Geologic Framework for the National Assessment of 

Carbon Dioxide Storage Resources─Bighorn Basin, 

Wyoming and Montana

Open-File Report 2012–1024-A 

U.S. Department of the Interior

U.S. Geological Survey
Geologic Framework for the National Assessment of

Carbon Dioxide Storage Resources─Bighorn Basin, 

Wyoming and Montana

By Jacob A. Covault, Marc L. Buursink, William H. Craddock, Matthew D. Merrill, Madalyn S. Blondes, 

Mayur A. Gosai, and Philip A. Freeman

Chapter A of

Geologic Framework for the National Assessment of Carbon Dioxide Storage Resources

Edited by Peter D. Warwick and Margo D. Corum

Open-File Report 2012–1024-A 

U.S. Department of the Interior

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

KEN SALAZAR, Secretary

U.S. Geological Survey

Marcia K. McNutt, Director

U.S. Geological Survey, Reston, Virginia: 2012

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Suggested citation:

Covault, J.A., Buursink, M.L., Craddock, W.H., Merrill, M.D., Blondes, M.S., Gosai, M.A., and Freeman, P.A., 2012, 

Geologic framework for the national assessment of carbon dioxide storage resources—Bighorn Basin, Wyoming and 

Montana, chap. A of Warwick, P.D., and Corum, M.D., eds., Geologic framework for the national assessment of 

carbon dioxide storage resources: U.S. Geological Survey Open-File Report 2012–1024-A, 23 p., available at 

http://pubs.usgs.gov/of/2012/1024/a/. 

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 material contained within this report.
iv

Editors’ Preface

By Peter D. Warwick and Margo D. Corum

The 2007 Energy Independence and Security Act (Public Law 110–140) directs the U.S. 

Geological Survey (USGS) to conduct a national assessment of potential geologic storage resources for 

carbon dioxide (CO2) and to consult with other Federal and State agencies to locate the pertinent 

geological data needed for the assessment. The geologic sequestration of CO2 is one possible way to 

mitigate its effects on climate change.

The methodology that is being used by the USGS for the assessment was described by Brennan 

and others (2010), who revised the methodology by Burruss and others (2009) according to comments 

from peer reviewers, members of the public, and experts on an external panel. The assessment 

methodology is non-economic and is intended to be used at regional to subbasinal scales. 

The operational unit of the assessment is a storage assessment unit (SAU), composed of a porous 

storage formation with fluid flow and an overlying fine-grained sealing unit. Assessments are conducted at 

the SAU level and are aggregated to basinal and regional results. SAUs have a minimum depth of 3,000 

feet (ft), which ensures that the CO2 is in a supercritical state (and thus occupies less pore space than a 

gas). Standard SAUs have a maximum depth of 13,000 ft below the surface, a depth accessible with 

average injection pipeline pressures (Burruss and others, 2009; Brennan and others, 2010). Where 

geologic conditions favor CO2 storage below 13,000 ft, an additional deep SAU is assessed. 

The assessments are also constrained by the occurrence of relatively fresh formation water; any 

formation water having a salinity less than 10,000 parts per million (ppm, which is equivalent to 

milligrams per liter, mg/L) total dissolved solids (TDS), regardless of depth, has the potential to be used as 

a potable water supply (U.S. Environmental Protection Agency, 2009). The U.S. Environmental Protection 

Agency (2008) has proposed the limit of 10,000 ppm (mg/L) TDS for injection of CO2. Therefore, the 

potential storage resources for CO2 in formations where formation waters have salinities less than 10,000 

ppm (mg/L) TDS are not assessed (Brennan and others, 2010). 

This report series contains geologic descriptions of each SAU identified within the assessed basins 

and focuses on the particular characteristics specified in the methodology that influence the potential CO2

storage resource. Although assessment results are not contained in these reports, the geologic framework 

information will be used to calculate a statistical Monte Carlo-based distribution of potential storage space 

in the various SAUs following Brennan and others (2010). Figures in this report series show SAU 

boundaries and cell maps of well penetrations through the sealing unit into the top of the storage 

formation. Wells sharing the same well borehole are treated as a single penetration. Cell maps show the 

number of penetrating wells within one square mile and are derived from interpretations of incompletely 

attributed well data (IHS Energy Group, 2011; and other data as available), a digital compilation that is 

known not to include all drilling. The USGS does not expect to know the location of all wells and cannot 

guarantee the amount of drilling through specific formations in any given cell shown on cell maps.
v

References Cited

Brennan, S.T., Burruss, R.C., Merrill, M.D., Freeman, P.A., and Ruppert, L.F., 2010, A probabilistic 

assessment methodology for the evaluation of geologic carbon dioxide storage: U.S. Geological Survey 

Open-File Report 2010–1127, 31 p., accessed March 22, 2011, at http://pubs.usgs.gov/of/2010/1127/. 

Burruss, R.C., Brennan, S.T., Freeman, P.A., Merrill, M.D., Ruppert, L.F., Becker, M.F., Herkelrath, 

W.N., Kharaka, Y.K., Neuzil, C.E., Swanson, S.M., Cook, T.A., Klett, T.R., Nelson, P.H., and Schenk, 

C.J., 2009, Development of a probabilistic assessment methodology for evaluation of carbon dioxide 

storage: U.S. Geological Survey Open-File Report 2009–1035, 81 p., accessed March 22, 2011, at

http://pubs.usgs.gov/of/2009/1035/. 

IHS Energy Group, 2011, ENERDEQ U.S. well data: IHS Energy Group; online database available from 

IHS Energy Group, 15 Inverness Way East, D205, Englewood, CO 80112, U.S.A., accessed 

January 20, 2011, at http://energy.ihs.com/. 

U.S. Environmental Protection Agency, 2008, Federal requirements under the underground injection 

control (UIC) program for carbon dioxide (CO2) geologic sequestration (GS) wells: Washington, D.C., 

U.S. Environmental Protection Agency, proposed rule, accessed March 23, 2011, at 

http://www.epa.gov/fedrgstr/EPA-WATER/2008/July/Day-25/w16626.htm. 

