Geologic Framework for the National Assessment of 

Carbon Dioxide Storage Resources─Williston Basin,

Central Montana Basins, and Montana Thrust Belt Study 

Areas

By Marc L. Buursink, Matthew D. Merrill, William H. Craddock, Tina L. Roberts-Ashby, Sean T. Brennan, Madalyn S. 

Blondes, Philip A. Freeman, Steven M. Cahan, Christina A. DeVera, and Celeste D. Lohr

Chapter J 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–J

U.S. Department of the Interior

U.S. Geological Survey
ii

U.S. Department of the Interior

SALLY JEWELL, Secretary

U.S. Geological Survey

Suzette M. Kimball, Acting Director

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

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Suggested citation:

Buursink, M.L., Merrill, M.D., Craddock, W.H., Roberts-Ashby, T.L., Brennan, S.T., Blondes, M.S., Freeman, P.A., 

Cahan, S.M., DeVera, C.A., and Lohr, C.D., 2014, Geologic framework for the national assessment of carbon dioxide 

storage resources— Williston Basin, Central Montana Basins, and Montana Thrust Belt study areas, chap. J 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–J, 40 p., http://dx.doi.org/10.3133/ofr20121024J.

ISSN 2331-1258 (online)

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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.
iii

Editors’ Preface

By Peter D. Warwick and Margo D. Corum

The 2007 Energy Independence and Security Act (Public Law 110–140; U.S. Congress, 2007) 

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 storage of CO2 is one possible way to 

mitigate its effects on climate change.

The methodology 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, an external panel of experts, and members of the public. During the implementation phase of 

the assessment (from 2010 to 2012), several practical steps were added to the assessment methodology of 

Brennan and others (2010). The details of the methodology used in the assessment are described in 

Blondes and others (2013). The assessment methodology is non-economic and is intended to be used at 

regional to sub-basinal scales. 

The operational unit of the assessment is a storage assessment unit (SAU), which is 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; Blondes 

and others, 2013). 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 (EPA) (2010) defines the lower 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; Blondes and others, 2013). 

This report series contains a geologic description of each SAU identified within each report’s 

assessed basins and focuses on particular characteristics specified in the methodology that influence the 

potential CO2 storage resource. The geologic framework information contained in these reports was used 

to calculate a statistical Monte Carlo-based distribution of potential storage space in the various SAUs 

following Brennan and others (2010) and Blondes and others (2013). Assessment data, results, and 

summary can be found in the U.S. Geological Survey Geologic Carbon Dioxide Storage Resources 

Assessment Team’s (2013a,b,c) reports. 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.
iv

References Cited

Blondes, M.S., Brennan, S.T., Merrill, M.D., Buursink, M.L., Warwick, P.D., Cahan, S.M., Cook, T.A., 

Corum, M.D., Craddock, W.H., DeVera, C.A., Drake, R.M., Drew, L.J., Freeman, P.A., Lohr, C.D., 

Olea, R.A., Roberts-Ashby, T.L., Slucher, E.R., and Varela, B.A., 2013, National assessment of 

geologic carbon dioxide storage resources—Methodology implementation: U.S. Geological Survey 

Open-File Report 2013–1055, 26 p., at http://pubs.usgs.gov/of/2013/1055/.

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.

U.S. Congress, 2007, Energy Independence and Security Act of 2007—Public Law 110–140: U.S. 

Government Printing Office, 311 p., accessed October 30, 2012, at http://frwebgate.access.gpo.gov/cgibin/getdoc.cgi?dbname=110_cong_public_laws&docid=f:publ140.110.pdf.

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. 

U.S. Environmental Protection Agency, 2010, Final rule for 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 Web site, accessed October 15, 2012, at 

http://water.epa.gov/type/groundwater/uic/class6/gsregulations.cfm.

U.S. Geological Survey Geologic Carbon Dioxide Storage Resources Assessment Team, 2013a, National 

assessment of geologic carbon dioxide storage resources—Summary (ver. 1.1, September 2013): U.S. 

Geological Survey Fact Sheet 2013–3020, 6 p. (Supersedes ver. 1.0 released June 26, 2013.), at 

http://pubs.usgs.gov/fs/2013/3020/.

U.S. Geological Survey Geologic Carbon Dioxide Storage Resources Assessment Team, 2013b, National 

assessment of geologic carbon dioxide storage resources—Data (ver. 1.1, September 2013): U.S. 

Geological Survey Data Series 774, 13 p., plus 2 appendixes and 2 large tables in separate files 

(Supersedes ver. 1.0 released June 26, 2013.), at http://pubs.usgs.gov/ds/774/.

U.S. Geological Survey Geologic Carbon Dioxide Storage Resources Assessment Team, 2013c, National 

assessment of geologic carbon dioxide storage resources—Results (ver. 1.1, September 2013): U.S. 

Geological Survey Circular 1386, 41 p. (Supersedes ver. 1.0 released June 26, 2013.), at 

http://pubs.usgs.gov/circ/1386/.
v

Contents

Editors’ Preface ............................................................................................................................................................. iii

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

Conversion Factors........................................................................................................................................................vi

Abbreviations................................................................................................................................................................ vii

Report Overview............................................................................................................................................................ 1

Abstract ......................................................................................................................................................................... 3

Williston Basin Introduction............................................................................................................................................ 4

Basin Physiography ................................................................................................................................................... 4

Geologic History......................................................................................................................................................... 4

Hydrocarbon Exploration and Production................................................................................................................... 5

Storage Resource Assessment.................................................................................................................................. 6

Deadwood and Black Island Formations SAU C50310101 and Deadwood and Black Island Formations Deep SAU 

C50310102.................................................................................................................................................................... 9

Winnipegosis Formation, Interlake Formation, and Bighorn Group SAU C50310103...................................................12

Three Forks Formation and Jefferson Group SAU C50310104....................................................................................15

Kibbey Formation and Madison Group SAU C50310105 .............................................................................................18

Minnelusa Group SAU C50310106...............................................................................................................................21

Lower Swift Formation SAU C50310107 ......................................................................................................................23

Inyan Kara Group SAU C50310108..............................................................................................................................26

Newcastle Formation SAU C50310109 ........................................................................................................................29

Eagle Sandstone ..........................................................................................................................................................32

Central Montana Basins ...............................................................................................................................................33

Montana Thrust Belt .....................................................................................................................................................33

Acknowledgments ........................................................................................................................................................35

References Cited..........................................................................................................................................................35

Figures

Figure 1. Map of Williston Basin, Central Montana Basins, and Montana Thrust Belt study areas in Montana, 

North Dakota, and South Dakota................................................................................................................................... 2

Figure 2. Map showing the Williston Basin study area, North Dakota, South Dakota, and Montana, including 

major structural features................................................................................................................................................ 7

Figure 3. Generalized stratigraphic column of geologic units in the Williston Basin study area, North Dakota, 

South Dakota, and Montana .......................................................................................................................................... 8

Figure 4. Map showing the Deadwood and Black Island Formations, and Deadwood and Black Island 

Formations Deep Storage Assessment Units .............................................................................................................. 11

Figure 5. Map showing the Winnipegosis Formation, Interlake Formation, and Bighorn Group Storage 

Assessment Unit.......................................................................................................................................................... 14

Figure 6. Map showing the Three Forks Formation and Jefferson Group Storage Assessment Unit...................... 17

Figure 7. Map showing the Kibbey Formation and Madison Group Storage Assessment Unit ............................... 20

