U.S. Department of the Interior

U.S. Geological Survey

Digital Data Series DDS–69–U

National Assessment of Oil and Gas Project:

Total Petroleum Systems and Geologic Assessment of Oil 

and Gas Resources in the Powder River Basin Province, 

Wyoming and Montana
Total Petroleum Systems and Geologic 

Assessment of Oil and Gas Resources in 

the Powder River Basin Province, Wyoming 

and Montana

Chapter 1

Geologic Assessment of Undiscovered Oil and Gas in the 

Powder River Basin Province, Wyoming and Montana 

By Lawrence O. Anna

Chapter 2

Tabular Data and Graphical Images in Support of the 

U.S. Geological Survey National Oil and Gas Assessment—

Powder River Basin Province (5033)

By T.R. Klett and P.A. Le

Digital Data Series DDS–69–U

U.S. Department of the Interior

U.S. Geological Survey

National Assessment of Oil and Gas Project:
Geologic Assessment of Undiscovered 

Oil and Gas in the Powder River Basin 

Province, Wyoming and Montana

By Lawrence O. Anna

Chapter 1

Digital Data Series DDS–69–U

U.S. Department of the Interior

U.S. Geological Survey
U.S. Department of the Interior

KEN SALAZAR, Secretary

U.S. Geological Survey

Suzette M. Kimball, Acting Director

U.S. Geological Survey, Reston, Virginia: 2009

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reproduce any copyrighted materials contained within this report.

Suggested citation:

Lawrence O. Anna, 2009, Geologic assessment of undiscovered oil and gas in the Powder River Basin Province: U.S. 

Geological Survey Digital Data Series DDS–69–U, 93 p.
iii

Contents

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

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

Pennsylvanian-Permian Composite Total Petroleum System ...............................................................2

Petroleum Source Rocks.....................................................................................................................3

Source Rock Thermal Maturity ..........................................................................................................8

Hydrocarbon Migration........................................................................................................................9

Reservoir Rocks ....................................................................................................................................9

Minnelusa Formation..........................................................................................................................10

Tensleep Sandstone...........................................................................................................................14

Leo Formation......................................................................................................................................14

Traps and Seals...................................................................................................................................14

Mowry Total Petroleum System ...............................................................................................................17

Petroleum Source Rocks...................................................................................................................17

Source Rock Thermal Maturity ........................................................................................................18

Hydrocarbon Migration......................................................................................................................20

Reservoir Rocks ..................................................................................................................................21

Fall River–Lakota Sandstones ................................................................................................21

Muddy Sandstone .....................................................................................................................22

Traps and Seals...................................................................................................................................27

Mowry TPS as a Continuous Reservoir ..........................................................................................27

Niobrara Total Petroleum System.............................................................................................................28

Source Rocks.......................................................................................................................................28

Source Rock Thermal Maturity ........................................................................................................32

Hydrocarbon Migration......................................................................................................................32

Reservoir Rocks ..................................................................................................................................34

Frontier Formation......................................................................................................................34

Belle Fourche Member.............................................................................................................37

Emigrant Gap Member..............................................................................................................37

Wall Creek Sandstone Member ..............................................................................................37

Turner Sandy Member ..............................................................................................................37

Cody Shale ...........................................................................................................................................38

Shannon Sandstone Member..................................................................................................38

Sussex Sandstone Member.....................................................................................................38

Mesaverde Formation........................................................................................................................41

Parkman Sandstone Member..................................................................................................41

Teapot Sandstone Member......................................................................................................41

Lewis Shale..........................................................................................................................................42

Teckla Sandstone Member ......................................................................................................42

Traps and Seals...................................................................................................................................42

Niobrara Total Petroleum System as a Continuous Reservoir....................................................44

Paleozoic-Mesozoic Composite Total Petroleum System ...........................................................44

Petroleum Source Rocks...................................................................................................................47
iv

Source Rock Thermal Maturity ........................................................................................................48

Hydrocarbon Migration......................................................................................................................48

Reservoir Rocks ..................................................................................................................................49

Traps and Seals...................................................................................................................................49

Tertiary-Upper Cretaceous Coalbed Methane Total Petroleum System ...........................................49

Cretaceous Biogenic Gas Total Petroleum System ..............................................................................49

Assessment of Undiscovered Petroleum Resource ..............................................................................50

Assessment of Undiscovered Petroleum Resources in Conventional Assessment Units ..............52

Minnelusa-Tensleep-Leo Sandstone AU (50330501).....................................................................52

Fall River–Lakota Sandstones AU (50330201) .......................................................................53

Muddy Sandstone AU (50330202)............................................................................................53

Frontier-Turner Sandstones AU (50330301) ...........................................................................54

Sussex-Shannon Sandstones AU (50330302)........................................................................56

Mesaverde-Lewis Sandstones AU (50330303)......................................................................57

Basin Margin AU (50330601) ....................................................................................................58

Eastern Basin Margin Upper Fort Union Sandstone AU (50330101)..................................58

Conventional Assessment Summary...............................................................................................58

Assessment of Undiscovered Petroleum Resources in Continuous Assessment Units .................59

Mowry Continuous Oil AU (50330261)..............................................................................................59

Niobrara Continuous Oil AU (50330361) ..........................................................................................59

Shallow Continuous Biogenic Gas AU (50330461).........................................................................60

Assessment Summary........................................................................................................................61

Comparison of Results of 1995 and 2005 Assessments.........................................................................61

Acknowledgments.......................................................................................................................................61

References....................................................................................................................................................61

Appendixes ...................................................................................................................................................73
v

Figures

1. Map showing boundary of Powder River Basin Province.....................................................2

2. Generalized east-west cross section of Powder River Basin ..............................................3

3. Map showing structure contours of the Mowry Shale, Powder River Basin......................4

4. Generalized diagram showing major structural elements that border the Powder 

River Basin............................................................................................................................................5

5. Map showing Minnelusa-Tensleep-Leo Assessment Unit boundary 

and hydrocarbon production locations.....................................................................................6

6. Stratigraphic column of Pennsylvanian and Permian strata in the Powder 

 River Basin and central Wyoming .............................................................................................7

7. Map showing the general location of the Phosphoria Formation, including

the Meade Peak and Retort Phosphatic Shale Members .....................................................8

8. Events chart for the Minnelusa-Leo-Tensleep Assessment Unit (AU), 

Pennsylvanian-Permian Composite Total Petroleum System (TPS) ................................... 10

9. Generalized paleogeography of late Minnelusa time in parts of the 

Powder River Basin and adjacent areas. ..............................................................................11

10. Southwest-northeast cross section of Permian strata in the Powder River Basin...... link

11. Diagram showing a time slice of generalized environments of deposition that 

comprise strata of the Minnelusa Formation in the Powder River Basin .........................12

12. Diagram showing correlation of a geophysical log to a Minnelusa Formation 

depositional cycle.......................................................................................................................13

13. Generalized stratigraphic section of Minnelusa Formation A, B, and C zones................ 15

14. Map showing Minnelusa Formation production fairway and outlying fields in 

the Powder River Basin, Wyoming.............................................................................................. 16

15. Stratigraphic column and succession intervals of Lower Cretaceous strata in 

the Powder River Basin including identification of the Mowry Total Petroleum 

System................................................................................................................................................. 18

16. Map of Powder River Basin showing Lower Cretaceous production, 

including production from Fall River–Lakota Sandstones Assessment 

Unit and Muddy Sandstone Assessment Unit .......................................................................19

17. Core and outcrop vertical sections showing Mowry Shale total organic 

carbon values (Corg [%]) near Douglas, Wyoming .................................................................20

18. Burial history curve for east side of the Powder River Basin based on combined 

input and calibration data from several locations................................................................... 21

19. Burial history curve for west side of the Powder River Basin based on combined 

input and calibration data from several locations................................................................... 22

20. Map of Powder River Basin Province showing Lower Cretaceous production.............. 23

21. Maps of Powder River Basin Province showing Lower Cretaceous production;

 A, Average API gravity, and B, average gas/oil ratio............................................................. 24

22. Events chart for Fall River–Lakota Sandstone and Muddy Sandstone 

Assessment Units............................................................................................................................. 26

23. Map showing relation between Fall River Sandstone delta system and Fall 

River production at Buck Draw field, Powder River Basin, Wyoming................................ 27

24. Generalized cross section of Muddy Sandstone depositional environments and 

successions in the Powder River Basin (PRB)......................................................................... 28

25. Cross sections of Muddy Sandstone interval, Sand Dunes field, 

Powder River Basin................................................................................................................. link
vi

26. Map of Powder River Basin Province showing Mowry Shale potential sweet 

spots derived from the congregation of published lineament and lineament 

zones, and current production from the Mowry Shale, Powder River Basin...................29

27. Stratigraphic column of Upper Cretaceous strata in the Powder River Basin (PRB) .... 30

28. Map showing Upper Cretaceous oil and gas production, area where depth 

to Niobrara Formation is greater than 8,000 feet, and boundaries of assessment 

units (AU) within the Niobrara Total Petroleum System in the Powder River 

Basin Province ............................................................................................................................31

29. Events chart for assessment units (AU) in the Niobrara Total Petroleum 

System (TPS) in the Powder River Basin, Wyoming. (A) Frontier-Turner 

Sandstones Assessment Unit; (B) Sussex-Shannon Sandstones Assessment 

Unit; and (C) Mesaverde-Lewis Sandstones Assessment Unit ..........................................33

30. Map of Powder River Basin Province showing Upper Cretaceous production, 

area where depth to Niobrara Formation is greater than 8,000 feet. (A) average 

API gravity for Upper Cretaceous fields; (B) average gas oil ratio (GOR) for Upper 

Cretaceous fields ............................................................................................................................. 35

31. West-east cross section of the Frontier Formation and Turner Sandy Member

interval, Powder River Basin ................................................................................................. link

32. Map of Powder River Basin Province showing Sussex Sandstone Member 

oil and gas production, Sussex-Shannon Sandstones Assessment Unit 

(AU) boundary, and area where depth to Niobrara Formation 

is more than 8,000 feet...............................................................................................................39

33. Map of Powder River Basin Province showing Shannon Sandstone Member 

oil and gas production, Sussex-Shannon Sandstone Assessment Unit 

(AU) boundary, and area where depth to Niobrara Formation is more 

than 8,000 feet .............................................................................................................................40

34. Generalized cross section showing generalized facies distribution of the 

Sussex “B” sandstone, Powder River Basin ............................................................................ 41

35. Map of Powder River Basin Province showing oil and gas production of Parkman 

Sandstone and Teapot Sandstone Members of Mesaverde Formation and 

Teckla Sandstone Member of Lewis Shale of the Mesaverde-Lewis Conventional 

Oil and Gas Assessment Unit (AU), and the area where depth to Niobrara 

Formation is more than 8,000 feet. ............................................................................................... 43

36. Map of the Powder River Basin Province showing Niobrara Formation 

potential sweet spots derived from published lineament and lineament 

zones, and current production from the Niobrara Formation............................................... 45

37. Map of the Powder River Basin Province showing oil and gas production 

and boundary of the Basin Margin Assessment Unit (AU).................................................... 46

38. Generalized cross section of basin margin thrusting showing structural 

positions of Basin Margin Assessment Unit (AU) and adjacent assessment 

units...............................................................................................................................................47

39. Chart comparing sulfur and gravity values of Powder River Basin oil reservoirs .......... 48

40. Events chart of the Basin Margin Assessment Unit (AU) of the 

Paleozoic-Mesozoic Composite Total Petroleum System (TPS) 

showing multiple reservoirs, sources, and seals..................................................................50

41. Map of the Powder River Basin showing oil and gas production of Frontier 

Formation and Turner Sandy Member of the Carlile Shale .................................................55
vii

Table

1. Powder River Basin Province assessment results ...............................................................51

Abstract

The U.S. Geological Survey completed an assessment 

of the undiscovered oil and gas potential of the Powder River 

Basin in 2006. The assessment of undiscovered oil and gas 

used the total petroleum system concept, which includes 

mapping the distribution of potential source rocks and known 

petroleum accumulations and determining the timing of 

petroleum generation and migration. Geologically based, it 

focuses on source and reservoir rock stratigraphy, timing of 

tectonic events and the configuration of resulting structures, 

formation of traps and seals, and burial history modeling. The 

total petroleum system is subdivided into assessment units 

based on similar geologic characteristics and accumulation 

and petroleum type. For the Powder River Basin Province, 

five total petroleum systems, eight conventional assessment 

units, and three continuous assessment units were defined and 

the undiscovered oil and gas resources within each assessment 

unit quantitatively estimated. 

Introduction

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

quantitative estimate of the undiscovered oil and gas potential 

of the Powder River Basin (PRB) Province of northeastern 

Wyoming, southeastern Montana, and southwestern South 

Dakota in 2006 (fig. 1). The assessment of the province 

was based on geologic principles and applied the total 

petroleum system (TPS) concept. The TPS consists of one 

or more assessment units (AU), the basic geologic unit that 

is assessed. An AU is a mappable part of a petroleum system 

in which discovered and undiscovered fields constitute a 

single, relatively homogeneous population. The assessment 

methodology was based on the simulation of the number and 

sizes of undiscovered fields. The TPS includes all genetically 

related petroleum within a limited mappable geologic space, 

along with other essential mappable geologic elements 

(reservoir, seal, and overburden rocks) that control the 

fundamental processes of generation, expulsion, migration, 

entrapment, and preservation of petroleum (Magoon and 

Dow, 1994). A TPS may equate to a single AU, or it may be 

subdivided into two or more AUs to assess individually if 

each unit is sufficiently homogeneous in terms of geology, 

exploration considerations, and geologic risk. Using this 

geologic framework, the USGS (1) defined five TPSs 

and eight conventional AUs, and three continuous (or 

unconventional) AUs in the PRB; and (2) quantitatively 

estimated the undiscovered oil and gas resources in each. The 

TPSs, AUs, and resource assessments are described in detail 

herein. 

An integral part of TPS and AU descriptions is an events 

chart that graphically portrays its temporal evolution. The 

principal components are (1) the intervals of time during 

which source, reservoir, and seal rocks were deposited; (2) 

the timing of hydrocarbon generation, migration, and accumulation; and (3) the period of time during which traps were 

formed. Such charts accompany each of the AU descriptions. 

The PRB, located in northeastern Wyoming and southeastern Montana, developed during the Laramide orogeny 

similar to other Rocky Mountain foreland structural basins. 

The basin is asymmetric with the axis on the west side (fig. 2). 

The deepest part can be 17,000 ft or more to the top of the 

Precambrian basement. On the east flank, regional dip is about 

100 ft/mi to the west but increases to about 500 ft/mi along 

the west limb of the Black Hills monocline; on the west flank, 

regional dip is about 500 ft/mi but decreases to less than 

50 ft/mi north of the Wyoming-Montana border (figs. 1 and 3). 

The boundaries of the basin are delineated by several 

uplifts including the Black Hills to the east (including the 

Fanny Peak monocline), the Hartville uplift and Laramie 

Range to the south, the Casper arch, Bighorn Mountains, and 

the Hardin platform on the west, and the Miles City arch, Bull 

Mountains, and Porcupine dome on the north (fig. 4). Except 

for the broad arching structures, most basin bounding features 

are hydrologic as well as structural boundaries. The province 

boundary was originally defined in the 1995 assessment of the 

PRB (Dolton and Fox, 1995) and was drawn on county lines 

that most closely followed geologic or basin boundaries. 

In the PRB, numerous structures now observed at the 

surface originated as faults, shear zones, or zones of weakness in the basement rocks during Precambrian time and were 

rejuvenated during the Laramide orogeny, and by periodic 

recurrent movement throughout the Phanerozoic. In the 

PRB, most structures are oriented northwest-southeast and 

Geologic Assessment of Undiscovered Oil and Gas in the 

Powder River Basin Province, Wyoming and Montana

By Lawrence O. Anna
2 Geologic Assessment of Undiscovered Oil and Gas in the Powder River Basin Province, Wyoming and Montana

Figure 1. Map showing boundary of Powder River Basin Province in Wyoming and Montana. Province 

boundary is shown as heavy blue line.

northeast‐southwest, trends that probably influenced local 

and regional sedimentation patterns (Anna, 1986a, b). For 

example, the location of the shoreline during deposition of 

the Upper Minnelusa Sandstone was parallel to northeastsouthwest-trending normal faults, with the downthrown side 

to the southeast toward an open sea. Upper Minnelusa oil 

fields are generally aligned with the prevailing trend, thereby 

reflecting the structural control on the orientation of reservoir 

rock deposition. The same structures also influenced drainage 

patterns on erosional surfaces during deposition of Cretaceous 

reservoirs.

Pennsylvanian-Permian Composite 

Total Petroleum System 

The boundary of the Pennsylvanian-Permian Composite 

TPS (fig. 5) was determined from current and projected oil and 

gas production areas of the Minnelusa Formation, Tensleep 

Sandstone, and Leo Formation reservoirs within the interior 

of the basin (excluding the basin margin, which is a separate 

AU). Hydrocarbon source rock for these reservoirs is interpreted to be the Phosphoria Formation in western and central 

109° W 108° W 107° W 106° W 105° W 104° W 103° W

46° N

45° N

44° N

43° N

42° N

Billings 

Sheridan 

Gillette 

Casper 

MONTANA 

WYOMING 

NEBRASKA 

SOUTH 

DAKOTA 

NORTH 

DAKOTA 

CANADA

94

ND MT

WY

ID

UT CO

SD

NE

KS

90

25

90

Powder River Basin

Province

90

0 20 40 MILES

0 30 60 KILOMETERS
Pennsylvanian-Permian Composite Total Petroleum System 3

Figure 2. Generalized east-west cross section of Powder River Basin showing a west side basin axis. Black Hills monocline is 

shown in Cretaceous and Paleozoic rocks on east side of basin. 

Wyoming and black shales of the Leo Formation in the southeast part of the basin. Because the pod of mature Phosphoria 

source rock is west of the PRB province, it is not included as 

part of this TPS. 

Oil seeps were observed in Minnelusa Formation outcrops on the northwestern flank of the Black Hills uplift in the 

early 1900s. Subsequent drilling downdip from outcrops in 

1906 established the first Minnelusa field (Rocky Ford), but it 

was soon abandoned. Since the initial discovery, exploration 

focused on structural closures near the Black Hills monocline 

and other surface exposed Laramide structures. In the 1940s 

and 1950s, seismic profiles helped expand exploration for 

deep structures not exposed at the surface. As the hunt for new 

structures declined, exploration for Minnelusa stratigraphic 

traps increased—a strategy that continues today.

The Minnelusa Formation, a name that was originally 

applied to Pennsylvanian and Lower Permian rocks in the 

Black Hills (fig. 6), is also applied to equivalent strata in the 

PRB and in parts of the Williston Basin. The Amsden Formation is applied to the Lower Pennsylvanian, and Tensleep 

Sandstone is applied to the Upper Pennsylvanian and Lower 

Permian in central, west, and northwestern Wyoming (fig. 6). 

These names generally have not been extended eastward into 

the PRB subsurface except along the west flank immediately 

adjacent to the Bighorn Mountain front.

Petroleum Source Rocks

It has long been established that the Phosphoria Formation generated considerable amounts of hydrocarbons 

that were trapped in numerous Paleozoic reservoirs in the 

north-central Rocky Mountains (for example, see Cheney and 

Sheldon, 1959; Sheldon, 1967; Claypool and others, 1978; 

Maughan, 1984), including the Minnelusa Formation and 

Tensleep Sandstone in the PRB (fig. 6). Although alternative 

sources of oil in Minnelusa and Tensleep reservoirs in the PRB 

have been proposed (William Barbat, consultant, written commun., 1983), most agree that the Phosphoria is the main source 

of oil, based on published geochemical evidence. Alternative 

hypotheses to long range migration include (1) locally derived 

oil from shales of the lower and middle parts of the Minnelusa 

Formation and (2) oil generation from organic-rich sabkhas 

and supratidal rocks contiguous to sandstone beds of the upper 

Minnelusa. 

The Phosphoria Formation was deposited in a large, relatively shallow epicontinental embayment (called the Sublette 

Basin by Maughan, 1979) in what is now southern Idaho, 

southwestern Montana, western Wyoming, northwestern 

Colorado, northern Utah, and northeastern Nevada. The area 

consisted of a basin and slope surrounded on three sides by a 

carbonate platform. The basin and slope were covered by the 

Phosphoria sea in which were deposited phosphatic-rich beds 

of the Phosphoria; the Park City Formation, on the carbonate platform, consisted mostly of shelf carbonates. Several 

eustatic sea-level changes induced marine transgressions and 

regressions, forming complex depositional cycles resulting 

in interbedded strata of the Phosphoria and Park City Formations. The basin is interpreted to have covered about 100,000 

mi2

 and to have had a maximum water depth of more than 800 

ft (Maughan, 1984). 

Maximum extent of the Phosphoria Formation and of 

the Phosphoria sea (fig. 7) is reflected by the distribution 

of the lower Meade Peak Phosphatic Shale Member and 

0

Horizontal scale

0 20 MILES

Precambrian

Tertiary

Lower Cretaceous

Paleozoic

Upper Cretaceous

0

15

10

5

DEPTH (FEET, IN THOUSANDS)

Black Hills

Bighorn Mountains

Casper arch

Powder River Basin

fault

fault

West East
4 Geologic Assessment of Undiscovered Oil and Gas in the Powder River Basin Province, Wyoming and Montana

Figure 3. Map showing structure contours on top of Mowry Shale, Powder River Basin. Light gray lines are county lines. 

Contour interval is 2,000 feet. Basin bounding faults are not shown. Elevation data from IHS Energy Group, 2006. Province 5033 

refers to code number assigned to Powder River Basin Province.

4000

2000

2000

–2000

2000 – 

000,2

2000

–2000

–2000

–4000

–2000

6000 –

2000

–8000

–6000

–6000

4000 –

–4000

–2000

EXPLANATION

Contour

Counties

Province 5033

0 

0

0 

Contour interval is 2000 feet
Pennsylvanian-Permian Composite Total Petroleum System 5

Figure 4. Generalized diagram showing major structural elements that border the Powder River Basin. Modified 

from Shurr and others (1988).

the upper Retort Phosphatic Shale Member. Both members 

are interpreted to be the main oil generation intervals in the 

Phosphoria. 

The Meade Peak Phosphatic Shale and the Retort 

Phosphatic Shale Members were deposited in cold, nutrientrich, oceanic water from the Cordilleran sea that upwelled into 

the relatively shallow Sublett Basin. The shale was enriched 

in phosphorite, possibly from a volcanic source to the west, 

which supported high organic productivity from the process 

of phosphogenesis (Johnson, 2003; Saltzman, 2003, describes 

the phosphogenesis process). As a result, the Meade Peak 

and Retort members have an average maximum total organic 

carbon (TOC) content of about 10 weight percent, and in 

the organically richest beds, as high as 30 weight percent 

(Maughan, 1984). 

The Phosphoria Formation is generally considered 

to contain Type II organic matter that was incorporated in 

sediment that was deposited in a marine environment. Analysis 

of a single sample of the Retort member collected at its type 

locality in southwestern Montana indicates Type II organic 

matter (Lewan, 1985). The Phosphoria also generates oil with 

a high sulfur content that averages 2.1 weight percent (NRG 

Associates, 2006), a parameter that commonly distinguishes 

Phosphoria oil from low-sulfur Cretaceous oil. 

Source rocks for oil in Leo Formation reservoirs in 

the southeastern part of the PRB are interpreted to originate 

locally and are interbedded with limestone and intertidal and 

eolian siliciclastics (Desmond and others, 1984; Ahlbrandt 

and others, 1994). TOC values range from less than 1 to 30 

percent and average 5.5 percent (Ahlbrandt and others, 1994). 

Laramie Range 

Hartville Uplift 

Black Hills uplift 

Porcupine 

 dome 

Bull Mountains 

Hardin 

platform 

Casper 

arch 

Powder 

 

 River 

 

 Basin 

Cedar Creek anticline 

Williston 

 Basin 

North Dakota 

South Dakota 

Wyoming 

Montana 

Chadron arch 

Denver 

 Basin 

Nebraska 

Belle Fourche arch 
6 Geologic Assessment of Undiscovered Oil and Gas in the Powder River Basin Province, Wyoming and Montana

Figure 5. Map of Powder River Basin Province 5033 showing Minnelusa-Tensleep-Leo Assessment Unit (AU) 

boundary and hydrocarbon production. TPS, total petroleum system.

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Johnson 

Campbell 

Big Horn 

Crook 

Converse 

Weston 

Niobrara 

Sheridan 

Natrona 

Powder River 

Rosebud 

 

 

TPS and AU boundary

EXPLANATION

Minnelusa and Tensleep 

Formations, and Leo 

Sandstone production

Province 5033 boundary
Pennsylvanian-Permian Composite Total Petroleum System 7

Figure 6. Stratigraphic column of Pennsylvanian and Permian strata in the Powder River Basin and 

central Wyoming. A–E units in upper part of the Minnelusa Formation are of informal usage. Gray pattern 

represents carbonate beds that separate units A–E. Fm, Formation; Sh, shale; TPS, total petroleum system; 

Ls, limestone; Mbr, member. 

Phosphoria 

 Fm 

Retort Tongue 

Park City Fm 

Meade Peak 

Member 

Madison Limestone 

Guadalupian 

Ervay Ls Mbr of the Goose Egg Fm 

Powder River Basin 

NORTHERN

AREA

SOUTHERN

AREA

CENTRAL 

WYOMING 

Minnekahta Limestone 

AGE

Leonard 

Wolfcamp 

Virgil 

Missouri 

Des Moines 

Atoka 

Morrow 

MississUpper Member Middle Member Lower Member 

Opeche Sh Opeche Sh 

A 

B

C 

D 

E 

Mostly 

Carbonates 

and 

Shales 

Mostly 

Carbonates 

and 

Shales 

Carbonates 

and 

Shales 

Carbonates 

and 

Shales 

Mostly 

Carbonates 

and 

Shales 

Tensleep Sandstone 

Bell sand 

Amsden Formation 

Red Shale Marker 

Leo sandstones 

Lower Member Leo Formation Upper Member 

ippian Pennsylvanian Permian PERIOD

Minnelusa Formation Minnelusa Formation Minnelusa Formation 
8 Geologic Assessment of Undiscovered Oil and Gas in the Powder River Basin Province, Wyoming and Montana

Figure 7. Map showing general location of the Phosphoria Formation deposition, including Meade Peak and 

Retort Phosphatic Shale Members in relation to the Powder River Basin. Mbr, member Modified from Maughan 

(1984).

Characteristics of Leo oil include 20° to 40° API gravity, 

varying amounts of hydrogen sulfide (H2

S) gas which can 

be as much as 40 percent, and low sulfur content (NRG 

Associates, 2006). The latter two constituents distinguish Leo 

oil from Phosphoria oil. 

Source Rock Thermal Maturity

As part of the USGS oil and gas assessment of 

southwestern Wyoming, Nuccio and Roberts (2003) 

constructed burial-history curves for several locations. The 

modeled sites were calibrated with vitrinite reflectance (Ro

) 

data from Cretaceous shales (sampled by Pawlewicz and Finn, 

2002), whereby Phosphoria Formation oil generation results 

were projected from the calibrated burial curves. Results show 

that Phosphoria source rocks passed through the oil generation 

window no earlier than 88 Ma in the mid-Late Cretaceous. 

According to Claypool and others (1978), hydrocarbon 

generation began in most areas of the former Sublette Basin 

when the Meade Peak Phosphatic Shale and the Retort 

Phosphatic Shale Members exceeded a burial depth of about 

6,560 ft. Maughan (1984) reported that numerous samples 

collected from the Meade Peak had Ro

 measurements 

greater than 1.35 weight percent, indicating that most of the 

Phosphoria Formation has undergone complete transformation 

of kerogen to hydrocarbons. Maughan (1984) also reported 

that in some areas in the northwestern part of the former 

Sublette Basin the Meade Peak was immature, however, 

most of the Meade Peak in central Wyoming is considered 

mature. According to Maughan (1984), an increase in ambient 

temperature of the Meade Peak and Retort Members in the 

Overthrust Belt of western Wyoming and eastern Idaho 

resulting from thrust loading probably did not significantly 

increase hydrocarbon generation. 

Phosphoria Formation

Meade Pk Phosphatic 

Shale Mbr (lower)

Retort Phosphatic 

Shale Mbr (upper)

Powder

 River

 Basin 
Pennsylvanian-Permian Composite Total Petroleum System 9

Many workers who have studied hydrocarbon generation 

in the Phosphoria Formation (for example, Sheldon [1967]; 

Stone [1967]; Claypool and others [1978]; Momper and 

Williams [1984]; and Burtner and Nigrini [1994]) reported that 

migration into the Weber and Tensleep Sandstones in western 

and central Wyoming took place during the Late Jurassic and 

Early Cretaceous. Fryberger and Koelmel (1986) interpreted 

Phosphoria-sourced oil to have migrated into the Weber in 

northwestern Colorado during the Early Cretaceous, and Britt 

and Howard (1982) concluded that in central Utah, Phosphoria 

oil began migrating during the middle part of the Cretaceous.

Based on the many contributions to the study of the 

maturation history of the Phosphoria Formation in this region, 

Johnson (2003) reported that Phosphoria source rocks in 

southeastern Idaho, where early Mesozoic overburden was the 

thickest, probably started generating oil at the beginning of 

the Early Cretaceous (based primarily on the work of Claypool and others, 1978). In the area of the Greater Green River 

Basin, Phosphoria source rocks were apparently not buried 

to a depth that would generate oil until the Late Cretaceous 

(based primarily on the work of Claypool and others, 1978; 

Roberts and others, 2003). Even though the earliest maturation of Phosphoria oil was in southeastern Idaho, Phosphoria 

oil from this area could have migrated eastward into central 

Wyoming and beyond. 

Hydrocarbon Migration

Timing of migration of Minnelusa oil is an enigma, but 

Early to Late Cretaceous is most probable. Sevier orogeny 

thrusting during Early to middle Cretaceous in Idaho and Utah 

(Maughan, 1984) could have initiated eastward groundwater 

movement and oil migration similar to processes developed along thrust fronts in the Arkoma foreland basin and 

the Western Canadian Basin (Ge and Garven, 1992, 1994), 

respectively. This eastward movement could have also transported hydrocarbons to the PRB (Barbat, 1967) until intervening structures generated during the late Laramide orogeny 

changed hydraulic gradients and diverted flow paths away 

from the PRB.

Regional isopach maps of Middle Permian to Upper 

Jurassic strata show north-south to northwest-southeast 

orientations, indicating a structural trend in those directions. 

Isopach maps of Lower Cretaceous rocks, however, show a 

shift to east-west and northeast-southwest orientations. Therefore, in Early Cretaceous time the east to northeast direction 

may have been a conduit for oil migration for Phosphoria 

Formation oil into the PRB along the Belle Fourche arch 

(Slack, 1981). The oil may have migrated into the Minnelusa 

C, D, and E sands (Tensleep Sandstone equivalents, fig. 6) 

but migrated later into Minnelusa A and B sands. Some of the 

oil may have escaped to the surface or continued east past the 

present-day Black Hills, although evidence for that is lacking 

(Moore, 1986).

A geologic events chart (fig. 8) shows the elements that 

define the Minnelusa-Tensleep-Leo AU. 

Reservoir Rocks

Reservoir rocks in the Pennsylvanian-Permian Composite 

TPS are in the Minnelusa and Leo Formations and Tensleep 

Sandstone. They are combined because of their similar ages, 

lithologic characteristics, and production histories.

Pennsylvanian and Permian rocks in the PRB and 

adjacent areas can be divided into four unconformable 

depositional successions, two in each system (fig. 6). The 

Lower Pennsylvanian succession comprises sediments that 

record a transgression onto the continental shelf following 

differential epeirogenic uplift at the end of Mississippian 

(Chesterian) time. An epeirogenic disturbance in middle 

to late Atokan time interrupted deposition, developed an 

unconformity, and initiated the spread of fine‐grained sand 

from a distant northwestern provenance. Another epeirogenic 

disturbance near the end of the Pennsylvanian into the Early 

Permian brought uplift in central Montana and southward 

through central Wyoming into north-central Colorado. 

