Matching. History matching of gas and water production (from 1,428 PRB CBM

wells, organized into 14 distinct coal seam and basin partition sets (shown on Table 3-12)

was used to establish:

 • Permeability (matrix, fracture)

 • Coal porosity (matrix, fracture)

 • Gas and water saturation

 • Confirmation of reservoir pressure and gas content

For example, Figure 3-2 provides the gas and water production history match for the

“average” well completed in the Wyodak coal seam in the 2-township area of Partition #4, shown in Figure 3-1. (See Section 6.4 for further discussion.). Table 3-13

summarizes the reservoir properties and expected gas and water recoveries for the 14 sets

of history-matched PRB coalbed methane wells.
3-9

Time Zero Plot f or an Average Well

0

5,000

1 0,000

1 5,000

20,000

25,000

0 5 1 0 1 5 20 25 30 35 40 45

T i me (M onths)

0

20

40

60

80

1 00

1 20

1 40

1 60

1 80

GAS

WATER

Well Count

Figure 3-1. Wyodak Coal Seam Time Zero Plot

1 Intensely drilled township area.

2 Time zero well in partition.

3 All Big George wells in Sec. 16, 48N 77W.

4 Includes partitions with significant numbers of CBM wells, with sufficient production data for history matching.

192 Pawnee

1072 19 Wall 1

651 134 Cook 1

173 38 Big George 1

159 Wyodak 1

1471 172 Canyon 1

1911 2611 89 Anderson 1

102 Smith

3 4 5 8 11

Partitions 4

Coal Seam

Table 3-12. Number and Nature of CBM Wells for History Matching
3-10

700

650

600

550

500

450

400

350

300

250

200

150

100

50

0

0 250 500 750 1,000 1,250 1,500 1,750 2,000 2,250 2,500 2,750 3,000 3,250 3,500 3,750

Actual

Water Rate

Actual

Gas Rate

Actual Cum Water

Actual Cum Gas

700

650

600

550

500

450

400

350

300

250

200

150

100

50

0

Gas and Water Production Rate (Mcfd; Bwpd)

Cumulative Gas and Water Recovery (MMcf; Mbw)

Days On

Figure 3-2. Wyodak Type Well History Match

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

B C D E F G H I J K L M N O PQ R

Seam Part Area # of 

Wells

Depth 

(Top) ft

Thickness 

(ft)

Spacing 

(A/W)

Pressure 

(top) psi

Pressure 

Gradient, 

psi/ft

 Comparison 

to Regional 

Prs Grad 

Gas 

Content 

(cf/cf)

Gas 

Content 

(cf/ton)

Porosity 

f

Porosity 

m Sw - f Sw - m Perm (md) -f

Big G 3 T43-44N 74W 38 1,000 67.5 80 335 0.320 Same 3.58 86 0.002 0.040 1.00 1.00 35.0 

Anderson 4 T51N 73W 89 500 20.0 80 150 0.270 Same 1.79 43 0.002 0.015 0.92 0.90 225.0 

Wyodak 4 T47-48 R72 159 541 78.0 40 163 0.274 Same 2.73 65 0.010 0.060 0.95 0.90 500.0 

Canyon 4 T52-51 R73 172 625 37.5 80 186 0.273 Same 2.19 52 0.004 0.030 0.93 0.93 200.0 

Wall 4 T52N 73W 19 800 25.0 80 255 0.300 Same 2.82 67 0.010 0.100 1.00 1.00 100.0 

Big G 5 1 WELL 1 1,260 150.0 80 451 0.346 Same 4.33 104 0.010 0.100 1.00 1.00 250.0 

Smith 5 AVG 10 640 30.0 80 197 0.284 Same 2.29 55 0.001 0.011 1.00 1.00 45.0 

Anderson 8 T54 R76-77 261 650 52.5 80 200 0.285 Same 1.80 43 0.002 0.015 1.00 0.78 175.0 

Wall 8 AVG 107 963 30.0 80 300 0.296 Lower 3.22 77 0.010 0.095 1.00 1.00 42.0 

Pawnee 8 AVG 19 1,055 33.0 80 358 0.325 Same 3.70 89 0.005 0.050 1.00 1.00 125.0 

Cook 8 T55N 75-76W 134 752 55.0 80 237 0.295 Same 2.71 65 0.001 0.024 1.00 0.99 50.0 

Anderson-Dietz 11 T57N R83-84W 191 650.0 22.5 80 200 0.285 Same 2.30 55 0.005 0.025 0.98 0.98 450.0 

Canyon-Monarch 11 T57N R83-84W 147 930.0 20.0 80 306 0.313 Same 3.25 78 0.005 0.095 0.98 0.98 275.0 

Cook-Carney 11 T57N R83-84W 65 1,050.0 30.0 80 356 0.325 Same 3.68 88 0.010 0.080 0.99 0.99 150.0 

Anderson 4 T51N 73W 89 500 20.0 80 150 0.270 Same 1.79 43 0.002 0.015 0.92 0.90 225.0 

Anderson 8 T54 R76-77 261 650 52.5 80 200 0.285 Same 1.80 43 0.002 0.015 1.00 0.78 175.0 

Anderson-Dietz 11 T57N R83-84W 191 650 22.5 80 200 0.285 Same 2.30 55 0.005 0.025 0.98 0.98 450.0 

Big G 3 T43-44N 74W 38 1,000 67.5 80 335 0.320 Same 3.58 86 0.002 0.040 1.00 1.00 35.0 

Big G 5 1 WELL 1 1,260 150.0 80 451 0.346 Same 4.33 104 0.010 0.100 1.00 1.00 250.0 

Canyon 4 T52-51 R73 172 625 37.5 80 186 0.273 Same 2.19 52 0.004 0.030 0.93 0.93 200.0 

Canyon-Monarch 11 T57N R83-84W 147 930 20.0 80 306 0.313 Same 3.25 78 0.005 0.095 0.98 0.98 275.0 

Cook 8 T55N 75-76W 134 752 55.0 80 237 0.295 Same 2.71 65 0.001 0.024 1.00 0.99 50.0 

Cook-Carney 11 T57N R83-84W 65 1,050 30.0 80 356 0.325 Same 3.68 88 0.010 0.080 0.99 0.99 150.0 

Pawnee 8 AVG 19 1,055 33.0 80 358 0.325 Same 3.70 89 0.005 0.050 1.00 1.00 125.0 

Smith 5 AVG 10 640 30.0 80 197 0.284 Same 2.29 55 0.001 0.011 1.00 1.00 45.0 

Wall 4 T52N 73W 19 800 25.0 80 255 0.300 Same 2.82 67 0.010 0.100 1.00 1.00 100.0 

Wall 8 AVG 107 963 30.0 80 300 0.296 Lower 3.22 77 0.010 0.095 1.00 1.00 42.0 

Wyodak 4 T47-48 R72 159 541 78.0 40 163 0.274 Same 2.73 65 0.010 0.060 0.95 0.90 500.0 

Table 3-13. Summary Results for PRB Coalbed Methane History Matching
3-11

Gas and Water Production Rate (Mcfd; Bwpd)

Cumulative Gas and Water Recovery (MMcf; Mbw)

Days On

700

650

600

550

500

450

400

350

300

250

200

150

100

50

0

700

650

600

550

500

450

400

350

300

250

200

150

100

50

0 0 250 500 750 1,000 1,250 1,500 1,750 2,000 2,250 2,500 2,750 3,000 3,250 3,500 3,750

Actual

Water Rate

Actual

Gas Rate

Actual/Projected

Cum Water

Actual/Projected

Cum Gas

Figure 3-3. 10-Year Simulation of Gas and Water Production for

Wyodak Type Well

4. Reservoir Simulation. Advanced Resources’ COMET3 reservoir simulator, a triple

porosity and triple permeability finite difference model specifically developed for

coalbed methane production and reserve assessments, was used for history matching and

establishing 14 “type wells” reflecting the geologic and reservoir diversity encountered in

PRB coals.

5. Production Forecast. The history-matched “type wells” were extended in time (using

COMET3) to provide 10-year gas and water rates and estimates of ultimate recovery. 

For example, Figure 3-3 provides the 10-year reservoir simulation-based forecast for gas

and water production for the Wyodak type well in Partition #4, as presented previously in

Figures 3-1 and 3-2.

6. Type Wells. The 14 PRB “type wells” were scaled using actual depth, thickness and gas

content to develop 142 individual “type wells” to reflect average, high and low performance for each major coal seam in each basin partition, shown on Table 3-14. For

example, the history-matched set of 89 Anderson wells in T51N T3W of Partition #4

(shown previously on Table 3-13), with a coal thickness of 20 feet, were scaled to

represent the average 30 foot coal thickness “type well” for the Anderson coal seam in

Partition #4 (as shown in Table 3-5). The expected average, high and low well

performance was based primarily on the variability in coal thickness in the partition. The

average well represents the average coal thickness (and other reservoir properties) value

and the low and high wells represent the lowest and highest 25% of the coal thickness in

the townships of the partition.
3-12

12 Oedekoven* 1 1

11 Cache 3 3 1 3 10

2 Roland 1 1 3 5

TOTAL 9 8 21 28 16 14 23 8 15 142

10 Pawnee 1 3 3 3 1 3 1 15

9 Wall 3 3 1 1 3 11

8 Cook 1 1 3 3 1 1 3 3 3 19

7 Big George 1 3 3 1 8

6 Wyodak 3 3 1 7

5 Canyon 2 3 3 3 3 1 3 3 3 24

4 Anderson 1 1 3 3 1 3 3 1 9 25

3 Smith/Swartz 4 1 4 9

1 Wasatch 1 4 3 8

1&2 3&12 4 5 6 7 8 9&10 11 TOTAL

Partitions

Major Seams

* Includes deep “wildcats.”

Table 3-14. Number of CBM Type Wells for Basin Assessment
4-1

4.0 COSTS OF PRB CBM DEVELOPMENT

This section presents the cost model used for assessing the economics of Powder River Basin

(PRB) coalbed methane (CBM) development. The section contains:

 • A summary presentation of the basic capital, operating and maintenance, gas transportation and compression, and water disposal costs,

 • A discussion of other financial considerations such as royalties, production taxes, and

basin differentials,

 • More detailed discussions of CBM capital costs,

 • More detailed discussion of CBM O&M costs, and

 • A discussion of water disposal capital and O&M costs for four water management

alternatives—surface disposal, infiltration impoundment, shallow re-injection and active

treatment using reverse osmosis.

4.1 Basic Cost Model

4.1.1 Introduction

This section provides the basic capital and operating cost model for Powder River Basin coalbed

methane development. The model attempts to reflect a series of “typical” CBM wells in the

basin, with cost variability determined by well depth, geographic location and volume of gas and

water production. In reality, the variability in costs is much greater than can be defined by these

“typical” CBM wells and the three factors (depth, location, and gas and water production) that

are used to capture a portion of this variability. As such, the cost and well performance information are intended for use on a regional rather than a site or prospect-specific basis.

The authors are deeply indebted to the many sources of cost information made available for this

study. These include contributions of cost data from the producers and service companies in the

basin, detailed cost data from Advanced Resources’ past studies of coalbed methane in the

Powder River Basin and other coal basins, and the cost surveys and comments by the Producers

Association of Wyoming. We welcome suggestions and data that would improve the quality of

the information and the cost model.

4.1.2 Capital Costs for PRB CBM Well

The basic capital costs for a PRB CBM well include outlays for land, permits, drilling and

completion, and infrastructure (capital costs for water disposal are presented later). These costs

vary considerably by well depth and location. For example purposes, we will use a Powder

River Basin coalbed methane well at 600 feet of depth, spaced on 80 acres, with 2 wells per pad. 

Capital costs are per well, assuming a 16-well, 8-pad development unit. Gas treating and

compression is assumed, provided by a third party contract. Additional detail on each of the cost

items and how costs vary with depth are provided in subsequent sections of this report.
4-2

The basic capital costs for the above described example PRB CBM well are estimated at

$88,000, as shown below.

Table 4-1. Capital Costs for PRB CBM Well

Cost Item Capital Costs

Land Costs and Permits $13,000

Well Drilling and Completion (@600 feet) 48,180

Water Gathering* 10,210

Electric Power, inc. cable** 8,450

Gas Gathering*** 7,820

Miscellaneous 340

Total $88,000

* Allocated based on small diameter water gathering piping of 2,000 feet per

 well (including common trenching and survey for water, gas, and electrical

cable), central water transportation (2 lines) of 10,000 feet, right of way for

42,000 feet, two surface pumps and contingency insurance and other costs

of 10%.

** Allocated based on central 3-phase power installation costs of $75,000 per

unit, electrical cable of 2,000 feet per well, and contingency, insurance and

other costs of 10%.

*** Allocated based on small diameter gas gathering piping of 2,000 feet per well,

central gas transportation (2 lines) of 10,000 feet, and contingency, insurance

and other costs of 10%.

4.1.3 O&M Costs for PRB CBM Well

The basic lease and well operating and maintenance (O&M) costs for a Powder River coalbed

methane well varies by year of production, with higher costs during the initial years because of

more frequent well enhancements and pump replacements. Additional detail on these costs is

provided in subsequent sections of this report.

For illustrative example purposes, assuming CBM recovery of 0.3 Bcf (gross) per well, the

O&M costs are $0.215 per Mcf and G&A costs are $0.043 per Mcf, for total O&M/G&A costs

of $0.258 per Mcf. Additional O&M costs are incurred for water management and disposal, as

discussed later.
4-3

Table 4-2. O&M Costs for PRB CBM Well

O&M Costs/Well

Basic O&M* O&M Inc.G&A

Annual Monthly Annual Monthly

Year 1 $16,700 $1,390 $20,040 $1,670

Years 2 - 4 $7,500 $625 $9,000 $750

Years 5 - 10 $4,200 $350 $5,040 $420

TOTAL (Years 1 - 10) $64,400 $644 $77,280 $773

*A G&A charge of 20% for engineering, accounting, legal and other indirect costs is added to basic well costs.

4.1.4 Gas Transportation, Compression, and Fuel Use

The costs of gas treatment, compression and transportation are subtracted from the PRB netback

price to establish a PRB CBM wellhead price. The costs will vary, depending on the gathering

system charges for transporting natural gas from the compressor to the Colorado Interstate Gas

(CIG), or another hub, and on the nature and extent of contracted third-party compression. 

These costs depend on the location of the CBM development in the PRB, as follows:

 • A charge of $0.43 per Mcf is used for third-party compression and dehydration

(assuming no lease compression), and for transportation for the central and southern

portions of the PRB (Partitions #1, 2, 3, 4, and 5).

 • A charge of $0.57 per Mcf is used for third-party compression and dehydration

(assuming no lease compression), and for transportation for the northeast and southwest

portions of the PRB (Partitions #6, 8, and 9).

 • A charge of $0.77 per Mcf is used for third-party compression and dehydration

(assuming no lease compression), and for transportation for the northwest and western

portions of the PRB (Partitions #7, 10, 11 and 12).

A fuel adjustment (“shrinkage”) for operating gas powered compressor stations, estimated at 4 to

6% of gross production, is subtracted from the sales volume. A second fuel adjustment

(“shrinkage”), involving the BTU adjustment for CBM, generally 2 to 8% (to account for 920 to

980 Btu content gas), is also subtracted from the sales volume.

4.1.5 Water Disposal Alternatives

Alternatives. A series of alternatives are being used or considered for CBM water disposal in the

Powder River Basin, including:

 • Untreated or passively treated water with surface discharge.
4-4

 • Infiltration impoundment with enhanced evaporation and/or land application.

 • Shallow re-injection of the produced water.

 • Actively treated water with infiltration, evaporation, land application, and/or surface

discharge, and disposition of the residual concentrate by trucking or deep re-injection.

Deep re-injection of the untreated, relatively high-quality CBM produced water would constitute

a loss of a valuable resource and thus has not been included among the water disposal alternatives in this study.

Capital Costs. The capital costs for the alternative CBM water disposal options add from $1,400

to $35,200 per well, depending on the water management alternative selected, as shown for the

example well below.

Table 4-3. Capital Costs for Alternate Methods of Water Disposal

Water Disposal Costs

Capital Costs/Well O&M Costs/Bbl.*

Water Disposal

Surface Discharge $1,400 $0.02

Infiltration Impoundment $10,300 $0.06

Shallow Re-Injection $15,150 $0.06

Active Treatment w/Disposal of

Residual Concentrate

 • Trucking $19,600 $0.24

 • Deep Re-Injection $35,200 $0.14

* Per barrel of water produced for a “typical” CBM well producing 320 barrels per day

 (average) during the first 2 years.

O&M Costs. The operating costs of alternative CBM water disposal options will add from $0.02

to $0.25 per barrel of produced water to basic well and lease O&M costs, depending on the water

management alternative selected.

4.1.6 Other Considerations

Royalties. Royalty payments for PRB CBM production depend on mineral ownership, as set

forth below:

 • Royalties on federal lands are 12.5%.

 • Royalties on state lands are 16.7%.

 • Royalties on private lands range from 15% to 20%.

State Severance and Ad Valorem Taxes. State and county tax payments for PRB CBM

production are state specific, as set forth below:

 • Wyoming severance and ad valorem taxes are 12%.
4-5

 • Montana severance taxes are 9.3%.

4.1.7 Basin Differentials

Because of higher transportation costs and other market conditions, the gas price at the CIG (or

another Wyoming/Rocky Mountain) hub is discounted from a marker price, as set by the Henry

Hub or NYMEX (commonly called the “basin differential”). As of mid-June 2002, with the

Henry Hub gas price at $3.11 per MMBtu, the Wyoming Pool and the Opal hub are both at $1.33

per MMBtu, for a basin differential of $1.78 per MMBtu.

The economic model assumes that the long-term basin differential between Henry Hub and

Rocky Mountain hubs reverts back to a historically-based value of $0.80 per MMBtu, as

published by Petrie Parkman & Co. (October 2000). Sensitivity cases have been run to examine

the effects of higher basin differentials.

4.2 Discussion of CBM Development Capital Costs

4.2.1 Land Costs and Permits

Regular land and permit costs for CBM development in the Powder River Basin include the

following:

 • Mineral lease purchase and maintenance.

 • WOGCC hearing, division orders, and permits.

 • DEQ, State Engineer Office and BLM permits.

The costs for water disposal permits are included later.

The costs for mineral leases is $200 per acre; the costs for regular permitting and studies is

$5,000 for an 80-acre well pad. For a federal lease, additional costs are required for NEPA and

other permitting studies, estimated to cost an additional $10,000 for an 80-acre well pad. 

Assuming approximately one-half of the leases are federal, this would add $5,000 of costs for an

average permit.

The total land and permit costs for an 80-acre well pad are estimated at $26,000. With two wells

per pad, the cost per CBM well is $13,000.

4.2.2 Well Drilling and Completion

Well drilling and completion costs are governed primarily by well depth, assuming single zone

coal seam completions. The intangible (expensed) and tangible (capitalized) drilling and completion costs for two representative PRB CBM wells, one at 500 feet and one at 850 feet, are

provided below:
4-6

Table 4-4. Sample Tangible and Intangible Costs for Two PRB CBM Wells

Coal Seam Depth

500 feet 850 feet

Well Drilling Costs $28,200 $36,500

 Intangible 24,400 30,500

 Tangible 3,800 6,000

Well Completion Costs $12,800 $14,300

 Intangible 4,700 4,700

 Tangible 8,100 9,600

TOTAL* $41,000 $50,800

* Contingency, insurance costs and other costs, estimated at 10% ,are added to the above well

 D&C costs.

A significant number of the cost items, such as site preparation, rentals, wellhead, and gas/ water

metering, are relatively insensitive to differences in well depth. Other cost items, such as

production casing, tubing, and the pumping system, are directly related to well depth.