Figure 8. Map showing the Minnelusa Group Storage Assessment Unit ................................................................ 22

Figure 9. Map showing the Lower Swift Formation Storage Assessment Unit........................................................ 25

Figure 10. Map showing the Inyan Kara Group Storage Assessment Unit................................................................ 28

Figure 11. Map showing the Newcastle Formation Storage Assessment Unit .......................................................... 31
vi

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

acre 0.4047 hectare (ha)

acre 0.004047 square kilometer (km2)

square mile (mi2) 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)

liter (L) 0.2642 gallon (gal)
vii

Abbreviations

BCFG billion cubic feet of gas

CO2 carbon dioxide

EPA U.S. Environmental Protection Agency

mD millidarcy

mg/L milligrams per liter

MMBO million barrels of oil

MTB Montana Thrust Belt

NOGA national oil and gas assessment

OFR open-file report

ppm parts per million

SAU storage assessment unit

TDS total dissolved solids

USDW underground source of drinking water

USGS U.S. Geological Survey
1

Report Overview

This three-part report contains the geologic framework for three adjacent study areas, including 

the Williston Basin, multiple Central Montana basins, and the Montana Thrust Belt (MTB) (fig. 1). 

Although these study areas are in close proximity and are included in a combined geologic framework 

report, the basins were formed and filled under different circumstances, and each is investigated and 

assessed separately, when amenable.

The Williston Basin study area is situated in the northern Great Plains and extends into North 

Dakota, South Dakota, Montana and Canada. It is a relatively large structural and sedimentary 

intracratonic basin, with Cambrian through Tertiary formations, and has no topographic depression. The 

Central Montana Basins study area contains many of the same Cambrian through Tertiary age formations 

found in the sedimentary basins east of the northern Rocky Mountain Cordillera. This wide study area 

encompasses numerous smaller basins and structural uplifts. The MTB study area occupies the mostly 

mountainous terrain of western Montana, and borders Canada and Idaho. The MTB comprises the 

Cordilleran Thrust Belt located within the State of Montana, includes Paleozoic to Tertiary age 

sedimentary units, and consists of numerous thrust sheets and intrusive bodies (Perry, 1995).

As in previous chapters of the Geologic Framework for the National Assessment of Carbon 

Dioxide Storage Resources series, geologists describe their investigation of the study areas and their work 

on unique storage assessments units (SAUs), when amenable. Furthermore, to preserve a consistent 

format across report chapters, these individual SAU descriptions are treated as top-level sections. Lastly, 

each of the three study areas requires a separate introduction to develop the geologic assessment 

framework, as in prior chapters of this series.
2

Figure 1. Map of Williston Basin, Central Montana Basins, and Montana Thrust Belt study areas in Montana, North Dakota, and South Dakota that were 

evaluated for geologic carbon-dioxide storage potential. The map includes major structural features (Peterson and MacCary, 1987; Vuke and others, 2007; 

Anna and others, 2011). Study areas are modified from the respective U.S. Geological Survey national oil and gas assessment (NOGA) reports (Dyman, 

1995; Schenk and others, 2002; Anna and others, 2011).
3

Abstract

The 2007 Energy Independence and Security Act directs the U.S. Geological Survey (USGS) to 

conduct a national assessment of potential geologic storage resources for carbon dioxide (CO2). The 

methodology used by the USGS for the national CO2 assessment follows that of previous USGS work. 

This methodology is non-economic and is intended to be used at regional to sub-basinal scales.

The Williston Basin of North Dakota, South Dakota, and Montana, along with the Central 

Montana Basins and Montana Thrust Belt study areas are adjacent and share similar geologic units. In 

general, the Williston Basin study area is a wide sedimentary basin, whereas the Central Montana Basins 

study area contains sedimentary rocks along topographic highs and flat plains, and the Montana Thrust 

Belt study area is more structurally complex.

This report identifies and contains geologic descriptions of nine storage assessment units (SAUs) 

in Cambrian to Upper Cretaceous sedimentary rocks within the Williston Basin study area. The Central 

Montana Basins and Montana Thrust Belt study areas were also investigated for this report. Nevertheless, 

no SAUs in these study areas were assessed because they contained potential sources of underground 

drinking water; although sufficient geologic data were available, and suitable storage formations meeting 

our size, depth, reservoir quality, and regional seal guidelines were found. Ultimately, the report focuses 

on the characteristics, specified in the methodology, that influence the potential CO2 storage resource in 

the 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, porosity, permeability, 

groundwater quality, and structural reservoir traps, are usually provided to illustrate geologic factors 

critical to the assessment. The geologic information herein was employed, as specified in the USGS 

methodology, to calculate a probabilistic distribution of potential storage resources in each SAU with 

these assessment outputs contained in a companion results report.

Figures in this report show the study area boundaries along with the SAU extent and cell maps of 

well penetrations through sealing units into the top of the storage formations. The USGS does not 

necessarily know the location of all wells and cannot guarantee the full extent of drilling through specific 

formations in any given cell shown on the cell maps.
4

Geologic Framework for the National Assessment of 

Carbon Dioxide Storage Resources─Williston Basin, 

Central Montana Basins, and Montana Thrust Belt Study 

Areas

By Marc L. Buursink, Matthew D. Merrill, William H. Craddock, Tina L. Roberts-Ashby, Sean T. Brennan, Madalyn S. 

Blondes, Philip A. Freeman, Steven M. Cahan, Christina A. DeVera, and Celeste D. Lohr

Williston Basin Introduction

Basin Physiography

The Williston Basin is a structural and sedimentary intracratonic basin on the western shelf of the 

Paleozoic North American craton (Peterson, 1995). The middle part of North America consisted of a thin 

craton prior to the Phanerozoic Eon followed by relatively thin and discontinuous Paleozoic sediments 

deposited on the shelf of the Cordilleran orogeny (Anna and others, 2011). Interaction between two 

Archean sheer systems may have controlled the evolution of the Williston Basin by creating a depressed 

block and initiating sedimentation (Gerhard and others, 1990). Thinning of most sedimentary units from 

basin center to basin edge reflects its structural simplicity (Peterson and MacCary, 1987; Pollastro and 

others, 2008).

The elliptical basin is a mostly flat-lying, moderately dissected plain with little topographic relief,

occupies a large segment of the northern Great Plains, and extends northward into Canada (Peterson, 

1995; Pollastro and others, 2008) (figs. 1 and 2). Our Williston Basin study area is bordered to the 

southeast by the Transcontinental arch and to the north by the United States and Canada international 

border, whereas the western and southwestern borders are defined by the Bowdoin dome, Porcupine 

dome, Miles City arch, and Black Hills uplift, which are Laramide or rejuvenated Laramide structures 

(Peterson, 1995; Anna and others, 2011) (fig. 2). In Canada, the basin is defined by the Canadian Shield 

to the east and the Bow Island arch to the northwest (not shown in fig. 2).

The study area covers about 143,000 square miles across parts of North Dakota, South Dakota, 

and Montana, and contains a sedimentary rock volume of about 202,000 cubic miles (Peterson, 1995; 

Pollastro and others, 2008). Cambrian through Holocene sedimentary rocks are found in the basin, and the 

maximum thickness of Phanerozoic rocks is greater than 16,000 ft in North Dakota (Anna and others, 

2011). Except for southwestern North Dakota and adjoining parts of eastern Montana and South Dakota, 

the Williston Basin is covered by Pleistocene glacial sediments (Gerhard and others, 1990). In the main 

part of the basin, the oldest outcrops are Late Cretaceous age, whereas lower Paleozoic rocks are exposed 

in Manitoba at the edge of the Canadian Shield and in the Black Hills of South Dakota (Gerhard and 

others, 1990).