The Lower Permian succession is composed of sandstone, 

carbonate, and evaporites deposited in an intracratonic 

basin east of this uplift. The Upper Permian is characterized 

by several transgressions across central Wyoming, during 

which sabkha, intertidal, and shallow subtidal-deposited red 

mudstone and evaporitic rocks were deposited in eastern 

Wyoming and adjacent areas (fig. 9).

Near Mayoworth, Wyoming, on the southwest flank of 

the basin, sandy dolomite beds that contain Wolfcampian 

fusulinids have been included in the Tensleep Sandstone 

(Verville, 1957). However, these strata lie unconformably 

above thick-bedded, massive to high-angle, cross-stratified 

sandstone typical of the Tensleep; lithologically, they resemble 

the Minnelusa and are assigned to the upper parts of the 

Minnelusa Formation (Verville, 1957). Equivalent strata of 

similar lithology are present in the upper part of the Casper 

Formation in the Laramie Range.

During the Permian, a shallow open sea existed southeast of the PRB at which intertidal and sabkha successions 

were deposited in the basin. The shoreline throughout the 

Early Permian frequently shifted positions in response to 

regional and local tectonism and to eustatic changes in sea 

level (fig. 9). These shoreline shifts gave rise to vertical cyclic 

sedimentation packages (or genetic units) informally defined 

as the A, B, C, D, and E zones of the upper member of the 

Minnelusa Formation (fig. 6; see next section). The shoreline 

probably extended to the northeast beyond the current Black 

Hills as well as to the southwest beyond the Casper arch 

(fig. 8). Following deposition of the upper A zone, a surface of 

erosion developed from a sea-level drop that eroded parts of 

the A and B zones (fig. 10).

Dolomites and evaporites of the A, B, and C zones 

of the Upper Minnelusa formed in a shallowing-upward 
10 Geologic Assessment of Undiscovered Oil and Gas in the Powder River Basin Province, Wyoming and Montana

Figure 8. Events chart for the Minnelusa-Tensleep-Leo Assessment Unit (AU), Pennsylvanian-Permian Composite Total 

Petroleum System (TPS). Geologic time scale is in millions of years ago. E, early; M, middle; L, late; Plio, Pliocene; Mio, 

Miocene; Eoc, Eocene; Olig, Oligocene; Pal, Paleocene. 

succession of intertidal and supratidal (sabkha) environments 

as regression of the sea continued to the southeast. Ensuing 

subaerial conditions resulted in the deposition of eolian 

sediments over the evaporite succession (fig. 11). The sea 

then transgressed rapidly to the northwest, depositing various 

assortments of limestone (which was diagenetically altered 

to dolomite), completing the depositional cycle. When the 

sea transgressed, the tops of the eolian deposits probably 

were reworked, preserving well sorted, high-porosity sands 

in topographically low areas. In addition, groundwater, which 

was oversaturated with cement-forming constituents, rose in 

fine-grained sand, but less so in coarse-grained sand due to 

capillary pressure creating vertical stratification of porosity. 

Therefore, in general, the upper parts of the A, B, and C sands 

are more porous and permeable than lower parts. In addition, 

freshwater may have flushed cements from the tops of zones. 

As the Permian sea withdrew from the PRB, incised 

northwest-southeast drainage patterns developed on the Minnelusa surface. The incisement process eroded as much as 

100 ft of the Minnelusa and to greater depths south and west 

of the main production fairway (fig. 10). Subsequently, a 

saline pan system consisting of lacustrine, alluvial, and evaporite deposits developed over most of the PRB and adjacent 

areas depositing the Opeche Shale (Benison and Goldstein, 

2000). Conglomerates or evaporites were deposited in some 

incised valleys.

Minnelusa Formation

The Minnelusa Formation in the PRB can be divided 

informally into lower, middle, and upper members (fig. 6). 

The lower and middle members are Pennsylvanian in age and 

the upper unit is Permian. In the northern part of the basin 

the lower and middle members are mostly shales and carbonates; the shales have low potential as a source rock and the 

carbonates have low porosity and a low potential as a reservoir rock. In the western part of the basin and westward into 

Events Chart

Powder River Basin Province—Pennsylvanian Permian Composite TPS

Laramide Foreland Basin

Minnelusa-Tensleep-Leo AU

0

600500400300200100

50

550450350250150

Cretaceous

Paleogene

Permian

T ria s s ic

Jurassic

Precambrian

Cambrian

Ordovician

Silurian

Devonian

E

M

L

EE

E

E

E

M

LL

M

L

E

L

M

L

E

L

M

L

E

M

L

E

L

Mississippian

Pennsylvanian

Neogene

Pal

Eoc

Olig

Mio Plio

GENERATION

BASIN TYPE

TRAP FORMATION

OVERBURDEN ROCK

RESERVOIR ROCK

SEAL ROCK

SOURCE ROCK

PETROLEUM

SYSTEM EVENTS

GEOLOGIC 

TIME

SCALE

MIGRATION

ACCUMULATION

Leo shales Phosphoria Formation

Leo Sandstsone Upper Minnelusa-Tensleep Formation

Minnelusa-Tensleep generation is pre-Laramide Leo generation is post-Laramide

Minnelusa-Tensleep migration is pre-Laramide Leo migration is post-Laramide
Pennsylvanian-Permian Composite Total Petroleum System 11

central Wyoming, the Amsden Formation is equivalent to the 

lower member of the Minnelusa, and the Tensleep Sandstone 

is equivalent to the middle member of the Minnelusa and the 

lower part of Permian rocks (fig. 6). In the southern part of the 

PRB, intertidal and eolian siliciclastics of the Leo Formation, 

equivalent to the middle member of the Minnelusa (fig. 6), 

produce oil and gas. In the northern part of the PRB, the upper 

member of the Minnelusa, based on oil company terminology, 

is divided into five successions or cycles— A, B, C, D, and E, 

with E being the oldest cycle. Generally, each zone consists of 

a basal dolomite, succeeded by a thin evaporitic layer, another 

dolomite, and an upper sandstone. Each depositional cycle 

consists of dolomite, evaporitic succession and overlying 

sandstone (fig. 12). Lateral variation of the carbonate sand 

cycle is common and can make correlation difficult. In the 

western part of the basin the Tensleep is equivalent to the C, 

D, and E zones of the middle part of the Minnelusa. 

The sandstones in the lower D and E zones are seldom 

penetrated because all production to date is from the upper 

Minnelusa A, B, or C zones. Where penetrated, however, 

the lower zones show varying degrees of sandstone porosity 

and thickness. For example, the D zone from the L.L. & 

E. #1 Flocchini well, T. 45 N., R. 72 W., sec. 1, has 35 ft 

of 18 percent porosity at 11,650 ft, whereas the Shell #34 

Meadowlark well, T. 46 N., R. 73 W., sec. 28, has 14 ft of 7 

percent porosity at 12,400 ft depth. Moore (1975) estimated an 

8 percent maximum effective porosity at depths greater than 

12,000 ft; on the west side of the basin Minnelusa reservoirs 

have significant amounts of oil with 9 percent porosity at 

15,000 ft, but permeability is possibly fracture enhanced. 

The A, B, and C zones are a complex succession of 

dolomite, evaporite, and sandstone (fig. 13). Of the three, 

the C zone is the most continuous, extending over the entire 

basin, exhibits the best lateral and vertical continuity, and has 

the best porosity and permeability. The sandstones generally 

increase in reservoir quality and quantity from south to north 

in the basin. Commonly, the top of the C zone is defined by 

the C marker bed (fig. 12), defined by sonic and gamma ray 

characteristics as a thin time-stratigraphic shale or bentonite 

bed. However, the marker loses its characteristics in places 

Figure 9. Generalized paleogeography of late Minnelusa time in parts of the Powder River Basin 

and adjacent areas. 

Wind direction

MONTANA

N. DAKOTA

 S. DAKOTA

NEBRASKA

WYOMING

Major 

Laramide 

uplifts

COLORADO

SHALLOW EVAPORITIC SEA

CONTINENTAL SABKHA

COASTAL DUNES AND SHORELINE SANDS

EXPLANATION
12 Geologic Assessment of Undiscovered Oil and Gas in the Powder River Basin Province, Wyoming and Montana

Figure 11. Diagram showing a time slice of generalized environments of deposition that comprise strata of the Minnelusa 

Formation in the Powder River Basin. Transgression and regression events form cyclic stacking patterns in the Minnelusa.

OPEN SHELF

OR 

BASIN

TIDAL

FLAT

TIDAL

CHANNEL

REEFS ISLAND

LIME

SAND

 SHOALS

LAGOON

LAND

TIDAL FLAT

(100s OF METERS TO 10s OF KILOMETERS WIDE)

DESERT

Gypsum

Anhydrite

SUPRATIDAL

SALT FLAT

 (SABKHA)

BEACH

RIDGE

INTERTIDAL

TIDAL

CREEK

SUPRATIDAL

 ELEVATED 

 WELL DRAINED

SUPRATIDAL

 ALGAL 

 MARSH

POND

LEVEE

Open marine

Open marine

Supratidal Intertidal Subtidal
Figure 12. Diagram showing correlation of a geophysical log to a Minnelusa Formation depositional cycle. Pmk, Minnekahta Formation; Po, OpePm, Minnelusa Formation. 

11,500 11,400 11,300

DAVIS OIL CO.

Pinto Federal # 1

T. 47 N., R. 72 W., sec. 28

porosity sonic gamma ray

Pmk

Po

Pm

C marker

10 % 

porosity

Interdune

Dune

water table

Supratidal (sand sheet, low porosity and permeability)

Subtidal (dolomite, sandy dolomite)

Sabkha (evaporite)

Subtidal (dolomite, sandy dolomite)

Depth 

in feet
14 Geologic Assessment of Undiscovered Oil and Gas in the Powder River Basin Province, Wyoming and Montana

to the west and south, but other time-stratigraphic markers 

maybe present. Many published reports use the Minnekahta 

Limestone as a time-stratigraphic marker to correlate and 

develop the stratigraphic framework of the Minnelusa and 

overlying formations.

Sea-level fall at the close of Minnelusa time exposed the 

Minnelusa surface to various amounts of incisement by fluvial 

processes, leaving isolated to partly isolated remnants of the A 

zone and B zones and, in places, incised into the C zone. The 

surface was covered with a saline pan system of bedded anhydrite and halite, red mudstone, siltstone, and thin sandy layers 

of the Opeche Shale (fig. 13; Benison and Goldstein, 2000). 

In the PRB, the A, B, and C zones are all productive. The 

C zone is productive from several fields, the A and B zones 

are productive mainly in the eastern and northern part of the 

Minnelusa production fairway (fig. 14). In general, the B zone 

does not produce when a porous A zone is present, although 

both zones do produce in some fields. Most Minnelusa 

reservoirs are sandstone, although there is production from 

fractured dolomite facies in the Reno field on the west flank 

of the basin and from one well in the Bone Pile field in the 

production fairway. Best production practice includes at least 

10 ft of net sand in a potential reservoir because half of such 

a bed will be cemented at the bottom and also possibly at the 

top. That would leave a minimum net pay of about 5 ft, which 

is adequate for a well to be economic with an active water 

drive.

Minnelusa Formation reservoirs are generally small 

(averaging four wells per field) but prolific. Production per 

field averages 3.7 MMBO (NRG Associates, 2006). Primary 

and secondary production averages 0.5 MMBO per well or 

more. Most fields have limited water drive because of the 

complex stratigraphy, but about 20 percent of the fields have 

an active water drive. Active water drive fields have the best 

production statistics and typically average 500 barrels per 

acre-ft. 

Tensleep Sandstone

Tensleep Sandstone is the lateral equivalent of the 

Minnelusa Formation C, D, and E cycles. The term Tensleep 

originated in central Wyoming and carried eastward to 

the west margin of the PRB. The Minnelusa Formation 

designation originated in the Black Hills and was carried 

west into the PRB, up to the basin margin. The Tensleep 

has similar depositional and reservoir characteristics as the 

Minnelusa Formation; that is, it contains multiple boundaries 

in response to frequent and high-amplitude sea-level changes. 

A generalized upward succession of Tensleep strata consists 

of (1) thick marine carbonate beds; (2) thin, low porosity, 

interdune sandstone layers; (3) dominantly porous and 

permeable eolian crossbedded dune sandstones; and (4) 

thin, discontinuous carbonates. The siliciclastic units form 

the dominant reservoir, whereas dolomites, although vuggy, 

rarely produce because of low bulk permeability. Porosity 

and permeability distributions are constrained by succession 

boundaries, facies change, and diagenetic alteration.

Few wells produce from reservoirs designated as 

Tensleep in the Pennsylvanian-Permian Composite TPS. Most 

Upper Pennsylvanian and Permian production outside the 

main Minnelusa fairway is termed Minnelusa, not Tensleep, 

although Reno and Reno East fields, in the western part of the 

TPS, have been identified in the literature as both Tensleep and 

Minnelusa. Tensleep production in the Basin Margin TPS is 

from large anticlines such as those found at Teapot Dome and 

Salt Creek fields and from stratigraphic traps such as those at 

North Fork field and parts of Sussex field.

Leo Formation

The Middle Pennsylvanian Leo Formation is bounded by 

unconformities; it is confined to the southeastern part of the 

PRB, the Hartville uplift, and the northern Denver Basin. The 

Leo is underlain by the lower member of the Minnelusa Formation in places in the southeastern PRB and by the Amsden 

Formation in other parts of the basin, and is overlain by the 

upper member of the Minnelusa Formation (fig. 6).

The Leo Formation consists of six successions or cycles 

of shale, limestone, and intertidal and eolian siliciclastics 

(Desmond and others, 1984; Ahlbrandt and others, 1994). 

The successions are informally labeled in descending order 

as Leo 1–6. Siliciclastic intervals are also informally labeled 

Leo sands 1–6. Sandstone reservoir quality can vary greatly 

between cycles due to primary sedimentation patterns and 

diagenetic alteration. As a result, porosity can range from less 

than 5 to more than 20 percent over short distances. Thicknesses of each succession vary by tens of feet but commonly 

average about 50 ft, whereas thicknesses of the siliciclastic 

intervals range from a few feet to more than 30 ft. 

Only minor amounts of oil are produced from the Leo 

Formation (NRG Associates, 2006) in the southeastern part of 

the TPS. The minor production appears to be trapped stratigraphically in a low-porosity (sonic log calculated), possibly 

fractured sandstone, although the type and location of lateral 

seals are unknown. Most Leo production is from basin margin 

anticlines in the southern and southeastern parts of the basin, 

including south of the Black Hills in South Dakota (fig. 4). 

Traps and Seals

The Minnelusa Formation consists of several types of 

structural and stratigraphic traps (fig. 13). Trotter (1963) 

identified two types of structural traps: (1) four-way structural 

closure and (2) buried topography associated with an anticline. 

Trotter also identified four types of stratigraphic traps: (1) 

buried topography, (2) buried topography associated with a 

breached pre-Opeche structure, (3) updip porosity pinchout, 

and (4) facies change. 

Van West (1972) mapped several Minnelusa Formation 

fields as to their trap type: topographic, permeability pinchout, 
Figure 13. Generalized stratigraphic section of Minnelusa Formation A, B, and C zones. Green represents potential stratigraphic oil traps. C markedefined by wireline log characteristics. 

Minnekahta

Opeche Shale 

A A A

B

B1 B1 

B3

B2

B3

C marker

 A sandstone 

Minnekahta Limestone 

C marker bed 

B sandstone 

limestone or dolomite 

B sandstone 

C sandston

limestone or dolomite 

Dolomite cement Anhydrite cement 
16 Geologic Assessment of Undiscovered Oil and Gas in the Powder River Basin Province, Wyoming and Montana

Figure 14. Map showing Minnelusa Formation production fairway and outlying fields in the Powder River Basin, 

Wyoming. Light gray lines are county boundaries.

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Campbell

Crook

Weston

Johnson

Powder River

Sheridan

Montana

Wyoming
Mowry Total Petroleum System 17

or structural closure. Most trap types were either topographic 

or a permeability pinchout, with the larger fields being the 

topographic type. Most new field discoveries since Van West’s 

publication in 1972 have been stratigraphic traps (NRG 

Associates, 2006). 

Trapping mechanisms for the A and B zones of the upper 

member of the Minnelusa Formation are mostly controlled by 

pre-Opeche incisement. The incisement differentially erodes 

parts of unit A and locally unit B, leaving parts of A and B 

sands juxtaposed to Opeche shales and mudstones, an effective 

vertical and lateral seal (figs. 10, 13). The most effective trapping condition is where the A or B sandstones are eroded on 

the updip side. Because incisement patterns can be structurally 

influenced, their general pattern may be predictable. Van West 

(1972) published isopach maps of various Mississippian to 

Permian time intervals showing contours that trend northwestsoutheast, similar to previously mapped structural trends. 

Traps in the Tensleep Sandstone were identified from 

surface studies in the Bighorn Basin (Ciftci and others, 2004), 

which identified facies changes bounded with surfaces that 

segregated permeability and capillary pressure variations. 

These changes help compartmentalize and segregate fluids that 

help trap oil within the Tensleep. 

Trap styles in Leo Formation reservoirs in this TPS are 

uncertain because of limited production, although probably 

both structural and stratigraphic types exist.

Mowry Total Petroleum System 

This section describes the Mowry TPS, which includes 

three AUs in the PRB: (1) Lower Cretaceous Fall RiverLakota Sandstone AU, (conventional reservoirs); (2) Lower 

Cretaceous Muddy Sandstone AU (conventional reservoir); 

and (3) Mowry Shale AU, which is the main oil source for the 

TPS (continuous reservoir). Stratigraphic relations of the rocks 

composing these AUs are shown in figure 15.

The PRB has a long history of oil production from Lower 

Cretaceous sandstone reservoirs (fig. 16). Muddy Sandstone 

oil production was first established in the late 1800s from 

Fiddlers Creek and Clareton fields immediately downdip from 

oil seeps on the east side of the basin. In the 1950s, Lower 

Cretaceous production was established in the deeper part of 

the basin while exploring for the Upper Minnelusa Formation. 

Some 85 percent of the fields are classified as oil (NRG 

Associates, Inc., 2006) whereas a few fields are classified as 

gas largely because of a limited volume of source rocks in the 

gas generation window. Most gas on the east side of the basin 

is associated gas, but in the deepest parts of the basin, where 

the Mowry Shale has reached gas generation temperatures, 

there are a few nonassociated gas fields (NRG Associates, 

Inc., 2006). 

Petroleum Source Rocks

The Mowry Shale is considered the main hydrocarbon 

source for Lower Cretaceous reservoirs in the PRB, although 

minor quantities of hydrocarbons may be generated from 

the Lower Cretaceous Skull Creek Shale and Fuson Shale 

(fig. 15). The lower contact of the Mowry is the lowermost 

gamma ray kick just above a low resistivity zone, and the 

upper contact is the Clay Spur Bentonite Bed marking the 

base of the Frontier Formation (Burtner and Warner, 1984). 

The Mowry was deposited as dark brownish gray siliceous 

shale during maximum marine transgression that ranged 

from the end of the Lower Cretaceous Albian Stage to the 

lower part of the Upper Cretaceous Cenomanian Stage 

(Merewether, 1996). The shale is organic rich because of the 

preservation of organic material due to anoxic conditions 

and the lack of detrital sediment that would have inhibited 

organic input (Nixon, 1973; Byers and Larson, 1979). In 

the TPS, Mowry Shale thicknesses average about 250 ft and 

range from about 100 ft to more than 400 ft (Momper and 

Williams, 1984, their fig. 4). Three depositional units can be 

mapped within the Mowry (Byers and Larson, 1979) based 

on several bentonite markers that divide the unit into time 

stratigraphic intervals. The units are regionally persistent and 

lithologically distinctive (Merewether and others, 1977; Fox, 

1993); therefore, the unit boundaries are isochronous and can 

be traced in the subsurface for long distances.

Geophysical log resistivities are commonly used to 

indicate lithology of the Mowry Shale. High resistivity 

indicates siliceous shale, sandy or silty shale, siltstone, or 

silty sandstone, whereas low resistivity indicates clay-rich 

shale and bentonite (Nixon, 1973). However, the presence of 

hydrocarbons may alter the resistivity signature; therefore, any 

lithologic interpretation should be made with caution. 

The Mowry Shale has a TOC of 2 to more than 3 weight 

percent Type II and Type III kerogen (Nixon, 1973; Schrayer 

and Zarrella, 1963). Schrayer and Zarrella (1966) published 

maps of central Wyoming that showed Mowry TOC values 

increasing from west to east, with the highest values near the 

PRB west margin. Vertical profiles of Mowry TOC values, 

near Douglas, Wyoming (fig. 17), show values as much as 4 

weight percent near the middle of the formation. These values 

may be conservative if the Mowry in this area has generated 

oil and therefore spent some of its original organic matter 

(Meissner, 1985). Heacock and Hood (1970) showed that 

the Mowry has one of the highest average TOC values for 

Cretaceous shales in the PRB. Momper and Williams (1984) 

reported that within the basin the Mowry Shale expelled about 

11.9 BBO (billion barrels of oil) from an average of 3 weight 

percent TOC, which should be considered a maximum for 

the total fluid expulsion. That volume converts to an oilgenerating capability of 105 barrels/acre-ft, with an expulsion 

efficiency of 6 to 8 percent. Cumulative known oil production 

from all reservoirs in the Mowry TPS (but not including basin 

margin Lower Cretaceous reservoirs) as of 2005 is about 630 

MMBO (NRG associates, 2006), or 5 percent of the 
18 Geologic Assessment of Undiscovered Oil and Gas in the Powder River Basin Province, Wyoming and Montana

11.9 billion barrels of expelled oil estimated by Momper and 

Williams (1984), for the Mowry source rocks. It should be 

noted that their amount does not include oil generated from 

the Fuson and Skull Creek Shales according to Momper and 

Williams (1984); the Fuson expelled a maximum of about 1 to 

2 million barrels of waxy oil and minor amounts of gas, and 

the Skull Creek expelled a maximum of about 1 BBO from 

Type II organic matter. 

Source Rock Thermal Maturity

Because of hydrocarbon mixtures, types, and 

temperatures, the Mowry Shale probably started generating 

hydrocarbons at depths exceeding 7,000 ft (Nixon, 1973). 

Basin and Ro

 modeling (described below) showed that 

significant hydrocarbon generation could have started at about 

8,000 ft. Two one-dimensional burial history plots (using 

Figure 15. Stratigraphic column and succession intervals of Lower Cretaceous strata in the Powder River Basin 

including identification of the Mowry Total Petroleum System. TPS, total petroleum system. 

1

2

3

4

5

CRETACEOUS

Lower Upper

Aptian

Albian

Cenomanian

 (part)

System Series Stage Powder River Basin

Belle Fourche Shale

Inyan Kara Group

Neocomian

 (part)

Frontier Formation

Mowry TPS

Sequence

Interval

Mowry Shale

Muddy Sandstone

Fall River Sandstone

Lakota Sandstone

Fuson Shale

Skull Creek Shale

Petroleum source rock

EXPLANATION

Reservoir
Mowry Total Petroleum System 19

Figure 16. Map of Powder River Basin showing Lower Cretaceous production, including production from Fall 

River–Lakota Sandstones Assessment Unit and Muddy Sandstone Assessment Unit.

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Johnson

Campbell

Big Horn

Crook

Converse

Weston

Niobrara

Sheridan

Natrona

Powder River

Rosebud

Wyoming

Montana

Province 5033 boundary

Muddy Sandstone 

production

Lakota and Fall River 

Sandstones production

EXPLANATION
20 Geologic Assessment of Undiscovered Oil and Gas in the Powder River Basin Province, Wyoming and Montana

Corg % Corg %

DEPTH, IN FEET

DEPTH FROM TOP OF MEASURED SECTION, IN FEET

sample

interval sample

interval

Mowry Shale near Douglas Wyoming

Core Outcrop

Figure 17. Core and outcrop vertical sections showing 

Mowry Shale total organic carbon values (Corg [%]) near 

Douglas, Wyoming. 

PetroMod 1-D; Integrated Exploration Systems, 2002) were 

used to determine (1) the depth at which oil generation started, 

(2) the depth at which maximum oil generation occurred, 

and (3) the age range of petroleum generation. One model 

was derived for the east side of the basin and another for the 

west side, where formation depths and other input data were 

averaged from several sources. Therefore, the models reflect 

a general sense of burial and temperature history for each side 

of the basin. The models were calibrated to various sources of 

Ro

 data, including Higley and others (1997), Hunt (1979), and 

Surdam and others (1994). Although the models were not from 

a specific location, the output gives reasonable information 

about the basin’s thermal history. 

On the east side of the basin, results showed that (1) 

hydrocarbon generation started at the base of the Mowry 

Shale about 50 Ma at a depth of about 8,000 ft, at an Ro

 of 

0.6 weight percent (fig. 18) which started formation overpressuring within the Mowry, and (2) Ro

 values for the Mowry 

have not yet reached more than 0.63 weight percent and are 

currently at about that value. 

On the west side of the basin, modeling results showed 

that (1) hydrocarbon generation started at the base of the 

Mowry about 65 Ma at a depth of about 8,000 ft and at an Ro

of 0.6 weight percent (fig. 19), which also started formation 

overpressuring; (2) the Mowry reached peak Ro

 of about 0.9 

percent at about 25 Ma at a depth of about 13,000 ft and is 

currently at about 0.92 percent; and (3) Ro values would be 

entering the gas generation window at depths greater than 

13,000 ft.

Hydrocarbon Migration

Buoyancy of fluids and pressure gradients are important 

to hydrocarbon migration because of oil being lighter and gas 

being much lighter than water, causing oil and gas, once they 

have been expelled, to move upgradient through porous and 

permeable carrier beds. However, if the buoyancy pressure 

is less than the capillarity of the carrier bed, the permeability 

barriers prevent migration until the pressure and capillarity 

reach equilibrium.

In the Mowry TPS, this process is common in that hydrocarbon production is located up structural gradient from the 

Mowry oil-generation kitchen located in the deep part of the 

basin (fig. 3). Oil migrates from the generation area toward 

the east where it is trapped in Lower Cretaceous reservoirs 

(fig. 20). The migration direction and rate was probably influenced by northeast-southwest-trending structures (Slack, 1981; 

Anna, 1986a, b; and Maughan and Perry, 1986). Conversely, 

the lack of production north of the generation area (fig. 20) 

could be explained as follows: (1) The area to the north is 

nearly parallel to the basin axis and not subject to buoyancy 

flow; (2) migration was confined to northeast-southwesttrending structures, even though present-day groundwater flow 

is both north and south out of the basin; (3) lack of quality 

reservoirs; and (4) a combination of the above. Geologically, 

there appears to be no ready explanation for the conspicuous 

absence of production in the Mowry kitchen area, although 

there have been a few recent discoveries (for example, 

African Swallow field trend) in the southwestern part of the 

basin.

Migration from the Mowry Shale into the Muddy Sandstone is a simple process because the Mowry directly overlies 

the Muddy. However, migration into the Fall River and Lakota 

Sandstones is a more arduous process because the Fuson and 

Skull Creek Shales are in between. Therefore, open fault and 

fracture zones served as vertical pathways for fluids to migrate 

from the Mowry to the Fall River-Lakota. 

Plots of API gravity and gas/oil ratios (GOR) of several 

fields producing from Lower Cretaceous reservoirs show a 

general trend of decreasing values from west–to-east (fig. 21). 

This may indicate that the generated oil was being degraded 

along its west to east migration path, and that most of the 

oil was generated in the Mowry Shale at depths greater than 

8,000 ft. Only along parts of the basin margin, however, is 

there some change in oil characteristics because of degradation 

(Wenger and Reid, 1961). 
Mowry Total Petroleum System 21

Lower Cretaceous

BURIAL DEPTH, IN FEET

Stratigraphic 

interval

0.50 [%Ro]

0.60 [%Ro]

0.70 [%Ro]

0.80 [%Ro]

0.90 [%Ro]

1.00 [%Ro]

1.10 [%Ro]

Tertiary

Upper Cretaceous

Niobrara Fm

Mowry Shale

Jurassic

Triassic

Permian

Pennsylvanian

Mississippian 

and older rocks

Age [Ma]

150 120 100 80 60 40 20 0

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

MESOZOIC CENOZOIC

Jurassic Cretaceous Paleogene Neogene

Figure 18. Burial history curve for east side of the Powder River Basin based on combined input and calibration 

data from several locations. The 8,000-foot datum marks the horizon below which Mowry Shale enters the oil 

generation window at about 42 million years ago. The Niobrara Formation does not enter the oil generation 

window over most of the east part of the basin. Ro

, vitrinite reflectance; Fm, Formation; J, Jurassic; K, Cretaceous; 

Pg, Paleogene; Ng, Neogene. 

A geologic events chart (fig. 22) shows elements that 

define the Fall River–Lakota Sandstones AU and the Muddy 

AU.

Reservoir Rocks

Fall River–Lakota Sandstones 

Lower Cretaceous strata (Aptian and lower Albian) in 

the Rocky Mountain region are collectively called the Dakota 

Group, which is formally divided into a lower Inyan Kara 

Group and the overlying Fall River Sandstone. Some workers 

include the Skull Creek Shale and Muddy Sandstone in the 

Dakota Group, especially east of the Black Hills where the 

Skull Creek Shale thins and the Inyan Kara and the Muddy 

coalesce into one unit. Both the Fall River and Lakota produce 

oil and gas in the PRB, although cumulative production to 

date is only about 20 percent of that produced by the overlying 

Muddy. The lower production rates are probably because the 

Fall River and Lakota reservoir quality is more variable than 

the Muddy, and oil migration into the Fall River and Lakota 

from the Mowry Shale may not have been as efficient as into 

the Muddy (Dolson and Muller, 1994). 

The Lower Cretaceous strata consist of four major and 

several minor stratigraphic intervals, separated in part by 

regional and local unconformities. The oldest major sequence 

overlies a regional unconformity that in places truncates 

Jurassic, Triassic, and, locally upper Paleozoic strata (Dolson 

and Muller, 1994). This succession consists of stacked 

conglomerates and coarse-grained sandstones separated by 

siltstones and mudstones of variable thicknesses of the Lakota 

Sandstone and the variegated shales and mudstones of the 

Fuson Shale.
22 Geologic Assessment of Undiscovered Oil and Gas in the Powder River Basin Province, Wyoming and Montana

The second major succession rests unconformably on 

the first and consists of the transgressive gray to black Skull 

Creek Shale. A third sequence, deposited during a lowstand 

event with widespread incisement into the Skull Creek, is 

represented by sandstone, siltstone, and mudstone of the Fall 

River Sandstone. A fourth succession also involved a major 

sea-level drop followed by incisement and the gradual fluvial 

and estuarine filling of channels characteristic of the Muddy 

Sandstone. 

The Lakota Sandstone was deposited on an alluvial 

plain over a large area, not as a sheet deposit but as a large, 

north-trending drainage system associated with incised 

valleys on multiple surfaces (Meyers and others, 1992). 

Several successions of sandstone, siltstone, and shale make 

correlation of individual sandstones difficult and has led to 

misinterpretation of sandstone trends. 

The Fall River Sandstone was deposited as a broad 

deltaic system that included incised valley and distributary 

fill, delta plain facies, and delta front facies (Rasmussen and 

others, 1985). Most Fall River production is from the incised 

valley and distributary systems, whereas minor production is 

from adjacent deltaic plain and delta front facies. Buck Draw 

field (Anderson and Harrison, 1997) is the largest Fall River 

oil producer (fig. 23). South of Buck Draw field, the width of 

the incisement decreases and the valley-fill sandstones have a 

lower sand/shale ratio than valley fill to the north. As a result, 

production volumes in that area are less than at Buck Draw. 

Rasmussen and others (1985) presented pictorially east-west 

cross sections of several north-trending incised valleys at 

various stratigraphic levels of the Fall River, indicating the 

possible abundance of reservoir-quality sandstones in the 

southern part of the basin. 

