U.S. Shale Gas and Shale Oil Plays

Review of Emerging Resources: 

July 2011

www.eia.gov

U.S. Depa rtment of Energy

Washington, DC 20585
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The information presented in this overview is based on the report Review of Emerging Resources: 

U.S. Shale Gas and Shale Oil Plays, which was prepared by INTEK, Inc. for the U.S. Energy Information 

Administration (EIA), the statistical and analytical agency within the U.S. Department of Energy. The 

full report is attached. By law, EIA’s data, analyses, and forecasts are independent of approval by any 

other officer or employee of the United States Government. The views in this report therefore should 

not be construed as representing those of the Department of Energy or other Federal agencies.
4 U.S. Energy Information Administration | Review of Emerging Resources: U.S. Shale Gas and Shale Oil Plays

Review of Emerging Resources: U.S. Shale Gas and Shale Oil Plays

Background

The use of horizontal drilling in conjunction with hydraulic fracturing has greatly expanded the ability of producers to profitably 

recover natural gas and oil from low-permeability geologic plays—particularly, shale plays. Application of fracturing techniques 

to stimulate oil and gas production began to grow rapidly in the 1950s, although experimentation dates back to the 19th century. 

Starting in the mid-1970s, a partnership of private operators, the U.S. Department of Energy (DOE) and predecessor agencies, 

and the Gas Research Institute (GRI) endeavored to develop technologies for the commercial production of natural gas from the 

relatively shallow Devonian (Huron) shale in the eastern United States. This partnership helped foster technologies that eventually 

became crucial to the production of natural gas from shale rock, including horizontal wells, multi-stage fracturing, and slickwater fracturing.1

 Practical application of horizontal drilling to oil production began in the early 1980s, by which time the advent 

of improved downhole drilling motors and the invention of other necessary supporting equipment, materials, and technologies 

(particularly, downhole telemetry equipment) had brought some applications within the realm of commercial viability. 2

The advent of large-scale shale gas production did not occur until Mitchell Energy and Development Corporation experimented 

during the 1980s and 1990s to make deep shale gas production a commercial reality in the Barnett Shale in North-Central Texas. 

As the success of Mitchell Energy and Development became apparent, other companies aggressively entered the play, so that by 

2005, the Barnett Shale alone was producing nearly 0.5 trillion cubic feet of natural gas per year. As producers gained confidence in 

the ability to produce natural gas profitably in the Barnett Shale, with confirmation provided by results from the Fayetteville Shale in 

Arkansas, they began pursuing other shale plays, including Haynesville, Marcellus, Woodford, Eagle Ford, and others.

Although the U.S. Energy Information Administration’s (EIA) National Energy Modeling System (NEMS) and energy projections 

began representing shale gas resource development and production in the mid-1990s, only in the past 5 years has shale gas been 

recognized as a “game changer” for the U.S. natural gas market. The proliferation of activity into new shale plays has increased dry 

shale gas production in the United States from 1.0 trillion cubic feet in 2006 to 4.8 trillion cubic feet, or 23 percent of total U.S. dry 

natural gas production, in 2010. Wet shale gas reserves increased to about 60.64 trillion cubic feet by year-end 2009, when they 

comprised about 21 percent of overall U.S. natural gas reserves, now at the highest level since 1971.3 Oil production from shale 

plays, notably the Bakken Shale in North Dakota and Montana, has also grown rapidly in recent years. 

To gain a better understanding of the potential U.S. domestic shale gas and shale oil resources, EIA commissioned INTEK, Inc. to 

develop an assessment of onshore Lower 48 States technically recoverable shale gas and shale oil resources. This paper briefly 

describes the scope, methodology, and key results of the report and discusses the key assumptions that underlie the results. The 

full report prepared by INTEK is provided in Attachment A. The shale gas and shale oil resource assessment contained in the INTEK 

report and summarized here was incorporated into the Onshore Lower 48 Oil and Gas Supply Submodule (OLOGSS) within the Oil 

and Gas Supply Module (OGSM) of NEMS to project oil and natural gas production for the Annual Energy Outlook 2011 (AEO2011).

EIA also anticipates using the assessment to inform other analyses and to provide a starting point for future work.

Scope and results

The INTEK shale resources report estimates shale gas and shale oil resources for the undeveloped portions of 20 shale plays 

that have been discovered (Table 1). Eight of those shale plays are subdivided into 2 or 3 areas, resulting in a total of 29 separate 

resource assessments. The total of 750 trillion cubic feet shown in Table 1 excludes three additional components of resources: 

proven reserves, inferred reserves in actively developed areas and un-discovered resources as estimated by the U.S. Geological 

Survey (USGS). The map in Figure 1 shows the location of the shale plays in the Lower 48 States. 

Eighty-six percent of the total 750 trillion cubic feet of technically recoverable shale gas resources identified in Table 1 are located 

in the Northeast, Gulf Coast, and Southwest regions, which account for 63 percent, 13 percent, and 10 percent of the total, 

respectively. In the three regions, the largest shale gas plays are the Marcellus (410.3 trillion cubic feet, 55 percent of the total), 

Haynesville (74.7 trillion cubic feet, 10 percent of the total), and Barnett (43.4 trillion cubic feet, 6 percent of the total).

Table 1 also summarizes the INTEK shale report’s assessment of technically recoverable shale oil resources, which amount to 23.9 

billion barrels in the onshore Lower 48 States. The largest shale oil formation is the Monterey/Santos play in southern California, 

which is estimated to hold 15.4 billion barrels or 64 percent of the total shale oil resources shown in Table 1. The Monterey shale 

play is the primary source rock for the conventional oil reservoirs found in the Santa Maria and San Joaquin Basins in southern 

California. The next largest shale oil plays are the Bakken and Eagle Ford, which are assessed to hold approximately 3.6 billion 

barrels and 3.4 billion barrels of oil, respectively.
U.S. Energy Information Administration | Review of Emerging Resources: U.S. Shale Gas and Shale Oil Plays 5

 Review of Emerging Resources: U.S. Shale Gas and Shale Oil Plays

The 750 trillion cubic feet of shale gas resources in the INTEK shale report is a subset of the AEO2011 onshore Lower 48 States 

natural gas shale technically recoverable resource estimate of 862 trillion cubic feet. The AEO2011 includes 35 trillion cubic feet of 

proved reserves reported to the Securities and Exchange Commission (SEC) and the EIA, 20 trillion cubic feet of inferred reserves 

not included in the INTEK shale report, and 56 trillion cubic feet of undiscovered resources estimated by the USGS.

Table 1. INTEK estimates of undeveloped technically recoverable shale gas and shale oil

resources remaining in discovered shale plays as of January 1, 2009

Onshore Lower-48 Oil and Gas Supply

Submodule region Shale play

Shale gas resources

(trillion cubic feet)

Shale oil resources

(billion barrels)

Northeast Marcellus 410 --

Antrim 20 --

Devonian Low Thermal Maturity 14

New Albany 11 --

Greater Siltstone 8 --

Big Sandy 7 --

Cincinnati Arch* 1 --

Subtotal 472 --

Percent of total 63% --

Gulf Coast Haynesville 75 --

Eagle Ford 21 3

Floyd-Neal & Conasauga 4 --

Subtotal 100 3

Percent of total 13% 14%

Mid-Continent Fayetteville 32 --

Woodford 22 --

Cana Woodford 6 --

Subtotal 60 --

Percent of total 8% --

Southwest Barnett 43 --

Barnett-Woodford 32 --

Avalon & Bone Springs -- 2

Subtotal 76 2

Percent of total 10% 7%

Rocky Mountain Mancos 21 --

Lewis 12 --

Williston-Shallow Niobraran* 7 --

Hilliard-Baxter-Mancos 4 --

Bakken -- 4

Subtotal 43 4

Percent of total 6% 15%

West Coast Monterey/Santos -- 15

Subtotal -- 15

Percent of total -- 64%

Total onshore Lower-48 States 750 24

*Note: From previous EIA estimates and thus not assessed in the INTEK shale report.

Subtotals and total may not equal sum of components due to independent rounding.
6 U.S. Energy Information Administration | Review of Emerging Resources: U.S. Shale Gas and Shale Oil Plays

Review of Emerging Resources: U.S. Shale Gas and Shale Oil Plays

Figure 1. Map of U.S. shale gas and shale oil plays (as of May 9, 2011)

Source U.S. Energy Information Administration based on data from various published studies.

Upeate: May 9, 2011

Methodology

The resource estimates shown in Table 1 were developed by INTEK from publicly available company data and commercial 

databases for wells and acreage currently in production. The estimates of technically recoverable resources shown in Table 

1 are based on the area, well spacing, and average expected ultimate recovery (EUR) for each shale play or subportion of the 

play. An effective recovery factor has been applied which reflects: (a) a probability factor that takes into account the results 

from current shale gas activity as an indicator of how much is known or unknown about the shale play; (b) a recovery factor 

that takes into account prior experience in how production occurs, on average, given a range of factors (including mineralogy 

and geologic complexity) that affect the response of the geologic play to the application of best-practice shale gas recovery 

technology; and (c) resources in the play that have already been produced or added into proved reserves.

Estimates of technically recoverable shale gas resources are certain to change over time as new wells go into production and 

new technologies are developed. For example, the gas resource estimates in the INTEK shale report are predicated on the 

assumption that natural gas production rates for current wells covering only a limited portion of a play are representative 

of an entire play or play sub-area; however, across a single play or play sub-area there can be significant variations in depth, 

thickness, porosity, carbon content, pore pressure, clay content, thermal maturity, and water content. As a result, individual 

well production rates and recovery rates can vary by as much as a factor of 10.

There is considerable uncertainty regarding the ultimate size of technically recoverable shale gas and shale oil resources, 

including but are not limited to the following:

•	 Because most shale gas and shale oil wells are only a few years old, their long-term productivity is untested. Consequently, 

the long-term production profiles of shale wells and their estimated ultimate recovery of oil and natural gas are uncertain.

•	 In emerging shale plays, production has been confined largely to those areas known as “sweet spots” that have the highest 

known production rates for the play. If the production rates for the sweet spots are used to infer the productive potential 

of entire plays, their productive potential probably will be overstated. The INTEK shale report mitigates this problem by 

differentiating the productivity of a play’s sweet spot from the productivity for rest of that play.8
U.S. Energy Information Administration | Review of Emerging Resources: U.S. Shale Gas and Shale Oil Plays 7

 Review of Emerging Resources: U.S. Shale Gas and Shale Oil Plays

•	 Many shale plays are so large (e.g., the Marcellus shale) that only portions have been extensively production tested.

•	 Technical advancements could lead to more productive and less costly well drilling and completion.

•	 Currently untested shale plays, such as thin-seam plays or untested portions of existing plays, could prove to be highly 

productive.

Estimating the technically recoverable oil and natural gas resource base in the United States is an evolving process. For shale 

gas and oil, the evolution of resource estimates is likely to continue for some time. The size of the technically recoverable oil and 

natural gas resource base in the United States becomes evident only as producers drill into geologic deposits with oil and natural 

gas potential and attempt to produce from them on a commercial basis. As producers find plays to be more or less bountiful than 

expected, resource estimates are adjusted to reflect that information. As time passes and our knowledge of the resource base and 

future technologies and management practices improves, estimates of the technically recoverable resource base will be refined. 

Consequently, the resource estimates in the current report will be modified over time as more wells are drilled and completed, 

technologies evolve, and the long-term performance of shale wells becomes better established.

The estimates of shale oil and shale gas resources provided here represent a reasonable estimate of the resource potential for those 

shale plays for which public information is currently available. The potential impacts of the current uncertainty regarding shale gas 

resources on projected natural gas supply, consumption, and prices are described in the AEO2011 Issues in Focus article, “Prospects 

for shale gas.”9

Footnotes

1

 G.E. King, Apache Corporation, “Thirty Years of Gas Shale Fracturing: What Have We Learned?”, presentation SPE 133456, SPE 

Annual Technical Conference and Exhibition (Florence, Italy, September 2010), www.spe.org/atce/2010/pages/schedule/tech_

program/documents/spe1334561.pdf; and U.S. Department of Energy, “DOE’s Early Investment in Shale Gas Technology Producing 

Results Today” (February 2, 2011), www.netl.doe.gov/publications/press/2011/11008-DOE_Shale_Gas_Research_Producing_R.

html.

2

 U.S. Energy Information Administration, Drilling Sideways—A Review of Horizontal Well Technology and Its Domestic Application, 

DOE/EIA-TR-0565 (Washington, DC, April 1993), ftp://tonto.eia.doe.gov/pub/oil_gas/natural_gas/analysis_publications/drilling_

sideways_well_technology/pdf/tr0565.pdf.

3

 U.S. Energy Information Administration, U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves (Washington, DC, 

November 30, 2010), www.eia.doe.gov/oil_gas/natural_gas/data_publications/crude_oil_natural_gas_reserves/cr.html.

4 American Association of Petroleum Geologists, “Monterey Shale Gets New Look,” Explorer, Vol. 31, No. 11 (No-vember 2010), 

http://www.aapg.org/explorer/2010/11nov/monterey1110.cfm.

5

 Additional information and comparisons of the SEC and EIA reserves can be found in the EIA report “U.S. Crude Oil, Natural Gas, 

and Natural Gas Liquids Proved Reserves, 2009” and a supplemental report “Top 100 Operators: Proved Reserves and Production, 

Operated vs Owned, 2009”. http://www.eia.gov/oil_gas/natural_gas/data_publications/crude_oil_natural_gas_reserves/cr.html.

6

 HPDI, LLC production database, and Nehring Associates (NRG), Significant Oil and Gas Fields of the United States Database.

7

 The EURs presented in this report do not include natural gas plant liquids.

8

 In the INTEK report, the “sweet spot” portion of the formation is referred to as the “active area.” The remaining portion of the 

formation that has seen little or no drilling activity is referred to as the “undeveloped area.”

9

 U.S. Energy Information Administration, Annual Energy Outlook 2011, DOE/EIA-0383(2011) (Washington, DC, April 2011), 

“Prospects for shale gas,” www.eia.gov/forecasts/aeo/IF_all.cfm#prospectshale.
8 U.S. Energy Information Administration | Review of Emerging Resources: U.S. Shale Gas and Shale Oil Plays

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 Review of Emerging Resources: U.S. Shale Gas and Shale Oil Plays

Attachment A
 INTEK, Inc. 

Review of Emerging Resources

U.S. Shale Gas and Shale Oil Plays 

December 2010

Prepared for:

Office of Energy Analysis

Energy Information Administration 

U.S. Department of Energy

Washington, D.C

Disclaimer

Neither the United States Government nor any agency thereof, nor any of their employees or contractors, 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 herein to any specific commercial product, process or service by 

trade name, trademark, manufacture, or otherwise, does not constitute or imply its endorsement, 

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

opinions expressed herein are not those of the United States Government or any agency thereof. The information 

in the technology profiles was provided by the host institutions; there has been no independent verification of 

any of this information. This work was completed under contract number DE-EI0000564 and task order number 

DE-DT0001772. Neither INTEK, Inc., nor the Department of Energy makes any representation as to the 

accuracy of the information.

