Chapter 1

Assessment of Undiscovered Oil and Gas 

Resources of the Anadarko Basin Province 

of Oklahoma, Kansas, Texas, and Colorado, 

2010

By Debra K. Higley, Stephanie B. Gaswirth, Marvin M. Abbott, Ronald R. 

Charpentier, Troy A. Cook, Geoffrey S. Ellis, Nicholas J. Gianoutsos, Joseph R. 

Hatch, Timothy R. Klett, Philip H. Nelson, Mark J. Pawlewicz, Ofori N. Pearson, 

Richard M. Pollastro, and Christopher J. Schenk

Chapter 1 of 13

Petroleum Systems and Assessment of Undiscovered Oil and Gas 

in the Anadarko Basin Province, Colorado, Kansas, Oklahoma, and 

Texas—USGS Province 58

Compiled by Debra K. Higley

U.S. Geological Survey Digital Data Series DDS–69–EE

U.S. Department of the Interior

U.S. Geological Survey

Click here to return to

Volume Title Page
U.S. Department of the Interior

SALLY JEWELL, Secretary

U.S. Geological Survey

Suzette M. Kimball, Acting Director

U.S. Geological Survey, Reston, Virginia: 2014

For more information on the USGS—the Federal source for science about the Earth, its natural and living 

resources, natural hazards, and the environment, visit http://www.usgs.gov or call 1–888–ASK–USGS.

For an overview of USGS information products, including maps, imagery, and publications, 

visit http://www.usgs.gov/pubprod

To order this and other USGS information products, visit http://store.usgs.gov

Any use of trade, firm, or product names is for descriptive purposes only and does not imply endorsement by the 

U.S. Government.

Although this information product, for the most part, is in the public domain, it also may contain copyrighted materials 

as noted in the text. Permission to reproduce copyrighted items must be secured from the copyright owner.

Suggested citation:

Higley, D.K., Gaswirth, S.B., Abbott, M.M., Charpentier, R.R., Cook, T.A., Ellis, G.S., Gianoutsos, N.J., Hatch, J.R., 

Klett, T.R., Nelson, P.H., Pawlewicz, M.J., Pearson, O.N., Pollastro, R.M., and Schenk, C.J., 2014, Assessment of 

undiscovered oil and gas resources of the Anadarko Basin Province of Oklahoma, Kansas, Texas, and Colorado, 2010, 

chap. 1, in Higley, D.K., compiler, Petroleum systems and assessment of undiscovered oil and gas in the Anadarko 

Basin Province, Colorado, Kansas, Oklahoma, and Texas—USGS Province 58: U.S. Geological Survey Digital Data 

Series DDS–69–EE, 3 p. http://dx.doi.org/10.3133/ds69EE.

ISSN 2327-638X (online)
iii

Contents

Abstract...........................................................................................................................................................1

Introduction.....................................................................................................................................................1

Resource Summary .......................................................................................................................................1

For Further Information........................................................................................................................2

Anadarko Basin Province Assessment Team..................................................................................2

Figure

1. Map showing boundaries of the Anadarko Basin Province (red line), the Woodford

Composite total petroleum system (TPS, black line), and the Pennsylvanian

Composite TPS (blue line) ...........................................................................................................2

Table

1. Anadarko Basin Province assessment results listed by total petroleum system

(TPS) and assessment unit (AU). Included are estimated volumes of undiscovered

technically recoverable oil, gas, and natural gas liquids (NGL)...........................................3

Abstract

The U.S. Geological Survey, using a geoscience-based 

assessment methodology, estimated mean technically recoverable undiscovered continuous and conventional resources 

that total 495 million barrels of oil, 27.5 trillion cubic feet of 

natural gas, and 410 million barrels of natural gas liquids in 

the Anadarko Basin Province; this assessment includes the Las 

Animas arch area of southeastern Colorado. The province is 

at a mature stage of exploration and development for conventional resources. Mean undiscovered continuous resources are 

estimated at 79 percent of oil, 90 percent of natural gas, and 

81 percent of natural gas liquids in the province.

Introduction

The U.S. Geological Survey (USGS) in 2010 completed 

an assessment of the undiscovered oil and gas potential of 

the Anadarko Basin Province of western Oklahoma, western 

Kansas, northern Texas, and southeastern Colorado (fig. 1). 

The assessment is based on the geologic elements of each 

defined total petroleum system (TPS), including (1) hydrocarbon source rocks (source-rock richness and thermal maturation, hydrocarbon generation, adsorption, and migration); 

(2) reservoir rock type (conventional or continuous), distribution, and quality; and (3) types and distribution of reservoir 

traps and seals, including timing relative to petroleum generation and migration. Using this geologic framework, the USGS 

defined 2 TPSs, with 12 included assessment units (AU), and 

quantitatively estimated undiscovered oil, gas, and natural gas 

liquids resources in each AU (table 1).

The Anadarko Basin Province is in a mature state of 

exploration and development for conventional resources. 

Much of the production is reported as being commingled 

from numerous formations that were deposited over broad age 

ranges; this commingling influenced grouping of formations 

into the AUs. The Woodford Composite and Pennsylvanian 

Composite TPSs represent source rock contributions from 

numerous Ordovician through Pennsylvanian formations. The 

Woodford Composite TPS source rocks primarily contribute 

to Cambrian through Mississippian reservoirs, and those of the 

Pennsylvanian Composite TPS to Pennsylvanian and Permian 

reservoirs. Migration and accumulation of hydrocarbons from 

variable sources can occur along fault systems and updip from 

the extent of the Woodford Shale and other source rocks. Biogenic gas from the Cretaceous Niobrara Formation is produced 

from western Kansas and eastern Colorado; however, that 

resource was evaluated in the Denver Basin Province assessment (USGS Fact Sheet 002–03).

Resource Summary

The USGS assessment of undiscovered conventional 

and continuous (unconventional) resources within the province resulted in mean estimates of 495 million barrels of 

oil (MMBO), 27 trillion cubic feet of natural gas (TCFG), 

and 410 million barrels of natural gas liquids (MMBNGL) 

within 12 AUs in the 2 TPSs (table 1). Much of the remaining 

conventional resources are from field growth in this mature 

province. Continuous resources are focused in the deep part 

of the Anadarko Basin in Oklahoma and Texas. Boundaries of the Woodford Shale Oil and Woodford Shale Gas AUs 

and locations of sweet spots within them were based mainly 

on (1) extent and thickness of the formation, (2) filling of 

underlying Hunton Formation eroded channels, (3) historical 

and estimated ultimate production from existing wells, and 

(4) levels of thermal maturation based on 1D, 2D, and 3D 

petroleum system models and on vitrinite reflectance maps 

and data. The Thirteen Finger Limestone–Atoka Shale Gas 

continuous AU does not have documented production and has 

limited published information. Boundaries for this AU were 

based largely on characteristics such as thickness and lateral 

extent of included formations from well-log examination, and 

it is within the boundary of wet and dry gas generation based 

on 1D and 3D petroleum system models. This uncertainty is 

reflected in a fairly broad range of F5 to F95 resource estimates (table 1); mean undiscovered resources are 6.85 TCFG 

and 82 MMBNGL.

Assessment of Undiscovered Oil and Gas Resources of 

the Anadarko Basin Province of Oklahoma, Kansas, Texas, 

and Colorado, 2010

Compiled by Debra K. Higley
2 Assessment of Undiscovered Oil and Gas Resources of the Anadarko Basin Province, 2010

For Further Information

Supporting geologic studies of total petroleum systems 

and assessment units and reports on the methodology used in 

the Anadarko Basin Province assessment are in preparation. 

Assessment results and geologic reports will be available as 

completed at the USGS Web site http://energy.cr.usgs.gov/

oilgas/noga/.

Figure 1. Map showing boundaries of the Anadarko Basin Province (red line), the Woodford 

Composite total petroleum system (TPS, black line), and the Pennsylvanian Composite TPS 

(blue line). 

Anadarko Basin Province Assessment Team:

Debra K. Higley (Task Leader; higley@usgs.gov), 

Stephanie B. Gaswirth, Marvin M. Abbott, Ronald R. Charpentier, Troy A. Cook, Geoffrey S. Ellis, Nicholas J. Gianoutsos, Joseph R. Hatch, Timothy R. Klett, Philip H. Nelson, 

Mark J. Pawlewicz, Ofori N. Pearson, Richard M. Pollastro, 

and Christopher J. Schenk (National Assessment of Oil and 

Gas Project Chief).

OKLAHOMA

COLORADO KANSAS

TEXAS

NEW

MEXICO

Pennsylvanian 

Composite TPS

Woodford 

Composite TPS

104° 103° 102° 101° 100° 99° 98° 97° 

39° 

38° 

37° 

36° 

35° 

34° 

0 50 100 MILES

0 50 100 KILOMETERS

GULF 

OF 

MEXICO

TEXAS

NEW

MEXICO

COLORADO KANSAS

OKLAHOMA

Anadarko 

 Basin 

 Province

Anadarko_Fig_1.ai

Anadarko Basin
Resource Summary 3

Table 1. Anadarko Basin Province assessment results listed by total petroleum system (TPS) and assessment unit (AU). Included are 

estimated volumes of undiscovered technically recoverable oil, gas, and natural gas liquids (NGL). 

[MMBO, million barrels of oil; BCFG, billion cubic feet of gas; MMBNGL, million barrels of natural gas liquids; gray shading, not applicable. Type refers 

to mainly oil or gas accumulations in the assessment unit. Fractiles (F95, F50, F5) are fully risked estimates. F95 denotes a 95-percent chance of at least the 

amount tabulated. Other fractiles are defined similarly. Fractiles are additive only under the assumption of perfect positive correlation]

Total Petroleum Systems 

(TPS) 

and Assessment Units (AU)

Field 

Type

Total Undiscovered Resources

Oil (MMBO) Gas (BCFG) NGL (MMBNGL)

F95 F50 F5 Mean F95 F50 F5 Mean F95 F50 F5 Mean

Woodford Composite TPS

Arbuckle-Ellenburger AU

Oil 2 5 12 6 7 24 61 28 0 1 2 1

Gas 43 164 371 181 0 1 2 1

Simpson Group AU

Oil 2 4 9 5 6 17 39 19 0 0 1 1

Gas 33 114 252 125 2 9 21 10

Viola Group AU

Oil 2 5 10 5 3 9 20 10 0 1 2 1

Gas 10 27 58 30 0 0 0 0

Hunton Group AU

Oil 2 8 21 9 8 32 87 38 0 1 3 1

Gas 71 281 641 310 0 2 4 2

Mississippian AU

Oil 5 16 31 17 15 46 99 50 0 2 4 2

Gas 125 350 663 367 3 8 17 9

Pennsylvanian Composite TPS

Morrowan-Atokan AU

Oil 6 14 29 15 21 55 121 61 1 2 5 2

Gas 101 261 469 271 2 5 10 5

Desmoinesian AU

Oil 2 6 12 6 8 23 52 26 0 1 2 1

Gas 29 87 167 92 1 3 5 3

Missourian-Permian AU

Oil 10 22 38 23 49 114 223 122 2 4 8 4

Gas 61 130 231 136 2 4 7 4

Greater Granite Wash 

Composite AU

Oil 4 14 34 16 22 78 198 90 1 2 7 3

Gas 192 646 1,496 719 7 24 60 27

Total Conventional

 Resources 35 94 196 102 804 2,458 5,248 2,675 21 70 160 77

Woodford Composite TPS

Woodford Shale Oil AU

Woodford Shale Gas AU

Oil 175 357 730 393 795 1,750 3,851 1,963 22 51 121 59

Gas 8,806 15,131 25,998 15,973 94 178 336 192

Pennsylvanian Composite TPS

Thirteen Finger LimestoneAtoka Shale Gas AU

Oil

Gas 3,040 6,229 12,763 6,850 33 73 161 82

Total Continuous

 Resources 175 357 730 393 12,641 23,110 42,612 24,786 149 302 618 333

Total Resources 210 451 926 495 13,445 25,568 47,860 27,461 170 372 778 410

Chapter 2

Overview

By Debra K. Higley and Stephanie B. Gaswirth

Chapter 2 of 13

Petroleum Systems and Assessment of Undiscovered Oil and Gas 

in the Anadarko Basin Province, Colorado, Kansas, Oklahoma, and 

Texas—USGS Province 58

Compiled by Debra K. Higley

U.S. Geological Survey Digital Data Series DDS–69–EE

U.S. Department of the Interior

U.S. Geological Survey

Click here to return to

Volume Title Page
U.S. Department of the Interior

SALLY JEWELL, Secretary

U.S. Geological Survey

Suzette M. Kimball, Acting Director

U.S. Geological Survey, Reston, Virginia: 2014

For more information on the USGS—the Federal source for science about the Earth, its natural and living 

resources, natural hazards, and the environment, visit http://www.usgs.gov or call 1–888–ASK–USGS.

For an overview of USGS information products, including maps, imagery, and publications, 

visit http://www.usgs.gov/pubprod

To order this and other USGS information products, visit http://store.usgs.gov

Any use of trade, firm, or product names is for descriptive purposes only and does not imply endorsement by the 

U.S. Government.

Although this information product, for the most part, is in the public domain, it also may contain copyrighted materials 

as noted in the text. Permission to reproduce copyrighted items must be secured from the copyright owner.

Suggested citation:

Higley, D.K., and Gaswirth, S.B., 2014, Overview, chap. 2, in Higley, D.K., compiler, Petroleum systems and 

assessment of undiscovered oil and gas in the Anadarko Basin Province, Colorado, Kansas, Oklahoma, and Texas—

USGS Province 58: U.S. Geological Survey Digital Data Series DDS–69–EE, 5 p. http://dx.doi.org/10.3133/ds69EE.

ISSN 2327-638X (online)
iii

Contents

Introduction.....................................................................................................................................................1

Discussion of Chapters.................................................................................................................................1

Contact Information.......................................................................................................................................5

Disclaimer.......................................................................................................................................................5

Using This CD..................................................................................................................................................5

References Cited............................................................................................................................................5

Figures

1. Map showing the Anadarko Basin Province is delineated by the maximum areal 

extent of the Woodford Composite and Pennsylvanian Composite Total Petroleum

Systems (TPSs). The province includes the Anadarko Basin (red line), part of the 

Palo Duro Basin, and the Las Animas arch..............................................................................2

2. Generalized surface and subsurface stratigraphic columns for the Anadarko Basin

and the Southern Oklahoma Fold Belt Provinces for the Precambrian to

Mississippian. Assessment units (AU) are included in the Woodford Composite

TPS. Blue text and lowercase descriptors indicate informal status. Wavy horizontal

lines and vertical bars indicate unconformities and their duration. Modified from

Bebout and others (1993) and Henry and Hester (1995). Ages in millions of years

before present (Ma) from Haq and Van Eysinga (1998) and Gradstein and others

(2004) (red text). Fm., Formation; Mbr., Member......................................................................3

3. Generalized surface and subsurface stratigraphic columns for the Anadarko Basin

and the Southern Oklahoma Fold Belt Provinces for the Precambrian to

Mississippian. Assessment units (AU) are included in the Woodford Composite

TPS. Italic (blue) text and lowercase descriptors indicate informal status. Wavy

horizontal lines and vertical bars indicate unconformities and their duration.

Modified from Bebout and others (1993) and Henry and Hester (1995). Ages in

millions of years before present (Ma) from Haq and Van Eysinga (1998) and

Gradstein and others (2004) (red text). Fm., Formation; Mbr., Member...............................4

Overview

By Debra K. Higley and Stephanie B. Gaswirth

Introduction

This publication provides research results and related 

data in support of the U.S. Geological Survey (USGS) 

assessment of the undiscovered oil and gas resource potential 

of the Anadarko Basin Province of western Oklahoma and 

Kansas, northern Texas, and southeastern Colorado (fig. 1). 

This province area includes the Las Animas arch of southeastern Colorado, part of the Palo Duro Basin of Texas, and 

the Anadarko Basin. This is hereafter referred to as the 2011 

assessment, which corresponds to the publication release date 

of the assessment results (Higley and others, 2011). Results 

of the geologic analysis and resource assessment (chapter 1) 

are based on the geologic elements of each defined total 

petroleum system (TPS), including hydrocarbon source rocks 

(source-rock maturation, hydrocarbon generation and migration), reservoir rocks (sequence stratigraphic and petrophysical properties), hydrocarbon traps (trapping mechanisms and 

timing), and seals. Using this geologic framework, the USGS 

defined 2 TPSs, the Woodford Composite TPS and Pennsylvanian Composite TPS (fig. 1) and 12 included assessment 

units (AU) (chapters 1 and 5–7), and quantitatively estimated 

the undiscovered oil and gas resources within these AUs. The 

assigned TPS and AU names and numeric codes follow. 

Woodford Composite TPS 505801:

1. Arbuckle-Ellenburger, AU 50580101

2. Simpson Group, AU 50580102

3. Viola Group, AU 50580103

4. Hunton Group, AU 50580104

5. Mississippian, AU 50580105

6. Woodford Shale Gas, AU 50580161

7. Woodford Shale Oil, AU 50580162

8. Pennsylvanian Composite TPS 505802:

9. Morrowan-Atokan, AU 50580201

10. Desmoinesian, AU 50580202

11. Missourian-Permian, AU 50580203

12. Greater Granite Wash Composite, AU 50580204

13. Thirteen Finger Limestone–Atoka Shale Gas, AU 

50580261

There are nine conventional and three continuous AUs. 

Continuous AUs are the (1) Devonian and Mississippian 

Woodford Shale Gas and (2) Woodford Shale Oil AUs of the 

Woodford Composite TPS, and (3) the Pennsylvanian Thirteen Finger Limestone–Atoka Shale of the Pennsylvanian 

Composite TPS. The stratigraphic charts show units within the 

Woodford Composite TPS (fig. 2) and Pennsylvanian Composite TPS (fig. 3).

Discussion of Chapters

The 13 chapters included in DDS–69–EE cover topics 

that range from the oil and gas resource assessment results 

(chapter 1) of the Anadarko Basin Province, to background 

geological and geochemical research (chapters 3–11), tabular 

data and graphs in support of the assessment (chapter 12), and 

data releases of geographic information systems (GIS) shape 

files, zmap-format grid files that were used to build petroleum 

system models, and a standalone three-dimensional (3D) geologic model (chapter 13). Information on individual chapters 

is below. 

Chapter 3. Thermal maturation history is based on 

one-dimensional (1D) and four-dimensional (4D) petroleum 

system models created as part of this study and on published 

research. This information was used to model hydrocarbon 

generation, migration, and accumulation through time for 

three assigned source intervals, the Ordovician Oil Creek 

Formation, Devonian-Mississippian Woodford Shale, and the 

informal Atokan Thirteen Finger limestone. Thermal maturation boundaries were also used to delineate continuous assessment units. 

Chapter 4. The geochemistry of produced gases from the 

Anadarko Basin was analyzed with particular regard for their 

source and timing of generation, and this information helped 

to define the assessment units used in the assessment of undiscovered resources.

Chapter 5. The geology and assessment of Cambrian 

through Devonian stratigraphy of the Anadarko Basin Province is discussed. Included are descriptions of the units that 

compose the AUs: the Reagan Sandstone, the Arbuckle Group, 

the Simpson Group, the Viola Group, the Sylvan Shale, the 

Hunton Group, and the Misener sand (fig. 2).
2 Overview

Chapter 6. Contained are the geology, thermal maturation history, and assessment of continuous resources of the 

Devonian-Mississippian Woodford Shale Gas and Woodford 

Shale Oil AUs (fig. 2). 

Chapter 7. Conventional undiscovered resources of Mississippian through Permian AUs are discussed, as well as continuous gas resources from the Atokan Thirteen Finger limestone 

AU (figs. 2 and 3). Background information on these AUs 

includes the geologic characteristics and thermal maturation and 

petroleum production histories of the source and reservoir rocks.

Chapters 8 and 9. Pore pressures in Pennsylvanian strata of 

the greater Anadarko Basin range from overpressure in the deep 

basin, to normal pressure in the northeastern flank, to underpressure in the northwestern flank. The characteristics and evolution 

of the overpressured system are discussed in chapter 8, along 

with the finding of a paleo-overpressure zone more extensive 

than the present-day area of overpressure. The characteristics and 

causes of the underpressure, which grades into normal pressure 

along the northern flank of the basin, are discussed in chapter 9.

Chapter 10. Lithologies derived from mud logs, sample 

logs, and geophysical logs are presented on eight structural 

cross sections that cover the Oklahoma portion of the 

Anadarko Basin. There are three major lithologic groups: (1) 

the carbonate-dominated units of Mississippian age and older, 

(2) mostly siliciclastic units of Pennsylvanian age, and (3) 

evaporites and red shales of Permian age. 

Chapter 11. This discussion of the tectonic and structural 

evolution of the Anadarko Basin is accompanied by a structural interpretation of a key two-dimensional (2D) seismic line 

and associated structural restoration. 

Chapter 12. Contained are tabular data and graphs used in 

support of assessment of undiscovered oil and gas resources of 

the Anadarko Basin Province.

Chapter 13. Included are grid files and associated 

readme and metadata files used to build and document a 4D 

petroleum system model of the province. The 2D grid files 

comprise (1) 26 structural surfaces across the province, (2) 

estimated eroded thickness of strata in the Cenozoic, (3) 

total organic carbon content of the Woodford Shale, and (4) 

basement heat flow. Also included with this chapter is a 3D 

standalone geologic model of the Anadarko Basin Province 

that incorporates the 2D grid files. 

Figure 1. Map showing the Anadarko Basin Province is delineated by the maximum areal 

extent of the Woodford Composite and Pennsylvanian Composite Total Petroleum Systems 

(TPSs). The province includes the Anadarko Basin (red line), part of the Palo Duro Basin, 

and the Las Animas arch.

OKLAHOMA

COLORADO KANSAS

TEXAS

NEW

MEXICO

Pennsylvanian 

Composite TPS

Woodford 

Composite TPS

104° 103° 102° 101° 100° 99° 98° 97° 

39° 

38° 

37° 

36° 

35° 

34° 

CH2_Figure 1. 

Denver

Basin

Raton

Basin

Anadarko

Basin

 Las 

 Animas

arch

Palo

Duro

Basin

Nemaha uplift

Central Kansas uplift

Salina

Basin

Hardeman 

Basin

Arbuckle

uplift

0 50 100 MILES

0 50 100 KILOMETERS

GULF 

OF 

MEXICO

TEXAS

NEW

MEXICO

COLORADO KANSAS

OKLAHOMA

Anadarko 

 Basin 

 Province
Discussion of Chapters 3

Figure 2. Generalized surface 

and subsurface stratigraphic 

columns for the Anadarko Basin 

and the Southern Oklahoma 

Fold Belt Provinces for the 

Precambrian to Mississippian. 

Assessment units (AU) are 

included in the Woodford 

Composite TPS. Blue text and 

lowercase descriptors indicate 

informal status. Wavy horizontal 

lines and vertical bars indicate 

unconformities and their duration. 

Modified from Bebout and others 

(1993) and Henry and Hester 

(1995). Ages in millions of years 

before present (Ma) from Haq and 

Van Eysinga (1998) and Gradstein 

and others (2004) (red text). Fm., 

Formation; Mbr., Member.

ArbuckleEllenburger 

Simpson

Group

Viola

Group

Hunton 

Group

Woodford

Shale 

Gas, Oil

333

340

365

374

379

421

432

452

472

514

443.7

 ±1.5

416.0

± 2.8

359.2

 ± 2.5

318.1

 ±1.3

488.3

 ±1.7

542.0

 ±1.0

System

Series

Age, Ma

AU

names

CH2_Fig2

348

Hugoton

Embayment

Kansas

Northern

Anadarko

Basin

Southern

Anadarko

Basin

Mississippian

Mississippian

Chesterian Mera- Mecian Osag- ean

Springer

Formation

Chester

Group

Cunningham sand Markham sand

Britt sand

Chester Group Manning zone

Ste. Genevieve Formation

Mississippi lime

St. Louis Formation

Salem Fm. (Spergen Fm.)

Warsaw Formation

Osage chert

Gilmore City Limestone

Hannibal Shale

Meramec lime

Meramec

lime

Mississippi chat

Mississippi solid

Cowley Formation

Ste. Genevieve Limestone

St. Louis Limestone

Salem Limestone

Warsaw Limestone

Osage lime

Kinderhook Shale

 Kinderhookian

Cunningham sands

Britt sand

Aldridge sand

Spiers sand Humphreys sand

Boatwright sands Sims sands

Springer Formation

Mayes Group

Goddard Shale Goodwin sand

Delaware Creek Shale

 (Caney Shale)

Sycamore Limestone

Chautauquan

Misener sand Misener sand

Senecan Erian Ulsterian

Devonian Silurian

Cayugan Niagaran Alexandrian

Hunton Group

Frisco Formation

Bois d'Arc Formation

Haragan Formation

Henryhouse Formation

Chimneyhill Limestone

Hunton Group

Chimneyhill subgroup

Clarita 

 Fm.

Fitzhugh Mbr.

Prices Falls

Member

Cochrane 

Formation

Keel Formation

Ordovician Cambrian

Cincinnatian Champlainian Canadian Trempea- leauan Franco- nian Dresb- achian

Viola Formation

?

Sylvan Shale Sylvan Shale

Welling Fm.

(Fernvale-Viola)

Viola Springs

 Formation

 Bromide

FormationBromide dense (lime)

Viola Group Simpson Group Arbuckle Group

First Bromide sand

Second Bromide sand

(Third Bromide sand)

Tulip Creek Formation

Brown zone

McLish Formation

Oil Creek Formation

Joins Formation

West Spring Creek Fm.

Kindblade Formation

Cool Creek Formation

McKenzie Hill Formation

Butterly Dolomite Signal Mountain Formation Royer Dolomite

Fort Sill Limestone

Timbered Hills 

 Group

Fernvale Limestone

Trenton Limestone

Arbuckle Group

(undivided) Arbuckle Group

Reagan (Lamotte)

Sandstone

?

?

?

Simpson Group

Simpson Group

Bromide Formation

Tulip Creek Formation

McLish Formation

Oil Creek Formation

Joins Formation

(Simpson dense,Wilcox sands)

Frisco Formation

Bois d'Arc Formation

Haragan Formation

Henryhouse Formation

Bonneterre 

Dolomite

Reagan (Lamotte)

Sandstone

Bonneterre 

Dolomite

(undivided)

Woodford Shale Woodford Shale
4 Overview

Figure 3. Generalized surface and 

subsurface stratigraphic columns for the 

Anadarko Basin and the Southern Oklahoma 

Fold Belt Provinces for the Precambrian to 

Mississippian. Assessment units (AU) are 

included in the Woodford Composite TPS. 

Italic (blue) text and lowercase descriptors 

indicate informal status. Wavy horizontal lines 

and vertical bars indicate unconformities 

and their duration. Modified from Bebout and 

others (1993) and Henry and Hester (1995). 

Ages in millions of years before present 

(Ma) from Haq and Van Eysinga (1998) and 

Gradstein and others (2004) (red text). Fm., 

Formation; Mbr., Member.

Greater Granite Wash Composite

Missourian – Permian

Pennsylvanian

Marmaton Group

Lagonda Ss.

Verdigris Lst.

Tiawah Lst.

Taft Ss.

Inola Lst.

Bluejacket Ss.

Warner Ss.

Chelsea Ss.

Cherokee Group

Atoka Group Atoka Group

Morrow shale

Puryear sand

Keyes sand

Kearny 

 Fm.

Morrow Group

Morrowan Atokan Desmoinesian

Morrow Formation

Lower Upper

Purdy sand

Keyes sand

Thirteen Finger lime

Deese 

Group

Atoka Shale

Dornick Hills 

 shale

Primrose Ss.

Dornick Hills Group

?

Thirteen Finger 

Limestone - Atoka 

Shale

256

271

300

304

308

311

318.1

 ± 1.3

299.0

± 0.8

251.0

 ± 0.4

System

Series Guada- lupian Leonar- dian Wolfcampian Missourian Virgilian

Age, Ma

Hugoton

Embayment

Kansas

Northern

Anadarko

Basin

Southern

Anadarko

Basin

AU

names

Ochoan

Permian

Cloud Chief Formation Big Basin Formation

Day Creek Dolomite

Whitehorse Fm. Whitehorse Group

Nippewalla Group El Reno Group

Sumner

Group

Stone Corral Fm.

Ninnescah Fm.

Wellington Fm.

Enid

Group

Hennessey Sh.

Chase Group

Council Grove Group

Admire Group

Wabaunsee Group

Shawnee Group

Topeka Lst.

Douglas Group

Oread Lst.

Lansing Group

Kansas City 

 Group

Pleasanton Group

Kansas City Gp.

Dewey Lst.

Hogshooter Lst.

Dodds Creek Ss.

Checkerboard Lst.

Garber Ss.

Pontotoc 

 Group

Ada Group

Vamoosa Group

Hoxbar 

 Group

CH2_Fig3

Wellington Fm. Wellington Fm.

Stone Corral Fm.

Chase Group

Council Grove Group

Admire Group

Wabaunsee Group

Douglas Group

Lansing Group

Marmaton Group

Pumpkin 

Creek

Limestone

Desmoinesian MorrowanAtokan Morrowan- Atokan
References Cited 5

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References Cited

Bebout, D.G., White, W.A., Hentz, T.F., and Grasmick, M.K., 

eds., 1993, Atlas of major mid-continent gas reservoirs: 

Bureau of Economic Geology, 85 p.

Gradstein, F.M., Ogg, J.G., Smith, A.G., Bleeker, Wouter, 

Lourens, L.J., 2004, A new geologic time scale with special 

reference to Precambrian and Neogene: Episodes, June 

2004, v. 27, no. 2, p. 83–100.

Haq, B.U., and Van Eysinga, F.W.B., 1998, Geological time 

table: Elsevier Science, Amsterdam, New York, 1 chart.

Henry, M.E., and Hester, T.C., 1995, Anadarko Basin Province (058), in Gautier, D.L., Dolton, G.L., Takahashi, K.I., 

and Varnes, K.L., eds., 1995 National assessment of United 

States oil and gas resources on CD-ROM: U.S. Geological Survey Digital Data Series 30, 51 p., accessed April 20, 

2011, at http://energy.cr.usgs.gov/oilgas/noga/1995.html.

Higley, D.K., Gaswirth, S.B., Abbott, M.M., Charpentier, 

R.R., Cook, T.A., Ellis, G.S., Gianoutsos, N.J., Hatch, 

J.R., Klett, T.R., Nelson, Philip, Pawlewicz, M.J., Pearson, 

O.N., Pollastro, R.M., and Schenk, C.J., 2011, Assessment 

of undiscovered oil and gas resources of the Anadarko 

Basin province of Oklahoma, Kansas, Texas, and Colorado, 2010: U.S. Geological Survey Fact Sheet 2011–3003, 

2 p., accessed February 2011, at http://pubs.usgs.gov/

fs/2011/3003/.

Chapter 3

Thermal Maturation of Petroleum Source 

Rocks in the Anadarko Basin Province, 

Colorado, Kansas, Oklahoma, and Texas

By Debra K. Higley

Chapter 3 of 13

Petroleum Systems and Assessment of Undiscovered Oil and Gas 

in the Anadarko Basin Province, Colorado, Kansas, Oklahoma, and 

Texas—USGS Province 58

Compiled by Debra K. Higley

U.S. Geological Survey Digital Data Series DDS–69–EE

U.S. Department of the Interior

U.S. Geological Survey

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Volume Title Page
U.S. Department of the Interior

SALLY JEWELL, Secretary

U.S. Geological Survey

Suzette M. Kimball, Acting Director

U.S. Geological Survey, Reston, Virginia: 2014

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Suggested citation:

Higley, D.K., 2014, Thermal maturation of petroleum source rocks in the Anadarko Basin Province, Colorado, Kansas, 

Oklahoma, and Texas, chap. 3, in Higley, D.K., compiler, Petroleum systems and assessment of undiscovered oil and 

gas in the Anadarko Basin Province, Colorado, Kansas, Oklahoma, and Texas—USGS Province 58: U.S. Geological 

Survey Digital Data Series DDS–69–EE, 53 p., http://dx.doi.org/10.3133/ds69EE.

ISSN 2327-638X (online)
iii

Contents

Abstract...........................................................................................................................................................1

Introduction.....................................................................................................................................................1

Petroleum System Modeling Methodology...............................................................................................5

Geologic Setting.............................................................................................................................................9

Structural History..................................................................................................................................9

Petroleum Source Rocks............................................................................................................................15

Ordovician Source Rocks..................................................................................................................16

Devonian-Mississippian Woodford Shale ......................................................................................17

Mississippian Source Rocks.............................................................................................................19

Pennsylvanian Source Rocks ...........................................................................................................20

Petroleum System Model of the Anadarko Basin ..................................................................................21

Petroleum Generation Kinetics ........................................................................................................21

Burial History.......................................................................................................................................30

Petroleum Migration and Accumulation..................................................................................................41

Secondary Migration of Hydrocarbons ..........................................................................................41

Tertiary Migration of Hydrocarbons ................................................................................................45

Conclusions...................................................................................................................................................47

Acknowledgments.......................................................................................................................................47

References Cited..........................................................................................................................................47

Figures

1. Map showing Anadarko Basin Province (dashed line) and boundaries of total

petroleum systems (TPS) and assessment units (AU). Only AUs that contain source

rocks are shown. The Woodford Shale is divided into the Woodford Shale Oil and

Woodford Shale Gas AUs based mainly on levels of thermal maturation and

formation thickness. The Desmoinesian and Missourian-Permian AUs share a

common boundary with the Pennsylvanian Composite TPS, with the exception that

the AUs exclude an area of the deep basin that is the Granite Wash Composite AU

(not shown). There are common boundaries for most AUs...................................................2

2. Generalized stratigraphic column for the Anadarko Basin Province with oil and gas

source rocks (brown text). Increases in source rock potential are indicated by

larger numbers. The expected hydrocarbons header indicates whether the source

rock is more oil or gas prone. Hatch (oral commun., 2010), and modified from

Burruss and Hatch (1989). Vertical lines show a generalized time range of

unconformity from Bebout and others (1993, fig. 5). Gp., Group; Fm., Formation...............3

3. Map showing basement heat flow contours across the Anadarko Basin based on

data from Carter and others (1998), Blackwell and Richards (2004), and data

downloads from the Southern Methodist University Web site

(http://smu.edu/geothermal/). Basin areas within and north of the Wichita

Mountain and Amarillo uplifts exhibit generally lower heat flows than other basin

areas. Highest measured heat flow is in the northwest, along the Las Animas arch.

The northwest trending Central Kansas uplift (CKU) also exhibits elevated heat flow

values. Contours are in milliwatts per square meter (mW/m2). Red fault lines are

from Adler and others (1971).......................................................................................................7
iv

4. Map showing formation temperatures on the top of the Woodford Shale model

layer. Cross section location is orange line on map. Black contour lines are

temperature on the Woodford Shale from Gallardo and Blackwell (1999). Formation

temperatures on the cross section are from ground surface to the Precambrian.

The red dot is location of the Woodford Shale layer. Elevation in meters is relative

to sea level. Purple fault lines are from Adler and others (1971)..........................................7

5. Map showing modeled Celsius (°C) temperatures on the top of the Wabaunsee

layer. Oklahoma (black) contour lines from Gallardo and Blackwell (1999) are

estimated temperatures on the top of the Pennsylvanian, which is roughly

analogous to the Wabaunsee elevation. Both sets of contours show general

increase in temperature with greater burial depth. Increasing depth with burial is

shown by the underlying Precambrian through Morrowan layers (red arrow). 3D

view is 10 times vertical exaggeration. Purple fault lines are from Adler and others

(1971)...............................................................................................................................................8

6. View to the southeast of elevation on the top of the Woodford Shale model layer is

from the two-dimensional WoodfordTft.DAT grid file (Higley and others, 2014) that

was created using Earthvision®. Vertical exaggeration is 18 times. Woodford

extent is approximated by the -12,000-foot elevation contour, although Woodford is

also present east of the Central Kansas uplift (CKU). Major structures are labeled.

Precambrian faults (red) are from Adler and others (1971). Wichita Mountain uplift

bounding faults are vertical for four-dimensional model purposes only, and the

Woodford Shale surface in this area is unknown because of insufficient data. Data

sources for this surface include Woodford picks from well logs, Rottmann (2000a,

2000b), and edited IHS Energy (2009a, 2009b) formation tops.............................................10

7. View to the southeast showing Woodford Shale layer lithofacies. Vertical

exaggeration is 18 times. View orientation is similar to the 1-kilometer grid spacing

Earthvision® image (fig. 6). This PetroMod® image shows underlying and lateral

facies changes for the Woodford Shale layer, which is shown in white. Lateral

lithofacies within the Woodford layer are primarily limestone and dolomite of the

Viola Group. Because the purpose of this image is to show lateral changes in

lithofacies assignments on a model layer, this information is generalized in the

explanation and not all listed formations are visible. The southern half of the

Kansas Woodford has almost 0 meter thickness and represents grid extrapolation

between the northeast Kansas and Oklahoma extents. Vertical yellow bars are

faults from Adler and others (1971). CKU, Central Kansas uplift; lst, limestone; sh,

shale; U, upper; L, lower............................................................................................................11

8. View to the southeast of elevation on the top of the Desmoinesian layer (Higley and

others, 2014, DesmoinesianTft.DAT grid file). Vertical exaggeration is 18 times.

Major structures are labeled. CKU is Central Kansas uplift. Precambrian faults (red)

are from Adler and others (1971). Wichita Mountain and Amarillo uplift faults are

vertical for three-dimensional Earthvision® model purposes only, and presence of

the Desmoinesian in this area is unknown because of insufficient data. Data

sources for this surface include picks from well logs and edited IHS Energy (2009a,

2009b) well formation tops. Elevation is relative to sea level..............................................13

9. Map showing thickness of strata between the Hunton Group and Desmoinesian

layers ranges from less than 500 meters over most of the Kansas shelf to more than

5,000 meters in the deep basin of Oklahoma. This wedge of units is oriented

northwest-southeast. Precambrian faults (blue lines) and named structures are

from Adler and others (1971). The north-south red line is the general location of the

figure 10 image............................................................................................................................14
v

10. Cube dissection of the four-dimensional petroleum system model shows

present-day elevation on the Desmoinesian layer surface; color variations on the

Desmoinesian correspond to lithologies from Adler and others (1971). Vertical color

bands represent lithofacies assignments for the Desmoinesian through

Precambrian layers. For example, the labeled Mississippian layer is about 900

meters (2,900 feet) thick at the location. Location of the slice is in figure 9. Vertical

exaggeration is 15 times............................................................................................................14

11. Map showing vitrinite reflectance (R

o

) contours for the Woodford Shale; black line

contours are in increments of 0.4% R

o

. Generation stages on R

o

 legend are

generalized, as gas generation also occurs within the oil generation range. Black

triangles and white dots include R

o

 data from Cardott (1989; written commun.,

2011), Price (1997), and Mark Pawlewicz (written commun., 2010). Labeled white

dot well locations are (1) Bertha Rogers 1, (2) Petree Ranch 1, (3) West Edmond

SWD 1-24, and (4) Streeter 1. Brown lines are faults in the underlying Hunton Group

(Rottmann, 2000a, pl. 3)..............................................................................................................15

12. Cross section showing the Woodford Shale (WDFD, blue line) and terminus of the

Morrow Group (MRRW) and overlying Thirteen Finger Limestone portion of the

Atoka Group (ATOKA, gold line) in the deep Anadarko Basin. Line of section is

shown in figure 13. Vertical scale is in feet relative to the top of the WDFD. MRMT

is Marmaton Group, CHRK is Cherokee Group, MSSP is Mississippian, HNTN is

Hunton Group, SLVN is Sylvan Shale, VIOL is Viola Group, and SPRG, CSTR, and

MRMC are the respective Mississippian Springer Formation, Chester Group, and

Meramec lime. Labeled well log traces are gamma (0 to 200 API), resistivity, sonic

density, neutron density, spontaneous potential, and density............................................18

13. Three-dimensional isopach image of the Woodford Shale in the Anadarko Basin.

Vitrinite reflectance (% R

o

) contours (white lines) from figure 11 approximate end of

oil generation at 1.2% R

o

 to overmature for petroleum generation (4% R

o

). White dot

well locations are, from left to right, Bertha Rogers 1, Petree 1, and Streeter 1.

Dashed white line is location of figure 12 cross section. Woodford thickness is

derived from Rottmann (2000b, pl. 2), analysis of more than 100 well logs, and

edited formation tops from IHS Energy (2009a, 2009b). Faults (red) are from

Rottmann (2000a, pl. 3). Image is tilted and 1,300 times vertical exaggeration................19

14. Map showing total organic carbon (TOC) content in weight percent (wt%) for the

Woodford Shale based on TOC data from Burruss and Hatch (1989) and mean

values from Hester and others (1990). TOC ranges from 0.08 to 14.05 wt% and

averages 3.7 wt% for core and well log density calculations from 123 wells. There

is considerable TOC variation, but almost the entire area that is thermally mature

for petroleum generation contains greater than 2 wt% TOC. Oil and gas generation

depletes TOC and HI (hydrogen index), the fuels for petroleum, so original TOC 

and HI values would have been greater. Red lines are faults from Adler and others 

(1971).............................................................................................................................................20

15. View to the southeast of elevation on the top of the Thirteen Finger limestone layer

(Higley and others, 2014, ThirteenFingerTft.DAT grid file). Vertical exaggeration is

18 times. Thirteen Finger lime extent is approximated by the light blue line. Major

structures are labeled. Precambrian faults (red) are from Adler and others (1971).

Wichita Mountain uplift faults are vertical for four-dimensional model purposes

only, and surface in this area is unknown because of insufficient data. Data

sources for this surface include Thirteen Finger limestone picks from well logs and

edited IHS Energy (2009a, 2009b) formation tops. Elevation is relative to sea level.

CKU, Central Kansas uplift ........................................................................................................22
vi

16. Isopach map of the top of the stratigraphic interval from the Thirteen Finger

limestone to the Morrow Formation, based on Andrews (1999a, b), examination of

more than 120 well logs, and edited tops from IHS Energy (2009a, 2009b). Morrow

Formation faults (green) are modified from Andrews (1999b). Color contour interval

is 20 feet and (black) line contours are 10-feet intervals. Figure 17 cross sections

are labeled A-A’ and B-B’. White polygons are Perryton (Texas) and Knowles

Northwest (Oklahoma Panhandle) oil fields...........................................................................23

17.A, Southwest to northeast and B, southeast to northwest cross sections of the

Thirteen Finger limestone (TRFG) of the Pennsylvanian Atoka Group (ATOKA) in the

Anadarko Basin. Lines of section are shown in figure 16. Vertical scale is feet

relative to the base of the Thirteen Finger. MRMT is Marmaton Group, CHRK is

Cherokee Group, MRRW is Morrow Group, and MSSP is top of the Mississippian.

Labeled well log traces are gamma (0 to 200 American Petroleum Institute [API]

range), resistivity, sonic density, and neutron density .........................................................24

18. Graphic showing comparison of calculated vitrinite reflectance (% R

o

) and

transformation ratios (TR) using Woodford Shale and Phosphoria kinetic algorithms

from Lewan and Ruble (2002), gas generation from coals based on Pepper and

Corvi (1995a, 1995b), and dry gas generation using Tsuzuki and others (1999).

Calculations are for the Bertha Rogers 1 and Petree Ranch 1 wells shown on figure

11. Woodford hydrous pyrolysis (HP) TR of onset- (0.1percent) to-completion of oil

generation (99 percent) correlates to a range of about 0.6 to 1.2% R

o

; Woodford

Rock Eval pyrolysis (REV) TR range is much broader at approximately 0.4 to 2.6% Ro

, and Phosphoria HP TR onset and completion are about 0.4 to 0.8% R

o

. Woodford

REV TR is at 81 percent when the HP TR has completed at 100 percent. Pepper and

Corvi (1995a, 1995b) kinetics provides a range of gas generation from 0.55 to 3.0% Ro

 from the Type III kerogen in coals. Basin heating rate of 5 °C/m.y. was based on

the Bertha Rogers 1 well; present-day geothermal gradient is 21.3 °C/km to the

Woodford (19 °C surface and 200 °C Woodford temperature at 8,486.5-meter depth)...27

19. Graph showing depth distribution of wet and dry gas in the Anadarko Basin and of

1D vitrinite reflectance (% R

o

) profiles for the Bertha Rogers 1 and Petree Ranch 1

wells (fig. 11). Depth range for end of oil generation to start of dry gas generation

for the one-dimensional wells is about 3,200 to 5,000 meters. Increase in dry gas

fraction and decrease in scatter below 5,000 meters indicates gas is becoming

progressively dryer for these samples, with 1.0 being 100 percent methane. Gas

data are from the Energy geochemistry data base (U.S. Geological Survey, 2010).

The blue symbols are mostly Colorado and Kansas wells. Oklahoma and Texas

wells were selected for detailed study because Colorado and Kansas portions of

the province are thermally immature for gas generation. Light blue background is a

generalized boundary for gas distribution..............................................................................28

20. Burial history curves for the Bertha Rogers 1 and Petree Ranch 1 wells. Modeled

vitrinite reflectance (percent Ro) through time includes heat flow of about 68

milliwatts per square meter (mW/m

2

) to 260 million years ago (Ma) followed by 42

mW/m

2

 for Bertha Rogers 1, and 68 mW/m

2

 to 260 Ma followed by 52 mW/m

2

 for

Petree Ranch 1. Pale-yellow and blue lines follow the Thirteen Finger limestone

and Woodford Shale, respectively. Gp., Group; Lst., Limestone; Ord., Ordovician;

Sil., Silurian, Neog., Neogene...................................................................................................29
vii

21. Burial history transformation ratios (TR) for the Bertha Rogers 1 well based on

Woodford Shale hydrous pyrolysis (HP) kinetics (Lewan and Ruble, 2002). Depth

compared to temperature and vitrinite reflectance profiles are calibrated at (1) 40

milliwatts per square meter (mW/m

2

) heat flow (HF) through time, and (2) 70

mW/m

2

 to 260 million years ago (Ma) followed by 42 mW/m

2

 to present. Woodford

Shale interval is marked with the blue line and the Thirteen Finger limestone by

the gold line. Vitrinite reflectance (% R

o

) calibration data are from Price (1997).

Temperature dots are corrected bottom hole temperatures (BHT) from Gallardo and

Blackwell (1999, fig. 8) and bars show range from measured to maximum estimated

BHT. Gp., Group; Ord., Ordovician; Sil., Silurian, Neog., Neogene .....................................31

22. Burial history for the Bertha Rogers 1 well based on Phosphoria Formation hydrous

pyrolysis (HP) kinetics (Lewan and Ruble, 2002). Depths are shown relative to

calculated porosity, lithostatic, pore, and hydrostatic pressure; light blue line is

hydrostatic pressure of 9,800 Pascals/meter (MPa/m) (0.465 psi/ft). Yellow band is

probable zone of overpressure based on Al-Shaieb and others (1994). Woodford

Shale interval is marked with the blue line and the Thirteen Finger limestone by the

gold line. Ord., Ordovician; Sil., Silurian, Neog., Neogene...................................................32

23. Burial history for the Petree Ranch 1 well based on Woodford Shale and

Phosphoria Formation hydrous pyrolysis (HP) kinetics (Lewan and Ruble, 2002).

Model is calibrated using 68 milliwatts per square meter (mW/m

2

) heat flow to 260

million years before present (Ma), then 52 mW/m

2

 to present. Woodford Shale

interval is marked on the transformation ratio (TR) charts with the blue line, and the

Thirteen Finger limestone by the gold line. Vitrinite reflectance (% R

o

) calibration

data are from Pawlewicz (1989) (brown dots) and Woodford Shale estimates from

Cardott (1989) (yellow and red dots). Temperature data from Pawlewicz (1989, table

2) (blue dots and connecting line) were calculated based on 1.3 °F increase per

100 feet depth from a 15 °C (60 °F) surface temperature. The corrected bottom hole

temperature (BHT) (yellow dot) was derived using Gallardo and Blackwell (1999,

fig. 7). Ord., Ordovician; Sil., Silurian, Neog., Neogene........................................................33

24. Graph showing history of generation of oil from the Oil Creek Formation, Woodford

Shale, and Thirteen Finger limestone sources in the four-dimensional petroleum

system model based on Woodford Shale HP kinetics. Gray bars delineate periods

of peak oil generation. Early oil generation from the Oil Creek layer, prior to about

70 million years before present (Ma), is in a narrow band that is proximal to the

Wichita Mountain uplift. This band exceeds maximum depth of the formation and is

the result of poor data control in the area bordering the fault zone. The error could

have been removed by clipping the four-dimensional model extent to the basin axis

and northward, but less of the model would have been visible and usable.....................35

25. South to north cross sections of thermal maturation using Woodford

transformation ratio (TR) at present (0 Ma) and at 300 million years before present

(Ma). The inset shows the location of these extracts from the four-dimensional

model. Yellow and pink dots are approximate locations of the Woodford Shale and

Thirteen Finger limestone, respectively. Elevation is relative to sea level, and

vertical and lateral scales are equivalent for the cross sections. Map image is TR

on the Woodford Shale layer at 0 Ma and at 10 times vertical exaggeration. Red

line is the approximate location of the cross section...........................................................37
viii

26. Images showing present-day vitrinite reflectance (% R

o

) on Ordovician to Virgilian

model layers (fig. 2), using Sweeney and Burnham (1990) kinetics. Changes in

thermal maturity on the shelf areas of Kansas and Colorado are minor and source

rocks are mostly immature for oil generation at less than 0.6% R

o

. Thermal maturity

for source rocks in the deep basin of Oklahoma and Texas ranges generally from

mature for oil generation to overmature for gas generation at about 4% R

o

 and

greater. Red contour lines mark the 99 percent transformation ratio for each layer;

it is approximately equivalent to 1.2% R

o

. Precambrian faults (Adler and others,

1971) are shown as blue lines...................................................................................................38

27. Images showing transformation ratios (TR) through time on tops of the Oil Creek,

Woodford Shale, and Thirteen Finger Limestone layers. Ten times vertical

exaggeration results in variable shading within contours. Onset of oil generation

was about 370 million years ago (Ma) (Oil Creek), 330 Ma (Woodford), and 300

Ma (Thirteen Finger) based on modeled vitrinite reflectance and 0.1 percent

TR. Completion of oil generation is indicated by 99 percent TR. Source rocks

are overmature for oil generation at greater than 99 percent TR (medium gray).

Precambrian faults (Adler and others, 1971) are shown as blue lines ..............................39

28. Map and rotated three dimensional images of modeled petroleum migration

catchments on the Thirteen Finger limestone layer. Layer boundaries extend

across the images but catchments represent greater than zero meter thickness

for the Thirteen Finger limestone. Oil and gas flow paths are compartmentalized

within each catchment until a change in lithofacies or structure results in

petroleum accumulations or loss to bounding formations. The “cluttered”

compartments on the west represent more complex flow and are represented on

flow path maps as broken lines or groups of rays. Olive green lines and vertical

bars are Precambrian faults of Adler and others (1971)......................................................41

29. Two views of modeled oil (green) and gas (red) flow path lines, and oil (yellow)

accumulations for the Thirteen Finger limestone. Layer shown in dark gray on three

dimensional map view is the top of the Morrow Group layer. The gray space in the

deep basin that is devoid of oil flow paths is the area that is mature for gas

generation from the Thirteen Finger limestone. Inset image is a rotated view at 10

times vertical exaggeration ......................................................................................................42

30. Images showing oil migration flow paths from 320 to 40 million years ago (Ma).

Blank migration areas can indicate no migration, (invisible) Darcy flow through

lithofacies, or overmaturity for petroleum generation. Hunton Group facies from

Howery (1993) are delineated by orange lines for limestone (Darcy flow area) and

dolomite (flow path migration). Onset of oil generation preceded migration from the

Oil Creek Formation layer source rocks (light green), which started about 340 Ma.

This was followed by Woodford Shale oil generation about 335 Ma, then the

Thirteen Finger limestone (blue) about 300 Ma. Lst, limestone. Maroon lines are

Precambrian faults of Adler and others (1971)......................................................................43

31. Image showing present-day oil and gas migration flow paths. Blank migration

areas indicate no migration, (invisible) Darcy flow through lithofacies, or

overmaturity for petroleum generation. Oil migration flow paths from mostly Oil

Creek layer source rocks (light green) are overlain by mostly Woodford Shale (dark

green), and then Thirteen Finger limestone (blue) flow paths. Gas (red) flow paths

are not differentiated by source rocks. Maroon lines are the fault system from

Adler and others (1971)..............................................................................................................45
ix

Tables

1. Anadarko Basin Province assessment results are listed by name and code of total

petroleum system (TPS) and assessment unit (AU)................................................................4

2. Summary of kinetic parameters derived for expelled-oil generation based on

hydrous pyrolysis (HP) in isothermal experiments, and nonisothermal open-system

pyrolysis (REV) that were derived from Lewan and Ruble (2002, tables 4 and 5) and

cracking of oil to gas (Tsuzuki and others, 1999). The Woodford Shale analyses

were on an unweathered, thermally immature sample that contained 12.7 percent

total organic carbon (TOC), from section 25, T. 2 S., R. 1 E., Carter Co., Oklahoma

(Lewan, 1983)...............................................................................................................................23

3. Onset of oil generation in the Anadarko Basin 4D model, and onset and completion

dates in millions of years before present (Ma) for the Bertha Rogers 1 and Petree

Ranch 1 one-dimensional models based on Woodford Shale hydrous pyrolysis (HP)

kinetics (Lewan and Ruble, 2002). The Douglas Group overlies the youngest

potential petroleum source rocks on figure 2. The (HP) kinetics-based onset of oil

generation is 0.1 percent transformation ratio (TR) and completion is 99 percent

TR. Oil generation histories in the four-dimensional model were recorded at 10 Ma

increments, and the plus symbol indicates onset was before the listed age ..................35

32. Images showing modeled gas (red) and oil accumulations at 300 million years

before present (Ma) and present day for above named layers. Some major oil and

gas fields are outlined and labeled. Brown lines are the Precambrian fault system

from Adler and others (1971); the purple lines north of this fault system are modeled

locations of the Wichita Mountain uplift at 200 Ma and at present. Accumulations

preferentially form on large structures, such as the Cement field, and updip

pinchout of reservoir layers against seal layers, such as for the Hunton Group

accumulations in northeast Oklahoma. Stratigraphic traps are commonly not filled

in this leaky four-dimensional model because of the coarse grid size and lithologic

assignments.................................................................................................................................46

Abstract

Petroleum source rocks are thermally mature for oil 

and gas generation across most of the Anadarko Basin in 

Oklahoma and Texas based on one-dimensional and fourdimensional petroleum system models. Three petroleum 

source rocks were defined in the four-dimensional model. 

They are the Oil Creek Formation of the Ordovician Simpson 

Group, the Devonian-Mississippian Woodford Shale, and 

the informal Thirteen Finger limestone of the Pennsylvanian 

Atoka Group. Modeled onset of oil generation in the basin 

was about 370 million years ago for the Oil Creek Formation, 

330 million years ago for the Woodford Shale, and 300 million 

years ago for the Thirteen Finger limestone. The deep basin of 

Oklahoma and Texas is thermally mature for gas from Atokan 

and older source rocks. Deep basin areas that are overmature 

for gas generation are within the gas preservation window, as 

indicated by gas production from Woodford and older formations in this area, and on modeled levels of thermal maturation. Almost all of the Colorado and Kansas portions of the 

basin are thermally immature for petroleum generation. However, Mississippian and older source rocks may be marginally 

mature to mature for oil generation in the Las Animas arch of 

southeastern Colorado based on calculated vitrinite reflectance 

and transformation ratios from a four-dimensional petroleum 

system model. 

Oil and gas migration pathways were mainly radially 

northward from the deep basin in Oklahoma and proximal 

Texas, and north and west from the Texas Panhandle. Petroleum was further funneled by local structures. The Nemaha 

uplift in central Oklahoma was a barrier that limited eastward 

migration. Northward flow was diverted toward the Pratt anticline and Central Kansas uplift in south-central Kansas, and to 

the northwest Hugoton embayment. Decrease in burial pressure associated with the Laramide uplift and erosion resulted 

in a probable volume increase of gas that displaced oil in 

reservoirs with subsequent renewed gas migration. Evidence 

for this includes Permian gas reservoirs of the southern Central Kansas uplift and Pratt anticline areas, and the Hugoton 

embayment gas fields. 

Thermal Maturation of Petroleum Source Rocks in the 

Anadarko Basin Province, Colorado, Kansas, Oklahoma, 

and Texas

By Debra K. Higley

Introduction

The U.S. Geological Survey (USGS) recently completed 

an assessment of the undiscovered oil and gas resource potential of the Anadarko Basin Province of western Oklahoma and 

Kansas, northern Texas, and southeastern Colorado (fig. 1). 

This is hereafter referred to as the 2011 assessment, which 

corresponds to the publication release date of the assessment 

results (Higley and others, 2011). This province area includes 

the Anadarko Basin, Las Animas arch, and a portion of the 

Palo Duro Basin. Stratigraphic units range in age from Precambrian to present, and petroleum is produced from Cambrian through Permian strata. Mesozoic strata are absent over 

most of the basin, being limited primarily to the Colorado and 

Kansas portions. The Cretaceous Niobrara Formation is productive near the northwestern boundary of the basin, but this 

biogenic methane resource was included in the Denver Basin 

assessment (Higley and Cox, 2007; Higley and others, 2007). 

Figure 1 shows the province boundary and labeled total 

petroleum systems (TPS) and assessment units (AU). Total 

petroleum systems and included AUs are defined in Magoon 

and Dow (1994). The TPS concept basically incorporates 

hydrocarbon source rocks (source-rock maturation, hydrocarbon generation, migration, and accumulation), reservoir rocks 

(sequence stratigraphy and petrophysical properties), and 

hydrocarbon traps (trap formation, timing, and seals) whose 

provenance is a pod or closely related pods of active source 

rock. The TPS is basically a hydrocarbon fluid system that 

links petroleum source rocks, migration pathways, and real 

and (or) hypothetical oil and gas accumulations. An AU within 

a TPS is defined as a mappable volume of strata that incorporates petroleum accumulations (discovered and undiscovered) 

that have the same hydrocarbon source rock(s), and similar 

geologic and economic factors that control oil and (or) gas 

entrapment, exploration, and development. These accumulations should therefore be sufficiently homogeneous in terms 

of geology, exploration strategy, and risk so that the chosen 

method of resource assessment is applicable. A TPS might 

contain a single or multiple AUs, depending on whether differences are sufficient to warrant separation. Assigning AUs is 
2 Thermal Maturation of Petroleum Source Rocks in the Anadarko Basin Province, Colo., Kansas, Oklahoma, and Texas

also based on the quality and availability of petroleum source, 

reservoir, well history, and production data. Each AU can 

incorporate several exploration plays that are based on different reservoir formations, trap types, exploration strategies, and 

discovery histories.

The Anadarko Basin Province includes two TPSs that 

include nine conventional and three continuous AUs (Higley and others, 2011). The stratigraphic column in the basin 

(fig. 2) lists Ordovician through Pennsylvanian shales and 

limestones that are petroleum source and potential source 

rocks. The Woodford Composite TPS encompasses Ordovician 

through Mississippian petroleum source rocks and is named 

for the principal source rock. The Pennsylvanian Composite 

TPS includes the remaining petroleum source rocks. Reasoning behind this generalized TPS division is that geochemical 

research in the basin has been focused on the Woodford Shale, 

with lesser information on other possible petroleum source 

rocks. Continuous AUs are the Woodford Shale Gas and 

Woodford Shale Oil of the Woodford Composite TPS, and the 

Thirteen Finger Limestone–Atoka Shale of the Pennsylvanian 

Composite TPS. The AU assignments and associated codes are 

listed below; they are based primarily on (1) the lateral extent 

and thickness of associated reservoir and petroleum source 

formations, (2) timing and degree of thermal maturation of 

potential contributing petroleum source rocks, (3) oil and gas 

generation and migration pathways through time based on 

4D petroleum system modeling of the basin, and (4) faults 

and other structures that would limit or enhance oil and gas 

accumulations. Results of the oil, gas, and natural gas liquids 

(NGL) assessment are listed in table 1. 

Figure 1. Map showing Anadarko Basin Province (dashed line) and boundaries of total 

petroleum systems (TPS) and assessment units (AU). Only AUs that contain source rocks 

are shown. The Woodford Shale is divided into the Woodford Shale Oil and Woodford 

Shale Gas AUs based mainly on levels of thermal maturation and formation thickness. 

The Desmoinesian and Missourian-Permian AUs share a common boundary with the 

Pennsylvanian Composite TPS, with the exception that the AUs exclude an area of the deep 

basin that is the Granite Wash Composite AU (not shown). There are common boundaries for 

most AUs.

Pennsylvanian 

Composite TPS

Woodford 

Composite TPS

Thirteen Finger 

Limestone-Atoka 

Shale Gas Woodford 

Shale Oil

MissourianPermian

Desmoinesian

MorrowanAtokan

Woodford Shale 

Gas

Mississippian

Viola Group

Simpson Group

104° 103° 102° 101° 100° 99° 98° 97° 

39°

38°

37° 

36° 

35° 

34°

33°

0 50 100 MILES

0 50 100 KILOMETERS

GULF 

OF 

MEXICO

TEXAS

NEW

MEXICO

COLORADO KANSAS

OKLAHOMA

Anadarko 

 Basin 

 Province

OKLAHOMA

KANSAS

COLORADO

NEW MEXICO

TEXAS

Figure 1, chapter 3
Introduction 3

Figure 2. Generalized stratigraphic column for the Anadarko Basin Province with oil and gas source rocks (brown text). Increases in 

source rock potential are indicated by larger numbers. The expected hydrocarbons header indicates whether the source rock is more 

oil or gas prone. Hatch (oral commun., 2010), and modified from Burruss and Hatch (1989). Vertical lines show a generalized time range 

of unconformity from Bebout and others (1993, fig. 5). Gp., Group; Fm., Formation.

Sumner Gp; Enid Gp.; Hennessey Gp.

System

Series Lithostratigraphic Unit

(HC Source Rocks in Red)

Expected

Hydrocarbons

Relative HC

Source Rock

Potential (1-5)

Permian (part) Pennsylvanian Mississippian Devonian Silurian Ordovician Cambrian (part)

Leonardian

Wolfcampian

Virgilian

Missourian

Desmoinesian

Atokan

Morrowan

Chesterian

Meramecian

Osagean

Kinderhookian

Chautauquan

Cayugan

Cincinnatian

Trempealeauan

Niagaran

Canadian

Champlainian

Chase Group

Council Grove Group

Admire Group

Lansing Group

Kansas City Group 

Marmaton Group

Cherokee Group

Atoka Gp.; Thirteen Finger limestone 

Morrow Gp./Fm.; lower Dornick Hills Gp.

Springer Formation

Chester Group 

Wabaunsee Group

Shawnee Group

Douglas Group

Ada Group

Franconian

Woodford Shale, Chattanooga Shale

Misener sand

Hunton Group

Sylvan Shale; Maquoketa Shale 

Simpson Group

Arbuckle Group

Reagan Sandstone

Alexandrian

Senecan

Pontotoc Group

Viola Group/Formation

Meramec lime

Osage lime

Mayes Group

Hoxbar Group

Deese Group

??

2

5 +

2

?

Kinderhook Shale

Erian

Ulsterian

1-2

1-2

1-2

2-3

1-2

1-2

Gas

Gas Oil

Gas Oil

Oil

Oil

Gas

Gas

Oil

Gas Oil

Gas Oil

Gas Oil

Gas Oil
4 Thermal Maturation of Petroleum Source Rocks in the Anadarko Basin Province, Colo., Kansas, Oklahoma, and Texas

Table 1. Anadarko Basin Province assessment results are listed by name and code of total petroleum system (TPS) and assessment 

unit (AU).

[Resources are undiscovered oil, gas, and (or) natural gas liquids. MMBO, million barrels of oil; BCFG, billion cubic feet of gas; MMBNGL, million barrels 

of natural gas liquids. Type refers to mainly oil or gas accumulations in the AU. Fractiles are fully risked estimates. F95 denotes a 95-percent chance of at least 

the amount tabulated. F50 and F5 fractiles are defined similarly. Fractiles are additive only under the assumption of perfect positive correlation. Gray shading 

indicates not applicable]

Total Petroleum Systems 

(TPS) and Assessment Units 

(AU)

Field 

Type

Total Undiscovered Resources

Oil (MMBO) Gas (BCFG) NGL (MMBNGL)

F95 F50 F5 Mean F95 F50 F5 Mean F95 F50 F5 Mean

Woodford Composite TPS

Arbuckle-Ellenburger AU

Oil 2 5 12 6 7 24 61 28 0 1 2 1

Gas 43 164 371 181 0 1 2 1

Simpson Group AU

Oil 2 4 9 5 6 17 39 19 0 0 1 1

Gas 33 114 252 125 2 9 21 10

Viola Group AU

Oil 2 5 10 5 3 9 20 10 0 1 2 1

Gas 10 27 58 30 0 0 0 0

Hunton Group AU

Oil 2 8 21 9 8 32 87 38 0 1 3 1

Gas 71 281 641 310 0 2 4 2

Mississippian AU

Oil 5 16 31 17 15 46 99 50 0 2 4 2

Gas 125 350 663 367 3 8 17 9

Pennsylvanian Composite TPS

Morrowan-Atokan AU

Oil 6 14 29 15 21 55 121 61 1 2 5 2

Gas 101 261 469 271 2 5 10 5

Desmoinesian AU

Oil 2 6 12 6 8 23 52 26 0 1 2 1

Gas 29 87 167 92 1 3 5 3

Missourian-Permian AU

Oil 10 22 38 23 49 114 223 122 2 4 8 4

Gas 61 130 231 136 2 4 7 4

Greater Granite Wash 

Composite AU

Oil 4 14 34 16 22 78 198 90 1 2 7 3

Gas 192 646 1,496 719 7 24 60 27

Total Conventional

 Resources 35 94 196 102 804 2,458 5,248 2,675 21 70 160 77

Woodford Composite TPS

Woodford Shale Oil AU

Woodford Shale Gas AU

Oil 175 357 730 393 795 1,750 3,851 1,963 22 51 121 59

Gas 8,806 15,131 25,998 15,973 94 178 336 192

Pennsylvanian Composite TPS

Thirteen Finger LimestoneAtoka Shale Gas AU

Oil

Gas 3,040 6,229 12,763 6,850 33 73 161 82

Total Continuous

 Resources 175 357 730 393 12,641 23,110 42,612 24,786 149 302 618 333

Total Resources 210 451 926 495 13,445 25,568 47,860 27,461 170 372 778 410
Petroleum System Modeling Methodology 5

Woodford Composite TPS 505801:

1. Arbuckle-Ellenburger, AU 50580101

2. Simpson Group, AU 50580102

3. Viola Group, AU 50580103

4. Hunton Group, AU 50580104

5. Mississippian, AU 50580105

6. Woodford Shale Gas, AU 50580161

7. Woodford Shale Oil, AU 50580162

Pennsylvanian Composite TPS 505802:

1. Morrowan-Atokan, AU 50580201

2. Desmoinesian, AU 50580202

3. Missourian-Permian, AU 50580203

4. Greater Granite Wash Composite, AU 50580204

5. Thirteen Finger Limestone–Atoka Shale Gas, AU 

50580261

Petroleum productive and potentially productive formations were divided into the two TPSs, with Ordovician 

through Mississippian source rocks mainly contributing 

to reservoirs of that age range, and Pennsylvanian source 

rocks to those of Pennsylvanian and Permian age reservoirs (fig. 2). The Hunton Group is not listed in figure 2 

as containing petroleum source rocks. Also, there is only 

limited evidence for source potential from the ArbuckleEllenburger AU (Burruss and Hatch, 1989; J. Hatch, oral 

communication, 2010). The TPS and AU divisions were also 

influenced by the accuracy and existence of well history and 

production data. For example, much of the Atokan petroleum production is reported commingled with Morrowan 

production. The Thirteen Finger Limestone–Atokan Shale 

Gas continuous AU is based largely on source rock potential 

based on Carr and Hentz (2009) and on low permeability and 

source rock potential from well log analysis. Source rock 

research and data have been focused on the Woodford Shale 

in the Anadarko and adjacent basins. Most of the vitrinite 

reflectance data in the Anadarko Basin is from Woodford 

Shale cores, well cuttings, and outcrop samples. The onedimensional (1D) and four-dimensional (4D) petroleum 

system models are preferentially calibrated to the Woodford 

Shale vitrinite reflectance data of Cardott (1989), Price 

(1997), and two wells in the Edmond West field (Chesapeake 

Energy [written communication, 2008] and Mark Pawlewicz 

[written communication, 2010] analyses). Source rock potential for other petroleum source rocks incorporate published 

research, vitrinite reflectance values from Pawlewicz (1989), 

and results of the 1D and 4D models of this study. 

Petroleum System Modeling 

Methodology

Petroleum system modeling is designed to recreate, 

through time, oil and gas generation, expulsion, migration, saturation, accumulation, and loss for included petroleum source 

and reservoir rocks, and at well to basin scales. The timing and 

extent of petroleum generation from each source rock requires 

kinetic parameters that relate the geologic time required for 

generation reactions to the burial temperatures of source 

rocks. Development and assignment of kinetic algorithms 

for the Woodford Shale and other petroleum source rocks 

are discussed in Lewan (1983, 1985) and Lewan and Ruble 

(2002). Created models show levels of thermal maturation and 

generation of oil and gas through time based on kinetic factors such as transformation ratios (TR) and levels of thermal 

maturity for source organofacies based on calculated vitrinite 

reflectance, TR, and other factors. 1D, two-dimensional (2D), 

and 4D models commonly integrate influences through time 

of (a) basal heat flow, (b) water depth, (c) surface temperature, 

(d) time and extent of deposition and erosion, (e) vertical and 

lateral lithologic properties within each layer, (f) profiles of 

lithofacies decompaction through time, and (g) geochemical characteristics for each source organofacies, such as total 

organic carbon (TOC) content and hydrogen index (HI). 

Maps and models were generated using Dynamic Graphics® Earthvision® (Dynamic Graphics® and Earthvision® 

are registered trademarks of Dynamic Graphics, Inc.) and 

PetroMod® software (Schlumberger, 2011). Schlumberger PetroMod® software was used for 1D and 4D petroleum system 

models. PetroMod® is pressure/volume/temperature (PVT) 

modeling software. The Anadarko 4D model incorporates flow 

path and Darcy flow migration that is referred to as hybridDarcy in PetroMod® documentation. Flow path migration of 

liquid and vapor components of petroleum and water is largely 

buoyancy-driven by hydrostatic pressure changes, whereas 

the Darcy flow is a multiphase process that uses gas diffusion 

and PVT to model migration. Structural relief on the top of the 

carrier (reservoir) layers is the primary control on migration 

pathways for oil and gas. Petroleum migration flow paths are 

vertical and lateral. When fluids and gases enter a reservoir or 

other permeable layer, the flow through the most permeable 

lithofacies is toward the top of the layer, and then laterally 

upward along the overlying seal layer. This seal layer can 

be breached by its thinning or lateral change to a permeable 

lithology, or the presence of an open fault system. Flow is then 

mostly vertical until the next seal is reached. These flow paths 

are more readily viewed than the more diffuse oil and gas 

Darcy flow within the reservoir layer. Oil and gas trapped as a 

result of accumulation or Darcy saturation in reservoirs does 

not further migration without a change in PVT conditions, 

such as uplift, erosion, open faults, or change in hydrodynamic 

flow. Modeling requirements, strengths, and weaknesses are 

discussed in Higley and others (2006). 
6 Thermal Maturation of Petroleum Source Rocks in the Anadarko Basin Province, Colo., Kansas, Oklahoma, and Texas

Faults associated with the Wichita Mountain, Amarillo, 

Nemaha, and Central Kansas (CKU) uplifts are modeled as 

closed through time (see fig. 3 for locations). Main potential 

effects of this are to decrease petroleum migration east of 

the Nemaha uplift and south of the Wichita Mountain and 

Amarillo uplifts, and to channel migration in areas such as the 

Pratt anticline and CKU. Faults along the northern boundaries 

of the Wichita Mountain and Amarillo uplifts are modeled as 

vertical, with only minimal horizontal offset from Precambrian 

to ground surface. Also critical to migration and accumulation 

is the proximity of reservoir strata to vertical and lateral seals 

and to thermally mature source rock. 

Petroleum system models were constructed using formation tops, lithologies, and ages of deposition and erosion from 

numerous sources. Data sources for the models include (1) 

formation top picks in more than 220 wells across the province, 

(2) IHS Energy (2009a, 2009b) and Kansas Geological Survey 

(2010, http://www.kgs.ku.edu/PRS/petroDB.html) formation 

tops, and (3) maps and data from Fay (1964), Rascoe and Hyne 

(1987), Robbins and Keller (1992), Cederstrand, and Becker 

(1998), Andrews (1999a, 1999b, 2001), and Rottmann (2000a, 

2000b). Formation ages and lithologies are commonly generalized and include Denison and others (1984), Ludvigson and 

others (2009), and the National Geologic Map Database (2011, 

http://ngmdb.usgs.gov/Geolex/). Figures within this chapter 

of the report may have feet or meters as vertical scales. This 

is because the 1D, 2D, and 4D petroleum system models have 

meters as the vertical scale, largely because of ease in using the 

modeling software. Vertical scale of most contour maps and of 

well-log cross sections are in feet because that is traditionally 

used in the United States. Tilted three-dimensional (3D) images 

generally do not have map scales because edges would have 

different scales, with the associated clutter.

4D petroleum system models consist of stacked layers 

of formations and groups of formations. The Anadarko Basin 

model contains 30 layers. Below are names of modeled layers 

that correspond generally to associated formation, group, and 

period names.

1. Surface 16. Atokan

2. OgallalaBase 17. Thirteen Finger

3. Cretaceous 18. MorrowU

4. Permian 19. MorrowM

5. Blaine 20. MorrowL

6. StoneCorral 21. Springer

7. Wellington 22. Woodford

8. Chase 23. Hunton

9. CouncilGrove 24. Sylvan

10. Wabaunsee 25. Viola

11. HeebnerT 26. SimpsonT

12. HeebnerB 27. Oil Creek

13. Douglas 28. SimpsonB

14. Desmoinesian 29. Arbuckle

15. Cherokee 30. Precambrian

Formations that compose each layer were grouped based 

on common petroleum system elements of reservoir, source, 

seal, overburden, or underburden. Assigned petroleum source 

rocks in the model are the Oil Creek, Woodford, and Thirteen 

Finger layers; these correspond generally to the petroleum 

source rocks in figure 2. All model layers extend across the 

study area, even if the included formation(s) has limited lateral 

extent. This is because of a software requirement that all grid 

cells be populated with numbers representing the structural 

elevation relative to sea level, or isopach thickness of zero 

or greater. The structural surface of layers is somewhat like a 

geologic map in that the extent of the modeled formation is 

shown, as well as any lateral subcropping formations. Some 

layers consist of one formation, such as for the Sylvan Shale, 

Hunton Group, Woodford Shale, Chase Group, and Blaine 

Formation, and others are compound, such as the Desmoinesian and Missourian layers. Selection of layer intervals was 

based mainly on the quality of formation tops data and their 

relative importance as source, reservoir, and seal units. 

X and Y axis grid spacing are 6 kilometers (km) for the 

4D basin models, primarily because of computer processing 

and display limitations. File sizes of these “simplified” 4D 

models can exceed 170 gigabytes. The coarse gridding results 

in somewhat pixilated graphic images. Spacing is 1 kilometer 

(km) for published grids (Higley and others, 2014) and as 

initial “pre-filtered” input of the 4D models. Intervals with 

their associated lithologic properties are homogenized at this 

6-km scale. A primary result of this homogenization is that 

most generated oil and gas is not trapped within but instead 

migrates outside the model; this lost petroleum is mainly along 

the northern extension of the model in Colorado and Kansas. 

Models for stratigraphic traps and those constrained by PVT 

history require more detailed lithologic assignments and closer 

grid spacing. 

A heat flow map (fig. 3) was assigned as basement heat 

flow in the 4D model. Variation in measured heat flow is probably greater than that shown, as is indicated by “bull’s eye” 

contours in areas of closer data control. There are areas in western Kansas that display minor change in heat flow; these result 

from fewer data points, and perhaps less variation than other 

map areas. Data sources for downhole temperature include 

Carter and others (1998), Gallardo and Blackwell (1999), Price 

(1997), and drillstem test and corrected borehole temperatures. 

These well data were used to calibrate 1D models, and were 

also compared to 4D model temperatures for further calibration. Shown on figures 4 and 5 are present-day modeled and 

measured temperatures on the Devonian-Mississippian Woodford and the Virgilian Wabaunsee layers. Model layers and 

datasets show trends of increasing temperature with burial and 

similar temperature values. Woodford layer contours show the 
Petroleum System Modeling Methodology 7

Figure 3. Map showing basement heat flow 

contours across the Anadarko Basin based on 

data from Carter and others (1998), Blackwell 

and Richards (2004), and data downloads from 

the Southern Methodist University Web site 

(http://smu.edu/geothermal/). Basin areas within 

and north of the Wichita Mountain and Amarillo 

uplifts exhibit generally lower heat flows than 

other basin areas. Highest measured heat flow 

is in the northwest, along the Las Animas arch. 

The northwest trending Central Kansas uplift 

(CKU) also exhibits elevated heat flow values. 

Contours are in milliwatts per square meter 

(mW/m2). Red fault lines are from Adler and 

others (1971). 

24

28

32

36

40

44

48

52

56

60

64

68

72

76

80

EXPLANATION

Heat Flow 

(mW/m2

)

103° 102° 101° 100° 99° 98° 97°

39°

38°

37°

36°

35°

COLORADO KANSAS NEW MEXICO

CKU Las Animas arch

Wichita 

Mountain 

uplift

Amarillo uplift

OKLAHOMA

TEXAS

Arbuckle 

Mountains

Nemaha uplift

Figure 3, chapter 3

0 50 100 MILES

0 50 100 KILOMETERS

Figure 4. Map showing formation temperatures on the top of the 

Woodford Shale model layer. Cross section location is orange line on 

map. Black contour lines are temperature on the Woodford Shale from 

Gallardo and Blackwell (1999). Formation temperatures on the cross 

section are from ground surface to the Precambrian. The red dot is 

location of the Woodford Shale layer. Elevation in meters is relative to 

sea level. Purple fault lines are from Adler and others (1971). 

2,000

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

0 50 100 150 200 250 300

OKLAHOMA KANSAS

KILOMETERS

75

100

125

175

200

EXPLANATION

Temperature (oC)

20 to 40

40 to 60

60 to 80

80 to 100

100 to 120

120 to 140

140 to 160

160 to 180

180 to 200

200 to 220

220 to 240

240 to 260

260 to 280

280 to 300

 KANSAS

OKLAHOMA

TEXAS

SOUTH NORTH COLORADO

 103° 102° 101° 100° 99° 98° 97° 

38°

37°

36°

35°

0 50 100 MILES

0 50 100 KILOMETERS
8 Thermal Maturation of Petroleum Source Rocks in the Anadarko Basin Province, Colo., Kansas, Oklahoma, and Texas

Figure 5. Map showing modeled Celsius (°C) temperatures on the top 

of the Wabaunsee layer. Oklahoma (black) contour lines from Gallardo 

and Blackwell (1999) are estimated temperatures on the top of the 

Pennsylvanian, which is roughly analogous to the Wabaunsee elevation. 

Both sets of contours show general increase in temperature with greater 

burial depth. Increasing depth with burial is shown by the underlying 

Precambrian through Morrowan layers (red arrow). 3D view is 10 times 

vertical exaggeration. Purple fault lines are from Adler and others (1971).

N

40

45

50

55

45

20 to 30

30 to 40

40 to 50

50 to 60

60 to 70

70 to 80

80 to 90

90 to 100

100 to 110

110 to 120

120 to 130

130 to 140

140 to 150

Figure 5. Chapter 3 

EXPLANATION

Temperature (oC) KANSAS

OKLAHOMA

TEXAS COLORADO

 101° 102° 101° 100° 99° 98° 97°

38°

37°

36°

35° 0 50 100 MILES

0 50 100 KILOMETERS
Geologic Setting 9

same northwest trend and similar values to those of Gallardo 

and Blackwell (1999). This indicates that temperatures for the 

4D model compare generally with measured data. Subsurface 

temperatures are influenced by various factors. The Precambrian in the deep basin is primarily rhyolite, which is cooler 

than the mainly granitic rocks of the shallower basement and 

shelf regions. The rhyolite could influence thermal maturation by dampening thermal effects, essentially slowing onset 

of generation from overlying rocks. The Carter and others 

(1998) measured heat flow in the basin decreased from 55 to 

64 milliwatts per square meter (mW/m2) in the northern part, to 

39 to 54 mW/m2 in the southern part. Lee and Deming (1999) 

incorporated this information into their mean heat flows in 

the northern and southern basin of 39 mW/m2 and 51 mW/m2, 

respectively. They found no evidence that basement lithology 

influenced the increased heat flow from the south to north. 

Their work was based on thermal conductivity measurements 

of drill cuttings from nine wells in the basin. These and other 

heat flow data were contoured (fig. 3) and applied to the 4D 

model. Basement heat flow exhibits a heterogeneous distribution (fig. 3) with somewhat lower values in the southern 

part of the basin and greater heat flow across parts of the Las 

Animas arch, Central Kansas uplift, and parts of the Nemaha 

uplift. Lithofacies that overlie source intervals can also influence onset of maturation. For example, evaporites have good 

thermal conductivity that allows heat conduction away from 

kitchen areas, whereas thick shale and coal beds have the opposite effect, acting as thermal blankets that insulate underlying 

rocks. Minor differences in assigned lithofacies have no effect 

on modeling results. 

Geologic Setting

Structural History

The Anadarko Basin is a south-dipping asymmetric basin 

in which the present configuration is controlled mainly by 

the late Paleozoic Wichita Mountain uplift and the Ouachita 

thrust plate (Amsden, 1975, 1989). Southern Oklahoma was 

initially described by Shatski (1946) as a failed Cambrian 

aulacogen. The deepest part of the basin is along and north of 

this rift zone and is proximal to its southern margin along the 

Wichita Mountain uplift (fig. 6). The tectonic history of the 

Anadarko Basin strongly influenced rate of sediment deposition, sediment sources, depositional environments, erosion, 

and especially burial depth of reservoir, seal, and source rocks. 

Depth of burial through time is the main control on thermal 

maturation of petroleum source rocks, although oil and gas 

generation is also influenced by factors such as basement heat 

flow and thermal conductivity of lithofacies. The focus of 

this is on oil and gas generation, migration and accumulation 

through time from source rocks in the basin.

The Wichita Mountain and Amarillo uplifts and adjacent 

basins were strongly influenced by structural, stratigraphic, 

and thermal evolution of the southern Oklahoma aulacogen 

(Rascoe and Adler, 1983) that was emplaced on the Precambrian craton (Ham and others, 1964). It is about 100 miles (mi) 

[160 kilometers (km)] wide and 300 mi (480 km) long with 

the southern boundary approximated by the Wichita Mountain uplift (fig. 6). The Wichita Mountain and Amarillo uplifts 

include a number of faults, such as Mountain View, Cordell, 

Cement, Meers, and Duncan-Criner (Luza, 1989) that are 

along and proximal to the northern boundary of the uplifts,

Early and Middle Cambrian rifting and igneous activity 

was the initial phase in basin development (Denison, 1976; 

Gallardo and Blackwell, 1999). Increased subsidence in the 

aulacogen during the Early Cambrian resulted in a greater rate 

of deposition near the present-day basin axis; the subsidence 

rate slowed by the beginning of the Silurian (Feinstein, 1981). 

This is indicated by the relatively thin Silurian and Devonian 

rocks (Johnson and others, 1988; Johnson, 1989) that are of 

limited lateral extent. Figure 7 shows generalized lateral extent 

of the Woodford Shale within the Woodford Shale model 

layer. Model layers are somewhat like geologic maps through 

time in that they display the extent of the named formation, 

and “subcropping” lateral formations. All formations on the 

surface of figure 7 are assigned to the Woodford layer. The 

Viola layer, for example, would show the same assigned 

lithofacies of the Viola Group and any underlying formations 

outside its extent. 

The Ouachita-Marathon orogeny and related tectonism 

began in Mississippian (probably Chesterian) time (Burgess, 

1976; Perry, 1989). Anadarko began to form as an independent 

structural basin in Late Mississippian time, when the Texas 

promontory of the southern continental margin of Paleozoic 

North America first reacted to early stages of plate collision 

with Gondwana or an intervening microplate (Perry, 1989). 

During Early to Late Pennsylvanian time the principal tectonic 

activity in the basin occurred in several pulses: (1) the Morrowan Wichita Mountain and Amarillo uplifts were accompanied by downwarping of the basin (Gallardo and Blackwell, 

1999) with greater thickness of Morrowan strata in the deep 

basin relative to the shelf; and (2) Late Morrowan uplift 

along most of the Wichita Mountain and Amarillo blocks is 

evidenced by the upper Morrowan fan-delta chert conglomerate (Johnson, 1989). These were derived from Mississippian cherty limestones and dolomites that mantled the uplift 

(Johnson, 1989).

Climax of the Wichita orogeny during the Atokan was 

evidenced by Wichita Mountain and Amarillo uplift of thousands of feet relative to the proximal basin axis to north (Ball 

and others, 1991). Overthrusting associated with the uplift 

resulted in 15 ± 5 km (9 ± 3 mi) of crustal shortening (Brewer 

and others, 1983). The uplift supplied sediments to the 

informally named Granite Wash, which was deposited from 

Atokan through much of the Virgilian time. Transition from 

arkosic granite wash to felsic quartz grains extended some 

30 miles northward from the mountain front during the Atokan 

(Ball and others, 1991). The Wichita Mountain and Amarillo 

uplifts persisted as major positive tectonic features during 

Missourian time (Johnson, 1989). The Anadarko Basin has 
10 Thermal Maturation of Petroleum Source Rocks in the Anadarko Basin Province, Colo., Kansas, Oklahoma, and Texas

Figure 6. View to the southeast of elevation on the top of the Woodford Shale model layer is from the two-dimensional WoodfordTft.DAT 

grid file (Higley and others, 2014) that was created using Earthvision®. Vertical exaggeration is 18 times. Woodford extent is approximated 

by the -12,000-foot elevation contour, although Woodford is also present east of the Central Kansas uplift (CKU). Major structures 

are labeled. Precambrian faults (red) are from Adler and others (1971). Wichita Mountain uplift bounding faults are vertical for fourdimensional model purposes only, and the Woodford Shale surface in this area is unknown because of insufficient data. Data sources for 

this surface include Woodford picks from well logs, Rottmann (2000a, 2000b), and edited IHS Energy (2009a, 2009b) formation tops. 

EXPLANATION

Elevation (feet) 

relative to sea level

4,000

0

-4,000

-8,000

-12,000

-16,000

-20,000

-24,000

-28,000

-32,000

-36,000

-40,000

-44,000

-48,000

 KANSAS

COLORADO

OKLAHOMA

Figure 6. Ch. 3 

N

 NEW 

MEXICO

TEXAS

Arbuckle 

Mountains

Wichita 

Mountain 

uplift

CKU

Pratt

anticline

Nemaha uplift

Hugoton embayment

Amarillo uplift

Cimarron 

arch

Sierra 

 Grande uplift

Keyes

dome
Geologic Setting 11

Figure 7. View to the southeast showing Woodford Shale layer lithofacies. Vertical exaggeration is 18 times. View orientation is similar 

to the 1-kilometer grid spacing Earthvision® image (fig. 6). This PetroMod® image shows underlying and lateral facies changes for the 

Woodford Shale layer, which is shown in white. Lateral lithofacies within the Woodford layer are primarily limestone and dolomite of the 

Viola Group. Because the purpose of this image is to show lateral changes in lithofacies assignments on a model layer, this information 

is generalized in the explanation and not all listed formations are visible. The southern half of the Kansas Woodford has almost 0 meter 

thickness and represents grid extrapolation between the northeast Kansas and Oklahoma extents. Vertical yellow bars are faults from 

Adler and others (1971). CKU, Central Kansas uplift; lst, limestone; sh, shale; U, upper; L, lower. 

Figure 7. Ch. 3 

Woodford Shale

Sylvan Shale, sh

U. Simpson Group

L. Simpson Group

Arbuckle Group

lst, dolomite

Precambrian

rhyolite, granite

Hunton Group lst, } dolomite

} Viola Group lst, 

shale, dolomite 

}

Oil Creek Fm, sh

}

}

}

EXPLANATION

N

Wichita 

Mountain 

uplift

Nemaha uplift

Hugoton embayment

Amarillo uplift

CKU
12 Thermal Maturation of Petroleum Source Rocks in the Anadarko Basin Province, Colo., Kansas, Oklahoma, and Texas

essentially been structurally dormant since Early Permian time 

(Perry, 1989), as indicated by relatively uniform thicknesses 

of Wolfcampian and Leonardian formations, and that Council 

Grove, Chase, and Hennessey Groups, and other strata can 

be fairly readily correlated across the basin. Guadalupian and 

younger units exhibit more irregular distribution because of 

nondeposition and uplift, tilting, and erosion associated with 

the Laramide orogeny. The Laramide orogeny in the southern Rocky Mountains began about 67.5 million years before 

present (Ma) and ended about 50 Ma (Tweto, 1975). Johnson and others (1988) indicated that southern Oklahoma has 

been structurally quiescent since the Permian, except for the 

Laramide orogeny causing slight eastward tilting. Subdued 

modest reactivation of older basin faults may have occurred 

during the Jurassic and Cretaceous, and minor Holocene 

movement has occurred on the Meers fault of the Wichita 

Mountain uplift (Crone and Luza, 1986), and possibly other 

faults in the basin (Perry, 1989). 

Present-day surface expression of the Anadarko Basin 

is broad and low-relief with elevation decrease and drainage from west to east. This is in contrast to subsurface relief 

of Wolfcampian and older strata, which form a broad shelf 

over the Kansas and eastern Colorado portions of the basin 

that deepens gradually southward into Oklahoma and Texas. 

Northern Oklahoma and northeastern Texas evidence a marked 

increase in slope as the basin radially deepens southward 

to the Wichita Mountain uplift and its bounding high-angle 

reverse faults. Figures 6 and 7 are views to the southeast on 

the Woodford Shale layer. These and other three-dimensional 

(3D) structural images extend to the edges of the model, rather 

than terminating at the limits of contained formations. The 

slope of the Woodford surface increases gradually from the 

shelf southward to the basin axis; then slopes steeply upward 

toward the Wichita Mountain uplift and bounding faults. This 

slope increase is mirrored by increased thickness of most 

Pennsylvanian and older formations. The deep basin gradually 

filled with sediments through time. Figure 8 shows elevation on the Desmoinesian layer. Desmoinesian strata covered 

most of the Anadarko Basin, but is absent across most of the 

Wichita Mountain uplift, Central Kansas uplift, the Cimarron 

arch of northeastern New Mexico, and the Sierra Grande uplift 

of northeastern New Mexico and southeastern Colorado. 

The figure 9 isopach of strata between the top of the 

Hunton Group and the Desmoinesian layers shows southward 

increase in thickness. The absence of contours just north of the 

Wichita Mountain uplift is because of variable thicknesses of 

layers next to the uplift and associated terminations of layers 

against fault segments. Greatest thickness of strata is along the 

basin axis, proximal and north of the Wichita Mountain uplift. 

Thickness changes in southeastern Colorado are associated 

with the Las Animas arch, primarily a Laramide feature that 

also experienced movement during the late Paleozoic (Rascoe, 

1978). The pronounced thickening of strata in the deep basin 

is also shown by the cube slice of Precambrian through 

Desmoinesian layers from the 4D petroleum system model 

in figure 10. It shows the same break in slope southward that 

results in the wedge of sedimentation. The Atokan through 

Desmoinesian strata generalized lithofacies assignments were 

from Adler and others (1971) and are displayed as the gray, 

green and blue colors on the top slice of the model (fig. 10). 

Each color change across the vertical cut corresponds to a 

unique lithofacies assignment. Some of these extend across 

layers, such as for the Atokan through Desmoinesian layers. 

The result of this homogenization is a fairly leaky petroleum 

system model. For example, the Mississippian layer is about 

900 meters (m) thick at the marked location, when corrected to 

vertical. The lithologic assignment (modified from Adler and 

others, 1971) for the light green bands in this layer is about 

40 percent limestone, 30 percent sandstone, and 30 percent 

shale, and the intervening dark green band is 60 percent limestone, 20 percent sandstone, and 20 percent shale. Unless these 

assigned lithofacies truncate against or form a structure under 

a low-permeability seal layer, oil and gas is not trapped. 

Model layers can be modified to better represent the 

vertical and lateral lithofacies variation in the basin, but this 

was beyond the scope of this project. Lithofacies for most 

layers were derived from the Adler and others (1971) generalized clastic and carbonate assignments. An overpressured 

zone in the basin that persisted through geologic time could 

not be modeled, at least partly because of the coarse 6 to 9 km 

grid sizes of the 4D model and the generalized lithofacies 

assignments. Most generated petroleum for the Pennsylvanian 

through Permian strata migrated outside the model edges. 

The Al-Shaieb and others (1994) megacompartment complex 

(MCC) is composed of Devonian, Mississippian, and Pennsylvanian stratigraphic intervals and is characterized by overpressured conditions in the Anadarko Basin that exceed the normal 

gradient of 10.515 kilopascal per meter (kPa/m) [0.465 pounds 

per square inch per foot (psi/ft)]. The isolation of the MCC is 

maintained through considerably long geologic times (early 

Missourian to present) via encasement by an intricately complex framework of top, basal, and lateral seals (Al-Shaieb and 

others, 1990). 

Primary effect of the wedge of overburden is that thermal 

maturation of source rocks increases to the south. The primary kitchen area in the Anadarko Basin is in the Oklahoma 

and northeastern Texas portions (fig. 11). Thermal maturation ranges from onset to completion of oil generation from 

about 0.6 percent vitrinite reflectance (Ro) to 1.2 percent Ro, 

and overmature for gas generation at greater than 4 percent 

Ro. Increased slope of Ro contours is mirrored by depth of the 

Woodford Shale and thickness of overburden. The general 

northwest trend of Ro contours is similar to those of overburden thickness. The Cardott (1989) least squares regression 

correlation was 0.893 for 80 of the Woodford Shale Ro values 

compared to depth. Spread in Ro correlations can be influenced 

by (1) initial transformation of organic matter to vitrinite; 

(2) random experimental error; (3) interpretation of low-gray 

(low reflectance) vitrinite populations; (4) anisotropy of vitrinite-broadening reflectance histograms starting at 1.0 percent 

Ro, with a noticeable effect at greater than 2 percent Ro (Dow, 

1977; Hunt, 1979); and (5) suppression of Ro in alginite-rich 
Geologic Setting 13

Figure 8. View to the southeast of elevation on the top of the Desmoinesian layer (Higley and others, 2014, DesmoinesianTft.DAT grid 

file). Vertical exaggeration is 18 times. Major structures are labeled. CKU is Central Kansas uplift. Precambrian faults (red) are from 

Adler and others (1971). Wichita Mountain and Amarillo uplift faults are vertical for three-dimensional Earthvision® model purposes 

only, and presence of the Desmoinesian in this area is unknown because of insufficient data. Data sources for this surface include 

picks from well logs and edited IHS Energy (2009a, 2009b) well formation tops. Elevation is relative to sea level. 

Wichita 

Mountain 

uplift

EXPLANATION

Elevation (feet) 

relative to sea level

4,000

0

-4,000

-8,000

-12,000

-16,000

-20,000

-24,000

-28,000

-32,000

-36,000

-40,000

-44,000

-48,000

COLORADO

TEXAS

CKU

Pratt

anticline

Nemaha uplift

Hugoton embayment

Amarillo uplift

Figure 8. Ch. 3 

Cimarron

arch

 Sierra 

 Grande uplift

Keyes

dome

NEW MEXICO

OKLAHOMA

KANSAS

N

rocks (Cardott, 1989; p. 41), which may be a factor in the 

Type II kerogen within the Woodford Shale. 

Part of the area proximal to the Nemaha uplift (eastern 

part of fig. 11) is thermally immature for oil generation from 

the Woodford Shale based on Cardott (1989), but immature 

to mature based on Ro measurements for the West Edmond 

SWD 1-24 (0.55 percent mean Ro) and Streeter 1 (0.75 percent 

mean Ro) wells from Brian Cardott (written commun., 2011) 

and Mark Pawlewicz (written commun., 2010), respectively 

(fig. 11). The West Edmond SWD 1-24 sample was also analyzed by Chesapeake Energy (on January 10, 2008) with an 

estimated mean of 0.83 percent Ro and a range of 0.44 to 0.96 

percent Ro based on Rock Eval Tmax values for 19 samples 

of the Woodford Shale interval. Gaswirth and Higley (2014) 

calibrated 1D petroleum system models of these wells using 

the measured Ro data. The Streeter 1 Woodford Shale sample 

was located just above the Hunton cored interval, and sample 

quality was marginal. It was analyzed using Rock Eval 

pyrolysis with associated TOC of 0.96 weight percent (wt%), 

Tmax of 550 oC, and low hydrocarbon and oxygen indices of 

68 and 39, respectively. These wells may also record localized elevated thermal maturation. Possible increased thermal 

maturation along the Nemaha uplift could be associated with 

hydrothermal fluids along these deep faults, and increased erosion compared to wells to the west also contributed to greater 

thermal maturation. 

Fractures are present within the Woodford Shale throughout its extent in Oklahoma and Arkansas, and province areas in 

which fractures are most commonly filled with bitumen include 

the Arbuckle Mountains and the southern part of the Anadarko 

Basin; these were areas of intense late Paleozoic orogenic 

activity (Comer and Hinch, 1987). Fractures filled with bitumen were located in Woodford samples along the Nemaha 

uplift in central Oklahoma, and in the southern Anadarko Basin 
14 Thermal Maturation of Petroleum Source Rocks in the Anadarko Basin Province, Colo., Kansas, Oklahoma, and Texas

Figure 9. Map showing thickness of strata 

between the Hunton Group and Desmoinesian 

layers ranges from less than 500 meters over 

most of the Kansas shelf to more than 5,000 

meters in the deep basin of Oklahoma. This 

wedge of units is oriented northwest-southeast. 

Precambrian faults (blue lines) and named 

structures are from Adler and others (1971). The 

north-south red line is the general location of 

the figure 10 image.

Figure 10. Cube dissection of the four-dimensional petroleum system model shows present-day elevation on the 

Desmoinesian layer surface; color variations on the Desmoinesian correspond to lithologies from Adler and others 

(1971). Vertical color bands represent lithofacies assignments for the Desmoinesian through Precambrian layers. 

For example, the labeled Mississippian layer is about 900 meters (2,900 feet) thick at the location. Location of the 

slice is in figure 9. Vertical exaggeration is 15 times.

 2,000

 0

 -2,000

 -4,000

 -6,000

 -8,000

-10,000

Elevation, in meters

OKLAHOMA KANSAS

Wichita

Mountain

uplift

0

200

300

Scale (kilometers)

Mississippian layer

Sierra Grande uplift

SOUTH

NORTH

400

Figure 9. Ch. 3 

EXPLANATION

Thickness,

in meters

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000

5,500

6,000

103° 102° 101° 100° 99° 98° 97°

39°

38°

37°

36°

35°

COLORADO KANSAS

TEXAS

NEW MEXICO

OKLAHOMA

Wichita 

 Mountain 

 uplift

Nemaha uplift

Arbuckle

Mountains

Salina 

Basin

Pratt

anticline

Amarillo uplift

Las Animas arch

Central Kansas uplift

Sierra Grande uplift

Cimarron 

arch

Dalhart

 Basin

Anadarko Basin

0 50 100 MILES

0 50 100 KILOMETERS
Petroleum Source Rocks 15

Figure 11. Map showing vitrinite 

reflectance (Ro) contours for 

the Woodford Shale; black line 

contours are in increments of 

0.4% Ro. Generation stages on Ro

legend are generalized, as gas 

generation also occurs within 

the oil generation range. Black 

triangles and white dots include 

Ro data from Cardott (1989; written 

commun., 2011), Price (1997), 

and Mark Pawlewicz (written 

commun., 2010). Labeled white 

dot well locations are (1) Bertha 

Rogers 1, (2) Petree Ranch 1, 

(3) West Edmond SWD 1-24, and 

(4) Streeter 1. Brown lines are 

faults in the underlying Hunton 

Group (Rottmann, 2000a, pl. 3).

1 2

3

 4

OKLAHOMA

 TEXAS

KANSAS

0.4

0.5 Immature

0.6 Early oil

0.7

0.8 

0.9 

 Late oil (1.2)

1.0 Wet gas (1.2)

2.0 Dry gas

3.0

4.0 Overmature

5.0

 100° 99° 98° 97°

37°

36°

35°

Apache Gas 

Unit 1 well

EXPLANATION

%Ro Generation 

Stages

Figure 11. Ch. 3 

0 50 100 MILES

0 50 100 KILOMETERS

and Arbuckle Mountains (Comer and Hinch, 1987). Bitumen 

is assumed to be sourced from the Woodford as generated oil 

migrated laterally and then vertically along the faults. Vitrinite reflectance was contoured relative to the Hunton faults 

of Rottmann (2000a), which also isolates samples from the 

Wichita Mountain uplift relative to those in the basin. That 

the uplifted samples exhibit lower levels of thermal maturation than samples located north of the fault system shows that 

uplift occurred prior to maximum burial in the basin. Thermal 

maturation in the Wichita Mountain uplift is extrapolated from 

several outcrop samples and does not reflect the actual conditions because of the complexity of faulting, timing of uplift, 

and distribution of the Woodford Shale. Uplift samples should 

be considered point sources because of extensive faulting. For 

example, the Woodford Shale is present at least 4 times within 

the 1,930- to 19,000-ft depth interval of the Apache Gas Unit 1 

well (fig. 11); this well was not sampled, but it is likely that 

there would be a spread of Ro values. 

Petroleum Source Rocks

Petroleum source rocks in the Anadarko Basin were 

depPetroleum source rocks in the Anadarko Basin were 

deposited in marine environments. Burruss and Hatch (1989) 

and Joseph Hatch (oral commun, 2010) identified shale 

intervals of the Simpson Group, Woodford Shale, and Middle 

and Upper Pennsylvanian strata as the main source rocks 

in the Anadarko Basin (fig. 2). Burruss and Hatch (1989, 

p. 57) identified the following Anadarko Basin source rocks 

as having moderate to good hydrocarbon potential based on 

oil and source rocks geochemical analyses: (1) Ordovician 

Simpson Group shale, (2) Devonian-Mississippian Woodford 

Shale, and (3) Pennsylvanian black shales. They indicated 

absent to moderate source potential for the Ordovician Sylvan 

Shale based on geochemical analysis of oil and rock samples 

in Kansas and Oklahoma. There is no evidence for source 

potential from the Sylvan (or equivalent Maquoketa) Shale 

in the Anadarko Basin based on studies by Hatch and others (1987) and Wang and Philp (1997), and the poor gamma 

response from examination of about 90 well logs across the 

basin. The primary and most studied petroleum source rock in 

the Anadarko Basin is the Devonian-Mississippian Woodford 

Shale; equivalent strata are termed the Chattanooga Shale in 

Kansas. Because of limited source rock information for many 

other formations, all but the Woodford will be grouped by 

system. The Woodford Composite TPS includes the Cambrian 

through Mississippian section, and the Pennsylvanian Composite TPS includes source and reservoir rocks of Pennsylvanian through Permian age. 

Three layers in the 4D petroleum system model were 

assigned as petroleum source rocks based partly on the Burruss and Hatch (1989) determination of three oil types in the 

Anadarko Basin. They conducted geochemical analysis of 

104 crude oils and 190 core samples of Cambrian through 

Pennsylvanian dark colored shales, and their sampled oils 

and source intervals are from (1) the Middle Ordovician 

Simpson Group, (2) Silurian to Mississippian reservoirs, and 

(3) Pennsylvanian strata. The modeled source intervals are the 
16 Thermal Maturation of Petroleum Source Rocks in the Anadarko Basin Province, Colo., Kansas, Oklahoma, and Texas

Oil Creek Formation layer of the Simpson Group, the Woodford Shale layer, and the informal Thirteen Finger limestone 

layer (fig. 2). The Thirteen Finger limestone was chosen to 

represent Pennsylvanian source rocks because I mapped the 

thickness and extent of this high-gamma interval formation 

across the Anadarko Basin Province and therefore had a layer 

to assign source properties. 

This definition of three petroleum source rock layers 

serves to model which source(s) contribute to which reservoir 

layers, and also if this contribution varies across the basin and 

through time. Three assigned source intervals in a basin that 

contains probable other source rocks further homogenizes the 

model, but can also be used to determine if all potential reservoir intervals are charged. For example, does the Oil Creek 

layer source charge underlying Arbuckle layer reservoirs? 

If not, is it because of the coarseness of the model and (or) 

would this indicate source intervals in the Arbuckle? 

Middle Ordovician Simpson Group reservoirs contain 

“typical” Ordovician oils that are characterized by (1) strong 

odd-carbon predominance in the C13 to C19 n-alkanes, (2) few 

or no acyclic isoprenoids, and (3) d13C values of -33.9 parts 

per thousand (ppt) (saturates) and -33.7 ppt (aromatics) (Burruss and Hatch, 1989). Oils from Silurian to Mississippian 

reservoirs show little or no odd-carbon predominance in the 

n-alkanes, a regular decrease in abundance of n-alkanes with 

increasing carbon number, pristane/phytane ratios (pr/ph) 

of 1.1 to 1.5, and delta carbon-13 (d13C) values of -30.6 ppt 

(saturates) and -30.1 ppt (aromatics). Oils in Pennsylvanian 

reservoirs have the greatest amounts of carbon 15+ (C15+) 

hydrocarbons, are isotopically heavy (-27.5 ppt (saturates) and 

-26.4 ppt (aromatics), have methyl-cyclohexane as the most 

abundant hydrocarbon, and have pr/ph values from 2.0 to 0.9. 

The Wavrek (1992) gas chromatography analysis of 

385 Cambrian through Cretaceous crude oils from 83 fields 

across the Ardmore and Marietta Basins, south and east of the 

Anadarko Basin resulted in the assignment of 7 oil families. 

These A through G families were based largely on relative 

n-alkane distribution, cyclic isoprenoids, alkylated cyclic 

hydrocarbons, alkylated sulfur compounds, aryl-isoprenoids, 

hopanes, steranes, and carbon isotopes. Types A through E 

oils appear to correlate with respective source facies within 

the (A) Pennsylvanian (Atoka Group?), (B) Mississippian 

(Goddard Shale, Caney Shale, and Sycamore Limestone of the 

Mayes Group), (C) Devonian-Mississippian Woodford Shale, 

(D) upper Middle Ordovician Viola Group, and (E) Middle 

Ordovician Simpson Group (Wavrek, 1992). Type F oil was 

from Arbuckle Group reservoirs, but had uncertain parentage, 

and Type G oil had some characteristics of mixed oil types 

and possible effects of multiple sources because of proximity 

to the Ouachita thrust zone. Wavrek (1992) assigned greatest 

importance as a source rock to Type C, the Woodford Shale. 

Ordovician Source Rocks

The Cambrian and Ordovician Arbuckle Group lithologies include limestones with algal mats and boundstones 

(Donovan, 1986), bedded and disseminated anhydrite (Latham, 

1970; St. John and Eby, 1978; Ragland and Donovan, 1985; 

Donovan, 1986), and gray to dark gray limestone and some 

shale (Fay, 1989). The Arbuckle and Ellenburger Groups are 

partially equivalent and about 7,000 feet (ft) (2,150 m) thick in 

the deep basin; petroleum production is confined to the upper 

200–300 ft (Cardwell, 1977a). Pyrolysis-gas chromatographic 

analysis reveals that, in most of Oklahoma, the Arbuckle 

section is thermally mature but is deficient in organic matter 

(Cardwell, 1977a, 1977b). The Arbuckle Group is unlikely 

to contain petroleum source rocks in the Anadarko Basin. If 

present, source rocks are most likely proximal to the subsiding 

southern Oklahoma aulacogen (Johnson and Cardott, 1992), 

an area that is currently mostly overmature for hydrocarbon 

generation. This generation would have resulted in depletion 

of TOC, so original TOC would have been greater. TOC from 

21 Arbuckle and Ellenburger carbonate samples ranged from 

0.03–0.24 wt %, with an average of 0.1% (Cardwell, 1977a), 

less than good quality source rock of greater than 1.0 wt % 

TOC (Hatch and others, 1987). The Trask and Panode (1942, 

table 94, p. 263) Arbuckle TOC values ranged from 0.3 to 0.8 

wt % for 6 samples from 6 wells just east of the basin in Kansas and Oklahoma. Cardwell (1977a, p. 42) also observed that 

the composition of 9 Arbuckle oils from western Oklahoma 

were closely similar to those of 14 Desmoinesian oils from 

northeast Oklahoma and southeast Kansas. 

The Ordovician Simpson and Viola Groups contain 

mainly oil-prone source intervals (fig. 2) of Types I and II 

kerogen based on Rock-Eval pyrolysis results (Rice and others, 1989; Burruss and Hatch, 1989). Wang and Philp (1997) 

indicated the Viola and Woodford petroleum source intervals 

are mostly Type II kerogen based on Rock-Eval pyrolysis. 