Muddy Sandstone 

The Muddy Sandstone is a prolific oil producer in several 

Rocky Mountain foreland basins, including the PRB. The 

Muddy consists of marine and nonmarine sandstone, siltstone, 

0.50 [%Ro]

150 130 120 110 100 90 80 70 60 50 40 30 20 10 0

0

4,000

8,000

12,000

16,000

20,000

MESOZOIC CENOZOIC

Jurassic Cretaceous Paleogene Neogene

Age [Ma]

Tertiary

Upper Cretaceous

Upper Cretaceous

Lower Cretaceous

Niobrara

Mowry Shale

Jurassic

Triassic

Permian

Pennsylvanian

Mississippian 

and older rocks

0.60 [%Ro]

0.70 [%Ro]

0.80 [%Ro]

0.90 [%Ro]

1.00 [%Ro]

1.10 [%Ro]

Stratigraphic

interval

DEPTH, IN FEET 

Figure 19. Burial history curve for west side of the Powder River Basin based on combined input and calibration 

data from several locations. The 8,000 foot datum marks horizon below which Niobrara Formation enters oil generation 

window at about 30 million years ago, and where the Mowry Shale enters the window at about 64 Ma. At 12,000 feet, 

the Mowry is currently at a vitrinite reflectance value of about 0.92 weight percent. J, Jurassic; K, Cretaceous; Pg, 

Paleogene; Ng, Neogene; Ma, mega-annum, before present; Ro

, vitrinite reflectance.
Mowry Total Petroleum System 23

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Johnson

Campbell

Big Horn

Crook

Converse

Weston

Niobrara

Sheridan

Natrona

Powder River

Rosebud

EXPLANATION

Fall River–Lakota Sandstones AU 

and Muddy Sandstone AU 

boundary

Montana

Wyoming

Mowry Shale depth 

greater than 8,000 feet 

Province 5033 boundary

Muddy Sandstone 

production

Fall River and Lakota

Sandstones production

Figure 20. Map of Powder River Basin Province showing Lower Cretaceous production, area where depth 

to Mowry Shale is greater than 8,000 feet (blue area), and boundary of Mowry Total Petroleum System that 

also delineates the Fall River–Lakota Sandstones and Muddy Sandstone Assessment Units (AUs). Note that 

most of the current Lower Cretaceous production is east of the Mowry generation area. Province 5033 is 

code number for Powder River Basin Province.
24 Geologic Assessment of Undiscovered Oil and Gas in the Powder River Basin Province, Wyoming and Montana

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Johnson

Campbell

Big Horn

Crook

Converse

Weston

Niobrara

Sheridan

Natrona

Powder River

Rosebud

Carter

44

40

40

48

56

39

39

36

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37

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40

40

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34

47

37

40

42

39

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48

43 45

48

51

API (gravity)

34–37

38–41

42–45

46–51

52–56

EXPLANATION

Mowry oil source

A

Montana

Wyoming

Province 5033 boundary

Muddy Sandstone 

production

Lakota and Fall River 

Sandstones production

Mowry Shale depth

greater than 8,000 feet

Figure 21. Maps of Powder River Basin Province showing Lower Cretaceous production, the area where depth 

to Mowry Shale is greater than 8,000 feet, (A) average API gravity for Lower Cretaceous fields, (B) average 

gas/oil ratio (GOR) for Lower Cretaceous fields. API and GOR data from NRG Associates, Inc. (2006). Province 5033 

is code number for Powder River Basin Province.
Mowry Total Petroleum System 25

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Montana

Wyoming

B

GOR

EXPLANATION

Mowry oil source

Province 5033 boundary

Muddy Sandstone 

production

Lakota and Fall River 

Sandstones production

Mowry Shale depth

greater than 8,000 feet

<1,000

1,000–4,000

4,000–9,000

9,000–13,000

>13,000

Figure 21. Maps of Powder River Basin Province showing Lower Cretaceous production, the area where depth 

to Mowry Shale is greater than 8,000 feet, (A) average API gravity for Lower Cretaceous fields, (B) average 

gas/oil ratio (GOR) for Lower Cretaceous fields. API and GOR data from NRG Associates, Inc. (2006). Province 5033 

is code number for Powder River Basin Province.—Continued
26 Geologic Assessment of Undiscovered Oil and Gas in the Powder River Basin Province, Wyoming and Montana

BASIN TYPE 

TRAP FORMATION 

MIGRATION 

OVERBURDEN ROCK 

GENERATION 

SOURCE ROCK 

PETROLEUM 

SYSTEM EVENTS 

GEOLOGIC 

TIME 

SCALE 

PALEO. EOCENE OLIG. MIOCENE PP 

MESOZOIC CENOZOIC

TERTIARY 

E. M. L. E. M. L. E. L. 

CRETACEOUS QUAT. 

250 200 150 100 70 75 0 10 20 30 40 50 60 

Powder River Basin Province—Mowry TPS

RESERVOIR ROCK 

SEAL ROCK 

Fall River–Lakota Sandstones AU and Muddy Sandstone AU

Mowry Shale 

Fall River, Lakota and Muddy Ss 

Stratigraphic 

Foreland Structural Basin 

Structural

TRIASSIC JURASSIC

Events Chart

Figure 22. Events chart for Fall River–Lakota Sandstones and Muddy Sandstone Assessment Units (AUs) in the Mowry Total 

Petroleum System (TPS). Ss, sandstone; Quat, Quaternary; PP, Plio-Pleistocene; Olig., Oligocene; Paleo., Paleocene; E., early; M., 

middle; L., late.

and mudstone deposited in a variety of sedimentary environments. In the PRB, the two main producing intervals consist 

of valley-fill fluvial and estuarine sandstones and transgressive 

nearshore marine sandstones. Fluvial strata are common on 

the east side of the basin, whereas estuarine strata are common 

on the west side. Transgressive nearshore marine sandstones 

are associated with incised valley systems, most commonly 

in the central and western parts of the basin. As a result, most 

Muddy production is associated with incised valley systems in 

stratigraphic traps and in some structural traps, although rarely 

is the Muddy a pure structural trap. 

The regional paleotopographic setting of the Muddy 

described by Dolson and others (1991) helped to integrate 

numerous smaller scale studies (Donovan, 1995; Gustason, 

1988; Martinsen, 1994); Waring, 1975; Weimer and others, 

1982, 1988; Wheeler and others, 1988) into a comprehensive 

understanding of a complex depositional system. Simply 

stated, during regression of the Mowry sea, sediments of 

the Muddy interval (fig. 24) were first deposited as part of 

a highstand systems tract (HST) as widespread, but thin, 

argillaceous and bioturbated sands and silts. This very fine 

grained unit generally has low porosity and permeability and 

is not considered an exploration target. A lowstand systems 

tract (LST) then developed at maximum Mowry regression, 

resulting in incised valleys into the exposed Muddy surface 

(Dolson and others, 1991). The transgressive systems tract 

of the incised valley fill unconformably overlies one or more 

of the following successions: fluvial deposits of sandstone, 

siltstone, and mudstone overlain by estuarine deposits of 

sandstone and capped by thin, transgressive sandstone. Some 

authors (Wheeler and others, 1988, and Gustason, 1988) have 

applied formation names to particular unconformity-bound 

sandstone intervals for a particular field or area. 

Fluvial deposits are most prevalent on the east side of 

the PRB proximal to the Mowry sea but are thin to absent 

on the west side. Fluvial deposits contain various amounts 

of sandstone but are sand rich on the east side, with sand 

percentage gradually decreasing to the west. Estuarine 

deposits are mostly siltstone and mudstone dominated 

with limited but variable amounts of sandstone. Sandstone 

percentage in the estuarine deposits also diminishes to the 

west. A major transgressive event deposited mostly fine 

grained, well-sorted sandstone over the Muddy surface, more 

so in topographically low areas coincident with the incised 

fluvial systems (fig. 25). As the transgression progressed, sand 

on topographic highs was eroded, whereas sand in topographic 

lows was preserved. These sandstones can be excellent 
Mowry Total Petroleum System 27

reservoirs as evidenced by high production rates from African 

Swallow and Sand Dunes fields (fig. 25). 

On the east side of the basin, in normal or underpressured 

sections, reservoir-quality sandstones have porosity exceeding 

20 percent and permeability ranging from 100 to more than 

1,000 millidarcies (mD). On the west side, in overpressured 

sections, reservoir quality sandstone has porosity of 10 to 15 

percent and permeability less than 200 mD. 

Traps and Seals

Traps in Lower Cretaceous strata in the PRB can be characterized as stratigraphic and a combination of stratigraphic 

and structural enhancement. Stratigraphic traps are the most 

common type and are associated with incised valley systems, a 

diversity of lithologies, and juxtaposed pattern of sandstones, 

siltstones, and shales in the valley systems; that is, the oilbearing reservoir sandstones are enclosed in low-porosity and 

low-permeability siltstones, shales, or mudstones that create a 

barrier to oil migration. Porosity reduction owing to increased 

clay content in reservoirs may also be a factor in some cases, 

but diagenetic alteration in forming potential traps is rare. 

Structural traps are a result of Laramide deformation 

that created numerous structural types at various scales. Most 

structures were created before oil was generated and migrated 

from Lower Cretaceous source rocks (fig. 22). As a result, oil 

migration into potential stratigraphic and structural traps was 

done in an efficient manner.

Mowry TPS as a Continuous Reservoir

The Mowry Shale is a self-contained petroleum system, 

in that it is a hydrocarbon source rock not only for other 

Lower Cretaceous reservoirs but also for intraformational 

reservoir, which is typical of a continuous (or unconventional) 

petroleum system. Production from the Mowry is enhanced 

by fracture permeability and storage, but there is a possibility 

that thin siltstones may be present, similar to siltstones and 

sandstones mapped in the Bighorn Basin to the west of the 

PRB (Davis and Byers, 1989). The siltstones could increase 

porosity and storage, which would supply oil to Mowry 

fracture networks. 

Mowry Shale thicknesses range from about 100 ft to 

more than 400 ft and average about 250 ft (Momper and 

Williams, 1984, their fig. 4). Three main depositional units can 

be mapped within the formation (Byers and Larson, 1979), 

all bounded by bentonite beds that divide the unit into timestratigraphic intervals. The units are regionally persistent and 

lithologically distinctive (Merewether and others, 1977; Fox, 

1993). Geophysical log resistivities are commonly used to 

identify lithologic type—high resistivity indicates siliceous, 

sandy or silty shale, and siltstone or silty sandstone; and low 

resistivity indicates clay-rich shale and bentonite (Nixon, 

1973). However, the presence of hydrocarbons may alter the 

resistivity signature, so lithologic interpretation should be 

made with caution. 

Most continuous reservoirs have sweet spots where 

production may be enhanced by an increase in secondary 

porosity or permeability. Several sweet spots associated with 

major lineaments and lineament zones were identified within 

the Mowry Shale (Slack, 1981; Anna, 1986a, 1986b; Maughan 

and Perry, 1986). The lineaments in figure 26 are assumed to 

be associated with zones of structural deformation and could 

be areas of enhanced secondary porosity and permeability 

0 6 MILES

BUCK DRAW FIELD

BAYHEAD

DELTA

Figure 23. Map showing relation between Fall River 

Sandstone delta system and Fall River production at Buck 

Draw field, Powder River Basin, Wyoming. Blue, water; yellow, 

fluvial system; brown, delta plain; gray, interfluvial island; solid 

dots, oil wells, open circles, dry holes. Diagram modified from 

Anderson and Harrison (1997).
28 Geologic Assessment of Undiscovered Oil and Gas in the Powder River Basin Province, Wyoming and Montana

West PRB target 

3 

1 

2 

4 

Marine siltstone and shale 

near shore 

East PRB target 

marine bay, tidal flats 

estuarine, valley fill

fluvial, valley fill

Marine 

Figure 24. Generalized cross section of Muddy Sandstone depositional environments and successions in the Powder 

River Basin (PRB). All lines mark unconformities. Estuarine and valley fill are production targets on east side of basin, 

whereas the nearshore and marine bay and tidal flats are targets on the west side. Diagram and concept modified from 

Weimer and others (1982).

in the formation. For example, lineaments that coincide 

with the Belle Fourche arch (fig. 4) may represent areas of 

increased fracture intensity along the arch because of flexing 

or enhanced stress, or they may coincide with folds where 

fractures developed as a mechanical response to folding. Most 

current Mowry production, but not all, is within sweet spot 

areas as shown in figure 26. The correlation may be considered circumstantial because the lack of control may not be 

statistically significant, or alternatively, the plotted lineament 

locations do not represent all structural zones. 

Niobrara Total Petroleum System (TPS)

The Niobrara TPS in the PRB includes (1) three conventional AUs: (a) the Frontier-Turner Sandstones AU, (b) the 

Sussex-Shannon Sandstones AU, and (c) the Mesaverde-Lewis 

Sandstones AU; and (2) one continuous AU, the Niobrara 

AU (fig. 27). The Niobrara TPS (fig. 28) consists of Upper 

Cretaceous marine-dominated siliciclastic reservoirs whose 

environments of deposition range from proximal and distal 

delta to marine shelf systems. Numerous sea-level changes 

produced transgressive and regressive systems tracts, initiated 

regional and local lowstand unconformities, and deposited 

shallow nearshore marine sandstones and mudstones capped 

by transgressive deepwater marine shales. 

The basin has long produced hydrocarbons from Upper 

Cretaceous sandstone reservoirs (fig. 28). Production was 

first established in the late 1950s with the discovery of Dead 

Horse Creek field followed by several discoveries in the 1970s 

of stratigraphic traps which became recognized as important 

exploration objectives.

Over 95 percent of the fields from Upper Cretaceous 

reservoirs are classified as oil (NRG Associates, Inc., 2006), 

because source rocks never reached temperatures to generate 

large amounts of gas. Most reservoirs produce associated gas, 

whereas only source rocks in the deepest part of the basin may 

have reached temperatures to be in the gas-generation window. 

Source Rocks

Carbonates of the Niobrara Formation are considered 

to be the primary hydrocarbon source for Upper Cretaceous 

reservoirs in the PRB, although a minor amount may have 

been generated from thick, areally extensive, younger 

Cretaceous marine shales. The formation was deposited in 

latest Turonian to early Campanian time as pelagic carbonate 

in a large but shallow interior seaway, with water depths 

ranging from 200 ft to more than 500 ft, similar to depositional 

environments of the Upper Cretaceous Austin Chalk of the 

Gulf Coast. The sea covered a broad, stable platform over 

the western flank of the North American craton during a 

sea-level rise and represented a major and one of the most 

prolonged highstands in the Cretaceous. On a regional basis, 

the Niobrara Formation is composed of both allochems and 

matrix components. The primary allochems are chalk pellets, 

inoceramid and oyster shell fragments, and forams; the 

primary matrix components are mud, clay, and silt. As a result, 

the formation is usually classified as (1) chalk (with greater 

than 95 percent carbonate), (2) chalky marl (with 65 to 95 

percent carbonate), (3) marl (with 35 to 65 percent carbonate), 

(4) marly shale (with 5 to 35 percent carbonate), and (5) shale 

(with less than 5 percent carbonate). Megascopically, there is 

little difference between the components except for color and 

organic content. The Niobrara can be classified as very fine 
Niobrara Total Petroleum System (TPS) 29

Figure 26. Map of Powder River Basin Province showing Mowry Shale potential sweet spots derived from the 

congregation of published lineament and lineament zones, and current production from the Mowry Shale, Powder 

River Basin. 

!( !(!(

!( !(

!( !( !(

!(

!(

!(

!(!(!(!(!(!(

!(

!(

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!( !(

!(

!(

!(!( !(

!(

!(

!( !( !(

!(!(

!(

!(!(!(

!( !(

!(!(

!(

!(

!(

!(

Lineament

Mowry Shale production

Mowry Shale depth

greater than 8,000 feet

Potential sweet spots

Province 5033 boundary

EXPLANATION
30 Geologic Assessment of Undiscovered Oil and Gas in the Powder River Basin Province, Wyoming and Montana CRETACEOUS Lower Upper 

Albian 

 (part) 

Cenomanian 

Turonian 

Coniacian 

Santonian 

Campanian 

Maastrichtian 

System Series Stage 

(part) 

Fox Hills Formation Cody Sh 

Lewis Sh 

Teapot Ss Mbr 

unnamed 

Parkman Ss Mbr 

unnamed 

Sussex Ss 

Shannon Ss 

Steele Sh 

Niobrara Fm 

Carlile Sh 

Wall Ck Mbr 

West PRB East PRB 

Fox Hills Formation 

Shannon Ss 

Pierre Sh 

Mowry Shale Mowry Shale 

Belle Fourche Sh 

Greenhorn Fm 

Carlile Sh 

Turner Sandy Mbr 

Pool Ck Mbr 

Niobrara Fm 

Steele Sh 

Teckla Ss Mbr 

Belle Fourche Mbr 

Mesaverde 

 Fm Frontier Fm 

Niobrara TPS 

Frontier 

sandstones 

Figure 27. Stratigraphic column of Upper Cretaceous strata in the Powder River Basin (PRB). Niobrara Formation 

source rock is highlighted and the units defining the Niobrara Total Petroleum System (TPS) are identified. Mbr, member; 

Ck, Creek; Fm, formation; Sh, shale; Ss, sandstone. 

grained and well sorted with pore throat sizes of less than 1 

micrometer; hence, matrix permeability is low, generally less 

than 0.01 mD. Matrix porosity can be as high as 20 percent, 

typically averages 10 percent, and is a function of depth and 

shale content, both of which increase to the west in the basin. 

The formation is divided into two members, the Fort 

Hays Limestone Member at the base and the overlying Smoky 

Hill Member. The Fort Hays Limestone Member is mostly 

carbonate and is defined as a chalk, whereas the Smoky Hill 

Member has more varied lithology and has the best source 

rock potential. Longman and others (1998) and Landon 

and others (2001) divided the formation into nine intervals 

because of the formation’s cyclic nature, with the lowest 

interval corresponding to the Fort Hays Limestone Member. 

The lithologic characteristics of both members are regionally 

persistent and can be traced by wireline logs in the subsurface 

for large distances. 

Merewether and others (1977) and Fox (1993) developed 

several regional cross sections across the PRB. Their mapping 

shows that the Niobrara is underlain by the Carlile Shale on 

the west side and by the Turner Sandy Member, equivalent 

to the Ferron Sandstone in Utah and the Codell Sandstone in 

Colorado, on the east side. Overlying the formation on the 

west side is the Fishtooth Sandstone and on the east side is the 

Pierre Shale. In general, the Niobrara is part of an extensive 

and thick Upper Cretaceous marine system, consisting mostly 
Niobrara Total Petroleum System (TPS) 31

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Johnson 

Campbell 

Big Horn 

Crook 

Converse 

Weston 

Niobrara 

Sheridan 

Natrona 

Powder River 

Rosebud 

Carter 

 EXPLANATION

 

 

Montana 

Wyoming 

Frontier-Turner Sandstones AU

Sussex-Shannon Sandstones AU

Mesaverde-Lewis Sandstones AU

Niobrara Fm depth greater

than 8,000 feet

Province 5033 boundary

Gas

Oil

Upper Cretaceous 

production

Figure 28. Map showing Upper Cretaceous oil and gas production, area where depth to Niobrara 

Formation is greater than 8,000 feet, and boundaries of assessment units (AU) within the Niobrara Total 

Petroleum System in the Powder River Basin Province. Most Upper Cretaceous production is within 

area where Niobrara Formation is more than 8,000 feet deep. 
32 Geologic Assessment of Undiscovered Oil and Gas in the Powder River Basin Province, Wyoming and Montana

of shale and carbonate with thin, low-permeability, shallow 

marine sandstones. Thicknesses average about 400 ft and 

range from less than 50 ft to more than 600 ft; within the AU 

boundary, average thicknesses are less than 400 ft, ranging 

from about 300 to 500 ft. 

Wireline resistivity logs of the Niobrara Formation are 

used to indicate hydrocarbon richness because hydrocarbons 

are a nonconducting fluid (Smagala and others, 1984). Accordingly, as oil saturation increases (as more hydrocarbons fill 

fractures) resistivity also increases. As Longman and others 

(1998) and Landon and others (2001) have indicated, individual deposition cycles must be mapped separately to accurately 

compare resistivity patterns. Mapping maximum resistivity of 

the total formation as an exploration tool can give misleading 

results. 

The Niobrara Formation averages more than 3 weight 

percent TOC of Type II kerogen in the PRB; Landon and 

others (2001) reported TOC values exceeding 7 weight percent 

in areas adjacent to the PRB. According to Heacock and 

Hood (1970), the formation has the highest averages of TOC 

of all the Upper Cretaceous rocks in the basin. The organic 

matter is mostly concentrated in thin, dark, and shaly laminae, 

whereas the chalky intervals have low TOC consisting of 1 to 

2 weight percent. Because the Niobrara becomes more shaly 

on the west side of the basin, TOC values may increase to the 

west. Owing to kerogen type and temperature, hydrocarbons 

probably did not start generating and migrating until the 

formation had reached a burial depth of at least 7,000 ft. 

Modeling of basin structural, depositional, and thermal 

histories shows that significant hydrocarbon generation could 

have started with about 8,000 ft of overburden (fig. 28).

Source Rock Thermal Maturity

Thermal maturity of the Niobrara Formation was 

evaluated using standard methods including Ro

 and depth 

plots, Rock-Eval pyrolysis data, correlation of resistivity 

and Ro

, and constructing burial history models for the east 

and west sides of the basin. Published Ro

 data were not 

conclusive because vertical depth profiles rarely fit a normal 

(linear) profile. Rock-Eval pyrolysis data were sporadic and 

also not conclusive. Smagala and others (1984) correlated 

Ro

 and resistivity as a semilog plot, and suggested that there 

is a correlation between in-situ generated hydrocarbons and 

high electrical resistivity of hydrocarbons. However, if the 

data are normalized to a constant temperature, the trend line 

flattens, indicating that there is a range of resistivity to identify 

a particular level of maturity and that the technique should be 

used only empirically. 

The software PetroMod1D (Integrated Exploration 

Systems, 2002) was used to model burial-history curves for 

the Niobrara TPS and the Mowry TPS. Results show that 

(1) on the east side of the basin, the Niobrara Formation did 

not reach thermal maturity (fig. 18); (2) on the west side of 

the basin, hydrocarbon generation started at about 30 Ma at 

a depth of about 8,000 ft (fig. 19) and at an Ro of 0.6 weight 

percent; (3) at the base of the formation the Niobrara reached a 

maximum Ro

 of about 0.68 percent at about 10 Ma, at a depth 

of about 9,700 ft; and (4) Ro

 is currently at about 0.68 percent. 

These modeled Ro

 values indicate that the Niobrara probably 

did not reach thermal maturation to generate nonassociated 

gas but could reach gas-generating temperatures in the deepest 

parts of the basin. 

Geologic events charts (fig. 29) show the elements that 

define the Frontier-Turner Sandstones AU, the SussexShannon Sandstones AU, and the Mesaverde-Lewis 

Sandstones AU. 

Hydrocarbon Migration

Unlike the Mowry TPS, Niobrara TPS production is 

almost exclusively confined to the Niobrara hydrocarbon 

generation area, indicating that most Niobrara migration has 

been vertical (fig. 27). The exception is that a few fields 

(Finn-Shurley, Todd, Coyote Creek South, and other small 

fields) on the east side of the basin produce almost exclusively 

from the Turner Sandy Member. The Turner in that area was 

sourced either by Niobrara oil migrating from the west or by 

Mowry oil migrating vertically through connected faults or 

fracture zones associated with the Belle Fourche arch. 

The lack of production in the northern part of the 

Niobrara hydrocarbon generation area (fig. 27) could be 

explained similarly by the following reasons: (1) northward 

migration would be along strike, therefore, not subject to 

buoyancy flow; (2) the northeast-trending structures confined 

migration parallel to the structures, even though presentday groundwater flow is north in the north half of the basin 

and south in the south half of the basin; (3) lack of quality 

reservoirs; (4) the area is underpressured or has normal 

pressure, so there is a lack of pressure or hydraulic gradients to 

“push” hydrocarbons into potential reservoirs; or (5) various 

combinations of the above reasons. 

Because all Upper Cretaceous reservoirs are encased 

in marine shale, even as much as several hundred feet, the 

most plausible explanation appears to be that vertical fault 

and fracture pathways in shale connect the Niobrara both 

to underlying and overlying reservoirs. Most rock fracture 

and fault lengths (or size) follow a power law distribution 

(meaning many short lengths and few long lengths) with 

the long lengths forming connected pathways. In addition, 

the longer lengths help connect shorter lengths to increase 

effective storage and pathways to a well bore (Dershowitz and 

others, 1999). 

Plots of API gravity and gas/oil ratios (GOR) of Upper 

Cretaceous oils show a northwest-southeast trend; GOR values 

decrease sharply northwest and southeast from the Belle 

Fourche arch, and API values decrease only northwest of the 

arch (fig. 30). Additionally, oil from fields east of the Niobrara generation area (for example, Finn-Shurley field) have 

similar API values as does the south half of the Niobrara 
Niobrara Total Petroleum System (TPS) 33

BASIN TYPE 

TRAP FORMATION 

MIGRATION 

OVERBURDEN ROCK 

GENERATION 

SOURCE ROCK 

PETROLEUM 

SYSTEM EVENTS 

GEOLOGIC 

TIME 

SCALE 

RESERVOIR ROCK 

SEAL ROCK 

PALEO. EOCENE OLIG. MIOCENE PP 

MESOZOIC CENOZOIC 

TR TERTIARY 

E. M. L. E. M. L. E. L. 

JURASSIC CRETACEOUS 

Niobrara Formation 

Upper Cretaceous reservoirs 

Stratigraphic 

Foreland structural basin 

Structural 

250 200 150 100 70 75 60 50 40 30 20 10 0 

Powder River Basin Province—Niobrara TPS

 Frontier-Turner Sandstones AU

Events Chart

Ma 

QUAT

A

BASIN TYPE 

TRAP FORMATION 

MIGRATION 

OVERBURDEN ROCK 

GENERATION 

SOURCE ROCK 

PETROLEUM 

SYSTEM EVENTS 

GEOLOGIC 

TIME 

SCALE 

RESERVOIR ROCK 

SEAL ROCK 

PALEO. EOCENE OLIG. MIOCENE PP 

MESOZOIC CENOZOIC 

TR TERTIARY 

E. M. L. E. M. L. E. L. 

JURASSIC CRETACEOUS 

Niobrara Formation 

Upper Cretaceous reservoirs 

Stratigraphic 

Foreland structural basin 

Structural 

250 200 150 100 75 70 60 50 40 30 20 10 0 

Powder River Basin Province—Niobrara TPS

 Sussex-Shannon Sandstones AU

Events Chart

Ma 

B

QUAT

Figure 29. Events chart for assessment units (AU) in the Niobrara Total Petroleum System (TPS) in the Powder River Basin, 

Wyoming. (A) Frontier-Turner Sandstones Assessment Unit; (B) Sussex-Shannon Sandstones Assessment Unit; and (C) MesaverdeLewis Sandstones Assessment Unit. Geologic time scale is in millions of years. Quat., Quaternary; PP., Plio-Pleistocene; Olig., 

Oligocene; Paleo., Paleocene; E., Early; M., Middle; L., Late.; TR., Triassic.
34 Geologic Assessment of Undiscovered Oil and Gas in the Powder River Basin Province, Wyoming and Montana

generation area, but GOR values are similar to those northwest and southeast of the Belle Fourche arch in south-central 

Campbell County (figs. 4, 30). In the vicinity of the arch, API 

and GOR values are both high; northwest of the arch API and 

GOR values are both low, and southeast of the arch and east 

of the generation area, values are high for API but low for 

GOR. Because there is little hydraulic potential to migrate 

oil from the Niobrara generation area eastward toward the 

Finn-Shurley and nearby fields, there is the possibility that 

those fields were sourced through vertical migration. Interpretation of the API and GOR data is not conclusive but suggests 

that Upper Cretaceous fields are producing oil that is similar 

to Niobrara-generated oil. The data also show that pathways 

from the generation area to the eastern fields were relatively 

direct, not the tortuous routes commonly found in fractured 

shale (Neuzil, 1986).

Reservoir Rocks

Frontier Formation

The Upper Cretaceous Frontier Formation was deposited 

as an eastward-prograding clastic wedge into a foreland 

basin in response to the Sevier orogenic disturbance in 

Late Cretaceous Cenomanian to Turonian time. Proximal 

lithologies of the clastic wedge include coarse-grained 

nonmarine fluvial strata incised into marine strata, whereas 

distal lithologies include marine nearshore strata. The Frontier 

overlies the Mowry Shale and underlies the Cody Shale; the 

base and top of the Frontier are marked by the Clay Spur 

Bentonite Bed and an unnamed bentonite, respectively. 

Ammonite zones that bracket the Frontier include Calycoceras 

gilberti at the base and Scaphites nigricollensis at the top 

(Merewether and others, 1976, 1979). 

BASIN TYPE 

TRAP FORMATION 

MIGRATION 

OVERBURDEN ROCK 

GENERATION 

SOURCE ROCK 

PETROLEUM 

SYSTEM EVENTS 

GEOLOGIC 

TIME 

 SCALE 

RESERVOIR ROCK 

SEAL ROCK 

PALEO. EOCENE OLIG. MIOCENE PP 

MESOZOIC CENOZOIC 

TR TERTIARY 

E. M. L. E. M. L. E. L. 

JURASSIC CRETACEOUS 

Niobrara Formation 

Upper Cretaceous reservoirs 

Stratigraphic 

Foreland structural basin 

Structural 

250 200 150 100 70 75 60 50 40 30 20 10 0 

Powder River Basin Province—Niobrara TPS

 Mesaverde-Lewis Sandstone AU

Events Chart

Ma 

C

QUAT

Figure 29. Events chart for assessment units (AU) in the Niobrara Total Petroleum System (TPS) in the Powder River Basin, 

Wyoming. (A) Frontier-Turner Sandstones Assessment Unit; (B) Sussex-Shannon Sandstones Assessment Unit; and (C) MesaverdeLewis Sandstones Assessment Unit. Geologic time scale is in millions of years. Quat., Quaternary; PP., Plio-Pleistocene; Olig., 

Oligocene; Paleo., Paleocene; E., Early; M., Middle; L., Late.; TR., Triassic.—Continued
Niobrara Total Petroleum System (TPS) 35

API (gravity) 

1–37

38–40

41–43

44–52

County boundary

Niobrara Fm depth > 8,000 feet

Province 5033 boundary

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Johnson 

Campbell 

Big Horn 

Crook 

Converse 

Weston 

Niobrara 

Sheridan 

Natrona 

Powder River 

Rosebud 

0 

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42 

EXPLANATION

A

Montana 

Wyoming 

Niobrara Fm. Oil

Upper Cretaceous

oil production 

Figure 30. Map of Powder River Basin Province showing Upper Cretaceous production, area where 

depth to Niobrara Formation is greater than 8,000 feet. (A) average API gravity for Upper Cretaceous 

fields; (B) average gas/oil ratio (GOR) for Upper Cretaceous fields. API and GOR data from NRG 

Associates, Inc. (2006).
36 Geologic Assessment of Undiscovered Oil and Gas in the Powder River Basin Province, Wyoming and Montana

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Big Horn 

Campbell 

Johnson 

Crook 

Converse 

Weston 

Niobrara 

Sheridan 

Natrona 

Powder River 

Rosebud 

0 

0 

71 

12 

302 

621 

293 

219 

113 

511 

323 

301 

343 

426 

744 

448 

504 

410 

589 

297 

329 

563 

638 

525 

343 

964 

764 

723 

512 

841 

1282 

2076 

1793 

1326 

1243 

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1103 

1964 

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3851 

2571 

5490 

5032 

1257 

1669 3821 

8322 

8740 

4189 

5430 

2203 5109 2145 

2299 

11039 

12654 

GOR

0–964

965–2,571

2,572–5,490

5,491–12,654

12,655–28,996

County boundary

Province 33 boundary

Niobrara Fm depth > 

 

 

Niobrara Fm. Oil

B

Montana 

Wyoming 

8,000 feet

EXPLANATION

Upper Cretaceous

oil production

Figure 30. Map of Powder River Basin Province showing Upper Cretaceous production, area where 

depth to Niobrara Formation is greater than 8,000 feet. (A) average API gravity for Upper Cretaceous 

fields; (B) average gas/oil ratio (GOR) for Upper Cretaceous fields. API and GOR data from NRG 

Associates, Inc. (2006).—Continued
Niobrara Total Petroleum System (TPS) 37

In the PRB there are three members of the Frontier 

Formation —the lower Belle Fourche Member, the middle 

Emigrant Gap Member (Merewether, 1996) called the 

unnamed member by Merewether and others, 1976), and the 

upper Wall Creek Sandstone Member. Fine-grained rocks 

compose about half of the total interval and include laminated 

to variably bioturbated shales and siltstones with several 

bentonite beds that are regionally persistent. Facies and 

geometry of sandstones indicate probable deposition as delta 

lobes (for example, Coleman and Wright, 1975; Bhattacharya 

and Walker, 1992; Johnson and Baldwin, 1996; Bhattacharya 

and Willis, 2001). The deltas were probably truncated at the 

top during transgression, as evidenced by a lack of subaerial 

exposure, presence of topset lags, and truncated inclined beds. 