Review of Emerging U.S. Shale Gas and Shale Oil Plays

i

Table of Contents

Executive Summary...........................................................................................................vii

I. Introduction .............................................................................................................1

II. Northeast Regional Summary..................................................................................3

A. Marcellus Shale Gas Play................................................................................5

B. Devonian Big Sandy Shale Gas Play...............................................................9

C. Devonian Low Thermal Maturity & Greater Siltstone Shale Gas Plays.......13

D. New Albany Shale Gas Play..........................................................................15

E. Antrim Shale Gas Play ..................................................................................19

III. Gulf Coast Regional Summary..............................................................................23

A. Haynesville Shale Gas Play...........................................................................25

B. Eagle Ford Shale Gas & Oil Play..................................................................29

C. Floyd-Neal/Conasauga Shale Gas Play.........................................................33

IV. Mid-Continent Regional Summary .......................................................................35

A. Fayetteville Shale Gas Play ...........................................................................37

B. Woodford Shale Gas Play .............................................................................41

C. Cana Woodford Shale Gas Play ....................................................................45

V. Southwest Regional Summary ..............................................................................49

A. Barnett Shale Gas Play ..................................................................................51

B. Barnett-Woodford Shale Gas Play ................................................................55

C. Avalon & Bone Springs Shale Oil Play ........................................................57

VI. Rocky Mountain Regional Summary ....................................................................61

A. Hilliard-Baxter-Mancos Shale Gas Play .......................................................63

B. Lewis Shale Gas Play ....................................................................................65

C. Mancos Shale Gas Play .................................................................................67

D. Bakken Shale Oil Play...................................................................................69

VII. West Coast Regional Summary.............................................................................73

A. Monterey/Santos Shale Oil Play....................................................................75

VIII. Appendix A – OLOGSS Shale Gas Data File .......................................................79
Review of Emerging U.S. Shale Gas and Shale Oil Plays

ii

List of Figures

Figure i U.S. Shale Gas and Shale Oil Plays..........................................................vii

Figure ii Shale Gas Technically Recoverable Resources and Cumulative Production...........ix

Figure 1 Northeast Shale Gas and Shale Oil Resources.............................................................3

Figure 2 Marcellus Shale Play....................................................................................................5

Figure 3 Marcellus Type Curve..................................................................................................8

Figure 4 Devonian-Big Sandy Shale Play ..................................................................................9

Figure 5 Devonian Low Thermal Maturity and Greater Siltstone Shale Plays........................13

Figure 6 New Albany Shale Play .............................................................................................15

Figure 7 Antrim Shale Play ......................................................................................................19

Figure 8 Gulf Coast Shale Gas and Shale Oil Resources.........................................................23

Figure 9 The Haynesville Shale Play .......................................................................................25

Figure 10 Haynesville Type Curve...........................................................................................27

Figure 11 Eagle Ford Shale Play ..............................................................................................29

Figure 12 Eagle Ford Type Curve ............................................................................................32

Figure 13 Floyd-Neal/Conasauga Shale Play...........................................................................33

Figure 14 Mid-Continent Shale Gas and Shale Oil Resources.................................................35

Figure 15 Fayetteville Shale Play.............................................................................................37

Figure 16 Fayetteville Type Curve...........................................................................................39

Figure 17 Woodford Shale Play ...............................................................................................41

Figure 18 Cana Woodford Shale Play......................................................................................45

Figure 19 Cana Woodford Type Curve ....................................................................................46

Figure 20 Southwest Shale Gas and Shale Oil Resources........................................................49

Figure 21 The Barnett Shale Play.............................................................................................51

Figure 22 Barnett Type Curve..................................................................................................53

Figure 23 Barnett-Woodford Shale Play ..................................................................................55

Figure 24 Avalon and Bone Springs Shale Play ......................................................................57

Figure 25 Rocky Mountains Shale Gas and Shale Oil Resources............................................61

Figure 26 Hilliard-Baxter-Mancos Shale Play .........................................................................63

Figure 27 Lewis Shale Play......................................................................................................65

Figure 28 The Mancos Shale Play............................................................................................67

Figure 29 Bakken Shale Play ...................................................................................................69

Figure 30 Bakken Shale Type Curve........................................................................................71

Figure 31 West Coast Shale Gas and Shale Oil Resources......................................................73

Figure 32 Monterey/Santos Shale Play ....................................................................................75

Figure 33 Monterey/Santos Type Curve ..................................................................................77
Review of Emerging U.S. Shale Gas and Shale Oil Plays

iii

List of Tables

Table i U.S Shale Gas Unproved Discovered Technically Recoverable Resources

Summary...................................................................................................viii

Table ii U.S Technically Recoverable Shale Oil Resources

Summary.......................................................................................................x

Table 1 State Distribution of the Marcellus Shale Play .............................................................5

Table 2 Marcellus Average EUR and Area ................................................................................6

Table 3 Average General Properties for the Marcellus Shale Play ............................................6

Table 4 Marcellus Lease Holders...............................................................................................7

Table 5 Devonian Big Sandy Average EUR and Area.............................................................10

Table 6 Average General Properties for the Devonian Big Sandy Shale Play.........................10

Table 7 Devonian-Big Sandy Lease Holders ...........................................................................10

Table 8 Devonian Low Thermal Maturity and Greater Siltstone Average EUR and Area......14

Table 9 Average General Properties for the Devonian-Low Thermal Maturity and Greater 

Siltstone Shale Plays.........................................................................................................14

Table 10 New Albany Average EUR and Area........................................................................16

Table 11 Average General Properties for the New Albany Shale Play....................................16

Table 12 New Albany Lease Holders.......................................................................................16

Table 13 Average Antrim EUR and Area ................................................................................20

Table 14 Average General Properties for the Antrim Shale Play ............................................20

Table 15 Antrim Lease Holders ...............................................................................................20

Table 16 Haynesville Average EUR and Area.........................................................................26

Table 17 Average General Properties for the Haynesville Shale Play.....................................26

Table 18 Haynesville Lease Holders........................................................................................26

Table 19 Eagle Ford Average EUR and Areas.........................................................................30

Table 20 Average General Properties for the Eagle Ford Shale Play ......................................30

Table 21 Eagle Ford Dry Gas Zone Lease Holders..................................................................30

Table 22 Eagle Ford Condensate Zone Lease Holders ............................................................31

Table 23 Eagle Ford Oil Zone Lease Holders..........................................................................31

Table 24 Floyd-Neal/Conasauga Average EUR and Area .......................................................33

Table 25 Average General Properties for the Floyd-Neal/Conasauga Shale Play ...................34

Table 26 Floyd-Neal/Conasauga Lease Holders......................................................................34

Table 27 Fayetteville Average EUR and Area .........................................................................37

Table 28 Average General Properties for the Fayetteville Shale Play .....................................38

Table 29 Fayetteville Lease Holders........................................................................................38

Table 30 Woodford Average EUR and Area ...........................................................................41

Table 31 Average General Properties for the Woodford Shale Play........................................42

Table 32 Woodford Lease Holders in the Arkoma and Ardmore Basins.................................42

Table 33 Cana Woodford Average EUR and Area ..................................................................45

Table 34 Average General Properties for the Cana Woodford Shale Play .............................45

Table 35 Cana Woodford Lease Holders .................................................................................46

Table 36 Average Barnett EUR and Area ................................................................................52

Table 37 Average General Properties for the Barnett Shale Play ............................................52

Table 38 Barnett Core/Tier 1 Lease Holders............................................................................52
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iv

Table 39 Barnett South/Western Counties Lease Holders .......................................................52

Table 40 Barnett-Woodford Average EUR and Area ..............................................................55

Table 41 Average General Properties for the Woodford Shale Play........................................56

Table 42 Barnett-Woodford Lease Holders .............................................................................56

Table 43 Avalon and Bone Springs EUR and Area .................................................................58

Table 44 General Properties for the Avalon/Bone Springs Shale Play....................................58

Table 45 Avalon and Bone Springs Lease Holders..................................................................58

Table 46 Hilliard-Baxter-Mancos Average EUR and Area .....................................................63

Table 47 Average General Properties for the Hilliard-Baxter-Mancos Shale Play..................64

Table 48 Hilliard-Baxter-Mancos Lease Holders.....................................................................64

Table 49 Lewis Average EUR and Area ..................................................................................65

Table 50 Average General Properties for the Lewis Shale Play ..............................................66

Table 51 Mancos Average EUR and Area ...............................................................................67

Table 52 Average General Properties for the Mancos Shale Play ...........................................68

Table 53 Mancos Lease Holders ..............................................................................................68

Table 54 Bakken Average EUR and Area................................................................................69

Table 55 Average General Properties for the Bakken Shale Play............................................70

Table 56 Bakken Lease Holders...............................................................................................70

Table 57 Monterey/Santos Average EUR and Area.................................................................75

Table 58 Average General Properties for the Monterey/Santos Shale Play.............................76

Table 59 Monterey/Santos Lease Holders................................................................................76
Review of Emerging U.S. Shale Gas and Shale Oil Plays

v

List of Abbreviations & Acronyms

Abbreviation/ Acronym Full Text

Bbbl Billion Barrels

bbl Barrel 

BBO Billion Barrels of Oil

BBOE Billion Barrels of Oil Equivalent

Bcf Billion Cubic Feet

Bcfe Billion Cubic Feet of Equivalent

BOE Barrels of Oil Equivalent

DOE Department of Energy

EIA Energy Information Administration

EUR Estimated Ultimate Recovery

MBOE Thousand Barrels of Oil Equivalent

MMBOE Million Barrels of Oil Equivalent

Tcf Trillion Cubic Feet

Tcfe Trillion Cubic Feet Equivalent

TRR Technically Recoverable Resources

USGS United States Geological Survey
Review of Emerging U.S. Shale Gas and Shale Oil Plays

vi
Review of Emerging U.S. Shale Gas and Shale Oil Plays

vii

Executive Summary

The Energy Information Administration’s (EIA) 2010 Annual Energy Outlook (AEO2010)

discussed the growing importance of shale gas as a component of natural gas production. 

“...[T]he biggest questions are the size of the shale gas resource base (which by most 

estimates is vast), the price level required to sustain its development, and whether there are 

technical or environmental factors that might dampen its development”. EIA’s AEO2010

reference case estimate for the shale gas resource base was 347 trillion cubic feet (Tcf).

In recognition of the increasing contribution of shale gas production to the United States, in 

late 2010, a study was undertaken to review and update the resource base estimates for the 

U.S. shale gas resources as well as emerging shale oil plays. These plays are illustrated in 

Figure i. 

Figure i U.S. Shale Gas and Shale Oil Plays

Shale Gas

Significant activities are underway in the United States to explore, develop, and produce 

America’s shale gas and oil plays. The shale gas plays contain “fine grained, organic rich, 

sedimentary rocks. The shales are both the source of and the reservoir for natural gas” and 

oil. They are also defined by the “extremely small pore sizes [which] make them relatively 

impermeable to gas flow, unless natural or artificial fractures occur”. A summary of the

San Joaquin 

Basin

Los Angeles 

Basin

California

Avalon 

and Bone 

Springs

Shale Gas and Shale Oil Plays, Lower 48 States

Shale Gas & Shale Oil Plays

Shale Gas Plays

Shale Oil Plays

Basins

Shallowest/ Youngest

Deepest/ Oldest

Stacked Plays

Shale Gas and Shale Oil Plays

Bakken

San Joaquin 

Basin

Los Angeles 

Basin

California

Avalon 

and Bone 

Springs

Shale Gas and Shale Oil Plays, Lower 48 States

Shale Gas & Shale Oil Plays

Shale Gas Plays

Shale Oil Plays

Basins

Shallowest/ Youngest

Deepest/ Oldest

Stacked Plays

Shale Gas and Shale Oil Plays

Bakken

Executive Summary
Review of Emerging U.S. Shale Gas and Shale Oil Plays

viii

unproved discovered technically recoverable resources (TRR) is provided in the following 

Table.

Table i U.S. Shale Gas Unproved Discovered Technically Recoverable Resources Summary

Play

Technically

Recoverable 

Resource

Area (sq. miles)

Average EUR

Gas 

(Tcf)

Oil 

(BBO)

Leased Unleased Gas 

(Bcf/ 

well)

Oil 

(MBO/ 

well)

Marcellus 410.34 ... 10,622 84,271 1.18 ...

Big Sandy 7.40 ... 8,675 1,994 0.33 ...

Low Thermal Maturity 13.53 ... 45,844 0.30 ...

Greater Siltstone 8.46 ... 22,914 0.19 ...

New Albany 10.95 ... 1,600 41,900 1.10 ...

Antrim 19.93 ... 12,000 0.28 ...

Cincinnati Arch* 1.44 ... NA 0.12 ...

Total Northeast 472.05 ... 101,655 128,272 0.74 ...

Haynesville 74.71 ... 3,574 5,426 3.57 ...

Eagle Ford 20.81 ... 1,090 5.00 ...

Floyd-Neal & Conasauga 4.37 ... 2,429 0.90 ...

Total Gulf Coast 99.99 ... 7,093 5,426 2.99 ...

Fayetteville 31.96 ... 9,000 2.07 ...

Woodford 22.21 ... 4,700 2.98 ...

Cana Woodford 5.72 ... 688 5.20 ...

Total Mid-Continent 59.88 ... 14,388 2.45 ...

Barnett 43.38 ... 4,075 2,383 1.42 ...

Barnett Woodford 32.15 ... 2,691 3.07 ...

Total Southwest 75.52 ... 6,766 2,383 1.85 ...

Hilliard-Baxter-Mancos 3.77 ... 16,416 0.18 ...

Lewis 11.63 ... 7,506 1.30 ...

Williston-Shallow Niobraran* 6.61 ... NA 0.45 ...

Mancos 21.02 ... 6,589 1.00 ...

Total Rocky Mountain 43.03 ... 30,511 0.69 ...

Total Lower 48 U.S. 750.38 ... 160,413 136,081 1.02 ...

*Cincinnati Arch and Williston-Shallow Niobraran were not assessed in this report.

The 750 trillion cubic feet of shale gas resources in the INTEK shale report is a subset of the 

AEO2011 onshore lower 48 natural gas shale resource estimate of 862 trillion cubic feet. The 

AEO2011 includes 35 trillion cubic feet of “proved reserves” reported to the Securities and 

Exchange Commission (SEC) and the EIA1, 20 trillion cubic feet of inferred reserves not 

 

1 Additional information and comparisons of the SEC and EIA reserves can be found in the 

EIA report “U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Proved Reserves, 2009” 

Executive Summary
Review of Emerging U.S. Shale Gas and Shale Oil Plays

ix

included in the INTEK shale report, and 56 trillion cubic feet of undiscovered resources 

estimated by the USGS. Of that amount, 41.4 trillion cubic feet is located in Southern 

California and 14.6 trillion cubic feet in the Rocky Mountain region. The play average 

expected ultimate recoveries (EUR) are between 0.12 billion cubic feet (Bcf) and 3.6 Bcf per 

well. The largest concentrations of shale gas are contained in the Northeast region which 

contains the Marcellus Shale and the Gulf Coast region containing the Haynesville Shale.

Figure ii shows the technically recoverable shale gas resource and the fraction which has 

already been produced. The figure shows that, excluding the Appalachian plays and some of 

the newly developing plays, between one and three percent has been produced. The size of 

the remaining resource underscores the importance that shale gas can play in U.S. natural gas 

production as well as the necessity of this resource review.

Figure ii Shale Gas Technically Recoverable Resources and Cumulative Production2

In order to realize this production, substantial drilling is required. As the effective lifespan of 

the shale gas wells is relatively short, new wells are required to maintain current production 

levels as well as increase them. 

 

and a supplemental report “Top 100 Operators: Proved Reserves and Production, Operated vs 

Owned, 2009”. 

http://www.eia.gov/oil_gas/natural_gas/data_publications/crude_oil_natural_gas_reserves/cr.

html

2 Due to data availability, the Appalachian plays not included in Figure ii are the Marcellus, Devonian Big 

Sandy, Devonian Low Thermal Maturity, Devonian Greater Siltstone and Cincinnati Arch.

Executive Summary

Produced 1 – 3%

Remaining
Review of Emerging U.S. Shale Gas and Shale Oil Plays

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Shale Oil

In addition to the gas produced in the shale plays, condensate and plant liquids may also be 

produced. Four shale oil plays were also identified and reviewed during this analysis. As 

seen in the following Table, the majority of these resources are located in the 

Monterey/Santos shales currently under development by OXY. The technically recoverable 

resource for these four plays is approximately 24 Billion barrels of oil (BBO) across nearly 

13,000 square miles. The average EUR for the plays is approximately 460 thousand barrels of 

oil (MBO).

Table ii U.S. Technically Recoverable Shale Oil Resources Summary

Play

Technically 

Recoverable 

Resource

Area (sq. miles)

Average EUR

Gas 

(Tcf)

Oil 

(BBO)

Leased Unleased Gas 

(Bcf/ 

well)

Oil 

(MBO/ 

well)

Eagle Ford ... 3.35 3,323 ... 300

Total Gulf Coast ... 3.35 3,323 ... 300

Avalon & Bone Springs ... 1.58 1,313 ... 300

Total Southwest ... 1.58 1,313 ... 300

Bakken ... 3.59 6,522 ... 550

Total Rocky Mountain ... 3.59 6,522 ... 550

Monterey/Santos ... 15.42 1,752 ... 550

Total West Coast ... 15.42 1,752 ... 550

Total Lower 48 U.S. ... 23.94 12,910 ... 460

References

1. Department of Energy, Energy Information Administration. Annual Energy Outlook 

2010. April 2010.

2. Department of Energy, Energy Information Administration. Modified by INTEK Inc.

3. Congressional Research Services. Unconventional Gas Shales: Development, 

Technology, and Policy Issues. October 2009.

4. NRG & Associates and HPDI Data.

Executive Summary
Review of Emerging U.S. Shale Gas and Shale Oil Plays

1

I. Introduction

This document provides a brief description of shale gas and shale oil plays in the United 

States organized by chapters based on the oil and gas supply module regions. The regions 

included in this document are the Northeast, Gulf Coast, Mid-Continent, Southwest, Rocky 

Mountain, and West Coast Region. Each play description includes an estimate of the resource 

at the well level and across the play, description of key properties, a list of the companies 

active in the play as well as their activities, a comparison against United States Geological 

Survey (USGS) estimates, and other information. This information has been collected from 

publicly available data sources including USGS, the Department of Energy (DOE), individual 

exploration and development companies, journal articles, and other data sources. 