U.S. Environmental Protection Agency, 2009, Safe Drinking Water Act (SDWA): Washington, D.C., U.S. 

Environmental Protection Agency Web site, accessed January 14, 2009, at 

http://www.epa.gov/ogwdw/sdwa/index.html. 
vi

Contents

Editors' Preface .............................................................................................................................................................iv

References Cited............................................................................................................................................................v

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

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

Present-Day Bighorn Basin Physiography ................................................................................................................. 2

Bighorn Basin Tectono-Stratigraphic Evolution.......................................................................................................... 2

Bighorn Basin Carbon Dioxide Storage Assessment ................................................................................................. 3

Tensleep Sandstone C50340101 and Tensleep Sandstone Deep C50340102............................................................. 8

Ervay Member C50340103 and Ervay Member Deep C50340104...............................................................................10

Crow Mountain Sandstone C50340105 and Crow Mountain Sandstone Deep C50340106 .........................................12

Cloverly Formation C50340107 and Cloverly Formation Deep C50340108 .................................................................14

Muddy Sandstone C50340109 and Muddy Sandstone Deep C50340110....................................................................16

Frontier Sandstone C50340111 and Frontier Sandstone Deep C50340112 ................................................................18

Acknowledgments ........................................................................................................................................................20

References Cited..........................................................................................................................................................20

Figures

1. Geologic map and cross section of the Bighorn Basin, Wyoming and Montana.................................................... 4

2. Map of Rocky Mountain region extending from southern Montana to northern New Mexico showing locations 

of Laramide sedimentary basins and intervening uplifts........................................................................................ 5

3. Map showing extent of the Western Interior Seaway during Campanian time....................................................... 6

4. Generalized stratigraphic column of geologic formations in the Bighorn Basin, Wyoming and Montana............... 7

5. Map of the USGS Storage Assessment boundary for the Tensleep Sandstone and Tensleep Sandstone 

Deep Storage Assessment Units in the Bighorn Basin, Wyoming and Montana ................................................... 9

6. Map of the USGS Storage Assessment boundary for the Ervay Member and Ervay Member Deep Storage 

Assessment Units in the Bighorn Basin, Wyoming and Montana ........................................................................ 11

7. Map of the USGS Storage Assessment boundary for the Crow Mountain Sandstone and Crow Mountain 

Sandstone Deep Storage Assessment Units in the Bighorn Basin, Wyoming and Montana ............................... 13

8. Map of the USGS Storage Assessment boundary for the Cloverly Formation and Cloverly Formation Deep 

Storage Assessment Units in the Bighorn Basin, Wyoming and Montana........................................................... 15

9. Map of the USGS Storage Assessment boundary for the Muddy Sandstone and Muddy Sandstone Deep 

Storage Assessment Units in the Bighorn Basin, Wyoming and Montana........................................................... 17

10. Map of the USGS Storage Assessment boundary for the Frontier Sandstone and Frontier Sandstone Deep 

Storage Assessment Units in the Bighorn Basin, Wyoming and Montana........................................................... 19
vii

Conversion Factors

Multiply By To obtain

Length

inch (in.) 2.54 centimeter (cm)

foot (ft) 0.3048 meter (m)

mile (mi) 1.609 kilometer (km)

Area

square foot (ft2) 0.09290 square meter (m2)

square foot (ft2) 0.00002296 acre 

square mile (mi2) 2.59 square kilometer (km2)

Volume

barrel (bbl), (petroleum, 1 barrel=42 gal) 0.1590 cubic meter (m3) 

cubic foot (ft3) 0.02832 cubic meter (m3) 

1,000 cubic feet (MCF) 28.32 cubic meter (m3)

cubic meter (m3) 6.290 barrel (petroleum, 1 barrel = 42 gal)
1

Geologic Framework for the National Assessment of 

Carbon Dioxide Storage Resources─Bighorn Basin, 

Wyoming and Montana

By Jacob A. Covault,1 Marc L. Buursink, William H. Craddock, Matthew D. Merrill, Madalyn S. Blondes, 

Mayur A. Gosai, and Philip A. Freeman

Abstract

The 2007 Energy Independence and Security Act (Public Law 110–140) directs the U.S. 

Geological Survey (USGS) to conduct a national assessment of potential geologic storage resources for 

carbon dioxide (CO2). The methodology used for the national CO2 assessment follows that of previous 

USGS work. The methodology is non-economic and intended to be used at regional to subbasinal scales. 

This report identifies and contains geologic descriptions of twelve storage assessment units 

(SAUs) in six separate packages of sedimentary rocks within the Bighorn Basin of Wyoming and 

Montana and focuses on the particular characteristics, specified in the methodology, that influence the 

potential CO2 storage resource in those SAUs. Specific descriptions of the SAU boundaries as well as 

their sealing and reservoir units are included. Properties for each SAU such as depth to top, gross 

thickness, net porous thickness, porosity, permeability, groundwater quality, and structural reservoir traps 

are provided to illustrate geologic factors critical to the assessment. Although assessment results are not 

contained in this report, the geologic information included here will be employed, as specified in the 

methodology of earlier work, to calculate a statistical Monte Carlo-based distribution of potential storage 

space in the various SAUs. Figures in this report show SAU boundaries and cell maps of well 

penetrations through the sealing unit into the top of the storage formation. Wells sharing the same well 

borehole are treated as a single penetration. Cell maps show the number of penetrating wells within one 

square mile and are derived from interpretations of incompletely attributed well data, a digital compilation 

that is known not to include all drilling. The USGS does not expect to know the location of all wells and 

cannot guarantee the amount of drilling through specific formations in any given cell shown on cell maps. 