Geologic History

The Williston Basin began subsiding during the Late Cambrian or Early Ordovician and has 

continued to subside through geologic time, with the center of subsidence remaining in about the same 
5

position in northwestern North Dakota (Peterson, 1995). The stratigraphic record in the basin is relatively 

complete, though periodic erosional events have occurred throughout the basin’s history, with several 

cycles of marine transgression and regression resulting in alternating cycles of basin filling and draining 

having been recorded (Pollastro and others, 2008). Basin filling initiated on crystalline Precambrian 

basement of the Cordilleran shelf, which subsided minimally (Gerhard and others, 1990).

The relatively complete stratigraphic record shows carbonate deposition in the Paleozoic and 

siliciclastic deposition in the Mesozoic and Cenozoic. The Paleozoic carbonate rocks are stacked, cyclic, 

and vary in thickness, except for an initial Phanerozoic transgression that resulted in deposition of 

Cambrian and Lower Ordovician clastic sediments (Anna and others, 2011). The carbonate interval in the 

basin includes minor to extensive hiatuses resulting in multiple unconformities, deposition of anhydrites, 

and secondary dolomitization of limestone (Anna and others, 2011). The mostly clastic interval in the 

basin was deposited in multiple environments, including continental, shoreline, and basin settings, and it 

consists of mudstone, shale, sandstone, siltstone, and coal lithologies (Anna and others, 2011). Anna and 

others (2011, p. 3) explain that “because water depths in the basin during the Phanerozoic were relatively 

shallow, a small change in water depth resulted in substantial depositional environment and sedimentation 

changes.”

Strong folding episodes did not occur in the Williston Basin, because it is underlain by cratonic 

crust, though structural styles in the basin include both classic basement-involved structures resulting in 

anticlines and more subtle low-relief features (Gerhard and others, 1990). Deformation during the 

Phanerozoic consisted mostly of fault displacements and subsequent sedimentation (Gerhard and others, 

1990). Structural styles, sedimentation, and major faults, lineaments, and fractures in the basin are related 

to regional wrench-fault tectonics coupled with large-scale tears from two major shear systems (Pollastro 

and others, 2008). These two Archean shear systems are the Brockton-Froid-Fromberg and ColoradoWyoming shear zones (Gerhard and others, 1990; Pollastro and others, 2008). The Nesson and Cedar 

Creek anticlines (fig. 2) resulted from these tectonics and are examples of the complex petroleum trapping

in the study area. For further information on Williston Basin geologic history, the reader is referred to 

Gerhard and Anderson (1988), Peterson (1988), Hunter and Schalla (1995), and Christopher and others 

(1998).

Hydrocarbon Exploration and Production

The Williston Basin is similar to many other petroleum provinces where discovery and production 

of hydrocarbons is strongly controlled by and distributed along geologic structures (Pollastro and others, 

2008). For example the two large fault-bounded anticlinal features in the basin, the Nesson and Cedar 

Creek anticlines, have trapped and produced most of its petroleum (Gerhard and others, 1990). 

Consequently, production is confined to the northern and western parts of the study area, which outlines 

the general area where source rocks have been buried to depths sufficient to generate hydrocarbons (Anna 

and others, 2011). Most of the hydrocarbons produced from the Cedar Creek anticline and in Canada 

migrated to these areas from deeper in the basin.

Hydrocarbon exploration in the Williston Basin was infrequent prior to World War II, and few 

deep wells were successful. Shallow gas was discovered in the Upper Cretaceous Eagle Sandstone on the 

Cedar Creek anticline in southeastern Montana in 1916 (Peterson, 1995). Following World War II, major 

petroleum companies renewed their interest in the deeper prospects of the basin. This new activity lead to 

the 1951 Beaver Lodge field discovery by the Amerada Oil Company on the Nesson anticline in North 

Dakota and the Richey and Southwest Richey fields discoveries by Shell Oil Company in eastern 

Montana (Peterson, 1995). Additional discoveries followed on the Nesson anticline trend by Amerada and 

other companies, and on the Cedar Creek anticline by Shell. Early production on the Nesson anticline 

occurred mainly from Mississippian carbonate reservoirs and on the Cedar Creek anticlines from 

Ordovician and Silurian carbonate reservoirs. By the 1960s about 25 large fields of greater than 15 

MMBO (million barrels of oil) had been discovered, and later in the 1970s several important large fields 
6

and many smaller ones were discovered, particularly in the deeper Ordovician Red River Formation and 

in the Silurian and Devonian reservoirs (Peterson, 1995).

The deepest well drilled in the basin to date penetrated Precambrian crystalline rocks at 15,340 ft 

(4,677 m; location not published); the deepest oil production is from the Ordovician Red River Formation 

at 14,343 ft (4,372 m) in the Mesa No. 113 Brandvik well in west central North Dakota (Gerhard and 

others, 1990). To date, the Williston Basin continues as a prolific hydrocarbon producing province, with 

cumulative production through 2008 alone reaching 2,740 MMBO and 2,700 billion cubic feet of gas 

(BCFG) coming mostly from the Madison Group and Red River Formation reservoirs (Anna and others, 

2011). In all, hydrocarbons have been produced from Cambrian, Ordovician, Silurian, Devonian, 

Mississippian, Pennsylvania, and Triassic age reservoirs in the Williston Basin (Peterson, 1995).

Production has undergone several cycles, starting with conventional oil production with associated gas, 

and then unconventional production from the Bakken and other formations as part of the latest cycle.

Storage Resource Assessment

The USGS regional carbon dioxide (CO2) storage resource assessment of the Williston Basin 

resulted in nine SAUs. Each SAU is described in the following sections and includes a storage formation 

and regional seal pair. The SAU name is typically based on the whole stratigraphic interval or lithology 

considered for storage (fig. 3). The geographic extents of the SAUs are defined by the depth to the top of 

the storage formation and by the geologic characteristics of the reservoir and overlying seal. Geologic 

characteristics described or considered for each SAU include both the seal and reservoir thickness, 

distribution, and the reservoir quality (such as net-to-gross ratio, porosity, and permeability). Furthermore, 

we identify regional trends in groundwater quality because the U.S. Environmental Protection Agency 

(2009, 2010) stipulates that underground sources of drinking water (USDW) with a total dissolved solids 

(TDS) concentration less than 10,000 mg/L (milligrams per liter [ppm]) may not be used for CO2 storage. 

For the Williston Basin assessment, groundwater-quality data, based on TDS content, was compiled from 

multiple sources, including databases (Breit, 2002; Gulf Coast Carbon Center, 2012) and publications 

(Busby and others, 1995; Bachu and Hitchon, 1996) as described in subsequent sections. As part of the 

USGS assessment, results from a prior storage capacity investigation in the Williston Basin by Sorenson, 

Bailey, and others (2009), and by Sorensen, Smith, and others (2009) were consulted, along with data for 

the Weyburn storage and monitoring project (Saskatchewan Industry and Resources, 2004) and studies by 

the Plains CO2 Reduction (PCOR) Partnership (2012). 

This assessment was conducted following the methodology of Burruss and others (2009), Brennan 

and others (2010), and Blondes and others (2013) that prescribes the geologic model employed here, a 

probabilistic statistical analysis, and subsurface conditions favoring supercritical phase CO2. Subsurface 

conditions favoring CO2 storage at high density include relatively high basin pressures and temperatures 

(Buursink, 2012). Based on the methodologies, our storage resource was allocated between residual 

trapping (typically larger but less certain) and buoyant trapping (typically smaller but more certain). 