The resource estimates in the following play descriptions were developed using a wide variety 

of data sources. These sources include institutes such as the USGS, professional associations 

such as the American Association of Petroleum Geologists (AAPG), commercial databases

from the HPDI and Nehring Associates (NRG), integrated oil and gas companies, and service 

companies. In addition to these public sources of data, proprietary data and insights gleamed 

from conversations with experts were used to augment the estimates of resource and other 

parameters. The acreage which is reported includes sections which are currently being 

produced. The Technically Recoverable Resources (TRR) provided in Table i and in the 

following play descriptions are a function of the area, the well spacing, and the play average 

EUR. An effective recovery factor has been applied which reflects (a) a probability factor 

which takes into account the results from current shale gas activity as an indicator of how 

much is known or unknown about the shale formation, (b) a recovery factor which takes into 

account prior experience in how production occurs, on average, given a range of factors 

including mineralogy and geologic complexity that affect the response of the geologic 

formation to the application of best practice shale gas recovery technology, and (c) the 

removal of the resources in the play that have already been produced or added into proved 

reserves. The EURs presented in this report do not include natural gas plant liquids. 

The Northeast Region includes the Marcellus, Devonian Big Sandy, Devonian Low Thermal 

Maturity, Devonian Greater Siltstone, New Albany and the Antrim shale gas plays. 

The Gulf Coast Region includes the Haynesville, Eagle Ford and the FloydNeal/Conasauga shale gas and shale oil plays. 

The Mid-Continent Region includes the Fayetteville, Woodford and the Cana 

Woodford shale gas plays. 

The Southwest Region includes the Barnett, Barnett-Woodford, and the Avalon and 

Bone Springs shale gas and shale oil plays. 

The Rocky Mountain Region includes the Hilliard-Baxter-Mancos, Lewis, Mancos 

and the Bakken shale gas and shale oil plays.

The West Coast Region includes the Monterey/Santos shale oil play.

Introduction
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Introduction
Review of Emerging U.S. Shale Gas and Shale Oil Plays

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II. Northeast Regional Summary

The Northeast region includes shale gas plays located in the Appalachian, Illinois and 

Michigan Basins. The Appalachian Basin includes the Marcellus, Devonian Big Sandy, 

Devonian Low Thermal Maturity, and the Devonian Greater Siltstone shale plays (Figure 1). 

New Albany is located in the Illinois Basin and the Antrim shale play is located within the 

Michigan Basin. The shale plays in the Northeast region cover a total estimated area of 

229,927 square miles with an average EUR between 0.3 and 2.3 Bcf per well and 

approximately 472 Tcf of technically recoverable gas.

Figure 1 Northeast Shale Gas and Shale Oil Resources

Antrim

New Albany

Big Sandy

Greater Siltstone

Marcellus

Low 

Thermal 

Maturity

Antrim

New Albany

Big Sandy

Greater Siltstone

Marcellus

Low 

Thermal 

Maturity

20 – 50 Tcf

50 – 300 Tcf

0 – 20 Tcf

Antrim

New Albany

Big Sandy

Greater Siltstone

Marcellus

Low 

Thermal 

Maturity

Antrim

New Albany

Big Sandy

Greater Siltstone

Marcellus

Low 

Thermal 

Maturity

20 – 50 Tcf

50 – 300 Tcf

0 – 20 Tcf

Northeast Region
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Northeast Region
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A. Marcellus Shale Gas Play

Play Description

The Marcellus shale gas play is located in the Appalachian Basin across the Eastern Part of 

the United States. The states which contain the shale, according to the USGS, are provided in 

Table 1.

Table 1 State Distribution of the Marcellus Shale Play

State Areal % of Marcellus

Maryland 1.09

New York 20.06

Ohio 18.19

Pennsylvania 35.35

Virginia 3.85

West Virginia 21.33

For purposes of EIA’s modeling, the Marcellus was divided into two main units: the Active

Area and the Undeveloped Area. The active area, defined using the acreage reportedly under 

lease by the companies, is primarily located within West Virginia and Pennsylvania. This 

area is 10,622 square miles. The remainder of the area, 84,271 square miles corresponds to 

the area which has not been leased by the companies. The areal extent of the Marcellus shale 

is provided in Figure 2.

Figure 2 Marcellus Shale Play

Marcellus
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Resource Estimate

As estimated by the USGS, the Marcellus shale has a total area of 95,000 square miles. The 

depth of the shale ranges between 4,000 and 8,500 with a thickness between 50 to 200 feet. 

The average EUR for both the active and undeveloped areas is 2.325 Bcfe per well. The 

active area, as detailed in Table 2, is 10,622 square miles and has a total TRR of 177.9 Tcf, 

which is equivalent to 3.5 Bcf per well. At the well level, the overwhelming majority of 

reported EURs range between 3 and 4 Bcf. Due to a development moratorium in New York, 

access to resource, lack of current production, and other issues in the undeveloped section of 

the Marcellus, the number of drilling locations and the total TRR is uncertain. However, the 

well level EUR has been estimated at 1.15 Bcf.

Table 2 Marcellus Average EUR and Area

Active Undeveloped

Area (sq. miles) 10,622 84,271

EUR (Bcfe/ well) 3.5 1.15

Well Spacing (wells/ sq. mile) 8 8

TRR (Tcf) 177.90 232.44

Other average properties were estimated for the Marcellus shale play. These include the 

depth, thickness, porosity, and total organic content for the shale. The values are provided in 

Table 3.

Table 3 Average General Properties for the Marcellus Shale Play

Depth (ft) 6,750

Thickness (ft) 125

Porosity (%) 8

Total Organic Content (% wt) 12

Active Companies

In 2008, there were 19 companies holding leases in the Marcellus shale. These companies, 

along with their net acreage, are provided in Table 4.

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Table 4 Marcellus Lease Holders

Company Net Acreage

Anadarko Petroleum 275,000

Atlas Energy Resources LLC 483,000

Cabot Oil & Gas 332,919

Carrizo Oil & Gas 57,000

Chesapeake 1,200,000

CNX Gas 161,000

Dominion 800,000

Equitable Resources 400,000

EXCO Resources 393,000

Penn-Virginia 15,000

Petroleum Development 35,000

Range Resources 1,400,000

Rex Energy 57,000

Quest energy Partners L.P. 119,000

Southwestern Energy 100,000

Talisman 640,000

Ultra Petroleum 140,100

Unit Corp. 38,000

XTO Energy 152,000

Based upon these lease holdings, the total active area is calculated at 6,798,019 net acres 

(10,622 square miles).

Well Costs

In 2008, Deutsche Bank reported the average well cost as between $3 and $4 million dollars. 

This is approximately the level of costs reported in 2010 by the majority of the companies. 

The highest reported cost is Rex Energy – between $4.5 and $4.7 million dollars.

USGS Comparison

In 2002, the USGS conducted an assessment of the Marcellus shale. They estimated that the 

total undiscovered resource is between 822 and 3,668 Bcf, with a mean of 1,925 Bcf.

Representative Type Curve

Figure 3 provides a representative type curve for a horizontal well in the Marcellus shale. 

According to Chesapeake Energy, the decline rate is initially 75% and bottoms out at 6% in 

the later years.

Marcellus
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Figure 3 Marcellus Type Curve

References

1. USGS. Assessment of Undiscovered Oil and Gas Resources of the Appalachian Basin 

Province. 2002.

2. Deutsche Bank. From Shale to Shining Shale. July 2008.

3. Wrightstone Gregory, Texas Keystone, Inc. Marcellus Shale – Geologic Controls on 

Production. Presented at the Winter Meeting of the IOGAWV. February 2009.

4. U.S. Department of Energy. Modern Shale Gas Development in the United States: A 

Primer. April 2009.

5. Carrizo Oil & Gas. Presented at the Howard Weil 38th Annual Energy Conference. 

March 24, 2010.

6. XTO Energy. Barnett vs. Marcellus – A Comparison of Two Shale Gas Giants. June 

2009.

7. Whitelight Development Inc. The Marcellus Shale Great Expedition.

8. Chesapeake Energy. Marcellus Shale Overview. 2008.

9. Chesapeake Energy. August 2010 Investor Presentation. August 2010.

10. EQT. Analyst Presentation. March 2009.

11. ALL Consulting. Evaluating the Environmental Implications of Hydraulic Fracturing 

in Shale Gas Reservoirs. Presented at the International Petroleum & BioFuels 

Environmental Conference, Albuquerque, New Mexico. November 2008.

12. Range Resources. March Company Presentation. March 2009.

13. Range Resources. The Marcellus Shale. 2007.

14. TransEnergy Incorporated. 2008.

15. Phasis Consulting. US Shale Gas Brief. September 2008.

16. Baylor, Brandon. Marcellus Shale Decline Analysis. 2010.

17. McKinsey & Company. The Surge of North American Unconventional Gas and Its 

Impact. Presented at the Conference on Energy in the USA, Paris. June 2010.

Marcellus
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B. Devonian Big Sandy Shale Gas Play

Play Description

The Devonian Big Sandy shale gas play includes the Huron, Cleveland and Rhinestreet 

formations located within the Appalachian Basin in Kentucky, Virginia and West Virginia. 

For modeling purposes, the Big Sandy was divided into two main units: the Developed Area 

and Undeveloped Area. The location of the Big Sandy shale play is provided in Figure 4.

Figure 4 Devonian-Big Sandy Shale Play

Resource Estimate 

The USGS estimated a total area for the Big Sandy shale play as 10,669 square miles 

(6,828,000 acres). The shale play has an average EUR of 0.325 Bcf per well and 

approximately 7.4 Tcf of technically recoverable gas. Big Sandy has a total active area of 

approximately 8,675 square miles and an undeveloped area of 1,994 square miles with a well 

spacing of 80 acres per well. According to Deutsche Bank, Big Sandy ranges from 1,600 to 

6,000 feet deep and has a thickness of 50 to 300 feet. These values are provided in Tables 5 

and 6.

Devonian Big Sandy
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Table 5 Devonian Big Sandy Average EUR and Area

Active Undeveloped

Area (sq. miles) 8,675 1,994

EUR (Bcf/ well) 0.325 0.325

Well Spacing (wells/ sq. mile) 8 8

TRR (Tcf) 6.47 0.92

Other average properties were estimated for the Big Sandy shale play. These include the 

depth, thickness, porosity, and total organic content for the shale. The values are provided in 

Table 6.

Table 6 Average General Properties for the Devonian Big Sandy Shale Play

Depth (ft) 3,800

Thickness (ft) 175

Porosity (%) 10

Total Organic Content (% wt) 3.75

Active Companies

In 2008, there were 10 companies holding leases in Big Sandy. These companies, along with 

their net acreage, as reported by Deutsche Bank, are listed in Table 7. 

Table 7 Devonian-Big Sandy Lease Holders

Company Net Acreage

Cabot Oil & Gas 962,471

Chesapeake Energy 500,000

CNX Gas 193,000

Dominion 300,000

Equitable Resources 2,900,000

EXCO Resources 117,000

GeoMet 52,000

NGAS Resources 275,000

Penn-Virginia 87,500

Range Resources 165,000

Based upon these lease holdings, the total active area is calculated at 5,551,971 net acres 

(8,675 square miles).

Well Costs

In 2008, Deutsche Bank reported a well cost ranging from $0.5 to $3.0 million dollars and as 

of 2009, Equitable Resources reports an average well cost of approximately $1.2 million 

dollars. 

Devonian Big Sandy
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USGS Comparison 

In 2002, the USGS conducted an assessment of Devonian Big Sandy in the Appalachian 

Basin. They estimated that the total undiscovered resource is between 3,877 and 9,562 Bcf, 

with a mean of 6,323 Bcf.

References

1. Deutsche Bank. From Shale to Shining Shale. July 2008.

2. USGS. Assessment of the Undiscovered Oil and Gas Resources of the Appalachian 

Basin Province. 2002.

3. USGS. U.S. Geological Survey Open-File Report 2005-1268. 2005.

4. Range Resources. March Company Presentation. March 2009.

5. Wrightstone Gregory, Texas Keystone, Inc. Marcellus Shale – Geologic Controls on 

Production. Presented at the Winter Meeting of the IOGAWV. February 2009.

6. Equitable Resources. Analyst Presentation. March 2009.

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Devonian Big Sandy
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C. Devonian Low Thermal Maturity & Greater Siltstone 

Shale Gas Plays

Play Description

The Devonian Low Thermal Maturity shale gas play, also know as the Northwestern Ohio 

shale, is located within the Appalachian Basin in Kentucky, New York, Ohio, Pennsylvania, 

Tennessee and West Virginia. The location of the Greater Siltstone is also within the 

Appalachian Basin in New York, Ohio, Pennsylvania, Virginia and West Virginia. The 

location of the Low Thermal Maturity and Greater Siltstone shale plays are provided in Figure 

5.

Figure 5 Devonian Low Thermal Maturity and Greater Siltstone Shale Plays

Resource Estimate 

The USGS estimated a total area for the Low Thermal Maturity as 45,844 square miles 

(29,340,000 acres) and a total area of 22,914 square miles (14,665,000 acres) for the Greater 

Siltstone shale play. The Devonian Low Thermal Maturity has an average EUR of 0.3 Bcf

per well and approximately 13.5 Tcf of technically recoverable gas. The Devonian Greater 

Siltstone has an average EUR of 0.19 Bcf per well and approximately 8.5 Tcf of technically 

Devonian Low Thermal Maturity & Greater Siltstone
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recoverable gas. These values are provided in Table 8 along with the average EURs and well 

spacing.

Table 8 Devonian Low Thermal Maturity and Greater Siltstone Average EUR and Area

Low Thermal Maturity Greater Siltstone

Area (sq. miles) 45,844 22,914

EUR (Bcf/ well) 0.2942 0.193

Well Spacing (wells/ sq. mile) 7 10.7

TRR (Tcf) 13.53 8.46

Other average properties were estimated for the Low Thermal Maturity and Greater Siltstone 

shale plays. These include the depth, thickness and porosity for the shale. Total organic 

content data was not publicly available. The values are provided in Table 9.

Table 9 Average General Properties for the Devonian-Low Thermal Maturity and Greater Siltstone Shale 

Plays

Low Thermal Maturity Greater Siltstone

Depth (ft) 3,000 2,911

Thickness (ft) 371 623

Porosity (%) 7 5.8

Total Organic Content (% wt) ---- ----

USGS Comparison 

In 2002, the USGS conducted an assessment of the Low Thermal Maturity and Greater 

Siltstone in the Appalachian Basin. They estimated that the total undiscovered resource for 

the Low Thermal Maturity is between 1,454 and 4,339 Bcf, with a mean of 2,654 Bcf. The 

total undiscovered resource for the Greater Siltstone was estimated between 892 Bcf and 

1,894 Bcf, with a mean of 1,294 Bcf. 

References

1. USGS. U.S. Geological Survey Open-File Report 2005-1268. 2005.

2. USGS. Assessment of the Undiscovered Oil and Gas Resources of the Appalachian 

Basin Province. 2002.

3. West Virginia Geological Economic Survey. Summary Data and Statistics: The Atlas 

of Major Appalachian Gas Plays. 1996.

Devonian Low Thermal Maturity & Greater Siltstone
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D. New Albany Shale Gas Play

Play Description

The New Albany shale gas play is located in the Illinois Basin in Illinois, Indiana and 

Kentucky. The location and extent of the New Albany shale is provided in Figure 6. 

Figure 6 New Albany Shale Play

Resource Estimate 

The total area for the New Albany shale play is approximately 43,500 square miles. The total 

area includes an active and undeveloped area of the play. Deutsche Bank estimated a total 

active area of 1,600 square miles. Thus, the remaining area is 41,900 square miles and is 

characterized as undeveloped area. New Albany has an average EUR of 1.1 Bcf per well and 

approximately 10.95 Tcf of technically recoverable gas. The depth of the New Albany shale 

ranges from 1,000 to 4,500 and is 100 to 300 feet thick. Due to the lack of current production 

and other issues in the undeveloped section of New Albany, the average EUR, well spacing, 

and total organic content is undetermined. These values are provided in Tables 10 and 11.

New Albany
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Table 10 New Albany Average EUR and Area

Active Undeveloped

Area (sq. miles) 1,600 41,900

EUR (Bcf/ well) 1.1 ----

Well Spacing (wells/ sq. mile) 8 ----

TRR (Tcf) 10.95

Other properties were estimated for the New Albany shale. These include the depth, 

thickness, porosity, and total organic content for the shale. The values are provided in Table 

11.