Based on the itemization of fixed and variable costs, the drilling and completion cost equation

for a shallow (less than 1,000 foot) PRB CBM well is as follows:

($27,000 + $28(WD)) * 1.10

where: WD is well depth <1,000 feet

As well depth increases, well drilling and completion costs rise to account for the extra costs

involved with increasing depth. Based on experiences in the PRB and other CBM basins, we

would estimate the cost equation for deeper, 1,000- to 3,000-foot CBM wells as follows:

($27,000 + $28(1,000) + $56 (WD-(1,000)) * 1.10

where: WD is well depth <3,000 feet

Using the above equation, the well drilling and completion costs for the example 600-foot PRB

CBM well and two deeper PRB CBM wells, one at 1,500 feet and one at 2,000 feet, are

calculated as follows:

($27,000 + $28(600)) * 1.10 = $48,180

($27,000 + $28,000 + $56(500)) * 1.10 = $91,300

($27,000 + $28,000 + $56(1,000)) * 1.10 = $122,100

Additional details on specific well drilling and completion costs are provided below.
4-7

Table 4-5. Additional Drilling and Completion Costs for Two PRB CBM Wells

Well Depth 500' 850'

Drilling Costs

Intangible Drilling Costs $24,400 $30,500

 Site Prep, Permit, Survey and ROW 3,700 3,700

 Drilling Rig, Bits, Fluids 12,600 16,200

 Cementing 4,200 4,400

 Logging 700 800

 Supervision (Drilling, Geologic) 2,400 3,600

 Other 800 1,800

Tangible Drilling Costs $3,800 $6,000

 Surface Casing (9-5/8" @ $10/ft) 600 850

 Production String (7" @ $5.50/ft) 2,750 4,300

 Wellhead 450 450

Completion Costs

Intangible Completion Costs $4,700 $4,700

 Supervision/Labor 2,400 2,400

 Enhancement 1,200 1,200

 Completion Rig 500 500

 Water Handling 600 600

Tangible Completion Costs $8,100 $9,600

 Tubing (2" @ $1.50/ft) 800 1,300

 Pump, Motor, Cable 2,500 3,500

 Electrical Controller/Transducer 2,000 2,000

 Wellhead, Flowline Fittings 1,000 1,000

 Gas and Water Metering 1,800 1,800

Total $41,000 $50,800

4.2.3 Infrastructure Costs

Basic Water Handling Facilities. The facilities for gathering and transporting produced CBM

water includes a pump and a water metering system (already included in well completion costs)

plus small diameter (3 inch) polyethylene pipe connected to the tubing of the well. The

polyethylene pipe is placed underground in a common trench from the wellhead to a point of

common collection. A second, larger diameter (6 inch) polyethylene pipe transports the gathered

water to a point of discharge involving a natural drainage outlet or a containment facility. For

purposes of the cost estimate, the following assumptions are used:
4-8

 • Well pads are placed on 80-acre spacing; on average, two wells exist per well pad;

16 wells (8 well pads on one 640-acre section) are linked together with an underground

gathering and piping system.

 • For cost estimation purposes, each well initially produces 400 BWD (in year 1) declining

to 240 BWD in year 2 and declining by 25% each subsequent year. Total water production is 470,000 barrels per well for the 10 years of a well’s life. (For this example

well, average water production is about 4 gpm (137 barrels per day) for 10 years.)

 • Approximately 2,000 feet of 3-inch polyethylene pipe is required for each well; 2 lines,

each using approximately 5,000 feet of 6-inch polyethylene pipe, link the 16-well unit to

2 water disposal sites.

 • Approximately 32,000 feet of common trenching is required for water gathering (as well

as the electrical cable and small-diameter gas-gathering lines) and 10,000 feet of common

trenching is required for water transportation (as well as for gas transmission).

 • The cost for trenching and the survey is estimated at $2.15 per foot; the cost of the

polyethylene pipe is estimated at $0.50 to $0.70 per foot; and, the cost for right of way

(ROW) is estimated at $0.60 per foot.

The cost of the water gathering and subsurface piping system for a 16-well unit is estimated at

$163,350 or $10,210 per well, based on the following: 

 • Trenching and Survey: (42,000 ft @ $2.15 ft) = $ 90,300

 • Water Gathering: 3 inch poly pipe (32,000 ft @ $0.50/ft.) = $ 16,000

 • Water Transport: 6 inch poly pipe (10,000 ft @ $0.70/ft.) = $ 7,000

 • Surface Pump: (2 units @ $5,000/unit) = $ 10,000

 • Right of Way: (42,000 ft. @ $0.60/ft.) = $ 25,200

 • Contingency, insurance, etc. (@10%) = $ 14,850

$163,350

Operating and maintenance costs for the water gathering and transportation system, including

electric power, surface pump maintenance and other costs, are included in the O&M costs for

surface discharge, are discussed later.

Electric Power. The costs of providing three-phase electric power and electrical cable to a

16-well unit (without trenching and survey) are as follows:

 • Central 3-Phase Power* $ 75,000

 • Electric Cable (32,000 ft. @ $1.50/ft.) 48,000

$123,000

 • Contingency, insurance, etc. (@ 10%) 12,300

Total $135,300

* Costs can range from $50,000 to $100,000, depending on location.

Based on 16 wells, the cost per well is estimated at $8,450.
4-9

Gas Gatherings. The costs of providing gas gathering and central gas transmission for the

16-well unit to a central compressor (without trenching and survey) are as follows:

 • Gas Gathering: (32,000 ft., 4" @ $0.90/ft.) $ 28,800

 • Gas Transmission: (10,000 ft, 12" @ $8.50/ft.) 85,000

$113,800

 • Contingency, insurance, etc. (@10%) 11,380

Total $125,180

Based on 16 wells, the cost per well is estimated at $7,820.

4.3 Discussion of CBM Well O&M Costs

4.3.1 O&M Costs for PRB CBM Well

Well and lease operating and maintenance (O&M) costs in the PRB are for electricity, wages for

the pumper and miscellaneous site maintenance. In addition, particularly during the initial years

of operation, CBM wells require periodic replacement of the downhole water pumping system

and remediation.

The cost model assumes two pump replacements and a well workover during the first year of

operation, an annual pump replacements during the next three years of operation (but no

additional well workover), and annual pump replacement with a smaller capacity pump during

the final 6 years of operation.

The costs for water lifting capacity depends on well depth and the water rate, as provided below:

Table 4-6. Pump Replacement Costs

Pump Size (bwpd)* Pump Cost ($) Rig ($)**

171 1,100 500 

342 1,365 500

684 2,115 500

1,028 2,865 500

1,371 3,696 500

* Pump size of 171 to 684 bwpd are sufficient for well depths from 300 to 1,000 feet; pump size

 1,028 to 1,371 bwpd are required for well depths below 1,000 feet.

** The cost for the workover rig assumes replacements of two pumps per day.

The annual O&M costs for electricity are scaled by water production rates of the CBM well,

with 305 barrels per day (average for the year) incurring $3,050 annual costs for electricity.

The cost of replacement plumps is scaled by well depth and varies in time by changing waterletting capacity requirements.
4-10

The annual cost for pump replacement for well depths from 300 to 1,000 feet is provided above. 

The cost for pump replacement for well depths below 1,000 feet is established by multiplying the

pump replacement costs for 1,000-foot wells by the following cost scaling factor:

 • Pump Replacement Cost (for 1,000' well) * (WD/1,000')2

 • For WD of 1,000' to 3,000'

The annual and monthly direct well and lease O&M costs for a PRB CBM well at 600 feet of

depth and producing 305 barrels of water per day in year 1 (declining with time), are provided

below, by year of operation:

Year 1 Annual Monthly

Electricity $3,050

Pumper 1,140

Workover* 6,270

1st Pump Replacement 2,620

2nd Pump Replacement 2,620

Annual ROW 700

Misc. 300

Total $16,700 $1,390

***Total w/G&A $20,040 $1,670

Year 2-4

Electricity  $1,500

Pumper 1,140

Pump Replacement 1,860

Workover**  2,000

Annual ROW 700

Misc. 300

Total $7,500 $625

Total w/G&A $9,000 $750

Years 5-10

Electricity**** $480

Pumper 1,140

Pump Replac. 1,600

Annual ROW 700

Misc. 280

Total $4,200 $350

Total w/G&A $5,040 $420

* Each well is assumed to require one re-enhancement to restore productivity

 during the first year.

** One out of three wells is assumed to require a clean-out during their second

 year.

 *** A G&A cost of 20% is added to the well and lease O&M costs, annual and

monthly costs are rounded.

**** Electricity costs are scaled based on annual water production.
5-1

5.0 ECONOMICS OF POWDER RIVER COALBED METHANE WITH

ALTERNATIVE WATER MANAGEMENT OPTIONS

5.1 Summary

5.1.1 Key Economic Factors

The economics of coalbed methane produced water management in the Powder River Basin are

influenced by four key factors:

 • Future natural gas prices and, most critical today, the “basin differential.” While natural

gas prices at the Henry Hub have recently ranged from $3 to $3.50 per Mcf, the prices

paid at the Wyoming hubs have ranged from $1 to $1.50 per Mcf, for an unprecedented

and persistent “basin differential” of $1.50 to $2.00 per Mcf.

 • The volume and timing of gas and water production from individual coal seams in

distinct portions of the basin. Expected gas recovery from a CBM well ranges by order

of magnitude, from 0.1 Bcf to 1 Bcf per well; and, water recovery varies twenty-fold,

from 100,000 to 2,000,000 barrels per well.

 • The capital and O&M costs for drilling and operating wells of different gas and water

productivity and at depths of 300 to 3,000 feet.

 • The coalbed methane produced water management option selected by the operator, as

discussed further below.

5.1.2 Economic Cases

To examine the economic impact of alternative water production practices, the study used three

gas price and “basin differential” cases:

Case 1 (Today). Case 1 assumes long-term natural gas prices of $3.00 per Mcf (in constant year

2002 prices) at the Henry Hub, with a basin differential of $1.80 per Mcf. This provides a

natural gas price at the Wyoming Hub of $1.20 per Mcf. (As a point of reference, on July 1,

2002 the natural gas price at the Wyoming Hub was $1.07 per MMBtu, with a Henry Hub price

of $3.20 per MMBtu.)

Case 2 (Transition). Case 2 uses the same gas price (at Henry Hub) as Case 1, but assumes that

the “basin differential” narrows with time, from $1.80 per Mcf today, to $1.30 per Mcf in 2003,

and to $0.80 per Mcf in 2003 and beyond.

Case 3 (Long Term). Case 3 uses the same gas price (at Henry Hub) as Cases 1 and 2, but

assumes that the “basin differential” is and remains at $0.80 per Mcf, consistent with historical

trends.

For the volumes of gas and water expected to be produced, the study uses the 142 type wells

representative of the different geological areas and coal seams in the PRB, presented in
5-2

Chapter 3. For capital and O&M costs, the study uses the cost and economic models presented

in Chapter 4.

5.1.3 Overview of Economic Analyses

The economics of alternative water management options in the PRB are as follows, using a 15%

(before corporate income tax) internal rate of return (IRR) as the threshold criteria.

Table 5-1. Volumes of Economically Recoverable CBM w/Alternative

Water Disposal Options*

Economic Cases

Surface

Discharge Impoundment

Shallow

Reinjection

Active

Treatment

Case 1 (Today) 1.5 Tcf -- -- --

Case 2 (Transition) 22.4 Tcf 20.0 Tcf 18.8 Tcf 7.1-10.2 Tcf

Case 3 (Long Term) 29.1 Tcf 27.8 Tcf 27.1 Tcf 17.8-21.6 Tcf

* Includes the 655 Bcf of CBM produced to date from the basin.

Analyses of the economics of alternative water management options for PRB CBM show the

following:

Case 1 (Today). Under today’s unfavorable economics (Case 1), surface disposal of produced

water is the only economic water management option, and even this option is economic only in

selected, high quality portions of the PRB. More costly water disposal options would preclude

further economic development of coalbed methane in the Powder River Basin. A significant

portion of the 1.5 Tcf of economic CBM potential shown in the above table is already under

development with about 650 Bcf of this volume produced to date, leaving little opportunity for

further economically justified expansion in this basin under today’s gas price and PRB “basin

differential.”

Case 2 (Transition). Assuming a transition toward more normal Wyoming basin price differentials, a significant portion of the basin becomes economic to develop with water management

practices of surface discharge, impoundment or shallow re-injection. Requiring active treatment

of the produced water (with current reverse osmosis technology) greatly reduces the basin’s

economic potential. Specifically, instead of 19 to 22 Tcf of economically recoverable coalbed

methane (using one of the first three water management options), only 7 to 10 Tcf of coalbed

methane remains economic to develop with a requirement for active water treatment. This

represents a loss of 12 Tcf of otherwise economically recoverable natural gas resource.

Case 3 (Long Term). Using a long-term outlook for gas prices in Wyoming (requiring that

development be delayed until the basin differential reaches historically more normal values), the

economic CBM resources of the PRB range from 27 to 29 Tcf (for the three lower cost water

management options). Imposing active treatment of water (with current reverse osmosis tech-
5-3

nology) reduces the economically viable PRB CBM potential to a range of 18 to 22 Tcf, for a

loss of 7 to 9 Tcf natural gas resources.

5.1.4 Impact of Risk Premium

Using a higher minimum rate of return—one potentially more reflective of the current higher

economic and regulatory risks in the PRB—would reduce the natural gas resource and production contribution from the PRB. Imposing higher cost water management options, such as

active produced water treatment with reverse osmosis, and a higher risk premium would also

preclude further economic development of coalbed methane in the PRB. The result of this risk

premium analyses, using Case 2 natural gas wellhead price and basin differential assumption, is

shown below:

Table 5-2. Volumes of Economically Recoverable CBM w/Alternative

Water Disposal Options

Water Management Options

Case 2

w/15% IRR

Treshold

Case 2

w/25% IRR

Threshold

Surface Discharge 22.4 Tcf 16.6 Tcf

Impoundment 20.0 Tcf 12.7 Tcf

Shallow Reinjection 18.8 Tcf 12.4 Tcf

Active Treatment

 w/Trucking 7.1 Tcf 0.8 Tcf

 w/Deep Disposal 10.2 Tcf 2.1 Tcf

5.2 Water Disposal Alternatives

A series of alternatives are being used or considered for CBM water disposal in the Powder

River Basin, including:

 • Untreated or passively treated water with surface discharge.

 • Infiltration impoundment with enhanced evaporation and/or land application.

 • Shallow re-injection of the produced water.

 • Actively treated water with infiltration, evaporation, land application, and/or surface 

discharge, and disposition of the residual concentrate by trucking or deep re-injection. 

Deep re-injection of the untreated, relatively high quality CBM produced water would be

wasting a valuable resource and thus has not been included among the water disposal alternatives

in this study.
5-4

5.3 Costs of Water Disposal Alternatives

5.3.1 Capital Costs

The capital costs for the alternative CBM water disposal options add from $1,400 to $35,200 per

well, depending on the water management alternative selected, as shown for the example well

below.

Table 5-3. CBM Water Disposal Alternative Costs

Water Disposal Costs

Capital Costs/Well O&M Costs/Bbl.*

Water Disposal

Surface Discharge $1,400 $0.02

Infiltration Impoundment $10,300 $0.06

Shallow Re-Injection $15,150 $0.06

Active Treatment w/Disposal of

Residual Concentrate

 Trucking $19,600 $0.24

 Deep Re-Injection $35,200 $0.14

* Per barrel of water produced for a “typical” CBM producing 320 barrels per day (average)

 during the first 2 years.

5.3.2 O&M Costs

The operating costs of alternative CBM water disposal options will add from $0.02 to $0.24 per

barrel of produced water to basic well and lease O&M costs, depending on the water management alternative selected.

5.3.3 Capital Costs for Water Treating and Associated Disposal

The total capital costs for using active water treatment (with RO) are as follows for a 900-gpm

(30,860 barrel per day) facility:
5-5

Table 5-4. Capital Costs for Disposal Options

Trucking Deep Disposal

Three RO Unit (installed) $1,600,000 $1,600,000

Deep Disposal well and facilities - $1,500,000

Three Impoundments $150,000 $150,000

Three surface discharge points $130,000 $130,000

TOTAL $1,880,000 $3,380,000

The cost for the RO unit and associated facilities, assuming trucking of the residual concentrate

to disposal, is $1,880,000 or $19,600 per well for a 96-well unit.

Using a deep disposal well and injection facilities would eliminate the costs of trucking the

residual concentrate, but would raise the capital costs to $3,380,000 or $35,200 per well for a

96-well unit.

5.3.4 Operating Costs for Water Treatment and Associated Disposal

Operating costs for the three RO units are estimated at $233,100 per year for a 96-well unit, or

$0.02 per barrel of water treated (assuming a capacity of 30,000 barrels per day), and an

operating factor of 95%. Adding the costs of maintaining the discharge points and impoundments, and providing electricity and maintenance for the pumps, bring operating costs to $0.04

per barrel of water produced.

For trucking, the total costs are estimated at $0.24 per barrel of water produced, assuming water

trucking costs of $2.00 per barrel and 10% residual concentrate.

For deep disposal, the total costs are estimated at $0.14 per barrel of water produced, assuming

deep re-injection well and facility O&M costs of $0.10 per barrel of water injected.

Table 5-5. Total Estimated Costs for Deep Disposal

Annual

Operating Costs*

Electric Power $57,000

Chemicals

 Anti-scalant $73,000

 Cleaning $5,000

 Iron removal $3,500

Membrane Replacement (After 5 years, annualized) $33,600

Reject Disposal (10% residual concentrate) see below

Annual Labor $22,000

$194,200

G&A of 20% $38,800

TOTAL $233,000

* Assuming a 96-well unit.
5-6

5.4 Discussion of Water Disposal Capital and O&M Costs

5.4.1 Surface Discharge

This alternative involves building two water discharge points with limestone rock (rip-rap) for

passive treatment of the produced water. (The cost for the water transportation system and

pumps has been included above.)

 • The cost for 20 cubic yards of limestone rock is estimated at $600.

 • The cost for building a discharge point is estimated at $5,000.

 • Contingency, insurance, and other costs of 10% are added to the above.

 • The cost for the NPDES permit is approximately $1,000 per well.

 • The total cost is estimated at $6,200 for a 16-well facility or $400 per typical CBM well,

plus $1,000 per well for the NPDES permit.

The operating costs for monitoring surface discharge, including electricity and maintenance for

the surface pumps, are estimated at $0.02 per barrel.

5.4.2 Infiltration Impoundment

This alternative involves constructing an impoundment (pond) and installing enhanced evaporation equipment (atomizers) or a surface irrigation system.

 • The size of the impoundment is 3 acres with a dam of 13 feet, providing 20 acre-feet

(150,000 barrels) of water capacity sufficient to hold 30 days of production from a

16-well unit.

 • Annual water infiltration is estimated at 8 feet of water loss per year, with enhanced

evaporation and surface irritation providing 12 feet of water loss per year. Together, this

provides 60 acre-feet (approximately 465,000 barrels) of water loss per year or about

1,275 barrels per day (with more during summer months and less during winter months).

 • An irrigation or atomizing system is added to the impoundment. One such unit is able to

dispose of 45 gpm or 1,500 barrels per day.

 • At an average water rate of 320 barrels per day (during the first two years of well operation), the 16-well unit will produce about 5,000 barrels per day of water. One impoundment with an irrigation system will accommodate about 8 wells (and more wells during

subsequent years). A 16-well unit requires two such infiltration and evaporation

impoundments.
5-7

 • The cost for constructing each impoundment is estimated at $25,000 to $50,000, based on

handling approximately 50,000 cubic yards of material at $0.50 to $1.00 per cubic yard. 

(Reclamation costs of $10,000 (on a present value basis) are added to this total).

 • The cost for one atomizer or irrigation system is estimated at $16,500 for a 1,500-barrels

per day (45 gpm) unit, with installation costs of about 20% or $3,500. Two such units

are required.

 • Contingency, insurance, right of way and other costs of 10% are added.

 • The total cost for two infiltration and evaporation impoundments is $148,500, or $9,300

per typical CBM well plus $1,000 per well for the NPDES permit.

Construction $ 75,000

Reclamation (PV) 20,000

Atomizers/Irrigation (2 units) 40,000

Contingency, etc. 13,500

$148,500

The operating cost for the infiltration and evaporation impoundment is estimated at $0.06 per

barrel of water produced, including $0.02 per barrel for electricity and maintenance for the

surface pumps and $0.04 per barrel for operating the irrigation system and maintaining the

impoundment.

5.4.3 Shallow Re-injection

This alternative involves identifying shallow, ideally relatively fresh water zones into which the

CBM produced water could be re-injected. A handful of such shallow well injection projects

exist, but with a mixed record of success. Basically, shallow re-injection is a high risk option

and may be considered a speculative alternative at this time. Therefore, shallow re-injection was

evaluated from a theoretical standpoint in this analysis.

Ideally, the shallow re-injection zone would be under pressured and highly permeable. This

would help reduce (or eliminate) pumped costs and reduce the number of required injection

wells.

The costs for a large, central shallow re-injection facility (or two smaller facilities) capable of

dispersing 30,000 barrels per day from 96 producing CBM wells is as follows:

 • The cost of two 3-acre (20 acre-foot) infiltration impoundments (with a combined

capacity fo 300,000 barrels) is estimated at $104,500. This would provide storage for

about 10 days of water production from a 96-well unit. The annual water loss from two

impoundments would be modest, the order of 1,500 barrels per day.

 • The remainder of the produced water would be injected into a series of shallow wells. 

Assuming water injection capacity of 2,000 barrels per day (based on water production
5-8

and a select number of injection projects in the basin), approximately 15 shallow wells

would be required.