Residual trapping occurs at the pore scale, and buoyant trapping is analogous to stratigraphic and (or) 

structural hydrocarbon trapping. The minimum buoyant-trapping volume is determined from cumulative 

oil and gas production together with the known hydrocarbon reserve volume, whereas the most likely 

buoyant-trapping volume adds the minimum volume and the estimated volumes of undiscovered 

resources (Brennan and others, 2010). The maximum buoyant resource is determined by the assessment 

geologist. Upon completion of the assessment, the following SAUs, listed by name and number, were 

described: Deadwood and Black Island Formations C50310101; Deadwood and Black Island Formations 

Deep C50310102; Winnipegosis Formation, Interlake Formation, and Bighorn Group C50310103; Three 

Forks Formation and Jefferson Group C50310104; Kibbey Formation and Madison Group C50310105;

Minnelusa Group C50310106; Lower Swift Formation C50310107; Inyan Kara Group C50310108; and 

Newcastle Formation C50310109.
7

Figure 2. Map showing the Williston Basin study area, North Dakota, South Dakota, and Montana, including major 

structural features (modified from Peterson and MacCary, 1987; Anna and others, 2011; Coleman and Cahan, 

2012). Study area boundaries were modified from the U.S. Geological Survey national oil and gas assessment 

(NOGA) of the Williston Basin Province (Anna and others, 2011).
8

Figure 3. Generalized stratigraphic column of geologic units in the Williston Basin study area, North Dakota, South 

Dakota, and Montana (modified from Hunter and Schalla, 1995, Peterson, 1995; Murphy and others, 2009; Anna 

and others, 2011). Storage assessment units (SAUs) consist of a reservoir (red) and regional seal (blue). Wavy 

lines indicate unconformable contacts, and gray areas represent unconformities or hiatuses. In some cases, 

subdivisions of units or lesser known correlative units are not shown.
9

Deadwood and Black Island Formations SAU C50310101 and Deadwood and 

Black Island Formations Deep SAU C50310102

By Marc L. Buursink

The Deadwood and Black Island Formations SAUs consist of those intervals of the preserved 

Cambrian and Ordovician siliciclastic lithology deemed suitable as reservoirs for CO2 storage and 

occurring beneath a regionally extensive seal in the Williston Basin. These are composite SAUs 

composed of multiple storage formations including the Deadwood and Black Island Formations (fig. 3). 

The Deadwood Formation consists of sandstone and a variable sequence of shale and impure limestone at 

its type locality near Deadwood in the Black Hills, South Dakota (Fuller, 1961; Lochman-Balk and 

Wilson, 1967). Specifically, the predominant basal sandstone is brown, micaceous, and glauconitic and is 

nonconformably underlain by Precambrian quartzite, granite, or gneiss (Kline, 1942; Carlson, 1960). The 

Deadwood Formation is interpreted as a stable shelf or onlap sequence deposit extending eastward from 

the Cordilleran geosyncline (Carlson and Anderson, 1965). The Black Island Formation of the Winnipeg 

Group (fig. 3) primarily consists of clean quartz sandstone and attains a thickness of more than 160 feet 

on the Nesson anticline (Carlson and Anderson, 1965). The Black Island Formation unconformably 

overlies the Deadwood Formation, except in eastern North Dakota where it onlaps the Deadwood and 

nonconformably overlies Precambrian rocks (Carlson and Anderson, 1965). The Winnipeg Group consists 

of more than 300 feet of basal sandstone and overlying shale units, which outline the early Williston 

Basin and were deposited under shoaling conditions (Fuller, 1961; Lochman-Balk and Wilson, 1967). The 

high sandstone content of the western part of the Winnipeg Group suggests a western source (Foster, 

1972). Regionally the Middle Ordovician Icebox and Roughlock Formations, deposited during 

transgressive events when the Williston Basin was part of an extensive epicontinental sea (Carlson and 

Anderson, 1965; Blakey, 2011), overlie the Black Island Formation and function as the SAU sealing 

formations (fig. 3). The Icebox Formation consists of greenish-gray and noncalcareous shale and averages 

more than 100 feet in thickness around the center of the basin (McCoy, 1952; Carlson, 1960). The 

Roughlock Formation consists of calcareous siltstones and silty dolomite and is usually relatively thin 

(about 20 feet thick) but attains a thickness of 80 feet in southeastern North Dakota (McCoy, 1952; 

Carlson, 1960).

The SAU boundaries are defined by the depth below the surface of the uppermost storageformation top and by the extent of the regional seal. Formation-top picks, reported in a proprietary 

commercial database (IHS Energy Group, 2011), for the Black Island Formation constrain the SAU 

boundaries. The Deadwood and Black Island Formations SAU lies between 3,000 and 13,000 ft in depth 

and covers about a 41-million acre most likely area; and the Deadwood and Black Island Formations 

Deep SAU lies between 13,000 and 15,000 ft and covers about a 6-million acre most likely area (fig. 4).

The SAUs do not extend into the western Williston Basin because the regional seal is absent (Foster, 

1972), and they do not extend into Canada because this is a U.S. national assessment. These 

interpretations are supported by structure contour and isopach maps from Carlson and Anderson (1965), 

from Downey (1986), from Peterson and MacCary (1987), and from Timothy Nesheim (North Dakota 

Geological Survey, written commun., 2011), and supplemented by the Geologic Atlas of the Rocky 

Mountain Region maps and cross sections (Foster, 1972).

The Deadwood and Black Island Formations SAU gross thickness ranges from 150 to 600 ft with 

a net thickness between 90 and 360 ft, and the Deadwood and Black Island Formations Deep SAU gross 

thickness ranges from 800 to 1,100 ft with a net thickness between 440 and 600 ft. Because these are

composite SAUs, isopach maps of the individual storage formations were first scanned, geo-referenced, 
10

and digitized; and then thickness values from the maps were scaled by formation-specific net-to-gross 

ratio derived from the literature and well logs (Foster, 1972; LeFever and others, 1987; Ellingson and 

LeFever, 1995; Anna, 2011). Finally, using a geographic information system, the net-porous interval of 

the composite SAU was summed (Buursink and others, 2011).

In the Williston Basin, the Deadwood and Black Island Formations comprise a marginally 

productive hydrocarbon interval (Peterson, 1995; Anna and others, 2011) with reservoir-quality data 

reported in multiple forms. Besides published porosity and permeability estimates (Stocker, 1956; Laird, 

1964) and those reported by Timothy Nesheim (North Dakota Geological Survey, written commun., 

2011) for this interval, additional values are estimated from relevant siliciclastic analogs (Ehrenberg and 

others, 2009), and average field values are extracted from Nehring Associates, Inc. (2010). The 

Deadwood and Black Island Formations SAU porosity ranges from 6 to 16 percent and permeability 

ranges from 0.01 to 5,000 millidarcies (mD); the Deadwood and Black Island Formations Deep SAU 

porosity ranges from 3 to 6 percent and permeability ranges from 0.001 to 10 mD.