Introduction

The Bighorn Basin of Montana and Wyoming is a large (≈10,400 mi2) sedimentary basin 

structurally bounded on the northeast by the Pryor Mountains, on the east by the Bighorn Mountains, on 

the south by the Owl Creek uplift, and on the west and northwest by the Absaroka Range and Beartooth 

Mountains, respectively (Finn and others, 2010) (figs. 1 and 2). Finn and others (2010) define the 

northern basin margin by a zone of structural deformation referred to as the Nye-Bowler lineament 

(Wilson, 1936) (fig. 2). The earliest commercial hydrocarbon production in the Bighorn Basin was in 

1906, which exploited Cretaceous sandstone reservoirs (Fox and Dolton, 1996). Total production from 

Cretaceous and Tertiary reservoirs is about 94 million barrels of oil and 830 billion ft3 of gas through 

2010 according to Finn and others (2010). Approximately 1.8 billion barrels of oil and 2.7 trillion ft3 of 

gas have been discovered as of year-end 1990 (Fox and Dolton, 1995). Production in the Bighorn Basin is 

 

1

 Current address: Chevron Energy Technology Company, Clastic Stratigraphy R&D, Houston, Texas 

77002, USA 
2

predominantly from anticlinal structural traps in Permian and Cretaceous reservoirs (Fox and Dolton, 

1995; Finn and others, 2010). 

The USGS recently completed a geology-based assessment of undiscovered oil and gas resources 

of the Bighorn Basin (U.S. Geological Survey Bighorn Basin Province Assessment Team, 2010). Two 

petroleum systems were identified, each comprising characteristic petroleum source rocks, reservoir 

rocks, and traps: Phosphoria (Permian) and Cretaceous-Tertiary Composite (U.S. Geological Survey 

Bighorn Basin Province Assessment Team, 2010). The U.S. Geological Survey Bighorn Basin Province 

Assessment Team (2010) estimated means of 72 million barrels of recoverable undiscovered oil, 989 

billion ft3 of recoverable undiscovered natural gas, and 13 million barrels of recoverable undiscovered 

total natural gas liquids from the two petroleum systems. Most of the conventional, anticlinal structural 

traps in the Bighorn Basin have been exploited. Thus, new conventional resource potential is interpreted 

to be from stratigraphic traps of Permian carbonate rocks and Upper Cretaceous sedimentary rocks (U.S. 

Geological Survey Bighorn Basin Province Assessment Team, 2010). 

Finn and others (2010) noted a limited zone of overpressure in sedimentary rocks deeper than 

approximately 13,000–17,000 ft below surface in the Bighorn Basin (Surdam and others, 1997; Johnson 

and Finn, 1998; Johnson and others, 1999). Moreover, the injection of large amounts of supercritical CO2

into subsurface reservoir formations of the Bighorn Basin might cause large pressure increases. The 

resulting overpressure might promote reactivation of fractures or create new fractures that compromise 

seal integrity (Burruss and others, 2009). Burruss and others (2009) provide a review of overpressure in 

the context of CO2 storage. Following the methodology of Brennan and others (2010), we do not consider 

overpressure in this assessment of potential geologic storage resources for CO2 in the Bighorn Basin. 

Present-Day Bighorn Basin Physiography

The present-day physiography of the Bighorn Basin is largely the result of Late Cretaceous to 

Eocene Laramide orogenesis (Dickinson and others, 1988) (figs. 1 and 2). The Laramide orogeny was 

characterized by a structural style of Precambrian basement-cored uplifts and intervening sedimentary 

basins developed over a wide area east of about 112° W. longitude (Coney, 1976; Dickinson and others, 

1988) (figs. 1 and 2). Laramide basins and associated uplifts of various shapes, sizes, and orientations are 

distributed throughout the central Rocky Mountain region (Dickinson and others, 1988). The Bighorn 

Basin generally trends northwest to southeast (fig. 1). The northeastern, eastern, and southern basin 

margins are basement-cored uplifts of the Pryor, Bighorn, and Owl Creek Mountains, respectively (Finn 

and others, 2010) (figs. 1 and 2). These mountains are flanked by folded and faulted Cambrian to 

Paleocene sedimentary rocks (Finn and others, 2010) (fig. 1). The western basin margin is the Absaroka 

Range, which predominantly comprises Eocene andesitic volcanic and volcaniclastic rocks that 

unconformably overlie folded and faulted Paleozoic, Mesozoic, and lower Tertiary sedimentary rocks 

(Sundell, 1990, 1993) (fig. 1). The northwest margin of the basin is the Beartooth Mountains, which are 

composed of a basement-cored uplift flanked by steeply dipping to overturned sedimentary rocks (Foose 

and others, 1961; Finn and others, 2010). The Nye-Bowler lineament is an approximately 60-mile-long 

regional anticlinal trend extending east to southeast from the northern Beartooth Mountains to the Pryor 

Mountains (Finn and others, 2010). It is interpreted to overlie a left-lateral basement shear zone (Wilson, 

1936). 

Bighorn Basin Tectono-Stratigraphic Evolution

The Bighorn Basin is part of the North American Cordilleran orogenic belt, which extends for 

nearly 4,000 miles from southern Mexico to the Canadian Arctic and Alaska (fig. 3) (DeCelles, 2004). 

This Cordillera became consolidated as a coherent high-elevation orogenic basin during the Late Jurassic

(DeCelles, 2004). The Cordilleran orogenic belt was constructed of sedimentary and metasedimentary 

rocks that were originally deposited in marine environments along the Neoproterozoic-early Paleozoic

rifted western margin of Laurentia (DeCelles, 2004). These Neoproterozoic-lower Paleozoic strata are
3

predominantly siliciclastic with some carbonate rock (DeCelles, 2004). The Proterozoic section ranges in

thickness from approximately 2–6 miles (Link and others, 1993; DeCelles, 2004). 

The development of the Cordillera was significantly influenced by Late Devonian-Early 

Mississippian Antler and Late Permian-Early Triassic Sonoma orogenies, elements of which can be traced 

from southwestern Nevada to southern Idaho (Miller and others, 1992; DeCelles, 2004). Following these 

orogenic episodes, the Triassic-Middle Jurassic succession was deposited and comprises shallow-marine 

to nonmarine lithofacies, including eolianites, fluvial sandstone and mudstone, and evaporites (DeCelles, 

2004). 