 • The drilling and completion costs for shallow wells estimated to be on the order of

$30,000 to $70,000 per well. Adding other costs, such as water transportation, pumps,

injection facilities, permits, etc., is estimated to be about $30,000 to $50,000 per well,

and provides total well costs of $90,000 (Source: CBM Producers Information Survey

Results, January 2002).

 • Assuming average shallow well drilling and completion costs per well of $90,000, the

costs for 15 wells would be $1,350,000 plus $104,500 for the impoundment facilities for

a total of $1,454,500 or $15,150 per typical CBM well, as shown below:

Impoundments (2) $ 104,500

Shallow Wells (10) $1,350,000

Total $1,454,500

The operating costs for the shallow wells and impoundment (including electricity and maintenance for the surface pumps) are estimated at $0.06 per barrel of water produced.

5.4.4 Active Treatment Using Reverse Osmosis

This alternative involves constructing water holding and residual concentration storage

impoundments, installing a water treatment system involving reverse osmosis (RO), surface

discharging the treated water, and either trucking or deep re-injecting the residual concentrate.

Capital Costs. The capital costs are for a large, central unit able to service 96-producing CBM

wells.

 • The cost of three surface discharge points is estimated at $18,600 (from above), plus

$15,000 for water piping and $96,000 for studies and permits, for a total of $130,000 for

a 96-well unit.

 • The cost of one 3-acre (20 acre-foot) infiltration impoundment (with a capacity of

150,000 barrels) is estimated at $52,250 (from above). This would provide storage for

about 5 days of water production from a 96-well unit. Two such impoundments are

required to provide 10 days of produced water storage capacity. The cost of a third

smaller (10 acre-foot) lined impoundment for storing the reject water (concentrate) from

the RO unit is estimated at $32,000, plus piping. This would provide storage for up to

one month of reject water. The total cost for impoundments is estimated at $150,000.

 • Assuming a 96-well unit and 320 barrels of water per day per well (average water rate for

first 2 years), 3 300-gpm (10,286 barrel per day) units are required with capacity to treat

30,000 barrels per day.
5-9

 • The cost for 3 RO units (from Filter Tech) is $1,212,000. Assuming 20% for site

preparation, the electrical system, building, etc., plus 10% for contingency, insurance and

other, the cost for three units is $1,600,000.

 • Two options, trucking and deep disposal, exist for disposing of the residual concentrate,

estimated at 10% of the treated water, or 3,000 barrels per day.

 • If trucking is the option, these costs are included in O&M costs, presented in the next 

section.

 • If disposal is the option, additional capital costs are required for a deep disposal well and

an injection facility for the residual concentrate. The costs of the re-injection well and

associated facilities are estimated at $1,000,000 for the deep re-injection well and

$500,000 for the facility (including large capacity pumps, electricity, water transportation

and other costs).

The total capital costs for using active water treatment (with RO) are as follows for a 900-gpm

(30,860 barrel per day) facility:

Table 5-6. Total Capital Costs for Active Water Treatment

Trucking Deep Disposal

Three RO Unit (installed) $1,600,000 $1,600,000

Deep Disposal well and facilities (est.) - $1,500,000

Three Impoundments $150,000 $150,000

Three surface discharge points $130,000 $130,000

TOTAL $1,880,000 $3,380,000

The cost for the RO unit and associated facilities, assuming trucking of the residual concentrate

to disposal, is $1,880,000 or $19,600 per well for a 96-well unit. Adding a deep disposal well

and injection facilities would eliminate the costs of trucking the residual concentrate, but would

raise the capital costs to $3,380,000 or $35,200 per well for a 96-well unit.

Operating and Maintenance Costs. Operating costs for the 3 RO units are estimated at $233,100

per year for a 96-well unit, or $0.03 per barrel of water treated (assuming a capacity of 30,000

barrels per day) and an operating factor of 95%, as shown below. Adding the costs of maintaining the discharge points and impoundments, and providing electricity and maintenance for the

pumps, brings operating costs to $0.04 per barrel of water produced.

If trucking is the option, the costs for operating the RO unit, pumping the water, operating the

discharge points, and disposing of the residual concentrate are estimated at $0.24 per barrel of

water produced assuming water trucking costs of $2.00 per barrel of residual concentrate and

10% residual concentrate.
5-10

Table 5-7. Annual Operating Costs for Trucking

Annual

Operating Costs*

Electric Power $57,000

Chemicals

 Anti-scalant $73,000

 Cleaning $5,000

 Iron removal $3,500

Membrane Replacement (After 5 years, annualized) $33,600

Reject Disposal (10% residual concentrate) see below

Annual Labor $22,000

$194,200

G&A of 20% $38,800

TOTAL $233,000

* Assuming a 96-well unit.

If deep disposal of the residual concentrate is the option, the costs for operating the RO unit,

pumping the water, operating the discharge points, and operating and maintaining the deep

injection facility are estimated at $0.14 per barrel of water produced, assuming deep re-injection

well and facility O&M costs of $1.00 per barrel of residual concentrate injected and 10%

residual concentrate.

5.5 Detailed Economic Analyses of Water Management Options

An example of the discounted cash flow analysis, prepared for one of the 142 PRB CBM type

wells is provided in Table 5-9. The economic analysis is for the Big George coal seam with

97 feet of coal at 1,372 feet of depth, in Partition #5 of the PRB. The economic assumptions are:

Table 5-8. Assumptions for Discounted Cash Flow Analyses

Price Calculation

 Gas Price (Henry Hub) $3.00/Mcf

 Basin Differential (PRB) $1.80 to $0.80/Mcf

 Gathering and Compression $0.57/Mcf

 Net Wellhead Price $0.63 to $1.63/Mcf

Sales Volume Adjustment

 Btu Adjustment (5%)

 Lease Fuel (5%)
5-11

The Big George coal seam in Partition #5 is estimated to recover 0.7 Bcf of natural gas plus

1,500,000 barrels of water. Economic analyses of this high water producing seam show that

current practices of produced water management enable this coal seam to be economically

developed. However, more costly water management options, such as reverse osmosis, will

make this major coal seam in Partition #5 uneconomic.
5-12
1

Some quantities have been subject to rounding.

6-1

6.0 PRESENTATION OF RESULTS BY BASIN PARTITION

The materials presented in the previous chapters of the Powder River Coalbed Methane Basin

Study provide an overview of the study methodology and findings. Chapter 6 provides a review

of this information at a more detailed, “basin partition” level. As such, Chapter 6 contains a

series of sections that provide the input data and the discussion of study findings for each of the

twelve basin partitions, identified previously1

. Within each section, additional information is

provided on the major Wasatch and Fort Union Formation coal seams present in the partition.

The individual sections in Chapter 6 provide the geologic setting of the partition and its in-place

and technically recoverable coalbed methane resources. This is followed by a coal seam by coal

seam discussion of key reservoir properties that govern the producibility of each coal seam. 

Finally, each section presents the distribution of expected gas and water production for major

coal seams, as represented by an average, high and low productivity CBM well completed in the

seam. A series of maps, tables and figures summarize the data base and analytic work performed

on the major coal seams in the Powder River Basin.

Section 6.4 of Chapter 6, discussing the study findings for Partition #4, contains the full set of

maps, type logs, well performance profiles, and reservoir simulation-based history matches that

serve as the foundation for the PRB Basin Study. For purposes of brevity, more summary

information is provided for the other basin partitions.

6.1 Partition #1

6.1.1 Summary

Partition #1 covers a 20-township area in the southern portion of the Powder River Basin, from

36N to 39N and from 72W to 76W, Figure 6-1. Only one township in Partition #1 contains coal

that meets the depth and thickness criteria of the study, the Anderson seam with 25 feet of coal at

450 feet. As such, the discussion of the Anderson coal in this partition is combined into

Partition #2, northeast of Partition #1.

6.2 Partition #2

6.2.1 Summary

The main features of Partition #2, in the southeastern portion of the Powder River Basin, are as

follows:

 • The partition covers a 17-township area on the eastern edge of the PRB, from 40N to 44N

and from 70W to 73W, Figure 6-2.
6-2

Figure 6-1. Partition #1 Base Map
6-3

Figure 6-2. Partition #2 Base Map
6-4

 • A series of coal mines exist in the townships along the shallower eastern edge; as a result,

the townships on the eastern edge of the partition (in 70W) are no longer available for

CBM development.

 • The stratigraphic section contains the Canyon, Wyodak, Big George, Cook and Pawnee

coal seams (plus the Anderson from Partition #1). The depth of these coals ranges from

450 to 1,340 feet, with coal seam thickness ranging from 22 to 90 feet (township level

averages).

 • The gas in-place in the two partitions is 2.2 Tcf, with technically recoverable gas of

1,630 Bcf. The results by coal seam are provided in Table 6-7.

6.2.2 Discussion of Major Seams

 • Anderson. The Anderson is the only significant seam in Partition #1. It does not meet

the depth and thickness criteria in Partition #2.

 - Area. The Anderson coal seam meets study inclusion criteria in 1 township,

located in the southern portion of Partition #1.

 - Coal Thickness. The Anderson seam coal thickness averages 25 feet.

 - Coal Depth. The depth to the top of the Anderson seam averages 450 feet. 

 - Development. Only a few Anderson wells currently exist in this partition.

 - Time Zero Plot. Not available.

 - Type Well. The history-matched Anderson well in Partition #4, adjusted for

depth, gas content and coal thickness, serves as the Anderson type well for

Partition #1.

Table 6-1. Anderson Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery 

(M bls)

Average 475 25 0.12 120

 • Canyon. The first major coal seam in Partition #2 is the Canyon, at times included within

or called the Wyodak.

 - Area. The Canyon coal seam meets study inclusion criteria in 2 townships

located in the western portion of the partition.

 - Coal Thickness. The Canyon coal seam thickness averages 48 feet, with a range

of 35 to 60 feet.
6-5

 - Coal Depth. The depth to the top of the Canyon seam averages 575 feet, with a

range of 450 to 700 feet.

 - Development. Considerable Canyon coal well development exists in this

partition with nearly 100 shut-in and permitted wells.

 - Time Zero Plot. The time zero plot for 7 recently drilled Canyon coal wells is

provided in Figure 6-3.

 - Type Well. Because the Canyon well production data in Partition #2 is recent,

limited and still erratic, the history-matched Canyon well in Partition #4, adjusted

for depth, gas content, and coal thickness, serves as the Canyon type well for

Partition #2. Because only two townships contain the Canyon coal seam, with

significantly different coal properties, only a high and low Canyon well are used.

Table 6-2. Canyon Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery

(M bls)

High 760 60 0.46 460

Low 485 35 0.17 270

 • Wyodak. A thick package of Wyodak coals exists in the central portion of Partition #2.

 - Area. The Wyodak coal seam meets study inclusion criteria in 5 townships.

 - Coal Thickness. The Wyodak coal seam thickness averages 86 feet, with a range

of 70 to 100 feet.

 - Coal Depth. The depth to the top of the Wyodak seam averages 440 feet, with a

range of 300 to 600 feet.

 - Development. Wyodak coal well development is active in this partition with over

500 wells having been drilled or permitted.

 - Time Zero Plot. The time zero plot for 181 Wyodak coal wells is provided in

Figure 6-4.

 - Type Well. Because the Wyodak well production performance in Partition #2 is

similar to the Wyodak well performance in Partition #4, the history-matched

Wyodak well in Partition #4, adjusted for depth, gas content, and coal thickness,

serves as the Wyodak type well for Partition #2.
6-6

Time Zero Plot for an Average Well

0

1,000

2,000

3,000

4,000

5,000

6,000

0 2 4 6 8 10 12 14

Time (Months)

Production (Mcf/mo.; Barrel/mo.)

0

1

2

3

4

5

6

7

8

Well Count

GAS

WATER

Well Count

Figure 6-3. Canyon Time Zero Plot
6-7

Time Zero Plot for an Average Well

0

5,000

10,000

15,000

20,000

25,000

0 5 10 15 20

Time (Months)

Production (Mcf/mo.; Barrel/mo.)

0

20

40

60

80

100

120

140

160

180

200

Well Count

GAS

WATER

Well Count

Figure 6-4. Wyodak Time Zero Plot
6-8

Table 6-3. Wyodak Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery

(M bls)

Average 525 86 0.37 1,140

High 700 100 0.58 1,330

Low 370 70 0.22 930

 • Big George. The Big George coal seam, stratigraphically and depositionally similar to

the Wyodak, exists in the western portion of Partition #2.

 - Area. The Big George coal seam meets study inclusion criteria in 2 townships.

 - Coal Thickness. The Big George coal seam thickness averages 90 feet, with a

range of 80 to 100 feet.

 - Coal Depth. The depth to the top of the Big George seam averages 860 feet, with

a range of 850 to 875 feet.

 - Development. Approximately 300 Big George coal wells have been drilled or

permitted in this partition.

 - Time Zero Plot. The Big George coal wells in Partition #2 have been combined

into a composite Fort Union interval in the production data base. Thus, a distinct

time zero plot for this coal seam is not available.

 - Type Well. The history-matched Big George well in Partition #3, adjusted for

depth, gas content, and coal thickness, serves as the Big George type well for

Partition #2. Because the Big George coal exists in only two townships and has

relatively uniform depth and thickness, only an average Big George well is used.

Table 6-4. Big George Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery

(M bls)

Average 950 90 0.55 700

 • Cook. The Cook coal seam exists at sufficient thickness in the central portion of

Partition #2.

 - Area. The Cook coal seam meets study inclusion criteria in two townships.

 - Coal Thickness. The Cook coal seam thickness averages 30 feet.
6-9

 - Coal Depth. The depth to the top of the Cook seam averages 740 feet, with a

range of 650 to 830 feet.

 - Development. The Cook coal seam is undeveloped.

 - Time Zero Plot. Not available.

 - Type Well. The history-matched Cook well in Partition #8, adjusted for depth,

gas content, and coal thickness, serves as the Cook type well for Partition #2. 

Because the Cook coal exists in only two townships with the same thickness, only

an average Cook well is used.

Table 6-5. Cook Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery

(M bls)

Average 770 30 0.21 200

 • Pawnee. The Pawnee seam exists at sufficient thickness in the southwestern portion of

Partition #2.

 - Area. The Pawnee coal seam meets study inclusion criteria in 5 townships.

 - Coal Thickness. The Pawnee coal seam thickness averages 22 feet with a range

of 20 to 30 feet.

 - Coal Depth. The depth to the top of the Pawnee seam averages 1,340 feet, with a

range of 1,200 to 1,620 feet.

 - Development. The Pawnee coal seam is undeveloped.

 - Time Zero Plot. Not available.

 - Type Well. The history-matched Pawnee well in Partition #8, adjusted for depth,

gas content, permeability, and coal thickness, serves as the Pawnee type well for

Partition #2. Because the Pawnee coal seam has relatively uniform depth and

thickness, only an average well is used.

Table 6-6. Pawnee Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery

(M bls)

Average 1,360 22 0.29 290
6-10

Table 6-7. In-Place and Technically Recoverable CBM, Partitions #1 and #2

Coal Seam No. Full

Townships

Average

Depth

(ft)*

Average

Thickness

(ft)

Average Gas

Content

(cf/ton)

Gas in

Place

(Bcf)

Technically

Recoverable

Resources

(Bcf)

Anderson 1 450 25 39 40 30

Canyon 2 575 48 51 210 180

Wyodak 5 440 86 42 760 560

Big George 2 860 90 86 550 320

Cook 2 740 30 65 150 120

Pawnee 5 1,336 22 108 470 420

Totals 2,170 1,630

* Top of coal

6.3 Partitions #3 and #12

6.3.1 Summary

The main features of Partitions #3 and #12, in the Powder River Basin, are as follows:

 • Partition #3 covers a 21-township area in the south-central portion of the PRB, from 40N

to 44N and from 73W to 79W, Figure 6-5. Partition #12 covers a 12-township area along

the western edge of the PRB, Figure 6-6. Only one township (42N 77W) and only one

coal seam, the Big George, meet the study inclusion criteria in Partition #12. Because

this township forms the western extent of the Big George coal seam in Partition #3, this

single township and coal seam in Partition #12 is included in the data and discussion of

the Big George coal seam in Partition #3.

 • The stratigraphic section contains the Anderson, Canyon, Wyodak, Big George, and

Cook coal seams. (The Wyodak “fairway” boundary crosses the northeast corner of the

partition.) The remainder of the area is included in the Big George “fairway” for coal

seam designation purposes.

 • The depth to the top of these coals ranges from 730 to 1,500 feet, with individual coal

seam thickness ranging from 30 to 130 feet (township level averages).

 • The gas in place in the partition is 8.3 Tcf, with technically recoverable gas of 4,060 Bcf. 

The results by coal seam are provided in Table 6-12.

6.3.2 Discussion of Major Seams

 • Anderson. The Anderson exists as a distinct seam on the eastern portion of the partition.

 - Area. The Anderson coal seam meets study inclusion criteria in one township.
6-11

Figure 6-5. Partition #3 Base Map
6-12

Figure 6-6. Partition #12 Base Map
6-13

 - Coal Thickness. The Anderson seam coal thickness averages 55 feet.

 - Coal Depth. The depth of the Anderson seam averages 855 feet to top of coal.

 - Development. Anderson coal seam development is just starting.

 - Time Zero Plot. Not available.

 - Type Well. The history-matched Anderson well in Partition #4, adjusted for

depth, gas content and coal thickness, serves as the Anderson type well for

Partition #3. Since only one township contains Anderson coal of sufficient depth

and thickness, only an average well is used.

Table 6-8. Anderson Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery

(M bls)

Average 855 55 0.40 270

 • Canyon. The Canyon exists as a distinct seam primarily in the eastern and central

portions of Partition #3. The Canyon is sometimes included within or called the

Wyodak.

 - Area. The Canyon coal seam meets study inclusion criteria in 9 townships

located in the western portion of the partition.

 - Coal Thickness. The Canyon coal seam thickness averages 43 feet, with a range

of 25 to 65 feet.

 - Coal Depth. The depth to the top of the Canyon seam averages 970 feet, with a

range of 730 to 1,425 feet.

 - Development. Canyon coal seam development is just starting and is concentrated

in township 44N 74W.

 - Time Zero Plot. Not available.

 - Type Well. The history-matched Canyon well in Partition #4, adjusted for depth,

gas content and coal thickness, serves as the Canyon type well for Partition #3.
6-14

Table 6-9. Canyon Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery

(M bls)

Average 1,013 43 0.33 330

High 960 60 0.43 460

Low 830 30 0.25 230

 • Big George. The Big George coal seam, stratigraphically and depositionally similar to

the Wyodak, exists in the central portion of Partition #3 and in Partition #12.

 - Area. The Big George coal seam meets study inclusion criteria in 11 townships,

including one township in Partition #12.

 - Coal Thickness. The Big George seam coal thickness averages 100 feet, with a

range of 70 to 125 feet.

 - Coal Depth. The depth to the top of the Big George seam averages 1,280 feet,

with a range of 970 to 1,500 feet.

 - Development. Over 300 Big George coal wells have been drilled or permitted in

this partition.

 - Time Zero Plot. The time zero plot for 38 producing Big George wells in

T43-44N, R74W is provided in Figure 6-7.

 - Type Well. The history-matched Big George well shown in Figure 6-8, adjusted

for depth, gas content and coal thickness, serves as the Big George type well for

Partition #3.

Table 6-10. Big George Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery

(M bls)

Average 1,380 100 0.66 770

High 1,525 125 0.89 970

Low 1,420 70 0.48 540

 • Cook. The Cook coal seam exists at sufficient thickness in the eastern portion of

Partition #3.

 - Area. The Cook coal seam meets study inclusion criteria in two townships.

 - Coal Thickness. The Cook coal seam thickness averages 30 feet.
6-15

Time Zero Plot f or an Average Well

0

2,000

4,000

6,000

8,000

1 0,000

1 2,000

1 4,000

0 5 1 0 1 5 20 25

Ti me ( M ont hs)

0

5

10

15

20

25

30

35

40

GAS

WATER

Well Count

Figure 6-7. Big George Time Zero Plot
6-16

Gas and Water Production Rate (Mcfd; Bwpd)

Cumulative Gas and Water Recovery (MMcf; Mbw)

Days On

550

500

450

400

350

300

250

200

150

100

50

0

0 250 500 750 1,000 1,250 1,500 1,750 2,000 2,250 2,500 2,750 3,000 3,250 3,500 3,750

550

500

450

400

350

300

250

200

150

100

50

0

Actual

Water Rate

Actual

Gas Rate

Actual/Projected

Cum Water

Actual/Projected

Cum Gas

Figure 6-8. Big George Partition #3
6-17

 - Coal Depth. The depth to the top of the Cook seam averages 1,030 feet, with a

range of 930 to 1,125 feet.

 - Development. The Cook coal seam is essentially undeveloped.