Water-quality data obtained from multiple sources, including databases (Breit, 2002; Gulf Coast 

Carbon Center, 2012) and publications (Downey and others, 1987; Busby and others, 1995; Bachu and 

Hitchon, 1996; Otton, 2006) for the study area indicated mixed freshwater and saline water areas in the 

SAUs. Storage-formation areas with groundwater below the 10,000 mg/L (ppm) total TDS limit were 

identified and discounted in the assessment. Generally, groundwater TDS values increase slightly with 

depth in the Deadwood and Black Island Formations SAU. In the Deadwood and Black Island Formations 

Deep SAU, the groundwater TDS value is above the USDW limit of 10,000 mg/L (ppm), and therefore 

the entire SAU area is available for storage. To generate a probabilistic maximum volume for buoyant 

trapping for each SAU, the size and location of mapped structural features (Peterson and MacCary, 1987; 

Gerhard and others, 1990) and NOGA play descriptions (Peterson, 1995; Anna and others, 2011) were 

used to extrapolate current hydrocarbon fields. The extrapolated Nehring Associates, Inc. (2010) average 

field size and field locations, along with the mean average SAU porosity and most likely net thickness, 

were used to estimate the maximum buoyant trapping resource.
11

Figure 4. Map showing the Deadwood and Black Island Formations, and Deadwood and Black Island Formations 

Deep Storage Assessment Units (SAUs) in the Williston Basin, North Dakota, South Dakota, and Montana. Grid 

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

2011) that have penetrated the storage-formation top. Study area boundaries were modified from the U.S. 

Geological Survey national oil and gas assessment (NOGA) (Anna and others, 2011).
12

Winnipegosis Formation, Interlake Formation, and Bighorn Group SAU 

C50310103

By Marc L. Buursink

The Winnipegosis Formation, Interlake Formation, and Bighorn Group SAU consists of those 

intervals of the preserved Ordovician, Silurian, and Devonian carbonate lithology deemed suitable as 

reservoirs for CO2 storage and occurring beneath a regionally extensive seal in the Williston Basin. This 

is a composite SAU composed of multiple storage formations including the Winnipegosis Formation, 

Interlake Formation, and the Stony Mountain and Red River Formations of the Bighorn Group. The 

Stonewall and Ashern Formations are not included, because of their low thickness and net-to-gross ratio. 

The Red River Formation (fig. 3) is the basal formation in the Ordovician Bighorn Group and 

conformably overlies the Winnipeg Group (Porter and Fuller, 1959). It consists of two intervals, including 

a lower, largely fragmented dolomitic limestone unit and an upper, cyclically deposited, evaporite-bearing 

unit, which together may be up to 800 ft thick in central North Dakota (Porter and Fuller, 1959). It is a 

major hydrocarbon producing formation in North Dakota along the Cedar Creek and Nesson anticlines

(fig. 2). The Stony Mountain Formation consists of two members, in ascending order, the Stoughton and 

Gunton Members. The Stoughton Member consists of dark-gray and brown argillaceous limestone with a 

few interbeds of calcareous shale (Murphy and others, 2009). It conformably overlies both the Red River 

Formation and underlies the Gunton Member. The Gunton Member consists of gray to brown fine 

crystalline dolostone (Murphy and others, 2009). Isopach maps for the Bighorn Group formations show a 

changing tectonic arrangement in the basin as the central part became an area of negative deposition 

(Carlson and Anderson, 1965). The Silurian Interlake Formation comprises three intervals (Carlson and 

Anderson, 1965; Gibbs, 1972). The lower Interlake Formation interval consists of gray to near-white, 

finely grained dolomite with thin clastic and evaporite beds, and is about 200 ft thick in northwest North 

Dakota; the middle Interlake Formation interval is lithologically similar to the lower interval but also 

includes vuggy dolomite and has increased porosity from coral molds, and ranges from 300 to 350 ft 

thick; the upper Interlake Formation interval consists of vuggy and fragmented dolomitic limestone, and 

is nearly 600 ft thick at the basin center (Porter and Fuller, 1959; Carlson and Anderson, 1965; Gibbs, 

1972).

The Elk Point Group contains the uppermost storage formation (Winnipegosis Formation) and the 

regional seal (Prairie Formation) for this SAU. The Winnipegosis Formation of the Elk Point Group in the 

Williston Basin is divided into three intervals, deposited while the basin was subsiding during the Middle 

Devonian. The lower interval is about 45 ft thick and consists of gray to green-gray dolomite and clastic 

rocks; the middle interval ranges from 60 to 130 ft thick and consists of dark gray calcareous shale and 

siltstone; the upper interval is about 120 ft thick and consists of gray skeletal limestone (Sandberg and 

Hammond, 1958; Baars, 1972; Ehrets and Kissling, 1987). Regionally the Middle Ordovician Prairie 

Formation of the Elk Point Group, a widespread and thick sequence of evaporites, overlies the 

Winnipegosis Formation and functions as the sealing formation (fig. 3). The Prairie Formation consists of 

a lower evaporite interval deposited during a transgressive event when the Williston Basin was drying 

out, and an upper massive evaporite interval deposited during basin subsidence and a regression event 

(Thompson and others, 1961; Blakey, 2011). The formation, which is up to 800 ft thick, consists of 

anhydrite intervals interbedded with shales and massive anhydrites, and forms an impenetrable vertical 

seal for migrating hydrocarbons according to Thompson and others (1961) and Baars (1972).

The SAU boundaries are defined by the depth below the surface of the uppermost storageformation top and by the extent of the regional seal. Formation-top picks, reported in a proprietary 
13

commercial database (IHS Energy Group, 2011), for the Winnipegosis Formation constrain the SAU 

boundary. The Winnipegosis Formation, Interlake Formation, and Bighorn Group SAU lies between 

3,000 and 13,000 ft in depth and covers about an 11-million acre most likely area (fig. 5). The SAU does 

not extend into the southeastern Williston Basin because the regional seal is absent and does not extend 

into Canada because this is a U.S. national assessment. These interpretations are supported by structure 

contour and isopach maps from Sandberg (1961), Thompson and others (1961), Carlson and Anderson 

(1965), and Downey (1986), and are supplemented by the Geologic Atlas of the Rocky Mountain Region 

maps and cross sections (Baars, 1972).

The Winnipegosis Formation, Interlake Formation, and Bighorn Group SAU gross thickness 

ranges from 1,600 to 2,200 ft with a net thickness between 760 and 1,100 ft. Because these are composite 

SAUs, isopach maps of the individual storage formations were first scanned, geo-referenced, and 

digitized; and then thickness values from the maps were scaled by formation-specific net-to-gross ratio 

derived from the literature and well logs (Porter and Fuller, 1959; Foster, 1972; Gibbs, 1972; Baars, 1972; 

Ehrets and Kissling, 1987; Megathan, 1987; Anna, 2011). Finally, using a geographic information system, 

the net-porous interval of the composite SAU was summed (Buursink and others, 2011).

In the Williston Basin, the Winnipegosis Formation, Interlake Formation, and Bighorn Group 

comprise a productive hydrocarbon interval (Peterson, 1995; Anna and others, 2011) with reservoirquality data reported in multiple forms. Besides published porosity and permeability estimates (Porter and 

Fuller, 1959; Inden and others, 1998; LeFever, 2006) for this interval, additional values are estimated 

from relevant carbonate analogs (Schmoker and others, 1985; Ehrenberg and others, 2006; Ehrenberg and 

others, 2009), and average field values are extracted from Nehring Associates, Inc. (2010). The reservoir 

portion of the Winnipegosis Formation consists of pinnacle reefs and this affects our net-to-gross ratio, 

porosity, and permeability estimates for the SAU (Fischer and Burke, 1987). The Winnipegosis 

Formation, Interlake Formation, and Bighorn Group SAU porosity ranges from 6 to 16 percent and 

permeability ranges from 0.01 to 200 mD.