Belle Fourche Member

The Belle Fourche Member is generally confined to the 

southwestern part of the basin. It is divided into four internal successions, informally termed 1st through 4th Frontier 

(Merewether and others, 1979). Numerous environments of 

deposition have been recognized on the basis of having various percentages of fluvial, estuarine, nearshore, and deepwater 

strata (Barlow and Haun, 1966; Merewether and others, 1979; 

Tillman and Merewether, 1994; Bhattacharya and Willis, 

2001). In the PRB all four successions have similar sedimentation characteristics, including (1) coarsening upward from 

marine shale to nearshore marine sandstone and (2) eroded 

tops capped with a coarse-grained lag over an erosional 

surface. 

Individual sandstones consist of very fine to fine-grained 

siliciclastics with planar to low-angle cross stratification. 

Sandstone thicknesses range from 50 ft in the southwestern 

part of the basin to a zero edge toward the east and southeast. 

Unlike the Wall Creek Sandstone Member, there is not a 

basinward sandstone equivalent of the Belle Fourche Member. 

Sandstones within the interval have similar reservoir parameters including porosity that ranges from 5 to15 percent and 

permeability that ranges from 1 to less than 100 mD. 

Emigrant Gap Member 

The Emigrant Gap Member (unit five of Merewether and 

others, 1979; Ryer, 1993) is a single succession bounded by 

unconformities with extensive top truncation. The member has 

limited extent compared with other Frontier Formation members. The Emigrant Gap has been mapped as two elongated, 

but narrow packages of sandstone, siltstone, and mudstone, 

one trending east-west near Casper, Wyoming, and another 

northwest-southeast between Buffalo and Kaycee, Wyoming. 

The member can be as much as 90 ft thick, with maximum 

sandstone thicknesses of 30 ft. Subsurface hydraulic characteristics of this member are not known. 

Wall Creek Sandstone Member 

The Wall Creek Sandstone Member (units six, seven, 

and eight of Merewether and others, 1979) disconformably 

overlies the Emigrant Gap Member and the Belle Fourche 

Member where the Emigrant Gap Member is absent. The Wall 

Creek consists of several successions of coarsening-upward 

mudstone, siltstone, and sandstone in a prograding deltaic 

environment. Several sea-level falls might have caused top 

truncation of some beds and consequent progradation of delta 

lobes eastward into the basin interior. The sandstones are 

generally well sorted and fine to locally medium grained, with 

varying amounts of detrital clay. Porosity values of sandstones 

range from near zero to 20 percent, with hydrocarbonproducing sandstones having porosities between 10 to 

20 percent. Permeability of sandstones from some facies can 

be as much as 100 mD but averages much less than 100 mD. 

The Wall Creek Sandstone Member thicknesses are 

as much as 400 ft in western Converse County and eastern 

Natrona County, Wyoming. Thickness trends appear to align 

east-west, although erosional surfaces within the Wall Creek 

Sandstone Member may preclude making meaningful interpretations of original depositional trends. In addition, the dominant paleocurrent directions are southeast, indicating a general 

progradation in that direction (Merewether and others, 1979). 

Turner Sandy Member

The Turner Sandy Member of the Carlile Shale (fig. 27) 

is generally linked to the Frontier Formation as a stratigraphic 

or chronographic equivalent, although there is little direct 

confirming evidence. Weimer and Flexer (1985) described 

the Turner as being a brackish to marine deposit in northeasttrending valleys with the lower part deposited in tidal flat 

and estuary environments. Rice and Keighin (1989) inferred 

that the lower part was deposited as an elongated sand body 

in a shelf depression, whereas Merewether and others (1979) 

suggested that the Turner was deposited from Wall Creek 

sands carried by tidal currents to an open shelf, although 

postdeposition transgression removed or reworked various 

parts.

Based on this detailed mapping of the Frontier Formation 

on the southwest side of the basin, Bhattacharya and Willis 

(2001) inferred that sea-level falls induced a progradation 

of Frontier delta sands basinward to the east and southeast, 

which then became detached from the main body and were 

deposited onto a previous offshore shelf during a regressive 

lowstand; this is similar to a process described by Plint (1988). 

Subsequent transgressions created surfaces that eroded sediment from bathymetric highs while reworking but preserving 

sand in low areas. Some or most of the original connection 

between the Turner and the Frontier was eroded over bathymetric highs, the Turner being preserved in bathymetric lows 

(fig. 31). Cores of the Turner from a well in the Finn-Shurley 

field showed the presence of two erosion surfaces, one at 

the base of the Wall Creek Sandstone Member marked by 
38 Geologic Assessment of Undiscovered Oil and Gas in the Powder River Basin Province, Wyoming and Montana

medium-grained, sharp-based sandstone and another halfway 

up from the base of the Wall Creek, marked by a thin pebble 

lag (fig. 31). Turner cores from the Porcupine Field (west 

of Finn-Shurley field) showed the presence of an erosional 

surface at the base of the Wall Creek, marked by mediumgrained, sharp-based sandstone over a thin pebble lag. 

In places, the Turner Sandy Member is more than 70 ft 

thick in the Finn-Shurley field but thins to less than 20 ft to 

the west and east. Core plugs in sandstone at Finn-Shurley 

field had measured permeability exceeding 2 darcies from 

medium-grained, clean, well-sorted sand. Core plugs from 

Porcupine field have measured permeability of more than 

10 mD from slightly argillaceous, fine-grained sandstone but 

less than 10 mD from argillaceous, fine-grained, and slightly 

bioturbated sandstone. 

Cody Shale

Shannon Sandstone Member

The Shannon Sandstone Member of the Upper 

Cretaceous Cody Shale was deposited as clean to argillaceous 

sand during early Campanian time in southeastern Montana, 

northeastern Wyoming, and northwestern South Dakota. 

Shannon Sandstones form conspicuous northwest-southeasttrending linear sand ridges; individual units are as much as 

50 ft thick, thousands of feet in width, and tens of miles in 

length. Both the Shannon and the overlying Sussex Sandstone 

Member represent distal ends of a transgressive-regressive 

wedge of a deltaic system to the north and northwest along 

the west margin of the Cretaceous seaway. One interpretation 

is that they were deposited as shelf sands or offshore bars, 

encased in marine shales, because of their classic upward 

coarsening grain size from a muddy shelf base, to fine- to 

medium-grained, well-sorted, clean and porous, cross- to 

planar-bedded sandstone at the top. Other interpretations 

include their being reworked delta systems, or they are incised 

nearshore and valley complexes, both of which require 

progradation events from a sea-level lowstand that created a 

variety of disconformities at the top and base (Bergman and 

Walker, 1995). An alternative interpretation for the origin of 

the Shannon might be similar to that of the Turner—that is, 

the depositional processes involved a transgressive ravinement 

surface upon which sand was preserved in bathymetric lows 

but eroded sediment over highs, the pattern of which may have 

been structurally controlled in part. 

Shannon Sandstone Member porosity ranges from near 

zero in argillaceous and bioturbated silt and sandy layers to 

over 20 percent in clean, well-sorted, medium-grained sandstone. Permeability ranges from less than 1 mD to more than 

100 mD, with a mean of 20 mD. 

Sussex Sandstone Member

The Sussex Sandstone Member of the Cody Shale was 

deposited during early Campanian time and was separated 

from the underlying Shannon Sandstone Member by tens of 

feet of marine shale. The member is informally subdivided 

into three units (Anderman, 1976): a lower B sandstone, a 

middle marine shale, and an upper A sandstone. Similar to the 

Shannon, the Sussex was originally interpreted to be deposited as a middle shelf bar in moderate to deep water, with the 

sand being transported across the shelf bottom from nearshore 

sand accumulations. Sandstone body geometry similar to the 

Shannon, is dominated by northwest-southeast-trending linear 

sandstone units, tens of miles long, 2–3 miles wide, and tens 

of feet thick. Sussex production tends to cluster about two 

areas, one along the House Creek–Porcupine field trend and 

the other farther west along the Spearhead Ranch–Scott field 

trend (fig. 32). Production tends to cluster along a single trend 

represented by the Hartzog Draw, Pine Tree, and Jepson fields 

(fig. 33), with most production being west and north of Sussex 

Sandstone Member production.

The top of the reservoir B sandstone is approximately 20 

to 60 ft below the Ardmore Bentonite Bed of the Steele Shale, 

based on correlation of well logs and core studies. Higley and 

others (1997) interpreted the B sandstone to have originated 

as a series of probable midshelf sand-ridge deposits in the 

Cretaceous epicontinental seaway (fig. 34). At House Creek 

field, for example, there are such units composing B sandstone. Higley and others (1997) inferred that a transgression 

during deposition created the westward (landward) backstepping stacked sand ridges, followed by a regression marked by 

a disconformity at the top of the sandstone identified by thin 

chert-pebble sandstone (Higley, 1992). 

Interridge lithologies consist mainly of burrowed and 

intact mudstone laminae, interbedded mudstone, and burrowed, fine-grained sandstone. These lithologies are effective 

permeability barriers, resulting in small reservoir compartments; this may be a cause for low production volumes. 

Thicknesses of the Sussex B sandstone vary from a few 

feet to more than 50 ft depending on the number of stacked 

ridges and the amount of erosion that occurred both internally 

and at the top of the sequence. The Sussex A sandstone has a 

similar depositional history but is thinner and more discontinuous except at the Triangle U field where it is thicker and 

more continuous than the underlying Sussex B sandstone. At 

the Triangle U field, the A sandstone has permeability ranging 

from 2.5 to 77 mD, with an average porosity of 13.5 percent, 

whereas the B sand has both lower permeability (0.01 to 

5.4 mD) and a porosity average less than 10 percent (Smith

and Larsen, 1997).
Niobrara Total Petroleum System (TPS) 39

EXPLANATION

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Campbell 

Big Horn 

Crook 

Converse 

Weston 

Niobrara 

Sheridan 

Natrona 

Powder River 

Rosebud 

Sussex production 

' Gas

' Oil

Sussex-Shannon Sandstones

AU boundary

County boundary

Niobrara depth > 8,000 feet

Province 5033 boundary

Montana 

Wyoming 

Figure 32. Map of Powder River Basin Province showing Sussex Sandstone Member oil and gas 

production, Sussex-Shannon Sandstones Assessment Unit (AU) boundary, and area where depth to Niobrara 

Formation is more than 8,000 feet.
40 Geologic Assessment of Undiscovered Oil and Gas in the Powder River Basin Province, Wyoming and Montana

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Big Horn 

Crook 

Converse 

Weston 

Niobrara 

Sheridan 

Natrona 

Powder River 

Rosebud 

' Gas

' Oil

Sussex-Shannon Sandstones

AU boundary

Province 5033 boundary

County boundary

Niobrara depth > 8,000 feet

Montana 

Wyoming 

EXPLANATION

Shannon production

Figure 33. Map of Powder River Basin Province showing Shannon Sandstone Member oil and gas 

production, Sussex-Shannon Sandstones Assessment Unit (AU) boundary, and area where depth to Niobrara 

Formation is more than 8,000 feet. 
Niobrara Total Petroleum System (TPS) 41

Shale

Cody Shale

Ripple-laminated, tabular, and 

wavy-bedded sandstone

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sand beds

Basal and upper disconfirmities

Chert-pebble lag

Glauconitic trough-crossbedded sandstone

Trough-crossbedded

sandstone

Primary current

direction to southwest

Sussex “B” Sandstone

Cody Shale

Figure 34. Generalized cross section showing generalized facies distribution of the Sussex “B” sandstone, Powder River Basin. 

Modified from Higley and others (1997).

Mesaverde Formation

Parkman Sandstone Member

The Parkman Sandstone Member of the Upper Cretaceous Mesaverde Formation (fig. 27) is the oldest sandstone 

member in a widespread cycle of Late Cretaceous regression 

and transgression following the long period of predominantly 

marine deposition represented by the thick Steele Shale (or 

Cody Shale to the west of the PRB). The member consists 

of a progradational delta complex that overlies the extensive 

marine shelf deposits of the Steele Shale. Lithologies include 

(1) prodelta shale and siltstone interbedded locally with very 

fine grained, well-sorted sandstone; (2) nearshore deposits of 

coarsening-upward successions of medium-grained sandstone 

with interbedded siltstone; and (3) terrigenous deposits of 

carbonaceous to lignitic silt and mudstone. Depth to Parkman 

reservoirs range from 5,000 ft to more than 9,500 ft near the 

Basin axis (Dolton and Fox, 1995). 

Van Wagoner and others (1990) divided the Parkman 

Sandstone Member into one progradational parasequence and 

the overlying Teapot Sandstone Member into two sequences. 

The lower Parkman appears to step basinward to the east, 

producing in the subsurface a well-log pattern characteristic 

of a progradational succession. Based on faunal zones, the 

member’s basinward time equivalent is the Red Bird Silty 

Member of the Pierre Shale. The top of the Parkman interval 

is bounded by a flooding surface caused by an abrupt increase 

in water depth recognized in well-log correlations as a planar 

surface (Van Wagoner and others (1990). Within each succession are minor flooding surfaces that create laterally variable 

units of interbedded mudstones and siltstones.

Teapot Sandstone Member 

The Teapot Sandstone Member was named after Teapot 

Rock, a prominent cliff-forming feature north of Casper, 

Wyoming. The nearby type section (Curry, 1976a) includes 

both marine and nonmarine sandstones, coals, and other 

associated lithologies. Curry (1976a) described the Teapot, 

from base to top, as 255–275 ft of lower prodelta shale, 

55–70 ft of delta front strata, and 40–50 ft of nonmarine delta 

plain strata. 
42 Geologic Assessment of Undiscovered Oil and Gas in the Powder River Basin Province, Wyoming and Montana

The prodelta section is dark-colored shale, with a regional 

unconformity at the base (Gill and Cobban, 1973; Krystinik 

and DeJarnett, 1995). The delta front strata consist of coarsening upward, lightly burrowed, thin sandstone laminations 

with low to medium cross stratification in places; fine-grained 

intervals are interpreted as lower shoreface. Geophysical logs 

indicate that if the contact with the underlying prodelta shale 

is sharp, as in WC and Mikes Draw fields, the unit is generally 

a thick sandstone (average thickness 30 ft) with good logcalculated porosity. If the contact is gradational, only the top 

few feet of the delta-front strata are sand rich, with variable 

log-calculated porosity. This interval is overlain by horizontal 

laminated and oxidized medium-grained sandstone interpreted 

as nearshore to beach with exposed root zones at the top. The 

delta-front facies contributes most of the oil production. 

The delta plain deposits consist of a variety of lithologies 

including distributary and overbank sandstone and siltstone, 

carbonaceous material including plant impressions, and thin 

discontinuous lignitic zones. 

The Teapot Sandstone Member is composed of two 

progradational intervals (Van Wagoner and others, 1990). 

The upper boundary of the lower interval is terminated by a 

major erosional event and a slight basinward shift in facies. 

The overlying set is composed of two intervals separated 

by a marine-flooding surface—shallow-marine sandstones 

below the boundary and deeper water mudstones above. The 

member’s basinward time equivalent is an unnamed shale of 

the Pierre Shale. 

Lewis Shale

Teckla Sandstone Member 

The Teckla Sandstone Member of the Lewis Shale is an 

Upper Cretaceous (uppermost Campanian, Baculites eliasi 

zone) marine sandstone and shale unit that is a secondary 

exploration target in the middle and southern parts of the 

PRB (fig. 35). The Teckla is part of a regressive-transgressive 

interval within the thick marine Lewis Shale, which is a time 

equivalent of the Bearpaw Shale of Montana and the upper 

part of the Pierre Shale of southern Wyoming and eastern 

Colorado. The Lewis Shale thickens from less than 300 ft 

in the northern part of the Basin to more than 1,500 ft in the 

southern part (Fox and Higley, 1996b). 

The reference section for the Teckla Sandstone Member 

is the Gulf Oil Corporation, no. 1 Government-Teckla well, in 

southeastern Campbell County, Wyoming (T. 41 N., R. 70 W., 

sec. 10). At the reference section, the Teckla is divided into 

three members: a lower 44-ft sandstone (informally called the 

Teckla B sand), a middle 38-ft bentonitic shale (informally 

called the Kara shale bed), and an upper 112-ft sandstone 

(informally called the Teckla A sand) (Runge and others, 

1973). According to Runge and others (1973), the contacts 

at the base and top of the Teckla are conformable, with no 

apparent discontinuity.

The Teckla Sandstone Member is part of a northeastprograding delta system with a north-northwest-trending 

strand line. At various times, the delta system migrated from 

northwest to southeast along the strand line. The northwestern 

part of the system was not extensive and had little sediment 

capacity with low accommodation space. The southeastern 

delta, in contrast, had more sediment capacity and more 

accommodation space. As a result, the Teckla in the southern 

part of the PRB has good reservoir-quality sandstones. At its 

reference section, the Teckla consists of a regressive delta 

front sandstone (Teckla B) overlain by the Kara shale bed, 

representing a short transgressive event; this was followed 

by another regressive event that deposited the Teckla A delta 

front sandstone. West of the reference section, delta plain units 

were deposited and overlie parts of the Lewis Shale where 

the Teckla is absent. From geophysical log interpretations, 

the delta plain deposits appear to consist of thin channel and 

overbank sandstone and interchannel mudstone and siltstone. 

The deposits trend north-northwest and are thickest in the 

southwestern part of the basin, with thicknesses as much as 

600 ft but thinning to the east and north. The sandstones east 

of the reference section average 15-percent porosity and about 

30-mD permeability, although the best permeability is usually 

less than 100 mD. Teckla delta-front sandstones gradually 

interfinger with the prodelta facies consisting of thin siltstone 

and shale. The prodelta facies has a similar trend as the deltafront interval. 

Traps and Seals

Traps in the Niobrara TPS can be characterized mostly as 

stratigraphic with structural enhancement in places, but only 

rarely with four-way structural closure. Most commonly, oil 

is trapped because reservoir-quality sandstones are adjacent 

to low-porosity and low-permeability siltstones, shales, or 

mudstones that were deposited during repeated transgressions, thereby creating permeability barriers to oil migration. 

Diagenetic alteration that reduced porosity is rare as a trapping 

mechanism. Stratigraphic traps due to incised valley systems 

are also rare although bathymetric low areas in foreland basins 

may trap and help preserve sand deposits during ravinement 

processes. Low areas in a subtidal setting may be structurally 

controlled similar to incised valley systems in a supratidal 

setting. 

Structural traps are a result of Laramide deformation 

that created numerous structural styles and types at various 

scales. Most structures in the basin were created prior to oil 

migration. Moore (1985) interpreted an east-west seismic line 

on the west side of the basin that showed potential fault traps 

involving the Frontier Formation as well as older rocks. 

Poison Draw field is the largest field that produces oil 

from the Teckla Sandstone Member; there, the reservoir is a 

complex unit of deltaic strandline sandstones in which oil is 
Niobrara Total Petroleum System (TPS) 43

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4 

n 

Big Horn 

Campbell 

Johnson 

Crook 

Converse 

Weston 

Niobrara 

Sheridan 

Natrona 

Powder River 

Rosebud 

EXPLANATION

Teckla production

' Oil and gas

Parkman production

' Oil and gas

Teapot production

' Oil and gas

County boundary

AU boundary

Niobrara depth > 8,000 feet

Province 5033 boundary

Montana 

Wyoming 

Figure 35. Map of Powder River Basin Province showing oil and gas production of Parkman Sandstone and 

Teapot Sandstone Members of Mesaverde Formation and Teckla Sandstone Member of Lewis Shale of the 

Mesaverde-Lewis Conventional Oil and Gas Assessment Unit (AU), and the area where depth to Niobrara 

Formation is more than 8,000 feet.
44 Geologic Assessment of Undiscovered Oil and Gas in the Powder River Basin Province, Wyoming and Montana

trapped by an updip loss of porosity because of an increase in 

siltstone and shale. The complexity is attested to by the presence of multiple oil/water contacts. One of the largest Teapot 

Sandstone Member producing fields, Well Draw, is a large, 

northwest-trending stratigraphic trap formed by an updip 

facies change from porous shallow-water marine sandstone 

into tight, offshore siltstone and shale. The Parkman Sandstone Member characteristically produces oil from accumulations trapped within northwest-trending marine bar sandstones 

(fig. 35), as at Dead Horse Creek–Barber Creek field. 

Niobrara Total Petroleum System as a 

Continuous Reservoir

The Niobrara Formation is in part a self-contained 

petroleum system in that it is a hydrocarbon source rock as 

well as also containing reservoir rocks, a relation that is typical 

of a continuous petroleum system. In the PRB, Niobrara 

thicknesses range from 50 ft near the Black Hills to about 

450 ft thick in the deepest parts of the basin, to a maximum of 

600 ft along the west flank of the basin; basinwide average is 

about 400 ft (Fox and Higley, 1996b, map J). 

Niobrara production is delivered through a network of 

fractures and faults, although the true nature of the networks 

is as yet not well known in detail, such as fracture intensity 

or connectivity, which control rates and distribution of fluids. 

Connectivity is best defined by fracture and fault orientation, 

length (or size in three dimensions), and intensity. Numerous 

studies (for example, Slack, 1981; Anna, 1986a, 1986b; Marrs 

and others, 1984; Martinsen and Marrs, 1985; Maughan and 

Perry, 1986; Mitchell and Rogers, 1993) have shown that 

the pervasive regional structural orientations in the PRB 

are northwest-southeast and northeast-southwest. Different 

orientations may exist, especially when associated with 

local stress systems, but they are minor contributors to the 

regional fracture and fault connectivity patterns. Fracture and 

fault lengths are difficult to measure, although partial length 

distributions can be expanded through statistical methods 

and used to eliminate censoring and bias from mapping. 

Conventional wisdom associates high fracture density with an 

increase in reservoir permeability, which may be true locally, 

but only if fracture length improves the connectivity of a given 

area (commonly called percolation theory). 

Most locally generated fractures are connected by a 

regional system that enhances reservoir permeability (except 

possibly in coals). Geologic sweet spots in the Niobrara, 

therefore, should be determined first by mapping regional 

structural trends and secondly, by mapping local structural 

features such as fractures related to folding. For example, 

outcrop maps and horizontal well formation microimager 

(FMI) well log images of Austin Chalk in south Texas reveal 

that fracture spacing ranges from several fractures to only a 

single fracture per foot for distances of hundreds of feet; the 

several fractures per foot could be considered a sweet spot 

(Fett, 1991). Sweet spots are not necessarily fault related but 

commonly are part of one structural event (Fett, 1991). Rates 

and cumulative production in the Austin Chalk point to large 

rock volumes being drained, indicating that 3-dimensional 

flow is probably taking place in large fractures connected to 

small but numerous fractures. 

There appears to be no correlation, however, when 

comparing sweet spot zones (mapped as lineaments) and 

current Niobrara Formation production in the PRB (fig. 36). 

This discrepancy may be due to several factors: (1) Niobrara 

production rates are not dependent on fractures and faults; 

(2) “sweet spot” areas are incorrectly mapped; (3) there is 

not sufficient control to make a valid comparison; (4) there 

is a bias in targeting other reservoirs as the primary objective 

rather than the Niobrara; therefore, its potential has not 

been established; (5) the Niobrara is used as a bailout zone, 

independent of fracture potential; and (6) increased shale 

content in the western part of the basin may increase fracture 

length but decrease spacing compared with the chalky and 

brittle intervals of the Niobrara. Therefore, “sweet spots” may 

have different characteristics in shale intervals than in chalk 

intervals.

Production data (IHS Energy Group, 2006) indicate that 

the Niobrara Formation from 34 wells has cumulative production of almost 600,000 barrels of oil (BO), 1.9 billion cubic 

feet of gas (BCFG) over a 30-year reporting period. However, few individual Niobrara wells have estimated ultimate 

recoveries (EUR) of over 100 MBO, with most accumulations 

of less than 50 MBO. Individual well-production plots indicate 

that most Niobrara wells produce little if any water from either 

oil or gas wells. Most operators target mid- to upper Niobrara 

strata. Lower zones are also a target but are not as laterally 

persistent as other zones, a condition that may form potential 

stratigraphic traps (Mitchell and Rogers, 1993). 

Water saturations (Sw) in chalk reservoirs that produce 

commercial quantities of oil are commonly less than 50 

percent (for example, the mean Sw for deep Denver Basin 

Niobrara is 0.39 ± 0.1). Intervals with water saturations above 

50 percent are generally marginal or noneconomic. However, 

chalky intervals with high pore surface area may produce economic quantities of oil at saturations greater than 50 percent. 

Paleozoic-Mesozoic Composite Total Petroleum 

System 

The Paleozoic-Mesozoic Composite TPS, which includes 

approximately 8,500 mi2

, is characterized by oil and gas 

accumulations in Laramide structures along the south and west 

margins of the PRB. This also constitutes the Basin Margin 

AU (fig. 37; Dolton and Fox, 1995),which can be described 

as the upthrown side of several coalesced major basementinvolved faults (fig. 38), similar to those described by Stone 

(2002), although some faults are not exposed at the surface. In 

those cases, the inner boundary of the TPS and AU is marked 

by the fold axes of monoclines resulting from basement offset, 

such as the monoclines at Sussex field and the east side of the 
Niobrara Total Petroleum System (TPS) 45

EXPLANATION

Lineament

' Niobrara production

Potential sweet spots

Province 5033 boundary

Niobrara depth > 8,000 feet

Figure 36. Map of the Powder River Basin Province showing Niobrara Formation potential sweet 

spots derived from published lineament and lineament zones, and current production from the Niobrara 

Formation. 
46 Geologic Assessment of Undiscovered Oil and Gas in the Powder River Basin Province, Wyoming and Montana

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Big Horn 

Campbell 

Johnson 

Crook 

Converse 

Weston 

Niobrara 

Sheridan 

Natrona 

Powder River 

Rosebud 

Basin margin production

' Oil

' Gas

Basin Margin AU boundary

County boundary

Province 33 boundary

EXPLANATION

Montana 

Wyoming 

Figure 37. Map of the Powder River Basin Province showing oil and gas production and boundary of the 

Basin Margin Assessment Unit (AU). 
Niobrara Total Petroleum System (TPS) 47

EXPLANATION

Other AUs

Precambrian rocks

Fault

Basin Margin AU

Figure 38. Generalized cross section of basin margin thrusting showing structural positions of Basin Margin Assessment Unit (AU) 

and adjacent assessment units. Diagram modified from Stone (2002).

Casper arch. The outer boundary of the TPS and AU is defined 

by mountain ranges or where the Phanerozoic section is thin or 

absent, although the northwest boundary is somewhat arbitrary 

and is not clearly defined. 

Some of the major boundary structures include the 

Casper thrust, Laramie Range fault, Hartville fault, Bighorn 

Mountain front fault, and a basement-involved thrust on the 

east side of the Casper arch. Smaller or antithetic structures 

are commonly force folds that are associated with faults at 

depth, some with four-way closure, three-way closure, or 

simple compression or buckle folds and associated tension 

faults. The combination of structural and stratigraphic traps 

are generally confined to Cretaceous reservoirs such as Sussex 

and Glenrock South fields, but reservoirs in large structural 

traps such as Salt Creek and Teapot Dome fields may be 

compartmentalized, with the oil and gas confined to specific 

parts of the structure due to spatial changes of porosity and 

permeability. Reservoirs range from Mississippian carbonates 

to Upper Cretaceous siliciclastics and fractured shale. 

Oil was first discovered in this TPS in the late 1880s at 

the Salt Creek field, although commercial production was not 

established until the 1920s. In its early history, the Salt Creek 

field was one of the major oil producers in the United States. 

Other discoveries soon followed, including Big Muddy, Cole 

Creek, North Fork, and Lance Creek, with the discovery wells 

being drilled on mappable surface structures.

Petroleum Source Rocks

Source rocks in the TPS include the same source rocks 

as were described for other TPSs in the PRB described in this 

report: (1) for Paleozoic reservoirs, organic-rich rocks of the 

Permian Phosphoria Formation from west of the province, and 

black shales of the Pennsylvanian Leo Sandstone within the 

province; and (2) for Lower and Upper Cretaceous reservoirs, 

the Mowry Shale and Niobrara Formation, respectively. Cretaceous and Paleozoic reservoirs have distinct oil types related 

to their different sources—gravities of oils in Cretaceous rocks 

are typically 30°–44° API, with less than 1 percent sulfur, 

whereas the Paleozoic oils are typically 20°–35° API, with 1 to 

4 percent sulfur (fig. 39) (NRG Associates, 2006). 

Clayton and others (1997) reported that the Pennsylvanian Leo Sandstone oil is easily distinguished from Minnelusa 

and Cretaceous oil on the basis of chemical and isotopic 

compositions. In addition, analyses of Leo gases indicate that 

the gas was generated at low temperatures and migrated short 

distances. Clayton and others (1997) also observed that (1) oil 

and gas in Leo reservoirs at Lance Creek (southeastern PRB) 

are derived from Cretaceous source rocks; (2) oil produced 

from the Jurassic Canyon Springs Sandstone Member is 

derived from Leo shales, and (3) gas has a Cretaceous rather 

than a Leo source. 
48 Geologic Assessment of Undiscovered Oil and Gas in the Powder River Basin Province, Wyoming and Montana

Because Cretaceous source rocks (Mowry Shale and 

Niobrara Formation) are too shallow to generate hydrocarbons 

in the basin margin of depths less than 4,000 ft, Cretaceous 

hydrocarbons must have migrated short distances from the 

Mowry and Niobrara hydrocarbon generating area (figs. 20 

and 27, respectively) through basin margin faults into Leo 

and Jurassic reservoirs at Lance Creek field and possibly in 

other places. Dennen and others (2005) in their study of oil 

and gas compositions in Teapot Dome field interpreted that 

two oil types were represented, one coming from Cretaceous 

reservoirs and the other from Pennsylvanian Tensleep Sandstone reservoirs. They concluded that Cretaceous oils are less 

mature, show more evidence of secondary biodegradation, 

and have a mixed terrestrial and marine kerogen source. In 

addition, Cretaceous oils can be separated into three different groups, Upper Cretaceous sandstone reservoirs, Upper 

Cretaceous shale reservoirs, and Lower Cretaceous sandstone 

reservoirs, although the distinctions are minor. In contrast, the 

Pennsylvanian Tensleep oil is more mature, less biodegraded, 

has high sulfur content, shows evidence of water washing, and 

has a marine kerogen source.

Hydrocarbon degradation of Cretaceous oil at the 

Teapot Dome Field appears to vary as a function of depth. 