Table 11 Average General Properties for the New Albany Shale Play

Active Undeveloped

Depth (ft) 2,750 2,750

Thickness (ft) 200 200

Porosity (%) 12 12

Total Organic Content (% wt) 13 ----

Active Companies

In 2008, there were 9 companies holding leases in the New Albany shale play. These 

companies, along with their net acreage, as reported by Deutsche Bank, are listed in Table 12. 

Table 12 New Albany Lease Holders

Company Net Acreage

BreitBurn Energy Partners 168,430

Carrizo Oil & Gas 22,000

CNX Gas 356,000

Continental Resources 44,000

El Paso 122,000

Forest Oil 31,900

NGAS Resources 8,750

Noble Energy 179,000

Rex Energy 92,000

Based upon these lease holdings, the total active area is calculated at 1,024,080 net acres 

(1,600 square miles).

Well Costs

According to Deutsche Bank, New Albany has a well cost ranging from $0.8 to $1.0 million 

dollars for the developed area. Due to a lack of drilling activity and harsh terrain in the 

undeveloped area, well costs in this region of the shale are undetermined.

USGS Comparison 

In 2007, the USGS completed an assessment of the Illinois Basin. As part of the assessment, 

they estimated the undiscovered resource for the Devonian to Mississippian New Albany 

continuous gas. They estimated resources between 1.3 and 8.1 Tcf with a mean undiscovered 

resource of 3.8 Tcf.

New Albany
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References

1. U.S. Department of Energy. Modern Shale Gas Development in the United States: A 

Primer. April 2009.

2. Deutsche Bank. From Shale to Shining Shale. July 2008.

3. USGS. Assessment of the Undiscovered Natural Gas Resources of the Illinois Basin.

August 2010.

4. Discovery Group Inc. 2007 New Albany Shale Update. June 2007.

5. Sundance Energy. Annual General Meeting. November 2006.

6. Gas Technology Institute. New Albany Shale Project – Project Update. Presented at 

Mid-Continent Gas Shale Forum and RPSEA Member Meeting. June 2009.

7. Phasis Consulting. US Shale Gas Brief. September 2008.

8. Forest Oil Corporation. In the Zone- 2008 Analyst Conference. April 2008.

9. Forest Oil Corporation. Analyst Conference. March 2006.

10. Marsh Operating Company. Unconventional Gas Plays SPEE. December 2007.

11. Carrizo Oil and Gas. Pritchard Capital- Energize 2010 Conference. January 2010.

12. GTI, RPSEA, and Restech. Spring Topical Conference 2009- Philadelphia Shale 

Evaluation. New Albany Example- RPSEA/ GTI Project. 2009.

13. GTI and RPSEA. New Albany Shale Gas Research Project. Presented at 24th World 

Gas Conference. October 2009.

New Albany
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New Albany
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E. Antrim Shale Gas Play

Play Description

The Antrim shale gas play is located in the Michigan Basin in the northern part of Michigan 

State. According to Red Fork Energy, the Antrim shale is the 13th largest natural gas producer 

in the United States. The location of the Antrim shale is provided in Figure 7.

Figure 7 Antrim Shale Play

Resource Estimate 

The total area of the Antrim shale play is approximately 12,000 square miles as shown in 

Table 13. The total area includes the developed and undeveloped area of the play. Based 

upon the active area reported by Deutsche Bank, the developed area is approximately 527 

square miles. Thus, the remaining area is 11,743 square miles as undeveloped area. Due to 

the large difference in areas of the developed and undeveloped sections, Antrim shale is being 

modeled as a single unit. The shale gas play has an average EUR of 0.28 Bcf per well and 

approximately 19.9 Tcf of technically recoverable gas. Antrim ranges from 600 to 2,200 feet 

deep and is 70 to 120 feet think.

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Table 13 Average Antrim EUR and Area

Active

Area (sq. miles) 12,000

EUR (Bcf/ well) 0.28

Well Spacing (wells/ sq. mile) 7

TRR (Tcf) 19.93

Other average properties were estimated for the Antrim shale play. These include the depth, 

thickness, porosity, and total organic content for the shale. The values are provided in Table 

14.

Table 14 Average General Properties for the Antrim Shale Play

Depth (ft) 1,400

Thickness (ft) 95

Porosity (%) 9

Total Organic Content (% wt) 11

Active Companies

In 2008, there were 4 companies holding leases in the Antrim shale play. These companies, 

along with their net acreage, as reported by Deutsche Bank, are listed in Table 15. 

Table 15 Antrim Lease Holders

Company Net Acreage

Atlas Energy Resources LLC 53,000

BreitBurn Energy Partners 256,438

HighMount E&P LLC 1,778

Whiting Petroleum 25,869

Based upon these lease holdings, the total active area is calculated at 337,085 net acres (527 

square miles).

Well Costs

In 2008, Deutsche Bank estimated an average well cost for the Antrim shale play ranging 

from $0.3 to $0.5 million dollars.

Current Activities

Antrim shale activity began in 1980 with 9,000 completed wells as of 2008.

USGS Comparison 

In 2004, USGS conducted an assessment of undiscovered oil and gas resources of the U.S. 

Portion of the Michigan Basin. As part of the assessment, they evaluated the Devonian 

Antrim continuous gas. Their estimate ranged from 5,864 Bcf to 9,669 Bcf with a mean of 

7,475 Bcf.

Reference

1. Red Fork Energy. Red Fork Energy’s Large Shale Gas Discovery in OklahomaInvestor Presentation. May 2010.

2. U.S. Department of Energy. Modern Shale Gas Development in the United States: A 

Primer. April 2009.

Antrim
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3. Deutsche Bank. From Shale to Shining Shale. July 2008.

4. Wayne R. Goodman and Timothy R. Maness. Michigan’s Antrim Gas Shale Play ─ A 

Two-Decade Template for Successful Devonian Gas Shale Development. April 2008.

5. USGS. Assessment of Undiscovered Oil and Gas Resources of the U.S. Portion of the 

Michigan Basin. 2004.

6. Gas Technology Institute. New Albany Shale Project – Project Update. Presented at 

Mid-Continent Gas Shale Forum and RPSEA Member Meeting. June 2009.

7. Jenkins, Creties, DeGolyer, MacNaughton, and Boyer, Charles II. Coalbed- and 

Shale- Gas Reservoirs. Journal of Petroleum Technology. February 2008.

8. MuleShoe Engineering. CBM and Shale Gas Upstream Facilities. 2010.

9. Milind Deo from University of Utah. Shale Gas- Promise and Current Status. 2008.

10. Phasis Consulting. US Shale Gas Brief. September 2008.

11. Novas Consulting Oil & Gas Consultancy. US Shale Gas What’s Going On. April 

2010.

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Antrim
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III. Gulf Coast Regional Summary

The Gulf Coast region includes the Haynesville, Eagle Ford and the Floyd-Neal/Conasauga 

shale gas and shale oil plays. The Haynesville shale play is located in Texas and Louisiana, 

Eagle Ford is located in the Texas Maverick Basin and Floyd-Neal/Conasauga lies in the 

Black Warrior Basin. The reviewed plays have a combined area of 14,752 square miles with 

an average EUR between 0.9 and 5.0 Bcf per well and 300 MBO per well. The reviewed 

plays contain approximately 99.99 Tcf of technically recoverable gas and 3.35 BBO of 

technically recoverable oil.

Figure 8 Gulf Coast Shale Gas and Shale Oil Resources

Haynesville

Floyd-Neal/ 

Conasauga

Eagle Ford

Haynesville

Floyd-Neal/ 

Conasauga

50 – 300 Tcf

20 – 50 Tcf

0 - 20 Tcf

3.35 BBbl

36.44 Tcf

Haynesville

Floyd-Neal/ 

Conasauga

Eagle Ford

Haynesville

Floyd-Neal/ 

Conasauga

50 – 300 Tcf

20 – 50 Tcf

0 - 20 Tcf

3.35 BBbl

36.44 Tcf

Gulf Coa

st Region
Review of Emerging U.S. Shale Gas and Shale Oil Plays

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Gulf Coat Region
Review of Emerging U.S. Shale Gas and Shale Oil Plays

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A. Haynesville Shale Gas Play

Play Description

The Haynesville shale gas play, also known as the Haynesville/Bossier shale play, is located 

in East Texas and Western Louisiana. In 2007, high shale gas well production rates suggested 

that the Haynesville might have significant gas reserves. The location of the play is provided 

in Figure 9.

Figure 9 The Haynesville Shale Play

Resource Estimate

The Haynesville shale has a total area of approximately 9,000 square miles and an estimated 

technically recoverable resource of 74.7 Tcf. The average EUR per well is estimated to be 3.6 

Bcf. The depth of the shale ranges between 10,500 and 13,500 feet with a thickness of 200 to 

300 feet. The Haynesville was divided into two zones: active and undeveloped. The active 

area corresponds with the acreage that is currently held by the companies and might be under 

Hayne

sville
Review of Emerging U.S. Shale Gas and Shale Oil Plays

26

development. The undeveloped area represents the acreage that is not currently held by 

companies.

The active area, as detailed in Table 16, is 3,574 square miles and has a TRR of 53.3 Tcf,

which is equivalent to 6.5 Bcf per well. At the well level, the reported EURs range between 4 

and 10 Bcf. The TRR for the undeveloped area is 19.41 Tcf or 1.5 Bcf per well.

Table 16 Haynesville Average EUR and Area

Active Undeveloped

Area (sq. miles) 3,574 5,426

EUR (Bcf/ well) 6.5 1.5

Well Spacing (wells/ sq. mile) 8 8

TRR (Tcf) 53.30 19.41

Other average properties were estimated for the Haynesville Shale. These include the depth, 

thickness, porosity, and total organic content for the shale. The values are provided in Table 

17.

Table 17 Average General Properties for the Haynesville Shale Play

Depth (ft) 12,000

Thickness (ft) 250

Porosity (%) 8.5

Total Organic Content (% wt) 2.25

Active Companies

In 2008, there were 24 companies holding leases in the Haynesville Shale. These companies, 

along with their net acreage, are listed in Table 18.

Table 18 Haynesville Lease Holders

Company Net Acreage

Anadarko Petroleum 60,000

Berry Petroleum 4,508

Cabot Oil & Gas 50,000

Chesapeake 440,000

Comstock 53,000

Cubic Energy 6,326

Devon Energy 200,000

El Paso 27,000

Encana Corp. 325,000

Encore Acquisition 6,000

EOG Resources 150,000

EXCO Resources 107,000

Forest Oil 90,000

GMX Resources 27,500

Goodrich Petroleum 60,500

Noble Energy 18,000

Penn-Virginia 54,000

Hayne

sville
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Company Net Acreage

Petrohawk 275,000

Plains Exploration & Production 110,000

Questar 29,500

SandRidge 32,739

St. Mary Land & Exploration 50,000

Unit Corp. 11,506

XTO Energy 100,000

Based upon these lease holdings, the total active area is calculated at 2,287,579 net acres 

(3,574 square miles).

Well Costs

In 2008, Deutsche Bank reported the average well cost as between $6 and $7 million dollars. 

In 2010, the cost has increased to at least $7 million dollars. The highest cost reported by a 

company is between $9.5 and $10 million dollars including at least $2 million for stimulation. 

Both Petrohawk and Encana report costs averaging $9 million per well.

Current Activities

There is significant current drilling activity in the Haynesville. In August of this year, Plains 

Exploration and Production reported that there were 48 rigs currently active in the play. They 

further stated that 31 of these were operated by Chesapeake. This report is consistent with 

statements reported by both Chesapeake and Petrohawk.

Representative Type Curve

Figure 10 provides a representative type curve for a Haynesville well. According to 

Petrohawk, the well produces 80% of the EUR within the first ten years.

Figure 10 Haynesville Type Curve

Hayne

sville
Review of Emerging U.S. Shale Gas and Shale Oil Plays

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USGS Comparison

This play has not been evaluated by USGS.

References

1. U.S. Department of Energy. Modern Shale Gas Development in the United States: A 

Primer. April 2009.

2. Petrohawk. Operations: Haynesville Shale and Bossier Shale. Presented at 

Petrohawk Energy Corporation 2010 Analyst Meeting. May 24, 2010.

3. Deutsche Bank. From Shale to Shining Shale. July 2008.

4. Chesapeake Energy. Haynesville Shale. Presented at the American Association of 

Drilling Engineers Conference. January 2010.

5. EXCO Resources, Inc. Second Quarter 2010 Review. August 4, 2010.

6. Encana. The New Encana. Presented at the 2010 CAPP Oil & Gas Investment 

Symposium. June 14, 2010.

7. Plains Exploration & Production Company. 2Q 2010 Presentation. August 2010.

8. Denbury Resources Inc. Haynesville Area. May 2010.

9. ALL Consulting. Evaluating the Environmental Implications of Hydraulic 

Fracturing in Shale Gas Reservoirs. Presented at the International Petroleum & 

BioFuels Environmental Conference, Albuquerque, New Mexico. November 2008.

10. Chesapeake Energy. August 2010 Investor Presentation. August 2010.

11. Comstock Resources. August 2010.

Hayne

sville
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B. Eagle Ford Shale Gas & Oil Play

Play Description

The Eagle Ford shale gas and oil play is located within the Texas Maverick Basin. The play 

contains a high liquid component. This has led to the definition of three zones: an oil zone, a 

condensate zone, and a dry gas zone. The play and the delimitation of the three zones are

provided in the following figure.

Figure 11 Eagle Ford Shale Play

The Eagle Ford shale was first discovered by Petrohawk in 2008. The initial well was located 

in the Hawkville field in LaSalle County, Texas. According to the Railroad Commission of 

Texas, as of September 2010, there are 162 completed wells in the Eagle Ford as well as 690 

well permits.

Resource Estimate 

The area for Eagle Ford was calculated using maps and other data reported by the companies 

who are currently leasing acres with the Eagle Ford shale play. The area of the dry gas zone 

is estimated at 200 square miles. The same process was done for the oil and condensate zone 

using the sum of the area for each company. The area of the condensate zone was estimated 

at 890 square miles and the area for the oil zone is estimated at 2,233 square miles. Eagle 

Ford has an average EUR of 5.0 Bcf per well and 300 MBO per well. The shale gas and shale 

oil play has approximately 20.81 Tcf of technically recoverable gas and 3.35 Bbbl of 

technically recoverable oil.

Eagle For

d
Review of Emerging U.S. Shale Gas and Shale Oil Plays

30

According to Talisman Energy and Rosetta Resources, 4 Bcf per well was reported as a 

minimum value for the average EUR, and Petrohawk Energy and Murphy Oil Corporation 

reported a maximum value of 6 Bcf. An average EUR range of 150 to 750 MBO per well was 

estimated by Petrohawk Energy as well. The average EUR obtained for the oil zone is 300 

MBO, the condensate zone has an average EUR of 4.5 Bcf and the dry gas zone has 

approximately 5.5 Bcf EUR. The average well spacing ranges from 4 to 8 wells per square 

mile, with dry gas zone as the lowest, condensate zone the highest and the oil zone with a well 

spacing of 5 wells per square mile. The TRR for the oil zone is 3.35 BBO while the dry gas 

and condensate zones have EURs of 4.4 and 16.4 Tcf respectively. The total TRR for the

play is 20.8 Tcf of gas and 3.35 BBO of liquids. These values are provided in Table 19.

Table 19 Eagle Ford Average EUR and Areas

Dry Gas 

Zone

Condensate 

Zone

Oil 

Zone

Area (sq. miles) 200 890 2,233

EUR (Bcf/ well) 5.5 4.5

EUR (MBO/ well) 300

Well Spacing (wells/ sq. mile) 4 8 5

TRR (BBO) 3.35

TRR (Tcf) 4.38 16.43

Other average properties were estimated for the Eagle Ford shale play. These include the 

depth, thickness, porosity, and total organic content for the shale. The values are provided in 

Table 20.

Table 20 Average General Properties for the Eagle Ford Shale Play

Depth (ft) 7,000

Thickness (ft) 200

Porosity (%) 9

Total Organic Content (% wt) 4.25

Active Companies

There are more than 11 companies currently holding leases in the Eagle Ford shale play. 

These companies, along with their net acreage, are listed in Tables 21 through 23 for each of 

the 3 Eagle Ford shale zones.