The Late Jurassic-Eocene evolution of the Cordilleran orogenic belt and foreland basin in North 

America took place contemporaneous with opening of the North Atlantic Ocean, subduction of oceanic 

plates beneath the western margin of the North American plate, closure of marginal oceanic basins, and 

accretion of fringing arcs along the western edge of the North American plate (DeCelles, 2004). During 

this period of about 100 million years, contractile deformation along the Cordilleran orogenic belt 

propagated greater than 600 miles eastward, culminating in the formation of the Laramide Rocky 

Mountains (DeCelles, 2004). During much of Cretaceous time, the part of Wyoming and Montana that is 

now the Bighorn Basin was located in the Western Interior Seaway and foreland basin system (fig. 3). 

Fluctuations in relative sea level and variations in sediment supply along the western shoreline of the 

Cretaceous foreland basin resulted in a complex pattern of intertonguing marine, marginal marine, and 

nonmarine deposits (Finn and others, 2010). 

Late Cretaceous to Eocene Laramide deformation within the central Rocky Mountain region broke 

the Western Interior foreland basin into discrete basins that became increasingly sedimentologically 

isolated through time and separated by emergent basement-cored uplifts, which served as local sources of 

synorogenic sediment (Dickinson and others, 1988) (fig. 2). Laramide basins such as the Bighorn Basin 

subsided rapidly and became depocenters for nonmarine sediment. During the Eocene Epoch, many 

Laramide basins, including the Bighorn Basin, were filled with volcaniclastic sediment from the 

Yellowstone-Absaroka area to the west (Love, 1988). Volcanic activity ended by Oligocene time, but 

basin filling continued as Oligocene and Miocene volcaniclastic sediment spilled over the crest of the 

Bighorn Mountains and was deposited in the Powder River Basin to the east (McKenna and Love, 1972). 

During middle Miocene time, regional uplift initiated the exhumation of the Laramide uplifts and basins, 

which continues to the present day (Love, 1988). 

Bighorn Basin Carbon Dioxide Storage Assessment

Reservoirs assessed for CO2 storage in the Bighorn Basin include: (1) Middle Pennsylvanian to 

Lower Permian Tensleep Sandstone, (2) Lower Permian Ervay Member of the Phosphoria Formation, (3) 

Triassic Crow Mountain Sandstone of the Chugwater Group, (4) Lower Cretaceous Cloverly Formation, 

(5) Lower Cretaceous Muddy Sandstone, and (6) Upper Cretaceous Frontier Formation (fig. 4). The 

extents of storage formations are defined by the geologic characteristics of the reservoirs and overlying 

seals and the subsurface physical properties of CO2 as described in Burruss and others (2009) and 

Brennan and others (2010). The following sections describe each of the storage assessment units defined 

in the Bighorn Basin. 
4

Figure 1. Geologic map and cross section of the Bighorn Basin, Wyoming and Montana (modified from Finn and 

others, 2010, their fig. 2). Vertical scale of cross section is in feet. 
5

Figure 2. Map of Rocky Mountain region extending from southern Montana to northern New Mexico showing 

locations of Laramide sedimentary basins (in brown) and intervening uplifts (modified from Dickinson and others, 

1988; from Finn and others, 2010, their fig. 4).
6

Figure 3. Map showing extent of the Western Interior Seaway during Campanian time. Tan areas show 

approximate geographic distribution of land areas (modified from Gill and Cobban, 1973; from Finn and others, 

2010, their fig. 5). 
7

Figure 4. Generalized stratigraphic column of geologic formations in the Bighorn Basin, Wyoming and Montana.

Storage assessment units consist of a reservoir (red) and regional seal (blue). Wavy lines indicate 

unconformable contacts, and gray sections represent eroded section. In some cases, subdivisions of units are 

not shown (modified from Fox and Dolton, 1995). 
8

Tensleep Sandstone C50340101 and Tensleep Sandstone Deep C50340102

By Matthew D. Merrill

The Pennsylvanian-Permian Tensleep Sandstone (figs. 4 and 5) predominantly includes fine- to 

medium-grained sandstone, with carbonate rocks and shale (Lawson and Smith, 1966). Uplift and 

denudation of the ancestral Rockies in the southeast of present-day Wyoming provided sediment to eolian 

dunes of the Tensleep Sandstone, which extends across central and western Wyoming (Lawson and 

Smith, 1966). Fine-grained rocks of the overlying Phosophoria Formation are relatively continuous and 

sufficiently thick (20–280 ft) to serve as a regional seal (Fox and Dolton, 1995). 

The Tensleep Sandstone comprises two potential reservoir units for CO2 storage in the Bighorn 

Basin: (1) between 3,000- and 13,000-ft subsurface depth, Tensleep Sandstone C50340101 and ( 2) below 

13,000-ft subsurface depth, Tensleep Sandstone Deep C50340102 (fig. 5). The SAU boundaries are 

defined by the 3,000- and 13,000-ft drilling depths from well penetrations (IHS Energy Group, 2010), 

published structure contour maps (Zapp, 1956), and faults bounding the Bighorn Basin. Zapp (1956) 

indicates that the thickness of the Tensleep Sandstone ranges from 100–300 ft, with a general thinning to 

the north. The net porous interval of the Tensleep Sandstone ranges from 10–150 ft (Nehring Associates, 

Inc., 2010). Sandstone porosity ranges from 4–15 percent in the shallow SAU (Tensleep Sandstone 

C50340101) and 2–7 percent in the deep SAU (Tensleep Sandstone Deep C50340102) (Fox and others, 

1975; Nehring Associates, Inc., 2010). Reservoir permeability values range from 0.1–1,000 millidarcies