Hydrocarbons from the southern and deeper parts of the field, 

for example, are less degraded than the northern and shallow 

parts. Pennsylvanian oil does not appear to show variation 

within the field or in adjacent fields. According to Dennen and 

others (2005), molecular and isotopic compositions of gases 

indicate that thermogenic gases may have been altered by two 

different microbial processes—methanogenesis and secondary 

bacterial alteration, processes that may occur in several 

locations around the basin margin.

Source Rock Thermal Maturity

Significant amounts of hydrocarbons have not been generated in the basin margin areas because most if not all source 

rocks are too shallow for the maturation level to have reached 

the oil generation window. There may be circumstances where 

local pockets of source rock entered the oil generation window 

because they are in a downthrown fault block (fig. 38) or near 

a localized high thermal source. These possibilities were not 

considered in this assessment. 

Hydrocarbon Migration

Mowry Shale source rock probably began expelling oil 

in Paleocene time, although the timing of oil migration into 

Laramide structures along the basin margin is uncertain. Major 

migration routes appear to trend eastward (fig. 20) rather 

than toward the south and west into the basin margins. The 

volume of Mowry oil that may have migrated toward these 

margins has not been determined, but steep updip gradients 

between the axial part of the PRB and the west margin may 

have provided sufficient buoyancy force to induce Mowry 

oil migration. Oil typing at Teapot Dome field (anticlinal trap 

with multiple stacked reservoirs; Dennen and others, 2005) 

Powder River Basin

0

1

2

3

0 10 20 30 40 50 60

SULFUR, WT %

Low Cretaceous

Upper Cretaceous

Paleozoic

Paleozoic at Salt Creek

Reservoirs

GRAVITY, API

Figure 39. Chart comparing sulfur and gravity values of Powder River Basin oil reservoirs. Paleozoic 

reservoirs are high in sulfur, whereas Lower and Upper Cretaceous and Jurassic reservoirs have low 

sulfur. One Jurassic sample may have a Paleozoic oil component. Data are from Wenger and Reid (1961), 

Coleman and others, (1978). wt %, weight percent.
Cretaceous Biogenic Gas Total Petroleum System 49

indicated that Mowry oil was the dominant oil type in several 

Cretaceous reservoirs at Teapot Dome field and that Niobrara 

oil made only a minor contribution. Because Niobrara oil 

generation started in late Eocene time, Mowry oil could have 

migrated into basin margin structures before Niobrara generation, excluding Niobrara oil, although some oil mixing may 

have occurred. Results of oil typing at Teapot Dome field are 

also assumed to be indicative of the type of oil that is present 

in other basin margin fields with multiple stacked reservoirs, 

especially on the west side of the basin, but data are lacking. 

Basin margin production from Mississippian Madison 

Limestone, Permian Tensleep and Minnelusa Sandstones, and 

Jurassic Sundance Sandstone reservoirs is from long-range oil 

migration from the Phosphoria Formation to the west prior to 

the formation of Laramide structures (Barbat, 1967). During 

the Laramide orogeny, oil was redistributed from stratigraphic 

traps or carrier beds into present-day structures (Moore, 1986). 

Alternative migration models indicate that Tensleep and Minnelusa oil was most likely generated locally because redistributed Phosphoria oil is not a viable model. 

Basin margin production on the south side includes sandstone reservoirs in the Leo and Sundance Formations. The oil 

was generated in the organic-rich shales of the Leo in the deep 

part of the basin, then migrated south along fault and fracture 

networks. Generation and migration probably were in early 

to mid-Paleocene time, which postdates Cretaceous generation and migration into Sundance reservoirs at Red Bird field 

(Clayton and others, 1997).

A geologic events chart (fig. 40) shows the elements that 

define the Basin Margin AU.

Reservoir Rocks

Most of the reservoirs discussed earlier for other TPSs 

are also Basin Margin AU reservoirs, including sandstones of 

the Lower Cretaceous Muddy and Dakota Formations, sandstones of the Upper Cretaceous Frontier Formation, Sussex 

and Shannon Sandstone Members of the Steele Shale, and the 

Pennsylvanian-Permian Tensleep Sandstone. Differences exist, 

however, with respect to structural position, hydraulic fluid 

potential, and depth. In some places fractured shales of 

Cretaceous age are also productive, as is the Mississippian 

Madison Limestone in the northwestern part of this TPS at 

Soap Creek Field. Multiple pay zones in anticlinal traps are 

common; fine-grained rocks intercalated with the reservoirs 

provide seals. A regional seal of Permian-Triassic red beds 

separates Paleozoic and Mesozoic reservoirs in most fields. 

Traps and Seals

Traps are commonly anticlines that rim the south and 

west margins of the basin. Most structures are relatively 

simple folds, reverse-faulted at depth, but with tension faults 

on their crests (Stone, 2002). Fault closures, particularly on 

plunging anticlinal noses, also produce, as do combination 

stratigraphic and structural traps such as Sussex and Glenrock 

South fields. Seals are commonly interreservoir shales or lowporosity siliciclastics. 

Tertiary-Upper Cretaceous Coalbed 

Methane Total Petroleum System 

Conventional accumulations of coalbed methane (CBM) 

are contained in sandstones interbedded with coal beds in 

the upper part of the Tertiary Fort Union Formation in the 

PRB; the assessed sandstones are within the Eastern Basin 

Margin Upper Fort Union Sandstone AU. Gas production from 

coals and contiguous sandstones has been described in detail 

(Flores, 2004; U.S. Geological Survey, 2004) and will not be 

discussed further in this report.

Cretaceous Biogenic Gas Total 

Petroleum System 

Small quantities of what is considered to be biogenic 

gas are currently produced from shallow low-permeability 

Cretaceous reservoirs around the edges of the PRB; ratios 

of methane to C2

 + C3 gas indicate a biogenic origin, but the 

evidence is not totally conclusive as to whether part of the gas 

mix is thermogenic. No isotope values of the gas are known 

to have been published. The assessed strata are within the 

Shallow Continuous Biogenic Gas AU. The gas is sourced and 

trapped as continuous-type accumulations, although structure 

and hydrodynamics may help concentrate the gas. Generation 

of biogenic gas is from methogenesis—that is, the methane is 

a product of O2

 depletion and sulfate reduction in the presence of organic matter in strata that can carry sufficient O2

 in 

the system. However, in a continuous-type system, a reservoir must allow gas to be trapped from capillary retention 

and buoyancy effects. Therefore, Cretaceous marine facies 

including fractured shales and shelf sandstones are well suited 

to trap biogenic gas in unconventional accumulations. Most 

Upper Cretaceous marine reservoirs are characterized by thin, 

discontinuous, low-permeability silty sandstones and silty or 

marly shales. The organic content of the shales can vary from 

less than 1 to more than 4 TOC by weight. 

Depth range for biogenic gas production must be above 

the depth needed to generate thermogenic hydrocarbons. 

The Ro

 at which no thermogenic generation could occur was 

modeled as 0.40, which corresponds to a maximum depth of 

3,400 ft. At such shallow depths, biogenic gas does not accumulate because of leakage and groundwater flushing, but it is 

also dependent on the type of seal rock. 
50 Geologic Assessment of Undiscovered Oil and Gas in the Powder River Basin Province, Wyoming and Montana

Powder River Basin 5033—Paleozoic Mesozoic TPS

 Basin Margin AU

Laramide foreland basin margin

Events Chart

Ma 0

600500400300200100

50

550450350250150

Cretaceous

Paleogene

Permian

Triassic

Jurassic

Precambrian

Cambrian

Ordovician

Silurian

Devonian

E

M

L

EE

E

E

E

M

LL

M

L

E

L

M

L

E

L

M

L

E

M

L

E

L

Mississippian

Pennsylvanian

Neogene

Pal

Eoc

Olig

Mio Plio

Niobrara

Abundant vertical migration along fault zones

GENERATION

BASIN TYPE

TRAP FORMATION

OVERBURDEN ROCK

RESERVOIR ROCK

SEAL ROCK

SOURCE ROCK

PETROLEUM

SYSTEM EVENTS

GEOLOGIC 

TIME

SCALE

MIGRATION

ACCUMULATION

Leo shales Phosphoria Mowry

Figure 40. Events chart of the Basin Margin Assessment Unit (AU) of the Paleozoic-Mesozoic Composite Total Petroleum 

System (TPS) showing multiple reservoirs, sources, and seals. Geologic time scale is in millions of years. Plio, Pliocene; Mio,

Miocene; Olig, Oligocene; Paleo, Paleocene; Eoc, Eocene; E, Early; M, Middle; L, Late.

Assessment of Undiscovered 

Petroleum Resource

Petroleum exploration in the PRB has been long and 

successful since oil was first discovered in the late 1800s. The 

basin has thick, organic-rich petroleum source rocks, a variety 

of reservoir rocks, and numerous types of traps ranging from 

large surface-exposed anticlines, topographically carved paleo 

sand dunes, incised channel sandstones, and overpressured 

tight marine sandstones. Over the years, 68,000 wells have 

been drilled in the basin, of which some 36,000 are currently 

producing or have produced in the past (IHS Energy Group, 

2006). 

The range of undiscovered oil and gas resources 

estimated for the five TPSs and their contained AUs in this 

assessment (table 1) reflects the mature exploration and 

production of the basin. That is, the range in the estimated 

amounts of technically recoverable new, undiscovered 

resources is relatively small because of the limited areas of 

the PRB that contain favorable conditions for hydrocarbon 

accumulation and as yet are untested. However, there is the 

potential for a moderate number of new oil and gas discoveries 

(fields containing a minimum of 5 million barrels of oil 

equivalent (MMBOE), especially on the west side of the basin. 

Following a numbering system established by the USGS 

to facilitate petroleum resource assessment (U.S. Geological 

Survey, 2000), unique six-digit numbers are assigned to 

TPSs—for example, the number 503301 is assigned to the 

Tertiary–Upper Cretaceous Coalbed Methane TPS, in which 

“5” denotes the region (North America), “033” denotes the 

PRB province, and “01” denotes the specific TPS. Assessment 

Units are also uniquely numbered (8 digits) (for reference 

see Klett and Le, this CD–ROM). The numbering system 

established for TPSs and AUs in the PRB is as follows:

503305 Pennsylvanian-Permian Composite TPS

50330501 Minnelusa-Tensleep-Leo AU

503302 Mowry TPS

50330201 Fall River–Lakota Sandstones AU

50330202 Muddy Sandstone AU

50330261 Mowry Continuous Oil AU

503303 Niobrara TPS

50330301 Frontier-Turner Sandstones AU 

50330302 Sussex-Shannon Sandstones AU 

50330303 Mesaverde-Lewis Sandstones AU

50330361 Niobrara Continuous Oil AU

503304 Cretaceous Biogenic Gas TPS

50330461 Shallow Continuous Biogenic Gas AU

503306 Paleozoic-Mesozoic Composite TPS

50330601 Basin Margin AU
Assessment of Undiscovered Petroleum Resource 51

 21.38 56.48 112.13 60.51 0.87 2.52 5.85 2.83 0.02 0.08 0.25 0.10

 0.00 50.90 261.40 81.40 3.34 7.26 13.39 7.32 0.17 0.41 0.86 0.44 

 18.14 58.58 127.53 64.05 18.58 64.98 162.77 74.70 1.03 3.81 10.25 4.48

 16.20 127.30 408.10 192.40 104.85 507.46 1,257.06 574.51 9.72 49.36 131.97 57.47

 10.95 40.62 106.81 47.34 31.03 122.43 360.08 149.14 2.71 10.89 32.87 13.43

 3.50 28.40 118.40 59.10 52.61 214.07 564.62 248.77 4.93 20.79 58.58 24.85

2.46 9.12 21.37 10.18 8.72 34.44 93.45 40.47 0.59 2.41 6.97 2.91

 2.75 7.97 16.98 8.67 2.25 7.09 17.30 8.09 0.17 0.55 1.45 0.65

1.55 5.19 13.20 6.00 1.90 6.97 19.84 8.41 0.13 0.48 1.44 0.59

5.20 43.30 124.20 58.10 0.00 0.00 107.43 27.37 0.00 0.00 0.00 0.00

4.79 16.30 36.76 17.93 3.46 12.58 32.89 14.66 0.11 0.44 1.23 0.53

 62.02 194.26 434.78 214.68 227.61 979.80 2,634.68 1,156.27 19.58 89.22 245.87 105.45

66.90 100.50 151.00 103.60 1,011.94 1,815.71 3,257.89 1,934.09 0.00 0.00 0.00 0.00

66.90 100.50 151.00 103.60 7,232.13 11,635.87 18,721.10 12,132.50 0.00 0.00 0.00 0.00

66.90 100.50 151.00 103.60 0.00 171.67 440.90 197.90 0.00 0.00 0.00 0.00

 116.99 189.32 306.38 197.61 103.35 185.50 332.95 197.61 5.56 10.91 21.37 11.86

 135.53 217.49 349.03 226.67 119.54 213.10 379.87 226.67 6.43 12.53 24.40 13.60

116.99 189.32 306.38 197.61 341.92 712.15 1,483.26 786.64 0.00 0.00 0.00 0.00

 252.52 406.81 655.41 424.28 8,808.88 14,734.00 24,615.97 15,475.41 11.99 23.44 45.77 25.46

 314.54 601.07 1,090.19 638.96 9,036.49 15,713.80 27,250.65 16,631.68 31.57 112.66 291.64 130.91

Total undiscovered resources Total Petroleum Systems 

(TPS) 

and Assessment Units (AU)

Field

type

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

Gas

Oil

Oil

Gas

Gas

Oil

Gas

Oil

Oil

Oil

Oil

Oil

Oil

[MMBO, million barrels of oil. BCFG, billion cubic feet of gas. MMBNGL, million barrels of natural gas liquids. Results shown 

are fully risked estimates. For gas fields, all liquids are included under the NGL (natural gas liquids) category. F95 denotes a 95-

percent chance of at least the amount tabulated. Other fractiles are defined similarly. Fractiles are additive under the 

assumption of perfect positive correlation. CBG, coal-bed gas. Gray shading indicates not applicable]

Gas

CBG

CBG

CBG

Table 1. Powder River Basin Province assessment results. 

Conventional Oil and Gas Resources Continuous Oil and Gas Resources

Total Continuous

Resources

Total Conventional

Resources

Minnelusa-Tensleep-Leo AU

Fall River-Lakota Sandstone AU

Tertiary-Upper Cretaceous

Coalbed Methane TPS

Mowry TPS

Niobrara TPS

Tertiary-Upper Cretaceous

Coalbed Methane TPS

Paleozoic-Mesozoic TPS

Pennsylvanian-Permian

Composite TPS

Mowry TPS

Niobrara TPS

Cretaceous Biogenic Gas TPS

Muddy Sandstone AU

Frontier-Turner Sandstones AU

Sussex-Shannon Sandstones AU

Mesaverde-Lewis Sandstones AU

Eastern Basin Margin Upper

Fort Union Sandstone AU

Basin Margin AU

Wasatch Formation AU

Upper Fort Union Formation AU

Lower Fort Union-Lance

Formation AU

Mowry Continuous Oil AU

Niobrara Continuous Oil AU

Shallow Continuous 

Biogenic Gas AU

Total Undiscovered

Oil and Gas Resources

Table 1. Powder River Basin Province assessment results.

[MMBO, million barrels of oil. BCFG, billion cubic feet of gas. MMBNGL, million barrels of natural gas liquids. Results shown are fully 

risked estimates. For gas fields, all liquids are included under the NGL (natural gas liquids) category. F95 denotes a 95-percent chance of at 

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

CBG, coal-bed gas. Gray shading indicates not applicable]
52 Geologic Assessment of Undiscovered Oil and Gas in the Powder River Basin Province, Wyoming and Montana

503301 Tertiary-Upper Cretaceous Coalbed Methane TPS

50330101 Eastern Basin Margin Upper Fort 

 Union Sandstone AU

A thorough analysis of all the available geologic data, 

as well as performance and development information, was 

presented earlier to a review panel for a final determination 

of the criteria and boundaries to be used for each of the 

AUs. In addition, estimates of the sizes and numbers of 

undiscovered oil and gas accumulations, based on a tabulation of existing field and well records provided by Klett and 

Le (this CD–ROM), were presented on input-data forms to the 

review panel. These input-data forms (see Klett and Le, this 

CD–ROM) constitute the basis for estimating undiscovered 

hydrocarbon resources in each AU. The default minimum 

accumulation size that has potential for additions to reserves 

is 0.5 million barrels of oil equivalent (MMBOE). Other data 

compiled or calculated for each assessment unit to aid in the 

final estimate of undiscovered resources include gas/oil ratios, 

natural gas liquids to gas ratios, API gravity, sulfur content, 

and drilling depth. Additionally, allocations of undiscovered 

resources were calculated for Federal, State, and private lands 

and for various ecosystem regions. All such data are available 

on the completed input-data forms for the individual AUs 

(see Klett and Le, this CD–ROM). The input form, a Seventh 

Approximation Data Form for Conventional Assessment 

Units, v. 6, developed by Charpentier and Klett (2005), is 

shown in Appendixes A–J. The form is organized into six 

major sections. The source of the known accumulation data is 

the Nehring database (NRG Associates, 2006) which provides 

accumulation size data for most fields in the United States. 

Assessment of Undiscovered 

Petroleum Resources in Conventional 

Assessment Units

Minnelusa-Tensleep-Leo AU (50330501)

The Minnelusa-Tensleep-Leo AU includes most of the 

interior part of the PRB. The Tensleep and Leo Sandstones are 

located on the west and southeast edges of the AU, respectively (fig. 5). Tensleep Sandstone nomenclature is problematic as some operators use the term Minnelusa and some use 

Tensleep for the same unit, especially on the west side of the 

basin. Although Tensleep is stratigraphically equivalent to the 

lower part of the upper Minnelusa Sandstone (fig. 6), for this 

assessment Minnelusa and Tensleep were used interchangeably. The Minnelusa-Tensleep reservoirs are the most prolific 

oil producers in the PRB, with most of the production in this 

AU; Leo sandstones contribute little production. 

The Minnelusa-Tensleep-Leo units have production of more than 600 million barrels of oil (MMBO) from 

approximately 1,700 producing wells in 167 fields (NRG 

Associates, 2006). In addition, some 7,000 wells have penetrated all or parts of the Minnelusa-Tensleep-Leo section (IHS 

Energy Group, 2006), which includes more than 3,700 new 

field wildcats (NRG Associates, 2006). Field size ranges from 

less than 0.5 to 48 MMBO with a mean and median of 3.7 

and 2.0 MMBO, respectively. The average field depth exceeds 

8,000 ft and ranges from 4,000 ft to more than 14,000 ft, 

although most production is from less than 12,000 ft. Oil gravity in most fields ranges from 20o to 30o API gravity but can 

range from 15o to 50o API gravity. 

Input values for the Assessment Data Form to assess this 

AU are shown in Appendix A. We estimated the number of 

undiscovered oil accumulations in this assessment unit to be 

a minimum of 5, a maximum of 65, and a mode of 18. There 

have been 167 new oil field discoveries since the first economic discovery in 1957, and although there has not been a 

new field discovery (above the minimum size) since 1997, a 

likely possibility exists for the discovery of at least 5 new oil 

fields above the minimum of 0.5 MMBO. The maximum estimate of 65 undiscovered fields is a reflection of the large geographic size of the AU and the large undrilled area for possible 

new Leo Sandstone discoveries in combination structural and 

stratigraphic traps. New Minnelusa and Tensleep Sandstone oil 

field discoveries will probably be small. Few new fields will 

be discovered on the west side of the basin because of the lack 

of structural traps and the low stratigraphic trap potential in 

the Tensleep and Minnelusa Formations. 

Estimated sizes of undiscovered oil accumulations are a 

minimum of 0.5 MMBO, a median of 1.5 MMBO, and a maximum of 20 MMBO. The default minimum size of 0.5 MMBO 

reflects that there will be one field greater than the minimum 

size and that most discovered fields are small. A median size 

of 1.5 MMBO was used to reflect the probability that most of 

the fields will be relatively small, which is the trend over the 

last several years. A maximum size of 20 MMBO reflects the 

maturity of the AU and is indicative of the probability that a 

larger discovery is remote. 

Although there has not been a gas discovery in this AU, a 

potential increase in drilling depths will increase the probability of a discovery in the future. Therefore, we estimated the 

number of undiscovered gas accumulations is a minimum of 1, 

a maximum of 3, and a mode of 1. 

Sizes of undiscovered gas accumulations are estimated to 

be a minimum of 3 billion cubic feet of gas (BCFG), a maximum of 20 BCFG, and a median of 4 BCFG. It is estimated 

that there will be at least one new gas field discovery equal 

or greater than the minimum size of 3 BCFG, but the overall 

numbers reflect the probability that the gas field discoveries 

will be relatively small. About 40 percent of the assessed gas 

will be from associated gas production. 

Mean estimates of undiscovered resources for the Minnelusa-Tensleep-Leo AU are 60.5 MMBO, 10.1 BCFG (2.8 

BCFG from associated gas), and 0.54 MMBNGL (table 1). 

Table 1 also shows a resource breakdown into the F95, F50, 

and F5 fractiles. The potential for future oil discoveries is 
Assessment of Undiscovered Petroleum Resources in Conventional Assessment Units 53

considered to be limited because, although parts of the AU are 

mature, other parts are sparsely drilled but have limited trapping potential. 

Fall River–Lakota Sandstones AU (50330201)

The Fall River–Lakota Sandstone AU (about 13.6 million 

acres) covers most of the interior part of the PRB; its outline is 

based on the distribution of Fall River–Lakota sandstones that 

have the potential to accumulate oil and gas, although most 

of the production is located in the southern part of the AU 

(fig. 20). The AU does not include the large structural features 

at the basin margin, which is a separate AU. As explained in 

the Mowry TPS section of this report, Fall River and Lakota 

nomenclature is problematic because some operators use the 

terms interchangeably; in addition, the term Dakota is also 

used, perhaps as a matter of convenience in cases where there 

is uncertainty in stratigraphic correlation. 

Fall River–Lakota Sandstone stratigraphic units have 

accumulated more than 100 MMBO and 10.6 BCFG from 

approximately 500 producing wells in 18 oil fields and 3 gas 

fields (NRG Associates, 2006). In addition, 10,000 wells or 

more have penetrated all or parts of the Fall River–Lakota 

section (IHS Energy Group, 2006), which includes some 4,700 

new field wildcats (NRG Associates, 2006). However, not all 

new field wildcats had the Fall River–Lakota section as the 

primary target. 

Current and past oil production volumes compared with 

field size can be classified as bimodal, with field sizes of 4 to 

8 MMBO producing about 34 MMBO and field sizes of 16 

to 32 MMBO producing in excess of 40 MMBO; these totals 

account for more than 74 percent of all Fall River–Lakota 

production in the AU. All gas volumes are produced from field 

sizes that range from 3 to 6 BCFG.

The average field depth is about 6,000 ft, ranging from 

less than 1,000 ft to more than 12,000 ft. Several recent field 

discoveries exceed 12,000-ft depth, a trend that may continue. 

Gravity in most fields ranges from 20° to 30° API units but 

can range from 15° to 50° API gravity. 

Input values for the Assessment Data Form to assess this 

AU are shown in Appendix B. The number of undiscovered 

oil accumulations in this assessment unit is estimated to be a 

minimum of 2, a maximum of 50, and a mode of 10. There 

have been 38 new oil field discoveries since the first economic 

discovery in 1949 and, although there has been no new field 

discovery (above the minimum size) since 1985 (NRG Associates, 2006), it is considered a likely possibility that at least 

2 new oil fields above the minimum of 0.5 MMBO will be 

discovered. The maximum estimate of 50 undiscovered fields 

is a reflection of the large geographic size of the AU and the 

large undrilled area yet to be tested for Fall River and Lakota 

Sandstone accumulations. New oil field discoveries will be 

small fields, most of which will be discovered on the west side 

of the basin in narrow, overpressured channel systems. The 

biggest risk for exploration is in locating channel systems with 

porous and permeable sandstone. 

Sizes of undiscovered oil accumulations are estimated 

at a minimum of 0.5 MMBO, a median of 2.5 MMBO, and 

a maximum of 20 MMBO. The default minimum size of 0.5 

MMBO reflects that there will be one new field that exceeds 

the minimum size and that most discoveries will be small. A 

median size of 2.5 MMBO, which is the long-term trend of 

new field discovery size, was used although the last two new 

field discoveries were substantially greater than 3 MMBO. A 

maximum size of 20 MMBO reflects the maturity of the AU, 

but the probability of such a large discovery is remote. 

Although only three new gas fields have been discovered in this AU, the probable increase in drilling depths will 

increase the probability of a gas discovery in the future. 

Therefore, estimated number of undiscovered gas accumulation is a minimum of 1, a maximum of 75, and a mode of 7. 

The skewed distribution indicates the uncertainty in estimating 

the number of new fields. 

Estimated sizes of undiscovered gas accumulations were 

3 BCFG (the minimum field size to assess), a maximum of 

200 BCFG, and a median of 15 BCFG. It is estimated that 

there will be at least one new gas field discovery equal to 

or greater than the minimum size of 3 BCFG. The numbers 

reflect the probability that the gas field discoveries will be 

relatively small. About 10 percent of the assessed gas will be 

from associated gas produced with oil. 

Mean estimates of undiscovered resources for the Fall 

River–Lakota Sandstone AU are 64.1 MMBO, 649.2 BCFG 

(74.7 BCFG from associated gas), and 61.9 MMBNGL 

(table 1). Table 1 also shows a resource breakdown into the 

F95, F50, and F5 fractiles. The potential for future oil discoveries is considered to be uncertain because, although there 

have been a substantial number of well penetrations in the AU, 

a significant percentage of channel systems remain untested or 

undertested. 

Muddy Sandstone AU (50330202)

The Muddy Sandstone AU (about 13.9 million acres) 

covers most of the interior part of the PRB; its outline is based 

on the distribution of Muddy Sandstone reservoirs that are 

either currently producing and (or) have the potential to accumulate oil and gas in the future. Muddy production is located 

in the east-central part of the basin with several new field 

discoveries in the southwestern part of the basin (fig. 20), and 

since the last USGS assessment (Dolton and Fox, 1995) most 

new production is from reserve growth of existing fields. The 

AU does not include the large structural features at the basin 

margin, which is a separate AU. This report uses the term 

Muddy Sandstone for all marine and nonmarine facies below 

the Mowry Shale and above the Skull Creek Shale. 

Muddy Sandstone reservoirs have produced over 530 

MMBO and 192 BCFG from approximately 3,600 producing 

wells in 79 oil fields and 8 gas fields. In addition, some 14,000 

wells have penetrated all or part of the Muddy Sandstone 

section (IHS Energy Group, 2006), which includes more than 
54 Geologic Assessment of Undiscovered Oil and Gas in the Powder River Basin Province, Wyoming and Montana

7,000 new field wildcats (NRG Associates, 2006), not all of 

which had the Muddy as the primary drilling target. 

Oil production volumes compared to field size were 

classified as bimodal with field sizes of 16 to 32 MMBO 

producing a total of more than 140 MMBO and those in the 

128 to 256 MMBO category producing a total of more than 

130 MMB0; these amounts account for more than 50 percent 

of all Muddy production in the AU. All other field size classes 

have less than 80 MMBO (NRG Associates, 2006). Gas 

production indicates that the largest field size class is 48 to 96 

BCFG (NRG Associates, 2006). 

The depth of new field discoveries has increased since 

the first Muddy discovery in the 1940s. The average depth 

then was about 4,000 ft compared to the average depth of 

more than 10,000 ft in the 1990s. Recently, several new field 

discoveries exceed the 12,000-ft depth, a trend that will probably continue. Oil gravity ranges between 15° and 65° API 

with a mean of 40 API. GOR ranges from less than 10 to over 

2,500 with a mean of 1,200. Input values for the Assessment 

Data Form to assess this AU are shown in Appendix C. The 

number of undiscovered oil accumulations is estimated to be 

a minimum of 2, a maximum of 30, and a mode of 10. There 

have been 79 new oil field discoveries since the first economic 

discovery in 1944, and although there has been no new field 

discovery (above the minimum size) since 1998 (NRG Associates, 2006), it is a likely possibility that at least 2 new oil fields 

above the minimum of 0.5 MMBO will be discovered. The 

maximum estimate of 30 undiscovered fields is a reflection of 

the large geographic size of the assessment unit and the large 

undrilled area yet to be tested for new Muddy Sandstone accumulations in combination structural and stratigraphic traps. 

This is the potential for new Muddy oil discoveries to be made 

on the west side of the basin in narrow, overpressured channel 

systems, but the biggest risk will be to locate channel systems 

containing porous and permeable sandstone. 

Estimated sizes of undiscovered oil accumulations are 

a minimum of 0.5 MMBO, a median of 1.5 MMBO, and a 

maximum of 100 MMBO. The default minimum size of 0.5 

MMBO reflects a potential that there will be one field discovered greater than the minimum size but that most new fields 

will be small. A median size of 1.5 MMBO was used, which 

is considered the long-term trend new field size. A maximum 

size of 100 MMBO reflects the upside potential of the AU and 

that there is the potential for a large field size discovery. 

Although only eight new gas fields have been discovered 

in this AU, there is an increase in probability of new field 

wildcats being drilled to deeper depths, which will increase 

the probability of gas discoveries in the future. Therefore, 

the estimated number of undiscovered gas accumulations is a 

minimum of 2, a maximum of 30, and a mode of 6. Sizes of 

undiscovered gas accumulations were estimated to be 3 BCFG 

(the minimum field size to assess), a maximum of 450 BCFG, 

and a median of 10 BCFG. At least one new gas field discovery is estimated to be equal to or greater than the minimum 

size of 3 BCFG. The numbers reflect the probability that the 

gas field discoveries will be relatively small. About 60 percent 

of the assessed gas is estimated to be from associated gas 

production. 

Mean estimates of undiscovered resources for the Muddy 

Assessment Unit are 47.3 MMBO, 398 BCFG (149.1 BCFG 

from associated gas), and 38.3 MMBNGL (table 1). Table 1 

also shows a resource breakdown into the F95, F50, and F5 

fractiles. Although there have been a substantial number of 

well penetrations in the Muddy Sandstone, large areas remain 

in which there may be channel systems that are untested or 

undertested, especially on the west side of the PRB. 

Frontier-Turner Sandstones AU (50330301)

The Frontier-Turner Sandstones AU (about 4.8 million 

acres) covers most of the south-central part of the PRB, and its 

outline is based on the distribution of reservoirs in the Frontier 

Formation and the Turner Sandy Member of the Carlile Shale 

that are currently producing oil and gas and have the potential 

for future production. Frontier production is located in the 

west side of the basin but does not include production from 

basin margin fields such as Salt Creek and Teapot Dome fields. 

Most Frontier production since the last USGS assessment of 

the PRB (Dolton and Fox, 1995) is from infield completions 

and from two new field discoveries with marginal Frontier 

production. Turner production is located in the east-central 

part of the basin (fig. 41) with new production from infield 

drilling and field extension. The K-bar field is a new field 

discovery since the last USGS assessment (Dolton and Fox, 

1995), and Brooks Draw field has limited Turner production.

As explained in the Niobrara TPS section of this report, 

Frontier Formation and Turner Sandy Member (of the Carlile 

Shale) nomenclature is commonly used interchangeably for 

the same lithostratigraphic interval. In this report a distinction 

is made between the Turner and the Frontier, in that the Turner 

is treated as a time equivalent of the Wall Creek Member of 

the Frontier (fig. 27) having been deposited in a lowstand 

setting east of the Wall Creek highstand location. In places, 

the Wall Creek and the Turner are separated physically and 

hydraulically by a ravinement surface of erosion (fig. 31). 

Frontier Formation and Turner Sandy Member reservoirs 

in this AU have produced some 74 MMBO and 289 BCFG 

from approximately 1,100 producing wells in 13 oil fields, 11 

oil and gas fields, and 1 gas field. In addition, more than 4,500 

wells have penetrated all or part of the Frontier-Turner section 

in this AU (IHS Energy Group, 2006), which includes some 

1,500 new field wildcats (NRG Associates, 2006). 