 - Time Zero Plot. Not available.

 - Type Well. The history-matched Cook well in Partition #8, adjusted for depth,

gas content, and coal thickness, serves as the Cook type well for Partition #3. 

Because the Cook coal exists in only two townships with the same coal thickness,

only an average Cook well is used in Partition #3.

Table 6-11. Cook Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery

(M bls)

Average 1,060 30 0.29 200

Table 6-12. In-Place and Technically Recoverable CBM, Partitions #3 and #12

Coal Seam

No.

Full

Townships

Average

Depth

(ft)*

Average

Thickness

(ft)

Average Gas

Content

(cf/ton)

Gas in

Place

(Bcf)

Technically

Recoverable

Resources

(Bcf)

Anderson 1 800 55 70 160 110

Canyon 9 970 43 81 1,260 870

Big George 11 1,280 100 107 6,620 2,910

Cook 2 1,030 30 86 210 170

Totals 8,250 4,060

* Top of coal

6.4 Partition #4

6.4.1 Summary

The main features of Partition #4, in the east-central portion of the Powder River Basin, are as

follows:

 • The partition covers a 22-township area on the eastern edge of the PRB, from 45N to 52N

and from 70W to 73W, Figure 6-9.

 • A series of coal mines exists in the townships along the shallower eastern edge; as a

result, the bulk of CBM development is in the eight townships along the western edge of 
6-18

Figure 6-9. Partition #4 Base Map
6-19

this partition. The partition contains some of the earliest CBM wells and "fields" in the

PBR, such as Caballo and Bonepile.

 • Partition #4 contains 7 major coal seams in the Fort Union Formation. The depth to these

coals ranges from 450 to 1,500 feet, with coal seam thickness ranging from 23 to 73 feet

(township level averages). The gas in place in the partition is 4.2 Tcf, with technically

recoverable gas of 3,540 Bcf. The results, by coal seam, are provided in Table 6-20.

 • The stratigraphic sequence for some of the major coal seams in this partition, such as the

Anderson, Canyon and Cook, is shown in Figure 6-10, a sample log from Sec. 3, 53N,

74W. The log identifies coals that meet the study criteria for selection in that township

(depth greater than 300 feet and thickness greater than 20 feet. In addition, a series of

thinner coals, with thickness of 10 to 20 feet, exist in this partition, such as the Smith and

Swartz.

6.4.2 Geologic Background

Partition #4 is located along the eastern rim of the Powder River Coal Basin in an area of Fort

Union Formation outcrops. Structural strike is NW/SE with a southwestern dip of 1.5 degrees. 

Subtle structural nosing and low relief normal faulting locally interrupt the gentile southwest dip.

Stratigraphically, the coal seams in Partition #4 exist in two groups – an upper group consisting

of the Smith, Swartz, Anderson, Canyon, Wyodak, and Cook seams, and a lower group

consisting of the Wall, Pawnee and the Cache seams. These groups are recognizable by their

depth, stratigraphic proximity and thickness.

The upper group, a thick succession of coals separated by thin "parts" and "splits," is

characterized by shallow depth (450 to 790 feet) and considerable coal thickness (30 to 70 feet). 

Correlation challenges exist due to stratigraphic proximity and apparent stratigraphic overlap due

to averaging data over an entire township. (Some Powder River CBM geologist include all 

upper groups of coals within the Wyodak.)

The lower group is characterized by deeper depth (1,020 to 1,500), lower coal thickness (20 to

30 feet), and considerable stratigraphic separation (200 to 300) feet between coal seams.

CBM operators have extensively developed this partition, with the great majority of the wells in

the Wyodak seam and/or its stratigraphic equivalents, the Anderson and Canyon seams, that are

often called the Fort Union.

6.4.3 Discussion of Major Seams

 • Anderson. The first major coal seam in Partition #4 is the Anderson, often included in

the Wyodak seam interval. The stratigraphic proximity of the Anderson to the adjacent

Canyon, Smith and Swartz seams provides correlation challenges. (This can lead to

correlation problems especially in the eastern portion of the partition where the Fort

Union Formation thins dramatically.)
6-20

Canyon

Anderson

Cook Split

Cook

Not Shown:

Wall

Pawnee

Cache

Figure 6-10. Partition #4 Sample Log
6-21

 - Area. The Anderson coal seam meets study inclusion criteria in 6 townships

located in the western and central portions of the partition.

 - Coal Thickness. The Anderson seam coal thickness averages 30 feet, with a

range of 20 to 50 feet.

 - Coal Depth. The depth to the top of the Anderson seam averages 450 feet, with a

range of 300 to 650 feet.

 - Development. Figure 6-11 provides the location of the currently drilled Anderson

CBM wells.

 - Time Zero Plot. The time zero plot for 89 producing Anderson coal seam wells

in T51N, R73W is provided in Figure 6-12. After initial rates of 150 barrels of

water per day, the water rates decline to about 60 barrels per day at the end of

year 1. Gas production starts and peaks early at about 100 Mcfd indicating the

presence of free gas.

 - Type Well. The history-matched type well for the Anderson coal seam is

provided in Figure 6-13. After normalizing for coal thickness, depth and gas

content, the estimated gas and water recoveries are as follows:

Table 6-13. Anderson Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery

(M bls)

Average 480 30 0.12 150

High 700 50 0.29 240

Low 470 20 0.08 100

 • Canyon. The Canyon seam is stratigraphically below the Anderson and is also often

included within the Wyodak seam. Like the Anderson, the Canyon presents correlation

problems in the western portion of the study area due the proximity of adjacent coal

seams.

 - Area. The Canyon coal seam meets study inclusion criteria in 12 townships

located in the western and central portion of the partition.

 - Coal Thickness. The Canyon coal seam thickness averages 35 feet, with a range

of 25 to 50 feet.

 - Coal Depth. The depth to the top of the Canyon seam averages 540 feet, with a

range of 300 to 800 feet.
6-22

Figure 6-11. Partition #4 Anderson Wells
6-23

Time Zero Plot for an Average Well

0

1,000

2,000

3,000

4,000

5,000

6,000

0 2 4 6 8 10 12 14

Time (Months)

Production (Mcf/mo.; Barrel/mo.)

0

1

2

3

4

5

6

7

8

Well Count

GAS

WATER

Well Count

Figure 6-12. Canyon Time Zero Plot
6-24

Gas and Water Production Rate (Mcfd; Bwpd)

Cumulative Gas and Water Recovery (MMcf; Mbw)

Days On

150

140

130

120

110

100

90

80

70

60

50

40

30

20

0

0 250 500 750 1,000 1,250 1,500 1,750 2,000 2,250 2,500 2,750 3,000 3,250 3,500 3,750

Actual

Water Rate

Actual

Gas Rate

Actual/Projected

Cum Water

Actual/Projected

Cum Gas

10

150

140

130

120

110

100

90

80

70

60

50

40

30

20

0

10

Figure 6-13. Anderson Type Well, Partition #4
6-25

 - Development. Figure 6-14 provides the location of the currently drilled Canyon

CBM wells.

 - Time Zero Plot. The time zero plot for 173 producing Canyon coal seam wells in

T51-52N, R73W is provided in Figure 6-15. Initial water rates are 300 or more

barrels producing for the first year, declining to about 50 barrels per day at the

end of year 3. Gas production starts early and peaks at nearly 300 Mcfd during

year 1, indicating the presence of free gas.

 - Type Well. The history-matched type well for Canyon coal seam is provided in

Figure 6-16. After normalizing for coal thickness, depth and gas content, the

estimated gas and water recoveries are as follows below.

Table 6-14. Canyon Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery

(M bls)

Average 575 35 0.20 270

High 700 50 0.35 380

Low 550 25 0.14 190

 • Wyodak. The Wyodak seam is the stratigraphic equivalent of the combined Anderson

and Canyon seams. As such, separating the Anderson and Canyon from the Wyodak is

often arbitrary.

 - Area. The Wyodak coal seam meets study inclusion criteria in 6 townships

located in the western portion of the partition.

 - Coal Thickness. The Wyodak seam coal thickness averages 73 feet, with a range

of 70 to 80 feet.

 - Coal Depth. The depth to the top of the Wyodak seam averages 600 feet, with a

depth range of 330 to 750 feet.

 - Development. Figure 6-17 provides the locations of the currently drilled Wyodak

CBM wells.

 - Time Zero Plot. The time zero plot for 164 producing Wyodak coal seam wells

in T47-48N, R72W is provided in Figure 6-18. Initial water rates are at 600

barrels per day, declining to about 400 barrels per day at the end of year 1 and to

about 130 barrels per day at the end of year 4. Gas production increases steadily,

reaching 300 Mcfd during year 1. After a 12-month plateau, gas production

declines to about 150 Mcfd at the end of year 2 and to about 80 Mcf at the end of

year 4.
6-26

Figure 6-14. Partition #4 Canyon Wells
6-27

Time Zero Plot f or an Average Well

0

2,000

4,000

6,000

8,000

1 0,000

1 2,000

0 5 1 0 1 5 20 25 30 35 40 45

Time ( M ont hs)

0

20

40

60

80

100

120

140

160

180

200

GAS

WATER

Well Count

Figure 6-15. Canyon Time Zero Plot
6-28

Gas and Water Production Rate (Mcfd; Bwpd)

Cumulative Gas and Water Recovery (MMcf; Mbw)

Days On

400

350

300

250

200

150

100

50

0

0 250 500 750 1,000 1,250 1,500 1,750 2,000 2,250 2,500 2,750 3,000 3,250 3,500 3,750

Actual

Water Rate

Actual

Gas Rate

Actual/Projected

Cum Water

Actual/Projected

Cum Gas

400

350

300

250

200

150

100

50

0

Figure 6-16. Canyon Type Well, Partition #4
6-29

Figure 6-17. Partition #4 Wyodak Wells
6-30

Time Zero Plot f or an Average Well

0

5,000

1 0,000

1 5,000

20,000

25,000

0 5 1 0 1 5 20 25 30 35 40 45

T i me ( M ont hs)

0

20

40

60

80

100

120

140

160

GAS 180

WATER

Well Count

Figure 6-18. Wyodak Time Zero Plot
6-31

 - Type Well. The history-matched type well for the Wyodak coal seam is provided

in Figure 6-19. After normalizing for coal thickness, depth and gas content, the

estimated gas and water recoveries are as follows:

Table 6-15. Wyodak Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery

(M bls)

Average 670 73 0.48 960

High 760 80 0.58 1,060

Low 400 70 0.28 930

 • Cook. The Cook seam defines the base of the upper group of Fort Union coals in

Partition #4. The Cook seam is stratigraphically below the Canyon and Wyodak

equivalents. The proximity of the Cook seam to the basal boundary of the Wyodak and

equivalents poses correlation problems throughout the partition.

 - Area. The Cook coal seam meets study inclusion criteria in 5 townships in the

western portion of the partition.

 - Coal Thickness. The Cook seam coal thickness averages 31 feet, with a range of

20 to 50 feet. 

 - Coal Depth. The depth to the top of the Cook seam averages 790 feet, with a

depth range of 600 to 930 feet. 

 - Development. The drilled Cook CBM wells are shown in Figure 6-20.

 - Time Zero Well. Not available.

 - Type Well. The history-matched Cook well in Partition #8, adjusted for depth,

gas content, permeability and coal thickness, serves as the Cook type well for

Partition #4.

Table 6-16. Cook Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery

(M bls)

Average 820 31 0.23 210

High 900 50 0.41 340

Low 620 20 0.12 140
6-32

Gas and Water Production Rate (Mcfd; Bwpd)

Cumulative Gas and Water Recovery (MMcf; Mbw)

Days On

700

650

600

550

500

450

400

350

300

250

200

150

100

50

0

700

650

600

550

500

450

400

350

300

250

200

150

100

50

0 0 250 500 750 1,000 1,250 1,500 1,750 2,000 2,250 2,500 2,750 3,000 3,250 3,500 3,750

Actual

Water Rate

Actual

Gas Rate

Actual/Projected

Cum Water

Actual/Projected

Cum Gas

Figure 6-19. Wyodak Type Well, Partition #4
6-33

Figure 6-20. Partition #4 Cook Wells
6-34

 • Wall. The Wall seam defines the top of the lower group of Fort Union Formation coals

in Partition #4. The Wall coal seam is stratigraphically below the Cook, separated by an

average of 230 feet.

 - Area. The Wall coal seam meets study inclusion criteria in 5 townships in the

central and western portions of the partition.

 - Coal Thickness. The Wall seam coal thickness averages 27 feet, with a range of

20 to 40 feet. 

 - Coal Depth. The depth to the top of the Wall seam averages 1,020 feet, with a

depth range of 800 to 1250 feet. 

 - Development. The drilled Wall CBM wells are shown in Figure 6-21.

 - Time Zero Plot. The time zero plot for 19 producing Wall coal seam wells in

Partition #4 is provided in Figure 6-22. Initial water rates are 300 or more barrels

producing for the first year, declining to about 50 barrels per day at the end of

year 3. Gas production starts early and peaks at nearly 90 Mcfd during year 1.

 - Type Well. The history-matched type well for Wall coal seam is provided in

Figure 6-23. After normalizing for coal thickness, depth and gas content, the

estimated gas and water recoveries are as follows in Table 6-17.

Table 6-17. Wall Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery

(M bls)

Average 1,050 27 0.24 460

High 1,060 40 0.35 680

Low 970 20 0.16 340

 • Pawnee. The Pawnee seam is stratigraphically below the Wall, separated by 275 feet of

section.

 - Area. The Pawnee coal seam meets study inclusion criteria in 5 townships in the

western portion of the partition.

 - Coal Thickness. The Pawnee seam coal thickness averages 27 feet with a range

of 25 to 30 feet.

 - Coal Depth. The depth to the top of the Pawnee seam averages 1,290 feet, with a

depth range of 1,150 to 1,500 feet.
6-35

Figure 6-21. Partition #4 Wall Wells
6-36

Time Zero Plot for an Average Well

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

0 2 4 6 8 10 12 14 16 18 20

Time (Months)

Production (Mcf/mo.; Barrel/mo.)

0

2

4

6

8

10

12

14

16

18

20

Well Count

GAS

WATER

Well Count

Figure 6-22. Wall Time Zero Plot
6-37

Gas and Water Production Rate (Mcfd; Bwpd)

Cumulative Gas and Water Recovery (MMcf; Mbw)

Days On

400

350

300

250

200

150

100

50

0

0 250 500 750 1,000 1,250 1,500 1,750 2,000 2,250 2,500 2,750 3,000 3,250 3,500 3,750

Actual

Water Rate

Actual

Gas Rate

Actual/Projected

Cum Water

Actual/Projected

Cum Gas

450

400

350

300

250

200

150

100

50

0

450

Figure 6-23. Wall Type Well, Partition #4
6-38

 - Development. Figure 6-24 provides the location of the currently drilled Pawnee

CBM wells.

 - Time Zero Plot. Not available.

 - Type Well. The history-matched Pawnee well in Partition #8, adjusted for depth,

gas content, permeability and coal thickness, serves as the Pawnee type well for

Partition #4.

Table 6-18. Pawnee Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery

(M bls)

Average 1,320 27 0.35 360

High 1,330 30 0.40 400

Low 1,230 25 0.30 330

 • Cache. The Cache coal seam is the basal unit of the lower group of Fort Union coals in

Partition #4. The Cache seam is stratigraphically below the Pawnee, separated by

205 feet of section.

 - Area. The Cache coal seam meets study inclusion criteria in 5 townships in the

western portion of the partition.

 - Coal Thickness. The Cache seam coal thickness averages 23 feet, with a range of

20 to 30 feet.

 - Coal Depth. The depth to the top of the Pawnee seam averages 1,500 feet, with a

depth range of 1,150 to1,750 feet.

 - Development. The Cache seam is lightly developed, as shown in Figure 6-25.

 - Time Zero Well. Not available.

 - Type Well. The history-matched Pawnee well in Partition #8, adjusted for depth,

gas content, permeability and coal thickness, serves as the Cache type well for

Partition #4.
6-39

Figure 6-24. Partition #4 Pawnee Wells
6-40

Figure 6-25. Partition #4 Cache Wells
6-41

Table 6-19. Cache Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery

(M bls)

Average 1,520 23 0.34 300

High 1,780 25 0.43 330

Low 1,170 20 0.23 260

Table 6-20. In-Place and Technically Recoverable CBM, Partition #4

Coal Seam No. Full

Townships

Average

Depth

(ft)*

Average

Thickness

(ft)

Average

Gas Content

(cf/ton)

Gas In

Place

(Bcf)

Technically

Recoverable

(Bcf)

Anderson 6 450 30 40 400 290

Canyon 12 540 35 47 920 800

Wyodak 6 601 73 54 890 770

Cook 5 790 31 67 450 350

Wall 5 1,020 27 84 440 350

Pawnee 5 1,295 27 106 570 510

Cache 5 1,550 23 121 540 480

Totals 44 4,210 3,550

* To top of coal

6.5 Partition #5

6.5.1 Summary

The main features of Partition #5, in the central portion of the Powder River Basin, are as

follows:

 • The partition covers a 38-township area in the PRB, from 45N to 52N and from 73W to

77W, Figure 6-26.

 • Partition #5 contains 12 major coal seams in the Wasatch and Fort Union Formation. 

The depth to these coals ranges from 320 to 2,260 feet, with coal seam thickness ranging

from 20 to 150 feet (township level averages). The gas in place in the partition is

25.5 Tcf, with technically recoverable gas of 14,910 Bcf. The results by coal seam are

provided in Table 6-33.
6-42

Figure 6-26. Partition #5 Base Map
6-43

6.5.2 Discussion of Major Seams

 • Felix. The first major coal seam in Partition #5 is the Felix. The stratigraphic proximity

of the Felix to the adjacent Roland seam provides correlation challenges. 

 - Area. The Felix coal seam meets study inclusion criteria in 4 townships in the

eastern portion of the partition.

 - Coal Thickness. The Felix seam coal thickness averages 24 feet, with a range of

20 to 30 feet.

 - Coal Depth. The depth to the top of the Felix seam averages 530 feet, with a

range of 320 to 780 feet.

 - Development. The Felix coal is essentially undeveloped.

 - Time Zero Plot. Not available.

 - Type Well. After adjustment for depth, gas content, permeability and coal

thickness, the type well for the Smith coal seam in Partition #5, discussed later,

serves as the type well for the Felix coal seam in this partition.

Table 6-21. Felix Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery

(M bls)

Average 555 24 0.12 90

 • Roland. The Roland seam is stratigraphically below the Felix. Like the Felix, the

Roland presents correlation problems in the eastern portion of the partition due the

proximity of adjacent coal seams. 

 - Area. The Roland coal seam meets study inclusion criteria in only 2 townships

located in the northern portion of the partition.

 - Coal Thickness. The Roland coal seam thickness averages 25 feet, with a range

of 20 to 30 feet.

 - Coal Depth. The depth to the top of the Roland seam averages 540 feet. 

 - Development. The Roland coal is essentially undeveloped. 

 - Time Zero Plot. Not available.
6-44

 - Type Well. After adjustment for depth, gas content, permeability and coal

thickness, the type well for the Smith coal seam in Partition #5, discussed later,

serves as the type well for the Roland coal seam in this partition.

Table 6-22. Roland Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery

(M bls)

Average 565 25 0.13 100

 • Smith. The Smith seam lies stratigraphically below the Roland seam and is a significant

coal seam in Partition #5.

 - Area. The Smith coal seam meets study inclusion criteria in 18 townships located

throughout the partition.

 - Coal Thickness. The Smith seam coal thickness averages 40 feet, with a range of

25 to 60 feet.

 - Coal Depth. The depth to the top of the Smith seam averages 820 feet, with a

depth range of 320 to 1,200 feet.

 - Development. The are a total of 339 drilled or permitted Smith CBM wells in

Partition #5.

 - Time Zero Plot. The time zero plot for 10 producing Smith coal seam wells is

provided in Figure 6-27. Initial water rates are at 130 barrels per day declining to

about 70 barrels per day after 6 months. Gas production increases steadily,

reaching 40 Mcfd during year 1.

 - Type Well. The history-matched type well for the Smith coal seam is provided in

Figure 6-28. After normalizing for coal thickness, depth and gas content, the

estimated gas and water recoveries are as follows.

Table 6-23. Smith Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery

(M bls)

Average 860 40 0.31 150

High 1160 60 0.47 230

Low 500 25 0.12 100

 • Swartz. Stratigraphically, the Swartz seam is between the overlying Smith seam and the

underlying Anderson coal seam.
6-45

Time Zero Plot for an Average Well

0

1,000

2,000

3,000

4,000

5,000

6,000

0 2 4 6 8 10 12 14 16 18 20

Time (Months)

Production (Mcf/mo.; Barrel/mo.)

