Scientific Investigations Report 2008–5225

Gas, Oil, and Water Production in the Wind River Basin, 

Wyoming

U.S. Department of the Interior

U.S. Geological Survey
Cover photo

Outcrop of Mowry Shale at Conant Creek anticline, southern Wind River Basin, Wyoming.

Photograph by C.J. Schenk
Gas, Oil, and Water Production in the 

Wind River Basin, Wyoming

By Philip H. Nelson, Patrick K. Trainor, and Thomas M. Finn

Scientific Investigations Report 2008–5225

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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Suggested citation:

Nelson, P.H., Trainor, P.K., and Finn, T.M., 2009, Gas, oil, and water production in the Wind River Basin, Wyoming: U.S. 

Geological Survey Scientific Investigations Report 2008–5225, 24 p.
iii

Contents

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

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

Procedure........................................................................................................................................................4

Fields Evaluated .............................................................................................................................................8

Fuller Reservoir Field............................................................................................................................9

Cooper Reservoir Field.........................................................................................................................9

Frenchie Draw Field..............................................................................................................................9

Cave Gulch Field..................................................................................................................................10

Madden Field.......................................................................................................................................10

Cody Shale ..................................................................................................................................10

Mesaverde Formation...............................................................................................................12

Lower Fort Union Formation.....................................................................................................13

Madison Limestone ...................................................................................................................13

Madden Field—Influences on Gas and Water Production ..................................................................13

Laramide Compressional Deformation and Gas Generation.......................................................14

Tectonic Extension..............................................................................................................................15

Regional Uplift and Erosion...............................................................................................................15

A Speculative Model..........................................................................................................................16

Interfield Comparisons of Fluid Production.............................................................................................16

Summary and Conclusions.........................................................................................................................22

Acknowledgments.......................................................................................................................................22

References Cited..........................................................................................................................................22
iv

Plates

1-5. Gas, Oil, and Water Production From:

 1. Fuller Reservoir Field

 2. Cooper Reservoir Field

 3. Frenchie Draw Field

 4. Cave Gulch Field

 5. Three Formations in Madden Field

6. Water Versus Gas Production and Oil Versus Gas Production for Three

Formations in Madden Field

7. Gas, Oil, and Water Production From Madison Limestone, Madden Field

8. Burial History, Thermal Maturity, Gas Generation, and Tectonic Regimes

 in Madden Field

Figures

1. Map showing the areas of fields evaluated in the Wind River Basin, Wyoming...............2

2. Stratigraphic chart of the Wind River Basin, Wyoming.........................................................3

3. Example of fluid production versus time and corresponding log-log 

 production diagrams for the Federal 13–18 well in Fuller Reservoir field, 

Wind River Basin, Wyoming .......................................................................................................5

4. Example of fluid production versus time and “vector” diagrams of changes 

in production with time, Cooper Reservoir Unit 11 well, Wind River Basin, 

Wyoming.........................................................................................................................................6

5. Water versus gas production rates plotted on a log-log diagram .......................................7

6. Oil versus gas production rates plotted on a log-log diagram..............................................8

7. Cross section showing conceptual distribution of gas along a south-north 

section in the Wind River Basin ...............................................................................................11

8. Diagram showing pressure from drillstem tests as a function of depth 

in the Madden field.....................................................................................................................12

9. Conceptual diagram of gas and water flow into a well producing from 

two siltstones in the Madden field...........................................................................................17

10. Diagram showing water versus gas production rates in five fields, 

Wind River Basin ........................................................................................................................18

11. Diagram showing oil and gas production in eight fields, Wind River Basin.....................19

12. Vector diagrams of six tight gas accumulations, Wind River Basin ..................................20

13. Normalized vector diagrams for six tight gas accumulations, Wind River Basin ...........21
v

Abbreviations Used in This Report 

°F degree Fahrenheit 

°F/100 ft degree Fahrenheit per 100 feet

bbl/day barrels per day

bbl/mmscf barrels per million standard cubic feet

ft foot, feet

m meter, meters

Ma mega-annum (date)

m.y. million years (interval)

m/m.y. meters per million years

mscf/day thousand standard cubic feet per day

mD millidarcy

psi pounds per square inch

psi/ft pounds per square inch per foot

Ro vitrinite reflectance

scf standard cubic feet

scf/bbl standard cubic feet per barrel

Conversion Factor

SI to Inch/Pound

Multiply By To obtain

meter (m) 3.281 foot (ft)
Left blank intentionally
Abstract

Gas, oil, and water production data were collected from 

the Fuller Reservoir, Cooper Reservoir, Frenchie Draw, Cave 

Gulch, and Madden fields in the Wind River Basin, Wyoming. 

These fields produce from the Mississippian Madison 

Limestone, the Upper Cretaceous Cody Shale and Mesaverde 

Formation, and the Paleocene lower unnamed member and 

Shotgun Member of the Fort Union Formation. Daily rates 

representative of early production from individual wells were 

derived from diagrams of gas, oil, and water production. For 

each producing interval, summary diagrams of oil versus gas 

and water versus gas production show fluid production rates, 

the change in rates during 5 years, the water-gas and oil-gas 

ratios, and the fluid type. These diagrams permit well-to-well 

and field-to-field comparisons. Fields producing dry gas are 

distinguished from those producing wet gas or oil. Fields 

producing water at low rates (water dissolved in gas in the 

reservoir) can be distinguished from fields producing water at 

moderate or high rates, and the water-gas ratios are quantified. 

Within the six fields having low permeability (tight gas) 

accumulations, few of the intervals studied produced water at 

rates low enough to be attributed solely to water dissolved in 

gas in the reservoir.

Diagrams of water and gas production from tight gas 

accumulations in three formations in the Madden field show 

that (1) water production either increased or decreased with 

time in all three formations, (2) increases and decreases in 

water production were greater in the Cody Shale than in either 

the Mesaverde Formation or the lower unnamed member of 

the Fort Union Formation, (3) the gas production rate declined 

more slowly in the lower part of the Fort Union Formation 

than in the Cody Shale or the Mesaverde Formation, 

(4) changes in gas and water production were not related to 

their initial production rates, and (5) there appears to be no 

relation between well location and the magnitudes or trends of 

gas and water production. 

To explain the apparent independence of gas and water 

production in the Cody Shale and Mesaverde Formation, 

a two-step scenario is proposed: gas was generated and 

emplaced under the compressive stress regime resulting 

from Laramide tectonism; then, fractures formed during a 

subsequent period of stress relaxation and extension. Gas is 

produced from the pore and fracture system near the wellbore, 

whereas water is produced from a larger scale system of 

extension fractures. The distribution of gas and water in 

the lower Fort Union resulted from a similar scenario, but 

continued generation of gas during post-Laramide extension 

may have allowed its more widespread distribution. 

Introduction

This study examined production of gas, oil, and water 

from low-permeability (tight gas) accumulations, in order to 

compare the production characteristics of such accumulations 

within a basin—in this case, selected fields in the Wind River 

Basin of Wyoming (fig. 1)—and, eventually, among basins. A 

few gas and oil reservoirs of moderate or even high permeability were included to serve as reference cases. In all examples, 

we looked for (1) wells with early production so that we 

could sample the fluid production when the reservoir was first 

tapped and avoid well interference effects, (2) continuity of 

production so that production trends with time could be sampled, (3) indications that records are valid, and (4) documentation of depths of producing intervals and stimulation methods. 

Productive strata examined in the five fields included 

in our study—Fuller Reservoir, Cooper Reservoir, Frenchie 

Draw, Cave Gulch, and Madden—are Mississippian, Late 

Cretaceous, and Paleocene in age (fig. 2); data are presented in 

plates 1–7. The youngest reservoirs studied are in the Shotgun 

Member of the Fort Union Formation in Fuller Reservoir field 

(pl. 1), which is considered to be a conventional, predominantly oil, reservoir within the Waltman Shale Total Petroleum 

System (Roberts, Roberts, and others, 2007). Its hydrocarbons 

are derived from the underlying Waltman Shale Member of the 

Fort Union Formation (fig. 2). Gas accumulations in the other 

four fields are considered as continuous accumulations within 

the Cretaceous–Lower Tertiary Composite Total Petroleum 

System (Johnson and others, 2007): the lower unnamed member of the Fort Union Formation (hereafter referred to as lower 

Fort Union Formation) in Cooper Reservoir (pl. 2); the lower 

Fort Union Formation in Frenchie Draw (pl. 3); the Lance 

Formation in Cave Gulch field (pl. 4); and the lower Fort 

Union Formation, the Mesaverde Formation, and the Cody 

Gas, Oil, and Water Production in the Wind River Basin, 

Wyoming

By Philip H. Nelson, Patrick K. Trainor, and Thomas M. Finn
Figure 1. Wind River Basin, Wyoming, showing areas of fields evaluated. Modified from Johnson and others (2007). TPS, Cretaceous–Lower TerComposite Total Petroleum System.