The Simpson Group reaches a maximum thickness of 2,300 ft 

(700 m), of which about 50 percent is shale (Schramm, 1964). 

Sparse sampling on the shelf indicated as much as 14 percent 

of these shales may contain more than the minimum 1.0 wt % 

TOC required for a petroleum source rock (Hatch and others, 1987). Burruss and Hatch (1989) state Ordovician rocks 

generally exhibit TOC less than 1.0 wt %, although several 

Kansas samples have TOC between 1.0 and 9.0 wt %. Joseph 

Hatch (oral commun., 2010) unpublished TOC data ranged 

from 0.02 to 18.2 wt % and averaged 1.54 wt % for 39 Ordovician core samples from 4 wells in Oklahoma and Kansas. The 

average was increased because of TOC values of 5.34, 8.81, 

and 18.2 wt % from a well located northeast of the province at 

about latitude 38.19 N. and longitude 97.66 W.; hydrocarbon 

index (HI) values for this well were 665 to 787 milligrams 

sulfur per gram of total organic carbon (mg S2/g) TOC. 

The Sylvan Shale is isolated to the deep basin in Oklahoma and Texas. It is light gray to grayish green and waxy 

(Johnson and others, 1988), with an average thickness of less 

than 250 ft (80 m) (Wang and Philp, 1997). Well log gamma 

ray signatures were subdued for the Sylvan Shale in 88 wells 

scattered across the Oklahoma and Texas portions of the basin. 

Signatures were distinct enough to correlate the formation, but 
Petroleum Source Rocks 17

the minor gamma response is characteristic of the generally 

low TOC for this formation in the province. 

Devonian-Mississippian Woodford Shale

The Woodford Shale in the Anadarko Basin is a carbonaceous, siliceous, pyritic, dark-gray to black shale (Cardott, 

1989), the general extent of which is outlined in figure 1 by 

the Woodford Shale Oil AU. Equivalent strata northeast of 

the province in Kansas are called the Chattanooga Shale. The 

Woodford Shale was deposited on a regional erosional surface 

of the Silurian-Devonian Hunton Group (fig. 2). This unconformity developed across a broad upwarping that was one 

of the most widespread in the entire Midcontinent (Amsden, 

1975, 1989); it was accompanied by little, if any, folding or 

faulting except for faulting along the Nemaha uplift (Johnson, 

1989). This upwarping partially isolated the epicontinental seaway. The organic-rich Woodford black shales were 

deposited under anoxic conditions during the early Kaskaskia 

transgression of this shallow epicontinental sea (von Almen, 

1970; Walper, 1977; Sullivan, 1985; Johnson and Cardott, 

1992; Lambert, 1993). Evidence of burrowing in exposed 

organic-rich rocks in the Arbuckle Mountains (fig. 3) suggests 

there were also periods of oxic depositional conditions (Neil 

Fishman, oral commun., March 2, 2011). Egenhoff and others (2011) indicated a basinward progression in the Woodford from siliciclastic mudstones to successively increasing 

downslope Tasmanites and then radiolarian cherts; short-term 

highstands completely shut off delivery of very fine-grained 

sediments to distal parts of the passive margin during Woodford deposition, enabling good preservation of Milankovitch 

cycles in the formation. 

Elevation on the top of the Woodford Shale in the 

Anadarko Basin ranges from about -2,500 ft (-760 m) on the 

southern Kansas shelf, to -27,000 ft (-8,000 m) in southern 

Oklahoma (fig. 3). The formation is mostly absent because 

of erosion in the Wichita Mountain and Amarillo uplifts, 

although the Woodford Shale Gas AU includes an area of 

Woodford in the Wichita Mountain uplift proximal to the fault 

zone. The Woodford Shale is a fairly easy pick from well logs 

because of the large gamma kick and low permeability of 

this formation (fig. 12). Gamma-ray responses are commonly 

greater than 160 American Petroleum Institute (API) units 

(Amsden, 1975; Sullivan, 1985). The figure 12 cross section is 

located perpendicular to a thick interval of Woodford channel 

fill (fig. 13). The easternmost well in the cross section exhibits 

lateral thinning of the Mississippian section and absence of 

Morrow Formation and Thirteen Finger limestone. 

Thickness of the Woodford Shale varies greatly across the 

province. It ranges up to 375 ft thick and averages 40 ft based 

on Rottmann (2000b), well-log picks from about 100 wells 

across the basin, and edited formation tops from IHS Energy 

(2009a, 2009b). Greatest thicknesses are in the southern part 

of the basin in Oklahoma and locally as fill within eroded 

channels of the underlying Hunton Group (figs. 12 and 13). 

This is also the basin area that is most thermally mature for 

gas generation. Areas within the Woodford Shale AUs boundaries (fig. 1) where the unit is absent or thin resulted from 

erosion or nondeposition. There are a few erosional remnants 

outside the Woodford Shale Oil AU boundary, and the unit is 

present northeast of the province in Kansas. Smooth contours 

near the southeastern corner of figure 13 reflect limited data 

and variable thicknesses because of extensive faulting. The 

Misener sand is a lower unit of the Woodford Shale that is 

located mainly in the northeastern basin in Oklahoma and 

Kansas. Petroleum resources of this unit were evaluated with 

the Hunton Group AU because the Misener sand reservoirs 

are conventional, and much of the petroleum production was 

reported as commingled with that of the Hunton Group.

The Woodford Shale comprises upper, middle, and lower 

informal members of carbonate- and silica-rich shales based 

on well-log signatures, palynomorphs, and geochemical differences (Urban, 1960; von Almen, 1970; Sullivan, 1983, 1985; 

Hester and others, 1990; Lambert, 1993). The middle shale 

member has the greatest areal extent and thickness, and is also 

the most organic rich (Lambert, 1993). The Woodford Shale 

exhibits two habits, fissile and nonfissile shale. Nonfissile 

contains phosphatic and siliceous shales, minor thin dolomite 

beds, phosphatic nodules, and rare chert; fissile shales are 

composed of laminations less than 1 centimeter (cm) thick and 

are more organic-rich than nonfissile shale (Krystyniak and 

Paxton, 2006). The Woodford has abundant Type A amorphous 

Type II kerogen [partially equivalent to the liptinite (exinite) 

maceral group] with the remaining primarily Type III kerogen 

(vitrinite) and Type I kerogen (Tasmanite alginite) (Lewan, 

1983; Thompson and Dembicki, 1986; Crossey and others, 

1986; Comer and Hinch, 1987; Burwood and others, 1988; 

Krystyniack and Paxton, 2006). Applied to the Woodford 

Shale layer within the 4D PetroMod® model were a generalized composition of the Woodford Shale is 37 percent quartz, 

26 percent illite, 15 percent kerogen, 17 percent carbonate, and 

5 percent kaolinite (Abousleiman, 2008), and a HI of 527 mg 

S2/g TOC based on Lewan and Ruble (2002). HI data ranged 

from 3 to 1,127 mg S2/g TOC and averaged 260 mg S2/g TOC 

based on analyses of 97 core samples from 30 wells that were 

scattered across Oklahoma and Kansas (Burruss and Hatch, 

1989; Joseph Hatch, oral commun., 2010). Kirkland and others (1992) indicated a HI range of 500 to 800 mg S2

/g TOC for 

their samples. The Oklahoma portion of the province is mostly 

mature to overmature for petroleum generation, whereas the 

Woodford (Chattanooga) in Kansas is immature. As such, the 

HI of 17 Kansas Woodford (Chattanooga) samples ranged 

from 89 to 600 and averaged 321 mg S2/g TOC.

Based on analysis of 101 Woodford core samples from 

30 wells that were scattered throughout its extent in Oklahoma and Kansas, Burruss and Hatch (1989) indicated the 

TOC ranged from greater than 2 wt % to 14 wt %. Joseph 

Hatch (oral commun., 2010) indicated that TOC data averaged 4 wt %. Estimated average TOC of a somewhat conservative 3.5 wt % was used for 1D models and was based 

on data from Hester and others (1990), Comer and Hinch 
Figure 12. Cross section showing the Woodford Shale (WDFD, blue line) and terminus of the Morrow Group (MRRW) and overlying Thirteen Finger Lportion of the Atoka Group (ATOKA, gold line) in the deep Anadarko Basin. Line of section is shown in figure 13. Vertical scale is in feet relative to the WDFD. MRMT is Marmaton Group, CHRK is Cherokee Group, MSSP is Mississippian, HNTN is Hunton Group, SLVN is Sylvan Shale, VIOL is Viola GrouCSTR, and MRMC are the respective Mississippian Springer Formation, Chester Group, and Meramec lime. Labeled well log traces are gamma (0 to 2resistivity, sonic density, neutron density, spontaneous potential, and density. 

Loosen 1-4 Arlon 1-36 Dragging Otter 1-29 Royse 1

 Chesapeake Energy Corporation Chesapeake Energy Corporation Chesapeake Energy Corporation Samedan Oil Corporation T. 16 N., R. 12 W., Sec. 4 T. 16 N., R. 11 W., Sec. 26 T. 15 N., R. 9 W., Sec. 29 T. 12 N., R. 7 W., Sec. 23

10.3 miles 9.1 miles 22.8 miles

Figure 12. Ch. 3 

NORTHWEST 

Gamma

Resistivity

Sonic

Neutron 

Spontaneous Potential

Density

FEET

1,000

500

0

-500

 A

MRMC

M

WDFD

C

MW

Total Depth 11,300 feet

MRRW

CSTRSPRG
Petroleum Source Rocks 19

Figure 13 Ch. 3. 

.

1

2

4

2

400

360

320

280

240

200

160

120

 80

 40

 0

EXPLANATION

Thickness

(Meters) OKLAHOMA

 TEXAS

COLORADO KANSAS

Figure 13. Three-dimensional isopach image of the Woodford Shale in the Anadarko Basin. Vitrinite reflectance (% Ro) contours 

(white lines) from figure 11 approximate end of oil generation at 1.2% Ro to overmature for petroleum generation (4% Ro). White dot 

well locations are, from left to right, Bertha Rogers 1, Petree 1, and Streeter 1. Dashed white line is location of figure 12 cross section. 

Woodford thickness is derived from Rottmann (2000b, pl. 2), analysis of more than 100 well logs, and edited formation tops from IHS 

Energy (2009a, 2009b). Faults (red) are from Rottmann (2000a, pl. 3). Image is tilted and 1,300 times vertical exaggeration.

(1987), Burruss and Hatch (1989), Price (1997), Joseph 

Hatch (oral commun., 2010), and the Energy Geochemistry 

Data Base (U.S. Geological Survey, 2010). 1D models are 

located in areas that are mature to overmature for petroleum 

generation from the Woodford Shale. As such, original TOC 

was greater. The 4D model incorporated a map generated 

from these TOC data (fig. 14), instead of assigning a value 

for the entire layer. The Comer and Hinch (1987) Woodford 

mean TOC content of 5.4 ± 6.9 percent by wt was based on 

analysis of 300 samples from 16 cores and 43 outcrops that 

were distributed across Oklahoma and Arkansas; uncertainty 

in TOC resulted from a range of less than 0.1 wt% in some 

chert beds to 26 wt% in highly compacted black shale. Their 

location A21 near the southeast corner of figure 14 averaged 

5.5 ± 3.9 percent by weight TOC and this Type II kerogen 

was in early stage oil generation. Krystyniack and Paxton 

(2006) TOC values ranged from 0.8 to 17 wt% for upper 

Woodford outcrop samples of south-central Oklahoma. 

Comer and Hinch (1987) indicated that chert beds contained 

less TOC, but more total bitumen and hydrocarbons per 

gram. This may be indicative of greater fracturing and petroleum retention in chert beds.

Mississippian Source Rocks

Middle Ordovician through lowermost Mississippian sedimentary rocks in the basin are composed of fossiliferous shallow-water marine carbonates interbedded with fine-grained 

to moderately coarse-grained clastics that were derived from 

the northeast and east (Johnson and others, 1988). Probable 

Mississippian petroleum source rocks are within the informal 

Osage lime and Springer Formation (fig. 2) (Wang and Philp, 

1997). Average thickness of the Springer Formation is about 

500 ft (150 m) and more than 60 percent of it is shale and 

mudstone (Wang and Philp, 1997). Organic-carbon values for 
20 Thermal Maturation of Petroleum Source Rocks in the Anadarko Basin Province, Colo., Kansas, Oklahoma, and Texas

Figure 14. Map showing total organic carbon (TOC) content in weight percent 

(wt%) for the Woodford Shale based on TOC data from Burruss and Hatch 

(1989) and mean values from Hester and others (1990). TOC ranges from 0.08 

to 14.05 wt% and averages 3.7 wt% for core and well log density calculations 

from 123 wells. There is considerable TOC variation, but almost the entire area 

that is thermally mature for petroleum generation contains greater than 2 wt% 

TOC. Oil and gas generation depletes TOC and HI (hydrogen index), the fuels for 

petroleum, so original TOC and HI values would have been greater. Red lines 

are faults from Adler and others (1971).

Figure 14_CH3 

1

2

3

4

5

6

7

8

9

10

11

12

13

14

EXPLANATION

TOC

(wt %)

103° 102° 101° 100° 99° 98° 97°

39°

38°

37°

36°

35°

COLORADO KANSAS

TEXAS

NEW MEXICO

OKLAHOMA

Wichita 

 Mountain 

 uplift

Salina 

Basin

Amarillo uplift

Las Animas arch

Central Kansas uplift

Sierra Grande uplift

Cimarron 

arch

Dalhart

 Basin

Anadarko Basin

0 50 100 MILES

0 50 100 KILOMETERS

thick shales in the Springer and Pennsylvanian (Morrowan) 

producing intervals range from 0.5 to 3.4 wt%; however, 

the kerogen is mostly Type III, indicating that it is primarily 

gas-prone (Hatch and others, 1987; Rice and others, 1989; 

Wang and Philp, 1997) (fig. 2). Johnson and Cardott (1992, 

fig. 7) indicate that Mississippian shales and novaculite in the 

Ouachita trough, southeast of the Anadarko Basin, contain 

Types II and III kerogen with TOC values ranging from less 

than 1.0 to 1.9 wt %. The Mississippian ended with regional 

uplift and erosion that marked the onset of the Wichita orogeny, and resulted in erosion of Devonian and older strata, such 

as the Woodford Shale on structural highs around the margin 

of the basin (Ball and others, 1991). 

Pennsylvanian Source Rocks

Morrowan, Atokan, Desmoinesian, and Missourian 

organic-rich shales are important petroleum source rocks in 

the Anadarko Basin (fig. 2) (Hatch and others, 1987; Burruss 

and Hatch, 1989). Absence of uppermost Morrowan through 

Atokan strata over most of the Cimarron arch indicates this 

structure formed toward the end of tectonic activity that gave 

rise to the Wichita Mountain and Amarillo uplifts (fig. 14) 

(Johnson, 1989). These strata are also absent over the Sierra 

Grande uplift (fig. 9), a broad regional feature that was 

active during the Precambrian and a positive feature since 

Paleozoic time (Speer, 1976). The Morrow Group averages 

1,500 ft (460 m) in thickness in the Oklahoma portion of the 

Anadarko Basin, and comprises more than 60 percent shale 

and mudstone (Wang and Philp, 1997). As is the case with 

most other formations in the basin, the Morrow thins northward from the basin axis and across the shelf. Deposition 

across the province varied from shallow marine to shoreline 

and deltaic environments (Tsiris, 1983). Lower Morrow 

Group lithofacies are mainly black shale beds with interbedded sandstone and thin limestone layers; these probably 

represent deposition in a shallow transgressive sea (Wang 

and Philp, 1997). The middle Morrow is dominantly marine 

shales and carbonates, and the upper Morrow contains black 

shale, thin coal layers, and recycled organic matter (Wang 

and Philp, 1997). Unpublished data for Morrowan shales 

from core of 14 wells in the Oklahoma portion of the basin 

were from Joseph Hatch (oral commun., 2010); results 

ranged from 0.48 to 10.71 wt % TOC and averaged 1.72 wt 

%; HI ranged from 15 to 179 mg S2/g TOC and averaged 46. 
Petroleum System Model of the Anadarko Basin 21

As is the case for Pennsylvanian and older rocks in the deep 

basin, sampled areas are thermally mature for petroleum 

generation and original TOC and HI values would have been 

greater. 4D model initial TOC and HI values are calculated 

by PetroMod® software based on present-day thermal maturation of source rocks and their burial through time. 

Atokan Series source rocks include shales and limestones of the Atoka Group and underlying Thirteen Finger 

limestone. The Atokan Series averages 390 ft thick in Texas 

and the Oklahoma Panhandle and overlies a second-order 

unconformity at the top of the Morrow Group (Carr and 

Hentz, 2009). The Thirteen Finger limestone, also called the 

13 Finger lime and Thirteen Finger lime, consists of fissile, 

organic-rich shale interbedded with fossiliferous wackestones that represents a third-order transgressive systems 

tract (Carr and Hentz, 2009; Carr and others, 2009). Depths 

range from about 4,000 to 18,500 ft across the mapped extent 

of the unit. Elevation of the Thirteen Finger limestone, based 

partly on examination of 125 wells across the basin, ranges 

from about -4,000 ft on the shelf areas of Colorado and 

Kansas, to -17,000 ft in the deep basin area of Oklahoma and 

Texas (fig. 15). There is limited change in elevation of the 

formation across the Colorado and Kansas shelf, aside from 

uplifts associated with the Las Animas arch in southeastern 

Colorado, and the Keyes dome. This dome (fig. 6) forms a 

trap for modeled Thirteen Finger limestone oil accumulations. The Cimarron arch and Sierra Grande uplift (fig. 6) 

were positive features during Morrowan and Atokan time, 

which prevented deposition of these strata. Thickness of 

the Thirteen Finger limestone is variable across its extent 

(fig. 16) and averages 95 ft based on examination of 125 well 

logs. Semicircular contours represent increased thickness 

along a curved axis of deposition, and data extrapolation in 

areas with sparse well coverage. Also shown in figure 16 is 

overall thinning of strata from the deep basin to shelf areas, 

although there is a northwest trend of increased thickness 

from the deep basin towards southeastern Colorado. The 

Perryton and Knowles Northwest oil fields (fig. 16) have 

cumulative production from the Thirteen Finger limestone of 

about 160,000 barrels of oil, 300 million cubic feet of gas, 

and 6,900 barrels of water (IHS Energy, 2010). These fields 

are considered to be conventional based on decline curves 

of petroleum and water production. Perryton and Knowles 

Northwest fields are also located in an area marginally 

mature to mature for oil generation from the Thirteen Finger 

limestone, based on modeled TR and Ro values. 

The thickest, most organic-rich interval in the Atokan 

Series is in the uppermost part of the Thirteen Finger limestone and it probably represents a third-order marine condensed section (Carr and Hentz, 2009). Carr and Hentz (2009) 

estimated the average TOC ranged from about 4–6 wt % 

based on petrophysical examination of 28 wells. The Thirteen 

Finger limestone is characterized on well logs as stacked thin 

shale and carbonate beds with irregular high gamma kicks 

of 140 API and greater (fig. 17). This results in the “fingers” 

appearance. It is fairly readily correlated across the extent of 

the underlying Morrow Group in the province, except where 

proximal to the Wichita Mountain uplift. This is primarily 

because of tilting of strata and increased contribution of clastic 

sediments relative to organics. Gamma response for cross section A-A’ is less pronounced than that of B-B’. This suggests 

that the Atokan section in B-B’ contains more organic matter. 

Source rocks in A-A’ are also thermally mature for oil and (or) 

gas generation, which would deplete the TOC and HI values. 

Gamma response of the overlying Atoka Group is unremarkable in the A-A’ cross section but the B-B’ response is similar 

to that of the Thirteen Finger limestone. The Atoka Group 

source interval differs in that it is primarily shale, rather than 

thin limestone and shale beds. 

Desmoinesian and Missourian source rocks (fig. 2) are 

primarily organic-rich shales. Sixteen of the sample analyses 

results from Joseph Hatch (oral commun., 2010) were loosely 

categorized as Desmoinesian source rocks, 13 from Oklahoma, 1 from Texas, and 2 from western Kansas—TOC values 

ranged from 0.08 to 11.2 wt %, averaging 2.9 wt %, and HI 

values ranged from 7 to 442 mg S2/g TOC, averaging 144 mg 

S2/g TOC. Two samples from the Missourian section in Oklahoma and 4 from western Kansas ranged from 0.5 to 39.4 wt 

% TOC, averaging 11.4 wt %, and HI values ranged from 7 to 

576 mg S2/g TOC, averaging 296 mg S2/g TOC (Joseph Hatch, 

oral commun., 2010).

Petroleum System Model of the 

Anadarko Basin

Petroleum Generation Kinetics

The 4D model of the Anadarko Basin was constructed 

of 30 layers of strata from Precambrian to ground surface. 

Incorporated in the model are maps of basal heat flow, water 

depth through time, periods and thicknesses of deposition and 

erosion, total organic carbon (TOC) and hydrogen indices (HI) 

for the Woodford Shale and other source rocks, and lithofacies 

for each layer. Ideally, once the 4D model is constructed, it 

can be readily calibrated to available temperature and thermal 

maturation data, but in actuality, numerous modifications and 

iterations are necessary to achieve “final” models. Changes 

are designed to fit the 4D model to generated 1D models and 

to measured temperature and thermal maturation indicators 

across the basin. 1D models and 1D extractions from the 4D 

model were calibrated using temperature and Ro data. 1D 

models were compared to 1D extractions from the 3D model 

as a further calibration step. Modeled Ro (Sweeney and Burnham, 1990) was preferentially calibrated on measured Ro

 from 

the Woodford Shale (Cardott, 1989; Price, 1997).

Onsets of petroleum generation and expulsion across 

the basin were determined primarily using modeled Ro and 

Woodford Shale hydrous pyrolysis (HP) kinetics (table 2) 

that were applied to potential source rocks of the Ordovician 

Simpson Group, Devonian-Mississippian Woodford Shale, 
22 Thermal Maturation of Petroleum Source Rocks in the Anadarko Basin Province, Colo., Kansas, Oklahoma, and Texas

Figure 15. View to the southeast of elevation on the top of the Thirteen Finger limestone layer (Higley and others, 2014, 

ThirteenFingerTft.DAT grid file). Vertical exaggeration is 18 times. Thirteen Finger lime extent is approximated by the light blue line. 

Major structures are labeled. Precambrian faults (red) are from Adler and others (1971). Wichita Mountain uplift faults are vertical for 

four-dimensional model purposes only, and surface in this area is unknown because of insufficient data. Data sources for this surface 

include Thirteen Finger limestone picks from well logs and edited IHS Energy (2009a, 2009b) formation tops. Elevation is relative to sea 

level. CKU, Central Kansas uplift.

Arbuckle 

EXPLANATION anticline

Elevation (ft) 

relative to sea level

4,000

0

-4,000

-8,000

-12,000

-16,000

-20,000

-24,000

Figure 3. Ch. 7 

Salina Basin

Wichita 

Mountain 

uplift

 KANSAS

COLORADO

TEXAS

CKU

Pratt

anticline

Nemaha uplift

Hugoton embayment

Amarillo uplift

Sierra Grande 

 uplift

Keyes

dome

NEW MEXICO

N

OKLAHOMA

Cimarron 

 arch

and Pennsylvanian Thirteen Finger limestone. Heat flow and 

erosional history, estimated depositional and thermal properties of assigned lithofacies, and choice of kinetic algorithms 

can significantly affect timing of generation. Petroleum modeling software can also affect results and associated conclusions 

(Higley and others, 2006). For these reasons I used several 

kinetic algorithms and heating histories. It is preferable to 

have kinetic algorithms calculated from and specific for each 

petroleum source rock, but those values were only available 

for the Woodford Shale. 

Phosphoria Formation HP kinetics (Lewan and Ruble, 

2002) was also applied to the models to investigate the effect 

of organic sulfur on timing of petroleum generation. Some 

wells in the Panhandle and Hugoton field area of the western 

basin produce sour oil and (or) gas from mostly Pennsylvanian reservoirs, but sour oil and (or) gas has also been 

reported from scattered Cambrian and Ordovician Arbuckle 

through Permian Chase reservoirs across the basin (Mason, 

1968; Owen, 1975; Nehring and Associates, Inc., 2009). 

The Woodford Shale contains a fairly low ratio of organicsulfur to carbon at 0.023 (Sorg/C); the Phosphoria Formation 

is fairly high at 0.045023 Sorg/C (Lewan and Ruble, 2002, 

table 1). HP kinetics depend partly on the organic-sulfur content of the original kerogen (Lewan and Ruble, 2002). Impact 

of the Type IIS kerogen organic sulfur on generation of oil is 

detailed in Lewan and Ruble (2002) and illustrated in Higley 

and others (2009). To simplify a complex process, essentially the organic sulfur results in sulfur-radical initiators that 

increase the associated reaction rates during thermal maturation of the source rock. A primary effect is that the onsetthrough-completion of oil generation and expulsion occurs 

at decreased levels of thermal maturation. The Tsuzuki and 

others’ (1999) secondary and tertiary generation (cracking) of oil to gas kinetics were applied for each petroleum 

source rock in the model. Because of the coarse grid spacing 

and generalized lithologies, little secondary or tertiary gas 
Petroleum System Model of the Anadarko Basin 23

Figure 16. Isopach map of the top of the stratigraphic interval 

from the Thirteen Finger limestone to the Morrow Formation, 

based on Andrews (1999a, b), examination of more than 120 well 

logs, and edited tops from IHS Energy (2009a, 2009b). Morrow 

Formation faults (green) are modified from Andrews (1999b). Color 

contour interval is 20 feet and (black) line contours are 10-feet 

intervals. Figure 17 cross sections are labeled A-A’ and B-B’. 

White polygons are Perryton (Texas) and Knowles Northwest 

(Oklahoma Panhandle) oil fields.

Figure 16. Ch. 3

103° 102° 101° 100° 99° 98° 97°

39°

38°

37°

36°

35°

TEXAS

 COLORADO NEW MEXICO

OKLAHOMA

KANSAS

EXPLANATION

Thickness, feet

A

Aʹ B

Bʹ

0

20

40

60

80

100

120

140

160

180

200

220

0 50 100 MILES

0 50 100 KILOMETERS

Table 2. Summary of kinetic parameters derived for expelled-oil generation based on hydrous pyrolysis (HP) in 

isothermal experiments, and nonisothermal open-system pyrolysis (REV) that were derived from Lewan and Ruble 

(2002, tables 4 and 5) and cracking of oil to gas (Tsuzuki and others, 1999). The Woodford Shale analyses were on an 

unweathered, thermally immature sample that contained 12.7 percent total organic carbon (TOC), from section 25, T. 

2 S., R. 1 E., Carter Co., Oklahoma (Lewan, 1983).

FormationName SampleNumber KerogenType Activation energy,Ea

(kcal/mol)

Frequency factorA0

(m.y–1) HImgHC/gTOC

Phosphoria P-64 Type II-S 42.71 4.31E x 1023 276.0

Woodford WD-5 Type II 52.16 5.706E x 1026 246.2

Woodford WD-5 (REV) Type II 56.1 (Mean) 8.111E x 1026 440.0

(C15+ crude oil )1 76.00 3.419E x 1033

1

 Tsuzuki and others (1999) secondary gas generation kinetics was applied to all petroleum source rocks.






















































































16 Geologic Assessment of Undiscovered Oil and Gas Resources in the Anadarko Basin

Sizes and Numbers of Undiscovered Fields in 

the Arbuckle-Ellenburger Assessment Unit

The Arbuckle Group is not well explored, largely because 

of its depth, especially in the deep basin. There have been 

problems with seismic exploration of the Arbuckle because 

of (1) poor data quality beneath the complex overthrust zones 

that exist along the southern boundary of the Anadarko Basin 

(Brown and others, 1991) and (2) the relatively low amplitude 

of the Arbuckle reflections in the basin compared to the higher 

amplitude reflections of the overlying strata. Arbuckle wells 

are characterized by high initial potential, steep decline rates, 

production of large quantities of oil, and high water-oil ratios.

Cumulative oil production in the Arbuckle-Ellenburger 

AU is 52 MMBO, with 1.3 MMBO from the Ellenburger 

Group in Texas (IHS Energy, 2010). Although there is oil 

production throughout the basin, gas production is limited to 

the deeper part of the basin, with 285 BCFG produced (IHS 

Energy, 2010; fig. 14). Production depths range from 3,000 ft 

to 26,500 ft. The most recent reported discoveries are on the 

Anadarko shelf, but with low cumulative oil and gas numbers reported by IHS Energy (2010; fig. 15). In commingled 

fields, which are common in the basin, the Arbuckle composes 

a relatively small portion of the total production based on a 

comparison of field data versus Arbuckle accumulation data 

for a given field (Nehring Associates Inc., 2009).

 Nehring Associates Inc. (2009) presented limited data 

for the Arbuckle-Ellenburger; only 4 of the 24 accumulations 

in the database have grown reserve accumulation numbers 

(fig. 15). This is likely because of a historical lack of reporting 

information from private operators to the state and other agencies for Midcontinent hydrocarbon production. Furthermore, 

there is a large amount of commingled production in the basin, 

as well as the incorrect reporting of the producing formation. 

Nehring field data were used to supplement the database, but 

are of marginal use because the production from all reservoirs 

is generally combined for a field, not just that of the ArbuckleEllenburger. In cases where the Arbuckle contribution can be 

determined by combining the field data with the grown data, 

the Arbuckle is a minor component of the total resource in the 

majority of the fields. 

Using the USGS assessment methodology for undiscovered conventional resources (Klett and others, 2005; 

Schmoker and Klett, 2005), the mean undiscovered oil and 

Figure 14. Map showing oil and gas production and dry hole penetrations for the Arbuckle 

and Ellenburger Groups in the Anadarko Basin Province (IHS Energy Group, 2010). Structure 

contours are drawn on the top of the Arbuckle Group; contour interval is 2,000 feet. The 

Anadarko Basin Province boundary is the black line, the Woodford Composite Total Petroleum 

System (TPS) boundary the red line, and the Arbuckle-Ellenburger Assessment Unit (AU) 

boundary the blue line.

-2,000

-2,000

-2,000

-2,000

-2,000

-2,000

-2,000

-2,000

-2,000

-2,000

-2,000

-2,000

-2,000

,-2,000

-2,000

KANSAS

TEXAS

OKLAHOMA

COLORADO

NEW MEXICO

104° 103° 102° 101° 100° 99° 98° 97°

39°

38°

37°

36°

35°

ch5_figure14

Arbuckle Group Top, elevation in feet

-28,000

-26,000

-24,000

-22,000

-20,000

-18,000

-16,000

-14,000

-12,000

-10,000

-8,000

-6,000

-4,000

-2,000

0

2,000

4,000

-2000

-2,000

EXPLANATION

Arbuckle-Ellenburger dry holes

Fault

Arbuckle-Ellenburger AU boundary

Woodford Composite TPS boundary

Anadarko Basin Province boundary

Arbuckle-Ellenburger oil production

Arbuckle-Ellenburger gas production

MAJOR CO.

BECKHAM CO.

WHEELER CO.

Nemaha uplift

Pratt anticline

-12,000

-10,000

-8,000

-6,000

-4,000

-14,000 -16000

-18,000

-28,000 -24,000

-22,000

-20,000

-26,000

Arbuckle

Mountains

Central Kansas uplift

0 25 50 MILES

0 25 50 KILOMETERS
Geologic Setting 17

gas resources for conventional reservoirs in the ArbuckleEllenburger AU are estimated at 5.5 MMBO and 181 BCFG 

(table 1). Estimates of the minimum, median, and maximum 

numbers of undiscovered accumulations are 1, 2, and 10 

for oil, and 1, 10, and 60 for gas. The broad ranges reflect 

the uncertainty of future potential. The Arbuckle has been 

penetrated more extensively on the shelf of the basin, where 

production is predominantly oil (fig. 14). There is more 

undrilled area in the deep basin along structures; gas production is more likely in the deep basin based on gas versus 

oil production in the Arbuckle, and the fact that the deep 

basin is thermally mature to overmature for gas production 

(figs. 9 and 13). Future oil production will likely be as small 

accumulations on the shelf, or associated with deeper gas 

production. The most recent Arbuckle discoveries are on the 

shelf near the Pratt anticline, but oil numbers are low in these 

fields, whereas gas fields in the deeper basin are larger, based 

on field data (Nehring and Associates, Inc., 2009; fig. 15). 

Large gas fields with Arbuckle production are Mayfield West 

(23 BCFG grown) and Bradbridge (7 BCFG grown). Production depth has a wide range (3,000 to 26,500 ft) depending 

on whether the Arbuckle is producing from the deep basin or 

the shelf (fig. 14). 

Estimates of the minimum, median, and maximum 

sizes of undiscovered oil accumulations are 0.5, 1.0, and 

10.0 MMBO. The 0.5 MMBO default signifies that there will 

be at least one field found greater than the minimum size, and 

the maximum reflects the uncertainty of Arbuckle accumulation sizes because of the lack of Nehring information. Production by field for the Arbuckle from the IHS database has 

been small (less than 4 MMBO). Estimates of the minimum, 

median, and maximum sizes of undiscovered gas accumulations are 3, 6, and 60 BCFG. The maximum reflects the uncertainty with deep gas production in the Arbuckle-Ellenburger, 

as it is sparsely drilled in the deep basin. The most recent 

accumulation reported by Nehring Associates, Inc. (2009) data 

was discovered in 2005. However, there are no Nehring accumulation data provided and none found for the Arbuckle in the 

IHS database (IHS Energy, 2010). 

The future role of the Arbuckle Group is an important question in the development of hydrocarbon resources 

in Oklahoma, as there may be significant undiscovered 

resources, especially in the deepest part of the Anadarko 

Basin, where drilling into the Arbuckle is sparse. There is 

also potential for future production downdip from the central 

Kansas production areas, or along migration routes the 

hydrocarbons generated in the deep basin followed through 

Oklahoma. The Texas Panhandle is also a viable area for 

exploration, as the Arbuckle is deep enough there to have 

possibly self-sourced.

Figure 15. Map showing accumulations for the Arbuckle-Ellenburger Assessment Unit (AU) 

(Nehring Associates, Inc., 2007). Accumulations without numbers are in purple. TPS, Total 

Petroleum System.

KANSAS

TEXAS

OKLAHOMA

COLORADO

NEW MEXICO

104° 103° 102° 101° 100° 99° 98° 97°

39°

38°

37°

36°

35°

Fault

Arbuckle-Ellenburger AU boundary

Woodford Composite TPS boundary

Arbuckle-Ellenburger Groups Nehring

 accumulations without data

Anadarko Basin Province boundary

EXPLANATION

Arbuckle-Ellenburger Groups Nehring

 accumulations with data

Nemaha uplift

Ch5_fig15

0 25 50 MILES

0 25 50 KILOMETERS
18 Geologic Assessment of Undiscovered Oil and Gas Resources in the Anadarko Basin

Simpson Group

The Middle Ordovician Simpson Group overlies the 

Arbuckle Group in the Anadarko Basin, and the rocks represent a departure from carbonate deposition because of an 

influx of clastic sediments. Simpson Group strata in Oklahoma are clean quartzose sandstones interbedded with thick, 

shallow-water marine limestones and thin to moderately 

thick greenish-gray shales (fig. 16; Flores and Keighin, 1989; 

Johnson, 1991). In Kansas, the Simpson is a sequence of 

clastics and sandy carbonate rocks. Fine- to coarse-grained 

clastic sediments were derived from the uplifted Canadian 

Shield to the north and east when sea level was lowered during 

the Middle Ordovician; the windblown sediment was carried 

southward and covered the emergent carbonate shelf (Johnson, 

1991). As sea level rose, sand was reworked into an extensive 

and sheet-like transgressive deposit in marine shoreface and 

tidal flat environments, which is overlain by marine shales 

and carbonates. Successive sea level fluctuations during the 

remainder of Simpson time produced a succession of sands, 

shales and limestones (Johnson, 1991). Clastic and carbonate 

rocks are dominant to the north, and offshore facies persist to 

the south (fig. 17). 

The total thickness of Simpson Group rocks ranges from 

100 to 300 ft on the basin shelf, to 2,300 ft in the basin depocenter (fig. 18). The Simpson is divided into five formations, 

in ascending order: (1) the Joins Formation, (2) the Oil Creek 

Formation, (3) the McLish Formation, (4) the Tulip Creek 

Formation, and (5) the Bromide Formation (figs. 2 and 16). 

Each has a basal sandstone facies and upper mudstone-siltstone-limestone facies (fig. 16). The basal sandstones of the 

Simpson are regionally extensive sheet-like bodies, ranging in 

thickness from 50 to 200 ft. Other sandstones are less continuous and cannot be traced for long distances laterally. In the 

subsurface of central Oklahoma, some of the sandstones are 

referred to as “Wilcox sands” (Johnson, 1991); the “Second 

Wilcox” is commonly correlated to the basal Bromide sand 

body (Rottmann, 1997). 

The Joins Formation is the exception in that it lacks the 

sandstone facies present in the upper Simpson Group formations, and is mainly carbonate that was deposited in a shallow 

marine environment during the post-Arbuckle sea-level lowering in the remaining finger of the carbonate sea in Oklahoma 

(fig. 19; Denison, 1997). Over a large area of Oklahoma the 

Joins Formation was embayed by the basal Oil Creek Formation sandstones. The basal Oil Creek sandstone is overlain by 

shale and limestone, the latter of which is a reservoir in some 

areas of the basin. The basal McLish Formation sandstone is 

one of the most widespread and persistent quartz-rich sandstones of the Simpson Group. The McLish Formation grades 

into limestones, dolomites, and shales, and represents a continuation of clear-water shallow-marine sedimentation (Suhm, 

1997). The Tulip Creek Formation has a basal sandstone body 

overlain by shale, and the uppermost Bromide Formation 

consists of varying amounts of sandstone, limestone, dolomite, 

and shale. The Bromide basal sandstone is the most areally 

Figure 16. Stratigraphic section of Simpson Group rocks 

(modified from Flores and Keighin, 1989).

 Bromide

Formation

Tulip Creek

 Formation

McLish

Formation

Oil Creek

Formation

Joins

Formation

Middle Ordovician

Simpson Group

EXPLANATION

Sandstone

Shale

Calcareous 

 shale

Limestone

FEET

0

250

METERS

0

250

ch5_fig16

Figure 17. Image showing major lithologies of Ordovician 

Simpson Group strata in the southern midcontinent (modified 

from Northcutt and Johnson, 1997).

Simpson

Group

?

BELT

?

OUACHITA

THRUST

Limestone

Dolomite

Sandstone

Eroded or not

 deposited

Shale

TEXAS

KANSAS

MISSOURI

OKLAHOMA ARKANSAS NEW MEXICO

LOUISIANA

ILLINOIS

MISSISSIPPI

EXPLANATION

COLORADO

0 100 200 MILES

0 100 200 KILOMETERS

104° 102° 100° 98° 96° 94° 92° 90°

39°

37°

35°

33°

31°
Geologic Setting 19

extensive of the Simpson sandstones, and the contact with the 

overlying Viola Group is distinct based on the change to clean, 

crystalline limestone (Suhm, 1997). 

In the Kansas portion of the Anadarko Basin, the Simpson is divided into six informal stratigraphic units that are 

correlated with the McLish and Bromide Formations. The 

McLish Formation corresponds to the two lower units and 

the Bromide Formation to the upper four units (Doveton and 

others, 1990; Charpentier and Doveton, 1991). The absence 

of the Joins, Tulip Creek, and Oil Creek Formations reflects 

the change from proximal shoreface facies in the deeper basin 

to offshore facies near the Pratt anticline (fig. 19; Charpentier 

and Doveton, 1991).

Source Rocks of the Simpson Group

Oil samples from the Middle Ordovician Simpson Group 

have the characteristics of Ordovician oils. The Woodford 

Shale is also a likely source rock for the Simpson Group 

reservoirs (figs. 7 and 20; Burruss and Hatch, 1989). Faults 

juxtapose the Woodford and Simpson in the basin, and migration from the Woodford Shale in the deep basin also charged 

Simpson reservoirs (Smith, 1997).

Simpson Group shales have been identified as a hydrocarbon source rock for the Oklahoma basin (fig. 3) by Adler 

and others (1971), Webster (1980), Hatch and others (1986), 

and Wavrek (1989). Philippie (1981) showed that shales of the 

Simpson Group acted as the source for oils in the stratigraphically older rocks of the Ellenburger Group in west Texas. 

Hatch and others (1986) also interpreted Simpson shales to be 

the probable source for Viola and Simpson Groups reservoirs 

in the Forest City Basin of Kansas and Nebraska. 

Burruss and Hatch (1989) identified potential source 

rocks in the shales of the Simpson Group as containing Type I 

and II kerogen. Sparse sampling on the Kansas shelf indicates 

as much as 14 percent of the Simpson shales may be of source 

rock quality (greater than 1 percent TOC; Burruss and Hatch, 

1989). Organic material in the Simpson Group is algal, and 

potentially improves in Kansas, where it is on the shelf. However, Simpson shales on the shelf are only marginally mature 

for oil and potential is considered poor to moderate (fig. 7; 

Burruss and Hatch, 1989). Quality is moderate in the deep 

basin where Simpson shales have reached maturity.

Reservoir Rocks in the Simpson Group 

Assessment Unit

The blanket-like sandstones with interbedded shales are 

the dominant reservoir facies within the Simpson Group. The 

Simpson Group is most productive from its sandstone units, but 

it also contains some carbonate reservoirs that are highly productive locally. Carbonate rocks within the lower Simpson yield 

oil and gas, especially in karsted reservoirs. All of the Simpson 

formations are productive to varying degrees. To the north in 

south-central Kansas, the Simpson increases in thickness west 

of the Pratt anticline and becomes dominated by sandy, cherty 

dolomite, which accounts for the loss of production in that area 

of the basin (Lynn Watney, written commun., 2010).

Reservoir porosity in producing sandstones ranges from 

10 to 30 percent, with permeabilities ranging from 15 to 300 

(mD) (Ball and others, 1991; Johnson, 1991). Reservoir quality is highest in well-sorted sandstones that are absent of clay, 

and which have had dissolution of intergranular carbonate 

cement during burial (Pollastro, 1989). The Second Wilcox 

(Bromide) is the principal producing unit of the Simpson 

on the central Oklahoma shelf, where overlying impermeable strata create stratigraphic traps when the sandstones are 

upthrown against impermeable strata and a fault seal occurs 

(Rottmann, 1997). 

The Simpson AU boundary follows the Simpson subcrop 

on the northwest, the province boundary on the west, the faults 

that the define the southern end of the Central Kansas uplift in 

the northeast, the Nemaha uplift on the east, and the Precambrian fault system along the Arbuckle Mountains to the south 

(fig. 18). Production is concentrated on the eastern edge of the 

basin and to the north along the Central Kansas uplift. There is 

also production in the southeast corner of the basin along the 

Precambrian fault system.

Traps and Seals in the Simpson Group 

Assessment Unit

Simpson Group sandstones have produced substantial 

volumes of hydrocarbons from structural traps, especially 

along the Nemaha uplift on the eastern edge of the basin 

(fig. 18). On the Nemaha uplift, production is on the flanks 

of structural highs from erosionally truncated sandstone that 

is sealed by overlying Pennsylvanian shales. Multiple Simpson fields produce along these complex structures, such as 

the Oklahoma City, Golden Trend, and Sho-Vel-Turn fields. 

The Oklahoma City field produces from a large anticline near 

the south end of the Nemaha uplift, bounded on the east by a 

normal fault (Northcutt and Johnson, 1997). There is a large 

amount of commingled production in these fields.

Historically, Simpson exploration has been largely 

related to structural traps, with little exploration for possible 

stratigraphic traps related to unconformities, porosity development, and pinchouts of porous sandstone and carbonates. 

There may also be significant potential for stratigraphic traps 

that lie off structure and below seismic resolution (Candelaria 

and others, 1997). 

Simpson reservoir seals are interbedded Simpson 

shales and tight sandstones or carbonates (fig. 20). Also, 

overlying Pennsylvanian shales on the flanks of structural 

highs form seals where the underlying strata have been 

removed by erosion.
20 Geologic Assessment of Undiscovered Oil and Gas Resources in the Anadarko Basin

Figure 18. Map showing production from and thickness of the Simpson Group; contour 

interval is 500 feet.

Figure 19. Image showing approximate distribution of the Joins 

sea during Ordovician time (modified from Denison, 1997).

Exposed

carbonate platform

Shelf

edge

Joins sea

OKLAHOMA

0 50 100 MILES

0 50 100 KILOMETERS

0

100

500

1,500

2,000

0

0

100

0

0

0

1,000

0

500

0

1,000

KANSAS

TEXAS

OKLAHOMA

COLORADO

NEW MEXICO

104° 103° 102° 101° 100° 99° 98° 97°

39°

38°

37°

36°

35°

Nemaha uplift

Pratt anticline

Arbuckle

Mountains

Central Kansas uplift

CH5_fig18

0 25 50 MILES

0 25 50 KILOMETERS

EXPLANATION

Simpson Group Production

Fault

Simpson Group Thickness, in feet

0

100

250

500

1,000

1,500

2,000

Simpson Group AU boundary

Woodford Composite TPS boundary

Anadarko Basin Province boundary
Geologic Setting 21

Figure 20. Simpson Goup Assessment Unit events chart showing 

the timing of source rock deposition and trap formation, and the age 

of overburden, reservoir, and seal rocks with different color bars 

(black, source rock; gray, overburden rock; blue, reservoir rock; 

pink, seal rock; purple, trap formation; dark green, generation; light 

green, migration accumulation). The chart also depicts the timing of 

oil generation, migration and accumulation as modeled for various 

wells in different parts of the Anadarko Basin. Plio, Pliocene; Mio, 

Miocene; Olig, Oligocene; Eoc, Eocene; Pal, Paleocene; L, Late; 

M, Middle; E, Early.

Intracratonic Basin

Source rockOverburden rockReservoir rockSeal rockTrap formationBasin type

Geologic 

time 

scale

Petroleum

system

events

GenerationMigration/accumulation

Pal

Eoc

Olig

Mio

0

100

200

300

400

50

150

250

350

Paleogene

Cretaceous

Jurassic

Triassic

Permian

65.5

146

200

251

359

416

Silurian

Devonian

299

318

E

E

E

E

E

E

E

E

M

M

M

M

L

L

L

L

L

L

L

L

Mississippian

Pennsylvanian

Neogene

23

Plio

Ordovician

Cambrian

542

488

444

450

500

550 Precambrian

Potential Arbuckle Group starting approximately340 Ma, Woodford Shale approximately 335 Ma

ch5_fig20
22 Geologic Assessment of Undiscovered Oil and Gas Resources in the Anadarko Basin

Sizes and Numbers of Undiscovered Fields in 

the Simpson Group Assessment Unit

The Simpson reservoirs are of limited lateral and vertical extent, but important enough to enable individual wells to 

produce more than 1 MMBO (Northcutt and Johnson, 1997). 

Production is commonly commingled with other reservoirs, 

especially reservoirs in the Viola Group. Nehring accumulation data (Nehring Associates, Inc., 2009) indicates that 

individual fields in the Simpson produce approximately 0.5 to 

8.0 MMBO in the basin. There is limited gas data available. 

There has been substantial penetration of the Simpson Group 

in south-central Kansas and near the Nemaha uplift, and scattered sporadic drilling throughout the remainder of the AU 

(fig. 21). There has been little drilling in the deep basin, near 

the basin depocenter.

Cumulative oil production in the Simpson AU is 

470 MMBO (IHS Energy Group, 2010). There is oil production throughout the basin, whereas gas production is limited 

to the deeper part of the basin, with 1.2 TCFG produced (IHS 

Energy, 2010; fig. 21). Production depths range from 3,000 to 

17,400 ft in the structurally deepest part of the basin (fig. 21). 

There is an overlap in the oil and gas production, with production concentrated on the eastern and southern parts of the 

basin, and accumulations split between oil and gas. 

The Nehring database (Nehring Associates, Inc., 2009) 

lists 105 Simpson accumulations, but only 18 have accumulation data (17 oil and 1 gas; fig. 22). As with the Arbuckle, 

this is likely because of the reporting of commingled production, or the erroneous reporting of the producing formation. 

Nehring field data (Nehring Associates, Inc., 2009) were used 

to supplement the database, but field data are of marginal use 

because it includes all producing reservoirs for a field, not just 

the Simpson Group. 

Using the USGS assessment methodology for undiscovered conventional resources (Klett and others, 2005; 

Schmoker and Klett, 2005), we estimated the mean undiscovered oil resources for conventional reservoirs in the 

Simpson Group AU at 5 MMBO and 125 BCFG (table 1). 

These estimates are based partly on data for 18 discovered 

accumulations that exceeded the minimum size of 0.5 MMBO 

(Nehring Associates, Inc., 2009). The distribution of the 

number of undiscovered oil accumulations is estimated to 

have a minimum of 1, a median of 3, and a maximum of 10. 

The estimated minimum, median, and maximum numbers of 

undiscovered gas accumulations exceeding the minimum size 

are 3, 6, and 60, respectively. The Simpson has been penetrated extensively on the shelf near the Oklahoma-Kansas 

border, along the Nemaha uplift, and on other structures in 

the basin (fig. 21). There are also dry holes and wells with 

minor production in the Texas Panhandle and into southcentral Kansas, where the Simpson becomes dominated by 

chert (Doveton and others, 1990; Charpentier and Doveton, 

1991). There is more undrilled area in the deep basin along 

structures in the same region where the Arbuckle is sparsely 

drilled. Future oil and gas production is likely limited on the 

shelf, as it has been extensively explored. The most recent 

Simpson discoveries were in the mid-1980s, suggesting that 

the interest and potential in the Simpson is waning.

The estimated minimum, median, and maximum sizes of 

undiscovered oil accumulations are 0.5, 0.8, and 8.0 MMBO. 

The 0.5 MMBO default signifies that there will be at least one 

field discovered greater than the minimum size, and the maximum reflects the maximum size of a potential undiscovered oil 

accumulation, and the largest grown oil field reported (Nehring 

Associates, Inc., 2009). Oil production per field for the Simpson 

is generally less than 2 MMBO. Estimated minimum, median, 

and maximum sizes of undiscovered gas accumulations are 3, 

6, and 60 BCFG. The maximum number reflects the uncertainty 

of deep gas production in the Simpson, similar to the ArbuckleEllenburger, as both are sparsely drilled in the deep basin. 

Viola Group

Simpson Group sandstones and limestones are overlain 

by the Upper Ordovician limestones of the Viola Group. Following a brief marine withdrawal, Viola seas transgressed 

over the exposed upper Bromide carbonates of the Simpson 

Group, and deposition was in a broad, shallow, epicontinental 

sea (Denison, 1997). The Viola is a marine limestone sequence 

deposited on a carbonate platform (figs. 4 and 23), and is 

widespread in the Anadarko Basin. It contains chert at several 

stratigraphic levels and is highly fossiliferous (Johnson and 

others, 2000). There is terrigenous detritus in the lower Viola 

in the aulacogen, and the strata grade upward into clean, skeletal limestones (Johnson, 1991). The vertical change indicates 

an upward decrease in water depth and corresponding increase 

in energy level and aerobic activity (Johnson and others, 

2000). Viola strata are 500-800 ft thick in the aulacogen, and 

thin to 50-500 ft on the shelf (fig. 24). The rift margin played 

an important role in the thickness and facies of the Viola carbonates. The Viola Group is absent in the northern and western 

parts of the basin (fig. 24).

In the southern Anadarko Basin, the Viola Group consists 

of the lower Viola Springs Formation and the upper Welling Formation (fig. 2), and represents a shallowing-upward 

sequence (Denison, 1997). Within the aulacogen, the Viola 

Springs comprises organic-rich, finely laminated lime mudstones deposited in deeper water, and the Welling is pelmatozoan-rich grainstones deposited in shallow water (Denison, 

1997). Outside the aulacogen, the basal Viola Springs lithology is packstone and wackestone. 

Viola carbonate deposition ended abruptly as the system 

was flooded with clays of the overlying Sylvan Shale. The Sylvan is a widespread green to greenish-gray shale sequence that 

ranges from 300 to 400 ft thick in the aulacogen and from 30 

to 200 ft thick in most shelf areas (Johnson and Cardott, 1992; 

fig. 25). The formation was included in the Viola Group AU for 

this assessment, although there is sparse, insignificant production despite numerous penetrations (fig. 25). Minor accumulations attributed to the Sylvan Shale by IHS Energy (2010) are 

likely erroneously reported and are from other units. 
Geologic Setting 23

Figure 21. Map showing oil and gas production and dry hole penetrations from the Simpson 

Group in the Anadarko Basin Province (IHS Energy Group, 2010). The structure contours are 

drawn on the top of the Simpson Group; contour interval is 2,000 feet. The Anadarko Basin 

Province boundary is the black line, the Woodford Composite Total Petroleum System (TPS) 

boundary the red line, and the Simpson Group Assessment Unit (AU) Boundary the blue line.

0

-2,000

-4,000

-6,000

-8,000

-10,000

-12,000

-14,000

-16,000 -18,000

-20,000

2,000

4,000 6,000

-22,000 -24,000

8,000

-26,000

-28,000

-10,000

-2,000

-4,000

0

-10,000

-2,000

-2,000

-8,000

0

-2,000 -6,000

-2000

-16,000

-4,000

-4,000

-8,000

0

-18,000 -8,000

-6,000

2,000

-6,000

-10,000

-2000

-4,000 -8,000

-4,000

0 0

-6,000

-4,000

0

-2,000

-4,000

0

-6,000

-2,000

-8,000

-4,000

-2,000

-2,000

0

0

0

-4,000

-12,000

-4,000

-2,000

-2,000

-2,000

-2,000

0

-2,000

-6,000

-10,000

KANSAS

TEXAS

OKLAHOMA

COLORADO

NEW MEXICO

104° 103° 102° 101° 100° 99° 98° 97°

39°

38°

37°

36°

35°

Arbuckle

Mountains

Central Kansas uplift

Ch5_fig21

Simpson Group Top, elevation in feet

-28,000

-26,000

-24,000

-22,000

-20,000

-18,000

-16,000

-14,000

-12,000

-10,000

-8,000

-6,000

-4,000

-2,000

0

2,000

4,000

6,000

8,000

EXPLANATION

Simpson Group dry holes

Fault

Simpson Group AU boundary

Woodford Composite TPS boundary

Anadarko Basin Province boundary

Simpson Group oil production

Simpson Group gas production

0 25 50 MILES

0 25 50 KILOMETERS

KANSAS

TEXAS

OKLAHOMA

COLORADO

NEW MEXICO

104° 103° 102° 101° 100° 99° 98° 97°

39°

38°

37°

36°

35°

0 25 50 MILES

0 25 50 KILOMETERS

Fault

Simpson Group AU boundary

Woodford Composite TPS boundary

Simpson Group Nehring

 accumulations without data

Anadarko Basin Province boundary

EXPLANATION

Simpson Group Nehring

 accumulations with data

Figure 22. Map showing 

accumulations for the 

Simpson Group Assessment 

Unit (AU) (Nehring 

Associates, Inc., 2007). 

Nehring accumulations with 

grown reserve accumulation 

numbers are shown in light 

blue. Accumulations without 

numbers are in purple. TPS, 

Total Petroleum System.
24 Geologic Assessment of Undiscovered Oil and Gas Resources in the Anadarko Basin

Figure 23. Image showing major lithologies of the Ordovician 

Viola Group strata in the southern midcontinent (modified from 

Northcutt and Johnson, 1997).

Figure 24. Map showing production from and thickness of the Viola Group; contour interval 

is variable.

?

BELT

? OUACHITA

TEXAS

KANSAS

MISSOURI

OKLAHOMA

ARKANSAS

COLORADO

NEW MEXICO

LOUISIANA

ILLINOIS

MISSISSIPPI

CH5_fig23

Limestone

Dolomite

Sandstone

Eroded or not

deposited

Shale

EXPLANATION

Viola

Group

THRUST

0 100 200 MILES

0 100 200 KILOMETERS

104° 102° 100° 98° 96° 94° 92° 90°

39°

37°

35°

33°

31°

0

250

500

750

0

100

KANSAS

TEXAS

OKLAHOMA

COLORADO

NEW MEXICO

Pratt anticline

104° 103° 102° 101° 100° 99° 98° 97°

39°

38°

37°

36°

35°

Arbuckle

Mountains

Central Kansas uplift

Nemaha uplift

Ch5_fig24

Viola Group thickness, in feet

0

100

250

500

750

EXPLANATION

Fault

Viola Group AU boundary

Woodford Composite TPS boundary

Anadarko Basin Province boundary

Viola Group production

0 25 50 MILES

0 25 50 KILOMETERS
Geologic Setting 25

Source Rocks of the Viola Group Assessment 

Unit

The Woodford Shale is the apparent source rock for Viola 

reservoirs, though there may be some self-sourcing as well as 

contributions from other Ordovician source rocks, such as the 

Simpson (figs. 7 and 26). Thin source beds that were sampled 

in the lowermost Viola Springs Formation have an average TOC of approximately 1 percent, with Type II kerogen 

(Denison, 1997; Wang and Philip, 1997). However, these data 

were disputed by Brown and Sentfle (1997) as a consequence 

of other studies indicating higher organic contents within the 

laminated marls of the Viola (average TOC of 2.4 percent) 

and basal chert (average TOC of 1.3 percent; see Wavrek and 

others, 1997). The Viola was reported as a source rock for oil 

in the Pauls Valley area of the Anadarko Basin by Jones and 

Philip (1990). 

Data on the Sylvan Shale indicate that the source-rock 

potential is poor to moderate (Johnson and Cardott, 1992). 

The Sylvan contains Type II kerogen with low TOC (less than 

1 percent; Burruss and Hatch, 1989). 

Reservoir Rocks in the Viola Group Assessment 

Unit

Viola reservoirs are in thick sequences of limestones and 

dolomites that have been subjected to fracturing and dissolution, with karst features and zones of vuggy porosity. The 

Viola ranges from about 4,000 to 13,000 ft in depth in the 

basin (fig. 27). Karstification occurred following Sylvan and 

Hunton deposition when the Viola was exhumed in southern 

Oklahoma (Sykes and others, 1997). Karst features include 

conduit-filling breccias, solution enlarged fractures, crackle 

breccias, vugs, and channels (Sykes and others, 1997). Surface 

karstic features are also common. Selective dolomitization 

also enhanced porosity and reservoir quality in the Viola. 

Reservoirs of the Viola Group may have primary and secondary porosity, and fracture systems are developed as a function of the brittle nature of the carbonate. The highest porosity 

is in intercrystalline, moldic, and vuggy subtidal dolomitic 

mudstones and wackestones (Newell, 2000). Porosity averages 

8–10 percent, but can be as high as 23 percent in dolomitized 

reservoirs in south-central Kansas (Newell, 2000).

Figure 25. Map showing production from and thickness of the Sylvan Shale; contour interval 

is 100 feet.

0

100

200

300

0

100

100

0

0

KANSAS

TEXAS

OKLAHOMA

COLORADO

NEW MEXICO

Nemaha uplift

Pratt anticline

104° 103° 102° 101° 100° 99° 98° 97°

39°

38°

37°

36°

35°

Ch5_fig25

Sylvan Shale thickness, in feet

0

100

250

200

300

EXPLANATION

Fault

Viola Group AU boundary

Woodford Composite TPS boundary

Anadarko Basin Province boundary

Viola Group production

0 25 50 MILES

0 25 50 KILOMETERS
26 Geologic Assessment of Undiscovered Oil and Gas Resources in the Anadarko Basin

The Viola is absent in the northern and western Anadarko 

Basin, and the subcrop and province boundary define the 

assessment unit in those parts of the basin (fig. 24). The AU 

boundary is defined by the faults that delineate the southern 

end of the Central Kansas uplift in the northeast, the Nemaha 

uplift on the east, and the Precambrian fault system along the 

Arbuckle Mountains to the south (fig. 24). 

Traps and Seals in the Viola Group Assessment 

Unit

Viola accumulations in the Anadarko Basin are commonly in structural or combination traps near the Central 

Kansas uplift and on the Nemaha uplift where the Viola is 

overlain by the Sylvan Shale or unconformably by Pennsylvanian shales (Carlson and Newell, 1997). The structural 

traps are in the same areas as the Simpson Group reservoirs. 

Production trends in south-central Kansas are in areas where 

dolomitized units are preserved on the crests of local anticlines 

(Newell, 2000). There is substantial Viola production in Fitts 

pool, to the southeast of the Anadarko Basin, on the western 

edge of the Arkoma Basin, where the structure is a large, faultbounded anticlinal fold. Stratigraphic variations resulting from 

localized movement during deposition can provide north-south 

closure for these structural traps. Stratigraphic traps may also 

be present where porous wedges of dolomitized Viola are 

enclosed by nonporous packstone and grainstone beds.

The primary seals in the Viola Group are the overlying Sylvan Shale, which has low porosity and permeability, 

or interbedded tight, impermeable limestone of the Viola 

(fig. 26). Oil and gas fields are also found where Viola reservoirs subcrop beneath the basal Pennsylvanian angular unconformity in south-central Kansas (Newell, 1997).

Sizes and Numbers of Undiscovered Fields in 

the Viola Group Assessment Unit

 The Viola Group is not considered as significant a 

reservoir as the Simpson Group, though it yields oil and gas 

from thick sequences of carbonates that are fractured and have 

solution-enhanced porosity (Northcutt and Johnson, 1997). 

Production is from locally dolomitized sections on structures 

tested for Simpson and Arbuckle production. Most of the 

production is in the eastern basin, along the Nemaha uplift 

and near the Central Kansas uplift, where the Simpson Group 

produces (figs. 24 and 27). 

The Viola has been extensively penetrated along the 

eastern and northern basin boundaries (fig. 27). Production is 

commonly commingled with other reservoirs, and formation 

water is produced with the oil. Hydraulic fracturing of the 

Viola reservoirs have been important to reservoir development 

(Johnson and others, 2000). The Viola has fair to good matrix 

porosity, but low permeability in many areas of the basin, 

requiring fracturing for production. The Viola is being pursued 

as a horizontal drilling candidate (Fritz and others, 1993). 

There is little reservoir information reported for the 

Viola Group in the Nehring database (Nehring Associates, 

Inc., 2009); of the 29 accumulations only 1 has reported oil 

accumulation data (fig. 28). Cumulative oil production from 

the Viola Group AU is 112 MMBO (IHS Energy, 2010). 

Cumulative gas production is 505 BCF (IHS Energy, 2010). 

Production depths range from 4,000 to 18,000 ft in the deepest 

basin. There is an overlap in the oil and gas production, with 

both concentrated on the eastern and northeastern parts of the 

basin (fig. 27).

Using the USGS assessment methodology for undiscovered conventional resources (Klett and others, 2005; Schmoker 

and Klett, 2005), it is estimated that the undiscovered oil and 

gas resources for conventional reservoirs in the Viola Group 

AU have a mean of 5 MMBO and 30 BCFG (table 1). The 

estimated minimum, median, and maximum numbers of (1) 

undiscovered oil accumulations exceeding the minimum size 

(0.5 MMBO) are 1, 2, and 10; and (2) undiscovered gas accumulations exceeding the minimum size (3 BCFG) are 1, 2, and 

10. Like the Simpson, the Viola has been penetrated extensively on the shelf near the Oklahoma-Kansas border, along the 

Nemaha uplift, and on other structures in the basin (fig. 27). 

There is undrilled area in the deep basin along structures in 

the same region where the Arbuckle and Simpson are sparsely 

drilled. Future oil and gas production is likely limited on the 

shelf, as it has been extensively explored along the structures. 

The maximum number of oil and gas accumulations was raised 

to account for possible deep basin drilling. The most recent 

Viola discoveries were in 2000, though no data were reported 

by Nehring Associates, Inc. (2009) for these fields.

The estimated minimum, median, and maximum sizes of 

undiscovered oil accumulations are 0.5, 1.0, and 5.0 MMBO. 

The 0.5 MMBO default signifies that there will be at least one 

field found greater than the minimum size, and the maximum reflects the maximum size of a potential undiscovered 

oil accumulation, based on field data, as there is only one 

oil accumulation reported for the Viola Group AU (Nehring 

Associates, Inc., 2009). Oil production by field for the Viola 

is generally less than 3 MMBO. The distribution of sizes 

of undiscovered gas accumulations was estimated to have a 

minimum of 3 BCFG, a median of 6 BCFG, and a maximum 

of 30 BCFG. The maximum reflects the uncertainty with deep 

gas production in the Viola Group. 

Hunton Group

The Silurian-Devonian was a time of widespread 

marine-carbonate deposition in the Midcontinent, and strata 

were deposited as a relatively thin veneer of limestones and 

dolomites in a ramp environment (fig. 29). Sea-level changes 

caused the migration of facies and generated the lateral distribution and vertical succession of carbonate strata (Al Shaieb 

and Puckette, 2002). The Hunton Group is a sequence of limestones, dolomites, and lesser clastic rocks of Late Ordovician 

to Early Devonian age (Al Shaieb and Puckette, 2002; fig. 2). 

Several distinct depositional environments are interpreted 
Geologic Setting 27

Figure 26. Viola Group Assessment Unit events chart showing the 

timing of source rock deposition and trap formation, and the ages 

of overburden, reservoir, and seal rocks with different color bars 

(black, source rock; gray, overburden rock; blue, reservoir rock; 

pink, seal rock; purple, trap formation; dark green, generation; light 

green, migration accumulation). The chart also depicts the timing of 

oil generation, migration and accumulation as modeled for various 

wells in different parts of the Anadarko Basin. Ma, mega-annum; Plio, 

Pliocene; Mio, Miocene; Olig, Oligocene; Eoc, Eocene; Pal, Paleocene; 

L, Late; M, Middle; E, Early.

Potential Arbuckle Group starting approximately340 Ma, Woodford Shale approximately 335 Ma

Intracratonic Basin

Source rockOverburden rockReservoir rockSeal rockTrap formationBasin type

Geologic 

time 

scale

(Ma)

Petroleum

system events

GenerationMigration/accumulation

Pal

Eoc

Olig

Mio

0

100

200

300

400

50

150

250

350

Paleogene

Cretaceous

Jurassic

Triassic

Permian

65.5

146

200

251

359

416

Silurian

Devonian

299

318

E

E

E

E

E

E

E

E

M

M

M

M

L

L

L

L

L

L

L

L

Mississippian

Pennsylvanian

Neogene

23

Plio

Ordovician

Cambrian

542

488

444

450

500

550 Precambrian

ch5_fig26
28 Geologic Assessment of Undiscovered Oil and Gas Resources in the Anadarko Basin

Figure 28. Map showing 

accumulations for the Viola Group 

Assessment Unit (AU) (Nehring 

Associates, Inc., 2007). Nehring 

accumulations with grown reserve 

accumulation numbers are shown 

in light blue. Accumulations without 

numbers are in purple. TPS, Total 

Petroleum System.

Figure 27. Map showing oil and gas production and dry hole penetrations for the Viola 

Group in the Anadarko Basin Province (IHS Energy Group, 2010). Structure contours are 

drawn on the top of the Viola Group; contour interval is 2,000 feet. The Anadarko Basin 

Province boundary is the black line, the Woodford Composite Total Petroleum System (TPS) 

boundary the red line, and the Viola Group Assessment Unit (AU) boundary the blue line.

KANSAS

TEXAS

OKLAHOMA

COLORADO

NEW MEXICO

104° 103° 102° 101° 100° 99° 98° 97°

39°

38°

37°

36°

35°

0 25 50 MILES

0 25 50 KILOMETERS

Fault

Viola Group AU boundary

Woodford Composite TPS boundary

Viola Group Nehring

 accumulations without data

Anadarko Basin Province boundary

EXPLANATION

Viola Group Nehring

 accumulations with data

-28,000

-26,000

-22,000

-22,000 -20,000

-20,000

-18,000

-18,000

-18,000

-16,000

-16,000 -14,000

-14,000

-12,000

-12,000

-12,000

-10,000

-8,000 -6,000

-6,000

-6,000

-4,000

-4,000

-4,000

-4,000

-4,000

-4,000

-2,000

-2,000

-2,000

-2,000

-2,000

-2,000

-2,000

-2,000

-2,000

-2,000

-2,000

-2,000

-2,000

-2,000

0

0

0

0

0

0

0

0

0

2,000

2000

2,000

4,0006,000

KANSAS

TEXAS

OKLAHOMA

COLORADO

NEW MEXICO

104° 103° 102° 101° 100° 99° 98° 97°

39°

38°

37°

36°

35°

Nemaha uplift

Pratt anticline

Arbuckle

 Mountains

Central Kansas uplift

ch5_fig27

0 25 50 MILES

0 25 50 KILOMETERS

Viola Group Top, elevation in feet

above sea level

-28,000

-26,000

-24,000

-22,000

-20,000

-18,000

-16,000

-14,000

-12,000

-10,000

-8,000

-6,000

-4,000

-2,000

0

2,000

4,000

6,000

8,000

10,000

EXPLANATION

Viola Group dry holes

Precambrian fault

Viola Group AU boundary

Woodford Composite TPS boundary

Anadarko Basin Province boundary

Viola Group oil production

Viola Group gas production
Geologic Setting 29

Figure 29. Image showing depositional setting during Hunton 

time in the midcontinent (modified from Fritz and Medlock, 1994).

Approaching Limit Of Maximum Carbonate Deposition

C A R B O N A T E P L A T F O R M

Shallow Sea

Shallow Sea

N

TEXAS

KANSAS

MISSOURI

OKLAHOMA

ARKANSAS

COLORADO

NEW 

MEXICO

LOUISIANA

ILLINOIS

MISSISSIPPI

TENNESSEE

ALABAMA

IOWA

ch5_fig29

from Hunton strata, including upper intertidal to supratidal, 

upper subtidal to lower intertidal, and subtidal facies (Fritz 

and Medlock, 1994; fig. 30). These facies are in shallowingupward cycles or parasequences. The Hunton comprises a 

series of progradational sequences that built generally southward across the carbonate ramp (Fritz and Medlock, 1994); 

predominantly subtidal rock, bioclastic, and oolitic facies that 

are less argillaceous and more bioturbated than the Arbuckle 

Group, the Hunton Group is divided into a number of formations (fig. 31). The basal unit in the southern Anadarko 

Basin of Oklahoma is the Ordovician Keel Formation, which 

resulted from eustatic shoaling of sea water with no significant terrigenous sedimentation, and has patchy distribution in 

Oklahoma (Johnson, 1991). The Keel is part of the informal 

Chimneyhill subgroup, which also contains the overlying 

Silurian Cochrane and Clarita Formations, which are dolomitic 

limestones and dolomite (fig. 31). The clean skeletal limestones and dolomites of the Chimneyhill are overlain by the 

argillaceous and silty limestones and dolomites of the Silurian 

Henryhouse and Silurian–Devonian Bois d’Arc Formations 

(Haragan Formation equivalent). The Henryhouse reservoirs 

are dolomitized intertidal facies (Al Shaieb and Puckette, 

2002). In central and southern Oklahoma, they are overlain by 

the Devonian Frisco Formation (fig. 32). The Frisco Formation 

consists of skeletal packstone and grainstones, whose main 

components are pelmatozoans, brachiopods, and local corals 

(Morgan and Schneider, 1981). There are several intra-Hunton 

unconformities, including the Silurian–Devonian contact, and 

at the base of the Frisco Formation (fig. 31). 

Following Hunton deposition, a pre-Woodford unconformity developed that is widespread in the Midcontinent 

(Johnson, 1989). This unconformity surface is one of the few 

in the Midcontinent in which the erosional geometry includes 

preserved incised channel features (Rottmann, 2000c). 

The inundation of Devonian seas was initially confined to 

erosional channels, filling them with Woodford Shale and 

preserving them. 

The Hunton conformably overlies the Sylvan Shale and is 

unconformably overlain by either the main body of the Woodford Shale or locally by the basal informal Misener sandstone 

of the Woodford, which is Late Devonian in age (fig. 2). The 

Misener was deposited on the post-Hunton unconformity in a 

marine environment, accumulating within preexisting fluvial 

channels (fig. 33). The sandstones are of the same source as 

the Simpson sandstones to the north and east, with the detritus 

being transported south as the early Woodford sea transgressed. The Misener is a fine-grained quartz sandstone with 

some dolomite, interbedded with Woodford-like shale. 

The Hunton thickens from a wedge edge near the 

Kansas-Oklahoma border to more than 1,600 ft in Washita 

and Beckman Counties, Oklahoma, in the deepest part of the 

basin (fig. 34). The Hunton is typically 100 to 400 ft thick on 

the northern shelf, where it is highly dolomitized (Johnson and 

others, 2000). The depositional extent of the Hunton has been 

modified by erosion (fig. 32).

Source Rocks of the Hunton Group Assessment 

Unit

The Hunton Group is not known to contain source rocks 

for hydrocarbons in the Anadarko Basin (Johnson and Cardott, 

1992). However, the Woodford Shale, which lies unconformably on the Hunton (fig. 2) and has excellent source rock quality is considered to be the primary source for Hunton reservoirs throughout the basin (figs. 7 and 35). Vitrinite reflectance 

data indicates that the Woodford is mature for the generation 

of both oil and gas, especially in the deep basin (fig. 8). 

Woodford hydrocarbons likely migrated up through the deep 

basin into Hunton reservoirs, although there is some indication 

from one-dimensional burial history models that there could 

be sourcing from the Woodford along the Nemaha uplift on 

the eastern edge of the basin (fig. 9). It is also likely that there 

is some contribution of Ordovician oil into the Hunton Group 

reservoirs as well, based on analyzed Hunton reservoir oils 

(J.R. Hatch, oral commun., 2010).

Reservoir Rocks in the Hunton Group 

Assessment Unit

The Hunton Group is a significant oil reservoir on the 

northern Anadarko Basin margin and a major gas producer 

in the deep (greater than 15,000 ft) basin (fig. 36). Reservoir 

development is largely facies dependent in the Hunton Group 

(Fritz and Medlock, 1994), though the wide range of depositional environments and diagenetic changes were also favorable for reservoir development. Typical facies for reservoir 

units are low-relief skeletal buildups and oolite shoals, both 

of which underwent some post-depositional dolomitization 

(Johnson and others, 2000). 
Figure 30. Depositional model for Chimneyhill subgroup through Bois d’Arc Formation strata of the Hunton Group (modified from Fritz and M

High-Tide LeLow-Tide Le

Lagoon Shoal Shoal

Upper Lower Upper-Shallow L

Lithofacies Supratidal Intertidal Subtidal

MudstoneWackestonePackstoneGrainstone

Major Environments

Sub-Environments

LG-LagoonSH-Shoal

Intertidal

Subtidal

Supratidal

Upper

Upper

Lower

Lower

LG

SH

SH

SH SH

SH

SH

LG

LG

LG

Supra- Tidal

EXPLANATION
Geologic Setting 31

Figure 31. Type log of the Hunton Group in central Oklahoma; 

gray are shales, pink are calcareous shales, blue are limestones, 

and purple represents dolomite (modifed from Fritz and Medlock, 

1994). GR, gamma-ray; R, resisitivity; Miss., Mississippian.

Figure 32. Pre-Woodford Shale subcrop map for 

Oklahoma and the northeast corner of the Texas 

panhandle (modified from Amsden, 1989). Fm, Formation.

 Sch

 

Sh

Df

Hunton strata absent

Sch

Ds

Ouachita Province

Sch

Dhbd

Df

Ds

Sch

?

?

Wichita Fault Zone

Hunton strata absent

? ?

Lower Mississippian–

Upper Devonian

Woodford Shale

Sallisaw Fm

Frisco Fm

Haragan-Bois d’Arc Fm

Henryhouse Fm

Hunton strata absent

Ordovician Silurian Devonian

Lower

Devonian

U. Silurian

(Pridoli–

Ludlow)

L. Silurian

Upper

Ordovician

(Hirnantian)

Ds

Sh

Sch

Df

Dhbd

Clarita Fm

Cochrane Fm

Keel Fm

Chimneyhill

subgroup

Hunton Group

Dhbd

OKLAHOMA

ch5_fig32

Series Type Log Stratigraphic

units at outcrop

Ordovician

(part)

Upper Lower Upper Lower Upper

Silurian Devonian

Sylvan Shale

Keel

Cochrane

Clarita

Henryhouse

Frisco

Woodford 

Bois D’ ArcHaragan

GR

R

Chimney Hill subgroup

Hunton Group

Middle

Miss.

Lower

(part)

Ch5-fig31
32 Geologic Assessment of Undiscovered Oil and Gas Resources in the Anadarko Basin

Figure 33. Image showing approximate distribution of the informal Misener sandstone of Woodford Shale and its relation to 

the Simpson Group subcrop (modifed from Kuykendall and Fritz, 1993).

TEXAS

NEBRASKA

MISSOURI

OKLAHOMA

ARKANSAS

COLORADO

ILLINOIS

MISSISSIPPI

KANSAS

IOWA

Ouachita Thrust Belt

Simpson Group subcrop

Area of Misener sandstone distribution

Ch5_fig33
Geologic Setting 33

Figure 34. Map showing production from the Hunton Group and informal Misener 

sandstone of the Woodford Shale, and Hunton Group thickness; contour interval is 250 feet. 

Black oval is the West Edmond field. TPS, Total Petroleum System; AU, Assessment Unit.

production from the Hunton Group and informal Misener sandstone of the Woodford Shale, and Hunton Group thickness; contou

 oval is the West Edmond field. TPS, Total Petroleum System; AU, Assessment Unit.

Hunton Group thickness, in feet

0

100

250

750

500

1,000

1,250

EXPLANATION

Fault

Hunton Group AU boundary

Woodford Composite TPS boundary

Anadarko Basin Province boundary

Hunton Group and Misener

 sandstone production

0

100

250

500

750

1,000

1,250

0

0

100

0

0

250

500

KANSAS

TEXAS

OKLAHOMA

COLORADO

NEW MEXICO

104° 103° 102° 101° 100° 99° 98° 97°

39°

38°

37°

36°

35°

Nemaha uplift

Pratt anticline

Sooner Trend

Aledo Field Custer City 

North Field

ch5_fig34

0 25 50 MILES

0 25 50 KILOMETERS
34 Geologic Assessment of Undiscovered Oil and Gas Resources in the Anadarko Basin

Figure 35. Hunton Group Assessment Unit events chart showing 

the timing of source rock deposition and trap formation, and the age 

of overburden, reservoir, and seal rocks with different color bars 

(black, source rock; gray, overburden rock; blue, reservoir rock; 

pink, seal rock; purple, trap formation; dark green, generation; light 

green, migration accumulation). The chart also depicts the timing of 

oil generation, migration and accumulation as modeled for various 

wells in different parts of the Anadarko Basin. Ma, mega-annum; 

Plio, Pliocene; Mio, Miocene; Olig, Oligocene; Eoc, Eocene; Pal, 

Paleocene; L, Late; M, Middle; E, Early.

Intracratonic Basin

Potential Arbuckle Group starting approximately340 Ma, Woodford Shale approximately 335 Ma

Source rockOverburden rockReservoir rockSeal rockTrap formationBasin Type

Geologic 

time 

scale

(Ma)

Petroleum

system events

GenerationMigration/accumulation

Pal

Eoc

Olig

Mio

0

100

200

300

400

50

150

250

350

Paleogene

Cretaceous

Jurassic

Triassic

Permian

65.5

146

200

251

359

416

Silurian

Devonian

299

318

E

E

E

E

E

E

E

E

M

M

M

M

L

L

L

L

L

L

L

L

Mississippian

Pennsylvanian

Neogene

23

Plio

Ordovician

Cambrian

542

488

444

450

500

550 Precambrian

ch5-fig35
Geologic Setting 35

Figure 36. Map showing oil and gas production and dry hole penetrations for the Hunton 

Group and informal Misener sandstone of the Woodford Shale in the Anadarko Basin 

Province (IHS Energy Group, 2010). Structure contours are drawn on the top of the Hunton 

Group; contour interval is 2,000 feet. The Anadarko Basin Province boundary is the black line, 

the Woodford Composite Total Petroleum System (TPS) boundary the red line, and the Hunton 

Group Assessment Unit (AU) Boundary the blue line.

Arbuckle

Mountains

Central Kansas uplift

Nemaha uplift

Pratt anticline

-6,000

-8,000

-4,000

-10,000

-12,000

-14,000

-22,000

-16,000 -18,000

-24,000

-20,000

-18,000

-6,000

-18,000

0 -8,000

-8,000

0

-4,000

-2,000

-20,000

-4,000

0

0

0

-8,000

-4,000

-6,000

0

KANSAS

TEXAS

OKLAHOMA

COLORADO

NEW MEXICO

104° 103° 102° 101° 100° 99° 98° 97°

39°

38°

37°

36°

35°

ch5_fig36

Hunton Group Top, elevation in feet

above sea level

-26,000

-24,000

-22,000

-20,000

-18,000

-16,000

-14,000

-12,000

-10,000

-8,000

-6,000

-4,000

-2,000

0

2,000

EXPLANATION

Hunton Group dry holes Woodford TPS

Fault

Hunton Group AU boundary

Woodford Composite TPS boundary

Anadarko Basin Province boundary

Hunton Group oil production

Hunton Group gas production

0 25 50 MILES

0 25 50 KILOMETERS
36 Geologic Assessment of Undiscovered Oil and Gas Resources in the Anadarko Basin

Fracturing, dolomitization, and dissolution are important 

factors for porosity development in the Hunton. Most Hunton 

reservoirs are in dolomitized rock. Upper subtidal and lower 

intertidal facies are dolomitized and have higher porosity (Wilson and others, 1991). Porosity ranges from 3 to 12 percent 

with an average of 8.6 percent over a depth range of 9,000 to 

19,500 ft (Ball and others, 1991). Significant porosity formation in the Hunton is commonly in oolitic dolomitized grainstones and dolomitized burrowed wackestones and packstones 

(Fritz and Medlock, 1994). The exception is the Frisco Formation (fig. 31), which is sparsely dolomitized and generally has 

interparticle and intraparticle porosity combined with moldic 

to vuggy porosity, as it has undergone multiple diagenesis 

phases (Fritz and Medlock, 1994; Medlock, 1984). Hydrocarbon accumulations in the Frisco are mainly in stratigraphic 

traps situated downdip of the areas where the formation has 

been severely truncated (Morgan and Schneider, 1981). Some 

giant fields that produce from the Devonian Frisco Formation 

include the Fitts and West Edmond fields. The West Edmond 

field in northwest Oklahoma County produces where the 

Hunton is truncated on the west flank of the Nemaha uplift. 

Most Hunton fields are west of the Nemaha uplift on 

the northeastern shelf of the Anadarko Basin. Another major 

region of production is in central Oklahoma (Johnson and 

others, 2000; fig. 34), and on the north flank of the Anadarko 

Basin, including the Sooner Trend, Aledo, and Custer City 

North fields. Unlike the Arbuckle, Simpson, and Viola, where 

production is largely dependent on structures, the Hunton 

production is unique in that it extends away from structural 

features. There has also been a substantial amount of production near the Hunton erosional edge near the KansasOklahoma border.

Production from the Misener sandstone has been concentrated in the northeast corner of the AU, especially in Garfield, 

Grant, and Alfalfa Counties (fig. 37). Most of the production 

from the unit is reported commingled with that of the Hunton 

Group. It is a common target where present because of its 

shallow depth.

The Hunton Group AU boundary is defined by the 

Nemaha uplift on the east, the Precambrian fault system 

along the Arbuckle uplift to the south, and the Hunton subcrop and production to the east and north (fig. 34). The AU 

boundary was drawn slightly beyond the subcrop to account 

for remnant islands of Hunton carbonates that may have 

production potential. 

Traps and Seals in the Hunton Group 

Assessment Unit

Most Hunton accumulations are in structure-stratigraphic 

combination traps, typically formed by the truncation of 

porous carbonate across structural noses (Fritz and Medlock, 

1994). Most structures containing Hunton strata produce from 

the Hunton, but truncation traps are most common (Johnson 

and others, 2000). Another reservoir configuration in the 

Hunton Group is trapping by permeability barriers that are 

the result of facies changes along structural noses or faults. 

The upper surface of the Hunton is sculpted by the regional 

pre-Woodford unconformity, and these erosional structures 

also shape the traps on the basin margin (Ball and others, 

1991). Weathering of the Hunton Group that occurred during 

pre-Woodford time and Pennsylvanian time also increased 

porosity and permeability.

The overlying Devonian–Mississippian Woodford Shale 

is a seal for the Hunton carbonates in the majority of the areas 

of the basin where the Hunton Group is present (fig. 35). However, the Woodford Shale is absent in some areas, and Mississippian strata form a seal for Hunton Group reservoirs in the 

Oklahoma and Texas Panhandles. There are also tight, lowporosity intervals within the Hunton Group that form intraformational seals for some reservoirs. Traps for the Misener 

sandstone are mainly stratigraphic, with some minor structural 

influence. Seals are likely interbedded shales.

Sizes and Numbers of Undiscovered Fields in 

the Hunton Group Assessment Unit

The Hunton Group is a prolific oil- and gas-producing 

unit in the Midcontinent. Some of the greatest potential 

for Hunton Group production is in the deepest parts of the 

Anadarko Basin, and some of the deepest gas fields in the 

world are located in the Hunton Group at depths below 

20,000 ft along the Oklahoma-Texas border (Fritz and Medlock, 1994; fig. 36). Gas recovery in the basin increases with 

depth. Well spacing does not seem to have a significant effect 

on gas recovery, and most spacing on deep wells is 640-acre 

units (Smith and others, 2000). 

The Hunton Group is a heterogenous reservoir, with 

a large amount of vertical and lateral variability. It is well 

explored and penetrated through most of the AU, but it is 

underexplored in the southwestern and north-central parts of 

the AU, where potential may exist, especially in stratigraphic 

plays (fig. 36).

There are 81 Nehring accumulations reported for the 

Hunton Group and Misener sandstone (fig. 38). Of these, 6 oil 

fields and 18 gas fields have accumulation data reported in the 

Nehring database (Nehring Associates, Inc., 2009). Cumulative oil production in the Hunton Group AU is 290 MMBO in 

the Hunton Group and 55 MMBO from the Misener sandstone 

(IHS Energy, 2010). Cumulative gas production is 5 TCFG 

from the Hunton and 127 BCFG from the Misener (IHS Energy 

Group, 2010). Production depths range from 4,000 ft to over 

25,000 ft in the deepest part of the basin (fig. 36). There is an 

overlap in the oil and gas production, especially along the eastnortheast AU boundary and in the Texas Panhandle.

Using the USGS assessment methodology for undiscovered conventional resources (Klett and others, 2005; Schmoker 

and Klett, 2005), it is estimated that the undiscovered oil 

resources for conventional reservoirs in the Hunton Group AU 

have a mean of 9 MMBO and 310 BCFG (table 1). Estimates 

of the minimum, median, and maximum numbers of (1) undiscovered oil accumulations exceeding the minimum size are 1, 
Geologic Setting 37

Figure 37. Map showing 

production from informal Misener 

sandstone of the Woodford Shale in 

the Anadarko Basin Province (IHS 

Energy Group, 2010). The structure 

contours are on the top of the 

Misener sandstone; contour interval 

is 500 feet. TPS, Total Petroleum 

System; Au, Assessment Unit.

Figure 38. Map showing 

accumulations for the Hunton Group 

Assessment Unit (AU) (Nehring 

Associates, Inc., 2007). Nehring 

accumulations with grown reserve 

accumulation numbers are shown 

in light blue. Accumulations without 

numbers are in purple. TPS, Total 

Petroleum System.

-6,500

-6,000

-7,000

-5,500

-5,000

-7,500

-8,000

-5,000

-5,500

-8,500

-9,000

KANSAS

TEXAS

OKLAHOMA

COLORADO

NEW MEXICO

GARFIELD 

COUNTY

GRANT 

COUNTY

ALFALFA 

COUNTY

Misener sandstone Top,

elevation in feet above sea level

-9,500

-9,000

-8,500

-8,000

-7,500

-7,000

-6,500

-6,000

-5,500

-5,000

EXPLANATION

Fault

Hunton Group AU boundary

Woodford Composite TPS boundary

Anadarko Basin Province boundary

Misener sandstone production

104° 103° 102° 101° 100° 99° 98° 97°

39°

38°

37°

36°

35°

Nemaha uplift

Pratt anticline

ch5-fig37

0 25 50 MILES

0 25 50 KILOMETERS

KANSAS

TEXAS OKLAHOMA

COLORADO

NEW MEXICO

104° 103° 102° 101° 100° 99° 98° 97°

39°

38°

37°

36°

35°

ch5_fig38

Fault

Hunton Group AU boundary

Woodford Composite TPS boundary

Hunton Group Nehring

 accumulations without data

Anadarko Basin Province boundary

EXPLANATION

Hunton Group Nehring

 accumulations with data

Nemaha uplift

Pratt anticline

0 25 50 MILES

0 25 50 KILOMETERS
38 Geologic Assessment of Undiscovered Oil and Gas Resources in the Anadarko Basin

3, and 15 and (2) undiscovered gas accumulations exceeding 

the minimum size are 1, 10, and 50. The Hunton has been 

well-explored on the shelf and along the Nemaha uplift, and in 

the southwest part of the AU in the Texas Panhandle (fig. 36). 

There is undrilled area in the deep basin along structures in 

the same region where the Arbuckle, Simpson, and Viola are 

sparsely drilled. There is potential, especially for gas, in this 

region of the basin from karstification of the Hunton during 

channelization in pre-Woodford time. These channels were 

later filled in with Woodford Shale. In the deep basin, these 

potential gas reservoirs have not been explored. 

Estimates of the minimum, median, and maximum numbers for the sizes of undiscovered oil accumulations are 0.5, 

1.0, and 20 MMBO. The 0.5 MMBO default signifies that there 

will be at least one field discovered greater than the minimum 

size, and the maximum reflects the large sizes of some of the 

historical Hunton oil accumulations, such as West Edmond 

field (100 MMBO), and along the Sooner trend (380 MMBO 

commingled; Nehring Associates, Inc., 2009). Estimates of 

the minimum, median, and maximum numbers for the sizes of 

undiscovered gas accumulations are 3, 10, and 200 BCFG. The 

maximum is raised to account for deep basin gas potential.

Conclusions

The Woodford Composite TPS includes the conventional 

Arbuckle-Ellenburger Group, Simpson Group, Viola Group 

and Hunton Group AUs. The Cambrian-Ordovician Arbuckle 

and Ellenburger Groups have produced 52 MMBO and 

285 BCFG as of this assessment, with reservoirs concentrated 

in dolomitized Arbuckle strata on the shelf of the Anadarko 

Basin in Kansas and Oklahoma. The reservoirs are concentrated along structures and in combination structural-stratigraphic traps. Seals are low porosity zones of the Arbuckle 

Group or overlying, impermeable shales of the Simpson 

Group. The Arbuckle reservoirs are primarily sourced by the 

Woodford Shale, with contribution from Ordovician source 

rocks. The source rock potential of the Arbuckle Group has 

been debated, and it is suggested that the Arbuckle Group is 

self-sourcing. The results of 1D and 3D modeling indicate the 

Arbuckle Group is overmature in the deep basin and in the oil 

window on the basin shelf. Undiscovered potential exists in 

the undrilled areas in the deep basin along the flanks of structures. Gas production is likely in the deep basin, where the 

Arbuckle Group is mature to overmature for gas production.

The Simpson Group has produced 470 MMBO and 

1.2 TCFG, with reservoirs in blanket sandstones with high 

porosity and permeability, and minor contributions from 

carbonate reservoirs. Production is concentrated in structural 

traps along the eastern edge of the basin and up into Kansas 

south of the Central Kansas uplift. Seals are interbedded tight 

carbonates and shales. The Simpson reservoirs are sourced by 

Ordovician source rocks and the Woodford Shale. Source rock 

potential of the Simpson is considered moderate. Undiscovered potential exists in the undrilled deep basin.

The Viola Group has produced 112 MMBO and 

505 BCFG, with reservoirs in limestones and dolomites that 

have been subjected to fracturing and dissolution to create secondary porosity. Production is in areas similar to the Simpson, 

along the eastern part of the Anadarko Basin. Traps are structural and combination structural-stratigraphic, and seals are the 

overlying Sylvan Shale or interbedded tight carbonates of the 

Viola Group. The Viola reservoirs are sourced by Ordovician 

source rocks and the Woodford Shale. Undiscovered potential is 

in the deep basin, in areas similar to the Arbuckle and Simpson.

The Hunton Group has produced 290 MMBO and 5 TCFG. 

Reservoirs are in carbonates of the Hunton Group and sandstones 

of the Misener. Misener sandstones are dominant reservoirs 

within the Hunton AU, producing 55 MMBO and 127 BCFG. 

Production is in a more limited area because of erosion of the 

Hunton throughout much of the basin; it is concentrated along 

the northeast and east portion of the AU. Traps are structural and 

stratigraphic and seals are interbedded tight carbonates of the 

Hunton and the overlying Woodford Shale. Source rocks for the 

Hunton reservoirs are the Woodford Shale, with possible contributions from Ordovician rocks. Undiscovered potential is in the 

deep basin, especially for reservoirs within the Hunton Group. 

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42 Geologic Assessment of Undiscovered Oil and Gas Resources in the Anadarko Basin

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Chapter 6

Petroleum Systems and Assessment of 

Undiscovered Oil and Gas in the Anadarko 

Basin Province, Colorado, Kansas, 

Oklahoma, and Texas—Woodford Shale 

Assessment Units

By Debra K. Higley, Troy A. Cook, and Mark J. Pawlewicz

Chapter 6 of 13

Petroleum Systems and Assessment of Undiscovered Oil and Gas 

in the Anadarko Basin Province, Colorado, Kansas, Oklahoma, and 

Texas—USGS Province 58

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Suggested citation:

Higley, D.K., T.A. Cook, M.J. Pawlewicz, 2014, Petroleum systems and assessment of undiscovered oil and gas in 

the Anadarko Basin Province, Colorado, Kansas, Oklahoma, and Texas—Woodford Shale Assessment Units, chap. 6, 

in Higley, D.K., compiler, Petroleum systems and assessment of undiscovered oil and gas in the Anadarko Basin 

Province, Colorado, Kansas, Oklahoma, and Texas—USGS Province 58: U.S. Geological Survey Digital Data Series 

DDS–69–EE, 24 p., http://dx.doi.org/10.3133/ds69EE.

ISSN 2327-638X (online)
iii

Contents

Abstract...........................................................................................................................................................1

Introduction.....................................................................................................................................................1

Geologic Setting of the Anadarko Basin Province...................................................................................5

Petroleum Source and Reservoir Rocks....................................................................................................5

Thermal Maturation.....................................................................................................................................12

Traps and Seals............................................................................................................................................17

Petroleum Production History ...................................................................................................................17

Conclusions...................................................................................................................................................20

Acknowledgments.......................................................................................................................................21

References Cited..........................................................................................................................................21

Figures

1. Map showing boundaries of the Anadarko Basin (red line) and the Woodford

Composite Total Petroleum System (TPS). The contained Woodford Shale Oil and

Woodford Shale Gas AUs are discussed in this chapter of the report. Green AU

boundary approximately encloses all Woodford Shale within the province. The

Henry House Creek quarry and State Route 77D outcrop locations are marked 

by the blue dot near the southeast corner of the figure. Background is surface 

elevation.........................................................................................................................................2

2. Generalized surface and subsurface stratigraphic columns for the Anadarko Basin

Province. The horizontal red line divides assessment units (AUs) and total

petroleum systems (TPSs) into those of the (above) Pennsylvanian Composite TPS

and (below) Woodford Composite TPS. Italics (blue text) indicate informal names.

Formal formation- and member-rank units are not necessarily differentiated (as

used by Bebout and others, 1993). Modified from Bebout and others (1993) and

Henry and Hester (1995). Ages in millions of years before present (Ma) from Haq

and Van Eysinga (1998) and Gradstein and others (2004) (red text). Intervals with

vertical bars and wavy horizontal lines represent time periods of nondeposition

and (or) erosion. Formation, Fm.; Member, Mbr......................................................................4

3. Map showing elevation on the top of the Woodford Shale in the 4D model layer.

Extent of the Woodford Shale in the Anadarko Basin is approximated by that of the

Woodford Shale Oil AU (pink line). Contours outside this boundary represent the

highest elevation of underlying model layers. The Woodford Shale is also located

east and northeast of the basin. The Woodford Shale Gas AU boundary (white line)

corresponds to a thickness of about 75 feet (25 meters) and a transformation ratio

of 0.99 percent, based on Woodford hydrous pyrolysis modeling. The black line

corresponds to location of the southwest to northeast cross sections in figure 12.

Precambrian faults (dark blue lines) and named structures are from Adler and

others (1971) ..................................................................................................................................6
iv

4. Generalized paleogeography at 360 million years before present showing marine

influx (blue) near the end of Woodford Shale deposition (modified from Blakey,

2011). Ground surface is shades of brown. Superimposed Neoproterozoic and early

Paleozoic rifts and continental margin (modified from Shatski, 1946; Perry, 1989)

(purple line) shows possible Cambrian failed southern Oklahoma rift (SOA) along

the southern boundary of and southeast of the Woodford Shale Gas assessment

unit (AU) (pink line). The SOA approximates the northern border of the Wichita

Mountain and Amarillo uplifts. Green line is the Woodford Shale Oil AU. Woodford

extent is not shown outside of the Anadarko Basin Province..............................................6

5. Three-dimensional isopach image of the Woodford Shale in the Anadarko Basin.

Vitrinite reflectance (% R

o

) contours (white lines) from figure 11 approximate the

end of oil generation at about 1% R

o

, to onset of dry gas generation at 2% R

o

, and

overmature for petroleum generation at 4% R

o

. Well locations (white dots) are, from

left to right, Bertha Rogers 1, Petree 1, and Streeter 1. Woodford thickness is

derived from Rottmann (2000b, pl. 2), analysis of more than 100 well logs, and

edited formation tops from IHS Energy (2009a, 2009b). Faults (red) are from

Rottmann (2000a, pl. 3). Image is tilted and 1,300 times vertical exaggeration..................7

6. Generalized stratigraphic column for the Anadarko Basin Province, with petroleum

source rocks identified with brown text. Increases in source rock potential are

indicated by larger numbers. Petroleum source rocks may be more oil-prone

(green) or gas-prone (red). Chart is modified from Burruss and Hatch (1989) and

Hatch (oral commun., 2010). Italicized text indicates informal names. Vertical lines

show a generalized time range of unconformity from Bebout and others (1993, fig.

5). Gp., Group; Fm., Formation.....................................................................................................8

7. Photograph showing outcrop of Woodford Shale is as much as 231 feet. thick and

is located on private property in the Henry House Falls quarry, sec. 6, T. 2 S., R. 1 E.,

on the south side of the Arbuckle uplift (Paxton, 2007) (fig. 1). Shown is a portion of

the upper member of the Woodford Shale. It was described by Paxton (2007) as an

organic-rich finely laminated fissile shale. The three resistant lighter-colored beds

at Stan Paxton’s thigh level are finely crystalline dolomite with hydrocarbon

saturation. Spherical phosphate nodules are present above the upper dolomite

layer. The upper member at this location is about 55 percent siliceous beds, 44

percent fissile beds, and 1 percent dolomite zones ...............................................................9

8. Photographs showing outcrop of a slightly overturned lower member of Woodford

Shale beds next to State Route 77D, in NE 1⁄4 sec. 30, T. 1 S., R 2 E., Murray County,

Oklahoma (fig. 1). Stratigraphically up is to the left on the road-cut image. Red

arrow on the upper right points to a fault and associated fault gouge, some of

which is saturated with hydrocarbon. This section, as described in Paxton and

Cardott (2008), strikes N. 70o W and dips 68o to the southwest, is highly siliceous,

and was highly susceptible to fracturing during the structural deformation. Strata

are generally less fissile than those in figure 7 .....................................................................10

9. Photograph showing detail of fracture patterns in the lower member of the

Woodford Shale at the State Route 77D outcrop photo from Paxton and Cardott

(2008) (fig. 1). Spacing and orientation of fracture patterns in the dark gray

siliceous shale differ from those in the underlying light-colored chert-rich facies........10
v

10. Map showing total organic carbon (TOC) for the Woodford Shale based on data

from Burruss and Hatch (1989) and mean estimated values from Hester and others

(1990). TOC ranges from 0.08 to 14.05 wt% and averages 3.7 wt% based on core and

well log density calculations from 123 wells. There is considerable TOC variation,

but almost the entire area that is thermally mature for petroleum generation

contains greater than 2 wt% TOC. Decrease in TOC in the deep basin is partly the

result of elevated levels of thermal maturation. Oil and gas generation depletes

TOC and hydrogen indices (HI)—the fuels for petroleum—so original TOC and HI

values would have been greater. Pink lines are Precambrian faults from Adler and

others (1971) ................................................................................................................................11

11. Maps showing A, calculated vitrinite reflectance (% R

o

) (Sweeney and Burnham,

1990) and B, transformation ratios (% TR) for the Woodford Shale from the

four-dimensional petroleum system model. The three-dimensional rendering

results in variable shading within contours. Pink contour line on the % R

o

 map and

the gas-oil ratio (GOR) inset corresponds to the 99% TR end of oil generation. The

inset bubble symbols are GOR, with larger bubbles representing greater GOR.

Greatest thermal maturation is in the deep basin of Oklahoma and Texas, whereas

most of Colorado and Kansas is immature for oil generation, as characterized by an Ro

 of about 6 percent and TR of 0.1 percent and greater. Blue lines are Precambrian

faults from Adler and others (1971)..........................................................................................13

12. South to north thermal maturation cross sections showing transformation ratios (%

TR) through time based on Woodford Shale hydrous pyrolysis kinetics from Lewan

(1983, 1985), and Lewan and Ruble (2002). Pink and dark blue lines are the

respective Woodford Shale and Thirteen Finger lime model layers. Cross section

location is in figure 3. Modeled vitrinite reflectance (R

o

) lines mark the boundaries

for generation and overmaturity for dry gas. Millions of year ago, Ma.............................14

13. History of petroleum generation from the Oil Creek Formation, Woodford Shale, and

Thirteen Finger lime (fig. 2) source layers in the four-dimensional petroleum system

model. History is based on Woodford hydrous pyrolysis kinetics (Lewan and Ruble,

2002). Shaded area brackets the main period of peak oil generation from the

Woodford Shale. Early oil generation from the Oil Creek layer, prior to about 70

million years ago, is in a narrow strip in the model that is proximal to the Wichita

Mountain uplift. This strip exceeds maximum depth of the formation and is

primarily the result of areas of poor data control in the area bordering the fault

zone. The error could have been removed by clipping the four-dimensional model

extent to the basin axis and northward, but less of the model would have been

visible and usable .......................................................................................................................15

14. Events chart for the Woodford Shale Gas assessment unit (AU) and Woodford

Shale Oil AU. Timing of oil and gas generation, migration, and accumulation is

based primarily on vitrinite reflectance and transformation ratios through time

from one-dimensional and four-dimensional (4D) models (Higley, 2014a). Timing of

oil generation (gray polygon) is also based on (unpublished) volumes of petroleum

generated through time using the 4D model; peak generation from the Woodford

Shale (blue bars) is from about 310 to 230 million of years before present (Ma). A

second phase of generation from about 80 to 50 Ma is associated with deposition

and erosion of strata associated with the Laramide orogeny. Lithofacies

assignments in the “Formations” row are intended only to show periods of

unconformities (wavy and horizontal lines) and deposition. Plio, Pliocene; Mio,

Miocene; Eoc, Eocene; Pal, Paleocene; L, Late; M, Middle; E, Early.................................16
vi

15. Map showing oil and gas wells that produce from the Devonian-Mississippian

Woodford Shale Oil and Woodford Shale Gas assessment units (AUs) in the

Anadarko Basin Province (code number 58) (IHS Energy, 2009a, 2010, 2011). Shown

also are AU code numbers. Some wells include production from other units,

primarily the Silurian-Devonian Hunton Group, Devonian informal Misener sand,

and Mississippian strata. The Woodford Composite TPS code is 50580.

Precambrian faults (pink) are from Adler and others (1971) ...............................................18

16. Map showing oil wells (green dots) and gas wells (red dots) that produce from the

Woodford Shale in the Anadarko Basin Province (IHS Energy, 2009a, 2010, 2011).

White dots are wells that are productive only from the Woodford Shale based on

a November 2011 retrieval of data from IHS Energy (2011). White dot wells that do

not contain oil or gas wells were added to the IHS database since the January

data retrieval. Extent of the Woodford Shale in the province is approximated by the

Woodford Oil AU line. Thickness was derived from Rottmann (2000b, pl. 2), analysis

of more than 100 well logs, and edited formation tops from IHS Energy (2009a,

2009b). The Kansas portion of the province contains variable thicknesses of

Woodford Shale, and the Oklahoma and Texas portions have several small

erosional remnants. The generalized location of the informal Misener sand (light

blue line) in the lower part of the Woodford Shale (fig. 2) is modified from Amsden

and Klapper (1972) and IHS Energy (2009a, 2009b). The Misener sand exhibits

variable thickness and distribution, and is also present in isolated lows in the

eroded, karst surface of the Hunton Group (Gaswirth and Higley, 2014). Pink lines

are Precambrian faults from Adler and others (1971) ..........................................................18

17. Discovery thirds for 74 wells with reported cumulative gas production from only the

Woodford Shale from 1946 to September, 2009 (IHS Energy, 2010). The apparently

poor production from the 3rd third is misleading, and actual performance is

probably greater, particularly with the present focus on horizontal wells. Reasons

for the spread in data include that early production likely incorporates (unreported)

oil and gas from the conventional basal Misener sand of the Woodford shale and

(or) bounding reservoirs, and the 3rd third only represents 6 months of Woodford

Shale gas from 24 wells. Average gas/oil ratio of the above data set is 237,000

cubic feet of gas per barrel of oil. Million cubic feet of gas, MMCFG...............................19

18. Map showing Woodford Shale calculated gas estimated ultimate recoverable

(EUR) ranges from about 0.1 million (MMCFG) to 11.9 billion cubic feet of gas for 76

wells based on production history from IHS Energy (2010). The dense cluster of

wells has contoured values, whereas those outside are measured values. Inset

map of contoured values is magnified 300 percent. Most gas production is located

at the 1.2% R

o

 and greater Woodford Shale contours created using data from

Cardott (1989), Price (1997), Chesapeake Energy Corporation (2009), and Mark

Pawlewicz. Faults (brown lines) on the underlying Hunton Group (Rottmann, 2000a)

were used to create the Woodford layer and to contour R

o

 values...................................20
vii

Tables

1. Anadarko Basin Province assessment results are listed by name and code of total

petroleum system (TPS) and assessment unit (AU)................................................................3

2. Oil generation onset for the Anadarko Basin four-dimensional model, and onset

and completion dates in millions of years before present (Ma) for the Bertha

Rogers 1 and Petree Ranch 1 one-dimensional models based on Woodford Shale

hydrous pyrolysis kinetics (Lewan and Ruble, 2002). The Douglas Group overlies

the youngest potential petroleum source rocks in figure 6. The HP kinetics-based

onset of oil generation is 0.1% TR and completion is 99% TR. Oil generation

histories in the four-dimensional model were recorded at 10 million year

increments, so the plus symbol indicates onset was before the listed age.....................17

Abstract

The Woodford Composite Total Petroleum System in the 

Anadarko Basin Province includes assessment units of Cambrian through Lower Mississippian oil and gas reservoirs. Two 

of the assessment units are continuous (unconventional)—the 

Woodford Shale Gas assessment unit and The Woodford 

Shale Oil assessment unit of the Upper Devonian and Lower 

Mississippian Woodford Shale. Assessment unit boundaries 

were defined based on extent, thickness, and levels of thermal maturation of this reservoir/source unit. The assessment 

units are self-sourced from this rich petroleum source rock, 

with thermal maturity ranging from marginally mature for oil 

generation on the basin shelf to overmature for gas generation 

in the deep basin. The Woodford Shale Oil assessment unit 

boundary is approximated by the extent of the Woodford Shale 

in the basin; mean assessed resources are 393 million barrels 

of oil, 1.963 trillion cubic feet of gas (TCFG), and 59 million 

barrels of natural gas liquids. The Woodford Shale Gas assessment unit is located in the deep basin of Oklahoma and Texas. 

The assessment unit area includes a Woodford Shale thickness 

of approximately 75 feet (25 meters) and greater, and a transformation ratio of 0.99 percent based on Woodford hydrous 

pyrolysis kinetics modeling; this corresponds to a vitrinite 

reflectance of about 1.2 percent. Mean undiscovered assessed 

resources for the Woodford Shale Gas assessment unit are 

15.973 trillion cubic feet of gas and 192 million barrels of 

natural gas liquids. 

Introduction

The U.S. Geological Survey (USGS) completed an 

assessment of the undiscovered oil and gas resource potential 

of the Anadarko Basin Province of western Oklahoma and 

Kansas, northern Texas, and southeastern Colorado (fig. 1). 

The province area includes the Las Animas arch of southeastern Colorado, part of the Palo Duro Basin of Texas, and the 

Anadarko Basin. This assessment is hereafter referred to as 

the 2011 assessment, which corresponds to the publication 

release date of the results (Higley and others, 2011). Results 

of the geologic analysis and resource assessment are based on 

the geologic elements of each defined total petroleum system 

(TPS), including hydrocarbon source rocks (source-rock maturation, hydrocarbon generation and migration), reservoir rocks 

(sequence stratigraphic and petrophysical properties), hydrocarbon traps (trapping mechanisms and timing), and seals. 