Water-quality data obtained from multiple databases (Breit, 2002; Gulf Coast Carbon Center, 

2012) and publications (Downey and others, 1987; Busby and others, 1995; Bachu and Hitchon, 1996; 

Otton, 2006) for the study area indicated predominantly saline waters in the SAU. No assessed areas with 

groundwater below the 10,000 mg/L (ppm) total TDS limit were identified, and therefore the entire SAU 

area is available for storage. The presence of the overlying evaporite seal supports this interpretation. To 

generate a probabilistic maximum volume for buoyant trapping for each SAU, the size and location of 

mapped structural features (Peterson and MacCary, 1987; Gerhard and others, 1990) and NOGA play 

descriptions (Peterson, 1995; Anna and others, 2011) were used to estimate hydrocarbon field

distribution. The extrapolated Nehring Associates, Inc. (2010) average field size and field locations, along 

with the mean average SAU porosity and most likely net thickness, were used to estimate the maximum 

buoyant trapping resource.
14

Figure 5. Map showing the Winnipegosis Formation, Interlake Formation, and Bighorn Group Storage Assessment 

Unit (SAU) in the Williston Basin, North Dakota, South Dakota, and Montana. Grid cells (one square mile) 

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

the storage-formation top. Study area boundaries were modified from the U.S. Geological Survey national oil and 

gas assessment (NOGA) (Anna and others, 2011).
15

Three Forks Formation and Jefferson Group SAU C50310104

By Tina L. Roberts-Ashby

The Upper Devonian Jefferson Group and Three Forks Formation of the Williston Basin form a 

composite CO2 storage reservoir, predominantly composed of carbonate-evaporite sequences, that 

stretches across the northeastern corner of Montana and the northwestern corner of North Dakota (figs. 2

and 6). The Jefferson Group consists of the Duperow Formation and the Birdbear Formation, from oldest 

to youngest (fig. 3). The Duperow Formation is a relatively thick, carbonate-evaporite sequence of 

limestone, dolostone, dolomitized limestone, and anhydrite that is interbedded and interfingered with thin 

layers of shale, siltstone, and argillaceous dolostone with some sand grains (Sandberg, 1961; Ballard, 

1963; Macke, 1993; Peterson, 1995). The formation has six shoaling-upward sedimentary cycles, and was 

deposited in a shallow-water marine, inner shelf, lime-mud sabkha environment (Macke, 1993). The 

Birdbear Formation (also called the Nisku Formation) conformably overlies the Duperow Formation 

within the Jefferson Group, and was deposited at the end of a single major sedimentary cycle (Sandberg, 

1961). The lower Birdbear Formation consists of a thick-bedded, porous, and finely crystalline dolostone 

and limestone, whereas the upper formation consistsof anhydritic dolostone, thin anhydrite-dolomite 

sequences, or a massive anhydrite bed, particularly in the upper 10 to 20 ft of the formation (Sandberg, 

1961; Ballard, 1963; Macke, 1993).

The Three Forks Formation abruptly, and typically conformably, overlies the Birdbear Formation 

and was deposited during a final Devonian sea-level regression (Macke, 1993). The formation contains 

marine and nonmarine sediments, and generally consists of dolomitic-siltstone, shale, and carbonate 

rocks, with anhydritic sections in its lower portion (Sandberg, 1961; Ballard, 1963; Macke, 1993; 

Gaswirth and others, 2013). The Three Forks Formation can be divided into three members, from oldest 

to youngest: (1) the Logan Gulch Member, which is a brecciated limestone and shale with some 

dolomitization; (2) the Trident Member, which consists of shale, calcareous and fossiliferous claystone, 

and carbonates; and (3) the Sappington Member, which is a clastic unit (Macke, 1993). The Upper 

Devonian and Lower Mississippian Bakken Formation (fig. 3) unconformably overlies the Three Forks 

Formation, and forms the regional sealing unit for the Upper Devonian CO2 storage reservoir. The 

Bakken Formation was deposited in a restricted-marine environment, and is divided into two organic-rich, 

black shale units that are separated by a layer that is predominantly calcareous siltstone, but that may also 

contain sandstone or dolostone (Sandberg, 1961; Ballard, 1963; Macke, 1993; Schmoker, 1996). 

Although the shales of the Bakken Formation form a thick (more than 100 ft; Downey, 1986), regional 

seal within the area of the Upper Devonian storage reservoir of the Williston Basin, it also serves as a 

major oil and gas producer, and therefore it has been fractured and has abundant well-penetrations, which 

could affect the integrity of the seal in some locations. 

The Three Forks Formation and Jefferson Group SAU C50310104 is identified in the Devonian 

rocks of the Williston Basin between 3,000 and 13,000 ft subsurface depth. The Three Forks Formation 

and Jefferson Group SAU encompasses an area of about 6,175,000 acres (with an error of plus or minus 

10 percent) (fig. 6). The majority of the petroleum production within the area of the SAU is from 

dolostones and dolomitized limestones of the carbonate-evaporite cycles within the Duperow and 

Birdbear Formations; however, additional production also occurs from carbonate reservoirs within the 

Three Forks Formation (Peterson, 1995; Anna and others, 2008; Nehring Associates, Inc., 2010).

The boundary of the Three Forks Formation and Jefferson Group SAU is defined by the 3,000-ft 

reservoir top-depths taken from 4,263 well penetrations (IHS Energy Group, 2010; Nehring Associates, 

Inc., 2010); the United States and Canada international border; and the lateral extent of the Bakken 
16

Formation seal where it is at least 75 ft thick, as determined from differencing formation tops from 2,882 

wells (IHS Energy Group, 2010) and from a published isopach map (Downey, 1986). The rocks within 

the SAU deepen and thicken toward the center of the basin, and on average range from 700 to 825 ft thick 

with a most likely thickness of 750 ft, as determined from differencing formation tops from 2,152 well 

penetrations located throughout the SAU (IHS Energy Group, 2010). 

The carbonates within many of the carbonate-evaporite sequences of the SAU commonly contain 

reefoid or mound buildups that have been largely dolomitized and contain abundant porosity (Peterson, 

1995). Average porosity in the porous intervals of the Three Forks Formation and Jefferson Group SAU is 

10 to 17 percent, with a most likely value of 12 percent (Nehring Associates, Inc., 2010). Net porous 

interval thickness was estimated by multiplying the total storage formation thickness by an average net-togross thickness ratio of 0.35, which was interpreted from geophysical logs. This resulted in an estimated 

average net porous interval thickness that ranges from 245 to 290 ft, with a most likely value of 260 ft for 

the Three Forks Formation and Jefferson Group SAU. Average permeability in the SAU is 0.5 to 100 mD, 

with a most likely value of 30 mD (Nehring Associates, Inc., 2010). 

Previous investigations of Devonian rocks in the Williston Basin report TDS values within 

formation waters of these rocks that on average range from 19,000 to 120,000 mg/L (ppm), but may be

more than 400,000 mg/L (ppm) in the area of the SAU (Barnes, 1952; Downey, 1986). Additionally, 

wells sampled within the confines of the SAU indicate formation waters have TDS values that are saline 

and over 400,000 mg/L (ppm) in some locations (Breit, 2002), all of which exceed the 10,000 mg/L 

(ppm) lower regulatory limit (U.S. Environmental Protection Agency, 2009). However, one well out of 

hundreds of wells that were sampled within the SAU showed a TDS value slightly below 10,000 mg/L 

(ppm) (Breit, 2002). Based upon the background literature (Barnes, 1952; Downey, 1986), and 

considering this suspected freshwater-well is surrounded by wells showing TDS values well above 10,000 

mg/L (ppm), its validity is questionable; therefore, it is most likely that 100 percent of the Three Forks 

Formation and Jefferson Group SAU is potentially suitable for storage of CO2, with a minimum 

likelihood of 98 percent and a maximum likelihood of 100 percent.