T

1

N

R 1 W R 1 E R 5 E

T

1

S

R 100 W 

R 95 W 

T

40

N

R 90 W 

R 95 W 

R 5 E

R 100 W 

R 1 W R 1 E

R 105 W 

R 5 W 

T

5

N

T

40

N

R 110 W 

T

1

N

T

1

S R 5 W 

Madden 

Fuller

Reservoir

Fields evaluatedTPS 

Cave Gulch

Cooper Reservoir

FrenchieDraw

Wind RiverBasin Province

EXPLANATION

0 10 20 30 40 MILES

0 10 20 30 40 KILOMETERS

Owl Creek thrust

Rattlesnake Hi

Split Rock syncline

44°N

43°N

110°W 109°W 108°W 107°W

Wind

River

Range

Bighorn Mountains

Casper

ar

Granite

Mountains

Owl Creek Mountains
Introduction 3

Shotgun

Member

JURASSIC/

TRIASSIC

PERMIAN

PENNSYLVANIAN

Jurassic and Triassic rocks undifferentiated

Phosphoria/Park City/ Goose Egg Formation

Tensleep Sandstone

Unnamed middle member

Parkman Sandstone Member

Fales Sandstone Member

Wallace Creek Tongue of Cody Shale

Southern and

 central Wind

 River Basin Eastern

Wind

River Basin

Western Wind

River Basin 

PALEOCENE UPPER

Western Wind River Basin Eastern Wind River Basin Southern and central

Wind River Basin

Lance

Formation

Teapot Sandstone Member

Cody Shale

Cody Shale

Cody Shale

Lance

Formation

Lance

Formation

Meeteetse Formation

Meeteetse

Formation

Meeteetse

Formation

Teapot Sandstone Member Teapot Sandstone Member Mesaverde Formation

Mesaverde Formation

Mesaverde Formation

lower part

lower part

Fort Union FormationFort Union Formation

Fort Union Formation

CRE

TACEOUS TERTIARY (part)

EOCENE

 (part)

Wind River and 

Indian Meadows 

Formations undivided

Mowry Shale

Frontier Formation

LOWER

Muddy Sandstone

Thermopolis Shale

Cloverly Formation

Frontier Formation Frontier Formation

Waltman Shale

Member

Waltman Shale

Member

Shotgun

Member

Shotgun

Member

Lower unnamed

member

Lower unnamed

member

Lower unnamed

member

Upper sandy member

Upper sandy member

Jurassic rocks

Triassic rocks (part)

Upper sandy 

member

Lower shaly member

Lower shaly member Lower shaly member

?

and

Lewis Shale undivided

Waltman Shale

Member

System Series

Wind River and 

Indian Meadows 

Formations undivided

Wind River and 

Indian Meadows 

Formations undivided

Amsden Formation

Madison Limestone MISSISSIPPIAN

Figure 2. Stratigraphic chart of the Wind River Basin, Wyoming. Yellow dots indicate formations for which fluid 

production is documented in this report. Modified from Johnson and others (2007) and Kirschbaum and others 

(2007).
4 Gas, Oil, and Water Production in the Wind River Basin, Wyoming

Shale in the Madden field (pls. 5, 6). In addition to data from 

these fields, production data from the Mississippian Madison 

Limestone in the Madden field, which produces gas at high 

rates and is considered to be a conventional accumulation, are 

also included (pl. 7). Gas from the Madison is believed to be 

derived from younger rocks in the Cretaceous–Lower Tertiary 

Total Petroleum System (Johnson and others, 2007)). Other 

gas fields in the Wind River Basin (Pavillion, Muddy Ridge, 

and Waltman) had inadequate water production records and 

were not studied. 

Further perspective on the Cretaceous and Tertiary 

stratigraphy of the Wind River Basin is provided in the form 

of descriptions, measured sections, and cross sections by Finn 

(2007), Johnson (2007), and Johnson and others (2007). 

The results of decline curve analysis, commonly used 

by reservoir engineers to quantify the productive capacity of 

wells, may be difficult to apply in the context of our study 

because of high variability among gas accumulations, and 

those results do not provide a uniform yardstick for interreservoir comparison. Furthermore, owing to changes in 

production practices, erratic records, low-quality data, and 

changes in the producing interval (recompletions) during the 

lifetime of a well, cumulative production figures were not used 

in this study. We consider water production to be an important 

characteristic of tight gas systems, so we address its behavior 

along with that of gas and oil. For these reasons, we devised a 

simple system of portraying gas, oil, and water production that 

can be used for any gas or oil reservoir as long as production 

records are of sufficient reliability, continuity, and length.

Ultimately, variations in gas, water, and oil production 

should be viewed as a tool that leads to better understanding 

of the circumstances of hydrocarbon emplacement in varied 

geologic settings, particularly for tight gas reservoirs, which at 

this time are not well understood. This report concludes with 

an attempt to link the disparate water production records from 

various reservoirs in the Madden field to the timing of gas 

generation and tectonic development in the northern part of the 

Wind River Basin.

Procedure

Monthly production data were taken from the IHS Energy 

Group production data base (IHS Energy Group, 2007) and 

were checked against data available on the Wyoming Oil and 

Gas Conservation Commission web site (Wyoming Oil and 

Gas Conservation Commission, 2007). Daily production rates 

were computed by dividing monthly volumes by the number 

of days of production in a month. Measurements of (1) gas 

rate, in thousands of cubic feet per day (mcf/day); (2) water 

rate, in barrels per day (bbl/day); (3) oil rate, in barrels per day 

(bbl/day); (4) water-gas ratio, in barrels of water per 

million standard cubic feet of gas (bbl/mmscf); and (5) gas-oil 

ratio, in standard cubic feet of gas per barrel of oil (scf/bbl), 

are all plotted on a logarithmic scale as a function of time 

(fig. 3A). To determine a representative flow rate of gas, oil, 

or water from a well, we selected a time interval early in the 

history of a given production record for which fluid production was judged to be representative of flow (fig. 3A). This 

time interval, referred to as “initial” time in this report, was 

generally selected to be about 2 years after commencement of 

production; such delay served to eliminate early transients and 

early changes in equipment, and it reduced the likelihood that 

fracturing fluids were included in the water tally. 

The method of determining daily rates of gas, oil, and 

water production during a 3-month interval is illustrated by 

the example in figure 3A. The resulting rates were then posted 

on summary diagrams with bilogarithmic (“log-log”) scales 

(figs. 3B and 3C), which accommodate wide ranges of production rates. With the use of bilogarithmic axes, constant ratios 

of production rates lie on 45-degree lines; the ratio increases 

upward and to the left. Zero values of water or oil, which 

cannot be accommodated on a logarithmic scale, are plotted 

below the dashed lines near the bottom of the diagram.

To show the change in gas and water production in each 

well, a second 3-month average was computed 5 years after 

the initial average (fig. 4A). These “5-year” gas and water production figures are plotted on the log-log production diagram 

(solid triangle in fig. 4B). Each 5-year value is linked to its 

initial value (solid square in fig. 4B) by a dashed line, producing a vector that shows the amount and direction of change in 

water and gas production with time. A vector of a given length 

and angle represents the same fractional change in daily gas 

and water production regardless of where it is positioned on 

the diagram. In the example shown in figure 4, both gas and 

water production decreased with time, and the water-gas ratio 

decreased slightly with time. 

To clarify the relative changes in water and gas production among wells, a log-log diagram of the change in water 

and gas production places all early-time production at a common origin (solid square at 1,1 in fig. 4C); changes in production during a 5-year span can then be compared among wells. 

The length and orientation of each vector is the same in figures 

4B and 4C, but the origin, which is its value at initial time, 

has been translated to the center position (1,1) of the diagram 

in figure 4C. In this example, the data were complete at the 

5-year interval, but in a few cases where data were missing, 

values from an earlier time (3 or 4 years after the initial time) 

were extrapolated to 5 years.

If one examines the amount of produced water, the question arises as to how much water could be dissolved in the gas 

in the reservoir and then released at the surface. The amount of 

water dissolved in gas in reservoirs increases with increasing 

temperature and decreases with increasing pressure (McCain, 

1990, p. 461). Likewise, the amount of water remaining in 

gas delivered to the pipeline depends upon pipeline pressure 

and temperature. The amount released at the surface is the 

difference between these two quantities, and it can be represented on a water-gas production diagram (fig. 5). The heavy 

blue diagonal lines represent the amount of water released 

at the surface by reservoirs at three depths—8,000, 12,000, 
Procedure 5

Time

1/1/1975 1/1/1980 1/1/1985 1/1/1990 1/1/1995 1/1/2000 1/1/2005 

Gas (mcf/day)

Oil (bbl/day)

Gas-Oil Ratio (scf/bbl)

106

105

104

103

102

101

100

Water (bbl/day)

Water-Gas Ratio (bbl/mmscf)

Gas 10.7 mscf/day

Oil 6.2 bbl/day

Water 34.9 bbl/day

Water-gas ratio 3,270 bbl/mmcf

Gas-oil ratio 1,711 scf/bbl

1 bbl/mmscf

0.1 bbl/mmscf

10 bbl/mmscf

100 bbl/mmscf

1,000 bbl/mmscf

10,000 bbl/mmscf

No water production

Water-gas ratio 3,270 bbl/mmcf 

No oil production

Gas-oil ratio 1,711 scf/bbl

B

A

C

Water Production Rate (bbl/day)

Oil Production Rate (bbl/day)

Gas Production Rate (mscf/day)

100 101 102 103 104 105

10–1

100

101

102

103

104

10–1

100

101

102

103

104

105

10–1

100

101

102

103

104

Gas Production Rate (mscf/day)

100 101 102 103 104 105

1 bbl/mmscf

0.1 bbl/mmscf

10 bbl/mmscf

100 bbl/mmscf

1,000 bbl/mmscf

10,000 bbl/mmscf

Figure 3. Example of fluid production versus time and corresponding log-log production diagrams, for the Federal 13–18 well 

in Fuller Reservoir field, Wind River Basin, Wyoming. A, Production of gas, oil, and water, and gas-oil ratio and water-gas ratio, 

all versus time. Vertical blue line indicates “initial” time, which is generally about two years after onset of production. Posted 

values are averages for months of July, August, and September, 1986. Open circles, values of production rates and ratios. 