Using this geologic framework, the USGS defined 2 TPS 

and 12 included Assessment Units (AUs), and quantitatively 

estimated the undiscovered oil and gas resources within these 

9 conventional and 3 continuous AUs (table 1). TPSs and AUs 

are listed below. 

Woodford Composite TPS 505801:

1. Arbuckle-Ellenburger, AU 50580101

2. Simpson Group, AU 50580102

3. Viola Group, AU 50580103

4. Hunton Group, AU 50580104

5. Mississippian, AU 50580105

6. Woodford Shale Gas, AU 50580161

7. Woodford Shale Oil, AU 50580162

Pennsylvanian Composite TPS 505802:

1. Morrowan-Atokan, AU 50580201

2. Desmoinesian, AU 50580202

3. Missourian-Permian, AU 50580203

4. Greater Granite Wash Composite, AU 50580204

5. Thirteen Finger Limestone–Atoka Shale Gas, AU 

50580261

Continuous AUs are the Devonian and Mississippian 

(1) Woodford Shale Gas and (2) Woodford Shale Oil of the 

Woodford Composite TPS, and (3) the Pennsylvanian Thirteen Finger Limestone–Atoka Shale of the Pennsylvanian 

Petroleum Systems and Assessment of Undiscovered 

Oil and Gas in the Anadarko Basin Province, Colorado, 

Kansas, Oklahoma, and Texas—Woodford Shale 

Assessment Units

By Debra K. Higley, Troy A. Cook, and Mark J. Pawlewicz
2 Petroleum Systems and Assessment of Undiscovered Oil and Gas in the Anadarko Basin Province

Composite TPS. The Woodford Shale Oil and Woodford 

Shale Gas AU assessment and geologic review are included in 

this chapter of the report. Description of the Thirteen Finger 

Limestone–Atoka Shale Gas AU is included in Higley (2014a, 

2014b), and associated oil resources are assessed as conventional within the Morrowan-Atokan AU. The stratigraphic chart 

shows units within the Woodford Composite TPS (fig. 2).

The Woodford Composite TPS encompasses all included 

AU boundaries, although only the Woodford Shale Gas and 

Woodford Shale Oil AUs are shown in figure 1. Assignment 

of Woodford AU boundaries and assessment results were 

based primarily on (1) the lateral extent and thickness of the 

Woodford Shale, (2) timing and degree of thermal maturation of the Woodford Shale based on one-dimensional and 

four-dimensional (4D) petroleum system models of the basin 

(Higley, 2014a) and published vitrinite reflectance data, and 

(3) faults and other structures that would limit or enhance oil 

and gas accumulations. The “fingers” appearance of the Woodford Shale Gas AU boundary partly reflects Woodford deposition in eroded channels of the unconformably underlying 

Silurian-Devonian Hunton Group. Results of the oil, gas, and 

natural gas liquids (NGL) assessment are in table 1 and Higley 

and others (2011).

The 4D petroleum system model consists of stacked 

grids of lithostratigraphic units that are referred to as layers. 

Each layer extends across the study area, a requirement of 

the PetroMod® petroleum system modeling software. This 

means that the highest elevation from the underlying layers 

is displayed if the modeled unit(s) has limited lateral extent. 

Model construction and data sources are discussed in Higley 

(2014a) and Higley and others (2014). Maps and models 

were generated using Dynamic Graphics® Earthvision® 

(Dynamic Graphics® and Earthvision® are registered trademarks of Dynamic Graphics, Inc.) and PetroMod® software 

(Schlumberger, 2011). PetroMod® software was used for 1D 

and 4D petroleum system models. Data sources for Woodford Shale isopach and structure surfaces include Rottmann 

(2000a, 2000b), well-log picks from about 100 wells across 

the basin, and edited formation tops from IHS Energy 

(2009a, 2009b).

Figure 1. Map showing boundaries of the Anadarko Basin (red line) and the Woodford 

Composite Total Petroleum System (TPS). The contained Woodford Shale Oil and 

Woodford Shale Gas AUs are discussed in this chapter of the report. Green AU boundary 

approximately encloses all Woodford Shale within the province. The Henry House Creek 

quarry and State Route 77D outcrop locations are marked by the blue dot near the southeast 

corner of the figure. Background is surface elevation.

OKLAHOMA

COLORADO KANSAS

TEXAS

NEW

MEXICO

Woodford 

Composite TPS

Woodford Shale Oil AU

Woodford Shale 

Gas AU

Anadarko Basin

104° 103° 102° 101° 100° 99° 98° 97° 

39° 

38° 

37° 

36° 

35° 

34° 

Denver

Basin

Raton

Basin

 Las 

 Animas

arch

Palo

Duro

Basin

Nemaha uplift

Central Kansas uplift

Salina

Basin

Hardeman 

Basin

0 50 100MILES

0 50 100KILOMETERS

GULF 

OF 

MEXICO

TEXAS

NEW

MEXICO

COLORADO KANSAS

OKLAHOMA

Anadarko 

 Basin 

 Province

Figure 1. Ch. 6 
Introduction 3

Table 1. Anadarko Basin Province assessment results are listed by name and code of total petroleum system (TPS) and assessment 

unit (AU).

[Resources are undiscovered oil, gas, and (or) natural gas liquids. MMBO, million barrels of oil; BCFG, billion cubic feet of gas; MMBNGL, million barrels of 

natural gas liquids. Type refers to mainly oil or gas accumulations in the assessment unit. Fractiles are fully risked estimates. F95 denotes a 95-percent chance of 

at least the amount tabulated. Other fractiles are defined similarly. Fractiles are additive only under the assumption of perfect positive correlation]

Total Petroleum Systems 

(TPS) and Assessment Units 

(AU)

Field 

Type

Total Undiscovered Resources

Oil (MMBO) Gas (BCFG) NGL (MMBNGL)

F95 F50 F5 Mean F95 F50 F5 Mean F95 F50 F5 Mean

Woodford Composite TPS

Arbuckle-Ellenburger AU

Oil 2 5 12 6 7 24 61 28 0 1 2 1

Gas 43 164 371 181 0 1 2 1

Simpson Group AU

Oil 2 4 9 5 6 17 39 19 0 0 1 1

Gas 33 114 252 125 2 9 21 10

Viola Group AU

Oil 2 5 10 5 3 9 20 10 0 1 2 1

Gas 10 27 58 30 0 0 0 0

Hunton Group AU

Oil 2 8 21 9 8 32 87 38 0 1 3 1

Gas 71 281 641 310 0 2 4 2

Mississippian AU

Oil 5 16 31 17 15 46 99 50 0 2 4 2

Gas 125 350 663 367 3 8 17 9

Pennsylvanian Composite TPS

Morrowan-Atokan AU

Oil 6 14 29 15 21 55 121 61 1 2 5 2

Gas 101 261 469 271 2 5 10 5

Desmoinesian AU

Oil 2 6 12 6 8 23 52 26 0 1 2 1

Gas 29 87 167 92 1 3 5 3

Missourian-Permian AU

Oil 10 22 38 23 49 114 223 122 2 4 8 4

Gas 61 130 231 136 2 4 7 4

Greater Granite Wash 

Composite AU

Oil 4 14 34 16 22 78 198 90 1 2 7 3

Gas 192 646 1,496 719 7 24 60 27

Total Conventional

 Resources 35 94 196 102 804 2,458 5,248 2,675 21 70 160 77

Woodford Composite TPS

Woodford Shale Oil AU

Woodford Shale Gas AU

Oil 175 357 730 393 795 1,750 3,851 1,963 22 51 121 59

Gas 8,806 15,131 25,998 15,973 94 178 336 192

Pennsylvanian Composite TPS

Thirteen Finger LimestoneAtoka Shale Gas AU

Oil

Gas 3,040 6,229 12,763 6,850 33 73 161 82

Total Continuous

 Resources 175 357 730 393 12,641 23,110 42,612 24,786 149 302 618 333

Total Resources 210 451 926 495 13,445 25,568 47,860 27,461 170 372 778 410
4 Petroleum Systems and Assessment of Undiscovered Oil and Gas in the Anadarko Basin Province

Figure 2. Generalized surface and 

subsurface stratigraphic columns for the 

Anadarko Basin Province. The horizontal 

red line divides assessment units (AUs) and 

total petroleum systems (TPSs) into those 

of the (above) Pennsylvanian Composite 

TPS and (below) Woodford Composite TPS. 

Italics (blue text) indicate informal names. 

Formal formation- and member-rank units 

are not necessarily differentiated (as used 

by Bebout and others, 1993). Modified from 

Bebout and others (1993) and Henry and 

Hester (1995). Ages in millions of years 

before present (Ma) from Haq and Van 

Eysinga (1998) and Gradstein and others 

(2004) (red text). Intervals with vertical bars 

and wavy horizontal lines represent time 

periods of nondeposition and (or) erosion. 

Formation, Fm.; Member, Mbr.

ArbuckleEllenburger 

Simpson

Group

Viola

Group

Hunton 

Group

Woodford

Shale 

Gas, Oil

Morrow shale

Puryear sand

Keyes sand

Kearny

Formation

Morrow Group

Morrowan Atokan

Morrow Formation

Lower Upper

Purdy sand

Keyes sand

Dornick Hills 

 shale

Primrose 

Sandstone

Lower Dornick Hills Group (part)

?

443.7

± 1.5

416.0

± 2.8

359.2

± 2.5

318.1

± 1.3

488.3

± 1.7

System

Series

Age, Ma

Hugoton

Embayment

Kansas

Northern

Anadarko

Basin

Southern

Anadarko

Basin

AU

Names

Figure 2. Ch. 6 

348

311

333

340

365

374

379

421

432

452

472

514

Atoka Group Atoka Shale Atoka Shale

Thirteen Finger lime Thirteen Finger lime Thirteen Finger lime

Mississippian Morrowan-Atokan

(part)

Mississippian Pennsylvanian

Chesterian Mera- mecian Osa- gean

Springer Formation Chester Group

Cunningham sand Markham sand

Britt sand

Chester Group Manning zone

Ste. Genevieve Formation

Mississippi lime

St. Louis Formation

Salem Fm. (Spergen Fm.)

Warsaw Formation

Osage chert

Gilmore City Limestone

Hannibal Shale

Meramec

lime

Meramec

lime

Mississippi chat

Mississippi solid

Cowley Formation

Ste. Genevieve Limestone

St. Louis Limestone

Salem Limestone

Warsaw Limestone

Osage limeKinderhook Shale

 Kinderhookian

Cunningham sands

Britt sand Aldridge sand

Spiers sand

Humphreys sand

Boatwright sands

Sims sands

Springer Fm. Mayes Group

Goddard Shale Goodwin sand

Delaware Creek Shale

 (Caney Shale)

Sycamore Limestone

Chautauquan

Upper member

Middle member

Lower member

Misener sand

Upper member

Middle member

Lower member

Woodford Shale

Misener sand

Woodford Shale

Senecan Erian Ulste- rian

Devonian Silurian

Cayugan Niagaran Alexandrian

Hunton Group

Frisco Formation

Bois d'Arc Formation

Haragan Formation

Henryhouse Formation

Chimneyhill Limestone

Hunton Group

Chimneyhill Subgroup Clarita 

 Fm.

Fitzhugh Mbr.

Prices Falls

 Member

Cochrane 

Formation

Keel Formation

Ordovician Cambrian

Cincinnatian Champlainian Canadian

Viola Formation

?

Sylvan Shale Sylvan Shale

Welling Fm.

(Fernvale-Viola)

Viola Springs

 Formation

 Bromide

FormationBromide dense (lime)

Viola Group Simpson Group Arbuckle Group

First Bromide sand

Second Bromide sand

(Third Bromide sand) Tulip Creek Formation

Brown zone

McLish Formation Oil Creek Formation Joins Formation

West Spring Creek Fm.

Kindblade Formation

Cool Creek Formation

McKenzie Hill Formation

Butterly Dolomite Signal Mountain Formation Royer Dolomite

Fort Sill Limestone

Timbered Hills 

 Group

Fernvale Limestone

Trenton Limestone

Arbuckle Group

(undivided)

Arbuckle Group

Reagan (Lamotte)

Sandstone

?

?

Simpson Group

Simpson Group

Bromide Formation

Tulip Creek Formation

McLish Formation

Oil Creek Formation

Joins Formation

(Simpson dense,Wilcox)

Frisco Formation

Bois d'Arc Formation

Haragan Formation

Henryhouse Formation

Bonneterre 

Dolomite

Reagan (Lamotte)

Sandstone

Bonneterre 

Dolomite

(undivided)
Petroleum Source and Reservoir Rocks 5

Geologic Setting of the Anadarko 

Basin Province

The Anadarko Basin Province includes (1) the Anadarko 

Basin, a south-dipping asymmetric basin; (2) the southwestnortheast-trending Las Animas arch, and (3) part of the 

southeast-dipping Palo Duro Basin. The province is bounded 

on the southeast by the Arbuckle uplift and Marietta-Ardmore 

Basin, on the east by the Nemaha uplift and Salina Basin, on 

the north by the Central Kansas uplift, on the west by the Denver and Raton Basins, and on the south by the eroded Amarillo 

and Wichita Mountain uplifts (fig. 3). The Nemaha uplift 

consists of a discontinuous series of block-faulted uplifts, most 

of which are 5 to 20 miles long (north-south) and 3 to 5 miles 

wide, and forms the axis and western boundary of the broad, 

gently raised Central Oklahoma platform (Johnson, 1989) that 

separates the Anadarko and Ardmore Basins. Elevation on the 

top of the Woodford Shale in the province ranges from about 

-2,500 feet (ft) [-760 meters (m)] on the southern Kansas 

shelf, to -27,000 ft (-8,000 m) in the deep basin of southern 

Oklahoma. Extent of the Woodford Shale within the Anadarko 

Basin Province is approximated by the Woodford Shale Oil 

AU boundary in figure 3. The formation is mostly absent 

because of erosion in the Nemaha, Wichita Mountain and 

Amarillo uplifts, although the AU includes an area of Woodford in the Wichita Mountain uplift proximal to the fault zone. 

The Woodford Shale also is present northeast of the province 

in the Salina Basin of Kansas, and is commonly named the 

Chattanooga Shale. The Woodford Shale in the Arkoma Basin 

is also a petroleum source and reservoir rock. The Woodford 

Shale layer was contoured using the data and fault systems of 

Rottmann (2000a, 2000b), who showed the Woodford contact 

with the bounding fault of the Wichita Mountain uplift to be 

north of the Precambrian faults of Adler and others (1971). 

Because of this, Woodford contours terminate basinward of 

the fault system of Adler and others (1971) (fig. 3).

Southern Oklahoma was initially described by Shatski 

(1946) as a failed Cambrian aulacogen. The deepest part of 

the Anadarko Basin is along and north of this rift zone and is 

proximal to its southern margin along the Wichita Mountain 

uplift (fig. 3). This southern Oklahoma aulacogen (Rascoe 

and Adler, 1983) was emplaced on the Precambrian craton as 

described by Ham and others (1964) and is about 100 miles 

(mi) [160 kilometers (km)] wide and 300 mi (480 km) long. 

Most of Late Cambrian through Mississippian time was 

marked by a broad epicontinental sea (Johnson and others, 

1988) that extended across most of the southern Midcontinent 

area, including the Anadarko Basin. Rates of basin subsidence were elevated in the Cambrian but decreased during the 

Silurian, Devonian, and Early Mississippian, one reason why 

Hunton and Woodford rocks are relatively thin (Feinstein, 

1981; Johnson and others, 1988; Johnson, 1989) and of limited 

areal extent. Following Hunton Group deposition and prior to 

Woodford Shale deposition, the entire area was emergent and 

subjected to extensive erosion, and the Amarillo and Wichita 

Mountain uplifts began to form as positive tectonic features 

(Eddleman, 1961). Early Mississippian seas advanced from 

the southeast and stable conditions again prevailed with deposition of mostly marine Mississippian carbonates (Eddleman, 

1961). Ball and others (1991) indicated that the Mississippian 

Period closed with regional uplift and erosion that marked the 

onset of the Wichita orogeny; the associated erosional unconformity further removed Devonian strata on structural highs 

around the basin margin, and truncated formations as deeply 

as the Arbuckle Group. Figure 4 shows generalized paleogeography near the end of Woodford deposition. Euxinic seas 

of the Late Devonian–Early Mississippian were replaced by 

shallow, well-oxygenated marine waters in which fossiliferous (commonly crinoidal, and some oolitic) limestones were 

deposited, some of which were interbedded with shale and siltstone (Johnson, 1989). Depth of water during Woodford deposition is estimated at 160 to 1,300 ft (50 to 400 m) (Krystyniak 

and Paxton, 2006) to less than 500 ft (150 m) (Kirkland and 

others, 1992).

Various tectonic events strongly influenced rates of 

sediment deposition, sediment sources, depositional environments, erosion, and especially burial depths of reservoir, seal, 

and source rocks. During Late Mississippian to Pennsylvanian time, rapid rates of subsidence coincided with tectonic 

development of the Anadarko Basin and the Wichita Mountain 

uplift (Ball and others, 1991; Al-Shaieb and others, 1994). 

Present basin configuration was impacted by movement of the 

late Paleozoic Wichita Mountain fault zone and the Ouachita 

thrust plate (Amsden, 1975, 1989). Depth of burial through 

time is the main control on thermal maturation of petroleum 

source rocks, although oil and gas generation is also influenced by factors such as basement heat flow and thermal 

conductivity of lithofacies.

Petroleum Source and Reservoir Rocks

Thickness of the Woodford Shale varies greatly across 

the province. It ranges up to 375 ft thick and averages 40 ft 

based on Rottmann (2000b), well-log picks from about 

100 wells across the basin, and edited formation tops from 

IHS Energy (2009a, 2009b) (fig. 5). Increased thickness of the 

Woodford Shale and Hunton Group strata southward is probably related more to basin subsidence than sediment supply 

(Amsden, 1989). Greatest thickness of the Woodford is in the 

southern part of the basin in Oklahoma, largely as fill within 

eroded channels of the underlying Hunton Group. This is also 

the basin area that is most thermally mature for gas generation. Areas within the AUs (fig. 1) in which the Woodford is 

absent or thin resulted from erosion or nondeposition, and 

there are a few erosional remnants outside the Woodford Shale 

Oil AU boundary. Smooth contours near the southeastern 

corner of figure 5 reflect limited data and variable thicknesses 

because of extensive faulting. The Misener sand is an informal lower unit of the Woodford Shale (fig. 2) that is located 

mainly in the northeastern part of the basin in Oklahoma and 
6 Petroleum Systems and Assessment of Undiscovered Oil and Gas in the Anadarko Basin Province

Figure 3. Map showing elevation on the top of the Woodford Shale in the 4D 

model layer. Extent of the Woodford Shale in the Anadarko Basin is approximated 

by that of the Woodford Shale Oil AU (pink line). Contours outside this boundary 

represent the highest elevation of underlying model layers. The Woodford Shale 

is also located east and northeast of the basin. The Woodford Shale Gas AU 

boundary (white line) corresponds to a thickness of about 75 feet (25 meters) 

and a transformation ratio of 0.99 percent, based on Woodford hydrous pyrolysis 

modeling. The black line corresponds to location of the southwest to northeast 

cross sections in figure 12. Precambrian faults (dark blue lines) and named 

structures are from Adler and others (1971).

Figure 4. Generalized paleogeography at 360 million years 

before present showing marine influx (blue) near the end of 

Woodford Shale deposition (modified from Blakey, 2011). Ground 

surface is shades of brown. Superimposed Neoproterozoic 

and early Paleozoic rifts and continental margin (modified from 

Shatski, 1946; Perry, 1989) (purple line) shows possible Cambrian 

failed southern Oklahoma rift (SOA) along the southern boundary 

of and southeast of the Woodford Shale Gas assessment unit 

(AU) (pink line). The SOA approximates the northern border of the 

Wichita Mountain and Amarillo uplifts. Green line is the Woodford 

Shale Oil AU. Woodford extent is not shown outside of the 

Anadarko Basin Province.

Neoproterozoic rifted c onti nental m argin

Reelfoot rift

Neoproterozoic rifted c onti nental m argin

Delaware 

aulacogen

SOA

Gulf 

of 

Mexico

TEXAS

NEW

MEXICO

COLORADO KANSAS

OKLAHOMA

Figure 3. Ch. 6 

EXPLANATION

Elevation, in feet

4,000

2,000

0

-2,000

-4,000

-6,000

-8,000

-10,000

-12,000

-14,000

-16,000

-18,000

-20,000

-22,000

-24,000

-26,000

103° 102° 101° 100° 99° 98° 97°

39°

38°

37°

36°

35°

 COLORADO

 

 OKLAHOMA

 

KANSAS

NEW MEXICO Woodford Shale Oil AU

Woodford Shale Gas AU

TEXAS

Wichita 

 Mountain 

 uplift

Nemaha uplift

Arbuckle

uplift

Salina 

Basin

Pratt

anticline

Amarillo uplift

Las Animas arch

Central Kansas uplift

Sierra Grande uplift

Cimarron 

arch

Anadarko Basin

Palo Duro 

Basin

Hardeman Basin

0 50 100 MILES

0 50 100 KILOMETERS
Petroleum Source and Reservoir Rocks 7

Kansas; petroleum resources of this unit were evaluated with 

the Hunton Group AU (Gaswirth and Higley, 2014). Primary 

reasons for this assignment were that Misener sand reservoirs 

are conventional, and much of the petroleum production was 

reported as commingled with that of the Hunton Group.

The primary petroleum source rock for the Woodford 

Composite TPS is the Woodford Shale; additional sources 

may include limestones and (or) shales from the Mississippian 

Mayes Group, and the Ordovician Viola Formation (or Group) 

and Simpson Group (Hatch and others, 1987; Burruss and 

Hatch, 1989) (fig. 6). The Woodford Shale and other petroleum 

source rocks are discussed in more detail in Higley (2014a). 

The Woodford Shale consists of upper, middle, and lower 

informal members of carbonaceous silica-rich fissile and 

non-fissile shales (von Almen, 1970; Sullivan, 1983, 1985; 

Hester and others, 1990; Lambert, 1993; Krystyniak and 

Paxton, 2006). Kirkland and others (1992, fig. 3) indicated 

Woodford Shale lithofacies in northwest Kansas and southeast Nebraska are more carbonate rich than those of the deep 

Anadarko Basin. Based primarily on data from outcrops in 

the Arbuckle Mountains (fig. 3) and well core, Egenhoff 

and others (2011) determined that the upper shale member 

represents a downslope extension of a carbonate or carbonatesiliciclastic shallow marine system into deeper water siliciclastics. Egenhoff and others (2011) indicated that (1) the upper 

shale member is composed primarily of laminated silt-rich 

mudstones with lag deposits; and (2) these facies grade progressively basinward into finer-grained laminated mudstones 

and, (3) most distally, into quartz-rich radiolarian cherts that 

are intercalated with laminated mudstones. The non-fissile 

strata include phosphatic and siliceous shales, dolomite beds, 

phosphatic nodules, and rare chert beds (Krystyniak and 

Paxton, 2006). Fissile shale can also contain dolomite beds 

and phosphate nodules, such as in the upper member outcrop 

Figure 5. Three-dimensional isopach image of the Woodford Shale in the Anadarko Basin. Vitrinite reflectance (% Ro) contours (white 

lines) from figure 11 approximate the end of oil generation at about 1% Ro, to onset of dry gas generation at 2% Ro, and overmature for 

petroleum generation at 4% Ro. Well locations (white dots) are, from left to right, Bertha Rogers 1, Petree 1, and Streeter 1. Woodford 

thickness is derived from Rottmann (2000b, pl. 2), analysis of more than 100 well logs, and edited formation tops from IHS Energy (2009a, 

2009b). Faults (red) are from Rottmann (2000a, pl. 3). Image is tilted and 1,300 times vertical exaggeration.

Figure 5 Ch. 6. 

.

1

2

4

2

400

360

320

280

240

200

160

120

 80

 40

 0

EXPLANATION

Thickness

(meters)

OKLAHOMA

TEXAS

COLORADO KANSAS
8 Petroleum Systems and Assessment of Undiscovered Oil and Gas in the Anadarko Basin Province

Figure 6. Generalized stratigraphic column for the Anadarko Basin Province, with petroleum source rocks identified with brown text. 

Increases in source rock potential are indicated by larger numbers. Petroleum source rocks may be more oil-prone (green) or gasprone (red). Chart is modified from Burruss and Hatch (1989) and Hatch (oral commun., 2010). Italicized text indicates informal names. 

Vertical lines show a generalized time range of unconformity from Bebout and others (1993, fig. 5). Gp., Group; Fm., Formation.

Sumner Gp; Enid Gp.; Hennessey Gp.

System

Series Lithostratigraphic Unit

(HC Source Rocks in Red)

Expected

Hydrocarbons

Relative HC

Source Rock

Potential (1-5)

Permian (part) Pennsylvanian Mississippian Devonian Silurian Ordovician Cambrian (part)

Leonardian

Wolfcampian

Virgilian

Missourian

Desmoinesian

Atokan

Morrowan

Chesterian

Meramecian

Osagean

Kinderhookian

Chautauquan

Cayugan

Cincinnatian

Trempealeauan

Niagaran

Canadian

Champlainian

Chase Group

Council Grove Group

Admire Group

Lansing Group

Kansas City Group 

Marmaton Group

Cherokee Group

Atoka Gp.; Thirteen Finger limestone 

Morrow Gp./Fm.; lower Dornick Hills Gp.

Springer Formation

Chester Group 

Wabaunsee Group

Shawnee Group

Douglas Group

Ada Group

Franconian

Woodford Shale, Chattanooga Shale

Misener sand

Hunton Group

Sylvan Shale; Maquoketa Shale 

Simpson Group

Arbuckle Group

Reagan Sandstone

Alexandrian

Senecan

Pontotoc Group

Viola Group/Formation

Meramec lime

Osage lime

Mayes Group

Hoxbar Group

Deese Group

??

2

5 +

2

?

Kinderhook Shale

Erian

Ulsterian

1-2

1-2

1-2

2-3

1-2

1-2

Gas

Gas Oil

Gas Oil

Oil

Oil

Gas

Gas

Oil

Gas Oil

Gas Oil

Gas Oil

Gas Oil
Petroleum Source and Reservoir Rocks 9

at the Henry House Falls quarry (fig. 7). These fissile shales 

are thin-bedded and laterally continuous. The fissile and nonfissile shales exhibit different fracture behavior; shale from 

the upper member is thin-bedded and fairly friable (fig. 7), 

whereas the non-friable lower-member siliceous shale is more 

competent (figs. 8 and 9). Chert beds within the shales display 

different fracture patterns, competence, and orientations than 

the bounding shales (fig. 9). 

Outcrop studies by Roberts and Mitterer (1992) and 

Krystyniak and Paxton (2006) determined that siliceous shale 

samples yield low weight percent total organic carbon (TOC) 

and fissile samples yield high TOC values. Outcrops and well 

cores were sampled at numerous locations across Oklahoma 

and Arkansas, including 11 in the Anadarko Basin Province, 

by Comer and Hinch (1987) in their analysis of source rock 

richness and hydrocarbon expulsion from the Woodford 

Shale; their results showed that for interbedded black shale 

and chert, the chert beds contain relatively less TOC, but 

more bitumen and hydrocarbons than the shale. This suggests that, whereas both the shale and chert beds can be 

hydrocarbon sources, the shale was more efficient at expelling petroleum and the chert beds were better traps. Comer 

and Hinch (1987) described fractures that occur within the 

Woodford throughout their study area; these include fractures 

filled with bitumen, which are most common in the Arbuckle 

Mountain uplift and proximal Marietta-Ardmore Basin, the 

frontal zone of the Ouachita system, and in the southern 

part of the Anadarko Basin, where late Paleozoic orogenic 

activity was intense. Fractures filled with bitumen are also in 

central Oklahoma (along the Nemaha Ridge), where tectonic 

activity was of less certain timing and style (Comer and 

Hinch, 1987). 

Figure 7. Photograph showing outcrop of Woodford Shale is as much as 231 feet. thick and is located on private property in the 

Henry House Falls quarry, sec. 6, T. 2 S., R. 1 E., on the south side of the Arbuckle uplift (Paxton, 2007) (fig. 1). Shown is a portion 

of the upper member of the Woodford Shale. It was described by Paxton (2007) as an organic-rich finely laminated fissile shale. 

The three resistant lighter-colored beds at Stan Paxton’s thigh level are finely crystalline dolomite with hydrocarbon saturation. 

Spherical phosphate nodules are present above the upper dolomite layer. The upper member at this location is about 55 percent 

siliceous beds, 44 percent fissile beds, and 1 percent dolomite zones.
10 Petroleum Systems and Assessment of Undiscovered Oil and Gas in the Anadarko Basin Province

Figure 8. Photographs showing outcrop of a slightly overturned lower member of Woodford Shale beds next to State Route 77D, in 

NE 1⁄4 sec. 30, T. 1 S., R 2 E., Murray County, Oklahoma (fig. 1). Stratigraphically up is to the left on the road-cut image. Red arrow on the 

upper right points to a fault and associated fault gouge, some of which is saturated with hydrocarbon. This section, as described in 

Paxton and Cardott (2008), strikes N. 70o W and dips 68o to the southwest, is highly siliceous, and was highly susceptible to fracturing 

during the structural deformation. Strata are generally less fissile than those in figure 7.

Figure 9. Photograph showing detail of fracture patterns in the lower member of the Woodford Shale 

at the State Route 77D outcrop photo from Paxton and Cardott (2008) (fig. 1). Spacing and orientation 

of fracture patterns in the dark gray siliceous shale differ from those in the underlying light-colored 

chert-rich facies.

Figure 8. 
Petroleum Source and Reservoir Rocks 11

The Woodford Shale includes abundant type A amorphous 

type II kerogen (partially equivalent to the liptinite [exinite] 

maceral group) with the remaining primarily type III kerogen 

(vitrinite) and type I kerogen (Tasmanite alginite) (Lewan, 

1983; Thompson and Dembicki, 1986; Crossey and others, 

1986; Comer and Hinch, 1987; Burwood and others, 1988; 

Cardott, 1989, p. 35; Krystyniak and Paxton, 2006). A generalized composition of the Woodford Shale based on Abousleiman (2008) is 37 percent quartz, 26 percent illite, 15 percent 

kerogen, 17 percent carbonate, and 5 percent kaolinite. TOC 

content for the upper Woodford ranges from 0.8 weight percent 

(wt%) up to 17 wt% and is highly variable vertically and 

laterally across the province based on data from Comer and 

Hinch (1987), Burruss and Hatch (1989), Hester and others 

(1990), Price (1997), Krystyniak and Paxton (2006), Joseph 

Hatch (oral commun., 2010), and data from the USGS Energy 

Geochemistry Data Base (2010, http://energy.cr.usgs.gov/

prov/og/) (fig. 10). Hester and others (1990) used log-derived 

formation density for 99 wells across the Anadarko Basin area 

to assign average TOC values of 3.2, 5.5, and 2.7 wt% for the 

respective lower, middle and upper members of the Woodford Shale; variation in TOC was not influenced by formation 

thickness, but by increased depth and thermal maturation with 

associated depletion by generation and expulsion of petroleum. 

Figure 10. Map showing total organic carbon (TOC) for the Woodford Shale 

based on data from Burruss and Hatch (1989) and mean estimated values from 

Hester and others (1990). TOC ranges from 0.08 to 14.05 wt% and averages 3.7 

wt% based on core and well log density calculations from 123 wells. There is 

considerable TOC variation, but almost the entire area that is thermally mature 

for petroleum generation contains greater than 2 wt% TOC. Decrease in TOC 

in the deep basin is partly the result of elevated levels of thermal maturation. 

Oil and gas generation depletes TOC and hydrogen indices (HI)—the fuels for 

petroleum—so original TOC and HI values would have been greater. Pink lines 

are Precambrian faults from Adler and others (1971).

1

2

3

4

5

6

7

8

9

10

11

12

13

14

EXPLANATION

TOC

weight, in percent

COLORADO

 OKLAHOMA

 TEXAS

KANSAS

NEW MEXICO

Woodford 

Composite TPS

Woodford Shale Oil AU

Woodford Shale Gas AU

Wichita 

 Mountain 

 uplift

Salina 

Basin

Amarillo uplift

Las Animas arch

Central Kansas uplif

Anadarko Basin t

103° 102° 101° 100° 99° 98° 97°

39°

38°

37°

36°

34°

35°

0 50 100 MILES

0 50 100 KILOMETERS
12 Petroleum Systems and Assessment of Undiscovered Oil and Gas in the Anadarko Basin Province

Thermal Maturation

The Woodford Shale is thermally mature for oil generation 

to overmature for gas generation over most of the Oklahoma 

and eastern Texas Panhandle portions of the Anadarko Basin 

Province (fig. 11). Levels of thermal maturation were based on 

1D and 4D petroleum system models and contoured Ro data 

from the Woodford Shale from Cardott (1989), Price (1997), 

and two wells in the Edmond West field provided by Chesapeake Energy and Mark Pawlewicz. Part of the area proximal 

to the Nemaha uplift is thermally immature for oil generation 

from the Woodford Shale based on Cardott (1989) Ro data but 

marginally mature to mature based on Ro measurements for the 

West Edmond SWD 1-24 (0.55 percent mean Ro) and Streeter 1 

(0.75 percent mean Ro) wells from Brian Cardott and Mark 

Pawlewicz, respectively. The West Edmond SWD 1-24 sample 

was also analyzed by Chesapeake Energy on January 10, 2008, 

with an estimated mean 0.83 percent Ro and range of 0.44 to 

0.96 percent Ro based on Rock Eval pyrolysis Tmax values for 

19 samples of the Woodford Shale interval. The models were 

preferentially calibrated to measured Ro data on the Woodford 

Shale. Extent of our modeled thermally mature source rocks 

is somewhat greater than that of Cardott (1989). The area of 

thermally mature Woodford Shale was also expanded slightly 

based on calibration of 1D and 1D extracted models (Gaswirth 

and Higley, 2014; Higley, 2014a) to incorporate areas in Oklahoma that are petroleum productive from the Woodford Shale, 

under the assumptions that the reservoir is self-sourced and 

internal lateral migration is minimal. The Woodford Shale may 

also be subject to Ro suppression based on Price and Barker 

(1985) and Cardott (1989), which could result in higher values 

than those recorded and displayed by Cardott (1989). These 

factors are discussed in more detail in Higley (2014a). 

Carter and others (1998) determined that oil generation 

from the Woodford Shale began as early as Late Mississippian in the western basin. Burial history models for two wells 

from the deep Anadarko Basin were used by Carter and others 

(1998) to determine that the Woodford Shales were thermally 

mature for oil generation by the end of the Permian; their 

burial history model for the northern shelf area of Oklahoma 

did indicate that the Woodford Shale has been in the early oil 

generation zone since Early Permian time. 

The modeled onset of oil generation and expulsion from 

the Woodford Shale in the deep basin was about 330 million 

years ago (Ma), based on generated volumes of oil through 

time. Onset through completion of hydrocarbon generation is 

highly dependent on burial depth, which varies greatly across 

the basin. Figure 12 shows two-dimensional extractions from 

the 4D model that display thermal maturation through time for 

a south-north cross section. Displayed are transformation ratios 

(TR) that range from 0.1 percent at onset, 50 percent at peak, 

and 99 percent at completion of oil generation (Higley, 2014a, 

fig. 18). The 99-percent TR boundary corresponds to about 1.2 

percent Ro based on Lewan and Ruble (2002) Woodford Shale 

hydrous pyrolysis kinetics; this represents the transition from 

primarily oil to only gas generation. Modeled Ro contours are 

also shown for the generalized onsets of dry gas (about 2 percent Ro

), and overmaturity for gas generation (about 4 percent 

Ro) based on secondary cracking reactions (Tsuzuki and others, 

1999; Higley, 2014a). Methane gas is stable in the Woodford 

Shale of the deep basin, based on thermodynamic calculations 

and constraints by Takach and others (1987) and Barker and 

Takach (1992), even considering the almost 28,000 ft current 

depth of the Woodford Shale in the Bertha Rogers 1 well (fig. 5) 

and greater than 30,000 ft maximum burial depth of the unit 

in the basin. Although this indicates that methane is probably 

present in the deepest portion of the Woodford Shale Gas AU, it 

does not address the effects of elevated pressure and decreased 

pore size and permeability on the stored volumes of gas. 

Oil generation began about 330 Ma and slightly deeper 

in the basin than the 330 Ma-cross section image (fig. 12). 

By 300 Ma, the Woodford Shale on this section ranged from 

thermally immature to overmature for oil generation, and by 

250 Ma the range was marginally mature for oil to overmature 

for gas generation. Because 250 Ma was approximately the 

time of maximum burial depth, changes in maturation from 

250 Ma to 0 Ma were fairly minor. The present-day Woodford Shale and Thirteen Finger Limestone model layers range 

from marginally mature for oil to overmature for gas generation. As is the case with Carter and others’ (1998) research, 

thermal maturation is strongly influenced by burial depth and 

temperature. Basement heat flow affects the wavy character 

of contours in the figure 12 thermal maturation cross sections, 

with areas of decreased heat flow exhibiting less thermal 

maturation. This relation is also displayed in Higley (2014a, 

figs. 39 and 40). Some of the “bumps” in the thermal maturation profiles were explained by Gallardo and Blackwell (1999) 

as associated with the thermal conductivity structure of the 

basin and heat generation properties of basement rocks. Cardott and Lambert (1985) and Cardott (1989) observed that the 

highest Ro values in the Woodford Shale are about 19–25 mi 

(30–40 km) north of the deepest part of the basin and change 

rapidly over a small lateral distance. Heating history is also 

influenced by lithologies, for example, evaporites are thermally conductive and thick sections can “cool” underlying 

strata, whereas coals and shales are thermal insulators that 

increase heat of underlying rocks. Within the Anadarko Basin, 

coals are thin and sparse and evaporite sequences are relatively thin, so these lithologies would have minimal impact 

on heating history. Shales are more common, particularly 

in the Pennsylvanian section, and would have functioned as 

thermal blankets for underlying strata. Morrowan black shales 

compose as much as 60 percent of the rocks in the Oklahoma 

portion of the province (Wang and Philp, 1997), and the 

Morrowan section is as much as 4,000 ft thick in the deep 

Anadarko Basin, thinning northward onto the shelf (Adler and 

others, 1971; Johnson, 1989). 

Hydrocarbons from the Woodford AUs are self-sourced. 

Oil migration within the Woodford Shale is probably limited 

because of the low permeability; consequently, migration is 

predominantly expulsion outward to bounding carrier (reservoir) beds. Petroleum migration is preferentially from higher to 
Figure 11. Maps showing A, calculated vitrinite reflectance (% Ro) (Sweeney and Burnham, 1990) and B, transformation ratios (% TR) for the Woodford Shale from the four-dimensional petroleum system model. The three-dimensional rendering results in variable shading within contours. Pink contour line on the % Ro map and the gas-oil ratio (GOR) inset corresponds to the 99% TR end of oil generation. The inset bubble symbols are GOR, with larger bubbles representing greater GOR. Greatest thermal maturation is in the deep basin of Oklahoma and Texas, whereas most of Colorado and Kansas is immature for oil generation, as characterized by an Ro of about 6 percent and TR of 0.1 percent and greater. Blue lines are Precambrian faults from Adler and others (1971).

COLORADO

OKLAHOMATEXAS

KANSAS

 102° 101° 100° 99° 98° 102° 101° 100° 

38°37°36°35°

38°37°36°35°

A B

% Ro TR (%)

0.1 to 1.01.0 to 1010 to 2525 to 5050 to 7575 to 9595 to 9999 to 100

0.40.50.60.70.80.91.02.03.04.05.0

EXPLANATION

COLORADO

OKLAHOMATEXAS

KANSAS

0 50 100 MILES

0 50 100 KILOMETERS

Figure 11. Ch. 6
14 Petroleum Systems and Assessment of Undiscovered Oil and Gas in the Anadarko Basin Province

Springer

Arbuckle

330 Ma

SOUTH NORTH

Douglas

Springer

Arbuckle

300 Ma

Springer

Blaine

Chase

Wabaunsee

Douglas

Arbuckle

Springer

Morrow

250 Ma

0

-1,000

-2,000

-3,000

-4,000

-5,000

-6,000

-7,000

-8,000

2.0% Ro Dry gas

4.0% Ro Overmature

Springer

Blaine

Wabaunsee

Douglas

Arbuckle

2.0% Ro Dry gas

4.0% Ro Overmature

0

-1,000

-2,000

-3,000

-4,000

-5,000

-6,000

-7,000

-8,000

0 Ma

EXPLANATION

TR, in percent

0.1 to 1.0

1.0 to 10 

10 to 25 

25 to 50

50 to 75

75 to 95

95 to 99

1,000

0

-1,000

-2,000

-3,000

-4,000

-5,000

-6,000

Elevation, in meters

figure 12. Ch. 6

0

-1,000

-2,000

-3,000

-4,000

-5,000

-6,000

-7000

Elevation, in meters Elevation, in meters Elevation, in meters

0 25 50 MILES

0 25 50 KILOMETERS

OKLAHOMA

KANSAS
Thermal Maturation 15

Figure 12. South to north thermal maturation cross sections 

showing transformation ratios (% TR) through time based on 

Woodford Shale hydrous pyrolysis kinetics from Lewan (1983, 

1985), and Lewan and Ruble (2002). Pink and dark blue lines are the

respective Woodford Shale and Thirteen Finger lime model layers. 

Cross section location is in figure 3. Modeled vitrinite reflectance 

(Ro) lines mark the boundaries for generation and overmaturity for 

dry gas. Millions of year ago, Ma.—Previous page

lower pressure environments, regardless of whether those are 

underlying or overlying strata. Oil and gas within the Woodford 

Shale mainly represent saturation from nonexpelled hydrocarbons and that within faults and fractures. Because this is a reservoir, albeit with low permeability, there is also the potential 

of hydrocarbons migrating into the Woodford from deeper in 

the basin or from other source rocks, especially gas, because of 

its mobility. However, it is unlikely that other petroleum source 

rocks contributed petroleum to the Woodford Shale, because 

it is currently overpressured relative to underlying strata in the 

deep basin (Al-Shaieb and others, 1994) and has probably been 

overpressured since it was mature for hydrocarbon generation. 

Comer and Hinch (1987) estimated the volume of 

expelled oil from their Woodford Shale study area by subtracting the TOC-normalized volume of hydrocarbons in black 

shale from the corresponding amount in chert. Their calculations also incorporated the Woodford Shale subcrop area and 

source rock total thickness, density and TOC concentration, as 

well as the density and amount of the expelled oil. Their calculated expulsion efficiency was between 27 and 50 percent. 

Estimated volume of expelled oil was 22 billion barrels from 

about (1) the eastern one-third of the Anadarko Basin, (2) the 

Marietta-Ardmore Basin, and (3) the western two thirds of the 

Central Oklahoma platform (Comer and Hinch, 1987, fig. 1). 

Figure 13 shows oil generation through time for the Oil Creek 

Formation, Woodford Shale, and Thirteen Finger lime petroleum source rocks (fig. 2). The curves are displayed as onset 

to completion, rather than volumes, partly because thickness 

of the Oil Creek layer is generalized and does not represent 

Figure 13. History of petroleum generation from the Oil Creek Formation, Woodford Shale, and Thirteen Finger 

lime (fig. 2) source layers in the four-dimensional petroleum system model. History is based on Woodford 

hydrous pyrolysis kinetics (Lewan and Ruble, 2002). Shaded area brackets the main period of peak oil generation 

from the Woodford Shale. Early oil generation from the Oil Creek layer, prior to about 70 million years ago, is in 

a narrow strip in the model that is proximal to the Wichita Mountain uplift. This strip exceeds maximum depth of 

the formation and is primarily the result of areas of poor data control in the area bordering the fault zone. The 

error could have been removed by clipping the four-dimensional model extent to the basin axis and northward, 

but less of the model would have been visible and usable.

400 350 300 250 200 150 100 50 0

Generation History, Million Years Before Present

Oil Creek 

Woodford 

Thirteen Finger

EXPLANATION

Onset Completion

Laramide orogeny

Wichita orogeny
16 Petroleum Systems and Assessment of Undiscovered Oil and Gas in the Anadarko Basin Province

the actual thickness of the source interval. Peak oil generation from the Woodford Shale was from about 310 to 230 Ma. 

Because Anadarko is a deep basin with a shallow shelf, age 

ranges for petroleum generation vary laterally as well as vertically, allowing for longer periods of oil and gas generation, 

migration, and trapping across the basin. A second period of 

Woodford oil generation from about 80 to 50 Ma is associated 

with Laramide deposition, uplift, erosion, and subtle tilting of 

the basin. The petroleum system events chart for the Woodford 

Shale Oil and Woodford Shale Gas AUs (fig. 14) shows time 

periods of deposition of source, reservoir, seal, and overburden 

Figure 14. Events chart for the Woodford Shale 

Gas assessment unit (AU) and Woodford Shale Oil 

AU. Timing of oil and gas generation, migration, and 

accumulation is based primarily on vitrinite reflectance 

and transformation ratios through time from onedimensional and four-dimensional (4D) models (Higley, 

2014a). Timing of oil generation (gray polygon) is 

also based on (unpublished) volumes of petroleum 

generated through time using the 4D model; peak 

generation from the Woodford Shale (blue bars) is from 

about 310 to 230 million of years before present (Ma). 

A second phase of generation from about 80 to 50 Ma 

is associated with deposition and erosion of strata 

associated with the Laramide orogeny. Lithofacies 

assignments in the “Formations” row are intended only 

to show periods of unconformities (wavy and horizontal 

lines) and deposition. Plio, Pliocene; Mio, Miocene; Eoc, 

Eocene; Pal, Paleocene; L, Late; M, Middle; E, Early.

Figure 14. Ch. 6

Pal

Eoc

Olig

Mio

0

100

200

300

400

50

150

250

350

Paleogene

Cretaceous

Jurassic

Triassic

Permian

65.5

146

200

251

359

416

Silurian

Devonian

299

318

E

E

E

E

E

E

E

E

M

M

M

M

L

L

L

L

L

L

L

L

Mississipian

Pennsylvanian

Neogene

23

Plio

Formations

Source rock

Reservoir rock

Seal rock

Overburden rock

Trap formationGeneration

Geologic 

time

scale

(Ma)

Accumulation

Ordovician

Cambrian

542

488

444 450

500

550

Woodford Shale

M

E

M

L

E

M

L

Precambrian

Woodford Shale

Petroleum 

System Events

strata. Timing of hydrocarbon generation, migration, and 

accumulation are derived mainly from the Higley (2014a) 

petroleum system models (fig. 13, table 2). 

to completion, rather than volumes, partly because 

thickness of the Oil Creek layer is generalized and does not 

represent the actual thickness of the source interval. Peak oil 

generation from the Woodford Shale was from about 310 to 

230 Ma. Because Anadarko is a deep basin with a shallow 

shelf, age ranges for petroleum generation vary laterally as 

well as vertically, allowing for longer periods of oil and gas 

generation, migration, and trapping across the basin. A second 
Petroleum Production History 17

Table 2. Oil generation onset for the Anadarko Basin four-dimensional model, and onset and 

completion dates in millions of years before present (Ma) for the Bertha Rogers 1 and Petree Ranch 

1 one-dimensional models based on Woodford Shale hydrous pyrolysis kinetics (Lewan and Ruble, 

2002). The Douglas Group overlies the youngest potential petroleum source rocks in figure 6. The HP 

kinetics-based onset of oil generation is 0.1% TR and completion is 99% TR. Oil generation histories in 

the four-dimensional model were recorded at 10 million year increments, so the plus symbol indicates 

onset was before the listed age.

Four Dimensional Model Bertha Rogers 1 Petree Ranch 1

Onset Onset End Onset End

Virgilian (Douglas Group) 270 100

Thirteen Finger limestone +300 290 265 270

Woodford Shale 330 330 310 290 200

Oil Creek Formation +370 340 320

period of Woodford oil generation from about 80 to 50 Ma 

is associated with Laramide deposition, uplift, erosion, and 

subtle tilting of the basin. The petroleum system events chart 

for the Woodford Shale Oil and Woodford Shale Gas AUs 

(fig. 14) shows time periods of deposition of source, reservoir, 

seal, and overburden strata. Timing of hydrocarbon generation, migration, and accumulation are derived mainly from the 

Higley (2014a) petroleum system models (fig. 13, table 2). 

Traps and Seals

The Woodford Shale Gas AU southern boundary includes 

a small portion of the overthrust belt that borders the Amarillo–Wichita Mountain uplift (fig. 3). Gas potential within 

wells in this area is influenced by complex faulting and 

fracturing that would likely enable leakage of gas from the 

Woodford Shale, adversely impacting production of gas. The 

area was included because Woodford intervals in this area are 

probably within the oil and gas generation windows, and some 

wells encounter repeated strata because of the faulting. For 

example, the Apache Gas Unit No. 1 vertical well penetrates 

the Woodford at least 4 times and at depths that range from 

about 1,900 to 19,000 ft. 

The Woodford Shale AUs are within the Anadarko Basin 

area defined by Nelson and Gianoutsos (2014) as overpressured. Al-Shaieb and others (1994) outlined an overpressured 

megacompartment that is primarily in the Oklahoma and 

Texas portions of the basin; the diagenetically enhanced basal 

seal is stratigraphically controlled and seems to coincide with 

the Woodford Shale. Overpressuring occurs in all reservoirs 

between the top seal at depths of about 7,500 to 10,000 ft 

(2,290 to 3,050 m) to the base of the Woodford Shale, with 

return to normal pressure in the underlying Hunton Group 

(Al-Shaieb and others, 1994). Overpressure probably assists 

petroleum production from the Woodford Shale if natural 

and induced fractures are open. Effects of overpressure on 

lateral and bounding seals are dependent on their competence.

Al-Shaieb and others (1994) indicated that the megacompartment complex is composed of sealed overpressured reservoirs 

with pressure gradients that exceed the normal gradient of 

10.515 thousand Pascals per meter (kPa/m) [0.465 pounds per 

square inch per foot (psi/ft)]; the megacompartment, including the Woodford Shale, is sealed to the south by a vertical 

cementation zone associated with the frontal fault zone of the 

Wichita Mountain uplift and by the convergence of the top and 

basal seals along its eastern, northern, and western boundaries. The overlying Kinderhook Shale probably provides a seal 

across its extent in the eastern basin.

Petroleum Production History

Distribution of oil and gas wells from the Woodford 

Shale is shown in figures 15 and 16. Gas production is located 

primarily within the Woodford Shale Gas AU and oil within 

the Woodford Shale Oil AU. Estimated mean undiscovered 

resources from the 2011 assessment are (1) 15.973 trillion 

cubic feet of gas (TCFG) and 192 million barrels of natural 

gas liquids (MMBNGL) for the Woodford Shale Gas AU; 

and (2) 393 million barrels of oil (MMBO), 1.963 TCFG, and 

59 MMBNGL for the Woodford Shale Oil AU. The Woodford Shale was included in the 1995 play assessment of the 

Anadarko Basin as the Woodford/Chattanooga/Arkansas 

Novaculite play, which was described by J. Schmoker in 

Henry and Hester (1995) as a hypothetical continuous play 

with no production or assigned estimates of undiscovered 

resources. The Misener sand (fig. 16) of the basal Woodford Shale was separately assessed in 1995 as the Devonian 

Misener sandstone oil play with mean undiscovered accumulations of 4.1 MMBO (Henry and Hester, 1995). The Misener 

sand for the 2011 assessment was not assessed separately, 

but was included within the conventional Hunton Group AU 

(table 1) (Gaswirth and Higley, 2014). 
18 Petroleum Systems and Assessment of Undiscovered Oil and Gas in the Anadarko Basin Province

Figure 15. Map showing oil and gas 

wells that produce from the DevonianMississippian Woodford Shale Oil 

and Woodford Shale Gas assessment 

units (AUs) in the Anadarko Basin 

Province (code number 58) (IHS 

Energy, 2009a, 2010, 2011). Shown also 

are AU code numbers. Some wells 

include production from other units, 

primarily the Silurian-Devonian Hunton 

Group, Devonian informal Misener 

sand, and Mississippian strata. The 

Woodford Composite TPS code is 50580. 

Precambrian faults (pink) are from Adler 

and others (1971). 

Figure 16. Map showing oil wells (green dots) and gas wells (red dots) that 

produce from the Woodford Shale in the Anadarko Basin Province (IHS Energy, 

2009a, 2010, 2011). White dots are wells that are productive only from the Woodford 

Shale based on a November 2011 retrieval of data from IHS Energy (2011). White dot 

wells that do not contain oil or gas wells were added to the IHS database since the 

January data retrieval. Extent of the Woodford Shale in the province is approximated 

by the Woodford Oil AU line. Thickness was derived from Rottmann (2000b, pl. 2), 

analysis of more than 100 well logs, and edited formation tops from IHS Energy 

(2009a, 2009b). The Kansas portion of the province contains variable thicknesses of 

Woodford Shale, and the Oklahoma and Texas portions have several small erosional 

remnants. The generalized location of the informal Misener sand (light blue line) in 

the lower part of the Woodford Shale (fig. 2) is modified from Amsden and Klapper 

(1972) and IHS Energy (2009a, 2009b). The Misener sand exhibits variable thickness 

and distribution, and is also present in isolated lows in the eroded, karst surface of 

the Hunton Group (Gaswirth and Higley, 2014). Pink lines are Precambrian faults from 

Adler and others (1971).

Figure 15. Ch. 6 

0 50 100 KILOMETERS

0 50 100 MILES

104° 103° 102° 101° 100° 99° 98° 97° 40°

39°

38°

37°

36°

35°

34°

Woodford Gas AU

 50580161

Woodford Oil AU

50580161

TEXAS

KANSAS

COLORADO

NEW 

MEXICO

OKLAHOMA

505801 TPS

Province 58 

Woodford Oil AU

Woodford Gas AU

Precambrian fault

Oil well

Gas well

EXPLANATION

Figure 16. Ch. 6 

0 50 100 KILOMETERS

0 50 100 MILES

102° 101° 100° 99° 98° 97°

38°

37°

36°

35°

Woodford Gas AU

 50580161

Woodford Oil AU

 50580161

Woodford Composite TPS

TEXAS

OKLAHOMA

KANSAS

0 to 25

25 to 50

50 to 75

75

75 to 100

100

100 to 125

125

125 to 150

150

150 to 175

175 to 200

200

200 to 225

225 to 250

250

250 to 275

275 to 300

300 to 325

325 to 350

EXPLANATION

Thickness,

in feet
Petroleum Production History 19

The 2011 assessment incorporated multiple databases 

of well and field history and production that included IHS 

Energy (2009a, 2009b, 2010) and Nehring and Associates, 

Inc. (2009). Cumulative production from the Woodford Shale 

across the province was about 2 MMBO and 34 BCFG, based 

mainly on data from IHS Energy (2010). Woodford Shale oil 

and gas has been mostly from vertical wells, with the production commonly reported commingled with the Hunton Group, 

Misener sand, Sycamore Limestone, and other units. Of the 

130 total wells, there were about 49 horizontal Woodford 

Shale completions (IHS Energy, 2009a, 2010). Future Woodford Shale wells are expected to be mainly horizontal. Gas-oil 

ratio averaged about 237,000 cubic feet of gas/barrel of oil for 

55 Woodford Shale wells in the province that did not report 

commingled production (IHS Energy, 2009b). Cumulative 

gas production for discovery thirds (fig. 17) shows largest gas 

production for the second third of production history. Largest 

Figure 17. Discovery thirds for 74 wells with reported 

cumulative gas production from only the Woodford Shale 

from 1946 to September, 2009 (IHS Energy, 2010). The 

apparently poor production from the 3rd third is misleading, 

and actual performance is probably greater, particularly 

with the present focus on horizontal wells. Reasons for 

the spread in data include that early production likely 

incorporates (unreported) oil and gas from the conventional 

basal Misener sand of the Woodford shale and (or) 

bounding reservoirs, and the 3rd third only represents 6 

months of Woodford Shale gas from 24 wells. Average gas/

oil ratio of the above data set is 237,000 cubic feet of gas 

per barrel of oil. Million cubic feet of gas, MMCFG.

20

100

1,000

0 5 10 15 20 25

1st third

2nd third

3rd third (April to September 2009)

EXPLANATION

Produced gas

Figure 17. Ch. 6 

Cumulative gas production (MMCFG)

Number of wells

decrease is for the last third of production history; however, 

the curves provide only limited information because of the 

short time range of production. Eighty-eight gas and 21 oil 

wells, respectively, with Woodford-only production were 

used to calculate estimated ultimate recovery (EUR) for the 

Woodford Shale Gas and Woodford Shale Oil AUs (IHS 

Energy, 2011). Contoured gas EURs are shown in figure 18. 

Present-day distribution of production for the Woodford 

Shale Gas AU is scattered across the formation extent, but 

gas production is concentrated in areas where Ro values are 

greater than 1.2 percent (fig. 18). The isolated blue dot of 

greater than 5,000 MMCFG (fig. 18) appears to be in an area 

of lower thermal maturity, but there are no proximal Ro samples, so the value here could be greater than indicated by the 

contours. The modeled TR through this point is 100 percent 

and Ro is 1.3 percent. Methodology for determining EUR is 

in Cook (2004). 
20 Petroleum Systems and Assessment of Undiscovered Oil and Gas in the Anadarko Basin Province

Figure 18. Map showing Woodford Shale calculated gas estimated ultimate recoverable (EUR) ranges from 

about 0.1 million (MMCFG) to 11.9 billion cubic feet of gas for 76 wells based on production history from IHS 

Energy (2010). The dense cluster of wells has contoured values, whereas those outside are measured values. 

Inset map of contoured values is magnified 300 percent. Most gas production is located at the 1.2% Ro and 

greater Woodford Shale contours created using data from Cardott (1989), Price (1997), Chesapeake Energy 

Corporation (2009), and Mark Pawlewicz. Faults (brown lines) on the underlying Hunton Group (Rottmann, 

2000a) were used to create the Woodford layer and to contour Ro values.

Figure 18. Ch. 6 

1.2

1.2

2.4

1.6

3.2

5.6 4.8

4.0

3.2

2.4

2.4

4.8

3.2

4.0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

11,000

EXPLANATION

EUR

(MMCFG)

0.6

0.6

0.4

1.6

0.4

0.8

1.6

2.4

1.6

1.6

0.8

0.8

0.8

OKLAHOMA

 TEXAS

KANSAS

100° 99° 98° 97°

37°

36°

35°

0 25 50 KILOMETERS

0 25 50 MILES

Conclusions

The Devonian-Mississippian Woodford Shale is an 

important petroleum source rock and reservoir in the Anadarko 

Basin Province. The formation consists of upper, middle, and 

lower informal members of carbonaceous silica-rich shales, 

and a lower informal Misener sand. The shale members contain 

fissile and non-fissile shale, including chert beds, all of which 

can exhibit different fracture behavior. Elevation on the top 

of the Woodford Shale ranges from about -2,500 ft (-760 m) 

on the southern Kansas shelf, to -27,000 ft (-8,000 m) in the 

deep basin of southern Oklahoma. Thickness of the Woodford 

Shale ranges up to 375 ft and averages 40 ft. Greatest thickness 

is within eroded channels of the underlying Hunton Group. 

Present-day total organic carbon (TOC) content for the upper 

Woodford ranges from about 0.8 wt% to 17 wt%. 

Hydrocarbons in the Woodford Shale Gas and Woodford 

Shale Oil AUs are self-sourced. Gas production is concentrated 

in areas where Ro values are greater than 1.2 percent, based 

mainly on the 4D model. Lateral migration distances are minor 

because of the low permeability within the source rock and 

primary expulsion is from this source outward to bounding 

carrier beds. Oil generation from the Woodford Shale began in 

the deep basin of southern Oklahoma about 330 Ma, based on 

1D and 4D petroleum system models; peak oil generation was 

from about 310 to 230 Ma. Because Anadarko is a deep basin 

that has a shallow shelf, age ranges for generation vary laterally 

as well as vertically. These time ranges allowed for longer periods of oil and gas generation, migration, and trapping across 

the basin. A second period of Woodford oil generation from 

about 80 to 50 Ma is associated with Laramide deposition, 

uplift, erosion, and subtle tilting of the basin. 
References Cited 21

Acknowledgments

Tom Judkins, Kristen Marra, and Kate Whidden of the 

USGS and Brian Cardott of the Oklahoma Geological Survey 

provided excellent technical reviews of this chapter of the 

report. Brian has also been a wonderful resource for thermal 

maturation and petroleum source rock research in the basin. 

Chesapeake Energy has been very generous with their time, 

data, and expertise, for which we are grateful. I would like to 

thank Kathy Winner and IHS Energy for providing information for our mapping and modeling efforts.

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R.R., Cook, T.A., Ellis, G.S., Gianoutsos, N.J., Hatch, 

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O.N., Pollastro, R.M., and Schenk, C.J., 2011, Assessment 

of undiscovered oil and gas resources of the Anadarko 

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S.M., 2014, Precambrian to ground surface grid cell maps 

of the Anadarko Basin Province, chap. 13, in Higley, D.K., 

compiler, Petroleum systems and assessment of undiscovered oil and gas in the Anadarko Basin Province, Colorado, 

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database available from IHS Energy, 15 Inverness Way 

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Inverness Way East, Englewood, CO 80112.

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Inverness Way East, Englewood, CO 80112.

Johnson, K.S., 1989, Geologic evolution of the Anadarko 

Basin, in Johnson, K.S., ed., Anadarko Basin symposium, 

1988: Oklahoma Geological Survey Circular 90, p. 3–12.

Johnson, K.S., Amsden, T.W., Denison, R.E., Dutton, S.P., 

Goldstein, A.G., Rascoe, B., Jr., Sutherland, P.K., and 

Thompson, D.M., 1988, Southern midcontinent region, in

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U.S., The Geology of North America: Boulder, Colo., Geological Society of America, v. D–2, p. 307–359.

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J.R., 1992, Geology and organic geochemistry of the Woodford Shale in the Criner Hills and western Arbuckle 
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rocks in the southern midcontinent, 1990 symposium: Oklahoma Geological Survey Circular 93, p. 38–69.

Krystyniak, A.M., and Paxton, S.T., 2006, Outcrop-based 

gamma-ray characterization of the Woodford Shale of 

south-central Oklahoma: Oklahoma Geological Survey, 

Coalbed methane and gas shales in the southern midcontinent conference, March 21, 2006, Oklahoma City, 16 p. 

Lambert, M.W., 1993, Internal stratigraphy and organic facies 

of the Devonian-Mississippian Chattanooga (Woodford) 

Shale in Oklahoma and Kansas: Chapter 11, American 

Association of Petroleum Geology Studies in Geology 

37: Source rocks in a sequence stratigraphic framework, 

p. 163–176.

Lewan, M.D., 1983, Effect of thermal maturation on stable 

organic carbon isotopes as determined by hydrous pyrolysis of Woodford Shale: Geochemica et Cosmochimica 

Acta, v. 47, p. 1471–1479.

Lewan, M.D., 1985, Evaluation of petroleum generation by 

hydrous pyrolysis experimentation: Philosophical Transactions of the Royal Society, A 315, p. 123–134.

Lewan, M.D., and Ruble, T.E., 2002, Comparison of petroleum generation kinetics by isothermal hydrous and nonisothermal open-system pyrolysis: Organic Geochemistry, 

v. 33, no. 12, p. 1457–1475. 

Nehring and Associates, Inc. (NRG), 2009, Significant oil 

and gas fields database: Colorado Springs, Colorado, NRG 

Associates, Inc. (Database available from NRG Associates, 

Inc., P.O. Box 1655, Colorado Springs, CO 80901).

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overpressure and paleopressure indicators in the greater 

Anadarko Basin, Oklahoma, Texas, Kansas, and Colorado, 

chap. 8, in Higley, D.K., compiler, Petroleum systems and 

assessment of undiscovered oil and gas in the Anadarko 

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USGS Province 58: U.S. Geological Survey Digital Data 

Series DDS–69–EE, 27 p. 

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Shale adjacent to the Henry House Falls quarry on the south 

side of the Arbuckle Mountains, in Cardott, B.J., Andrews, 

R.D., Miller, G.W., and Paxton, S.T., leaders, Woodford 

Shale gas field trip May 22 and 24, 2007: Oklahoma Geologic Survey Open File Report 1–2007, p. 42–47.

Paxton, S.T., and Cardott, B.J., 2008, Oklahoma gas shales 

field trip, October 21 and 23, 2008: Oklahoma Geological 

Survey Open File Report 2–2008, 61 p.

Perry, W.J., Jr., 1989, Tectonic evolution of the Anadarko 

Basin region, Oklahoma: U.S. Geological Survey Bulletin 

1866-A, p. A1–A19.

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controlling parameters of methane, as determined by C15+ 

hydrocarbon thermal stabilities, in Dyman, T.S., Rice, D.D., 

and Westcott, P.A., eds., Geologic controls of deep natural 

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reflectance in amorphous rich kerogen—A major unrecognized problem: Journal of Petroleum Geology, v. 8, p. 59–84.

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Shale in western Oklahoma: Oklahoma City Geological 

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24 Petroleum Systems and Assessment of Undiscovered Oil and Gas in the Anadarko Basin Province

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Bulletin, v. 81, no. 2, p. 249–274.
Chapter 7

Petroleum Systems and Assessment of 

Undiscovered Oil and Gas in the Anadarko 

Basin Province, Colorado, Kansas, 

Oklahoma, and Texas—Mississippian 

Through Permian Assessment Units 

By Debra K. Higley

Chapter 7 of 13

Petroleum Systems and Assessment of Undiscovered Oil and Gas 

in the Anadarko Basin Province, Colorado, Kansas, Oklahoma, and 

Texas—USGS Province 58

Compiled by Debra K. Higley

U.S. Geological Survey Digital Data Series DDS–69–EE

U.S. Department of the Interior

U.S. Geological Survey

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U.S. Department of the Interior

SALLY JEWELL, Secretary

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Suzette M. Kimball, Acting Director

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Suggested citation:

Higley, D.K., 2014, Petroleum systems and assessment of undiscovered oil and gas in the Anadarko Basin Province, 

Colorado, Kansas, Oklahoma, and Texas—Mississippian through Permian Assessment Units, chap. 7, in Higley, D.K., 

compiler, Petroleum systems and assessment of undiscovered oil and gas in the Anadarko Basin Province, Colorado, 

Kansas, Oklahoma, and Texas—USGS Province 58: U.S. Geological Survey Digital Data Series DDS–69–EE, 60 p., 

http://dx.doi.org/10.3133/ds69EE.

ISSN 2327-638X (online)
iii

Contents

Abstract...........................................................................................................................................................1

Introduction.....................................................................................................................................................1

Geologic Setting of the Anadarko Basin Province...................................................................................5

Structural History..................................................................................................................................5

Petroleum Production History .....................................................................................................................9

Petroleum Source Rocks and Thermal Maturity ....................................................................................11

Reservoir Rocks ...........................................................................................................................................14

Mississippian Assessment Unit........................................................................................................14

Morrowan-Atokan Assessment Unit...............................................................................................19

Thirteen Finger Limestone–Atoka Shale Gas Assessment Unit .................................................21

Desmoinesian Assessment Unit.......................................................................................................29

Missourian-Permian Assessment Unit ...........................................................................................35

Greater Granite Wash Composite Assessment Unit.....................................................................49

Mesozoic Strata..................................................................................................................................52

Conclusions...................................................................................................................................................55

Acknowledgments.......................................................................................................................................55

References Cited..........................................................................................................................................55

Figures

1. Map showing Anadarko Basin (red dashed line) and boundaries of total petroleum

systems (TPS) and assessment units (AU) that are described in this chapter of the

report. The Desmoinesian and Missourian-Permian AUs share a common boundary

with the Pennsylvanian Composite TPS, with the exception that the AUs include a

“donut hole” that is the Greater Granite Wash Composite AU. There are common

boundaries for most AUs.............................................................................................................2

2. Generalized stratigraphic columns for Devonian through Permian strata in the

Anadarko Basin Province. Assessment unit (AU) names and generalized divisions

are split at the horizontal red line into (upper) Pennsylvanian Composite Total

Petroleum System (TPS) and (lower) Woodford Composite TPS. Italics (blue text)

and lowercase names indicate informal status. The Devonian Misener sand was

evaluated as part of the Hunton Group AU (Gaswirth and Higley, 2014). Extension of

the Morrowan-Atokan AU into the Desmoinesian reflects the unclear boundary of

the Atoka Shale in the southern basin. Modified from Bebout and others (1993) and

Henry and Hester (1995). Ages in millions of years from Haq and Van Eysinga (1998),

and Gradstein and others, (2004) (red text). Fm.; Formation, Gp.; Group, Lst.;

Limestone, lm.; lime, Sh., Shale, Ss.; Sandstone .....................................................................4
iv

3. View to the southeast of elevation on the top of the informal Thirteen Finger

limestone model layer (Higley and others, 2014b). Areal extent of the Thirteen Finger

limestone is approximated by the light blue line. Major structures are labeled. CKU

is Central Kansas uplift. The Las Animas arch (not shown) is north of the Sierra

Grande uplift. The deep basin of Oklahoma and Texas is approximated by -6,000

feet elevation and deeper. Precambrian faults (red) are from Adler and others (1971). 

Faults bordering the Wichita Mountain uplift are vertical for 4D model purposes 

only, and subcropping strata on the uplift are unknown because of insufficient data. 

Data sources for this surface include formation picks from well logs and edited IHS 

Energy (2009, 2010a) formation tops. Vertical exaggeration is 18 times..............................6

4. South-north generalized cross sections showing stages of development of the

southern Oklahoma aulacogen (A, B) (modified from Gilbert, 1983; Perry, 1989),

southern Oklahoma trough (C), and Anadarko Basin and bounding Wichita

Mountain uplift and fault zone (D)..............................................................................................7

5. Map showing thickness of strata between the Hunton and Desmoinesian model

layers ranges from less than 500 meters (1,640 feet) over most of the Kansas shelf

to more than 5,000 meters (16,400 feet) in the deep basin of Oklahoma. This wedge

of Woodford Shale and younger rocks is oriented northwest-southeast, similar to

that of Woodford Shale thermal maturation contours. Precambrian faults (blue

lines) and named structures are from Adler and others (1971) ............................................8

6. Maps showing A, Oil and B, gas wells that produce from Pennsylvanian and (or)

Permian strata in the Anadarko Basin Province (IHS Energy, 2010a, 2010b).

Generalized field locations are from IHS Energy (2010a) and Bebout and others

(1993). Also shown are the Greater Granite Wash Composite Assessment Unit (AU)

and Pennsylvanian Composite Total Petroleum System (TPS) boundaries.

Precambrian faults are from Adler and others (1971) ..........................................................10

7. Generalized stratigraphic column for the Anadarko Basin Province, with

hydrocarbon source rocks highlighted (brown text). Increases in source rock

potential are indicated by larger numbers. The expected hydrocarbons column

heading indicate whether the source rock is more oil or gas prone. Blue highlights

source intervals used in the four-dimensional petroleum system model. Vertical

lines show a generalized time range of unconformity from Bebout and others (1993,

fig. 5). Chart is from J. Hatch (oral commun., 2010, and modified from Burruss and

Hatch (1989). Gp., Group; Fm., Formation................................................................................12

8. Images showing present-day thermal maturation of Woodford to Douglas model

layers using Woodford HP transformation ratio (% TR) kinetics (Lewan and Ruble,

2002) and vitrinite reflectance (% R

o

) (Sweeney and Burnham, 1990). Each layer

extends across the study area, including units located outside of the petroleum

source rocks. As an example, the Kansas portion of the Springer and Thirteen

Finger layers are almost identical because these units are absent over much of this

area and the thermal maturity reflects that of the underlying mostly Viola and

Simpson Groups strata. The vitrinite reflectance contours in equivalent layers in

chapter 3 (fig. 26) are limited to the extent of those strata, and also exhibit slightly

different thermal maturation patterns, which largely represents a somewhat newer

version of the model. Changes in thermal maturity on the shelf areas of Kansas and

Colorado are also minor because of shallow burial relative to the deep basin of

Oklahoma and Texas; source rocks are mostly immature for oil generation at less

than 0.6% R

o

. Thermal maturity for source rocks in the deep basin of Oklahoma and

Texas ranges from mature for oil generation, to overmature for gas generation at

about 4% R

o

 and greater. Red contour lines on the R

o

 images mark the 99 percent

transformation ratio that is approximately equivalent to 1.2% R

o

. Precambrian faults

(Adler and others, 1971) are shown as blue lines .................................................................13
v

9. Isopach map of Mississippian to Woodford petroleum system model layers, which

approximates the thickness of Mississippian rocks across the study area. Blank

areas indicate missing strata or insufficient data. Extent of the Woodford Shale is

approximated by the Woodford Shale Oil AU boundary in figure 1. Irregular

contours are mainly because of subtraction of these unfiltered (unsmoothed) layer

grids. Precambrian faults (green lines) are from Adler and others (1971)........................15

10. Maps showing A, Oil and B, gas wells that produce from the Mississippian AU in

the Anadarko Basin Province (IHS Energy, 2010b). Also shown in figure 10A are 276

horizontal wells drilled into Mississippian strata; 166 of these were completed after

2010 (IHS Energy, 2012)..............................................................................................................16

11. Cumulative number of producing wells by year for the Mississippian AU (IHS

Energy, 2010a, 2010b). Some of the wells include production from units other than

Mississippian. Onset of production from this AU for several major fields is also

shown. Locations are in figure 6 ..............................................................................................17

12. Grown gas and oil accumulation sizes for discovery thirds of the Mississippian

Assessment Unit of the Woodford Composite Total Petroleum System. Although

this is a mature assessment unit, the oil accumulations only show a minor drop for

the third of discoveries, and the gas accumulation history is stable. Data are from

the Nehring and Associates, Inc. (2009) field database, which has limited

information for the Mississippian fields. MMBO, million barrels of oil; BCFG, billion

cubic feet of gas .........................................................................................................................17

13. Petroleum system events chart for the Mississippian Assessment Unit of the

Woodford Composite Total Petroleum System. Timing of oil and gas generation,

migration, and accumulation is based primarily on Higley (2014) petroleum system

models. Potential petroleum source rocks (fig. 7; Hatch and others, 1986) are light

gray rectangles. Primary petroleum source rock for the Mississippian AU is the

Woodford Shale (Rice and others, 1988a, 1988b; Higley, 2014). The informal Osage

lime and Springer Formation are potential petroleum sources for the AU. Times of

peak generation from the Oil Creek Formation (blue), Woodford Shale (green) and

Thirteen Finger limestone (tan) source rocks are within blue shaded rectangles.

Paleogene trap formation, migration, and accumulation are based on Laramide

generation and potential remigration associated with erosion and basin tilting.

Unconformities, wavy and horizontal lines; lst, limestone; sh., shale; Fm., Formation;

Plio, Pliocene; Mio, Miocene; Eoc, Eocene; Pal, Paleocene; L, Late; M, Middle; E,

Early ..............................................................................................................................................18

14. History of petroleum generation from the Oil Creek Formation, Woodford Shale,

and informal Thirteen Finger limestone source layers in the four-dimensional (4D)

petroleum system model. History is based on Woodford hydrous pyrolysis kinetics

(Lewan and Ruble, 2002). Gray bars delineate periods of peak generation. Early oil

generation from the Oil Creek layer, prior to about 370 million years ago, is in a

narrow band that is proximal to the Wichita Mountain uplift. This band exceeds

maximum depth of the formation and is because of areas of poor data control in

the area bordering the fault zone. The error could have been removed by clipping

the 4D model extent to the basin axis and northward, but less of the model would

have been visible and usable ...................................................................................................19

15. Map showing elevation on the top of the Atoka model layer. Extent of Morrowan

and Atokan strata within the Pennsylvanian (Penn.) Composite Total Petroleum

System (TPS) is approximated by the Morrowan-Atokan Assessment Unit (AU)

boundary and in figure 3 elevation of the basal Thirteen Finger limestone. Elevation

is relative to sea level. Precambrian faults are from Adler and others (1971) .................20
vi

16. Maps showing A, Oil and B, gas wells that produce from Morrowan and Atokan 

reservoirs in the Anadarko Basin Province (IHS Energy, 2010a). The assessment

unit (AU) boundary approximates the extent of Morrowan and Atokan strata.

Precambrian faults are from Adler and others (1971). TPS, Total Petroleum System.....22

17. Cumulative number of wells by year that produce from the Morrowan and Atokan

(IHS Energy, 2010a, 2010b). Several major fields are also shown by year of

discovery; all are shown in figure 6.........................................................................................23

18. Discovery thirds of grown oil and gas accumulations for the Morrowan-Atokan

Assessment Unit (AU) of the Pennsylvanian Composite Total Petroleum System

(TPS). This is a mature AU, which is reflected by the generally larger field sizes

early in the exploration history (first third) relative to later discoveries (second

and third thirds). All thirds show similar trends in field sizes through time. Gas

accumulation history is stable for fields less than 10 billion cubic feet of gas

(BCFG), but exhibits progressive decline for fields greater than this. Data were

constructed using the Nehring and Associates, Inc. (2009) field database, which

has limited information for the Morrowan and Atokan fields. The database contains

more information on Morrowan and Atokan gas fields than oil fields, as indicated

by the data density on the plots. MMBO, million barrels of oil ...........................................23

19. Petroleum system events chart for the Morrowan-Atokan AU of the Pennsylvanian

Composite TPS. Woodford Shale (green) and Thirteen Finger limestone (tan)

ranges of oil and gas generation, migration, and accumulation are based primarily

on the petroleum system models. Potential petroleum source rocks from Hatch

and others (1986) are light gray. Time ranges of peak generation (fig. 14) are within

blue rectangles. Paleogene trap formation, migration, and accumulation are based

on Laramide generation and potential remigration associated with basin tilting.

Unconformities, wavy and horizontal lines; lst, limestone; sh., shale; Fm., Formation;

Plio, Pliocene; Mio, Miocene; Eoc, Eocene; Pal, Paleocene; L, Late; M, Middle; E,

Early ..............................................................................................................................................24

20. Isopach map of the top of the Thirteen Finger limestone to the Morrow Formation,

and the Thirteen Finger Limestone–Atoka Shale Gas AU (white line). Morrow and

Thirteen Finger tops are based on Andrews (1999a, 1999b), examination of more

than 120 well logs, and edited tops from IHS Energy (2009, 2010a). Morrow

Formation faults (pink) are modified from Andrews (1999b). Color contour interval

is 20 ft and (black) line contours are 10-feet intervals. Figure 21 cross sections are

labeled A–A’ and B–B’. White polygons are Perryton (Texas) and Knowles

Northwest (Oklahoma panhandle) oil fields, conventional oil reservoirs from the

Thirteen Finger limestone..........................................................................................................25

21.A, Southwest to northeast and B, southeast to northwest cross sections of the

Thirteen Finger limestone (TRFG) of the Pennsylvanian Atoka Group (ATOKA) in the

Anadarko Basin. Lines of section are in figure 20. Vertical scale is in feet relative to

the base of the Thirteen Finger limestone. MRMT is Marmaton Group, CHRK is

Cherokee Group, MRRW is Morrow Formation, and MSSP is top of the

Mississippian. Labeled well log traces are gamma (0 to 200 American Petroleum

Institute [API]), resistivity, sonic density, and neutron density...........................................26
vii

22. Petroleum system events chart for the continuous Thirteen Finger

Limestone–Atoka Shale Gas Assessment Unit (AU) of the Pennsylvanian Composite

Total Petroleum System. Timing of basin oil and gas generation, migration, and

accumulation is based primarily on the petroleum system models. Thirteen Finger

limestone (tan) periods of peak oil and gas generation are shown by the blue

rectangles. This AU is located in an overpressured zone of the deep basin

(Al-Shaieb and others, 1994). Because of this, Laramide uplift and erosion probably

had minimal effect on the pressure environment. Millions of years ago, Ma;

Unconformities, wavy and horizontal lines, lst; limestone, sh; shale.................................28

23. Photograph showing Desmoinesian outcrop along the San Juan River in the

Paradox Basin, southeastern Utah, illustrates carbonate/siliclastic cyclicity and

lateral continuity of beds. The informally named middle Desmoinesian “Old Yeller,”

Desert Creek, and Ismay zones are within the Paradox Formation and are roughly

age-equivalent to the upper Cherokee and lower Marmaton Groups in the

Anadarko Basin. This section is described in Grammer and others (1996) and is

located in about sec. 26, T. 41 S., R. 19 E. Raft is for scale and this north view of the

outcrop trends approximately west to east ...........................................................................30

24. Modeled surface on the Desmoinesian layer shows a broad gentle slope in

Colorado and Kansas that deepens near the basin axis, north of the Wichita

Mountain uplift. Vertical yellow bars are Precambrian faults, and surface colors

are generalized lithofacies from Adler and others (1971) that mainly record

increased clastics basinward. White areas do not contain Desmoinesian or

underlying Cherokee model layer lithofacies. Vertical exaggeration is 15 times............31

25. Maps showing A, Oil and B, gas wells that produce from the Desmoinesian

Assessment Unit (AU) Cherokee and Marmaton Groups in the Anadarko Basin

Province (IHS Energy, 2010a, 2010b). Generalized field locations are from IHS

Energy (2010a) and Bebout and others (1993). The Desmoinesian AU shares a

common boundary with the Pennsylvanian Composite Total Petroleum System

(TPS). Excluded from the AU is an oval area in the deep basin that is the Greater

Granite Wash Composite AU and included wells. Precambrian faults (pink) are from

Adler and others (1971)..............................................................................................................32

26. Cumulative number of new-field wildcats by year that produce from the

Desmoinesian AU (IHS Energy, 2010a, 2010b). Exploration and development was

static until about 1950, after which activity increased and has been fairly steady

through time. The displayed major fields by discovery dates produce oil and gas

from multiple units and ages. Field locations are shown in figure 25................................33

27. Grown gas and oil accumulation sizes for discovery thirds for the Cherokee and

Marmaton Groups reservoirs in the Desmoinesian Assessment Unit (AU)

(50580202). This AU has a mature exploration and development status with

production from about 1,400 fields in the province (IHS Energy, 2010a, 2010b);

however, only a few of these fields are represented on the figure. This paucity of

information from the Nehring and Associates, Inc. (2009) is primarily because of

reporting of production, mainly as commingled production from multiple units and

age ranges. The discovery thirds for oil accumulations show close agreement for

fields less than 8 MMBO, and for gas accumulations the limited data suggest that

the second third of discoveries was more successful than the first and third thirds.....33
viii

28. Petroleum system events chart for the Desmoinesian Assessment Unit (AU) of the

Pennsylvanian Composite Total Petroleum system (TPS). Potential petroleum

source rocks (fig. 7) from Hatch and others (1986) are light gray rectangles. The

Thirteen Finger limestone (tan) range of oil and gas generation, migration, and

accumulation represents Atokan and younger strata that are the primary

petroleum source rocks; the 300-million years ago (Ma) onset of generation is

based on the petroleum system one-dimensional and four-dimensional models.

Potential oil and gas contributions from older source rocks is bracketed by the

Woodford Shale (green) onset of generation of about 330 Ma. Time ranges of peak

generation (fig. 14) are within blue rectangles. Paleogene trap formation, migration,

and accumulation are based on Laramide generation and potential remigration

associated with basin tilting. Unconformities, wavy and horizontal lines; Plio,

Pliocene; Mio, Miocene; Eoc, Eocene; Pal, Paleocene; L, Late; M, Middle; E, Early ......34

29. Map showing elevation on the top of the Council Grove model layer for the

Anadarko Basin province. Inset image on the top of the overlying Chase layer

shows structures on this north-tilted view at 20 times vertical exaggeration. The

primary basin axis is proximal to the Wichita Mountain uplift (fig. 24) in Oklahoma

and Texas, the secondary axis trends northward along the west flank of the Central

Kansas uplift (CKU), which is bounded approximately by displayed faults. White

outlines the Panhandle (south) and Hugoton-Guymon (north) field areas (fig. 25).

Precambrian faults (red) are from Adler and others (1971).................................................36

30. Oil (green) and gas (red) migration flow paths on the Douglas and Permian layers in

the four-dimensional petroleum system model at present day. The image is tilted to

the north and is at 15 times exaggeration to better show flow paths. Yellow outline

is for the generalized locations of the Hugoton and Panhandle fields (fig. 25). In

general, flow follows topography on the model layers. Petroleum is generated

mostly in the deep basin and flows radially northward. Flow in northern Oklahoma

and in Kansas is directed toward the Las Animas arch (LA), Central Kansas uplift

(CKU), and Nemaha uplift. Gas flow paths at the western and eastern boundaries of

the map and the CKU resulted from decrease in pressure-volume-temperature

(PVT) conditions. Greenish-gold vertical bands are Precambrian faults (Adler and

others, 1971). These are the only modeled Missourian-Permian Assessment Unit

layers that have flow paths, mainly because (1) Heebner layer shale above the

Douglas layer provided enough of a seal to prevent upward leakage, (2) the

generalized lithologic assignments of other layers, and (3) coarse grid spacing

resulted in most generated petroleum migrating out of the model....................................38

31. Maps showing A, Oil and B, gas wells that produce from the Missourian-Permian

Assessment Unit (AU) in the Anadarko Basin Province (IHS Energy, 2010a, 2010b).

Also shown is the common boundary with the Greater Granite Wash Composite

AU boundary and included wells. Generalized field locations are from IHS Energy

(2010a) and Bebout and others (1993). Largest gas field is Hugoton-Guymon, which

extends northward from the Panhandle field. Gold-colored line on A is the

southeast to northwest cross section and (red dot) burial history plot location for

figure 39. Precambrian faults (pink) are from Adler and others (1971)..............................39

32. Graph showing production history of the Missourian-Permian Assessment Unit

(AU) in the Anadarko Basin Province with some of the major field discovery names

and dates (IHS Energy, 2010a, 2010b; Oklahoma Geological Survey, 2011a, 2011b).

Exploration and development was relatively slow until discovery of the

Watonga-Chickasha field. Development after about 1950 shows the same general

trends as those from other AUs ...............................................................................................40
ix

33. Map showing generalized contours of estimated ultimate gas recovery (EUR) in

million cubic feet of gas (MMCFG) from 1,024 leases in the Hugoton and Guymon

fields (data from Troy Cook, written commun., 2010). Leases represent single-well

production of gas from the Chase and (or) Council Grove Groups. Contours are

based on log10 EUR values to better show variability across the area. Horizontal

blue line is generalized location of cross sections shown in figure 35. Pink lines are

Precambrian faults from Adler and others (1971) .................................................................40

34. Graph showing discovery thirds of estimated ultimate recovery of gas (EUR) in

million cubic feet of gas (MMCFG) for 1,024 wells in the Hugoton and Guymon fields

that produce gas from the Chase and (or) Council Grove Groups (T. Cook, written

commun., 2010). Data represent leases that have one well per lease and are split

into the first, second, and third thirds of onset of production to November 2009,

based on data from IHS Energy (2010a, 2010b). The curves indicate that gas

production has undergone a steady decline since onset of production. Decline rate

is greatest for the more productive wells in the third of EUR .............................................41

35. Lithofacies in west to east cross sections across the Hugoton field for the (B)

Chase and (C) Council Grove Groups (modified from Dubois, 2007). These

stratigraphic cross sections are hung on the top of the Chase (B) and the Council

Grove (C), and location is in figure 33. Orange through red layers are continental

(Cont) sandstone (SS), siltstone (Silt) and shale. Other colors are marine

lithofacies, including fractured (Fxln) and crystalline (Cxln) dolomite (Dolo). Both

cross sections show lateral continuity of cyclical beds of marine and continental

strata. Marine strata increase in thickness to the east and continental beds thicken

westward. Dubois (2007) indicated that large-scale sedimentation patterns and

distribution of resultant lithofacies (at the cycle scale) are largely a function of the

position on the shelf and reflect the interaction of shelf geometry, sea level, and,

possibly, the proximity to siliclastic sources. Lithofacies distribution and

cycle-stacking patterns at larger scales may be a function of lower-order cyclicity

and a shift from icehouse to greenhouse conditions (upward) during the Lower

Permian ........................................................................................................................................42

36. Graphs showing grown oil and gas accumulation sizes for discovery thirds of the

Missourian-Permian Assessment Unit (AU) of the Pennsylvanian Composite Total

Petroleum System. Only a fraction of the about 1,420 oil and gas fields that produce

from this AU are shown, largely because many fields produce from multiple units

with reported commingled volumes. Discovery trends are similar of grown oil

accumulations less than about 20 million barrels of oil (MMBO). At greater than this 

volume, the first third of discoveries are larger than those of the second and third 

thirds. The early development history was marked by the giant Hugoton-Guymon 

and Panoma gas fields. In general, the gas accumulation chart shows a general 

decrease through time in field sizes. Billion cubic feet of gas, BCFG ...............................43

37. Model image showing oil and gas wells that produce from the Missourian-Permian

and Greater Granite Wash Composite assessment units (AU) in the Anadarko Basin

Province (IHS Energy, 2010a, 2010b) are superimposed on the image of Douglas

plus Permian layer flow paths (fig. 30). In general, areas with less flow have fewer

wells. Yellow outline is the Panhandle-Guymon-Hugoton field area, drilling is

somewhat faint within the gas fields because of the wider drill spacing than for oil

production. Absence of flow paths within the Panhandle field, with their

appearance on the west side of the field suggests (invisible) Darcy flow through

the reservoir because all potential source rocks are thermally immature in the

western Amarillo uplift (fig. 8) (Higley, 2014). Sorenson (2005) also indicated that

petroleum migrated southward from the basin into structural traps of the

Panhandle field. Precambrian faults are from Adler and others (1971) ............................44
x

38. Map showing basement heat flow contours across the Anadarko Basin based on

data from Carter and others (1998), Blackwell and Richards (2004), and data

downloads from the Southern Methodist University Web site (http://smu.edu/geothermal/). Shown are the cross sections (blue lines) in figures

39 and 40, location of the one-dimensional burial history model (red dot), and

Panhandle-Guymon-Hugoton field outlines (pink lines). Values are milliwatts per

square meter (mW/m

2

). The A–A’ section crosses several zones of elevated heat

flow and B–B’ is mainly in areas of decreased heat flow. Basin areas north of the

Wichita Mountain uplift and in the Amarillo uplift and northward exhibit generally

lower heat flows than other basin areas. Highest measured heat flow is in the

northwest, along the Las Animas arch. The northwest-trending Central Kansas

uplift also exhibits elevated heat flow values. Red lines are faults on the top of the

Hunton Group from Rottmann (2000a) that were used to contour Hunton and

Woodford layers, and Precambrian faults (modified from Adler and others, 1971) ........45

39. Southeast to northwest structural cross section with present-day transformation

ratios (% TR). The burial history plot of TR and vitrinite reflectance (% R

o

) is near

the red dot on the cross section, and both locations are in figure 38. Pink lines are

the general location of the Woodford Shale layer. The two “bumps” of increased

thermal maturation on the cross section correspond to areas of increased heat

flow in figure 38. Lithologic variation has minor effect on these increases because

of the generalized lithofacies assignments in the model. If basement heat flow was

one value across the basin, then the TR contours would be approximately

horizontal because of the strong influence of burial depth. The burial history plots

show the Council Grove layer as marginally mature for oil generation at 0.1 percent

TR and 0.6% R

o

, and the Woodford Shale layer is overmature for oil generation

based on 100 percent TR and more than 1.2% R

o

. The one-dimensional model is

about 2 kilometers southwest of the Woodford Shale measurement of Cardott

(1989, p. 45) for the 1 Miami Cattle well (1.56% mean R

o

 at -3,563 m elevation). These

images are extractions from the four-dimensional petroleum system model, and are

displayed in elevation relative to sea level ............................................................................46

40. Cross section showing vitrinite reflectance (% R

o

) and transformation ratio (% TR)

is an extraction from the four-dimensional model across the Panhandle field.

Location is in figure 38. The Panhandle field is located on the Amarillo uplift and oil

and gas are produced from Wolfcampian and Leonardian strata. The Stone Corral

model layer is bounded by pink lines and includes units from the top of the

Leonardian Wellington to the base of the Guadalupian Blaine Formations (fig. 2). It

is underlain by Wolfcampian strata. The Amarillo uplift and areas to the northwest

are thermally immature for oil generation, and potential petroleum source rocks

are absent because of erosion or nondeposition. Oil and gas migration flow

paths appear west of the Panhandle field in figures 30 and 36; this indicates that

hydrocarbons did flow through this field but were not trapped in this leaky model,

and were most likely sourced from the east and northeast from Pennsylvanian and

older source rocks and through open fault systems. Vertical exaggeration is 

33 times.........................................................................................................................................47
xi

41. Petroleum system events chart for the Missourian-Permian AU of the

Pennsylvanian Composite TPS. Primary hydrocarbon source rocks are dark gray

rectangles, and age ranges of potential source rocks from Hatch and others (1986)

(fig. 7) are light gray rectangles. Onset and peak petroleum generation (fig. 14) are

shown for the Oil Creek (blue), Woodford (green), and Thirteen Finger limestone

(tan) source rocks. Age ranges of peak hydrocarbon generation are indicated by

blue rectangles. Paleogene trap formation, migration, and accumulation are based

on Laramide generation and potential remigration associated with basin tilting.

Unconformities, wavy and horizontal lines; Fm(s)., Formation(s); Plio, Pliocene;

Mio, Miocene; Eoc, Eocene; Pal, Paleocene; L, Late; M, Middle; E, Early........................48

42. Simplified southwest to northeast structural cross section from the Oklahoma

deep basin to the shelf shows interfingering of granite wash lithofacies (blue) with

those basinward (modified from Johnson, 1989). Greater Granite Wash Composite

Assessment Unit (AU) boundary is gold line and cross section location is red line

on inset map. Datum is sea level. Sil.-Dev., Silurian-Devonian...........................................49

43. Map showing thickness of the top of the Atoka to the Stone Corral model layers in

the Greater Granite Wash Composite Assessment Unit (AU) ranges from about 0 to

more than 14,000 feet (ft). Areas of smooth contours have more limited data, such

as the Wichita Mountain uplift and Panhandle field areas; actual thicknesses here

are generally less than 1,000 ft (300 meters). Displayed wells produce oil and (or)

gas from granite wash facies. Contour lines are 500-feet intervals. Precambrian

faults (black) are from Adler and others (1971). Light gray lines are counties.................50

44. Map showing oil and gas wells that produce from the Greater Granite Wash

Composite Assessment Unit (AU) in the Pennsylvanian Composite Total Petroleum

System (TPS), Anadarko Basin Province (IHS Energy, 2010a, 2010b). Smaller scale

views of oil and of gas wells are in the Desmoinesian and Missourian-Permian oil

and gas figures 24 and 31. Generalized field locations are from IHS Energy (2010a),

Nehring and Associates, Inc. (2009), and Bebout and others (1993). The largest field

is Panhandle, which covers most of the Amarillo uplift and produces from granite

wash and other lithofacies. Precambrian faults (blue) are from Adler and others

(1971). Light gray lines are counties ........................................................................................50

45. Map showing oil and (or) gas wells that produce from the granite wash within the

Greater Granite Wash Composite Assessment Unit (AU). Some of the more than

3,600 Oklahoma Geological Survey (2011b) wells up to about 2008 are overlain by

the more than 6,900 wells through September 2010 from IHS Energy (2010a, 2010b).

Generalized field locations are from IHS Energy (2010a), Nehring and Associates,

Inc. (2009), and Bebout and others (1993). Precambrian faults (blue) are from Adler

and others (1971). Light gray lines are counties....................................................................51

46. Discovery halves for oil and thirds for gas grown accumulations for the Greater

Granite Wash Composite Assessment Unit (AU) in the Anadarko Basin Province.

Only a fraction of the oil and gas fields that produce from this AU are shown,

largely because most fields produce from multiple units with reported commingled

volumes. These also include giant fields, such as Panhandle, which is not included

in the discovery halves plot. Because these figures include some production

from strata north of the granite wash lithofacies, the discovery plots are further

compromised. The discovery halves of oil accumulations indicate that

development has decreased through time. This “trend” probably reflects the

paucity of data. The discovery thirds of gas accumulations indicates discovery has

been fairly stable through time, although field sizes have decreased for larger

fields as indicated by the third of accumulations greater than 20 billion cubic feet

of gas (BCFG)...............................................................................................................................52
xii

47. Production history of leases in the Greater Granite Wash Composite Assessment

Unit in the Anadarko Basin Province is shown relative to the more than 3,700

completed wells for the same time increments from Oklahoma Geological Survey

(OGS, 2011b). Granite wash development started about 1950 and the Oklahoma

Geological Survey (2011b) bars follow industry boom and bust cycles with an

increase in completions from 1976 to 1985, followed by a lull until about the 2002

increase in exploration. Shown are some of the major field discovery names and

year (Nehring and Associates, Inc., 2009; IHS Energy, 2010a, 2010b)................................53

48. Petroleum system events chart for the Greater Granite Wash Composite

Assessment Unit (AU) of the Pennsylvanian Composite Total Petroleum System

(TPS). Dashed reservoir rock rectangle shows an interval of potential granite wash

deposition that was included in the Morrowan-Atokan Assessment Unit (AU).

Potential petroleum source rocks from Hatch and others (1986) (fig. 7) are light gray

rectangles. Onset and peak petroleum generation (fig. 14) are shown for the Oil

Creek Formation (blue), Woodford Shale (green), and Thirteen Finger limestone

(tan) source rocks. Age ranges of peak generation are indicated by blue

rectangles. Paleogene trap formation, migration, and accumulation are based

on Laramide generation and potential remigration associated with basin tilting.

Unconformities, wavy and horizontal lines; Fm., Formation; Plio, Pliocene; Mio,

Miocene; Eoc, Eocene; Pal, Paleocene; L, Late; M, Middle; E, Early.................................54

Tables

1. Anadarko Basin Province assessment results are listed by name of Total Petroleum

System (TPS) and Assessment Unit (AU) .................................................................................3

2. Oil generation onset for the Anadarko Basin 4D model, and onset and completion

dates in millions of years before the present (Ma) for the Bertha Rogers 1 and

Petree Ranch 1 1D models based on Woodford Shale hydrous pyrolysis (HP)

kinetics (Lewan and Ruble, 2002). The Douglas Group overlies the youngest

potential petroleum source rocks in figure 7. The HP kinetics-based onset of oil

generation is 0.1 percent transformation ratio (TR) and completion is 99 percent TR.

Oil generation histories in the 4D model were recorded at 10-Ma increments; so

the plus symbol indicates onset was before the listed age ................................................11
Abstract

The Anadarko Basin Province includes the Anadarko 

Basin of western Oklahoma, western Kansas, and northern 

Texas, the Las Animas arch of southeastern Colorado, and 

the Palo Duro Basin of Texas. This is a mature petroleum 

province for conventional oil and gas reserves and resources. 

Two total petroleum systems were defined for the province. 

The Woodford Composite Total Petroleum System includes 

Cambrian through Mississippian strata, and the Pennsylvanian 

Composite Total Petroleum System comprises Pennsylvanian 

through Permian strata. This chapter of the report details 

assessment results and associated methodology for conventional and continuous resources for defined assessment units 

(AU) of Mississippian through Permian strata within the 

total petroleum systems. Mean undiscovered conventional 

resources for Mississippian through Permian assessment units 

in the Anadarko Basin Province total 77 million barrels of oil 

(MMBO), 1,934 billion cubic feet of gas (BCFG), and 60 million barrels of natural gas liquids (MMBNGL). 

Total petroleum system assessment methods of analysis resulted in mean undiscovered resources of 17 MMBO, 

417 BCFG, and 11 MMBNGL for the Mississippian Assessment Unit (AU) of the Woodford Composite Total Petroleum 

System (TPS). Mean undiscovered continuous gas resources 

for the Thirteen Finger Limestone–Atoka Shale Gas AU are 

6.850 trillion cubic feet of gas (TCFG) and 82 MMBNGL. 

Undiscovered oil resources for the Thirteen Finger limestone 

and Atoka Shale are incorporated in the conventional Morrowan-Atokan AU. Mean undiscovered conventional resources 

for the Pennsylvanian Composite TPS include:

a. 15 MMBO, 332 BCFG, and 7 MMBNGL for the 

Morrowan–Atokan AU; 

b. 6 MMBO, 118 BCFG, and 4 MMBNGL for the Desmoinesian AU;

c. 23 MMBO, 258 BCFG, and 8 MMBNGL for the 

Missourian–Permian AU

d. 16 MMBO, 809 BCFG, and 30 MMBNGL for the 

Desmoinesian through Permian Greater Granite Wash 

Composite AU

Introduction

The U.S. Geological Survey (USGS) recently completed 

an assessment of the undiscovered oil and gas resource potential of the Anadarko Basin Province of western Oklahoma, 

western Kansas, northern Texas, and southeastern Colorado 

(fig. 1). The province area covers 59,861 square miles and 

includes the Anadarko Basin, Las Animas arch, and Palo Duro 

Basin. This is hereafter referred to as the 2011 assessment, 

which corresponds to the publication date of the assessment 

results by Higley and others (2011). Results of the assessment and geologic analysis (table 1) are based on the geologic 

elements that are used to define each total petroleum system 

(TPS), including hydrocarbon source rocks (source-rock 

maturation, hydrocarbon generation and migration), reservoir 

rocks (sequence stratigraphy and petrophysical properties), 

and hydrocarbon traps (trap formation and timing). 

Using this geologic framework, the USGS defined the 

Woodford Composite TPS and Pennsylvanian Composite 

TPS and nine conventional and three continuous assessment 

units (AU), and quantitatively estimated the undiscovered 

oil and gas resources within each AU. The AU code numbers 

and assignments to TPSs are listed below. Those detailed 

within this chapter of the report are highlighted in bold text 

and AU boundaries are shown in figure 1 and the figure 2 

stratigraphic column of Devonian through Permian units. 

The Woodford Shale Oil AU and Woodford Shale Gas AU 

are discussed in Higley and Cook (2014a); they are included 

Petroleum Systems and Assessment of Undiscovered 

Oil and Gas in the Anadarko Basin Province, Colorado, 

Kansas, Oklahoma, and Texas—Mississippian Through 

Permian Assessment Units

By Debra K. Higley
2 Petroleum Systems and Assessment of Undiscovered Oil and Gas in the Anadarko Basin Province

Figure 1. Map showing Anadarko Basin (red dashed line) and boundaries of 

total petroleum systems (TPS) and assessment units (AU) that are described in 

this chapter of the report. The Desmoinesian and Missourian-Permian AUs share 

a common boundary with the Pennsylvanian Composite TPS, with the exception 

that the AUs include a “donut hole” that is the Greater Granite Wash Composite 

AU. There are common boundaries for most AUs.

Pennsylvanian 

Composite TPS, 

Desmoinesian, and 

Missourian-Permian AUs

Woodford 

Composite TPS

Thirteen Finger Limestone-

 Atoka Shale AU

Greater Granite 

Wash Composite AU

Morrowan-Atokan AU

Woodford Shale Oil AU

Woodford 

Shale 

Gas AU

Mississippian

 AU

104° 103° 102° 101° 100° 99° 98° 97°

39°

38°

37°

36°

35°

34°

GULF 

OF 

MEXICO

TEXAS

NEW

MEXICO

COLORADO KANSAS

OKLAHOMA

Anadarko 

 Basin 

 Province

Figure 1. Ch. 7 

Denver

Basin

Raton

Basin

Anadarko

Basin

 Las 

 Animas

arch

Palo

Duro

Basin

Nemaha uplift

0 50 100 MILES

0 50 100 KILOMETERS

COLORADO

NEW MEXICO

TEXAS

KANSAS
Introduction 3

Table 1. Anadarko Basin Province assessment results are listed by name of Total Petroleum System (TPS) and Assessment Unit (AU).

[Resources are undiscovered oil, gas, and (or) natural gas liquids. MMBO, million barrels of oil; BCFG, billion cubic feet of gas; MMBNGL, million barrels 

of natural gas liquids. Field type refers to mainly oil or gas accumulations in the assessment unit. Fractiles are fully risked estimates. F95 denotes a 95-percent 

chance of at least the amount tabulated. Other fractiles are defined similarly. Fractiles are additive only under the assumption of perfect positive correlation]

Total Petroleum Systems 

(TPS) and Assessment Units 

(AU)

Field 

Type

Total Undiscovered Resources

Oil (MMBO) Gas (BCFG) NGL (MMBNGL)

F95 F50 F5 Mean F95 F50 F5 Mean F95 F50 F5 Mean

Woodford Composite TPS

Arbuckle-Ellenburger AU

Oil 2 5 12 6 7 24 61 28 0 1 2 1

Gas 43 164 371 181 0 1 2 1

Simpson Group AU

Oil 2 4 9 5 6 17 39 19 0 0 1 1

Gas 33 114 252 125 2 9 21 10

Viola Group AU

Oil 2 5 10 5 3 9 20 10 0 1 2 1

Gas 10 27 58 30 0 0 0 0

Hunton Group AU

Oil 2 8 21 9 8 32 87 38 0 1 3 1

Gas 71 281 641 310 0 2 4 2

Mississippian AU

Oil 5 16 31 17 15 46 99 50 0 2 4 2

Gas 125 350 663 367 3 8 17 9

Pennsylvanian Composite TPS

Morrowan-Atokan AU

Oil 6 14 29 15 21 55 121 61 1 2 5 2

Gas 101 261 469 271 2 5 10 5

Desmoinesian AU

Oil 2 6 12 6 8 23 52 26 0 1 2 1

Gas 29 87 167 92 1 3 5 3

Missourian-Permian AU

Oil 10 22 38 23 49 114 223 122 2 4 8 4

Gas 61 130 231 136 2 4 7 4

Greater Granite Wash 

Composite AU

Oil 4 14 34 16 22 78 198 90 1 2 7 3

Gas 192 646 1,496 719 7 24 60 27

Total Conventional

 Resources 35 94 196 102 804 2,458 5,248 2,675 21 70 160 77

Woodford Composite TPS

Woodford Shale Oil AU

Woodford Shale Gas AU

Oil 175 357 730 393 795 1,750 3,851 1,963 22 51 121 59

Gas 8,806 15,131 25,998 15,973 94 178 336 192

Pennsylvanian Composite TPS

Thirteen Finger LimestoneAtoka Shale Gas AU

Oil

Gas 3,040 6,229 12,763 6,850 33 73 161 82

Total Continuous

 Resources 175 357 730 393 12,641 23,110 42,612 24,786 149 302 618 333

Total Resources 210 451 926 495 13,445 25,568 47,860 27,461 170 372 778 410
4 Petroleum Systems and Assessment of Undiscovered Oil and Gas in the Anadarko Basin Province

Figure 2. Generalized stratigraphic columns for Devonian 

through Permian strata in the Anadarko Basin Province. 

Assessment unit (AU) names and generalized divisions are 

split at the horizontal red line into (upper) Pennsylvanian 

Composite Total Petroleum System (TPS) and (lower) 

Woodford Composite TPS. Italics (blue text) and lowercase 

names indicate informal status. The Devonian Misener sand 

was evaluated as part of the Hunton Group AU (Gaswirth and 

Higley, 2014). Extension of the Morrowan-Atokan AU into the 

Desmoinesian reflects the unclear boundary of the Atoka 

Shale in the southern basin. Modified from Bebout and others 

(1993) and Henry and Hester (1995). Ages in millions of years 

from Haq and Van Eysinga (1998), and Gradstein and others, 

(2004) (red text). Fm.; Formation, Gp.; Group, Lst.; Limestone, 

lm.; lime, Sh., Shale, Ss.; Sandstone.

Woodford

Shale 

Gas, Oil Mississippian Morrowan- Atokan

 Wash Composite Greater Granite

Missourian – Permian Desmoinesian MorrowanAtokan

Pennsylvanian

Marmaton Gp.

Lagonda Ss.

Verdigris Lst.

Tiawah Lst.

Taft Ss.

Inola Lst.

Bluejacket Ss.

Warner Ss.

Chelsea Ss.

Cherokee Group

Atoka Group Atoka Group

Morrow shale

Puryear sand

Keyes sand

Kearny 

 Fm.

Morrow Group

Morrowan Atokan Desmoinesian

Morrow Formation

Lower Upper

Purdy sand

Keyes sand

Thirteen Finger lst.

Deese 

Group

Atoka Shale

Dornick Hills 

 shale

Primrose Ss.

Dornick Hills Group

?

Thirteen Finger 

Limestone - 

Atoka Shale

256

271

300

304

308

311

333

340

365

374

359.2

± 2.5

318.1

 ± 1.3

299.0

± 0.8

251.0

± 0.4

System

Series Guada- lupian Leonar- dian Wolfcampian Missourian Virgilian

Age, Ma

Hugoton

Embayment

Kansas

Northern

Anadarko

Basin

Southern

Anadarko

Basin

AU

names

Ochoan

Permian

Cloud Chief Formation Big Basin Formation

Day Creek Dolomite

Whitehorse Fm. Whitehorse Group

Nippewalla Gp. El Reno Group

Sumner

GroupStone Corral Fm.

Ninnescah Fm.

Wellington Fm.

Enid

Gp.

Hennessey Sh.

Chase Group

Council Grove Gp.