Table 21 Eagle Ford Dry Gas Zone Lease Holders

Company Net Acreage

EOG Resources 49,000

Swift Energy 78,000

Eagle For

d
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Table 22 Eagle Ford Condensate Zone Lease Holders

Company Net Acreage

Comstock 18,000

EOG Resources 26,000

Murphy Oil Corporation 100,000

Petrohawk Energy Corporation 270,000

Pioneer Natural Resources 89,000

Rosetta Resources 29,500

Talisman 37,000

Table 23 Eagle Ford Oil Zone Lease Holders

Company Net Acreage

Anadarko 260,000

EOG Resources 505,000

Goodrich Petroleum Corporation 35,000

Murphy Oil Corporation 100,000

Petrohawk Energy Corporation 87,000

TXCO Resources 442,000

In 2010, these companies have leased a total of 2,125,500 net acres (3,321 square miles).

Future Development

Since Eagle Ford is a developing play, there is minimal information available on the future 

drilling activity for the companies currently holding leases within the shale. One of the 

companies to discuss their future development is Pioneer Natural Resources, who plans to 

increase drilling activity to 6 – 7 rigs in year 2010, 10 rigs by 2011 and by 2012 they plan to 

be operating 14 rigs in Eagle Ford. 

Drilling Cost

According to Petrohawk Energy the average well cost ranges from 4.0 to 6.5 million dollars 

per horizontal well.

USGS Comparison

This play has not been evaluated by USGS.

Representative Type Curve

Figure 12 provides a representative type curve for an Eagle Ford well. This curve was 

developed by Petrohawk for the Hawkville Field within the condensate zone of the play. 

According to Petrohawk, the well will produce 30 percent of the EUR in the first year, and 

75% within the first ten years.

Eagle For

d
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Figure 12 Eagle Ford Type Curve

References

1. Talisman Energy. And Common’s Eagle Ford Assets Go to... Talisman! June 2010.

2. Railroad Commission of Texas. Eagle Ford Shale Play Highlights. 

3. Swift Energy. IPAA Oil & Gas Investment Symposium. June 2010.

4. EOG Resources. EOG Resources South Texas Eagle Ford. 2010.

5. TXCO Resources. Howard Weil 37th Annual Energy Conference. March 2009.

6. Anadarko Petroleum. Anadarko Investor Conference. March 2010.

7. Goodrich Petroleum Corporation. EnerCom- The Oil & Gas Conference. August 

2010.

8. Murphy Oil Corporation. Howard Weil 2010 Energy Conference. March 2010.

9. Rosetta Resources. IPAA Oil & Gas Investment Symposium. April 2010.

10. Pioneer Natural Resources. Investor Presentation June 2010. August 2010.

11. Talisman Energy. Investor Open House, May 2010 North American Operations.

May 2010.

12. Murphy Oil Corporation. Howard Weil 2010 Energy Conference. March 2010

13. Petrohawk Energy. 2010 Eagle Ford Shale Overview Presented at Annual 

Association of Drilling Engineers. January 2010.

14. Comstock. Comstock. September 2010.

15. Deutsche Bank. From Shale to Shining Shale. July 2008.

Eagle For

d
Review of Emerging U.S. Shale Gas and Shale Oil Plays

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C. Floyd-Neal/Conasauga Shale Gas Play

Play Description

The Floyd-Neal/Conasauga shale gas play is located within Alabama and Mississippi in the 

Black Warrior Basin. Due to the lack of data published on the individual shales, the FloydNeal and Conasauga were combined into a single play for evaluation purposes. The location 

and area is proved in Figure 13.

Figure 13 Floyd-Neal/Conasauga Shale Play

Resource Estimate 

According to Deutsche Bank, the Floyd-Neal/Conasauga shale contains approximately 2,429 

square miles of combined active net acres with an average EUR of about 0.9 Bcf per well and 

4.37 Tcf of technically recoverable gas. The shale ranges from 6,000 to 10,000 feet deep and 

80 to 180 feet thick with a well spacing of 2 well per square mile (320 acres per well). These 

values are provided in Tables 24 and 25.

Table 24 Floyd-Neal/Conasauga Average EUR and Area

Active

Area (sq. miles) 2,429

EUR (Bcf/ well) 0.9

Well Spacing (wells/ sq. mile) 2

TRR (Tcf) 4.37

Other average properties estimated for the Floyd-Neal/Conasauga are provided in Table 23. 

These include the depth, thickness, porosity, and total organic content for the shale. 

Floyd

-Neal/Conasauga
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Table 25 Average General Properties for the Floyd-Neal/Conasauga Shale Play

Depth (ft) 8,000

Thickness (ft) 130

Porosity (%) 1.6

Total Organic Content (% wt) 1.8

Active Companies

The active companies, along with their net acreage, are provided in Table 26.

Table 26 Floyd-Neal/Conasauga Lease Holders

Company Net Acreage

Anadarko Petroleum 250,000

Carrizo Oil & Gas 138,000

Chesapeake Energy 287,500

Edge Petroleum 13,563

Energen 287,500

HighMount E&P LLC 328,038

Murphy Oil 200,000

Range Resources 50,000

These companies have leased a total of 1,554,601 net acres (2,429 square miles).

Current Activities

Since the Floyd-Neal/Conasauga shale play is a new developing play, there is minimal 

information published for the future drilling activity for the companies who are currently 

holding leases within the shale. 

Well Costs

The average well cost for the Floyd-Neal/Conasauga shale is $3.0 million dollars as reported 

by Deutsche Bank. 

USGS Comparison

This play has not been evaluated by USGS.

References

1. IHS Energy. Exploration and Development Trends Southeastern States. 2007.

2. Deutsche Bank. From Shale to Shining Shale. July 2008.

3. Cane River Resources. Broomtown Prospect Conasauga Shale Bed Methane.

4. Kent A Bowker with Bowker Petroleum. Recent Activity in the Floyd, Neal, and 

Chattanooga Shale Plays, Black Warrior Basin, Alabama and Mississippi. 2008.

5. Mississippi Geological Society. eBulletin. 2007.

6. Carrizo Oil and Gas. Pritchard Capital- Energize 2010 Conference. January 2010. 

7. Range Resources. Company Presentation. August 2007.

8. Oil and Gas Investor. An Investor’s Guide to Shale Gas. January 2007.

Floyd

-Neal/Conasauga
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35

IV. Mid-Continent Regional Summary

The mid-continent region includes shale gas plays located in the Arkoma, Ardmore and 

Anadarko Basins. Located within theses basins are the Fayetteville, Woodford and Cana 

Woodford shale plays (Figure 14). The total area of the reviewed plays is estimated at 14,388 

square miles with an average EUR between 1.7 and 2.5 Bcf and approximately 59.9 Tcf of 

technically recoverable gas.

Figure 14 Mid-Continent Shale Gas and Shale Oil Resources

Fayetteville

Cana 

Woodford

Woodford 20 – 50 Tcf

50 – 300 Tcf

0 – 20 Tcf

Fayetteville

Cana 

Woodford

Woodford 20 – 50 Tcf

50 – 300 Tcf

0 – 20 Tcf

Mid

-Continent Region
Review of Emerging U.S. Shale Gas and Shale Oil Plays

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Mid

-Continent Region
Review of Emerging U.S. Shale Gas and Shale Oil Plays

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A. Fayetteville Shale Gas Play

Play Description

The Fayetteville shale gas play is located within the Arkoma Basin in Arkansas. Fayetteville 

is divided into two main units, Central and Western based on the location of the shale. 

Fayetteville Central extends from the Arkansas-Oklahoma border to the East of Johnson, 

Logan and Yell counties. Figure 15 shows the location and area of Fayetteville Central. 

Figure 15 Fayetteville Shale Play

Resource Estimate 

Based on the U.S. Department of Energy, the total area for the Fayetteville shale play, 

including Central and Western Fayetteville, is 9,000 square miles. Fayetteville Central is 

4,000 square miles and the remaining shale, Fayetteville Western, is approximately 5,000 

square miles. The shale gas play has an average EUR of 1.7 Bcf per well and approximately 

31.96 Tcf of technically recoverable gas. The shale ranges from 1,000 to 7,000 feet deep and 

20 to 200 feet thick. These values are summarized in Tables 27 and 28. 

Table 27 Fayetteville Average EUR and Area

Western Central

Area (sq. miles) 5,000 4,000

EUR (Bcf/ well) 1.15 2.25

Well Spacing (wells/ sq. mile) 8 8

TRR (Tcf) 4.64 27.32

Other average properties estimated for the Fayetteville shale play are provided in Table 28. 

These include the depth, thickness, porosity, and total organic content for the shale. 

Fayetteville Shale Play Outline

Mississippian outcrop

Fayetteville
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Table 28 Average General Properties for the Fayetteville Shale Play

Central/ Western

Depth (ft) 4,000

Thickness (ft) 110

Porosity (%) 5

Total Organic Content (% wt) 6.9

Active Companies

In 2008, there were 9 companies holding leases within the Fayetteville shale play. These 

companies, along with their net acreage, as reported by Deutsche Bank, are listed in Table 29. 

Table 29 Fayetteville Lease Holders

Company Net Acreage

Carrizo Oil and Gas 23,900

Chesapeake 585,000

Edge Petroleum 4,692

Penn-Virginia 14,500

PetroHawk 155,000

PetroQuest 18,000

Southwestern Energy 851,069

Storm Cat Energy 18,265

XTO Energy 300,000

These companies have leased a total of 1,970,426 net acres (3,079 square miles).

In 2010, XTO Energy reported that they increased their Fayetteville acreage to 380,000 net 

acres. Carrizo Oil and Gas reported 26,000 net acres and Southwestern Energy has a total of 

888,695 net acres in 2010.

Well Costs

According to Southwestern Energy, the average well cost completed for 2009 was $2.9 

million dollars. This is within the range of $1.75 to $3.05 million dollars as reported by

Deutsche Bank.

Current Activities

Southwestern Energy drilled and completed 249 wells within the first six months of 2010. 

They plan on participating in 650 to 680 wells by the end of the year and operate on 475 to 

500 wells. Currently, Chesapeake Energy is operating about 8 rigs and plans to have about 10 

rigs in 2010 to drill about 85 net well.

USGS Comparison

In 2010, the USGS conducted an assessment for the Fayetteville Shale Gas-Western Arkansas 

Basin Margin. They estimated that the total undiscovered resource is between 2,260 and 

6,865 Bcf, with a mean of 4,170 Bcf.

Representative Type Curve

Figure 16 provides a representative type curve for a Fayetteville well. According to 

Petrohawk, this 2.2 Bcfe Fayetteville type curve show the cumulative production and 

production rate for the play.

Fayetteville
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Figure 16 Fayetteville Type Curve

References

1. Advanced Resources International. Fayetteville Shale. 

2. U.S. Department of Energy. Modern Shale Gas Development in the United States: A 

Primer. April 2009.

3. Deutsche Bank. From Shale to Shining Shale. July 2008.

4. XTO Energy. Barnett vs. Marcellus – A Comparison of Two Shale Gas Giants. June 

2009.

5. Carrizo Oil and Gas. Pritchard Capital- Energize 2010 Conference. January 2010.

6. Southwestern Energy. August 2010 Update. August 2010.

7. Chesapeake Energy. August 2010 Investor Presentation. August 2010.

8. USGS. Assessment of the Undiscovered Natural Gas Resources of the Arkoma Basin 

Province and Geologically Related Areas. 2010.

9. Petrohawk Energy. Eagle Ford Shale & Other Q&A.

10. Range Resources. March Company Presentation. March 2009.

11. Howard Weil. Unconventional Gas and its Impact on Domestic Supply. April 2008.

12. Phasis Consulting. US Shale Gas Brief. September 2008.

13. Marsh Operating Company. Unconventional Gas Plays SPEE. December 2007.

14. Brian Teller with XTO Energy. Fayetteville Shale. January 2009.

Fayettevill

e
Review of Emerging U.S. Shale Gas and Shale Oil Plays

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Fayetteville
Review of Emerging U.S. Shale Gas and Shale Oil Plays

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B. Woodford Shale Gas Play

Play Description

The Woodford shale gas play is divided into two sections based on the location of the shale in 

Oklahoma. The Woodford Central is located in the Ardmore Basin and Woodford Western is 

located in the Arkoma Basin. The locations of the Woodford shales are provided in Figure 

17.

Figure 17 Woodford Shale Play

Resource Estimate 

Advanced Resources International estimated a total area for the Woodford Shales as 2,900 

square miles in the Arkoma Basin and 1,800 square miles in the Ardmore Basin, both 

containing a well spacing of 160 acres per square mile. The shale gas play has an average 

EUR of 2.5 Bcf per well and approximately 22.2 Tcf of technically recoverable gas for both 

the Western and Central Woodford. Within the Arkoma Basin, the Woodford Western ranges 

from 6,000 to 13,000 feet deep with a thickness of 150 feet and a EUR of 4.0 Bcf per well. 

The Woodford Central has a depth of 5,000 feet with a EUR of 1.0 Bcf per well. These 

average values are provided in Tables 30 and 31.

Table 30 Woodford Average EUR and Area

Western Central

Area (sq. miles) 2,900 1,800

EUR (Bcf/ well) 4.0 1.0

Well Spacing (wells/ sq. mile) 4 4

TRR (Tcf) 19.26 2.95

Woodford
Review of Emerging U.S. Shale Gas and Shale Oil Plays

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Other average properties were estimated for the Woodford shale play. These include the 

depth, thickness, porosity, and total organic content for the shale. The values are provided in 

Table 31.

Table 31 Average General Properties for the Woodford Shale Play

Western Central

Depth (ft) 9,500 5,000

Thickness (ft) 150 250

Porosity (%) 7 6

Total Organic Content (% wt) 6.5 4

Active Companies

In 2008, there were 13 companies holding leases within Woodford. These companies, along 

with their net acreage, as reported by Deutsche Bank, are listed in Table 32. 

Table 32 Woodford Lease Holders in the Arkoma and Ardmore Basins

Company Net Acreage

Chesapeake Energy 85,000

Cimarex 25,000

Continental Resources 45,000

Devon Energy 54,000

Linn Energy 46,000

Newfield Exploration 165,000

Penn-Virginia 40,000

Petroquest 39,500

Range Resources 13,000

St. Mary Land & Exploration 40,000

Williams Cos. 90,000

Unit Corporation 18,100

XTO Energy 160,000

These companies have leased a total of 820,600 net acres (1,282 square miles)

Well Costs

In 2007, Marsh Operating Company estimated that well costs for the Woodford shale in the 

Arkoma Basin range from $6 to $7 million dollars and in 2008 Deutsche Bank reported a 

larger range of $4.6 to $8 million dollars for the Woodford shale in the Arkoma and Ardmore 

Basins.

Current Activities

Due to the lack of drilling activity in the Ardmore Basin, there is no data available. The 

Woodford shale in the Arkoma Basin had 166 vertical wells and 37 horizontal wells 

completed in 2007. According to PetroQuest, 4 wells are completed as of August 2010 and 

the company is expecting a 3-rig Woodford program by the end of the year. Devon Energy 

drilled 61 wells in 2009 and plans to have about 85 wells drilled in 2010. 

Woodford
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USGS Comparison

In 2010, USGS conducted an assessment of the Woodford shale in the Arkoma Basin. They 

estimated that the total undiscovered resource is between 6,065 and 14,036 Bcf, with a mean 

of 10,068 Bcf. The shale gas resource in the Ardmore Basin has not been evaluated by 

USGS.

References

1. Advanced Resources International. Woodford Shale.

2. Range Resources. March Company Presentation. March 2009.

3. Deutsche Bank. From Shale to Shining Shale. July 2008.

4. Marsh Operating Company. Unconventional Gas Plays SPEE. December 2007.

5. PetroQuest Energy. PetroQuest Energy. August 2010. 

6. Devon Energy. IPAA Oil and Gas Investor Symposium. April 2010.

7. USGS. Assessment of the Undiscovered Natural Gas Resources of the Arkoma Basin 

Province and Geologically Related Areas. 2010.

8. Howard Weil. An Update on Shale Activity in the US.

9. Howard Weil. Unconventional Gas and its Impact on Domestic Supply. April 2008.

10. ALL Consulting. Evaluating the Environmental Implications of Hydraulic Fracturing 

in Shale Gas Reservoirs. Presented at the International Petroleum & BioFuels 

Environmental Conference, Albuquerque, New Mexico. November 2008.

11. XTO Energy. Barnett vs. Marcellus – A Comparison of Two Shale Gas Giants. June 

2009.

12. Cimarex Energy. EnerCom Oil & Gas Conference. August 2010.

13. United States Geological Survey. Shale Gas Resources in North America and Europe. 

June 2010.

14. Spyglass Energy Group. Woodford Shale Gas in Oklahoma. 2008.

15. Phasis Consulting. US Shale Gas Brief. September 2008.

16. TransEnergy Incorporated. 2008.

17. Wrightstone Gregory, Texas Keystone, Inc. Marcellus Shale – Geologic Controls on 

Production. Presented at the Winter Meeting of the IOGAWV. February 2009.