B, Water versus gas production; scales are logarithmic. Horizontal dashed line, water production rate; vertical dashed line, gas 

production rate (values from part A); blue triangle, water-gas ratio, which falls on a 45-degree line. C, Oil versus gas production; 

scales are logarithmic. Horizontal dashed line, oil production rate; vertical dashed line, gas production rate (values from part A); 

green triangle, gas-oil (or oil-gas) ratio, which falls on a 45-degree line. A gas-oil ratio of 1,711 scf/bbl is equivalent to an oil-gas 

ratio of 584 bbl/mmscf. bbl/day, barrels per day; bbl/mmscf, barrels per million standard cubic feet; mscf/day, thousand standard 

cubic feet per day; scf/bbl, standard cubic feet per barrel.
6 Gas, Oil, and Water Production in the Wind River Basin, Wyoming

1 bbl/mmscf

0.1 bbl/mmscf

10 bbl/mmscf

100 bbl/mmscf

1,000 bbl/mmscf

10,000 bbl/mmscf

No water production

A

B C Gas (mcf/day) Gas-Oil Ratio (scf/bbl)

Water Production Rate (bbl/day)

Change in Water Production (bbl/day)

Water (bbl/day)

Oil (bbl/day)

Water-Gas Ratio (bbl/mmscf)

Time

1/1/1990 1/1/1995 1/1/2000 1/1/2005 

Change In Gas Production (mscf/day)

1

Gas Production Rate (mscf/day)

1 10

10

100

1/100

1/100

1/10

1/10

100

Initial 

time 

Initial + 

5 years

91 bbl/day

20 bbl/day

537 mscf/day

191 mscf/day

gas

water

Gas

Gas-oil ratio

Water

Water-gas ratio

Oil 

101

10–1

10–1

100

101

102

103

104

105

100

101 102 103 104 105 106

101

102

103

104

102

103

104

105

106

107

Figure 4. Example of fluid production versus time and “vector” diagrams of changes in production with time, Cooper Reservoir 

Unit 11 well, Wind River Basin, Wyoming. A, Production of gas, water, and oil, and variation in gas-oil ratio and in water-gas ratio 

versus time. Open circles, values of production rates and ratios. B, Vector diagram showing water versus gas production; scales 

are logarithmic. Square, gas and water production at initial time; triangle, gas and water production at 5-year time, thus marking 

the head and tail of a vector. C, Normalized vector diagram showing change in water production versus change in gas production; 

scales are logarithmic axes. Square, initial-time value, placed at center of diagram so all vectors for a field share a common 

origin; circle, initial+5 year values. bbl/day, barrels per day; bbl/mmscf, barrels per million standard cubic feet; mscf/day, thousand 

standard cubic feet per day; scf/bbl, standard cubic feet per barrel.
Procedure 7

and 16,000 feet (ft). A pressure gradient of 0.433 pounds per 

square inch per foot (psi/ft) and a temperature gradient of 

1.4° Fahrenheit per 100 feet (°F/100 ft) were assumed in 

each case. Surface conditions at the separator were assumed 

to be 80°F and 1,000 psi. Roughly 3 barrels of water can be 

dissolved in 1 million standard cubic feet (mmscf) of gas 

at a depth of 16,000 ft, but only 0.2 barrels of water can be 

dissolved in gas at pressure and temperature conditions corresponding to a reservoir at a depth of 8,000 ft (fig. 5). For 

the gas accumulations examined in this study, the amounts of 

water that can be dissolved in gas in the reservoir and released 

as water at the surface are generally less than the amounts of 

water actually produced.

Because oil and gas types are defined as a function 

of gas-to-oil ratios (McCain, 1990), the fluid types can be 

displayed on the log-log oil production versus gas production 

101

10–1

100

101

102

103

104

102 103 104 105 106

10,000 bbl/mmscf

1,000 bbl/mmscf

100 bbl/mmscf

10 bbl/mmscf

1 bbl/mmscf

0.1 bbl/mmscf

16,000 ft

12,000 ft

8,000 ft

No water production

Gas Production Rate (mscf/day)

Water Production Rate (bbl/day)

Solubility of water in gas for conditions

of 0.43 psi/ft and 1.4 °F/100 ft

Figure 5. Water versus gas production rates plotted on a log-log diagram. Three 

diagonal blue lines give the upper bound of water-gas ratio for liquid water released 

at a surface separator, based on McCain (1990). For example, a gas reservoir at 

12,000 ft depth can hold as much as 1 barrel of dissolved, low-salinity water for 

every 1 million standard cubic feet of gas (bbl/mmscf), and a gas reservoir at 16,000 

ft depth can hold as much as 3 bbl/mmscf. °F/100 ft, degrees Fahrenheit per 100 

feet; bbl/day, barrels per day; mscf/day, thousand standard cubic feet per day; psi/ft, 

pounds per square inch per foot. 

diagrams (fig. 6). Black and volatile oil types have gas-oil 

ratios of less than 3,300 standard cubic feet per barrel 

(scf/bbl) of oil, and they occupy the upper left corner of an oilgas production diagram (fig. 6). In a retrograde gas reservoir, 

liquid condenses in the reservoir as reservoir pressure declines. 

Gas-oil ratios in retrograde gas reservoirs typically range 

from 3,300 to 5,000 scf/bbl, but they can have values as high 

as 150,000 scf/bbl; these reservoirs occupy a central diagonal 

band on an oil-gas diagram (fig. 6). Wet gases, also called 

condensate gases, have gas-oil ratios in excess of 

50,000 scf/bbl (<20 bbl of condensate/mmcf of gas), and they 

occupy the lower right corner of the diagram (fig. 6). Dry gas 

produces no oil, and corresponding points are plotted at the 

bottom of the diagram. 

Fluids from many of the wells examined in this study 

were produced from several perforated zones; consequently, 
8 Gas, Oil, and Water Production in the Wind River Basin, Wyoming

RETROGRADE GAS

Gas Production Rate (mscf/day)

101 102 103 104 105 106

Oil Production Rate (bbl/day)

10–1

100

101

102

103

104

100,000 scf/bbl

10,000,000 scf/bbl

1,000,000 scf/bbl

10,000 scf/bbl

1,000 scf/bbl

100 scf/bbl

WET GAS

DRY GAS (NO OIL)

BLACK & VOLATILE OILS

50,000 scf/bbl

2,000 scf/bbl

150,000 scf/bbl

the fluid volumes recorded at the surface represent the combined inflow from several intervals. Even so, the resulting 

fluid production can be regarded as representative of a formation in a particular field, possibly even more representative of 

a formation than production from a single interval. 

Fields Evaluated

The following discussions of fluid production are related 

to the data displayed in plates 1–7, which are arranged by area 

and geologic formation. A few general points are summarized 

here to avoid repetition.

•	 Perforated intervals and duration of production, 

displayed on the diagrams of daily production versus 

time in plates 1–7, were taken from IHS well data 

(IHS Energy Group, 2007) and were also spot checked 

against data available on the Wyoming Oil and Gas 

Conservation Commission web site (Wyoming Oil and 

Gas Conservation Commission, 2007). 

•	 Most perforated intervals were stimulated before 

production commenced. On the diagrams of daily 

production versus time, an “F” denotes hydraulic 

fracturing, and an “A” denotes acidization.

•	 Water rates were generally more erratic (“noisier”) 

than gas production rates. Water production records 

are considered less reliable than gas or oil production 

records, because there is less incentive to report water 

production carefully. For this reason, inconsistencies 

in reporting procedures may contribute to the erratic 

Figure 6. Oil versus gas production rates plotted on a log-log diagram. Fields indicate 

three reservoir fluid types, based on McCain (1990). Diagonal lines up to the right, 

bounds for each fluid type; diagonal lines down to the right, range of each fluid type. 

bbl/day, barrels per day; mscf/day, thousand standard cubic feet per day; scf/bbl, 

standard cubic feet per barrel.
Fields Evaluated 9

nature of reported water-production rates. As a 

consequence, the water-gas ratio tends to mimic the 

water production. 

•	 Gas, oil, and water production rates, water-gas ratio, 

and gas-oil ratio are all displayed on logarithmic scales 

on the diagrams of production versus time. Although 

six-decade scales are used, scales differ from area to 

area to accommodate different production rates and 

ratios.