Admire Group

Wabaunsee Gp.

Shawnee Group

Topeka Lst.

Douglas Group

Oread Lst.

Lansing Group

Kansas City 

 Group

Pleasanton Gp.

Kansas City Gp.

Dewey Lst.

Hogshooter Lst.

Dodds Creek Ss.

Checkerboard Lst.

Garber Ss.

Pontotoc 

 Group

Ada Gp.

Vamoosa Gp.

Hoxbar 

 Group

CH7_Figure2 

348

Wellington Fm. Wellington Fm.

Stone Corral Fm.

Chase Group

Council Grove Gp.

Admire Group

Wabaunsee Gp.

Douglas Group

Lansing Group

Marmaton Gp.

Pumpkin 

Creek

Limestone

Mississippian

Chesterian Mera- mecian Osa- Gean

Chester Group

Mississippi lime

Osage chert

Gilmore City Lst

Hannibal Shale

Mississippi chat

Mississippi solid

Cowley Formation

Osage lm.

Kinderhook Sh.

 Kinderhookian

Mayes Group

Caney Shale

Sycamore 

 Lst.

Chautauquan (Part)

Misener sand Misener sand

Senecan

Erian (part)

Devonian

Woodford Sh. Woodford Sh.

Meramec

lime

Meramec

lime

Springer 

 Fm.

Springer Fm.

Chester Group
Geologic Setting of the Anadarko Basin Province 5

in figure 1 because they delineate major petroleum source 

rocks in the basin. 

Woodford Composite TPS 505801:

1. Arbuckle-Ellenburger, AU 50580101

2. Simpson Group, AU 50580102

3. Viola Group, AU 50580103

4. Hunton Group, AU 50580104

5. Mississippian, AU 50580105

6. Woodford Shale Gas, AU 50580161

7. Woodford Shale Oil, AU 50580162

Pennsylvanian Composite TPS 505802:

1. Morrowan-Atokan, AU 50580201

2. Desmoinesian, AU 50580202

3. Missourian-Permian, AU 50580203

4. Greater Granite Wash Composite, AU 50580204

5. Thirteen Finger Limestone–Atoka Shale Gas, AU 

50580261

Geologic Setting of the Anadarko 

Basin Province

Structural and isopach surfaces used in this chapter of 

the report and for building a four-dimensional (4D) petroleum 

system model (Higley, 2014; Higley and others, 2014) were 

constructed using edited formation tops data from (1) more 

than 220 wells across the province; (2) IHS Energy (2009, 

2010a); (3) Kansas Geological Survey (2010, http://www.

kgs.ku.edu/PRS/petroDB.html); and (4) maps and data from 

Fay (1964), Rascoe and Hyne (1987), Robbins and Keller 

(1992), Cederstrand, and Becker (1998), Andrews (1999a, 

1999b, 2001), and Rottmann (2000a, 2000b). Rock unit 

ages and lithologies for surfaces and stratigraphic columns 

are commonly generalized; sources of information include 

Denison and others (1984), Ludvigon and others (2009), and 

the National Geologic Map Database (2011, http://ngmdb.

usgs.gov/Geolex/). Figures within this chapter of the report 

may variously have feet or meters as vertical scales. Metric scales are mainly used for the one-dimensional (1D), 

two-dimensional, and 4D petroleum system models, largely 

because of ease in using the modeling software. Vertical scale 

of most contour maps and of well-log cross sections are in 

feet because that is traditionally used in the United States. 

Tilted three-dimensional (3D) images generally do not have 

map scales because edges would have different scales, with 

the associated clutter.

Structural History

The Anadarko Basin Province, which also incorporates the Las Animas arch and Palo Duro Basin, is located 

in western Kansas, western Oklahoma, northern Texas, and 

southeastern Colorado. The Anadarko Basin is the deepest 

in the onshore United States and markedly asymmetrical, 

with Precambrian basement ranging in depth from more than 

40,000 feet (ft) at the basin axis in southern Oklahoma, to 

surface exposures on the broad shelf in the proximal Central 

Kansas uplift (CKU) of Kansas. The basin is bounded on the 

southeast by the Marietta-Ardmore Basin, on the east by the 

Nemaha uplift and Salina Basin, on the north by the CKU, and 

on the south by the eroded Amarillo–Wichita Mountain uplift 

(fig. 3). Western boundaries are the Denver and Raton Basins 

(fig. 1). The Nemaha uplift consists of a discontinuous series 

of block-faulted segments, each of which is about 5–20 mile 

long (north-south) and 3–5 mile wide, and forms the axis and 

western boundary of the broad, gently raised Central Oklahoma platform (Johnson, 1989) that separates the Anadarko 

Basin from the Ardmore Basin. The platform contains Precambrian and pre-Pennsylvanian rocks that are unconformably 

overlain by Desmoinesian and Missourian age strata (Rascoe 

and Adler, 1983). 

Schatski (1946) stated that southern Oklahoma was 

initially an aulacogen. The latest Precambrian to earliest 

Cambrian structural setting of southern Oklahoma is considered to be that of a failed linear rift (aulacogen) of an inferred 

plate tectonic triple junction (Burke, 1977; Perry, 1989), the 

common name of which is the Southern Oklahoma aulacogen. 

Axis of the resulting southern Oklahoma trough extended 

northwest from the paleocontinental eastern margin through 

the area now occupied by the Ardmore Basin and Arbuckle 

Mountains, the Wichita Mountains and vicinity, and into the 

northern Panhandle of Texas (Perry, 1989). At the close of 

the rifting phase, the aulacogen began to cool and subside 

(Feinstein, 1981). From Cambrian to Mississippian time, the 

area of the Anadarko Basin was located near the equator and 

predominantly covered by warm, shallow seas with mostly 

carbonate deposition (Wang and Philp, 1997). A passive 

continental margin existed outward from the trough during 

this time period (Nicholas and Rozendal, 1975; Keller and 

others, 1983). More than 3.3 kilometers (km) [11,000 feet (ft)] 

of Cambrian through Lower Devonian rocks were deposited 

over the axis of the aulacogen in the region of the Wichita and 

southwestern Arbuckle Mountains (Ham, 1973). 

The Late Mississippian (probably Chesterian) was 

marked by renewed tectonism (Perry, 1989). Major plate collision between the North American plate and either Gondwana 

or an intervening microplate resulted in onset of the Ouachita 

orogeny and formation of the ancestral Rocky Mountains 

(Kluth and Coney, 1981; Kluth, 1986). Ball and others (1991) 

indicated the Mississippian Period closed with regional uplift 

and erosion that marked the start of the Wichita orogeny. Near 

the end of Mississippian time, the seas retreated to the deeper 

areas of the geosyncline because of upwarping of the Wichita 
6 Petroleum Systems and Assessment of Undiscovered Oil and Gas in the Anadarko Basin Province

Mountain and Amarillo uplifts, elevation of the CKU, and subsequent emergence of the shelf areas, including the Oklahoma 

Panhandle and portions of the Texas Panhandle (Owen, 1975). 

There is distinctive Precambrian layering on seismic 

profiles recorded south of the Wichita Mountains that is not 

visible under the Anadarko Basin. The Proterozoic basin containing that layering may have been bounded on its north side 

by a Precambrian fault that was probably twice reactivated 

during formation of the Southern Oklahoma aulacogen—once 

during the late Precambrian (?)–Early Cambrian extension, 

and again during Pennsylvanian compression (Brewer and 

others, 1983). Pennsylvanian compression resulted in crystalline basement rocks of the Wichita Mountains being thrusted 

northeastward over the basin along a series of deep faults 

(about 20- to 24-km depths) with moderate (average 30° to 

40°) southwesterly dips (Brewer and others, 1983). Thrusting 

was northward toward the rapidly subsiding Anadarko Basin 

(Johnson, 1989). During the Early Pennsylvanian to Permian 

Ouachita and Wichita orogenies, Texas and Oklahoma moved 

northward and the Wichita Mountains and Amarillo arch were 

uplifted and thrust over the southern margins of the southern 

Oklahoma aulacogen and its superimposed basin, the southern 

Oklahoma trough (Ball and others, 1991). Figure 4 shows the 

generalized sequence of development from the Precambrian 

through Permian as the southern Oklahoma aulacogen proceeded from rifting into the Wichita Mountain uplift.

The Ouachita and Wichita orogenies were responsible for 

(1) folding and faulting of the Ouachita foldbelt in the Midcontinent, (2) subsidence of the Arkoma Basin, (3) emergence 

of the Amarillo, Wichita Mountain, and Nemaha uplifts; 

Figure 3. View to the southeast of elevation on the top of the informal Thirteen Finger limestone model layer (Higley and others, 2014b). 

Areal extent of the Thirteen Finger limestone is approximated by the light blue line. Major structures are labeled. CKU is Central Kansas 

uplift. The Las Animas arch (not shown) is north of the Sierra Grande uplift. The deep basin of Oklahoma and Texas is approximated by 

-6,000 feet elevation and deeper. Precambrian faults (red) are from Adler and others (1971). Faults bordering the Wichita Mountain uplift 

are vertical for 4D model purposes only, and subcropping strata on the uplift are unknown because of insufficient data. Data sources for 

this surface include formation picks from well logs and edited IHS Energy (2009, 2010a) formation tops. Vertical exaggeration is 18 times.

Arbuckle 

anticline

EXPLANATION

Elevation (feet) 

relative to sea level

 4,000

 0

-4,000

-8,000

-12,000

-16,000

-20,000

-24,000

Figure 3. Ch. 7 

Salina Basin

Wichita 

Mountain 

uplift

KANSAS

COLORADO

TEXAS

CKU

Pratt

anticline

Nemaha uplift

Hugoton embayment

Amarillo uplift

Sierra Grande 

 uplift

Keyes

dome

NEW MEXICO

N

OKLAHOMA

Cimarron 

 arch
Geologic Setting of the Anadarko Basin Province 7

Figure 4. South-north generalized cross sections showing 

stages of development of the southern Oklahoma aulacogen (A, B) 

(modified from Gilbert, 1983; Perry, 1989), southern Oklahoma trough 

(C), and Anadarko Basin and bounding Wichita Mountain uplift and 

fault zone (D). 

Wichita fault zone

Wichita Mountain uplift

Figure 4. ch. 7

~ 300 - 250 Ma

D

Reverse movement on older normal faults

~ 520 - 400 Ma

C

~ 540 - 520 Ma

B

~ 560 - 540 Ma

A

SOUTH NORTH

Arbuckle to Hunton Groups deposition

Granitic intrusions and rhyolite and 

ignimbrite extrusions

Gabbroic intrusions

Basalt flows Nonmarine Basin fill

Cooling and collapse of earlier rift

Initiation of syntectonic 

sedimentation
8 Petroleum Systems and Assessment of Undiscovered Oil and Gas in the Anadarko Basin Province

(4) uplift of the Cimarron arch and structures along the Las 

Animas arch; and (5) uplift of the Apishapa (Rascoe and 

Adler, 1983). The Anadarko Basin thus began to assume its 

present asymmetrical form (Owen, 1975). Associated faulting 

started at the southeast area of the basin in early Morrowan 

time (Ham and Wilson, 1967), whereas farther west it began in 

late Morrowan time; faulting persisted through the rest of the 

Pennsylvanian and probably died out during the Early Permian (Johnson, 1989). There is some evidence of left-lateral 

displacement associated with thrusting, but thrusting was most 

important in developing en echelon folds; strike-slip faulting 

was relatively minor and late, with most occurring during the 

Permian (Perry, 1989; Ball and others, 1991).

Pennsylvanian downwarping of the AnadarkoBasin 

was at least partially the result of thrust loading, in contrast 

with interpretations of Pennsylvanian structures resulting 

from mainly vertical movements along high-angle faults 

(Brewer and others, 1983). Maximum structural displacement between the Wichita Mountain uplift and the basin floor 

exceeds 9,144 meters (m) (30,000 ft) (Al-Shaieb and others, 

1994). Downwarping of the basin and compaction through 

time resulted in increased thickness of strata proximal to 

the Wichita Mountain and Amarillo uplifts. The Woodford 

Shale through Desmoinesian interval in particular has a pronounced wedge shape with a northwest-trending axis (fig. 5). 

Continued Permian filling of the Anadarko Basin following 

Pennsylvanian thrust loading may have resulted from compaction and dewatering of the thick Upper Mississippian and 

Pennsylvanian sediments (Perry, 1989). Compaction would 

have been greatest in the deep basin because these strata 

were thickest, with associated increased rate of deposition 

compared to shelf areas.

The current Rocky Mountains formed in the area of the 

eroded core of the Ancestral Rocky Mountains during the 

Laramide orogeny of Late Cretaceous and early Tertiary time. 

The orogeny raised and imparted an eastward and southeastward tilt to the entire region, with associated withdrawal of the 

Cretaceous epicontinental sea (Owen, 1975; Johnson, 1989) 

following deposition of the Upper Cretaceous Pierre Shale. 

Sorenson (2005) indicated that the Laramide orogeny may also 

Figure 5. Map showing thickness of strata between the Hunton and 

Desmoinesian model layers ranges from less than 500 meters (1,640 feet) 

over most of the Kansas shelf to more than 5,000 meters (16,400 feet) in 

the deep basin of Oklahoma. This wedge of Woodford Shale and younger 

rocks is oriented northwest-southeast, similar to that of Woodford Shale 

thermal maturation contours. Precambrian faults (blue lines) and named 

structures are from Adler and others (1971).

EXPLANATION

Thickness,

in meters

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000

5,500

6,000

103° 102° 101° 100° 99° 98° 97°

39°

38°

37°

36°

35°

COLORADO KANSAS

TEXAS

NEW MEXICO

OKLAHOMA

Wichita 

 Mountain 

 uplift

Nemaha uplift

Arbuckle

Mountains

Salina 

Basin

Pratt

anticline

Amarillo uplift

Las Animas arch

Central Kansas uplift

Sierra Grande uplift

Cimarron 

arch

Dalhart

 Basin

Anadarko Basin

Palo Duro

 Basin

0 50 100 MILES

0 50 100 KILOMETERS
Petroleum Production History 9

have influenced petroleum migration in the basin, specifically 

redistribution of Panhandle field fluid columns with northward 

spilling of gas into the Hugoton embayment.

Mostly alluvial sediments of the Miocene to Pliocene 

Ogallala Formation were deposited on an erosional surface of 

largely Permian, and Mesozoic strata in the western one-half 

of the basin (Seni, 1980; Johnson and others, 1988). Mesozoic 

units are present mostly in the Colorado and western Kansas 

portion of the province, with only scattered erosional remnants 

in Oklahoma and Texas. 

Petroleum Production History

With more than 220,000 drill holes (IHS Energy, 2010a), 

the Anadarko Basin Province is in a mature state of exploration 

and development. Horizontal well completions for reported 

Oklahoma wells increased from less than 5 percent in 2002 to 

almost 30 percent in 2010 (Boyd, 2011, fig. 6). The Desmoinesian granite wash (Mitchell, 2011) and Devonian–Mississippian 

Woodford Shale are preferentially completed as horizontal 

wells. Anadarko is also an old exploration basin, dating back to 

the early 1900s for the still-productive panhandle, Cement, and 

numerous other fields (fig. 6). Historical exploration focus was 

for conventional oil and gas, and exploration is fairly recent for 

continuous (unconventional) accumulations. 

Grouping of stratigraphic units into TPSs and AUs was 

affected by the quality and distribution of well and production 

data in the province. Production from most wells in the basin 

is reported as commingled from multiple units, and reservoir 

strata are sometimes misnamed. This commingling exists for 

small and large fields, and can extend across considerable formation ranges, such as for the Cement field of the deep basin 

in Oklahoma that has produced more than 186 million barrels 

of oil (MMBO) and 1.3 billion cubic feet of gas (BCFG) from 

Silurian through Permian strata (IHS Energy, 2010b). The 

Sooner trend of Oklahoma has yielded more than 334 MMBO, 

2.3 trillion cubic feet of gas (TCFG), and no reported water 

from the Cambrian–Ordovician Arbuckle Group through 

Virgilian rock units (IHS Energy, 2010b). Produced water 

is almost exclusively reported for Colorado and Texas, and 

not for Kansas and Oklahoma. Commingling also influenced 

populating the Nehring and Associates, Inc. (2009) database 

on petroleum fields because of the difficulty in assigning 

production and associated data to rock units. Most Permian 

production in the Kansas portion of the basin is reported in 

the IHS Energy (2010b) database as Permian, as opposed to 

listing the lithostratigraphic unit name(s). As such, data are 

inadequate to assign production to, for example, the Chase or 

Council Grove Groups in the Hugoton and Guymon fields that 

have together produced more than 79 MMBO and 26 TCFG 

from Wolfcampian and Leonardian reservoirs. Figures 6A and 

6B show oil and gas wells for Pennsylvanian through Permian 

production in the province; similar maps are presented for the 

Mississippian AU and other AUs. Although there is extensive 

well coverage, actual produced volumes and locations are 

adversely modified by reporting errors and commingling of 

production from multiple formations. 

Mean undiscovered conventional resources that were 

assessed for Mississippian through Permian strata in the 

Anadarko Basin Province total 77 MMBO, 1,934 BCFG, 

and 60 million barrels of natural gas liquids (MMBNGL) 

(table 1). Oil and gas in the Anadarko Basin were assessed 

in 1995 (Henry and Hester, 1995) with mean undiscovered 

resources of 45.7 MMBO and 604.7 BCFG for their Mississippian through Permian plays (5812 through 5827). Primary 

reasons for the differences between these assessment results 

include: (1) technological advances have increased recovery of 

petroleum from existing fields and from undiscovered accumulations; (2) the increased contribution from unconventional 

(continuous) reserves and resources; and (3) assessment methodology and play/AU boundaries are different for the 1995 

and 2011 assessments. For example, the Las Animas arch and 

Palo Duro Basin were assessed separately in 1995, whereas 

the Las Animas arch and most of the Palo Duro Basin were 

included in the Anadarko Basin Province for 2011. Well history and production data quality, although still variable, have 

improved since the 1995 assessment. 

Application of the TPS assessment methodology 

resulted in mean undiscovered resources for the Mississippian AU of the Woodford Composite TPS of 17 MMBO, 

417 BCFG, and 11 MMBNGL. Mean undiscovered oil and 

gas resources from the 1995 Anadarko Basin assessment 

totaled 14.0 MMBO and 133.2 BCFG for the Henry and 

Hester (1995) Lower Mississippian Stratigraphic Oil and 

Gas, Upper Mississippian Stratigraphic Oil and Gas, and 

Springer Stratigraphic Oil and Gas plays. Mean undiscovered 

resources were 4.4 MMBO and 0 BCFG for the Mississippian Carbonate play in the Las Animas arch (Keighin, 1995). 

Ball and Henry (1995) assessed one play for the Palo Duro 

Basin, the Upper Paleozoic play that included all Mississippian through Permian strata for which mean undiscovered 

resources were 4.9 MMBO and 0 BCFG.

Undiscovered oil resources for the Thirteen Finger 

limestone and Atoka Shale are included with the conventional 

Morrowan-Atokan AU. Mean undiscovered resources for 

the Thirteen Finger Limestone–Atoka Shale Gas continuous AU are assessed separately and are 6.850 TCFG and 

82 MMBNGL. Undiscovered conventional resources for the 

Pennsylvanian Composite TPS include:

a. 15 MMBO, 332 BCFG, and 7 MMBNGL for the Morrowan-Atokan AU; 

b. 6 MMBO, 118 BCFG, and 4 MMBNGL for the Desmoinesian AU;

c. 23 MMBO, 258 BCFG, and 8 MMBNGL for the 

Missourian-Permian AU;

d. 16 MMBO, 809 BCFG, and 30 MMBNGL for the Greater 

Granite Wash Composite AU.
10 Petroleum Systems and Assessment of Undiscovered Oil and Gas in the Anadarko Basin Province

Figure 6. Maps showing A, Oil 

and B, gas wells that produce 

from Pennsylvanian and (or) 

Permian strata in the Anadarko 

Basin Province (IHS Energy, 

2010a, 2010b). Generalized 

field locations are from IHS 

Energy (2010a) and Bebout 

and others (1993). Also shown 

are the Greater Granite Wash 

Composite Assessment Unit (AU) 

and Pennsylvanian Composite 

Total Petroleum System (TPS) 

boundaries. Precambrian faults 

are from Adler and others (1971). 

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0 50 100 KILOMETERS

0 50 100 MILES

104° 103° 102° 101° 100° 99° 98° 97° 40°

39°

38°

37°

36°

35°

34°

TEXAS

OKLAHOMA

KANSAS COLORADO

A

NEW MEXICO

Figure 6. (a). Ch. 7

Panhandle

HugotonGuymon

Cement

Keyes

dome

Postle

Sooner

Trend

WatongaChicasha

Trend

Sorrento

Arapaho

Stevens

Farnsworth

Stewart

Adams 

Ranch Mocane-Laverne

 gas area

Buffalo Wallow

Hansford

Pennsylvanian Comp.TPS

Province 58 

Greater Granite Wash 

 Composite AU

Precambrian fault

Oil well

Gas well

EXPLANATION

0 50 100 KILOMETERS

0 50 100 MILES

104° 103° 102° 101° 100° 99° 98° 97° 40°

39°

38°

37°

36°

35°

34°

TEXAS OKLAHOMA

KANSAS COLORADO

B

NEW MEXICO

Panhandle

HugotonGuymon

Cement

Keyes

dome

Postle

Sooner

Trend

WatongaChicasha

Trend

Sorrento

Arapaho

Stevens

Farnsworth

Stewart

Adams 

Ranch Mocane-Laverne

 gas area

Buffalo Wallow

Hansford
Petroleum Source Rocks and Thermal Maturity 11

Petroleum Source Rocks and Thermal 

Maturity

Petroleum source and potential source rocks in the 

Anadarko Basin include Ordovician through Missourian 

marine shale and limestone (fig. 7). Petroleum source rocks 

and thermal maturation history are discussed more fully in 

Higley (2014). The Woodford Composite TPS encompasses 

Ordovician through Mississippian petroleum source rocks and 

is named for the principal source rock in the province. The 

Pennsylvanian Composite TPS includes all Pennsylvanian 

petroleum source rocks. Primary reasons for this generalized 

TPS division are that (1) geochemical research in the basin 

has been focused on the Woodford Shale, with lesser information on other possible petroleum source rocks, and (2) the 

three source rocks with moderate to good hydrocarbon potential (Burruss and Hatch, 1989, p. 57) are the (a) Ordovician 

Simpson Group shale, (b) Devonian–Mississippian Woodford 

Shale, and (c) Pennsylvanian black shales. Organic-carbon 

values for thick shales in the Springer and Morrow Formations range from 0.5 to 3.4 percent; kerogen is Type III, 

indicating that it is mostly gas prone (Rice and others, 1989). 

Atokan, Desmoinesian, and Virgilian petroleum source rocks 

are mainly Types II and III kerogen (Rice and others, 1989). 

Figure 2 displays the Morrow as Morrow Group in western Kansas, and as Morrow Formation in the northern and 

southern Anadarko Basin; it is referred to as Morrow Formation in this report. The Atoka interval has group status in the 

Hugoton embayment and northern Anadarko Basin, and is the 

Atoka Shale and Pumpkin Creek Limestone of the Dornick 

Hills Group in the deep basin (fig. 2). It will be called Atoka 

Group in this chapter of the report. Discussions of Atoka 

shale refer to included shale intervals.

The three highlighted zones in figure 7 correspond to 

assigned hydrocarbon source rocks in the 4D petroleum 

system model. These generalized source intervals were 

chosen and based partly on the Burruss and Hatch (1989) 

determination of three oil types in the Anadarko Basin; their 

analyzed crude oils appeared to correlate with extracts from 

Ordovician, Devonian, and Pennsylvanian source rocks. The 

Atokan Thirteen Finger limestone was chosen to represent 

the Pennsylvanian hydrocarbon source rocks because the 

thickness and extent of this high gamma interval across the 

province. Morrowan black shales compose as much as 60 percent of the Morrow Formation in the Oklahoma portion of the 

province (Wang and Philp, 1997), but it would have been more 

difficult to define and map a specific petroleum source interval 

within the Morrow Formation across the basin. 

Timing of generation, migration, and accumulation of 

oil and gas are derived from the Higley (2014) petroleum 

system models (fig. 8, table 2). Schlumberger (2011) PetroMod® software was used for 1D and 4D petroleum system 

models. Within the Ordovician Simpson Group Oil Creek, 

Devonian-Mississippian Woodford, and Atokan Thirteen 

Finger petroleum source rocks in the 4D model, the Oil Creek 

Formation primarily sources Cambrian through Ordovician 

petroleum accumulations, the Woodford Shale is the major 

source for Devonian, Mississippian, and lower Morrowan 

accumulations, and the Thirteen Finger limestone is the main 

source for middle Morrowan through Permian accumulations (Higley, 2014). As is shown in figure 7, numerous other 

petroleum source rocks across the basin are potential contributors to reservoirs. The 4D petroleum system model consists of 

stacked grids of lithostratigraphic units that are referred to as 

layers. Each layer extends across the study area, a requirement 

of the PetroMod® software. This means that underlying layers 

are displayed if the modeled unit(s) has limited lateral extent. 

Model construction is discussed in Higley (2014) and Higley 

and others (2014b). Figure 8 shows modeled vitrinite reflectance (Ro

) and transformation ratio (TR) 3D images at present 

day for the Woodford through Douglas model layers that 

contain the source rocks that contributed oil and gas for Mississippian through Permian reservoirs. The TR maps record 

the beginning to the end of oil generation based on hydrous 

pyrolysis (HP) kinetics, and the Ro images show assigned 

Table 2. Oil generation onset for the Anadarko Basin 4D model, and onset and completion dates in 

millions of years before the present (Ma) for the Bertha Rogers 1 and Petree Ranch 1 1D models based 

on Woodford Shale hydrous pyrolysis (HP) kinetics (Lewan and Ruble, 2002). The Douglas Group overlies 

the youngest potential petroleum source rocks in figure 7. The HP kinetics-based onset of oil generation 

is 0.1 percent transformation ratio (TR) and completion is 99 percent TR. Oil generation histories in the 4D 

model were recorded at 10-Ma increments; so the plus symbol indicates onset was before the listed age.

Four Dimensional Model Bertha Rogers 1 Petree Ranch 1

Onset Onset End Onset End

Virgilian (Douglas Group) 270 100

Thirteen Finger limestone 300 290 265 270

Woodford Shale 330 330 310 290 200

Oil Creek Formation 370 340 320
12 Petroleum Systems and Assessment of Undiscovered Oil and Gas in the Anadarko Basin Province

Figure 7. Generalized stratigraphic column for the Anadarko Basin Province, with hydrocarbon source rocks highlighted (brown text). 

Increases in source rock potential are indicated by larger numbers. The expected hydrocarbons column heading indicate whether the 

source rock is more oil or gas prone. Blue highlights source intervals used in the four-dimensional petroleum system model. Vertical 

lines show a generalized time range of unconformity from Bebout and others (1993, fig. 5). Chart is from J. Hatch (oral commun., 2010, 

and modified from Burruss and Hatch (1989). Gp., Group; Fm., Formation.

Sumner Gp; Enid Gp.; Hennessey Gp.

System

Series Lithostratigraphic Unit

(HC Source Rocks in Red)

Expected

Hydrocarbons

Relative HC

Source Rock

Potential (1-5)

Permian (part) Pennsylvanian Mississippian Devonian Silurian Ordovician Cambrian (part)

Leonardian

Wolfcampian

Virgilian

Missourian

Desmoinesian

Atokan

Morrowan

Chesterian

Meramecian

Osagean

Kinderhookian

Chautauquan

Cayugan

Cincinnatian

Trempealeauan

Niagaran

Canadian

Champlainian

Chase Group

Council Grove Group

Admire Group

Lansing Group

Kansas City Group 

Marmaton Group

Cherokee Group

Atoka Gp.; Thirteen Finger limestone 

Morrow Gp./Fm.; lower Dornick Hills Gp.

Springer Formation

Chester Group 

Wabaunsee Group

Shawnee Group

Douglas Group

Ada Group

Franconian

Woodford Shale, Chattanooga Shale

Misener sand

Hunton Group

Sylvan Shale; Maquoketa Shale 

Simpson Group

Arbuckle Group

Reagan Sandstone

Alexandrian

Senecan

Pontotoc Group

Viola Group/Formation

Meramec lime

Osage lime

Mayes Group

Hoxbar Group

Deese Group

??

2

5 +

2

?

Kinderhook Shale

Erian

Ulsterian

1-2

1-2

1-2

2-3

1-2

1-2

Gas

Gas Oil

Gas Oil

Oil

Oil

Gas

Gas

Oil

Gas Oil

Gas Oil

Gas Oil

Gas Oil
Figure 8. Images showing present-day thermal maturation of Woodford to Douglas model layers using Woodford HP transformation ratio (% TR) kinetics (Lewan and Ruble, 2002) and vitrinite reflectance (% Ro) (Sweeney and Burnham, 1990). Each layer extends across the study area, including units located outside of the petroleum source rocks. As an example, the Kansas portion of the Springer and Thirteen Finger layers are almost identical because these units are absent over much of this area and the thermal maturity reflects that of the underlying mostly Viola and Simpson Groups strata. The vitrinite reflectance contours in equivalent layers in chapter 3 (fig. 26) are limited to the extent of those strata, and also exhibit slightly different thermal maturation patterns, which largely represents a somewhat newer version of the model. Changes in thermal maturity on the shelf areas of Kansas and Colorado are also minor because of shallow burial relative to the deep basin of Oklahoma and Texas; source rocks are mostly immature for oil generation at less than 0.6% Ro. Thermal maturity for source rocks in the deep basin of Oklahoma and Texas ranges from mature for oil generation, to overmature for gas generation at about 4% Ro and greater. Red contour lines on the Ro images mark the 99 percent transformation ratio that is approximately equivalent to 1.2% Ro. Precambrian faults (Adler and others, 1971) are shown as blue lines.

Springer

COLORADO

OKLAHOMATEXAS

KANSAS

Douglas

Douglas

Thirteen Finger

Woodford Springer Thirteen Finger

EX

 % 

0.40.50.60.70.80.91.02.03.04.05.0

0 50 100 MILES

0 50 100 KILOMETERS

Woodford

103o 102o 101o 100o 99o 98o

38o

37o36o35o
14 Petroleum Systems and Assessment of Undiscovered Oil and Gas in the Anadarko Basin Province

levels of maturation based on Sweeney and Burnham (1990) 

algorithms. The respective Ro and TR values in figure 8 are not 

identical, but the good agreement of levels of thermal maturation is largely because of calibrating the model to available 

downhole temperature and thermal maturation data. Primary 

conclusions from the images are (1) thermal maturity of 

Oklahoma and Texas ranges from immature for oil generation 

to overmature for gas generation, although production of gas 

from the deep basin indicates all or most of the area is within 

the limit of gas preservation; (2) the Colorado and Kansas 

portions of the province are almost exclusively immature to 

marginally mature for oil generation. Elevated thermal maturation in Colorado is associated with elevated basement heat 

flow (Higley, 2014); (3) the Douglas layer represents lower 

Virgilian strata, that are younger than the petroleum source 

rocks in figure 7, but if this layer contains source rocks in the 

deep basin they would mainly be immature to mature for oil 

generation; and (4) the primary factor that controls the degree 

of thermal maturation is depth of burial, which is mainly why 

the Woodford Shale is mature for oil and gas generation over a 

larger area than shallower units.

Reservoir Rocks

Mississippian Assessment Unit

A broad epicontinental sea extended across most of the 

southern Midcontinent from Late Cambrian through Mississippian time (Johnson and others, 1988). The Anadarko 

Basin Province area was a broad embayment that received a 

thick sequence of carbonates interbedded with thinner shales 

and sandstones (Johnson, 1989). Mississippian strata in the 

province are mainly limestones, cherty limestones, and shales 

that were deposited in shallow-marine environments (Craig 

and others, 1979; Frezon and Jordan, 1979; Mapel and others, 

1979; Johnson and others, 1988). Thickness of the Mississippian is greatest in the deep basin of Oklahoma and Texas, 

where the Chesterian section can exceed 5,000 ft in thickness, 

and pre-Chesterian Mississippian rocks can be more than 

2,000 ft thick (Adler and others, 1971). Craig and Connor 

(1979) indicated the total thickness of the Mississippian 

section along the northern shelf is about 1,000-2,000 ft. The 

Mississippian isopach (fig. 9) exhibits southeastward thickening from the Kansas and Colorado shelf to the deep basin. The 

irregular contours partly represent variations that resulted from 

subtracting the Mississippian and Woodford structure grids 

(layers) and (or) areas of poor data control.

Erosion of Springer Formation strata (fig. 2) over the 

Nemaha uplift resulted from pre-Pennsylvanian orogenic uplift 

(Johnson, 1989). The crest of the uplift has Precambrian and 

pre-Pennsylvanian rocks unconformably overlain by Desmoinesian and Missourian strata (Rascoe and Adler, 1983). Perry 

(1989) indicated that initial evidence of late Paleozoic tectonism is the abrupt pinchout of Springer strata in the adjacent 

western Ardmore Basin. This epeirogenic event caused gentle, 

widespread uplift and erosion over the Midcontinent; Mississippian and older Paleozoic rocks were eroded from the Cambridge arch, north of the province, and parts of the CKU, and 

from shelf areas bordering the Anadarko Basin and Arkoma 

Basin, to the east (Rascoe and Adler, 1983). 

The angular unconformity that resulted from the Late 

Mississippian epeirogeny, separates Mississippian carbonate strata from the overlying Morrow Formation (Bowen and 

Weimer, 2003), except in the deep part of the basin where 

they conformably overlie lithologically similar Springer strata 

(Johnson, 1989). Because of the lithologic similarities, it can 

be difficult to determine the Springer-Morrow contact in the 

basin (Johnson, 1989). Keighin and Flores (1989) identified 

three depositional facies for the Springer and Morrow Formations that include (1) fluvial-influenced coastal (FIC), (2) tidalinfluenced nearshore (TINS), and (3) mixed tidal and non-tidal 

marine influence (MT/NTM). 

The Mississippian AU extends across the province, with 

petroleum production from Kinderhookian through Chesterian 

strata. Reservoir rocks are mostly Lower Mississippian carbonates through Upper Mississippian sandstones and carbonates. Mississippian oil and gas wells are shown in figure 10. 

Springer Formation oil and gas are produced from thrust 

fault-bounded blocks on the northern flank of the Wichita 

Mountain uplift (Alder and others, 1971). Potential resources 

on the uplift should be predominantly oil because of shallower burial than the adjacent Anadarko Basin. There is also 

scattered petroleum production on and parallel to the Nemaha 

uplift. Horizontal drilling in Mississippian strata includes oil 

and gas wells (IHS Energy, 2012). Sixty percent of the 276 

horizontal wells in the province were completed after 2010; 

these are scattered within existing fields and also include 

lightly explored areas close to the eastern Kansas/Oklahoma 

border in the province (fig. 10A). Horizontal wells completed 

in 2010 or later were not incorporated into the Higley and 

others (2011) assessment of undiscovered resources in the 

province; this is about 80 percent of the wells. Mississippian 

cumulative production across the basin is mainly oil with more 

than 1.16 BBO, 15.9 TCFG, and 277 million barrels of water 

(MMBW) from more than 29,000 leases in 2,357 fields (IHS 

Energy, 2010a, 2010b). Water production was reported only 

for Colorado and Texas. Exploration and development started 

early for Mississippian reservoirs (fig. 11). The earliest exploration for petroleum in the basin was the Cement field in 1917 

(fig. 6), a faulted anticline in the deep basin that has produced 

oil and gas from Cambrian through Permian reservoirs (Davis 

and Northcutt, 1989). Exploration and development increased 

in the late 1950s with a continuing upward trend.

Discovery-thirds plots show the distribution of first, 

second, and third thirds of completion dates for Mississippian oil and gas fields. The division into thirds is based on 

early field discoveries frequently being the largest oil and gas 

accumulations, with later field sizes being smaller. Discovery 

thirds is also based on mathematically grown, as opposed to 

known, sizes of accumulations. This is incorporated because 

initial reserves of conventional accumulations are commonly 
Reservoir Rocks 15

Figure 9. Isopach map of Mississippian to Woodford petroleum system model layers, 

which approximates the thickness of Mississippian rocks across the study area. Blank areas 

indicate missing strata or insufficient data. Extent of the Woodford Shale is approximated by 

the Woodford Shale Oil AU boundary in figure 1. Irregular contours are mainly because of 

subtraction of these unfiltered (unsmoothed) layer grids. Precambrian faults (green lines) are 

from Adler and others (1971).

Figure 9. Ch. 7 

EXPLANATION

Thickness,

in feet 

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

103° 102° 101° 100° 99° 98° 97°

39°

38°

37°

36°

35°

0 50 100 MILES

0 50 100 KILOMETERS

COLORADO KANSAS

NEW MEXICO

OKLAHOMA

TEXAS
16 Petroleum Systems and Assessment of Undiscovered Oil and Gas in the Anadarko Basin Province

Figure 10. Maps showing A, Oil 

and B, gas wells that produce 

from the Mississippian AU in the 

Anadarko Basin Province (IHS 

Energy, 2010b). Also shown in 

figure 10A are 276 horizontal wells 

drilled into Mississippian strata; 

166 of these were completed after 

2010 (IHS Energy, 2012). 

0 50 100 KILOMETERS

0 50 100 MILES

TEXAS

KANSAS

COLORADO

NEW MEXICO

OKLAHOMA

104° 103° 102° 101° 100° 99° 98° 97° 40°

39°

38°

37°

36°

35°

34°

Figure 10. (a) cH. 7 

505801 TPS

Province 58 

Mississippian AU

Precambrian fault

Oil well

Gas well

EXPLANATION

A

Horizontal well

0 50 100 KILOMETERS

0 50 100 MILES

TEXAS

KANSAS

COLORADO

NEW MEXICO OKLAHOMA

104° 103° 102° 101° 100° 99° 98° 97° 40°

39°

38°

37°

36°

35°

34°

B
Reservoir Rocks 17

Figure 11. Cumulative number of producing wells by year for the 

Mississippian AU (IHS Energy, 2010a, 2010b). Some of the wells 

include production from units other than Mississippian. Onset of 

production from this AU for several major fields is also shown. 

Locations are in figure 6.

0

5,000

10,000

15,000

20,000

25,000

1916 1925 1934 1943 1952 1961 1970 1979 1988 1997 2006

First reported production (year)

Producing wells

Sooner Trend

Watonga-Chickasha Trend

Cement

Figure 11. Ch. 7

1

10

100

1,000

0 5 10 15 20

Gas-accumulation rank by size

Grown gas-accumulation size (BCFG)

0

1

10

100

0 5 10 15 20 25

Oil-accumulation rank by size

Grown oil-accumulation size (M

MBO)

First third of accumulations discovered

Second third of accumulations discovered

Third third of accumulations discovered

EXPLANATION

Figure 12. Grown gas and oil accumulation sizes for discovery thirds of the Mississippian Assessment Unit of the Woodford 

Composite Total Petroleum System. Although this is a mature assessment unit, the oil accumulations only show a minor drop for the 

third of discoveries, and the gas accumulation history is stable. Data are from the Nehring and Associates, Inc. (2009) field database, 

which has limited information for the Mississippian fields. MMBO, million barrels of oil; BCFG, billion cubic feet of gas.

underestimated. The development success of an AU is measured by sizes of accumulations through time. The Mississippian AU discovery thirds oil and gas production plots show 

that, even with the mature status of exploration, that the latest 

discoveries exhibit similar grown accumulation sizes to the 

early and middle discoveries (fig. 12). This indicates that the 

AU has continuing potential for resources, even considering its 

fairly mature exploration status. The discovery trends also continue from the smallest to the largest accumulations. Discovery 

thirds for oil and gas accumulations (fig. 12) (Nehring and 

Associates, Inc., 2009) only show a few of the fields that produce from Mississippian units. Shown fields should produce 

oil and gas almost exclusively from the Mississippian, with 

lesser reported commingled production from other units.

Trapping mechanisms for the AU are structural, stratigraphic, and a combination of the two. Structural traps are 

evidenced by the linear trends of some of the oil and gas 

production in the deep basin, proximal to the greatest thickness 

of Mississippian strata. This is also the area that is overmature for oil generation, but is within the gas generation and 

preservation windows (Higley, 2014). Probable Mississippian 

petroleum source rocks include strata within the informal 

Osage lime and Springer Formation (fig. 7). Organic-carbon 

values for thick shales in the Mississippian Springer and 

Pennsylvanian Morrowan producing intervals range from 0.5 

to 3.4 wt %; however, the kerogen is mostly Type III indicating that it is primarily gas-prone (Hatch and others, 1986; 

Rice and others, 1989) (fig. 2). Mississippian oil generally 
18 Petroleum Systems and Assessment of Undiscovered Oil and Gas in the Anadarko Basin Province

Figure 13. Petroleum system events chart for the 

Mississippian Assessment Unit of the Woodford 

Composite Total Petroleum System. Timing of oil and 

gas generation, migration, and accumulation is based 

primarily on Higley (2014) petroleum system models. 

Potential petroleum source rocks (fig. 7; Hatch and 

others, 1986) are light gray rectangles. Primary 

petroleum source rock for the Mississippian AU is 

the Woodford Shale (Rice and others, 1988a, 1988b; 

Higley, 2014). The informal Osage lime and Springer 

Formation are potential petroleum sources for the AU. 

Times of peak generation from the Oil Creek Formation 

(blue), Woodford Shale (green) and Thirteen Finger 

limestone (tan) source rocks are within blue shaded 

rectangles. Paleogene trap formation, migration, and 

accumulation are based on Laramide generation and 

potential remigration associated with erosion and 

basin tilting. Unconformities, wavy and horizontal 

lines; lst, limestone; sh., shale; Fm., Formation; Plio, 

Pliocene; Mio, Miocene; Eoc, Eocene; Pal, Paleocene; 

L, Late; M, Middle; E, Early. 

Oil Creek  Fm

Figure 13. Ch. 7 

Woodford Shale Mississippian lst, sh.

Mississippian limestone, sandstone

interbedded and overlying shales

Pal

Eoc

Olig

Mio

0

100

200

300

400

50

150

250

350

Paleogene

Cretaceous

Jurassic

Triassic

Permian

65.5

146

200

251

359

416

Silurian

Devonian

299

318

E

E

E

E

E

E

E

E

M

M

M

M

L

L

L

L

L

L

L

L

Mississipian

Pennsylvanian

Neogene

23

Plio

UnconformitiesSource rockReservoir rockSeal rockOverburden rock

Trap formationGeneration

Petroleum

system events

Geologic 

time

scale

Migration, accumulation

Ordovician

Cambrian

542

488

444 450

500

550

Kansas, Colorado

Precambrian

stratigraphic, structural traps

correlates with extracts of the Woodford Shale (Rice and others, 1988a, 1988b). The underlying Woodford Shale is also the 

predominant petroleum source rock for the Mississippian AU 

based on petroleum system modeling (Higley, 2014). Associated gases from Silurian, Devonian, and Mississippian carbonates from the Sooner trend were from depths as great as 9,678 

ft (2,950 m) and were generated from Type II kerogen; gases 

are isotopically lighter (mean δ13C1 value is -43.9 percent) and 

chemically wetter (mean C2+ value is 14 percent) than those 

derived from Type III kerogen at equivalent levels of thermal 

maturity (Rice and others, 1988a, 1988b). The petroleum system events chart for the Mississippian AU (fig. 13) shows time 

periods of source, reservoir, seal, and overburden strata, and 

trap formation. Timing of generation, migration, and accumulation of oil and gas are derived from Higley (2014) petroleum 

system models (fig. 14, table 2).
Reservoir Rocks 19

Figure 14. History of petroleum generation from the Oil Creek Formation, Woodford Shale, and informal 

Thirteen Finger limestone source layers in the four-dimensional (4D) petroleum system model. History is 

based on Woodford hydrous pyrolysis kinetics (Lewan and Ruble, 2002). Gray bars delineate periods of peak 

generation. Early oil generation from the Oil Creek layer, prior to about 370 million years ago, is in a narrow 

band that is proximal to the Wichita Mountain uplift. This band exceeds maximum depth of the formation and is 

because of areas of poor data control in the area bordering the fault zone. The error could have been removed 

by clipping the 4D model extent to the basin axis and northward, but less of the model would have been visible 

and usable.

400 350 300 250 200 150 100 50 0

Generation history, million years before present

Figure 14. Ch. 7 

Onset Completion

Laramide orogeny

Wichita orogeny

Oil Creek 

Woodford 

Thirteen Finger

EXPLANATION

Morrowan-Atokan Assessment Unit

The boundary of the Pennsylvanian Composite TPS 

(505802) and contained Morrowan-Atokan AU (50580201) 

are shown in figure 1. The AU approximates the extent of 

the contained assessed Morrow Formation and Atoka Group 

(fig. 2). The Colorado portion is limited by TPS and AU 

boundaries of the adjacent Denver Basin Province, for which 

Paleozoic AUs were assessed in 2002 (Higley and Cox, 2007; 

Higley and others, 2007). 

By Early Pennsylvanian, as much as 10,000 ft (3,050 m) 

of Springer-Morrow and Atoka sediments were deposited 

in the basin (Rascoe and Adler, 1983; Al-Shaieb and others, 

1994). The Morrow and Atoka Groups are each as much as 

4,000 ft thick in the deep Anadarko Basin, thinning northward 

onto the shelf (Adler and others, 1971; Johnson, 1989). By the 

end of Permian time, more than 20,000 ft of Pennsylvanian 

and Permian sediments were deposited in the deep Anadarko 

Basin (Jorgensen, 1989). Morrowan and Atokan strata were 

deposited on a broad low-relief shelf in Colorado and Kansas, and a subsiding deep basin in the Oklahoma and Texas 

portions of the province (figs. 3 and 15). The approximate 

Atokan onset of the Cimarron arch (fig. 5) is characterized by 

Morrowan rocks unconformably overlain on the crest by lower 

Desmoinesian strata (Rascoe and Adler, 1983). Lower Morrow 

strata pinch out along the flanks of the arch, but deposition 

of overlying Morrow sediments was associated with marine 

influx (Abels, 1959). 

Morrow Formation and Atoka Group reservoirs are 

mostly marine and nonmarine sandstone and calcareous 

sandstone, with lesser limestone beds. Morrow Formation 

sediment supply was from the Sierra Grande uplift, Ancestral 

Rocky Mountains, Nebraska, and CKU (Swanson, 1979). 

The lower Morrow Formation consists of shallow-marine 

shales, sandstones, and limestones that were deposited under 

transgressive conditions and onlap the eroded Mississippian 
20 Petroleum Systems and Assessment of Undiscovered Oil and Gas in the Anadarko Basin Province

Figure 15. Map showing elevation on the top 

of the Atoka model layer. Extent of Morrowan 

and Atokan strata within the Pennsylvanian 

(Penn.) Composite Total Petroleum System 

(TPS) is approximated by the Morrowan-Atokan 

Assessment Unit (AU) boundary and in figure 3 

elevation of the basal Thirteen Finger limestone. 

Elevation is relative to sea level. Precambrian 

faults are from Adler and others (1971).

103° 102° 101° 100° 99° 98° 97°

39°

38°

37°

36°

35°

Figure 15. Ch. 7 

4,000

2,000

0

-2,000

-4,000

-6,000

-8,000

-10,000

-12,000

-14,000

EXPLANATION

Elevation, in feet

COLORADO KANSAS

TEXAS

NEW MEXICO

OKLAHOMA

0 50 100 KILOMETERS

0 25 50 75 100 MILES

Pennsylvanian Composite 

 Total Petroleum System

Morrowan-Atokan

 assessment unit

Precambrian fault

EXPLANATION

rocks toward the north and northeast (Johnson, 1979). Upper 

Morrow strata in the western part of the basin were primarily a 

deltaic sequence that prograded toward the southeast, resulting 

in deposition of mainly shales with lenticular, discontinuous 

sandstones, minor conglomerates, and thin coals and limestones (Swanson, 1979). Abels (1959) identified thin coal beds 

in the upper third of the Morrow Formation in the panhandle 

area of Texas and Oklahoma, and in southwestern Kansas. 

This area is mainly thermally immature for oil generation, so 

it is unlikely that the coals would have provided thermogenic 

natural gas. 

The Morrowan on the shelf is characterized by marine 

to fluvial “clean, relatively well-sorted, non-glauconitic, and 

non-calcareous sandstone” (Adams, 1964), and the Hugoton 

field, Panhandle field, and Las Animas areas are mainly fluvial 

and shoreline sandstone reservoirs (Al-Shaieb and Walker, 

1986). Bowen and Weimer (2003) described a compound 

incised-valley fill in western Kansas and eastern Colorado that 

contains three facies tracts with unique reservoir characteristics: (1) an updip facies tract of predominantly amalgamated 

fluvial channel sandstones overlies (2) a transitional facies 

tract of fluvial channel sandstones and interbedded finergrained estuarine sandstones, and (3) a downdip facies tract 

of fluvial channel sandstones isolated in estuarine shale. Traps 

in their study are combination, structural, and stratigraphic; 

the structural component is where valley-fill deposits cross 

anticlines, or the trend of the valley-fill deposits bends against 

structural strike. Reservoir compartmentalization can result 

from erosional truncation and subsequent deposition of strata, 

and lateral facies change from shale to sandstone in these elongate accumulations.

Morrowan strata in the deep basin were deposited in lowenergy environments and consist primarily of argillaceous, 

poorly sorted, glauconitic, calcareous sandstone (Rascoe and 

Adler, 1983). The lower permeability and depth of the deepbasin sandstones are associated with decreased exploration 

and development. These strata are also overpressured with gradients that exceed the normal 0.465 psi/ft gradient as part of 

the sealed megacompartment complex of Al-Shaieb and others 

(1994). Morrowan and Atokan intervals exhibit approximately 

normal pressure on the shelf. 

Atokan strata consist of a series of southward-thickening 

marine shales, sandstones, and limestones that are about 

50–200 ft thick in the northern and western parts of the 

Anadarko Basin (Johnson, 1989). Atokan strata tend to grade 

laterally into granite wash lithofacies close to the Wichita 

Mountain uplift, making well-log picks more difficult. The 

Morrow Formation is disconformably to gradationally overlain by Atokan Thirteen Finger limestone. Morrow and Atoka 

reservoir seals are primarily overlying and interbedded shales 
Reservoir Rocks 21

that help create the primarily stratigraphic traps in the province. Morrow Formation sandstones account for most of the 

pre-Permian oil and gas production in the basin (Davis and 

Northcutt, 1989). Morrowan plus Atokan production from 

almost 20,000 leases in 1,461 fields in the AU is approximately 850 MMBO, 26.08 TCFG, and 418.39 MMBW (IHS 

Energy, 2010a, 2010b). 

Almost all reported water production in the province 

is from Colorado and Texas. Average production per well 

was about 51.8 thousand barrels of water (16,273 wells) and 

1.5 BCFG (18,491 wells); average gas-oil ratio (GOR) for 

12,865 wells is 3,530 MCFG/BO (IHS Energy, 2010a, 2010b). 

Morrow Formation reservoirs in western Kansas and eastern 

Colorado are largely valley-fill sequences that developed 

when extensive river systems incised the exposed marine 

shelf during relative lowstands, and have produced more than 

100 MMBO and 500 BCFG (Bowen and Weimer, 2003). 

Best quality reservoirs are medium- to coarse-grained fluvial 

sandstones with porosities ranging from 18 to 28 percent and 

permeabilities of 0.5 to 2.0 Darcy; overlying estuarine reservoirs contain 8 to 18 percent porosity and 10 to 500 millidarcies (mD) permeability (Bowen and Weimer, 2003). An area 

that also includes the Oklahoma Panhandle and northern Texas 

produced more than 200 MMBO and 8 TCFG from updip fluvial to deep-water marine strata (Bowen and Weimer, 2004). 

Production from the Atoka Group (including the Thirteen 

Finger limestone) is 27 MMBO and 1.7 TCFG (IHS Energy, 

2010a, 2010b). 

Cumulative production numbers are approximate for the 

Morrow and Atoka, as well as most other reservoirs in the 

basin, because of extensive use of multiple completions and 

reporting of commingled production for multiple units. The 

first Morrow discovery was from Keyes dome (fig. 6) in 1943, 

which produced 1.7 MMBO and 500 BCFG through 1985 

from the lower Morrow Formation Keyes sand (fig. 2) (Davis 

and Northcutt, 1989; Oklahoma Geological Survey (OGS) 

2011a, fields discovery wells database (FDW). The WatongaChickasha trend (figs. 6 and 17), discovered in 1960 in Blaine 

County, Oklahoma, includes reservoirs of Atokan, Morrowan, 

and Springer age; production through 1985 was 44 MMBO 

and 1.8 TCFG from sandstones in varied trap types (Davis and 

Northcutt, 1989). Since about 1955 trends in drilling and production have been relatively stable, even with the fairly extensive exploration and development of this AU. The discovery 

thirds of oil and gas fields are shown in figure 18. Discoveries 

in 1969 through 1978 of the (second thirds) Buffalo Wallow, 

Stiles Ranch, Allison-Parks, and Briscoe fields increased the 

associated discovery rate for 200 BCFG discoveries.

The petroleum system events chart for the MorrowanAtokan AU (fig. 19) shows time periods of petroleum source, 

reservoir, seal, and overburden strata, and trapping. Timing 

of generation, migration, and accumulation of oil and gas 

are derived from Higley (2014) petroleum system models 

(table 2). Onset of oil generation from potential Morrowan 

source rocks (fig. 7) would be slightly older than the 300-Ma 

age of the Thirteen Finger limestone on table 2.

Thirteen Finger Limestone–Atoka Shale Gas 

Assessment Unit

This is a continuous gas AU. Its boundary was determined based on the areal extent of the informally named 

Thirteen Finger limestone and overlying Atoka shale (fig. 2) of 

the Atoka Group (fig. 20), combined with the area that is thermally mature for gas generation based on petroleum system 

modeling by (fig. 20). Estimated oil resources for the Thirteen 

Finger limestone and Atoka shale were included as part of the 

Morrowan-Atokan AU assessment. Thirteen Finger limestone 

thickness contours that are outside the limits of the MorrowanAtokan AU shown in figure 20 are extrapolated outside areas 

of data control. Top, base, and extent of the Thirteen Finger 

limestone are based mainly on examination of 125 wells 

across the basin. Elevation on the top of the unit ranges from 

about -4,000 ft on the shelf areas of Colorado and Kansas to 

-17,000 ft in the deep basin area of Oklahoma and Texas (fig. 

3). Average thickness is 95 ft, and the greatest thickness is in 

the deep basin and trending northwest toward Colorado (fig. 

20). Also shown in figure 20 are locations of figure 21 cross 

sections. 

The Thirteen Finger limestone across the Anadarko Basin 

Province comprises 75 to 100 ft (23 to 30 m) of cyclical thin 

marine limestones and shales (Rascoe and Adler, 1983). The 

“fingers” name is because of its stacked thin shale and carbonate beds with irregular high gamma kicks of 140 American 

Petroleum Institute (API) and greater on well logs over most 

of its extent (fig. 21). The Carr and Hentz (2009) described the 

unit as fissile, organic-rich shale interbedded with fossiliferous 

wackestones that represent a third-order transgressive systems 

tract; the thickest, most organic-rich shale in the Atoka, at the 

top of the unit, is inferred to represent a third-order marine 

condensed section. They indicated that a third-order highstand 

systems tract downlaps this condensed section and contains 

several progradational parasequences that are capped by “conventional” Atoka limestone and dolomite reservoirs. The thin 

carbonate beds in the basal Atokan Thirteen Finger limestone 

(fig. 2) are potential reservoirs that are overlain by Atoka 

Formation shales. The basal Atoka shales that exhibit gamma 

signatures of greater than 140 API in well logs in areas of the 

basin, suggest elevated levels of organic matter (fig. 21). 

The Thirteen Finger limestone can be correlated across 

the extent of the underlying Morrow Formation in the province, except where proximal to the Wichita Mountain uplift. 

This is primarily the result of tilting of strata and increased 

contribution of clastic sediments relative to that of organic 

matter. Gamma response in wells in cross section B–B’ are 

more pronounced than those in A–A’, which suggests less 

organic matter in the deep basin. Source rocks in A–A’ are 

thermally mature for oil and (or) gas generation, which would 

deplete the TOC and HI values. Gamma response of the overlying Atoka Group is unremarkable in the A–A’ cross section 

but the B–B’ response is similar to that of the Thirteen Finger 

limestone. The Atoka Group source interval differs in that it is 

primarily shale, rather than thin limestone and shale beds. 
22 Petroleum Systems and Assessment of Undiscovered Oil and Gas in the Anadarko Basin Province

Figure 16. Maps showing A, Oil 

and B, gas wells that produce 

from Morrowan and Atokan 

reservoirs in the Anadarko Basin 

Province (IHS Energy, 2010a). The 

assessment unit (AU) boundary 

approximates the extent of 

Morrowan and Atokan strata. 

Precambrian faults are from Adler 

and others (1971). TPS, Total 

Petroleum System.

COLORADO

Figure 16. (a)

0 50 100 KILOMETERS

0 50 100 MILES

104° 103° 102° 101° 100° 99° 98° 97° 40°

39°

38°

37°

36°

35°

34°

TEXAS

OKLAHOMA

KANSAS

NEW

MEXICO

A

505802 TPS

Province 58 

Morrowan-Atokan AU

Precambrian fault

Oil well

Gas well

EXPLANATION

0 50 100 KILOMETERS

0 50 100 MILES

104° 103° 102° 101° 100° 99° 98° 97° 40°

39°

38°

37°

36°

35°

34°

B

COLORADO

TEXAS

OKLAHOMA

KANSAS

NEW

MEXICO
Reservoir Rocks 23

0

5,000

10,000

15,000

20,000

25,000

1930 1940 1950 1960 1970 1980 1990 2000 2010

Year of first production by lease

Cumulative number of leases

Sorrento, Arapahoe

Stewart

Stevens

Hugoton-Guymon, Hansford

Adams Ranch, Farnsworth

Buffalo Wallow

Postle, Watonga-Chicasha

Figure 17. Ch. 7

Figure 17. Cumulative number of wells by year that produce from 

the Morrowan and Atokan (IHS Energy, 2010a, 2010b). Several major 

fields are also shown by year of discovery; all are shown in figure 6.

Figure 18. Discovery thirds of grown oil and gas accumulations for the Morrowan-Atokan Assessment Unit (AU) of the Pennsylvanian 

Composite Total Petroleum System (TPS). This is a mature AU, which is reflected by the generally larger field sizes early in the 

exploration history (first third) relative to later discoveries (second and third thirds). All thirds show similar trends in field sizes through 

time. Gas accumulation history is stable for fields less than 10 billion cubic feet of gas (BCFG), but exhibits progressive decline for fields 

greater than this. Data were constructed using the Nehring and Associates, Inc. (2009) field database, which has limited information 

for the Morrowan and Atokan fields. The database contains more information on Morrowan and Atokan gas fields than oil fields, as 

indicated by the data density on the plots. MMBO, million barrels of oil.

10,000

1,000

100

10

1

Oil-accumulation rank by size Gas-accumulation rank by size

Grown oil-accumulation size (MMBO)

Grown gas-accumulation size (BCFG)

0 0

100

10

1

0

5 10 15 20 25 20 40 60 80 100

First third of accumulations discovered

Second third of accumulations discovered

Third third of accumulations discovered

EXPLANATION
24 Petroleum Systems and Assessment of Undiscovered Oil and Gas in the Anadarko Basin Province

Figure 19. Petroleum system events chart for the 

Morrowan-Atokan AU of the Pennsylvanian Composite 

TPS. Woodford Shale (green) and Thirteen Finger 

limestone (tan) ranges of oil and gas generation, 

migration, and accumulation are based primarily on 

the petroleum system models. Potential petroleum 

source rocks from Hatch and others (1986) are light 

gray. Time ranges of peak generation (fig. 14) are within 

blue rectangles. Paleogene trap formation, migration, 

and accumulation are based on Laramide generation 

and potential remigration associated with basin 

tilting. Unconformities, wavy and horizontal lines; lst, 

limestone; sh., shale; Fm., Formation; Plio, Pliocene; 

Mio, Miocene; Eoc, Eocene; Pal, Paleocene; L, Late; M, 

Middle; E, Early.

Figure 19. Ch. 7

Pal

Eoc

Olig

Mio

0

100

200

300

400

50

150

250

350

Paleogene

Cretaceous

Jurassic

Triassic

Permian

65.5

146

200

251

359

416

Silurian

Devonian

299

318

E

E

E

E

E

E

E

E

M

M

M

M

L

L

L

L

L

L

L

L

Mississipian

Pennsylvanian

Neogene

23

Plio

Unconformities

Source rock

Reservoir rock

Seal rock

Overburden rock

Trap formation

Petroleum

system

events

Geologic 

time

scale

Migration, accumulation

Ordovician

Cambrian

542

488

444 450

500

550

Kansas, Colorado

Thirteen Finger limestonePennsylvanian shales (?), Atoka shale

interbedded and overlying shales

Precambrian

Morrow Group, Thirteen Finger lst., Atoka Group

Woodford Shale

stratigraphic, structural traps

Petroleum generation
Reservoir Rocks 25

Figure 20. Isopach map of the top of the Thirteen Finger limestone to 

the Morrow Formation, and the Thirteen Finger Limestone–Atoka Shale 

Gas AU (white line). Morrow and Thirteen Finger tops are based on 

Andrews (1999a, 1999b), examination of more than 120 well logs, and 

edited tops from IHS Energy (2009, 2010a). Morrow Formation faults 

(pink) are modified from Andrews (1999b). Color contour interval is 20 ft 

and (black) line contours are 10-feet intervals. Figure 21 cross sections 

are labeled A–A’ and B–B’. White polygons are Perryton (Texas) and 

Knowles Northwest (Oklahoma panhandle) oil fields, conventional oil 

reservoirs from the Thirteen Finger limestone.

Pennsylvanian 

Composite Total

 Petroleum System

Morrowan-Atokan 

 assessment unit

0

20

40

60

80

100

120

140

160

180

200

220

103° 102° 101° 100° 99° 98° 97°

39°

38°

37°

36°

35°

0 50 100 KILOMETERS

0 50 100 MILES

TEXAS

NEW MEXICO COLORADO

OKLAHOMA

KANSAS

Figure 20. Ch. 7 

A

A' B

B'

EXPLANATION

Thickness, in feet

There is no recorded continuous gas production in this 

AU. Within the Morrowan-Atokan AU there is minor conventional oil and associated gas production based on decline 

curves of petroleum and water production; the Thirteen Finger 

limestone in the Perryton and Knowles Northwest fields 

(fig. 20) have cumulative production of about 160,000 barrels 

of oil, 300 million cubic feet of gas (MMCFG), and 6,900 barrels of water (IHS Energy, 2010b). The fields are also located 

in an area marginally mature to mature for oil generation from 

the Thirteen Finger limestone, based on modeled TR and Ro

values (fig. 8). Carr and Hentz (2009) indicated that Atoka 

reservoirs are mainly limestone, and also sandstone, and have 

been productive since the 1940s in the northwestern part of 

the Anadarko Basin; operators have recently been drilling 

horizontally and applying hydraulic-fracture stimulations in 

the thin (6–27 ft, average 11 ft) carbonate reservoirs to tap 

adjacent organic-rich shales. Cumulative conventional petroleum production is 185 BCFG and 6.7 MMBO in Ochiltree 

and Lipscomb Counties, northeast Texas (IHS Energy, 2010b). 

The petroleum system events chart (fig. 22) shows the 

timing of generation, migration, and accumulation of petroleum that are based on petroleum system models of (table 2). 

Onset of gas generation from the Thirteen Finger limestone 

and Atoka shale (fig. 7) is probably soon after the 300-Ma 

onset of oil generation from these petroleum source rocks. 

The AU boundary (fig. 20) approximates the 0.99 percent 

TR boundary (fig. 8) that marks the transition from the end 

of oil generation to gas generation from the Thirteen Finger 

limestone. Although the Thirteen Finger limestone and Atoka 

shale are assumed to be the petroleum source rocks for this 

AU, there could be potential contributions from shales of the 

underlying Morrow Formation. Also, timing of petroleum generation is based on Woodford hydrous pyrolysis (HP) kinetics. 

These boundaries would probably be slightly different, either 

larger or smaller, should HP kinetics values be available that is 

specific to the Thirteen Finger limestone and Atoka shale.
Figure 21. A, Southwest to northeast and B, southeast to northwest cross sections of the Thirteen Finger limestone (TRFG) Pennsylvanian Atoka Group (ATOKA) in the Anadarko Basin. Lines of section are in figure 20. Vertical scale is in feet relative the Thirteen Finger limestone. MRMT is Marmaton Group, CHRK is Cherokee Group, MRRW is Morrow Formation, and MSSP Mississippian. Labeled well log traces are gamma (0 to 200 American Petroleum Institute [API]), resistivity, sonic density, an

 Hohnke Leo Unit 1 Bredy 1-6 Williams 1-18 P Exxon Corporation Arkla Exploration Monsanto Company L T 10 N, R 18 W, S. 6 T 14 N, R 19 W, S. 6 T. 16 N, R. 17 W, S. 18 T 

24.8 miles 15.7 miles 20.8 miles

Figur

A SOUTHWEST 

CHRK

ATOKA

TRFG

MRRW

1,000

500

 0

-500

-1,000

MRMT

CHRKATOKAMRRW

Gamma MSSPResistivitySonic

Neutron 
Figure 21. A, Southwest to northeast and B, southeast to northwest cross sections of the Thirteen Finger limestone (TRFG) Pennsylvanian Atoka Group (ATOKA) in the Anadarko Basin. Lines of section are in figure 20. Vertical scale is in feet relative of the Thirteen Finger limestone. MRMT is Marmaton Group, CHRK is Cherokee Group, MRRW is Morrow Formation, and MSof the Mississippian. Labeled well log traces are gamma (0 to 200 American Petroleum Institute [API]), resistivity, sonic densneutron density.—Continued

 Sturtz-Deeds Unit 1 McGarraugh 2-129 Hale 1-7  Arco Oil & Gas Corp. Anadarko Petroleum Corp. Chesapeake Energy Survey: H&TC, Blk: 43 Survey: SPRR Abs: 333, Blk. 10, S. 129 T. 1 N., R. 20 E., S. 7 

B SOUTHEAST NO

MRMT

 CHRK

 ATOKA

TRFG

MRRW

1,000

500

 0

-500

MCAMM

17.6 miles 13.9 miles

MSSP

GammaResistivitySonic

Neutron 
28 Petroleum Systems and Assessment of Undiscovered Oil and Gas in the Anadarko Basin Province

Figure 22. Petroleum system events chart for the 

continuous Thirteen Finger Limestone–Atoka Shale 

Gas Assessment Unit (AU) of the Pennsylvanian 

Composite Total Petroleum System. Timing of basin 

oil and gas generation, migration, and accumulation 

is based primarily on the petroleum system models. 

Thirteen Finger limestone (tan) periods of peak oil and 

gas generation are shown by the blue rectangles. This 

AU is located in an overpressured zone of the deep 

basin (Al-Shaieb and others, 1994). Because of this, 

Laramide uplift and erosion probably had minimal effect 

on the pressure environment. Millions of years ago, 

Ma; Unconformities, wavy and horizontal lines, lst; 

limestone, sh; shale.

Figure 22. Ch. 7

Pal

Eoc

Olig

Mio

0

100

200

300

400

50

150

250

350

Paleogene

Cretaceous

Jurassic

Triassic

Permian

65.5

146

200

251

359

416

Silurian

Devonian

299

318

E

E

E

E

E

E

E

E

M

M

M

M

L

L

L

L

L

L

L

L

Mississipian

Pennsylvanian

Neogene

23

Plio

Unconformities

Source rock

Reservoir rock

Seal rockOverburden rock

Trap formationPetroleum generation

Petroleum

system

events

Geologic 

time

scale

Migration, accumulation

Ordovician

Cambrian

542

488

444 450

500

550

Thirteen Finger limestone, Atoka shale

interbedded and bounding shales

Precambrian

Thirteen Finger limestone, Atoka shale

300 Ma onset from Thirteen Finger lst, Atoka sh.
Reservoir Rocks 29

Desmoinesian Assessment Unit

Desmoinesian, Missourian, and Virgilian strata were 

deposited in transgressive-regressive cycles that periodically 

inundated the province with alternating thin-bedded predominantly marine sandstones, limestones, and shales; these can be 

separated into stratigraphic packages of mostly sandstone or 

mostly limestone reservoirs (Moore, 1979; Rascoe and Adler, 

1983). Desmoinesian strata, mainly of the Cherokee and Marmaton Groups (fig. 2) cover the province except where locally 

removed by erosion. They are absent over most of the Wichita 

Mountain uplift, in the CKU, Cimarron arch, and the Sierra 

Grande uplift (fig. 5). The lateral continuity of these strata are 

visible on well logs, but the Paradox Basin of southeastern 

Utah provides extensive outcrops to visualize the stacking 

symmetry and lateral continuity of beds (fig. 23). 

Desmoinesian seas covered the entire central Oklahoma 

arch and the northern shelf area, extending into central Kansas 

(Johnson, 1989). The shallow sea was estimated at 50 to as 

much as 100 ft (15 to 23 m) deep (McCrone, 1964). Alluvial 

plain, deltaic, and incised channels flowed from the north and 

east southward and westward into the basin; during lowstands 

the shelf edge was exposed, the streams were incised during 

extension, and submarine fans were deposited on the basin 

floor (Anderson, 1991) with subsequent valley-fill deposition 

as the seal level rose. During temporary stillstands, deltaic 

conditions developed in the lower stretches of the streams, 

and relatively thin delta-fringe sands formed sheet-like units; 

further rise in sea level inundated the stream systems, and 

estuarine settings preceded widespread shallow marine conditions (Al-Shaieb and others, 1989). Source area for lower Desmoinesian clastics was from the north, whereas upper Desmoinesian strata were sourced from the south for the Arkoma and 

Anadarko Basins (Rascoe and Adler, 1983). West of the CKU, 

the lower Desmoinesian consists of an alternating sequence 

of thin limestones with lesser shale; sandstone is present but 

not common in this region, and was probably sourced from 

the Cambrian Reagan Sandstone from the northern CKU and 

Cambridge arch (Rascoe and Adler, 1983). 

The lower Desmoinesian Cherokee Group and correlative 

strata are mainly marine shale with numerous thin limestones 

and some lenticular point-bar and channel-fill sandstones. 

The informal Red Fork sand is the most important reservoir 

of this group; its stacked channel-fill sandstones are generally 

coarser grained and thicker than the delta-fringe sandstone 

and other facies of the group (Al-Shaieb and others, 1994). 

The informal Prue sand, the uppermost unit of the Cherokee 

Group was deposited in fluvial, deltaic, and nearshore marine 

environments (Andrews and others, 1996; Boucher, 2009); it 

ranges in depth from 3,500 ft on the northern shelf to about 

12,000 ft near the Wichita Mountain uplift (Henry and Hester, 

1995). The upper Desmoinesian Marmaton Group across the 

northern Oklahoma shelf area consists almost entirely of limestones, but in the deep Anadarko Basin it is almost entirely 

clastic sediments that were derived from the Ouachita foldbelt to the south (Krumme, 1981; Rascoe and Adler, 1983). 

Modeled thickness of the Desmoinesian in the deep basin 

ranges southward from about 500 ft to more than 3,500 ft. The 

Marmaton Group comprises in ascending order, Fort Scott 

Limestone, Englevale Sandstone, and Oologah Limestone 

(Big lime) (Johnson, 1989) in the northern basin, and sandstones and shales of the Deese Group in the southern basin 

(fig. 2). Depths to the top of the Marmaton Group range from 

3,500 ft on the northern shelf, to about 13,000 ft proximal to 

the Wichita Mountain uplift (Henry and Hester, 1995). This 

marine sequence is 200–1,000 ft thick in the north and grades 

southward in the deep Anadarko Basin into 4,000–5,000 ft of 

granite wash (Johnson, 1989). Granite wash lithofacies are 

generalized in the 4D model as the gray clastic sequence in 

figure 24. Desmoinesian strata in the deep basin were assessed 

as part of the Greater Granite Wash Composite AU. 

The Desmoinesian AU boundary corresponds to that 

of the Pennsylvanian TPS, with the exception of an area in 

the deep basin that contains the Greater Granite Wash Composite AU (fig. 25). Oil and gas wells are distributed across 

the Desmoinesian AU, but are concentrated in the area of 

the Watonga-Chickasha and Sooner trends in the eastern 

half of the province, against the Nemaha uplift and, for oil 

wells, around the CKU. Trap types are structural and (or) 

stratigraphic. Fields close to the Wichita Mountain uplift are 

commonly structural, such as the large faulted anticline of the 

Cement field. Reservoirs are clastic and carbonate beds of the 

Cherokee and Marmaton Groups, and their lateral equivalents 

(fig. 2). Reservoirs range in depth from about 4,000 to 12,000 

ft (Nehring and Associates, Inc., 2009). Cumulative production in the province is about 747 MMBO, 8.29 TCFG, and 

49.4 MMBW from about 14,235 wells in 1,640 fields (IHS 

Energy, 2010a, 2010b). Average GOR is 18,000 CFG/BO. 

Three of the larger fields are (1) Cement, for which 85 of 

1,345 leases in the field record Desmoinesian production of 

1.4 MMBO and 210 BCFG, (2) Postle, which has produced 

5.4 MMBO and 9.5 BCFG from 25 Desmoinesian leases, 

and (3) the Watonga-Chickasha trend, which has produced 

2.4 MMBO and 123 BCFG from 180 of the 2,750 total leases 

(IHS Energy, 2010b) (fig. 25). Because much of the production in the province is reported as commingled from multiple units, volumes should be considered approximate. The 

discovery thirds plots of grown oil and gas accumulations 

contain only a few of the Desmoinesian reservoirs in the basin 

(fig. 26), largely because of the quality of well and production 

data, so trends in production are difficult to determine. The 

discovery thirds of oil accumulations appear to have a stable 

exploration and development history, although four of the five 

largest oil fields were discovered early in exploration. The gas 

discovery thirds has too few points to make valid conclusions. 

Burruss and Hatch (1989) determined there are three 

oil types in the basin based on geochemical analysis of 104 

crude oils and 190 shale core samples of Cambrian through 

Pennsylvanian rocks; these oil types are divided into (1) 

Pennsylvanian, (2) Silurian to Mississippian, and (3) Middle 

Ordovician Simpson Group reservoirs. This suggests that 

Pennsylvanian reservoirs are sourced from Pennsylvanian 
30 Petroleum Systems and Assessment of Undiscovered Oil and Gas in the Anadarko Basin Province

Figure 23. Photograph showing Desmoinesian outcrop along the San Juan River in the Paradox Basin, southeastern Utah, illustrates 

carbonate/siliclastic cyclicity and lateral continuity of beds. The informally named middle Desmoinesian “Old Yeller,” Desert Creek, and 

Ismay zones are within the Paradox Formation and are roughly age-equivalent to the upper Cherokee and lower Marmaton Groups in 

the Anadarko Basin. This section is described in Grammer and others (1996) and is located in about sec. 26, T. 41 S., R. 19 E. Raft is for 

scale and this north view of the outcrop trends approximately west to east.

Desert Creek zone Raft

Figure 23. 

algal mounds

in the lower 

Ismay zone

“Old Yeller”

shales, although additional research may indicate more 

complexity. There are also potential petroleum contributions 

to Desmoinesian reservoirs from Mississippian strata in the 

northeastern Oklahoma portion of the basin because Morrowan and Atokan rocks are absent there. Oil and gas are 

concentrated along the Nemaha uplift and Central Kansas 

uplift, and a broad age range of petroleum source rocks could 

contribute in these areas because of migration along fault systems and thinning of strata in Kansas. Sampled shales within 

the Desmoinesian contain a mixture of Types II and III kerogen (Rice and others, 1989). Thermal maturation of potential Desmoinesian source rocks (fig. 7) is approximated by 

the Thirteen Finger images in figure 8 and shown in Higley 

(2012, fig. 26). Cherokee and Marmaton Groups petroleum 

source rocks in the Texas and Oklahoma Panhandles would be 

slightly less mature than the Thirteen Finger image. Desmoinesian source rocks in the deep basin of Oklahoma and Texas 

are overmature for oil generation based on TR, and in the 

wet and dry gas generation windows using modeled vitrinite 

reflectance. The petroleum system events chart (fig. 28) displays the timing of generation, migration, and accumulation 

of petroleum based in part on petroleum system models (table 

2) (Higley, 2014). Onset of oil generation from Pennsylvanian 

source rocks for the Desmoinesian AU (fig. 7) approximates 

the 300-Ma onset of oil generation from Thirteen Finger limestone petroleum source rocks.
Reservoir Rocks 31

Figure 24. Modeled surface on the Desmoinesian layer shows a broad gentle slope in Colorado and Kansas that deepens 

near the basin axis, north of the Wichita Mountain uplift. Vertical yellow bars are Precambrian faults, and surface colors are 

generalized lithofacies from Adler and others (1971) that mainly record increased clastics basinward. White areas do not 

contain Desmoinesian or underlying Cherokee model layer lithofacies. Vertical exaggeration is 15 times.

OKLAHOMA

 COLORADO TEXAS

KANSAS

Nemaha uplift

Wichita 

 Mountain 

 uplift

Amarillo uplift

Central 

Kansas 

uplift

2,500

0

-2,500

-5,000

-7,500

-10,000

-12,500

-15,000

-17,500

N

Elevation (meters)

Figure 24. Ch. 7

0−20 percent carbonates and 80−100 percent clastics

20−50 percent carbonates and 50−80 percent clastics

50−80 percent carbonates and 20−50 percent clastics

EXPLANATION
32 Petroleum Systems and Assessment of Undiscovered Oil and Gas in the Anadarko Basin Province

Figure 25. Maps showing 

A, Oil and B, gas wells that 

produce from the Desmoinesian 

Assessment Unit (AU) Cherokee 

and Marmaton Groups in the 

Anadarko Basin Province (IHS 

Energy, 2010a, 2010b). Generalized 

field locations are from IHS 

Energy (2010a) and Bebout and 

others (1993). The Desmoinesian 

AU shares a common boundary 

with the Pennsylvanian 

Composite Total Petroleum 

System (TPS). Excluded from the 

AU is an oval area in the deep 

basin that is the Greater Granite 

Wash Composite AU and included 

wells. Precambrian faults (pink) 

are from Adler and others (1971).

0 50 100 KILOMETERS

0 50 100 MILES

104° 103° 102° 101° 100° 99° 98° 97° 40°

39°

38°

37°

36°

35°

34°

TEXAS

OKLAHOMA

KANSAS

COLORADO

NEW MEXICO

A

Pennsylvanian Composite

 TPS and Desmoinesian AU

Province 58 

Granite Wash AU

Precambrian fault

Oil well

Gas well

EXPLANATION

Figure 25. A. Ch. 7

Panhandle

HugotonGuymon

Cement

Keyes dome

Postle

Sooner

trend

WatongaChicasha

trend

Sorrento

Arapaho

Stevens

Farnsworth

Stewart

Adams 

Ranch Mocane-Laverne

 gas area

Buffalo Wallow

Hansford

0 50 100 KILOMETERS

0 50 100 MILES

Panhandle

HugotonGuymon

Cement

Keyes dome

Postle

Sooner

trend

WatongaChicasha

trend

Sorrento

Arapaho

Stevens

Farnsworth

Stewart

Adams 

Ranch

Mocane-Laverne

Buffalo Wallow

Hansford

Pennsylvanian Composite

 TPS and Desmoinesian AU

Province 58 

Granite Wash AU

Precambrian fault

Oil well

Gas well

EXPLANATION

104° 103° 102° 101° 100° 99° 98° 97° 40°

39°

38°

37°

36°

35°

34°

TEXAS

OKLAHOMA

KANSAS

COLORADO

NEW MEXICO

B
Reservoir Rocks 33

Figure 26. Cumulative number of new-field wildcats by 

year that produce from the Desmoinesian AU (IHS Energy, 

2010a, 2010b). Exploration and development was static until 

about 1950, after which activity increased and has been fairly 

steady through time. The displayed major fields by discovery 

dates produce oil and gas from multiple units and ages. Field 

locations are shown in figure 25.

0

200

400

600

800

1,000

1,200

1920 1930 1940 1950 1960 1970 1980 1990 2000 2010 Postle, Putnam (1960)

Drilling completion year

Cement (1917)

Cumulative number of new-field wildcats

Figure 26. Ch. 7 

Chicasha (1923)Sooner Trend (1946)

Watonga-Chicasha (1962)

Figure 27. Grown gas and oil accumulation sizes for discovery thirds for the Cherokee and Marmaton Groups 

reservoirs in the Desmoinesian Assessment Unit (AU) (50580202). This AU has a mature exploration and 

development status with production from about 1,400 fields in the province (IHS Energy, 2010a, 2010b); however, 

only a few of these fields are represented on the figure. This paucity of information from the Nehring and 

Associates, Inc. (2009) is primarily because of reporting of production, mainly as commingled production from 

multiple units and age ranges. The discovery thirds for oil accumulations show close agreement for fields less 

than 8 MMBO, and for gas accumulations the limited data suggest that the second third of discoveries was more 

successful than the first and third thirds.

1

10

100

1,000

0 1 2 3 4 5 6 7

Grown gas accumulation size, billion cubic feet of gas

Gas accumulation rank by size

First third of accumulations discovered

Second third of accumulations discovered

Third third of accumulations discovered

EXPLANATION

0

1

10

100

0 2 4 6 8 10 12 14 16

Grown oil accumulationsize, million barrels of oil

Oil accumulation rank bysize
34 Petroleum Systems and Assessment of Undiscovered Oil and Gas in the Anadarko Basin Province

Figure 28. Petroleum system events chart for 

the Desmoinesian Assessment Unit (AU) of the 

Pennsylvanian Composite Total Petroleum system 

(TPS). Potential petroleum source rocks (fig. 7) from 

Hatch and others (1986) are light gray rectangles. The 

Thirteen Finger limestone (tan) range of oil and gas 

generation, migration, and accumulation represents 

Atokan and younger strata that are the primary 

petroleum source rocks; the 300-million years ago 

(Ma) onset of generation is based on the petroleum 

system one-dimensional and four-dimensional 

models. Potential oil and gas contributions from older 

source rocks is bracketed by the Woodford Shale 

(green) onset of generation of about 330 Ma. Time 

ranges of peak generation (fig. 14) are within blue 

rectangles. Paleogene trap formation, migration, and 

accumulation are based on Laramide generation and 

potential remigration associated with basin tilting. 

Unconformities, wavy and horizontal lines; Plio, 

Pliocene; Mio, Miocene; Eoc, Eocene; Pal, Paleocene; L, 

Late; M, Middle; E, Early.

Figure 28. Ch. 7 

Thirteen Finger limestone, Atoka Group shaleDesmoinesian petroleum source rocks

Woodford  Shale

Pal

Eoc

Olig

Mio

0

100

200

300

400

50

150

250

350

Paleogene

Cretaceous

Jurassic

Triassic

Permian

65.5

146

200

251

359

416

Silurian

Devonian

299

318

E

E

E

E

E

E

E

E

M

M

M

M

L

L

L

L

L

L

L

L

Mississipian

Pennsylvanian

Neogene

23

Plio

UnconformitiesSource rockReservoir rockSeal rockOverburden rockTrap formationGeneration

Petroleum

system

events

Geologic 

time

scale

Migration, accumulation

Ordovician

Cambrian

542

488

444 450

500

550

Kansas, Colorado

interbedded and overlying shales

Precambrian

stratigraphic, structural traps
Reservoir Rocks 35

Missourian-Permian Assessment Unit

The Missourian-Permian AU shares a common boundary with the Pennsylvanian Composite TPS, but excludes the 

Greater Granite Wash Composite AU in the deep Anadarko 

Basin (fig. 1). The AU includes Missourian, Virgilian, Wolfcampian, and Leonardian carbonate and clastic reservoirs 

(fig. 2). Missourian and Virgilian strata were primarily 

deposited in transgressive-regressive cycles that periodically 

inundated the province with alternating thin-bedded predominantly marine sandstones, limestones, and shales; these can be 

separated into stratigraphic packages of mostly sandstone or 

mostly limestone reservoirs (Moore, 1979; Rascoe and Adler, 

1983). Movement and erosion of the Wichita and Amarillo 

uplifts provided sediment for Missourian and Virgilian strata. 

Deformation and uplift of the Ouachitas, southeast of the 

Anadarko Basin, began during the Desmoinesian, and by 

late Missourian time several delta-front clastic wedges were 

deposited from streams that drained the Ouachitas and flowed 

into the eastern part of the Anadarko Basin (Johnson, 1989). 

Sandstone content increases from west to east in the Oklahoma portion of the basin, and the associated progression from 

marine to marginal marine indicates uplift with subsequent 

erosion of the Ouachita foldbelt was a sediment source (Rascoe and Adler, 1983). The Ouachitas continued to contribute 

clastics to the eastern basin during Virgilian time; a source 

of coarse detritus for the southeastern basin was provided by 

rapid rise of the Arbuckle Mountains uplift (Johnson, 1989).

The thickness of Missourian strata ranges from 500 to 

1,000 ft in most of the northern shelf and Hugoton embayment 

area, to more than 2,500 ft at the depocenter in the southeastern Anadarko Basin (Johnson, 1989). The Missourian Series 

in southwest Kansas and the Oklahoma Panhandle are mostly 

marine limestones with some shale interbeds that grade to the 

south and southeast into shales and sandstones with minor 

carbonate beds; against the Wichita Mountain and Amarillo 

uplifts they become the thick arkosic and carbonate strata 

(Johnson, 1989) of the Greater Granite Wash Composite AU. 

Along the western margin of the Hugoton embayment, the 

Missourian Series consists of a clastic sequence of shales, 

siltstones, and sandstones, which are commonly red beds; 

Virgilian strata in the Hugoton embayment and proximal shelf 

area to the east are mainly marine limestones interbedded with 

shale (Johnson, 1989). 

The Virgilian sequence ranges in thickness from about 

500 to 1,500 ft in the north and west, to more than 4,500 ft 

in the southeastern corner of the province (Johnson, 1989). 

Virgilian and Wolfcampian marine carbonates and shales 

grade westward toward the Sierra Grande uplift into redbeds 

and sandstones that were sourced mainly from this uplift 

(Maher, 1953; Roth, 1955). An exception to the normal clastic/

carbonate sequences of the Missourian and Virgilian is the 

middle Virgilian Heebner Shale, which was deposited under 

deep marine conditions (Al-Shaieb and others, 1994). This 

laterally continuous interval provides a seal for underlying 

strata. Post-Heebner Virgilian sedimentation consisted of 

cyclic carbonates and shales on the Kansas shelf, and of cycles 

comprising carbonates and thick wedges of terrigenous deltaic 

strata on the eastern margin of the basin (Rascoe, 1978). 

Lower Wolfcampian strata in-filled the sediment-starved 

Anadarko Basin at the end of the Pennsylvanian; estimated 

maximum water depth was about 700 ft (213 m) based on 

thickness of adjacent Virgilian deltaic wedges (Rascoe and 

Adler, 1983). The Wolfcampian Admire, Council Grove, and 

Chase Groups strata (fig. 2) cover most of the province, being 

absent over the Sierra Grande uplift and parts of the Amarillo, 

Central Kansas, and Wichita Mountain uplifts. The Chase 

Group in the basin averages about 200 ft in thickness and 

consists of cyclical limestone, dolomitic limestone, dolomite, 

red shales, and siltstone lithofacies that become more shaly to 

the north and west (Ball and others, 1991). Modeled thickness 

of the Chase layer is about100 to 450 ft thick in the Kansas 

portion of the basin, and thickens southward to about 800 ft 

near the Amarillo and Wichita Mountain uplifts. The Council 

Grove model layer includes the underlying Admire Group; 

this interval also thickens southward in the basin to as much as 

800 ft in the Oklahoma and Texas portions of the basin. Unlike 

the Chase layer, which is thin in the Colorado portion of the 

model, the Council Grove and Admire interval has a northeasttrending increase in thickness that corresponds to the eastern 

flank of the Las Animas arch.

Owen (1975) ascribed evaporite deposition at the end 

of Wolfcampian time as resulting from landlocked seas. 

Continued basin subsidence in Guadalupian time resulted in 

deposition of as much as 1,500 ft of red beds and evaporites 

in the deep basin; the Wichita Mountain uplift subsided at a 

somewhat slower rate and all but the highest parts were probably buried by fine clastics (Johnson, 1989). Thicknesses of 

100–200 ft of Guadalupian Blaine Formation dolomite, anhydrite, and shale were deposited over almost the entire province 

during a marine transgression (Johnson, 1989). Leonardian 

and Guadalupian evaporites of the Wellington and Blaine Formations form important seals for underlying reservoir beds. 

Figure 29 shows elevation on the top of the Wolfcampian Council Grove and Chase model layers. Data in the Palo 

Duro Basin area, south of the Panhandle field (figs. 1 and 29) 

were insufficient to model this surface. Shown are the basin 

axis proximal to the Wichita Mountain and eastern Amarillo 

uplifts, and the north-northwest trend of the flanks of the basin 

that are important to hydrocarbon migration. Also visible are 

the structural high of the Amarillo uplift in the Panhandle 

field area, a slight structural low between the Panhandle and 

Hugoton-Guymon fields, and the east-southeast tilt of strata in 

the Hugoton-Guymon fields. 

Figure 30 is a tilted view of the present-day top of the 

Virgilian Douglas model layer with oil and gas migration 

flow paths. The process and methodology of modeled oil and 

gas generation, migration, and accumulation is explained in 

. Petroleum flow paths resemble hydrologic tributaries, with 

the exception that the flow is generally from deeper to shallower. Drilling depths to the top of the Douglas Group range 

from about 3,800 ft in the northeastern part of the province 
36 Petroleum Systems and Assessment of Undiscovered Oil and Gas in the Anadarko Basin Province

Figure 29. Map showing elevation on the top of the Council Grove model layer for the Anadarko Basin province. Inset image on 

the top of the overlying Chase layer shows structures on this north-tilted view at 20 times vertical exaggeration. The primary basin 

axis is proximal to the Wichita Mountain uplift (fig. 24) in Oklahoma and Texas, the secondary axis trends northward along the 

west flank of the Central Kansas uplift (CKU), which is bounded approximately by displayed faults. White outlines the Panhandle 

(south) and Hugoton-Guymon (north) field areas (fig. 25). Precambrian faults (red) are from Adler and others (1971). 

Figure 29. Ch. 7

EXPLANATION

Elevation,

in feet

4,500

3,500

2,500

1,500

500

-500

-1,500

-2,500

-3,500

-4,500

Central 

Kansas uplift

103° 102° 101° 100° 99° 98° 97°

39°

38°

37°

36°

35°

COLORADO

 OKLAHOMA

 TEXAS

KANSAS

NEW MEXICO

0 50 100 MILES

0 50 100 KILOMETERS
Reservoir Rocks 37

to about 11,000 ft in the southern basin (Henry and Hester, 

1995). Modeling indicates that migration on the Douglas 

layer is mainly from the deep basin radially outward to the 

Panhandle-Guymon-Hugoton fields, CKU, Salina Basin, and 

Nemaha uplift (fig. 30). Hydrocarbon flow follows topography 

on a layer, which is quite similar to structure on the Council 

Grove and Chase Groups (fig. 29), across the western and 

eastern flanks of the basin and up the secondary basin axis 

to the CKU. Gas flow paths are visible along the western 

and northwestern boundaries and CKU and mainly represent 

increase of gas volume because of pressure release proximal 

to outcrops and at major structures, such as the Sierra Grande 

uplift and Las Animas arch. Petroleum generation began in the 

deep basin (fig. 8) but then flowed up the flanks of the basin 

and toward bounding structures. 

Potential Pennsylvanian petroleum source rocks that 

underlie the Douglas layer in Kansas and most of the Oklahoma and Texas panhandle area are thermally immature for 

oil generation (fig. 8), so long-distance migration factors 

into these reservoirs. Lateral migration can exceed 200 km 

(124 mi), which is the distance between the extent of thermally mature source rocks for the Oil Creek layer and the 

northern limit of the 4D model. Maximum migration is probably considerably greater because migration pathways tend to 

follow curved paths through permeable carrier lithofacies and 

along structures. Also, the wealth of oil and gas resources for 

the CKU and the Cambridge arch to the north are in areas that 

are thermally immature for petroleum generation. Because 

most oil and gas is not trapped in the 4D model, the flow paths 

are useful for visualizing migration on structural surfaces. The 

V-shaped areas of low flow to the right and left of the CKU 

correspond to areas of fewer oil and gas wells in figure 30, but 

flow also appears to be mostly absent in most of the Panhandle 

field area. That oil and gas migration flow paths appear west 

of the Panhandle field indicates that hydrocarbons did flow 

through this field but did not accumulate in the model. 

Missourian-Permian AU oil and gas production is from 

more than 28,900 leases in 1,820 fields (fig. 31) and totals 

about 846 BBO, 50 TCFG, and 263 MMBW (IHS Energy, 

2010a, 2010b). Because the reservoirs are subject to the same 

data reporting problems as for other strata in the basin, these 

numbers should be considered approximate. The Nehring and 

Associates, Inc. (2009) database contains information on 66 

of the oil fields and 93 of the gas fields. This AU also includes 

oil and gas production from the Palo Duro Basin, and oil 

production from the Las Animas arch of southeastern Colorado (figs. 5 and 31). The Palo Duro Basin is bounded on the 

north by the Amarillo uplift (fig. 5), south of the Panhandle 

field. Oil and gas production, aside from the giant PanhandleGuymon-Hugoton field complex, is somewhat scattered across 

the province, particularly in regard to the number of wells 

that have been drilled. Oil and gas wells are concentrated 

in the Panhandle field, which is part of the Greater Granite 

Wash Composite AU (fig. 31); as such, some of the following 

discussion also applies to that AU. Within the MissourianPermian AU, oil wells are concentrated in northeast Texas, the 

Cement, Watonga-Chickasha trend, and Sooner trend fields, 

and Nemaha uplift of Oklahoma, and near the CKU in Kansas. 

Gas wells are similarly distributed with the exception of the 

vast Panhandle-Guymon-Hugoton gas field complex (fig. 31), 

the largest in North America at 8,500 mi2; through 1985 

it produced more than 48 TCFG, and accounted for about 

58 percent of the gas and 26 percent of the oil production in 

the basin (Davis and Northcutt, 1989). This field complex will 

be referred to as the Panhandle-Guymon-Hugoton field, even 

though it includes other fields (fig. 31). 

The Panhandle West field in the Panhandle-GuymonHugoton field was discovered in 1918, with production from 

Desmoinesian strata informally named “Big lime” (Mason, 

1968) of the Marmaton Group (figs. 2 and 32). Galloway and 

others (1983) determined that porosity and permeability for 

the Panhandle field averages 13 percent and 25 mD, at 2,850 ft 

depth. About 94 percent of the gas but less than 2 percent 

of the oil production from the Panhandle-Guymon-Hugoton 

fields is from the Missourian-Permian AU, almost all of it 

from the Permian, mainly Wolfcampian Council Grove and 

Chase Groups; most of the oil production is from granite 

wash in the Panhandle field, with other units producing minor 

amounts (IHS Energy, 2010a, 2010b). Hugoton-Guymon field 

production through September 2009 totaled about 1.4 BBO, 

51.8 TCFG, and 864 MMBW for all reported Mississippian 

through Permian units (IHS Energy 2010a, 2010b). 

Figure 33 shows estimated ultimate recovery (EUR) 

values for 1,024 wells across the Hugoton-Guymon portion of 

the field area. There is considerable variation in EURs, ranging mainly from about 400 to 7,000 MMCFG, and there are no 

clear trends in production. The EUR discovery thirds (fig. 34) 

show greatest production for the first third of discovered wells, 

followed by a progressive decline in EURs for the second and 

third of discovered wells. This is a complex set of reservoirs, 

and research by Dubois and others (2006) suggests that additional reserves may result from bypassed pay and by reservoir 

compartmentalization. Complex stacking, cyclicity, and lateral 

continuity of Council Grove and Chase Groups lithofacies 

are shown in figure 35. Average reservoir characteristics of 

the Chase Group in the field complex, north of about 35.5° 

latitude, include about 5-mD permeability, 14 percent porosity, 

25 percent water saturation, and 45 net feet of productive rock 

(Mason, 1968). Hugoton field initial reservoir pressure was 

485 pounds per square inch (psia) in about 1928 and pressure 

declined to 360 psia by 1958 and 260 psia by 1968; average formation temperature and depth are 90 °F and 2,700 ft 

(Mason, 1968). 

Discovery thirds of grown oil accumulations for the 

Missourian-Permian AU (fig. 36) do not decline much through 

time, aside from effects on the curves of early fields from 

which 20 MMBO and more was produced. The discovery 

thirds of gas fields do exhibit decline through time, particularly for larger fields.

Reservoir seals include interbedded shale lithofacies 

(Morse, 1963; Galloway and others, 1977). Missourian and 

Virgilian reservoir seals are mainly interbedded and overlying 
38 Petroleum Systems and Assessment of Undiscovered Oil and Gas in the Anadarko Basin Province

Figure 30. Oil (green) and gas (red) migration flow paths on the Douglas and Permian layers in the four-dimensional petroleum 

system model at present day. The image is tilted to the north and is at 15 times exaggeration to better show flow paths. Yellow 

outline is for the generalized locations of the Hugoton and Panhandle fields (fig. 25). In general, flow follows topography on the 

model layers. Petroleum is generated mostly in the deep basin and flows radially northward. Flow in northern Oklahoma and in 

Kansas is directed toward the Las Animas arch (LA), Central Kansas uplift (CKU), and Nemaha uplift. Gas flow paths at the western 

and eastern boundaries of the map and the CKU resulted from decrease in pressure-volume-temperature (PVT) conditions. 

Greenish-gold vertical bands are Precambrian faults (Adler and others, 1971). These are the only modeled Missourian-Permian 

Assessment Unit layers that have flow paths, mainly because (1) Heebner layer shale above the Douglas layer provided enough of 

a seal to prevent upward leakage, (2) the generalized lithologic assignments of other layers, and (3) coarse grid spacing resulted in 

most generated petroleum migrating out of the model.

Figure 30. Ch. 7

COLORADO KANSAS

TEXAS OKLAHOMA

Central Kansas

uplift

LA

Nemaha uplift

N
Reservoir Rocks 39

Figure 31. Maps showing A, Oil 

and B, gas wells that produce 

from the Missourian-Permian 

Assessment Unit (AU) in the 

Anadarko Basin Province (IHS 

Energy, 2010a, 2010b). Also shown 

is the common boundary with the 

Greater Granite Wash Composite 

AU boundary and included wells. 

Generalized field locations are 

from IHS Energy (2010a) and 

Bebout and others (1993). Largest 

gas field is Hugoton-Guymon, 

which extends northward from the 

Panhandle field. Gold-colored line 

on A is the southeast to northwest 

cross section and (red dot) burial 

history plot location for figure 39. 

Precambrian faults (pink) are from 

Adler and others (1971).

0 50 100 KILOMETERS

0 50 100 MILES

104° 103° 102° 101° 100° 99° 98° 97° 40°

39°

38°

37°

36°

35°

34°

TEXAS

OKLAHOMA

KANSAS

COLORADO

NEW MEXICO

A

Missourian-Permian AU

Province 58 

Granite Wash Comp. AU

Precambrian fault

Oil well

Gas well

EXPLANATION

Figure 31. (a) Ch. 7

Panhandle

HugotonGuymon

Cement

Keyes dome

Postle

Sooner

trend

WatongaChicasha

trend

Sorrento

Arapaho

Stevens

Farnsworth

Stewart

Adams 

Ranch Mocane-Laverne

Buffalo Wallow

Hansford

0 50 100 KILOMETERS

0 50 100 MILES

104° 103° 102° 101° 100° 99° 98° 97° 40°

39°

38°

37°

36°

35°

34°

Panhandle

Panoma

Cement

Keyes

dome

Postle

Sooner

trend

WatongaChicasha

trend

Farnsworth

Stewart

Adams 

Ranch Mocane-Laverne

Buffalo Wallow

Hansford

Hugoton

Guymon

Hugoton

B

TEXAS

OKLAHOMA

KANSAS

COLORADO

NEW MEXICO

Missourian-Permian AU

Province 58 

Granite Wash Comp. AU

Precambrian fault

Oil well

Gas well

EXPLANATION
40 Petroleum Systems and Assessment of Undiscovered Oil and Gas in the Anadarko Basin Province

Figure 32. Graph showing production history of the 

Missourian-Permian Assessment Unit (AU) in the 

Anadarko Basin Province with some of the major field 

discovery names and dates (IHS Energy, 2010a, 2010b; 

Oklahoma Geological Survey, 2011a, 2011b). Exploration 

and development was relatively slow until discovery of the 

Watonga-Chickasha field. Development after about 1950 

shows the same general trends as those from other AUs.

Figure 33. Map showing generalized contours of 

estimated ultimate gas recovery (EUR) in million cubic 

feet of gas (MMCFG) from 1,024 leases in the Hugoton and 

Guymon fields (data from Troy Cook, written commun., 

2010). Leases represent single-well production of gas 

from the Chase and (or) Council Grove Groups. Contours 

are based on log10 EUR values to better show variability 

across the area. Horizontal blue line is generalized 

location of cross sections shown in figure 35. Pink lines are 

Precambrian faults from Adler and others (1971).

20,000

17,500

15,000

12,500

10,000

7,500

5,000

2,500

0

1915 1925 1935 1945 1955 1965 1975 1985 1995 2005

Year of first production by well

Number of wells/leases

Cement 

Chicashaw 

Mobeetie

Mocane-Laverne 

Watonga-Chicashaw 

1970–2009 ~ 1,020 new  fields

Figure 32. Ch. 7 

Panhandle

Hugoton, Guymon

103° 102° 101° 100° 99° 98° 97°

39°

38°

37°

36°

35°

COLORADO

KANSAS

TEXAS OKLAHOMA

 KS

OK

0 50 100 MILES

0 50 100 KILOMETERS

0.3

0.6

1.6

3.1

10

25

63

159

398

1,000

2,510

6,310

15,850

0.1

1.0

10

100

1,000

10,000

EXPLANATION

MMCFG
Reservoir Rocks 41

Figure 34. Graph showing discovery thirds of estimated ultimate 

recovery of gas (EUR) in million cubic feet of gas (MMCFG) for 

1,024 wells in the Hugoton and Guymon fields that produce gas 

from the Chase and (or) Council Grove Groups (T. Cook, written 

commun., 2010). Data represent leases that have one well per 

lease and are split into the first, second, and third thirds of onset 

of production to November 2009, based on data from IHS Energy 

(2010a, 2010b). The curves indicate that gas production has 

undergone a steady decline since onset of production. Decline 

rate is greatest for the more productive wells in the third of EUR.

100,000

10,000

1,000

100

10

Estimated ultimate recovery, MMCFG

1

Percent of sample, in percent

0 10 20 30 40 50 60 70 80 90 100

First

Second

Third

Figure 34. Ch. 7

EXPLANATION

shales. Seals in Permian reservoirs include overlying shaleevaporite beds in the Leonardian strata, and seals for the 

Hugoton gas field may include capillary-pressure effects of 

bounding water. Trap types in this AU are mainly structural 

and (or) stratigraphic. Oil and gas fields that produce from 

Missourian rocks have a wide distribution, and are in structural, stratigraphic, and combination traps (Rascoe and Adler, 

1983). The Cement field in the deep basin is a faulted anticline 

that produces from Silurian through Permian strata. The primary trapping mechanism is structural in the Panhandle field 

but stratigraphic in the Hugoton field, with a hydrodynamic 

component to both (Owen, 1975). Pippin (1970, p. 211) created a structure map on the granite underlying the Panhandle 

field that suggested the Amarillo uplift was a great horst block 

circumscribed almost completely by faults. The Hugoton field 

is an east-dipping homocline with the western edge being a 

somewhat steeply dipping monocline. Mason (1968) indicated 

that Chase and Council Grove Groups strata have a common 

gas-water contact in the Hugoton field, and that production 

in the west is limited by updip water and by a permeability 

decrease in the Chase Group, and on the east by an eastwarddipping gas-water interface. 

Absence of an updip seal in the 4D model is indicated by 

flow of hydrocarbons westward through the Hugoton and Guymon fields (fig. 37); appearance of gas flow paths is largely 

the result of a decrease in pressure with shallower burial on 

the west and at the CKU. There were few accumulations with 

the 4D model, compared to overall production in the province, but production from this AU is generally focused along 

major Douglas layer flow paths. The overlying Heebner shale 

layer provided enough of a seal for the 4D petroleum system 

model to show migration of oil and gas on the underlying 

Douglas layer (fig. 30). The Heebner Shale is an exception to 

the normal clastic/carbonate sequences of the Missourian and 

Virgilian; its deep marine deposition was a period of uncommon Virgilian quiescence (Al-Shaieb and others, 1994). This 

shale generally is less than 100 ft thick and can be mapped 

across most of the province; it thickens in the deep basin 

and proximal to the Nemaha and Arbuckle uplifts shown in 

figure 5. Rascoe and Adler (1983) indicated the shale is only 

about 3 ft thick in the northern part of the basin, but increases 

to about 400 ft in the deep basin. 

Petroleum source rocks for the Missourian-Permian AU 

are probably Pennsylvanian shales and limestones. Rice and 

others (1988a, 1988b) indicated that Panhandle-Hugoton 

field nonassociated gases are mostly produced from Permian carbonates at depths less than 900 m (2,950 ft), and that 

Pennsylvanian and Permian gases display little compositional variation with a range of δ13C values from -46.4 to 

-39.9 percent (mean δ13C1 value is -43.2 percent, mean C2+

value is 14 percent). This isotopic composition is comparable 

to that of thermogenic gas from Atokan and Desmoinesian 

producing intervals in the central basin (Rice and others, 

1989), which indicates Pennsylvanian sources of hydrocarbons. Shales in Virgilian-producing intervals have a mixture 

of Type II and III kerogen (Rice and others, 1989). 

Permian oil and gas from the 4D model are mostly 

located in and west of the Panhandle through western Hugoton field areas (fig. 37); gas was sourced 56 percent from the 

Thirteen Finger limestone, 26 percent from the Oil Creek 

layer, and 18 percent from the Woodford layer. Because the 

4D model has far fewer traps or seals than exist in the basin, 

modeled contributions from the Woodford layer source rocks 

may not be present with a more complex model. Model 

reasons for the Oil Creek contribution are that (1) Woodford 

Shale and Thirteen Finger limestone source rocks are thin 

to absent north of the Amarillo uplift area; (2) the Woodford 

through Desmoinesian isopach (fig. 5) is thin in the Texas 

Panhandle area; (3) Pennsylvanian strata in the Panhandle 

field area are underlain by up-tilted edges of lower Paleozoic 

rocks (Mason, 1968), which could allow for greater contributions from deeper source rocks; and (4) this leaky 4D model 

allows for more vertical and lateral migration than would a 

more complex model. The Panhandle field contains sweet and 

sour gases (Owen, 1975), which also suggests contributions 

from deeper sources than the mostly Type II and III kerogen of 

Pennsylvanian source rocks.

Measured Ro values of the Upper Devonian–Lower 

Mississippian Woodford Formation are highest 30 to 40 km 

(20 to 40 mi) north-northwest of the deepest part of the 

Anadarko Basin, which is partly the result of the contrast in 

thermal conductivity between the high-conductivity granite 

wash strata adjacent to the Wichita uplift and the basinward 

low-conductivity shale section (Carter and others, 1998). 

The combination of decreasing heat flow toward the Wichita 
42 Petroleum Systems and Assessment of Undiscovered Oil and Gas in the Anadarko Basin Province

Figure 35. Lithofacies in west to east cross sections across the Hugoton field for the (B) Chase and (C) Council Grove Groups (modified 

from Dubois, 2007). These stratigraphic cross sections are hung on the top of the Chase (B) and the Council Grove (C), and location 

is in figure 33. Orange through red layers are continental (Cont) sandstone (SS), siltstone (Silt) and shale. Other colors are marine 

lithofacies, including fractured (Fxln) and crystalline (Cxln) dolomite (Dolo). Both cross sections show lateral continuity of cyclical beds 

of marine and continental strata. Marine strata increase in thickness to the east and continental beds thicken westward. Dubois (2007) 

indicated that large-scale sedimentation patterns and distribution of resultant lithofacies (at the cycle scale) are largely a function 

of the position on the shelf and reflect the interaction of shelf geometry, sea level, and, possibly, the proximity to siliclastic sources. 

Lithofacies distribution and cycle-stacking patterns at larger scales may be a function of lower-order cyclicity and a shift from icehouse 

to greenhouse conditions (upward) during the Lower Permian. 