(mD) with 10–200 mD values most typical at depths from 3,000–13,000 ft below surface. Deeper than 

13,000 ft, reservoir permeability values range from 0.1–10 mD (Fox and others, 1975). Water-quality 

measurements from 736 samples in the Tensleep Sandstone (Breit, 2002; Wyoming Oil and Gas 

Conservation Commission, 2010) indicate that groundwater in the formation is predominantly fresh (less 

than 10,000 ppm of total dissolved solids); however, at greater depths, water quality may trend toward

higher salinity. The minimum and central tendency buoyant trapping pore volumes were determined using 

methods described in Brennan and others (2010). Maximum buoyant trapping pore volume was calculated 

from the product of (1) the combined areas of structural reservoir traps interpreted from a structure map of 

the Tensleep Sandstone and reservoirs of producing fields (Nehring Associates, Inc., 2010), (2) the 

maximum net porous interval thickness, and (3) the maximum porosity (Brennan and others, 2010). 

Structural reservoir traps were defined by outlining areas of closure interpreted on a 1,000-ft-contourinterval structural map of the top of the Tensleep Sandstone (Zapp, 1956). 
9

Figure 5. Map of the U.S. Geological Survey Storage Assessment boundary for the Tensleep Sandstone and 

Tensleep Sandstone Deep Storage Assessment Units in the Bighorn Basin, Wyoming and Montana. Grid cells 

(one square mile) represent counts of wells derived from ENERDEQ well database (IHS Energy Group, 2011) 

that have penetrated the reservoir-formation top. Total Petroleum System boundary modified from U.S. 

Geological Survey Bighorn Basin Province Assessment Team (2010).
10

Ervay Member C50340103 and Ervay Member Deep C50340104 

By Marc L. Buursink

The Permian Ervay Member of the Phosphoria Formation predominantly includes dolomite 

grainstone and packstone, with some siliciclastic sandstone interpreted to represent tidal deposition (figs. 

4 and 6) (Coalson and Inden, 1990). Fine-grained rocks of the Phosophoria and overlying Dinwoody 

Formation are relatively continuous and sufficiently thick (as much as 1,000 ft) to serve as a regional seal 

(Campbell, 1962; Stone, 1967; Picard, 1978; Anderson and O'Connell, 1993).

The Ervay Member comprises two potential reservoir units for CO2 storage in the Bighorn Basin: 

(1) between 3,000- and 13,000-ft subsurface depth, Ervay Member C50340103; and (2) below 13,000-ft

subsurface depth, Ervay Member Deep C50340104 (fig. 6). The SAU boundaries are defined by the 

3,000- and 13,000-ft drilling depths from well penetrations (IHS Energy Group, 2010). Interpretations of 

boundaries are supported by the Wyoming digital geologic map of Green and Drouillard (1994) and the 

Wyoming Precambrian basement map of Blackstone (1993). The Phosphoria Formation ranges from 

approximately 20–280 ft thick in the Bighorn Basin and generally thickens to the southwest (Thomas, 

1965; Libra and others, 1981). Net Ervay Member sandstone ranges from approximately 12–100 ft (Tohill 

and Picard, 1966; High and Picard, 1969). Ervay Member sandstone porosity values range from 2–24 

percent in the shallow SAU (Ervay Member C50340103) and 2–7 percent in the deep SAU (Ervay 

Member Deep C50340104) (Nehring Associates, Inc., 2010). These values are broadly consistent with a 

global compilation of Permian mixed siliciclastic and carbonate reservoir rocks (Libra and others, 1981; 

Ehrenberg and others, 2009). Reservoir permeability values generally range from 1–1,000 mD (Libra and 

others, 1981; Nehring Associates, Inc., 2010). Water-quality measurements indicate that groundwater in 

the Ervay Member is both fresh and saline (greater than 10,000 ppm of total dissolved solids) (Breit, 

2002; Wyoming Oil and Gas Conservation Commission, 2010). The minimum and central tendency 

buoyant trapping pore volumes were determined using methods described in Brennan and others (2010). 

Maximum buoyant trapping pore volume was calculated from the product of (1) the combined areas of 

structural reservoir traps interpreted from a structure map of the Ervay Member and reservoirs of 

producing fields (Nehring Associates, Inc., 2010), (2) the maximum net-porous-interval thickness, and (3) 

the maximum porosity (Brennan and others, 2010). Structural reservoir traps were defined by outlining 

areas of closure interpreted on a 1,000-ft-contour-interval structural map of the top of the Ervay Member. 
11

Figure 6. Map of the U.S. Geological Survey Storage Assessment boundary for the Ervay Member and Ervay 

Member Deep Storage Assessment Units in the Bighorn Basin, Wyoming and Montana. Grid cells (one square 

mile) represent counts of wells derived from ENERDEQ well database (IHS Energy Group, 2011) that have 

penetrated the reservoir formation top. Total Petroleum System boundary modified from U.S. Geological Survey 

Bighorn Basin Province Assessment Team (2010).
12

Crow Mountain Sandstone C50340105 and Crow Mountain Sandstone Deep 

C50340106 

By Marc L. Buursink

The Triassic Crow Mountain Sandstone of the Chugwater Group predominantly includes fine- and 

medium-grained siliciclastic sandstone, which has been interpreted to represent shallow-marine 

deposition during a period of westward shoreline regression (figs. 4 and 7) (Tohill and Picard, 1966). 

Relatively fine-grained siliciclastic rocks of the overlying Triassic Popo Agie Formation (as much as 170 

ft thick) (Picard, 1978; Anderson and O'Connell, 1993) and anhydrite of the Middle Jurassic Gypsum 

Spring Formation (80–200 ft thick; Freethey and Cordy, 1991) are relatively continuous and sufficiently 

thick to serve as a regional seal.