•	 Production was erratic between 1985 and 1990 when 

wells were produced for fewer than 30 days per month 

in response to market conditions.

Fuller Reservoir Field

In the Fuller Reservoir field (fig. 1–1 of pl. 1), oil and 

gas are produced from the Shotgun Member of the Paleocene 

Fort Union Formation at fairly low rates from depths of 

3,000 ft. Specht (1989) described the trap types as “multiple 

local stratigraphic traps on large structural nose, possible local 

structural closure.” Reservoir porosity ranges from 18 to 

30 percent and permeability ranges from 0.1 to 50 millidarcies 

(mD) (Specht, 1989), so this reservoir is not in the lowporosity, low-permeability category. The production 

mechanism was initially solution-gas drive, according to 

Specht (1989). Cumulative production through 2005 from 

33 wells was 2.3 million barrels of oil and 4.4 billion cubic 

feet of gas (Roberts, Finn, and others, 2007). This field also 

produces from the lower Fort Union Formation, but those 

records were inadequate for our purpose. 

This shallow, densely drilled field covering several 

square miles is represented here by 18 wells (fig. 1–1 of pl. 1); 

production diagrams are shown for 7 of the 18 wells (pl. 1). 

As shown on the water-gas and oil-gas diagrams (figs. 1–2 and 

1–3), gas production from 18 wells at initial times ranged from 

5 to 84 mcf/day, water production ranged from 10 to 

142 bbl/day, and oil production ranged from 6 to 30 bbl/

day. All wells were stimulated prior to production either by 

hydraulic fracturing or by acidization or both. 

Nine of the 18 wells had adequate records after 7 years 

of production; thus, we were able to extract initial-to-5-year 

production vectors for those 9 wells (figs. 1–4, 1–5 of pl. 1). 

Water production was either flat or increased with time, while 

gas production generally decreased with time. Gas production 

did increase in 2 of the 9 wells; this apparent increase could 

represent either an artifact of record-keeping or a change in 

production practice.

In summary, in the Fuller Reservoir field, gas and oil 

production was low, gas decline rates were low, oil production 

tended to track gas production, water production was high, and 

the water-gas ratio was extremely high.

Cooper Reservoir Field

Gas production from sandstones in the lower Fort Union 

Formation commenced in the early 1960s (Boyd, 1969), at 

which time three sandstones at depths from 3,300 to 3,700 ft 

were completed and produced. Production then ceased for 

some time but recommenced in the 1990s when multistage 

hydraulic fracturing methods were applied to both the lower 

Fort Union Formation and the Lance Formation (Dempsey 

and others, 2001). According to Dempsey and others (2001), 

the sandstone reservoirs originated as braided and meandering 

stream deposits, isolated by shales, and gas-bearing and waterbearing units were in close proximity. Porosity ranges from 12 

to 20 percent and permeability ranges from 0.01 to 1.0 mD. 

Seven wells in Cooper Reservoir field were selected to 

give continuous production records and good spatial coverage 

(fig. 2–1 of pl. 2). The initial daily gas rates in the seven 

wells ranged from a minimum of 205 to a maximum of 

2,040 mcf/day. Initial water production ranged from 5 to 

130 bbl/day (fig. 2–2), and initial oil production ranged from 

1.6 to15 bbl/day (fig. 2–3). Although records show that oil 

production was erratic, oil production does track gas production in wells 7, 8, 11, and 14, as shown by the roughly constant 

gas-oil ratio (light gray trace) on the production-versus-time 

diagrams (pl. 2). The increase of oil with time in well 12 is 

unexplained.

Water-gas ratios plotted in figure 2–2 of plate 2 range 

from around 10 to more than 100 bbl/mmcf of gas, or about 

100 times as much water as could be dissolved in gas at 

reservoir conditions; thus, free water was being produced. The 

water-gas ratio either remained constant or increased with 

time (see daily production diagrams of pl. 2 and fig. 2–5). 

Gas-oil ratios for wells 6 and 24 were not plotted in figure 

2–3 because oil production was erratic. Gas-oil ratios for the 

remaining five wells fall within the wet gas domain on the oilgas diagram (fig. 2–3).

Frenchie Draw Field

Normark (1978) described Frenchie Draw field as “a 

combination structural-stratigraphic trap that produces gas 

and condensate from a number of discontinuous sandstones 

in the lower Fort Union Formation. ... Reservoirs appear to 

be composed of sandstone lenses a few hundred acres in areal 

extent and of widely varying quality.” The field is located on 

a north-plunging structural nose about 6 miles south of the 

Madden anticline (fig. 3–1 of pl. 3). Porosity ranges from 6 

to 12 percent and permeability ranges from 0.1 to 0.2 mD 

(Mueller, 1989). Normark (1978) reported that initial pressures 

throughout a wide depth range fit a pressure gradient of 

0.44 psi/ft and that bottom-hole temperatures range from 

195° to 215°F. On the basis of temperatures measured with 

drillstem tests, temperature gradients range from 1.6° to 2.0°F 

per 100 ft in Frenchie Draw field (Nelson and Kibler, 2007). 
10 Gas, Oil, and Water Production in the Wind River Basin, Wyoming

The seven wells with production records (pl. 3) include 

the discovery well, Frenchie Draw Unit 1, completed in 1961. 

Gas production from this well declined for the first 8 years, 

then held steady for the next 22 years. Other wells seem to 

show a similar pattern of decline followed by years of steady 

gas, oil, and water production (pl. 3). Initial rates of water 

production were high, corresponding with water-gas ratios 

ranging from 40 to 630 bbl/mmcf, and those rates increased 

further after the initial time (production diagrams of pl. 3 and 

figs. 3–4 and 3–5 of pl. 3). High rates of water production are 

sustainable economically because surface disposal of water is 

permitted for this field. Oil-to-gas ratios are somewhat higher 

than the upper limit for a wet gas (fig. 3–3 of pl. 3), and the 

ratio could be categorized as representing a retrograde gas 

(fig. 6). 

Cave Gulch Field

Cave Gulch field (pl. 4) has some characteristics of a 

conventional gas reservoir (Montgomery and others, 2001). In 

the Lance Formation, porosity ranges from 9 to 19 percent and 

permeability ranges from 0.1 to 50 mD. Water lies below gas 

(T. Enterline, Bill Barrett Corp., oral commun., 2008). Pressures are normal, and pressure-depth ratios are about 0.41 to 

0.43 psi/ft. On the other hand, Cave Gulch field also has some 

characteristics of a tight gas system (Montgomery and others, 

2001). Lance sandstones are very fine to fine grained. The 

productive interval in strata from the upper Meeteetse Formation to the lower part of the Fort Union Formation extends for 

nearly 5,000 vertical feet. Wells are hydraulically fractured 

prior to production. A large portion of the formation is low 

permeability of less than 0.1 mD (T. Enterline, Bill Barrett 

Corp., oral commun., 2008). Above the basal sandstone, which 

is 214 ft thick, are individual fluvial channel sandstones ranging in thickness from 3 to 40 ft, and stacked channel sandstone 

units are as thick as 130 ft (Johnson, 2007). The position of a 

well is a critical factor in its productivity, as the field is located 

in a faulted anticlinal structure beneath the Casper Arch thrust. 

Fracturing is believed to play a key role in well productivity in 

Cave Gulch field.

Nine of 10 wells shown on plate 4 lie on a northwestsoutheast line 1.6 miles in length (fig. 4–1 of pl. 4) (the tenth 

well lies about 1 mile west of the Cave Gulch Unit boundary). 

Two years after commencement of production, gas production ranged from 160 to 7,000 mcf/day and water production 

ranged from 2 to 53 bbl/day for the 10 wells shown in the 

diagrams of water versus gas production (fig. 4–2). All oil-gas 

ratios are less than 11 bbl/mmcf and lie in the “wet gas” field 

of the oil versus gas diagram (fig. 4–3). The six northernmost 

wells form a cluster on the water-gas production plot (fig. 4-4), 

characterized by small water decays between initial and 

5 years, as shown by the nearly horizontal vectors. Cave Gulch 

Federal 1 well also shows slow decay of water production. In 

three other wells (Cave Gulch 13, Branch South Federal B4, 

and West Cave Gulch 1–36) water decays rapidly. The three 

wells lowest on structure (Cave Gulch North 4–30, West Cave 

Gulch State 1–36, and Branch South Federal B4) had the lowest initial and 5-year gas- and water-production rates.