Figure 35Ch7

Facies

Cont SS

Cont Silt

Silt and Shale

Marine Silt

Mudstone

Wackstone

Fxln Dolo

Packstone

Grainstone

Cxln Dolo

Marine SS

350 ftft

Facies

Cont SS

Cont Silt

Silt and Shale

Marine Silt

Mudstone

Wackstone

Fxln Dolo

Packstone

Grainstone

Cxln Dolo

Marine SS

400 ftf

Herington

Krider

Winfield

Towanda

Ft. Riley

Wreford

Thick continental 

half-cycles

Thick marine 

half-cycles

vertical exaggeration 300 times

vertical exaggeration 300 times

Thick continental

half-cycles

Change in

shoreline

position

Mud

dominant

Grain

dominant

marine ss

continental ss

B

C

W E

Back-stepping

lithofacies

Thick marine

half-cycles

350 ft

80 MILES (130 KILOMETERS)

W E

80 MILES (130 KILOMETERS)
Reservoir Rocks 43

Figure 36. Graphs showing grown oil and gas accumulation sizes for discovery thirds of the Missourian-Permian Assessment 

Unit (AU) of the Pennsylvanian Composite Total Petroleum System. Only a fraction of the about 1,420 oil and gas fields that 

produce from this AU are shown, largely because many fields produce from multiple units with reported commingled volumes. 

Discovery trends are similar of grown oil accumulations less than about 20 million barrels of oil (MMBO). At greater than this 

volume, the first third of discoveries are larger than those of the second and third thirds. The early development history was 

marked by the giant Hugoton-Guymon and Panoma gas fields. In general, the gas accumulation chart shows a general decrease 

through time in field sizes. Billion cubic feet of gas, BCFG.

Oil accumulation rank by size Gas accumulation rank by size

Grownoil accumulation size, MMBO

Growngas accumulation size, BCFG

Figure 36. Ch7. 

100 100,000

10,000

1,000

100

10

1

10

1

0

0 5 10 15 20 25 0 5 10 15 20 25

First third of accumulations discovered

Second third of accumulations discovered

Third third of accumulations discovered

First third of accumulations discovered

Second third of accumulations discovered

Third third of accumulations discovered

EXPLANATION EXPLANATION

Mountains and the facies changes in the Pennsylvanian from 

marine shale to granite wash toward the uplift results in the 

highest formation temperatures being displaced about 50 km 

(31 mi) northward into the basin (Gallardo and Blackwell, 

1999). Basement heat flow is greater basinward than it is 

close to the mountain front (fig. 38), which results in the 

pronounced thermal maturity “bump” in the figure 39 cross 

section from within the Greater Granite Wash Composite AU 

northward to Kansas. The associated burial history plot is in 

an area of low basement heat flow that contains granite wash 

arkosic strata. The Panhandle field is located on the Amarillo 

uplift, which exhibits low heat flow (fig. 38) and is thermally 

immature for hydrocarbon generation (fig. 40). The basin just 

north of the uplift deepens rapidly and thermal maturation of 

potential petroleum source rocks within 30 km (20 mi) ranges 

from mature for oil to gas generation. Some of the model layers are identified in figure 40, but lateral continuity is variable 

mainly because of faulting and data quality of formation tops 

used to construct the layers. 

The petroleum system events chart (fig. 41) shows the 

timing of hydrocarbon generation, migration, and accumulation based on petroleum system models (table 2) (Higley, 

2014). Onset of oil generation from Pennsylvanian source 

rocks (fig. 7) approximates the 300-Ma beginning of oil generation from Thirteen Finger limestone petroleum source rocks 

based on 4D petroleum system modeling. This onset preceded 

deposition of reservoir rocks from this AU; so the 270-Ma 

beginning of oil generation for this AU is based on the Higley 

(2012, table 3) modeled onset of generation from potential 

Virgilian source rocks. 
44 Petroleum Systems and Assessment of Undiscovered Oil and Gas in the Anadarko Basin Province

Figure 37. Model image showing oil and gas wells that produce from the MissourianPermian and Greater Granite Wash Composite assessment units (AU) in the Anadarko Basin 

Province (IHS Energy, 2010a, 2010b) are superimposed on the image of Douglas plus Permian 

layer flow paths (fig. 30). In general, areas with less flow have fewer wells. Yellow outline is 

the Panhandle-Guymon-Hugoton field area, drilling is somewhat faint within the gas fields 

because of the wider drill spacing than for oil production. Absence of flow paths within the 

Panhandle field, with their appearance on the west side of the field suggests (invisible) Darcy 

flow through the reservoir because all potential source rocks are thermally immature in the 

western Amarillo uplift (fig. 8) (Higley, 2014). Sorenson (2005) also indicated that petroleum 

migrated southward from the basin into structural traps of the Panhandle field. Precambrian 

faults are from Adler and others (1971).

103° 102° 101° 100° 99° 98° 97° 39°

38°

37°

36°

35°

34°

TEXAS

OKLAHOMA

COLORADO KANSAS

NEW MEXICO

0 50 100 KILOMETERS

0 50 100 MILES

Missourian-Permian AU, Greater Granite

 Wash Composite AU

Precambrian faults

Oil and gas wells

EXPLANATION

Figure 37. C
Reservoir Rocks 45

Figure 38. Map showing basement heat flow contours across the Anadarko Basin 

based on data from Carter and others (1998), Blackwell and Richards (2004), and 

data downloads from the Southern Methodist University Web site (http://smu.edu/

geothermal/). Shown are the cross sections (blue lines) in figures 39 and 40, location of 

the one-dimensional burial history model (red dot), and Panhandle-Guymon-Hugoton 

field outlines (pink lines). Values are milliwatts per square meter (mW/m2). The A–A’

section crosses several zones of elevated heat flow and B–B’ is mainly in areas of 

decreased heat flow. Basin areas north of the Wichita Mountain uplift and in the 

Amarillo uplift and northward exhibit generally lower heat flows than other basin 

areas. Highest measured heat flow is in the northwest, along the Las Animas arch. The 

northwest-trending Central Kansas uplift also exhibits elevated heat flow values. Red 

lines are faults on the top of the Hunton Group from Rottmann (2000a) that were used to 

contour Hunton and Woodford layers, and Precambrian faults (modified from Adler and 

others, 1971).

24

28

32

36

40

44

48

52

56

60

64

68

72

76

80

EXPLANATION

Heat Flow

39°

38°

37°

36°

35°

KANSAS

OKLAHOMA

NEW MEXICO

Central 

Kansas

uplift Las Animas arch

Wichita 

 Mountain uplift

Amarillo uplift

 

TEXAS

Nemaha uplift

0 50 100 MILES

0 50 100 KILOMETERS

Figure 38, chapter 7

103° 102° 101° 100° 99° 98° 97°

A

A ́

B

B ́

Arbuckle 

Mountains

COLORADO
46 Petroleum Systems and Assessment of Undiscovered Oil and Gas in the Anadarko Basin Province

Figure 39. Southeast to northwest structural cross section with present-day transformation ratios (% TR). The burial 

history plot of TR and vitrinite reflectance (% Ro) is near the red dot on the cross section, and both locations are in figure 

38. Pink lines are the general location of the Woodford Shale layer. The two “bumps” of increased thermal maturation on 

the cross section correspond to areas of increased heat flow in figure 38. Lithologic variation has minor effect on these 

increases because of the generalized lithofacies assignments in the model. If basement heat flow was one value across the 

basin, then the TR contours would be approximately horizontal because of the strong influence of burial depth. The burial 

history plots show the Council Grove layer as marginally mature for oil generation at 0.1 percent TR and 0.6% Ro, and the 

Woodford Shale layer is overmature for oil generation based on 100 percent TR and more than 1.2% Ro. The one-dimensional 

model is about 2 kilometers southwest of the Woodford Shale measurement of Cardott (1989, p. 45) for the 1 Miami Cattle 

well (1.56% mean Ro at -3,563 m elevation). These images are extractions from the four-dimensional petroleum system 

model, and are displayed in elevation relative to sea level.

Figure 39. Ch. 7 

EXPLANATION

TR, in percent

0.1 to 1.0

1.0 to 10 

10 to 25 

25 to 50

50 to 75

75 to 95

95 to 99

800

0

-1,000

-2,000

-3,000

-4,000

5,000

-6,000

 300 200 100 0

Time, in millions of years Time, in millions of years

300 200 100 0

1,000

0

-1,000

-2,000

-3,000

-4,000

-5,000

1.2 to 2.0 Wet gas

2.0 to 4.0 Dry gas

4.0 Overmature

0.6 to 0.7 Early oil

0.25 to 0.6

1.0 to 1.2 Late oil

0.7 to 1.0 Main oil

% Ro

SOUTHEAST NORTHWEST

A TEXAS KANSAS A ́

TR

TR Ro

OKLAHOMA

Elevation, in meters Elevation, in meters

Tertiary

Blaine

Council Grove

Wabaunsee

Douglas

Springer

Precambrian

Springer

Arbuckle

0 50 100 MILES

0 50 100 KILOMETERS
Reservoir Rocks 47

Figure 40. Cross section showing vitrinite reflectance (% Ro) and transformation ratio (% TR) is an extraction from the fourdimensional model across the Panhandle field. Location is in figure 38. The Panhandle field is located on the Amarillo uplift 

and oil and gas are produced from Wolfcampian and Leonardian strata. The Stone Corral model layer is bounded by pink lines 

and includes units from the top of the Leonardian Wellington to the base of the Guadalupian Blaine Formations (fig. 2). It is 

underlain by Wolfcampian strata. The Amarillo uplift and areas to the northwest are thermally immature for oil generation, and 

potential petroleum source rocks are absent because of erosion or nondeposition. Oil and gas migration flow paths appear 

west of the Panhandle field in figures 30 and 36; this indicates that hydrocarbons did flow through this field but were not 

trapped in this leaky model, and were most likely sourced from the east and northeast from Pennsylvanian and older source 

rocks and through open fault systems. Vertical exaggeration is 33 times. 

1,000

0

-1,000

-2,000

-3,000

-4,000

-5,000

Elevation, in meters

 Permian

Blaine

 Stone Corral

Wellington

 Chase

 Wabaunsee

Arbuckle

Precambrian

Simpson

Douglas

Cherokee

Elevation, in meters

1.2 to 2.0 Wet gas

2.0 to 4.0 Dry gas

4.0 Overmature

0.6 to 0.7 Early oil

0.25 to 0.6

1.0 to 1.2 Late oil

0.7 to 1.0 Main oil

% Ro

TR, in percent

0.1 to 1.0

1.0 to 10 

10 to 25 

25 to 50

50 to 75

75 to 95

95 to 99

0 50 100 MILES

0 50 100 KILOMETERS

EXPLANATION

EXPLANATION

1,000

0

-1,000

-2,000

-3,000

-4,000

-5,000

 Permian

Blaine

 Stone Corral

Wellington

 Chase

 Wabaunsee

Arbuckle

Precambrian

Simpson

Douglas

Cherokee

Amarillo uplift Amarillo uplift

B B ́ B B ́

NORTHWEST SOUTHEAST

 Chase

 Council Grove

Blaine

NORTHWEST SOUTHEAST
48 Petroleum Systems and Assessment of Undiscovered Oil and Gas in the Anadarko Basin Province

Figure 41. Petroleum system events chart for the Missourian-Permian 

AU of the Pennsylvanian Composite TPS. Primary hydrocarbon source 

rocks are dark gray rectangles, and age ranges of potential source rocks 

from Hatch and others (1986) (fig. 7) are light gray rectangles. Onset and 

peak petroleum generation (fig. 14) are shown for the Oil Creek (blue), 

Woodford (green), and Thirteen Finger limestone (tan) source rocks. Age 

ranges of peak hydrocarbon generation are indicated by blue rectangles. 

Paleogene trap formation, migration, and accumulation are based on 

Laramide generation and potential remigration associated with basin 

tilting. Unconformities, wavy and horizontal lines; Fm(s)., Formation(s); Plio, 

Pliocene; Mio, Miocene; Eoc, Eocene; Pal, Paleocene; L, Late; M, Middle; 

E, Early.

Figure 41. Ch. 7 

Sandstone and limestone beds

overlying, lateral evaporites and shales Wellington, Hennessey, Flowerpot, Blaine and Dog Creek Fms. shales and evaporites

Pal

Eoc

Olig

Mio

0

100

200

300

400

50

150

250

350

Paleogene

Cretaceous

Jurassic

Triassic

Permian

65.5

146

200

251

359

416

Silurian

Devonian

299

318

E

E

E

E

E

E

E

E

M

M

M

M

L

L

L

L

L

L

L

L

Mississipian

Pennsylvanian

Neogene

23

Plio

UnconformitiesSource rockReservoir rockSeal rockOverburden rockTrap formationGeneration

Petroleum

system

events

Geologic 

time

scale

Migration, accumulation

Ordovician

Cambrian

542

488

444 450

500

550

Kansas, Colorado

Thirteen Finger limestone, Atoka Group shaleDesmoinesian through Virgilian shales

Precambrian

Woodford 

 Shale

stratigraphic, structural traps

Oil Creek Fm.
Reservoir Rocks 49

Greater Granite Wash Composite Assessment 

Unit

The Greater Granite Wash Composite AU is defined as 

including Desmoinesian through Virgilian strata. The informally named granite wash strata consist mainly of arkosic 

shale to conglomerate. Every major stratigraphic unit from 

Morrow, and probably Springer, through Wolfcampian in the 

basin includes some granite wash facies near the mountains 

based on Dobervich and Parker (1958) and Edwards (1959). 

The Wichita orogeny climaxed during the Atokan and 

slowed in Desmoinesian time; the orogeny was accompanied 

by uplift of tens of thousands of feet of the Wichita Mountain and Amarillo uplifts relative to the basin axis; associated 

erosion resulted in deposition of granite wash sediments in 

the subsiding basin north of the fault zones (Ball and others, 1991). Carbonate conglomerates were the first to form; 

these resulted from erosion of the thick sequence of early 

and middle Paleozoic carbonates that mantled the rising 

Wichita Mountain and Amarillo uplifts, subsequent deposition of conglomerates of arkosic lithofacies resulted from the 

exposure and erosion of granites and rhyolites in the core of 

the Wichita-Amarillo Mountains (Johnson, 1989; Gallardo 

and Blackwell, 1999). This heterogeneous mix of detritus in 

the granite wash became progressively finer northward of the 

source area. 

The Anadarko Basin has been dormant since Early Permian time (Perry, 1989), as indicated by the relatively uniform 

thickness of Wolfcampian and Leonardian units across the 

basin, and that the Council Grove and Chase Groups, Hennessey Shale, and other strata can be correlated across the 

basin. Guadalupian and younger units exhibit more irregular 

distribution because of areas of nondeposition, and Laramide 

orogeny-associated uplift, tilting, and erosion but are present 

over much of the AU based on Adler and others (1971). The 

granite wash is generalized in figure 42 as the wedge-shaped 

Figure 42. Simplified southwest to northeast structural cross section from the Oklahoma deep basin to the shelf shows 

interfingering of granite wash lithofacies (blue) with those basinward (modified from Johnson, 1989). Greater Granite Wash 

Composite Assessment Unit (AU) boundary is gold line and cross section location is red line on inset map. Datum is sea 

level. Sil.-Dev., Silurian-Devonian.

Wichita 

Mountain uplift Anadarko Basin

A B

SEA

LEVEL

KILOMETERS

3

6

9

12

?

?

Proterozoic

Sil.-Dev.

Cambrian-Ordovician

Early-Middle Cambrian

?

Mississippian

Pennsylvanian

Permian

TEXAS

A

B

TEXAS

OKLAHOMA

Wichita 

Mtn. uplift

0 50 100 MILES

0 50 100 KILOMETERS

Sandstone and shale

Salt, anhydrite, and shale

Limestone and dolomite

Shale, limestone, and sandstone

Conglomerate (granite wash)

Black shale

Rhyolite, granite, and gabbro

Granite (?) and rhyolite (?)

EXPLANATION
50 Petroleum Systems and Assessment of Undiscovered Oil and Gas in the Anadarko Basin Province

Figure 43. Map showing thickness of the top of the Atoka to the 

Stone Corral model layers in the Greater Granite Wash Composite 

Assessment Unit (AU) ranges from about 0 to more than 14,000 

feet (ft). Areas of smooth contours have more limited data, such 

as the Wichita Mountain uplift and Panhandle field areas; actual 

thicknesses here are generally less than 1,000 ft (300 meters). 

Displayed wells produce oil and (or) gas from granite wash facies. 

Contour lines are 500-feet intervals. Precambrian faults (black) are 

from Adler and others (1971). Light gray lines are counties. 

Figure 44. Map showing oil and gas wells that produce from 

the Greater Granite Wash Composite Assessment Unit (AU) in 

the Pennsylvanian Composite Total Petroleum System (TPS), 

Anadarko Basin Province (IHS Energy, 2010a, 2010b). Smaller 

scale views of oil and of gas wells are in the Desmoinesian and 

Missourian-Permian oil and gas figures 24 and 31. Generalized 

field locations are from IHS Energy (2010a), Nehring and 

Associates, Inc. (2009), and Bebout and others (1993). The largest 

field is Panhandle, which covers most of the Amarillo uplift and 

produces from granite wash and other lithofacies. Precambrian 

faults (blue) are from Adler and others (1971). Light gray lines 

are counties.

0 50 100 KILOMETERS

0 50 100 MILES

103° 102° 101° 100° 99°

37°

36°

35°

34°

TEXAS

OKLAHOMA

Pennsylvanian Composite

 Total Petroleum System

Greater Granite Wash 

 Composite AU

Precambrian fault

Oil well

Gas well

EXPLANATION

Panhandle

Stiles Ranch

Hemphill

Buffalo

Wallow

Lathem 

granite wash interval; lithofacies grade basinward into mostly 

marine strata. The granite wash sequence is as much as 

5,000 ft thick and is located within about 30 miles north of the 

Wichita Mountain and Amarillo uplifts (Owen, 1975; Johnson, 

1989). The extent of granite wash in Wolfcampian was less 

than 10 miles from the mountain front (Ball and others, 1991). 

The greatest thickness of included strata in the AU is 

along the axis of the deep basin, with progressive northward 

and westward thinning. Thickness of the Morrowan through 

Wolfcampian section varies from 0 to more than 12,000 ft, 

and the Atoka Group to Stone Corral Formation interval has 

a similar thickness and distribution (fig. 43). Morrowan and 

Atokan strata, however, are absent over most of the Amarillo 

and Wichita Mountain uplifts. Determination of formation 

contacts from well logs south of the basin axis is complicated 

by interbedding of granite wash and marine lithofacies, and 

steeper dips proximal to the Wichita Mountain and Amarillo 

uplifts. Thicknesses in the figure 43 isopach map are not corrected to true stratigraphic thickness. More detailed descriptions and thickness maps of the various granite wash intervals 

are located in Mitchell (2011). 

The Greater Granite Wash Composite AU has almost 

20,000 wells, with cumulative production of about 1.6 BBO, 

43.3 TCFG, and 1.1 BBW; about 11,000 of the wells are 

productive of oil and 19,000 have associated or nonassociated 

gas (IHS Energy, 2010a) (fig. 44). These totals include more 

than granite wash wells and production, mainly because the 

AU boundary includes strata that are not granite wash. This 

is because of the variable lateral extent and interfingering 

of these strata with other lithofacies, and some granite wash 

production is reported commingled with other units. Granite 

wash is listed as a producing interval from about 6,900 wells 

in the AU with cumulative production of about 1.44 BBO, 

4.32 TCFG, and 1.03 BBW (IHS Energy, 2010b) (fig. 45). 

The Oklahoma Geological Survey (OGS, 2011b) Web site 

also includes information on granite wash and other plays, 

and reported granite wash production to 2008 as more than 

61 MMBO and 1.88 TCFG from more than 4,200 wells. The 

apparent discrepancy between the IHS Energy and OGS numbers is partly the different reporting dates, but mainly because 

of the number and distribution of wells that were assigned to 

granite wash production (fig. 45). The OGS (2011b) included 

some wells just southeast of the TPS, and had fewer wells in 

the northwest Panhandle field area. Almost all wells in the 

western Panhandle field have completion dates after 2008, so 

the difference is likely how the OGS (2011b) evaluated the 

producing formations and associated production, compared to 

the reporting of IHS Energy (2011a, 2011b). Mitchell (2011) 

indicated that an average EUR from a vertical granite wash 

well is 1.5 BCFG and 21,000 BO. Many of the IHS Energy 

(2010a, 2010b) granite wash wells in the Panhandle field area 

correspond to oil wells in figure 44. Much of the Panhandle 

field gas production is identified as the informally named 

Wolfcampian Brown dolomite of the Chase Group and the 

Leonardian Red Cave of the Sumner Group, which are shallower than granite wash strata. The first Permian production 

0 50 100 KILOMETERS

0 50 100 MILES

102° 101° 100° 99°

36°

35°

34°

TEXAS

OKLAHOMA

Pennsylvanian Composite

 Total Petroleum System

Greater Granite Wash 

 Composite AU

Precambrian fault

IHS Energy (2010a) well

EXPLANATION

Thickness,

in feet

14,000

13,000

12,000

11,000

10,000

9,000

8,000

7,000

6,000

5,000

4,000

3,000

2,000

1,000
Reservoir Rocks 51

in the Greater Granite Wash Composite AU was from Red 

Cave interbedded redbeds and carbonates of the Panhandle 

field in 1919. 

Cotner and Crum (1933) listed the range in GOR from 

500 to 1,000,000 CFG/BO for the Panhandle field, which 

reflects that the Greater Granite Wash Composite AU includes 

oil and gas plays. Estimated gas/oil ratio (GOR) is 30,820 for 

the OGS (2011b) data. OGS (2011b) listed cumulative production of 99,400 BO, 1.0 BCFG, and more than 440,000 BW 

for a typical granite wash well. Smith and others (2001) 

indicated the average granite wash production for their 1,985 

wells was 24 MBO and 1.15 BCFG; associated mean GOR is 

48,000 CFG/BO. 

Discovery halves for oil and thirds for gas accumulations 

are shown in figure 46. Discovery halves data for oil fields are 

too limited to form conclusions. The first and second thirds 

of gas accumulations have been stable through time, and a 

decrease in discovery thirds more than 20 BCFG for gas accumulations may reflect the shorter production time for these 

fields, as well as the largest accumulations generally being 

discovered early in exploration. The curves were not skewed 

by the Panhandle field, which is not included on these charts. 

Exploration histories of Greater Granite Wash Composite AU 

leases and of wells within the granite wash (fig. 47) follow 

similar trends with those of other AUs in the province, with 

the exception of later onset of drilling. 

Drilling depths in the AU range from less than 100 ft to 

an estimated maximum of about 15,000 ft; petroleum production is as shallow as 300 ft, but most major reservoirs produce 

from depths of 4,700 to 16,500 feet based on Henry and Hester 

(1995) and Mitchell (2011). Permeability in the Pennsylvanian 

granite wash is variable, ranging from close to 0 to more than 

300 mD, with about 20 percent average porosity (Mason, 1968) 

for these conglomeratic to arkosic strata. Published API gravity 

values of oil in the Panhandle field area range from 34 to 37o

(Owen, 1975). Mitchell (2011) listed API gravities of 45-60o

for oil and condensate, and natural gas liquid yields are as 

high as 190 barrels per million cubic feet of gas (B/MMCFG); 

Virgilian and Missourian granite wash reservoirs are shallower 

and more oil-prone with API gravities of 45–50o.

Traps are structural and (or) stratigraphic. The northern 

fault of the Amarillo uplift brackets some oil wells, and wells 

north of the fault systems show a north-northwest trend that 

is oblique to Precambrian faults but fit well over Hunton fault 

systems of Rottman (2000a, 2000b) that are shown in figure 

38. Panhandle field is located on the Amarillo uplift and is 

bracketed on the north and south by bounding faults (figs. 

38 and 40). Seals include interbedded and overlying shales, 

change in updip and lateral facies, and fault offsets close to 

the Wichita and Amarillo uplifts. Differential compaction on 

the south side of the Amarillo uplift anticline also provided a 

seal (Mason, 1968). The Pennsylvanian in the Panhandle oil 

field area is underlain by up-tilted edges of older Paleozoic 

rocks (Mason, 1968), which probably resulted in contributions 

through time from multiple petroleum source rocks. 

Figure 45. Map showing oil and (or) gas wells that produce from 

the granite wash within the Greater Granite Wash Composite 

Assessment Unit (AU). Some of the more than 3,600 Oklahoma 

Geological Survey (2011b) wells up to about 2008 are overlain 

by the more than 6,900 wells through September 2010 from IHS 

Energy (2010a, 2010b). Generalized field locations are from IHS 

Energy (2010a), Nehring and Associates, Inc. (2009), and Bebout 

and others (1993). Precambrian faults (blue) are from Adler and 

others (1971). Light gray lines are counties.

0 50 100 KILOMETERS

0 50 100 MILES

103° 102° 101° 100° 99°

37°

36°

35°

34°

TEXAS

OKLAHOMA

Pennsylvanian Composite 

 Total Petroleum System

Greater Granite Wash 

 Composite AU

Precambrian fault

IHS Energy (2010a) well

OGS (2011b) well

EXPLANATION

Panhandle

Stiles Ranch

Hemphill

Buffalo

Wallow

Lathem 

The western quarter of the AU, including most of the 

Amarillo and Wichita Mountain uplifts, are thermally immature for oil generation because of shallow burial depths and 

decreased basement heat flow (figs. 8 and 38–40). Thermal 

maturation of Pennsylvanian petroleum source and potential 

source rocks in the rest of the AU ranges from immature for 

oil generation to mature for dry gas generation, as indicated 

by a modeled Ro of less than 4 percent for the Thirteen Finger 

limestone layer (fig. 8). The Woodford Shale is absent over the 

western AU area, but deeper petroleum source rocks range in 

maturity from oil generation to overmature for gas generation. 

Hydrocarbon migration was primarily from the deep basin 

with flow to the west and northwest (fig. 30). The Greater 

Granite Wash Composite AU petroleum system events chart 

(fig. 48) shows the timing of hydrocarbon generation, migration, and accumulation based on petroleum system models 

(table 2) (Higley, 2014). Onset of oil generation from Pennsylvanian source rocks approximates the 300-Ma beginning 

of oil generation from Thirteen Finger limestone petroleum 

source rocks, based on petroleum system modeling. This onset 

preceded deposition of reservoir rocks from this AU, so the 

270-Ma beginning of oil generation for this AU is based on the 

Higley (2012, table 3) modeled generation for potential Virgilian source rocks. 
52 Petroleum Systems and Assessment of Undiscovered Oil and Gas in the Anadarko Basin Province

Figure 46. Discovery halves for oil and thirds for gas grown accumulations for the Greater Granite Wash Composite Assessment Unit 

(AU) in the Anadarko Basin Province. Only a fraction of the oil and gas fields that produce from this AU are shown, largely because most 

fields produce from multiple units with reported commingled volumes. These also include giant fields, such as Panhandle, which is not 

included in the discovery halves plot. Because these figures include some production from strata north of the granite wash lithofacies, 

the discovery plots are further compromised. The discovery halves of oil accumulations indicate that development has decreased 

through time. This “trend” probably reflects the paucity of data. The discovery thirds of gas accumulations indicates discovery has been 

fairly stable through time, although field sizes have decreased for larger fields as indicated by the third of accumulations greater than 20 

billion cubic feet of gas (BCFG).

Mesozoic Strata

Post-Permian strata in the basin include scattered remnants of rocks ranging in age from Triassic to Quaternary. 

Mostly alluvial sediments of the Miocene to Pliocene Ogallala 

Formation were deposited on an erosional surface of mostly 

Permian strata in the western half of the basin (Seni, 1980; 

Johnson and others, 1988). Underlying Mesozoic units are 

present mostly in the Colorado and western Kansas portions 

of the province, with only scattered erosional remnants in 

Oklahoma and Texas. 

Johnson and others (1988) estimated that 500–1,000 ft of 

Triassic and Jurassic strata were deposited in the Oklahoma 

and Texas portions of the basin but subsequent Early Cretaceous erosion removed all but the scattered 25–200 ft that 

remains in the far western part of the Anadarko Basin. Based 

on geologic maps of the States, outcrops of Mesozoic strata 

occur southeast of the province, in the Central Kansas uplift, 

along the western border in Colorado, Oklahoma, and Texas, 

the Amarillo uplift, and in scattered exposures along drainages 

in Kansas, New Mexico, and Oklahoma. The Lower Cretaceous Dakota Group sandstones and shales were deposited 

in the Colorado, western Kansas, and Oklahoma panhandle 

areas of the basin. Although the Muddy (“J”) Sandstone of 

the Dakota Group is an important oil and gas reservoir in the 

Denver Basin, there is minimal potential for petroleum in the 

Anadarko Basin Province because of (1) thermally immature 

source rocks; (2) long vertical and lateral migration distances 

for Paleozoic source rocks; (3) depositional thinning and updip 

erosion of the strata; and (4) formation water in these porous 

and permeable sandstones. Other Mesozoic units have low 

potential for the same general reasons. An exception to this 

is the Upper Cretaceous Niobrara Shale in the northern Las 

Animas arch area of Colorado and western Kansas; however, 

this resource was included in the Denver Basin assessment 

(Higley and Cox, 2007; Higley and others, 2007) and will 

only be mentioned here. Because contained gas is biogenic, 

thermal maturity of source rocks and migration distances are 

not important considerations. Within the productive area, 

potential hydrocarbon source rocks are thermally immature for 

generation at about 0.3 to 0.4% Ro (Smagala and others, 1984, 

Tainter, 1984). Biogenic gas is located within shallow, underpressured, fractured, relatively clean chalks (Longman and 

others, 1998) in fields that have low-relief structural closures. 

0

1

10

100

0 1 2 3 4 5 6 7

Grownoil accumulation size, MMBO

1

10

100

1,000

10,000

0 5 10 15 20

Growngas accumulation size, BCFG

Oil accumulation rank by size Gas accumulation rank by size

Figure 46. Ch. 7

First half of accumulations discovered

Second half of accumulations discovered

Firstthirdof accumulationsdiscovered

Secondthirdofaccumulations discovered

Thirdthirdof accumulationsdiscovered

EXPLANATION EXPLANATION
Reservoir Rocks 53

Figure 47. Production history of leases in the Greater Granite Wash Composite Assessment Unit in the 

Anadarko Basin Province is shown relative to the more than 3,700 completed wells for the same time 

increments from Oklahoma Geological Survey (OGS, 2011b). Granite wash development started about 1950 

and the Oklahoma Geological Survey (2011b) bars follow industry boom and bust cycles with an increase in 

completions from 1976 to 1985, followed by a lull until about the 2002 increase in exploration. Shown are some 

of the major field discovery names and year (Nehring and Associates, Inc., 2009; IHS Energy, 2010a, 2010b). 

0

50

100

150

200

250

300

350

1920 1930 1940 1950 1960 1970 1980 1990 2000 2010

Figure 47. Ch. 7

Panhandle

Year of first production by well

Cumulative number of leases, containing one or more wells per lease 

Buffalo Wallow

Hemphill

Stiles Ranch

Lathem

Number of Completed Wells (OGS, 2011b)

900

800

700

600

500

400

300

200

100

0
54 Petroleum Systems and Assessment of Undiscovered Oil and Gas in the Anadarko Basin Province

Figure 48. Petroleum system events chart for the 

Greater Granite Wash Composite Assessment Unit 

(AU) of the Pennsylvanian Composite Total Petroleum 

System (TPS). Dashed reservoir rock rectangle shows 

an interval of potential granite wash deposition that 

was included in the Morrowan-Atokan Assessment Unit 

(AU). Potential petroleum source rocks from Hatch and 

others (1986) (fig. 7) are light gray rectangles. Onset and 

peak petroleum generation (fig. 14) are shown for the 

Oil Creek Formation (blue), Woodford Shale (green), and 

Thirteen Finger limestone (tan) source rocks. Age ranges 

of peak generation are indicated by blue rectangles. 

Paleogene trap formation, migration, and accumulation 

are based on Laramide generation and potential 

remigration associated with basin tilting. Unconformities, 

wavy and horizontal lines; Fm., Formation; Plio, Pliocene; 

Mio, Miocene; Eoc, Eocene; Pal, Paleocene; L, Late; 

M, Middle; E, Early.

Figure 48. Ch. 7 

Wellington, Hennessey, Flowerpot, Blaineand Dog Creek Formation shale and evaporite

? ? ?

arkosic sandstone

overlying and interbedded shales, evaporites

Pal

Eoc

Olig

Mio

0

100

200

300

400

50

150

250

350

Paleogene

Cretaceous

Jurassic

Triassic

Permian

65.5

146

200

251

359

416

Silurian

Devonian

299

318

E

E

E

E

E

E

E

E

M

M

M

M

L

L

L

L

L

L

L

L

Mississipian

Pennsylvanian

Neogene

23

Plio

UnconformitiesSource rockReservoir rockSeal rockOverburden rockTrap formationGeneration

Petroleum

system

events

Geologic 

time

scale

Migration, accumulation

Ordovician

Cambrian

542

488

444 450

500

550

Kansas, Colorado

Thirteen Finger limestone, Atoka Group shale

Precambrian

Woodford 

 Shale

stratigraphic, structural traps

Oil Creek Fm
References Cited 55

Reservoir quality is controlled by burial diagenesis (Scholle, 

1977) and influenced by fracturing on low-relief structures. 

Fracturing may also be associated with dissolution of underlying Permian evaporites. The fractured Niobrara chalks 

commonly have porosities of 40 percent and greater (Lockridge and Scholle, 1978) but low matrix permeability. Burial 

temperatures do not exceed 75 oC in areas of active biogenic 

generation of gas (Rice and Claypool, 1981).

Conclusions

The Anadarko Basin Province is in a mature state of 

exploration and development, with more than 220,000 wells 

drilled. Oil and gas reserves and resources are distributed 

across the province and within Cambrian through Lower Permian strata. Much of the production is reported commingled 

from two or more formations, which complicates assigning 

oil and gas production and reserves to specific strata. This was 

a primary rationale for grouping assessment units (AU). The 

AUs discussed in this chapter of the report are conventional, 

with the exception of the continuous (unconventional) Thirteen 

Finger Limestone–Atoka Shale AU that has the same general 

extent as the vertically bounding Morrowan-Atokan AU. 

The Mississippian AU extends across the province, with 

petroleum production from mostly Lower Mississippian carbonates through Upper Mississippian sandstones and carbonates. The Morrowan-Atokan AU outlines the extent of these 

strata. These Morrow and Atoka Group reservoirs are mostly 

marine and nonmarine sandstone and calcareous sandstone, 

with lesser limestone beds. The Thirteen Finger limestone and 

overlying Atoka shale intervals are the reservoir and petroleum 

source rocks for the Thirteen Finger Limestone–Atoka Shale 

AU. Cyclical thin limestone and shale beds are the potential 

reservoirs. The Greater Granite Wash Composite AU is located 

in the deep basin in Oklahoma and Texas. Informally named 

granite wash reservoirs consist mainly of Desmoinesian to 

Virgilian arkosic shale to conglomerate. Granite wash lithofacies grade northward and interfinger with mostly marine strata 

of other AUs. The surrounding Desmoinesian and MissourianPermian AUs extend to the province boundaries. Desmoinesian, Missourian, and Virgilian strata were deposited in 

transgressive-regressive cycles that periodically inundated the 

province with alternating thin-bedded mainly marine sandstones, limestones, and shales that are stratigraphic packages 

of mostly sandstone or mostly limestone reservoirs. Desmoinesian AU reservoirs are clastic and carbonate beds of the 

Cherokee and Marmaton Groups, and their lateral equivalents. 

The Missourian-Permian AU includes Missourian, Virgilian, 

Wolfcampian, and Leonardian carbonate and clastic reservoirs. 

Assignment of petroleum source rocks to AUs was based 

mainly on previous research, analysis of well history and production data from proprietary databases, and 1D and 4D petroleum system models that were constructed for this project. 

The Devonian-Mississippian Woodford Shale was the primary 

petroleum source rock for Mississippian and lower Morrow 

Formation units. Overlying Morrowan through Permian strata 

were mainly sourced from Pennsylvanian black shales, including the Atokan Thirteen Finger limestone. 

The Anadarko Basin is the deepest basin in the onshore 

United States. It is markedly asymmetrical, with Precambrian 

basement ranging in depth from more than 40,000 ft at the 

basin axis in southern Oklahoma, to surface exposures on the 

broad shelf in the proximal Central Kansas uplift (CKU of 

Kansas). Ordovician through Pennsylvanian petroleum source 

rocks and potential source rocks in the shelf area are almost 

entirely thermally immature for oil generation. In the deep 

basin they range from marginally mature for oil generation 

to overmature for gas generation. Modeling indicates that oil 

generation began in the deep basin as early as 330 Ma in the 

Woodford Shale, 300 Ma in the Thirteen Finger limestone, 

and 270 Ma in Virgilian strata, which may contain the youngest petroleum source rock(s). Oil and gas were generated 

mostly in the deep basin and flowed radially northward. Flow 

in northern Oklahoma and in Kansas was directed toward the 

Las Animas arch, CKU, and Nemaha uplift. The Laramide 

orogeny may also have influenced petroleum migration 

through uplift and by imparting a subtle southeastern tilt to the 

basin, specifically resulting in redistribution of Panhandle field 

fluid columns with northward spilling of gas into the Hugoton 

embayment. Migration distances range from self-sourced for 

the Thirteen Finger Limestone–Atoka Shale AU, to long range 

from thermally mature source rocks in Oklahoma and Texas to 

reservoirs in Kansas and Colorado.

Acknowledgments

Chesapeake Energy generously provided well logs for 

use in cross sections and correlating strata across the province. 

Troy Cook of the USGS contributed EUR data for the Hugoton-Guymon fields and his expertise for the Anadarko Basin 

project. Larry Anna, Tom Judkins, and Sarah Hawkins of the 

USGS and Neil Suneson, of the University of Oklahoma, gave 

excellent technical reviews of this paper.

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Chapter 8

Present-Day Overpressure and 

Paleopressure Indicators in the Greater 

Anadarko Basin, Oklahoma, Texas, Kansas, 

and Colorado

By Philip H. Nelson and Nicholas J. Gianoutsos

Chapter 8 of 13

Petroleum Systems and Assessment of Undiscovered Oil and Gas 

in the Anadarko Basin Province, Colorado, Kansas, Oklahoma, and 

Texas—USGS Province 58

Compiled by Debra K. Higley

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Anadarko Basin, Oklahoma, Texas, Kansas, and Colorado, chap. 8, in Higley, D.K., comp., Petroleum systems and 

assessment of undiscovered oil and gas in the Anadarko Basin Province, Colorado, Kansas, Oklahoma, and Texas—

USGS Province 58: U.S. Geological Survey Digital Data Series DDS–69–EE, 28 p., http://dx.doi.org/10.3133/ds69EE.

ISSN 2327-638X (online)
iii

Plates

1. Pressure-depth plots for the Anadarko Basin in Oklahoma............................................. link

2. Resistivity logs in map position in the Anadarko Basin in Oklahoma ............................. link

3. Resistivity logs on west-east cross-section A-A’ .............................................................. link

4. Resistivity logs on south-north cross-section B-B’........................................................... link

5. Resistivity logs on south-north cross-section C-C’ ........................................................... link

6. Resistivity logs on south-north cross-section D-D’........................................................... link

Figures

1. Map showing study area encompassing the greater Anadarko Basin in western

Oklahoma, the Texas Panhandle, southwestern Kansas, and southeastern

Colorado. Areas studied by Breeze (1970) and Al-Shaieb and others (1994a,b) are

also shown. Basin axis coincides with deepest structural contours of the Woodford

Shale ...............................................................................................................................................2

2. Stratigraphic chart for the Anadarko Basin, from Higley (chapter 3 of this report).

Wavy lines represent unconformities. Areas with vertical lines represent periods of

non-deposition. (Camb., Cambrian; Miss., Mississippian).....................................................3

3. Burial history for the Ferris 1-28 well, from Carter and others (1998). Well location

is shown in figure 1. The times when overpressure and underpressure probably

developed are highlighted. (pC, Precambrian; C, Cambrian; O, Ordovician; S,

Silurian; D, Devonian; M, Mississippian; lP, Pennsylvanian; P, Permian; ^, Triassic;

J, Jurassic; K, Cretaceous;:, Paleocene; E, Eocene; O, Oligocene; M, Miocene;

FMS., Formations).........................................................................................................................4

4. Plots of pressure against depth for five areas A through E in the greater Anadarko

Basin. Each plot contains pressure data from wells within a 30- by 30-mile area

located in the index map. Faults in basement rocks bound the eastern and southern

parts of the basin. Pressure data designated by green letters representing geologic

periods are from Al-Shaieb and others (1994a). Pressure data from drillstem tests,

bottom-hole pressures, and mud weights are taken from IHS Energy (2009)....................6

Contents

Abstract...........................................................................................................................................................1

Introduction.....................................................................................................................................................1

Overpressure in Rocks of Pennsylvanian and Mississippian Age ........................................................4

Indicators of Paleopressure from Previous Work..................................................................................10

Indicators of Paleopressure from Reduction in Resistivity ..................................................................17

Procedure.............................................................................................................................................17

Results ..................................................................................................................................................20

Comparison of Overpressured and Paleopressured Areas..................................................................22

Summary and Conclusions.........................................................................................................................25

Acknowledgments.......................................................................................................................................25

References Cited..........................................................................................................................................25
iv

5. Map showing elevation of top of overpressure, based on data displayed in plate 1 .......7

6. Map showing outline of present-day overpressure in rocks of Desmoinesian age,

based on data from Al-Shaieb and others (1994a) and augmented with pressure

data from IHS Energy (2009). Contour lines and shading represent the ratio of

pressure to depth in pounds per square inch per foot (psi/ft) ..............................................8

7. Map showing outline of present-day overpressure in rocks of Morrowan and

Springer age, based on data from Al-Shaieb and others (1994a) and augmented by

pressure data from IHS Energy (2009). Contour lines and shading represent the

ratio of pressure to depth in pounds per square inch per foot (psi/ft).................................8

8.A, Nine overpressured compartments in Morrowan and Springer age rocks, from

Powley (1984). Elevation in feet (ft) of potentiometric surface H is given for each

area. B, Pressure as a function of elevation for three overpressured areas in

Morrow and Springer Formations, from Powley (1984). Pressure data are from oil

and gas fields and individual wells. Each line has a slope of 0.465 pounds per

square inch per foot (psi/ft).........................................................................................................9

9. Map showing contours of present-day pressure-depth ratios in the Morrow

Formation, showing change from overpressure [greater than 0.5 pounds per square

inch per ft (psi/ft)] to underpressure (less than 0.4 psi/ft), based on data from

Breeze (1970). Six named wells (small green circles) show well-log indicators of

paleopressure, as interpreted by Breeze (1970). Water chemistry falls into three

distinct types as shown by Stiff plots labeled X, Y, and Z, from Dickey and Soto

(1974). Each brown circle is the locus of several wells from which water samples

were taken ...................................................................................................................................10

10. Graphs showing indicators of paleopressure in mudrocks from resistivity, sonic,

and self potential (SP) logs in six wells from Breeze (1970). Well locations are

shown in figure 9 and in the inset map. Salinity of produced water from a nearby

well is also from Breeze (1970). Pressure data from wells within a 3- to 10-mile

distance from the designated well taken from Al-Shaieb and others (1994a). A,

Neely 1 well; B, Cheyenne-Arapahoe Unit 1 well; C, Raymond Moss 1 well; D,

Knabe 1 well; E, Kamp 1 well; and F, Fox 1 well.....................................................................11

11. Gamma-ray, resistivity, neutron, and density logs in the West Edmond SWD 1-24

well (location shown on plate 2). Resistivity trendline is based on lowest resistivity

values in mudrocks, which are represented by gamma-ray values in excess of 70

American Petroleum Institute (API) units (gray shading) and neutron porosity in

excess of 20 percent (brown shading). Low resistivity in sandstones (light yellow

shading) is attributed to saline water in the pore space. In this well, resistivity and

density in mudrocks increase steadily with depth and there is no indication of

paleopressure .............................................................................................................................18

12. Gamma-ray, resistivity, neutron, and sonic logs in the Bredy well. The resistivity

trendline is based on the lowest resistivity values in mudrocks above 9,000 feet,

which are represented by gamma-ray values in excess of 70 American Petroleum

Institute (API) units (gray shading) and neutron porosity in excess of 20 percent

(brown shading). In this well, the top of paleopressure is at 9,000 feet. Below the

top of paleopressure, resistivity in mudrocks decreases with increasing depth and

sonic slowness in mudrocks increases with depth..............................................................19

13. Map of the elevation of top of paleopressure as determined from resistivity logs.

Lines A–A’ through D–D’ show location of cross sections on plates 3–6. A resistivity

reversal was found in 107 wells (green circles) but was absent in 68 wells (red

triangles) ......................................................................................................................................20

14. Map of age of rock unit containing top of paleopressure, based on the depth where

the resistivity log changes from increasing downwards to decreasing downwards.

The green area includes rocks of either Morrowan or Springer age, or both.................21
v

15. Map showing extents of paleopressure and overpressure in rocks of Morrowan

and Springer age. The extent of the paleopressure indicator from resistivity logs is

derived from figure 14 and the extent of present-day overpressure from pressure

data is taken from figure 7. Modeled vitrinite reflectance contours of 0.8 and 1.2

percent for source rocks of Thirteen Finger lime of Atokan age taken from Higley

(chapter 7 of this report)............................................................................................................23

16. Map showing extents of paleopressure and overpressure in rocks of Desmoinesian

age. The extent of the paleopressure indicator from resistivity logs is derived from

figure 14 and the extent of present-day overpressure from pressure data is taken

from figure 6. Modeled vitrinite reflectance contours of 0.8 and 1.2 percent for

source rocks of Desmoinesian age taken from Higley (chapter 7 of this report)............24

17. Map showing extents of paleopressure and overpressure in rocks of Missourian

age. The extent of the paleopressure indicator from resistivity logs is derived from

figure 14. Modeled vitrinite reflectance contours of 0.8 and 1.0 percent for source

rocks of early Virgilian age taken from Higley (chapter 7 of this report) ..........................24

Appendix 1

 List of wells shown in plates 3–6..............................................................................................27

Conversion Factors

Inch/Pound to SI

Multiply By To obtain

Length

foot (ft) 0.3048 meter (m)

mile (mi) 1.609 kilometer (km)

Volume

barrel (bbl), (petroleum, 1 

barrel=42 gal) 0.1590 cubic meter (m3

) 

cubic foot (ft3) 0.02832 cubic meter (m3) 

Flow rate

cubic foot per day (ft3/d) 0.02832 cubic meter per day (m3/d)

Pressure

atmosphere, standard (atm) 101.3 kilopascal (kPa)

bar 100 kilopascal (kPa) 

pound per square inch (lb/in2) 6.895 kilopascal (kPa) 

Density

pound per cubic foot (lb/ft3) 16.02 kilogram per cubic meter (kg/m3)

pound per cubic foot (lb/ft3) 0.01602 gram per cubic centimeter (g/cm3)

Temperature in degrees Celsius (°C) may be converted to degrees Fahrenheit (°F) as follows:

°F=(1.8×°C)+32

Concentrations of chemical constituents in water are given either in milligrams per liter (mg/L) 

or micrograms per liter (μg/L).

Abstract

Formation fluids in Pennsylvanian strata of the Anadarko 

Basin are overpressured throughout the deep part of the 

basin, as known from previous studies. We take a closer look 

at the state of overpressuring, documenting the progressive 

deepening of the top of overpressure from north to south, the 

increasing vertical extent of overpressure from north to south 

as strata thicken, the compartmentalization of overpressure 

in strata of Desmoinesian and Morrowan age, and the areal 

extent of overpressure in these same strata. Resistivity logs 

distributed throughout the basin display trendline reversals, 

with resistivity decreasing with depth rather than continuing 

to increase along a normal compaction trend. These trendline 

reversals are interpreted as evidence of an overpressured state 

in which the pressure can either still be present or else has 

dissipated, a condition referred to herein as paleopressure. 

Areas where there are trendline reversals are called paleopressured areas. Paleopressured areas in rocks of Morrowan, 

Desmoinesian, and Missourian age are more than twice the 

size of present-day overpressured areas, indicating that the 

extent of present-day overpressured areas have contracted 

from paleopressured areas. We suggest that the contraction 

took place concurrently with the development of normal and 

subnormal pore pressures on the flanks of the basin when erosional processes exposed Permian and Pennsylvanian strata at 

the eastern edge of the basin.

Introduction

This study examines the distribution of present-day 

overpressure and the evidence that the extent of overpressure 

at one time occupied an area larger than the present-day distribution of overpressure within the greater Anadarko Basin. 

Chapter 9 of this report by Nelson and Gianoutsos, which 

also covers the study area of figure 1, examines the extent and 

cause of underpressure in the basin. Our two studies on formation fluid pressure were undertaken in support of and in parallel with the work reported by Higley (chapter 7 of this report) 

and Gaswirth (chapter 5 of this report) on the assessment of oil 

and gas in the Anadarko Basin. Previous studies dealing with 

fluid pressure in the basin from Breeze (1970) and Al-Shaieb 

and others (1994a, b) are cited extensively in this chapter of 

the report; their study areas are shown in figure 1. 

The elevation contours of the Woodford Shale illustrate 

the structure of the Anadarko Basin (fig. 1); a line drawn 

through the deepest part of the Woodford Shale serves to 

locate the deep basin in subsequent figures. Stratigraphic relations of Paleozoic rocks are shown in figure 2; further discussion of the geology of the basin is given by Higley (chapters 

5 and 7 of this report). A representative burial history plot 

(fig. 3) shows that during times of rapid burial, overpressure 

developed in rocks of the Morrowan, Atokan, Desmoinesian, 

Missourian, and to a lesser degree in the Virgilian Series, all of 

Pennsylvanian age, as indicated schematically by the highlighting in figure 3. The areal and stratigraphic distribution of 

overpressure and its contraction with time is the subject of this 

chapter of the report. 

In this chapter of the report, the term “present-day 

overpressure” or “overpressure” refers to fluid pressure 

measurements for which the ratio of measured pressure to the 

depth of measurement is greater than that of saline formation water, nominally 0.465 pounds per square inch per foot 

(psi/ft). Moreover, these terms refer to the pressure prior to the 

production of oil or gas, because pore pressure decreases as 

hydrocarbons are produced. Measurements of post-production 

pressures are generally less than pre-production pressure and, 

although of great interest to reservoir engineers, are considered noise in our studies. The term “paleopressure” refers to 

overpressure inferred to have existed in the past, either where 

there is no present-day overpressure or where overpressure 

in the geologic past was possibly greater than present-day 

overpressure. In this chapter of the report, paleopressured rock 

volumes are delineated by the departure of resistivity logs 

from a normal mudrock compaction trend.

This chapter of the report comprises four parts. In the 

first part, we review the overpressured zone delineated by 

Al-Shaieb and others (1994a, b), which is notable because 

of its large extent and the compartmentalization of pressure 

within it. Access to the dataset used by Al-Shaieb and others 

Present-Day Overpressure and Paleopressure Indicators 

in the Greater Anadarko Basin, Oklahoma, Texas, Kansas, 

and Colorado

By Philip H. Nelson and Nicholas J. Gianoutsos
2 Present-Day Overpressure and Paleopressure Indicators in the Greater Anadarko Basin

(1994a) has made it possible to reformat the pressure-depth 

plots and produce maps of pressure as a function of geologic 

age. An important characteristic of the overpressured zone 

in the Anadarko basin is its preservation for the 250 million 

years that have elapsed since the presumed onset of overpressure during Permian time. We will return to this point when 

comparing the overpressured area with the paleopressured area 

in the third part of this chapter of the report.

In the second part of this chapter of the report, we review 

previously published work on pressure, salinity, and well log 

reversals and then, in the third part, describe our own examination of well-log evidence for high pressure in strata of 

Pennsylvanian and Mississippian age. A decrease of resistivity 

with increasing depth (rather than an increase along a normal 

mudrock compaction trend) is an indicator that rocks are not 

normally compacted (Bigelow, 1994). The lack of complete 

compaction can be attributed to either of two causes. (1) During burial, the rocks were partially prevented from compacting 

by pore pressure that remained higher than normal. This can 

happen if pore water is prevented from escaping from the pore 

space, so the pore water bears part of the vertical stress, a phenomenon referred to as disequilibrium compaction. (2) Excess 

pressure arises during the generation of oil and gas because 

of a volume increase in the amount of fluid in the pore space, 

causing microcracks to open within the rock. Microcracks that 

opened during generation of excess pressure remain partially 

open, with consequent reductions of resistivity and sonic 

velocity. Regardless of how the excess pressure was generated, if that pressure is maintained, either in whole or in part 

into the present day, then the excess pressure is measurable as 

overpressure. If the pressure from either of these two causes 

was not maintained but diminished either partly or entirely at 

some time in the past, then we refer to it as paleopressure. In 

this chapter of the report, the reversals in resistivity logs are 

called a “paleopressure indicator” and the rock volume thus 

affected is referred to as being paleopressured. 

In the fourth part of this chapter of the report, we compare the overpressured and paleopressured areas with levels of 

thermal maturity obtained from basin modeling, finding that 

the highest levels of thermal maturity nearly coincide with 

the highest levels of present-day overpressure. We show that 

the area of the Anadarko Basin where resistivity reversals are 

present (the geographic extent of paleopressure) is greater than 

(and includes) the present-day overpressured zone delineated 

by Al-Shaieb and others (1994a, b). The main finding of this 

chapter of the report is the inferred contraction in horizontal 

Figure 1. Map showing study area encompassing the greater Anadarko Basin in western 

Oklahoma, the Texas Panhandle, southwestern Kansas, and southeastern Colorado. Areas 

studied by Breeze (1970) and Al-Shaieb and others (1994a,b) are also shown. Basin axis 

coincides with deepest structural contours of the Woodford Shale. 

0

-8,000

-2,000

1,000

-4,000

-10,000

-12,000

-14,000

-16,000 -18,000

2,000

-2,000

0

-20,000

-6,000

-2,000

-4,000

-2,000

0

2,000

0

-4,000

-4,000

-6,000

-8,000

-8,000

Breeze (1970)

Al-Shaieb & others (1994a,b)

This study

Reference well

COLORADO

OKLAHOMA

TEXAS

KANSAS

Basin axis

Faults in basement rocks

EXPLANATION

Elevation of top of Woodford 

 Shale, in feet

102° 100°

36°

37°

38°

39°

35°

34°

98° 96°

0 15 30 MILES

0 15 30 KILOMETERS

Nelson_Ch8_Figure 1
Introduction 3

Figure 2. Stratigraphic chart for the Anadarko Basin, from Higley (chapter 3 of this 

report). Wavy lines represent unconformities. Areas with vertical lines represent 

periods of non-deposition. (Camb., Cambrian; Miss., Mississippian).

Sumner Group, Enid Group, Hennessey Group

System

Series Lithostratigraphic Unit

Permian (part) Pennsylvanian Miss. Devonian Silurian Ordovician Camb.

Leonardian

Wolfcampian

Virgilian

Missourian

Desmoinesian

Atokan

Morrowan

Chesterian

Meramecian

Osagean

Kinderhookian

Chautauquan

Cayugan

Cincinnatian

Trempealeauan

Niagaran

Canadian

Champlainian

Chase Group

Admire Group

Lansing Group 

Marmaton Group

Atoka Group

Morrow Group/Formation

Springer Formation

Chester Group 

Wabaunsee Group

Shawnee Group

Douglas Group

Ada Group

Franconian

Woodford Shale

Misener sand

Hunton Group

Sylvan Shale; Maquoketa Shale 

Simpson Group

Arbuckle Group

Reagan Sandstone

Alexandrian

Senecan

Council Grove Group Pontotoc Group

Viola Group/Formation

Meramec lime

Osage lime

Mayes Group

Kansas City Group Hoxbar Group

Cherokee Group Deese Group

Kinderhook Shale

Erian

Ulsterian

Guadalupian Whitehorse Group; El Reno Group

Nelson_Ch8_Figure 2
4 Present-Day Overpressure and Paleopressure Indicators in the Greater Anadarko Basin

and vertical extent of the paleopressured rock volume to its 

smaller present-day overpressured volume. Some speculative ideas on the timing of the contraction are included in the 

fourth part of the chapter.

Overpressure in Rocks of 

Pennsylvanian and Mississippian Age

Al-Shaieb and others (1994a, b) used 4,439 reservoir-pressure data points to map the pressure regime in the Oklahoma 

and Texas portions of the Anadarko Basin. Sources were (1) 

pressures calculated from static initial wellhead shut-in pressures (2,579 points), (2) shut-in pressures from drillstem tests 

(1,787 points), and (3) recorded bottom-hole pressures from 

P/Z plots in production records (73 points). Their primary finding was the delineation of a large overpressured volume called 

the megacompartment complex (designated Level 1, with lateral dimensions of 100 miles) that contains sub-compartments 

within a single stratigraphic interval (Level 2 compartments, 

with lateral dimensions of tens of miles). Nested within Level 2 

compartments are Level 3 compartments, with lateral dimensions of a few miles, that are linked to depositional facies 

within reservoirs. The megacompartment complex is bounded 

by the Woodford Shale at the base, and by major structural 

offsets on the south. The top of the overpressured zone lies 

between depths of 7,500 and 10,000 feet (ft) and crosses stratigraphic boundaries. The northern edge is formed by the convergence of the top and basal boundaries as strata thin to the north.

Figure 3. Burial history for the Ferris 1-28 well, from Carter and others (1998). Well location 

is shown in figure 1. The times when overpressure and underpressure probably developed 

are highlighted. (pC, Precambrian; C, Cambrian; O, Ordovician; S, Silurian; D, Devonian; 

M, Mississippian; lP, Pennsylvanian; P, Permian; ^, Triassic; J, Jurassic; K, Cretaceous;:, 

Paleocene; E, Eocene; O, Oligocene; M, Miocene; FMS., Formations).

Carter et al., 1998 

Burial history for Ferris 1-28 well.

pC C O S D M P P J K E O M

0

2,000

4,000

6,000

8,000

10,000

12,000

600 500 400 300 200 100 0

225 ̊C

200 ̊C

175 ̊C

150 ̊C

125 ̊C

100 ̊C

75 ̊C

50 ̊C

25 ̊C

Guadalupian

Leonardian

Wolfcampian

VirgilianMissourian

DesmoinesianAtokan

MorrowanSpringer Fms.

Mississippian

SYLVAN SHALE

Hunton Group

Viola-simpson Fms.

ArbuckleReagan Fms.

Time, in millions of years

Depth, in meters

Ochoan

Nelson_Ch8_Figure 3





Development of

underpressure

Development of

overpressure

WOODFORD SHALE
Overpressure in Rocks of Pennsylvanian and Mississippian Age 5

We have combined data from Al-Shaieb and others 

(1994a) with data extracted from a commercial database (IHS 

Energy, 2009) to provide illustrative examples of pressuredepth plots from various parts of the basin (fig. 4). These 

examples demonstrate underpressure in the northwestern 

part of the basin (A and B of fig. 4), normal pressure on the 

northern flank (C of fig. 4), and overpressure in the deep 

basin (D and E of fig. 4). Underpressure is revealed by the 

slight gap between the mud-weight pressures, which track the 

0.465 psi/ft line, and the drillstem-test pressures in A and B of 

figure 4. Underpressure in the Missourian-Virgilian and Morrowan rocks was mapped but not discussed by Al-Shaieb and 

others (1994a). The characterization and cause of underpressure in the greater Anadarko Basin is the subject of chapter 

9 of this report by Nelson and Gianoutsos. Normal pressure 

is shown where the drillstem-test pressures coincide with the 

mud-weight pressures on the 0.465 psi/ft line as illustrated in 

figure 4C and at depths shallower than 10,000 ft in figure 4D. 

(Because many of the pressures from drillstem tests are lower 

than the actual pore pressure, because of either inadequate 

tests or to reservoir depletion, only the righthand edge of the 

drillstem-test data field should be considered as representative 

of pore pressure.)

Overpressure is present in rocks of Desmoinesian and 

Morrowan age as shown in figure 4D. Evidence of the compartmentalization cited by Al-Shaieb and others (1994a) is 

seen where the pressures in Morrowan rocks reach a maximum pressure-depth ratio of nearly 1.0 psi/ft, whereas the 

pressures in Desmoinesian rocks reach a lesser maximum of 

nearly 0.9 psi/ft. As pore pressure builds, drillers increase the 

mud weight to maintain control of the well while drilling. 

The mud-weight and drillstem-test pressures shown in D and 

E of figure 4 are consistent with the pressures compiled by 

Al-Shaieb and others (1994a), keeping in mind that the two 

datasets were not taken from the same wells but represent all 

wells with data in a 30- by 30-mile area. 

The complete dataset for Oklahoma of Al-Shaieb and 

others (1994a) is displayed in 28 pressure-depth plots in plate 

1. Each pressure-depth plot incorporates all data in a block of 8 

to 15 townships. Many of the blocks (blocks B, C, F–O, R, and 

S on the index map in plate 1) are three townships (18 miles) 

in the south-north direction and four townships (24 miles) in 

the west-east direction; other blocks have comparable areas 

but different shapes. Grouping the data in this way permits 

inspection of the pressure-depth profiles and selection of the 

top of overpressure as a function of location; the pressure-depth 

trends cannot be examined in individual wells because a single 

well typically contributes only a few pressure measurements. 

Some observations regarding the relations among pressure, 

depth, and location within the basin are:

(1) The presence of megacompartments pointed out by 

Al-Shaieb and others (1994a, b) can be seen as a step increase 

in pressure with depth in Desmoinesian and Morrowan age 

rocks in blocks H, I, L, and M. Another step increase in pressure with depth takes place between Atokan/Desmoinesian and 

Morrowan rocks in block S. 

(2) Below the overpressured intervals in Desmoinesian 

and Morrowan rocks in blocks H, I, J, and L, pressures return 

to normal in underlying rocks of Silurian age. The pressure 

regression supports the statement of Al-Shaieb and others 

(1994a, b) that the Devonian Woodford Shale is the base of the 

overpressured interval. In other blocks, the return to normal 

pressure at depth cannot be observed because rocks deeper 

than Morrowan were not penetrated. An exception occurs in 

the southeastern part of the study area in blocks Z and ZZ 

where Ordovician rocks are overpressured.

(3) Overpressured conditions prevail to a depth of 

20,000 ft in rocks of Mississippian age in blocks X and Y.

(4) Normal to subnormal pressures prevail in blocks A–E 

on the northern flank of the area. The northernmost appearance of overpressure in Desmoinesian and Morrowan rocks is 

in blocks F and G in portions of T. 18-20 N. Normal pressures 

prevail in rocks of various ages on the east side of the basin in 

blocks Q, W, and YY.

(5) In general, the top of overpressure deepens from 

north to south. The top of overpressure is here defined as the 

depth below which several points have pressure-depth ratios 

exceeding 0.5 psi/ft. Examining the north to south progression 

in R. 11-14 W., the top of overpressure is located at depths 

of approximately 6,500 ft in block G, 8,100 ft in block K, 

10,100 ft in block O, and 13,000 ft in block U. A similar deepening of the top of overpressure can be observed in blocks F, J, 

N, and T in R. 15-18 W. 

The top of overpressure was determined for each of the 

28 blocks shown in the index map on plate 1. Because the top 

of overpressure is determined by the depth of the shallowest overpressured measurements, and because there may be 

overpressured rocks above that depth for which no pressure 

was determined, it is likely that the top of overpressure is 

shallower in those blocks with sparse data, but it is unlikely 

that the top of overpressure is deeper than the selected depth. 

The depth of the top of overpressure and the average surface 

elevation was determined for each of the 28 blocks, and the 

elevation of the top of overpressure relative to sea level was 

then computed. The resulting contour map (fig. 5), based on 

28 points and with a limited extension into the Texas Panhandle, shows the basinward drop in the top of overpressure from 

elevations above -6,000 ft to elevations deeper -10,000 ft. 

No comparable map was presented by Al-Shaieb and others (1994a), although the map in figure 5 appears compatible 

with the top of overpressure illustrated on a cross section 

(Al-Shaieb and others 1994a, figure 11).

Al-Shaieb and others (1994a) presented pressure-contour maps of the (1) Missourian/Virgilian interval (showing 

mostly normal pressures), (2) Desmoinesian Red Fork Sandstone (showing pressure-depth ratios exceeding 0.8 psi/ft), 

(3) Morrowan Series (showing pressure-depth ratios exceeding 

0.9 psi/ft), and (4) Hunton Group (showing a return to normal pressure below the base of the Woodford Shale, with the 

exception of one overpressured value of 0.74 psi/ft attributed 

to an isolated Hunton compartment). Using their digital dataset 

augmented by pressure data from IHS Energy (2009), we 
Figure 4. Plots of pressure against depth for five areas A through E in the greater Anadarko Basin. Each plot contains pressure data from welarea located in the index map. Faults in basement rocks bound the eastern and southern parts of the basin. Pressure data designated by green geologic periods are from Al-Shaieb and others (1994a). Pressure data from drillstem tests, bottom-hole pressures, and mud weights are taken 

Depth, in feet

0

25,000

Pressure, in pounds per square inch 0 25,000

1.0 psi/ft 0.465 psi/ft

Mud weights

M Morrowan 

Bottom-hole 

pressure

Drillstem tests

0.9 0.70.8 0.50.6

Latitude 35.18 to 35.63Longitude -100.01 to -99.47

Drillstem tests

Mud weights

O Ordovician 

A Atokan

R Missourian

C Mississippian 

D Desmoinesian 

COLORADO

TEXAS O

KANSAS

A B 

A B C

D E

Latitude 35.18 to 35.63Longitude -98.93 to -98.39

Latitude 36.53 to 36.98Longitude -100.55 to -100.01

Latitude 36.53 to 36.98Longitude -102.17 to -101.63

102° 100°

36°

37°

38°

39°

35°

34°

EXPLANATION

Basin axis

Faults in basement  rocks
Overpressure in Rocks of Pennsylvanian and Mississippian Age 7

Figure 5. Map showing elevation of top of overpressure, based on data displayed in plate 1.

created outlines of present-day overpressure for the Morrowan 

and Desmoinesian series (figs. 6 and 7). The Desmoinesian 

outline (fig. 6), which includes pressures measured in rocks of 

Desmoinesian age, extends farther north and west than the area 

mapped by Al-Shaieb and others (1994a), which is restricted to 

pressures measured in the Desmoinesian Red Fork Sandstone. 

The outer boundary includes measurements with pressuredepth ratios greater than 0.5 psi/ft and the inner boundary 

shows the area of highest pressure with pressure-depth ratios 

greater than 0.7 psi/ft. The southern edge of the outer boundary 

is drawn in close proximity to the bounding fault. 

The Morrowan outline (fig. 7), which includes pressures 

measured in rocks of Morrowan and Springer age, follows the 

outline established by Al-Shaieb and others (1994a) except 

in Dewey County of Oklahoma, where the outline extends 

roughly 10 miles farther to the north. The eastern edge coincides with the truncation edge of Morrowan age rocks. The 

southern edge is drawn in close proximity to the bounding 

fault. Pressure compartments within the Morrow and Springer 

Formations (fig. 8A) were outlined by Powley (1984) in a 

study for Amoco. Amoco data were incorporated in the work 

of Al-Shaieb and others (1994a), and the boundaries of the two 

studies are similar. Moreover, Powley (1984) delineated nine 

pressure compartments within the Morrow and Springer Formations, each characterized by distinctive pressure-elevation 

relations with a unique potentiometric surface H calculated 

from H(ft) = Z(ft) + P(psi)/0.465, where Z is elevation and P

is pressure. Eight of the nine compartments are overpressured, 

as shown by values of H that are greater than normal values 

of 2,000 to 3,500 ft (fig. 8A). Pressure-elevation plots for 

three of the nine areas demonstrate that differences in pressure 

between compartments is on the order of several thousand psi 

and that pressure gradients are around 0.465 psi/ft (fig. 8B). 

The determination of pressure-depth gradients of 0.465 psi/ft, 

equivalent to the density of a moderately saline brine, shows 

that elevated hydrostatic gradients prevail over substantial 

areas within strata of Morrowan and Springer age. Thus, these 

overpressured compartments are water-dominated, and gas and 

oil accumulations within the compartments can be expected to 

be in buoyant equilibrium with water. 

Nelson_Ch8_Figure 5

KANSAS

TEXAS

OKLAHOMA

-6,000

-7,000

-8,000

-9,000

-10,000

EXPLANATION

Elevation of top of

 overpressure, in feet

Faults in basement

 rocks

Basin axis

103° 102° 101° 100° 99° 98° 97° 96°

38°

37°

36°

35°

34°

0 15 30 MILES

0 15 30 KILOMETERS
8 Present-Day Overpressure and Paleopressure Indicators in the Greater Anadarko Basin

Figure 7. Map showing outline 

of present-day overpressure 

in rocks of Morrowan and 

Springer age, based on data from 

Al-Shaieb and others (1994a) and 

augmented by pressure data from 

IHS Energy (2009). Contour lines 

and shading represent the ratio of 

pressure to depth in pounds per 

square inch per foot (psi/ft).

Outline of present-day overpressure 

in rocks of Morrowan and Springer age

0.5 psi/ft

0.7 psi/ft

TEXAS

OKLAHOMA

KANSAS

DEWEY 

CO.

EXPLANATION

Faults in basement

 rocks

Basin axis

103° 102° 101° 100° 99° 98° 97° 96°

38°

37°

36°

35°

34°

0 15 30 MILES

0 15 30 KILOMETERS

Figure 6. Map showing outline 

of present-day overpressure 

in rocks of Desmoinesian age, 

based on data from Al-Shaieb and 

others (1994a) and augmented 

with pressure data from IHS 

Energy (2009). Contour lines and 

shading represent the ratio of 

pressure to depth in pounds per 

square inch per foot (psi/ft). 

Nelson_Ch8_Figure 6

Outline of present-day overpressure

in rocks of Desmoinesian age

0.5 psi/ft

0.7 psi/ft

TEXAS

OKLAHOMA

KANSAS

EXPLANATION

Faults in basement

 rocks

Basin axis

103° 102° 101° 100° 99° 98° 97° 96°

38°

37°

36°

35°

34°

0 15 30 MILES

0 15 30 KILOMETERS
Overpressure in Rocks of Pennsylvanian and Mississippian Age 9

Figure 8. A, Nine overpressured compartments in Morrowan 

and Springer age rocks, from Powley (1984). Elevation in feet (ft) of 

potentiometric surface H is given for each area. B, Pressure as a 

function of elevation for three overpressured areas in Morrow and 

Springer Formations, from Powley (1984). Pressure data are from oil and 

gas fields and individual wells. Each line has a slope of 0.465 pounds per 

square inch per foot (psi/ft). 

–6,000

–8,000

–10,000

–12,000

–14,000

–16,000

–18,000

–20,000

–22,000

Elevation, in feet

Pressure, in psi

4,000 8,000 12,000 16,000 20,000

Deep Basin

 +19,300 ft

North Basin Flank +13,800 ft

Canadian Area +6,800 ft

–101° –100° –99° –98° 97° 37°

36°

35°

34°

0 15 30 MILES

0 15 30 KILOMETERS

A

B

Canadian Area

North Basin Flank

Deep Basin

EXPLANATION

Basin axis

Faults in basement

 rocks

TEXAS

OKLAHOMA

Morrowan truncation 

 edge

Bounds of pressure 

 compartments

+6,800

ft

+13,800 ft

+8,500 ft

+4,400 ft

+10,500 

 ft

+8,500 

 ft

-1,600

 ft +6,500 

 ft

+19,300 ft

Nelson_Ch8_Figure 8
10 Present-Day Overpressure and Paleopressure Indicators in the Greater Anadarko Basin

Indicators of Paleopressure from 

Previous Work

In the course of investigating the cause of underpressure 

in the Morrowan sandstones of the northwestern Anadarko 

Basin, Breeze (1970) examined the characteristics of sonic 

logs, resistivity logs, and formation water salinity in six wells 

(fig. 9). The data from Breeze (1970), presented in the first 

three columns of figures 10A–10F of this chapter of the report, 

show increasing resistivity and decreasing sonic slowness1 of 

mudrocks in the upper part of each well, followed by reversals 

in these trends in the lower part of each well. The maximum 

resistivity at the top of the reversal in the six wells is about 

10 ohm-m, and the minimum sonic slowness is 70 to 75 

(μs/ft). However, the density logs show a steady increase of 

density with depth with no reversals and hence do not show 

evidence of undercompaction (density logs shown by Breeze 

for the six wells of figures 10A–10F are not reproduced here).

1

 Sonic slowness, also called sonic travel time, is the inverse of sonic 

velocity. Slowness is measured by sonic logs and presented in units of microseconds per foot (μs/ft). The term “slowness” will be used throughout the 

remainder of this chapter of the report.

Pressure data, shown in the right-hand plot of figures 

10A-10F, behaves quite differently than the sonic and resistivity logs and formation water salinities. Present-day pressure varies from greater than hydrostatic (overpressured) in 

the Neely 1 well (fig. 10A), which is the southeasternmost of 

the six wells, to moderately overpressured in the CheyenneArapahoe Unit 1 well (fig. 10B), to normally pressured in 

the Raymond Moss and Knabe 1 wells (figs. 10C and 10D), 

to underpressured in the Kamp and Fox wells (figs. 10E and 

10F). Thus, the present-day pressure ranges from overpressure to underpressure in a line of wells (fig. 9) in which the 

sonic and resistivity logs suggest overpressured conditions in 

mudrocks. Breeze (1970, p. 73) decided that the conditions 

producing the well log reversals differed from present-day 

conditions, “It is therefore concluded that the entire area 

was once subject to a similar history of deposition that left 

undercompacted shales as evidence.” The thesis of this report 

follows the same line of reasoning.

The salinity of formation water, which is around 

100,000 ppm total dissolved solids in the upper part of each 

well, decreases in the lower part of each well to values about 

one-third of the values in the upper part (figs. 10A–10F). Water 

chemistry over a more extensive area was also reported by 

Figure 9. Map showing contours of present-day pressure-depth ratios in the Morrow 

Formation, showing change from overpressure [greater than 0.5 pounds per square inch per 

ft (psi/ft)] to underpressure (less than 0.4 psi/ft), based on data from Breeze (1970). Six named 

wells (small green circles) show well-log indicators of paleopressure, as interpreted by 

Breeze (1970). Water chemistry falls into three distinct types as shown by Stiff plots labeled 

X, Y, and Z, from Dickey and Soto (1974). Each brown circle is the locus of several wells from 

which water samples were taken.

X

Y

Z

Fox 1 Kamp 1

Knabe 1

0.3 0.4

Neely 1

0.5 0.6 0.7 psi/ft

Cheyenne-Arapahoe 1

Basin axis

TEXAS

OKLAHOMA

COLORADO KANSAS

102° 101° 100° 99° 98° 97°

38°

37°

36°

35°

34°

103° 96°

0 15 30 MILES

0 15 30 KILOMETERS

EXPLANATION

Pressure-depth ratio

 in Morrow Formation

 in psi/ft

Basin axix

Morrow truncation

 edge

Locations of wells

 in figure 10

Na/1,000

Ca/1,000

Mg/100

Cl/1,000

HCO3 /10

SO4

/10

Stiff plot

Wells with water 

 chemistry

Raymond Moss 1
Figure 10. Graphs showing indicators of paleopressure in mudrocks from resistivity, sonic, and self potential (SP) logs in six wells from Blocations are shown in figure 9 and in the inset map. Salinity of produced water from a nearby well is also from Breeze (1970). Pressure datto 10-mile distance from the designated well taken from Al-Shaieb and others (1994a). A, Neely 1 well; B, Cheyenne-Arapahoe Unit 1 well; CD, Knabe 1 well; E, Kamp 1 well; and F, Fox 1 well. Water salinity, in parts per million of sodium chloride 104 105 106

Salinity from SP logProduced water

Hall-Jones Oil CorporationNeely 1 sec. 9, T. 14 N., R. 11 W. 

Resistivity, in ohm-meter

Depth, in feet

4,0005,0006,0007,0008,0009,000

10,00011,000

Missourian

Desmoinesian

Atokan

Morrowan

Sonic slowness, in micro

seconds per feet

60 70 80 90 100

Resistive shale cap

Pressure, in p

1 10 0 2,000 4

A Well with overpressure and well log reversals

0.465

EXPLANATION
Figure 10. Graphs showing indicators of paleopressure in mudrocks from resistivity, sonic, and self potential (SP) logs in six wells from Brlocations are shown in figure 9 and in the inset map. Salinity of produced water from a nearby well is also from Breeze (1970). Pressure dat3- to 10-mile distance from the designated well taken from Al-Shaieb and others (1994a). A, Neely 1 well; B, Cheyenne-Arapahoe Unit 1 welwell; D, Knabe 1 well; E, Kamp 1 well; and F, Fox 1 well.—Continued

3,0004,0005,0006,0007,0008,0009,000

10,000

Pan American Petroleum Corp.Cheyenne-Arapaho Unit 1 Sec. 30, T. 19 N., R. 13 W.

100 104 105 106

Missourian

Desmoinesian

Atokan

Morrowan Mississippian

Virgilian

1 10 60 0 2,000 4,0

B Well with overpressure and well log reversals

0.465 0.50

Loca

Salinity from SP logProduced water

EXPLANATION

Water salinity, in parts per million

of sodium chloride

Resistivity, in ohm-meter

Depth, in feet

Sonic slowness, in micro

seconds per feet

Pressure, in p

O
Figure 10. Graphs showing indicators of paleopressure in mudrocks from resistivity, sonic, and self potential (SP) logs in six wells from Brelocations are shown in figure 9 and in the inset map. Salinity of produced water from a nearby well is also from Breeze (1970). Pressure data 10-mile distance from the designated well taken from Al-Shaieb and others (1994a). A, Neely 1 well; B, Cheyenne-Arapahoe Unit 1 well; C, RaKnabe 1 well; E, Kamp 1 well; and F, Fox 1 well.—Continued

4,0005,0006,0007,0008,0009,000

10,000

Continental Oil Corporation

Raymond Moss 1 

100 104 105

Missourian

Desmoinesian

Atokan

Morrowan

Virgilian

Mississippian

1 10 60 0 2,000 

Sec. 16, T. 19 N., R. 19 W.

C Well with normal pressure and well log reversals

0.465

Lo

Water salinity, in parts per million

of sodium chloride

Resistivity, in ohm-meter

Depth, in feet

Sonic slowness, in micro

seconds per feet

Pressure, in 
Figure 10. Graphs showing indicators of paleopressure in mudrocks from resistivity, sonic, and self potential (SP) logs in six wells from Breezshown in figure 9 and in the inset map. Salinity of produced water from a nearby well is also from Breeze (1970). Pressure data from wells withfrom the designated well taken from Al-Shaieb and others (1994a). A, Neely 1 well; B, Cheyenne-Arapahoe Unit 1 well; C, Raymond Moss 1 welwell; and F, Fox 1 well.—Continued

0.465

3,0004,0005,0006,0007,0008,0009,000

10,000

W. G. Rogers Knabe 1 

100 104 105 106

Virgilian

Missourian

Desmoinesian

Atokan

Morrowan

Mississippian

60 0 2,000 

D Well with normal pressure and well log reversals

0.465

Sec. 22, T. 23 N., R. 20 W.

1 10

Water salinity, in parts per million

of sodium chloride

Resistivity, in ohm-meter

Depth, in feet

Sonic slowness, in micro

seconds per feet

Pressure, in 

L

Salinity from SP logProduced water

EXPLANATION
Figure 10. Graphs showing indicators of paleopressure in mudrocks from resistivity, sonic, and self potential (SP) logs in six wells from Breezare shown in figure 9 and in the inset map. Salinity of produced water from a nearby well is also from Breeze (1970). Pressure data from wells distance from the designated well taken from Al-Shaieb and others (1994a). A, Neely 1 well; B, Cheyenne-Arapahoe Unit 1 well; C, Raymond Mwell; E, Kamp 1 well; and F, Fox 1 well.—Continued

3,0004,0005,0006,0007,0008,0009,000

10,000

Phillips Petroleum Corp.Kamp 1 

100 104 105 106

Virgilian

Missourian

Desmoinesian

Atokan

Morrowan

Mississippian

1 10 60 0 2,000 

Sec. 3, T. 1 N., R. 28 E.

E Well with underpressure and well log reversals

0.465

Salinity from SP logProduced water

EXPLANATION

Water salinity, in parts per million

of sodium chloride

Resistivity, in ohm-meter

Depth, in feet

Sonic slowness, in micro

seconds per feet

Pressure, in 

L
Figure 10. Graphs showing indicators of paleopressure in mudrocks from resistivity, sonic, and self potential (SP) logs in six wells from Breeare shown in figure 9 and in the inset map. Salinity of produced water from a nearby well is also from Breeze (1970). Pressure data from wells distance from the designated well taken from Al-Shaieb and others (1994a). A, Neely 1 well; B, Cheyenne-Arapahoe Unit 1 well; C, Raymond Mwell; E, Kamp 1 well; and F, Fox 1 well.—Continued

3,0004,0005,0006,0007,0008,0009,000

10,000

Horizon Oil and Gas Co.Fox 1 

100 104 105 106

Virgilian

Missourian

Desmoinesian

Atokan

Morrowan

Mississippian

1 10 60 0 2,000 

Sec. 28, T. 1 N., R. 19 E.

F Well with underpressure and well log reversals

0.465

Salinity from SP logProduced water

EXPLANATION

Water salinity, in parts per million

of sodium chloride

Resistivity, in ohm-meter

Depth, in feet

Sonic slowness, in micro

seconds per feet

Pressure, in 

Lo
Indicators of Paleopressure from Reduction in Resistivity 17

Dickey and Soto (1974), as shown by the Stiff diagrams in 

figure 9. Water types X, Y, and Z of figure 9 were defined by 

Dickey and Soto (1974) to distinguish three compositional 

groups. Water chemistry changes from moderate salinity 

(30,000–80,000 mg/L) sulfate waters of the chloride-calcium 

type X in the northwest, to typical connate high-salinity 

(100,000–200,000 mg/L) brines of the chloride-calcium type Y, 

to a low-salinity (10,000–30,000 mg/L) high-bicarbonate type 

Z. The type Z samples are located in the area studied by Breeze. 

Dickey and Soto (1974, p. 116) attempted to explain the presence of waters of a similar chemistry (type Z) throughout the 

transition from apparent overpressure to underpressure (fig. 9), 

first stating that “if the type Z water is meteoric in origin, it cannot be circulating now,” and then concluding that “the abnormally high pressure in the Morrow sand and the presence of 

the dilute type Z water in that area indicate that they have been 

effectively isolated hydraulically. The relatively dilute waters, 

therefore, may not be of meteoric origin, but rather water somehow removed from the normal processes of concentration.” In 

summary, both water chemistry and petrophysical properties 

reflected in the well logs indicate that the current pressure state 

of the Morrow Formation differs from an earlier condition.

Indicators of Paleopressure from 

Reduction in Resistivity

Following the finding by Breeze (1970), we examined 

resistivity logs from the Anadarko deep basin and shelf in 

Oklahoma, Texas, and Kansas. Our collection of sonic logs 

was not adequate for interpreting indicators of paleopressure, 

but the resistivity logs provided enough coverage and consistency that a shale trendline could be determined. 

Procedure

Approximately 175 resistivity logs were inspected 

for indications of paleopressure. A resistivity trendline was 

established in each well based on the resistivity of mudrocks 

in strata below the evaporites and limestones of Permian age 

(figs. 11and 12). Mudrocks were identified by high gamma-ray 

and high neutron porosity readings, which were made distinguishable by shading the gamma-ray log where it exceeded 

70 American Petroleum Institute (API) units and by shading 

the neutron log where it exceeded a neutron porosity of 20 

percent—this rule of thumb was varied somewhat in wells 

where the gamma-ray or neutron log required shifting. The 

resulting trendline represents the normal resistivity compaction trend for that well. In many wells, the resistivity log 

follows the trendline without a reversal throughout the Pennsylvanian siliciclastic sequence, as in the example of the West 

Edmond well (fig. 11). The resistivity is less than the trendline 

in sandstones, as indicated by yellow shading in the resistivity curve, but not in the mudstones. Because no resistivity 

reversal is discernible in the West Edmond well, rocks in this 

area were either never overpressured or else the paleopressure signature was not retained. The density log also increases 

steadily with depth, also indicating a normal compaction trend.

In other wells, the resistivity trend in mudstones reverses 

and decreases with depth rather than continuing to increase 

along the trendline. The depth of the first clear separation 

between the resistivity log and the trendline is selected and 

recorded; this depth is considered to be the top of paleopressure. For example, in the Bredy well (fig. 12), the top of 

paleopressure is located at a depth of 9,000 ft. Resistivity then 

decreases further with depth below the top of paleopressure 

although the trendline indicates that resistivity would increase 

in the absence of the effect of paleopressure; the separation 

between the two is made visible by the red shading. Within 

the Springer Formation at 14,800 ft, resistivity in mudstones 

is around 2 ohm-m where the trendline value is greater than 

10 ohm-m. The sonic slowness in mudrocks tends to be 

higher within the paleopressured zone rather than lower as it 

would be under a normal compaction gradient. For example, 

at depths of 7,000 and 8,400 ft, sonic slowness is around 

80 (μs/ft), but in deeper zones where resistivity is less than the 

resistivity trendline, as at 12,300 and 14,300 ft, the sonic slowness is around 90 μs/ft. 

After eliminating wells that were not suitable for our study 

because of incomplete well logs or insufficient depth of penetration, 175 wells were used in this study. Of these, 68 wells 

displayed no reversal in the resistivity log, that is, the resistivity 

of mudrocks increased steadily along the trendline determined 

for that well. Wells in which the resistivity reversal is absent 

establish the eastern, western, and northern limits of the area 

of paleopressure. The top of paleopressure was established in 

the remaining 107 wells and based on formation tops for each 

well, the approximate geologic age of the top of paleopressure was assigned in terms of Pennsylvanian provincial series 

(Morrowan, Atokan, Desmoinesian, Missourian, or Virgilian). 

Formation tops of Springer age were included within the Morrowan Series. Twenty-four wells in the northwestern part of 

the study area display reduced resistivity values in the Morrow 

Formation but not above or below the Morrow. 

Selected resistivity logs are presented in map format on 

plate 2 to provide an overview of the resistivity variations 

throughout the Anadarko Basin. The geographic variation of 

resistivity and paleopressure indicators can also be examined 

on one west-east (pl. 3) and three south-north cross sections 

(pls. 4–6). The tops of one formation boundary and four provincial series boundaries are also shown on plates 3–6, along with 

a line labeled “top of paleopressure,” that marks the shallowest 

depth where resistivity falls below the trendline value. The locations and elevations of the resistivity reversals for the 44 wells 

on the four cross sections in plates 3–6 are given in Appendix 1. 

The top of the reversal in resistivity could be picked with 

a high level of certainty in some wells but with less certainty 

in other wells, depending on such factors as the thickness and 

abundance of mudrock units, the presence and quality of the 

neutron log, and the slope of the trendline. For example, of the 

13 wells in Line C–C’ (pl. 5), inspection shows that the top of 
18 Present-Day Overpressure and Paleopressure Indicators in the Greater Anadarko Basin

Figure 11. Gamma-ray, resistivity, neutron, and density logs in the West Edmond SWD 1-24 well (location shown on plate 

2). Resistivity trendline is based on lowest resistivity values in mudrocks, which are represented by gamma-ray values in 

excess of 70 American Petroleum Institute (API) units (gray shading) and neutron porosity in excess of 20 percent (brown 

shading). Low resistivity in sandstones (light yellow shading) is attributed to saline water in the pore space. In this well, 

resistivity and density in mudrocks increase steadily with depth and there is no indication of paleopressure.

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000

5,500

6,000

6,500

7,000

Resistivity

Gamma Ray

Caliper

Neutron

Density

Resistivity in ohm-meters

Well A - West Edmond SWD 1-24

Neutron Porosity 

in percent

Density in grams per

cubic centimeter

Gamma Ray 

in API units

 Caliper

in inches

0 140

8 28 45 15 2 3 1 10 100 1,000

Desmoinesian

Woodford Shale

Missourian

Chase Group (Permian)

Depth

 in

feet

Resistivity 

trendline

Nelson_Ch8_Figure 11
Indicators of Paleopressure from Reduction in Resistivity 19

Figure 12. Gamma-ray, resistivity, neutron, and sonic logs in the Bredy well. The resistivity trendline is based on the lowest 

resistivity values in mudrocks above 9,000 feet, which are represented by gamma-ray values in excess of 70 American 

Petroleum Institute (API) units (gray shading) and neutron porosity in excess of 20 percent (brown shading). In this well, the 

top of paleopressure is at 9,000 feet. Below the top of paleopressure, resistivity in mudrocks decreases with increasing depth 

and sonic slowness in mudrocks increases with depth.

Resistivity

Resistivity in ohm-meters

Well B - Bredy 1-6

Neutron porosity

 in percent

Gamma ray 

in API units

0 140 1 10 100 1,000 30 0 120 40

Desmoinesian

Springer Fm (Morrowan and Mississippian)

Missourian

Depth

in

feet

Resistivity 

trendline

Sonic slowness

in microseconds

per feet

6,000

7,000

8,000

9,000

10,000

11,000

12,000

13,000

14,000

15,000

16,000

17,000

Nelson_Ch8_Figure 12
20 Present-Day Overpressure and Paleopressure Indicators in the Greater Anadarko Basin

the reversal could not have been picked at a shallower depth 

in 6 wells, but could have been picked at a shallower depth 

in the other 7 wells, with a range of 147 to 710 ft. Similarly, 

the top of the reversal could not have been picked at a deeper 

depth in 5 wells but could have been picked at a deeper depth 

in the other 8 wells, with a range of 64 to 297 ft. Because the 

errors are not normally distributed, it is difficult to estimate an 

overall error, but it does appear that a typical error is several 

hundred feet in about half of the wells.

Results

The geographic overview (pl. 2) shows how the paleopressure indicator varies with well position in the basin. 

The red shading between the trendline and the resistivity 

log indicates the presence of mudrocks, as determined by 

high gamma-ray (typically greater than 70 API units) or high 

neutron porosity (typically greater than 20 percent) readings. 

Resistivity is more reduced with respect to the trendline in the 

deeper part of the basin than on the flanks. Two maps show the 

elevation of the top of paleopressure (fig. 13) and the age of 

formations of the top of paleopressure (fig. 14).

The slope of the trendline is steepest on the flanks of the 

basin and not as steep in the deep basin, that is, resistivity 

increases with depth at a greater rate in the deep basin than on 

the flanks of the basin (pl. 2). This is not unexpected, as compaction determines the increase of resistivity with depth and 

compaction is greatest where burial depths are greatest. As a 

consequence, the width of the separation between the resistivity curve and the trendline is greatest in the deep basin, so the 

red shading is more obvious (fig. 12). Wells in which the shale 

resistivity decreases to less than 1/10 of the trendline value are 

outlined with a red circle in figure 13; these wells are mostly 

in the southeastern part of the Anadarko Basin.

The zone of paleopressure is bounded on the west 

and east by wells with no resistivity reversal, indicating no 

evidence of paleopressure (see plate 2 and wells on the west 

and east end of line A–A′ in plate 3). All strata are thinner on 

the shelf than in the deep basin, and as strata thin the zone of 

paleopressure also thins becoming more difficult to discern, 

as shown in the northern most wells on lines B–B′, C–C′, and 

D–D′ (pls. 4-6). At the northern edge of the area, the paleopressure indicators reduce in number and thickness, until it is 

not possible to determine whether paleopressure is present or 

not. For this reason, no effort was made to trace the extent of 

paleopressure into southern Kansas, with the exception of the 

wells in the southwestern counties. In southwestern Kansas, 

paleopressure is only visible in strata of Morrowan age (pl. 2) 

with the exception of a single well in which the top of paleopressure is in Desmoinesian age rocks (fig. 14). 

Figure 13. Map of the elevation of top of paleopressure as determined from resistivity logs. 

Lines A–A’ through D–D’ show location of cross sections on plates 3–6. A resistivity reversal 

was found in 107 wells (green circles) but was absent in 68 wells (red triangles).

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B

B' C'

C

D'

D

A

A'

-4,000

-6,000

-8,000 -10,000

-4,000

-6,000

-8,000

-8,000

-12,000

-2,000

-10,000

Well with resistivity reversal

▲ Well with no resistivity reversal

Wells with mudrock resistivity values that 

 are less than 1/10 of trendline values

Elevation of top of paleopressure in feet 

 relative to sea level

EXPLANATION

Basin axis

Faults in basement rocks

TEXAS

OKLAHOMA

KANSAS

0 15 30 MILES

0 15 30 KILOMETERS

103° 102° 101° 100° 99° 98° 97° 96°

38°

37°

36°

35°

34°
Indicators of Paleopressure from Reduction in Resistivity 21

The changing relation between the top of paleopressure 

and rock unit age from west to east is seen by comparing the 

three north-south sections in plates 4–6. On the westernmost 

line B–B′ (pl. 4), the top of paleopressure lies within the lower 

Desmoinesian or Atokan, within 500 ft above the informal 

Thirteen Finger lime, which is considered to be a source rock 

(Higley, chapter 7 of this report). The same relation holds over 

the northern portion of line C–C′ (pl. 5), but in the southern 

part of line C–C′, paleopressure extends stratigraphically 

upwards into rocks of early Virgilian age in wells Bobby 1-14 

and Weatherly 1. The upward extension of paleopressure produces a large southward deflection of the 8,000-ft contour in 

figure 13, encompassing a lobate area of approximately 15 by 

30 miles where the top of paleopressure is higher in elevation 

(fig. 13) and higher stratigraphically (fig. 14) than immediately 

to the west and east. On the easternmost of the three southnorth cross sections, the top of paleopressure lies within rocks 

of Missourian age in the eight wells on the southern part of the 

line (pl. 6, fig. 14). The elevation of the top of paleopressure 

is fairly constant over a distance of about 50 miles, as can be 

seen in plate 6 and by the wide separation between the 6,000- 

and 8,000-ft contours of figure 13. Line A–A′ (pl. 3) also 

shows the general west to east stratigraphic climb of the top 

of paleopressure, interrupted by the high point into rocks of 

Virgilian age that is reached in the Weatherly well where line 

A–A′ intersects line C–C′.

The top of paleopressure lies in rocks of Morrowan age 

along the west and northwest sides of the mapped area (fig. 14), 

with the exception of one outlying well in southwestern Kansas 

in which the paleopressure indicator extends into rocks of 

Desmoinesian age. The northwest-trending boundary between 

Morrowan and Desmoinesian age rocks is a transitional one 

because in some wells the resistivity reversals are in only a 

few thin units above the Thirteen Finger lime and cannot be 

unambiguously assigned to either Morrowan or Desmoinesian 

(Atokan units are absent or poorly defined in this area). The top 

of paleopressure does extend into recognizable Atokan units 

in five wells in an area straddling the Texas-Oklahoma border 

(fig. 14). Three wells in the southeastern edge of the basin 

show a clear indication of paleopressure in Springer mudrocks. 

Because there are no rocks older than Morrowan-Springer that 

show indications of paleopressure, areas marked Morrowan/

Springer in figure 14 do not show evidence of paleopressure in 

any other sequences. Paleopressure extends stratigraphically 

upward from Desmoinesian rocks into Missourian rocks in the 

southeastern part of the study area and also in a single isolated 

well in the Texas Panhandle. As previously mentioned, the 

top of paleopressure extends into rocks of Virgilian age in two 

wells, as shown in fig. 14.

As can be seen in plates 2–6, the greatest depth extent 

of the paleopressure indicator lies in the deep basin; that is, 

the depth range from top of paleopressure to either the base 

Figure 14. Map of age of rock unit containing top of paleopressure, based on the depth 

where the resistivity log changes from increasing downwards to decreasing downwards. The 

green area includes rocks of either Morrowan or Springer age, or both.

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Top of paleopressure

in rocks of Missourian age

Top of paleopressure

in rocks of Desmoinesian age

Northern limit of well control

Top of paleopressure

in rocks of Morrowan age

Top of paleopressure

 in rocks of Springer age

Top of paleopressure

in rocks of Atokan age

Top of paleopressure

in rocks of Virgilian age

COLORADO

OKLAHOMA

TEXAS

KANSAS

▲

Wells with resistivity log reversal

Wells with no resistivity log reversal

EXPLANATION

Nelson_Ch8_Figure 14

0 15 30 MILES

0 15 30 KILOMETERS

Precambrian faults

Basin axis

103° 102° 101° 100° 99° 98° 97° 96°

38°

37°

36°

35°

34°
22 Present-Day Overpressure and Paleopressure Indicators in the Greater Anadarko Basin

of paleopressure or the bottom of the well is greatest in the 

deep basin. Paleopressure extends downward through rocks of 

Morrowan age and into mudrocks of Mississippian age. Paleopressure does not register in Mississippian carbonates where 

mudrocks are absent. Somewhat surprisingly, the paleopressure indicator does not show up in the Devonian Woodford 

Shale (for example, Shirley 1-20 and Laubhan 35-1 wells of 

line B–B′, pl. 4; Vierson and Coram A1 wells of line C–C′, 

pl. 5). However, the Ordovician Sylvan Shale does produce 

a reduction in resistivity that shows up as a paleopressure 

indicator (Schneider 1 well, line C–C′, pl. 5; Girard 1 well, 

line A–A′, pl. 3). 

Comparison of Overpressured and 

Paleopressured Areas

The area of paleopressure is much more extensive than 

that of present-day overpressure. The contraction of both areal 

and vertical extents are shown in figures 15–17. In these figures, the outlines of paleopressure are derived from figure 14, 

accounting for the fact that areas of paleopressure are stacked 

such that paleopressure exists in Morrowan (the oldest) 

through Virgilian (the youngest) rocks in the small area where 

the top of paleopressure extends to rocks of Virgilian age, 

paleopressure exists in Morrowan through Missourian rocks in 

the brown-shaded area where the top of paleopressure extends 

upward into rocks of Missourian age, and so on. The outlines 

of overpressured areas in Desmoinesian and Morrowan rocks 

are taken from figures 6 and 7 and the outline of overpressured areas in Missourian rocks, not previously displayed, is 

shown in figure 14. Figures 15–17 show that (1) the outline of 

present-day overpressure at 0.5 psi/ft in rocks of Morrowan 

and Springer age is less than half of its respective area of 

paleopressure (fig. 15), (2) the area of present-day overpressure for Desmoinesian age rocks is less than half the area of 

paleopressure for Desmoinesian-age rocks (fig. 16), and (3) for 

Missourian age rocks, the outline of present-day overpressure is less than one-fourth that of the area of paleopressure 

(fig. 17). (Based on evidence from mud logs and gas flares, the 

area of present-day overpressure in Missourian age rocks is 

greater than shown in figure 17 [John Mitchell, oral commun., 

2011)].) In all three cases, the area of present-day overpressure 

is substantially less than the area of paleopressure.

The vertical extents of paleopressure and overpressure are 

more difficult to compare than the horizontal extents. North 

of the overpressured area, defined by the 0.5 psi/ft contours 

(figs. 15–17), overpressure is not present but paleopressure 

has a finite vertical extent. Within the overpressured areas, the 

situation is mixed. Where paleopressure extends upward into 

younger rocks of Virgilian age, as shown in figure 14 and in 

the southward bowing of the -8,000-ft contour in figure 13, 

the top of paleopressure is clearly at a higher elevation than 

the top of overpressure. In other areas, the two surfaces appear 

to be at comparable elevations (compare fig. 13 with fig. 5), 

suggesting that there has been little downward movement of 

the overpressured zone. In a few areas, the top of paleopressure is at a lower elevation than the top of overpressure. These 

lower-elevation areas are where well coverage for paleopressure is sparse, so the counter-intuitive relation of a paleopressure surface deeper than an overpressure surface is discounted 

as an artifact of inadequate coverage. In summary, it appears 

that the top of the original overpressured volume has moved 

downward a few thousand feet in some locations, but overall 

there has been little downward movement of the top of the 

original overpressured volume.

A somewhat analogous setting exists in the Green River 

Basin of Wyoming, where Jonah field, a fault-bounded, 

overpressured tight gas system lies within an extensive area of 

normally pressured strata. Resistivity and sonic logs display 

trend reversals at the top of the overpressured gas system in 

Jonah Field. The reversals are also at the same stratigraphic 

level in wells in non-productive, normally pressured Tertiary 

strata outside the field, where the well log signatures and 

present-day pressure are decoupled (Cluff and Cluff, 2004). 

Cluff and Cluff (2004) concluded that the well log reversals 

record pressure conditions at the time of maximum burial, and 

that the “signature was frozen into the rocks during subsequent 

exhumation” making Jonah Field “an anomalous remnant” of 

a former regional overpressured area (Cluff and Cluff, 2004, 

p. 143). 

Thermal maturity maps based on petroleum system 

modeling (chapter 3 of this report) provide contours of vitrinite 

reflectance (Ro) that can be compared with the outlines of 

paleopressure and present-day overpressure (figs. 15–17). In 

Morrowan age rocks, most of the overpressured area within 

the 0.7 psi/ft boundary lies within the 1.2% Ro contour, and 

almost all of the 0.5 psi/ft area lies within the 0.8% Ro contour 

(fig. 15). However, a substantial part of the paleopressured 

area lies outside the 0.8 percent contour. In Desmoinesian age 

rocks (fig. 16), the 1.2% Ro contour roughly coincides with 

the 0.7 psi/ft contour, showing that the highest present-day 

overpressures are in the same area as the levels of thermal 

maturity associated with gas generation. The 0.8% Ro contour 

includes most of the area within the 0.5 psi/ft contour but does 

not include all of the paleopressured area in rocks of Desmoinesian age. For comparison with paleopressured and presentday overpressured areas of Missourian age rocks (fig. 17), we 

display the contours of 0.8% Ro and 1.0% Ro from a model for 

the Douglas Group of early Virgilian age, which immediately 

overlies rocks of Missourian age. No Ro values higher than 

1.0 percent were computed for this model. The areas of paleopressure and present-day overpressure (fig. 17) coincide with 

part of the area circumscribed by a 0.8% Ro contour. 

In summary, the comparisons among overpressured areas, 

paleopressured areas, and Ro contours from petroleum system 

modeling (figs. 15–17) show that (1) the areas of high overpressure and high Ro

 values are comparable in Morrowan and 

Desmoinesian rocks, (2) most of the overpressured areas lie 

within the 0.8% Ro contours, and (3) paleopressured areas generally extend beyond the 0.8% Ro

 contours. 
Comparison of Overpressured and Paleopressured Areas 23

The continued existence of an overpressured zone long 

after the cessation of burial and hydrocarbon generation has 

perplexed a number of investigators because containment of 

overpressure for long time periods requires extremely low values of permeability to fluid flow on the top, bottom, and sides 

of the overpressured volume. Using a one-dimensional model 

of pressure dissipation and parameters relevant to the Anadarko 

Basin, Lee and Deming (2002) observed that the retention of 

pressure from either compaction disequilibrium or hydrocarbon generation (with uplift) requires permeability in seals of 

100-m thickness to be so low as to be effectively zero. In a 

related report, Deming and others (2002) discuss the dilemma 

of long-lived overpressured volumes in the Anadarko Basin 

(and in sedimentary basins in general) and contribute a possible 

explanation for the retention of fluids within the basins. The 

explanation relies on laboratory experiments reported by Shosa 

and Cathles (2001), in which water flowing through a layered 

sand pack with flow rates and pressures governed by Darcy’s 

law ceased flowing when gas was introduced into the system. 

Experimental checks verified that the cessation of flow was 

caused by gas bubbles immobilized at the interfaces between 

coarse and fine sand packs. Deming and others (2002) extrapolated the laboratory work to the basin scale, using well logs 

to show that the requisite number of fine-grain/coarse-grain 

interfaces are present in the Anadarko Basin. 

The question of timing of the contraction of the overpressured area from its original (paleopressured) extent to 

its present configuration is another difficult question, and 

depends upon the chosen explanation for the retention of 

overpressure. The presence of underpressure in the northern 

and western parts of the basin is documented in a companion 

report by Nelson and Gianoutsos (chapter 9 of this report) and 

the timing of its development is conjectured to be quite recent 

in geological time. Assuming that the mechanism reported by 

Shosa and Cathles (2001) was (and is still) operative, then it is 

plausible that as erosion exposed Permian and Pennsylvanian 

strata, the pressure gradients changed direction in such a way 

as to render the gas-bubble lockup no longer effective on the 

northern flank of the basin. Moreover, the conversion from an 

overpressured system to a normal/underpressured system may 

be ongoing at the northern edge of the present-day overpressured area. 

Figure 15. Map showing extents of paleopressure and overpressure in rocks of Morrowan 

and Springer age. The extent of the paleopressure indicator from resistivity logs is derived 

from figure 14 and the extent of present-day overpressure from pressure data is taken from 

figure 7. Modeled vitrinite reflectance contours of 0.8 and 1.2 percent for source rocks of 

Thirteen Finger lime of Atokan age taken from Higley (chapter 7 of this report). 

0.7 psi/ft

0.5 psi/ft

Morrowan

 truncation

 edge Paleopressure in rocks of

Morrowan and Springer age

Outlines of present-day overpressure 

in rocks of Morrowan and Springer age

COLORADO

OKLAHOMA

TEXAS

KANSAS

Nelson_Ch8_Figure 15

0.8 %

Modeled vitrinite reflectance 1.2 %

0 15 30 MILES

0 15 30 KILOMETERS

Faults in basement rocks

Basin axis

EXPLANATION

103° 102° 101° 100° 99° 98° 97° 96°

38°

37°

36°

35°

34°
24 Present-Day Overpressure and Paleopressure Indicators in the Greater Anadarko Basin

Figure 16. Map showing extents 

of paleopressure and overpressure 

in rocks of Desmoinesian age. 

The extent of the paleopressure 

indicator from resistivity logs is 

derived from figure 14 and the 

extent of present-day overpressure 

from pressure data is taken 

from figure 6. Modeled vitrinite 

reflectance contours of 0.8 and 

1.2 percent for source rocks of 

Desmoinesian age taken from 

Higley (chapter 7 of this report).

Figure 17. Map showing 

extents of paleopressure 

and overpressure in rocks of 

Missourian age. The extent of 

the paleopressure indicator 

from resistivity logs is derived 

from figure 14. Modeled vitrinite 

reflectance contours of 0.8 and 

1.0 percent for source rocks of 

early Virgilian age taken from 

Higley (chapter 7 of this report).

Outlines of present-day overpressure

in rocks of Desmoinesian age

Paleopressure in rocks

of Desmoinesian age

0.5 psi/ft

0.7 psi/ft

OKLAHOMA

TEXAS

COLORADO KANSAS

Modeled vitrinite reflectance

1.2%

0.8%

Nelson_Ch8_Figure 16

0 15 30 MILES

0 15 30 KILOMETERS

Faults in basement rocks

Basin axis

EXPLANATION

103° 102° 101° 100° 99° 98° 97° 96°

38°

37°

36°

35°

34°

Outline of present-day overpressure

in rocks of Missourian age

Paleopressure in rocks

of Missourian age

0.5 psi/ft

TEXAS

COLORADO KANSAS

OKLAHOMA

Modeled vitrinite reflectance 0.8%

1.0%

1.0%

0 15 30 MILES

0 15 30 KILOMETERS

Faults in basement rocks

Basin axis

EXPLANATION

103° 102° 101° 100° 99° 98° 97° 96°

38°

37°

36°

35°

34°
References Cited 25

Summary and Conclusions

Our review of the state of overpressure in the Anadarko 

Basin shows (1) the prevalence of normal to subnormal pressures on the northern flank of the basin (pl. 1, fig. 4), (2) the 

progressive deepening of the top of overpressure from north 

to south (pl. 1, fig. 5), (3) the increasing vertical extent of 

overpressure from north to south as strata thicken (pl. 1), and 

(4) the distinct compartmentalization of overpressure in rocks 

of Desmoinesian and Morrowan age (pl. 1). 

The area of overpressure in rocks of Desmoinesian age is 

roughly 100 miles in the west-northwest direction and 50 miles 

in the east-northeast direction, based on the 0.5 psi/ft contour 

(fig. 6). The area of highest pressures within the 0.7 psi/ft 

contour nearly coincides with the 1.2% Ro contour (fig. 16), 

illustrating a close connection between high present-day 

overpressure and a thermal maturity level that is considered 

to be the end of oil generation for the Devonian-Mississippian 

Woodford Shale (chapter 3 of this report). The area of overpressure in rocks of Morrowan age is greater than 150 miles in 

the west-northwest direction and greater than 50 miles in the 

east-northeast direction, based on the 0.5 psi/ft contour (fig. 6). 

The area of highest pressures within the 0.7 psi/ft contour lies 

mostly within the 1.2% Ro contour (fig. 15). Evaluation of 

a dataset from Powley (1984) strengthens the case for subcompartments within strata of Morrowan age and establishes 

the existence of pressure gradients of 0.465 psi/ft at elevated 

overall pressures in three of the subcompartments (fig. 8). 

These gradients show that water, not gas, is the continuous 

fluid within the subcompartments.

Reversals in resistivity logs from a normal mudrock 

compaction trend are most manifest in the deep basin and 

persist northward onto the shelf, but do not exist in wells east 

and west of the basin (pls. 2–5 and figs. 13–14). The top of 

the trend reversals lies in Virgilian and Missourian rocks in 

the deep basin and in Morrowan rocks on the western and 

southeastern fringes of the system (fig. 14), although the pattern with regard to rock age is an irregular one. The resistivity 

trend reversals in Desmoinesian rocks extend to the Oklahoma-Kansas border and may have extended farther to the 

north, but the top of the trend reversal cannot be selected with 

confidence where strata thin on the northern flank of the basin.