0

2

4

6

8

10

12

Well Count

GAS

WATER

Well Count

Figure 6-27. Smith Time Zero Plot
6-46

Gas and Water Production Rate (Mcfd; Bwpd)

Cumulative Gas and Water Recovery (MMcf; Mbw)

Days On

200

160

20

0

0 250 500 750 1,000 1,250 1,500 1,750 2,000 2,250 2,500 2,750 3,000 3,250 3,500 3,750

Actual

Water Rate

Actual

Gas Rate

Actual/Projected

Cum Water

Actual/Projected

Cum Gas

40

60

80

100

120

140

180

200

160

20

0

40

60

80

100

120

140

180

Figure 6-28. Smith Type Well, Partition #5
6-47

 - Area. The Swartz coal seam meets study inclusion criteria in 2 townships in the

northern portion of the partition.

 - Coal Thickness. The Swartz seam coal thickness averages 43 feet, with a range

of 40 to 45 feet. 

 - Coal Depth. The depth to the top of the Swartz seam averages 740 feet, with a

depth range of 700 to 770 feet. 

 - Development. The Swartz coal is essentially undeveloped.

 - Time Zero Well. Not available.

 - Type Well. The history-matched Smith well in Partition #5, adjusted for depth,

gas content, permeability and coal thickness, serves as the Swartz type well in this

partition.

Table 6-24. Swartz Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery

(M bls)

Average 785 43 0.30 160

 • Anderson. The Anderson coal seam is stratigraphically below the Swartz, separated by

an average of 300 feet of section. The Anderson seam is often included with the Canyon

seam or the Wyodak elsewhere in the Powder River Basin.

 - Area. The Anderson coal seam meets study inclusion criteria in 9 townships.

 - Coal Thickness. The Anderson seam coal thickness averages 38 feet, with a

range of 25 to 60 feet. 

 - Coal Depth. The depth to the top of the Anderson seam averages 1,030 feet, with

a depth range of 800 to 1,400 feet. 

 - Development. The are a total of 362 drilled or permitted Anderson CBM wells in

Partition #5.

 - Time Zero Plot. The time zero plot for 216 producing Anderson coal seam wells

in Partition #5 is provided in Figure 6-29. Initial water rates remain high, at 250

to 300 barrels per day through the first 2 years. Gas production starts early and

reaches 60 Mcfd during year 1, indicating the presence of free gas.
6-48

Time Zero Plot for an Average Well

0

5,000

10,000

15,000

20,000

25,000

30,000

0 5 10 15 20 25 30

Time (Months)

Production(Mcf/mo.; Barrel/mo.)

0

50

100

150

200

250

Well Count

GAS

WATER

Well Count

Figure 6-29. Anderson Time Zero Plot
6-49

 - Type Well. The history-matched Anderson well in Partition #8, adjusted for

depth, gas content, permeability and coal thickness, serves as the Anderson type

well in this partition.

Table 6-25. Anderson Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery

(M bls)

Average 1070 38 0.33 100

High 860 60 0.43 160

Low 920 25 0.20 70

 • Canyon. The Canyon seam is the most intensely developed coal seam in Partition #5.

 - Area. The Canyon coal seam meets study inclusion criteria in 16 townships

throughout the partition.

 - Coal Thickness. The Canyon seam coal thickness averages 39 feet with a range

of 30 to 55 feet.

 - Coal Depth. The depth to the top of the Canyon seam averages 1,060 feet, with a

depth range of 700 to 1,400 feet. 

 - Development. A total of 1,610 drilled or permitted Canyon CBM wells exist in

Partition #5.

 - Time Zero Plot. The time zero plot for 73 producing Canyon coal seam wells in

Partition #5 is provided in Figure 6-30. Initial water rates are high, at 300 to 450

barrels per day, dropping to about 130 barrels per day after 18 months. Gas

production reaches 80 Mcfd after 6 months. 

 - Type Well. The history-matched Canyon well in Partition #4, adjusted for depth,

gas content, permeability and coal thickness, serves as the Canyon type well for

Partition #5.

Table 6-26. Canyon Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery

(M bls)

Average 1,100 39 0.32 300

High 1,060 55 0.43 420

Low 1,030 30 0.23 230
6-50

Time Zero Plot for an Average Well

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

0 5 10 15 20 25 30

Time (Months)

Production(Mcf/mo.; Barrel/mo.)

0

10

20

30

40

50

60

70

80

Well Count

GAS

WATER

Well Count

Figure 6-30. Canyon Time Zero Plot
6-51

 • Big George. The Big George is the second most intensely developed seam in

Partition #5. It lies approximately 200 feet deeper than the Canyon seam and is

equivalent to the Wyodak coal in the eastern portion of this partition.

 - Area. The Big George coal seam meets study inclusion criteria in 16 townships

in the central and southern portions of the partition.

 - Coal Thickness. The Big George seam coal thickness averages 97 feet, with a

range of 80 to 140 feet. 

 - Coal Depth. The depth to the top of the Big George seam averages 1,280 feet,

with a depth range of 1,150 to1,460 feet. 

 - Development. The are a total of 1,027 drilled or permitted Big George CBM

wells in Partition #5.

 - Time Zero Well. The time zero plot for 121 producing Big George coal seam

wells in Partition #5 is provided in Figure 6-31. Initial water rates start at 480

barrels per day, climbing to a peak late in year 2 at 1,800 barrels per day. Water

rates drop off only slightly at the end of year 2 to 1,330 barrels per day. Gas

production begins slowly and gradually peaks at 270 Mcfd after 20 months. The

time zero plot for the Big George wells in Partition #5 shows constraints in water

production during initial production. Therefore, a relatively intensely drilled area

of the partition, Sec. 16 T44N, R77W, was examined in more detail. The location

of these wells and the elevation map for the section is provided in Figure 6-32. 

These 17 wells were combined to establish the time zero plot for the Big George

coal well in Partition #5, Figure 6-33.

 - Type Well. The history-matched Big George coal seam well in Partition #5 was

used to develop the 80 acre type well in Figure 6-34. After normalizing for coal

thickness, depth, and gas content, the estimated gas and water recoveries are as

follows in Table 6-27.

Table 6-27. Big George Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery 

(M bls)

Average 1,380 97 0.69 1,520

High 1,440 140 1.05 2,210

Low 1,320 80 0.56 1,260

 • Wyodak. Essentially an equivalent of the thick Big George seam, the Wyodak coal seam

exists only on the eastern side of the partition, adjacent to Partition #4. 
6-52

Time Zero Plot for an Average Well

0

10,000

20,000

30,000

40,000

50,000

60,000

0 5 10 15 20 25

Time (Months)

Production (Mcf/mo.; Barrel/mo.)

0

20

40

60

80

100

120

140

Well Count

GAS

WATER

Well Count

Figure 6-31. Big George Coal Seam - Aggregate
6-53

Figure 6-32. Big George Coal Seam Well Location and Elevation Map, Partition #5.
6-54

Time Zero Plot for an Average Well

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

100,000

0 5 10 15 20 25

Time (Months)

Production (Mcf/mo.; Barrel/mo.)

0

0

0

1

1

1

1

Well Count

GAS

WATER

Well Count

Figure 6-33. Big George Time Zero Plot
6-55

Gas and Water Production Rate (Mcfd; Bwpd)

Cumulative Gas and Water Recovery (MMcf; Mbw)

Days On

400

0

0 250 500 750 1,000 1,250 1,500 1,750 2,000 2,250 2,500 2,750 3,000 3,250 3,500 3,750

Actual

Water Rate

Actual

Gas Rate

Actual/Projected

Cum Water

Actual/Projected

Cum Gas

800

1,200

1,600

2,000

2,400

400

0

800

1,200

1,600

2,000

2,400

Figure 6-34. Big George Type Well Partition #5
6-56

 - Area. The Wyodak coal seam meets study inclusion criteria in 2 townships in the

southeastern portion of the partition.

 - Coal Thickness. The Wyodak seam coal thickness averages 73 feet, with a range

of 70 to 75 feet. 

 - Coal Depth. The depth to the top of the Wyodak seam averages 1,000 feet, with a

depth range of 950 to 1,050. 

 - Development. The Wyodak coal seam is extensively developed with nearly 700

drilled or permitted wells in Partition #5.

 - Time Zero Well. The time zero plot for 442 producing Wyodak coal seam wells

in Partition #5 is provided in Figure 6-35. Initial water rates start at 270 barrels

per day. Gas production begins early at about 60 Mcfd and increases steadily to

nearly 220 Mcfd at the end of 2 years.

 - Type Well. The history-matched Wyodak well in Partition #4, adjusted for depth,

gas content, permeability and coal thickness, serves as the type well for

Partition #5. Because the Wyodak coal exists in only two townships with

relatively uniform production, only an average well is used. 

Table 6-28. Wyodak Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery 

(M bls)

Average 1,075 73 0.37 480

 • Cook. The Cook seam defines the base of the upper group of Fort Union coals in

Partition #5. The proximity of the Cook seam to the basal boundary of the Wyodak and

equivalents poses correlation problems throughout the partition. 

 - Area. The Cook coal seam meets study inclusion criteria in 17 townships

throughout the partition.

 - Coal Thickness. The Cook seam coal thickness averages 40 feet, with a range of

25 to 60 feet.

 - Coal Depth. The depth to the top of the Cook seam averages 1,320 feet, with a

depth range of 900 to 1,700. 

 - Development. A total of 1,321 drilled or permitted Cook CBM wells exist in

Partition #5.

 - Time Zero Well. Not available.
6-57

Time Zero Plot for an Average Well

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

0 5 10 15 20 25 30

Time (Months)

Production(Mcf/mo.; Barrel/mo.)

0

50

100

150

200

250

300

350

400

450

500

Well Count

GAS

WATER

Well Count

Figure 6-35. Wyodak Time Zero Plot
6-58

 - Type Well. The history-matched Cook well in Partition #8, adjusted for depth,

gas content, permeability and coal thickness, serves as the Cook type well for

Partition #5.

Table 6-29. Cook Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery 

(M bls)

Average 1,360 40 0.37 270

High 1,460 60 0.58 410

Low 960 25 0.16 170

 • Wall. The Wall coal seam defines the top of the lower group of Fort Union Formation

coals in Partition #5. The Wall coal seam is stratigraphically below the Cook, separated

by an average of 175 feet. 

 - Area. The Wall coal seam meets study inclusion criteria in 16 townships

throughout the partition.

 - Coal Thickness. The Cook seam coal thickness averages 33 feet, with a range of

20 to 45 feet. 

 - Coal Depth. The depth to the top of the Cook seam averages 1,500 feet, with a

depth range of 1,220 to 1,900. 

 - Development. The Wall coal seam is extensively developed in only one township

in the southern portion of Partition #5.

 - Time Zero Well. Not available.

 - Type Well. The history-matched Wall well in Partition #4, adjusted for depth, gas

content, permeability and coal thickness, serves as the type well for the Wall seam

in Partition #5.

Table 6-30. Wall Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery 

(M bls)

Average 1,530 33 0.31 560

High 1,520 45 0.39 760

Low 1,470 20 0.18 340

 • Pawnee. The Pawnee coal seam is stratigraphically below the Wall, separated by an

average of 215 feet.
6-59

 - Area. The Pawnee coal seam meets study inclusion criteria in 18 townships

throughout the central and northern portions of the partition.

 - Coal Thickness. The Pawnee seam coal thickness averages 41 feet, with a range

of 25 to 70 feet. 

 - Coal Depth. The depth to the top of the Pawnee seam averages 1,710 feet, with a

depth range of 1,350 to 2,260. 

 - Development. A total of 368 drilled or permitted Pawnee CBM wells,

concentrated in a handful of townships, exist in Partition #5.

 - Time Zero Well. Not available.

 - Type Well. The history-matched Pawnee well in Partition #8, adjusted for depth,

gas content, permeability and coal thickness, serves as the Pawnee type well for

Partition #5.

Table 6-31. Pawnee Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery 

(M bls)

Average 1,750 41 0.45 540

High 1,470 70 0.64 920

Low 1,580 25 0.25 330

 • Cache. The Cache coal seam is the basal unit of the lower group of Fort Union coals in

Partition #5. The Cache seam is stratigraphically below the Pawnee, separated by

approximately 300 feet of section.

 - Area. The Cache coal seam meets study inclusion criteria in 14 townships

throughout the central and northern portions of the partition.

 - Coal Thickness. The Cache seam coal thickness averages 32 feet, with a range of

20 to 50 feet. 

 - Coal Depth. The depth to the top of the Cache seam averages 2,020 feet, with a

depth range of 1,510 to 2,350. 

 - Development. The Cache coal seam is essentially undeveloped. 

 - Time Zero Well. Not available.
6-60

 - Type Well. The history-matched Pawnee well in Partition #8, adjusted for depth,

gas content, permeability and coal thickness, serves as the Cache type well for

Partition #5.

Table 6-32. Cache Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery 

(M bls)

Average 2,050 32 0.34 420

High 1,910 50 0.50 660

Low 2,220 20 0.14 260

Table 6-33. In-Place and Technically Recoverable CBM, Partition #5

Coal Seam No. Full

Townships

Average

Depth

(ft)*

Average

Thickness

(ft)

Average

Gas Content

(cf/ton)

Gas In 

Place

(Bcf)

Technically

Recoverable

(Bcf)

Felix 4 530 24 46 180 140

Roland 2 540 25 47 100 80

Smith 18 820 39 70 2,310 1,560

Swartz 2 740 43 63 220 180

Anderson 9 1030 38 86 1,180 830

Canyon 16 1060 39 88 2,320 1,500

Big George 16 1280 97 107 6,760 3,510

Wyodak 2 1000 73 85 250 210

Cook 17 1320 40 109 3,060 1,810

Wall 16 1500 32 120 2,250 1,350

Pawnee 18 1710 41 137 4,000 2,320

Cache 14 2020 32 159 2,700 1,320

Wildcat 1 2190 45 101 180 90

Totals 25,510 14,910

* To top of coal

6.6 Partition #6

6.6.1 Summary

The main features of Partition #6, in the western portion of the Powder River Basin, are as

follows:

 • The partition covers a 31-township area in the west-central portion of the PRB, from 45N

to 52N and from 78W to 80W in the south and 78W to 82W in the north, Figure 6-36.
6-61

Figure 6-36. Partition #6 Base Map
6-62

 • Partition #5 contains 12 major coal seams in the Wasatch and Fort Union Formations. 

The depth to these coals ranges from 560 to 2,900 feet, with coal seam thickness ranging

from 20 to 100 feet (township level averages). The gas in place in the partition is

6.2 Tcf, with technically recoverable gas of 3,460 Bcf. The results, by coal seam, are

provided in Table 6-45.

6.6.2 Discussion of Major Seams

 • Cameron. The first major coal seam in Partition #6 is the Cameron. The Cameron is

separated from the underlying Murry seam by an average of 100 feet of section.

 - Area. The Cameron coal seam meets study inclusion criteria in one township in

the northwestern portion of the partition.

 - Coal Thickness. The Cameron seam coal thickness averages 20 feet.

 - Coal Depth. The depth to the top of the Cameron seam averages 700 feet. 

 - Development. The Cameron coal seam is essentially undeveloped in Partition #6.

 - Time Zero Plot. Not available.

 - Type Well. After adjustment for depth, gas content, permeability and coal

thickness, the type well for the Smith coal seam in Partition #5 serves as the type

well for the Cameron coal seam.

Table 6-34. Cameron Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery 

(M bls)

Average 720 20 0.14 80

 • Murry. The Murry seam is stratigraphically below the Cameron coal seam. Due to

stratigraphic proximity, separation of these seams is difficult outside of the northwestern

portion of the partition.

 - Area. The Murry coal seam meets study inclusion criteria in one township

located in the northwestern portion of the partition.

 - Coal Thickness. The Murry coal seam thickness averages 50 feet.

 - Coal Depth. The depth to the top of the Murry seam averages 800 feet.

 - Development. The Murry seam is essentially undeveloped in Partition #6.

 - Time Zero Plot. Not available
6-63

 - Type Well. After adjustment for depth, gas content, permeability and coal

thickness, the type well for the Smith coal seam in Partition #5 serves as the type

well for the Murry coal seam.

Table 6-35. Murry Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery 

(M bls)

Average 850 50 0.40 190

 • Felix. The Felix coal seam lies stratigraphically below the Cameron and Murry seams.

 - Area. The Felix coal seam meets study inclusion criteria in one township located

in the northwestern portion of the partition.

 - Coal Thickness. The Felix seam coal thickness averages 30 feet.

 - Coal Depth. The depth to the top of the Felix seam averages 750 feet.

 - Development. The Felix seam is essentially undeveloped in Partition #6.

 - Time Zero Plot. Not available.

 - Type Well. After adjustment for depth, gas content, permeability and coal

thickness, the type well for the Smith coal seam in Partition #5 serves as the type

well for the Felix coal seam.

Table 6-36. Felix Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery 

(M bls)

Average 780 30 0.22 120

 • Ucross. The Ucross coal seam is often difficult to distinguish from the overlying

Cameron, Murry, and Felix seams.

 - Area. The Ucross coal seam meets study inclusion criteria in 3 townships in the

northwestern portion of the partition.

 - Coal Thickness. The Ucross seam coal thickness averages 23 feet, with a range

of 20 to 25 feet.

 - Coal Depth. The depth to the top of the Ucross seam averages 790 feet, with a

depth range of 560 to 950 feet. 
6-64

 - Development. A small number of Ucross coal seams exist in one of the townships in Partition #6.

 - Time Zero Well. Not available.

 - Type Well. The history-matched Smith well in Partition #5, adjusted for depth,

gas content, permeability and coal thickness, serves as the Ucross type well in this

partition.

Table 6-37. Ucross Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery 

(M bls)

Average 810 23 0.18 90

 • Roland. The Roland is the uppermost Fort Union coal seam in Partition #6.

 - Area. The Roland coal seam meets study inclusion criteria in 5 townships in the

northern portion of the partition.

 - Coal Thickness. The Roland seam coal thickness averages 21 feet, with a range

of 20 to 25 feet. 

 - Coal Depth. The depth to the top of the Roland seam averages 1,060 feet, with a

depth range of 830 to 1,480 feet. 

 - Development. The are a total of 107 drilled or permitted Roland CBM wells in

two of the townships in Partition #6.

 - Time Zero Plot. Not available.

 - Type Well. The history-matched Smith well in Partition #5, adjusted for depth,

gas content, permeability and coal thickness, serves as the Roland type well in

this partition.

Table 6-38. Roland Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery 

(M bls)

Average 1,080 21 0.16 80

 • Anderson. The Anderson coal seam is thin and relatively undeveloped in Partition #6.

 - Area. The Anderson coal seam meets study inclusion criteria in 3 townships in

the central portion of the partition.
6-65

 - Coal Thickness. The Anderson seam coal thickness averages 30 feet, with a

range of 20 to 40 feet. 

 - Coal Depth. The depth to the top of the Anderson seam averages 1,220 feet, with

a depth range of 1,030 to 1,480 feet. 

 - Development. The Anderson coal seam is undeveloped in Partition #6.

 - Time Zero Plot. Not available.

 - Type Well. The history-matched Anderson well in Partition #8, adjusted for

depth, gas content, permeability and coal thickness, serves as the Anderson type

well for Partition #6.

Table 6-39. Anderson Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery 

(M bls)

Average 1,250 30 0.26 80

 • Canyon. The Canyon seam in Partition #6 is approximately 300 feet deeper than the

overlying Anderson seam. 

 - Area. The Canyon coal seam meets study inclusion criteria in 8 townships

throughout the partition.

 - Coal Thickness. The Canyon seam coal thickness averages 30 feet, with a range

of 20 to 50 feet. 

 - Coal Depth. The depth to the top of the Canyon seam averages 1,520 feet, with a

depth range of 1,300 to1,720 feet. 

 - Development. The Canyon coal seam is undeveloped in Partition #6.

 - Time Zero Well. Not available.

 - Type Well. The history-matched Canyon well in Partition #4, adjusted for depth,

gas content, permeability and coal thickness, serves as the Canyon type well for

Partition #6.

Table 6-40. Canyon Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery 

(M bls)

Average 1,550 30 0.32 230
6-66

High 1,600 50 0.27 190

Low 1,740 20 0.24 150

 • Big George. Stratigraphically equivalent to the Anderson and Canyon coals, the Big

George seam exists in areas where these two coals merge.

 - Area. The Big George coal seam meets study inclusion criteria in 2 townships in

the southeastern portion of the partition.

 - Coal Thickness. The Big George seam coal thickness averages 85 feet, with a

range of 70 to 100 feet. 

 - Coal Depth. The depth to the top of the Big George seam averages 1,665 feet,

with a depth range of 1,630 to 1,700 feet. 

 - Development. The Big George coal seam is essentially undeveloped in

Partition #6.