Madden Field 

Considerable amounts of gas have been produced from 

the upper sandy member of the Cody Shale, the Mesaverde 

Formation, the lower Fort Union Formation, and the Madison 

Limestone. The migration of gas from three prominent source 

rocks into reservoirs within the Madden field is depicted in 

figure 7. All units between the base of the Waltman Shale 

Member of the Fort Union Formation and the Jurassic 

Morrison Formation are overpressured, as indicated by the 

mud weight contours in figure 7 and by the pressure-depth 

diagram in figure 8. The pressure-depth diagram (fig. 8) 

indicates that an elevated hydrostatic gradient exists below the 

top of the lower member of the Fort Union Formation and that 

an interval of even higher overpressure exists below the top 

of the Mesaverde Formation. This two-compartment pressure 

signature has not been observed elsewhere in the Wind River 

Basin. The following sections discuss the gas, water, and oil 

production from these three formations as portrayed on plates 

5–7. Well locations are shown on the map on plate 5. The 

26 production diagrams are labeled with letters A–Z and the 

corresponding production interval is indicated by its letter on 

the cross section on plate 5. Zones in wells not on the cross 

section have been projected to the cross section. In several 

wells, a formerly producing interval was abandoned and 

the well was recompleted in another interval. For example, 

well A in the Cody Shale (pl. 5) produced from completion 

intervals A1 and A2, which are shown on the cross section on 

plate 5. In addition to production from the three formations 

documented on plates 5 and 6, production from the Madison 

Limestone is displayed on plate 7.

Cody Shale

Production is from sandstones in the upper sandy member of the Upper Cretaceous Cody Shale, which are commonly 

referred to as the Shannon and Sussex sandstones (Dunleavy 

and Gilbertson, 1986; Finn, 2007). The blanket-like character 

of these sandstones is apparent on the cross section of plate 5. 

Sixteen production intervals (A1, A2, B1, .... L) are shown 

in twelve well logs (A, B, ... L) at the bottom of plate 5. Dry 

gas is produced from all wells, as indicated by the lack of any 

oil production. Of the 16 production intervals we examined, 

initial gas production ranged from 567 to 16,333 mcf/day and 

water production ranged from 7 to 243 bbl/day (fig. 6–9 of 

pl. 6). Half of these producing intervals produced a limited 

amount of water initially, as shown by the eight data points (D, 

K, C, G, E2, H, J, and I) positioned next to and parallel with 

the limiting line for water dissolved in reservoir gas (fig. 6–9). 

The average water-gas ratio of these eight producing intervals 

was 3.6 bbl/mmcf. Of these, production intervals G, H, I, J, 
Fields Evaluated 11

er

shaly member

B

A

C

Madden

Anticline

300°F isotherm

12 lb mud

12 lb mud

10 lb mud

10 lb mud

12 lb mud

10 lb mud

200°F isotherm

South North

North

Cody Shale

Fort Union

Formation

South

South North

shaly member

sandy member

Shotgun member

Mesaverde Formation

Meeteetse Formation

Frontier Formation

Lance Formation

shaly member

sandy member

Mesaverde Formation

Meeteetse Formation

Frontier Formation

Lance Formation

Wind River Formation

Mowry Shale/

Thermopolis Shale

lower unnamed member

Waltman Shale Member

Shotgun member

Wind River Formation

lower unnamed member

Waltman Shale Member

Ro 0.73%

Ro

 1.1%

300°F isotherm

200°F isotherm

sandy member

Shotgun member

Mesaverde Formation

Meeteetse Formation

Frontier Formation

Lance Formation

Wind River Formation

Mowry Shale/

Thermopolis Shale

Waltman Shale Member

Ro 0.73%

Ro

 1.1%

300°F isotherm

200°F isotherm

Mowry Shale/

Thermopolis Shale

Ro 0.73%

Ro

 1.1%

Figure 7. Conceptual distribution of gas along a south-north section in the Wind River Basin. Gas derived from 

A, Mowry Shale, B, shaly member of Cody Shale, C, Meeteetse Formation. Pink area, thermogenic gas; green area, 

oil. Solid red line, mud weight contour; dashed blue line, vitrinite reflectance contour; dashed green line; isotherm. 

°F, degree Fahrenheit; lb, pound; RO, vitrinite reflectance. From Johnson and others (2007, fig. 25).
12 Gas, Oil, and Water Production in the Wind River Basin, Wyoming

and K are in wells located east of wells A, B, E, F, which 

have higher water-gas ratios, but the high water-gas ratio of 

well L and the low ratio of wells C and D make it difficult to 

establish a geographic control on water-gas ratios. The highest 

initial water-gas ratio, recorded in production interval B2, is 

148 bbl/mmcf. The vector diagrams (figs. 6–11, 6–12), based 

on 11 records, show that water decreased with time in 6 cases, 

remained almost unchanged in 2 cases, and increased in 

3 cases. 

Mesaverde Formation

Production from the Upper Cretaceous Mesaverde 

Formation was sampled with eight production intervals in six 

wells (M, N, O, P, Q, R; pl. 5) on the west half of the crest of 

the Madden anticline. The geologic cross section shows no 

correlatable sandstone intervals between wells, as expected in 

this fluvial setting. Of the 8 production intervals, 3 produced 

water at water-gas ratios that can be attributed to water of 

5

6

7

5,000

Pressure (psi)

0 2,000 4,000 6,000 8,000 10,000 12,000

Elevation (ft)

–15,000

–10,000

–5,000

0

Cody

Shale

Mesaverde

Fm.

Meeteetse Fm.

Lower Member

of Fort Union Fm.

Lance Fm.

Upper pressure

compartment

Lower pressure

compartment

Elevated hydrostatic gradient

0.433 0.

0.

0.

Figure 8. Pressure from drillstem tests as a function of depth in the Madden field. Black 

needle represents maximum shut-in pressure, red needle represents flowing pressure. 

Flowing pressure is generally a small fraction of shut-in pressure, as is the case here for 

elevations shallower than mean sea level. In overpressured compartments below sea level, 

flowing pressure is a large fraction of shut-in pressure. Formation boundaries are those of 

wells on the crest of Madden anticline. Pressure data provided by the Wetterhorn Company 

(2004). Fm., formation; ft, feet; psi, pounds per square inch.
Madden Field—Influences on Gas and Water Production 13

condensation, 2 produced at water-gas ratios of around 

5 bbl/mmcf, and 3 produced at extremely high water 

rates—water-gas ratios exceed 100 bbl/mmcf (fig. 6–5 of 

pl. 6). Well location does not appear to determine water 

production, as the two wells (N and R) with very high water 

production rates and water-gas ratios are the westernmost and 

easternmost of the six wells producing from the Mesaverde 

Formation (production diagrams and map of pl. 5). Dry gas 

is produced from all wells, as shown by the lack of any oil 

production (pls. 5, 6). The vector diagrams (figs. 6–7, 6–8) 

show 2 producing intervals with constant gas and increasing 

water production, 2 intervals with decreasing gas and not 

much change in water production, and 2 intervals with small 

decreases in gas and water production during a 5-year period. 

Lower Fort Union Formation

The lower Fort Union Formation (Paleocene) was 

sampled in 11 producing intervals in eight wells distributed 

along the eastern part of the crest of the anticline (pl. 5). Wells 

shown on plates 5 and 6 lie within a sandy fluvial facies of 

the lower Fort Union Formation (Johnson, 2007, figs. 24, 25; 

pl. 3 of this report). The geologic cross section (pl. 5) shows 

no correlatable sandstone intervals between wells, as expected 

in this fluvial setting. Six wells were completed during the 

years 1968 to 1971 and began producing before 1975, the 

time at which production records were available. However, 

gas and water production are fairly constant with time (pl. 5), 

so the initial sample is assumed to represent early production even though it was acquired 4 or 5 years after production 

began rather than within 2 years of commencement. Seven of 

11 intervals produced from perforations not far below the top 

of the lower member (base of the Waltman Shale Member) 

(pl. 5); however, depth does not play a role in water rate or the 

water-gas ratio (fig. 6–1 of pl. 6). Water-gas ratios vary by two 

orders of magnitude (fig. 6–1), and all exceed the upper limit 

for water of condensation. Oil-gas ratios are fairly consistent 

among the 11 sampled intervals and are characteristic of a wet 

gas (fig. 6–2). The vector diagrams are tightly clustered (figs. 

6–3, 6–4), particularly in comparison with the vector diagrams 

for the Mesaverde Formation and Cody Shale (figs. 6–7, 6–8, 

6–11, 6–12), reflecting the low decline rates that are apparent 

in the production time diagrams (pl. 5). 

Madison Limestone

The highest gas production rates in the Madden field 

come from the Mississippian Madison Limestone (pl. 7), 

a carbonate formation with good permeability. Depths to 

Madison reservoirs range from 23,600 to 24,400 ft in the 

Bighorn 2–3, Bighorn 1–5, and Bighorn 4–36 wells. Gas rates 

of 22 to 43 mmcf/day are constrained by surface facilities and 

the increase of both water and gas with time are attributed to 

changes in surface facilities. Water-gas ratios of approximately 

10 bbl/mmcf (fig. 7–2 of pl. 7) are attributed to water in 

solution in reservoir gas; the dissolved water volume is 

high owing to a reservoir temperature of 420°F (Brown and 

Shannon, 1989). No condensate is produced, so this gas is dry 

(fig. 7–3). The gas is believed to be derived from Cretaceous 

source rocks across faults (Johnson and others, 2007, fig. 63 

of that report). Pressure cannot be much above normal, 

because in the Bighorn 1–5 well, the Madison was drilled with 

10.5-pound mud with no significant gas shows (Dunleavy and 

Gilbertson, 1986). 