The Crow Mountain Sandstone comprises two potential reservoir units for CO2 storage in the 

Bighorn Basin: (1) between 3,000- and 13,000-ft subsurface depth, Crow Mountain Sandstone 

C50340105; and (2) below 13,000-ft subsurface depth, Crow Mountain Sandstone Deep C50340106 

(fig. 7). The SAU boundaries are defined by the 3,000- and 13,000-ft drilling depths from well 

penetrations (IHS Energy Group, 2010). Interpretations of boundaries are supported by the Wyoming 

digital geologic map of Green and Drouillard (1994) and the Wyoming Precambrian basement map of 

Blackstone (1993). The Chugwater Group ranges from approximately 500–1,100 ft thick in the Bighorn 

Basin and generally thickens to the southwest (Thomas, 1965; Libra and others, 1981). The net porous 

interval of the Crow Mountain Sandstone ranges from approximately 10–140 ft (Tohill and Picard, 1966; 

High and Picard, 1969). Crow Mountain Sandstone porosity values range from 5–22 percent in the 

shallow SAU (Crow Mountain Sandstone C50340105) and 3–10 percent in the deep SAU (Crow 

Mountain Sandstone Deep) (Nehring Associates, Inc., 2010). These values are broadly consistent with a 

global compilation of Triassic siliciclastic reservoir rocks (Ehrenberg and others, 2009). Reservoir 

permeability values generally range from 1–1,000 mD for both the shallow and deep SAUs (Nehring

Associates, Inc., 2010). Water-quality measurements indicate that groundwater in the formation is both 

fresh and saline (greater than 10,000 ppm of total dissolved solids) (Breit, 2002; Wyoming Oil and Gas 

Conservation Commission, 2010). The minimum and central tendency buoyant trapping pore volumes 

were determined using methods described in Brennan and others (2010). Maximum buoyant trapping pore 

volume was calculated from the product of (1) the combined areas of structural reservoir traps interpreted

from a structure map of the Crow Mountain Sandstone and reservoirs of producing fields (Nehring

Associates, Inc., 2010), (2) the maximum net porous interval thickness, and (3) the maximum porosity 

(Brennan and others, 2010). Structural reservoir traps were defined by outlining areas of closure 

interpreted on a 1,000-ft-contour-interval structural map of the top of the Crow Mountain Sandstone. 
13

Figure 7. Map of the U.S. Geological Survey Storage Assessment boundary for the Crow Mountain Sandstone and 

Crow Mountain Sandstone Deep Storage Assessment Units in the Bighorn Basin, Wyoming and Montana. Grid 

cells (one square mile) represent counts of wells derived from ENERDEQ well database (IHS Energy Group, 

2011) that have penetrated the reservoir formation top. Total Petroleum System boundary modified from U.S. 

Geological Survey Bighorn Basin Province Assessment Team (2010). 
14

Cloverly Formation C50340107 and Cloverly Formation Deep C50340108

By Jacob A. Covault

The Lower Cretaceous Cloverly Formation is as much as 310 ft thick and predominantly includes 

siliciclastic sandstone and conglomerate (figs. 4 and 8) (Keefer and others, 1998; Finn and others, 2010). 

The Cloverly Formation has been subdivided into at least three members, from base to top: the Pryor

Conglomerate Member (Moberly, 1960), the Greybull Sandstone Member, and the informal “rusty beds” 

(Love and others, 1945; Keefer and others, 1998; Finn and others, 2010). The Cloverly Formation

unconformably overlies the Upper Jurassic Morrison Formation and progressively fines up-section into 

the Lower Cretaceous Thermopolis Shale (Finn and others, 2010). The Thermopolis Shale comprises as 

much as 230 ft of shale and siltstone and is interpreted to be a sealing unit for the underlying Cloverly 

Formation. Both the Cloverly Formation and Thermopolis Shale are regionally extensive across the 

Bighorn Basin (Finn, 2010). The Cloverly Formation and overlying Thermopolis Shale couplet has been 

interpreted to represent a landward retreat of depositional environments from predominantly nonmarine 

fluvial to fully marine systems in the Cretaceous Western Interior Seaway foreland basin (Finn and others,

2010). 

The Cloverly Formation comprises two potential reservoir units for CO2 storage in the Bighorn 

Basin: (1) between 3,000- and 13,000-ft subsurface depth, Cloverly Formation C50340107; and (2) below 

13,000-ft subsurface depth, Cloverly Formation Deep C50340108 (fig. 8). The SAU boundaries are 

defined by the 3,000- and 13,000-ft drilling depths from greater than 500 well penetrations (IHS Energy 

Group, 2010), published structure contour maps (Roberts and others, 2008), and faults bounding the 

Bighorn Basin. Fault locations were approximated from structural contour maps of Roberts and others 

(2008) and Finn and others (2010). The range of total storage formation thickness for reservoir units was 

determined from regional subsurface stratigraphic correlations of Finn (2010). The thickness of the net 

porous interval was calculated by multiplying the total storage formation thickness by a net porous 

thickness to gross thickness ratio of 0.52 interpreted from gamma-ray wireline logs of Finn (2010). Finn 

and others (2010) indicate a porosity range from 5–30 percent and a permeability range from 0.41–150 

mD (Hafenbrack and others, 1958; Tonnsen, 1985; Bartow-Campen, 1986; Cardinal and others, 1989; 

Nehring Associates, Inc., 2010). These data were employed in order to populate porosity and permeability 

ranges for the SAU C50340107 between 3,000 and 13,000 ft. A relatively small proportion of greater than 

1-D permeability is interpreted for the shallow Cloverly Formation C50340107 SAU based on gravel-size

sediment of the Pryor Conglomerate Member of the Cloverly Formation. Porosity and permeability values 

are interpreted to diminish with depth (Ehrenberg and others, 2009). Accordingly, we reduced the 

porosity range of the Cloverly Formation Deep C50340108 SAU by approximately 50 percent of the 

range of the shallower Cloverly Formation C50340107 SAU. These adjustments to petrophysical 

properties with depth are consistent with empirical data from Cretaceous siliciclastic sandstone reservoirs 

of the Rocky Mountain region (Nehring Associates, Inc., 2010). Water-quality measurements indicate that 

groundwater in the formation is both fresh and saline (greater than 10,000 ppm of total dissolved solids) 