Most oil production from Frontier-Turner reservoirs is 

produced from one field size class, that of 16 to 32 MMBO 

with a total volume of 44 MMBO. Smaller field size classes 

produce the remaining oil of 30 MMBO (NRG Associates, 

2006). Gas production is from one field, Porcupine, which has 

produced 39 BCFG; all other gas production is from associated gas (NRG Associates, 2006). 

Since the discovery of Frontier-Turner production in the 

early 1900s, production depth from new field discoveries in 

the 1960s averaged 4,500 ft; but since the 1970s depths have 
Assessment of Undiscovered Petroleum Resources in Conventional Assessment Units 55

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Powel l 

Porcupin e 

Coyote C k 

Fin n K ba r 

Tod d 

Big Horn 

Campbell 

Johnson 

Crook 

Converse 

Weston 

Niobrara 

Sheridan 

Natrona 

Powder River 

Rosebud 

Frontier-Turner production

' Oil

' Gas

County boundary

Frontier-Turner 

Sandstones AU boundary

Niobrara depth > 8,000 feet

Province 5033 boundary

EXPLANATION

Montana 

Wyoming 

Figure 41. Map of the Powder River Basin showing oil and gas production of Frontier Formation and Turner Sandy 

Member of the Carlile Shale. The Frontier and Turner were combined into the Frontier-Turner Sandstones Assessment 

Unit (AU). Major fields are labeled.
56 Geologic Assessment of Undiscovered Oil and Gas in the Powder River Basin Province, Wyoming and Montana

ranged from about 6,000 ft to more than 12,000 ft. Wells in 

the most recent discovery K-Bar field in 1997 have an average 

depth exceeding10,000 ft (NRG Associates, 2006). Oil gravity 

ranges from 30o to 52o API with a mean of 40o API. GORs 

range from less than 500 cfg/bo to more than 29,000 cfg/bo 

with a mean of 5,000 cfg/bo. 

Input values for the Assessment Data Form to assess this 

AU are shown in Appendix D. Estimated number of undiscovered oil accumulations are a minimum of 1, a maximum of 

20, and a mode of 3. There have been 24 new oil field discoveries and, although there has not been a new field discovery 

(above the minimum size) since 1997 (NRG Associates, 

2006), it is considered a likely possibility that at least 1 new 

oil field above the minimum of 0.5 MMBO will be discovered. 

The maximum estimate of 20 undiscovered fields is a reflection of some areas with few wells that could have tested the 

Frontier and Turner reservoirs in combination structural and 

stratigraphic traps. New Frontier-Turner oil discoveries will 

be in the deeper parts of the basin in overpressured reservoirs; 

the biggest challenge is searching out porous and permeable 

sandstone in overpressured compartments. 

Estimated sizes of undiscovered oil accumulations are a 

minimum of 0.5 MMBO, a median of 1 MMBO, and a maximum of 10 MMBO. The minimum size of 0.5 MMBO reflects 

what is considered to be the potential for discovering one field 

greater than the minimum size; however, most new fields are 

thought to be small. A median size of 1 MMBO, which is an 

average volume for new field size for the most recent discoveries, was used although the range of most recent discoveries 

is between 3 and 0.5 MMBO. A maximum size of 10 MMBO 

is established as the upside potential of the AU, but there is 

considerable uncertainty as to the discovery of a large field. 

There has been only one new gas field discovered in this 

AU, and the probability of new gas fields being discovered is 

limited because the potential gas generation volume in Niobrara source rocks is areally restricted. Therefore, the number 

of undiscovered gas accumulations greater than the minimum 

is estimated as 0. Mean estimates of undiscovered resources 

for the Frontier-Turner Sandstones AU are 10.2 MMBO, 

40.5 BCFG, and 2.9 MMBNGL (table 1). Table 1 also shows a 

resource breakdown into the F95, F50, and F5 fractiles. 

Sussex-Shannon Sandstones AU (50330302)

The Sussex-Shannon Sandstones AU (about 6.6 million 

acres) covers most of the central part of the PRB, and its 

north-south outline is based on the distribution of reservoirs 

in the Sussex and Shannon Sandstone Members of the Cody 

Shale that are currently producing and have potential for future 

discoveries. Sussex production is located in the eastern and 

southwestern parts of the AU, whereas Shannon production is 

in the west-central part. The Sussex and Shannon Sandstone 

Members are combined in this AU because they have similar 

reservoir characteristics and production styles and histories. 

The Sussex Sandstone Member has been informally 

subdivided into three units (Anderman, 1976), a lower B sand, 

a middle marine shale, and an upper A sand; both the A and 

B sands are productive. The Shannon Sandstone Member is 

one unit consisting of a lower silt unit overlain by interbedded sandstones that are commonly truncated at the top. The 

reservoirs are northwest-southeast-trending linear sandstone 

bodies, tens of miles long, 2–3 miles wide, and tens of feet 

thick; however, the sandstones thin to the north and east from 

current production. Sussex production tends to cluster in two 

areas, one along the House Creek–Porcupine field trend and 

the other farther west along the Spearhead Ranch–Scott field 

trend (fig. 32). Shannon production tends to cluster in one 

trend, including the Hartzog Draw, Pine Tree, and Jepson 

fields (fig. 33). Most of the Shannon production lies west of 

the main area of Sussex production to the north but follows 

along trend of the Sussex to the south. 

Sussex and Shannon reservoirs have produced some 

216 MMBO and 98 BCFG from approximately 1,200 

producing wells in 17 oil fields. Only associated gas is 

produced, with no designated gas fields. In total, more than 

5,000 wells have penetrated these sandstone units in this AU 

(IHS Energy Group, 2006), which includes 3,500 or more new 

field wildcats (NRG Associates, 2006). 

Most oil production from Sussex and Shannon reservoirs 

is from one field size class, which is in the range of 64 to 

128 MMBO, with a total volume of 120 MMBO. Smaller 

field size classes produce the remaining 96 MMBO (NRG 

Associates, 2006). Oil volumes compared to accumulation size 

classes follow a power law distribution. 

Since the early discovery of Sussex and Shannon production in the late 1960s to the present, production depths from 

new field discoveries averaged 9,000 ft and ranged from about 

7,000 to 10,200 ft. During this period, there has been a general 

trend toward drilling to greater depths to reach the reservoirs 

(NRG Associates, 2006). Oil gravity ranges between 30° 

and 45° API with a mean of 35°. GOR ranges from less than 

200 cfg/bo to more than 2,500 cfg/bo with a mean of 

500 cfg/bo. 

Input values for the Assessment Data Form to assess this 

AU are shown in Appendix E. Estimated numbers of undiscovered oil accumulations are a minimum of 1, a maximum 

of 10, and a mode of 3. There have been 17 new oil field 

discoveries, and although there has not been a new field discovery (above the minimum size) since 1994 (NRG Associates, 2006), it is likely that at least 1 new oil field above the 

minimum of 0.5 MMBO will be discovered. The maximum 

estimate of 10 undiscovered fields is a reflection of some areas 

with few wells that could have tested the Sussex and Shannon 

in combination stratigraphic traps. Growth in oil reservoirs 

will be mostly from infield drilling and field extensions. New 

fields and field growth may be in deeper parts of the basin, but 

also possibly in shallower parts. The highest potential for new 

field discoveries is believed to be in exploring for porous and 

permeable sandstone in overpressured compartments. 

Estimated sizes of undiscovered oil accumulations 

include a minimum of 0.5 MMBO, a median of 1.5 MMBO, 

and a maximum of 12 MMBO. The default minimum size 
Assessment of Undiscovered Petroleum Resources in Conventional Assessment Units 57

of 0.5 MMBO reflects that there will be the discovery of one 

field greater than the minimum size but that most fields will 

be small. A median size of 1.5 MMBO was used, which is an 

average volume for field sizes for the most recent discoveries. 

A maximum size of 12 MMBO reflects some possible upside 

potential of the AU, but there is much doubt that a large volume field will be discovered. 

There have been no new gas fields discovered in this AU, 

and the probability of new gas fields being discovered is low 

because gas generation potential in Niobrara source rocks is 

limited. Therefore, the number of undiscovered gas accumulations was estimated to be 0. We estimate that most of the 

assessed gas will be from associated gas production. 

Mean estimates of undiscovered resources for the SussexShannon Sandstones AU are 8.7 MMBO, 8.1 BCFG, and 

0.65 MMBNGL (table 1). Table 1 also shows a resource 

breakdown into the F95, F50, and F5 fractiles. 

Mesaverde-Lewis Sandstones AU (50330303)

The Mesaverde-Lewis Sandstones AU (about 6.1 million 

acres) covers most of the central part of the PRB, and its north 

south outline is based on the distribution of Mesaverde-Lewis 

Sandstone reservoirs that are currently producing and have the 

potential for future production. Reservoirs include the Parkman Sandstone and the Teapot Sandstone Members of the 

Mesaverde Formation and the Teckla Sandstone Member of 

the Lewis Shale (fig. 27); they are combined in a single AU 

because they have similar reservoir characteristics, production style and type, and depositional history. Production of the 

Teckla and Teapot sandstones is limited to the southern part 

of the basin, whereas Parkman production is distributed in the 

southern and central parts. 

In general, most Mesaverde and Lewis fields produce 

modest volumes of oil from several multipay fields, although a 

few fields produce large volumes of oil (there are no designated gas fields; NRG Associates, 2006). For example, (1) 

the Parkman produces large quantities of oil from the Empire, 

Dead Horse, and Scott fields; (2) the Teapot has production 

from Flat Top, Kaye, Mikes Draw, and Well Draw fields; and 

(3) the Teckla has excellent production from Poison Draw 

field. Some wells have good initial production but have steep 

declines. The modest production from these reservoirs is 

indicative of their high clay content and low permeability. A 

few wells have low initial production rates with flat declines, 

although it is unclear if these wells are pressure depleted 

because of multiple pay zones. Most units within the Teapot, 

Parkman, and Teckla Sandstones have an average reservoir 

thickness of 10 to 150 ft, with a porosity and permeability 

range of 12 to 18 percent and 2 to 34 mD, respectively; some 

beds may have permeabilities exceeding 100 mD. 

Mesaverde-Lewis Sandstone reservoirs in this AU have 

produced in excess of 126 MMBO and 187 BCFG from some 

1,500 producing wells in 19 oil fields. Only oil with associated 

gas is produced from the 19 oil fields; there are no designated 

gas fields (NRG Associates, 2006). In addition, more than 

5,100 wells have been drilled through the Mesaverde-Lewis 

interval to reach deeper targets (IHS Energy Group, 2006), 

which includes 2,100 new field wildcats (NRG Associates, 

2006). Most oil production from Mesaverde-Lewis reservoirs 

is produced from two field size classes—16 to 32 MMBO and 

32 to 64 MMBO—with a total volume of 88 MMBO. Five 

other field size classes from 0.5 to 16 MMBO produce the 

remaining 38 MMBO (NRG Associates, 2006). 

Since the discovery of Mesaverde-Lewis production in 

the late 1950s at Dead Horse field, production depths from 

new field discoveries have averaged about 7,300 ft and ranged 

from about 5,500 to 9,500 ft. The historical trend, although 

short, is flat (NRG Associates, 2006). Oil gravity ranges from 

35° to 47° API gravity per field with a mean of 39°. GOR 

ranges from less than 10 cfg/bo to more than 11,000 cfg/bo 

with a mean of 1,200 cfg/bo. Input values for the Assessment 

Data Form to assess this AU are shown in Appendix F. The 

number of undiscovered oil accumulations in this assessment 

unit was estimated to be a minimum of 1, a maximum of 10, 

and a mode of 2. There have been 19 new oil field discoveries, 

and although there has not been a new field discovery above 

the minimum size of 0.5 MMBO since 1980 (NRG Associates, 2006), it is a likely possibility that at least 1 new oil 

field above the minimum will be discovered. The maximum 

estimate of 10 undiscovered fields is a reflection of some areas 

with wells that could have tested sandstones in the MesaverdeLewis interval in combination stratigraphic traps, but failed to 

do so. New Mesaverde-Lewis oil discoveries will probably be 

mostly small fields in deeper parts of the basin, although the 

potential in shallower parts of the basin should not be overlooked. Exploration efforts should focus on finding porous and 

permeable sandstones with updip pinchouts. 

Estimated sizes of undiscovered oil accumulations are 

a minimum of 0.5 MMBO, a median of 1.5 MMBO, and a 

maximum of 10 MMBO. The default minimum size of 0.5 

MMBO reflects a potential for one field to be discovered that 

is greater than the minimum size, but most discovered fields 

are expected to be small. A median size of 1.5 MMBO was 

used, which is an average volume for a new field size based on 

the most recent discoveries in the AU. A maximum size of 10 

MMBO reflects some upside potential of the AU, especially 

because there are three fields that have produced more than 

20 MMBO; but there is large uncertainty in discovering a new 

large-volume field. 

There have been no new gas fields discovered in this 

AU, and the probability of new gas fields being discovered 

in limited because gas generation in Niobrara source rocks is 

limited. Therefore, the number of undiscovered gas accumulations was a minimum of 0, a maximum of 7, and a mode of 

1. Estimated sizes of undiscovered gas accumulations are 3 

BCFG (the minimum field size to assess), a maximum of 10 

BCFG, and a median of 3.5 BCFG. There is a potential for 

at least one new gas field to be discovered equal to or greater 

than the minimum size of 3 BCFG because a large area in the 

northern part of the basin remains to be tested. The assigned 

numbers reflect the probability that future discoveries will be 
58 Geologic Assessment of Undiscovered Oil and Gas in the Powder River Basin Province, Wyoming and Montana

relatively small. Most of the assessed gas will be from gas 

associated with oil production. 

Mean estimates of undiscovered resources for the 

Mesaverde-Lewis Sandstones Assessment Unit are 6.0 

MMBO, 8.4 BCFG, and 0.6 MMBNGL (table 1). Table 1 

also shows a resource breakdown into the F95, F50, and F5 

fractiles. 

Basin Margin AU (50330601)

The Basin Margin AU (about 5.45 million acres) includes 

the structurally upthrown parts of the western and southern 

rims of the PRB. Reservoirs include the same Paleozoic and 

Mesozoic strata that produce in the central part of the basin 

and are described in previous sections. 

The production history of most Basin Margin fields show 

relatively small declines over decades of production, although 

some low-volume fields show some erratic production histories, and others show modest production increases over short 

time intervals due to secondary recovery. Most fields have a 

strong water drive, whereas some have solution gas drives, 

and a few have only solution gas drives. 

Basin margin fields have produced the greatest volumes 

of oil in the PRB, owing to stacked pay zones trapped in structural closures; cumulative production exceeds 1,300 MMBO 

and 1,050 BCFG from more than 2 wells in 45 oil fields. Only 

associated gas is produced, and there are no designated gas 

fields. In addition, some 2,000 new-field wildcats have been 

drilled in this AU (NRG Associates, 2006). 

Most oil production is from a field size class of 512 

to 1,024 MMBO with a total volume of more than 700 

MMBO. The giant Salt Creek field has produced more than 

735 MMBO (NRG Associates, 2006), which is more than 6 

times as much oil as the next largest producer, the Meadow 

Creek–Sussex field complex. Five other field size classes, 

ranging from 0.5 to 128 MMBO, produce the remaining oil of 

590 MMBO (NRG Associates, 2006). 

Since the early discovery of production in the early 1900s 

at Salt Creek field, depths of new field discoveries ranged 

from 150 to 10,000 ft and averaged 4,500 ft. In addition, there 

is a slight trend toward deeper field depths over time (NRG 

Associates, 2006). Oil gravity ranges from 15° to 50° API 

gravity per field with a mean of 33°. GOR ranges from less 

than 10 cfg/bo to more than 16,000 cfg/bo with a mean of 

900 cfg/bo.

Input values for the Assessment Data Form to assess this 

AU are shown in Appendix G. Estimated numbers of undiscovered oil accumulations are a minimum of 1, a maximum of 

20, and a mode of 5. Although there has not been a new field 

discovery (above the minimum size) since 1998 (NRG Associates, 2006), it is estimated that at least 1 new oil field above 

the minimum of 0.5 MMBO will be discovered. The maximum estimate of 20 undiscovered fields reflects the potential 

for new discoveries in stratigraphic traps and combinations of 

structural and stratigraphic traps, especially through the testing 

of new pay zones in some of the more recent discoveries, and 

additional exploration that helps to define such structural and 

stratigraphic traps. 

Estimated sizes of undiscovered oil accumulations are 

a minimum of 0.5 MMBO, a median of 1.5 MMBO, and a 

maximum of 20 MMBO. The default minimum size of 0.5 

MMBO reflects the potential for one field to be discovered that 

is greater than the minimum size; however, most new fields 

probably will be small. A median size of 1.5 MMBO was used, 

based on an average volume of the most recent discoveries. 

Although the potential is low for discovering a new largevolume field, a maximum size of 20 MMBO reflects at least 

some potential, especially because 20 MMBO is an average 

field for this AU. 

There have been no new gas fields discovered in this AU, 

and the probability of new gas fields being discovered is low 

because gas generation or gas migration potential is limited. 

Therefore, the number of undiscovered gas accumulations was 

estimated to be 0. Most of the assessed gas will be from gas 

associated with oil production. 

Mean estimates of undiscovered resources for the Basin 

Margin Assessment Unit are 17.9 MMBO, 14.7 BCFG, and 

0.53 MMBNGL (table 1). Table 1 also shows a resource 

breakdown into the F95, F50, and F5 fractiles. The potential for future oil discoveries is considered to be limited but 

uncertain because a large area in the northern part of the basin 

remains to be evaluated. 

Eastern Basin Margin Upper Fort Union 

Sandstone AU (50330101)

Eastern Basin Margin Upper Fort Union Sandstone AU 

is a conventional AU with coalbed methane (CBM) contained 

in sandstones (not in coals) interbedded with coal in the upper 

part of the Paleocene Fort Union Formation. The fluvial 

channel sandstones, which have a gross thickness of as much 

as 300 ft, are mainly in the Tongue River Member. Gas may 

migrate from the interbedded coals into sandstones when gas 

is being desorbed during pressure-reducing events (Flores, 

2004), such as erosion of overlying sediments. 

Mean estimates of undiscovered resources for the Eastern 

Basin Margin Upper Fort Union Sandstone Assessment Unit 

are 0 MMBO, 27.4 BCFG, and 0 MMBNGL. These data were 

reported by Flores (2004) and are incorporated in table 1.

Conventional Assessment Summary

The Powder River Basin Province is a productive 

hydrocarbon province, with reservoirs that range in age from 

Mississippian through Paleocene. There are two excellent 

Cretaceous source rocks—Mowry Shale and Niobrara 

Formation—that have generated billions of barrels of oil and 

gas equivalent (Momper and Williams, 1984); the Permian 

Phosphoria Formation also has generated large amounts of oil, 

some of which migrated into Paleozoic reservoirs. 
Assessment of Undiscovered Petroleum Resources in Continuous Assessment Units 59

Although the province has been extensively drilled, 

especially on the east and south sides of the basin, untested 

and undertested sections remain that likely will produce in 

the future. This assessment calculated that, in the future, there 

will be 25 percent more oil and almost 100 percent more 

gas discovered in the province than has been recovered as of 

2006. New production will likely come from infill and new 

pay zones discovered in old fields, especially on the east side 

of the basin, and new field discoveries will likely come from 

deep reservoirs on the west side of the basin. The number 

and sizes of new field discoveries will be relatively small 

compared to historical numbers, and gas discoveries will outperform oil discoveries. 

Mean estimates of total conventional undiscovered 

resources for the PRB Province are 215 MMBO, 1,156 BCFG 

of associated and nonassociated gas, and 105 MMBNGL 

(table 1). 

Assessment of Undiscovered 

Petroleum Resources in Continuous 

Assessment Units

Mowry Continuous Oil AU (50330261)

The methods used to assess a continuous type play 

apply a cell-based grid that assigns a probability of ultimate 

gas recovery in each cell. The size of each cell is based on 

geologic controls, extent of drainage area, and the production 

history of analog fields. 

Estimated ultimate recovery (EUR) plots for the 

Mowry Continuous AU were developed from modeled 

production decline curves; the production data were taken 

from Integrated Exploration Systems (2002). Cumulative 

probability production curves were generated to determine the 

total possible recovery per cell for untested cells. Data were 

used from the Upper Cretaceous Mowry Shale producing 

fields with vertical wells in the PRB and from DevonianMississippian Bakken Shale (upper and lower members) fields 

in the Williston Basin in North Dakota with vertical wells. 

The cell size applied had a median value of 0.25 MMBO, a 

minimum value of 0.02 MMBO, and a maximum value of 

0.35 MMBO. Production from several fields in the PRB that 

produce from the Mowry were used in the probability plots 

including Maysdorf, Krejci, Lonetree Creek, Breen, Am-Kirk, 

Big Hand, Dillinger Ranch East, and Lightning Creek fields 

(Wyoming Oil and Gas Conservation Commission, 2003).

The Mowry Continuous Oil AU was characterized as a 

continuous reservoir with lateral limits confined to geologic 

sweet spots identified by the location of lineaments and faults 

(fig. 26). An upper limit of 8,000 ft corresponds to the upper 

boundary of overpressuring caused by hydrocarbon generation (Surdam and others, 1994). There may have been some 

migration in the Mowry at depths less than 8,000 ft, but in that 

case the reservoir is probably normally pressured to underpressured, and hydrocarbon extraction may not have occurred. 

There is no known lower depth limit, but it could be as much 

as 15,000 ft. 

Thousands of wells have been drilled through the Mowry 

Shale, but only a few have been drill-stem or production 

tested. The formation commonly has hydrocarbon shows but 

is commonly considered a secondary option for completion. 

Because fractured shale reservoirs require special completion 

techniques that are being improved, the Mowry as a primary 

objective will probably be more successful than in the past; 

hence, its past history may not reflect future upside potential. 

Of the 6.3 million acres in the AU, 3.2 million acres, 

or 50.3 percent, are within zones of high potential or sweet 

spots. Despite uncertainties in the mapping of lineament sand 

interpreting the structural forms, the minimum, maximum, and 

median percentages of untested assessment areas that have 

the potential for additions to reserves were calculated (above 

0.02 MBO per well minimum cutoff). The minimum value is 

8 percent, maximum value is 45 percent, and the median value 

is 25 percent (see Appendix H). Minimum value was calculated on the basis of the assumption that only 10 percent of the 

sweet spot area would be productive and have a 90-percent 

success ratio—that is, the sweet spots would be confined to a 

small area, but the area would have a high probability of success. The maximum value was based on similar assumptions, 

but reversed—that is, 90 percent of sweet spots would be 

productive, but with only a 10-percent probability of success. 

The median value was calculated with a 50-percent sweet spot 

productive area and a 50-percent probability of success. The 

values were also based on a 270-acre median cell size. Mean 

estimate of undiscovered resources for the Mowry AU is 198 

MMBO, 198 BCFG, and 11.9 MMBNGL (table 1). 

Niobrara Continuous Oil AU (50330361)

The method used to assess a continuous-type play applies 

a cell-based grid that uses a probability of ultimate gas recovery in each cell. The size of each cell was based on geologic 

controls, drainage area, and production history of analog 

fields. 

Estimated ultimate recovery (EUR) plots for the Niobrara 

Continuous Oil AU were developed from modeled production 

decline curves, and the production data were taken from an 

Integrated Exploration Systems (2002) database. Cumulative 

probability production curves were generated to determine 

the total recovery per cell for untested cells. Data were used 

from fields producing from the Upper Cretaceous Niobrara 

Formation in the PRB and from vertical wells in the Silo field 

in the Denver Basin in southeastern Wyoming. The cell size 

had a median value of 0.028 MMBO, a minimum value of 

0.02 MMBO and a maximum value of 0.5 MMBO. Several 

fields in the PRB producing from the Mowry were also used 

in the calculations, including Highlight, Payne, East Fork, 
60 Geologic Assessment of Undiscovered Oil and Gas in the Powder River Basin Province, Wyoming and Montana

and Shawnee fields (Wyoming Oil and Gas Conservation 

Commission, 2003).

The Niobrara Continuous Oil AU was characterized as 

a continuous unit with estimated recoverable areas limited to 

sweet spots identified by the location of lineaments and faults 

(fig. 36). A depth of 8,000 ft was determined as the upper 

extent of overpressuring caused by hydrocarbon generation 

(Surdam and others, 1994), and this could extend to depths 

as much as 14,000 ft. There may be some migration in the 

Niobrara at depths shallower than 8,000 ft, but this would be 

under normally pressured or underpressured conditions. Of the 

thousands of wells that have been drilled through the Niobrara 

Formation, only a few have been drill-stem tested or production tested in the PRB even though the formation usually has 

hydrocarbon shows. Past histories of Niobrara production 

may therefore not be indicative of future potential, especially 

in view of the new and improved techniques now becoming 

available to better evaluate the economic viability of fractured 

carbonate and carbonaceous shale reservoirs. 

Of the 4.6 million acres in the Niobrara Continuous 

Oil AU, 2.5 million acres, or 54.5 percent, are within zones 

mapped as high potential or sweet spots. Despite the uncertainties inherent in the mapping of lineaments and interpreting 

their structural characteristics, estimates were made of the 

minimum, maximum, and median percentages of untested 

areas that have the potential for additions to reserves from 

wells capable of producing at least 20,000 barrels of oil (BO) 

in the next 30 years. These estimates are: minimum, 8 percent; 

maximum, 45 percent; and median, 25 percent. The minimum value was calculated on the basis of the assumption that 

10 percent of a given sweet spot area would be productive, 

and would have a 90-percent success ratio. The maximum 

value was calculated on the basis of similar assumptions, but 

reversed—90 percent of sweet spots would be productive but 

with only a 10-percent probability of success. The median 

value was calculated with a 50-percent sweet spot productive 

area and a 50-percent probability of success. The values also 

were based on a 130-acre median cell-size area. 

Estimated ultimate recoveries (EUR) in the Niobrara 

Continuous Oil AU were based on current production statistics 

reported by IHS Energy Group (2006). Cumulative probability production curves were generated to determine the total 

recovery per cell for untested cells. Data were used from vertical Niobrara producing wells in the PRB and from vertical 

Niobrara wells in the Silo field in the northern Denver Basin 

of southeastern Wyoming. Median value of 0.28 MMBO was 

selected at 50-percent probability, minimum value of 0.02 

MMBO at the 12-percent probability, and the maximum value 

of 0.5 MMBO at 100-percent probability. Fields with Niobrara 

Formation production that were used in the probability plots 

include Goer Draw, WC, K-Bar, Big Muddy, Haps Draw, 

Orpha, Payne, Si Tanka, Rocky Hill, Shawnee, and Highlight 

fields (Wyoming Oil and Gas Conservation Commission, 

2003). The values were also based on a 130-acre median cell 

size. Input values for the Assessment Data Form to assess this 

AU are shown in Appendix I.

Mean estimates of undiscovered resources for the 

Niobrara AU are 227 MMBO, 227 BCFG, and 13.6 

MMBNGL (table 1). 

Shallow Continuous Biogenic Gas AU (50330461)

Methods used to assess a continuous-type play applies a 

cell-based grid that uses a probability of ultimate gas recovery 

in each cell. The size of each cell was based on geologic 

controls, drainage area, and production history of analog 

fields. 

The Cretaceous biogenic gas AU was characterized as 

hypothetical with potential production in Cretaceous sandstone and siltstone but with lateral and vertical limits that trap 

gas in place. An upper depth limit was arbitrary, but 300 ft of 

overburden could possibly prevent upward leakage. The lower 

limit was determined to be 3,400 ft where above that, only 

biogenic gas would be generated. 

Estimated ultimate recovery (EUR) plots for the Shallow 

Continuous Biogenic Gas AU were developed from modeled 

production decline curves (production data from Integrated 

Exploration Systems, 2002). Cumulative probability production curves were generated to determine the total recovery per 

untested cells. Data were used from current producing fields 

in and adjacent to the PRB including the West Short Pine Hills 

field in Harding County, South Dakota. The cell size had a 

median value of 0.08 BCFG, a minimum value of 0.01 BCFG, 

and a maximum value of 1.5 BCFG. Some of the fields that 

were used in the analysis are Hardin, Lilscom Creek, Pumpkin 

Creek, Gaslight, Hammond, and Ardmore fields (Wyoming 

Oil and Gas Conservation Commission, 2003; George Shurr, 

written commun., 1999). Because of the uncertainty associated 

with the origin of the gas in these fields, this AU was assessed 

as a hypothetical AU. Input values for the Data Form to assess 

this AU are shown in Appendix J.

Of the 19.7 million acres (median) in the play area, 

6.14 million acres, or 31.2 percent, are within zones of high 

potential or sweet spots. Despite uncertainties in the mapping 

of lineaments and interpreting their structural characteristics, 

calculations were made of the minimum, maximum, and 

median percentages of untested assessment areas that have 

the potential for additions to reserves (> 0.01 BCFG per well 

minimum cutoff) in the next 30 years. The resulting estimates 

were 1,12.5, and 5 percent, respectively (Appendix J). Minimum value was calculated based on the assumption that only 

10 percent of the sweet spot area would be productive, but 

with a 90-percent success ratio. Maximum value was based on 

similar assumptions, but reversed—90 percent of sweet spots 

would be productive, with a 10 percent probability of success. 

The median value was calculated with a 50-percent sweet spot 

productive area and a 50-percent probability of success. The 

values were also based on a 160-acre median cell size. Mean 

estimate of undiscovered resources for the Cretaceous continuous Biogenic Gas AU is 787 BCFG (table 1). 
References 61

Assessment Summary

Continuous hydrocarbon accumulations in the PRB are 

difficult to assess because the strata involved typically have 

been thought of as source rocks rather than also being reservoirs that are a primary exploration target. Historically, well 

testing of fractured shale and limy shale reservoirs indicate 

poor production performance because of little fluid recovery, 

even with mud log shows. New completion techniques should 

help production performance for these reservoirs in structurally enhanced areas. 

Mean estimates of continuous undiscovered resource 

for the basin are 424 MMBO, 1,211 BCFG (excludes CBG 

resources), and 25.5 MMBNGL (table 1).

Comparison of Results of 1995 and 2005 

Assessments

A comparison between the 1995 and 2006 USGS 

resource estimates for the Powder River Basin Province shows 

an appreciable change in the estimated size of the undiscovered oil and gas resource. In 1995, Dolton and Fox (1995), 

using a play concept, estimated a total mean undiscovered 

oil and gas resource of 1,131 MMBO and 983 BCFG for 11 

conventional and 1 continuous play in the PRB Province. In 

2006, for the assessment discussed in this report using the total 

petroleum system concept, a mean resource of 639 MMBO 

and 2,368 BCFG (excluding coalbed gas) was calculated for 

the 11 assessment units in 6 TPSs. It should be noted that in 

the 1995 assessment the Mowry and Niobrara continuous AUs 

were not assessed. Considering differences in methodology, 

the 2006 estimates reflect a notable decrease in oil resource 

estimates, the difference being in the respective assessed value 

for the Minnelusa-Tensleep-Leo s AU. The 2006 assessed 

value had only a mean of 60 MMBO, whereas the 1995 

assessment of the same units calculated a much larger combined value of 604 MMBO. The 1995 assessment speculated 

that the vast untested acreage in the western and southern parts 

of the basin where Minnelusa-Tensleep-Leo are present would 

eventually produce significant amounts of oil. However, in 

the present assessment, much less was estimated for the same 

untested area because of a perceived lack of potential traps. 

Gas resource for this assessment was significantly higher 

than the 1995 assessment—2,368 BCFG compared to 938 

BCFG— mainly due to an increase in estimated volumes of 

gas in the continuous Mowry and Niobrara reservoir systems, 

as well as biogenic gas (excluding CBM reservoirs). Conventional gas was assessed at 1,156 BCFG compared with the 

1995 assessment of 1,011 BCFG. 

Acknowledgments

Valuable suggestions were given by Ron Charpentier, 

Troy Cook, Tim Klett, Rich Pollastro, and Christopher Schenk, 

U.S. Geological Survey Central Energy Resources Assessment 

Team. The report was greatly improved by technical reviews 

from Christopher Schenk and Mark Kirschbaum, USGS. The 

assistance of Wayne Husband for graphic design and Chris 

Anderson for GIS management is gratefully acknowledged.