18. Unit Corporation. Unit Corporation Presentation. August 2010.

19. Evolution Petroleum Corporation. Corporate Presentation. June 2010.

20. Exxon Mobil. Global Unconventional Resource Opportunity. December 2009.

21. Newfield Exploration. How the Pieces Fit Together UBS Global Oil & Gas 

Conference. May 2010.

22. Newfield Exploration. Deutsch Bank- Energy & Utilities Conference. May 2008.

Woodford
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Woodford
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C. Cana Woodford Shale Gas Play

Play Description

Cana Woodford is an emerging gas play located within the Oklahoma Anadarko Basin, about 

40 miles west of Oklahoma City (Figure 18). Companies have estimated that Cana Woodford 

contains a high liquid content of about 65% gas, 30% NGL and 5% oil. 

Figure 18 Cana Woodford Shale Play

Resource Estimate

Based on companies’ leased acreage for the shale, as provided in Table 33, the active area for 

Cana Woodford is approximately 688 square miles. Cana Woodford is said to be the world’s 

deepest commercial horizontal shale play with depths that range from about 11,500 to 14,500 

feet. The shale’s EUR ranges from 4 to 12 Bcf with an average EUR of 5.2 Bcf per well. The 

TRR is estimated to be 5.7 Tcf with a well spacing of 4 wells per square miles (160 acres per 

well) as provided bellow in Table 33.

Table 33 Cana Woodford Average EUR and Area

Active

Area (sq. miles) 688

EUR (Bcf/ well) 5.2

Well Spacing (wells/ sq. mile) 4

TRR (Tcf) 5.72

Other average properties estimated for Cana Woodford are provided in Table 34. These 

include the depth, thickness, porosity, and total organic content for the shale.

Table 34 Average General Properties for the Cana Woodford Shale Play

Depth (ft) 13,500

Thickness (ft) 200

Porosity (%) 7

Total Organic Content (% wt) 6

Cana Woodford
Review of Emerging U.S. Shale Gas and Shale Oil Plays

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Active Companies

The active companies, along with their net acreage, are listed in Table 35.

Table 35 Cana Woodford Lease Holders

Company Net Acreage

Devon Energy 230,000

Continental Resources 47,500

Cimarex Energy 97,000

Questar Resources 66,000

These companies have leased a total of 440,500 net acres (688 square miles).

Future Development

Since Cana Woodford is a new developing play, there is little information published for the 

future drilling activity for the companies who are currently holding leases within the shale.

Drilling Cost

According to companies that report activities within Cana Woodford, the average well cost 

ranges from $4 to $12 million dollars per horizontal well.

USGS Comparison

This play has not been evaluated by USGS.

Representative Type Curve

Figure 19 provides a Type Curve for Cana Woodford as reported by Cimarex Energy.

Figure 19 Cana Woodford Type Curve

Cana Woodford
Review of Emerging U.S. Shale Gas and Shale Oil Plays

47

References

1. Devon Energy. Cana Woodford Shale Presented at Annual Association of Drilling 

Engineers. January 2010.

2. Questar Resources. Investor Presentation. August 2010.

3. Cimarex Energy. EnerCom Oil & Gas Conference. August 2010.

4. Continental Resources. Pritchard Capital Bakken Mini- Conference. May 2010.

5. Devon Energy. Investor Meeting. August 2010.

6. Devon Energy. Devon Cana- Woodford Update: 11 Bcfe Type Curve. June 2010. 

7. Cimarex Energy. Cimarex in the Cana- Woodford. May 2010.

8. Petrohawk Energy Corporation. Petrohawk Offers Anadarko and Arkoma Basin 

Assets. June 2010.

9. Panhandle. 2009 Annual Report. 2009.

Cana Woodford
Review of Emerging U.S. Shale Gas and Shale Oil Plays

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Cana Woodford
Review of Emerging U.S. Shale Gas and Shale Oil Plays

49

V. Southwest Regional Summary

The Southwest region includes shale gas and shale oil plays located in the Fort Worth and 

Permian Basins (Figure 20). Located within these basins is the Barnett, Barnett-Woodford 

and the Avalon and Bone Springs shale play with a total area of 10,462 square miles. The 

reviewed plays have an average per well EUR between 1.2 and 3.0 Bcf and 300 MBO. There 

is approximately 75.5 Tcf of technically recoverable gas and 1.58 Bbbl of technically 

recoverable oil.

Figure 20 Southwest Shale Gas and Shale Oil Resources

Barnett

BarnettWoodford

Avalon and 

Bone Springs Barnett

BarnettWoodford

Avalon and 

Bone Springs

0 – 25 Tcf 0 – 5 BBbl

25 – 50 Tcf 5 – 10 BBbl

Barnett

BarnettWoodford

Avalon and 

Bone Springs Barnett

BarnettWoodford

Avalon and 

Bone Springs

0 – 25 Tcf 0 – 5 BBbl

25 – 50 Tcf 5 – 10 BBbl

Southwest Region
Review of Emerging U.S. Shale Gas and Shale Oil Plays

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Southwest Region
Review of Emerging U.S. Shale Gas and Shale Oil Plays

51

A. Barnett Shale Gas Play

Play Description

The Barnett shale gas play is located within the Fort Worth and Permian Basins in Texas. 

The Barnett shale is divided into two sections: the “Core/Tier I” and the Undeveloped. The 

Core/Tier I section corresponds to the areas of the Barnett Shale that are currently under 

development. It is primarily located in the Parker, Wise, Johnson, and other neighboring 

counties. The undeveloped section corresponds with those areas of the Barnett that have not 

been developed by the companies. Because the Barnett extends across two petroleum basins 

that are in different regions of Texas, the active and undeveloped sections of the Barnett were 

further subdivided for modeling purposes. The location of the shale, as defined by Wood 

Mackenzie, is provided in Figure 21.

Figure 21 The Barnett Shale Play

Resource Estimate

The total area for the Barnett, as estimated by USGS is 6,458 square miles. This area is 

subdivided into two sections: the Greater Newark East Frac-Barrier Continuous Barnett Shale 

Gas (1,555 square miles) and the Extended Continuous Barnett Shale Gas (4,903 square 

miles). As the development of the Barnett extended beyond the Newark East field, the active 

section of the Barnett was also extended. The remaining area is considered to be undeveloped

section of the Barnett. The TRR in these sections is shown in Table 36. The Barnett shale 

gas play, including the active and undeveloped areas, has an average EUR of 1.4 Bcf per well 

and approximately 43.37 Tcf of technically recoverable gas. An average EUR and well 

spacing for the active area are based on company data. These values were used to calculate 

the average well and TRR for the undeveloped section of the Barnett. These averages are 

summarized in Table 36.

Barnett
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Table 36 Average Barnett EUR and Area

Active Undeveloped

Area (sq. miles) 4,075 2,383

EUR (Bcf/ well) 1.6 1.2

Well Spacing (wells/ sq. mile) 5.5 8

TRR (Tcf) 23.81 19.56

Other average properties were estimated for the Barnett shale play. These include the depth, 

thickness, and porosity for the shale. The values, which are the same for the active and 

undeveloped sections, are provided in Table 37.

Table 37 Average General Properties for the Barnett Shale Play

Depth (ft) 7,500

Thickness (ft) 300

Porosity (%) 5

Active Companies

In 2008, there were 10 companies holding leases in the Barnett Shale Core and 10 companies 

in the South/Western section of the shale. These companies, along with their net acreage, are 

listed in Tables 38 and 39 respectively.

Table 38 Barnett Core/Tier 1 Lease Holders

Company Net Acreage

Carrizo Oil & Gas 85,429

Chesapeake 260,000

Devon Energy 527,000

EnCana Corp 71,500

EOG Resources 96,000

Quicksilver 16,525

Parallel Petroleum 17,600

Range Resources 20,000

Williams Cos. 32,000

XTO Energy 125,000

Table 39 Barnett South/Western Counties Lease Holders

Barnett
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Company Net Acreage

Chesapeake 19,400

Denbury 40,400

Devon Energy 199,900

EOG Resources 554,000

EnCana Corp. 71,500

Forest Oil 34,000

Petroleum Development 8,868

Quicksilver 247,000

Range Resources 57,000

XTO Energy 125,000

These Companies have leased a total of 2,608,122 net acres (4,075 square miles).

Well Costs

The well costs reported in 2008 and 2009 have been between $2 and $3 million dollars for a 

well in the Barnett Core. The costs in the Southern and Western counties have a larger range 

– between $1.6 and $3.7 million per well. The differences in costs are consistent with EOG 

Resources reported costs.

Current Activities

There is significant current drilling activity in the Barnett. There are at least 58 rigs currently 

active in the shale. Of these, 14 are operated by EOG Resources and 22 by Chesapeake.

Representative Type Curve

Figure 22 provides a representative type curve for a Barnett well.

Figure 22 Barnett Type Curve

Barnett
Review of Emerging U.S. Shale Gas and Shale Oil Plays

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USGS Comparison

In 2003, USGS completed an assessment of the undiscovered oil and gas resources within the 

Fort Worth Basin. As part of the study, they evaluated two assessment units within the 

Barnett-Paleozoic total petroleum system. The total undiscovered gas resource is between 

21,716 Bcf and 31,521 Bcf, with a mean estimate of 26,229 Bcf.

References

1. Deutsche Bank. From Shale to Shining Shale. July 2008.

2. U.S. Department of Energy. Modern Shale Gas Development in the United States: A 

Primer. April 2009.

3. XTO Energy. Barnett vs. Marcellus – A Comparison of Two Shale Gas Giants. June 

2009.

4. Benedetto, Larry. Unconventional Gas and its Impact on Domestic Supply. April 

2008.

5. Chesapeake Energy. Reported at 

http://shale.typepad.com/barnettshale/2009/08/chesapeake-energy-.html. 

6. USGS. Assessment of Undiscovered Oil and Gas Resources of the Bend Arch – Fort 

Worth Basin Province of North – Central Texas and Southwestern Oklahoma. 2003.

7. Baylor, Brandon. Marcellus Shale Decline Analysis. 2010.

8. Phasis Consulting. US Shale Gas Brief. September 2008.

9. Range Resources. March Company Presentation. March 2009.

10. Wrightstone Gregory, Texas Keystone, Inc. Marcellus Shale – Geologic Controls on 

Production. Presented at the Winter Meeting of the IOGAWV. February 2009.

11. TransEnergy Incorporated

12. Berman, Arthur. Shale Plays, A Time for Critical Thinking. Presented at the 

Association for the Study of Peak Oil and Gas. October 2009.

13. Darbonne, Nissa. The Barnett Shale and Other Shale Dreams. IHS Energy User 

Forum. May 2006.

14. Range Resources Corporation. Company Presentation. July 2010.

15. Deo, Milind. University of Utah. Shale Gas Promise and Current State. Presented at 

the RPSEA Unconventional Gas Development in the Western Energy Corridor Forum. 

May 12, 2009.

16. Devon. Shale Gas: Understanding the Rock is Key. Presented at the Peters & Co. 

Limited Energy Conference. January 28, 2009.

17. Drake, Steve. Marsh Operating Company. Unconventional Gas Plays. SPEE. 

December 6, 2007.

18. Jenkins, Creties, DeGolyer, MacNaughton, and Boyer, Charles II. Coalbed- and 

Shale- Gas Reservoirs. Journal of Petroleum Technology. February 2008.

19. Bob Cluff. The Discovery Group Inc. 2007 New Albany Shale Update. Presented at 

the Explorers Club Luncheon, Denver Colorado. June 21, 2007.

20. Salehi, Iraj. Gas Technology Institute. New Albany Shale Project: Project Update. 

Presented at the Mid-Continent Gas Shale Forum and RPSEA Member Meeting. June 

4, 2009.

21. Forest Oil Corporation. 2008 Analyst Conference. April 1, 2008.

Barnett
Review of Emerging U.S. Shale Gas and Shale Oil Plays

55

B. Barnett-Woodford Shale Gas Play

Play Description

The Barnett-Woodford shale gas play is located in the Permian Basin in West Texas. The 

location and area of the Barnett-Woodford shale is provided in Figure 23.

Figure 23 Barnett-Woodford Shale Play

Resource Estimate

The Barnett-Woodford shale play has an area of approximately 2,691 square miles combined 

from the net acreage in Table 38 and a well spacing of 160 acres per well (4 wells per square 

mile). The shale gas play has an average EUR of 3.0 Bcf per well and approximately 32.2 Tcf

of technically recoverable gas. The shale ranges from 5,100 to 15,300 feet deep and 4 to 800 

feet thick. These values are provided in Tables 40 and 41.

Table 40 Barnett-Woodford Average EUR and Area

Active

Area (sq. miles) 2,691

EUR (Bcf/ well) 3.0

Well Spacing (wells/ sq. mile) 4

TRR (Tcf) 32.15

Barnett

-Woodford
Review of Emerging U.S. Shale Gas and Shale Oil Plays

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Other average properties were estimated for Barnett-Woodford. These include the depth, 

thickness and total organic content for the shale. Porosity data was not publicly available. 

The values are provided in Table 41.

Table 41 Average General Properties for the Barnett-Woodford Shale Play

Active

Depth (ft) 10,200

Thickness (ft) 400

Porosity (%) ----

Total Organic Content (% wt) 5.5

Active Companies

In 2008, there were 8 companies holding leases in the Barnett-Woodford Shale. These 

companies, along with their net acreage, as reported by Deutsche Bank, are listed in Table 42. 

Table 42 Barnett-Woodford Lease Holders 

Company Net Acreage

Abraxas 15,000

Carrizo Oil & Gas 70,000

Chesapeake 815,000

Continental Resources 67,000

EnCana Corporation 287,000

Quicksilver 375,000

Range Resources 20,000

TXCO Resources 73,500

Based upon these lease holdings, the total active area is calculated at 1,722,500 net acres 

(2,691 square miles).

Well Costs

According to Deutsche Bank in 2008, Barnett-Woodford has an average well cost of $6.5 

million dollars.

USGS Comparison

This play has not been evaluated by USGS. 

References

1. Deutsche Bank. From Shale to Shining Shale. July 2008.

2. The Discovery Group Inc. Barnett Shale-Woodford Shale pay of the Delaware Basin- is it 

Another Giant Shale Gas Field in Texas?

3. Marsh Operating Company. Unconventional Gas Plays SPEE. December 2007.

Barnett

-Woodford
Review of Emerging U.S. Shale Gas and Shale Oil Plays

57

C. Avalon & Bone Springs Shale Oil Play

Play Description

The Avalon and Bone Springs shale oil play is located in the Permian Basin in Southeast New 

Mexico and West Texas. The Avalon play also includes the New Mexico Leonard Shale. 

Due to the lack of data published, Bone Spring and the Avalon shale are combined into a 

single unit. In Figure 24, SandRidge Energy shows the location and area of the shale play. 

Figure 24 Avalon and Bone Springs Shale Play

Resource Estimate 

The area for Avalon and Bone Springs was calculated using maps and other data reported by

the companies who are currently leasing acres within Avalon and Bone Springs. The total 

active area is approximately 1,313 square miles. The shale oil play has an average EUR of 

300 MBO per well and approximately 1.58 Bbbl of technically recoverable oil. The play has 

a reported depth from 6,000 to 13,000 feet and a thickness ranging from 900 to 1,700 feet. 

These values are provided in Table 43.

Avalon & Bone Springs
Review of Emerging U.S. Shale Gas and Shale Oil Plays

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Table 43 Avalon and Bone Springs EUR and Area

Active

Area (sq. miles) 1,313

EUR (MBO/ well) 300

Well Spacing (wells/ sq. mile) 4

TRR (BBO) 1.58

Other average properties were estimated for Avalon and Bone Springs. These include the 

depth and thickness. The values are provided in Table 44. Due to the lack of publicly 

reported data, the porosity and total organic content are undetermined.

Table 44 General Properties for the Avalon/Bone Springs Shale Play

Active

Depth (ft) 8,750

Thickness (ft) 1,300

Porosity (%) ----

Total Organic Content (% wt) ----

Active Companies

In 2008, there were 6 companies holding leases in the Avalon and Bone Springs play. These 

companies, along with their net acreage, are listed in Table 45. 

Table 45 Avalon and Bone Springs Lease Holders

Company Net Acreage

Chesapeake 190,000

EOG Resources 120,000

Devon Energy 235,000

SandRidge Energy 25,000

Anadarko Petroleum 170,000

Concho 100,000

As of 2010, these companies have leased a combined total of 840,000 net acres (1,313 square 

miles).

Well Costs

According to Concho, the average well cost within the Bone Springs play range from $3 to $5 

million dollars.

Current Activities

SandRidge Energy currently has 31 horizontal rigs drilling within the Bone Springs and 

Avalon shale play and according to Concho, as of August 2010, the industry has drilled 250 

horizontal wells within Bone Springs play.