(Breit, 2002; Wyoming Oil and Gas Conservation Commission, 2010). The minimum and central 

tendency buoyant trapping pore volumes were determined using methods described in Brennan and others 

(2010). Maximum buoyant trapping pore volume was calculated from the product of (1) the combined 

areas of structural reservoir traps interpreted from contours of Roberts and others (2008) and reservoirs of 

producing fields (Nehring Associates, Inc., 2010), (2) the maximum net porous interval thickness, and (3) 

the maximum porosity (Brennan and others, 2010). Structural reservoir traps were defined by outlining 

areas of closure interpreted on a 1,000-ft-contour-interval structural map of the top of the Cloverly 

Formation. In the Cloverly Formation Deep C50340108 SAU, areas of structural enclosure were also 

interpreted in the proximal footwalls of thrust faults of the Bighorn Basin (fig. 1). 
15

Figure 8. Map of the U.S. Geological Survey Storage Assessment boundary for the Cloverly Formation and 

Cloverly Formation Deep Storage Assessment Units in the Bighorn Basin, Wyoming and Montana. Grid cells 

(one square mile) represent counts of wells derived from ENERDEQ well database (IHS Energy Group, 2011) 

that have penetrated the reservoir formation top. Total Petroleum System boundary modified from U.S. 

Geological Survey Bighorn Basin Province Assessment Team (2010).
16

Muddy Sandstone C50340109 and Muddy Sandstone Deep C50340110

By Jacob A. Covault

The Lower Cretaceous Muddy Sandstone is as much as 70 ft thick and predominantly includes 

sandstone interbedded with mudstone (figs. 4 and 9) (Finn and others, 2010). The Muddy Sandstone 

unconformably overlies the Lower Cretaceous Thermopolis Shale and underlies the Lower and Upper 

Cretaceous Mowry Shale. The Mowry Shale is as much as 800 ft thick and is interpreted to seal the 

underlying Muddy Sandstone. Both the Muddy Sandstone and overlying Mowry Shale are regionally 

extensive across the Bighorn Basin (Finn, 2010). However, the Muddy Sandstone is thickest in the 

southeastern Bighorn Basin, where it is sandstone-rich, and thinnest in the north-northwestern part of the 

basin, where it includes sandstone encased in shale (Finn and others, 2010). The Mowry Shale increases 

in thickness from about 400 ft in the southeastern part of the Bighorn Basin to 800 ft in the northwestern

part of the Bighorn Basin (Finn and others, 2010). The Muddy Sandstone and overlying Mowry Shale 

couplet has been interpreted to represent a landward retreat of depositional environments from a marginal 

marine fluvial and (or) incised valley system that transitions to offshore bars (Muddy Sandstone) from 

southeast to northwest, to fully marine systems (Mowry Shale) in the Cretaceous Western Interior Seaway 

and foreland basin (Paull, 1962; Dolson and others, 1991; Long, 1999; Finn and others, 2010). 

The Muddy Sandstone comprises two potential reservoir units for CO2 storage in the Bighorn 

Basin: (1) between 3,000- and 13,000-ft subsurface depth, Muddy Sandstone C50340109; and (2) below 

13,000-ft subsurface depth, Muddy Sandstone Deep C50340110 (fig. 9). The SAU boundaries are defined 

by the 3,000- and 13,000-ft drilling depths from greater than 4,200 well penetrations (IHS Energy Group, 

2010) and faults bounding the Bighorn Basin. Fault locations were approximated from structural contour 

maps for the underlying Cloverly Formation (Finn and others, 2010). The range of total storage formation 

thickness for reservoir units was determined from an isopach map of Finn and others (2010). The 

thickness of the net porous interval was calculated by multiplying the total storage formation thickness by 

a net porous thickness to gross thickness ratio of 0.64 interpreted from gamma-ray wireline logs of Finn 

(2010). Finn and others (2010) indicate a porosity range from 2–23 percent and a permeability range from 

0.01–33 mD (Cardinal and others, 1989; Nehring Associates, Inc., 2010). These data were employed in 

order to populate porosity and permeability ranges for the SAU C50340109 between 3,000 and 13,000 ft. 

Porosity and permeability values are interpreted to diminish with depth (Ehrenberg and others, 2009). 

Accordingly, we reduced the porosity range of the SAU deeper than 13,000 ft below surface (C50340110) 

by approximately 50 percent of the range of the shallower Muddy Sandstone C50340109 SAU. These 

adjustments to petrophysical properties with depth are consistent with empirical data from Cretaceous

siliciclastic sandstone reservoirs of the Rocky Mountain region (Nehring Associates, Inc., 2010). Waterquality measurements indicate that groundwater in the formation is both fresh and saline (greater than 

10,000 ppm of total dissolved solids) (Breit, 2002; Wyoming Oil and Gas Conservation Commission, 

2010). The minimum and central tendency buoyant trapping pore volumes were determined using 

methods described in Brennan and others (2010). Maximum buoyant trapping pore volume was calculated 

from the product of (1) the combined areas of structural reservoir traps interpreted from a structure map of 

the Muddy Sandstone and reservoirs of producing fields (Nehring Associates, Inc., 2010), (2) the 

maximum net porous interval thickness, and (3) the maximum porosity (Brennan and others, 2010). 