Equating the resistivity trend reversals with paleopressure allows comparisons between the areal and vertical 

extents of the paleopressured system with the extents of 

the present-day overpressured system. The areal extents of 

paleopressure are substantially larger, about twice as large, 

as the areal extents of present-day overpressure in rocks of 

Morrowan, Desmoinesian, and Missourian age (figs. 15–17). 

Changes in vertical extent, however, are more subtle and 

more difficult to determine. Although the high points of the 

original overpressured volume have moved downwards a few 

thousand feet in some locations, overall there has been little 

downward migration of the top of the original overpressured 

volume. The largest reductions in resistivity relative to trendlines, and correspondingly the most profound expressions of 

paleopressure, are in an area that extends for 100 miles in a 

northwesterly direction more or less aligned with the basin 

axis and extending 20 to 40 miles north from the basin axis 

(pls. 3–6, fig. 13). This area of large reductions in resistivity 

coincides with the area where paleopressures extended into 

rocks of Missourian age (fig 14). 

The contraction of the paleopressured area to the area of 

present-day overpressure could conceivably have occurred 

over any span of geological time since the end of Permian 

deposition. However, it seems likely that the contraction 

occurred when the pressure reference for strata on the northern flank of the basin was established as erosional processes 

exposed strata of Permian and Pennsylvanian age at the eastern edge of the basin. 

Acknowledgments

James Puckette, of the Geology Department at Oklahoma State University, provided access to files of pressure 

data from the publication by Al-Shaieb and others (1994a). 

Elena Hickman, U.S. Geological Survey (USGS) contractor, 

provided registered digital maps. Debra Higley, USGS, provided formation tops and other geological information. Many 

constructive review comments by Noel Osborne, USGS, led 

to revisions that have improved the clarity of the chapter of 

the report. 

References Cited

Al-Shaieb, Z., Puckett, J.O., Abdalla, A.A., and Ely, P.B., 

1994a, Megacompartment complex in the Anadarko Basin: 

A completely sealed overpressured phenomenon, in Ortoleva, Peter J., ed., Basin compartments and seals: American 

Association of Petroleum Geologists Memoir 61, p. 55–68. 

Al-Shaieb, Z., Puckett, J.O., Abdalla, A.A., and Ely, P.B., 

1994b, Three levels of compartmentation within the overpressured interval of the Anadarko Basin, in Ortoleva, Peter 

J., ed., Basin compartments and seals: American Association of Petroleum Geologists Memoir 61, p. 69–83.

Bigelow, E.L., 1994, Well logging methods to detect abnormal 

pressure, in Fertl, W.H., Chapman, R.E., and Hotz, R.F., 

eds., chap. 7, Studies in abnormal pressure: Developments 

in Petroleum Science 38, Amsterdam, Elsevier, 454 p.

Breeze, A.F., 1970, Abnormal-subnormal pressure relationships in the Morrow sands of northwestern Oklahoma: 

University of Oklahoma, M.S. thesis, 122 p. 

Carter, L.S., Kelley, S.A., Blackwell, D.D., and Naeser, N.D., 

1998, Heat flow and thermal history of the Anadarko Basin, 

Oklahoma: American Association of Petroleum Geologists 

Bulletin, v. 82, no. 2, p. 291–316.
26 Present-Day Overpressure and Paleopressure Indicators in the Greater Anadarko Basin

Cluff, R.M., and Cluff, S.G., 2004, The origin of Jonah Field, 

northern Green River Basin, Wyoming, chap. 8 in Robinson, J.W., and Shanley, K.W., eds.: Jonah Field: Case study 

of a tight-gas fluvial reservoir: AAPG Studies in Geology 

52 and Rocky Mountain Association of Geologists 2004 

Guidebook, p. 127–145.

Deming, D., Cranganu, C., and Lee, Y., 2002, Self-sealing 

in sedimentary basins: Journal of Geophysical Research, 

v. 107, n. B12, 2329, 9 p.

Dickey, P.A., and Soto, C., 1974, Chemical composition of 

deep subsurface waters on the western Anadarko Basin: 

Society of Petroleum Engineers Paper 5178, 17 p. 

IHS Energy, 2009, U.S. production and well data: database 

available from IHS Energy, 15 Inverness Way East, D205, 

Englewood, CO 80112.

Lee, Y., and Deming, D., 2002, Overpressures in the Anadarko 

Basin, southwestern Oklahoma: Static or dynamic?: American Association of Petroleum Geologists Bulletin, v. 86, 

n. 1, p. 145–160.

Powley, D.E., 1984, Subsurface fluid compartments: American Association of Petroleum Geologists Search and 

Discovery Article 60006 (2006), adapted from Amoco 

Geological Research Report, 52 p. accessed December 14, 2010, at http://www.searchanddiscovery.com/

documents/2006/06015powley/images/powley01.pdf.

Shosa, J.D. and Cathles, L.M., 2001, Experimental investigation of capillary blockage of two phase flow in layered 

porous media, in Fillon, R.H. and others eds., Petroleum 

systems of deep-water basins: Global and Gulf of Mexico 

experience: 21st Annual Bob F. Perkins Research Conference [CD-ROM], Gulf Coast Section, Society of Economic 

Paleontological and Mineralogical Society, Houston, Texas.

U.S. Geological Survey, 2014, Colorado, Kansas, New 

Mexico, Oklahoma, and Texas: U.S. Geological Survey 

digital data, The National Map, accessed August 4, 2014, 

at: http://viewer.nationalmap.gov/viewer/.
Appendix 1

List of wells shown on cross sections on plates 3–6 

(Excel file format).

API

number

Lease

name

No. Operator State County

Reference 

elevation, 

in feet

Reference Latitude Longitude Section Township Range

Rock unit 

at top of 

resistivity 

reversal

3501723998 West Edmond 

Swd

1-24 Chesapeake Operating Inc Oklahoma Canadian 1,159 DF 35.669 -97.683 24 14N 05W Absent 

4248330610 Miles Gas Unit 1 Exxon Corporation Texas Wheeler 2,509 KB -- -- RRC 

Dist 10, 

Sec 2

Blk A-4 Survey: 

H&GN

Absent 

4248331989 Hagermann 21 1 Chesapeake Operating Inc Texas Wheeler 2,164 KB 35.433 -100.00 RRC 

Dist 10, 

Sec 21

BLK OS2 Peterman CE 

Survey

Absent 

3512920675 MillingtonShields 1 El Paso Natural Gas Company Oklahoma Roger Mills 2,158 GR 35.454 -99.589 1 11N 23W IM Desmoinesian 3501520950 Tillman 1 Monsanto Company Oklahoma Caddo 1,475 DF 35.418 -98.355 22 11N 11W IM Missourian 3501522365 Lindley 3-30 Apache Corporation Oklahoma Caddo 1,427 GR 35.402 -98.401 30 11N 11W IM Missourian 3501721307 Girard 1 Key Operating Company Oklahoma Canadian 1,455 DF 35.388 -98.083 31 11N 08W IM Missourian 3514920050 Richert 1 Conoco Inc Oklahoma Washita 1,607 KB 35.382 -98.760 35 11N 15W IM Missourian 3514920342 Hohnke Leo 

Unit

1 Exxon Corporation Oklahoma Washita 1,849 DF 35.367 -99.149 6 10N 18W IM Missourian 

3501721288 Royse 1 Samedan Oil Corporation Oklahoma Canadian 1,342 GR 35.504 -97.906 23 12N 7W IM Absent 3512920639 A H Douglas 

Estate

1 Exxon Corporation Oklahoma Roger Mills 2,277 DF 35.456 -99.759 5 11N 24W Atokan 

3512930019 Weatherly 1 Petroleum Waste Recovery Inc Oklahoma Roger Mills -- -- 35.543 -99.406 3 12N 21W IM Virgilian 3514920232 Davis 28-1 Getty Oil Company Oklahoma Washita 1,601 DF 35.403 -98.689 28 11N 14W IM Missourian 3500921156 Cat Creek 1-19 Chesapeake Operating Inc Oklahoma Beckham 2,045 DF 35.329 -99.786 19 10N 24W Absent 3504520748 Laubhan 35 1 Marathon Oil Company Oklahoma Ellis 2,370 DF 35.996 -99.940 35 18N 26W Atokan 3500720640 Dixon 1-6 King Resources Company Oklahoma Beaver 2,491 DF 36.839 -100.188 6 04N 27E CM Desmoinesian 3500721928 Homes Or 

Holmes?

36-2 Home Petroleum Corporation Oklahoma Beaver -- -- 36.684 -100.105 36 03N 27E CM Desmoinesian 

3504521097 Schoenhals 1 Marathon Oil Company Oklahoma Ellis 2,450 DF 36.183 -99.984 28 20N 26W IM Desmoinesian 3512922603 Shirley 1-20 The Ghk Company Oklahoma Roger Mills 2,056 DF 35.679 -99.768 20 14N 24W Desmoinesian 4229531218 Gadberry 1-174 Williford Energy Co Texas Lipscomb 2,488 KB -- -- RRC 

Dist 10, 

Sec 174

Blk 10 Survey: 

H&GN

DesMonesian 

3512922522 Bobby 1-14 Chesapeake Operating Inc Oklahoma Roger Mills 2,007 GR 35.512 -99.391 14 12N 21W IM Virgilian 3504520879 Coram A 1 Cities Service Company Oklahoma Ellis 2,268 DF 36.103 -99.468 20 19N 21W IM Desmoinesian 3505921196 Blasdel 2 Terra Resources Inc Oklahoma Harper 1,759 DF 36.847 -99.514 1 27N 22W IM Desmoinesian 3505922317 Horton 1-11 Chesapeake Operating Inc Oklahoma Harper 2,125 DF 36.664 -99.640 11 25N 23W IM Desmoinesian 3512920125 Viersen Unit 1 Pride Energy Company Oklahoma Roger Mills -- -- 35.794 -99.564 8 15N 22W IM Desmoinesian 3515320043 Everett Johns 1-18 A. R. Dillard Inc Oklahoma Woodward 2,077 GR 36.383 99.379 18 22N 20W Desmoinesian 3515321951 Schneider 1 Plains Petroleum Operating Co Oklahoma Woodward 1,896 GR 36.476 -99.455 16 23N 21W IM Desmoinesian 
API

number

Lease

name

No. Operator State County

Reference 

elevation, 

in feet

Reference Latitude Longitude Section Township Range

Rock unit 

at top of 

resistivity 

reversal

3515322725 Grunewald 1-26A Chesapeake Operating Inc Oklahoma Woodward 2,165 DF 36.270 -99.417 26 21N 21W IM Desmoinesian 3514920705 Niece 3-27 Meridian Oil Inc Oklahoma Washita 1,828 GR 35.312 -99.306 27 10N 20W IM DesMonesian 3512923149 Switzer 4-32 Apache Corporation Oklahoma Roger Mills 1,755 DF 35.640 -99.453 32 14N 21W IM Missourian 3514920152 Kilhoffer 1-27 The Ghk Company Oklahoma Washita 2,019 DF 35.400 -99.303 27 11N 20W IM Missourian 3514920020 Bertha Rogers 1 Lone Star Producing Company Oklahoma Washita 1,922 DF 35.309 -99.193 27 10N 19W IM Desmoinesian 3501121816 Wisdom 1-5 Sabine Production Company Oklahoma Blaine 1,311 DF 36.062 -98.401 5 18N 11W IM Desmoinesian 3501122895 Gypsum U S 1-27 Chesapeake Operating Inc Oklahoma Blaine 1,595 DF 36.090 -98.470 27 19N 12W IM Desmoinesian 3501122962 Chain 1-6 Chesapeake Operating Inc Oklahoma Blaine 1,574 DF 35.982 -98.525 6 17N 12W IM Desmoinesian 3501123150 Christensen 1-36 Chesapeake Operating Inc Oklahoma Blaine 1,598 DF 35.910 -98.532 36 17N 13W IM Desmoinesian 3501123174 Gwyn 1-2 Chesapeake Operating Inc Oklahoma Blaine 1,166 DF 36.154 -98.235 2 19N 10W IM Desmoinesian 3501520860 Allred 18-1 L G Williams Oil Company Oklahoma Caddo 1,462 GR 35.258 -98.611 18 9N 13W IM Missourian 3503920435 Swosu 1 Amoco Production Company Oklahoma Custer 1,610 DF 35.548 98.661 3 12N 14W IM Missourian 3503921952 Wingard 1-16 Chesapeake Operating Inc Oklahoma Custer 1,746 DF 35.685 -98.689 16 14N 14W IM Missourian 3503922053 Pitzer 1-2 Zinke & Trumbo Inc Oklahoma Custer 1,699 DF 35.628 -98.655 2 13N 14W IM Missourian 3514920141 Seger Indian 

School

1-21 Hamilton Brothers Oil Company Oklahoma Washita 1,601 DF 35.331 -98.680 21 10N 14W IM Missourian 

3514920153 Aaron Unit 1 Amoco Production Company Oklahoma Washita 1,558 DF 35.374 -98.653 2 10N 14W IM Missourian 3514920202 Arthur 24-1 Towner Petroleum Company Oklahoma Washita 1,429 DF 35.156 -98.633 24 8N 14W IM Missourian Explanation: IM, Indian Meridian; CM, Cimarron MeridianWell names and locations from Oklahoma Corporation Commission (www.occeweb.com) and Railroad of Texas (http://www.rrc.state.tx.us/) 
Chapter 9

Potentiometric Surfaces for Seven 

Stratigraphic Units and an Explanation for 

Underpressure in the Greater Anadarko 

Basin, Oklahoma, Texas, Kansas, and 

Colorado

By Philip H. Nelson and Nicholas J. Gianoutsos

Chapter 9 of 13

Petroleum Systems and Assessment of Undiscovered Oil and Gas 

in the Anadarko Basin Province, Colorado, Kansas, Oklahoma, and 

Texas—USGS Province 58

Compiled by Debra K. Higley

U.S. Geological Survey Digital Data Series DDS–69–EE

U.S. Department of the Interior

U.S. Geological Survey

Click here to return to

Volume Title Page
U.S. Department of the Interior

SALLY JEWELL, Secretary

U.S. Geological Survey

Suzette M. Kimball, Acting Director

U.S. Geological Survey, Reston, Virginia: 2014

For more information on the USGS—the Federal source for science about the Earth, its natural and living 

resources, natural hazards, and the environment, visit http://www.usgs.gov or call 1–888–ASK–USGS.

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Although this information product, for the most part, is in the public domain, it also may contain copyrighted materials 

as noted in the text. Permission to reproduce copyrighted items must be secured from the copyright owner.

Suggested citation:

Nelson, P.H., and Gianoutsos, N.J., 2014, Potentiometric surfaces for seven stratigraphic units and an explanation for 

underpressure in the Greater Anadarko Basin, Oklahoma, Texas, Kansas, and Colorado, chap. 9, in Higley, D.K., comp., 

Petroleum systems and assessment of undiscovered oil and gas in the Anadarko Basin Province, Colorado, Kansas, 

Oklahoma, and Texas—USGS Province 58: U.S. Geological Survey Digital Data Series DDS–69–EE, 24 p., 

http://dx.doi.org/10.3133/ds69EE.

ISSN 2327-638X (online)
iii

Contents

Abstract...........................................................................................................................................................1

Introduction.....................................................................................................................................................1

Conversion of Pressure to Hydraulic Head ...............................................................................................8

Effect of Density Variations in the Computation of Hydraulic Head....................................................10

Relation Between Salinity and Density for Sodium Chloride Solutions.....................................10

Salinity of Subsurface Waters.................................................................................................11

Problem of Variable Brine Density in Computing Hydraulic Head.....................................12

Computation of Hydraulic Head along West-East and South-North Swaths ....................................13

Potentiometric Surfaces.............................................................................................................................15

Procedure.............................................................................................................................................15

Maps Showing Potentiometric Surfaces and Overpressured Areas ........................................16

Hunton-and-older Stratigraphic Units....................................................................................17

Mississippian Stratigraphic Unit.............................................................................................17

Morrowan Stratigraphic Unit...................................................................................................17

Desmoinesian Stratigraphic Unit ............................................................................................17

Missourian Stratigraphic Unit .................................................................................................18

Virgilian Stratigraphic Unit.......................................................................................................18

Permian Stratigraphic Unit.......................................................................................................18

Discussion.....................................................................................................................................................19

Summary........................................................................................................................................................22

Acknowledgments.......................................................................................................................................23

References Cited..........................................................................................................................................23

Plates

1. Maps of salinity in seven stratigraphic units in the Anadarko Basin ............................. link

2. Hydraulic head, surface elevation, and drillstem test elevation for four north-south

swaths and seven stratigraphic units .................................................................................. link

3. Hydraulic head data and processing for 13 west-east lines and resulting

potentiometric surfaces for rocks of Missourian age....................................................... link

4. Potentiometric surfaces for seven stratigraphic units ..................................................... link

5. Separation between potentiometric and land surfaces for seven stratigraphic 

units............................................................................................................................................ link

Figures

1. Map showing areas of this and previous studies of overpressure and

underpressure. Contours for the top of the Woodford Shale show the structure of

the Anadarko Basin; basin axis appears in subsequent figures as a reference line.

Reference well is the Ferris 1-28 well. The study area for this chapter extends from

latitude 33.5° to 39.5° N. and longitude 96° to 103.5° W.........................................................2
iv

2. Stratigraphic chart of the Anadarko Basin, with stratigraphic units (purple shading)

as defined in this study to examine pressure data. The lithostratigraphic units are

modified from Higley (chapter 3 of this report). Geohydrologic units were defined

by Jorgensen and others (1996) for a regional study; light blue shading indicates

the presence of rock units with well defined patterns of hydraulic head that can be

considered to be aquifers. Cretaceous rocks are not present in the study area of

figure 1 but are present in the regional study area of Jorgensen and others (1996).

Wavy lines represent unconformities. Areas with vertical lines represent periods of

non-deposition. PC, Precambrian; Camb., Cambrian; Miss., Mississippian.......................3

3. Map of Anadarko Basin showing pressure-depth ratios for reservoirs of

Desmoinesian age, based on data from NRG Associates (2009). psi/ft, pounds per

square inch per foot.....................................................................................................................4

4. Map of greater Anadarko Basin showing surface elevation contours in 400-foot

intervals, basin axis, Precambrian faults, and outcrops of selected formations.

Precambrian faults from Adler and others (1971). Thickness of Permian evaporites

from Gianoutsos and others (chapter 10 of this report). Outcrops of Garber

Sandstone and three Virgilian formations, and base of Wellington Formation in

Kansas and Oklahoma from Stoesser and others (2005). East-west oriented Line F

shows location of drillstem test data shown in figure 10.......................................................5

5. Burial history for the Ferris 1-28 well, from Carter and others (1998). Overpressure

developed during rapid burial during Pennsylvanian time with a possible secondary

development around 100 Ma. Underpressure development is believed to be recent,

commensurate with exposure of strata in central Oklahoma. The Permian cap

provides a low permeability seal over the area. pC, Precambrian; _, Cambrian; O,

Ordovician; S, Silurian; D, Devonian; M, Mississippian; P, Pennsylvanian; P,

Permian, T, Triassic, J, Jurassic; K, Cretaceous; P

E

, Paleocene; E, Eocene; O,

Oligocene, M, Miocene; Fms, Formations; Gp, Group; Ss, Sandstone, °C, degrees

Celsius ............................................................................................................................................6

6. Structural cross section showing Permian and younger rocks in the Texas

Panhandle (see inset for location). Mudstone, anhydrite, and salt form

impermeable layers in Permian rocks. An interpreted salt dissolution feature is

near the center of the section. From McGookey and others (1988). Co., County;

Quat., Quaternary; Tert., Tertiary; Fm., Formation; Gp., Group...............................................7

7. Graph showing pressure in relation to elevation from wells in a small area in the

Oklahoma Panhandle. The average surface elevation of 2,542 feet is represented

by the y-intercept of the hydrostatic gradient. The dashed lines are reference lines

for the pressure data, most of which correspond to underpressured conditions.............9

8. Example demonstrating the calculation of hydraulic head and pressure-depth ratio

for two wells testing the same formation. The pressure-depth ratio is the same in

the two wells, but the hydraulic head is much greater in Well A than in Well B. ft,

foot; psi, pounds per square inch; psi/ft, pounds per square inch per foot......................10

9. Box-and-whiskers plot of salinity in seven stratigraphic units with number of

samples in each group. Each whisker and each box represents 25 percent of the

data. Salinity data taken from a compilation by Breit (2002), which is based on

waters produced from oil and gas wells ................................................................................12

10. Data from drillstem tests in Missourian rocks from west-east swath Line F close to

and parallel with the Kansas-Oklahoma border (location in figure 4). A, Surface

elevation (black plus symbols), elevation of drillstem tests (triangular symbols), and

computed hydraulic head (red dash symbols); B, pressure measurements; C,

computed pressure-depth ratio indicating underpressure where less than 0.465

pounds per square inch per foot (psi/ft) .................................................................................14
v

Tables

1. Increments of density used for salinity maps of plate 1.......................................................11

2. Specific volume of water as a function of pressure and temperature..............................11

11. Hydraulic head H computed for one-dimensional flow Q in a medium of low

hydraulic conductivity in the west, KW, and high conductivity in the east, KE, with

KW/KE = 1/30. The length of the low-conductivity section, XW, is 1/4 the length of the

high-conductivity section, XE. Values of H range from 1,250 to 3,000 feet, with colors

between 250-foot contours of H selected to match the colors in plate 4. Concept for

one-dimensional model taken from Belitz and Bredehoeft (1988)......................................16

12. West-east structural cross section showing features influencing the creation and

maintenance of underpressure. Permian and Pennsylvanian strata crop out along

and east of the Nemaha uplift. Brown shading indicates the impermeable

evaporite-bearing strata of Permian age. Pinchout and thinning of strata on the

Sierra Grande arch provide limited entry for recharge. East of longitude 102° W. the

cross section is based largely on well data. West of long 102° W. the cross section

is based on information from Roberts and others (1976), Weeks and Gutentag

(1981), and McGookey and others (1988)................................................................................20

13. Comparison between a separation map from plate 5F and degree of

underpressuring for the Virgilian unit. Contours on the separation map give the

Virgilian potentiometric surface minus the surface elevation. Dots give the location

of individual oil and gas fields for which pressure-depth ratios were computed

from data provided by NRG Associates (2009) ......................................................................20

14. Map with contours showing separation between the potentiometric surface in

Permian rocks and land surface elevation, in feet. For example, the yellow areas

show where the potentiometric surface lies -1,500 to -1,800 ft below surface

elevation. The underpressured Hugoton-Panhandle gas field lies in a trough of

maximum separation between the potentiometric surface and surface elevation ........21
vi

Conversion Factors

Inch/Pound to SI

Multiply By To obtain

Length

foot (ft) 0.3048 meter (m)

mile (mi) 1.609 kilometer (km)

Volume

barrel (bbl), (petroleum, 1 barrel=42 gal) 0.1590 cubic meter (m3) 

cubic foot (ft3) 0.02832 cubic meter (m3) 

Pressure

atmosphere, standard (atm) 101.3 kilopascal (kPa)

bar 100 kilopascal (kPa) 

pound per square inch (lb/in2) 6.895 kilopascal (kPa) 

Density

pound per cubic foot (lb/ft3) 16.02 kilogram per cubic meter (kg/m3)

pound per cubic foot (lb/ft3) 0.01602 gram per cubic centimeter (g/cm3)
Abstract

The controls on subsurface pressure across the northern part of the Anadarko Basin are examined with the aid of 

potentiometric maps constructed for seven stratigraphic units 

ranging in age from Cambrian to Early Permian. Pressure data 

from drillstem tests are converted to hydraulic head, a step that 

is complicated by variations in brine density within the basin, 

as shown by maps of salinity for each of the seven stratigraphic 

units considered in this study. Seven potentiometric maps were 

constructed using a series of filtering and mapping steps to 

drape a surface over the highest values of hydraulic head. The 

maps show that, for rocks of Desmoinesian, Missourian, Virgilian, and Lower Permian age, hydraulic head values approach 

surface elevation values along the Nemaha uplift in central 

Oklahoma where Lower Permian and Pennsylvanian strata 

are exposed. From the Nemaha uplift westward to southwestern Kansas and the panhandle areas of Oklahoma and Texas, 

hydraulic head increases by several hundred feet in each rock 

unit, whereas surface elevation increases by thousands of feet. 

The underpressuring of the aquifer-supported oil and gas fields, 

which increases from east to west, is a consequence of the 

westward-increasing vertical separation between surface elevation and hydraulic potential. Recharge to the deep confined 

rock units is limited. The thick cap of Permian evaporites and 

shales restricts recharge to the underlying strata, preventing reestablishment of a normal hydrostatic gradient. Recharge from 

the west is restricted because of onlap of Pennsylvanian and 

older strata onto the eastern flank of the Sierra Grande arch. 

Present-day underpressuring of oil and gas reservoirs on the 

northwest flank of the basin is the result of uplift and exposure 

of Lower Permian and Pennsylvanian strata along the Nemaha 

uplift and restricted recharge to the basin.

Introduction

This study explores the cause of widespread underpressure in the western and northern parts of the greater Anadarko 

Basin, an area that extends from the southeast corner of 

Colorado eastward to central Kansas and Oklahoma and 

includes the Oklahoma Panhandle and a portion of the Texas 

Panhandle (fig. 1). The structure of the Anadarko Basin is 

defined by the elevation contours of the Woodford Shale 

(fig. 1); a line drawn through the deepest part of the Woodford 

Shale serves to locate the deep basin in subsequent figures. 

Further discussion of the geology of the Anadarko Basin is 

given by Higley (chapters 5 and 7 of this report). Underpressure exists in rock units that are Paleozoic in age (fig. 2); rock 

units younger than Permian form unconfined aquifers above 

the deeper confined rock units where both underpressure and 

overpressured conditions exist. Chapter 8 of this report (Nelson 

and Gianoutsos), which also covers the study area of figure 1, 

examines the extent of overpressure which presently is confined to the deep basin but is hypothesized to have had a greater 

areal extent in the geologic past. The terms overpressure and 

underpressure refer to preproduction fluid pressures that are 

respectively greater than and less than hydrostatic pressure. 

The two studies on formation fluid pressure were undertaken in 

conjunction with the work reported by Higley (chapter 7 of this 

report) and Gaswirth and Higley (chapter 5 of this report) on 

the assessment of oil and gas in the Anadarko Basin. 

The existence of underpressured oil and gas reservoirs in 

parts of the Anadarko Basin has been reported by a number of 

authors. Breeze (1970) documented the transition in the Morrow Formation in northwestern Oklahoma from overpressure 

in the deep basin to underpressure on the flank of the basin; 

his area of study is outlined in figure 1. Blubaugh (1999a, 

1999b) mapped the widespread extent of underpressuring in 

the Hunton Group of Silurian and Devonian age. In the course 

of documenting the overpressured megacompartments in the 

deep Anadarko Basin, Al-Shaieb and others (1994) noted the 

existence of underpressured areas but did not investigate their 

cause; their study area is outlined in figure 1 and their data 

set is discussed in a companion report (Nelson and Gianoutsos, chapter 8 of this report). Original reservoir pressure 

in the extensive Permian age Panhandle-Hugoton gas field 

(fig. 1) was 435 pounds per square inch (psi) at a depth range 

of 2,500 to 3,000 feet for a pressure-depth ratio of less than 

0.18 pounds per square inch per foot (psi/ft), as described by 

Pippin (1970) and Sorenson (2005). In 14 fields of 6 counties 

Potentiometric Surface Maps for Seven Stratigraphic 

Units and an Explanation for Underpressure in the Greater 

Anadarko Basin, Oklahoma, Texas, Kansas, and Colorado

By Philip H. Nelson and Nicholas J. Gianoutsos
2 Potentiometric Surface Maps for Seven Stratigraphic Units in the Greater Anadarko Basin

of the eastern part of the Texas Panhandle, the pressure-depth 

ratio ranges from 0.21 to 0.40 psi/ft with a median value of 

0.29 psi/ft (Taylor and others, 1977)—rocks in these 14 fields 

range from Ordovician to Late Pennsylvanian in age, representing 6 of the 7 stratigraphic units considered in this report. 

Thus, many authors have either noted the presence of underpressure or have reported pore pressure values significantly 

less than a nominal hydrostatic pressure-depth ratio of 0.465 

psi/ft. From the broad geographic and stratigraphic ranges 

reported, it is clear that underpressuring in the Anadarko Basin 

is a widespread phenomenon.

In addition to the aforementioned studies, pressure and 

depth to the top of reservoir are available for many reservoirs 

in the Anadarko Basin (NRG Associates, 2009). The ratios of 

those two values are posted on a map for reservoirs of Desmoinesian age (fig. 3). For purposes of discussion, pressuredepth ratios between 0.43 and 0.50 psi/ft can be considered to 

be normally pressured. Only 10 values fall within the normal 

pressure range and these are scattered throughout much of the 

mapped area. A few values exceed 0.50 psi/ft; 3 of these are 

along or immediately north of the basin axis where overpressuring is known to exist. The rest of the pressure-depth ratios 

are less than 0.43 psi/ft, showing that underpressuring is widespread throughout much of the area. The lowest values, which 

are less than 0.30 psi/ft, are mostly clustered in the Texas and 

Oklahoma Panhandles. The map (fig. 3) substantiates that 

much of the area is underpressured, most notably the northern 

and northwestern flanks of the basin. It is also apparent that 

pressure-depth ratios for reservoirs do not follow any trends in 

relation to geographic position. The same can be said of pressure data from individual wells, a condition which has provided 

a challenge in determining potentiometric levels in this study.

Three studies concerned with the distribution of subsurface pressure were helpful to us in developing our hypotheses 

on the nature of underpressure in the Anadarko Basin. Sorenson (2005) explained the underpressuring of the HugotonPanhandle gas field in terms of aquifer communication with 

outcrop in eastern Kansas. This report builds on Sorenson’s 

findings by examining the potentiometric distribution of 

the entire stratigraphic section throughout the basin, finding 

that the tie to outcrop lies along the Nemaha uplift in central 

Oklahoma. A hydrodynamic study of the Palo Duro Basin 

(Bair, 1987) used water level and drillstem measurements 

extending beyond the limits of the basin itself; the northern 

Figure 1. Map showing areas of this and previous studies of overpressure and 

underpressure. Contours for the top of the Woodford Shale show the structure of the 

Anadarko Basin; basin axis appears in subsequent figures as a reference line. Reference well 

is the Ferris 1-28 well. The study area for this chapter extends from latitude 33.5° to 39.5° N. 

and longitude 96° to 103.5° W.

0

-8,000

-2,000

1,000

-4,000

-10,000

-12,000

-14,000

-16,000 -18,000

2,000

-2,000

0

-20,000

-6,000

-2,000

-4,000

-2,000

0

2,000

0

-4,000

-4,000

-6,000

-8,000

-8,000

Pippin (1970), 

Sorenson (2005)

Breeze (1970) Al-Shaieb and others (1994)

This study

Reference well

Belitz and Bredehoeft (1988)

Bair (1987)

COLORADO

OKLAHOMA

TEXAS

KANSAS

Basin axis

102° 100°

37°

38°

39°

35°

34°

98° 96°

36°

Panhandle-Hugoton

field

Structural contours on

Woodford Shale

-6,000

Faults in

basement rocks

0 15 30 MILES

0 15 30 KILOMETERS

Nelson_Ch9_Figure 1
Introduction 3

Figure 2. Stratigraphic chart of the 

Anadarko Basin, with stratigraphic 

units (purple shading) as defined in this 

study to examine pressure data. The 

lithostratigraphic units are modified 

from Higley (chapter 3 of this report). 

Geohydrologic units were defined 

by Jorgensen and others (1996) for 

a regional study; light blue shading 

indicates the presence of rock units with 

well defined patterns of hydraulic head 

that can be considered to be aquifers. 

Cretaceous rocks are not present in the 

study area of figure 1 but are present 

in the regional study area of Jorgensen 

and others (1996). Wavy lines represent 

unconformities. Areas with vertical lines 

represent periods of non-deposition. PC, 

Precambrian; Camb., Cambrian; Miss., 

Mississippian.

Sumner Group, Enid Group, 

Hennessey Group

System

Series Lithostratigraphic Units

 in the Anadarko Basin

Permian Pennsylvanian Miss. Devonian Silurian Ordovician Camb.

Leonardian

Wolfcampian

Virgilian

Missourian

Desmoinesian

Atokan

Morrowan

Chesterian

Meramecian

Osagean

Kinderhookian

Chautauquan

Cayugan

Cincinnatian

Trempealeauan

Niagaran

Canadian

Champlainian

Chase Group

Admire Group

Lansing Group 

Marmaton Group

Atoka Group

Morrow Group/Formation

Springer Formation

Chester Group 

Wabaunsee Group

Shawnee Group

Douglas Group

Ada Group

Franconian

Woodford Shale

Misener sand

Hunton Group

Sylvan Shale; Maquoketa Shale 

Simpson Group

Arbuckle Group

Reagan Sandstone

Alexandrian

Senecan

Council Grove Group Pontotoc 

Group

Viola Group/Formation

Meramec lime

Osage lime

Mayes Group

Kansas City Group Hoxbar Group

Cherokee Group Deese Group

Kinderhook Shale

Erian

Ulsterian

Guadalupian Whitehorse Group; El Reno Group

Cretaceous Tertiary PC

 Stratigraphic

 Units (this study)

Triassic Jurassic

Ochoan

Upper

Lower

Dockum Group

Ogallala Formation

absent

absent

absent

Nelson_Ch9_Figure 2

Permian

Virgilian

Missourian

Desmoinesian

Mississippian

Hunton and older

Morrowan

Geohydrologic

Units

High Plains aquifer

Great Plains 

confining system

Maha aquifer

Apishapa 

aquifer

Apishapa

confining unit

Great

Plains

aquifer

system

Western

Interior

Plains

confining

system

Western

Interior

Plains

aquifer

system

Basement

confining unit

Lower

aquifer

units

Confining

unit

Upper 

aquifer

unit
4 Potentiometric Surface Maps for Seven Stratigraphic Units in the Greater Anadarko Basin

and eastern boundaries of Bair’s study are shown in figure 1. 

The strata in the deepest of three hydrostratigraphic flow units, 

which includes Cambrian to Wolfcampian rocks, are underpressured. The underpressured condition is partly attributed to 

the “greater depth from the ground surface to potentiometric 

levels in the deep-basin strata beneath the High Plains compared to the Rolling Plains” and that “the regional flow pattern 

is controlled by the elevation and location of outcrops serving 

as regional recharge and discharge areas” (Bair, 1987, p. 169). 

Belitz and Bredehoeft (1988) examined the cause of underpressure in the Denver Basin and developed a hydrologic flow 

model extending from eastern Colorado into southern South 

Dakota, Nebraska, and Kansas; the southwestern corner of 

their study area is indicated in figure 1. The general cause of 

an underpressured or subnormal condition was stated by Belitz 

and Bredehoeft (1988, p. 1356):

“Generally, subnormal fluid pressures might be 

found in any subaerial, topographically tilted, 

structural basin capped by a thick sequence of lowpermeability rocks (i.e., shale or evaporites). The 

tilt can provide the topographic driving force for the 

fluid flow. The low-permeability cap can provide 

insulation from the elevation head of the water table, 

and the structure can provide the mechanism for 

reducing permeability in the basin deep that allows 

for better hydrologic connection to low-elevation 

outcrops than to high-elevation outcrops.” 

As indicated by the findings of Bair (1987), Belitz and 

Bredehoeft (1988), and Sorenson (2005), surface topography 

and outcrop elevation are critical considerations in diagnosing an underpressured condition. Surface elevation is greater 

than 4,400 ft above sea level in the northwestern part of the 

study area, and declines to less than 800 ft in the southeastern 

part (fig. 4). Contours of surface elevation trend north-south in 

most of the study area, with westward swings where river valleys are present. As a consequence of the general north-south 

elevation contours, outcrops in central Oklahoma and Kansas 

also trend north-south, as shown by outcrops of Lower Permian Garber Sandstone and Virgilian formations, and the base of 

the Permian Wellington Formation (fig 4). These north-south 

Figure 3. Map of Anadarko Basin showing pressure-depth ratios for reservoirs of Desmoinesian 

age, based on data from NRG Associates (2009). psi/ft, pounds per square inch per foot.

0.30

0.30

0.40

0.40

0.40

0.50

0.50

0.60

0.14

0.22

0.23

0.23 0.24

0.25

0.25

0.26

0.26

0.26

0.27

0.27 0.29 0.29

0.31

0.31

0.32

0.33

0.33

0.33

0.33

0.34

0.34

0.34

0.34

0.34

0.35

0.35

0.36

0.36

0.36

0.37

0.37

0.37

0.38 0.38

0.38

0.38

0.38

0.39 0.39

0.39

0.41

0.42

0.43

0.43

0.43

0.43

0.45

0.45

0.45

0.46

0.46

0.52

0.52

0.68 0.84

1.16

0.31

0.38

EXPLANATION

Pressure-depth ratio in 

 psi/ft in oil and gas fields

 

Precambrian faults from

 Adler and others, 1971

0.38

0.30 to 0.42 psi/ft

0.43 to 0.50 psi/ft

Greater than 0.50 psi/ft

Less than 0.30 psi/ft

COLORADO

KANSAS

OKLAHOMA

TEXAS

Nemaha uplift

Basin axis

102° 101° 100° 99° 98° 97°

38°

37°

36°

35°

34°

0 15 30 MILES

0 15 30 KILOMETERS

Nelson_Ch9_Figure 3
Introduction 5

trending outcrops of Early Permian and Late Pennsylvanian 

age, in close proximity to the Nemaha uplift, play an important 

role in our interpretation of the hydrologic regime of the basin. 

The burial history chart (fig. 5) reveals rapid deposition 

and burial during Late Mississippian and Pennsylvanian time. 

During times of rapid burial, overpressure developed in rocks 

of the Morrowan, Atokan, Desmoinesian, Missourian, and to 

a lesser degree in the Virgilian Series, all or in part of Pennsylvanian age, as indicated schematically by the red highlighting in figure 5; overpressure development is the subject of a 

companion report (Nelson and Gianoutsos, chapter 8 of this 

report). Uplift and erosion occurred in recent geologic time 

as indicated by the linear decrease in depth for all rock units 

from 45 to 0 Ma. As uplift and erosion took place, hydrologic 

conditions were altered, causing the development of underpressure, as symbolized by the vertical blue bar at the right 

hand side of figure 5. The areal and stratigraphic distribution 

of underpressure, as expressed in potentiometric and derivative maps, is the subject of this chapter of the report. The 

burial history chart demonstrates that the creation of overpressure and underpressure are widely separated in geologic time.

Mudstones and evaporites of Permian age form a low 

permeability cap (fig. 5) that covers most of the study area. 

The cross section of figure 6 shows that a sequence of mudstones and evaporites is 1,800-ft thick at the Texas-Oklahoma 

border. Anhydrites and gypsum of the Blaine Formation 

(fig. 6) extend into Oklahoma where they are mapped in 

outcrop (Fay, 1964). Based on mud log data from oil and 

Figure 4. Map of greater Anadarko Basin showing surface elevation contours in 400-foot 

intervals, basin axis, Precambrian faults, and outcrops of selected formations. Precambrian 

faults from Adler and others (1971). Thickness of Permian evaporites from Gianoutsos and 

others (chapter 10 of this report). Outcrops of Garber Sandstone and three Virgilian formations, 

and base of Wellington Formation in Kansas and Oklahoma from Stoesser and others (2005). 

East-west oriented Line F shows location of drillstem test data shown in figure 10.

800 

1,200

1,600

2,000

2,800

2,400

3,200

3,600

4,400

4,000

800

1,600

1,200

2,000

2,400

2,800

3,200

4,000

3,600

Central Kansas Uplift

500

100

0

103° 102° 101° 100° 99° 98° 97°

38°

39°

37°

36°

35°

34°

0 15 30 MILES

0 15 30 KILOMETERS

Thickness (feet) of

Permian evaporites

Nemaha uplift

Virgilian outcrops

Garber Sandstone

(Lower Permian)

Base of Wellington

Formation (Base of

Leonardian)

Basin axis

Precambrian 

faults

Line F

Nelson_Ch9_Figure 4

KANSAS

COLORADO

OKLAHOMA

TEXAS
6 Potentiometric Surface Maps for Seven Stratigraphic Units in the Greater Anadarko Basin

gas wells, evaporites are nearly ubiquitous in Upper Permian strata throughout the Anadarko Basin (Gianoutsos and 

others, chapter 10 of this report), thinning to zero thickness 

immediately west of the Nemaha uplift (fig. 4). The eastward 

extent of Leonardian strata is demarcated by the base of the 

Wellington Formation of the Enid Group in the vicinity of the 

Nemaha uplift (fig. 4). Although no direct measurements of 

permeability were conducted for this study, the permeability of 

evaporites below 1,500 ft of burial is reduced to levels so low 

that the beds are considered impermeable to groundwater flow, 

based on geological evidence and laboratory measurements 

(Ingebritsen and others, 2008, p. 340–342). Thus an impermeable cap of Permian age separates shallow aquifers from 

deeper strata that are Pennsylvanian and older.

These four geologic elements—basin structure, surface 

topography, uplift and erosion, and an impermeable cap (figs. 

1, 4, 5, and 6)—compose the essential elements resulting in 

the present-day hydrologic regime. The main contribution of 

this report is documentation of the potentiometric surfaces at 

the basin scale for seven stratigraphic units—Hunton Groupand-older, Mississippian, Morrowan, Desmoinesian, Missourian, Virgilian, and Permian. Inspection of the potentiometric 

surfaces, and of a second set of surfaces showing the separation between each potentiometric surface and surface elevation, provide an explanation for the underpressured conditions 

that exist in the northern and northwestern portions of the 

greater Anadarko Basin. 

The present study lies in the southwestern part of a 

regional examination of major hydrologic units in the central 

Midwest, an area encompassing all of Kansas and Nebraska 

and parts of adjoining states (Jorgensen and others, 1993). 

The relation between the aquifers and confining units of the 

regional study and the stratigraphic units of this chapter of the 

report can be examined in figure 2. Of the units defined in the 

regional study, the Western Interior Plains aquifer and confining systems are most relevant to the present study. The lower 

and upper aquifer units of the Western Interior Plains aquifer 

are nearly identical to the Hunton-and-older and Mississippian 

Figure 5. Burial history for the Ferris 1-28 well, from Carter and 

others (1998). Overpressure developed during rapid burial during 

Pennsylvanian time with a possible secondary development around 

100 Ma. Underpressure development is believed to be recent, 

commensurate with exposure of strata in central Oklahoma. The 

Permian cap provides a low permeability seal over the area. pC, 

Precambrian; _, Cambrian; O, Ordovician; S, Silurian; D, Devonian; M, 

Mississippian; P, Pennsylvanian; P, Permian, T, Triassic, J, Jurassic; K, 

Cretaceous; PE, Paleocene; E, Eocene; O, Oligocene, M, Miocene; Fms, 

Formations; Gp, Group; Ss, Sandstone, °C, degrees Celsius.

0

2,000

4,000

6,000

8,000

10,000

12,000

600 500 400 300 200 100 0

225 ̊C

200 ̊C

175 ̊C

150 ̊C

125 ̊C

100 ̊C

75 ̊C

50 ̊C

25 ̊C Guadalupian

Leonardian

Wolfcampian

VirgilianMissourian

DesmoinesianAtokan

MorrowSpringer Fms

Mississippian (Part) WOODFORD SHALE

SYLVAN SHALE

Hunton Group

Viola-Simpson Fms

Arbuckle Gp -

Reagan Ss

Time, in millions of years

Depth, in meters

Ochoan

Development of

underpressure

Development of

overpressure

Deposition of

Permian cap

Nelson_Ch9_Figure 5

  O S D M P T J K E OM




Figure 6. Structural cross section showing Permian and younger rocks in the Texas Panhandle (see inset for location). Mudstone, ansalt form impermeable layers in Permian rocks. An interpreted salt dissolution feature is near the center of the section. From McGook(1988). Co., County; Quat., Quaternary; Tert., Tertiary; Fm., Formation; Gp., Group.

ELEVATION

METERS

1,300

1,200

1,100

1,000

900

800

700

600

500

400

300

200100

Sea

Level

FEET

4,200

4,000

3,800

3,600

3,400

3,200

3,000

2,800

2,600

2,400

2,200

2,000

1,6001,800

1,400

1,200

1,000

800600400200

0

VERTICAL EXAGGERATION = 106x

WEST 

HARTLEY 

CO.

DALLAM 

CO.

HARTLEY

CO.

by D. A. McGookey, T. C. Gustavson, and A. D. HoadleyBureau of Economic Geology1988

Dalhart Basin

HIGH PLAINS

Cimarron Arch Anadarko Basin

MOORE

CO.

HUTCHINSON

CO.

ROBERTS

CO.

HEM

ROLLING PLAINS ? ?

CANADIAN 

 RIVER

OKLAHOMA

TEXAS

NEW MEXICO

TriassicDockum Gp

Anhydrite

Sandstone

Mudstone

Salt; salt with mud

Mudstone

Dolomite

salt dissol.

175 miles

0 10 20 MILES

0 10 20 KILOMETERS
8 Potentiometric Surface Maps for Seven Stratigraphic Units in the Greater Anadarko Basin

stratigraphic units of the present study. The Western Interior 

Plains confining system includes permeable sandstone and 

limestone beds within thick shale units. Because the sandstone 

and limestone beds do not extend across the entire area of the 

confining system, they are not considered a regional hydraulic system (Jorgensen and others, 1993, p. B50). However, 

as demonstrated in this paper, maps of hydraulic head values 

for the Morrowan, Desmoinesian, Missourian, Virgilian, and 

Permian stratigraphic units suggest good hydraulic continuity over our study area. Corresponding lithostratigraphic units 

for the Cretaceous age Great Plains aquifer and confining 

systems are not shown in figure 2, because Cretaceous age 

rocks are only marginally present in our study area and were 

not considered as part of this study. The High Plains aquifer, 

which consists of the Ogallala Formation and unconsolidated 

deposits, will receive only brief consideration in this chapter 

of the report.

To develop potentiometric surfaces, we used pressure 

measurements in oil and gas wells that were obtained from 

drillstem tests over a time period of more than 50 years. Two 

steps are required to construct a potentiometric surface from 

pressure data. The first step, the conversion of a pressure 

measurement to hydraulic head, seemingly a straightforward 

computation, is complicated by the presence of gas and by 

variations in the density of water, the latter primarily because 

of salinity variations; these complications are discussed in 

the following sections, “Conversion of pressure to hydraulic 

head” and “Effect of density variations on the computation of 

hydraulic head.” The second step, the conversion of individual hydraulic head values to form a potentiometric surface, 

requires examination of a large number of values distributed 

unevenly within the study area. For several reasons, only a 

fraction of these values are valid and can be used to define a 

potentiometric surface. The useful fraction is determined on a 

set of 13 west-east swaths on which the data are inspected and 

filtered, and from which a potentiometric level is defined as a 

continuous curve along the length of the swath. The potentiometric levels from the swaths are then combined using mapping algorithms to construct a potentiometric surface. These 

procedures are described in detail in the section “Potentiometric surfaces.”

Conversion of Pressure to Hydraulic 

Head

In oil and gas exploration, formation pressure P is routinely measured and plotted as a primary parameter of interest. 

As an example, pressure data from the Oklahoma Panhandle 

are plotted as a function of the elevation of the test interval 

(fig. 7). A solid blue line represents a hydrostatic gradient of 

0.465 psi/ft and an intercept of 2,542 ft on the vertical axis, 

which is the average surface elevation for this dataset. Virtually all the pressure data fall to the left of the hydrostatic line, 

indicating a state of underpressure. Four dashed lines, each 

with a gradient of 0.465 psi/ft, intercept the elevation axis at 

0, 500, 1,000, and 1,500 ft. Each intercept represents the value 

of hydraulic head H for a point lying on its respective line. For 

example, a point lying on the upper dashed line has a value of 

H equal to 1,500 ft.

In hydrological work, hydraulic head H (also referred to 

as potentiometric elevation) is a primary parameter of interest. 

In order to map potentiometric surfaces within a stratigraphic 

unit, we need to convert measurements of P to H. The relation between the two, which is discussed in textbooks (for 

example, Fetter, 1988; Toth, 2009), is straightforward if three 

assumptions can be made regarding the fluids in the formation. First, it is assumed that flow velocity is negligible, so 

that kinetic energy is unimportant compared to potential 

energy. Second, it is assumed that fluid density does not vary 

much within the area under study. This second assumption 

is violated because the density of water varies with pressure, 

temperature, and salinity; the resulting limitations on the 

conversion of P to H and the resulting potentiometric surfaces 

are discussed in the section “Effect of density variations in the 

computation of hydraulic head.” Third, if gas instead of water 

is the continuous phase, then the simple relation that follows 

cannot be applied, as discussed by Nelson and Condon (2008). 

Consequently, we chose not to compute H in the deep overpressured basin, because we suspect that gas is the continuous 

phase in parts of the deep basin.

Hydraulic head, H, is the sum of two components,

H = Z + P/ρg	 (1a)

where

Z is the elevation of the perforated interval, P is 

the formation pressure, ρ is the density of 

water, and g is the acceleration of gravity. 

In oilfield units Z is in feet, P is in psi, ρg

is in psi/ft, and consequently H is in feet. 

Equation 1a can be rearranged,

Z = H - P/ρg	 (1b)

which is the equation for the lines plotted in figure 7, with Z

the variable on the vertical axis, H the intercept on the vertical 

axis, P the variable on the horizontal axis, and 1/ρg the slope 

of the line. For any pressure measurement P at an elevation 

Z, the equivalent H can be determined graphically (fig. 7) or 

computationally using equation 1a. It should be mentioned 

that a pressure-depth plot is not compatible with equation 1b. 

Compatibility with equation 1b requires that pressure be plotted as a function of elevation, as it is in figure 7.

Following the convention of other investigators in the 

Anadarko Basin, we set ρg = (ρg)o = 0.465 psi/ft, which corresponds to a brine density of 1.07 g/cm3

. As already mentioned, 

density varies as a function of salinity, temperature and pressure, so adoption of a fixed value of 0.465 psi/ft introduces 

errors that are discussed in the section “Effect of density variations in the computation of hydraulic head.” The reference 
Conversion of Pressure to Hydraulic Head 9

elevation for Z is taken to be sea level, which means that H is 

determined relative to sea level. Elevations above sea level are 

positive and elevations below sea level are negative.

As an example, consider the case where the pressure P

determined from a drillstem test is 700 psi, the mean perforated depth D for the drillstem test is 2,000 ft, and the Kelly 

Bushing elevation (KBE), is 3,500 ft (Well A in fig. 8). (Depth 

in a well is measured from the Kelly bushing on the drill rig 

rather than from ground surface; consequently KBE must be 

used to determine the elevation of a point in the well corresponding to a particular depth.)

The mean elevation for the drillstem test is

Z = -(D - KBE) = -(2,000 – 3,500) = 1,500 ft.

The hydraulic head is

H = Z + P/(ρg)o = 1,500 + 700/0.465 = 3,000 ft. 

And the pressure/depth ratio for this example is 

P/D = 700/2,000 = 0.35 psi/ft. 

Hydraulic head is computed for each stratigraphic unit 

and displayed as a function of latitude or longitude. Pressures 

from drillstem tests, depths of measurement, and KBEs were 

taken from IHS Energy (2009). The pressure value is the largest of either the initial shut-in value or the final shut-in value 

of a drillstem test. A very low pressure will result in a hydraulic head not much greater than Z, the measurement elevation, 

and is considered invalid. A potentiometric surface is determined by mapping and contouring the high values of hydraulic 

head of each stratigraphic unit. 

The pressure-depth ratio can be expressed in terms of H, 

Z, and D by rearranging equation 1a and dividing by D,

P/D = 0.465*(H – Z)/D (2a)

which shows that the pressure-depth ratio is proportional to 

(H – Z)/D. In figure 8, (H – Z)/D = (3,000–1,500)/2,000 = 

0.75 ft in Well A and (H – Z)/D = [1,000-(-2,000)]/4,000 = 0.75 

in Well B, showing that the P/D ratio is 0.75 that of normal in 

both wells, and is equal to 0.75×0.465 = 0.35 psi/ft. Equation 

2a has a simple geometrical interpretation: if the cross formed 

by the vertical brown line (length D) and the horizontal blue 

Figure 7. Graph showing pressure in relation to elevation from 

wells in a small area in the Oklahoma Panhandle. The average 

surface elevation of 2,542 feet is represented by the y-intercept 

of the hydrostatic gradient. The dashed lines are reference 

lines for the pressure data, most of which correspond to 

underpressured conditions.

Pressure, in pounds per square inch

0 1,000 2,000 3,000 4,000 5,000

Elevation relative to sea level, in feet

4,000

2,000

0

-2,000

-4,000

-6,000

Hydrostatic gradient

Nelson_Ch9_F
10 Potentiometric Surface Maps for Seven Stratigraphic Units in the Greater Anadarko Basin

line (elevation H) retains the same proportion from one well to 

the next, then the pressure-depth ratio is constant.

Equation 2a can also be written in terms of the vertical 

separation between the surface elevation KBE and H,

P/D = 0.465*{1 – (KBE – H)/D} (2b)

The main products of the present work are maps of 

hydraulic head H, referred to as potentiometric surfaces, and 

of H – KBE, the separation between H and the Earth’s surface. 

The separation H – KBE is used as an indicator of underpressure rather than the ratio P/D.

Effect of Density Variations in the 

Computation of Hydraulic Head

The conversion of pressure P to hydraulic head H in 

equation 1a requires a choice of density ρg. We used a value 

(ρg)o = 0.465 psi/ft, a value that corresponds to a sodium 

chloride brine with a specific gravity of 1.074 and a salinity 

of approximately 101,700 parts per million (ppm) at standard 

conditions of pressure and temperature. Because density 

varies with salinity, pressure, and temperature, the effect 

of this assumption on H at different locations in the basin 

requires evaluation. 

Relation Between Salinity and Density for 

Sodium Chloride Solutions

Salinity is measured by weighing a salt solution, then 

weighing the solids that remain after evaporating the solution. Salinity is referred to as “total dissolved solids” (TDS) 

and expressed as weight percent or as ppm. For example, 

1,000 grams (g) of solution containing 30 g of solids 

would have TDS = (30/1,000)*100 = 3 weight percent or 

(30/1,000)*106 = 30,000 ppm. The TDS of sea water is 

around 35,000 ppm. 

The volume of brine is not a simple function of solute 

weight and water weight. Consequently, the density of brine 

(weight divided by volume) cannot be computed simply from 

TDS, it must be measured. Measurements for sodium chloride 

brine are tabulated in terms of specific gravity (SG) as a function of TDS (Wolf and others, 1973). (The specific gravity of 

brine is equivalent to the weight of brine divided by the weight 

of an equivalent volume of distilled water. Specific gravity is 

a dimensionless quantity.) The density of brine in field units 

Figure 8. Example demonstrating the calculation of 

hydraulic head and pressure-depth ratio for two wells testing 

the same formation. The pressure-depth ratio is the same in 

the two wells, but the hydraulic head is much greater in Well 

A than in Well B. ft, foot; psi, pounds per square inch; psi/ft, 

pounds per square inch per foot.

Hydraulic head 

H = Z + P / 0.465

Horizontal distance, many miles

Elevation, in feet –2,000

0

2,000

4,000

Drillstem tests

Sea Level

3,000 ft

1,000 ft

DST elevation Z 1,500 ft

Surface elevation 3,500 ft

2,000 ft

 Well A Well B

Total depth 2,000 ft 4,000 ft

Pressure P 700 psi 1,400 psi

Pressure/Depth 0.35 psi/ft 0.35 psi/ft

Nelson_Ch9_F

–2,000 ft
Effect of Density Variations in the Computation of Hydraulic Head 11

such as pounds per gallon (ppg), or pounds per square inch per 

foot (psi/ft) are related to SG by 

SG = ρg (ppg) / 8.33 = ρg (psi/ft) / 0.433 (3)

where 8.33 ppg is the density of water in pounds per gallon and 0.433 psi/ft is the density of water in psi/ft. In the 

petroleum industry, the unit of psi/ft is referred to as pressure 

gradient. However, psi/ft is also a unit of density, being the 

weight in pounds of water contained in 12 cubic inches (one 

square inch in area by one foot in height). The relations among 

density, specific gravity, and salinity for sodium chloride solutions are given in table 1.

The density of water increases with an increase in pressure and decreases with an increase in temperature. Because 

both pressure and temperature increase with increasing depth, 

the two effects tend to cancel over restricted ranges of pressure 

and temperature. For example, the volume factor for water is 

1.00±0.01 for a temperature of 100 °F and pressures of 1,000, 

2,000, and 3,000 psi, and also for a temperature of 150 °F and 

pressures of 3,000, 4,000, and 5,000 psi (table 2). However, at 

200 °F, a pressure greater than 5,000 psi is required to maintain a volume factor of 1.00±0.01. Temperatures of 200 °F 

and greater are attained in the deep basin, but not on the flanks 

of the basin that are the focus of this study. Thus, most of 

the variation in density will be because of salinity variations, 

which are examined next.

Salinity of Subsurface Waters

In the Anadarko Basin, the salinity of produced waters 

takes a wide range of values, from less than 10,000 ppm to 

greater than 300,000 ppm (fig. 9, pl. 1). The 8 salinity increments of approximately 30,000 ppm chosen for the maps 

of plate 1 correspond to equal increments of 0.01 psi/ft for 

density, as shown in table 1. High salinity values are shown 

in the brightly colored symbols and low salinities are in dull 

colors. Unfortunately, the salinity data are not distributed 

evenly across the basin, but are clustered along and east of the 

Nemaha uplift in Oklahoma and within the Central Kansas 

uplift (pl. 1). Data within the deep Anadarko Basin are few in 

number, with the exception of data for the Morrow Formation 

(pl. 1C). Some observations are:

1. The highest values, greater than 220,300 ppm, lie along 

the south-north trending Nemaha uplift in the following 

units: Hunton-and-older, Mississippian (limited data), 

Desmoinesian, Missourian, and Virgilian. Salinities 

Table 1. Increments of density used for salinity maps of plate 1, in units of pounds per square inch per foot. Specific gravity 

(dimensionless) is equivalent to density. Equivalent total dissolved solids (parts per million, ppm) for sodium chloride solutions taken 

from Wolf and others, 1973. Δρ/ρ (dimensionless) is the fractional change in density from the base value of 0.465 psi/ft.

[psi/ft, pounds per square inch per foot; TDS, total dissolved solids] 

Density

(psi/ft) 0.433 0.445 0.455 0.465 0.475 0.485 0.495 0.505

Spec. gravity 1 1.028 1.051 1.074 1.097 1.120 1.143 1.166

TDS (ppm) 0 35,754 70,552 101,737 132,349 162,377 191,723 220,284

Δρ/ρ –0.0688 –0.0430 –0.0215 0.0000 0.0215 0.0430 0.0645 0.0860

Table 2. Specific volume of water as a function of pressure and temperature, 

from Amyx and others (1960).

Pressure

(pounds per square inch) Temperature (°F)

100 150 200 250

1000 1.0025 1.0153 1.0335 1.0560

2000 0.9995 1.0125 1.0304 1.0523

3000 0.9966 1.0095 1.0271 1.0487

4000 0.9938 1.0067 1.0240 1.0452

5000 0.9910 1.0039 1.0210 1.0418
12 Potentiometric Surface Maps for Seven Stratigraphic Units in the Greater Anadarko Basin

decrease eastward from the Nemaha uplift in all five of 

these units, showing similar salinity trends in all units for 

which data are available for the Nemaha uplift. 

2. Along the central Kansas uplift, in rocks of Missourian, Virgilian, and Permian age, TDS is greater than 

220,300 ppm at the southeast end of the uplift and 

decreases to the northwest, although values at the northwest end of the uplift generally remain greater than 

100,000 ppm. In rocks that are Hunton and older in age, 

the highest values are 132,000 ppm at the southeast end 

of the central Kansas uplift, and decrease to the northwest 

where many values are less than 36,000 ppm. Thus, along 

the Central Kansas uplift, waters in rocks that are Hunton 

and older in age are considerably less saline than rocks of 

Missourian, Virgilian, and Permian age.

3. Waters in rocks of Morrowan age are less than 

36,000 ppm in the deep basin and onto the shelfal area of 

the northeastern Texas Panhandle and the eastern Oklahoma Panhandle (pl. 1C). Values are erratic north and 

west of the limit of the 36,000 ppm values. Spatial variations in the chemistry of Morrowan waters are discussed 

in chapter 8 of this report on present-day overpressure and 

paleopressure indicators (Nelson and Gianoutsos, chapter 

8 of this report). 

4. In areas other than the Nemaha uplift and the Central 

Kansas uplift, and with the exception of the Morrowan 

unit, the salinity data are few in number and reveal no 

obvious trends. 

Problem of Variable Brine Density in Computing 

Hydraulic Head

Variable brine density constitutes an important 

theoretical problem in basin-scale groundwater flow modeling 

(Bachu, 1995; Bachu and Michael, 2002). In dealing with aquifers 

of limited spatial extent, it is reasonable to assume constant brine 

density when computing hydraulic head in accordance with 

equation 1a,

H = Z + P/ρg	 (1a)

However, for the deep confined basin-scale aquifers 

that are considered in this chapter of this report, the brine 

density ρg varies throughout the basin because of variations 

in salinity, pressure, and temperature. As explained by Bachu 

(1995), because of the variations in density ρg, the driving 

force on a unit quantity of brine cannot be written simply as the 

gradient of a potential, H. However, the horizontal component 

of flow in aquifers of finite dip can be represented in the 

following formulation of Darcy’s law (Bachu and Michael, 2002, 

equation 5),

Figure 9. Box-and-whiskers plot of salinity in seven stratigraphic 

units with number of samples in each group. Each whisker and each 

box represents 25 percent of the data. Salinity data taken from a 

compilation by Breit (2002), which is based on waters produced from 

oil and gas wells. 

Total dissolved solids, in parts per million

0 100x103 200x103 300x103 400x103

Permian 385 

Virgilian 607 

Missourian 1,115

Desmoinesian 1,560

Morrowan 508

Mississippian 564

Hunton Group and older 4,144

minimum median maximum

25th percentile 75th percentile
Computation of Hydraulic Head along West-East and South-North Swaths 13

q = − ∇ + ∇ 



 



 kρ g E o

μ o

∆ ρ

ρo

H

(4)

where

k is permeability, μ is viscosity, Ho is defined 

in equation 1a with ρ set equal to ρo, Δρ = 

ρ – ρo, and E is the elevation of the surface 

representing the aquifer. This formulation 

shows that the flow vector q is the vector 

sum of ∇Ho, which is directed along the 

maximum hydraulic gradient, and ∇E, 

which is directed along the maximum 

slope of the aquifer surface. The term ∇Ho

is the force due to the combined gradients 

of pressure and measurement elevation and 

is directed perpendicular to the contours 

of Ho. The term (Δρ/ρ)∇E is the buoyancy 

force because of variations in brine density 

and is directed downslope if ρ>ρo, and 

Δρ is therefore positive, or upslope if 

ρ<ρo. In areas where the leading term, is 

unchanging, the direction of flow vector q

is given by the vector sum of the two terms 

in equation 4. 

The buoyancy term (Δρ/ρ)E in equation 4 is insignificant 

in areas where (1) density (ρg) is equal to (ρog) or nearly so, 

and (or) (2) lateral changes in the elevation of the aquifer 

are small. In these two situations, the flow vector direction 

depends only on the gradient of hydraulic head. On the other 

hand, the ∇Ho term can be less than the ∇E term in equation 4 

wherever the hydraulic head Ho has little lateral variation but 

density and aquifer elevation are changing. As a consequence 

of salinity and elevation changes, the flow vector q will 

undergo local variations in direction that cannot be derived 

from inspection of the potentiometric surface. This fact must 

be kept in mind when inspecting the potentiometric surfaces 

discussed in the subsection “Maps showing potentiometric 

surfaces and overpressured areas.” 

Numerical hydrologic models are a means of accounting for variations in density and permeability. As an example, 

along the Nemaha uplift and central Kansas uplift where salinity variations are greatest, a numerical model that accounts 

for variable density produced flow vectors that differ significantly from flow vectors produced by a constant-density 

model (Signor and others, 1996, p. C59–C75). However, at 

this point our purpose in constructing potentiometric maps and 

cross sections is to understand the nature of underpressuring 

in the Anadarko Basin and not to model groundwater flow. 

Equation 4 is not used to compute flow vectors but serves to 

explain the limitations of the potentiometric surfaces that are a 

product of this report.

The preceding discussion of density variations leads to 

two conclusions regarding the computation of hydraulic head 

in the Anadarko Basin. First, we cannot expect that local flow 

vectors can be accurately derived from the potentiometric 

surfaces. Second, the effect of salinity variations are likely to 

be greatest in those areas where salinity gradients are manifest, 

particularly along the Nemaha uplift and along the southern 

edge of the Central Kansas uplift. 

Computation of Hydraulic Head along 

West-East and South-North Swaths

The computation of hydraulic head along a west-east 

profile is illustrated in figure 10, which shows drillstem tests 

within a swath that is six miles wide in the north-south direction. Each data point in parts A, B, and C of figure 10 represents either data (surface elevation, elevation of drillstem tests, 

pressure) or a computed parameter (hydraulic head, pressuredepth ratio) from rocks of Missourian age. The surface 

elevations reveal the eastward drop from 4,200 ft in the west 

to 1,000 ft at the east end of the swath. The concave-upward 

pattern of the test elevations, which lie above sea level at the 

west and east ends of the swath, results from the intersection of the west-east line and the northward-shallowing basin 

geometry. The upper edge of the pressure data forms a convexupward pattern, which when summed with the test elevations 

in accordance with equation 1a, forms the upper edge of the 

hydraulic head pattern (fig. 10A) that is labeled “interpreted 

level of hydraulic head.” Although the elevations and pressure measurements vary by thousands of feet, their values are 

complementary and tend to cancel when summed, leaving an 

interpreted level of hydraulic head that changes by less than 

500 ft from west to east. 

Pressures falling below the convex-upward bound in 

figure 10B did not sample the original formation pressure and 

result in hydraulic head values that fall below the upper edge 

in figure 10A. Thus, only a fraction of the pressure measurements convert to interpretable values of hydraulic head which 

are indicated by the horizontal lines at the upper edge of the 

red dash symbols. A few values of hydraulic head H that are 

higher than the interpreted level of hydraulic head, such as 

those from longitude 101° to 102° W., could be because of 

small isolated compartments of high pressure or possibly 

because of pressure maintenance operations. The elevation 

of the Ogallala water table is considerably higher than the 

interpreted level of hydraulic head for the Missourian rocks 

(fig. 10A). The impermeable cap of Permian rocks (fig. 5) 

separates the shallow Ogallala aquifer from the deeper and 

older hydrological systems represented by Missourian rocks 

in figure 10. 

Dividing a pressure measurement by the depth of the 

measurement results in the pressure-depth ratio plotted in figure 10C. As was the case for hydraulic head, only the upper 

edge of the data swarm represents the true pressure-depth 

ratio at that location, because most of the pressure measurements were less than true formation pressure. The upper edge 

of the swarm of pressure-depth values reaches a maximum 

at long 98° W., where it is somewhat less than the value of 
14 Potentiometric Surface Maps for Seven Stratigraphic Units in the Greater Anadarko Basin

Figure 10. Data from drillstem tests in Missourian rocks from 

west-east swath Line F close to and parallel with the KansasOklahoma border (location in figure 4). A, Surface elevation (black 

plus symbols), elevation of drillstem tests (triangular symbols), 

and computed hydraulic head (red dash symbols); B, pressure 

measurements; C, computed pressure-depth ratio indicating 

underpressure where less than 0.465 pounds per square inch per 

foot (psi/ft).

Line F latitude 37° 10’ N. to 37° 15’ N. Drillstem tests in Missourian rocks

-4000

0

2000

4000 Surface

elevation

Elevation of

drillstem tests

COLORADO KANSAS

Pressure-depth ratio 

Longitude, in degrees

104° W 102° W 100° W 98° W 96° W

Pressure-depth ratio,

in psi/feet

0.2

0.3

0.4

0.5

0.6

0.465 psi/ft 

Pressure 

Pressure, in pounds

per square inch

0

500

4,000

2,000

–2,000

–4,000

2,500

2,000

1,500

1,000

Elevation, in feet

0 110 MILES

0 110 KILOMETERS

Hydraulic

head

Ogallala water table

Interpreted level of hydraulic head

A

B

C

Nelson_Ch
Potentiometric Surfaces 15

0.465 psi/ft that was assumed for the conversion of pressure to hydraulic head (equation 1a). West of that point, the 

pressure-depth ratio declines to less than 0.3 psi/ft, illustrating a westward increase in the degree of underpressure. As 

seen in figure 10A, the progressive westward increase in the 

degree of underpressure coincides with increasing separation 

between the surface elevation and the interpreted level of 

hydraulic head. In the following discussion, we will use the 

separation between surface elevation and the upper edge of 

hydraulic head as an indicator of underpressure, rather than 

the pressure-depth ratio.

The format of figure 10A is repeated in plate 2, which 

contains four south-north cross sections arranged in four columns. Seven stratigraphic units are displayed for each southnorth cross section; the stratigraphic units form the seven rows 

of plate 2. The geometry of the surface elevations and the 

drillstem test elevations on plate 2 have a different “look” than 

those of figure 10. On each cross section of plate 2, the surface 

elevation is relatively unvarying from south to north; however, 

the west-to-east drop in surface elevation is apparent on the 

progression from lines H, where surface elevation is around 

3,000 ft, to line N, where surface elevation is around 1,000 ft. 

The drillstem test elevations, which display a U-shaped geometry on the west-east line in figure 10, show the asymmetry 

of the Anadarko Basin on the south-north lines of plate 2. For 

example, the Desmoinesian test elevations on line J drop by 

6,000 ft from north to south. The major structure bounding 

the southern part of the basin is revealed by the upturn in test 

elevations at latitude 35° 30’ N. on the Desmoinesian and the 

Hunton-and-older sections of line J. 

As previously discussed in connection with figure 10, 

only the uppermost values of hydraulic head are valid. The 

separation between those uppermost values and the surface 

elevation, which tracks the degree of apparent underpressuring, can be inspected as a function of longitude and stratigraphic unit. The separation feature is highlighted by yellow 

shading in the explanation on plate 2. Separation is greatest 

on the westernmost cross sections of Swath H and appears 

on all seven horizons, although data are sparse on the section 

for Hunton-and-older rocks. Separation appears to be greater 

in the deeper (Mississippian and Hunton-and-older) horizons 

than in the shallower (Permian and Virgilian) horizons. Separation diminishes from west to east in all of the seven stratigraphic units. For example, in rocks of Desmoinesian age at 

latitude 38° N., the separation of 1,600 ft on line H diminishes 

to 1,300 ft on line J, to 900 ft on line L, and to 500 ft on line 

N. The separation increases from south to north on line N as 

the surface elevation increases from south to north. A similar 

south-to-north increase in separation cannot be seen on lines 

H, J, or L because surface elevation is nearly constant along 

these three lines. In summary, the separation between the 

surface elevation and the upper edge of hydraulic head values 

(pl. 2) is fairly constant from south to north but diminishes 

from west to east. 

Potentiometric Surfaces

A potentiometric surface is compiled by contouring the 

measurements of hydraulic head H over the study area. The 

resulting surface represents the level to which water would 

rise in tightly cased wells that are in hydraulic connection with 

a confined aquifer. In this study, we compile potentiometric 

surfaces for each of the seven stratigraphic units.

Procedure

The problem of map representation of hydraulic head is 

analogous to fitting a rubber sheet downward onto a sea of 

data, in which only the sea surface is of interest. Points falling 

below the sea surface should not be represented. The problem is compounded by local spikes of unwanted high values 

that extend upwards from the sea surface. Ideally, the spikes 

should pass through the rubber sheet, leaving them extending upwards and unrepresented. To handle this problem, we 

used software designed to deal with potential field (gravity 

and magnetics) data. The data were divided into 13 west-east 

swaths (pl. 3), each displaying hydraulic head on the vertical 

axis and longitude on the x-axis. Individual values of hydraulic head were either used in the filtering process (red points on 

lines 1-13 in pl. 3) or were deactivated if not used in the filtering process (green points in pl. 3).

Each swath was filtered independently of the others to 

establish 13 independent fits. A rolling statistic curve called 

ROLL was calculated by taking the maximum of 11 points, 5 

to the left and 5 to the right of each hydraulic head value. The 

purpose of ROLL was to select points on the uppermost values 

of hydraulic head (values judged to be erroneously high were 

deactivated before the application of ROLL). The output of 

ROLL, shown as a green line in pl. 3, was input to a low-pass 

filter called LOWROLL. The 81-point low-pass filter utilized 

40 points to the left and 40 points to the right of each output 

point. The smoothed output of the low-pass filter is shown as a 

series of blue dots in each swath of plate 3.

Special problems that were encountered included areas 

of sparse data, areas of data with high scatter, and end effects. 

As already mentioned, each line for each stratigraphic unit 

was cleaned manually by removing points significantly below 

the tops of the values and removing high points that were 

considered outliers in the data set. In some cases, spaces were 

added in the database to manipulate the LOWROLL points to 

better follow the tops of the hydraulic head data. For example, if 40 blank spaces were added to the left of a point, the 

ROLL and LOWROLL would then only be calculated by the 

values to the right of that point. This process was used when 

the user clearly determined where the top of the hydraulic 

head values were but the output of LOWROLL was displayed 

in a slightly different location. Problems of this type were 

dealt with on a case-by-case basis as adjustments were made 
16 Potentiometric Surface Maps for Seven Stratigraphic Units in the Greater Anadarko Basin

to improve the fit of the “rubber sheet” to the top of the surface on each swath. 

The potentiometric surface for each stratigraphic unit 

was based upon the outputs of the low-pass filter for all of 

the swaths in a given stratigraphic unit. A grid was calculated 

using a minimum curvature algorithm with spacings of 0.1 and 

0.01 (pl. 3). The 0.01-potentiometric surface, which clearly 

shows the relation between individual points on a swath and 

the resulting contour interval, was used for quality control and 

editing of the 0.1-surface, which with additional notation is 

presented in plate 4. In this way, potentiometric surfaces were 

constructed from computations of hydraulic head for each of 

the seven stratigraphic units. 

In order to represent the height of the potentiometric 

surface with respect to the land surface, a second set of maps 

was constructed by computing the difference between the 

filtered (LOWROLL) values and the Kelly Bushing of each 

well. These data were then treated in a manner similar to that 

followed for the potentiometric surfaces to create maps of 

the separation be the Earth’s surface and the potentiometric 

surface (pl. 5). 

Maps Showing Potentiometric Surfaces and 

Overpressured Areas

For each stratigraphic unit (Permian, Virgilian, Missourian, Desmoinesian, Morrowan, Mississippian, and Huntonand-older), the potentiometric surface, in feet above sea level, 

is shown as a colored contour map (pl. 4). The Morrowan 

and Desmoinesian maps include an outline of their respective overpressured areas (red areas in parts C and D of pl. 4), 

drawn to include pressure-depth ratios greater than 0.5 psi/ft, 

based on inspection of the data set from Al-Shaieb and others 

(1994) and the drillstem-test-derived map of potentiometric 

surface. Potentiometric contours are also interrupted in the 

Hunton-and-older, Missourian, and Virgilian units (gray areas 

in parts A, E, and F of pl. 4), where the data in the central 

basin were insufficient to define a potentiometric surface. The 

overpressured areas in the deep basin are not considered further here, but are discussed in a companion paper by Nelson 

and Gianoutsos (chapter 8 of this report). Most importantly, 

the seven maps of plate 4 show that the overpressured zone in 

the deep basin has left an imprint in all rock units, except possibly those of Permian age.

As further introduction to plate 4, consider the potentiometric surface for Permian rocks (pl. 4G), which has widely 

separated contours between 1,250 and 1,500 ft (light green 

area), demonstrating a low hydraulic gradient over more than 

one-half of the mapped area. The low hydraulic gradient is 

also shown in the west-east and south-north swaths of figure 

10 and plate 2. In the western portion of the map (pl. 4G), 

contours are tightly grouped and the surface rises from 1,500 

to 3,250 ft. The pattern of a broad area of low hydraulic 

gradient flanked on the west by a narrow area of high hydraulic gradient is common to all potentiometric surfaces except 

the Morrowan (pl. 4). The change in hydraulic gradient 

from high in the west to low in the east can be explained by 

changes in permeability or hydraulic conductivity. According 

to Darcy’s law, an inverse relation exists between hydraulic 

gradient and hydraulic conductivity. One-dimensional flow 

can be expressed as Q = -K(dH/dX), where Q is the flow 

rate, K is hydraulic conductivity, and dH/dX is the hydraulic 

gradient expressed as the change in hydraulic head H over a 

distance X. This concept is illustrated in a model (fig. 11), in 

which flow is constrained to a pipe. Hydraulic conductivity 

K is low in the short, western segment of the pipe and high 

in the longer eastern segment. The tight clustering of increments of head H in the western segment, which is comparable 

to the contours in plate 4A, was computed for the ratios of 

length and hydraulic conductivity indicated in the diagram: 

the length XE and hydraulic conductivity KE of the eastern 

segment are 4 and 30 times greater, respectively, than XW and 

KW of the western segment. Thus, areas with a low hydraulic 

gradient (wide spacing between contours in pl. 4) are likely 

to be areas with high K relative to areas with a low hydraulic 

gradient (tightly spaced contours).

Because the pressure-depth ratio can be computed from 

the separation between potentiometric and land surfaces 

(eq. 2b), it follows that the separation between potentiometric 

surface and land surface is an indicator of whether pressure in 

a given stratigraphic unit is underpressured or normally pressured. The separation is mapped for the seven stratigraphic 

units (pl. 5) by subtracting the land surface represented in 

figure 4 from each of the potentiometric surfaces in parts 

A-G of plate 4. The zero contour, separating pink from grayblue areas, is the locus of intersection of the two surfaces. 

Figure 11. Hydraulic head H computed for one-dimensional flow 

Q in a medium of low hydraulic conductivity in the west, KW, and 

high conductivity in the east, KE, with KW/KE = 1/30. The length of 

the low-conductivity section, XW, is 1/4 the length of the highconductivity section, XE

. Values of H range from 1,250 to 3,000 feet, 

with colors between 250-foot contours of H selected to match the 

colors in plate 4. Concept for one-dimensional model taken from 

Belitz and Bredehoeft (1988).

Q

KE

XW

3,000

2,500

2,000

1,500

1,250

Darcy’s Law Q = – K (dH /dX)

H (feet)

Q

XE

 KW /KE = 1/30

 XW /XE

 = 1/4
Potentiometric Surfaces 17

Where the separation is positive (pink areas), groundwater 

has the potential to flow to the surface through tightly cased 

wells completed in the aquifer or through naturally occurring conduits in overlying geologic units. Under unconfined 

conditions, groundwater will discharge to springs and streams 

where the water table intersects land surface. The areas with 

wide spacing between contours that are present in plate 4 are 

not present in plate 5 because the land surface varies more 

than the potentiometric surfaces, especially in the western 

part of the study area. As a result, the land surface topography 

dominates the maps of plate 5, resulting in the north-south 

banding over a large portion of the maps. 

Hunton-and-older Stratigraphic Units

The potentiometric surface drops from around 1,500 ft in 

the western and southwestern portions of the study area to less 

than 500 ft in the eastern part of the study area (pl. 4A). The 

potentiometric surface ranges between 750 and 1,000 ft over 

much of central Kansas, including the Central Kansas uplift, 

showing a remarkably low gradient over an area that is more 

than 200 miles from west to east and more than 150 miles 

from south to north. The dense drilling pattern in Kansas is 

largely due to oil and gas production from the Arbuckle Group 

on the Central Kansas uplift. (The Cambrian-Ordovician 

Arbuckle Group may compose a separate hydrological system 

as the connection to the surface may lie along its surface 

exposures in central Missouri [L. Watney, Kansas Geological 

Survey, written commun., June 2011)] Groundwater, which 

flows from high head to low head, generally flows northnortheast across the northern flank of the Anadarko Basin, 

where the contour shading grades from yellow or light green 

to light blue in southern Kansas and northern Oklahoma. The 

750-foot contour lies immediately east of and parallel to the 

Nemaha uplift. 

The separation between land surface and the potentiometric surface drops steadily from west to east (pl. 5A). Because 

the potentiometric surface is nearly flat (pl. 4A), the separation 

between land surface and potentiometric surface is dominated 

by land surface topography. The 0±300 contour areas occupy a 

large area of roughly 150 by 150 miles in the southeastern part 

of the map where the Nemaha and the Arbuckle fault systems 

intersect. Locally, the separation exceeds +300 ft, suggesting 

artesian flow conditions for wells completed in the Huntonand-older stratigraphic unit. The Arbuckle-Simpson aquifer 

comprises the Simpson, Arbuckle, and Timbered Hills Groups 

(Christenson and others, 2011) and crops out in the southeast 

part of the map (pl. 5A) in a location that is consistent with the 

potentiometric surface.

Mississippian Stratigraphic Unit

This potentiometric surface (pl. 4B) is similar to the 

one for Hunton-and-older rocks (pl. 4A), with a broad low 

gradient area of values ranging from 750 to 1,000 ft in 

Kansas, and a southeast-northwest trending 1,000-ft contour 

separating areas of higher hydraulic head in Oklahoma and 

Texas from lower values in Kansas. A west-east trend of 

values exceeding 1,750 ft in western Oklahoma and the 

northeast corner of the Texas Panhandle occupies an area 

that is overpressured in Desmoinesian and Morrowan rocks 

(figs. 4C and 4D); however this area is not overpressured in 

Mississippian rocks, although scattered measurement of high 

hydraulic head made it difficult to define a reliable potentiometric surface. The 750-ft south-north contour lies east of the 

Nemaha uplift. As with the Hunton-and-older stratigraphic 

unit, groundwater flows generally north-northeastward from 

the northern flank of the basin, from northern Oklahoma into 

southern Kansas. A potentiometric surface for Mississippian 

rocks was not examined by Al Shaieb and others (1994), so 

no comparisons can be made.

The separation between land surface and the potentiometric surface for Mississippian rocks (pl. 5B) is similar to that 

for Hunton-and-older rocks (pl. 5A), as expected because the 

potentiometric surfaces are similar. 

Morrowan Stratigraphic Unit

A northwest-southeast trending truncation edge bounds 

the Morrowan and Springer rock units (pl. 4C), which consequently occupy a smaller fraction of the study area than other 

rock units. The potentiometric surface rises from somewhat 

greater than 750 ft at the truncation edge in Kansas to values 

greater than 2,000 ft in a four-county area of southwestern 

Kansas, southeastern Colorado, and the Oklahoma Panhandle. 

A west-east belt of values exceeding 1,750 ft lies immediately 

north of the overpressured area.

Establishment and maintenance of a low (750–1,500 ft) 

potentiometric surface is presumed to be through hydraulic 

connectivity with either overlying Desmoinesian or underlying 

Mississippian strata, or both, because the Morrowan rocks do 

not extend far enough eastward to directly establish a discharge 

to surface. However, immediately north of the overpressured 

area, where the northeast corner of the Texas Panhandle meets 

the southeast corner of the Oklahoma Panhandle, lies an area 

of high hydraulic head (pl. 4C), as mentioned above, which 

creates a corresponding area where the potentiometric surface 

approaches the land surface (pl. 5C). This area may be a relic 

of a once-overpressured part of the system, (see fig. 14 and 

relevant discussion in Nelson and Gianoutsos, chapter 8 of this 

report) as it lies well to the west of the zero contour on other 

difference maps.

Desmoinesian Stratigraphic Unit

The potentiometric surface drops from values in excess 

of 2,500 ft in southeastern Colorado to values ranging from 

500 to 1,500 ft in a broad low-gradient area in the eastern half 

of the mapped area (pl. 4D). A low-potential area approximately 30 by 50 miles in central Kansas includes values less 

than 500 ft. The southern edge of the overpressured area lies 

immediately south of the basin axis. Two salients projecting 
18 Potentiometric Surface Maps for Seven Stratigraphic Units in the Greater Anadarko Basin

northward from the main overpressured area are mapped with 

both the data from this study (bright contours underlying the 

shaded overpressure) and the data set from Al-Shaieb and 

others (1994). A halo of hydraulic head values in the 1,000- to 

1,500-ft range surrounds the overpressured area. The overpressured area shown in plate 4D is larger than that of the 

overpressured Red Fork Sandstone area shown by Al-Shaieb 

and others (1994), because the Desmoinesian pressure map 

includes formations and units of Desmoinesian age in addition 

to the Red Fork Sandstone. 

The potentiometric surface approaches land surface 

(-300 ft line in pl. 5D) along a line trending northeast in the 

eastern part of the mapped area. The -300 ft contour approaches 

and parallels the Nemaha uplift in northern Oklahoma and 

southern Kansas, suggesting that the Nemaha uplift is the 

discharge area for rocks of Desmoinesian age. The eastern edge 

of the overpressured area lies about 20 miles from the Nemaha 

uplift in the southeastern part of the Anadarko Basin. This 

relatively short distance from edge of overpressure to discharge 

point reflects the effectiveness of the pressure seal.

Missourian Stratigraphic Unit

The potentiometric surface ranges from 1,000 to 1,250 ft 

along the Nemaha uplift and increases steadily westward 

to the western Kansas border where values exceed 1,750 ft 

(pl. 4E). As noted on the map, an area in north-central Kansas 

is well defined by the data, but sporadic measurements of 

higher head exist within the area. The potentiometric surface 

cannot be defined in a large southern area that encompasses 

the deep basin due to scatter in hydraulic head; numerous 

values of hydraulic head greater than 2,000 ft exist. Pressuredepth ratios of 0.5 psi/ft and greater suggest that this area is 

slightly overpressured, with pressure-depth ratios generally 

0.5 to 0.6 in the informal lower Missourian sandstones—

Medrano, Marchand, and Cleveland. This interpretation of 

overpressure in the lowermost Missourian sandstones differs 

from that of Al-Shaeib and others (1994), who categorized the 

Missourian unit as normally pressured. 

As is the case with other maps of the separation 

between the potentiometric and land surfaces, the contour 

spacing and orientation of the Missourian stratigraphic 

unit (pl. 5E) is dominated by the land surface. The -300-ft 

contour lies 70 miles west of and parallel to the Nemaha 

uplift. The map indicates that an area east of the Nemaha 

uplift and another area south of the Arbuckle fault zone 

have potentials high enough for artesian flow (separation 

values greater than 0 ft). 

Virgilian Stratigraphic Unit

The potentiometric surface increases from 1,000 to 

1,250 ft along the Nemaha uplift to more than 1,500 ft in 

the northwestern part of the study area (pl. 4F). Between 

these two areas lies a broad low-gradient area with head 

values ranging from 1,500 to 1,250 ft. This low west-to-east 

decrease in the potential surface is interrupted in two areas. 

Values range up to 2,250 ft within the Central Kansas uplift, 

where the potentiometric surface is clearly defined despite a 

small fraction of measurements with higher hydraulic head. 

Higher head values are also located in the deep Anadarko 

Basin, but in this area there were insufficient data to determine the potentiometric surface.

The potentiometric surface approaches land surface 

(-300 ft line in pl. 5F) along a line that is 70 miles west of 

and parallel to the Nemaha uplift. The broad discharge area 

for Virgilian strata extends from the -300 ft line to the eastern 

edge of the study area. West of the -300 line, the separation 

increases steadily to the western edge of the study area.

With the exception of the deep basin, the maps of potentiometric surface and separation between potentiometric and 

land surfaces are rather similar for Missourian and Virgilian rocks (compare pls. 4E and 4F, and pls. 5E and 5F). The 

similarity suggests that Missourian and Virgilian units are 

closely coupled and may act as one hydrologic system. The 

two systems were considered as one system by Al-Shaeib and 

others (1994).

Permian Stratigraphic Unit 

The potentiometric surface increases from 750 ft along 

the Arbuckle fault trend to 1,250 ft along the Nemaha uplift 

and remains between 1,250 and 1,500 ft over an area that 

is roughly one-half of the study area (pl. 4G). In the westernmost counties of Kansas, an area which includes the 

western edge of the Hugoton gas field, values climb rapidly, 

exceeding 3,000 ft at the western edge of the study area. 

The hydraulic gradient in western Kansas, Oklahoma, and 

Texas is the highest of any of the maps (pl. 4A to 4F). The 

computed hydraulic head values that were used to define the 

map of plate 4G are the most consistent of the seven mapped 

units, in that the surface is well defined on all 13 swaths 

with very few points above the surface and no areas, other 

than gaps shown as blank areas, where the surface could not 

be defined. 

The map of the separation between the potentiometric surface and land surface for Permian rocks (pl. 5G) is 

similar to the maps for the Desmoinesian, Missourian, and 

Virgilian units (pls. 5D, 5E, 5F), the main difference being 

that, in the Permian stratigraphic unit, the separation is less 

in the westernmost part of Kansas and Oklahoma, due to 

the greater height of the Permian potentiometric surface 

in this area. The discharge area, represented by the 0±300 

contours, straddles the Nemaha uplift area and includes the 

high transmissibility Central Oklahoma aquifer (pl. 5G) 

where the water table lies just below surface elevation. The 

Central Oklahoma aquifer comprises the Garber Sandstone 

and Wellington Formation (fig. 4), as well as the Chase, 

Council Grove, and Admire Groups, all of Lower Permian 

age (Parkhurst and others, 1996).
Discussion 19

Discussion

The main feature of the potentiometric surfaces is the 

broad low-gradient area in central Kansas and northern Oklahoma, manifested as hydraulic head elevations between 1,250 

and 1,500 ft in Permian, Virgilian, and Missourian units and as 

elevations between 750 and 1,000 ft in Desmoinesian, Mississippian, and Hunton-and-older units (pl. 4). The main feature 

in the maps showing separation between the Earth’s surface 

and the potentiometric surfaces (pl. 5) is the north-south 

stripes formed as a result of subtracting the eastward-declining 

topography (fig. 4) from the broad low-gradient areas (pl. 4). 

Separation maps for Permian, Virgilian, Missourian, and Desmoinesian units show separation changing from -2,400 ft in the 

west to 0±300 ft in the vicinity of the Nemaha uplift. 

The position of the 0±300 ft contour for Permian, Virgilian, Missourian, and Desmoinesian units is explained by 

the location of outcrops along and immediately east of the 

Nemaha uplift (fig. 12). The southern part of the Nemaha 

uplift also appears to be the control or partial control for the 

Mississippian and Hunton-and-older rock units. Along the 

Nemaha uplift, through exposure of strata to the surface or 

just below the surface and through connections with permeable faults, water pressure in the aquifers has equilibrated with 

atmospheric pressure causing the potentiometric elevation to 

be generally equal to surface elevation. The exact locations of 

equilibration are unknown and the areas where equilibration 

takes place is likely to be only a fraction of the area encompassed by the 0±300 ft contours. Shales and evaporites of 

Permian age provide hydraulic isolation of deep strata from 

the surface so that the area around the Nemaha uplift is the 

dominant pressure equilibration point for these four units. 

The separation maps reflect the degree of apparent underpressuring expected to exist in oil and gas wells in Permian 

and Pennsylvanian strata. To estimate the degree of underpressure at a desired location and depth, the separation KBE – H, 

which is expressed in feet, can be read from the appropriate 

map in plate 5 and converted to a pressure-depth ratio in psi/ft 

using equation 2b. For example, consider a location on the 

Texas-Oklahoma border at the northeasternmost corner of the 

Texas Panhandle, where the separation contour on the Desmoinesian map (pl. 5D) is H - KBE = -900 ft, or KBE - H = +900 

ft . For a Desmoinesian interval at a depth of 6,700 ft, the 

pressure/depth ratio from equation 2b is 0.465*(1-900/6700) = 

0.403, which is slightly underpressured. Note that underpressure cannot be read directly from the separation maps because 

equation 2b requires that the depth be specified independently.

A comparison between the Virgilian separation map of 

plate 5F and the pressure-depth ratio for a number of oil and 

gas reservoirs is shown in figure 13. The separation map was 

derived from well-based pressure measurements, not from 

reservoir-based pressure measurements, so the comparison of 

figure 13 is something of a check although not an independent check. The pressure-depth ratios are slightly subnormal 

(0.42 psi/ft) where the separation is close to 300 ft, are less 

than 0.30 psi/ft where the separation is greater than 1,500 ft, 

and decrease to values of 0.15 psi/ft where the separation is 

more than 1,800 ft. Between the eastern and western extremes, 

the pressure-depth ratio decreases more or less steadily as 

separation increases. Bearing in mind that the pressure-depth 

ratio is related to, but not directly proportional to separation, 

the general agreement between the trends in the pressure-depth 

ratios and the separation map gives confidence that underpressuring in oil and gas reservoirs and a low-gradient potentiometric surface are one and the same phenomenon. 

A scenario for the origin of the Panhandle oil and 

gas field in Texas was presented by Sorenson (2005), in a 

pressure-depth plot and a series of five maps showing paleogeology from Late Permian to Quaternary. (Our only modification to Sorenson’s scenario, which is summarized in this 

paragraph, is that aquifer pressure is equilibrated along the 

Nemaha uplift, in place of his proposed equilibration point in 

northeastern Kansas.) The Panhandle oil and gas field formed 

in Late Permian time and remained in place until early Tertiary 

when some spillage of gas northward into the Kansas Hugoton 

field may have begun. Aquifer pressure dropped in late Tertiary time as downcutting exposed Permian rocks. As aquifer 

pressure dropped, the Panhandle gas expanded, augmented by 

gas coming out of solution in oil. Reservoir pressure fell to its 

present-day value of 435 psi at a depth range of 2,500–3,000 

ft, for a pressure-depth ratio of less than 0.18 psi/ft (Sorenson, 

2005). In support of this scenario, the outline of the Hugoton 

field coincides with a maximum separation between surface 

elevation and potentiometric surface, as shown in figure 14. 

The maximum in separation corresponds to the western edge 

of the broad, low-gradient area where potentiometric elevation 

ranges between 1,250 and 1,500 ft (pl. 4G), demonstrating that 

the location of the Hugoton gas field is bounded on the west 

by a sharp increase in potentiometric elevation. 

Having established the discharge zone to be in the 

general vicinity of the Nemaha uplift, the question arises: 

where is the zone of recharge? Recharge is expected to take 

place where strata crop out at a high-elevation terminus of a 

groundwater system, in this case along the Rocky Mountain 

uplift in southeastern Colorado and northeastern New Mexico. 

However, during Pennsylvanian time the Sierra Grande arch 

in northeastern New Mexico was a positive feature. Pennsylvanian and pre-Pennsylvanian strata of the Anadarko Basin 

terminate on the eastern flank of the Sierra Grande arch, disrupting hydrological continuity with the Raton Basin and the 

Rocky Mountain uplift. Hydrological continuity to the west is 

limited to Lower Permian (Wolfcampian) continental deposits 

that drape the Sierra Grande arch in southeastern Colorado and 

a narrow west-east strip in New Mexico immediately south of 

the New Mexico–Colorado border (Wilson, 1977; Robson and 

Banta, 1987, Roberts and others, 1976). 

Recharge is limited by what can best be described as a 

choke caused by onlap of Pennsylvanian and older strata on 

the Sierra Grande arch (fig. 12). Flow from west of the arch is 

restricted to permeable beds in Lower Permian (Wolfcampian 

and Leonardian) strata that are approximately 1,000 ft thick 

on top of the arch, as shown at longitude 104° W. of figure 12. 
20 Potentiometric Surface Maps for Seven Stratigraphic Units in the Greater Anadarko Basin

Figure 12. West-east structural cross section showing features influencing the creation and maintenance of underpressure. Permian 

and Pennsylvanian strata crop out along and east of the Nemaha uplift. Brown shading indicates the impermeable evaporite-bearing 

strata of Permian age. Pinchout and thinning of strata on the Sierra Grande arch provide limited entry for recharge. East of longitude 

102° W. the cross section is based largely on well data. West of long 102° W. the cross section is based on information from Roberts and 

others (1976), Weeks and Gutentag (1981), and McGookey and others (1988).

104° 102° 100° 98° 96° 

TEXAS

KANSAS

OKLAHOMA

COLO.

Longitude, in degrees

103° 102° 101° 100° 99° 98° 97° 96° 

Elevation, in feet

-7,000

-5,000

-3,000

-1,000

1,000

3,000

5,000

VERTICAL EXAGGERATION 56:1

Leonardian

Wolfcampian

Virgilian

Missourian Morrowan Desmoinesian

Mississippian

Nemaha 

fault zone

Tertiary (Ogallala Formation)

104° 

7,000

Precambrian

Line of section

Nelson_Ch9_Figure 12

? ?

Triassic–Cretaceous

Mudstone, salt, and anhydrite 

in rocks of Permian age

Outcrops of Wolfcampian and older 

strata at elevations of 1,200 feet and less. 

Known extent of 

highly saline 

formation water 

Sierra Grande arch

Limited entry for

recharge from

west

Steep hydraulic gradients in

Permian, Virgilian, Missourian,

Desmoinesian, and Morrowan rocks

Upper Permian

Nemaha 

fault zone

COLORADO

OKLAHOMA

TEXAS

KANSAS

NEW MEXICO

Precambrian faults

Basin axis

Potentiometric surface well defined in 

this area with sporadic measurements 

of higher hydraulic head

Potentiometric surface not well

defined in this area because of 

scatter in hydraulic head

0.10

0.33

0.30

0.40

0.12

0.15

0.15

0.15 0.16 0.16

0.23 0.21

0.24

0.24 0.24

0.25

0.25

0.26 0.26

0.26

0.26

0.27

0.27

0.27

0.28

0.33

0.28

0.29 0.29

0.29

0.29

0.31

0.31

0.31

0.32

0.32

0.33

0.33

0.33 0.33

0.34

0.34

0.34

0.34

0.34

0.34

0.35

0.35

0.35

0.36

0.36

0.37

0.37

0.38

0.38

0.38

0.39

0.41

0.42

0.42

0.42

0.43

0.44

0.55

0.36

0.15

0.37

0.33 0.66

0.34

0.33

0.33

104° 103° 102° 101° 100° 99° 98°

38°

39°

37°

36°

35°

34° 0 15 30 MILES

0 15 30 KILOMETERS

Earth’s Surface

Potentiometric Surface

-300

-600

-900

-1,200

-1,500

-1,800

-2,100

-2,400

-2,700

0 300

Figure 13. Comparison 

between a separation map 

from plate 5F and degree 

of underpressuring for the 

Virgilian unit. Contours on 

the separation map give 

the Virgilian potentiometric 

surface minus the surface 

elevation. Dots give the 

location of individual oil and 

gas fields for which pressuredepth ratios were computed 

from data provided by NRG 

Associates (2009).
Discussion 21

Figure 14. Map with contours showing separation between the potentiometric surface in Permian rocks and land 

surface elevation, in feet. For example, the yellow areas show where the potentiometric surface lies -1,500 to -1,800 

ft below surface elevation. The underpressured Hugoton-Panhandle gas field lies in a trough of maximum separation 

between the potentiometric surface and surface elevation.

COLORADO

OKLAHOMA

TEXAS

KANSAS

NEW MEXICO

Precambrian faults

Basin axis

PanhandleHugoton 

field

Yellow and green areas represent

areas of greatest underpressure.

104° 103° 102° 101° 100° 99° 98°

38°

39°

37°

36°

35°

34°

Nelson_Ch9_Figure 14

0 15 30 MILES

0 15 30 KILOMETERS

Earth’s Surface

Potentiometric Surface

-300

-600

-900

-1,200

-1,500

-1,800

-2,100

0 300
22 Potentiometric Surface Maps for Seven Stratigraphic Units in the Greater Anadarko Basin

East of the arch, groundwater flow must spread downward 

from Lower Permian strata into the eastward-thickening 

Pennsylvanian strata. Flow must also spread laterally, as the 

arch is not covered everywhere by rocks of Wolfcampian age 

(fig. 6 of Roberts and others, 1976). Consequently, the northsouth cross-sectional area open to flow over the arch is much 

smaller than the north-south cross-sectional area to be filled by 

eastward-migrating waters. In addition, discharge to the east 

may be inhibited by dense, high salinity waters in all seven 

stratigraphic units along the Nemaha uplift (pl. 1 and fig. 12). 

It is likely that these highly saline waters result from the dissolution of salt in Upper Permian strata. Buoyancy (negative 

buoyancy in this case) forces tend to cause the denser waters 

to descend westward and downward, counter to the overall 

west-to-east hydraulic gradients indicated in the potentiometric surfaces of plate 4. These two effects—limited recharge 

from the west and density-induced counter-flow from the 

east—combine to set up a relatively stagnant groundwater system in the deep confined aquifers of the Anadarko Basin. The 

presence of overpressured strata in the deep basin (Nelson and 

Gianoutsos, chapter 8 of this report) further restricts groundwater circulation in deep confined aquifers. A supporting 

insight is provided by Gallardo and Blackwell (1999, p. 357) 

who studied the thermal regime of the basin: “We found no 

evidence for significant fluid flow in this basin at the present 

time ... the temperature structure can be explained adequately 

by normal conductive heat flow when the thermal conductivity 

of the rocks is taken into account in the modeling.” 

Our interpretation of a stagnant low-gradient groundwater system with limited hydraulic continuity to the west 

is counter to a scenario of a regional groundwater sysem 

recharged from the west and flowing from west to east in continuous strata that were tilted upward during Laramide uplift 

(Jorgensen, 1989). 

Summary

Conversion of pressure from drillstem tests to hydraulic 

head, seemingly straightforward in a water-dominated system, 

is complicated by variations in salinity across the basin. Errors 

are not easily assessed because salinity is poorly documented 

in much of the basin. Nevertheless, the seven potentiometric 

surfaces and the seven derivative surfaces showing separation 

between land surface and potentiometric surface portray the 

state of hydraulic potential and the nature of underpressuring 

over the greater Anadarko Basin.

On the basis of their respective potentiometric and 

separation surfaces, the seven stratigraphic units fall into three 

groups. 

1. In the units designated as Hunton-and-older and Mississippian, a large fraction of the potentiometric surface lies 

750 to 1,000 ft above sea level (pl. 4A, B). The separation 

maps indicate that the discharge area lies in the southeast 

part of the study area (pl. 5A, B). 

2. Northwest of the overpressured deep Anadarko Basin, the 

potentiometric and separation surfaces of the truncated 

Morrow age rocks are similar to the Mississippian surfaces. Hence, it appears that the Morrowan groundwater 

system is coupled to the groundwater system in Mississippian strata in this area. 

3. The potentiometric surfaces of the four uppermost units—

Desmoinesian, Missourian, Virgilian, and Permian—share 

a general north-south to northeast-southwest trend in the 

contour patterns. The Nemaha uplift lies within the -300 

to +300 ft contours of the separation surfaces in all four 

units (pl. 5D-F), indicating that the discharge areas lie in 

the vicinity of the Nemaha uplift. 

Outside the overpressured area in the deep basin, hydraulic potentials of Lower Permian and older strata are controlled 

by outcrops at elevations of 1,200 ft and less. Land surface 

rises to the west, so separation between land surface and 

potentiometric surface increases westward, and consequently, 

so does the degree of underpressuring. Underpressured reservoirs, including that of the Hugoton field, are the result of 

exposure of strata to atmospheric pressure in the vicinity of 

and east of the Nemaha uplift.

Four lines of evidence point to a low-flow to no-flow 

hydrologic system in the confined strata of the Anadarko 

Basin. Recharge of groundwater into Pennsylvanian and older 

strata on the northern flank of the Anadarko Basin is greatly 

limited by the presence of the low-permeability Permian cap. 

Recharge is further constricted by the pinchout of strata on the 

Sierra Grande uplift to the west (fig. 12). Highly saline formation water in strata along the Nemaha uplift imposes a fluid 

density barrier to west-to-east flow. And finally, overpressured 

strata in the deep basin further restrict fluid movement. 

Our hypothesis of a markedly low-flow system warrants 

further investigation, possibly with detailed hydrological 

modeling. Features of the system awaiting elucidation are 

(1) the steep hydraulic gradient between longitude 102° W. 

and 103° W., (2) better mapping of salinity variations and the 

effect of high salinity waters along the Nemaha uplift, and 

(3) the details of pressure equilibration along the Nemaha 

uplift for the different stratigraphic units. 

There are two practical ramifications of this work. First, 

the geologically recent drop in pressure brought on by the 

exposure of discharge zones along the Nemaha uplift has 

altered the original pressure distribution in the Anadarko 

Basin. The expansion of the Hugoton gas field is but one 

outcome. Other, smaller oil and gas fields have doubtless 

undergone gas expansion as a result of the pressure drop. The 

effects of this late-stage modification remain to be worked out 

for the distribution of oil and gas, particularly for gas. Second, 

the hydraulic potential of the deep confined strata is important 

when considering the injection and sequestration of carbon 

dioxide, if and when that takes place. A low-flow hydrologic 

regime, capped by impermeable strata, makes an attractive 

setting for carbon dioxide sequestration because the time durations for return flow to the surface are likely to be quite long.
References Cited 23

Acknowledgments

We benefitted from discussions with many people who 

visited our poster on this topic at annual meetings of the 

Geological Society of America and the American Association 

of Petroleum Geologists. We also benefitted from reviews 

by Noel Osborne, Sarah Hawkins, and Tom Judkins of the 

U.S. Geological Survey. Water salinity maps were originally 

compiled by Jessica Mager and Marvin Abbott of the U.S. 

Geological Survey. Rick Saltus of the U.S. Geological Survey 

introduced us to the Oasis Montaj software package and suggested the general filtering approach. 

References Cited

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Henslee H.T., Hicks, I.C., Larson, T.G., McCracken, M.H., 

Parker, M.C., Rascoe, B., Jr., Schramm, Jr., M.W., and 

Wells, J.S., 1971, Future petroleum provinces of the midcontinent, Region 7, in Cram, I.H., ed., Future petroleum 

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pt. 1, Shale Shaker, Sept.-Oct., p. 61–80.

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pt. 2, Shale Shaker, Nov.-Dec., p. 90–105.

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aquifers in the central Midwest of the United States in 

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Paper 1414-A, 67 p. 
24 Potentiometric Surface Maps for Seven Stratigraphic Units in the Greater Anadarko Basin

McGookey, D.A., Gustavson, T.C., and Hoadley, A.D., 1988, 

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R.B., 1996, Geohydrology and simulation of steady-state 

flow conditions in regional aquifer systems in Cretaceous 

and older rocks underlying Kansas, Nebraska, and parts of 

Arkansas, Colorado, Missouri, New Mexico, Oklahoma, 

South Dakota, Texas, and Wyoming: U.S. Geological Survey Professional Paper 1414-C, 105 p. 

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Panhandle and Hugoton fields, western Anadarko Basin: 

American Association of Petroleum Geologists Bulletin, 

v. 89, no. 7, p. 921–938.

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Wilson, A.B., Moore, D.W., and Van Gosen, B.S., 2005, 

Preliminary integrated geologic map databases for the 

United States: U.S. Geological Survey Open-File Report 

2005-1351, available online at http://pubs.usgs.gov/

of/2005/1351/.

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1977, Selected gas fields of the Texas Panhandle: Amarillo, 

Texas, Panhandle Geological Society, 83 p.

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Mexico, Oklahoma, and Texas: U.S. Geological Survey 

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Press, p. D192–D234.
Chapter 10

Lithology of Paleozoic Rock Units in 

62 Wells, Anadarko Basin, Oklahoma

By Nicholas J. Gianoutsos, Jaquidon D. Kruger, Philip H. Nelson, and 

Debra K. Higley

Chapter 10 of 13

Petroleum Systems and Assessment of Undiscovered Oil and Gas 

in the Anadarko Basin Province, Colorado, Kansas, Oklahoma, and 

Texas—USGS Province 58

Compiled by Debra K. Higley

U.S. Geological Survey Digital Data Series DDS–69–EE

U.S. Department of the Interior

U.S. Geological Survey

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Suggested citation: 

Gianoutsos, N.J., Kruger, J.D., Nelson, P.H., and Higley, D.K., 2014, Lithology of Paleozoic rock units in 62 wells, 

Anadarko Basin, Oklahoma, chap. 10, in Higley, D.K., compiler, Petroleum systems and assessment of undiscovered oil 

and gas in the Anadarko Basin Province, Colorado, Kansas, Oklahoma, and Texas—USGS Province 58: U.S. Geological 

Survey Digital Data Series DDS–69–EE, 6 p., http://dx.doi.org/10.3133/ds69EE.