Madden Field—Influences on Gas and 

Water Production

The following features regarding gas and water production from the Madden field can be seen in the vector and 

normalized vector diagrams of plate 6:

•	 Increases and decreases in water production were 

greater in the Cody Shale than in either the Mesaverde 

or lower Fort Union Formations. (The yellow vectors 

(fig. 6–12) are longer than red vectors (fig. 6–8) and 

blue vectors (fig. 6–4).)

•	 Decreases in gas production were least in the lower 

Fort Union Formation—that is, the gas decline rate 

was lower in that unit than in the Cody Shale or the 

Mesaverde Formation. (The x-components of the blue 

vectors (fig. 6–4) are shorter than x-components of the 

red vectors (fig. 6–8) or yellow vectors (fig. 6–12).)

•	 Water production either increased or decreased 

with time: Cody Shale (fig. 6–12), 3 increases and 

7 decreases; Mesaverde Formation (fig. 6–8), 3 

increases and 3 decreases; lower Fort Union Formation 

(fig. 6–4), 3 increases and 5 decreases.

•	 Figures 6–3, 6–7, and 6–11 show that changes in gas 

and water production are not related to their initial 

production rates—that is, there is no grouping of vector 

length or angle with respect to initial magnitudes 

(black squares).

To explain these observations, we propose that two different fluid-flow systems presently exist in the Madden field, one 

for gas and one for water. Our main pieces of evidence in this 

somewhat speculative discussion are the present-day pressure 

profile in the Madden anticline (fig. 8) and a cross section and 

diagram that show burial history, thermal maturity, times of 

gas generation, and evidence for changing tectonic regimes 

(pl. 8). The burial history for the Bighorn 1–5 well and timing 

of gas and oil generation (lower half of pl. 8) are taken from 

Roberts, Finn, and others (2007).

To develop the argument, we next consider (1) the nearly 

coincident timing of compressional deformation and gas 
14 Gas, Oil, and Water Production in the Wind River Basin, Wyoming

generation, and the consequent development of the present-day 

pressure compartments; (2) the period of tectonic extension; 

and (3) the relatively minor effect of uplift and erosion. 

Laramide Compressional Deformation and Gas 

Generation

Dunleavy and Gilbertson (1986) summarized the evidence for (1) early structural growth of the Madden anticline 

during Late Cretaceous Meeteetse and Lance deposition, and 

(2) a possible quiescent period during deposition of the upper 

part of the lower member and Waltman Shale Member of the 

Paleocene Fort Union Formation, followed by (3) development of the Madden thrust in Eocene time (pl. 8). Using 

depositional and structural field evidence in the Badwater 

area some 10 miles east of the Madden anticline, Love (1978) 

interpreted a series of tectonic events in the late Paleocene and 

early Eocene that record compressional features (pl. 8). Most 

prominent of these events was the thrusting of the Bighorn 

Mountains southward, overturning Paleocene and older strata 

in the northeastern Wind River Basin. 

Gas generation commences when a Type-III source rock 

reaches a level of thermal maturity characterized by a vitrinite reflectance (Ro

) of 0.5 percent (Roberts, Finn, and others, 

2007). Commencement of gas generation (pl. 8, solid dots) by 

six source rocks is coincident with the intersection of a formation boundary with a 0.5 percent Ro

 line on the burial history 

chart. Similarly, peak gas generation (triangles) is determined 

when a formation attains a thermal maturity of 0.8 percent Ro,

and gas generation (squares) ends when a formation reaches 

and exceeds 2.0 percent Ro. Gas generation by Mesaverde 

and older formations was completed by the end of the major 

compressional period at the end of early Eocene (pl. 8). In 

addition to directly generating gas, the lower shaly member of 

the Cody Shale and the Mowry Shale (which is an oil-prone 

(Type-II) source rock) contributed gas to the system as its thermal maturity increased to the point at which oil cracked to gas. 

Peak generation of oil cracking to gas is defined at a transformation ratio of 0.5 for that process. Conversion of oil to gas 

terminated in early Eocene for the Mowry Shale and in middle 

Eocene for the lower shaly member of the Cody Shale (pl. 8).

Pressure data from drillstem tests reveal two pressure 

compartments (fig. 8, pl. 8). On the basis of drillstem pressure data, the top of the lower pressure compartment is near 

the top of the Mesaverde Formation (fig. 8). Molecular and 

isotopic analyses of gases also indicate the existence of two 

compartments separated at the Mesaverde level (Schelling and 

Wavrik, 1999). On the basis of well log character (Nelson and 

Kibler, 2007) and the reduction in mud weight at the top of the 

Paleozoic (Dunleavy and Gilbertson, 1986), the base of the 

lower pressure compartment appears to be near the top of the 

Morrison Formation. 

Overpressuring in the lower pressure compartment is 

attributed mainly to gas generation in the Mowry Shale, 

Cody Shale, and Mesaverde Formation that peaked during 

Laramide deformation (pl. 8). Thermal maturity in the lower 

shaly member of the Cody Shale exceeded 1.1 percent Ro

around 60 Ma, just prior to formation of the Madden anticline. 

Additional gas was supplied by the cracking of oil to gas in 

two oil-prone source rocks, the Mowry Shale and the lower 

shaly member of the Cody Shale (pl. 8). Subsidence rates 

were high (~300 meters per million years (m/m.y.)) to medium 

(~150 m/m.y.) during Laramide tectonism (pl. 8), on the basis 

of parameters used for burial-history modeling of the Bighorn 

1–5 well (Roberts, Finn, and others, 2007, table 2). The high 

rate of subsidence of 300 m/m.y. during deposition of the 

Lance Formation at the close of Cretaceous time could have 

caused overpressure development prior to gas generation in 

the Meeteetse and older formations. Early overpressuring of 

this type, commonly referred to as compaction disequilibrium, 

requires a top seal that prevents loss of water during burial. A 

tongue of marine Lewis Shale within the Meeteetse Formation 

in the northeastern portion of the basin (Johnson and others, 

2007, fig. 14; Johnson, 2007, fig. 17 and pl. 3) could have 

provided such a seal, although others have alluded to a 

structural discontinuity at the Mesaverde level (Schelling and 

Wavrek, 1999). The combination of rapid burial and a high 

rate of gas generation resulted in overpressuring that exists 

to the present, as shown by the drillstem test pressure data 

(fig. 8) as well as by decreases in sonic velocity and resistivity 

(Nelson and Kibler, 2007). Despite subsequent fracturing 

and regional uplift and exhumation, the effects of this initial 

overpressuring persist in the Madden anticline as a pressure 

compartment extending from the top of the Mesaverde 

Formation to the top of the Morrison Formation. High pore 

pressure reduces effective stress. Because of reduced effective 

stress, the lower overpressured interval was prone to faulting 

and fracturing during Laramide compression and the ensuing 

period of tectonic extension. 

The upper pressure compartment extends from the base 

of the Meeteetse Formation to the top of the lower Fort Union 

Formation, where the overlying Waltman Shale Member forms 

a thick seal (fig. 8). As burial continued, gas was generated 

throughout Eocene time from Meeteetse, Lance, and Fort 

Union source rocks (pl. 8), providing a source of gas for the 

upper pressure compartment. The elevated hydrostatic gradient in the upper compartment (fig. 8) has been attributed to 

uplift of a sealed, water-dominated, normally pressured system 

rather than to overpressuring owing to gas (Nelson and Kibler, 

2007). If this interpretation is correct, there is no evidence that 

the upper compartment was ever overpressured as a result of 

gas generation. If so, then effective stress remained high in the 

upper compartment, and that compartment may be less faulted 

and fractured than the lower pressure compartment—at the 

least, the style of faulting and fracturing can be expected to be 

different in the two pressure compartments.
Madden Field—Influences on Gas and Water Production 15

Tectonic Extension

Evidence for extension in or adjacent to the Wind River 

Basin comes from several sources, as listed below. Timing of 

these extensional events is indicated in the annotated burial 

history chart for the Bighorn 1–5 well (pl. 8). 

•	 In a study of the Granite Mountains (fig. 1), Love 

(1970) documented the existence of volcanic vents 

in the Rattlesnake Hills area during middle and late 

Eocene time and the subsidence of the Granite Mountains and the development of the Split Rock syncline 

southeast of the Wind River Basin. 

•	 Blackstone (1990) stated that extensional tectonism is 

common in the Wind River Basin and that “extensional 

faults occur in the hanging wall of the Owl Creek 

Thrust Fault and trend subparallel to the major fault. 

The faults are the result of extension during the bowing 

upward (folding) of the toe of the hanging wall of the 

fault and are in the nature of a “keystone”... .” 

•	 North of the Madden anticline, the southern end of 

the Bighorn Mountains downdropped after Miocene 

deposition ceased (Love, 1978).

•	 Normal faults in the Wind River Formation (Love and 

Christiansen, 1985), oriented east-west and extending 

westward for 20 miles from the center of the Madden 

anticline, demonstrate extension after deposition of the 

Eocene Wind River Formation.