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Appendixes 73

Appendixes
74 Geologic Assessment of Undiscovered Oil and Gas in the Powder River Basin Province, Wyoming and Montana

Appendix A. Basic input data for the Minnelusa-Tensleep-Leo Sandstones Assessment Unit (50330501). SEVENTH APPROXIMATION 

DATA FORM (NOGA, Version 6, 4-9-2003). [AU, assessment unit; bcfg, billion cubic feet of gas; bliq/mmcfg, barrels of liquid per million 

cubic feet of gas; bng/mmcfg, barrels of natural gas liquids per million cubic feet of gas; cfg/bo, cubic feet of gas per barrel of oil; m, meters; 

min, minimum; mmboe, million barrels of oil equivalent; ngl, natural gas liquids]

SEVENTH APPROXIMATION

DATA FORM FOR CONVENTIONAL ASSESSMENT UNITS (Version 6, 9 April 2003)

Assessment Geologist: L.O. Anna Date: 30-May-06

Region: North America Number: 5

Province: Powder River Basin Number: 5033

Total Petroleum System: Pennsylvanian-Permian Composite Number: 503305

Assessment Unit: Minnelusa-Tensleep-Leo Sandstones Number: 50330501

Based on Data as of: IHS Energy (2006) and NRG (2005, data current through 2003), Wyoming Oil and 

Notes from Assessor:

CHARACTERISTICS OF ASSESSMENT UNIT

Oil (<20,000 cfg/bo overall) or Gas (>20,000 cfg/bo overall): Oil

What is the minimum accumulation size? 0.5 mmboe grown

(the smallest accumulation that has potential to be added to reserves)

No. of discovered accumulations exceeding minimum size: Oil: 163 Gas: 0

Established (>13 accums.) X Frontier (1-13 accums.) Hypothetical (no accums.)

Median size (grown) of discovered oil accumulations (mmbo):

1st 3rd 3.74 2nd 3rd 3.37 3rd 3rd 1.6

Median size (grown) of discovered gas accumulations (bcfg):

1st 3rd 2nd 3rd 3rd 3rd

Assessment-Unit Probabilities:

 Attribute Probability of occurrence (0-1.0)

1. CHARGE: Adequate petroleum charge for an undiscovered accum. > minimum size: 1.0

2. ROCKS: Adequate reservoirs, traps, and seals for an undiscovered accum. > minimum size: 1.0

3. TIMING OF GEOLOGIC EVENTS: Favorable timing for an undiscovered accum. > minimum size 1.0

Assessment-Unit GEOLOGIC Probability (Product of 1, 2, and 3): 1.0

UNDISCOVERED ACCUMULATIONS

No. of Undiscovered Accumulations: How many undiscovered accums. exist that are > min. size?:

 (uncertainty of fixed but unknown values)

Oil Accumulations: minimum (>0) 5 mode 18 maximum 65

Gas Accumulations: minimum (>0) 1 mode 1 maximum 3

Sizes of Undiscovered Accumulations: What are the sizes (grown) of the above accums?:

 (variations in the sizes of undiscovered accumulations)

Oil in Oil Accumulations (mmbo): minimum 0.5 median 1.5 maximum 20

Gas in Gas Accumulations (bcfg): minimum 3 median 4 maximum 20

IDENTIFICATION INFORMATION

Gas Conservation Commission
Appendixes 75

Assessment Unit (name, no.)

Minnelusa-Tensleep-Leo Sandstones, 50330501

AVERAGE RATIOS FOR UNDISCOVERED ACCUMS., TO ASSESS COPRODUCTS

(uncertainty of fixed but unknown values)

Oil Accumulations: minimum mode maximum

Gas/oil ratio (cfg/bo) 20 40 80

NGL/gas ratio (bngl/mmcfg) 10 20 80

Gas Accumulations: minimum mode maximum

Liquids/gas ratio (bliq/mmcfg) 30 60 90

Oil/gas ratio (bo/mmcfg)

SELECTED ANCILLARY DATA FOR UNDISCOVERED ACCUMULATIONS

(variations in the properties of undiscovered accumulations)

Oil Accumulations: minimum mode maximum

API gravity (degrees) 15 25 45

Sulfur content of oil (%) 0.5 2.8 4

Depth (m) of water (if applicable)

minimum F75 mode F25 maximum

Drilling Depth (m) 500 2750 4700

Gas Accumulations: minimum mode maximum

Inert gas content (%) 1 5 15

CO2 content (%) 0.5 4.5 12

Hydrogen-sulfide content (%) 0.1 2 50

Depth (m) of water (if applicable)

minimum F75 mode F25 maximum

Drilling Depth (m) 2000 3100 4800
76 Geologic Assessment of Undiscovered Oil and Gas in the Powder River Basin Province, Wyoming and Montana

SEVENTH APPROXIMATION

DATA FORM FOR CONVENTIONAL ASSESSMENT UNITS (Version 6, 9 April 2003)

Assessment Geologist: L.O. Anna Date: 31-May-06

Region: North America Number: 5

Province: Powder River Basin Number: 5033

Total Petroleum System: Mowry Number: 503302

Assessment Unit: Fall River-Lakota Sandstones Number: 50330201

Based on Data as of: IHS Energy (2006) and NRG (2005, data current through 2003), Wyoming Oil 

 NRG reservoir growth function, 30 years

CHARACTERISTICS OF ASSESSMENT UNIT

Oil (<20,000 cfg/bo overall) or Gas (>20,000 cfg/bo overall): Oil

What is the minimum accumulation size? 0.5 mmboe grown

(the smallest accumulation that has potential to be added to reserves)

No. of discovered accumulations exceeding minimum size: Oil: 18 Gas: 3

Established (>13 accums.) X Frontier (1-13 accums.) Hypothetical (no accums.)

Median size (grown) of discovered oil accumulations (mmbo):

1st 3rd 5.52 2nd 3rd 4.46 3rd 3rd 3.89

Median size (grown) of discovered gas accumulations (bcfg):

1st 3rd 2nd 3rd 3rd 3rd

Assessment-Unit Probabilities:

 Attribute Probability of occurrence (0-1.0)

1. CHARGE: Adequate petroleum charge for an undiscovered accum. > minimum size: 1.0

2. ROCKS: Adequate reservoirs, traps, and seals for an undiscovered accum. > minimum size: 1.0

3. TIMING OF GEOLOGIC EVENTS: Favorable timing for an undiscovered accum. > minimum size 1.0

Assessment-Unit GEOLOGIC Probability (Product of 1, 2, and 3): 1.0

UNDISCOVERED ACCUMULATIONS

No. of Undiscovered Accumulations: How many undiscovered accums. exist that are > min. size?:

 (uncertainty of fixed but unknown values)

Oil Accumulations: minimum (>0) 2 mode 10 maximum 50

Gas Accumulations: minimum (>0) 1 mode 7 maximum 75

Sizes of Undiscovered Accumulations: What are the sizes (grown) of the above accums?:

 (variations in the sizes of undiscovered accumulations)

Oil in Oil Accumulations (mmbo): minimum 0.5 median 2.5 maximum 20

Gas in Gas Accumulations (bcfg): minimum 3 median 15 maximum 200

IDENTIFICATION INFORMATION

Appendix B. Basic input data for the Fall River-Lakota Sandstones Assessment Unit (50330202). SEVENTH APPROXIMATION 

DATA FORM (NOGA, Version 6, 4-9-2003). [AU, assessment unit; bcfg, billion cubic feet of gas; bliq/mmcfg, barrels of liquid per 

million cubic feet of gas; bng/mmcfg, barrels of natural gas liquids per million cubic feet of gas; cfg/bo, cubic feet of gas per barrel 

of oil; m, meters; min, minimum; mmboe, million barrels of oil equivalent; ngl, natural gas liquids]

Notes from Assessor:

and Gas Conservation Commission
Appendixes 77

Assessment Unit (name, no.)

Fall River-Lakota Sandstones, 50330201

AVERAGE RATIOS FOR UNDISCOVERED ACCUMS., TO ASSESS COPRODUCTS

(uncertainty of fixed but unknown values)

Oil Accumulations: minimum mode maximum

Gas/oil ratio (cfg/bo) 500 1000 2000

NGL/gas ratio (bngl/mmcfg) 30 60 90

Gas Accumulations: minimum mode maximum

Liquids/gas ratio (bliq/mmcfg) 50 100 150

Oil/gas ratio (bo/mmcfg)

SELECTED ANCILLARY DATA FOR UNDISCOVERED ACCUMULATIONS

(variations in the properties of undiscovered accumulations)

Oil Accumulations: minimum mode maximum

API gravity (degrees) 20 38 50

Sulfur content of oil (%) 0 0.1 0.3

Depth (m) of water (if applicable)

minimum F75 mode F25 maximum

Drilling Depth (m) 500 3500 4300

Gas Accumulations: minimum mode maximum

Inert gas content (%) 0.1 0.4 2

CO2 content (%) 0.1 0.5 2.7

Hydrogen-sulfide content (%) 0 0 0

Depth (m) of water (if applicable)

minimum F75 mode F25 maximum

Drilling Depth (m) 500 3600 4600
78 Geologic Assessment of Undiscovered Oil and Gas in the Powder River Basin Province, Wyoming and Montana

Appendix C. Basic input data for the Muddy Sandstone Assessment Unit (50330202). SEVENTH APPROXIMATION DATA FORM

(NOGA, Version 6, 4-9-2003). [AU, assessment unit; bcfg, billion cubic feet of gas; bliq/mmcfg, barrels of liquid per million cubic feet 

of gas; bng/mmcfg, barrels of natural gas liquids per million cubic feet of gas; cfg/bo, cubic feet of gas per barrel of oil; m, meters; 

min, minimum; mmboe, million barrels of oil equivalent; ngl, natural gas liquids]

SEVENTH APPROXIMATION

DATA FORM FOR CONVENTIONAL ASSESSMENT UNITS (Version 6, 9 April 2003)

Assessment Geologist: L.O. Anna Date: 31-May-06

Region: North America Number: 5

Province: Powder River Basin Number: 5033

Total Petroleum System: Mowry Number: 503302

Assessment Unit: Muddy Sandstones Number: 50330202

Based on Data as of: IHS Energy (2006) and NRG (2005, data current through 2003), Wyoming Oil and 

Notes from Assessor : NRG reservoir growth function, 30 years

CHARACTERISTICS OF ASSESSMENT UNIT

Oil (<20,000 cfg/bo overall) or Gas (>20,000 cfg/bo overall): Oil

What is the minimum accumulation size? 0.5 mmboe grown

(the smallest accumulation that has potential to be added to reserves)

No. of discovered accumulations exceeding minimum size: Oil: 60 Gas: 8

Established (>13 accums.) X Frontier (1-13 accums.) Hypothetical (no accums.)

Median size (grown) of discovered oil accumulations (mmbo):

1st 3rd 2.36 2nd 3rd 2.9 3rd 3rd 1.03

Median size (grown) of discovered gas accumulations (bcfg):

1st 3rd 39.32 2nd 3rd 9.07 3rd 3rd

Assessment-Unit Probabilities:

 Attribute Probability of occurrence (0-1.0)

1. CHARGE: Adequate petroleum charge for an undiscovered accum. > minimum size: 1.0

2. ROCKS: Adequate reservoirs, traps, and seals for an undiscovered accum. > minimum size: 1.0

3. TIMING OF GEOLOGIC EVENTS: Favorable timing for an undiscovered accum. > minimum size 1.0

Assessment-Unit GEOLOGIC Probability (Product of 1, 2, and 3): 1.0

UNDISCOVERED ACCUMULATIONS

No. of Undiscovered Accumulations: How many undiscovered accums. exist that are > min. size?:

 (uncertainty of fixed but unknown values)

Oil Accumulations: minimum (>0) 2 mode 10 maximum 30

Gas Accumulations: minimum (>0) 2 mode 6 maximum 30

Sizes of Undiscovered Accumulations: What are the sizes (grown) of the above accums?:

 (variations in the sizes of undiscovered accumulations)

Oil in Oil Accumulations (mmbo): minimum 0.5 median 1.5 maximum 100

Gas in Gas Accumulations (bcfg): minimum 3 median 10 maximum 450

IDENTIFICATION INFORMATION

Gas Conservation Commission
Appendixes 79

Assessment Unit (name, no.)

Muddy Sandstones, 50330202

AVERAGE RATIOS FOR UNDISCOVERED ACCUMS., TO ASSESS COPRODUCTS

(uncertainty of fixed but unknown values)

Oil Accumulations: minimum mode maximum

Gas/oil ratio (cfg/bo) 1350 2700 5400

NGL/gas ratio (bngl/mmcfg) 60 90 120

Gas Accumulations: minimum mode maximum

Liquids/gas ratio (bliq/mmcfg) 50 100 150

Oil/gas ratio (bo/mmcfg)

SELECTED ANCILLARY DATA FOR UNDISCOVERED ACCUMULATIONS

(variations in the properties of undiscovered accumulations)

Oil Accumulations: minimum mode maximum

API gravity (degrees) 25 40 55

Sulfur content of oil (%) 0 0.1 0.35

Depth (m) of water (if applicable)

minimum F75 mode F25 maximum

Drilling Depth (m) 600 3600 4600

Gas Accumulations: minimum mode maximum

Inert gas content (%) 0.1 0.5 5

CO2 content (%) 0.1 0.9 2.2

Hydrogen-sulfide content (%) 0 0 0

Depth (m) of water (if applicable)

minimum F75 mode F25 maximum

Drilling Depth (m) 1000 3900 4600
80 Geologic Assessment of Undiscovered Oil and Gas in the Powder River Basin Province, Wyoming and Montana

Appendix D. Basic input data for the Frontier-Turner Sandstones Assessment Unit (50330301). SEVENTH APPROXIMATION DATA FORM

(NOGA, Version 6, 4-9-2003). [AU, assessment unit; bcfg, billion cubic feet of gas; bliq/mmcfg, barrels of liquid per million cubic feet 

of gas; bng/mmcfg, barrels of natural gas liquids per million cubic feet of gas; cfg/bo, cubic feet of gas per barrel of oil; m, meters; 

min, minimum; mmboe, million barrels of oil equivalent; ngl, natural gas liquids]

SEVENTH APPROXIMATION

DATA FORM FOR CONVENTIONAL ASSESSMENT UNITS (Version 6, 9 April 2003)

Assessment Geologist: L.O. Anna Date: 31-May-06

Region: North America Number: 5

Province: Powder River Basin Number: 5033

Total Petroleum System: Niobrara Number: 503303

Assessment Unit: Frontier-Turner Sandstones Number: 50330301

Based on Data as of: IHS Energy (2006) and NRG (2005, data current through 2003), Wyoming Oil and

Notes from Assessor: NRG reservoir growth function, 30 years

CHARACTERISTICS OF ASSESSMENT UNIT

Oil (<20,000 cfg/bo overall) or Gas (>20,000 cfg/bo overall): Oil

What is the minimum accumulation size? 0.5 mmboe grown

(the smallest accumulation that has potential to be added to reserves)

No. of discovered accumulations exceeding minimum size: Oil: 21 Gas: 1

Established (>13 accums.) X Frontier (1-13 accums.) Hypothetical (no accums.)

Median size (grown) of discovered oil accumulations (mmbo):

1st 3rd 2.15 2nd 3rd 1.16 3rd 3rd 0.88

Median size (grown) of discovered gas accumulations (bcfg):

1st 3rd 2nd 3rd 3rd 3rd

Assessment-Unit Probabilities:

 Attribute Probability of occurrence (0-1.0)

1. CHARGE: Adequate petroleum charge for an undiscovered accum. > minimum size: 1.0

2. ROCKS: Adequate reservoirs, traps, and seals for an undiscovered accum. > minimum size: 1.0

3. TIMING OF GEOLOGIC EVENTS: Favorable timing for an undiscovered accum. > minimum size 1.0

Assessment-Unit GEOLOGIC Probability (Product of 1, 2, and 3): 1.0

UNDISCOVERED ACCUMULATIONS

No. of Undiscovered Accumulations: How many undiscovered accums. exist that are > min. size?:

 (uncertainty of fixed but unknown values)

Oil Accumulations: minimum (>0) 1 mode 3 maximum 20

Gas Accumulations: minimum (>0) 0 mode 0 maximum 0

Sizes of Undiscovered Accumulations: What are the sizes (grown) of the above accums?:

 (variations in the sizes of undiscovered accumulations)

Oil in Oil Accumulations (mmbo): minimum 0.5 median 1 maximum 10

Gas in Gas Accumulations (bcfg): minimum median maximum

IDENTIFICATION INFORMATION

Gas Conservation Commission
Appendixes 81

Assessment Unit (name, no.)

Frontier-Turner Sandstones, 50330301

AVERAGE RATIOS FOR UNDISCOVERED ACCUMS., TO ASSESS COPRODUCTS

(uncertainty of fixed but unknown values)

Oil Accumulations: minimum mode maximum

Gas/oil ratio (cfg/bo) 1700 3400 6800

NGL/gas ratio (bngl/mmcfg) 36 72 108

Gas Accumulations: minimum mode maximum

Liquids/gas ratio (bliq/mmcfg)

Oil/gas ratio (bo/mmcfg)

SELECTED ANCILLARY DATA FOR UNDISCOVERED ACCUMULATIONS

(variations in the properties of undiscovered accumulations)

Oil Accumulations: minimum mode maximum

API gravity (degrees) 35 40 50

Sulfur content of oil (%) 0 0.1 0.3

Depth (m) of water (if applicable)

minimum F75 mode F25 maximum

Drilling Depth (m) 800 3600 3900

Gas Accumulations: minimum mode maximum

Inert gas content (%)

CO2 content (%)

Hydrogen-sulfide content (%)

Depth (m) of water (if applicable)

minimum F75 mode F25 maximum

Drilling Depth (m)
82 Geologic Assessment of Undiscovered Oil and Gas in the Powder River Basin Province, Wyoming and Montana

Appendix E. Basic input data for the Sussex-Shannon Sandstones Assessment Unit (50330302). SEVENTH APPROXIMATION 

DATA FORM(NOGA, Version 6, 4-9-2003). [AU, assessment unit; bcfg, billion cubic feet of gas; bliq/mmcfg, barrels of liquid per 

million cubic feet of gas; bng/mmcfg, barrels of natural gas liquids per million cubic feet of gas; cfg/bo, cubic feet of gas per barrel 

of oil; m, meters; min, minimum; mmboe, million barrels of oil equivalent; ngl, natural gas liquids]

SEVENTH APPROXIMATION

DATA FORM FOR CONVENTIONAL ASSESSMENT UNITS (Version 6, 9 April 2003)

Assessment Geologist: L.O. Anna Date: 31-May-06

Region: North America Number: 5

Province: Powder River Basin Number: 5033

Total Petroleum System: Niobrara Number: 503303

Assessment Unit: Sussex-Shannon Sandstones Number: 50330302

Based on Data as of: IHS Energy (2006) and NRG (2005, data current through 2003), Wyoming Oil and 

Notes from Assessor: NRG reservoir growth function, 30 years

CHARACTERISTICS OF ASSESSMENT UNIT

Oil (<20,000 cfg/bo overall) or Gas (>20,000 cfg/bo overall): Oil

What is the minimum accumulation size? 0.5 mmboe grown

(the smallest accumulation that has potential to be added to reserves)

No. of discovered accumulations exceeding minimum size: Oil: 17 Gas: 0

Established (>13 accums.) X Frontier (1-13 accums.) Hypothetical (no accums.)

Median size (grown) of discovered oil accumulations (mmbo):

1st 3rd 6.51 2nd 3rd 6.04 3rd 3rd 1.62

Median size (grown) of discovered gas accumulations (bcfg):

1st 3rd 2nd 3rd 3rd 3rd

Assessment-Unit Probabilities:

 Attribute Probability of occurrence (0-1.0)

1. CHARGE: Adequate petroleum charge for an undiscovered accum. > minimum size: 1.0

2. ROCKS: Adequate reservoirs, traps, and seals for an undiscovered accum. > minimum size: 1.0

3. TIMING OF GEOLOGIC EVENTS: Favorable timing for an undiscovered accum. > minimum size 1.0

Assessment-Unit GEOLOGIC Probability (Product of 1, 2, and 3): 1.0

UNDISCOVERED ACCUMULATIONS

No. of Undiscovered Accumulations: How many undiscovered accums. exist that are > min. size?:

 (uncertainty of fixed but unknown values)

Oil Accumulations: minimum (>0) 1 mode 3 maximum 10

Gas Accumulations: minimum (>0) 0 mode 0 maximum 0

Sizes of Undiscovered Accumulations: What are the sizes (grown) of the above accums?:

 (variations in the sizes of undiscovered accumulations)

Oil in Oil Accumulations (mmbo): minimum 0.5 median 1.5 maximum 12

Gas in Gas Accumulations (bcfg): minimum median maximum

IDENTIFICATION INFORMATION

Gas Conservation Commission
Appendixes 83

Assessment Unit (name, no.)

Sussex-Shannon Sandstones, 50330302

AVERAGE RATIOS FOR UNDISCOVERED ACCUMS., TO ASSESS COPRODUCTS

(uncertainty of fixed but unknown values)

Oil Accumulations: minimum mode maximum

Gas/oil ratio (cfg/bo) 400 800 1600

NGL/gas ratio (bngl/mmcfg) 40 80 120

Gas Accumulations: minimum mode maximum

Liquids/gas ratio (bliq/mmcfg)

Oil/gas ratio (bo/mmcfg)

SELECTED ANCILLARY DATA FOR UNDISCOVERED ACCUMULATIONS

(variations in the properties of undiscovered accumulations)

Oil Accumulations: minimum mode maximum

API gravity (degrees) 30 35 45

Sulfur content of oil (%) 0 0.17 0.25

Depth (m) of water (if applicable)

minimum F75 mode F25 maximum

Drilling Depth (m) 2100 2800 3500

Gas Accumulations: minimum mode maximum

Inert gas content (%)

CO2 content (%)

Hydrogen-sulfide content (%)

Depth (m) of water (if applicable)

minimum F75 mode F25 maximum

Drilling Depth (m)
84 Geologic Assessment of Undiscovered Oil and Gas in the Powder River Basin Province, Wyoming and Montana

Appendix F. Basic input data for the Mesaverde-Lewis conventional oil and gas Assessment Unit (50330303). SEVENTH 

APPROXIMATION DATA FORM(NOGA, Version 6, 4-9-2003). [AU, assessment unit; bcfg, billion cubic feet of gas; 

bliq/mmcfg, barrels of liquid per million cubic feet of gas; bng/mmcfg, barrles of natural gas liquids per million cubic feet of gas; 

cfg/bo, cubic feet of gas per barrel of oil; m, meters; min, minimum; mmboe, million barrels of oil equivalent; ngl, natural gas liquids;

Comm., Commission]

SEVENTH APPROXIMATION

DATA FORM FOR CONVENTIONAL ASSESSMENT UNITS (Version 6, 9 April 2003)

Assessment Geologist: Lawrence O. Anna Date:

Region: North America Number: 5

Province: Powder River Basin Number: 5033

Total Petroleum System: Niobrara Number: 503303

Assessment Unit: Mesaverde - Lewis conventional oil & gas Number: 50330303

Based on Data as of: PI/Dwights 2006, Wyo Oil & Gas Convervation Comm., Nehring Data base

Notes from Assessor: Well Draw field as analog

CHARACTERISTICS OF ASSESSMENT UNIT

Oil (<20,000 cfg/bo overall) or Gas (>20,000 cfg/bo overall): oil

What is the minimum accumulation size? 0.5 mmboe grown

(the smallest accumulation that has potential to be added to reserves)

No. of discovered accumulations exceeding minimum size: Oil: 19 Gas: 0

Established (>13 accums.) x Frontier (1-13 accums.) Hypothetical (no accums.)

Median size (grown) of discovered oil accumulations (mmbo):

1st 3rd 2.44 2nd 3rd 1.77 3rd 3rd 1.19

Median size (grown) of discovered gas accumulations (bcfg):

1st 3rd 2nd 3rd 3rd 3rd

Assessment-Unit Probabilities:

 Attribute Probability of occurrence (0-1.0)

1. CHARGE: Adequate petroleum charge for an undiscovered accum. > minimum size: 1.0

2. ROCKS: Adequate reservoirs, traps, and seals for an undiscovered accum. > minimum size: 1.0

3. TIMING OF GEOLOGIC EVENTS: Favorable timing for an undiscovered accum. > minimum size: 1.0

Assessment-Unit GEOLOGIC Probability (Product of 1, 2, and 3): 1.0

UNDISCOVERED ACCUMULATIONS

No. of Undiscovered Accumulations: How many undiscovered accums. exist that are > min. size?: 

 (uncertainty of fixed but unknown values)

Oil Accumulations: minimum (>0) 1 mode 2 maximum 10

Gas Accumulations: minimum (>0) 0 mode 1 maximum 7

Sizes of Undiscovered Accumulations: What are the sizes (grown) of the above accums?: 

 (variations in the sizes of undiscovered accumulations)

Oil in Oil Accumulations (mmbo): minimum 0.5 median 1.5 maximum 10

Gas in Gas Accumulations (bcfg): minimum 3 median 3.5 maximum 10

IDENTIFICATION INFORMATION
Appendixes 85

Assessment Unit (name, no.)

Mesaverde-Lewis Conventional oil & gas 50330303

AVERAGE RATIOS FOR UNDISCOVERED ACCUMS., TO ASSESS COPRODUCTS

(uncertainty of fixed but unknown values)

Oil Accumulations: minimum mode maximum

Gas/oil ratio (cfg/bo) 10 400 12,000

NGL/gas ratio (bngl/mmcfg) 10 80 200

Gas Accumulations: minimum mode maximum

Liquids/gas ratio (bliq/mmcfg) 50 300 750

Oil/gas ratio (bo/mmcfg)

SELECTED ANCILLARY DATA FOR UNDISCOVERED ACCUMULATIONS

(variations in the properties of undiscovered accumulations)

Oil Accumulations: minimum mode maximum

API gravity (degrees) 35 39 50

Sulfur content of oil (%) 0.01 0.09 0.25

Depth (m) of water (if applicable) 300 2800 3100

minimum F75 mode F25 maximum

Drilling Depth (m) 1200 2300 3050

Gas Accumulations: minimum mode maximum

Inert gas content (%) 0.1 0.7 2.7

CO2 content (%) 0.1 0.4 0.7

Hydrogen-sulfide content (%) 0 0 0

Depth (m) of water (if applicable)

minimum F75 mode F25 maximum

Drilling Depth (m)

1900 2400 3100
86 Geologic Assessment of Undiscovered Oil and Gas in the Powder River Basin Province, Wyoming and Montana

Appendix G. Basic input data for the Basin Margin Assessment Unit (50330601). SEVENTH APPROXIMATION DATA FORM 

(NOGA, Version 6, 4-9-2003). [AU, assessment unit; bcfg, billion cubic feet of gas; bliq/mmcfg, barrels of liquid per million 

cubic feet of gas; bng/mmcfg, barrels of natural gas liquids per million cubic feet of gas; cfg/bo, cubic feet of gas per barrel of oil; m, meters; 

min, minimum; mmboe, million barrels of oil equivalent; ngl, natural gas liquids]

SEVENTH APPROXIMATION

DATA FORM FOR CONVENTIONAL ASSESSMENT UNITS (Version 6, 9 April 2003)

Assessment Geologist: L.O. Anna Date: 31-May-06

Region: North America Number: 5

Province: Powder River Basin Number: 5033

Total Petroleum System: Paleozoic-Mesozoic Composite Number: 503306

Assessment Unit: Basin Margin Number: 50330601

Based on Data as of: IHS Energy (2006) and NRG (2005, data current through 2003), Wyoming Oil and

Notes from Assessor: NRG reservoir growth function, 30 years

CHARACTERISTICS OF ASSESSMENT UNIT

Oil (<20,000 cfg/bo overall) or Gas (>20,000 cfg/bo overall): Oil

What is the minimum accumulation size? 0.5 mmboe grown

(the smallest accumulation that has potential to be added to reserves)

No. of discovered accumulations exceeding minimum size: Oil: 41 Gas: 0

Established (>13 accums.) X Frontier (1-13 accums.) Hypothetical (no accums.)

Median size (grown) of discovered oil accumulations (mmbo):

1st 3rd 8.31 2nd 3rd 10.44 3rd 3rd 1.88

Median size (grown) of discovered gas accumulations (bcfg):

1st 3rd 2nd 3rd 3rd 3rd

Assessment-Unit Probabilities:

 Attribute Probability of occurrence (0-1.0)

1. CHARGE: Adequate petroleum charge for an undiscovered accum. > minimum size: 1.0

2. ROCKS: Adequate reservoirs, traps, and seals for an undiscovered accum. > minimum size: 1.0

3. TIMING OF GEOLOGIC EVENTS: Favorable timing for an undiscovered accum. > minimum size 1.0

Assessment-Unit GEOLOGIC Probability (Product of 1, 2, and 3): 1.0

UNDISCOVERED ACCUMULATIONS

No. of Undiscovered Accumulations: How many undiscovered accums. exist that are > min. size?:

 (uncertainty of fixed but unknown values)

Oil Accumulations: minimum (>0) 1 mode 5 maximum 20

Gas Accumulations: minimum (>0) 0 mode 0 maximum 0

Sizes of Undiscovered Accumulations: What are the sizes (grown) of the above accums?:

 (variations in the sizes of undiscovered accumulations)

Oil in Oil Accumulations (mmbo): minimum 0.5 median 1.5 maximum 20

Gas in Gas Accumulations (bcfg): minimum median maximum

IDENTIFICATION INFORMATION

Gas Conservation Commission
Appendixes 87

Assessment Unit (name, no.)

Basin Margin, 50330601

AVERAGE RATIOS FOR UNDISCOVERED ACCUMS., TO ASSESS COPRODUCTS

(uncertainty of fixed but unknown values)

Oil Accumulations: minimum mode maximum

Gas/oil ratio (cfg/bo) 350 700 1400

NGL/gas ratio (bngl/mmcfg) 18 36 54

Gas Accumulations: minimum mode maximum

Liquids/gas ratio (bliq/mmcfg)

Oil/gas ratio (bo/mmcfg)

SELECTED ANCILLARY DATA FOR UNDISCOVERED ACCUMULATIONS

(variations in the properties of undiscovered accumulations)

Oil Accumulations: minimum mode maximum

API gravity (degrees) 15 33 50

Sulfur content of oil (%) 0 0.5 4

Depth (m) of water (if applicable)

minimum F75 mode F25 maximum

Drilling Depth (m) 250 1800 3200

Gas Accumulations: minimum mode maximum

Inert gas content (%)

CO2 content (%)

Hydrogen-sulfide content (%)

Depth (m) of water (if applicable)

minimum F75 mode F25 maximum

Drilling Depth (m)
88 Geologic Assessment of Undiscovered Oil and Gas in the Powder River Basin Province, Wyoming and Montana

Appendix H. Basic input data for the Mowry Continuous Oil Assessment Unit (50330261). FORSPAN ASSESSMENET MODEL FOR 

CONTINUOUS ACCUMULATIONS (NOGA, Version 7, 6-30-2000). [AU, assessment unit; bcfg, billion cubic feet of gas; 

bliq/mmcfg, barrels of liquid per million cubic feet of gas; bng/mmcfg, barrels of natural gas liquids per million cubic feet of gas; 

cfg/bo, cubic feet of gas per barrel of oil; m, meters; min, minimum; mmboe, million barrels of oil equivalent; ngl, natural gas liquids]

FORSPAN ASSESSMENT MODEL FOR CONTINUOUS

ACCUMULATIONS--BASIC INPUT DATA FORM (NOGA, Version 7, 6-30-00)

IDENTIFICATION INFORMATION

Assessment Geologist:... L.O. Anna Date: 8/5/2002

Region:........................ North America Number: 5

Province:...................... Powder River Basin Number: 5033

Total Petroleum System:. Mowry Number: 503302

Assessment Unit:.......... Mowry Continuous Oil Number: 50330261

Based on Data as of:...... PI/Dwights 2001, Wyoming Oil and Gas Conservation Commission

Notes from Assessor..... 1- to 2-well (Mowry) fields in basin and Bakken Shale as analogs

Based on EURs and drainage areas of vertical wells

Future success ratio: 50%

CHARACTERISTICS OF ASSESSMENT UNIT

Assessment-Unit type: Oil (<20,000 cfg/bo) or Gas (>20,000 cfg/bo) Oil

What is the minimum total recovery per cell?... 0.002 (mmbo for oil A.U.; bcfg for gas A.U.)