 - Time Zero Well. Not available.

 - Type Well. The history-matched Big George well in Partition #3, adjusted for

depth, gas content, permeability and coal thickness, serves as the Big George type

well for Partition #6.

Table 6-41. Big George Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery 

(M bls)

Average 1,750 85 0.85 660

 • Cook. The Cook seam defines the base of the upper group of Fort Union coals in

Partition #6. The proximity of the Cook seam to the basal boundary of the Canyon and

equivalents poses correlation problems.

 - Area. The Cook coal seam meets study inclusion criteria in 2 townships along the

eastern edge of the partition.

 - Coal Thickness. The Cook seam coal thickness averages 58 feet, with a range of

25 to 90 feet. 

 - Coal Depth. The depth to the top of the Cook seam averages 1,863 feet, with a

depth range of 1,850 to 1,875 feet. 

 - Development. The Cook seam is essentially undeveloped in Partition #6.
6-67

 - Time Zero Well. Not available.

 - Type Well. The history-matched Cook well in Partition #8, adjusted for depth,

gas content, permeability and coal thickness, serves as the Cook type well for

Partition #6.

Table 6-42. Cook Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery 

(M bls)

Average 1,920 58 0.66 390

 • Wall. The Wall coal seam defines the top of the lower group of Fort Union Formation

coals in Partition #6.

 - Area. The Wall coal seam meets study inclusion criteria in one township in the

northeastern portion of the partition.

 - Coal Thickness. The Cook seam coal thickness averages 40 feet.

 - Coal Depth. The depth to the top of the Cook seam averages 1,630 feet.

 - Development. The are no Wall CBM wells drilled in Partition #6.

 - Time Zero Well. Not available.

 - Type Well. The history-matched Wall well in Partition #8, adjusted for depth, gas

content, permeability and coal thickness, serves as the type well for the Wall seam

in Partition #6.

Table 6-43. Wall Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery 

(M bls)

Average 1,670 40 0.38 520

 • Pawnee. The Pawnee coal seam is stratigraphically below the Wall, separated by an

average interval of 365 feet.

 - Area. The Pawnee coal seam meets study inclusion criteria in 4 townships in the

north-central portion of the partition.

 - Coal Thickness. The Pawnee seam coal thickness averages 44 feet, with a range

of 20 to 100 feet.
6-68

 - Coal Depth. The depth to the top of the Pawnee seam averages 2,000 feet, with a

depth range of 1,730 to 2,270 feet.

 - Development. The Pawnee coal seam is essentially undeveloped in Partition #6.

 - Time Zero Well. Not available.

 - Type Well. The history-matched Pawnee well in Partition #8, adjusted for depth,

gas content, permeability and coal thickness, serves as the Pawnee type well for

Partition #6.

Table 6-44. Pawnee Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery 

(M bls)

Average 2,040 44 0.47 580

High 2,000 100 1.05 1,320

Low 1,750 20 0.19 260

Table 6-45. In-Place and Technically Recoverable CBM, Partition #6

Coal Seam No. Full

Townships

Average

Depth

(ft)*

Average

Thickness

(ft)

Average

Gas Content

(cf/ton)

Gas In 

Place

(Bcf)

Technically

Recoverable

(Bcf)

Cameron 1 700 20 60 50 40

Felix 1 750 30 63 140 110

Murry 1 800 50 69 80 60

Ucross 3 790 23 66 190 150

Roland 5 1,060 21 86 370 240

Anderson 3 1,220 30 99 370 220

Canyon 8 1,520 30 123 1,090 660

Big George 2 1,670 85 136 930 490

Cook 2 1,860 58 147 690 380

Wall 1 1,630 40 130 200 110

Pawnee 4 2,000 44 158 1,270 620

Wildcat 4 2,640 25 191 760 370

Totals 6,150 3,460

* To top of coal

6.7 Partition #7

6.7.1 Summary

The main features of Partition #7, in the northern Wyoming portion of the Powder River Basin,

are as follows:
6-69

 • The partition covers a 23-township area in the northwestern portion of the PRB, from

53N to 58N and from 78W to 82W, Figure 6-37.

 • Partition #7 contains 9 major coal seams in the Wasatch and Fort Union Formations. The

depth to these coals ranges from about 390 to 2,980 feet, with coal seam thickness

ranging from 20 to 40 feet (township level averages). The gas in place in the partition is

2.8 Tcf, with technically recoverable gas of 1,680 Bcf. The results, by coal seam, are

provided in Table 6-55.

6.7.2 Discussion of Major Seams

 • Wasatch. The shallowest major coal seam in Partition #7 is the Wasatch that combines

the Felix and Ucross seams. The Wasatch is separated from the underlying Roland seam

by an average of 280 feet of section.

 - Area. The Wasatch coal seam meets study inclusion criteria in 6 townships

located in the southern portion of the partition.

 - Coal Thickness. The Wasatch seam coal thickness averages 25 feet, with a range

of 20 to 34 feet.

 - Coal Depth. The depth to the top of the Wasatch seam averages 540 feet, with a

range of 390 to 730 feet. 

 - Development. The are a total of 124 drilled or permitted Wasatch CBM wells in

Partition #7.

 - Time Zero Plot. Not available.

 - Type Well. After adjustment for depth, gas content, permeability and coal

thickness, the type well for the Smith coal seam in Partition #5 serves as the type

well for the Wasatch coal seam in this partition.
6-70

Figure 6-37. Partition #7 Base Map
6-71

Table 6-46. Wasatch Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery 

(M bls)

Average 570 25 0.13 100

High 620 34 0.19 130

Low 420 20 0.08 80

 • Roland. The Roland seam lies stratigraphically below the Wasatch and is the first Fort

Union coal seam in this partition.

 - Area. The Roland coal seam meets study inclusion criteria in 3 township located

in the southern portion of the partition.

 - Coal Thickness. The Roland seam coal thickness averages 27 feet, with a range

of 20 to 40 feet.

 - Coal Depth. The depth to the top of the Roland seam averages 820 feet, with a

range of 800 to 850 feet.

 - Development. The are a total of 169 drilled or permitted Roland CBM wells in

Partition #7.

 - Time Zero Plot. Not available. 

 - Type Well. After adjustment for depth, gas content, permeability and coal

thickness, the type well for the Smith coal seam in Partition #5 serves as the type

well for the Roland coal seam in this partition.

Table 6-47. Roland Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery 

(M bls)

Average 850 27 0.21 100

High 840 40 0.31 150

Low 840 20 0.16 80

 • Smith. The Smith seam is stratigraphically below the Roland coal seam, separated by

approximately 350 feet of section.

 - Area. The Smith coal seam meets study inclusion criteria in two townships,

located in the central portion of the partition.

 - Coal Thickness. The Smith coal seam thickness averages 20 feet.
6-72

 - Coal Depth. The depth to the top of the Smith seam averages 1,180 feet, with a

range of 1,065 to 1,300 feet.

 - Development. The are a handful of Smith wells and permits in Partition #7.

 - Time Zero Plot. Not available

 - Type Well. After adjustment for depth, gas content, permeability and coal

thickness, the type well for the Smith coal seam in Partition #5 serves as the type

well for the Smith coal seam in this partition.

Table 6-48. Smith Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery 

(M bls)

Average 1,200 20 0.16 80

 • Anderson. The Anderson seam is stratigraphically below the Smith coal seam.

 - Area. The Anderson coal seam meets study inclusion criteria in 5 townships, 4 of

which lie in the northernmost portion of the partition.

 - Coal Thickness. The Anderson seam coal thickness averages 21 feet, with a

range of 20 to 25 feet. 

 - Coal Depth. The depth to the top of the Anderson seam averages 910 feet, with a

depth range of 370 to 1,480 feet. 

 - Development. The Anderson coal seam is essentially undeveloped in

Partition #7.

 - Time Zero Well. Not available.

 - Type Well. The history-matched Anderson well in Partition #8, adjusted for

depth, gas content, permeability and coal thickness, serves as the Anderson type

well in this partition.

Table 6-49. Anderson Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery 

(M bls)

Average 930 21 0.16 60

High 1,500 25 0.24 50

Low 390 20 0.07 50
6-73

 • Canyon. The Canyon is about 600 feet below the Anderson.

 - Area. The Canyon coal seam meets study inclusion criteria in two townships in

the southern portion of the partition.

 - Coal Thickness. The Canyon seam coal thickness averages 25 feet.

 - Coal Depth. The depth to the top of the Canyon seam averages 1,500 feet, with a

depth range of 1,450 to 1,540 feet. 

 - Development. The Canyon coal seam is undeveloped in Partition #7.

 - Time Zero Plot. Not available.

 - Type Well. The history-matched Canyon well in Partition #4, adjusted for depth,

gas content, permeability and coal thickness, serves as the Canyon type well in

this partition.

Table 6-50. Canyon Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery 

(M bls)

Average 1,520 25 0.26 190

 • Cook. The Cook seam is the next deepest coal in Partition #7.

 - Area. The Cook coal seam meets study inclusion criteria in two townships in the

northern portion of the partition.

 - Coal Thickness. The Cook seam coal thickness averages 28 feet, with a range of

25 to 30 feet.

 - Coal Depth. The depth to the top of the Cook seam averages 2,300 feet, with a

depth range of 2,250 to 2,350 feet. 

 - Development. The Cook coal seam is undeveloped in Partition #7.

 - Time Zero Plot. Not available.

 - Type Well. The history-matched Cook well in Partition #8, adjusted for depth,

gas content, permeability and coal thickness, serves as the Cook type well for

Partition #7.
6-74

Table 6-51. Cook Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery 

(M bls)

Average 2,330 28 0.36 190

 • Wall. The Wall coal underlies the Cook coal seam by 250 feet of section. 

 - Area. The Wall coal seam meets study inclusion criteria in one township in the

northern portion of the partition.

 - Coal Thickness. The Wall seam coal thickness averages 30 feet.

 - Coal Depth. The depth to the top of the Wall seam averages 2,500 feet.

 - Development. Wall coal seam is undeveloped in Partition #7.

 - Time Zero Well. Not available.

 - Type Well. The history-matched Wall well in Partition #8, adjusted for depth,

gas content, permeability and coal thickness, serves as the Wall type well for

Partition #7:

Table 6-52. Wall Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery 

(M bls)

Average 2,530 30 0.36 390

 • Pawnee. The Pawnee coal seam underlies the Wall coal in this partition.

 - Area. The Pawnee coal seam meets study inclusion criteria in one township in

the southeastern portion of the partition.

 - Coal Thickness. The Pawnee seam coal thickness averages 40 feet.

 - Coal Depth. The depth to the top of the Pawnee seam averages 2,050 feet.

 - Development. The Pawnee coal seam is undeveloped in Partition #7.

 - Time Zero Well. Not available.

 - Type Well. The history-matched Pawnee well in Partition #8, adjusted for depth,

gas content, permeability and coal thickness, serves as the Pawnee type well for

this partition.
6-75

Table 6-53. Pawnee Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery 

(M bls)

Average 2,090 40 0.47 530

 • Cache. The Cache seam is the deepest major coal seam, both stratigraphically and

structurally, in Partition #7. It is nearly 600 feet below the Pawnee seam. 

 - Area. The Cache coal seam meets study inclusion criteria in 3 townships in the

northern and central portions of the partition.

 - Coal Thickness. The Cache seam coal thickness averages 30 feet in each of the

3 townships.

 - Coal Depth. The depth to the top of the Cache seam averages 2,623 feet, with a

depth range of 2,200 to 2,980 feet. 

 - Development. The Cache coal seam is undeveloped in Partition #7.

 - Time Zero Well. Not available.

 - Type Well. The history-matched Cache well in Partition #8, adjusted for depth,

gas content, permeability and coal thickness, serves as the Cache type well for

Partition #7:

Table 6-54. Cache Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery 

(M bls)

Average 2,650 30 0.38 400
6-76

Table 6-55. In-Place and Technically Recoverable CBM, Partition #7

Coal Seam No. Full

Townships

Average

Depth

(ft)*

Average

Thickness

(ft)

Average

Gas Content

(cf/ton)

Gas In 

Place

(Bcf)

Technically

Recoverable

(Bcf)

Wasatch 6 540 25 47 290 230

Roland 3 820 27 70 250 200

Smith 2 1,180 20 96 160 90

Anderson 5 910 21 75 320 230

Canyon 2 1,500 25 120 250 150

Cook 2 2,300 28 178 400 210

Wall 1 2,500 30 186 210 100

Pawnee 1 2,050 40 160 250 140

Cache 3 2,623 30 190 680 330

Totals 2,820 1,680

* To top of coal

6.8 Partition #8

6.8.1 Summary

The main features of Partition #8, in the Wyoming portion of the Powder River Basin, are as

follows:

 • The partition covers a 41-township area in the northeastern portion of the Powder River

Basin, from 53N to 58N and from 72W to78W, Figure 6-38.

 • Partition #8 contains 9 major coal seams in the Fort Union Formation. The depth of these

coals ranges from about 300 to 2,770 feet, with coal seam thickness ranging from 20 to

85 feet (township level averages). The gas in place in the partition is 9.2 Tcf, with

technically recoverable gas of 7,020 Bcf. The results, by coal seam, are provided in

Table 6-64.

6.8.2 Discussion of Major Seams

 • Smith. The Smith coal seam is the shallowest major coal seam in Partition #8.

 - Area. The Smith coal seam meets study inclusion criteria in 8 townships, most of

which are located in the southern portion of Partition #8.

 - Coal Thickness. The Smith seam coal thickness averages 33 feet, with a range of

20 to 38 feet.

 - Coal Depth. The depth to the top of the Smith seam averages 430 feet, with a

range of 300 to 500 feet.
6-77

Figure 6-38. Partition #8 Base Map
6-78

 - Development. The are a total of 66 drilled and permitted Smith CBM wells in

Partition #8.

 - Time Zero Plot. Not available.

 - Type Well. After adjustment for depth, gas content, permeability and coal

thickness, the type well for the Smith coal seam in Partition #5 serves as the type

well for the Smith coal seam in this partition.

Table 6-56. Smith Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery 

(M bls)

Average 460 33 0.15 130

High 500 38 0.18 150

Low 320 20 0.06 80

 • Swartz. The Swartz seam lies stratigraphically below the Smith seam, separated by an

average of 150 feet of section.

 - Area. The Swartz coal seam meets study inclusion criteria in 2 township located

in the southern portion of the partition.

 - Coal Thickness. The Swartz seam coal thickness averages 21 feet.

 - Coal Depth. The depth to the top of the Swartz seam averages 580 feet.

 - Development. The Swartz coal seam is undeveloped in Partition #8.

 - Time Zero Plot. Not available.

 - Type Well. After adjustment for depth, gas content, permeability and coal

thickness, the type well for the Smith coal seam in Partition #5 serves as the type

well for the Swartz coal seam in Partition #8.

Table 6-57. Swartz Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery 

(M bls)

Average 600 21 0.12 80

 • Anderson. The Anderson seam is often grouped with the underlying Canyon coal seam

as the Wyodak coal. Close stratigraphic proximity with the Canyon makes recognition of

the Anderson difficult in much of the partition.
6-79

 - Area. The Anderson coal seam meets study inclusion criteria in 9 townships

located in the southern and central portions of the partition.

 - Coal Thickness. The Anderson coal seam thickness averages 35 feet, with a

range of 25 to 50 feet.

 - Coal Depth. The depth to the top of the Anderson seam averages 600 feet, with a

range of 400 to 900 feet.

 - Development. The are a total of 532 drilled and permitted Anderson CBM wells

in Partition #8.

 - Time Zero Plot. The time zero plot for 261 producing Anderson coal seam wells

is provided in Figure 6-39. Initial water rates are 130 barrels per day declining to

about 90 barrels per day after 1 year. Gas production begins immediately with an

initial rate of 30 Mcfd. The gas rate peaks at 135 Mcfd at the beginning of year 2.

 - Type Well. The history-matched type well for the Anderson coal seam is

provided in Figure 6-40. After normalizing for coal thickness, depth and gas

content, the estimated gas and water recoveries are as follows in the table below.

Table 6-58. Anderson Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery 

(M bls)

Average 630 35 0.18 90

High 710 50 0.29 130

Low 630 25 0.13 70

 • Canyon. The Canyon seam is stratigraphically below the Anderson seam but is often

difficult to distinctly identify.

 - Area. The Canyon coal seam meets study inclusion criteria in 19 townships

throughout the partition.

 - Coal Thickness. The Canyon seam coal thickness averages 37 feet, with a range

of 30 to 47 feet.

 - Coal Depth. The depth to the top of the Canyon seam averages 620 feet, with a

depth range of 300 to 950 feet.

 - Development. The are a total of 1184 drilled and permitted Canyon CBM wells

in this partition.

 - Time Zero Well. Not available.
6-80

Time Zero Plot for an Average Well

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

0 5 10 15 20 25

Time (Months)

Production (Mcf/mo.; Barrel/mo.)

0

50

100

150

200

250

300

Well Count

GAS

WATER

Well Count

Figure 6-39. Anderson Time Zero Plot
6-81

Gas and Water Production Rate (Mcfd; Bwpd)

Cumulative Gas and Water Recovery (MMcf; Mbw)

Days On

40

0

0 250 500 750 1,000 1,250 1,500 1,750 2,000 2,250 2,500 2,750 3,000 3,250 3,500 3,750

Actual

Water Rate

Actual

Gas Rate

Actual/Projected

Cum Water

Actual/Projected

Cum Gas

80

120

160

200

240

20

60

100

140

180

220

40

0

80

120

160

200

240

20

60

100

140

180

220

Figure 6-40. Anderson Type Well, Partition #8
6-82

 - Type Well. The history-matched Canyon well in Partition #4, adjusted for depth,

gas content, permeability and coal thickness serves as the Canyon type well in

this partition.

Table 6-59. Canyon Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery 

(M bls)

Average 660 37 0.24 280

High 950 47 0.45 360

Low 560 30 0.17 230

 • Cook. The Cook coal seam is about 100 feet below the Canyon coal seam.

 - Area. The Cook coal seam meets study inclusion criteria in 22 townships

throughout the partition.

 - Coal Thickness. The Cook seam coal thickness averages 39 feet, ranging from

25 to 52 feet. 

 - Coal Depth. The depth to the top of the Cook seam averages 730 feet, with a

depth range of 400 to 1,200 feet. 

 - Development. The are a total of 1,211 drilled and permitted Cook CBM wells in

Partition #8. 

 - Time Zero Plot. The time zero plot for 134 producing Cook coal seam wells is

provided in Figure 6-41. Initial water rates are 400 barrels per day declining to

about 200 barrels per day after 1 year. Gas production begins immediately with

an initial rate of 70 Mcfd. The gas rate continues to climb through 18 months to

200 Mcfd.

 - Type Well. The history-matched type well for the Cook coal seam is provided in

Figure 6-42. After normalizing for coal thickness, depth and gas content, the

estimated gas and water recoveries are as follows in Table 6-60.

Table 6-60. Cook Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery 

(M bls)

Average 770 39 0.27 270

High 970 52 0.46 350

Low 530 25 0.12 170
6-83

Time Zero Plot for an Average Well

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

0 2 4 6 8 10 12 14 16 18 20

Time (Months)

Production (Mcf/mo.; Barrel/mo.)

0

20

40

60

80

100

120

140

160

Well Count

GAS

WATER

Well Count

Figure 6-41. Cook Time Zero Plot
6-84

Gas and Water Production Rate (Mcfd; Bwpd)

Cumulative Gas and Water Recovery (MMcf; Mbw)

Days On

0 250 500 750 1,000 1,250 1,500 1,750 2,000 2,250 2,500 2,750 3,000 3,250 3,500 3,750

Actual

Water Rate

Actual

Gas Rate

Actual/Projected

Cum Water

Actual/Projected

400 Cum Gas

350

300

250

200

150

100

50

0

450

400

350

300

250

200

150

100

50

0

450

Figure 6-42. Cook Type Well, Partition #8
6-85

 • Wall. The Wall seam is stratigraphically below the Cook seam, separated by an average

of 230 feet of section.

 - Area. The Wall coal seam meets study inclusion criteria in 21 townships

throughout the partition.

 - Coal Thickness. The Wall seam coal thickness averages 30 feet, with a range of

20 to 40 feet.

 - Coal Depth. The depth to the top of the Wall seam averages 960 feet, with a

depth range of 530 to 1,300 feet. 

 - Development. The are 486 drilled and permitted Wall CBM wells in Partition #8.

 - Time Zero Plot. The time zero plot for 107 producing Cook coal seam wells is

provided in Figure 6-43. Initial water rates are about 200 barrels per day and

remain high for 15 months. Gas production begins slowly with an initial rate of

10 Mcfd. The gas rate gradually climbs to a maximum of 100 Mcfd at the end of

2 years.