ISSN 2327-638X (online)
iii

Contents

Abstract...........................................................................................................................................................1

Introduction.....................................................................................................................................................1

Procedure........................................................................................................................................................1

Lithologic Data.......................................................................................................................................2

Time-Stratigraphic Boundaries ...................................................................................................................3

Cross Section Displays .................................................................................................................................3

Discussion and Summary.............................................................................................................................3

Acknowledgments.........................................................................................................................................6

References Cited............................................................................................................................................6

Plates

1. Cross section A-A, west to east............................................................................................ link

2. Cross section B-B, west to east............................................................................................ link

3. Cross section C-C, south to north ......................................................................................... link

4. Cross section D-D, south to north......................................................................................... link

5. Cross section E-E, south to north.......................................................................................... link

6. Cross section F-F, south to north........................................................................................... link

7. Cross section G-G, south to north......................................................................................... link

8. Cross section H-H, south to north......................................................................................... link

Figures

1. Map of Anadarko Basin and shelf, Oklahoma showing locations of wells and cross

sections ..........................................................................................................................................2

2. Generalized stratigraphic section for the Anadarko Basin, listing prominent groups

and formations, modified from Bebout and others (1993, fig. 5). The cross sections

in this report used the tops of 5 horizons (red italicized print) to establish 5

time-stratigraphic boundaries. Granite wash is in the Upper Pennsylvanian and

lowermost Permian strata. Red beds and evaporites are generally in rocks of

Permian age. [Camb., Cambrian; Miss., Mississippian].........................................................4

3. Map of total thickness of evaporite in Permian rocks in the Anadarko Basin...................5
iv

Appendixes (Digital Files)

1. Spreadsheet with list of 62 wells used in this study.......................................................... link

2. Spreadsheet with lithologic determinations from well information................................ link

Conversion Factors

Inch/Pound to SI

Multiply By To obtain

Length

foot (ft) 0.3048 meter (m)

mile (mi) 1.609 kilometer (km)
Abstract

Lithology derived from mud logs, sample logs, and well 

logs are presented on eight structural cross sections covering 

the Oklahoma portion of the Anadarko Basin. Seven lithologies are identified: dolomite, limestone, evaporite, sandstone, 

red shales/red beds, arkose (locally referred to as granite 

wash), and shale. All cross sections reveal three major lithologic groups: (1) the carbonate-dominated units of Mississippian age and older, (2) the siliciclastic units of Pennsylvanian 

age, and (3) the evaporites and red shales of Permian age. In 

addition to the cross section displays, the lithologic data are 

provided in spreadsheet form.

Introduction

This report focuses on lithologic determinations of 

Paleozoic strata in the Anadarko Basin, based primarily on 

interpretations of mud logs, sample logs, and well logs. It is 

part of a series of reports that includes (1) chapters by Higley 

(chapters 6 and 7 of this report) and Gaswirth and Higley 

(chapter 5 of this report) on the assessment of undiscovered oil 

and gas resources in the Anadarko basin, and (2) two chapters 

by Nelson and Gianoutsos (chapters 8 and 9 of this report) 

that examine the extent and cause of abnormal pressures in the 

greater Anadarko Basin.

The lithologies reported here were originally interpreted 

by Gallardo (1989) and Gallardo and Blackwell (1999) for 

the purpose of computing the temperature structure of the 

Anadarko Basin of western Oklahoma. Using mud logs, 

sample logs, and well logs, including spontaneous potential, 

gamma ray, density, and neutron porosity logs, they assigned 

1 of 7 lithologies to each 10-ft interval in 63 wells distributed 

across the basin. A value of thermal conductivity was then 

assigned to each lithology, an independent estimate of heat 

flow was assigned to each well, and the temperature profile was 

computed for each of the 63 wells, 62 of which are used in the 

cross sections (pls. 1–8) contained in this chapter of the report.

A significant outcome of Gallardo and Blackwell’s work 

was a map of present-day temperature contours at the top 

of the Woodford Shale that was compared with a previously 

published contour map of vitrinite reflectance (Gallardo and 

Blackwell, 1999, fig. 12). The maps show that the highest 

vitrinite reflectance (thermal maturity) values and highest 

present-day temperatures coincide but are offset from the 

deepest part of the basin. The location of the thermal maturity 

and temperature maxima was attributed to lateral lithologic 

variations and their impact on heat conduction (Gallardo and 

Blackwell, 1999).

The lithologic interpretations used to create the thermal 

profiles have previously gone unpublished. It is our belief that 

these gross lithologic interpretations, when viewed at the basin 

scale, are of sufficient value to warrant their presentation here 

on a series of structural cross sections showing the lithologic 

units across the basin, along with selected time stratigraphic 

boundaries. The 62 wells are arranged in 2 west-east and 6 

south-north cross sections (fig. 1, pls. 1–8), providing a basinscale perspective of lithologic variations. 

Procedure

The 62 wells used in this study are the same wells (with 

one exception) that were used in the thermal study by Gallardo 

and Blackwell (1999; Appendix 1); that list is repeated here 

with a few corrections and additions to the well locations and 

American Petroleum Institute (API) numbers (Appendix 1 

of this chapter of the report) compiled from the Oklahoma 

Corporation Commission online database (2010). The Shell 

McDaniel 1 well (well number 8, Appendix 1) was not used in 

the cross sections because the well was not sufficiently deep. 

Our work flow consisted of preparation of the lithology files 

for plotting, selection of five time-stratigraphic boundaries for 

correlation, and the production of the cross-section displays. 

Lithology of Paleozoic Rock Units in 62 Wells, Anadarko 

Basin, Oklahoma

By Nicholas J. Gianoutsos,1 Jaquidon D. Kruger,2 Philip H. Nelson,1 and Debra K. Higley1

1

U.S. Geological Survey, Denver, Colorado.

2

Raytheon Company, Dallas, Texas.
2 Lithology of Paleozoic Rock Units in 62 Wells, Anadarko Basin, Oklahoma

Lithologic Data

Seven lithologies are identified, based on well log 

response and lithologic information: (1) dolomite, (2) limestone, (3) evaporite, (4) sandstone, (5) red shales (referred to as 

red beds) (6) arkose (locally referred to as granite wash), and 

(7) shale. According to Gallardo and Blackwell (1999, p. 339), 

much of the Permian section is characterized by red shales with 

interbedded evaporates and other lithologies, commonly on a 

very fine vertical scale. As these types of deposits are typically 

referred to as red beds, the term red bed was assigned to all 

lithologies of Permian age that were not identifiable as another 

lithology. These seven lithologies are represented by colors on 

the cross sections shown on plates 1–8. 

Lithology was determined for each well on 10-foot (ft) 

intervals. In older wells from the shelf, sample logs were 

used in combination with well logs to assign lithologies. In 

wells from the deep basin, mud logs were the source of direct 

lithologic information along with the well logs. In cases where 

a mixed lithology was indicated (for example, dolomitic limestone), the dominant lithology (limestone) was assigned to that 

10-ft interval. Siltstone was not included as a category because 

siltstone could not be reliably interpreted from the available 

information. The “red bed” lithology was assigned to shales 

of Permian age whereas the “shale” lithology was assigned 

to shales (generally gray or black) older than Permian. This 

distinction, although somewhat arbitrary, was based on the 

interbedded red shales and evaporites that composed much of 

the Permian section and had a practical application in terms of 

the assignment of thermal conductivity values (Gallardo and 

Blackwell, 1999). 

Spreadsheets originally compiled from well logs and 

other sources were modified to make them suitable as input 

files for LMKR Geographix plotting software. The spreadsheets gave the thickness but not the depth of each lithology, 

so the thicknesses were summed to provide a depth for each 

lithology interface. A single lithology can extend from a minimum of 10 feet to hundreds of feet.

Figure 1. Map of Anadarko Basin and shelf, Oklahoma showing locations of wells and cross sections. 

59

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63

A

A’,

B

B’

C’

D’ E’ F’ G’

H’

C D

E

F

G

H

KANSAS

OKLAHOMA

TEXAS

101° 100° 99° 98° 97°

37°

36°

35°

0

-2,500

-5,000

-7,500

-10,000

-12,500

-15,000

-17,500

-20,000

-22,500

-25,000

Elevation of the top of

Woodford Shale relative

to sea level, in feet.

34.5°

35.5°

36.5°

37.5°

EXPLANATION

Note: Well 8 was not used in

the cross sections and has

been omitted from this map.

CH10_Fig1

0 25 50 MILES

0 25 50 KILOMETERS
Discussion and Summary 3

The original requirement for the lithology data was to 

assign thermal conductivity values from the surface to the base 

of the Paleozoic section, in order to model temperature in the 

basin (Gallardo and Blackwell, 1999). To produce continuous 

lithologies from the top to the bottom of each primary well, 

information from many primary wells was supplemented with 

information from nearby wells—lithologies obtained from 

nearby wells have been retained in this chapter of the report. 

In addition, where no information was available from either 

the primary or a nearby well, a lithology was assigned to 

fill the gap from the top of information to the surface; these 

lithologies have been deleted from this chapter of the report. 

Consequently, the lithology data presented in this chapter of 

the report are based mainly on the information available from 

each primary well, with supplemental information from nearby 

wells in many cases. 

The lithologic data for each well are tabulated in Appendix 2, including the lithology type, the depth to the top of a 

given lithology, and the thickness of the lithology units.

Time-Stratigraphic Boundaries

To provide a stratigraphic framework for the lithology 

logs, five time-stratigraphic units were selected for portrayal 

on the cross sections: Devonian and older, Mississippian, 

Lower to Middle Pennsylvanian, Middle to Upper Pennsylvanian, Wolfcampian, and Leonardian to Guadalupian. The 

boundaries for these five time-stratigraphic units are based 

approximately on five lithostratigraphically defined tops 

(fig. 2). Three sources were used to establish the depth of a 

formation top: (1) mud log picks, which were available for 

only some of the formation tops; (2) transitions in lithology, 

which were judged to be definitive for two of the five boundaries (see below); and (3) maps representing stratigraphic units, 

as determined from mapping software (Dynamic Graphics® 

Earthvision®). The maps were defined using a database consisting of stratigraphic unit picks from well logs, stratigraphic 

unit tops from various publications, and a database by IHS 

Energy (2010). Erroneously high values of a surface were 

eliminated by visual inspection, followed by spatial filtering to 

smooth the surfaces. 

The five time-stratigraphic boundaries, located approximately using lithostratigraphic correlations (fig. 2), are: 

1. Devonian and older. The boundary for the top of the 

Devonian is based on the top of the Woodford Shale, 

which is generally of Late Devonian age, although part 

of the formation appears to be of Early Mississippian age 

(Kirkland and others, 1992). There is high confidence 

in the location of the top of the Woodford Shale in most 

areas, so this boundary is generally shown as a solid line 

in the cross sections (pls. 1–8).

2. Mississippian. The boundary for the top of the Mississippian is based on the top of the Springer Group, although 

the uppermost part of the Springer Group is assigned a 

Pennsylvanian age (Andrews, 2008). Given the uncertainty in the relation between the top of the Mississippian 

and the top of the Springer Group, this boundary is shown 

as a dashed line throughout the basin (pls. 1–8).

3. Lower to Middle Pennsylvanian. The boundary for the 

Middle Pennsylvanian is based on the top of the Cherokee 

Group of the Desmoinesian Series. As the location of the 

top of the Cherokee Group was uncertain in many areas, 

this boundary is shown as a dashed line throughout the 

basin (pls. 1–8). 

4. Middle to Upper Pennsylvanian. The boundary between 

upper Pennsylvanian and Wolfcampian ages is based on 

the top of the Wabaunsee Group. In some locations, this 

boundary was adjusted to coincide with the base of the 

oldest red shale. Because of the uncertainty in the location 

of this boundary, it is shown as a dashed line throughout 

the basin (pls. 1–8).

5. Wolfcampian and Leonardian to Guadalupian. The 

boundary between Wolfcampian and Guadalupian ages 

is equivalent to the top of the Chase Group, which was 

adjusted to the base of the lowermost evaporite. Wherever 

the thick evaporite is present, confidence in the location of 

this boundary is high, as represented by the solid line on 

most of the cross sections. 

Cross Section Displays

The structural cross sections (plates 1–8) are designed to 

be plotted and inspected at a scale of one inch per 2,000 vertical feet; elevations are displayed with respect to sea level rather 

than to a stratigraphic datum. Spacing between wells is proportional to actual distances. Correlations were not continued 

across major structural offsets in the southern part of the basin. 

At the scale of 1 inch to 2,000 ft, the resulting time-stratigraphic boundaries can only be approximated, with uncertainties ranging from a few feet to possibly several hundred feet in 

a few locations. Thus the results should not be used specifically 

for detailed correlations in certain cases, as noted on each plate. 

Discussion and Summary

All cross sections reveal three major groups of lithologies 

in the Anadarko Basin: (1) the carbonate-dominated units of 

Mississippian age and older, (2) the siliciclastic units of Pennsylvanian age, and (3) the evaporites and red beds of Permian age. This association between lithologic groups and three 

major time-stratigraphic groups persists across the entire state 

of Oklahoma (Oklahoma City Geologic Society, 1971). These 

three major lithologic groups play an important role in:

• the thermal regime of the basin (Gallardo and Blackwell, 1999)
4 Lithology of Paleozoic Rock Units in 62 Wells, Anadarko Basin, Oklahoma

Figure 2. Generalized stratigraphic section for the Anadarko 

Basin, listing prominent groups and formations, modified from 

Bebout and others (1993, fig. 5). The cross sections in this report 

used the tops of 5 horizons (red italicized print) to establish 5 

time-stratigraphic boundaries. Granite wash is in the Upper 

Pennsylvanian and lowermost Permian strata. Red beds and 

evaporites are generally in rocks of Permian age. [Camb., 

Cambrian; Miss., Mississippian]

Sumner Group, Enid Group, Hennessey Group

System

Series Lithostratigraphic Unit

Permian (part) Pennsylvanian Mississippian Devonian Silurian Ordovician Cambrian

Leonardian

Wolfcampian

Virgilian

Missourian

Desmoinesian

Atokan

Morrowan

Chesterian

Meramecian

Osagean

Kinderhookian

Chautauquan

Cayugan

Cincinnatian

Trempealeauan

Niagaran

Canadian

Champlainian

Chase Group

Admire Group

Lansing Group 

Marmaton Group

Atoka Group

Morrow Group/Formation

Springer Formation

Chester Group 

Wabaunsee Group

Shawnee Group

Douglas Group

Ada Group

Franconian

Woodford Shale

Misener sand

Hunton Group

Sylvan Shale; Maquoketa Shale 

Simpson Group

Arbuckle Group

Reagan Sandstone

Alexandrian

Senecan

Council Grove Group Pontotoc Group

Viola Group/Formation

Meramec lime

Osage lime

Mayes Group

Kansas City Group Hoxbar Group

Cherokee Group Deese Group

Kinderhook Shale

Erian

Ulsterian

Guadalupian Whitehorse Group; El Reno Group

CH10_Fig2
Discussion and Summary 5

• the hydrologic regime of the basin (Nelson and 

Gianoutsos, chapter 9 of this report)

• the determination of oil and gas assessment units (Higley, chapters 1, 6 and 7 of this report; Gaswirth and 

Higley, chapter 5 of this report)

• the migration history of oil and gas within the basin 

(Higley, chapters 3, 5, 6 and 7 of this report)

In addition to these basin-scale features, other products 

can be derived from inspection of the plates and manipulation 

of the data in Appendix 2. For example, cross sections A–A′ and 

B–B′ show that evaporite layers are present in the western part 

of each cross section but are absent in the eastern part of the 

cross sections. From the data in Appendix 2, the total thickness of evaporite was computed by summing all 10-ft intervals 

listed for each well. These sums were used to construct a map 

showing total evaporite thickness (fig. 3), which shows that the 

total evaporite thickness exceeds 1,000 ft in western Oklahoma 

and even exceeds 2,000 ft in three wells in the southwestern part 

of the Anadarko Basin. Evaporite thickness decreases steadily 

to the southeast and is absent in the southeastern part of the 

Anadarko Basin. Other mappable parameters and statistical 

results can be derived from the lithology data in Appendix 2.

Figure 3. Map of total thickness of evaporite in Permian rocks in the Anadarko Basin.

0

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190

250

1,020

1,160

1,700

1,070

1,470

1,030

1,320 1,510 1,070

1,360 1,110

1,100

2,070

2,130

1,210

1,760 1,430

1,400

1,330

2,650

0

100

500

1,000

2,000

1,500

KANSAS

TEXAS

OKLAHOMA

EXPLANATION

Contour interval variable, in feet

180

Well location

Evaporite thickness in feet

Contour poorly defined

100° 99° 98° 97°

37°

36°

35°

0 20 40 MILES

0 20 40 KILOMETERS

CH10Fig3
6 Lithology of Paleozoic Rock Units in 62 Wells, Anadarko Basin, Oklahoma

Acknowledgments

We thank David Blackwell of Southern Methodist 

University for his support and encouragement of this work. 

Reviews by Thomas Finn of the U.S. Geological Survey 

and Rick Andrews of the Oklahoma Geological Survey and 

guidance by Dick Keefer and Larry Anna of the U.S. Geological Survey led to improvements in the manuscript and 

cross sections. 

References Cited

Andrews, R.D., 2008, Morrow and Springer strata in the 

southern midcontinent, in Andrews, R.D., ed., Morrow and Springer in the southern midcontinent, 2005 

symposium: Oklahoma Geological Survey Circular 111, 

p. 81–97.

Bebout, D.G., White, W.A., Hentz, T.F., and Grasmick, M.K. 

eds., 1993, Atlas of major mid-continent gas reservoirs: 

Bureau of Economic Geology, 85 p.

Gallardo, J.D., 1989, Empirical model of temperature structure, Anadarko Basin, Oklahoma: Dallas, Tex., Southern 

Methodist University, Master’s thesis, 186 p.

Gallardo, Jaquidon, and Blackwell, D.D., 1999, Thermal 

structure of the Anadarko Basin, American Association of 

Petroleum Geologists Bulletin, v. 83, no. 2, p. 333–361.

IHS Energy, 2010, U.S. Production and well data: database 

available from IHS Energy, 15 Inverness Way East, D205, 

Englewood, Colorado 80112.

Kirkland, D.W., Dension, R.E., Summers, D.M., and Gormly, 

J.R., 1992, Geology and organic geochemistry of the Woodford Shale in the Criner Hills and western Arbuckle Mountains, Oklahoma; Oklahoma Geological Survey Circular 93, 

p. 38–69.

Oklahoma City Geological Society, 1971, Cross section of 

Oklahoma from SW to NE corners of state, Witt, W.J., 

Chairman of Stratigraphic Committee, 1 pl. 

Oklahoma Corporation Commission, 2010, Oil and gas database, http://www.occeweb.com/Orawebapps/OCCOraWebAppsone.html.

U.S. Geological Survey, 2014, Colorado, Kansas, New 

Mexico, Oklahoma, and Texas: U.S. Geological Survey 

digital data, The National Map, accessed August 4, 2014, 

at: http://viewer.nationalmap.gov/viewer/.
Chapter 11

Tectonic and Structural Evolution of

the Anadarko Basin and Structural

Interpretation and Modeling of a Composite

Regional 2D Seismic Line

By Ofori N. Pearson and John J. Miller

Chapter 11 of 13

Petroleum Systems and Assessment of Undiscovered Oil and Gas 

in the Anadarko Basin Province, Colorado, Kansas, Oklahoma, and 

Texas—USGS Province 58

Compiled by Debra K. Higley

U.S. Geological Survey Digital Data Series DDS–69–EE

U.S. Department of the Interior

U.S. Geological Survey

Click here to return to

Volume Title Page
U.S. Department of the Interior

SALLY JEWELL, Secretary

U.S. Geological Survey

Suzette M. Kimball, Acting Director

U.S. Geological Survey, Reston, Virginia: 2014

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Suggested citation: 

Pearson, O.N., and Miller, J.J., 2014, Tectonic and structural evolution of the Anadardo Basin and structural interpretation and modeling of a composite regional two-dimensional seismic line, chap. 11, in Higley, D.K., compiler, 

Petroleum systems and assessment of undiscovered oil and gas in the Anadarko Basin Province, Colorado, Kansas, 

Oklahoma, and Texas—USGS Province 58: U.S. Geological Survey Digital Data Series DDS–69–EE, 23 p., 

http://dx.doi.org/10.3133/ds69EE.

ISSN 2327-638X (online)
iii

Contents

Abstract...........................................................................................................................................................1

Introduction.....................................................................................................................................................1

Tectonic, Structural, and Stratigraphic Overview....................................................................................1

Precambrian Crustal Consolidation...................................................................................................3

Late Precambrian to Middle Cambrian Development of the Southern Oklahoma 

Aulacogen.................................................................................................................................6

Late Cambrian to Early Mississippian Isostatic Subsidence ........................................................7

Late Mississippian to Early Permian Development of the Anadarko Basin................................8

Stratigraphic Overview........................................................................................................................9

Cambrian and Ordovician Rocks...............................................................................................9

Silurian, Devonian, and Mississippian Rocks .........................................................................9

Pennsylvanian Rocks ................................................................................................................10

Permian Rocks............................................................................................................................10

2D Reflection Seismic Datasets Available to the U.S. Geological Survey .........................................11

2D Reflection Seismic Data Interpretation..............................................................................................13

General Description of the Seismic Lines ......................................................................................13

Seismic Interpretation of the Anadarko Composite Seismic Line.......................................................16

Structural Restoration of the Anadarko Composite Seismic Line .......................................................17

Summary........................................................................................................................................................21

Acknowledgments.......................................................................................................................................21

References Cited..........................................................................................................................................21

Figures

1. Map showing the location of the Anadarko Basin Province (red line). The general

outline of the Anadarko Basin (blue line) is from Johnson and others (1988)....................2

2. Map showing the location of seismic lines (blue) licensed by the USGS within the

Anadarko Basin Province (red line). Names by which the seismic lines are referred

are also shown. Seismic data are owned or controlled by Seismic Exchange, Inc .........2

3. Map showing the major structural provinces of the Anadarko Basin and adjacent

areas. Traces of major thrust faults are also shown in red, with U and D designating

the upthrown and downthrown sides of selected faults. The fault system on the

northern edge of the Wichita and Amarillo uplifts is known as the Wichita fault

system (Harlton, 1963). Faults specifically referred to in the text are labeled. State

boundaries are outlined in black; counties are outlined in gray. Modified from Luza

and others (1987), Johnson (1989), and Luza (1989). Traces of seismic lines are

shown in light blue........................................................................................................................3

4. Simplified stratigraphic column for the northern Anadarko Basin (modified from

Higley and Gaswirth, 2014, and references therein). Informal unit names are

italicized. Names in red are the stratigraphic units used in the seismic

interpretation and structural restoration. Wavy horizontal lines and vertical bars

indicate unconformities. Ages are in millions of years before the present (Ma).

Note the change of vertical scale between the Cambrian–Mississippian column

and the Pennsylvanian–Permian column .................................................................................4
iv

5. Maps showing the sequence of Proterozoic events that formed the complex suite

of basement rocks beneath the Anadarko Basin Province. Modified from

Whitmeyer and Karlstrom (2007). A, Yavapai orogeny; B, intrusion of the Yavapai

Province by granitoids; C, Mazatzal orogeny; D, intrusion of Mazatzal granitoids;

E, suturing of the Granite-Rhyolite Province; F, extensive granitoid intrusion of the

Yavapai, Mazatzal, and Granite-Rhyolite Provinces; G, intrusion of Grenville-aged

granitoids and development of the Midcontinent rift system; H, development of the

southern Oklahoma aulacogen. Ga, billion years before the present .................................5

6. Map showing the geometry of the eastern Laurentian margin during the Cambrian

in the southern and eastern United States. Locations and geometries of the

southern Oklahoma aulacogen and the Reelfoot rift are shown. Paleogeographic

map for the Middle Cambrian (510 Ma) is from Blakey (2011). Rifted margin

geometry and location of the Reelfoot rift and southern Oklahoma aulacogen are

from Keller and others (1983)......................................................................................................6

7. Map showing the location of the northwestern limits of the southern Oklahoma

aulacogen relative to the present Anadarko Basin. The aulacogen is shown in light

gray, thrust and reverse faults of the Wichita fault system are shown in red, and

contour lines show approximate depths to basement in the Anadarko Basin, with

depths in tens of thousands of feet below sea level. Modified from Perry (1989) and

references therein. Ga, billions of years before the present ................................................7

8. Root mean square velocity model used to migrate and convert seismic Line

D. Velocities were determined using an automated velocity picking algorithm,

and subsequently smoothed using a 201 common depth point horizontal, and

250-millisecond vertical, smoothing operator. A color bar illustrating the velocity

scale is also shown. Seismic data are owned or controlled by Seismic Exchange,

Inc.; interpretation is that of the U.S. Geological Survey.....................................................12

9. Uninterpreted seismic Line A. Location of line is shown in figure 2. Horizontal 

and vertical scales are equal. Black colors are amplitude peaks; red colors are

amplitude troughs. Seismic data are owned or controlled by Seismic 

Exchange, Inc..............................................................................................................................13

10. Uninterpreted seismic Line B. Location of line is shown in figure 2. Horizontal and

vertical scales are equal. Dark black colors are amplitude peaks; dark red colors

are amplitude troughs. Seismic data are owned or controlled by Seismic 

Exchange, Inc. Figure 10 is oversized. Click on the thumbnail to view the enlarged 

version ..........................................................................................................................................14

11. Uninterpreted seismic Line C. Location of line is shown in figure 2. Horizontal and

vertical scales are equal. Dark black colors are amplitude peaks; dark red colors

are amplitude troughs. Seismic data are owned or controlled by Seismic 

Exchange, Inc..............................................................................................................................14

12. Uninterpreted seismic Line D. Location of line is shown in figure 2. Horizontal and

vertical scales are equal. Dark black colors are amplitude peaks; dark red colors

are amplitude troughs. Seismic data are owned or controlled by Seismic 

Exchange, Inc. Figure 12 is oversized. Click on the thumbnail to view the enlarged 

version ..........................................................................................................................................15

13. Uninterpreted seismic Line E. Location of line is shown in figure 2. Horizontal and

vertical scales are equal. Dark black colors are amplitude peaks; dark red colors

are amplitude troughs. Seismic data are owned or controlled by Seismic 

Exchange, Inc. Figure 13 is oversized. Click on the thumbnail to view the enlarged 

version ..........................................................................................................................................15
v

14. Map showing the location of wells used to aid in the interpretation of the

composite seismic line. Oklahoma counties are shown in gray. The segments of the

composite seismic line are shown in blue. American Petroleum Institute well

numbers are given......................................................................................................................16

15. Interpreted seismic Line C. Location of line is shown in figure 2. Horizontal and

vertical scales are equal. Dark black colors are amplitude peaks; dark red colors

are amplitude troughs. Well symbols are the same as those used in fig. 14.

American Petroleum Institute well numbers are indicated. Lithology codes for well

tops are given in table 1. Seismic data are owned or controlled by Seismic

Exchange, Inc.; interpretation is that of the U.S. Geological Survey .................................17

16. Interpreted seismic Line D. Location of line is shown in figure 2. Horizontal and

vertical scales are equal. Dark black colors are amplitude peaks; dark red colors

are amplitude troughs. Well symbols are the same as those used in fig. 14.

American Petroleum Institute well numbers are indicated. Lithology codes for well

tops are given in table 1. Seismic data are owned or controlled by Seismic

Exchange, Inc.; interpretation is that of the U.S. Geological Survey. Figure 16 is

oversized. Click on the thumbnail to view the enlarged version ........................................18

17. Interpreted seismic Line E. Location of line is shown in figure 2. Horizontal and

vertical scales are equal. Dark black colors are amplitude peaks; dark red colors

are amplitude troughs. Well symbols are the same as those used in figure 14.

American Petroleum Institute well numbers are indicated. Lithology codes for well

tops are given in table 1. Seismic data are owned or controlled by Seismic

Exchange, Inc.; interpretation is that of the U.S. Geological Survey. Figure 17 is

oversized. Click on the thumbnail to view the enlarged version ........................................18

18. Structural restoration showing individual restoration stages. Depth in each stage is

shown in thousands of feet below sea level; horizontal distance is given in miles

from the southwestern edge of seismic Line C (no vertical exaggeration). Seismic

data are owned or controlled by Seismic Exchange, Inc.; interpretation is that of

the U.S. Geological Survey. Figure 18 is oversized. Click on the thumbnail to view

the enlarged version ..................................................................................................................18

19. Incremental shortening (blue line and round markers) and cumulative shortening

(red line and star markers) is shown for all stages of the structural restoration

shown in figure 18. Note that the vertical axis is time, rather than stratigraphic

thickness ......................................................................................................................................20

Tables

1. Lithology codes and corresponding stratigraphic units for formation tops shown in

figures 15, 16, and 17 ..................................................................................................................10

2. Seismic line names, counties and states where seismic lines were recorded, the

year the USGS purchased licenses for the data, and the lengths of each line.

Seismic data are owned or controlled by Seismic Exchange, Inc.; interpretation is

that of the U.S. Geological Survey ...........................................................................................11

3. Data acquisition parameters for the five seismic lines used in this study. Seismic

data are owned or controlled by Seismic Exchange, Inc.; interpretation is that of

the U.S. Geological Survey........................................................................................................11

Abstract

The U.S. Geological Survey recently completed an 

assessment of undiscovered oil and gas resources in the 

Anadarko Basin Province of western Oklahoma and Kansas, 

northern Texas, and southeastern Colorado. The assessment 

methodology required a detailed look at the region’s tectonic 

and structural evolution, which can be divided into the following four periods: (1) Precambrian crustal consolidation; 

(2) development of the southern Oklahoma aulacogen during 

late Precambrian to Middle Cambrian time; (3) thermally 

controlled isostatic subsidence of the failed rift from Late 

Cambrian to Early Mississippian time; and (4) development 

of the Ouachita-Marathon orogeny that caused the Wichita 

uplift and development of the asymmetric Anadarko Basin 

beginning in Late Mississippian time. Many of the basin’s 

key structural elements are visible on two-dimensional reflection seismic lines, and interpretations of the data reveal the 

basin’s subsurface structural geometry. A structural restoration based upon the seismic interpretation shows the possible geometric evolution for 22 of the Anadarko Basin’s key 

stratigraphic units.

Introduction

The asymmetric Anadarko Basin (fig. 1) is the deepest 

interior cratonic basin in the conterminous United States, containing as much as ≈40,000 feet of Upper Cambrian–Permian 

sedimentary rocks (Johnson and others, 1988). It has been one 

of the more productive U.S. basins in terms of production of 

oil and gas, with cumulative production in excess of 5.4 billion 

barrels of oil and 125 trillion cubic feet of gas (IHS Energy, 

2010). In 2010, the U.S. Geological Survey (USGS) conducted 

an assessment of undiscovered oil and gas resources contained 

within the Anadarko Basin Province of western Oklahoma and 

Kansas, northern Texas, and southeastern Colorado (fig. 1), 

resulting in means of 495 million barrels of oil, 27,461 billion 

cubic feet of gas, and 410 million barrels of natural gas liquids 

(Higley and others, 2011).

As part of the 2010 assessment, an analysis of the 

Anadarko Basin’s tectonic and structural evolution was 

conducted. A broad overview is presented in this chapter 

of the report, based on previously published studies and 

an interpretation and structural restoration of five twodimensional (2D) reflection seismic lines (fig. 2) acquired 

by the USGS within the basin. Published studies typically 

describe four main phases of tectonic and structural activity 

for the Anadarko Basin, and those divisions are adopted for 

this study. The acquisition and processing of the reflection 

seismic lines are also described. Three of those lines (fig. 2; 

Lines C, D, and E) that lie in close proximity to one another 

were combined into a composite regional line, and the 

seismic interpretation of this line is discussed. A structural 

restoration is documented that was built from the seismic 

interpretation and key findings of the restoration are tied into 

elements of the broader tectonic and structural evolution of 

the Anadarko Basin.

Tectonic, Structural, and Stratigraphic 

Overview

Although the oldest sedimentary rocks in the Anadarko 

Basin are of Cambrian age, the basin’s earlier tectonic and 

structural history plays an important role in the depositional 

history of the Paleozoic section and on the petroleum systems 

that are the subject of the 2010 USGS assessment. The eastern 

margin of North America has undergone two complete Wilson 

cycles (plate-tectonic spreading and convergence; Wilson, 

1966)—the assembly and breakup of both the Rodinia and 

Pangaea land masses. Basement and sedimentary rocks of the 

Anadarko Basin Province were involved in the Proterozoic 

assembly and breakup of Rodinia, and the Paleozoic assembly 

of Pangaea.

Most workers describe the evolution of the Anadarko 

Basin in terms of four main tectonic and structural events, 

two of which occurred before deposition of the basin’s oldest 

(Cambrian) sedimentary rocks. These four primary phases of 

tectonic and structural activity are: (1) Precambrian crustal 

Tectonic and Structural Evolution of the Anadarko Basin 

and Structural Interpretation and Modeling of a Composite 

Regional 2D Seismic Line

By Ofori N. Pearson and John J. Miller
2 Tectonic and Structural Evolution of the Anadarko Basin, Structural Interpretation and Modeling of a Seismic Line

Figure 1. Map showing the 

location of the Anadarko Basin 

Province (red line). The general 

outline of the Anadarko Basin 

(blue line) is from Johnson and 

others (1988).

Figure 2. Map showing the 

location of seismic lines (blue) 

licensed by the USGS within 

the Anadarko Basin Province 

(red line). Names by which the 

seismic lines are referred are 

also shown. Seismic data are 

owned or controlled by Seismic 

Exchange, Inc.

104° 103° 102° 101° 100° 99° 98° 97°

39° 

38° 

37° 

36° 

35° 

34° 

GULF 

OF 

MEXICO

TEXAS

NEW

MEXICO

COLORADO KANSAS

OKLAHOMA

Anadarko 

 Basin 

 Province

OKLAHOMA

KANSAS

COLORADO

TEXAS

NEW

MEXICO

Ch11_Figure 1

Anadarko Basin

0 50 100 MILES

0 50 100 KILOMETERS

104° 103° 102° 101° 100° 99° 98° 97° 

39°

38°

37°

36°

35°

34°

0 50 100 MILES

0 50 100 KILOMETERS

OKLAHOMA

KANSAS

COLORADO

TEXAS

NEW

MEXICO

Line E

Line D

Line C

Line B

Line A

Anadarko Basin
Tectonic, Structural, and Stratigraphic Overview 3

consolidation; (2) late Precambrian to Middle Cambrian 

development of the southern Oklahoma aulacogen; (3) Late 

Cambrian to Early Mississippian isostatic subsidence; and 

(4) development of the Anadarko Basin beginning in the Late 

Mississippian, because of the Ouachita orogeny. The following discussion gives a broad overview of each of these 

four phases, primarily as they relate to the Anadarko Basin 

proper. Although the Anadarko Basin Province also contains 

parts of other major structural elements (fig. 3) that make up 

the southern midcontinent region (for example, the Hugoton 

embayment, the Cimarron arch, the Palo Duro Basin, and 

the Nemaha uplift), these are discussed only in terms of how 

they relate to the Anadarko Basin. A simplified stratigraphic 

column for the basin is shown in figure 4. A rationale for the 

simplification shown in the column and a description of the 

lithologies are provided in the stratigraphic summary portion 

of this report.

Precambrian Crustal Consolidation

Figure 5 (modified from Whitmeyer and Karlstrom, 

2007) portrays the Proterozoic sequence of events that led to 

crustal consolidation of basement rock beneath the Anadarko 

Basin Province. Also shown in figure 5 are the ages of rocks 

that were sutured onto the southeastern margin of Laurentia 

and also the ages of intrusives that accompanied the various 

orogenies and stitched terranes together. The oldest basement rocks in the province (fig. 5A) were likely accreted 

onto the margin of Laurentia during the Yavapai orogeny 

≈1.76–1.72 billion years before the present (Ga) (Whitmeyer and Karlstrom, 2007). During the orogeny, oceanic 

arc terranes (1.76–1.72 Ga) sutured onto Laurentia along the 

Cheyenne belt in Wyoming and the Spirit Lake tectonic zone 

at the southern margin of the western Superior and Penokean 

Provinces (Whitmeyer and Karlstrom, 2007). Following 

accretion, the Yavapai Province was intruded by granitoids 

(fig. 5B) dated at ≈1.72–1.68 Ga (Whitmeyer and Karlstrom, 

2007). The next major event to affect the southeastern margin 

of Laurentia was the Mazatzal orogeny, during which crust 

dated at 1.69–1.65 Ga formed in continental margin volcanic arcs and back-arc-related supracrustal successions were 

accreted along a bivergent suture zone (fig. 5C; Whitmeyer 

and Karlstrom, 2007). During later stages of the Mazatzal 

orogeny (1.65–1.60 Ga), both the Yavapai and Mazatzal 

Provinces were intruded by granitoids (fig. 5D). The southernmost portion of the Anadarko Basin Province may be underlain by basement rocks of the 1.55–1.35 Ga Granite-Rhyolite 

Province (fig. 5E; Van Schmus and others, 1996). Following 

Figure 3. Map showing the major structural provinces of the Anadarko Basin and adjacent areas. Traces of major thrust faults 

are also shown in red, with U and D designating the upthrown and downthrown sides of selected faults. The fault system on the 

northern edge of the Wichita and Amarillo uplifts is known as the Wichita fault system (Harlton, 1963). Faults specifically referred to 

in the text are labeled. State boundaries are outlined in black; counties are outlined in gray. Modified from Luza and others (1987), 

Johnson (1989), and Luza (1989). Traces of seismic lines are shown in light blue.

UD

U

U U U

U

U

U

U U

U

UU U U U

D

D D D

D

D

D

D D

D

D D D D

D

UD

UD U

D

0 50 100 MILES

0 50 100 KILOMETERS

104° 102° 100° 98° 96° 94°

38°

36°

34°

NEW

MEXICO

COLORADO

TEXAS

OKLAHOMA

KANSAS

MISSOURI

ARKANSAS

Anadarko Basin

Marietta Basin

Ardmore

Basin Hardeman Basin

Palo Duro Basin Hollis Basin

Dalhart

Basin

Arkoma Basin

Las

Animas

arch

Sierra

Grande

arch

Bravo dome

Apishapa

uplift

Amarillo uplift

Wichita uplift

Cimarron arch

Hugoton

embayment Nemaha uplift

Ozark uplift

Arbuckle

Mountain 

uplift

Gulf Coastal Plain

Ouachita

Mountain

uplift

MOUNTAIN VIEW FAULT

CORDELL

FAULT
4 Tectonic and Structural Evolution of the Anadarko Basin, Structural Interpretation and Modeling of a Seismic Line

Figure 4. Simplified stratigraphic column for the northern Anadarko Basin (modified from Higley and Gaswirth, 2014, and references 

therein). Informal unit names are italicized. Names in red are the stratigraphic units used in the seismic interpretation and structural 

restoration. Wavy horizontal lines and vertical bars indicate unconformities. Ages are in millions of years before the present (Ma). Note 

the change of vertical scale between the Cambrian–Mississippian column and the Pennsylvanian–Permian column.

Bonneterre Dolomite

Reagan (Lamotte) Sandstone

Arbuckle Group

Simpson Group

Viola Group

Sylvan Shale

Hunton Group

Woodford Shale

Osage lime

Meramec lime

Chester Group

Cunningham sand Britt sand

Northern

Anadarko Basin

Dresbachian

Franconian

Trempealeauan

Canadian

Champlainian

Cincinnatian

Alexandrian

Niagaran

Cayugan

Ulsterian

Erian

Senecan

Chautauquan

Kinderhookian

Osagean

Meramecian

Chesterian

Series

Cambrian

(part) Ordovician Silurian Devonian Mississippian

System

501

497

492.5

488.3

±1.7

472

452

443.7

±1.5

432

421

416.0

±2.8

379

374

365

359.2

±2.5

348

340

333

318.1

±1.3

Morrow Formation

Atoka Group

Cherokee Group

(incl. Taft Sandstone)

Marmaton Group

Kansas City Group (incl. Hogshooter Limestone & Checkerboard Limestone)

Lansing Group

Douglas Group

Oread Limestone

Topeka Limestone

Wabaunsee Group

Admire Group

Council Grove Group

Chase Group

Wellington Formation

Hennessey Shale

Stone Corral Formation

El Reno Group

Whitehorse Group

Cloud Chief Formation

Northern

Anadarko Basin

Morrowan

Atokan

Desmoinesian

Missourian

Virgilian

Wolfcampian

Leonardian

Guadalupian

Ochoan

Series

Permian Pennsylvanian

System

318.1

±1.3

311

308

304

300

299.0

±0.8

271

256

251.0

±0.4

Age, 

ma

Age, 

ma

cH11_Figure 4
Tectonic, Structural, and Stratigraphic Overview 5

Figure 5. Maps showing the sequence of Proterozoic events that formed the complex suite of 

basement rocks beneath the Anadarko Basin Province. Modified from Whitmeyer and Karlstrom 

(2007). A, Yavapai orogeny; B, intrusion of the Yavapai Province by granitoids; C, Mazatzal orogeny; 

D, intrusion of Mazatzal granitoids; E, suturing of the Granite-Rhyolite Province; F, extensive 

granitoid intrusion of the Yavapai, Mazatzal, and Granite-Rhyolite Provinces; G, intrusion of 

Grenville-aged granitoids and development of the Midcontinent rift system; H, development of the 

southern Oklahoma aulacogen. Ga, billion years before the present.

H

0.535 Ga

38°

36°

34°

G

1.3-0.95 Ga

F

1.45-1.35 Ga

38°

36°

34°

E

1.55-1.35 Ga

D

1.65-1.60 Ga

38°

36°

34°

C

1.69-1.65 Ga

104° 102° 100° 98°

B

1.72-1.68 Ga

104° 102° 100° 98° 

38°

36°

34°

A

1.76-1.72 Ga

Convergent

 margins

Major normal

 faults

Anadarko Basin

 Province boundary

State

 boundaries

1.76–1.72 Ga

 Yavapai Province

1.72–1.68 Ga

 juvenile arcs

1.72–1.68 Ga

 granitoids

1.69–1.65 Ga

 Mazatzal Province

1.65–1.60 Ga

 granitoids

1.55–1.35 Ga Granite-

 Rhyolite Province

1.2–1.1 Ga mid-

 continent rift system

0.535 Ga Oklahoma

 aulacogen rift basin 1.45–1.35 Ga granitoids

1.3–0.95 Ga granitoids

Ch11_Figure 5

EXPLANATION

100 MILES

100 KILOMETERS

0

0
6 Tectonic and Structural Evolution of the Anadarko Basin, Structural Interpretation and Modeling of a Seismic Line

accretion of the Granite-Rhyolite Province to the southeastern 

margin of Laurentia, the Yavapai, Mazatzal, and Granite-Rhyolite Provinces were all intruded by extensive bimodal A-type 

granites (1.45–1.35 Ga, fig. 5F; Whitmeyer and Karlstrom, 

2007) that stitched together the three provinces.

The Proterozoic assembly of Laurentia culminated during 

the 1.30–0.95 Ga Grenville orogeny (fig. 5G). The GrenvilleLlano deformation front (the Llano front is the likely southwestern continuation in Texas of the Grenville front) lay to the 

south of the Anadarko Basin Province in the Granite-Rhyolite 

Province (Thomas, 1991), thus probably did not affect basement rocks within the Anadarko Basin Province. Along with 

the Grenville deformation front, late Grenville granitoids 

intrusions in Colorado and the southernmost extent of the 

1.2–1.1 Ga Midcontinent rift system in Kansas (fig. 5G) are 

likely the most proximal signatures of the Grenville orogeny. 

Following the amalgamation of Laurentia during the Grenville 

orogeny, a long process of diachronous rifting began. Early 

rifting (between 0.78 and 0.68 Ga) occurred to the west, and 

separated Australia, Antarctica, south China, and Siberia from 

Laurentia. Rifting on the eastern margin of Laurentia began 

between 0.62 and 0.55 Ga (Whitmeyer and Karlstrom, 2007). 

The final rifting event that affected the midcontinent region 

was the separation of the Argentinian Precordillera terrane 

from the Ouachita embayment of eastern Oklahoma and 

Texas (Thomas and Astini, 1996). Although the mechanics 

behind the translation of the Argentinian Precordillera from 

the southeastern margin of Laurentia to the western margin 

of Gondwana are poorly understood, they likely involve the 

Reelfoot rift and Southern Oklahoma aulacogen (Whitmeyer 

and Karlstrom, 2007). Formation of the southern Oklahoma 

aulacogen (fig. 5H) during the Cambrian (~0.535 Ga) was the 

next major tectonic and structural event to affect the Anadarko 

Basin Province.

Late Precambrian to Middle Cambrian 

Development of the Southern Oklahoma 

Aulacogen

The second half of the first complete Wilson cycle to 

affect the eastern margin of North America involved the 

breakup of Rodinia and the opening of the Iapetus Ocean. 

Toward the end of this rifting phase in the Early Cambrian, 

at least two triple junctions developed in what is now the 

southeastern United States (Whitmeyer and Karlstrom, 2007). 

Evidence for the presence of these triple junctions includes the 

Reelfoot rift and the southern Oklahoma aulacogen (fig. 6). 

Development of the southern Oklahoma aulacogen played a 

key role in the formation of the Anadarko Basin, as the aulacogen’s geometry and thermal effect on the surrounding crust 

exhibited first-order controls on subsequent depositional and 

structural trends.

Shatsky (1946) was the first to suggest the presence of an 

aulacogen in southern Oklahoma. The primary lines of evidence that support the existence of a failed rift system are an 

extensive suite of bimodal Cambrian igneous rocks and a linear 

trend of high Bouguer gravity anomaly values across southern 

Oklahoma. Bimodal igneous rocks of Cambrian age are wellexposed on the Wichita uplift (fig. 3) south of the Anadarko 

Basin. These rocks include: (1) the Glen Mountains Layered 

Complex, which is a layered mafic intrusion; (2) the 525-million 

years before the present (Ma) Carlton Rhyolite Group, which 

comprises over 40,000 cubic kilometers (km3) of silicic intrusive and volcanic rocks (Gilbert, 1983); and (3) other basalts 

and granites (Keller and Stephenson, 2007). The other primary 

line of evidence that supports the existence of the southern 

Oklahoma aulacogen is the linear trend of high Bouguer gravity anomaly values extending from about long. 96° to 101° W. 

across southern Oklahoma (see fig. 3 of Keller and Stephenson, 

2007). This gravity high has been linked to the presence of a 

deep and massive mafic intrusive (Keller and Baldridge, 1995). 

The three-armed pattern of Bouguer gravity highs at the southeastern edge of the aulacogen is likely tied to a rift-rift-rift triple 

junction (see fig. 3 of Keller and Stephenson, 2007).

Rift systems are typically bounded by extensive normal 

fault systems, and the presence of such faults around the 

southern Oklahoma aulacogen was inferred by Gilbert (1982, 

1987). However, normal fault systems flanking the aulacogen 

that are clearly rift-related have not been recognized (Keller 

and Stephenson, 2007). This is likely because of a combination of poor exposures and extensive deformation during the 

latter parts of the Paleozoic that may have inverted or reactivated Cambrian extensional structures.

Although the axes of the southern Oklahoma aulacogen 

and the Anadarko Basin are subparallel, the two features do 

not completely overlap. The northern edge of the aulacogen 

probably lies beneath the southern edge of the Anadarko Basin 

Figure 6. Map showing the geometry of the eastern Laurentian 

margin during the Cambrian in the southern and eastern United 

States. Locations and geometries of the southern Oklahoma 

aulacogen and the Reelfoot rift are shown. Paleogeographic map 

for the Middle Cambrian (510 Ma) is from Blakey (2011). Rifted 

margin geometry and location of the Reelfoot rift and southern 

Oklahoma aulacogen are from Keller and others (1983).

LATE PROTEROZOIC RIFTED

CONTINENTAL

MARGIN

LATE PROTEROZOIC RIFTED

CONTINENTAL

MARG

ANADARKO BASIN PROVINCE IN

Paleo-continental margin

Southern Oklahoma aulacogen

Reelfoot rift

30°

40°

50°

120° 110° 100° 90° 80° 70°

cH1

500 MILES

500 KILOMETERS

250

250

0

0
Tectonic, Structural, and Stratigraphic Overview 7

Figure 7. Map showing the location of the northwestern limits of the southern Oklahoma 

aulacogen relative to the present Anadarko Basin. The aulacogen is shown in light gray, 

thrust and reverse faults of the Wichita fault system are shown in red, and contour lines 

show approximate depths to basement in the Anadarko Basin, with depths in tens of 

thousands of feet below sea level. Modified from Perry (1989) and references therein. Ga, 

billions of years before the present.

100 MILES

100 KILOMETERS

50

50

0

0

OKLAHOMA

COLORADO KANSAS

TEXAS

NEW

MEXICO

104° 103° 102° 101° 100° 99° 98° 97° 

39°

38°

37°

36°

35°

34°

Anadarko Basin

10

20

30 40 WICHITA FAULT SYSTEM

Cambrian basement

Ch11_Figure 7

(Perry, 1989; fig. 7). Some of the thrust and reverse faults that 

separate the basin from the Wichita uplift could be inverted 

normal faults associated with Cambrian rifting.

By the end of the Middle Cambrian, rifting along the 

incipient spreading center below southern Oklahoma ended, 

and the extensive suite of igneous rocks that had been incorporated into the crust in the vicinity of the aulacogen began to 

cool. This period of thermal subsidence lasted from the Late 

Cambrian through the Early Mississippian, and characterizes 

the next major phase in the region’s tectonic, structural, and 

depositional evolution.

Late Cambrian to Early Mississippian Isostatic 

Subsidence

The oldest sedimentary rocks in the Anadarko Basin are 

the Upper Cambrian Reagan Sandstone (fig. 4). The deposition of these rocks marks the beginning of a lengthy phase 

dominated by basin subsidence, during which more than 

40,000 ft of Upper Cambrian through Permian sediments 

accumulated. The initial phase of subsidence occurred from 

Late Cambrian through Early Mississippian time, and was 

dominated by thermally controlled isostatic subsidence 

caused primarily by cooling of the southern Oklahoma aulacogen (Feinstein, 1981).

This lengthy initial period of subsidence occurred during 

a time when the southern midcontinent region was isolated 

from tectonic events related to the start of the second Wilson 

cycle. In North America, the Appalachian-Ouachita orogenic 

belt records successive, diachronous orogenies that resulted in 

the closure of the Iapetus Ocean and the formation of Pangaea during the Permian (Thomas, 2006). These orogenies 

are the Taconic (Ordovician-Silurian), Acadian (DevonianMississippian), and the Alleghanian (Mississippian-Permian). 

During the Taconic and Acadian orogenies, which mainly 

affected more northern parts of the North American continent, a passive margin outboard of the southern midcontinent 

region persisted until Mississippian time (Thomas, 1989). The 

relative isolation of the southern midcontinent region from tectonic stresses that occurred farther to the north, suggests that 

unconformities within the Upper Cambrian through Lower 
8 Tectonic and Structural Evolution of the Anadarko Basin, Structural Interpretation and Modeling of a Seismic Line

Mississippian stratigraphic section of the Anadarko Basin are 

more likely related to global sea level changes than to structural events.

The cooling southern Oklahoma aulacogen created 

accommodation space in what is known as the southern Oklahoma trough, which is generally coincident with the geometry 

of the aulacogen (Perry, 1989). More than 11,700 ft of Cambrian-Devonian rocks were deposited in this trough (Ham, 

1973; Cardott and Lambert, 1985). Feinstein (1981) proposed 

a two-stage mechanism to explain the Late Cambrian through 

Early Mississippian subsidence of the Oklahoma trough. 

The earliest stage occurred during deposition of the basal 

Upper Cambrian Reagan Sandstone. The rate of subsidence 

at this stage was low, and can be compared to that of other 

basins where elastic flexure of the lithosphere in response 

to an increased load (rocks emplaced during the aulacogen) 

governed subsidence (Feinstein, 1981). Feinstein (1981) 

proposed that higher rates of subsidence that followed deposition of the Reagan Sandstone can be attributed to detachment of the aulacogen from the adjacent platform, possibly 

reactivating normal fault systems that bounded the aulacogen. 

After detaching from the adjacent platform, evolution of the 

Oklahoma trough generally followed an exponential curve 

of subsidence with time controlled by isostatic subsidence 

driven by cooling of rocks emplaced during formation of the 

aulacogen (Feinstein, 1981). This two-stage model supports 

observations that slow initial rates of Cambrian subsidence 

accelerated during the Early Ordovician before slowing again 

in the Late Ordovician as the aulacogen reached thermal equilibrium; slow gradual rates of subsidence continued during 

Silurian, Devonian, and Early Mississippian time (see figs. 2 

and 3 in Feinstein, 1981).

Late Mississippian to Early Permian 

Development of the Anadarko Basin

Beginning in the Late Mississippian, the prolonged 

period of relative tectonic and structural quiescence in the 

southern midcontinent region ended abruptly as compressional 

forces associated with the Appalachian-Ouachita orogeny 

arrived. For the southern midcontinent region, this marked the 

onset of the second Wilson cycle, which included the assembly and subsequent breakup of Pangaea. For the remainder 

of this discussion, this orogenic period will be referred to 

as the Ouachita-Marathon orogeny, as this nomenclature is 

more commonly used in the literature to describe the collision 

between the North American and the South American–African 

plates. Compressional forces of the Ouachita-Marathon orogeny are generally thought to be responsible for the structural 

inversion of the southern Oklahoma aulacogen, and the subsequent formation of the Anadarko Basin (Kluth and Coney, 

1981; Kluth, 1986).

Structures related to the Ouachita-Marathon orogeny in 

the Anadarko Basin Province have been extensively documented and described (see, for example, McConnell, 1989; 

Perry, 1989), as they have not been overprinted by subsequent 

deformation. Identification of many of these structures has 

been aided by the availability of extensive subsurface datasets 

produced during exploration for petroleum. Detailed descriptions of individual structural features are not provided in the 

following summary, but the tectonic forces that caused the 

formation of the Anadarko Basin and the resultant basin-scale 

structural features are discussed.

The earliest compressional stresses of the Ouachita-Marathon orogeny affected the Alabama promontory during Middle 

Mississippian time in what is now the Black Warrior Basin 

of Alabama (Thomas, 2006). The deformation front migrated 

toward the northwest along the Alabama-Oklahoma transform 

fault, and reached the Arkoma Basin (fig. 3) by the Early 

Pennsylvanian (Thomas, 1989). This migration of the deformation front is an excellent example of tectonic inheritance, 

as preexisting crustal weaknesses that developed during the 

rifting of Rodinia were exploited by the Ouachita-Marathon 

orogeny (Thomas, 2006).

Within the Anadarko Basin region, the earliest sign of 

the approaching deformation front may be the pinching-out of 

uppermost Mississippian–lowermost Pennsylvanian sandstones in the western Ardmore Basin (fig. 3; Perry, 1989). 

During Morrowan time, a broad uplift formed that extended 

from the Criner Hills southward into Texas and northwestward 

toward the Wichita Mountains. Tomlinson and McBee (1959) 

called this uplift the Wichita-Criner uplift, and it included the 

Wichita Mountains, which were rising during this time. To 

the northeast of the uplift, a narrow trough developed, into 

which greater thicknesses of Morrowan through Desmoinesian 

sediments were deposited relative to the shelf farther to the 

northeast (Johnson, 1989). Development of the Wichita-Criner 

uplift accelerated during the late Morrowan, and climaxed 

during Atokan time. On the northeast flank of the Wichita 

Mountains, synorogenic sediments derived from the weathering of both Mississippian limestones that mantled the Wichita 

Mountains and basement rocks were deposited in the immediate footwall of the developing Wichita fault system (fig. 3; 

Johnson, 1989). These synorogenic sediments suggest that the 

mountains had been unroofed by this time. The Wichita fault 

system may have reactivated normal faults that formed during 

emplacement of the southern Oklahoma aulacogen. By the 

beginning of Desmoinesian time, faulting along the margins 

of the Wichita Mountains had ended (Perry, 1989). However, 

the uplift remained a positive feature through the end of the 

Pennsylvanian, and continued to supply sediments into the 

deepening Anadarko Basin. During the Late Pennsylvanian, 

the deformation front appears to have migrated both to the east 

and to the southwest. The eastward migration is evidenced by 

structural activity in the Arbuckle Mountains (Perry, 1989) 

and in the Ouachita Mountains of southeastern Oklahoma and 

west-central Arkansas (Johnson, 1989). Westward migration is 

seen by deformation in the Marathon region of western Texas, 

which climaxed in the Virgilian or Wolfcampian; by Leonardian time, the Ouachita-Marathon orogeny had ended (Kluth 

and Coney, 1981).
Tectonic, Structural, and Stratigraphic Overview 9

Major structural activity in the Anadarko Basin ended by 

the Early Permian (Perry, 1989). Deposition continued to the 

end of the Permian; accommodation space was likely created both by continued gradual subsidence of the basin and 

compaction of older rocks. The final act of the second Wilson 

cycle to affect the eastern margin of North America began in 

the Triassic with the onset of Atlantic rifting. By this time, 

however, the Anadarko Basin was located far inboard of the 

continental margin, and does not appear to have been affected. 

The most recent structural activity within the basin involves 

minor reactivation of normal faults that may have occurred 

during the Jurassic, Cretaceous, and Holocene (Perry, 1989).

As previously mentioned, the Wichita Mountains are 

bounded to the northeast by the Wichita fault system (fig. 3). 

Brewer and others (1983) reported that deep reflection seismic 

profiles across the Anadarko Basin and Wichita Mountains 

image a series of thrust faults that dip 30° to 40° toward 

the southeast, and accommodated 9.3 ± 3.1 miles of crustal 

shortening. This amount of shortening supports the idea that 

subsidence of the Anadarko Basin was at least partially related 

to hanging-wall crustal loading (Brewer and others, 1983). 

In addition to dip-slip motion along the Wichita fault system, 

there is considerable evidence based upon offset fold hinges 

and isochores that left-lateral strike slip motion may also 

have occurred. McConnell (1989) proposed that as much as 

7.5 miles of left-lateral motion occurred along the Mountain 

View fault (fig. 3), and that this supports the arguments put 

forth by Kluth and Coney (1981) that intracratonic uplifts 

related to the Ouachita-Marathon orogeny were caused by 

reactivated slip on faults bounding basement-cored uplifts.

Geodynamic calculations discussed by Garner and 

Turcotte (1984) led to the suggestion that formation of the 

Anadarko Basin can best be modeled in terms of elastic 

flexure of the lithosphere. Under this scenario, compressional 

forces related to the Ouachita-Marathon orogeny did not 

cause basinal subsidence. Rather, Garner and Turcotte (1984) 

argued that compression was caused by flexure-related 

subsidence of the Anadarko Basin. Given the large amounts 

of compression accommodated by the Mountain View fault 

system, it seems likely that formation of the Anadarko Basin 

was caused by a combination of thrust-loading and flexurerelated subsidence.

Stratigraphic Overview

Although a detailed stratigraphic description of the rocks 

within the Anadarko Basin is beyond the scope of this report, it 

is important to summarize the key lithologic characteristics of 

the units shown in the interpretation of the composite seismic 

line and the structural model (discussed in subsequent sections). 

A simplified stratigraphic column for the northern Anadarko 

Basin is shown in figure 4. This study adopts the commonly 

used stratigraphic nomenclature established for the northern part 

of the basin, as more well control was available for the northern parts of the composite seismic line. The Anadarko Basin 

contains too many stratigraphic units to incorporate all into a 

regional seismic interpretation and structural model. Therefore, 

stratigraphic picks on the seismic lines were made for key units 

based in part on available well control along the seismic lines. 

The units highlighted in red (fig. 4) were used in the seismic 

interpretation and structural model. For a more complete 

stratigraphic section for the Anadarko Basin, see Higley and 

Gaswirth (2014). Table 1 provides a list of codes for the formation tops identified in the selected wells; the names of some 

of these tops appear in the following stratigraphic summary. 

The subsequent paragraphs describe key lithologic features of 

only the units that are picked on the composite seismic line and 

incorporated into the structural restoration.

Cambrian and Ordovician Rocks

The oldest unit identified in the seismic interpretation is 

the Cambrian-Ordovician Arbuckle Group (fig. 4). It consists 

of shallow-water marine carbonate mudstones and secondary 

dolomites that reach thicknesses of ≈8,000 ft. (Ball and others, 1991), and forms a significant petroleum reservoir with 

production primarily from porous dolomite zones (Johnson, 

1989). The unconformably overlying Middle Ordovician 

Simpson Group comprises shallow-water marine limestones, 

sandstones, and shales (Schramm, 1964). The next overlying Viola Group is a cherty, dolomitic limestone (Bornemann 

and Doveton, 1983), and the uppermost Ordovician unit is 

the Sylvan Shale, which is fissile dark green to brown silty 

marine shale that contains thin intervals of dolomitic sandstone (Huffman, 1953).

Silurian, Devonian, and Mississippian Rocks

Silurian and Lower Devonian rocks of the Anadarko 

Basin belong to the Hunton Group (fig. 4), which consists of 

a sequence of limestones and dolomites (Kopaska-Merkel and 

Friedman, 1989). A significant regional unconformity related 

to a major sea level low-stand separates the Hunton Group 

from the overlying Woodford Shale (Kuykendall and Fritz, 

1993). The Woodford Shale, which includes the basal informal 

Misener sand, is one of the Anadarko Basin’s major source 

rocks. The formation is a dark gray to black organic-rich 

siliceous shale (Kuykendall and Fritz, 1993). Overlying the 

Woodford Shale are Mississippian carbonates of the Kinderhookian, Osagean, and Meramecian Series. The informal 

Meramec lime is a thick unit of argillaceous to silty micritic 

limestone, with higher energy deposits increasing toward the 

north (Bokman, 1954; Harris, 1975). The Meramec lime is 

represented in the seismic interpretation by the Goddard Shale 

(table 1), which is a time equivalent unit (Higley and Gaswirth, 2014) from the southern Anadarko Basin. The youngest 

Mississippian unit identified in the seismic interpretation is 

the informal Britt sand (fig. 4), which is part of the Chesterian 

Series. The Britt sand is predominantly a quartzarenitic to subarkosic sandstone (Andrews and others, 2001). Unconformities within and at the top of the Chesterian Series are products 

of the onset of the Wichita orogeny.
10 Tectonic and Structural Evolution of the Anadarko Basin, Structural Interpretation and Modeling of a Seismic Line

Pennsylvanian Rocks

The oldest Pennsylvanian unit identified in the seismic 

interpretation is the Morrow Formation (fig. 4). It consists 

mostly of shale deposited during a marine transgression; 

interbedded sandstones were deposited during brief regressions (Ball and others, 1991). Following the climax of the 

Wichita orogeny during Atokan time, rocks of the Cherokee 

Group, including the Taft Sandstone, were deposited. The 

Taft Sandstone is also known informally as the Red Fork sand 

(Higley and Gaswirth, 2014; table 1), which comprises mainly 

shale interbedded with thin limestone and calcareous siltstone 

(Mannhard and Busch, 1974). The overlying Marmaton Group 

consists of limestones interbedded with shales and a coarsening-upward sequence of mudstones and sandstones (Rascoe, 

1962; Hentz, 1994). Missourian rocks of the Kansas City 

Group (including the Checkerboard and Hogshooter Limestones) and the Lansing Group (including the Cottage Grove 

Sandstone) are predominantly dark gray shales interbedded 

with a few sandstones and thin, dense limestones (Rascoe, 

1962). The Douglas Group at the base of the Virgilian Series, 

which includes the informal Tonkawa sand (Higley and Gaswirth, 2014; table 1), is mostly red and gray sandy shales and 

thin, dense limestones (Rascoe, 1962). The Topeka Limestone 

is a massive shelfal carbonate that grades into a sequence of 

silty shales and thin limestones and sandstones in deeper parts 

of the Anadarko Basin (Rascoe, 1962). The Wabaunsee Group, 

which consists of shelfal limestones and calcareous shales in 

the deep basin (Rascoe, 1962), occupies the top of the Pennsylvanian section.

Permian Rocks

Rocks of the Wolfcampian Series (fig. 4) are primarily shallow marine limestones and shales. The basal Admire 

Group and overlying Council Grove Group are made up of 

massive marine limestones and shales; in the northern part 

of the basin, there are nonmarine red silty shales and siltstones (Rascoe and Adler, 1983). The Chase Group is mostly 

interbedded limestones and shales; in western parts of the 

basin, the group grades abruptly into red silty sandstones and 

shales (Rascoe, 1962). The only Leonardian unit identified 

in the seismic interpretation is the Wellington Formation, 

which consists of interbedded alluvial and deltaic sandstones 

and shales (Johnson and others, 1988). The youngest unit 

identified in the seismic interpretation is the Guadalupian 

Whitehorse Group (fig. 4), which includes the Rush Springs 

Formation (Higley and Gaswirth, 2014; table 1). The Whitehorse Group consists of red sandstones and thin anhydrites 

(Johnson and others, 1988).

Table 1. Lithology codes and corresponding stratigraphic units for formation tops shown in figures 15, 16, and 17.

Lithology code Corresponding stratigraphic unit (see fig. 4)

RSPG Rush Springs Formation (upper part of the Whitehorse Group) (Higley and Gaswirth, 2014)

WLNG Wellington Formation

CHSE Chase Group

CCGV Council Grove Group

ADMR Admire Group

WBNS Wabaunsee Group

TOPK Topeka Limestone

TNKW Tonkawa sand (upper part of the Douglas Group) (Higley and Gaswirth, 2014)

CGGV Cottage Grove Sandstone (lower part of the Lansing Group)

HGSR Hogshooter Limestone

CCKB Checkerboard Limestone

MRMN Marmaton Group

RDFK Taft Sandstone (also called the Red Fork sand) (Higley and Gaswirth, 2014)

MRRW Morrow Formation

BRTT Britt sand

GDRD Goddard Shale (same age as the Meramec lime) (Higley and Gaswirth, 2014)

WDFD Woodford Shale

HNTN Hunton Group

SLVN Sylvan Shale

VIOL Viola Group
2D Reflection Seismic Datasets Available to the U.S. Geological Survey 11

2D Reflection Seismic Datasets 

Available to the U.S. Geological Survey

As part of the 2010 Anadarko Basin petroleum resource 

assessment, the USGS licensed five seismic lines from Seismic Exchange, Inc., that total approximately 137 line miles 

(220 km; fig. 2). The lines were acquired by four different 

companies between 1978 and 1985, using widely varying data 

acquisition (recording) parameters. The line names, locations 

where recorded (county names), year purchased by the USGS, 

and line lengths are given in table 2. Relevant recording 

parameters for each of the lines are given in table 3. Note 

that because of the proprietary nature of the seismic data, the 

lines shown in figure 2 are given general names (Line A, Line 

B, Line C, Line D, and Line E), rather than the original line 

names provided by Seismic Exchange, Inc.

The data were reprocessed by the USGS between 2008 

and 2010 using Halliburton’s ProMAX seismic data processing software. Lines B, D, and E were completely reprocessed 

by the USGS, beginning with the field data, through the point 

of migrated depth. Line A was reprocessed beginning with the 

field data through detailed velocity analysis, and the resulting 

velocity model was used to convert the industry-migrated data 

Table 2. Seismic line names, counties and states where seismic lines were recorded, the year the USGS purchased 

licenses for the data, and the lengths of each line. Seismic data are owned or controlled by Seismic Exchange, Inc.; 

interpretation is that of the U.S. Geological Survey.

Line name Counties and States where recorded Year licensed Line lengths in miles/kilometers

Line A Beckham & Roger Mills, OK; Wheeler, TX 2009 17.0/27.4

Line B Woodward, Ellis, & Dewey, OK 2007 31.2/50.2

Line C Kiowa & Washita, OK 2009 16.8/27.0

Line D Washita & Custer, OK 2007 34.7/55.8

Line E Blaine, Caddo, Major, & Washita, OK 2007 36.9/59.3

Table 3. Data acquisition parameters for the five seismic lines used in this study. Seismic data are owned or controlled by Seismic 

Exchange, Inc.; interpretation is that of the U.S. Geological Survey.

Recording

parameter

Line name and associated parameter values

Line A Line B Line C Line D Line E

Year recorded 1978 1985 1980 1980 1982

Recorded by Seismic

Resources, Inc.

Western Seismic

Resources, Inc.

Milestone Digicon

Energy source type Dynamite Vibroseis Dynamite Dynamite Dynamite

Source depth 150 feet

45.7 meters

n/a 150 feet

45.7 meters

100–260 feet

30.5–79.2 meters

160 feet

47.8 meters

Charge size 25-40 pounds

11.4-18.2 kilograms

n/a 50 pounds

22.7 kilograms

5-40 pounds

2.3–18.2 kilograms

10–40 pounds

4.5-18.2 kilograms

Sweep frequencies/

length

n/a 10-85 hertz/

10 seconds

n/a n/a n/a

Source pattern Single hole 3 or 4 Vibrators Single hole Single hole Single hole

Source interval(s) 440 feet

134.1 meters

165 feet

50.3 meters

440 feet

134.1 meters

240 feet

73.1 meters

440 feet

134.1 meters

Number of receiver 

channels

96 96 96 120 96

Receiver spread 

configuration

Symmetrical

split spread

Symmetrical

split spread

Symmetrical

split spread

End-on Symmetrical

split spread

Near/far source-receiver 

offset

220/10,560 feet

67/3,219 meters

660/8415 feet

201.2/2,565 meters

165/5170 feet

50.3/1,578 meters

120/14,440 feet

36.5/4,386 meters

110/10,340 feet

33.5/3,152 meters

Receiver group interval 220 feet

67 meters

165 feet

50.3 meters

110 feet

33.5 meters

120 feet

36.5 meters

220 feet

67 meters

Nominal common depth 

point fold

24 48 12 30 24
12 Tectonic and Structural Evolution of the Anadarko Basin, Structural Interpretation and Modeling of a Seismic Line

Figure 8. Root mean square velocity model used to migrate and convert seismic Line D. Velocities were determined using an 

automated velocity picking algorithm, and subsequently smoothed using a 201 common depth point horizontal, and 250-millisecond 

vertical, smoothing operator. A color bar illustrating the velocity scale is also shown. Seismic data are owned or controlled by Seismic 

Exchange, Inc.; interpretation is that of the U.S. Geological Survey.

to depth. Line C was not reprocessed, but the stacking velocities were analyzed, edited, smoothed, and used to convert the 

industry-migrated data to depth. During reprocessing, the following generalized sequence of processing steps was used.

Before stacking: amplitude scaling, single or multiple 

window spiking deconvolution, datum statics using smoothed 

surface elevations, velocity analysis [root-mean-square (RMS) 

velocities determined directly from the seismic data], surfaceconsistent residual statics, a second velocity analysis, second 

pass of residual statics if necessary, normal moveout correction using the stacking velocities, and common depth point 

(CDP) stacking.

After stacking: shift both the seismic data and the 

velocity fields to a horizontal datum, automatic gain control 

scaling, bandpass filter, post-stack time migration using a 

smoothed version of the stacking velocity field, and depth 

conversion using the same smoothed velocity field. With the 

exception of Line C as explained below, the stacking velocities were determined directly from the seismic data using 

conventional velocity analysis applied at points along the 

lines where there was good signal-to-noise ratio. Two passes 

of velocity analyses were performed, one before and one 

after residual statics analysis. Velocity functions were picked 

manually from the interactive onscreen analysis display, 

except for the second pass on Line D, where an automated 

velocity picking routine was used. This method used the 

manually picked velocities from the first pass as a guide function. Velocity functions were picked at a 25-CDP interval, and 

were constrained to -5 percent to +10 percent about the guide 

function at the surface, and ±10% about the guide function 

at 2,500 milliseconds (ms). This method was successful in 

producing a detailed velocity field for stacking. However, 

the stacked image produced using the automated velocity 

picks was only minimally improved over that of the manually 

picked velocity model. This velocity model was smoothed 

(201 CDPs horizontal; 250 ms vertical smoothing operator), 

and was used for migration and depth conversion (fig. 8). For 

Line C, stacking velocities were provided with the industrymigrated data. These velocities were analyzed and edited to 

ensure that the interval velocities were geologically reasonable, and then a smoothed version of those velocities was 

used for migration and depth conversion.

Ch11_Figure 8

8,000 9,000

Velocity

10,000 11,000 12,000 13,000 14,000

Time (milliseconds) 200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

2,200

2,400

2,600

2,800

3,000

3,200

3,400

3,600

3,800

5,000

4,200

4,400

4,000

4,600

4,800
2D Reflection Seismic Data Interpretation 13

2D Reflection Seismic Data 

Interpretation

General Description of the Seismic Lines

Although the seismic lines were all acquired almost 

30 years ago, key stratigraphic and structural features of the 

Anadarko Basin can be seen in the images. Figures 9–13 show 

uninterpreted depth sections for Line A, Line B, Line C, Line 

D, and Line E, respectively. All lines are shown at the same 

scale, with the vertical (depth) and horizontal (miles along the 

surface) axes equal. All lines are also shown with identical 

red to black color bars, where red colors represent amplitude 

troughs and black colors represent amplitude peaks. A brief 

qualitative description is given in the following paragraphs for 

each of the seismic lines.

Line A (fig. 9) crosses the southern boundary of the 

Anadarko Basin onto the Wichita uplift (fig. 3). Noncontinuous reflectors with apparent northeast dips can be seen 

at shallow depths along the southwestern portion of the line. 

The lack of continuous reflectors at the line’s southwestern 

most edge likely shows the presence of Precambrian basement 

rocks of the Wichita uplift in the hanging-wall of the Mountain 

View fault system. The subparallel reflectors that reach depths 

of ≈30,000 ft and extend across the northeastern two-thirds 

of the line are caused by Cambrian-Permian rocks of the 

Anadarko Basin. The axis of the basin lies between about 

three to five miles from the southwest edge of the seismic line, 

depending upon the stratigraphic level.

Line B (fig. 10) shows subparallel, largely continuous 

reflectors with apparent gentle southwest dips. It is possible 

to trace many of the shallow reflectors (above 15,000 ft at the 

southwest edge of the line) along the entire 31.2-mile length of 

the seismic line. The southwestern expansion of the Cambrian-Permian stratigraphic section can be clearly seen. For 

example, the prominent reflectors at depths of approximately 

2,500 ft and 7,500 ft at the northeastern edge of the line reach 

depths of approximately 3,500 ft and 12,000 ft at the southwestern edge of the line.

Line C (fig. 11) is similar in many ways to Line A, in that 

it spans the boundary between the Anadarko Basin and the 

Wichita uplift. Although the basin-bounding thrust faults are 

not directly imaged, it is possible to infer the presence of at 

least two faults. The Mountain View fault system likely exists 

at the southwest edge of the line, and is responsible for elevating basement rock characterized by non-continuous reflectors. 

The obvious monoclinal flexure in the middle of the line may 

be caused by the Cordell fault (fig. 3). Although the southwestern third of the line is poorly imaged, the fold geometry is 

similar to that described for many Laramide basement-cored 

uplifts (Erslev, 1991; Brandenburg and others, 2012). Shallow 

Figure 9. Uninterpreted seismic Line A. Location of line is shown in figure 2. Horizontal and vertical scales are equal. 

Black colors are amplitude peaks; red colors are amplitude troughs. Seismic data are owned or controlled by Seismic 

Exchange, Inc.

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

Depth, in feet below sea level

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17

SOUTHWEST Distance, in miles NORTHEAST

Line A

CH11_Figure 9
14 Tectonic and Structural Evolution of the Anadarko Basin, Structural Interpretation and Modeling of a Seismic Line

Figure 10. Uninterpreted seismic Line B. Location of line is shown in figure 2. Horizontal and vertical scales are equal. 

Dark black colors are amplitude peaks; dark red colors are amplitude troughs. Seismic data are owned or controlled by 

Seismic Exchange, Inc. Figure 10 is oversized. Click on the thumbnail to view the enlarged version.

Figure 11. Uninterpreted seismic Line C. Location of line is shown in figure 2. Horizontal and vertical scales are 

equal. Dark black colors are amplitude peaks; dark red colors are amplitude troughs. Seismic data are owned or 

controlled by Seismic Exchange, Inc.

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

Depth, in feet below sea level

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16

SOUTHWEST Distance, in miles NORTHEAST

Line C

Ch11_Figure 11

0

5,000

10,000

15,000

20,000

25,000

30,000

0

5,000

10,000

15,000

20,000

25,000

30,000

Depth, in feet below sea level

Depth, in feet below sea level

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31

SOUTHWEST NORTHEAST

Line B

Distance, in miles

Ch11_Figure 10
2D Reflection Seismic Data Interpretation 15

Figure 12. Uninterpreted seismic Line D. Location of line is shown in figure 2. Horizontal and vertical scales are equal. 

Dark black colors are amplitude peaks; dark red colors are amplitude troughs. Seismic data are owned or controlled by 

Seismic Exchange, Inc. Figure 12 is oversized. Click on the thumbnail to view the enlarged version.

Figure 13. Uninterpreted seismic Line E. Location of line is shown in figure 2. Horizontal and vertical scales are equal. Dark 

black colors are amplitude peaks; dark red colors are amplitude troughs. Seismic data are owned or controlled by Seismic 

Exchange, Inc. Figure 13 is oversized. Click on the thumbnail to view the enlarged version.

0

5,000

10,000

15,000

20,000

25,000

30,000

Depth, in feet below sea level

SOUTH-SOUTHWEST Distance, in miles NORTH-NORTHEAST

Line D

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34

Ch11_Figure 12

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

Depth, in feet below sea level

SOUTHWEST Distance, in miles NORTHEAST

Line E

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36

Ch11_Figure 13
16 Tectonic and Structural Evolution of the Anadarko Basin, Structural Interpretation and Modeling of a Seismic Line

reflectors that have apparent dips toward the northeast along 

the southwestern third of the line are generally poorly imaged 

and are difficult to track. However, stratigraphic on-lap and 

angular truncation of reflectors can be seen at depths above 

5,000 ft from six to eight miles from the southwest edge of the 

seismic line. Depending upon the stratigraphic level, the axis 

of the basin is between approximately 8 and 12 miles from the 

southwestern edge of the seismic line. Northeast of the basin’s 

axis, subparallel reflectors made by Cambrian-Permian rocks 

are well-imaged and are easy to track.

Line D (fig. 12) is characterized by well-imaged, subparallel reflectors with apparent south-southwest dips. As with 

Line B, it is possible to track numerous reflectors across the 

entire 34.7-mile-long seismic line. At the resolution and scale 

of the image, reflectors (those above approximately 27,500 ft 

at the south-southwest edge of the image) do not appear to 

be offset by faults. The south to southwestern expansion of 

the Cambrian-Permian section is well-imaged by this line; 

Figure 14. Map showing the location of wells used to 

aid in the interpretation of the composite seismic line. 

Oklahoma counties are shown in gray. The segments of 

the composite seismic line are shown in blue. American 

Petroleum Institute well numbers are given.

WOODWARD MAJOR

BLAINE

DEWEY

CUSTER

CANADIAN

WASHITA CADDO

KIOWA

Line C

Line D

Line E

35011228950000

35011218160000

35011229620000 35011228930000

35011231500000 35011230850000

35039219520000

35011228770000

35039202600000

35015208600000

35149201530000 35149200500000 35149202320000

35015208600000

35149201410000

35039203480000

35039204350000

35039220530000

36.25°

36.25°

36.00°

35.75°

35.50°

35.25°

99.00° 98.75° 98.50° 98.25°

Ch11_Figure 14

Dry Hole

Gas

EXPLANATION

0 10 20MILES

0 10 20 KILOMETERS

reflectors at depths of approximately 12,500 ft at the northnortheast edge of the line reach depths of approximately 

27,500 ft at the south-southwest edge of the line.

Line E (fig. 13) contains a well-imaged section down to 

approximately 15,000 ft depth at the southwest edge of the 

line and 10,000 ft at the northeast edge. As with previously 

described lines, it is possible to trace numerous individual 

reflectors across the entire 36.9-mile length of the seismic 

image without encountering any offsets because of faulting. 

Reflectors have gentle apparent dips toward the southwest and 

show the thickening of the Cambrian-Permian section toward 

the basin’s axis. Layered intrusives possibly related to the 

southern Oklahoma aulacogen may be visible between depths 

of 30,000 and 35,000 ft along the southwestern half of the 

seismic line.

Because of their proximity to each other, Lines C, D, and 

E were selected for a more detailed seismic interpretation. 

These three lines are henceforth collectively referred to as the 

Anadarko “composite seismic line.” Interpretation of the composite seismic line was guided by formation tops information 

from 18 selected wells (fig. 14) that were projected orthogonally onto the line of section from distances of up to 7.5 miles 

off the composite seismic line. These wells are a subset of 

more than 220 wells across the Anadarko Basin Province that 

contain edited formation tops. A detailed discussion of the 

numerous data sources and the methodology behind picking 

these formation tops is given in Higley and others (2014) and 

references therein.

Seismic Interpretation of the Anadarko 

Composite Seismic Line

Interpretations for Line C, Line D, and Line E are shown 

in figures 15, 16, and 17, respectively. The lines are all shown 

at the same scale, and the vertical (depth) and horizontal 

(distance along the surface) axes are identical. The projected 

location of the wells and relevant formation tops (table 1) are 

also shown.

Interpretation of Lines D and E is facilitated by the ease 

with which numerous individual reflectors can be traced across 

the entire length of the lines. No faults were interpreted to 

be present on these two lines; however, if present, they were 

either not imaged by the seismic data or are of a subseismic 

scale. Formation tops from the 17 wells projected onto these 

two seismic lines permits identification of 20 horizons; the 

only two horizons for which well control is not available are 

the Simpson and Arbuckle Groups. On Line E (fig. 17), the top 

of the Simpson Group was placed at the next prominent reflector below the top of the Viola Group in well 35011230850000, 

which gives an apparent thickness for the Viola Group at that 

location of ≈460 ft. The top of the Arbuckle Group was placed 

at the next prominent reflector below the top of the Simpson 

Group at the same location, which yields an apparent thickness for the Simpson Group of ≈750 ft. Although these two 
Structural Restoration of the Anadarko Composite Seismic Line 17

horizons probably do not represent the actual tops of the Simpson and Arbuckle Groups, they are likely to be close. Evidence 

in support of this comes from the combined thickness of the 

Viola and Simpson Groups at the southwestern edge of the 

interpretation on Line C. Johnson and others (1988) suggested 

that the maximum combined thickness of the two groups in 

southern Oklahoma is in excess of ≈2,500 ft; the maximum 

thickness of the two groups at the southwestern edge of the 

interpretation is ≈2,800 ft.

Interpretation was only done for the northeastern half of 

Line C (fig. 15), because of the poor quality of the seismic 

data combined with a lack of well control and the complex 

geometries of the frontal portion of the Wichita uplift in the 

southwestern part. McConnell (1989) provided examples of 

complex compressional geometries at the northern edge of 

the Wichita uplift. Although locations for thrust faults of the 

Mountain View fault system and the Cordell fault (fig. 3) 

could have been hypothesized, available data do not permit 

determination of the hanging-wall and footwall cutoff relations, and thus constrain either the magnitude or timing of 

displacement along the faults.

Structural Restoration of the Anadarko 

Composite Seismic Line

A structural restoration of the composite seismic line was 

built using Midland Valley’s 2DMove software. The restoration shown in figure 18 details 22 stages corresponding to each 

of the interpreted stratigraphic units (fig. 4) described in the 

preceding sections. As with all other figures that show the seismic lines and interpretations, the horizontal and vertical scales 

in each panel of figure 18 are identical.

The restoration was pinned at the northeast edge of the 

composite seismic line, and all horizons were restored to a 

horizontal surface at an elevation of the present sea level. 

The primary restoration algorithm used within 2DMove was 

“Flexural Slip Unfolding.” The flexural slip algorithm was 

used for the following reasons: (1) it maintains the line length 

of the template horizon (the template horizon is the horizon 

that is being restored to the horizontal surface) in the direction 

of unfolding; (2) it maintains the orthogonal bed thickness 

between the template horizon and all other passive horizons 

Figure 15. Interpreted seismic Line C. Location of line is shown in figure 2. Horizontal and vertical scales are equal. Dark 

black colors are amplitude peaks; dark red colors are amplitude troughs. Well symbols are the same as those used in fig. 14. 

American Petroleum Institute well numbers are indicated. Lithology codes for well tops are given in table 1. Seismic data are 

owned or controlled by Seismic Exchange, Inc.; interpretation is that of the U.S. Geological Survey.

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

Depth, in feet below sea level

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16

SOUTHWEST Distance, in miles NORTHEAST

Line C

GDRD

RDFK

MRRW

BRTT

RSPG

35149212390000

Ch11_Figure 15

Arbuckle Group

Simpson Group

Hunton Group

Woodford Shale

Meramec lime

Viola Group

Sylvan Shale

Hogshooter Limestone

Lansing Group

Douglas Group

Topeka Limestone

Wabaunsee Group

Admire Group

Council Grove Group

Chase Group

Wellington Formation

Whitehorse Group

Britt sand

Morrow Formation

Taft Sandstone

Marmaton Group

Checkerboard Limestone

EXPLANATION

Gas Well

Neutron

 Porosity Log
18 Tectonic and Structural Evolution of the Anadarko Basin, Structural Interpretation and Modeling of a Seismic Line

Figure 16. Interpreted seismic Line D. Location of line is shown in figure 2. Horizontal and 

vertical scales are equal. Dark black colors are amplitude peaks; dark red colors are amplitude 

troughs. Well symbols are the same as those used in fig. 14. American Petroleum Institute well 

numbers are indicated. Lithology codes for well tops are given in table 1. Seismic data are 

owned or controlled by Seismic Exchange, Inc.; interpretation is that of the U.S. Geological 

Survey. Figure 16 is oversized. Click on the thumbnail to view the enlarged version.

Figure 17. Interpreted seismic Line E. Location of line is shown in figure 2. Horizontal and 

vertical scales are equal. Dark black colors are amplitude peaks; dark red colors are amplitude 

troughs. Well symbols are the same as those used in figure 14. American Petroleum Institute well 

numbers are indicated. Lithology codes for well tops are given in table 1. Seismic data are owned 

or controlled by Seismic Exchange, Inc.; interpretation is that of the U.S. Geological Survey. Figure 

17 is oversized. Click on the thumbnail to view the enlarged version.

Figure 18. Structural restoration showing individual restoration stages. Depth in each stage 

is shown in thousands of feet below sea level; horizontal distance is given in miles from the 

southwestern edge of seismic Line C (no vertical exaggeration). Seismic data are owned or 

controlled by Seismic Exchange, Inc.; interpretation is that of the U.S. Geological Survey. Figure 

18 is oversized. Click on the thumbnail to view the enlarged version.

0

5,000

10,000

15,000

20,000

25,000

30,000

Depth, in feet below sea level

Distance, in miles

Line D

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34

SOUTH-SOUTHWEST NORTH-NORTHEAST

CGGV

TNKW

MRMN

RDFK

CHSE

CCKB

RSPG

MRRW

HGSR

BRTT

35039219520000

CGGV

TNKW

MRMN

TOPK

RDFK

CHSE

CCKB

RSPG

MRRW

HGSR

WLNG

BRTT

35039220530000

CGGV

TNKW

MRMN

TOPK

RDFK

CHSE

CCKB

RSPG

MRRW

HGSR

35039204350000

CGGV

RDFK

CCKB

RSPG

MRRW

HGSR

BRTT

35039203480000

WBNS

CGGV

TNKW

RDFK

CHSE

CCKB

RSPG

MRRW

HGSR

BRTT

35149202320000

GDRD

WBNS

CGGV

TNKW

TOPK

RDFK

CHSE

CCKB

ADMR

RSPG

MRRW

HGSR

CCGV

WLNG

35149201530000

GDRD

CHSE

MRMN

RDFK

CCKB

ADMR

MRRW

HGSR

CCGV

WBNS

CGGV

TNKW

TOPK

35149200500000

WBNS

CGGV

TNKW

MRMN

TOPK

RDFK

CHSE

CCKB

ADMR

HGSR

CCGV

WLNG

35149201410000

WBNS

CGGV

TNKW

TOPK

RDFK

CHSE

CCKB

ADMR

RSPG

MRRW

HGSR

CCGV

35015208600000

MRRW

HGSR

35039202600000

CGGV

TNKW

CCKB

RDFK

USGS DDS-69-EE

Chapter 11 Figure 16

Arbuckle Group

Simpson Group

Hunton Group

Woodford Shale

Meramec lime

Viola Group

Sylvan Shale

Hogshooter Limestone

Lansing Group

Douglas Group

Topeka Limestone

Wabaunsee Group

Admire Group

Council Grove Group

Chase Group

Wellington Formation

Whitehorse Group

Britt sand

Morrow Formation

Taft Sandstone

Marmaton Group

Checkerboard Limestone

EXPLANATION

Gas Well

Neutron

 Porosity Log

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

Depth, in feet below sea level

SOUTHWEST Distance, in miles NORTHEAST

Line E

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36

GDRD

WBNS

CGGV

TNKW

MRMN

TOPK

RDFK

CHSE

CCKB

MRRW

WDFD

CCGV

WLNG

BRTT

35011228950000

GDRD

WBNS

CGGV

TNKW

MRMN

TOPK

RDFK

CHSE

CCKB

MRRW

CCGV

WLNG

BRTT

35011218160000

RDFK

MRRW

HGSR

BRTT

35011228930000

CGGV

TNKW

MRMN

TOPK

RDFK

CHSE

CCKB

MRRW

CCGV

WLNG

BRTT

35011229620000

HNTN

GDRD

VIOL

SLVN

CGGV

MRMN

RDFK

CCKB

MRRW

WDFD

HGSR

BRTT

35011230850000

CGGV

TNKW

MRMN

TOPK

RDFK

CHSE

CCKB

MRRW

WLNG

BRTT

35011231500000

RDFK

MRRW

BRTT

35011228770000

CGGV

TNKW

CCKB

HGSR

RDFK

MRRW

35039202600000

Arbuckle Group

Simpson Group

Hunton Group

Woodford Shale

Meramec lime

Viola Group

Sylvan Shale

Hogshooter Limestone

Lansing Group

Douglas Group

Topeka Limestone

Wabaunsee Group

Admire Group

Council Grove Group

Chase Group

Wellington Formation

Whitehorse Group

Britt sand

Morrow Formation

Taft Sandstone

Marmaton Group

Checkerboard Limestone

EXPLANATION

Gas Well

Neutron

 Porosity Log

Gas Well

Council Grove Group Admire Group Wabaunsee Group Topeka Limestone Douglas Group Lansing Group Hogshooter Limestone Checkerboard Limestone Marmaton Group Taft Sandstone Morrow Formation Britt sand Meramec lime Woodford Shale Hunton Group Sylvan Shale Viola Group Simpson Group

Distance, in miles

0

5

10

15

20

25

Depth

0 5 10 15 20 25 30 35 40 45 50 55 60 65 70 75 80 85

SW NE F. COUNCIL GROVE GROUP

Admire Group Wabaunsee Group Topeka Limestone Douglas Group Lansing Group Hogshooter Limestone Checkerboard Limestone Marmaton Group Taft Sandstone Morrow Formation Britt sand Meramec lime Woodford Shale Hunton Group Sylvan Shale Viola Group Simpson Group Council Chase Group Grove Group

Distance, in miles

0

5

10

15

20

25

Depth

0 5 10 15 20 25 30 35 40 45 50 55 60 65 70 75 80 85

SW NE E. CHASE GROUP

Wellington Formation Chase Group Council Grove Group Admire Group Wabaunsee Group Topeka Limestone Douglas Group Lansing Group Hogshooter Limestone Checkerboard Limestone Marmaton Group Taft Sandstone Morrow Formation Britt sand Meramec lime Woodford Shale Hunton Group Sylvan Shale Viola Group Simpson Group

Distance, in miles

0

5

10

15

20

25

30

Depth

0 5 10 15 20 25 30 35 40 45 50 55 60 65 70 75 80 85

SW D. NE WELLINGTON FORMATION

Distance, in miles

0

5

10

15

20

25

30

Depth

0 5 10 15 20 25 30 35 40 45 50 55 60 65 70 75 80 85

SW NE C. WHITEHORSE GROUP

Distance, in miles

0

5

10

15

20

25

30

Depth

0 5 10 15 20 25 30 35 40 45 50 55 60 65 70 75 80 85

SW B. PRESENT NE

Distance, in miles

0

5

10

15

20

25

30

35

40

45

Depth, in 1,000’s feet below sea level

0 5 10 15 20 25 30 35 40 45 50 55 60 65 70 75 80 85 SW NE

Line C Line D Line E A. SEISMIC INTERPRETATION

Whitehorse Group Wellington Formation Chase Group Council Grove Group Admire Group Wabaunsee Group Topeka Limestone Douglas Group Lansing Group Hogshooter Limestone Checkerboard Limestone Marmaton Group Taft Sandstone Morrow Formation Britt sand Meramec lime Woodford Shale Hunton Group Sylvan Shale Viola Group Simpson Group

Whitehorse Group Wellington Formation Chase Group Council Grove Group Admire Group Wabaunsee Group Topeka Limestone Douglas Group Lansing Group Hogshooter Limestone Checkerboard Limestone Marmaton Group Taft Sandstone Morrow Formation Britt sand Meramec lime Woodford Shale Hunton Group Sylvan Shale Viola Group Simpson Group

EXPLANATION

EXPLANATION

EXPLANATION

EXPLANATION

EXPLANATION

Checkerboard Limestone Marmaton Group Taft Sandstone Morrow Formation Britt sand Meramec lime Woodford Shale Hunton Group Sylvan Shale Viola Group Simpson Group Arbuckle Group

EXPLANATION Whitehorse Group Wellington Formation Chase Group Council Grove Group Admire Group Wabaunsee Group Topeka Limestone Douglas Group Lansing Group Hogshooter Limestone

USGS DDS-69-EE

Chapter 11 Figure 18 a-f
Structural Restoration of the Anadarko Composite Seismic Line 19

Figure 18. Structural restoration showing individual restoration stages. Depth in each stage 

is shown in thousands of feet below sea level; horizontal distance is given in miles from the 

southwestern edge of seismic Line C (no vertical exaggeration). Seismic data are owned or 

controlled by Seismic Exchange, Inc.; interpretation is that of the U.S. Geological Survey. Figure 

18 is oversized. Click on the thumbnail to view the enlarged version.—Continued

Checkerboard Limestone Marmaton Group Taft Sandstone Morrow Formation Britt sand Meramec lime Woodford Shale Hunton Group Sylvan Shale Viola Group Simpson Group

Distance, in miles

0

5

10

15

20

Depth

0 5 10 15 20 25 30 35 40 45 50 55 60 65 70 75 80 85

SW M. CHECKERBOARD LIMESTONE NE

Hogshooter Limestone Checkerboard Limestone Marmaton Group Taft Sandstone Morrow Formation Britt sand Meramec lime Woodford Shale Hunton Group Sylvan Shale Viola Group Simpson Group

Distance, in miles

0

5

10

15

20

Depth

0 5 10 15 20 25 30 35 40 45 50 55 60 65 70 75 80 85

SW L. HOGSHOOTER LIMESTONE NE

Simpson Group

Distance, in miles

0

5

Depth

0 5 10 15 20 25 30 35 40 45 50 55 60 65 70 75 80 85

SW W. SIMPSON GROUP NE

EXPLANATION

EXPLANATION

EXPLANATION

EXPLANATION

EXPLANATION

EXPLANATION

EXPLANATION

EXPLANATION

EXPLANATION

EXPLANATION

Viola Group Simpson Group

Distance, in miles

0

5

Depth

0 5 10 15 20 25 30 35 40 45 50 55 60 65 70 75 80 85

SW V. VIOLA GROUP NE

Sylvan Shale Viola Group Simpson Group

Distance, in miles

0

5

Depth

0 5 10 15 20 25 30 35 40 45 50 55 60 65 70 75 80 85

SW U. SYLVAN SHALE NE

Hunton Group Sylvan Shale Viola Group Simpson Group

Distance, in miles

0

Depth

5

0 5 10 15 20 25 30 35 40 45 50 55 60 65 70 75 80 85

SW T. HUNTON GROUP NE

Woodford Shale Hunton Group Sylvan Shale Viola Group Simpson Group

Distance, in miles

0

5

Depth

0 5 10 15 20 25 30 35 40 45 50 55 60 65 70 75 80 85

SW S. WOODFORD SHALE NE

Meramec lime Woodford Shale Hunton Group Sylvan Shale Viola Group Simpson Group

Distance, in miles

0

5

10

Depth

0 5 10 15 20 25 30 35 40 45 50 55 60 65 70 75 80 85

SW R. MERAMEC LIME NE

Britt sand Meramec lime Woodford Shale Hunton Group Sylvan Shale Viola Group Simpson Group

Distance, in miles

0

5

10

15

Depth

0 5 10 15 20 25 30 35 40 45 50 55 60 65 70 75 80 85

SW Q. NE BRITT SAND

Morrow Formation Britt sand Meramec lime Woodford Shale Hunton Group Sylvan Shale Viola Group Simpson Group

Distance, in miles

0

5

10

15

Depth

0 5 10 15 20 25 30 35 40 45 50 55 60 65 70 75 80 85

SW P. MORROW FORMATION NE

Taft Sandstone Morrow Formation Britt sand Meramec lime Woodford Shale Hunton Group Sylvan Shale Viola Group Simpson Group

Distance, in miles

0

5

10

15

20

Depth

0 5 10 15 20 25 30 35 40 45 50 55 60 65 70 75 80 85

SW O. TAFT SANDSTONE NE

Marmaton Group Taft Sandstone Morrow Formation Britt sand Meramec lime Woodford Shale Hunton Group Sylvan Shale Viola Group Simpson Group

Distance, in miles

0

5

10

15

20

Depth

0 5 10 15 20 25 30 35 40 45 50 55 60 65 70 75 80 85

SW N. MARMATON GROUP NE

Lansing Group Hogshooter Limestone Checkerboard Limestone Marmaton Group Taft Sandstone Morrow Formation Britt sand Meramec lime Woodford Shale Hunton Group Sylvan Shale Viola Group Simpson Group

Distance, in miles

0

5

10

15

20

Depth

0 5 10 15 20 25 30 35 40 45 50 55 60 65 70 75 80 85

SW K. LANSING GROUP NE

Douglas Group Lansing Group Hogshooter Limestone Checkerboard Limestone Marmaton Group Taft Sandstone Morrow Formation Britt sand Meramec lime Woodford Shale Hunton Group Sylvan Shale Viola Group Simpson Group

Distance, in miles

0

5

10

15

20

25

Depth

0 5 10 15 20 25 30 35 40 45 50 55 60 65 70 75 80 85

SW J. DOUGLAS GROUP NE

Topeka Limestone Douglas Group Lansing Group Hogshooter Limestone Checkerboard Limestone Marmaton Group Taft Sandstone Morrow Formation Britt sand Meramec lime Woodford Shale Hunton Group Sylvan Shale Viola Group Simpson Group

Distance, in miles

0

5

10

15

20

25

Depth

0 5 10 15 20 25 30 35 40 45 50 55 60 65 70 75 80 85

SW I. TOPEKA LIMESTONE NE

Wabaunsee Group Topeka Limestone Douglas Group Lansing Group Hogshooter Limestone Checkerboard Limestone Marmaton Group Taft Sandstone Morrow Formation Britt sand Meramec lime Woodford Shale Hunton Group Sylvan Shale Viola Group Simpson Group

Distance, in miles

0

5

10

15

20

25

Depth

0 5 10 15 20 25 30 35 40 45 50 55 60 65 70 75 80 85

SW H. WABAUNSEE GROUP NE

Admire Group Wabaunsee Group Topeka Limestone Douglas Group Lansing Group Hogshooter Limestone Checkerboard Limestone Marmaton Group Taft Sandstone Morrow Formation Britt sand Meramec lime Woodford Shale Hunton Group Sylvan Shale Viola Group Simpson Group

Distance, in miles

0

5

10

15

20

25

Depth

0 5 10 15 20 25 30 35 40 45 50 55 60 65 70 75 80 85

SW G. ADMIRE GROUP NE

EXPLANATION

EXPLANATION

EXPLANATION

EXPLANATION

EXPLANATION

EXPLANATION

EXPLANATION
20 Tectonic and Structural Evolution of the Anadarko Basin, Structural Interpretation and Modeling of a Seismic Line

251

300

350

400

450

500

0.00 0.25 0.50 0.75 1.00 1.25 1.50

Cumulative shortening, in percentage

0.00 0.05 0.10 0.15 0.20 0.25 0.30

Incremental shortening (percentage)

Age, millions of years before the present

Cambrian

(part) Ordovician Silurian Devonian Mississippian

PennsylvanianPermian

Simpson Group

* informal unit

Viola Group

Sylvan Shale

Hunton Group

Woodford Shale

Meramec lime*

Britt sand*

Morrow Formation

Marmaton Group Kansas City Group Lansing Group Virgilian Series

Admire Group

Council Grove Group

Chase Group

Wellington Formation

Whitehorse Group

CH11_Figure 19

Taft Sandstone

Figure 19. Incremental shortening (blue line and 

round markers) and cumulative shortening (red line and 

star markers) is shown for all stages of the structural 

restoration shown in figure 18. Note that the vertical axis is 

time, rather than stratigraphic thickness.
References Cited 21

(passive horizons are the horizons below the template horizon); and (3) it maintains area of the fold and model. Additionally, the flexural slip algorithm is an appropriate choice 

inasmuch as the composite seismic line is roughly orthogonal to the northern flank of the Wichita uplift; the dominant 

stresses responsible for the creation of the Wichita uplift and 

the Anadarko Basin were therefore roughly aligned with the 

northeast-southwest orientation of the composite seismic line.

Each stage of the restoration (fig. 18 B–W) shows the 2D 

geometry that may have existed at the end of deposition of each 

interpreted lithologic unit. The restoration shows that in deeper 

parts of the basin, between approximately 7 and 45 miles from 

the southwest end of the model, subtle structural relief developed along most of the horizons soon after the deposition of 

individual units. For example, a broad fold had developed in 

the Meramec lime about 20 miles from the southwestern end of 

the model (fig. 18 Q and R) by the end of deposition of the Britt 

sand. Some of the shorter wavelength features, such as the narrow fold at about 37 miles from the southwest end of the model 

(fig. 18 Q–W), are likely artifacts of the restoration.

As previously mentioned, the restoration is pinned at 

the northeast edge of the composite seismic line. Relative to 

the margin of the Ouachita orogeny, this location is within 

the stable North American craton. Progressive shortening of 

the restoration can therefore be seen by individual horizons 

lengthening in a southwesterly direction, in reverse chronological order. During the time represented by the deposition of 

the Simpson Group through the Whitehorse Group, the cumulative amount of shortening along the cross-section is 1.45 

percent. Although this is not a large amount of shortening, it 

is important to recognize that it took place entirely within the 

footwalls of the thrust faults that separate the Wichita uplift 

and the Anadarko Basin. McConnell (1989) estimated that 

approximately 6.7 miles of reverse-slip occurred on these 

frontal faults. The magnitude of Ordovician through Permian shortening is shown in figure 19, which displays both the 

incremental (blue line and round markers) and cumulative (red 

line and star markers) shortening percentages through time. 

For example, by the end of deposition of the Viola Group, 

the underlying Simpson Group rocks had been shortened by 

0.10 percent; by the end of deposition of the Britt sand, the 

underlying Meramec lime had been shortened by 0.31 percent. 

The cumulative shortening line reveals that most of the shortening within the basin was during Mississippian and Pennsylvanian time. Since deposition of the Virgilian Series, almost 

no shortening has occurred. Significant tectonic shortening 

during the Permian is absent, so accommodation space for 

Permian rocks was likely created by isostatic subsidence of the 

basin. Calculation of the relatively minor amount of shortening experienced by rocks within the Anadarko Basin to the 

north of the Mountain View fault system supports the interpretation (figs. 15, 16, and 17) that no faults are present along 

the seismic lines, at least none that is visible at the scale of 

the seismic data available for this study. The key point is that 

shortening within the Anadarko Basin was primarily accommodated by minor folding, rather than faulting.

Summary

The structural evolution of the Anadarko Basin Province 

was affected by tectonic processes associated with two complete Wilson cycles that affected the eastern margin of North 

America. The first Wilson cycle, which involved the creation 

and subsequent breakup of the Rodinian supercontinent, 

accounts for the consolidation of basement rock beneath the 

Anadarko Basin Province and the emplacement of the southern Oklahoma aulacogen. The second Wilson cycle, which 

involves the formation and breakup of Pangaea, controlled the 

depositional environments of the Anadarko Basin’s more than 

40,000 feet of Cambrian through Permian sediments and the 

geometry of the basin’s current geometry. The geometry of 

each of the major structural elements was partially inherited 

from prior tectonic and structural events.

The U.S. Geological Survey licensed and analyzed five 

two-dimensional reflection seismic lines within the Anadarko 

Basin. Three of the lines have endpoints that approximately 

overlap; these were combined into a regional composite seismic line that extends almost 90 miles in a northeast-southwest 

direction across the basin. A detailed seismic interpretation, 

based in part on well data, shows relatively undeformed Cambrian through Permian strata that dip toward the southwest 

into the trough of the Anadarko Basin. The Wichita Mountains 

structural high and disrupted strata associated with the Wichita 

fault system can also be seen on the southeastern edge of the 

composite seismic line. A structural restoration shows the 

sequential burial of 22 key stratigraphic horizons. At the scale 

of the available seismic data, there is little visible structural 

deformation within the Anadarko Basin northeast (in the footwall) of the Wichita fault system.

Acknowledgments

We would like to thank Kristen Marra, Sarah Hawkins, 

and Dick Keefer for constructive technical reviews of this 

paper. We also thank Seismic Exchange, Inc., for giving 

permission to publish the seismic data. Members of the USGS 

Anadarko Basin assessment team, in particular Debra Higley 

and Stephanie Gaswirth, provided insightful discussions about 

the Anadarko Basin, and were a valuable aid in our study.

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Chapter 12

Tabular Data and Graphical Images in 

Support of the U.S. Geological Survey 

National Oil and Gas Assessment—

Anadarko Basin Province (5058)

By T.R. Klett and P.A. Le

Chapter 12 of 13

Petroleum Systems and Assessment of Undiscovered Oil and Gas 

in the Anadarko Basin Province, Colorado, Kansas, Oklahoma, and 

Texas—USGS Province 58

Compiled by Debra K. Higley

U.S. Geological Survey Digital Data Series DDS–69–EE

U.S. Department of the Interior

U.S. Geological Survey

Click here to return to

Volume Title Page
U.S. Department of the Interior

SALLY JEWELL, Secretary

U.S. Geological Survey

Suzette M. Kimball, Acting Director

U.S. Geological Survey, Reston, Virginia: 2014

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Suggested citation:

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assessment of undiscovered oil and gas in the Anadarko Basin Province, Colorado, Kansas, Oklahoma, and Texas—

USGS Province 58: U.S. Geological Survey Digital Data Series DDS–69–EE, 20 p., http://dx.doi.org/10.3133/ds69EE.

ISSN 2327-638X (online)
iii

Contents

Introduction.....................................................................................................................................................1

Disclaimers .....................................................................................................................................................1

Data Sources..................................................................................................................................................1

Data Overview................................................................................................................................................1

Data Tables ............................................................................................................................................2

Summary Tables....................................................................................................................................2

Graphs.....................................................................................................................................................2

Numeric Codes...............................................................................................................................................2

Summary Tables.............................................................................................................................................3

Graphical Data................................................................................................................................................3

File List.............................................................................................................................................................4

Tabular Data....................................................................................................................................................4

References Cited..........................................................................................................................................19

Introduction

This chapter describes data used in support of the U.S. 

Geological Survey (USGS) National Oil and Gas Assessment 

(NOGA) project. Digital tabular data used in this chapter of 

the report and archival data that permit the user to perform 

further analyses are available elsewhere with this report and 

online at: http://energy.usgs.gov/OilGas/AssessmentsData/

NationalOilGasAssessment.aspx.

Because of the number and variety of platforms and 

software available, graphical images are provided as Portable 

Document Format files (.pdf files) and tabular data are provided in a raw form as tab-delimited text files (.tab files).

Disclaimers

This publication was prepared by an agency of the U.S. 

Government. Neither the U.S. Government nor any agency 

thereof, nor any of its employees, make any warranty, expressed 

or implied, or assume any legal liability or responsibility for 

the accuracy, completeness, or usefulness of any information, 

apparatus, product, or process disclosed in this report, or represent that its use would not infringe upon privately owned rights. 

Although all data and software published with this report have 

been used by the USGS, no warranty, expressed or implied, is 

made by the USGS as to the accuracy of the data and related 

materials. The act of distribution shall not constitute any such 

warranty, and no responsibility is assumed by the USGS in the 

use of these data or related materials. Any use of trade, firm, 

or product names is for descriptive purposes only and does not 

imply endorsement by the U.S. Government.

Data Sources

Crude oil and natural gas production data (including all volumetric and descriptive data such as cumulative 

production, remaining reserves, known recoverable volumes, 

major producing reservoirs, and petroleum type) and historical data (including field-discovery dates, well-completion 

dates, exploration objectives, and well depths) for fields, 

reservoirs, and wells are derived from commercial databases 

leased and (or) purchased by the USGS, including (1) PI/

Dwights Plus US Production Data (IHS Energy Group, 

2010a), (2) PI/Dwights Plus US Well Data (IHS Energy 

Group, 2010b), and (3) NRG Associates, Inc., “Significant 

Oil and Gas Fields of the United States” (NRG Associates, 

2009), as well as older versions of these databases. Data 

from these databases are subject to proprietary constraints, 

but derivative representations in the form of graphs and 

summary statistics are allowed to be published and were 

prepared for each assessment unit. To supplement commercial databases, additional data are obtained, where available, 

from operators, other Federal and State agencies, or published geological reports.

The PI/Dwights Plus US Production database provides 

production data for wells, leases, or production units. The PI/

Dwights Plus US Well database provides individual well data 

(including data for dry holes), including well identifications, 

locations, initial and final well status classifications, completion dates, and information on penetrated formations. The 

NRG Associates, Inc., “Significant Oil and Gas Fields of the 

United States” database provides volumetric and production 

data for fields and reservoirs.