USGS Comparison

In 2007, USGS assessed the undiscovered oil and gas resources in the Permian Basin. This 

was the first time they broke out the continuous gas resources. However, the Avalon shale 

was not assessed at that time.

Avalon & Bone Springs
Review of Emerging U.S. Shale Gas and Shale Oil Plays

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References

1. SandRidge Energy. SandRidge- Investor Presentation. August 2010.

2. Carrizo Oil & Gas. Presented at the Howard Weil 38th Annual Energy Conference. 

March 24, 2010.

3. USGS. Assessment of Undiscovered Oil and Gas Resources of the Permian Basin 

Province of West Texas and Southeast New Mexico. 2007.

4. USGS. Bone Spring Formation. September 2010.

5. Concho. Investor Presentation. August 2010.

6. http://www.oilshalegas.com/avalonshale.html

7. http://www.aapgbull.geoscienceworld.org/cgi/content/abstract/81/9/1423

8. Chesapeake Energy. August 2010 Investor Presentation. August 2010.

9. Cimarex Energy. EnerCom Oil & Gas Conference. August 2010.

10. Anadarko Petroleum Corporation. Investor Conference. March 2010. 

11. PLS Inc. Prospect Centre. Market Alert. April 14, 2010.

12. PLS Inc. A&D Transactions. Market Alert. July 2010.

Avalon & Bone Springs
Review of Emerging U.S. Shale Gas and Shale Oil Plays

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Avalon & Bone Springs
Review of Emerging U.S. Shale Gas and Shale Oil Plays

61

VI. Rocky Mountain Regional Summary

The Rocky Mountain region includes shale gas and shale oil plays in the Greater Green River, 

San Juan, Uinta, and Williston Basins. Located within these basins are the Hilliard-BaxterMancos, Lewis, Mancos and the Bakken shale plays with a combined area of 37,033 square 

miles (Figure 25). The reviewed plays have an average EUR between 0.18 and 1.3 Bcf and 

55 MBO. There is approximately 43.0 Tcf of technically recoverable gas and 3.59 Bbbl of 

technically recoverable oil.

Figure 25 Rocky Mountains Shale Gas and Shale Oil Resources

Lewis

HilliardBaxterMancos

Bakken

Mancos

Lewis

HilliardBaxterMancos

Bakken

Mancos

10 – 30 Tcf

30 – 60 Tcf

0 – 10 Tcf

5 – 10 BBbl

0 – 5 BBbl

Lewis

HilliardBaxterMancos

Bakken

Mancos

Lewis

HilliardBaxterMancos

Bakken

Mancos

10 – 30 Tcf

30 – 60 Tcf

0 – 10 Tcf

5 – 10 BBbl

0 – 5 BBbl

Rocky Mountain Region
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Rocky Mountain Region
Review of Emerging U.S. Shale Gas and Shale Oil Plays

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A. Hilliard-Baxter-Mancos Shale Gas Play

Play Description

The Hilliard-Baxter-Mancos shale gas play is located in the Greater Green River Basin in 

Wyoming and Colorado. According to Deutsche Bank, this is an environmentally sensitive 

region with high bottomhole pressures that complicates drilling completions. The location of 

the shale play is provided in Figure 26.

Figure 26 Hilliard-Baxter-Mancos Shale Play

Resource Estimate 

According to USGS, the total active area for Hilliard-Baxter-Mancos is 16,416 square miles. 

The shale gas play has an average EUR of 0.18 Bcf per well and approximately 3.77 Tcf of 

technically recoverable gas. The depth for the shale ranges from 10,000 to 19,500 square 

miles and is 2,850 to 3,300 feet thick. These values are provided in Table 46.

Table 46 Hilliard-Baxter-Mancos Average EUR and Area

Active

Area (sq. miles) 16,416

EUR (Bcf/ well) 0.18

Well Spacing (wells/ sq. mile) 8

TRR (Tcf) 3.77

Hilliard

-Baxter

-Mancos
Review of Emerging U.S. Shale Gas and Shale Oil Plays

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Other average properties were estimated for the Hilliard-Baxter-Mancos shale play. These 

include the depth, thickness, porosity, and total organic content for the shale. These values 

are provided in Table 47.

Table 47 Average General Properties for the Hilliard-Baxter-Mancos Shale Play

Active

Depth (ft) 14,750

Thickness (ft) 3,075

Porosity (%) 4.25

Total Organic Content (% wt) 1.75

Active Companies

In 2008, there were 5 companies holding leases in the Hilliard-Baxter-Mancos shale play. 

These companies, along with their net acreage, as reported by Deutsche Bank, are listed in

Table 48. 

Table 48 Hilliard-Baxter-Mancos Lease Holders

Company Net Acreage

Anadarko Petroleum unspecified

Devon Energy 157,000

Kodiak Oil & Gas 19,879

Questar 146,000

Ultra Petroleum 62,756

Based upon these lease holdings, the total active area is calculated at 385,634 net acres (603 

square miles).

Well Costs

In 2008, Deutsche Bank reported an average well cost of $20 million dollars for the HilliardBaxter-Mancos shale play.

Current Activities

There is minimal information published for the current and future drilling activities of the 

companies who are currently holding leases within the shale.

USGS Comparison

In 2002, the USGS conducted an assessment of the Hilliard-Baxter-Mancos shale play. Their 

estimated area was 16,416 square miles. The USGS estimated that the total undiscovered 

resource for Hilliard-Baxter-Mancos continuous gas between 4.9 and 22.7 Tcf with a mean 

undiscovered resource of 11.8 Tcf.

References

4. Deutsche Bank. From Shale to Shining Shale. July 2008.

5. United States Geological Survey. Assessment of the Undiscovered Natural Gas 

Resources of the Arkoma Basin Province and Geologically Related Areas. 2010.

6. Rice University. The Impacts of Cap-and-Trade, RPS, and Electric Vehicles on the 

North American Natural Gas Market. June 2010.

Hilliard

-Baxter

-Mancos
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B. Lewis Shale Gas Play

Play Description

The Lewis shale gas play is located in the San Juan Basin in Colorado and New Mexico. The 

location of the Lewis shale is provided in Figure 27.

Figure 27 Lewis Shale Play

Resource Estimate

According to USGS, the area for the Lewis shale play is approximately 7,506 square miles. 

The depth of the Lewis shale ranges from 1,640 to 8,202 feet deep and is 200 to 300 feet 

thick. The shale gas play has an average EUR of 1.3 Bcf per well and approximately 11.6 Tcf

of technically recoverable gas. The well spacing for Lewis is estimated at 200 acres per well 

(3 wells per square mile). Theses average values are provided in Table 49.

Table 49 Lewis Average EUR and Area

Active

Area (sq. miles) 7,506

EUR (Bcf/ well) 1.3

Well Spacing (wells/ sq. mile) 3

TRR (Tcf) 11.63

Lewis
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Other average properties were estimated for the Lewis shale play. These properties include 

depth, thickness and porosity as provided in Table 50. Due to a lack of current production 

and other issues within the play, the total organic content is undetermined.

Table 50 Average General Properties for the Lewis Shale Play

Active

Depth (ft) 4,500

Thickness (ft) 250

Porosity (%) 3.5

Total Organic Content (% wt) ----

Active Companies

Information on the active companies and their leased acreage is not currently available. 

Well Costs

Information on the well drilling and completion costs is not currently available.

USGS Comparison

In 2002, USGS conducted an assessment of the Lewis shale play. They estimated that the 

total undiscovered resource for the Lewis continuous gas is between 8,315 and 12,282 Bcf 

with a mean undiscovered resource of 10,177 Bcf.

References

1. http://www.bjservices.com/website/index.nsf/webpages/Shale-LewisPage?OpenDocument

2. USGS. Assessment of Undiscovered Oil and Gas of the San Juan Basin Province of 

New Mexico and Colorado. 2002.

3. USGS. San Juan Basin, Province 5022 (Province 22). 2003 Continuous Assessment

Input Data. 2003.

4. Jenkins, Creties, DeGolyer, MacNaughton, and Boyer, Charles II. Coalbed- and 

Shale- Gas Reservoirs. Journal of Petroleum Technology. February 2008.

5. John B Curtis. Shale Gas: From Onerous Stepchild to Premier Resource. 2008.

Lewis
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C. Mancos Shale Gas Play

Play Description

The Mancos shale gas play is located within the Uinta Basin in Colorado and Wyoming

(Figure 28).

Figure 28 The Mancos Shale Play

Resource Estimate

In 2002, The Mancos shale was assessed by USGS as the Uinta Continuous Gas within the 

Mancos/Mowry total petroleum system. At that time, the median assessment area was 

estimated to be 4,217,000 acres (6,589 square miles). The EUR for the Mancos, apart from 

the Mesaverde, Wasatch, and other formations in the Uinta Basin, was reported as 

approximately 1.0 Bcf per well. The shale gas play is estimated to have 21.02 Tcf of 

technically recoverable gas. Typical well spacing for the Mancos shale was 40 to 80 acres. 

No company data was available in order to determine a minimum or maximum value for the 

EUR.

The Average calculated EUR for the Mancos shale is provided in Table 51.

Table 51 Mancos Average EUR and Area

Active

Area (sq. miles) 6,589

EUR (Bcf/ well) 1.0

Well Spacing (wells/ sq. mile) 8

TRR (Tcf) 21.02

The shale is estimated to be between 13,000 and 17,500 feet deep and have an average 

thickness of 3,000 feet. The average values calculated for the Mancos shale are provided in 

Table 52.

Mancos
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Table 52 Average General Properties for the Mancos Shale Play

Depth (ft) 15,250

Thickness (ft) 3,000

Porosity (%) 3.5

Total Organic Content (% wt) 14

Active Companies

In 2008, there were 9 companies holding leases in the Mancos shale play. These companies, 

along with their net acreage, are listed in Table 53.

Table 53 Mancos Lease Holders

Company Net Acreage

Anadarko Petroleum 60,000

Berry Petroleum 4,508

Cabot Oil & Gas 50,000

Chesapeake 440,000

Comstock 53,000

Cubic Energy 6,326

Devon Energy 200,000

El Paso 27,000

EnCana Corp. 325,000

These companies have leased a combined total of 1,165,834 net acres (1,822 square miles). 

These companies were just beginning to test and develop their acreage. No additional data 

could be found regarding their activities specifically in the Mancos shale.

USGS Comparison

In 2002, USGS completed an assessment of the Uinta Piceance Basin within Colorado and 

Utah. As part of the assessment, they examined the continuous gas within the 

Mancos/Mowry Total Petroleum System. USGS estimated that the area of the shale was 

6,589 square miles and contained between 1.8 Tcf and 4.9 Tcf. The mean estimated resource 

is 3.1 Tcf of natural gas.

References

1. Deutsche Bank. From Shale to Shining Shale. A Primer on North American Natural 

Gas Shale Plays. July 2008.

2. USGS. Assessment of Undiscovered Oil and Gas Resources of the Uinta-Piceance 

Province of Colorado and Utah. 2002.

Mancos
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D. Bakken Shale Oil Play

Play Description

The Bakken shale oil play is located within the Williston Basin in Montana and North Dakota

(Figure 29). While the shale extends into the Canadian provinces of Manitoba and 

Saskatchewan, only the United States portion is considered in this evaluation. This oil field 

could contain 3.65 billion barrels which would be the largest finding in U.S history.

Figure 29 Bakken Shale Play

Resource Estimate

Based on the leaseholders combined net acreage for Bakken, the area is approximately 6,522 

square miles in the United States. The shale oil play has an average EUR of 550 MBO per 

well and approximately 3.59 Bbbl of technically recoverable oil. The Bakken shale ranges 

from 4,500 to 7,500 feet deep with a mean of 6,000 feet and an average thickness of 22 feet. 

According to Kodiak Oil and Gas Corporation and other companies, the well spacing ranges 

from 320 to 1,280 acres per well with a mean of 640 acres per well (1 well per square mile). 

These values are provided in Table 54.

Table 54 Bakken Average EUR and Area

Active

Area (sq. miles) 6,522

EUR (MBO/ well) 550

Well Spacing (wells/ sq. mile) 1

TRR (BBO) 3.59

Other average properties estimated for Bakken are provided in Table 55. These include the 

depth, thickness, porosity, and initial oil saturation for the shale.

Bakken
Review of Emerging U.S. Shale Gas and Shale Oil Plays

70

Table 55 Average General Properties for the Bakken Shale Play

Depth (ft) 6,000

Thickness (ft) 22

Porosity (%) 8

Initial Oil Saturation (%) 68

Active Companies

The active companies, along with their net acreage, are listed in Table 56.

Table 56 Bakken Lease Holders

Company Net Acreage

Brigham Exploration 358,200

Concho Resources 11,193

Continental Resources 589,937

Encore Acquisition Company 70,000

GeoResources 49,000

Hess Corporation 500,000

Kodiak Oil and Gas Corporation 9,565

Marathon Oil Corporation 350,000

MDU Resources 56,000

Newfield Exploration 400,000

Oasis Petroleum 159,500

Parshall Field 18,188

Petroleum Development 16,200

Questar 89,000

Rosetta Resources 291,000

SM Energy 78,000

Southern Alberta Basin 224,000

Unit Corporation 12,750

Whiting Petroleum Corporation 442,092

XTO Energy 450,000

These companies have leased a total of 4,174,625 acres (6,522 sq. miles).

Current Activities

There are extensive activities within the Bakken shale play. Nearly all of the reported lease 

holders have given information about their 2010 development plans. Companies are running 

at least 45 rigs in 2010 and have indicated that number will increase to more than 54. Of 

these, 14 are operated by Continental Resources, 12 by EOG Resources, and 5 by Marathon 

Oil Corporation. In addition, many of the companies have significant capital programs 

devoted to the Bakken shale. Kodiak Oil and Gas Corporation has stated they plan to spend 

$60 millions dollars, Oasis will spend $144 million dollars in the West Williston Basin, and 

Whiting Petroleum Corporation will spend $284 million dollars for operations in the Sanish 

and Parshall sections of the Bakken shale play.

Bakken
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Well Costs

Well cost range form $5.5 to $8.5 million dollars. The vast majority of the companies which 

provide data have costs less than $7.2 million dollars. The lowest price, $5.5 million dollars, 

is also reported by Whiting Petroleum Corporation and Marathon Oil Corporation. In 

addition, Marathon Oil Corporation reports operating costs are less than $5 per barrel in the 

Bakken play.

USGS Comparison

In 2008, USGS conducted an assessment of the Bakken shale. The total undiscovered 

resource is estimated between 3,063 and 4,319 MMOE, with a mean at 3,645 MMBO of total 

continuous resources.

Representative Type Curve

Figure 30 provides a representative type curve for Middle Bakken/ Three Forks area from 

Oasis Petroleum for Bakken in West Williston and East Nesson.

Figure 30 Bakken Shale Type Curve

Bakken
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References

1. http://www.oilshalegas.com/bakkenshale.html.

2. http://www.transformsw.com/resources/studies.html.

3. Rosetta Resources. Rosetta Resources. August 2010.

4. Kodiak Oil and Gas Corporation. Corporate Presentation. August 2010.

5. Denbury Resources. Spring Analyst Meetings. May 2010.

6. Continental Resources. Bakken Shale: The Game-Changer from Hart’s Developing 

Unconventional Oil Conference 2010. May 2010.

7. Whiting Petroleum Corporation. Current Corporate Information. August 2010.

8. USGS. Assessment of Undiscovered Oil and Gas Resources of the Williston Basin 

Province of North Dakota, Montana, and South Dakota. 2008.

9. Oasis Petroleum. Oasis Petroleum Company Presentation. August 2010.

10. Concho. Raymond James Boston Spring Investors Conference. June 2010.

11. GeoResources. GeoResources, Inc Corporate Profile. August 2010.

12. SM Energy. Macquarie Capital USA Small- & Mid- Cap Conference. June 2010.

13. Deutsche Bank. From Shale to Shining Shale. July 2008.

14. QEP Resources. Investor Presentation. August 2010.

15. Newfield Exploration. How the Pieces Fit Together UBS Global Oil & Gas 

Conference. May 2010.

16. EOG Resources. EOG Resources South Texas Eagle Ford. 2010.

17. Marathon Oil Corporation. UBS Global Oil & Gas Conference. May 2010.

18. Hess Corporation. Bernstein Strategic Decisions Conference. June 2010.

19. Brigham Exploration Company. EnerCom- The 2010 Oil & Gas Conference. August 

2010.

20. MDU Resources. A Strong Infrastructure Utility Resources is the Heart of Energy our 

Economy Construction Materials. March 2010.