 - Type Well. The history-matched type well for the Wall coal seam is provided in

Figure 6-44. After normalizing for coal thickness, depth and gas content, the

estimated gas and water recoveries are as follows in Table 6-61.

Table 6-61. Wall Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery 

(M bls)

Average 990 30 0.20 390

High 1,120 40 0.30 530

Low 800 20 0.11 260

 • Pawnee. The Pawnee coal seam is the deepest, currently producing major coal in this

partition. 

 - Area. The Pawnee coal seam meets study inclusion criteria in 11 townships. 

 - Coal Thickness. The Pawnee seam coal thickness averages 33 feet, ranging from

25 to 40 feet.

 - Coal Depth. The depth to the top of the Pawnee seam averages 1,060 feet,

ranging from 600 to 1,400 feet.

 - Development. There are 150 Pawnee CBM wells drilled and permitted in

Partition #8.
6-86

Time Zero Plot for an Average Well

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

0 5 10 15 20 25

Time (Months)

Production (Mcf/mo.; Barrel/mo.)

0

20

40

60

80

100

120

Well Count

GAS

WATER

Well Count

Figure 6-43. Wall Time Zero Plot
6-87

Gas and Water Production Rate (Mcfd; Bwpd)

Cumulative Gas and Water Recovery (MMcf; Mbw)

Days On

400

350

300

250

200

150

100

50

0

0 250 500 750 1,000 1,250 1,500 1,750 2,000 2,250 2,500 2,750 3,000 3,250 3,500 3,750

Actual

Water Rate

Actual

Gas Rate

Actual/Projected

Cum Water

Actual/Projected

Cum Gas

400

350

300

250

200

150

100

50

0

Figure 6-44. Wall Type Well Partition #8
6-88

 - Time Zero Well. The time zero plot for 19 producing Pawnee coal seam wells is

provided in Figure 6-45. Initial water rates are 300 barrels per day. Gas

production begins slowly with an initial rate of 10 Mcfd, but steadily climbs to

over 200 Mcfd in 8 months.

 - Type Well. The history-matched type well for the Pawnee coal seam is provided

in Figure 6-46. After normalizing for coal thickness, depth and gas content, the

estimated gas and water recoveries are as follows:

Table 6-62. Pawnee Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery 

(M bls)

Average 1,090 33 0.35 430

High 840 40 0.33 530

Low 1,330 25 0.33 330

 • Cache. The Cache seam is separated from the Pawnee seam by an average of 490 feet.

 - Area. The Cache coal seam meets study inclusion criteria in 4 townships. 

 - Coal Thickness. The Cache seam coal thickness averages 27 feet, ranging from

20 to 40 feet.

 - Coal Depth. The depth to the top of the Cache seam averages 1,540 feet, ranging

from 1,100 to 2,430 feet.

 - Development. The Cache coal seam is undeveloped in Partition #8.

 - Time Zero Well. Not available.

 - Type Well. The history-matched Cache well in Partition #8, adjusted for depth,

gas content, permeability and coal thickness, serves as the Cache type well for

this partition.

Table 6-63. Cache Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery 

(M bls)

Average 1,570 27 0.26 350

High 1,140 40 0.29 530

Low 1,370 20 0.18 260
6-89

Time Zero Plot for an Average Well

0

2,000

4,000

6,000

8,000

10,000

12,000

0 5 10 15 20 25

Time (Months)

Production (Mcf/mo.; Barrel/mo.)

0

2

4

6

8

10

12

14

16

18

20

Well Count

GAS

WATER

Well Count

Figure 6-45. Pawnee Time Zero Plot
6-90

Gas and Water Production Rate (Mcfd; Bwpd)

Cumulative Gas and Water Recovery (MMcf; Mbw)

Days On

0 250 500 750 1,000 1,250 1,500 1,750 2,000 2,250 2,500 2,750 3,000 3,250 3,500 3,750

Actual

Water Rate

Actual

Gas Rate

Actual/Projected

Cum Water

Actual/Projected

Cum Gas

400

350

300

250

200

150

100

50

0

450

400

350

300

250

200

150

100

50

0

450

Figure 6-46. Pawnee Type Well Partition #8
6-91

 • Oedekoven. The Oedekoven seam is the deepest major coal seam in Partition #8, an

average of 1,000 feet below the Cache seam. 

 - Area. The Oedekoven coal seam meets study inclusion criteria in 2 townships in

the western portion of the partition.

 - Coal Thickness. The Oedekoven seam coal thickness averages 20 feet.

 - Coal Depth. The depth to the top of the Oedekoven seam averages 2,560 feet,

with a depth range of 2,340 to 2,770 feet.

 - Development. The Oedekoven coal seam is undeveloped in Partition #8.

 - Time Zero Well. Not available.

 - Type Well. The history-matched Oedekoven well in Partition #8, adjusted for

depth, gas content, permeability and coal thickness, serves as the Oedekoven type

well for Partition #8.

Table 6-64. Oedekoven Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery 

(M bls)

Average 2,580 20 0.30 260

Table 6-65. In-Place and Technically Recoverable CBM, Partition #8

Coal Seam No. Full

Townships

Average

Depth

(ft)*

Average

Thickness

(ft)

Average

Gas Content

(cf/ton)

Gas In 

Place

(Bcf)

Technically

Recoverable

(Bcf)

Smith 8 430 33 38 380 300

Swartz 2 580 21 49 90 70

Anderson 9 600 35 51 750 530

Canyon 19 620 37 54 1,810 1,560

Cook 22 730 39 62 2,280 1,800

Wall 21 960 30 80 1,890 1,230

Pawnee 11 1,060 33 87 1,200 1,070

Cache 4 1,550 27 123 490 290

Oedekoven 2 2,560 20 188 300 170

Totals 9,190 7,020

* To top of coal
6-92

6.9 Partition #9

6.9.1 Summary

Partition #9 covers 22 townships in the eastern Montana portion of the Powder River Basin,

Figure 6-47. Only one township in Partition #9 contains coal that meets the depth and thickness

criteria of the study, the Pawnee seam, with 20 feet of coal at 1,075 feet. As such, the discussion

of the Pawnee coal in this partition is combined into Partition #10, on the west of Partition #9.

6.10 Partition #10

6.10.1 Summary

The main features of Partition #10, in the western Montana portion of the Powder River Basin,

are as follows:

 • The partition covers a 10-township area on the western edge of the PRB, from 6S to 9S

and from 39E to 41E, Figure 6-48.

 • A series of coal mines exist in the townships along the northern edge and the coals

shallow to the north; as a result, the townships on the northern edge of the partition are

excluded.

 • The stratigraphic section contains the Deitz (Anderson equivalent), the Monarch (Canyon

equivalent), and the Carney (Cook equivalent) seams, plus the Pawnee coal seam from

Partition #9. The depth of these coals range from 250 to 1,200 feet, with coal seam

thickness ranging from 20 to 50 feet (township level averages).

 • The gas in place in the two partitions is 1.0 Tcf, with technically recoverable gas of

860 Bcf. The results by coal seam are provided in Table 6-70.

6.10.2 Discussion of Major Seams

 • Dietz (Anderson). The Dietz is the uppermost significant seam in Partition #10 and

contains three subunits, called Dietz #1, #2, and #3.

 - Area. The Dietz coal seam meets study inclusion criteria in 2 townships, located

in the southern portion of Partition #10.

 - Coal Thickness. The Dietz seam coal thickness averages 49 feet. The thickness

of the Dietz in any locale depends on how many of the Dietz subunits are present

and have been combined.

 - Coal Depth. The depth to the top of the Dietz seam averages 250 feet.

 - Development. A limited number of Dietz wells currently exist in this partition.
6-93

Figure 6-47. Partition #9 Base Map
6-94

Figure 6-48. Partition #10 Base Map
6-95

 - Time Zero Plot. The time zero plot for 22 recently drilled Dietz coal wells is

provided in Figure 6-49.

 - Type Well. The history-matched Dietz well in Partition #11, adjusted for depth,

gas content and coal thickness, serves as the Dietz type well for Partition #10.

Because the Dietz coal seam exists in only two townships, only one average well

is used in Partition #10.

Table 6-66. Dietz Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery 

(M bls)

Average 300 49 0.16 410

 • Monarch (Canyon). The major coal seam in Partition #10 is the Monarch, located in the

southern portion of the partition.

 - Area. The Monarch coal seam meets study inclusion criteria in 7 townships. 

 - Coal Thickness. The Monarch coal seam thickness averages 24 feet, with a range

of 20 to 30 feet. 

 - Coal Depth. The depth to the top of the Monarch seam averages 470 feet, with a

range of 325 to 680 feet. 

 - Development. Considerable Monarch coal well development exists in this

partition.

 - Time Zero Plot. The time zero plot for 25 recently drilled Monarch coal wells is

provided in Figure 6-50.

 - Type Well. The Monarch well production profile in Partition #10 is similar to the

Monarch wells in Partition #11. Thus, the history-matched Monarch well in

Partition #11, adjusted for depth, gas content and coal thickness, serves as the

Monarch type well in this partition.

Table 6-67. Monarch Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery 

(M bls)

Average 490 24 0.12 420

High 580 30 0.17 530

Low 420 20 0.08 350
6-96

Time Zero Plot for an Average Well

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

0 5 10 15 20 25 30

Time (Months)

Production (Mcf/mo.; Barrel/mo.)

0

5

10

15

20

25

Well Count

GAS

WATER

Well Count

Figure 6-49. Dietz Time Zero Plot
6-97

 • Carney (Cook). The Carney coal seam exists at sufficient thickness in the central and

southern portions of Partition #10.

 - Area. The Carney coal seam meets study inclusion criteria in seven townships.

 - Coal Thickness. The Carney coal seam thickness averages 23 feet, with a range

of 15 to 35 feet. 

 - Coal Depth. The depth to the top of the Carney seam averages 650 feet, with a

range of 530 to 860 feet. 

 - Development. The Carney coal seam is lightly developed. 

 - Time Zero Plot. The time zero plot for 25 recently drilled Carney coal wells is

provided in Figure 6-51.

 - Type Well. The history-matched Carney well in Partition #11, adjusted for depth,

gas content, and coal thickness, serves as the Carney type well for Partition #10.

Table 6-68. Carney Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery 

(M bls)

Average 670 23 0.15 390

High 685 35 0.23 590

Low 870 15 0.13 250

 • Pawnee. The Pawnee seam exists in Partition #9 (eastern Montana portion of the PRB)

and includes one undesignated (wildcat) seam in Partition #10, as discussed above.

 - Area. The Pawnee coal seam (including the wildcat coal seam) meets study

inclusion criteria in 3 townships.

 - Coal Thickness. The Pawnee seam coal thickness averages 20 feet, with a range

of 20 to 22 feet. 

 - Coal Depth. The depth to the top of the Pawnee seam averages 1,100 feet, with a

range of 1,000 to 1,200 feet. 

 - Development. The Pawnee coal seam is undeveloped.

 - Time Zero Plot. Not available.

 - Type Well. The history-matched Pawnee well in Partition #8, adjusted for depth,

gas content, permeability and coal thickness, serves as the Pawnee type well for
6-98

Time Zero Plot for an Average Well

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

0 5 10 15 20 25 30

Time (Months)

Production (Mcf/mo.; Barrel/mo.)

0

5

10

15

20

25

30

Well Count

GAS

WATER

Well Count

Figure 6-50. Monarch Time Zero Plot
6-99

 Partition #10. Because the Pawnee coal seam has relatively uniform depth and

thickness, only an average well is used.

Table 6-69. Pawnee Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery

(M bls)

Average 1,120 20 0.22 260

Table 6-70. In-Place and Technically Recoverable CBM, Partitions #9 and #10

Coal Seam No. Full

Townships

Average

Depth

(ft)*

Average

Thickness

(ft)

Average Gas

Content

(cf/ton)

Gas in

Place

(Bcf)

Technically

Recoverable

Resources

(Bcf)

Deitz 

(Anderson) 2 250 49 25 100 90

Monarch

(Canyon) 7 470 24 41 280 250

Carney (Cook) 7 650 23 55 380 330

Pawnee 3 1,080 20 88 210 190

Totals 970 860

* Top of coal

6.11 Partition #11

6.11.1 Summary

The main features of Partition #11, in the Wyoming portion of the Powder River Basin, are as

follows:

 • The partition covers a 12-township area on the northwestern portion of the PRB, from

53N to 58N and from 82W to 84W, Figure 6-52.

 • The stratigraphic section contains the locally named Dietz (Anderson equivalent),

Monarch (Canyon equivalent), and Carney (Cook equivalent) coal seams. The depth of

these coals range from 990 to 1,070 feet, with coal seam thickness ranging from 20 to

40 feet (township level averages).

 • The gas in place in the two partition is 2.1 Tcf, with technically recoverable gas of

1,850 Bcf. The results by coal seam are provided in Table 6-76.
6-100

Time Zero Plot for an Average Well

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

0 5 10 15 20 25

Time (Months)

Production (Mcf/mo.; Barrel/mo.)

0

5

10

15

20

25

30

Well Count

GAS

WATER

Well Count

Figure 6-51. Cook-Carney Time Zero Plot
6-101

6.11.2 Discussion of Major Coal Seams

 • Dietz #1 (Anderson). The Dietz #1 coal, the first major seam, extends over much of the

northern portion of Partition #11 and shallows along the western and northern edge of the

partition.

 - Area. The Dietz #1 coal seam meets study inclusion criteria in 5 townships.

 - Coal Thickness. The Dietz #1 coal seam coal thickness averages 24 feet, with a

range of 20 to 25 feet.

 - Coal Depth. The depth to the top of the Dietz #1 seam averages 910 feet, with a

range of 300 to 1,840 feet. 

 - Development. The Dietz #1 seam is being aggressively developed.

 - Time Zero Plot. The time zero plot for 191 producing Dietz (Anderson) coal

seam wells in T57N, R83-84W is provided in Figure 6-53. After initial rates of

nearly 300 barrels per day, water production declines sharply to about 180 barrels

per day after 1 year. Gas production starts early at 100 to 200 Mcfd.

 - Type Well. The type well for the Dietz (Anderson) series of coal seams (Dietz #1,

#2, and #3) is provided in Figure 6-54. After normalizing for coal thickness,

depth and gas content, the estimated gas and water recoveries for the Dietz #1

coal seam are as follows in Table 6-71.

Table 6-71. Dietz #1 Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery 

(M bls)

Average 930 24 0.22 200

High 1,140 25 0.29 210

Low 800 20 0.16 170

 • Dietz #2. The Dietz #2 coal, the second split of the larger Dietz (Anderson) seam, exists

along the northern portion of Partition #11.

 - Area. The Dietz #2 coal seam meets study inclusion criteria in 5 townships.

 - Coal Thickness. The Dietz #2 coal seam coal thickness averages 24 feet, with a

range of 20 to 30 feet.

 - Coal Depth. The depth to the top of the Dietz #2 seam averages 680 feet, with a

range of 300 to 1,160 feet. 
6-102

Figure 6-52. Partition #11 Base Map
6-103

Time Zero Plot for an Average Well

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

0 5 10 15 20 25

Time (Months)

Production (Mcf/mo.; Barrel/mo.)

0

50

100

150

200

250

Well Count

GAS

WATER

Well Count

Figure 6-53. Dietz (Anderson) Time Zero Plot
6-104

 - Development. The Dietz #2 seam is lightly developed in this area.

 - Time Zero Plot. The time zero plot and data for Dietz #2 coal seam wells are

included in the overall Dietz time zero plot, discussed previously.

 - Type Well. The type well for the Dietz #2 coal seam is the aggregate Dietz well,

provided previously in Figure 6-54, adjusted for coal thickness, depth and gas

content. The estimated gas and water recoveries are as follows in Table 6-72.

Table 6-72. Dietz #2 Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery 

(M bls)

Average 700 24 0.17 200

High 1,190 30 0.36 250

Low 620 20 0.13 170

 • Dietz #3. The Dietz #3 coal, the third split of the larger Dietz (Anderson) seam, exists

along the northern portion of Partition #11.

 - Area. The Dietz #3 coal seam meets study inclusion criteria in 6 townships.

 - Coal Thickness. The Dietz #3 coal seam coal thickness averages 22 feet, with a

range of 20 to 25 feet. 

 - Coal Depth. The depth to the top of the Dietz #3 seam averages 1,030 feet, with

a range of 350 to 1,970 feet.

 - Development. The Dietz #3 seam is lightly developed in this area.

 - Time Zero Plot. The time zero plot and data for Dietz #3 coal seam wells are

included in the overall Dietz time zero plot, discussed previously.

 - Type Well. The type well for the Dietz #3 coal seam is the aggregate Dietz well,

provided previously in Figure 6-54, adjusted for coal thickness, depth and gas

content. The estimated gas and water recoveries are as follows below.

Table 6-73. Dietz #3 Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery 

(M bls)

Average 1,050 22 0.23 180

High 980 25 0.25 210

Low 600 20 0.12 170
6-105

 • Monarch (Canyon). The Monarch coal is stratigraphically below the Dietz and extends

over much of the partition. It shallows on the western edge of the PRB basin.

 - Area. The Monarch coal seam meets study inclusion criteria in 8 townships.

 - Coal Thickness. The Monarch coal seam thickness averages 22 feet, with a range

of 20 to 25 feet.

 - Coal Depth. The depth to the top of the Monarch seam averages 1,070 feet, with

a range of 500 to 2,200 feet.

 - Development. The Monarch coal seam is under development.

 - Time Zero Plot. The time zero plot for 147 producing Monarch (Canyon) coal

seam wells in T57N, R83-84W is provided in Figure 6-55. Water production

starts at 300 barrels per day and remains high for the first 2 years. Gas production

starts early, reaching 200 Mcfd in year 2.

 - Type Well. The type well for the Monarch (Canyon) coal seam is provided in

Figure 6-56. After normalizing for coal thickness, depth and gas content, the

estimated gas and water recoveries are as follows:

Table 6-74. Monarch Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery 

(M bls)

Average 1,090 24 0.26 430

High 1,340 25 0.32 440

Low 820 20 0.16 350

 • Carney (Cook). The Carney coal, stratigraphically below the Monarch, exists over a

limited portion of the partition.

 - Area. The Carney coal seam meets study inclusion criteria in three townships.

 - Coal Thickness. The Carney seam coal thickness averages 23 feet, with a range

of 20 to 30 feet.

 - Coal Depth. The depth to the top of the Carney seam averages 1,030 feet, with a

range of 600 to 1,440 feet.

 - Development. The Carney coal seam is undeveloped.
6-106

Gas and Water Production Rate (Mcfd; Bwpd)

Cumulative Gas and Water Recovery (MMcf; Mbw)

Days On

200

160

20

0

0 250 500 750 1,000 1,250 1,500 1,750 2,000 2,250 2,500 2,750 3,000 3,250 3,500 3,750

Actual

Water Rate

Actual

Gas Rate Actual/Projected

Cum Water

Actual/Projected

Cum Gas

40

60

80

100

120

140

180

300

260

220

240

280

200

160

20

0

40

60

80

100

120

140

180

300

260

220

240

280

Figure 6-54. Dietz (Anderson), Partition #11
6-107

Time Zero Plot for an Average Well

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

0 5 10 15 20 25

Time (Months)

Production (Mcf/mo.; Barrel/mo.)

0

20

40

60

80

100

120

140

160

Well Count

GAS

WATER

Well Count

Figure 6-55. Monarch (Canyon) Time Zero Plot
6-108

 - Time Zero Plot. The time zero plot for 65 producing Carney (Cook) wells in

Partition #11 is provided in Figure 6-57. After initial rates of about 300 barrels of

water per day, the water rates decline to about 200 barrels per day at the end of

year 1. Gas production starts early and peaks at about 200 Mcf at the end of

year 1.

 - Type Well. The history-matched Carney (Cook equivalent) well, Figure 6-58,

adjusted for depth, gas content and coal thickness, serves as the Carney type well

for Partition #11. Since only three townships include the Carney and the coal

thickness is relatively uniform, only an average well is used.