Given that post-Laramide extension occurred in the 

region, the question then becomes whether extensional 

features exist in the subsurface in the hanging wall of the 

Madden thrust. Dunleavy and Gilbertson (1986, p. 145) issue 

a somewhat cautionary note: “Large-scale normal faulting 

occurred in late Tertiary along the leading edge of the Owl 

Creek system, but there is only a little evidence in well control 

for significant normal faults at Madden (Reid, 1978).” On the 

other hand, an interpreted seismic section (Ray and Keefer, 

1985; that report’s fig. 8) shows normal faults orthogonal to 

and above the Madden thrust fault, terminating upward in 

the Waltman Shale Member. Further, an interpreted seismic 

section in our custody shows a single normal fault just north 

of the Inexco MDU Deep 1 well with large offsets extending 

from Cody Shale upward into the lower Fort Union Formation 

and terminating in the Waltman Shale Member. Accordingly, 

the existence of subsurface normal faults antithetical to the 

Madden thrust seems sufficiently substantiated. Likewise, on 

the basis of core and three-dimensional seismic surveys, strata 

in the Madden anticline are regarded as extremely fractured 

and faulted (C. Hawkins, oral communication, 2008). 

However, the distribution and characteristics of fractures 

that developed during extension on the Madden anticline are 

unknown. 

Gas generation in the Cody Shale and Mesaverde 

Formation had largely ceased by the end of the early Eocene 

and the beginning of tectonic extension (pl. 8). Overpressure, 

presently between 0.6 and 0.7 psi/ft, was probably higher and 

could have been high enough to reduce the minimum effective 

stress to nearly zero and induce opening-mode fractures. It is 

also reasonable to think that faulting and fracturing is greater 

in the Mesaverde-Morrison interval than in the overlying 

Meeteetse–Lance–lower Fort Union interval, owing to high 

pore pressure and consequent reduced effective stress.

Gas generation in the Lance and Fort Union Formations 

spans both the compressional and extensional phases 

(pl. 8). It is possible that high pore pressure was a factor in 

fracture formation, but the overpressure signature existing 

today is produced by an elevated hydrostatic gradient, not 

by a relict overpressured gas signature. Gas generation in 

the Lance and Fort Union persisted throughout the Eocene 

and Oligocene and into Miocene time, during the period of 

tectonic extension. The timing of extension is uncertain, but 

for the sake of discussion, we designate gas generated during 

extension as “later” and gas generated prior to extension as 

“earlier.” The “later” gas could have entered newly formed 

fractures and migrated upward under buoyant pressure. If gas 

did migrate in fractures, then we can expect to find “later” gas 

accumulated in more porous reservoirs at some distance from 

source rocks and “earlier” gas in “tight” reservoirs adjacent to 

source rocks. The pressure record indicates that gas quantities 

were insufficient to drive water from the upper pressure 

compartment.

On the basis of its pressure gradient, the pore space of 

upper pressure compartment, which extends from the base 

of the Waltman Shale Member to the top of the Mesaverde 

Formation, appears to be dominated by water, not by gas. 

Two possibilities exist: (1) only a fraction of mobile water 

was displaced from any “reservoir” because insufficient 

quantities of gas were generated to displace the water, and, as 

a consequence, water remained the continuous phase; or (2) 

any overpressure signature caused by early gas generation has 

been lost because fractures that opened during the extension 

phase are water filled, causing equilibration along a (now 

elevated) hydrostatic pressure gradient. In either case, the 

now-elevated hydrostatic pressure gradient is a relic of a 

normal hydrostatic pressure gradient that existed before 

regional uplift and erosion. 

Regional Uplift and Erosion

Regional uplift and erosion commenced about 15 Ma 

(Roberts, Finn, and others, 2007). The consequent reduction 

in vertical and horizontal stresses allowed existing fractures to 

open further. Except for the lower Fort Union Formation, gas 

generation had ceased before Miocene time and in particular 

before commencement of uplift and erosion, so the enhanced 
16 Gas, Oil, and Water Production in the Wind River Basin, Wyoming

fracture permeability did not result in a redistribution of gas. 

Fractures now form permeable conduits to aquifers, probably 

for distances considerably greater than the drainage area of 

gas to a well. The relative independence of water and gas 

production rates, the variations in water-gas ratios, and the 

commencement of water flow with gas flow all indicate that 

the present-day gas and water flow networks are largely 

independent. 

A Speculative Model

One possible explanation for the independence of gas and 

water production in the Madden field is that gas is drawn from 

one storage and flow system, and water is drawn from another. 

The burial history chart (pl. 8) shows that gas generation 

and emplacement first occurred when burial was most rapid 

and a compressive tectonic regime existed during Laramide 

deformation. We hypothesize that a second set of permeable 

fractures was created later, during a period of post-Laramide 

stress relaxation and extension. Gas remained largely trapped 

in the pore and fracture system where it had been emplaced 

during compression, while water entered the newly formed 

fracture system. An individual well penetrating a gas-charged 

sandstone draws both gas and water from natural and induced 

fractures, but the gas is drawn from a volume relatively near 

the well, whereas the water is drawn from a much larger, 

fracture-connected volume. This concept is summarized in an 

idealized sketch of a producing well (fig. 9). 

Thus we propose a two-step scenario governing the 

distribution of fluids in the Cody Shale and Mesaverde 

Formation: gas generation and emplacement under a 

compressive stress regime followed by fracture formation 

during a subsequent period of stress relaxation and extension. 

However, an added complication occurred in the overlying 

Meeteetse, Lance, and Fort Union Formations, where gas 

continued to be generated during the extensional period, after 

compression had ceased and before commencement of uplift. 

This “later” gas entered fractures where it could migrate under 

buoyancy drive and be distributed more widely than gas that 

had been generated during late Laramide compression. This 

model remains speculative because of several unknowns: 

(1) the exact timing of extension, (2) the intensity and 

character of small-scale fracturing, (3) the orientation and 

scale of large fractures, and (4) poor understanding of water 

migration in fractured systems. 

Interfield Comparisons of Fluid 

Production

Gas, water, and oil production “initial” values of the eight 

fields presented on plates 1–7 are summarized in figures 10

and 11. Two reservoirs with conventional characteristics, 

Fuller Reservoir (Shotgun Member) and Madden (Madison), 

plot separately from the cluster of six tight gas accumulations 

(fig. 10). The water-gas character of Fuller Reservoir is not 

directly comparable with the character of other accumulations 

shown in figure 10 because economic recoveries in this field 

are determined by the production of oil, not gas. The other 

exception is the Madison Limestone in the Madden anticline, 

considered a conventional reservoir, which does produce water 

that is dissolved in reservoir gas (fig. 7–2 of pl. 7). 

Six gas accumulations clustered in the center of 

figure 10—Frenchie Draw (lower Fort Union), Cooper 

(lower Fort Union), Cave Gulch (Lance), Madden (lower Fort 

Union), Madden (Mesaverde), and Madden (Cody)—had gas 

production rates ranging from 100 to 10,000 mcf/day, water 

production rates ranging from 1 to more than 1,000 bbl/day, 

and water-gas ratios ranging from 1 to more than 

100 bbl/mmcf. All six are generally categorized as tight gas 

accumulations, although permeabilities cited for Cave Gulch 

(Lance) exceed 1.0 mD. The water-gas ratio was consistently 

greater in Frenchie Draw and Cooper Reservoir than in the 

other four accumulations, partly because gas production rates 

were comparatively lower in these two fields. In only two of 

these six accumulations—Madden (Mesaverde) and Madden 

(lower Fort Union)—were some water-gas ratios low enough 

to indicate that all produced water was dissolved in gas in 

the reservoir. In other words, almost all producing intervals 

produced water at rates greater than could be sustained by 

water dissolved in gas.

Values of vitrinite reflectance (Ro) were added to the 

oil-gas diagram (fig. 11) to represent the approximate thermal 

maturity of each reservoir. The three deepest accumulations 

in the Madden field have Ro values greater than 2.0 percent 

and produce dry gas with no oil. Wet gas is produced from the 

lower Fort Union at Madden and the Lance at Cave Gulch, 

with values of 0.8 and 0.7 percent Ro, respectively. No Ro

value could be assigned to Cooper Reservoir field. The Ro

value of 1.1 percent associated with production from Frenchie 

Draw field is anomalously high. A value of 0.5 percent Ro

represents Fuller Reservoir field; its source is the underlying 

Waltman Shale Member. No relationship between vitrinite 

reflectance and water-gas production was observed, so no 

corresponding diagram is shown. Thus, the degree of thermal 

maturity might influence the oil (condensate)-to-gas ratio, but 

it has no bearing upon water-gas ratio.

Vector and normalized vector diagrams demonstrate the 

differences in water and gas production among six tight gas 

accumulations (figs. 12, 13). Of the six gas accumulations, 

water and gas declines were the most uniform in Cooper 

Reservoir (lower Fort Union). Uniform declines were also 

observed in the main part of Cave Gulch (Lance) field (the 

steep declines in water production were in wells south and 

west of the Cave Gulch anticlinal structure; see fig. 4–1 of 

pl. 4). From the relatively uniform declines and the general 

tracking of water and gas, we infer that water and gas are 

produced from the same rock volumes and that, among the 

six accumulations, these two fields are the least perturbed by 

fracture systems. 
Interfield Comparisons of Fluid Production 17

Figure 9. Conceptual diagram of gas and water flow into a well producing from two siltstones in 

the Madden field. Gas migrates to the wellbore through fractures opened by hydraulic fracturing. 