Data Overview

This report provides various data files supporting the 

NOGA project. The files contain data that are the sources for 

the various graphs, data tables, and summary tables used in 

the assessment process. Tabular data are provided as tabdelimited text files (.tab files), usable in spreadsheet and 

database software. Graphical and summary data are provided 

as Portable Document Format files (.pdf files). File name 

conventions are as follows:

Tabular Data and Graphical Images in Support of the U.S. 

Geological Survey National Oil and Gas Assessment—

Anadarko Basin Province (5058)

By T.R. Klett and P.A. Le
2 Tabular Data and Graphical Images in Support of USGS National Oil and Gas Assessment—Anadarko Basin Province

Data Tables

eco####.tab

fed####.tab

own####.tab

sta####.tab

vol####.tab

inf####.tab

ins####.tab

kvol####.tab

Summary Tables

c######.pdf

d######.pdf

u######.pdf

Graphs

em######.pdf

fp######.pdf

g######.pdf

k######.pdf

Prefixes are defined as follows. The eco####.tab, 

fed####.tab, own####.tab, and sta####.tab files contain 

volume-percent data of undiscovered petroleum allocated to 

ecosystem regions, Federal lands, general land-ownership 

parcels, and States, respectively. The vol####.tab (volumes 

of undiscovered resources) table contains estimates of 

undiscovered petroleum resources along with parameters that 

express uncertainty in these estimates. The inf####.tab table 

(input FORSPAN) contains input data from the FORSPAN 

Assessment Model for Continuous Accumulations—Basic 

Input Data Form (Klett and Charpentier, 2003; Crovelli, 

2005) used in this assessment and provided in the u######.

pdf (unconventional assessment units) files. The ins####.tab 

(input Seventh) table contains input data from the Seventh 

Approximation Data Forms for Conventional Assessment 

Units (Klett and others, 2005; Schmoker and Klett, 2005) 

used in this assessment and provided in the c######.pdf 

(conventional assessment units) files. Data in the kvol####.

tab (known volumes) table are recoverable volumes reported 

in a commercially purchased database. The d######.

pdf (discovery history) table contains known recoverable 

volumes divided into historic discovery segments (first- and 

second-half or first-, second-, and third-third of accumulations discovered). The em######.pdf (output from the Monte 

Carlo program called EMC2; Charpentier and Klett, 2005) 

files contain graphs of input data and estimated petroleum 

resource volumes for conventional assessment units. The 

fp######.pdf (FORSPAN probability distributions for input 

and output variables) files contain graphs of input data and 

estimated petroleum resource volumes for continuous assessment units. The g######.pdf (grown recoverable volumes) 

and k######.pdf (known recoverable volumes) files contain 

graphs of exploration and discovery data for conventional 

assessment units.

For identification purposes, numbers in the positions 

occupied by the four symbols “####” represent the province 

code. Files with these numbers contain data for the entire 

province. Files having numbers in the positions occupied by 

the six symbols “######” (which represent the last six digits 

of the assessment-unit code) contain data only for that assessment unit.

Numeric Codes

A hierarchical numeric code identifies each region, province, total petroleum system, and assessment unit. The criteria 

for assigning codes are uniform throughout the NOGA project 

and throughout all resulting publications. The numeric codes 

used in this study are listed below.

Unit Name Code

Region North America 5

Province Anadarko Basin 5058

Total Petroleum System Woodford Composite 505801

Pennsylvanian Composite 505802

Assessment Units Arbuckle-Ellenburger 50580101

Simpson Group 50580102

Viola Group 50580103

Hunton Group 50580104

Mississippian 50580105

Woodford Shale Gas 50580161

Woodford Shale Oil 50580162

Morrowan-Atokan 50580201

Desmoinesian 50580202

Missourian-Permian 50580203

Greater Granite Wash 

Composite

50580204

Thirteen Finger Limestone–Atoka Shale Gas50580261

The assessment-unit portion of the code (last two digits) 

defines the type of assessment unit. Numbers from 01 to 59 

represent conventional assessment units: 61 to 79 represent 

continuous oil or gas assessment units, and 81 to 99 represent 

coalbed-gas assessment units. No total petroleum system 

or assessment-unit codes end with 0, for example 505800, 

50580160 or 50580180.

To maintain the conventional labeling of files (8-character 

name and 3-character extension), some file names that contain 

assessment-unit numbers do not include the first two digits. 

For example, a summary table that contains input data for the 

Arbuckle-Ellenburger assessment unit is labeled “c580101.pdf.”
Graphical Data 3

Summary Tables

The c######.pdf and u######.pdf files are copies of the 

completed input data forms used in the assessment process. 

The c######.pdf files contain the Seventh Approximation Data 

Forms for Conventional Assessment Units. The u######.pdf 

files contain the FORSPAN Assessment Model for Continuous 

Accumulations–Basic Input Data Form. These data are defined 

in the inf####.tab and ins####.tab sections of this report.

The d######.pdf files contain three tables of known 

and grown petroleum volumes in an assessment unit as a 

whole and in terms of discovery history. Grown field sizes 

are defined as known accumulation sizes that were adjusted 

upward to account for estimated future reserve growth. NA 

means not applicable and is shown in place of volumes for 

which only one accumulation is present to protect the proprietary nature of the data.

Graphical Data

The fp######.pdf files contain graphs of input data 

and estimated petroleum resource volumes for continuous 

assessment units. The data are defined in the inf####.tab and 

vol####.tab sections of this report. The graphs contained in 

these files are derived from a report generated by a commercial 

software package. The quality of these preformatted graphs, 

therefore, does not necessarily meet USGS editorial standards.

The em######.pdf files contain graphs of input data 

and estimated petroleum resource volumes for conventional 

assessment units. The data are defined in the ins####.tab and 

vol####.tab sections of this report. The graphs contained 

in these files are derived from a report generated by a commercial software package. The quality of these preformatted 

graphs, therefore, does not necessarily meet USGS editorial 

standards.

The g######.pdf and k######.pdf files contain graphs 

of exploration and discovery data for conventional assessment 

units. The volumetric data are defined in the kvol####.tab 

sections of this report. To protect the proprietary nature of the 

data, these files are not provided if the total number of accumulations in the assessment unit that are greater than or equal 

to the specified minimum size is less than four.

Two sets of exploration-activity and discovery-history 

graphs are provided for each of the assessment units, one 

set showing known field sizes (cumulative production plus 

remaining reserves) and the other showing field sizes that 

were adjusted to compensate for potential reserve growth that 

may occur in the next 30 years (labeled “grown”). Within 

each set of graphs, oil fields and gas fields are treated separately. The graphs include:

• Cumulative Number of New-Field Wildcat Wells vs. 

Drilling-Completion Year

• Number of New-Field Wildcat Wells vs. DrillingCompletion Year

• Oil- or Gas-Accumulation Size [million barrels of oil 

(MMBO) or billion cubic feet of gas (BCFG)] vs. Oilor Gas-Accumulation Rank by Size (With Respect to 

Discovery Halves or Thirds)

• Number of Oil or Gas Accumulations vs. Oil- or GasAccumulation Size Classes (MMBO or BCFG) (With 

Respect to Discovery Halves or Thirds)

• Volume of Oil or Gas (MMBO or BCFG) vs. Oil- or 

Gas-Accumulation Size Classes (MMBO or BCFG)

• Oil- or Gas-Accumulation Size (MMBO or BCFG) vs. 

Accumulation-Discovery Year

• Oil- or Gas-Accumulation Size (MMBO or BCFG) vs. 

Cumulative Number of New-Field Wildcat Wells

• Cumulative Oil or Gas Volume (MMBO or BCFG) vs. 

Accumulation-Discovery Year

• Cumulative Oil or Gas Volume (MMBO or BCFG) vs. 

Cumulative Number of New-Field Wildcat Wells

• Cumulative Number of Oil or Gas Accumulations vs. 

Accumulation-Discovery Year

• Cumulative Number of Oil or Gas Accumulations vs. 

Cumulative Number of New-Field Wildcat Wells

• Reservoir Depth, Oil or Gas Accumulations [feet (ft)] 

vs. Accumulation-Discovery Year

• Reservoir Depth, Oil or Gas Accumulations (ft) vs. 

Cumulative Number of New-Field Wildcat Wells

• Gas/Oil, Oil Accumulations [cubic feet of gas per barrel of oil, (CFG/BO)] vs. Mean Reservoir Depth (ft)

• NGL/Gas, Oil Accumulations [barrels of natural gas 

liquids per million cubic feet of gas (BNGL/MMCFG)] 

vs. Mean Reservoir Depth (ft)

• Liquids/Gas, Gas Accumulations [barrels of oil and 

natural gas liquids per million cubic feet of gas (BL/

MMCFG)] vs. Mean Reservoir Depth (ft)

• Number of Reservoirs in Oil Accumulations vs. American Petroleum Institute (API) Gravity (Degrees)

If data are insufficient or do not exist, graphs are not provided. Therefore, not all graphs are included in all files.
4 Tabular Data and Graphical Images in Support of USGS National Oil and Gas Assessment—Anadarko Basin Province

File List

Data tables

eco5058.tab

fed5058.tab

inf5058.tab

ins5058.tab

kvol5058.tab

own5058.tab

sta5058.tab

vol5058.tab

Summary tables Assessment-unit name

c580101.pdf Arbuckle-Ellenburger

c580102.pdf Simpson Group

c580103.pdf Viola Group

c580104.pdf Hunton Group

c580105.pdf Mississippian

c580201.pdf Morrowan-Atokan

c580202.pdf Desmoinesian

c580203.pdf Missourian-Permian

c580204.pdf Greater Granite Wash Composite

d580101.pdf Arbuckle-Ellenburger

d580102.pdf Simpson Group

d580103.pdf Viola Group

d580104.pdf Hunton Group

d580105.pdf Mississippian

d580201.pdf Morrowan-Atokan

d580202.pdf Desmoinesian

d580203.pdf Missourian-Permian

d580204.pdf Greater Granite Wash Composite

u580161.pdf Woodford Shale Gas

u580162.pdf Woodford Shale Oil

u580261.pdf Thirteen Finger Limestone–Atoka Shale Gas

Graphs Assessment-unit name

em580101.pdf Arbuckle-Ellenburger

em580102.pdf Simpson Group

em580103.pdf Viola Group

em580104.pdf Hunton Group

em580105.pdf Mississippian

em580201.pdf Morrowan-Atokan

em580202.pdf Desmoinesian

em580203.pdf Missourian-Permian

em580204.pdf Greater Granite Wash Composite

fp580161.pdf Woodford Shale Gas

fp580162.pdf Woodford Shale Oil

fp580261.pdf Thirteen Finger Limestone–Atoka Shale Gas

g580101.pdf Arbuckle-Ellenburger

g580102.pdf Simpson Group

Data tables

g580103.pdf Viola Group

g580104.pdf Hunton Group

g580105.pdf Mississippian

g580201.pdf Morrowan-Atokan

g580202.pdf Desmoinesian

g580203.pdf Missourian-Permian

g580204.pdf Greater Granite Wash Composite

k580101.pdf Arbuckle-Ellenburger

k580102.pdf Simpson Group

k580103.pdf Viola Group

k580104.pdf Hunton Group

k580105.pdf Mississippian

k580201.pdf Morrowan-Atokan

k580202.pdf Desmoinesian

k580203.pdf Missourian-Permian

k580204.pdf Greater Granite Wash Composite

Tabular Data

The eco####.tab, fed####.tab, own####.tab, and sta####.

tab files contain volume-percent data of undiscovered petroleum allocated to ecosystem regions, Federal lands, general 

land-ownership parcels, and States. Cells are left blank if data 

are unavailable.

The eco####.tab table contains 59 columns. The sum of 

the percentages should equal those for the total area (excluding offshore) in the own####.tab file. Data columns for these 

files are as follows:

1. Code—assessment-unit code number.

2. Name—assessment-unit name.

3. Area km2—area of the assessment unit in square 

kilometers.

4. Eco 1—name of first ecosystem that occupies all or part 

of the assessment-unit area.

5. E1 Area %—percentage of assessment-unit area that is 

occupied by ecosystem 1.

6. E1 Oil %—estimated percentage of undiscovered oil 

volume allocated to ecosystem 1.

7. E1 Gas %—estimated percentage of undiscovered gas 

volume allocated to ecosystem 1.

8. Eco 2—name of second ecosystem that occupies part of 

the assessment-unit area.

9. E2 Area %—percentage of assessment-unit area that is 

occupied by ecosystem 2.
Tabular Data 5

10. E2 Oil %—estimated percentage of undiscovered oil 

volume allocated to ecosystem 2.

11. E2 Gas %—estimated percentage of undiscovered gas 

volume allocated to ecosystem 2.

12. Eco 3—name of third ecosystem that occupies part of the 

assessment-unit area.

13. E3 Area %—percentage of assessment-unit area that is 

occupied by ecosystem 3.

14. E3 Oil %—estimated percentage of undiscovered oil 

volume allocated to ecosystem 3.

15. E3 Gas %—estimated percentage of undiscovered gas 

volume allocated to ecosystem 3.

16. Eco 4—name of fourth ecosystem that occupies part of 

the assessment-unit area.

17. E4 Area %—percentage of assessment-unit area that is 

occupied by ecosystem 4.

18. E4 Oil %—estimated percentage of undiscovered oil 

volume allocated to ecosystem 4.

19. E4 Gas %—estimated percentage of undiscovered gas 

volume allocated to ecosystem 4.

20. Eco 5—name of fifth ecosystem that occupies part of the 

assessment-unit area.

21. E5 Area %—percentage of assessment-unit area that is 

occupied by ecosystem 5.

22. E5 Oil %—estimated percentage of undiscovered oil 

volume allocated to ecosystem 5.

23. E5 Gas %—estimated percentage of undiscovered gas 

volume allocated to ecosystem 5.

24. Eco 6—name of sixth ecosystem that occupies part of the 

assessment-unit area.

25. E6 Area %—percentage of assessment-unit area that is 

occupied by ecosystem 6.

26. E6 Oil %—estimated percentage of undiscovered oil 

volume allocated to ecosystem 6.

27. E6 Gas %—estimated percentage of undiscovered gas 

volume allocated to ecosystem 6.

28. Eco 7—name of seventh ecosystem that occupies part of 

the assessment-unit area.

29. E7 Area %— percentage of assessment-unit area that is 

occupied by ecosystem 7.

30. E7 Oil %—estimated percentage of undiscovered oil 

volume allocated to ecosystem 7.

31. E7 Gas %—estimated percentage of undiscovered gas 

volume allocated to ecosystem 7.

32. Eco 8—name of eighth ecosystem that occupies part of 

the assessment-unit area.

33. E8 Area %—percentage of assessment-unit area that is 

occupied by ecosystem 8.

34. E8 Oil %—estimated percentage of undiscovered oil 

volume allocated to ecosystem 8.

35. E8 Gas %—estimated percentage of undiscovered gas 

volume allocated to ecosystem 8.

36. Eco 9—name of ninth ecosystem that occupies part of the 

assessment-unit area.

37. E9 Area %—percentage of assessment-unit area that is 

occupied by ecosystem 9.

38. E9 Oil %—estimated percentage of undiscovered oil 

volume allocated to ecosystem 9.

39. E9 Gas %—estimated percentage of undiscovered gas 

volume allocated to ecosystem 9.

40. Eco 10—name of tenth ecosystem that occupies part of 

the assessment-unit area.

41. E10 Area %—percentage of assessment-unit area that is 

occupied by ecosystem 10.

42. E10 Oil %—estimated percentage of undiscovered oil 

volume allocated to ecosystem 10.

43. E10 Gas %—estimated percentage of undiscovered gas 

volume allocated to ecosystem 10.

44. Eco 11—name of eleventh ecosystem that occupies part 

of the assessment-unit area.

45. E11 Area %—percentage of assessment-unit area that is 

occupied by ecosystem 11.

46. E11 Oil %—estimated percentage of undiscovered oil 

volume allocated to ecosystem 11.

47. E11 Gas %—estimated percentage of undiscovered gas 

volume allocated to ecosystem 11.

48. Eco 12—name of twelfth ecosystem that occupies part of 

the assessment-unit area.

49. E12 Area %—percentage of assessment-unit area that is 

occupied by ecosystem 12.

50. E12 Oil %—estimated percentage of undiscovered oil 

volume allocated to ecosystem 12.

51. E12 Gas %—estimated percentage of undiscovered gas 

volume allocated to ecosystem 12.
6 Tabular Data and Graphical Images in Support of USGS National Oil and Gas Assessment—Anadarko Basin Province

52. Eco 13—name of thirteenth ecosystem that occupies part 

of the assessment-unit area.

53. E13 Area %—percentage of assessment-unit area that is 

occupied by ecosystem 13.

54. E13 Oil %—estimated percentage of undiscovered oil 

volume allocated to ecosystem 13.

55. E13 Gas %—estimated percentage of undiscovered gas 

volume allocated to ecosystem 13.

56. Eco 14—name of fourteenth ecosystem that occupies part 

of the assessment-unit area.

57. E14 Area %—percentage of assessment-unit area that is 

occupied by ecosystem 14.

58. E14 Oil %—estimated percentage of undiscovered oil 

volume allocated to ecosystem 14.

59. E14 Gas %—estimated percentage of undiscovered gas 

volume allocated to ecosystem 14.

The fed####.tab table contains 83 columns. The sum of 

the percentages should equal those for Federal lands in the 

own####.tab file. Data columns for these files are:

1. Code—assessment-unit code number.

2. Name—assessment-unit name.

3. Area km2—area of the assessment unit in square kilometers.

4. BLM—“Bureau of Land Management (BLM),” name of 

Federal land that occupies all or part of the assessmentunit area.

5. BLM Area %—percentage of assessment-unit area that is 

occupied by Bureau of Land Management lands.

6. BLM Oil %—estimated percentage of undiscovered oil 

volume allocated to Bureau of Land Management lands.

7. BLM Gas %—estimated percentage of undiscovered gas 

volume allocated to Bureau of Land Management lands.

8. BLMW—“BLM Wilderness Areas (BLMW),” name of 

Federal land that occupies all or part of the assessmentunit area.

9. BLMW Area %—percentage of assessment-unit area that 

is occupied by Bureau of Land Management Wilderness 

Areas.

10. BLMW Oil %—estimated percentage of undiscovered oil 

volume allocated to Bureau of Land Management Wilderness Areas.

11. BLMW Gas %—estimated percentage of undiscovered 

gas volume allocated to Bureau of Land Management 

Wilderness Areas.

12. BLMR—“BLM Roadless Areas (BLMR),” name of Federal land that occupies all or part of the assessment-unit 

area.

13. BLMR Area %—percentage of assessment-unit area that 

is occupied by Bureau of Land Management Roadless 

Areas.

14. BLMR Oil %—estimated percentage of undiscovered oil 

volume allocated to Bureau of Land Management Roadless Areas.

15. BLMR Gas %—estimated percentage of undiscovered gas 

volume allocated to Bureau of Land Management Roadless Areas.

16. NPS—“National Park Service (NPS),” name of Federal 

land that occupies all or part of the assessment-unit area.

17. NPS Area %—percentage of assessment-unit area that is 

occupied by National Park Service lands.

18. NPS Oil %—estimated percentage of undiscovered oil 

volume allocated to National Park Service lands.

19. NPS Gas %—estimated percentage of undiscovered gas 

volume allocated to National Park Service lands.

20. NPSW—“NPS Wilderness Areas (NPSW),” name of 

Federal land that occupies all or part of the assessmentunit area.

21. NPSW Area %—percentage of assessment-unit area that 

is occupied by National Park Service Wilderness Areas.

22. NPSW Oil %—estimated percentage of undiscovered oil 

volume allocated to National Park Service Wilderness 

Areas.

23. NPSW Gas %—estimated percentage of undiscovered 

gas volume allocated to National Park Service Wilderness 

Areas.

24. NPSP—“NPS Protected Withdrawals (NPSP),” name of 

Federal land that occupies all or part of the assessmentunit area.

25. NPSP Area %—percentage of assessment-unit area that is 

occupied by National Park Service Protected Withdrawals.

26. NPSP Oil %—estimated percentage of undiscovered 

oil volume allocated to National Park Service Protected 

Withdrawals.

27. NPSP Gas %—estimated percentage of undiscovered 

gas volume allocated to National Park Service Protected 

Withdrawals.

28. FS—“Forest Service (FS),” name of Federal land that 

occupies all or part of the assessment-unit area.
Tabular Data 7

29. FS Area %—percentage of assessment-unit area that is 

occupied by USDA Forest Service lands.

30. FS Oil %—estimated percentage of undiscovered oil volume allocated to USDA Forest Service lands.

31. FS Gas %—estimated percentage of undiscovered gas 

volume allocated to USDA Forest Service lands.

32. FSW—“FS Wilderness Areas (FSW),” name of Federal 

land that occupies all or part of the assessment-unit area.

33. FSW Area %—percentage of assessment-unit area that is 

occupied by USDA Forest Service Wilderness Areas.

34. FSW Oil %—estimated percentage of undiscovered oil 

volume allocated to USDA Forest Service Wilderness 

Areas.

35. FSW Gas %—estimated percentage of undiscovered gas 

volume allocated to USDA Forest Service Wilderness 

Areas.

36. FSR—“FS Roadless Areas (FSR),” name of Federal land 

that occupies all or part of the assessment-unit area.

37. FSR Area %—percentage of assessment-unit area that is 

occupied by USDA Forest Service Roadless Areas.

38. FSR Oil %—estimated percentage of undiscovered oil 

volume allocated to USDA Forest Service Roadless 

Areas.

39. FSR Gas %—estimated percentage of undiscovered 

gas volume allocated to USDA Forest Service Roadless 

Areas.

40. FSP—“FS Protected Withdrawals (FSP),” name of Federal land that occupies all or part of the assessment-unit 

area.

41. FSP Area %—percentage of assessment-unit area that is 

occupied by USDA Forest Service Protected Withdrawals.

42. FSP Oil %—estimated percentage of undiscovered oil 

volume allocated to USDA Forest Service Protected 

Withdrawals.

43. FSP Gas %—estimated percentage of undiscovered gas 

volume allocated to USDA Forest Service Protected 

Withdrawals.

44. FWS—“U.S. Fish and Wildlife Service (USFWS),” name 

of Federal land that occupies all or part of the assessmentunit area.

45. FWS Area %—percentage of assessment-unit area that is 

occupied by U.S. Fish and Wildlife Service lands.

46. FWS Oil %—estimated percentage of undiscovered oil 

volume allocated to U.S. Fish and Wildlife Service lands.

47. FWS Gas %—estimated percentage of undiscovered gas 

volume allocated to U.S. Fish and Wildlife Service lands.

48. FWSW—“USFWS Wilderness Areas (USFWSW),” name 

of Federal land that occupies all or part of the assessmentunit area.

49. FWSW Area %—percentage of assessment-unit area that 

is occupied by U.S. Fish and Wildlife Service Wilderness 

Areas.

50. FWSW Oil %—estimated percentage of undiscovered 

oil volume allocated to U.S. Fish and Wildlife Service 

Wilderness Areas.

51. FWSW Gas %—estimated percentage of undiscovered 

gas volume allocated to U.S. Fish and Wildlife Service 

Wilderness Areas.

52. FWSP—“USFWS Protected Withdrawals (USFWSP),” 

name of Federal land that occupies all or part of the 

assessment-unit area.

53. FWSP Area %—percentage of assessment-unit area that 

is occupied by U.S. Fish and Wildlife Service Protected 

Withdrawals.

54. FWSP Oil %—estimated percentage of undiscovered oil 

volume allocated to U.S. Fish and Wildlife Service Protected Withdrawals.

55. FWSP Gas %—estimated percentage of undiscovered 

gas volume allocated to U.S. Fish and Wildlife Service 

Protected Withdrawals.

56. WS—“Wilderness Study Areas (WS),” name of Federal 

land that occupies all or part of the assessment-unit area.

57. WS Area %—percentage of assessment-unit area that is 

occupied by Wilderness Study Areas.

58. WS Oil %—estimated percentage of undiscovered oil 

volume allocated to Wilderness Study Areas.

59. WS Gas %—estimated percentage of undiscovered gas 

volume allocated to Wilderness Study Areas.

60. DOE—“Department of Energy (DOE),” name of Federal 

land that occupies all or part of the assessment-unit area.

61. DOE Area %—percentage of assessment-unit area that is 

occupied by Department of Energy lands.

62. DOE Oil %—estimated percentage of undiscovered oil 

volume allocated to Department of Energy lands.

63. DOE Gas %—estimated percentage of undiscovered gas 

volume allocated to Department of Energy lands.

64. DOD—“Department of Defense (DOD),” name of 

Federal land that occupies all or part of the assessmentunit area.
8 Tabular Data and Graphical Images in Support of USGS National Oil and Gas Assessment—Anadarko Basin Province

65. DOD Area %—percentage of assessment-unit area that is 

occupied by Department of Defense lands.

66. DOD Oil %—estimated percentage of undiscovered oil 

volume allocated to Department of Defense lands.

67. DOD Gas %—estimated percentage of undiscovered gas 

volume allocated to Department of Defense lands.

68. BOR—“Bureau of Reclamation (BOR),” name of Federal 

land that occupies all or part of the assessment-unit area.

69. BOR Area %—percentage of assessment-unit area that is 

occupied by Bureau of Reclamation lands.

70. BOR Oil %—estimated percentage of undiscovered oil 

volume allocated to Bureau of Reclamation lands.

71. BOR Gas %—estimated percentage of undiscovered gas 

volume allocated to Bureau of Reclamation lands.

72. TVA—“Tennessee Valley Authority (TVA),” name of 

Federal land that occupies all or part of the assessmentunit area.

73. TVA Area %—percentage of assessment-unit area that is 

occupied by Tennessee Valley Authority lands.

74. TVA Oil %—estimated percentage of undiscovered oil 

volume allocated to Tennessee Valley Authority lands.

75. TVA Gas %—estimated percentage of undiscovered gas 

volume allocated to Tennessee Valley Authority lands.

76. Other—“Other Federal,” other unspecified Federal lands 

that occupy all part of the assessment-unit area.

77. Oth Area %—percentage of assessment-unit area that is 

occupied by other unspecified Federal lands.

78. Oth Oil %—estimated percentage of undiscovered oil 

volume allocated to other unspecified Federal lands.

79. Oth Gas %—estimated percentage of undiscovered gas 

volume allocated to other unspecified Federal lands.

80. Fed 20—name of additional specified Federal lands that 

occupy all or part of the assessment-unit area.

81. (81)F20 Area %—percentage of assessment-unit area that 

is occupied by additional specified Federal lands.

82. F20 Oil %—estimated percentage of undiscovered oil volume allocated to additional specified Federal lands.

83. F20 Gas %—estimated percentage of undiscovered gas 

volume allocated to additional specified Federal lands.

The own####.tab table contains 59 columns. The sum of 

the percentages should equal 100. Data columns for these files 

are as follows:

1. Code—assessment-unit code number.

2. Name—assessment-unit name.

3. Area km2—area of the assessment unit in square 

kilometers.

4. Fed—“Federal Lands,” all Federal lands that occupy all or 

part of the assessment-unit area.

5. Fed Area %—percentage of assessment-unit area that is 

occupied by Federal lands.

6. Fed Oil %—estimated percentage of undiscovered oil 

volume allocated to Federal lands.

7. Fed Gas %—estimated percentage of undiscovered gas 

volume allocated to Federal lands.

8. Pri—“Private Lands,” all private lands that occupy all or 

part of the assessment-unit area.

9. Pri Area %—percentage of assessment-unit area that is 

occupied by private lands.

10. Pri Oil %—estimated percentage of undiscovered oil 

volume allocated to private lands.

11. Pri Gas %—estimated percentage of undiscovered gas 

volume allocated to private lands.

12. Tri—“Tribal Lands,” all tribal lands that occupy all or 

part of the assessment-unit area.

13. Tri Area %—percentage of assessment-unit area that is 

occupied by tribal lands.

14. Tri Oil %—estimated percentage of undiscovered oil 

volume allocated to tribal lands.

15. Tri Gas %—estimated percentage of undiscovered gas 

volume allocated to tribal lands.

16. Oth—name of other unspecified lands or offshore areas 

that occupy all or part of the assessment-unit area.

17. Oth Area %—percentage of assessment-unit area that is 

occupied by other unspecified lands or offshore areas.

18. Oth Oil %—estimated percentage of undiscovered oil 

volume allocated to other unspecified lands or offshore 

areas.

19. Oth Gas %—estimated percentage of undiscovered gas 

volume allocated to other unspecified lands or 

offshore areas.

20. State 1—name of first State for which State-owned lands 

or waters occupy all or part of the assessment-unit area.

21. S1 Area %—percentage of assessment-unit area that is 

occupied by State 1-owned lands or waters.

22. S1 Oil %—estimated percentage of undiscovered oil volume allocated to State 1-owned lands or waters.
Tabular Data 9

23. S1 Gas %—estimated percentage of undiscovered gas 

volume allocated to State 1-owned lands or waters.

24. State 2—name of second State for which State-owned 

lands or waters occupy all or part of the assessmentunit area.

25. S2 Area %—percentage of assessment-unit area that is 

occupied by State 2-owned lands or waters.

26. S2 Oil %—estimated percentage of undiscovered oil volume allocated to State 2-owned lands or waters.

27. S2 Gas %—estimated percentage of undiscovered gas 

volume allocated to State 2-owned lands or waters.

28. State 3—name of third State for which State-owned lands 

or waters occupy all or part of the assessment-unit area.

29. S3 Area %—percentage of assessment-unit area that is 

occupied by State 3-owned lands or waters.

30. S3 Oil %—estimated percentage of undiscovered oil volume allocated to State 3-owned lands or waters.

31. S3 Gas %—estimated percentage of undiscovered gas 

volume allocated to State 3-owned lands or waters.

32. State 4—name of fourth State for which State-owned lands 

or waters occupy all or part of the assessment-unit area.

33. S4 Area %—percentage of assessment-unit area that is 

occupied by State 4-owned lands or waters.

34. S4 Oil %—estimated percentage of undiscovered oil volume allocated to State 4-owned lands or waters.

35. S4 Gas %—estimated percentage of undiscovered gas 

volume allocated to State 4-owned lands or waters.

36. State 5—name of fifth State for which State-owned lands 

or waters occupy all or part of the assessment-unit area.

37. S5 Area %—percentage of assessment-unit area that is 

occupied by State 5-owned lands or waters.

38. S5 Oil %—estimated percentage of undiscovered oil volume allocated to State 5-owned lands or waters.

39. S5 Gas %—estimated percentage of undiscovered gas 

volume allocated to State 5-owned lands or waters.

40. State 6—name of sixth State for which State-owned lands 

or waters occupy all or part of the assessment-unit area.

41. S6 Area %—percentage of assessment-unit area that is 

occupied by State 6-owned lands or waters.

42. S6 Oil %—estimated percentage of undiscovered oil volume allocated to State 6-owned lands or waters.

43. S6 Gas %—estimated percentage of undiscovered gas 

volume allocated to State 6-owned lands or waters.

44. State 7—name of seventh State for which State-owned 

lands or waters occupy all or part of the assessmentunit area.

45. S7 Area %—percentage of assessment-unit area that is 

occupied by State 7-owned lands or waters.

46. S7 Oil %—estimated percentage of undiscovered oil volume allocated to State 7-owned lands or waters.

47. S7 Gas %—estimated percentage of undiscovered gas 

volume allocated to State 7-owned lands or waters.

48. State 8—name of eighth State for which State-owned 

lands or waters occupy all or part of the assessmentunit area.

49. S8 Area %—percentage of assessment-unit area that is 

occupied by State 8-owned lands or waters.

50. S8 Oil %—estimated percentage of undiscovered oil volume allocated to State 8-owned lands or waters.

51. S8 Gas %—estimated percentage of undiscovered gas 

volume allocated to State 8-owned lands or waters.

52. State 9—name of ninth State for which State-owned lands 

or waters occupy all or part of the assessment-unit area.

53. S9 Area %—percentage of assessment-unit area that is 

occupied by State 9-owned lands or waters.

54. S9 Oil %—estimated percentage of undiscovered oil volume allocated to State 9-owned lands or waters.

55. S9 Gas %—estimated percentage of undiscovered gas 

volume allocated to State 9-owned lands or waters.

56. State 10—name of tenth State for which State-owned 

lands or waters occupy all or part of the assessmentunit area.

57. S10 Area %—percentage of assessment-unit area that is 

occupied by State 10-owned lands or waters.

58. S10 Oil %—estimated percentage of undiscovered oil volume allocated to State 10-owned lands or waters.

59. S10 Gas %—estimated percentage of undiscovered gas 

volume allocated to State 10-owned lands or waters.

The sta####.tab table contains 59 columns. The sum of 

the percentages should equal 100. Data columns for these files 

are as follows:

1. Code—assessment-unit code number.

2. Name—assessment-unit name.

3. Area km2—area of the assessment unit in square 

kilometers.

4. State 1—name of first State (onshore and offshore) that 

occupies all or part of the assessment-unit area.
10 Tabular Data and Graphical Images in Support of USGS National Oil and Gas Assessment—Anadarko Basin Province

5. S1 Area %—percentage of assessment-unit area that is 

occupied by State 1.

6. S1 Oil %—estimated percentage of undiscovered oil 

volume allocated to State 1.

7. S1 Gas %—estimated percentage of undiscovered gas 

volume allocated to State 1.

8. State 2—name of second State (onshore and offshore) that 

occupies all or part of the assessment-unit area.

9. S2 Area %—percentage of assessment-unit area that is 

occupied by State 2.

10. S2 Oil %—estimated percentage of undiscovered oil 

volume allocated to State 2.

11. S2 Gas %—estimated percentage of undiscovered gas 

volume allocated to State 2.

12. State 3—name of third State (onshore and offshore) that 

occupies all or part of the assessment-unit area.

13. S3 Area %—percentage of assessment-unit area that is 

occupied by State 3.

14. S3 Oil %—estimated percentage of undiscovered oil 

volume allocated to State 3.

15. S3 Gas %—estimated percentage of undiscovered gas 

volume allocated to State 3.

16. State 4—name of fourth State (onshore and offshore) that 

occupies all or part of the assessment-unit area.

17. S4 Area %—percentage of assessment-unit area that is 

occupied by State 4.

18. S4 Oil %—estimated percentage of undiscovered oil 

volume allocated to State 4.

19. S4 Gas %—estimated percentage of undiscovered gas 

volume allocated to State 4.

20. State 5—name of fifth State (onshore and offshore) that 

occupies all or part of the assessment-unit area.

21. S5 Area %—percentage of assessment-unit area that is 

occupied by State 5.

22. S5 Oil %—estimated percentage of undiscovered oil 

volume allocated to State 5.

23. S5 Gas %—estimated percentage of undiscovered gas 

volume allocated to State 5.

24. State 6—name of sixth State (onshore and offshore) that 

occupies all or part of the assessment-unit area.

25. S6 Area %—percentage of assessment-unit area that is 

occupied by State 6.

26. S6 Oil %—estimated percentage of undiscovered oil 

volume allocated to State 6.

27. S6 Gas %—estimated percentage of undiscovered gas 

volume allocated to State 6.

28. State 7—name of seventh State (onshore and offshore) 

that occupies all or part of the assessment-unit area.

29. S7 Area %—percentage of assessment-unit area that is 

occupied by State 7.

30. S7 Oil %—estimated percentage of undiscovered oil 

volume allocated to State 7.

31. S7 Gas %—estimated percentage of undiscovered gas 

volume allocated to State 7.

32. State 8—name of eighth State (onshore and offshore) that 

occupies all or part of the assessment-unit area.

33. S8 Gas %—percentage of assessment-unit area that is 

occupied by State 8.

34. S8 Oil %—estimated percentage of undiscovered oil 

volume allocated to State 8.

35. S8 Gas %—estimated percentage of undiscovered gas 

volume allocated to State 8.

36. State 9—name of ninth State (onshore and offshore) that 

occupies all or part of the assessment-unit area.

37. S9 Area %—percentage of assessment-unit area that is 

occupied by State 9.

38. S9 Oil %—estimated percentage of undiscovered oil 

volume allocated to State 9.

39. S9 Gas %—estimated percentage of undiscovered gas 

volume allocated to State 9.

40. State 10—name of tenth State (onshore and offshore) that 

occupies all or part of the assessment-unit area.

41. S10 Area %—percentage of assessment-unit area that is 

occupied by State 10.

42. S10 Oil %—estimated percentage of undiscovered oil 

volume allocated to State 10.

43. S10 Gas %—estimated percentage of undiscovered gas 

volume allocated to State 10.

44. State 11—name of eleventh State (onshore and offshore) 

that occupies all or part of the assessment-unit area.

45. S11 Area %—percentage of assessment-unit area that is 

occupied by State 11.

46. S11 Oil %—estimated percentage of undiscovered oil 

volume allocated to State 11.
Tabular Data 11

47. S11 Gas %—estimated percentage of undiscovered gas 

volume allocated to State 11.

48. State 12—name of twelfth State (onshore and offshore) 

that occupies all or part of the assessment-unit area.

49. S12 Area %—percentage of assessment-unit area that is 

occupied by State 12.

50. S12 Oil %—estimated percentage of undiscovered oil 

volume allocated to State 12.

51. S12 Gas %—estimated percentage of undiscovered gas 

volume allocated to State 12.

52. State 13—name of thirteenth State (onshore and offshore) 

that occupies all or part of the assessment-unit area.

53. S13 Area %—percentage of assessment-unit area that is 

occupied by State 13.

54. S13 Oil %—estimated percentage of undiscovered oil 

volume allocated to State 13.

55. S13 Gas %—estimated percentage of undiscovered gas 

volume allocated to State 13.

56. State 14—name of fourteenth State (onshore and offshore) that occupies all or part of the assessment-unit 

area.

57. S14 Area %—percentage of assessment-unit area that is 

occupied by State 14.

58. S14 Oil %—estimated percentage of undiscovered oil 

volume allocated to State 14.

59. S14 Gas %—estimated percentage of undiscovered gas 

volume allocated to State 14.

The vol####.tab table contains estimates of undiscovered petroleum resources along with parameters that express 

uncertainty in these estimates. The table contains 40 columns. 

Blank cells represent no data. Data columns for these files are 

as follows:

1. Code—assessment-unit code number.

2. Name—assessment-unit name.

3. Type—type of assessment unit, conventional, continuous 

oil, continuous gas, or coalbed gas.

4. Status—remarks indicating that assessment unit was not 

quantitatively assessed; otherwise blank.

5. Prob %—geologic probability of the assessment unit.

6. OILF95 MMB—the estimated value of undiscovered oil 

(oil in oil accumulations) such that there is a 95-percent 

probability that this amount or more exists in the assessment unit. The volume is given in millions of barrels of 

oil (MMBO).

7. OILF50 MMB—the estimated value of undiscovered oil 

(oil in oil accumulations) such that there is a 50-percent 

probability that this amount or more exists in the assessment unit. This is the median value. The volume is given 

in millions of barrels of oil (MMBO).

8. OILF5 MMB—the estimated value of undiscovered oil 

(oil in oil accumulations) such that there is a 5-percent 

probability that this amount or more exists in the assessment unit. The volume is given in millions of barrels of 

oil (MMBO).

9. OILMN MMB—the estimated mean (average) value of 

undiscovered oil (oil in oil accumulations). The volume is 

given in millions of barrels of oil (MMBO).

10. OILSD MMB—the estimated standard deviation value of 

undiscovered oil (oil in oil accumulations). The volume is 

given in millions of barrels of oil (MMBO).

11. AGF95 BCF—the estimated value of undiscovered associated/dissolved gas (gas in oil accumulations) such that 

there is a 95-percent probability that this amount or more 

exists in the assessment unit. The volume is given in billions of cubic feet of gas (BCFG).

12. AGF50 BCF—the estimated value of undiscovered associated/dissolved gas (gas in oil accumulations) such that 

there is a 50-percent probability that this amount or more 

exists in the assessment unit. This is the median value. The 

volume is given in billions of cubic feet of gas (BCFG).

13. AGF5 BCF—the estimated value of undiscovered associated/dissolved gas (gas in oil accumulations) such that 

there is a 5-percent probability that this amount or more 

exists in the assessment unit. The volume is given in billions of cubic feet of gas (BCFG).

14. AGMN BCF—the estimated mean (average) value of 

undiscovered associated/dissolved gas (gas in oil accumulations). The volume is given in billions of cubic feet of 

gas (BCFG).

15. AGSD BCF—the estimated standard deviation value of 

undiscovered associated/dissolved gas (gas in oil accumulations). The volume is given in billions of cubic feet of 

gas (BCFG).

16. NGLF95 MMB—the estimated value of undiscovered 

natural gas liquids (NGL in oil accumulations) such that 

there is a 95-percent probability that this amount or more 

exists in the assessment unit. The volume is given in millions of barrels of NGL (MMBNGL).

17. NGLF50 MMB—the estimated value of undiscovered 

natural gas liquids (NGL in oil accumulations) such 

that there is a 50-percent probability that this amount or 

more exists in the assessment unit. This is the median 

value. The volume is given in millions of barrels of NGL 

(MMBNGL).
12 Tabular Data and Graphical Images in Support of USGS National Oil and Gas Assessment—Anadarko Basin Province

18. NGLF5 MMB—the estimated value of undiscovered 

natural gas liquids (NGL in oil accumulations) such that 

there is a 5-percent probability that this amount or more 

exists in the assessment unit. The volume is given in millions of barrels of NGL (MMBNGL).

19. NGLMN MMB—the estimated mean (average) value of 

undiscovered natural gas liquids (NGL in oil accumulations). The volume is given in millions of barrels of NGL 

(MMBNGL).

20. NGLSD MMB—the estimated standard deviation value 

of undiscovered natural gas liquids (NGL in oil accumulations). The volume is given in millions of barrels of NGL 

(MMBNGL).

21. NGF95 BCF—the estimated value of undiscovered nonassociated gas (gas in gas accumulations) such that there 

is a 95-percent probability that this amount or more exists 

in the assessment unit. The volume is given in billions of 

cubic feet of gas (BCFG).

22. NGF50 BCF—the estimated value of undiscovered nonassociated gas (gas in gas accumulations) such that there 

is a 50-percent probability that this amount or more exists 

in the assessment unit. This is the median value. The volume is given in billions of cubic feet of gas (BCFG).

23. NGF5 BCF—the estimated value of undiscovered nonassociated gas (gas in gas accumulations) such that there 

is a 5-percent probability that this amount or more exists 

in the assessment unit. The volume is given in billions of 

cubic feet of gas (BCFG).

24. NGMN BCF—the estimated mean (average) value of 

undiscovered nonassociated gas (gas in gas accumulations). The volume is given in billions of cubic feet of gas 

(BCFG).

25. NGSD BCF—the estimated standard deviation value of 

undiscovered nonassociated gas (gas in gas accumulations). The volume is given in billions of cubic feet of gas 

(BCFG).

26. LIQF95 MMB—the estimated value of undiscovered 

liquids (oil and NGL in gas accumulations) such that there 

is a 95-percent probability that this amount or more exists 

in the assessment unit. The volume is given in millions of 

barrels of liquids (MMBL).

27. LIQF50 MMB—the estimated value of undiscovered liquids (oil and NGL in gas accumulations) such that there is 

a 50-percent probability that this amount or more exists in 

the assessment unit. This is the median value. The volume 

is given in millions of barrels of liquids (MMBL).

28. LIQF5 MMB—the estimated value of undiscovered 

liquids (oil and NGL in gas accumulations) such that there 

is a 5-percent probability that this amount or more exists 

in the assessment unit. The volume is given in millions of 

barrels of liquids (MMBL).

29. LIQMN MMB—the estimated mean (average) value of 

undiscovered liquids (oil and NGL in gas accumulations). 

The volume is given in millions of barrels of liquids 

(MMBL).

30. LIQSD MMB—the estimated standard deviation value of 

undiscovered liquids (oil and NGL in gas accumulations). 

The volume is given in millions of barrels of liquids 

(MMBL).

31. LOF95 MMB—the estimated size of the largest undiscovered conventional oil accumulation such that there is 

a 95-percent probability of that accumulation being this 

amount or larger. The volume is given in millions of barrels of oil (MMBO).

32. LOF50 MMB—the estimated size of the largest undiscovered conventional oil accumulation such that there is 

a 50-percent probability of that accumulation being this 

amount or larger. This is the median value. The volume is 

given in millions of barrels of oil (MMBO).

33. LOF5 MMB—the estimated size of the largest undiscovered conventional oil accumulation such that there is 

a 5-percent probability of that accumulation being this 

amount or larger. The volume is given in millions of barrels of oil (MMBO).

34. LOMN MMB—the estimated mean (average) value of the 

largest undiscovered conventional oil accumulation. The 

volume is given in millions of barrels of oil (MMBO).

35. LOSD MMB—the estimated standard deviation value of 

the largest undiscovered conventional oil accumulation. 

The volume is given in millions of barrels of oil (MMBO).

36. LGF95 BCF—the estimated size of the largest undiscovered conventional gas accumulation such that there is a 

95-percent probability of that accumulation being this 

amount or larger. The volume is given in billions of cubic 

feet of gas (BCFG).

37. LGF50 BCF—the estimated size of the largest undiscovered conventional gas accumulation such that there is a 

50-percent probability of that accumulation being this 

amount or larger. This is the median value. The volume is 

given in billions of cubic feet of gas (BCFG).

38. LGF5 BCF—the estimated size of the largest undiscovered conventional gas accumulation such that there is 

a 5-percent probability of that accumulation being this 

amount or larger. The volume is given in billions of cubic 

feet of gas (BCFG).

39. LGMN BCF—the estimated mean (average) value of the 

largest undiscovered conventional gas accumulation. The 

volume is given in billions of cubic feet of gas (BCFG).
Tabular Data 13

40. LGSD BCF—the estimated standard deviation value of 

the largest undiscovered conventional gas accumulation. The volume is given in billions of cubic feet of gas 

(BCFG).

The inf####.tab table contains input data from the 

FORSPAN Assessment Model for Continuous Accumulations—Basic Input Data Form used in this assessment. Blank 

cells represent no data. This table contains 80 columns. Data 

columns are as follows:

1. Date—date of assessment.

2. Geol—assessing geologist’s name.

3. Regno—region code number.

4. Reg—region name.

5. Provno—province code number.

6. Prov—province name.

7. TPSno—total petroleum system code number.

8. TPS—total petroleum system name.

9. AUno—assessment-unit code number.

10. AU—assessment-unit name.

11. Data1—data sources used to aid in completing the datainput form.

12. Data2—additional data sources used to aid in completing 

the data-input form.

13. Comm—assessment unit type, the primary commodity 

type in the assessment unit, based on the gas-to-oil ratio 

(GOR) of the petroleum endowment, which includes both 

the discovered and undiscovered petroleum. An assessment unit is characterized as being oil prone if the gas-tooil ratio (GOR) is less than 20,000 cubic feet of gas per 

barrel of oil; otherwise, it is gas prone.

14. RminMMBBCF—minimum total recovery per cell considered for assessment, in million barrels of oil (MMBO) 

for oil assessment units or billion cubic feet of gas 

(BCFG) for gas assessment units.

15. Numtest1—number of tested cells in the assessment unit.

16. Numtest2—number of tested cells in the assessment unit 

that have total recoveries equal to or larger than the specified minimum total recovery per cell.

17. AUM—assessment-unit maturity, the exploration maturity of the assessment unit. Assessment-unit maturity is 

classified as “established” if more than 24 cells exceed the 

minimum total recovery, “frontier” if 1 to 24 cells exceed 

the minimum total recovery, or “hypothetical” if no cells 

exceed the minimum total recovery.

18. Med1MMBBCF—median total recovery per cell of the 

set of tested cells equal to or greater than the minimum 

total recovery that constitute the first third of the total 

number of cells ranked according to date of discovery within the assessment unit, in million barrels of oil 

(MMBO) for oil assessment units or billion cubic feet of 

gas (BCFG) for gas assessment units.

19. Med2MMBBCF—median total recovery per cell of the 

set of tested cells equal to or greater than the minimum 

total recovery that constitute the second third of the 

total number of cells ranked according to date of discovery within the assessment unit, in million barrels of oil 

(MMBO) for oil assessment units or billion cubic feet of 

gas (BCFG) for gas assessment units.

20. Med3MMBBCF—median total recovery per cell of the 

set of tested cells equal to or greater than the minimum 

total recovery that constitute the third third of the total 

number of cells ranked according to date of discovery within the assessment unit, in million barrels of oil 

(MMBO) for oil assessment units or billion cubic feet of 

gas (BCFG) for gas assessment units.

21. Prob1 %—charge probability, the probability for adequate 

petroleum charge for at least one untested cell equal to 

or larger than the minimum total recovery, somewhere in 

the assessment unit, having the potential to be added to 

reserves. Charge probability is given as a fractional value 

from 0 to 1.0.

22. Prob2 %—rocks probability, the probability for adequate 

reservoirs, traps, and seals for at least one untested cell 

equal to or larger than the minimum total recovery, somewhere in the assessment unit, having the potential to be 

added to reserves. Rocks probability is given as a fractional value from 0 to 1.0.

23. Prob3 %—timing probability, the probability for favorable geologic timing for at least one untested cell equal 

to or larger than the minimum total recovery, somewhere 

in the assessment unit, having the potential to be added to 

reserves. Timing probability is given as a fractional value 

from 0 to 1.0.

24. Geoprob %—geologic probability, the product of charge, 

rocks, and timing probabilities. Geologic probability is 

given as a fractional value from 0 to 1.0.

25. TAAmin a—estimated minimum (F100) area of the 

assessment unit. The area is given in acres.

26. TAAmod a—estimated mode of area of the assessment 

unit. The area is given in acres.

27. TAAmax a—estimated maximum (F0) area of the assessment unit. The area is given in acres.

28. TAAmean a—estimated mean area of the assessment unit. 

The area is given in acres.
14 Tabular Data and Graphical Images in Support of USGS National Oil and Gas Assessment—Anadarko Basin Province

29. CAmin a—estimated minimum (F100) area per cell 

of untested cells having the potential for additions to 

reserves in the assessment unit. This area is equivalent to 

the drainage area of wells. This area is given in acres.

30. CAmod a—estimated mode of area per cell of untested 

cells having the potential for additions to reserves in the 

assessment unit. This area is equivalent to the drainage 

area of wells. This area is given in acres.

31. CAmax a—estimated maximum (F0) area per cell 

of untested cells having the potential for additions to 

reserves in the assessment unit. This area is equivalent to 

the drainage area of wells. This area is given in acres.

32. CAmean a—estimated mean area per cell of untested cells 

having the potential for additions to reserves in the assessment unit. This area is equivalent to the drainage area of 

wells. This area is given in acres.

33. CAminmn a—estimated minimum of the mean area per 

cell of untested cells having the potential for additions to 

reserves in the assessment unit. This area is equivalent to 

the drainage area of wells. This area is given in acres.

34. CAmaxmn a—estimated maximum of the mean area per 

cell of untested cells having the potential for additions to 

reserves in the assessment unit. This area is equivalent to 

the drainage area of wells. This area is given in acres.

35. TAAUmin %—estimated minimum (F100) percentage of 

the total assessment-unit area that is untested.

36. TAAUmod %—estimated mode of percentage of the total 

assessment-unit area that is untested.

37. TAAUmax %—estimated maximum (F0) percentage of 

the total assessment-unit area that is untested.

38. (38)TAAUmean %—estimated mean percentage of the 

total assessment-unit area that is untested.

39. UAAPmin %—estimated minimum (F100) percentage of 

the untested area in the assessment unit having the potential for additions to reserves).

40. UAAPmod %—estimated mode of percentage of the 

untested area in the assessment unit having the potential 

for additions to reserves.

41. UAAPmax %—estimated maximum (F0) percentage of 

the untested area in the assessment unit having the potential for additions to reserves.

42. UAAPmean %—estimated mean percentage of the 

untested area in the assessment unit having the potential 

for additions to reserves.

43. RminMMBBCF—estimated minimum (F100) total 

recovery per cell for untested cells in the assessment unit 

having the potential for additions to reserves. This volume 

is given as million barrels of oil (MMBO) for oil assessment units and billion cubic feet of gas (BCFG) for gas 

assessment units.

44. RmedMMBBCF—estimated median (F50) total recovery 

per cell for untested cells in the assessment unit having 

the potential for additions to reserves. This volume is 

given as million barrels of oil (MMBO) for oil assessment 

units and billion cubic feet of gas (BCFG) for gas assessment units.

45. RmaxMMBBCF—estimated maximum (F0) total 

recovery per cell for untested cells in the assessment unit 

having the potential for additions to reserves. This volume 

is given as million barrels of oil (MMBO) for oil assessment units and billion cubic feet of gas (BCFG) for gas 

assessment units.

46. RmeanMMBBCF—estimated mean total recovery per 

cell for untested cells in the assessment unit having the 

potential for additions to reserves. This volume is given as 

million barrels of oil (MMBO) for oil assessment units and 

billion cubic feet of gas (BCFG) for gas assessment units.

47. GminCF/B—estimated minimum (F100) gas to oil ratio 

(GOR), in cubic feet of gas per barrel of oil (CFG/BO), 

of untested cells equal to or larger than the minimum total 

recovery in oil assessment units.

48. GmodCF/B—estimated mode of gas to oil ratio (GOR), in 

cubic feet of gas per barrel of oil (CFG/BO), of untested 

cells equal to or larger than the minimum total recovery in 

oil assessment units.

49. GmaxCF/B—estimated maximum (F0) gas to oil ratio 

(GOR), in cubic feet of gas per barrel of oil (CFG/BO), 

of untested cells equal to or larger than the minimum total 

recovery in oil assessment units.

50. NminB/MMCF—estimated minimum (F100) natural 

gas liquids (NGL) to gas ratio, in barrels of natural gas 

liquids per million cubic feet of gas (BNGL/MMCFG), of 

untested cells equal to or larger than the minimum total 

recovery in oil assessment units.

51. NmodB/MMCF—estimated mode of natural gas liquids 

(NGL) to gas ratio, in barrels of natural gas liquids per 

million cubic feet of gas (BNGL/MMCFG), of untested 

cells equal to or larger than the minimum total recovery in 

oil assessment units.

52. NmaxB/MMCF—estimated maximum (F0) natural 

gas liquids (NGL) to gas ratio, in barrels of natural gas 

liquids per million cubic feet of gas (BNGL/MMCFG), of 

untested cells equal to or larger than the minimum total 

recovery in oil assessment units.

53. LminB/MMCF—estimated minimum (F100) liquids (oil 

plus natural gas liquids) to gas ratio (LGR), in barrels of 

liquids per million cubic feet of gas (BNGL/MMCFG), of 
Tabular Data 15

untested cells equal to or larger than the minimum total 

recovery in gas assessment units.

54. LmodB/MMCF—estimated modal liquids (oil plus natural gas liquids) to gas ratio (LGR), in barrels of liquids per 

million cubic feet of gas (BNGL/MMCFG), of untested 

cells equal to or larger than the minimum total recovery in 

gas assessment units.

55. LmaxB/MMCF—estimated maximum (F0) liquids (oil 

plus natural gas liquids) to gas ratio (LGR), in barrels of 

liquids per million cubic feet of gas (BNGL/MMCFG), of 

untested cells equal to or larger than the minimum total 

recovery in gas assessment units.

56. APImin deg—estimated minimum (F100) American 

Petroleum Institute gravity, in degrees, of oil in untested 

cells in oil assessment units.

57. APImod deg—estimated modal American Petroleum 

Institute gravity, in degrees, of oil in untested cells in oil 

assessment units.

58. APImax deg—estimated maximum (F0) American Petroleum Institute gravity, in degrees, of oil in untested cells 

in oil assessment units.

59. Smin %—estimated minimum (F100) sulfur (S) content, 

in percent, of oil in untested cells in oil assessment units.

60. Smod %—estimated mode of sulfur (S) content, in percent, of oil in untested cells in oil assessment units.

61. Smax %—estimated maximum (F0) sulfur (S) content, in 

percent, of oil in untested cells in oil assessment units.

62. ODmin m—estimated minimum (F100) drilling depth, in 

meters, of oil in untested cells in oil assessment units.

63. ODf75 m—estimated 75th fractile (F75) of drilling depth, 

in meters, of oil in untested cells in oil assessment units.

64. ODmod m—estimated mode of drilling depth, in meters, 

of oil in untested cells in oil assessment units.

65. ODf25 m—estimated 25th fractile (F25) drilling depth, in 

meters, of oil in untested cells in oil assessment units.

66. ODmax m—estimated maximum (F0) drilling depth, in 

meters, of oil in untested cells in oil assessment units.

67. OWDmin m—estimated minimum (F100) water depth, 

in meters, of oil in untested cells in oil assessment units 

(ocean, bays, or lakes; if applicable).

68. OWDmod m—estimated mode of water depth, in meters, 

of oil in untested cells in oil assessment units (ocean, 

bays, or lakes; if applicable).

69. OWDmax m—estimated maximum (F0) water depth, 

in meters, of oil in untested cells in oil assessment units 

(ocean, bays, or lakes; if applicable).

70. IGmin %—estimated minimum (F100) inert gas (IG) content, in percent, of gas in untested cells in gas assessment 

units (nitrogen and helium, and so forth).

71. IGmod %—estimated mode of inert gas (IG) content, in 

percent, of gas in untested cells in gas assessment units 

(nitrogen and helium, and so forth).

72. IGmax %—estimated maximum (F0) inert gas (IG) content, in percent, of gas in untested cells in gas assessment 

units (nitrogen and helium, and so forth).

73. CO2min %—estimated minimum (F100) carbon dioxide 

(CO2) content, in percent, of gas in untested cells in gas 

assessment units.

74. CO2med %—estimated mode of carbon dioxide (CO2) 

content, in percent, of gas in untested cells in gas assessment units.

75. CO2max %—estimated maximum (F0) carbon dioxide 

(CO2) content, in percent, of gas in untested cells in gas 

assessment units.

76. H2Smin %—estimated minimum (F100) hydrogen sulfide 

(H2S) content, in percent, of gas in untested cells in gas 

assessment units.

77. H2Smod %—estimated mode of hydrogen sulfide (H2S) 

content, in percent, of gas in untested cells in gas assessment units.

78. H2Smax %—estimated maximum (F0) hydrogen sulfide 

(H2S) content, in percent, of gas in untested cells in gas 

assessment units.

79. HVmin btu—estimated minimum heating value, in British 

Thermal Units (btu), of gas in untested cells in gas assessment units.

80. HVmod btu—estimated mode of heating value, in British 

Thermal Units (btu), of gas in untested cells in gas assessment units.

81. HVmax btu—estimated maximum heating value, in British Thermal Units (btu), of gas in untested cells in gas 

assessment units.

82. GDmin m—estimated minimum (F100) drilling depth, in 

meters, of gas in untested cells in gas assessment units.

83. GDf25 m—estimated 25th fractile (F25) drilling depth, in 

meters, of gas in untested cells in gas assessment units.

84. GDmod m—estimated mode of drilling depth, in meters, 

of gas in untested cells in gas assessment units.

85. GDf25 m—estimated 25th fractile (F25) drilling depth, in 

meters, of gas in untested cells in gas assessment units.

86. GDmax m—estimated maximum (F0) drilling depth, in 

meters, of gas in untested cells in gas assessment units.
16 Tabular Data and Graphical Images in Support of USGS National Oil and Gas Assessment—Anadarko Basin Province

87. GWDmin m—estimated minimum (F100) water depth, 

in meters, of gas in untested cells in gas assessment units 

(ocean, bays, or lakes; if applicable).

88. GWDmod m—estimated mode of water depth, in meters, 

of gas in untested cells in gas assessment units (ocean, 

bays, or lakes; if applicable).

89. GWDmax m—estimated maximum (F0) water depth, in 

meters, of gas in untested cells in gas assessment units 

(ocean, bays, or lakes; if applicable).

90. FSRmean %—estimated mean future success ratio, as 

percent.

91. FSRmin %—estimated minimum (F100) future success 

ratio, as percent.

92. FSRmod %—estimated mode of future success ratio, as 

percent.

93. FSRmax %—estimated maximum (F100) future success 

ratio, as percent.

94. HSR %—historical success ratio, as percent.

95. TWCP—Typical well-completion practices (conventional, 

open hole, open cavity, other).

96. FWTS—Fraction of wells drilled that are typically stimulated.

97. FST—Predominant type of stimulation (none, frac, acid, 

other).

98. FHW—Fraction of wells drilled that are horizontal.

The ins####.tab table contains input data from the Seventh Approximation Data Forms for Conventional Assessment 

Units used in this assessment and provided in the c######.

pdf files. Cells are left blank if data are unavailable. This table 

contains 78 columns. Data columns are as follows:

1. Date—date of assessment.

2. Geol—assessing geologist’s name.

3. Regno—region code number.

4. Reg—region name.

5. Provno—province code number.

6. Prov—province name.

7. TPSno—total petroleum system code number.

8. TPS—total petroleum system name.

9. AUno—assessment-unit code number.

10. AU—assessment-unit name.

11. Data—data sources used to aid in completing the datainput form.

12. Comm—primary commodity type in the assessment 

unit, based on the gas-to-oil ratio of the petroleum 

endowment, which includes both the discovered and 

undiscovered petroleum. An assessment unit is characterized as being oil prone if the gas-to-oil ratio is less than 

20,000 cubic feet of gas per barrel of oil; otherwise, it is 

gas prone.

13. Minsize MMB—minimum accumulation size considered for assessment, in million barrels of oil equivalent 

(MMBOE).

14. Numoil—number of oil accumulations equal to or larger 

than the minimum accumulation size discovered in the 

assessment unit.

15. Numgas—number of gas accumulations equal to or larger 

than the minimum accumulation size discovered in the 

assessment unit.

16. AUM—assessment-unit maturity, the exploration maturity of the assessment unit. Assessment-unit maturity is 

classified as “established” if more than 13 accumulations 

exceeding minimum size have been discovered, “frontier” 

if 1 to 13 accumulations exceeding minimum size have 

been discovered, or “hypothetical” if no accumulations 

exceeding minimum size have been discovered.

17. MedO1MMB—median size of the set of discovered 

oil accumulations that constitute the first one-third or 

one-half of the total number of oil accumulations ranked 

according to date of discovery within the assessment unit, 

in million barrels of oil (MMBO). This size is derived 

from known oil volumes that were adjusted upward to 

account for estimated future reserve growth.

18. MedO2MMB—median size of the set of discovered oil 

accumulations that constitute the second one-third or 

one-half of the total number of oil accumulations ranked 

according to date of discovery within the assessment unit, 

in million barrels of oil (MMBO). This size is derived 

from known oil volumes that were adjusted upward to 

account for estimated future reserve growth.

19. MedO3MMB—median size of the set of discovered oil 

accumulations that constitute the third one-third of the 

total number of oil accumulations ranked according to 

date of discovery within the assessment unit, in million 

barrels of oil (MMBO). This size is derived from known 

oil volumes that were adjusted upward to account for 

estimated future reserve growth.

20. MedG1BCF—median size of the set of discovered gas 

accumulations that constitute the first one-third or onehalf of the total number of gas accumulations ranked 

according to date of discovery within the assessment unit, 

in billion cubic feet of gas (BCFG). This size is derived 

from known gas volumes that were adjusted upward to 

account for estimated future reserve growth.
Tabular Data 17

21. MedG2BCF—median size of the set of discovered gas 

accumulations that constitute the second one-third or 

one-half of the total number of gas accumulations ranked 

according to date of discovery within the assessment unit, 

in billion cubic feet of gas (BCFG). This size is derived 

from known gas volumes that were adjusted upward to 

account for estimated future reserve growth.

22. MedG3BCF—median size of the set of discovered gas 

accumulations that constitute the third one-third of the 

total number of gas accumulations ranked according to 

date of discovery within the assessment unit, in billion cubic feet of gas (BCFG). This size is derived from 

known gas volumes that were adjusted upward to account 

for estimated future reserve growth.

23. Prob1 %—charge probability, the probability for adequate 

petroleum charge for at least one undiscovered accumulation equal to or larger than the minimum accumulation 

size, somewhere in the assessment unit, having the potential to be added to reserves. Charge probability is given as 

a fractional value from 0 to 1.0.

24. Prob2 %—rocks probability, the probability for adequate 

reservoirs, traps, and seals for at least one undiscovered 

accumulation equal to or larger than the minimum accumulation size, somewhere in the assessment unit, having 

the potential to be added to reserves. Rocks probability is 

given as a fractional value from 0 to 1.0.

25. Prob3 %—timing probability, the probability for favorable geologic timing for at least one undiscovered accumulation equal to or larger than the minimum accumulation size, somewhere in the assessment unit, having the 

potential to be added to reserves. Timing probability is 

given as a fractional value from 0 to 1.0.

26. Geoprob %—geologic probability, the product of charge, 

rocks, and timing probabilities. Geologic probability is 

given as a fractional value from 0 to 1.0.

27. NOmin—estimated minimum (F100) number of undiscovered oil accumulations equal to or larger than the 

minimum accumulation size in the assessment unit.

28. NOmod—estimated mode of number of undiscovered oil 

accumulations equal to or larger than the minimum accumulation size in the assessment unit.

29. NOmax—estimated maximum (F0) number of undiscovered oil accumulations equal to or larger than the minimum accumulation size in the assessment unit.

30. NGmin—estimated minimum (F100) number of undiscovered gas accumulations equal to or larger than the 

minimum accumulation size in the assessment unit.

31. NGmod—estimated mode of number of undiscovered 

gas accumulations equal to or larger than the minimum 

accumulation size in the assessment unit.

32. NGmax—estimated maximum (F0) number of undiscovered gas accumulations equal to or larger than the 

minimum accumulation size in the assessment unit.

33. SOminMMB—estimated minimum (F100) size, in million barrels of oil (MMBO), of undiscovered oil accumulations in the assessment unit.

34. SOmedMMB—estimated median (F50) size, in million 

barrels of oil (MMBO), of undiscovered oil accumulations in the assessment unit.

35. SOmaxMMB—estimated maximum (F0) size, in million 

barrels of oil (MMBO), of undiscovered oil accumulations in the assessment unit.

36. SGminBCF—estimated minimum (F100) size, in billion 

cubic feet of gas (BCFG), of undiscovered gas accumulations in the assessment unit.

37. SGmedBCF—estimated median (F50) size, in billion 

cubic feet of gas (BCFG), of undiscovered gas accumulations in the assessment unit.

38. SGmaxBCF—estimated maximum (F0) size, in billion 

cubic feet of gas (BCFG), of undiscovered gas accumulations in the assessment unit.

39. GminCF/B—estimated minimum (F100) gas-to-oil ratio 

(GOR), in cubic feet of gas per barrel of oil (CFG/BO), of 

undiscovered oil accumulations equal to or larger than the 

minimum accumulation size in the assessment unit.

40. GmodCF/B—estimated mode of gas-to-oil ratio (GOR), 

in cubic feet of gas per barrel of oil (CFG/BO), of undiscovered oil accumulations equal to or larger than the 

minimum accumulation size in the assessment unit.

41. GmaxCF/B—estimated maximum (F0) gas-to-oil ratio 

(GOR), in cubic feet of gas per barrel of oil (CFG/BO), of 

undiscovered oil accumulations equal to or larger than the 

minimum accumulation size in the assessment unit.

42. NminB/MMCF—estimated minimum (F100) natural 

gas liquids (NGL) to gas ratio, in barrels of natural gas 

liquids per million cubic feet of gas (BNGL/MMCFG), of 

undiscovered oil accumulations equal to or larger than the 

minimum accumulation size in the assessment unit.

43. NmodB/MMCF—estimated mode of natural gas liquids 

(NGL) to gas ratio, in barrels of natural gas liquids per 

million cubic feet of gas (BNGL/MMCFG), of undiscovered oil accumulations equal to or larger than the minimum accumulation size in the assessment unit.

44. NmaxB/MMCF—estimated maximum (F0) natural 

gas liquids (NGL) to gas ratio, in barrels of natural gas 

liquids per million cubic feet of gas (BNGL/MMCFG), of 

undiscovered oil accumulations equal to or larger than the 

minimum accumulation size in the assessment unit.
18 Tabular Data and Graphical Images in Support of USGS National Oil and Gas Assessment—Anadarko Basin Province

45. LminB/MMCF—estimated minimum (F100) liquids (oil 

plus natural gas liquids) to gas ratio (LGR), in barrels of 

liquids per million cubic feet of gas (BL/MMCFG), of 

undiscovered gas accumulations equal to or larger than 

the minimum accumulation size in the assessment unit.

46. LmodB/MMCF—estimated mode of liquids (oil plus 

natural gas liquids) to gas ratio (LGR), in barrels of 

liquids per million cubic feet of gas (BL/MMCFG), of 

undiscovered gas accumulations equal to or larger than 

the minimum accumulation size in the assessment unit.

47. LmaxB/MMCF—estimated maximum (F0) liquids (oil 

plus natural gas liquids) to gas ratio (LGR), in barrels of 

liquids per million cubic feet of gas (BL/MMCFG), of 

undiscovered gas accumulations equal to or larger than 

the minimum accumulation size in the assessment unit.

48. APImin deg—estimated minimum (F100) American 

Petroleum Institute gravity, in degrees, of oil in undiscovered oil accumulations in the assessment unit.

49. APImod deg—estimated mode of American Petroleum 

Institute gravity, in degrees, of oil in undiscovered oil 

accumulations in the assessment unit.

50. APImax deg—estimated maximum (F0) American Petroleum Institute gravity, in degrees, of oil in undiscovered 

oil accumulations in the assessment unit.

51. Smin %—estimated minimum (F100) sulfur (S) content, 

in percent, of oil in undiscovered oil accumulations in the 

assessment unit.

52. Smod %—estimated mode of sulfur (S) content, in 

percent, of oil in undiscovered oil accumulations in the 

assessment unit.

53. Smax %—estimated maximum (F0) sulfur (S) content, in 

percent, of oil in undiscovered oil accumulations in the 

assessment unit.

54. ODmin m—estimated minimum (F100) drilling depth, in 

meters, of oil in untested cells in oil assessment units.

55. ODf75 m—estimated 75th fractile (F75) of drilling depth, 

in meters, of oil in untested cells in oil assessment units.

56. ODmod m—estimated mode of drilling depth, in meters, 

of oil in untested cells in oil assessment units.

57. ODf25 m—estimated 25th fractile (F25) drilling depth, in 

meters, of oil in untested cells in oil assessment units.

58. ODmax m—estimated maximum (F0) drilling depth, in 

meters, of oil in untested cells in oil assessment units.

59. OWDmin m—estimated minimum (F100) water depth, 

in meters, of oil in untested cells in oil assessment units 

(ocean, bays, or lakes; if applicable).

60. OWDmod m—estimated mode of water depth, in meters, 

of oil in untested cells in oil assessment units (ocean, 

bays, or lakes; if applicable).

61. OWDmax m—estimated maximum (F0) water depth, 

in meters, of oil in untested cells in oil assessment units 

(ocean, bays, or lakes; if applicable).

62. IGmin %—estimated minimum (F100) inert (IG) gas content, in percent, of gas in untested cells in gas assessment 

units (nitrogen and helium, and so forth).

63. IGmod %—estimated mode of inert gas (IG) content, in 

percent, of gas in untested cells in gas assessment units 

(nitrogen and helium, and so forth).

64. IGmax %—estimated maximum (F0) inert gas (IG) content, in percent, of gas in untested cells in gas assessment 

units (nitrogen and helium, and so forth).

65. CO2min %—estimated minimum (F100) carbon dioxide 

(CO2) content, in percent, of gas in untested cells in gas 

assessment units.

66. CO2mod %—estimated mode of carbon dioxide (CO2) 

content, in percent, of gas in untested cells in gas assessment units.

67. CO2max %—estimated maximum (F0) carbon dioxide 

(CO2) content, in percent, of gas in untested cells in gas 

assessment units.

68. H2Smin %—estimated minimum (F100) hydrogen sulfide 

(H2S) content, in percent, of gas in untested cells in gas 

assessment units.

69. H2Smod %—estimated mode of hydrogen sulfide (H2S) 

content, in percent, of gas in untested cells in gas assessment units.

70. H2Smax %—estimated maximum (F0) hydrogen sulfide 

(H2S) content, in percent, of gas in untested cells in gas 

assessment units.

71. GDmin m—estimated minimum (F100) drilling depth, in 

meters, of gas in untested cells in gas assessment units.

72. GDf25 m—estimated 25th fractile (F25) drilling depth, in 

meters, of gas in untested cells in gas assessment units.

73. GDmod m—estimated mode of drilling depth, in meters, 

of gas in untested cells in gas assessment units.

74. GDf25 m—estimated 25th fractile (F25) drilling depth, in 

meters, of gas in untested cells in gas assessment units.

75. GDmax m—estimated maximum (F0) drilling depth, in 

meters, of gas in untested cells in gas assessment units.

76. GWDmin m—estimated minimum (F100) water depth, 

in meters, of gas in untested cells in gas assessment units 

(ocean, bays, or lakes; if applicable).
References Cited 19

77. GWDmod m—estimated mode of water depth, in meters, 

of gas in untested cells in gas assessment units (ocean, 

bays, or lakes; if applicable).

78. GWDmax m—estimated maximum (F0) water depth, in 

meters, of gas in untested cells in gas assessment units 

(ocean, bays, or lakes; if applicable).

Data in the kvol####.tab table are derived from a commercially purchased database (NRG Associates, 2009) and are 

current through 2007. This table contains 15 columns. Blank 

cells represent no data. Data columns for these files are as 

follows:

1. Code—assessment-unit code number.

2. Name—assessment-unit name.

3. Numres—number of reported reservoirs in the assessment 

unit.

4. CUMOIL MMB—cumulative production of oil from the 

reported reservoirs in the assessment unit. This volume is 

in million barrels of oil (MMBO).

5. REMOIL MMB—remaining oil reserves in the reported 

reservoirs in the assessment unit. This volume is in million barrels of oil (MMBO).

6. KROIL MMB—known recoverable oil volume (cumulative production plus remaining reserves) from the reported 

reservoirs in the assessment unit. This volume is in million barrels of oil (MMBO).

7. CUMGAS BCF—cumulative production of natural gas 

from the reported reservoirs in the assessment unit. This 

volume is in billion cubic feet of gas (BCFG).

8. REMGAS BCF—remaining natural gas reserves in the 

reported reservoirs in the assessment unit. This volume is 

in billion cubic feet of gas (BCFG).

9. KRGAS BCF—known recoverable natural gas volume 

(cumulative production plus remaining reserves) from the 

reported reservoirs in the assessment unit. This volume is 

in billion cubic feet of gas (BCFG).

10. CUMNGL MMB—cumulative production of natural gas 

liquids (NGL) from the reported reservoirs in the assessment unit. This volume is in million barrels of natural gas 

liquids (MMBNGL).

11. REMNGL MMB—remaining natural gas liquids (NGL) 

reserves in the reported reservoirs in the assessment unit. 

This volume is in million barrels of natural gas liquids 

(MMBNGL).

12. KRNGL MMB—known recoverable natural gas liquids 

(NGL) volume (cumulative production plus remaining 

reserves) from the reported reservoirs in the assessment 

unit. This volume is in million barrels of natural gas liquids (MMBNGL).

13. CUMPET MMB—cumulative production of petroleum 

(oil, gas, and NGL) from the reported reservoirs in the 

assessment unit. This volume is in million barrels of oil 

equivalent (MMBOE).

14. REMPET MMB—remaining petroleum (oil, gas, and 

NGL) reserves in the reported reservoirs in the assessment 

unit. This volume is in million barrels of oil equivalent 

(MMBOE).

15. KRPET MMB—known recoverable petroleum (oil, gas, 

and NGL) volume (cumulative production plus remaining 

reserves) from the reported reservoirs in the assessment 

unit. This volume is in million barrels of oil equivalent 

(MMBOE).

References Cited

Charpentier, R.R., and Klett, T.R., 2005, A Monte Carlo simulation method for the assessment of undiscovered, conventional 

oil and gas, chap. 21, in USGS Southwestern Wyoming 

Province Assessment Team, eds., Petroleum systems and 

geologic assessment of oil and gas in the Southwestern 

Wyoming Province, Wyoming, Colorado, and Utah: U.S. 

Geological Survey Digital Data Series DDS–69–D, 5 p. 

[available at http://energy.usgs.gov/OilGas/AssessmentsData/

NationalOilGasAssessment/Methodology.aspx].

Crovelli, R.A., 2005, Analytic resource assessment method for 

continuous petroleum accumulations—The ACCESS assessment method, chap. 22, in USGS Southwestern Wyoming 

Province Assessment Team, eds., Petroleum systems and 

geologic assessment of oil and gas in the Southwestern Wyoming Province, Wyoming, Colorado, and Utah: U.S. Geological Survey Digital Data Series DDS–69–D, 10 p. [available at http://energy.usgs.gov/OilGas/AssessmentsData/

NationalOilGasAssessment/Methodology.aspx].

IHS Energy Group, 2010a [includes data current as of December 2010], PI/Dwights Plus US production data: IHS Energy 

Group, database available from IHS Energy Group, 15 

Inverness Way East, D205, Englewood, CO 80112.

IHS Energy Group, 2010b [includes data current as of December 2010], PI/Dwights Plus US well data: IHS Energy 

Group; database available from IHS Energy Group, 15 

Inverness Way East, D205, Englewood, CO 80112.

Klett, T.R., and Charpentier, R.R., 2003, FORSPAN model users 

guide: U.S. Geological Survey Open-File Report 03-354, 30 p. 

[available at http://energy.usgs.gov/OilGas/AssessmentsData/

NationalOilGasAssessment/Methodology.aspx].
20 Tabular Data and Graphical Images in Support of USGS National Oil and Gas Assessment—Anadarko Basin Province

Klett, T.R., Schmoker, J.W., and Charpentier, R.R., 2005, 

U.S. Geological Survey input-data form and operational 

procedure for the assessment of conventional petroleum 

accumulations, chap. 20, in USGS Southwestern Wyoming 

Province Assessment Team, eds., Petroleum systems and 

geologic assessment of oil and gas in the Southwestern Wyoming Province, Wyoming, Colorado, and Utah: U.S. Geological Survey Digital Data Series DDS–69–D, 7 p. [available at http://energy.usgs.gov/OilGas/AssessmentsData/

NationalOilGasAssessment/Methodology.aspx].

NRG Associates, 2009 [includes data current as of December 

2007], The significant oil and gas fields of the United States: 

NRG Associates, Inc., database available from NRG Associates, Inc., P.O. Box 1655, Colorado Springs, CO 80901.

Schmoker, J.W., and Klett, T.R., 2005, U.S. Geological Survey 

assessment concepts for conventional petroleum accumulations, chap. 19, in USGS Southwestern Wyoming Province 

Assessment Team, eds., Petroleum systems and geologic 

assessment of oil and gas in the Southwestern Wyoming 

Province, Wyoming, Colorado, and Utah: U.S. Geological Survey Digital Data Series DDS–69–D, 6 p. [available at http://energy.usgs.gov/OilGas/AssessmentsData/

NationalOilGasAssessment/Methodology.aspx].
Chapter 13

Precambrian to Ground Surface Grid Cell 

Maps and 3D Model of the Anadarko Basin 

Province

By Debra K. Higley, Nicholas J. Gianoutsos, Michael P. Pantea, and 

Sean M. Strickland

Chapter 13 of 13

Petroleum Systems and Assessment of Undiscovered Oil and Gas 

in the Anadarko Basin Province, Colorado, Kansas, Oklahoma, and 

Texas—USGS Province 58

Compiled by Debra K. Higley

U.S. Geological Survey Digital Data Series DDS–69–EE

U.S. Department of the Interior

U.S. Geological Survey

Click here to return to

Volume Title Page
U.S. Department of the Interior

SALLY JEWELL, Secretary

U.S. Geological Survey

Suzette M. Kimball, Acting Director

U.S. Geological Survey, Reston, Virginia: 2014

For more information on the USGS—the Federal source for science about the Earth, its natural and living 

resources, natural hazards, and the environment, visit http://www.usgs.gov or call 1–888–ASK–USGS.

For an overview of USGS information products, including maps, imagery, and publications, 

visit http://www.usgs.gov/pubprod

To order this and other USGS information products, visit http://store.usgs.gov

Any use of trade, firm, or product names is for descriptive purposes only and does not imply endorsement by the 

U.S. Government.

Although this information product, for the most part, is in the public domain, it also may contain copyrighted materials 

as noted in the text. Permission to reproduce copyrighted items must be secured from the copyright owner.

Suggested citation:

Higley, D.K., Gianoutsos, N.J., Pantea, M.P., and Strickland, S.M., 2014, Precambrian to ground surface grid cell maps 

and 3D model of the Anadarko Basin Province, chap. 13, in Higley, D.K., compiler, Petroleum systems and assessment 

of undiscovered oil and gas in the Anadarko Basin Province, Colorado, Kansas, Oklahoma, and Texas—USGS Province 

58: U.S. Geological Survey Digital Data Series DDS–69–EE, 8 p., http://dx.doi.org/10.3133/ds69EE.

ISSN 2327-638X (online)
iii

Contents

Introduction.....................................................................................................................................................1

Data Description and Processing Steps....................................................................................................4

Zmap-Format Grid Files.................................................................................................................................6

Standalone 3D Geologic Model Files .........................................................................................................6

Computer Requirements to View the 3D EarthVision® Geologic Model .............................................6

Acknowledgments.........................................................................................................................................6

References and Software Cited ..................................................................................................................7

Figures

1. Geographic extent of grid files as displayed by basement heat flow contours

across the Anadarko Basin Province based on data from Carter and others (1998),

Blackwell and Richards (2004), and data downloads from the Southern Methodist

University Web site (http://smu.edu/geothermal/). Basin areas north of the Wichita

Mountain uplift and in the Amarillo uplift and northward exhibit generally lower

heat flows than other basin areas. Highest measured heat flow is in the northwest,

along the Las Animas uplift. The northwest-trending Central Kansas uplift (CKU)

also exhibits elevated heat flow values. Heat flow units are milliwatts per square

meter (mW/m2). Precambrian faults (red lines) are from Adler and others (1971) ............3

2. View to the southeast showing the Woodford Shale layer and modeled lithofacies.

Vertical exaggeration is 18 times. Extent of the Woodford Shale is shown in white.

This PetroMod® image shows underlying and lateral formations and facies

changes for the Woodford Shale layer. The southern half of the Kansas portion

has almost 0 meter thickness and represents grid extrapolation from the Woodford

(Chattanooga) Shale east of the Central Kansas uplift (CKU) to the Woodford Shale

proximal to the Kansas-Oklahoma border. Lateral lithofacies are primarily

limestone and dolomite of the Viola Group. Because the purpose of this image is to

show lateral changes in formation and lithofacies assignments on a model layer,

this information is generalized in the legend and not all listed formations are

visible. Vertical yellow bars are Precambrian faults from Adler and others (1971) ..........5
iv

Tables

1. Two-dimensional grid file names, times intervals of deposition and erosion in

millions of years ago (Ma), and lithofacies assignments. [Grids represent the

highest elevation of the named unit relative to sea level. Lithofacies that were

assigned in the PetroMod® v. 11.3 software are included for archival purposes and

names are not defined, merely labeled with general terms. Lithology names that

are similar to layer names are custom lithofacies based on published distributions

of facies or compositions that are mainly derived from sources that include Adler

and others (1971), Denison and others (1984), Howery (1993), Ludvigson and others

(2009), and the National Geologic Map Database (2011,

http://ngmdb.usgs.gov/Geolex/)]................................................................................................2

2. Geographic coordinate information for the zmap-format two-dimensional grid files

is located in the ZmapFormatGridFiles folder. [All grid x and y dimensions are in

meters and the grid spacings are 1 kilometer. Grid size refers to the total number of

grid cells. Structure and erosional isopach grids z dimension is in feet relative to

sea level. Contour values for total organic carbon (TOC) are weight percent

carbon, and for basement heat flow are milliwatts per square meter (mW/m2)] ..............3
Precambrian to Ground Surface Grid Cell Maps and 3D 

Model of the Anadarko Basin Province

By Debra K. Higley, Nicholas J. Gianoutsos, Michael P. Pantea, and Sean M. Strickland

Introduction

The digital files listed in table 1 were compiled as part 

of the U.S. Geological Survey (USGS) 2010 assessment 

of the undiscovered oil and gas potential of the Anadarko 

Basin Province of western Oklahoma, western Kansas, 

northern Texas, and southeastern Colorado. This publication contains a three-dimensional (3D) geologic model that 

was constructed of two-dimensional (2D) structural surface 

grids across the province and Precambrian fault surfaces 

generated from Adler and others (1971). Also included are 

(1) 26 zmap-format structure grid files on Precambrian to 

present-day surfaces across the province; (2) estimated 

eroded thickness of strata following the Laramide orogeny 

and based on one-dimensional (1D) models and 1D extractions from the four-dimensional (4D) PetroMod® model 

(Schlumberger, 2011; Higley, 2014); (3) present-day weight 

percent total organic carbon (TOC) for the Woodford Shale 

based on TOC data from Burruss and Hatch (1989) and mean 

values from Hester and others (1990); and (4) basement heat 

flow contours (fig. 1) across the province based on data from 

Carter and others (1998), Blackwell and Richards (2004), 

and data downloads from the Southern Methodist University 

Web site (http://smu.edu/geothermal/).

The 3D geologic model and 2D grids were created using 

EarthVision® software [Dynamic Graphics Inc. (DGI), 2010] 

and grids were saved in zmap format. Lateral scales of the 

3D model and all grids are in meters, and vertical scales of 

the structure and eroded thickness grids and model are in 

feet. TOC grid values are weight percent (wt %) and the heat 

flow grid is milliwatts per square meter (mW/m2) (fig. 1). 

The age range represented by the stratigraphic intervals 

composing the grid files is 1,600 million years ago (Ma) to 

present day. File names and age ranges of deposition and 

erosion are listed in table 1. These time period assignments 

are generalized because of the lack of precise information 

regarding formation ages; there are no time overlaps because 

of modeling software requirements. 

Metadata associated with this publication are within the 

AnadarkoMetadata.xml, AnadarkoMetadata.doc, and AnadarkoMetadata.htm files. Included are information on the study 

area and the names of the zmap-format grid files, such as file 

name and type, geographic coordinates of the grids and 3D 

model (table 2), and background information on the files in 

this publication.
Table 1. Two-dimensional grid file names, times intervals of deposition and erosion in millions of years ago (Ma), and lithofacies assignments. [Grids represent the highest elevation of the named unit relative to sea level. Lithofacies that were assigned in the PetroMod® v. 11.3 software are included for archival purposes merely labeled with general terms. Lithology names that are similar to layer names are custom lithofacies based on published distributions of facies or compositions that are maiinclude Adler and others (1971), Denison and others (1984), Howery (1993), Ludvigson and others (2009), and the National Geologic Map Database (2011, http://ngmdb.usgs.g

Number Zmap file name Deposition age from (Ma) to (Ma) Erosion age from (Ma) to (Ma) Total petroleum system assignment Lithofacies va

Assigned in PetroMo

1 surfaceDEMft.DAT 1.83 1.8 1.8 0 Overburden rock Sandstone (typical) 2 OgallalaTft.DAT 5.3 1.83 0 0 Overburden rock Sandstone (clay poor) 3 CretaceousTft.DAT 250 33 33 5.3 Overburden rock Sandstone (clay rich) 4 PermianTft.DAT 255 252 252 250 Overburden rock Sandstone (subarkose, quartz rich) 5 BlaineTft.DAT 261 255 0 0 Seal rock Blaine (custom lithologies) 6 StoneCorralTft.DAT 266 261 0 0 Seal rock Limestone (shaly) 7 WellingtonTft.DAT 271 266 0 0 Seal rock Wellington (custom lithologies) 8 ChaseTft.DAT 285 271 0 0 Reservoir rock Limestone (shaly) 9 CouncilGroveTft.DAT 296 285 0 0 Reservoir rock Limestone (shaly) 10 WabaunseeTft.DAT 298.2 296 0 0 Reservoir rock Siltstone (organic lean) 11 HeebnerTTft.DAT 298.4 298.2 0 0 Seal rock Shale (organic lean, typical) 12 HeebnerBTft.DAT 298.5 298.4 0 0 Seal rock Siltstone (organic lean) 13 DouglasTft.DAT 304 298.5 0 0 Reservoir rock Sandstone (typical) 14 DesmoinesianTft.DAT 305.3 304 0 0 Reservoir rock Limestone (shaly) 15 CherokeeTft.DAT 308 305.3 0 0 Reservoir rock Limestone (shaly) 16 AtokanTft.DAT 310 308 0 0 Reservoir rock SHALEcarb 17 ThirteenFingerTft.DAT 311 310 0 0 Source rock Limestone (shaly) 18 MorrowTft.DAT 324 311 0 0 Reservoir, seal rock SHALEsilt, Sandstone (clay poor) 19 SpringerTft.DAT 354 330 330 324 Reservoir rock Limestone (shaly) 20 WoodfordTft.DAT 369 354 0 0 Source rock Woodford (custom lithologies) 21 HuntonTft.DAT 442 379 379 369 Reservoir rock Limestone (shaly), Dolomite (typical) 22 SylvanTft.DAT 445 442 0 0 Seal rock Shale (black) 23 ViolaTft.DAT 456 445 0 0 Reservoir rock Limestone (organic rich - typical), Do24 SimpsonTft.DAT 471 456 0 0 Reservoir, source rock SHALEsilt, Sandstone (quartzite, very 25 ArbuckleTft.DAT 520 476 0 0 Reservoir rock Limestone (organic rich - typical)26 PrecambrianTft.DAT 1,600 544 544 520 Underburden rock Granite (greater than 1,000 Ma old), R27 CreataceousErosionThickft.DAT 33 5.328 HeatFlow_mWm2.DAT29 WoodfordTOC.DAT
Introduction 3

Figure 1. Geographic extent of grid files as displayed by basement heat flow 

contours across the Anadarko Basin Province based on data from Carter 

and others (1998), Blackwell and Richards (2004), and data downloads from 

the Southern Methodist University Web site (http://smu.edu/geothermal/). 

Basin areas north of the Wichita Mountain uplift and in the Amarillo uplift and 

northward exhibit generally lower heat flows than other basin areas. Highest 

measured heat flow is in the northwest, along the Las Animas uplift. The 

northwest-trending Central Kansas uplift (CKU) also exhibits elevated heat flow 

values. Heat flow units are milliwatts per square meter (mW/m2). Precambrian 

faults (red lines) are from Adler and others (1971).

Table 2. Geographic coordinate information for the zmap-format two-dimensional grid files is located in the ZmapFormatGridFiles 

folder.

[All grid x and y dimensions are in meters and the grid spacings are 1 kilometer. Grid size refers to the total number of grid cells. Structure and erosional 

isopach grids z dimension is in feet relative to sea level. Contour values for total organic carbon (TOC) are weight percent carbon, and for basement heat flow 

are milliwatts per square meter (mW/m2)]

Geographic coordinate system Lambert Conformal Conic

World Geodetic System (WGS) WGS 84 ellipsoid 

First and second standard parallels (degrees, north) 35 38

Central meridian (degrees, west) 99

Latitude of origin (degrees, north) 35

Semi-major axis, Semi-minor axis 6378137 6356752.3142

False Northing, False easting 0 0

X and Y dimensions of grid files

Xminimum, Yminimum, grid cell size –400000.0000 –100000.0000 601

Xmaximum, Ymaximum, grid cell size 200000.0000 475000.0000 576

24

28

32

36

40

44

48

52

56

60

64

68

72

76

80

EXPLANATION

Heat Flow 

(mW/m2

)

103° 102° 101° 100° 99° 98° 97°

39°

38°

37°

36°

35°

COLORADO KANSAS NEW MEXICO

Las Animas arch

Wichita 

Mountain 

uplift

Amarillo uplift

OKLAHOMA

TEXAS

Arbuckle 

Mountains

Nemaha uplift

Figure 1, chapter 13

Central

Kansas

uplift

0 50 100 MILES

0 50 100 KILOMETERS
4 Precambrian to Ground Surface Grid Cell Maps and 3D Model of the Anadarko Basin Province

Data Description and Processing Steps

1. Elevation, thickness, and fault data sources for the 2D 

grids and 3D model include formation tops from more 

than 220 wells across the province, edited formation tops 

from IHS Energy (2009a, 2009b) and the Kansas Geological Survey (2010, http://www.kgs.ku.edu/PRS/petroDB.

html), and maps and data from Fay (1964), Adler and others (1971), Rascoe and Hyne (1987), Robbins and Keller 

(1992), Cederstrand and Becker (1998), Andrews (1999a, 

1999b, 2001), and Rottmann (2000a, 2000b). Sources 

of ground elevations for 2D grids were well records and 

digital elevation model (DEM) data. Locations of formation outcrops/subcrops were derived primarily from 

surface geologic maps of the region and Rascoe and Hyne 

(1987). Formation ages and lithologies are commonly 

generalized; sources of information include Adler and 

others (1971), Denison and others (1984), Howery (1993), 

Ludvigson and others (2009), and the National Geologic 

Map Database (2011, http://ngmdb.usgs.gov/Geolex/). 

2. Names and age ranges of formations change within and 

across the Anadarko Basin Province; consequently, data 

retrievals were based mainly on approximate age-equivalent units. Data files were edited using Environmental 

Systems Research Institute (ESRI) (2010) ArcMaptm and 

Dynamic Graphics, Inc. (2010) EarthVision® software 

to remove anomalies, examples of which include location errors and incorrect formation-top elevations. Maps 

generated with EarthVision® software were compared to 

published cross sections and maps, and anomalous surfaces were corrected by editing the scattered data files and 

regridding the files.

3. This chapter of the report contains fault trace and volume 

views of a standalone 3D geologic model of the study 

area. The model can be viewed and manipulated, and 

.jpg or .tiff images of user-defined views can be saved. 

Both a basic “getting started” and detailed help file were 

provided by Dynamic Graphics, Inc., and are in the 

3Dviewer_HelpFiles folder as aids to understanding the 

included 3D viewer. The included 3D viewer is designed 

to work with the Microsoft Windows operating system. 

The USGS has licensed from Dynamic Graphics, Inc., the 

rights to provide an encrypted model that allows the viewers to use the enclosed data sets and interpreted model. 

The license allows the USGS the service and rights to 

provide unlimited distribution. We designed this product 

to function from the DVD–ROM media but recommend 

that the necessary files be copied to a local hard drive for 

better performance. No additional installation programs 

are needed to view the model and datasets using the 

3D standalone viewer. Should there be error messages 

when starting the software that reference the Microsoft 

C++ libraries; selecting “OK” several times will start the 

software. The folder “bug fix” includes a possible fix for 

this error message problem and is provided as a courtesy 

by Dynamic Graphics, Inc. More information about the 

viewing software and EarthVision® may be obtained from 

Dynamic Graphics, Inc., at http://www.dgi.com/.

4. The extent and elevation of model layers in highly 

faulted and deformed areas is not well documented or 

constrained. For that reason, surfaces on and south of the 

Wichita Mountain and Amarillo uplifts should be considered erroneous. The modeling software requires all grids 

to extend to the map boundaries, even if the modeled 

strata are only present within a portion of the layer. The 

shallowest elevation of the immediately underlying surface is included for strata with limited geographic range. 

For example, the Woodford Shale is only located in the 

deep part of the Anadarko Basin of Texas and Oklahoma 

and in a portion east of the Central Kansas uplift (fig. 2), 

but the structure grid of this surface also includes Precambrian through Silurian “subcrops.” 

5. 2D grids downloadable from this publication and used 

to build the standalone 3D models were generated using 

the Dynamic Graphics, Inc. EarthVision® Briggs Biharmonic Spline algorithm. Horizontal scales are in meters. 

Coordinate information is provided in table 2, grid file 

headers, and the metadata files. The x and y grid spacing 

are both 1,000 meters. As many as 15 data values were 

evaluated from each grid node and a scattered data feedback algorithm follows each biharmonic iteration. These 

modeling steps result in the curvature of the surface being 

distributed between data points rather than concentrated 

at individual data points. This generates a more natural 

appearing modeled surface of the modeled grid nodes that 

accurately reflect the scattered data. Grids generated for 

this publication were not smoothed or filtered. More information on this process and software are available from 

Dynamic Graphics, Inc., at http://www.dgi.com. Volumes 

of units are defined and shown as the space between (1) 

two geologic surfaces, (2) geologic surfaces and fault 

planes, or (3) geologic surfaces and model extents. 

For the Earthvision® 3D model, faults were defined 

as extending from Precambrian basement to the ground 

surface. Due to modeling and time constraints, most 

intersecting faults were designated as vertical and thoroughgoing. Modeled faults were added sequentially as 

follows: (1) faults that cross the model, (2) faults that 

truncated other faults, and (3) faults to help show the 

basin geometry. Where data or details were missing, data 

points were extrapolated from known data points based 

on local thickness of modeled units or fault displacements. For example, if the only local data control for 

a surface was a contact on the geologic map, we used 

that X, Y, and Z value and calculated local overlying 

and (or) underlying z-surface-elevation values based on 

thickness. Some thickness and surface variations shown 

in the model may reflect additional small faulting or 

inherent uncertainties of defined picks from the data, but 
Data Description and Processing Steps 5

Figure 2. View to the southeast showing the Woodford Shale layer and modeled lithofacies. Vertical exaggeration is 18 times. Extent 

of the Woodford Shale is shown in white. This PetroMod® image shows underlying and lateral formations and facies changes for the 

Woodford Shale layer. The southern half of the Kansas portion has almost 0 meter thickness and represents grid extrapolation from the 

Woodford (Chattanooga) Shale east of the Central Kansas uplift (CKU) to the Woodford Shale proximal to the Kansas-Oklahoma border. 

Lateral lithofacies are primarily limestone and dolomite of the Viola Group. Because the purpose of this image is to show lateral changes 

in formation and lithofacies assignments on a model layer, this information is generalized in the legend and not all listed formations are 

visible. Vertical yellow bars are Precambrian faults from Adler and others (1971).

Figure 2. 

Ch. 13 

Woodford Shale

Sylvan Shale, sh

U. Simpson 

Group

L. Simpson 

Group

Arbuckle Group

lst, dolomite

Hunton Group lst, } dolomite

} Viola Group lst, 

shale, dolomite 

} Oil Creek Fm, sh

}

}

}

EXPLANATION

N

Wichita 

Mountain 

uplift

Nemaha uplift

Hugoton embayment

Amarillo uplift

CKU

OKLAHOMA

KANSAS

COLORADO

NEW MEXICO

are considered to be reasonable interpretations based on 

objective criteria in surface maps, lithological descriptions, and geophysical interpretations. 

The top of the Precambrian basement is the lowermost modeled unit and was used as a base for the deep 

fault structures in the 3D geologic model. This was necessary because the EarthVision® 3D modeling technique 

builds the geologic layers upward from the base, and fault 

displacement propagates vertically until other data are 

available or some model extent or boundary is reached. 

Geologic surface data were then edited proximal to the 

faults to generate clean fault scarps. This was necessary 

because converting grid files to X, Y, and Z data files commonly places data points on the fault scarps, which EarthVision® tries to interpret as geologic surfaces. This process 

and the associated 3D EarthVision® model were created 

subsequent to the PetroMod® zmap-format grid files in 

this publication, most of which have different terminations against the southern fault system. The PetroMod® 4D 

petroleum system model of the Anadarko Basin includes 

a modeled sequence of northward-stepping vertical faults 

along the Amarillo–Wichita Mountains uplift that are 

connected laterally at the tops and bases. Vertically curved 

faults are not an option with PetroMod®. 

6. Negative isopach values can be present in grid files in 

areas where data are lacking, in which case negative 

thickness values were replaced by zero or 2 meter thickness because of requirements of the EarthVision® and PetroMod® modeling software. Identical structural surfaces 
result in a mottled appearance in the EarthVison® 3D 

model because the software defines these intersections as 

a contact with a resulting black line. Grids were modified 

to exceed 1 foot in thickness in order to minimize identical surfaces. This process can result in the disappearance 

of units that are only a few feet thick.

Zmap-Format Grid Files

In table 1, names are listed for the 29 zmap-format 

grid files associated with this publication. Also included for 

archival purposes are PetroMod® model assignments of time 

periods of deposition and erosion, total petroleum system(s), 

and generalized lithofacies(s). Each PetroMod® structure grid 

contains at least one lithology but may have multiple assigned 

lithologies. These are represented by lateral changes in color 

within a model layer, such as is shown in figure 2. 

Zmap-format grids include file headers with (1) a 

comment section with original file names and locations, file 

creation date and time; and (2) original file name and folder, 

file type, grid spacing, and coordinate information. The file 

structure is a series of rows and columns with values listed 

for each grid cell. Included data and coordinates are incorporated in maps and models by using software that reads 

zmap-format files. Software programs are available to import 

and convert zmap-format files. These grid formats can be 

read by EarthVision®, ArcMap®, and PetroMod®, as well as 

other mapping and modeling software. Metadata are saved 

in text (.txt) and XML (.xml) formats, the latter of which is 

readable using ESRI ArcGIS® and some XML, WWW, and 

word-processing software.

Standalone 3D Geologic Model Files

There are three standalone EarthVision® 3D geologic models, which are opened by double-clicking on the 

open_viewer.bat file located within the 3DgeologicModel 

folder and then selecting one of the three “.faces” files below. 

Background information on PC requirements, loading, opening, viewing, and manipulating the models is located within 

the Demo3DViewer.pdf and QuickHelp.pdf files located in 

the 3Dviewer_HelpFiles. Because the standalone model uses 

considerable processing power, the 3DgeologicModel folder 

should be moved to a computer hard drive before opening the 

model. 

1. 5_3_11_hor.sliced.encn.faces—Model comprises the 26 

structural surfaces listed in table 1. Also displayed are 

vertical red bands that depict the Precambrian faults of 

Adler and others (1971).

2. 5_3_11_hor.sliced.fault.encn.faces—Precambrian fault 

traces are treated as vertical faults, as opposed to incorporating the structural dips of these complex fault systems.

3. 5_3_11_hor.sliced.surf.encn.faces—Within this model, 

the Precambrian fault traces (gray) are vertical and extrapolated across the model to intersect other fault systems. 

Computer Requirements to View the 3D 

EarthVision® Geologic Model

Windows® XP or Windows 7 Operating System

Graphics Card Recommendations

• An OpenGL capable graphics card with dedicated 

memory is required.

• We recommend the graphics card have at least 512MB 

of memory onboard.

• Some large monitors (30-inch or greater) require a 

dual-link DVI capable connector.

• DGI recommends graphics cards from the NVIDIA 

Quadro FX series (NVIDIA Quadro FX with at least 

512MB of memory) for use with its software.

Computer Processor Unit (CPU) Requirements

• Time to open, view, and manipulate a model is partially 

dependent on the processor speed of the PC CPU.

• Although most of DGI’s software does not currently 

take advantage of multiple CPUs⁄Cores, their presence will allow running more software simultaneously 

without impacting performance.

• CPUs designed for lower power solutions (UltraLow Voltage [ULV] or Consumer Ultra-Low Voltage 

[CULV]) are not recommended at this time as they are 

optimized for decreased power consumption, rather 

than performance.

Memory Requirements

• 4GB memory minimum

• For 32-bit systems, 4GB is recommended. This is the 

maximum amount of memory supported on 32-bit 

Windows XP Professional system. However, depending on the BIOS (basic input output system) and 

operating system settings, the user may only see 3GB 

or 3.5GB available.

6 Precambrian to Ground Surface Grid Cell Maps and 3D Model of the Anadarko Basin Province
References and Software Cited 7

Acknowledgments

This chapter of the report benefited from excellent technical reviews by Laura Biewick, Jennifer Eoff, and Gregory 

Gunther of the USGS. Gregory also generated the initial 

metadata associated with grid files in this chapter. 

References and Software Cited

Adler, F.J., Caplan, W.M., Carlson, M.P., Goebel, E.D., 

Henslee H.T., Hick, I.C., Larson, T.G., McCracken, M.H., 

Parker, M.C., Rascoe, G., Jr., Schramm, M.W., and Wells, 

J.S., 1971, Future petroleum provinces of the mid-continent, 

in Cram, I.H., ed., Future petroleum provinces of the United 

States—Their geology and potential: American Association 

of Petroleum Geologist Memoir 15, v. 2, p. 985–1120.

Andrews, R.D., 1999a, Map showing regional structure at the 

top of the Morrow Formation in the Anadarko Basin and 

shelf of Oklahoma: Oklahoma Geological Survey Special 

Publication 99–4, pl. 3.

Andrews, R.D., 1999b, Morrow gas play in the Anadarko 

Basin and shelf of Oklahoma: Oklahoma Geological Survey 

Special Publication 99–4, 133 p., 7 pl.

Andrews, R.D., 2001, Map showing regionlal (sic) structure at 

the top of the Springer Group in the Ardmore Basin, and the 

Anadarko Basin and shelf of Oklahoma: Oklahoma Geological Survey Special Publication 2001–1, pl. 5. 

Blackwell, D.D., and Richards, M., 2004, Geothermal map of 

North America: American Association of Petroleum Geologists, 1 sheet, scale 1:6,500,000.

Burruss, R.C., and Hatch, J.R., 1989, Geochemistry of oils and 

hydrocarbon source rocks, greater Anadarko Basin: Evidence 

for multiple sources of oils and long-distance oil migration, 

in Johnson, K.S., ed., Anadarko Basin symposium, 1988: 

Oklahoma Geological Survey Circular 90, p. 53–64.

Carter, L.S., Kelly, S.A., Blackwell, D.D., and Naeser, N.D., 

1998, Heat flow and thermal history of the Anadarko Basin, 

Oklahoma: American Association of Petroleum Geologists 

Bulletin, v. 82, no. 2, p. 291–316. 

Cederstrand, J.R., and Becker, M.F., 1998, Digital map of 

base of aquifer for the High Plains aquifer in parts of 

Colorado, Kansas, Nebraska, New Mexico, Oklahoma, 

South Dakota, Texas, and Wyoming: U.S. Geological 

Survey Open-File Report 98–393, digital data and metadata, accessed March 2011, at http://cohyst.dnr.ne.gov/

metadata/m001aqbs_99.html.

Dynamic Graphics, Inc., 2010, EarthVision software: Available from Dynamic Graphics, Inc., 1015 Atlantic Avenue, 

Alameda, CA 94501, accessed August 2010, at http://www.

dgi.com.

Environmental Systems Research Institute, 2010, Geographic 

Information Systems software; accessed November 2011, at 

http:www.esri.com/.

Fay, R.O., 1964, The Blaine and related formations of northwestern Oklahoma and southern Kansas: Oklahoma Geological Survey Bulletin 98, 238 p., 24 pl. 

Hester, T.C., Schmoker, J.W., and Sahl, H.L., 1990, Logderived regional source-rock characteristics of the Woodford Shale, Anadarko Basin, Oklahoma: U.S. Geological 

Survey Bulletin 1866-D, 38 p. 

Higley, D.K., 2014, Thermal maturation of petroleum source 

rocks in the Anadarko Basin Province, Colorado, Kansas, 

Oklahoma, and Texas, chap. 3, in Higley, D.K., comp, 

Petroleum systems and assessment of undiscovered oil and 

gas in the Anadarko Basin Province, Colorado, Kansas, 

Oklahoma, and Texas—USGS Province 58: U.S. Geological 

Survey Digital Data Series 69–EE, 53 p. 

Howery, S.D., 1993, A regional look at Hunton production in 

the Anadarko Basin, in Johnson, K.S., ed., Hunton Group 

core workshop and field trip: Oklahoma Geological Survey 

Special Publication 93-4, p. 77–81.

IHS Energy, 2009a, IHS energy well database: Unpublished 

database available from IHS Energy, 15 Inverness Way 

East, Englewood, CO 80112. 

IHS Energy, 2009b, GDS database: Unpublished geological data services database available from IHS Energy, 15 

Inverness Way East, Englewood, CO 80112. 

Kansas Geological Survey, 2010, downloadable formations 

tops and LAS well data: accessed April 2012, at http://www.

kgs.ku.edu/PRS/petroDB.html.

National Geologic Map Database, 2011, U.S. Geological 

Survey, accessed December 1, 2011, at http://ngmdb.usgs.

gov/Geolex/.

Rascoe, B., Jr., and Hyne, N.J., 1987, Petroleum geology of 

the midcontinent: Tulsa Geological Society Special Publication 3, 162 p.

Robbins, S.L., and Keller, G.R., 1992, Complete Bouguer 

and isostatic residual gravity maps of the Anadarko Basin, 

Wichita Mountains, and surrounding areas, Oklahoma, 

Kansas, Texas, and Colorado: U.S. Geological Survey 

Bulletin 1866–G, 11 p., 2 pls.
Rottmann, Kurt, 2000a, Structure map of Hunton Group in 

Oklahoma and Texas Panhandle: Oklahoma Geological 

Survey Special Publication 2000-2, pl. 3.

Rottmann, Kurt, 2000b, Isopach map of Woodford Shale in 

Oklahoma and Texas Panhandle: Oklahoma Geological 

Survey Special Publication 2002-2, pl. 2.

Schlumberger, 2011, PetroMod Basin and Petroleum Systems 

Modeling Software: IES GmbH, Ritterstrasser, 23, 52072 

Aachen, Germany, accessed January 2011, at http://www.

ies.de. Southern Methodist University: accessed August 

2011, at http://smu.edu/geothermal/.

8 Precambrian to Ground Surface Grid Cell Maps and 3D Model of the Anadarko Basin Province