Structural reservoir traps were defined by outlining areas of closure interpreted on a 1,000-ft-contourinterval structural map of the top of the Muddy Sandstone. In the Muddy Sandstone Deep C50340110 

SAU, areas of structural enclosure were also interpreted in the proximal footwalls of thrust faults of the 

Bighorn Basin (fig. 1).
17

Figure 9. Map of the U.S. Geological Survey Storage Assessment boundary for the Muddy Sandstone and Muddy 

Sandstone Deep Storage Assessment Units in the Bighorn Basin, Wyoming and Montana. Grid cells (one square 

mile) represent counts of wells derived from ENERDEQ well database (IHS Energy Group, 2011) that have 

penetrated the reservoir formation top. Total Petroleum System boundary modified from U.S. Geological Survey 

Bighorn Basin Province Assessment Team (2010).
18

Frontier Sandstone C50340111 and Frontier Sandstone Deep C50340112

By William H. Craddock

The Upper Cretaceous Frontier Sandstone ranges from approximately 100–300 ft thick and 

comprises lobate packages of sandstone and siltstone interbedded with shale (figs. 4 and 10). The 

sandstone packages generally exhibit gradational contacts with underlying shale units, coarsen upward, 

and are composed of inch- or foot-scale, buff-colored sandstone and siltstone beds. Eastward, across the 

Bighorn Basin, sandstone packages thin, become finer grained, and interfinger with the shale units. 

Sandstone beds exhibit hummocky, swaley, and trough cross stratification, burrowing, and bioturbation 

(Bhattacharya and Willis, 2001). The formation contains abundant marine fossils and trace fossil 

assemblages, including skolithos and ophiomorpha (Bhattacharya and Willis, 2001). The Frontier 

Sandstone is overlain by the Upper Cretaceous Cody Shale, which is laterally extensive shale as much as

2,000 ft thick. A range of marine depositional environments is represented by the Frontier Sandstone, 

including shelf, prodelta, lower shoreface, and upper shoreface. The Cody Shale is interpreted to be a 

marine hemipelagic fallout deposit, which accumulated in deeper water below the storm-wave base. The 

formations were deposited during the early Late Cretaceous, in the western part of the Western Interior 

Seaway and foreland basin (fig. 3) (Barlow and Haun, 1966; Bhattacharya and Willis, 2001; Finn and 

others, 2010). 

The Frontier Sandstone comprises two potential reservoir units for CO2 storage in the Bighorn 

Basin: (1) between 3,000- and 13,000-ft subsurface depth, Frontier Sandstone C50340111; and (2) below 

13,000-ft subsurface depth, Frontier Sandstone Deep C50340112 (fig. 10). The SAU boundaries are 

defined by the 3,000- and 13,000-ft drilling depths from well penetrations (Finn and others, 2010; IHS 

Energy Group, 2010) and faults bounding the Bighorn Basin. Fault locations were approximated from 

structural contour maps for the underlying Cloverly Formation (Finn and others, 2010). Regional 

subsurface stratigraphic correlations were used to define gross formation thickness (Finn and others, 

2010). Net porous interval thickness for the Frontier Sandstone was adapted from Fox and Dolton (1996) 

and represents an aggregate of all beds in excess of 10 ft. 

In order to assess the porosity of the Frontier Sandstone, a sandstone compaction curve was 

generated from 21 petroleum-reservoir-averaged porosity measurements distributed around the Bighorn 

Basin (Nehring Associates, Inc., 2010). In the shallow Frontier Sandstone C50340111 SAU, modal 

porosity is approximately 13 percent, but the range in reservoir-scale porosity values varies widely across 

the basin. Because no petroleum production occurs in the deepest portions of the Bighorn Basin, the 

porosity of the deepest rocks was estimated using a global compilation of Cretaceous siliciclastic rocks 

(Ehrenberg and others, 2009). The compilation suggests a modal porosity of 9 percent. Petroleum 

production data were also used to assess the permeability of the Frontier Sandstone (Nehring Associates, 

Inc., 2010). The trend of Frontier Sandstone permeability with depth suggests that the Frontier Sandstone 

Deep C50340112 SAU predominantly includes rocks with permeabilities less than 1 mD. Much of the 

Frontier Sandstone contains fresh groundwater with less than 10,000 ppm of total dissolved solids (Breit, 

2002; Wyoming Oil and Gas Conservation Commission, 2010); therefore, the viable storage area for the 

formation is restricted by U.S. Environmental Protection Agency regulations (U.S. Environmental 

Protection Agency, 2008). The minimum and central tendency buoyant trapping pore volumes were 

determined using methods described in Brennan and others (2010). Maximum buoyant trapping pore 

volume was calculated from the product of (1) the combined areas of structural reservoir traps interpreted

from a structure map of the Frontier Sandstone and reservoirs of producing fields (Nehring Associates, 

Inc., 2010), (2) the maximum net porous interval thickness, and (3) the maximum porosity (Brennan and 

others, 2010). Structural reservoir traps were defined by outlining areas of closure interpreted on a 1,000-

ft-contour-interval structural map of the top of the Frontier Sandstone. In the Frontier Sandstone Deep 

C50340112 SAU, areas of structural enclosure were also interpreted in the proximal footwalls of thrust 

faults of the Bighorn Basin (fig. 1). 
19

Figure 10. Map of the U.S. Geological Survey Storage Assessment boundary for the Frontier Sandstone and 

Frontier Sandstone Deep Storage Assessment Units in the Bighorn Basin, Wyoming and Montana. Grid cells 

(one square mile) represent counts of wells derived from ENERDEQ well database (IHS Energy Group, 2011) 

that have penetrated the reservoir formation top. Total Petroleum System boundary modified from U.S. 

Geological Survey Bighorn Basin Province Assessment Team (2010).
20

Acknowledgments

The authors thank Steven M. Cahan, Christina A. DeVera, and Celeste D. Lohr for their help in 

collecting reference material and for scanning and digitizing maps used in this review. James L. Coleman, 

Jr., helped to compile water-quality data used in this report. Paul G. Schuben and Brian Varela helped to 

compile the drilling and hydrocarbon production data for the basin. Troy A. Cook, Mahendra K. Verma, 

and Hossein Jahediesfanjani helped to interpret petroleum engineering data for the basin. We thank the 

Big Sky Carbon Sequestration Partnership for their help in supplying geologic information used in this 

review. The content and presentation of this report benefited greatly from the technical reviews of Robert 

Ryder and Ron Johnson. 

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