Water migrates from distant sources through a single fracture and then into fractures opened by 

hydraulic fracturing. The production profile shows water entering the wellbore through the lower set 

of perforations and gas entering through both sets of perforations. Open circle, perforation; red arrow 

and line, gas; blue arrow and line, water.

Gas

reservoir

Gas reservoir

0 100%

Siltstone

Shale

Limit of

hydraulic

fracturing

Production

profile

Water-filled

fracture
18 Gas, Oil, and Water Production in the Wind River Basin, Wyoming

Gas Production Rate (mscf/day)

100 101 102 103 104 105 106

Water Production Rate (bbl/day)

10–1

100

101

102

103

104

Madden

(Cody)

Cave Gulch

(Lance)

0.1 bbl/mmscf

1 bbl/mmscf

10 bbl/mmscf

100 bbl/mmscf

1,000 bbl/mmscf

10,000 bbl/mmscf

No water production

Madden

(Madison)

Madden

(Fort Union)

Cave Gulch

(Lance)

Madden

(Mesaverde)

Cooper

Reservoir

(Lance)

Fuller Reservoir

(Shotgun Member)

Frenchie Draw

(Fort Union)

Figure 10. Water versus gas production rates in five fields, Wind River Basin. 

Each point represents the initial production rate of a single producing interval, 

taken from plates 1–4, 6, and 7, and coded by field. Colored backgrounds 

outline the range of water and gas production rates for each field. The fields 

designated Madden (Madison) and Fuller Reservoir (Shotgun Member) are 

considered conventional reservoirs; all others are tight gas accumulations. 

bbl/day, barrels per day; bbl/mmscf, barrels per million standard cubic feet; 

mscf/day, thousand standard cubic feet per day. Well symbols: circle, Fuller 

Reservoir (Shotgun Member); circle half filled, Frenchie Draw (Fort Union); 

upright triangle, Cooper Reservoir (Fort Union); inverted triangle, Madden 

(Mesaverde); square, Madden (Fort Union); square with two filled quadrants, 

Madden (Madison); ×, Madden (Cody); diamond, Cave Gulch (Lance). 
Interfield Comparisons of Fluid Production 19

Gas Production Rate (mscf/day)

100 101 102 103 104 105 106

Oil Production Rate (bbl/day)

10–1

100

101

102

103

104

0.1 bbl/mmscf

1 bbl/mmscf

10 bbl/mmscf

100 bbl/mmscf

10,000 bbl/mmscf

1,000 bbl/mmscf

No oil production

Cave Gulch

(Lance) 0.7

Madden

(Madison) 4.0

Madden

(Cody) 2.6

Madden

(Mesaverde) 2.2

Vitrinite reflectance

(percent)

Wet gas upper limit

Black and volatile oils lower limit

Frenchie Draw

(Fort Union) 1.1

Fuller Reservoir

(Shotgun Member) 0.5

Madden

(Fort Union) 0.8

Cooper

Reservoir

(Lance)

Figure 11. Oil and gas production in eight fields, Wind River Basin. Each 

point represents the initial production from a single producing interval, coded 

by field. For example, gas production rates from the Madden (Mesaverde) 

accumulation are shown as inverted triangles. Vitrinite reflectance values 

(number following field name) from Nelson and Kibler (2007). bbl/day, 

barrels per day; bbl/mmscf, barrels per million standard cubic feet; mscf/

day, thousand standard cubic feet per day. Well symbols: purple circle, 

Fuller Reservoir (Shotgun Member); blue square, Frenchie Draw (Fort Union); 

upright yellow triangle (Cooper Reservoir); inverted red triangle, Madden 

(Mesaverde); brown square, Madden (Fort Union); square with two filled 

quadrants, Madden (Madison); ×, Madden (Cody); dark red diamond, Cave 

Gulch (Lance). 
20 Gas, Oil, and Water Production in the Wind River Basin, Wyoming

Gas Production Rate (mscf/day) Gas Production Rate (mscf/day)

Gas Production Rate (mscf/day)

Gas Production Rate (mscf/day)

Gas Production Rate (mscf/day)

Gas Production Rate (mscf/day)

101

Water Production Rate (bbl/day)

Water Production Rate (bbl/day)

10–1

100

101

102

103

104

10–1

100

101

102

103

104

Water Production Rate (bbl/day)Water Production Rate (bbl/day)

Water Production Rate (bbl/day)Water Production Rate (bbl/day)

102 103 104 105 106

101

10–1

100

101

102

103

104

10–1

100

101

102

103

104

10–1

100

101

102

103

104

10–1

100

101

102

103

104

102 103 104 105 106

101 102 103 104 105 106 101 102 103 104 105 106

101 102 103 104 105 106

101 102 103 104 105 106

10,000 bbl/mmscf

1,000 bbl/mmscf

100 bbl/mmscf

10 bbl/mmscf1 bbl/mmscf

0.1 bbl/mmscf

Madden - Lower Fort Union Frenchie Draw - Lower Fort Union

Madden - Mesaverde Cave Gulch - Lance

Madden - Cody Shale Cooper Reservoir - Lower Fort Union

Figure 12. Vector diagrams of six tight gas accumulations, Wind River Basin. Black square, gas and water 

production at about 2 years; attached symbol, gas and water production about 2+5 years. bbl/day, barrels 

per day; mscf/day, thousand standard cubic feet per day.
Interfield Comparisons of Fluid Production 21

Change in Water Production (bbl/day)

1/100 1/10 1 10 100

1/100

1/10

1

10

100

Change in Gas Production (mscf/day)

Change in Water Production (bbl/day)

1/100 1/10 1 10 100

1/100

1/10

1

10

100

Change in Water Production (bbl/day)

1/100 1/10 1 10 100

1/100

1/10

1

10

100

Change in Water Production (bbl/day)

1/100 1/10 1 10 100

1/100

1/10

1

10

100

Change in Water Production (bbl/day)

Change in Gas Production (mscf/day)

Change in Gas Production (mscf/day) Change in Gas Production (mscf/day)

Change in Gas Production (mscf/day) Change in Gas Production (mscf/day) Change in Water Production (bbl/day)

1/100 1/10 1 10 100

1/100

1/10

1

10

100

1/100 1/10 1 10 100

1/100

1/10

1

10

100

Madden - Lower Fort Union

Madden - Mesaverde 

Madden - Cody Shale

Frenchie Draw - Lower Fort Union

Cave Gulch - Lance

Cooper Reservoir - Lower Fort Union

Figure 13. Normalized vector diagrams for six tight gas accumulations, Wind River Basin. Black square 

in center of diagram, gas and water production at initial time for all vectors; attached symbol, gas and 

water production 5 years after initial time. bbl/day, barrels per day; mscf/day, thousand standard cubic 

feet per day.
22 Gas, Oil, and Water Production in the Wind River Basin, Wyoming

Summary and Conclusions 

If one considers the three fields producing from the lower 

Fort Union (Frenchie Draw, Cooper Reservoir, and Madden), 

examination of their vector diagrams (figs. 12, 13) shows that 

the three accumulations responded differently with time. In 

Frenchie Draw wells, gas declined slowly with time and at 

about the same rate as in Madden, but water was unchanging 

with time (with one exception), whereas water production 

either increased or decreased with time in Madden. Both gas 

and water declined at much higher rates in Cooper Reservoir 

than in either Frenchie Draw or Madden. The differences in 

water production may indicate that fracturing plays a smaller 

role in Cooper Reservoir and Frenchie Draw than it does in 

Madden.

On the other hand, production-time diagrams of fluids 

produced from the three tight gas Madden field accumulations—Cody Shale, Mesaverde Formation, and lower Fort 

Union Formation—show little or no correlation between gas 

and water, with consequent disparate signatures among wells 

on the vector diagrams (figs. 12 and 13). Fractional change in 

gas and water production during a 5-year period was greatest 

in the Cody Shale and least in the lower Fort Union Formation. 

Water production generally commenced with gas production 

and increased or decreased with time while gas production 

generally decreased. Well position along the Madden anticline 

does not seem to control fluid production. The initial magnitude of gas production was not a determinant of either the 

magnitude or the sense of subsequent water production. We 

conclude that gas and water production from tight gas accumulations in the Madden field are generally independent of 

one another, and a speculative model linking tectonics, timing 

of gas generation, and fracture flow has been proposed.

Acknowledgments

We benefitted from discussions with Ted Enterline of Bill 

Barrett Corporation, Dean Dubois of EnCana Corporation, 

Connie Hawkins of Hawkins Oil and Gas, and Ron Baugh, 

consulting geologist, and from reviews by Steve Roberts and 

Troy Cook of the U.S. Geological Survey. Ron Johnson, U.S. 

Geological Survey, supplied formation tops for the Lance and 

Fort Union Formations in the Madden area. Well locations are 

taken from the web site of the Wyoming Oil and Gas Conservation Commission. Shauna Ewald, a U.S. Geological Survey 

student employee, assisted with data preparation. 

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