Bakken
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VII. West Coast Regional Summary

The West Coast region includes shale oil plays in the San Joaquin and Los Angeles Basins

(Figure 31). Located within these basins is the Monterey/Santos shale oil play with a total

area estimated at 1,752 square miles. The reviewed play has an average EUR of 550 MBO

per well and approximately 15.42 Bbbl of technically recoverable oil.

Figure 31 West Coast Shale Gas and Shale Oil Resources

California

10 – 25 BBbl

0 – 10 BBbl California

10 – 25 BBbl

0 – 10 BBbl

West Coast Region
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West Coast Region
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A. Monterey/Santos Shale Oil Play

Play Description

The Monterey/Santos shale oil play includes the Lower Monterey and Santos shales and is 

located in the San Joaquin and Los Angeles Basins in California. The general location of the

Monterey/Santos shale play is provided in Figure 32.

Figure 32 Monterey/Santos Shale Play

Resource Estimate 

The active area for the Monterey/Santos shale play is approximately 1,752 square miles in the 

San Joaquin and Los Angeles Basin. The depth of the shale ranges from 8,000 to 14,000 feet 

deep and is between 1,000 and 3,000 feet thick. The shale oil play has an average EUR of 

550 MBO per well and approximately 15.42 Bbbl of technically recoverable oil. These 

average values are provided in Table 57.

Table 57 Monterey/Santos Average EUR and Area

Active

Area (sq. miles) 1,752

EUR (MBO/ well) 550

Well Spacing (wells/ sq. mile) 16

TRR (BBO) 15.42

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Other average properties were estimated for the Monterey/Santos shale. These include the 

depth, thickness, porosity, and total organic content for the shale. The values are provided in 

Table 58.

Table 58 Average General Properties for the Monterey/Santos Shale Play

Active

Depth (ft) 11,250

Thickness (ft) 1,875

Porosity (%) 11

Total Organic Content (% wt) 6.5

Active Companies

The companies, along with their net acreage who are currently holding leases within the 

Monterey/Santos shale play as of 2010, are listed in Table 59.

Table 59 Monterey/Santos Lease Holders

Company Net Acreage

Berry Petroleum 6,500

National Fuel Gas Company (NFG) 14,000

Occidental Petroleum Company (Oxy) 873,000

Plains Exploration and Production 70,000

Venoco 158,000

Based upon these lease holdings, the total active area is calculated at 1,121,500 net acres 

(1,752 square miles).

Well Costs

Plains Exploration and Production Company reports an average gross well cost in 2010 of 

$1.2 million dollars per well. Oxy reports cost for vertical well ranging from $2 to $2.5 

million and horizontal well costs ranging from $5 to 7 million. They also report finding and 

development costs between $8 and 18 dollars/BOE, depending upon the field.

Current Activities

Oxy Corporation has undertaken a 4-year development program and remains the largest 

leaseholder within the Monterey/Santos play. Seneca Resources/ NFG first went into 

production in February 2010 and have completed a 14 well development program. In 2010, 

Venoco completed their 1st horizontal well in the Monterey Basin and plan to increase their 

net acreage. 

USGS Comparison

This play has not been evaluated by USGS.

Representative Type Curve

Figure 33 provides a representative type curve reported by Oxy Corporation for a vertical 

well, horizontal well, and for the Elk Hills Area “shale” vertical well within the 

Monterey/Santos shale play.

Monterey/Santos
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Figure 33 Monterey/Santos Type Curve

USGS Comparison

In 2003, the USGS conducted an assessment of the San Joaquin Basin. At that time, they did 

not assess the unconventional resources.

References

1. Todd Stevens with Oxy Corporation. Monterey/Santos Unconventional. May 2010.

2. Venoco Corporation. September Update. September 2010. 

3. Plains Exploration and Production Company. 2Q 2010 Presentation. August 2010.

4. Seneca Resources and National Fuel Gas Corporation. EnerCom Oil and Gas 

Conference. August 2010.

5. USGS. Assessment of the Undiscovered Oil and Gas Resources of the San Joaquin 

Basin Province of Monterey/Santos. 2003.

6. http://www.ogj.com/ogj/en-us/index/article-tools-template.articles.oil-gasjournal.exploration-development-2.2010.05.oxy-sees_major_growth.html

7. http://western-energy.com/pages/focus_areas.htm

Monterey/Santos
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Monterey/Santos
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VIII. Appendix A– OLOGSS Shale Gas Data File

The following table provides the key information contained in the shale gas data file used in 

the Onshore Lower 48 Oil and Gas Supply Submodule (OLOGSS). Within the OLOGSS 

model database, each shale play/subplay has 3 well productivity categories to capture the 

large variation in well EUR that exists within a play: 1) Best Area, which covers 30 percent of 

the total play/subplay wells, 2) Average Area, which covers 30 percent of the play/subplay 

wells, and 3) Below Average Area, which covers 40 percent of the play/subplay wells. The 

EURs presented in this report do not include natural gas plant liquids.

Play Name

Basin 

Area 

(sq. 

miles)

Well 

Spacing

(wells/sq. 

mile)

Avg. 

Depth

(ft)

EUR (Bcf/well)

Top 10% Next 

20%

Next 

30%

Next 

40%

Success 

Rate (fr)

Appalachia - Big Sandy 

Central Act 8675 8 3800 0.65 0.49 0.33 0.16 0.86

Best Area 2603 8 3800 0.86 0.65 0.43 0.22 0.86

Average Area 2603 8 3800 0.65 0.49 0.33 0.16 0.86

Below Average Area 3470 8 3800 0.49 0.37 0.24 0.12 0.86

Appalachia - Big Sandy 

Extension 1994 8 3800 0.65 0.49 0.33 0.16 0.86

Best Area 598 8 3800 0.86 0.65 0.43 0.22 0.86

Average Area 598 8 3800 0.65 0.49 0.33 0.16 0.86

Below Average Area 798 8 3800 0.49 0.37 0.24 0.12 0.86

Appalachia - Greater 

Siltstone Area 22914 11 2911 0.58 0.29 0.19 0.06 0.74

Best Area 6874 11 2911 0.77 0.39 0.26 0.08 0.74

Average Area 6874 11 2911 0.58 0.29 0.19 0.06 0.74

Below Average Area 9166 11 2911 0.44 0.22 0.14 0.04 0.74

Appalachia - Low 

Thermal Maturity 45844 7 3000 0.90 0.45 0.30 0.08 0.74

Best Area 13753 7 3000 1.20 0.60 0.40 0.10 0.74

Average Area 13753 7 3000 0.90 0.45 0.30 0.08 0.74

Below Average Area 18338 7 3000 0.68 0.34 0.23 0.06 0.74

Michigan Antrim 12000 7 1400 0.58 0.43 0.24 0.14 0.95

Best Area 3600 7 1400 0.77 0.57 0.32 0.19 0.95

Average Area 3600 7 1400 0.58 0.43 0.24 0.14 0.95

Below Average Area 4800 7 1400 0.44 0.32 0.18 0.11 0.95

Illinois New Albany 

Developing Area 1600 8 2750 3.30 1.67 1.10 0.26 0.5

Best Area 480 8 2750 4.39 2.22 1.46 0.35 0.5

Average Area 480 8 2750 3.30 1.67 1.10 0.26 0.5

Below Average Area 640 8 2750 2.48 1.25 0.83 0.20 0.5

Cincinnati Arch -

Devonian Shales 6000 4 1800 0.36 0.18 0.12 0.03 0.5

Best Area 1800 4 1800 0.48 0.24 0.16 0.04 0.5

Average Area 1800 4 1800 0.36 0.18 0.12 0.03 0.5

Below Average Area 2400 4 1800 0.27 0.14 0.09 0.02 0.5

Williston - Shallow 

Niobraran 10000 2 1000 1.35 0.68 0.45 0.14 0.58

Best Area 3000 2 1000 1.80 0.90 0.60 0.18 0.58

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Average Area 3000 2 1000 1.35 0.68 0.45 0.14 0.58

Below Average Area 4000 2 1000 1.01 0.51 0.34 0.10 0.58

Fort Worth Barnett - Core 

Area P 1426 5 7500 3.20 2.40 1.60 0.80 0.95

Best Area 428 5 7500 4.26 3.19 2.13 1.06 0.95

Average Area 428 5 7500 3.20 2.40 1.60 0.80 0.95

Below Average Area 570 5 7500 2.40 1.80 1.20 0.60 0.95

Fort Worth Barnett -

Extension P 1906 8 7500 2.40 1.80 1.20 0.60 0.75

Best Area 572 8 7500 3.19 2.39 1.60 0.80 0.75

Average Area 572 8 7500 2.40 1.80 1.20 0.60 0.75

Below Average Area 762 8 7500 1.80 1.35 0.90 0.45 0.75

Fort Worth Barnett - Core 

Area F 2649 5 7500 3.20 2.40 1.60 0.80 0.95

Best Area 795 5 7500 4.26 3.19 2.13 1.06 0.95

Average Area 795 5 7500 3.20 2.40 1.60 0.80 0.95

Below Average Area 1060 5 7500 2.40 1.80 1.20 0.60 0.95

Fort Worth Barnett -

Extension F 477 8 7500 2.40 1.80 1.20 0.60 0.75

Best Area 143 8 7500 3.19 2.39 1.60 0.80 0.75

Average Area 143 8 7500 2.40 1.80 1.20 0.60 0.75

Below Average Area 191 8 7500 1.80 1.35 0.90 0.45 0.75

Woodford-Barnett -

Active 2691 4 10200 6.00 4.50 3.00 1.50 0.75

Best Area 807 4 10200 7.98 5.99 3.99 2.00 0.75

Average Area 807 4 10200 6.00 4.50 3.00 1.50 0.75

Below Average Area 1076 4 10200 4.50 3.38 2.25 1.13 0.75

Lewis Shale 7506 3 4500 3.25 2.44 1.30 0.82 0.95

Best Area 2252 3 4500 4.32 3.25 1.73 1.09 0.95

Average Area 2252 3 4500 3.25 2.44 1.30 0.82 0.95

Below Average Area 3002 3 4500 2.44 1.83 0.98 0.62 0.95

Fayetteville - Central 4000 8 4000 6.74 3.38 2.25 0.68 0.94

Best Area 1200 8 4000 8.96 4.50 2.99 0.90 0.94

Average Area 1200 8 4000 6.74 3.38 2.25 0.68 0.94

Below Average Area 1600 8 4000 5.06 2.54 1.69 0.51 0.94

Fayetteville - West 5000 8 4000 3.45 1.75 1.15 0.35 0.88

Best Area 1500 8 4000 4.59 2.33 1.53 0.46 0.88

Average Area 1500 8 4000 3.45 1.75 1.15 0.35 0.88

Below Average Area 2000 8 4000 2.59 1.31 0.86 0.26 0.88

Woodford - Western 

Arkoma 2900 4 9500 11.97 6.00 4.00 1.20 0.9

Best Area 870 4 9500 15.92 7.98 5.32 1.60 0.9

Average Area 870 4 9500 11.97 6.00 4.00 1.20 0.9

Below Average Area 1160 4 9500 8.98 4.50 3.00 0.90 0.9

Woodford - Central OK 

Fold Belt 1800 4 5000 2.99 1.50 1.00 0.30 0.86

Best Area 540 4 5000 3.98 2.00 1.33 0.40 0.86

Average Area 540 4 5000 2.99 1.50 1.00 0.30 0.86

Below Average Area 720 4 5000 2.24 1.13 0.75 0.23 0.86

Woodford - Cana 688 4 13500 15.56 7.80 5.20 1.50 0.86

Best Area 206 4 13500 20.69 10.37 6.92 2.00 0.86

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Average Area 206 4 13500 15.56 7.80 5.20 1.50 0.86

Below Average Area 726 4 13500 11.67 5.85 3.90 1.13 0.86

Haynesville ShaleDeveloped 3574 8 12000 13.00 9.75 6.50 3.25 0.75

Best Area 1072 8 12000 17.29 12.97 8.65 4.32 0.75

Average Area 1072 8 12000 13.00 9.75 6.50 3.25 0.75

Below Average Area 1430 8 12000 9.75 7.31 4.88 2.44 0.75

Haynesville ShaleUndeveloped 5426 8 12000 3.00 2.25 1.50 0.75 0.75

Best Area 1628 8 12000 3.99 2.99 2.00 1.00 0.75

Average Area 1628 8 12000 3.00 2.25 1.50 0.75 0.75

Below Average Area 2170 8 12000 2.25 1.69 1.13 0.56 0.75

Appalachia - Marcellus 

Dev 10622 8 6750 7.00 5.25 3.50 1.75 0.7

Best Area 3187 8 6750 9.31 6.98 4.66 2.33 0.7

Average Area 3187 8 6750 7.00 5.25 3.50 1.75 0.7

Below Average Area 4249 8 6750 5.25 3.94 2.63 1.31 0.7

Appalachia - Marcellus 

Und- MD 920 8 6750 2.30 1.73 1.15 0.58 0.7

Best Area 276 8 6750 3.06 2.30 1.53 0.77 0.7

Average Area 276 8 6750 2.30 1.73 1.15 0.58 0.7

Below Average Area 368 8 6750 1.73 1.30 0.86 0.44 0.7

Appalachia - Marcellus 

Und- NY 16926 8 6750 2.30 1.73 1.15 0.58 0.7

Best Area 5078 8 6750 3.06 2.30 1.53 0.77 0.7

Average Area 5078 8 6750 2.30 1.73 1.15 0.58 0.7

Below Average Area 6770 8 6750 1.73 1.30 0.86 0.44 0.7

Appalachia - Marcellus 

Und- OH 15348 8 6750 2.30 1.73 1.15 0.58 0.7

Best Area 4604 8 6750 3.06 2.30 1.53 0.77 0.7

Average Area 4604 8 6750 2.30 1.73 1.15 0.58 0.7

Below Average Area 6139 8 6750 1.73 1.30 0.86 0.44 0.7

Appalachia - Marcellus 

Und- PA 29828 8 6750 2.30 1.73 1.15 0.58 0.7

Best Area 8948 8 6750 3.06 2.30 1.53 0.77 0.7

Average Area 8948 8 6750 2.30 1.73 1.15 0.58 0.7

Below Average Area 11931 8 6750 1.73 1.30 0.86 0.44 0.7

Appalachia - Marcellus 

Und- VA 3249 8 6750 2.30 1.73 1.15 0.58 0.7

Best Area 975 8 6750 3.06 2.30 1.53 0.77 0.7

Average Area 975 8 6750 2.30 1.73 1.15 0.58 0.7

Below Average Area 1300 8 6750 1.73 1.30 0.86 0.44 0.7

Appalachia - Marcellus 

Und- WV 18000 8 6750 2.30 1.73 1.15 0.58 0.7

Best Area 5400 8 6750 3.06 2.30 1.53 0.77 0.7

Average Area 5400 8 6750 2.30 1.73 1.15 0.58 0.7

Below Average Area 7200 8 6750 1.73 1.30 0.86 0.44 0.7

Eagleford Shale - DRY 

GAS 200 4 7000 11.00 8.25 5.50 2.75 0.892

Best Area 60 4 7000 14.63 10.97 7.32 3.66 0.892

Average Area 60 4 7000 11.00 8.25 5.50 2.75 0.892

Below Average Area 80 4 7000 8.25 6.19 4.13 2.06 0.892

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Eagleford Shale - WET 

GAS 890 8 7000 9.00 6.75 4.50 2.25 0.892

Best Area 267 8 7000 11.97 8.98 5.99 2.99 0.892

Average Area 267 8 7000 9.00 6.75 4.50 2.25 0.892

Below Average Area 356 8 7000 6.75 5.06 3.38 1.69 0.892

Floyd/Neal-Conasauga 2429 2 8000 1.80 1.35 0.90 0.45 0.906

Best Area 729 2 8000 2.39 1.80 1.20 0.60 0.906

Average Area 792 2 8000 1.80 1.35 0.90 0.45 0.906

Below Average Area 972 2 8000 1.35 1.01 0.68 0.34 0.906

Uinta Mancos 6589 8 15250 2.00 1.50 1.00 0.50 0.95

Best Area 1977 8 15250 2.66 2.00 1.33 0.67 0.95

Average Area 1977 8 15250 2.00 1.50 1.00 0.50 0.95

Below Average Area 2636 8 15250 1.50 1.13 0.75 0.38 0.95

GGB Hilliard Baxter 

Mancos 16416 8 14750 0.36 0.27 0.18 0.09 0.8

Best Area 4925 8 14750 0.48 0.36 0.24 0.12 0.8

Average Area 4925 8 14750 0.36 0.27 0.18 0.09 0.8

Below Average Area 6566 8 14750 0.27 0.20 0.14 0.07 0.8

Appendix