Folds and closures associated with carbonate-bank buildups that are sealed by anhydrites or 

overlying shales are typical trapping mechanisms within the Upper Devonian rocks that compose the 

SAU (Peterson, 1995). In order to calculate the maximum buoyant pore volume within structural and 

stratigraphic closures for the Three Forks Formation and Jefferson Group C50310104 SAU, the known 

closure areas from the highly productive regions located throughout the SAU were extrapolated and 

multiplied by the upper estimates on regional reservoir thickness and porosity. The known closure areas 

were calculated by summing petroleum reservoir areas for the SAU (Nehring Associates, Inc., 2010). An 

assumption underlying this calculation is that there is potential for additional uncharged or undiscovered 

structural and stratigraphic closures outside of regions of historical hydrocarbon production.
17

Figure 6. Map showing the Three Forks Formation and Jefferson Group Storage Assessment Unit (SAU) in the 

Williston Basin, North Dakota, South Dakota, and Montana. Grid cells (one square mile) represent counts of wells 

derived from ENERDEQ well database (IHS Energy Group, 2011) that have penetrated the storage-formation 

top. Study area boundaries were modified from the U.S. Geological Survey national oil and gas assessment 

(NOGA) (Anna and others, 2011).
18

Kibbey Formation and Madison Group SAU C50310105

By Tina L. Roberts-Ashby

The Mississippian Madison Group and Kibbey Formation of the Williston Basin form a composite 

CO2 storage reservoir, predominantly composed of carbonate-evaporite sequences, that stretches across 

eastern Montana, western North Dakota, and the northwestern corner of South Dakota (figs. 2 and 7). The 

Madison Group contains interbedded carbonates and evaporites, and was deposited in a warm, shallowwater marine environment (Sloss, 1952). The group is divided into three formations, from oldest to 

youngest: (1) the Lodgepole Limestone, which consists of a thin sand and basal shale interval that is 

overlain by cherty, argillaceous, and crinoid-fragmental limestone; (2) the Mission Canyon Limestone, a 

predominantly limestone, sometimes argillaceous, unit with increased dolomitization toward the upper

section that contains relatively thick, fossiliferous, and highly porous intervals throughout; and (3) the 

Charles Formation, a predominantly anhydrite unit with a porous basal limestone that contains some 

dolostone, limestone, salt, and shales throughout (Barnes, 1952; Sloss, 1952). The Kibbey Formation of 

the Big Snowy Group is generally disconformable, but in some locations is transitional with the 

underlying Madison Group, and is composed of lenticular, quartzitic sands and red shales, with some 

carbonates and evaporites (Barnes, 1952; Sloss, 1952). The remainder of the Big Snowy Group consists 

of the Otter Formation and Heath Formation (fig. 3), both of which form a composite regional seal for the 

underlying Mississippian CO2 storage reservoir. The Otter Formation consists predominantly of green 

shales with some oolitic limestone, whereas the Heath Formation is a black, carbonaceous shale with thin 

layers of limestone and sand, although these formations are generally undifferentiated in the subsurface 

(Barnes, 1952; Sloss, 1952). In the area of the storage reservoir, this composite Otter and Heath 

Formations seal is typically 100 to 200 ft thick, but may be more than 500 ft thick in some regions.

One CO2 storage reservoir, the Kibbey Formation and Madison Group C50310105 SAU, is 

identified in the Mississippian rocks of the Williston Basin, and occurs between 3,000- and 13,000-ft 

subsurface depth. The Kibbey Formation and Madison Group SAU encompasses an area of about 

33,043,000 acres (with an error of plus or minus 10 percent) (fig. 7). The majority of the petroleum 

production within the area of the SAU is from the Madison Group, specifically the Mission Canyon 

Limestone and Charles Formation, which is the largest oil reserve discovered to date in the basin (Barnes, 

1952; Peterson, 1995; Nehring Associates, Inc., 2010).

The boundary of the Kibbey Formation and Madison Group SAU is defined by the 3,000-ft 

reservoir top-depths taken from 11,144 well penetrations (IHS Energy Group, 2010; Nehring Associates, 

Inc., 2010); the United States and Canada international border; and the lateral extent of the Otter and 

Heath Formations seal where it is at least 50 ft thick, as determined from differencing formation tops from 

2,980 wells (IHS Energy Group, 2010) and from published cross sections (Barnes, 1952; Sloss, 1952). 

The rocks within the SAU deepen and thicken toward the center of the basin and on average are 1,500 to 

2,000 ft thick, with a most likely thickness of 1,800 ft, as determined from differencing formation tops 

from 3,204 well penetrations located throughout the SAU (IHS Energy Group, 2010). 

Porosity and reservoir-rock quality are best in the Mission Canyon Limestone and Charles 

Formation of the Madison Group, and typically consist of dolomitized carbonate algal-oolitic, crinoidal, 

or bioclastic banks, as well as limestones with abundant vuggy or fracture porosity (Barnes, 1952; 

Peterson, 1995). Average porosity in the porous intervals of the Kibbey Formation and Madison Group 

SAU is 7 to 16 percent, with a most likely value of 10 percent (Nehring Associates, Inc., 2010). Net-togross was interpreted from geophysical logs and porous interval contour maps (Downey, 1984, 1986), and 

resulted in an average net porous interval thickness that ranges from 150 to 450 ft, with a most likely 
19

value of 300 ft for the Kibbey Formation and Madison Group SAU. Average permeability in the SAU is 

0.01 to 1,800 mD, with a most likely value of 4 mD (Nehring Associates, Inc., 2010). 

Published literature contains little water-quality data for the Kibbey Formation; however, previous 

investigations of the Madison Group, which makes up the majority of the SAU in the Williston Basin,

report that TDS values within formation waters of these rocks range from 3,200 on average to greater than 

300,000 mg/L (ppm) (Barnes, 1952; Downey, 1986). Wells sampled within the confines of the SAU 

indicate formation waters within the Kibbey Formation and rocks of the Madison Group are both fresh 

(TDS less than 10,000 mg/L [ppm]) and saline (TDS greater than 10,000 mg/L [ppm]) (Breit, 2002). 

Therefore, most likely 70 percent of the area of the Kibbey Formation and Madison Group SAU is 

considered potentially suitable for storage of CO2, with a minimum likelihood of 60 percent and a 

maximum likelihood of 75 percent.