Number of tested cells:............. 62

Number of tested cells with total recovery per cell > minimum: ......... 31

Established (>24 cells > min.) X Frontier (1-24 cells) Hypothetical (no cells)

Median total recovery per cell (for cells > min.): (mmbo for oil A.U.; bcfg for gas A.U.)

 1st 3rd discovered 2nd 3rd 3rd 3rd

Assessment-Unit Probabilities:

 Attribute Probability of occurrence (0-1.0)

1. CHARGE: Adequate petroleum charge for an untested cell with total recovery minimum ...... > 1.0

2. ROCKS: Adequate reservoirs, traps, seals for an untested cell with total recovery minimum. > 1.0

3. TIMING: Favorable geologic timing for an untested cell with total recovery minimum........... > 1.0

Assessment-Unit GEOLOGIC Probability (Product of 1, 2, and 3):........................ 1.0

4. ACCESS: Adequate location for necessary petroleum-related activities for an untested cell

 with total recovery > minimum ........................................................................ 1.0

NO. OF UNTESTED CELLS WITH POTENTIAL FOR ADDITIONS TO RESERVES IN THE NEXT 30 YEARS

1. Total assessment-unit area (acres): (uncertainty of a fixed value)

minimum 6,009,000 median 6,325,000 maximum 6,641,000

2. Area per cell of untested cells having potential for additions to reserves in next 30 years (acres):

(values are inherently variable) minimum 40 median 270 maximum 640

3. Percentage of total assessment-unit area that is untested (%): (uncertainty of a fixed value)

minimum 99.6 median 99.7 maximum 99.8

4. Percentage of untested assessment-unit area that has potential for additions to reserves in

next 30 years (%): ( a necessary criterion is that total recovery per cell > minimum)

(uncertainty of a fixed value) minimum 8 median 25 maximum 45
Appendixes 89

Assessment Unit (name, no.)

Mowry Continuous Oil, 50330261

TOTAL RECOVERY PER CELL

Total recovery per cell for untested cells having potential for additions to reserves in next 30 years:

(values are inherently variable)

(mmbo for oil A.U.; bcfg for gas A.U.) minimum 0.002 median 0.025 maximum 0.35

AVERAGE COPRODUCT RATIOS FOR UNTESTED CELLS, TO ASSESS COPRODUCTS

(uncertainty of fixed but unknown values)

Oil assessment unit: minimum median maximum

 Gas/oil ratio (cfg/bo)..................................... 500 1000 1500

 NGL/gas ratio (bngl/mmcfg).......................... 30 60 90

Gas assessment unit:

 Liquids/gas ratio (bliq/mmcfg)........................

SELECTED ANCILLARY DATA FOR UNTESTED CELLS

(values are inherently variable)

Oil assessment unit: minimum median maximum

 API gravity of oil (degrees)............................. 35 40 45

 Sulfur content of oil (%)................................. 0 0.5 2

 Drilling depth (m) ........................................ 2400 2900 4300

 Depth (m) of water (if applicable)...................

Gas assessment unit:

 Inert-gas content (%).....................................

 CO2 content (%)...........................................

 Hydrogen-sulfide content (%).........................

 Drilling depth (m)........................................

 Depth (m) of water (if applicable)...................
90 Geologic Assessment of Undiscovered Oil and Gas in the Powder River Basin Province, Wyoming and Montana

Appendix I. Basic input data for the Niobrara Continuous Oil Assessment Unit (50330361). FORSPAN ASSESSMENT MODEL FOR 

CONTINUOUS ACCUMULATION (NOGA, Version 7, 6-3-2000). [AU, assessment unit; bcfg, billion cubic feet of gas; 

bliq/mmcfg, barrels of liquid per million cubic feet of gas; bng/mmcfg, barrels of natural gas liquids per million cubic feet of gas; 

cfg/bo, cubic feet of gas per barrel of oil; m, meters; min, minimum; mmboe, million barrels of oil equivalent; ngl, natural gas liquids]

FORSPANASSESSMENT MODEL FOR CONTINUOUS

ACCUMULATIONS--BASIC INPUT DATA FORM (NOGA, Version 7, 6-30-00)

IDENTIFICATION INFORMATION

Assessment Geologist:... L.O. Anna Date: 8/6/2002

Region:........................ North America Number: 5

Province:...................... Powder River Basin Number: 5033

Total Petroleum System:. Niobrara Number: 503303

Assessment Unit:.......... Niobrara Continuous Oil Number: 50330361

Based on Data as of:...... PI/Dwights 2001, Wyoming Oil and Gas Conservation Commission

Notes from Assessor..... 1- to 2-well (Niobrara) fields in basin and Silo Field as analogs

Based on EURs and drainage areas of vertical wells

Future success ratio: 60%

CHARACTERISTICS OF ASSESSMENT UNIT

Assessment-Unit type: Oil (<20,000 cfg/bo) or Gas (>20,000 cfg/bo) Oil

What is the minimum total recovery per cell ... ? 0.002 (mmbo for oil A.U.; bcfg for gas A.U.)

Number of tested cells:............. 43

Number of tested cells with total recovery per cell > minimum: ......... 25

Established (>24 cells > min.) X Frontier (1-24 cells) Hypothetical (no cells)

Median total recovery per cell (for cells > min.): (mmbo for oil A.U.; bcfg for gas A.U.)

 1st 3rd discovered 2nd 3rd 3rd 3rd

Assessment-Unit Probabilities:

 Attribute Probability of occurrence (0-1.0)

1. CHARGE: Adequate petroleum charge for an untested cell with total recovery minimum ...... > 1.0

2. ROCKS: Adequate reservoirs, traps, seals for an untested cell with total recovery minimum. > 1.0

3. TIMING: Favorable geologic timing for an untested cell with total recovery minimum........... > 1.0

Assessment-Unit GEOLOGIC Probability (Product of 1, 2, and 3):........................ 1.0

4. ACCESS: Adequate location for necessary petroleum-related activities for an untested cell

 with total recovery > minimum ........................................................................ 1.0

NO. OF UNTESTED CELLS WITH POTENTIAL FOR ADDITIONS TO RESERVES IN THE NEXT 30 YEARS

1. Total assessment-unit area (acres): (uncertainty of a fixed value)

minimum 4,372,000 median 4,602,000 maximum 4,832,000

2. Area per cell of untested cells having potential for additions to reserves in next 30 years (acres):

(values are inherently variable) minimum 10 median 130 maximum 320

3. Percentage of total assessment-unit area that is untested (%): (uncertainty of a fixed value)

minimum 99.77 median 99.87 maximum 99.97

4. Percentage of untested assessment-unit area that has potential for additions to reserves in

next 30 years (%): ( a necessary criterion is that total recovery per cell > minimum)

(uncertainty of a fixed value) minimum 4.1 median 16.4 maximum 27.2
Appendixes 91

Assessment Unit (name, no.)

Niobrara Continuous Oil, 50330361

TOTAL RECOVERY PER CELL

Total recovery per cell for untested cells having potential for additions to reserves in next 30 years:

(values are inherently variable)

(mmbo for oil A.U.; bcfg for gas A.U.) minimum 0.002 median 0.028 maximum 0.5

AVERAGE COPRODUCT RATIOS FOR UNTESTED CELLS, TO ASSESS COPRODUCTS

(uncertainty of fixed but unknown values)

Oil assessment unit: minimum median maximum

 Gas/oil ratio (cfg/bo)..................................... 500 1000 1500

 NGL/gas ratio (bngl/mmcfg).......................... 30 60 90

Gas assessment unit:

 Liquids/gas ratio (bliq/mmcfg)........................

SELECTED ANCILLARY DATA FOR UNTESTED CELLS

(values are inherently variable)

Oil assessment unit: minimum median maximum

 API gravity of oil (degrees)............................. 34 39 45

 Sulfur content of oil (%)................................. 0.02 0.1 0.5

 Drilling depth (m) ........................................ 2400 2900 4000

 Depth (m) of water (if applicable)...................

Gas assessment unit:

 Inert-gas content (%).....................................

 CO2 content (%)...........................................

 Hydrogen-sulfide content (%).........................

 Drilling depth (m)........................................

 Depth (m) of water (if applicable)...................
92 Geologic Assessment of Undiscovered Oil and Gas in the Powder River Basin Province, Wyoming and Montana

Appendix J. Basic input data for the Shallow Continuous Biogenic Gas Assessment Unit (50330461). FORSPAN ASSESSMENT 

MODEL FOR CONTINUOUS ACCUMULATION (NOGA, Version 7, 6-3-2000). [AU, assessment unit; bcfg, billion cubic feet of gas; 

bliq/mmcfg, barrels of liquid per million cubic feet of gas; bng/mmcfg, barrels of natural gas liquids per million cubic feet of gas; 

cfg/bo, cubic feet of gas per barrel of oil; m, meters; min, minimum; mmboe, million barrels of oil equivalent; ngl, natural gas liquids]

FORSPAN ASSESSMENT MODEL FOR CONTINUOUS

ACCUMULATIONS--BASIC INPUT DATA FORM (NOGA, Version 7, 6-30-00)

IDENTIFICATION INFORMATION

Assessment Geologist:... L.O. Anna Date: 8/6/2002

Region:........................ North America Number: 5

Province:...................... Powder River Basin Number: 5033

Total Petroleum System:. Cretaceous Biogenic Gas Number: 503304

Assessment Unit:.......... Shallow Continuous Biogenic Gas Number: 50330461

Based on Data as of:...... PI/Dwights 2001

Notes from Assessor..... West Short Pine Hills Field as analog

Future success ratio: 40%

CHARACTERISTICS OF ASSESSMENT UNIT

Assessment-Unit type: Oil (<20,000 cfg/bo) or Gas (>20,000 cfg/bo) Gas

What is the minimum total recovery per cell? 0.01 (mmbo for oil A.U.; bcfg for gas A.U.)

Number of tested cells:............. 0

Number of tested cells with total recovery per cell > minimum: ......... 0

Established (>24 cells > min.) Frontier (1-24 cells) Hypothetical (no cells) X

Median total recovery per cell (for cells > min.): (mmbo for oil A.U.; bcfg for gas A.U.)

 1st 3rd discovered 2nd 3rd 3rd 3rd

Assessment-Unit Probabilities:

 Attribute Probability of occurrence (0-1.0)

1. CHARGE: Adequate petroleum charge for an untested cell with total recovery minimum ...... > 1.0

2. ROCKS: Adequate reservoirs, traps, seals for an untested cell with total recovery minimum. > 1.0

3. TIMING: Favorable geologic timing for an untested cell with total recovery minimum........... > 1.0

Assessment-Unit GEOLOGIC Probability (Product of 1, 2, and 3):........................ 1.0

4. ACCESS: Adequate location for necessary petroleum-related activities for an untested cell

 with total recovery > minimum ........................................................................ 1.0

NO. OF UNTESTED CELLS WITH POTENTIAL FOR ADDITIONS TO RESERVES IN THE NEXT 30 YEARS

1. Total assessment-unit area (acres): (uncertainty of a fixed value)

minimum 18,726,000 median 19,712,000 maximum 20,698,000

2. Area per cell of untested cells having potential for additions to reserves in next 30 years (acres):

(values are inherently variable) minimum 40 median 160 maximum 320

3. Percentage of total assessment-unit area that is untested (%): (uncertainty of a fixed value)

minimum 100 median 100 maximum 100

4. Percentage of untested assessment-unit area that has potential for additions to reserves in

next 30 years (%): ( a necessary criterion is that total recovery per cell > minimum)

(uncertainty of a fixed value) minimum 1 median 5 maximum 12.5
Appendixes 93

Assessment Unit (name, no.)

Shallow Continuous Biogenic Gas, 50330461

TOTAL RECOVERY PER CELL

Total recovery per cell for untested cells having potential for additions to reserves in next 30 years:

(values are inherently variable)

(mmbo for oil A.U.; bcfg for gas A.U.) minimum 0.01 median 0.08 maximum 1.5

AVERAGE COPRODUCT RATIOS FOR UNTESTED CELLS, TO ASSESS COPRODUCTS

(uncertainty of fixed but unknown values)

Oil assessment unit: minimum median maximum

 Gas/oil ratio (cfg/bo).....................................

 NGL/gas ratio (bngl/mmcfg)..........................

Gas assessment unit:

 Liquids/gas ratio (bliq/mmcfg)........................ 0 0 0

SELECTED ANCILLARY DATA FOR UNTESTED CELLS

(values are inherently variable)

Oil assessment unit: minimum median maximum

 API gravity of oil (degrees).............................

 Sulfur content of oil (%).................................

 Drilling depth (m) ........................................

 Depth (m) of water (if applicable)...................

Gas assessment unit:

 Inert-gas content (%).....................................

 CO2 content (%)........................................... 0.00 0.20 0.30

 Hydrogen-sulfide content (%)......................... 0.00 0.00 0.00

 Drilling depth (m)........................................ 200 600 1040

 Depth (m) of water (if applicable)...................
Publishing support provided by: 

Denver Publishing Service Center

For more information concerning this publication, contact:

Team Chief Scientist, USGS Central Energy Resources

Box 25046, Mail Stop 939

Denver, CO 80225

(303) 236-1647

Or visit the Central Energy Resources Team site at:

http://energy.cr.usgs.gov/
Tabular Data and Graphical Images in 

Support of the U.S. Geological Survey 

National Oil and Gas Assessment—

Powder River Basin Province (5033)

By T.R. Klett and P.A. Le

Chapter 2 

Digital Data Series DDS–69–U

U.S. Department of the Interior

U.S. Geological Survey
U.S. Department of the Interior

KEN SALAZAR, Secretary

U.S. Geological Survey

Suzette M. Kimball, Acting Director

U.S. Geological Survey, Reston, Virginia: 2009

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

U.S. Government.

Although this report is in the public domain, permission must be secured from the individual copyright owners to 

reproduce any copyrighted materials contained within this report.

Suggested citation:

Klett, T.R., Le, P.A., 2009, Tabular data and graphical images in support of the U.S. Geological Survey National Oil and 

Gas Assessment—Powder River Basin Province (5033): U.S. Geological Survey Digital Data Series DDS–69–U, 20 p.
iii

Contents

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

Disclaimers .....................................................................................................................................................1

Data Sources..................................................................................................................................................1

Data Overview................................................................................................................................................2

Data Tables ............................................................................................................................................2

Summary Tables....................................................................................................................................2

Graphs.....................................................................................................................................................2

Numeric Codes...............................................................................................................................................2

Summary Tables....................................................................................................................................3

Graphical Data................................................................................................................................................3

File List.............................................................................................................................................................4

Tabular Data....................................................................................................................................................5

References Cited..........................................................................................................................................20

Tabular Data and Graphical Images in Support of the U.S. 

Geological Survey National Oil and Gas Assessment—

Powder River Basin Province (5033)

By T.R. Klett and P.A. Le

Introduction

This chapter describes data used in support of the process being applied by the U.S. Geological Survey (USGS) National 

Oil and Gas Assessment (NOGA) project. Digital tabular data used in this report and archival data that permit the user to 

perform further analyses are available elsewhere on this CD–ROM. Computers and software may import the data without 

transcription from the Portable Document Format files (.pdf files) of the text by the reader. Because of the number and variety 

of platforms and software available, graphical images are provided as .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 United States Government. Reference therein to any specific commercial 

product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its 

endorsement, recommendation, or favoring by the United States Government or any agency thereof.

The 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.

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, 2006a), (2) PI/Dwights Plus US Well Data (IHS Energy Group, 2006b), (3) NRG Associates, Inc., “Significant 

Oil and Gas Fields of the United States” (NRG Associates, 2005), 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.
2 Tabular Data and Graphical Images of the USGS Survey National Oil and Gas Assessment—Powder River Basin 

Data Overview

This report provides various data files supporting the NOGA project. The files contain data that are the source for the 

various graphs, data tables, and summary tables used in the assessment process. Tabular data are provided as tab-delimited 

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:

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

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 Powder River Basin 5033

Total Petroleum System Cretaceous-Tertiary Composite 503301

Mowry 503302

Niobrara 503303

Cretaceous Biogenic Gas 503304

Pennsylvanian-Permian Composite 503305

Paleozoic-Mesozoic Composite 503306

Assessment Units Eastern Basin Margin Upper Fort Union Sandstone 50330101

Wasatch Formation 50330181

Upper Fort Union Formation 50330182

Lower Fort Union–Lance Formations 50330183
Graphical Data 3

Fall River–Lakota Sandstones 50330201

Muddy Sandstones 50330202

Mowry Continuous Oil 50330261

Frontier-Turner Sandstones 50330301

Sussex-Shannon Sandstones 50330302

Mesaverde-Lewis Sandstones 50330303

Niobrara Continuous Oil 50330361

Shallow Continuous Biogenic Gas 50330461

Minnelusa-Tensleep-Leo Sandstones 50330501

Basin Margin 50330601

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 503300, 

50330160 or 50330180.

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 

Eastern Basin Margin Upper Fort Union Sandstone assessment unit is labeled “c330101.pdf.”

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 

field 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. Drilling-Completion Year

• Oil- or Gas-Accumulation Size (MMBO or BCFG) vs. Oil- or Gas-Accumulation Rank by Size (With Respect to 

Discovery Halves or Thirds)
4 Tabular Data and Graphical Images of the USGS Survey National Oil and Gas Assessment—Powder River Basin 

• Number of Oil or Gas Accumulations vs. Oil- or Gas-Accumulation 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 (ft) vs. Accumulation-Discovery Year

• Reservoir Depth, Oil or Gas Accumulations (ft) vs. Cumulative Number of New-Field Wildcat Wells

• Gas/Oil, Oil Accumulations (CFG/BO) vs. Mean Reservoir Depth (ft)

• NGL/Gas, Oil Accumulations (BNGL/MMCFG) vs. Mean Reservoir Depth (ft)

• Liquids/Gas, Gas Accumulations (BL/MMCFG) vs. Mean Reservoir Depth (ft)

• Number of Reservoirs in Oil Accumulations vs. API Gravity (Degrees)

If data are insufficient or do not exist, graphs are not provided. Therefore, not all graphs are included in all files.

File List

Data tables

eco5033.tab

fed5033.tab

inf5033.tab

ins5033.tab

kvol5033.tab

own5033.tab

sta5033.tab

vol5033.tab

Summary tables Assessment-unit name

c330101.pdf Eastern Basin Margin Upper Fort Union Sandstone

c330201.pdf Fall River–Lakota Sandstones

c330202.pdf Muddy Sandstones

c330301.pdf Frontier-Turner Sandstones

c330302.pdf Sussex-Shannon Sandstones

c330303.pdf Mesaverde-Lewis Sandstones

c330501.pdf Minnelusa-Tensleep-Leo Sandstones

c330601.pdf Basin Margin

d330201.pdf Fall River–Lakota Sandstones

d330301.pdf Frontier-Turner Sandstones

d330302.pdf Sussex-Shannon Sandstones

d330303.pdf Mesaverde-Lewis Sandstones

d330501.pdf Minnelusa-Tensleep-Leo Sandstones

d330601.pdf Basin Margin

u330181.pdf Wasatch Formations

u330182.pdf Upper Fort Union Formation

u330183.pdf Lower Fort Union–Lance Formations
Tabular Data 5

u330261.pdf Mowry Continuous Oil

u330361.pdf Niobrara Continuous Oil

u330461.pdf Shallow Continuous Biogenic Gas

Graphs Assessment-unit name

em330101.pdf Eastern Basin Margin Upper Fort Union Sandstone

em330201.pdf Fall River–Lakota Sandstones

em330202.pdf Muddy Sandstones

em330301.pdf Frontier-Turner Sandstones

em330302.pdf Sussex-Shannon Sandstones

em330303.pdf Mesaverde-Lewis Sandstones

em330501.pdf Minnelusa-Tensleep-Leo Sandstones

em330601.pdf Basin Margin

fp330181.pdf Wasatch Formations

fp330182.pdf Upper Fort Union Formation

fp330183.pdf Lower Fort Union–Lance Formations

fp330261.pdf Mowry Continuous Oil

fp330361.pdf Niobrara Continuous Oil

fp330461.pdf Shallow Continuous Biogenic Gas

g330201.pdf Fall River–Lakota Sandstones

g330301.pdf Frontier-Turner Sandstones

g330302.pdf Sussex-Shannon Sandstones

g330303.pdf Mesaverde-Lewis Sandstones

g330501.pdf Minnelusa-Tensleep-Leo Sandstones

g330601.pdf Basin Margin

k330201.pdf Fall River–Lakota Sandstones

k330301.pdf Frontier-Turner Sandstones

k330302.pdf Sussex-Shannon Sandstones

k330303.pdf Mesaverde-Lewis Sandstones

k330501.pdf Minnelusa-Tensleep-Leo Sandstones

k330601.pdf Basin Margin

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.

(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.
6 Tabular Data and Graphical Images of the USGS Survey National Oil and Gas Assessment—Powder River Basin 

(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.

(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 

assessment-unit 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 

assessment-unit area.
Tabular Data 7

(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 

assessment-unit 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 Withdrawals (NPSP),” name of Federal land that occupies all or part of the assessment-unit 

area.

(25) NPSP Area %—percentage of assessment-unit area that is occupied by National Park Service Withdrawals.

(26) NPSP Oil %—estimated percentage of undiscovered oil volume allocated to National Park Service 

Withdrawals.

(27) NPSP Gas %—estimated percentage of undiscovered gas volume allocated to National Park Service 

Withdrawals.

(28) FS—“Forest Service (FS),” name of Federal land that occupies all or part of the assessment-unit area.

(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.
8 Tabular Data and Graphical Images of the USGS Survey National Oil and Gas Assessment—Powder River Basin 

(40) FSP—“FS Protected Withdrawals (FSP),” name of Federal land that occupies all or part of the assessmentunit 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 

assessment-unit 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 

assessment-unit 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 assessmentunit 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.

(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 assessmentunit 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 

assessment-unit 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.
Tabular Data 9

(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) 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.

(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 assessmentunit 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 assessmentunit 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.
10 Tabular Data and Graphical Images of the USGS Survey National Oil and Gas Assessment—Powder River Basin 

(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 assessmentunit 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 assessmentunit 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 assessmentunit 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.

(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.
Tabular Data 11

(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.

(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).
12 Tabular Data and Graphical Images of the USGS Survey National Oil and Gas Assessment—Powder River Basin 

(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).

(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).
Tabular Data 13

(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).

(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) Data—data sources used to aid in completing the data-input form.

(12) 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-to-oil ratio (GOR) is less than 20,000 

cubic feet of gas per barrel of oil; otherwise, it is gas prone.

(13) 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.

(14) Numtest1—number of tested cells in the assessment unit.

(15) 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.
14 Tabular Data and Graphical Images of the USGS Survey National Oil and Gas Assessment—Powder River Basin 

(16) 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.

(17) 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.

(18) 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.

(19) 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.

(20) 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.

(21) 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.

(22) 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.

(23) Geoprob %—geologic probability, the product of charge, rocks, and timing probabilities. Geologic 

probability is given as a fractional value from 0 to 1.0.

(24) Prob4 %—accessibility probability, the probability for adequate location for necessary petroleumrelated activities to discover 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. Accessibility probability is 

given as a fractional value from 0 to 1.0.

(25) TAAmin a—minimum total assessment-unit area, the estimated minimum (F100) area of the assessment 

unit. The area is given in acres.

(26) TAAmed a—median total assessment-unit area, the estimated median (F50) area of the assessment unit. 

The area is given in acres.

(27) TAAmax a—maximum total assessment-unit area, the estimated maximum (F0) area of the assessment 

unit. The area is given in acres.

(28) CAmin a—minimum area per cell of untested cells with potential, the 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.

(29) CAmed a—median area per cell of untested cells with potential, the estimated median (F50) 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) CAmax a—maximum area per cell of untested cells with potential, the 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.

(31) TAAUmin %—estimated minimum (F100) percentage of the total assessment-unit area that is untested.

(32) TAAUmed %—estimated median (F50) percentage of the total assessment-unit area that is untested.

(33) TAAUmax %—estimated maximum (F0) percentage of the total assessment-unit area that is untested.

(34) UAAPmin %—estimated minimum (F100) percentage of the untested area in the assessment unit having 

the potential for additions to reserves).

(35) UAAPmed %—estimated median (F50) percentage of the untested area in the assessment unit having the 

potential for additions to reserves.

(36) UAAPmax %—estimated maximum (F0) percentage of the untested area in the assessment unit having the 

potential for additions to reserves.
Tabular Data 15

(37) 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.

(38) 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.

(39) 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.

(40) 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.

(41) GmedCF/B—estimated median (F50) 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.

(42) 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.

(43) 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.

(44) NmedB/MMCF—estimated median (F50) 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.

(45) 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.

(46) 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 untested cells equal to or larger than 

the minimum total recovery in gas assessment units.

(47) LmedB/MMCF—estimated median (F50) 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.

(48) 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.

(49) APImin deg—estimated minimum (F100) API gravity, in degrees, of oil in untested cells in oil assessment 

units.

(50) APImed deg—estimated median (F50) API gravity, in degrees, of oil in untested cells in oil assessment 

units.

(51) APImax deg—estimated maximum (F0) API gravity, in degrees, of oil in untested cells in oil assessment 

units.

(52) Smin %—estimated minimum (F100) sulfur content, in percent, of oil in untested cells in oil assessment 

units.

(53) Smed %—estimated median (F50) sulfur content, in percent, of oil in untested cells in oil assessment units.

(54) Smax %—estimated maximum (F0) sulfur content, in percent, of oil in untested cells in oil assessment 

units.

(55) ODmin m—estimated minimum (F100) drilling depth, in meters, of oil in untested cells in oil assessment 

units.

(56) ODmed m—estimated median (F50) drilling depth, in meters, of oil in untested cells in oil assessment 

units.

(57) ODmax m—estimated maximum (F0) drilling depth, in meters, of oil in untested cells in oil assessment 

units.

(58) OWDmin m—estimated minimum (F100) water depth, in meters, of oil in untested cells in oil assessment 

units (ocean, bays, or lakes; if applicable).

(59) OWDmed m—estimated median (F50) water depth, in meters, of oil in untested cells in oil assessment 

units (ocean, bays, or lakes; if applicable).
16 Tabular Data and Graphical Images of the USGS Survey National Oil and Gas Assessment—Powder River Basin 

(60) OWDmax m—estimated maximum (F0) water depth, in meters, of oil in untested cells in oil assessment 

units (ocean, bays, or lakes; if applicable).

(61) IGmin %—estimated minimum (F100) inert gas content, in percent, of gas in untested cells in gas 

assessment units (nitrogen and helium, and so forth).

(62) IGmed %—estimated median (F50) inert gas content, in percent, of gas in untested cells in gas assessment 

units (nitrogen and helium, and so forth).

(63) IGmax %—estimated maximum (F0) inert gas content, in percent, of gas in untested cells in gas 

assessment units (nitrogen and helium, and so forth).

(64) CO2min %—estimated minimum (F100) carbon dioxide content, in percent, of gas in untested cells in gas 

assessment units.

(65) CO2med %—estimated median (F50) carbon dioxide content, in percent, of gas in untested cells in gas 

assessment units.

(66) CO2max %—estimated maximum (F0) carbon dioxide content, in percent, of gas in untested cells in gas 

assessment units.

(67) H2Smin %—estimated minimum (F100) hydrogen sulfide content, in percent, of gas in untested cells in 

gas assessment units.

(68) H2Smed %—estimated median (F50) hydrogen sulfide content, in percent, of gas in untested cells in gas 

assessment units.

(69) H2Smax %—estimated maximum (F0) hydrogen sulfide content, in percent, of gas in untested cells in gas 

assessment units.

(70) GDmin m—estimated minimum (F100) drilling depth, in meters, of gas in untested cells in gas assessment 

units.

(71) GDmed m—estimated median (F50) drilling depth, in meters, of gas in untested cells in gas assessment 

units.

(72) GDmax m—estimated maximum (F0) drilling depth, in meters, of gas in untested cells in gas assessment 

units.

(73) GWDmin m—estimated minimum (F100) water depth, in meters, of gas in untested cells in gas assessment 

units (ocean, bays, or lakes; if applicable)(74) GWDmed m—estimated median (F50) water depth, 

in meters, of gas in untested cells in gas assessment units (ocean, bays, or lakes; if applicable).

(75) GWDmax m—estimated maximum (F0) water depth, in meters, of gas in untested cells in gas assessment 

units (ocean, bays, or lakes; if applicable).

(76) FSRmean %—estimated mean future success ratio, as percent.

(77) FSRmin %—estimated minimum (F100) future success ratio, as percent.

(78) FSRmed %—estimated median (F50) future success ratio, as percent.

(79) FSRmax %—estimated maximum (F100) future success ratio, as percent.

(80) HSR %—historical success ratio, as percent.

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 data-input 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.
Tabular Data 17

(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 onethird 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 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.

(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.
18 Tabular Data and Graphical Images of the USGS Survey National Oil and Gas Assessment—Powder River Basin 

(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.

(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) API gravity, in degrees, of oil in undiscovered oil accumulations 

in the assessment unit.

(49) APImod deg—estimated mode of API gravity, in degrees, of oil in undiscovered oil accumulations in the 

assessment unit.

(50) APImax deg—estimated maximum (F0) API gravity, in degrees, of oil in undiscovered oil accumulations 

in the assessment unit.

(51) Smin %—estimated minimum (F100) sulfur content, in percent, of oil in undiscovered oil accumulations in 

the assessment unit.

(52) Smod %—estimated mode of sulfur content, in percent, of oil in undiscovered oil accumulations in the 

assessment unit.

(53) Smax %—estimated maximum (F0) sulfur 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.
Tabular Data 19

(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 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 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 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 content, in percent, of gas in untested cells in gas 

assessment units.

(66) CO2mod %—estimated mode of carbon dioxide content, in percent, of gas in untested cells in gas 

assessment units.

(67) CO2max %—estimated maximum (F0) carbon dioxide content, in percent, of gas in untested cells in gas 

assessment units.

(68) H2Smin %—estimated minimum (F100) hydrogen sulfide content, in percent, of gas in untested cells in 

gas assessment units.

(69) H2Smod %—estimated mode of hydrogen sulfide content, in percent, of gas in untested cells in gas 

assessment units.

(70) H2Smax %—estimated maximum (F0) hydrogen sulfide 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).

(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, 2002) and 

are current through 2000. 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).
20 Tabular Data and Graphical Images of the USGS Survey National Oil and Gas Assessment—Powder River Basin 

(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

IHS Energy Group, 2006a [includes data current as of December 2005], PI/Dwights Plus US production data: IHS Energy 

Group; database available from IHS Energy Group, 15 Inverness Way East, D205, Englewood, CO 80112, U.S.A.

IHS Energy Group, 2006b [includes data current as of December 2005], PI/Dwights Plus US well data: IHS Energy Group; 

database available from IHS Energy Group, 15 Inverness Way East, D205, Englewood, CO 80112, U.S.A.

NRG Associates, 2002 [includes data current as of December 2000], 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, U.S.A.

For more information concerning this publication, contact:

Team Chief Scientist, USGS Central Energy Resources

Box 25046, Mail Stop 939

Denver, CO 80225

(303) 236-1647

Or visit the Central Energy Resources Team site at:

http://energy.cr.usgs.gov/
Anna and others—Total Petroleum Systems and Geologic Assessment of Oil and Gas Resources in Wyoming and Montana—Digital Data Series 69–U