Table 6-75. Carney Coal Seam

Type Well Well Depth

(ft)

Coal Thickness

(ft)

Cumulative Gas

Recovery

(Bcf)

Cumulative

Water Recovery 

(M bls)

Average 1,050 23 0.23 390

Table 6-76. In-Place and Technically Recoverable CBM, Partitions #11

Coal Seam No. Full

Townships

Average

Depth

(ft)*

Average

Thickness

(ft)

Average Gas

Content

(cf/ton)

Gas in

Place

(Bcf)

Technically

Recoverable

Resources

(Bcf)

Deitz #1

(Anderson) 5 910 24 75 510 450

Dietz #2 5 680 24 58 330 290

Dietz #3 6 1,030 22 84 390 340

Monarch

(Canyon) 8 1,070 24 88 640 570

Carney

(Cook) 3 1,030 23 84 220 190

Totals 2,090 1,850

* Top of coal
6-109

Gas and Water Production Rate (Mcfd; Bwpd)

Cumulative Gas and Water Recovery (MMcf; Mbw)

Days On

400

350

300

250

200

150

100

50

0

0 250 500 750 1,000 1,250 1,500 1,750 2,000 2,250 2,500 2,750 3,000 3,250 3,500 3,750

Actual

Water Rate

Actual

Gas Rate

Actual/Projected

Cum Water

Actual/Projected

Cum Gas

400

350

300

250

200

150

100

50

0

Figure 6-56. Monarch (Canyon), Partition #11
6-110

Time Zero Plot for an Average Well

0

2,000

4,000

6,000

8,000

10,000

12,000

0 5 10 15 20 25

Time (Months)

Production (Mcf/mo.; Barrel/mo.)

0

10

20

30

40

50

60

70

Well Count

GAS

WATER

Well Count

Figure 6-57. Carney (Cook) Time Zero Plot
6-111

Gas and Water Production Rate (Mcfd; Bwpd)

Cumulative Gas and Water Recovery (MMcf; Mbw)

Days On

400

350

300

250

200

150

100

50

0

0 250 500 750 1,000 1,250 1,500 1,750 2,000 2,250 2,500 2,750 3,000 3,250 3,500 3,750

Actual

Water Rate

Actual

Gas Rate

Actual/Projected

Cum Water

Actual/Projected

Cum Gas

600

550

500

450

400

350

300

250

200

150

100

50

0

600

550

500

450

Figure 6-58. Carney (Cook), Partition #11
A-1

APPENDIX A

GAS SORPTION CAPACITY AND GAS CONTENT FOR 

POWDER RIVER BASIN COALS

INTRODUCTION

Considerable differences of opinion surround two closely related issues of importance to the

outlook for coalbed methane in the Powder River Basin:

 • First, what is the correct sorption (storage) capacity of the low rank PRB coals, and how

does this sorption capacity change by coal depth and coal seam?

 • Second, what is the actual (in situ) gas content in these coals, and are the PRB coals

essentially fully saturated or undersaturated with gas?

Attempts to conclusively answer these two questions in the past have been impeded by the high

permeability in the coals, difficulties with conventional gas content measurement approaches,

and the presence of much lower than normal pressure conditions in the shallow coals.

This memorandum provides the data and assumptions used by Advanced Resources to address

these two issues for the Powder River Basin in the DOE/NETL report “Powder River CBM

Development and Produced Water Management Study” (PRB Study) of November, 2002.

SUMMARY OF ADVANCED RESOURCES DATA AND METHODOLOGY

Background

Operators in the basin have struggled greatly with the issue of the gas content and the level of

gas saturation in the coal. Early gas content data, gathered in the 1980s, showed the shallow

coals along the eastern portion of the PRB to hold little methane. This gas content data led to

extremely low values for gas in place, considerably below the actual gas recovery volumes

established by the producing CBM wells.

Further uncertainty was introduced by the significantly underpressured conditions of these

shallow coals. For example, the Wyodak coal (in T47-48 R72) has a pressure gradient of 0.274

psi/ft, giving it a pressure of 163 psi (at a depth of 541 ft to top of coal with a coal thickness of

78 ft), approximately 35% less than a normal pressure of about 250 psi. This condition, plus the

high water production and delay in the arrival of gas production in the initial sets of wells, led

many to conclude that the coals were also undersaturated with gas. [As is further discussed

below, high initial water production and delay in gas production was due to the high

permeability of the coals and the immaturity of development (lack of sufficient numbers of

bounded wells) in the basin.]
A-2

These data and observations led many operators to conclude that the PRB coals were

uneconomic, delaying industry’s entry into the basin.

Gas Content

The Advanced Resources PRB Study assembled available gas content data and adsorption

isotherms, appropriate for the low rank coals of the Powder River Basin, from the following

sources:

 • Past gas content data collected by the BLM and published gas content and isotherm data

by industry and the USGS were used as a point of reference,

 • Advanced Resources’ own gas content and isotherm data collected for analogous low

rank coals in other basins, and

 • Verification of the gas content and isotherm data using history matching (with COMET3)

of alternative isotherms against long-term (4+year) gas and water production data in the

PRB.

The best fit coalbed methane isotherm was from actual gas content and isotherm data collected

on an analogous overseas low rank coal basin. Advanced Resources was the on-site field service

contractor for the gas content measurement for these coals and used Terra Tek (in our view one

of the most consistent, high quality CBM labs) for the adsorption isotherm (sorption capacity). 

The moisture content, volatile matter and fixed carbon content of the overseas low rank coal and

the PRB Wyodak coal were similar as shown on Table A-1.

Table A-1. Comparison PRB Wyodak Coal and Overseas Low Rank Coal

PRB Wyodak Coal *

(59 Analyses)

Overseas Low 

Rank Coal **

Average Range

Rank Lignite/Sub-bituminous Lignite/Sub-bituminous

Fixed Carbon 33.5% 30-41% 32.4%

Volatile Matter 30.7% 26-33% 44.6%

Moisture Content 29.8% 23-37% 23.0%***

Ash 6% 3-12% 11%

Heating Value (Btu/lb) 8,224 7,420-9,310 7,440

* Source: Breckenridge, et al, (1974)

** Source: Advanced Resources Int’l, Inc. (1995)

*** Moisture at 96% RH and 40o

C

Figure A-1 provides the gas content isotherm used in the study of Powder River Basin coalbed

methane. As a point of comparison, Figure A-2 provides the average synthesized adsorption

isotherm for coal in the PRB assembled by the Wyoming BLM from earlier data.
A-3

Figure A-1. Gas Content Isotherm Used for Powder River Coalbed

Methane

Figure A-2. Average Synthesized Adsorption Isotherm for 41 Coal

Samples From the PRB, Based on a Compilation of Data From Public

and Private Sources
A-4

Free Gas Saturation

The nature of actual early time water and gas production from producing CBM wells in the basin

was used to establish whether the PRB coals were undersaturated, fully saturated or contained

free gas in the pore space:

 • Gas and water production data were assembled and compiled for over selected 1,400

PRB CBM wells.

 • Observation of production data from these 1,400 wells and history matching (with 

COMET3) of this production data was used to establish that the coals were (in general)

fully gas saturated and, for certain seams, had free gas in the coal cleat and matrix

system.

Based on this work, the PRB Study established that modest amounts of free gas exist in the coal

cleat (fracture) and matrix porosity system for the shallower coal seams.

FINDINGS BY OTHER INVESTIGATORS

Bustin and Downey

The most recent, publicly available data on gas sorption and content for the Powder River Basin

was presented by Bustin and Downey on the Dietz #3 (Anderson equivalent) coal in the

northwestern portion of the PRB. Their work on the sorption capacity of the Dietz #3 coal (as a

function of temperature and pressure) is provided in Figure A-3. The 20o

C sorption capacity line

would be reasonably representative of the upper Tongue River coals in the PRB.

A. Sorption Capacity. The Sorption Capacity Isotherm used in the Advanced Resources

Study is compared with the sorption isotherm of Bustin and Downey in Figure A-4, with

the vertical scale enlarged for easier comparison. The overlay of the data shows that the

Advanced Resources Sorption Capacity Isotherm for PRB coals is somewhat lower than

the 20o

C Sorption Capacity Isotherm of Bustin and Downey for the Dietz #3 coal.

B. Gas Content and Saturation. In the same paper, Bustin and Downey provide a series of

observations with respect to the gas content and gas saturation conditions for the coals in

the PRB. (Note that when coals are saturated and/or have free gas, the gas content value

is the same as the value on the Sorption Capacity Isotherm. And, it is not physically

possible to have free gas and undersaturated coals at the same time). Bustin and Downey

wrote:

“There have been some 12,000 coalbed methane gas wells in the Powder River

Basin to date, to produce methane gas from Eocene Fort Union Formation coal

seams. Most have targeted the thick Wyodak coal seam(s) along the eastern flank

of the basin where the coals are saturated and/or have free gas. . . . “
A-5

Source: Bustin and Downey (2002)

Figure A-3. Variation in Sorption Capacity with Temperature, Dietz #3 Coal

Figure A-4. Comparison of Bustin and Downey Adsorption Isotherm for Dietz #3

Coal with Advanced Resources Adsorption Isotherm for PRB Coals
1

“Gas-in-place in the Powder River Basin: Coal Core – Why Do Them? Some Field Results,

Comparisons, and Suggestion”, R. Marc Bustin, the University of British Columbia, Vancouver, and Rover A.

Downey, Energy Ingenuity Company, RMAG PTTC GTI 2002 Coalbed Methane Symposium, June 19, 2002.

A-6

”Free gas in coals is predicted wherever structural closure and uplift can be

demonstrated. If the coals have been substantially uplifted, desorbed gas may

partially flush the fractures resulting in lower water saturations. Near one of the

coal mines on the east side of the Powder River Basin, coal seam gas contents

and isotherm data, correlate very well and suggest the Wyodak coal is saturated

at current pressure conditions although the gas content is markedly depleted as a

result of depressurization.”1

However, Bustin and Downey do state that they have observed that “some of the deeper coal

seams, such as the Cache and Pawnee, may be void of methane in some areas”, particularly in

areas south of Gillette, while “these coals appear to contain (and produce) methane in areas north

of Gillette.”

Empirical Observations of Production Data

A. Basic Mechanisms. The production profile for a typical coalbed methane well is high

initial water production with little to no gas production. As the water rate declines and

the reservoir pressure decreases, gas is desorbed from the coal, moves through the coal

matrix by diffusion and through the coal cleat system by Darcy flow to the production

well. The need to establish a critical gas saturation and overcome the low initial relative

permeability to gas further delay the arrival of the released methane in the production

well.

Depending on reservoir and development conditions (and assuming no free gas), it may

take 3 months to a year (or longer) to observe significant rates of gas production.

B. Evidence of Free Gas and Fully Saturated Coals. The early production of gas, as

demonstrated by the 164 Wyodak coal wells drilled in the mid-1990s in T47-48N, R72W,

Figure A-5, can only be explained by the presence of free gas. Advanced Resources

reservoir simulation-based history matching of this set of wells, indicates the presence of

10% free gas in the matrix porosity and 5% free gas in the cleat system, Figure A-6.

To examine the difference that the presence or absence of free gas has on gas production rates

and recovery, we set the free gas values to zero in our next simulation run, while helping other

reservoir properties the same. The resulting production curve clearly shows that gas production

is much lower and later than has actually occurred, Figure A-7.

Finally, we examine how the Wyodak coal wells would produce in this area if they were 23% to

66% undersaturated. The use of such extreme gas undersaturation values for the Wyodak coal

provides a gas production curve that is many-fold lower than actually observed, making this coal

essentially non-productive, as shown on Figures A-8 and A-9.
A-7

Time Zero P lot for an Average Well

0

5,000

1 0,000

1 5,000

20,000

25,000

0 5 1 0 1 5 20 25 30 35 40 45

Time (Months)

Production (Mcf/mo.; Barrel/mo.)

0

20

40

60

80

100

120

140

160

180

Well Count

GAS

WATER

Well Count

Figure A-5. Wyodak Time Zero Well Data Gas and Water Production Rate (Mcfd; Bwpd)

Cumulative Gas and Water Recovery (MMcf; Mbw)

Days On

700

650

600

550

500

450

400

350

300

250

200

150

100

50

0

700

650

600

550

500

450

400

350

300

250

200

150

100

50

0 0 250 500 750 1,000 1,250 1,500 1,750 2,000 2,250 2,500 2,750 3,000 3,250 3,500 3,750

Actual

Water Rate

Actual

Gas Rate

Actual/Projected

Cum Water

Actual/Projected

Cum Gas

Figure A-6. History Match Wyodak Type Well w/ Free Gas
A-8

Gas Rate

Cum Gas

Gas Production Rate (Mcfd)

Cumulative Gas Recovery (MMcf)

Days On

Actual

Gas Rate

No Free Gas Rate

Actual Cum Gas

No Free Gas

Cum Gas

400

350

300

250

200

150

100

50

0

400

350

300

250

200

150

100

50

0

0 100 200 300 400 500 600 700 800 900 1,000 1,100 1,200 1,300 1,400 1,500

Figure A-7. Reservoir Simulation of Wyodak Type Well w/ No Free Gas Gas Production Rate (Mcfd)

Cumulative Gas Recovery (MMcf)

Days On

Actual

Gas Rate

23%

Undersaturated

Gas Rate

Actual Cum Gas

23%

Undersaturated

Cum Gas

400

350

300

250

200

150

100

50

0

0

400

350

300

250

200

150

100

50

0

0 100 200 300 400 500 600 700 800 900 1,000 1,100 1,200 1,300 1,400 1,500

Figure A-8. Reservoir Simulation of Wyodak Type Well w/ 23% Gas Undersaturation
A-9

Gas Production Rate (Mcfd)

Cumulative Gas Recovery (MMcf)

Days On

Actual

Gas Rate

66%

Undersaturated

Gas Rate

Actual Cum Gas

66%

Undersaturated

Cum Gas

0 100 200 300 400 500 600 700 800 900 1,000 1,100 1,200 1,300 1,400 1,500

400

350

300

250

200

150

100

50

0

400

350

300

250

200

150

100

50

0

Figure A-9. Reservoir Simulation of Wyodak Type Well w/ 66% Gas Undersaturation

Table A-2 provides a comparison of the results from reservoir modeling of the four gas

saturation cases against actual production data. 

Table A-2. Comparison of Gas Production Rates for Wyodak Type Well

Reservoir Simulation Output

Actual

Data

Fully Saturated Undersaturated

w/Free Gas w/No Free Gas 23% 66%

Gas Rate (Mcfd)

@ 46 days 263 276 69 41 0

@ 289 days 301 291 200 142 51

Cumulative Gas Recovery (MMcf)

@1,475 days 255 255 196 144 58

Table A-3 provides data on key reservoir properties, such as coal seam depth, gas content,

pressure, and porosity used in the history match and sensitivity cases for the Wyodak coals

discussed in this memo.
A-10

T ime Zero Plo t f o r an A verag e W ell

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

0 5 10 15 20 25

Time ( M ont hs)

0

5

1 0

1 5

20

25

30

35

40

GAS

WATER

Wel Coun t

Figure A-10. Big George Time Zero Well Data

Table A-3. Wyodak Coal Seam Properties 

Coal

Seam

Depth

Gas

Content

Pressure

Gradient

Pressure

(Top of

Coal)

Porosity

Fracture Matrix

(feet) (cf/t) (psi/ft) (psi) (%) (%)

Wyodak

(Partition #4)

541 65 0.274 163 1.0 6.0

Evidence for Undersaturated Coals

No doubt undersaturated coals exist for some of the coal seams in some portions of the basin, as

discussed earlier by Bustin and Downey. Even in the Warrior Basin, some pockets of low gas

saturation have been observed in seams where the coals have been breached by faults.

However, high early water production and a delay in gas production (accepted as normal in most

other coal basins of the world) are not necessarily evidence that the coals are undersaturated. To

examine this, we assembled data on a group of 38 Big George coal wells in a deep, immaturely

developed portion of the basin. The time-zero gas and water production curve for these wells is

provided in Figure A-10. The reservoir simulation history match for these wells showed that the

coals were fully gas saturated (but with no free gas) and that the delayed onset of gas production

was caused by the difficulties in drawing down reservoir pressure due to high permeability and

the unconfined nature of the wells, Figure A-11.
A-11

Gas and Water Production Rate (Mcfd; Bwpd)

Cumulative Gas and Water Recovery (MMcf; Mbw)

Days On

550

500

450

400

350

300

250

200

150

100

50

0

0 250 500 750 1,000 1,250 1,500 1,750 2,000 2,250 2,500 2,750 3,000 3,250 3,500 3,750

550

500

450

400

350

300

250

200

150

100

50

0

Actual

Water Rate

Actual

Gas Rate

Actual/Projected

Cum Water

Actual/Projected

Cum Gas

Figure A-11. History Match Big George Type Well

As for the Wyodak, we examined how the Big George coal wells in this area would produce if

they were 23% to 66% undersaturated. Again, the use of such extreme gas undersaturation

values for the Big George coal provides gas production and recovery values that are much lower

than actually observed, as shown in Figure A-12 for the 23% gas undersaturated case. (No gas

production occurs from the Big George coal for the 66% undersaturated case during the first

year).

Table A-4 provides a comparison of the results from reservoir modeling of the three gas

saturation cases against actual production data. 

Table A-4. Comparison of Gas Production Rates for Big George Type Well

Reservoir Simulation Output

Actual

Data

Fully Saturated

w/No Free Gas

Undersaturated

23% 66%

Gas Production (Mcfd)

@ 76 days 24 21 0 0

@ 289 days 78 61 20 0

Gas Recovery (MMcf)
A-12

Days On

Gas Production Rate (Mcfd)

Cumulative Gas Recovery (MMcf)

Actual

Gas Rate

23% Undersaturated

Gas Rate

Actual Cum Gas

23% Undersaturated

Cum Gas

110

90

80

70

60

50

40

30

20

100

10

0

150

140

130

120

110

90

80

70

60

50

40

30

20

100

10

0

150

140

130

120

0 50 100 150 200 250 300 350 400 450 500

Figure A-12. Reservoir Simulation of Big George Type Well w/23% Gas Undersaturation

@350 days 16 16 3 0

Table A-5 provides the data on key reservoir properties, such as coal seam depth, gas content,

pressure, and porosity used in the history match and sensitivity cases for the Big George coal

discussed in the memo.

Table A-5. Big George Coal Seam Properties

Coal

Seam

Depth

Gas

Content

Pressure

Gradient

Pressure

(Top of

Coal)

Porosity

Fracture Matrix

(feet) (cf/t) (psi/ft) (psi) (%) (%)

Big George

(Partition #3)

1,000 86 0.320 335 0.2 4.0

OTHER STUDIES

The 1995 USGS National Assessment included estimates for coalbed methane in the Powder

River Basin. Dudley Rice, of the USGS, collected the geologic and reservoir data and Advanced

Resources conducted the reservoir simulations to establish recoverable gas. This past

assessment included the following data for the coals in the PRB, Table A-6:
A-13

 • The shallow coals were assumed to be fully gas saturated (desorption pressure equals

reservoir pressure); the deep coals were assumed to be 86% gas saturated.

 • The gas content for the shallow coals (at 500 feet and 165 psi) was calculated at 60

scf/ton; the gas content for the deep coals (at 1,250 feet and 490 psi) was calculated at

126 scf/ton.

 • The shallow coals were assumed to have 30% free gas in the fracture system; the deep

coals were assumed to have no free gas.

Table A-6. Reservoir Parameters for Powder River Basin (Fort Union Coals)

Shallow Deep

Coal Depth, feet 500 1,250

Coal Thickness, feet 90 90

Pressure Gradient, psi/ft 0.30 0.38

Initial Reservoir Pressure, psia 165 490

Initial Water (Gas) Saturation, % 70 (30) 100 (0)

In Situ Langmuir Volume, scf/ton a 562 562

Langmuir Pressure, psia 1,380 1,380

In Situ Gas Content, scf/ton a 60 126

Desorption Pressure, psia 165 390b

Sorption Time, days 3 3

Reservoir Temperature, o

F 72 100

Cleat Porosity, % 4 2

Pore Volume Compressibility, 10 -6 psi -1 200 200

Cleat Spacing, inches 0.2 0.2

Gas Gravity 0.75 0.75

Water Viscosity at Reservoir Conditions, cp 0.96 0.69

Water Formation Volume Factor, RB/STB 1.01 1.01

Completion and Stimulation Open-hole/Cased &

Frac'd c

Cased & Frac'd

xf = 40 ft d

Well Operation Pump Down Schedule 150 bwpd Pump Rate

Well Spacing, acres/well 40 40

Aquifer Recharge Rate, bwpd Weak (50), Strong (400) None

Absolute Cleat Permeability, md 10, 50, 75 1, 5, 10

 a In situ conditons include 3% ash and 20% moisture

 b Deeper coals are 86% saturated relative to the adsorptive capacity

 c Both completion types yield similar performance; rw = 0.26 ft used in simulations with no skin

factor applied

 d Assumes infinite conductivity fracture half-length (xf)
A-14

The comparison of gas content in the two studies, Table A-7 below, shows the PRB Study used

somewhat lower gas content values for the PRB coals than those used in the 1995 USGS

National Assessment.

Table A-7. Comparison of 1995 USGS and 2002 ARI Values for Gas Content of PRB Coals

Shallow Coal Deep Coal

1995 USGS 2002 ARI 1995 USGS 2002 ARI

Pressure (psi) 165 165 490 490

Gas Content (cf/t) 60 45 126 105