Folds and closures associated with carbonate-bank or mound buildups that are sealed by 

anhydrites, salts, or overlying shales are the predominant trapping mechanisms within the Kibbey 

Formation and Madison Group SAU, although lateral facies changes also contribute to trapping within 

these rocks (Peterson, 1995). In order to calculate the maximum buoyant pore volume within structural 

and stratigraphic closures for the Kibbey Formation and Madison Group SAU, the known closure areas 

from the highly productive regions located throughout the SAU were extrapolated and combined with 

upper bounds on regional reservoir thickness and porosity. The known closure areas were calculated by 

summing petroleum reservoir areas for the SAU (Nehring Associates, Inc., 2010). An assumption 

underlying this calculation is that there is potential for additional uncharged or undiscovered structural 

and stratigraphic closures outside of regions of historical hydrocarbon production.
20

Figure 7. Map showing the Kibbey Formation and Madison Group Storage Assessment Unit (SAU) in the Williston 

Basin, North Dakota, South Dakota, and Montana. Grid cells (one square mile) represent counts of wells derived 

from ENERDEQ well database (IHS Energy Group, 2011) that have penetrated the storage-formation top. Study 

area boundaries were modified from the U.S. Geological Survey national oil and gas assessment (NOGA) (Anna 

and others, 2011).
21

Minnelusa Group SAU C50310106

By Sean T. Brennan

The Minnelusa Group in the Williston Basin comprises the Pennsylvanian Tyler and Amsden 

Formations and the Permian Broom Creek Formation (figs. 2 and 3). The Tyler Formation is a mixed 

sandstone, dolomite, and evaporite formation deposited in shallow, restricted environments (Murphy and 

others, 2009). The Tyler Formation is overlain by the shallow marine Amsden Formation, which in the 

Williston Basin is predominantly dolomite, with interbedded shale and sandstone (Murphy and others, 

2009). At the base of the Amsden Formation is the Alaska Bench Member, which is primarily shaleymicritic limestone. The Amsden Formation is overlain by the shallow marine Broom Creek Formation, 

which is predominantly sandstone, with interbedded dolomite, anhydrite, shale, and chert (Murphy and 

others, 2009). The Minnelusa Group is overlain by the restricted marine Opeche Shale, which in the 

Williston Basin is shale to mudstone, with gypsum, anhydrite, and thick halite deposits up to 200 feet 

thick in the central basin; the formation averages 200 feet in thickness in the Williston Basin (Benison and 

Goldstein, 2000; Murphy and others, 2009). The Opeche Shale forms the sealing unit for the Minnelusa 

Group SAU.

The Minnelusa Group SAU boundaries were defined based on the thickness of the Opeche Shale 

sealing unit. Where the Opeche Shale was greater than 100 feet thick on average, according to available 

data (Sorensen, Smith, and others, 2009; IHS Energy Group, 2011), it was considered thick enough to be 

an adequate regional seal for an SAU. Areas where the measured thickness of the Opeche was less than 

100 feet on average were excluded from the SAU. The Minnelusa Group SAU is 17,514,000 acres (fig. 8) 

and is located predominantly within North Dakota. The depth of the top of the Minnelusa is between 

3,950 and 8,400 feet, with an average value of 7,300 feet (IHS Energy Group, 2011). The average 

thickness of the Minnelusa Group is based on available formation tops data (IHS Energy Group, 2011), 

which indicated that it is between 400 and 700 feet thick, with an average value of 550 feet. Water-quality 

data (Breit, 2002) show that all but one analysis of waters from the Minnelusa Group are above 10,000 

mg/L (ppm) TDS; therefore, the area of the SAU that is available for storage according to salinity 

requirements ranges between 95 and 100 percent, with a most likely value of 100 percent. The range of 

net thickness value for the Minnelusa Group is based on extrapolation of information available on isopach 

maps of siliciclastic ratio, sand/shale percent, and net thickness (Ballard, 1963; Ziebarth, 1972). These 

maps indicate that the net thickness of the Minnelusa Group ranges from 70 to 130 feet, with a most likely 

value of 100 feet. 

The petrophysical data for the Minnelusa Group in the Williston Basin is sparse, and is combined 

with data from nearby Rocky Mountain basins that serve as analogs (Nehring Associates, Inc., 2010). The 

range of porosity values used is a best approximation based on the disparate types of storage formation 

rock types, and averages about 10 percent. The permeability data indicate that most of the rocks within 

the Minnelusa Group are Class 2 (between 1 mD and 1 Darcy) based on the methodology by Brennan and 

others (2010).

The buoyant storage resource values are based on the produced hydrocarbon volume, corrected for 

the formation volume factor, which provides the minimum value for the range. This minimum value plus 

the undiscovered hydrocarbon volume as determined by the USGS NOGA for the Williston Basin 

Province (Anna, 2011) is the most likely value. The maximum value of the buoyant storage resource is 

based on identifying potential trapping structures within the Minnelusa Group based on available 

structural contour maps (Sorensen, Bailey, and others, 2009) and those derived from available data (IHS

Energy Group, 2011).
22

Figure 8. Map showing the Minnelusa Group Storage Assessment Unit (SAU) in the Williston Basin, North Dakota, 

South Dakota, and Montana. Grid cells (one square mile) represent counts of wells derived from ENERDEQ well 

database (IHS Energy Group, 2011) that have penetrated the storage-formation top. Study area boundaries were 

modified from the U.S. Geological Survey national oil and gas assessment (NOGA) (Anna and others, 2011).
23

Lower Swift Formation SAU C50310107

By William H. Craddock

The Swift Formation of Williston Basin was deposited during the Oxfordian and Kimmeridgian 

Ages of the Jurassic Period (Peterson, 1957; Turner and Peterson, 2004) in a shallow seaway related to 

flexural subsidence along the eastern flank of the Nevadan orogenic system (for example see DeCelles, 

2004; Turner and Peterson, 2004). At its type locality in northwestern Montana, the formation is 

characterized by a glauconitic sandstone member that is bounded above and below by more shale-prone 

members (for example see Cobban, 1945; Francis, 1957). In general, the proportion and thickness of 

sandstone strata decrease to the east across Williston Basin (for example see Peterson, 1957), perhaps 

reflecting an increasing spatial separation from sediment sources in the Nevadan orogenic highlands to the 

west. In the vicinity of Montana and North Dakota, the overlying Morrison Formation (fig. 3) consists of 

varicolored shales deposited in a nonmarine setting (Peterson, 1957; Turner and Peterson, 2004). Analysis 

of regional networks of geophysical logs indicates that the Morrison is more shale-prone in Williston 

Basin than it is in nearby regions of the northern Rocky Mountains (North Dakota Geological Survey, 

written commun., 2011). In fact, locally in Williston Basin, the Morrison Formation appears to comprise 

several hundred feet of shale with very few sandstone interbeds, such that it may serve as a robust top seal 

for the underlying Swift Formation. In light of the fact that the upper Swift Formation is mostly shale, and

that in some studies, the Morrison Formation top seal is undifferentiated from the Swift Formation 

altogether (Gerhard and others, 1990), we name our SAU the Lower Swift Formation SAU for the 

coarser-grained intervals that could serve as reservoirs for CO2.

The SAU boundaries were defined using a combination of overburden thickness maps and isopach 

maps for the overlying Morrison Formation, derived from a database of borehole stratigraphic information 

with more than 3,000 penetrations of the Swift Formation, evenly distributed across Williston Basin (IHS 

Energy Group, 2010) (figs. 1 and 9). The 3,000-ft overburden contour defines the outer perimeter of the 

SAU area to the south and east. Additionally, the western SAU boundary is defined by the limit of the 

Williston Basin Province (Anna and others, 2008), and the northern SAU boundary is defined by the 

international border with Canada. We also limited our SAU area to regions with top seal in excess of 50 

feet, such that some areas near the western SAU limit are not considered to be prospective for CO2

storage (fig. 9). The regional top seal isopach map was generated from a stratigraphic database similar to 

the one described above, with more than 900 thickness measurements distributed across Williston Basin 

(IHS Energy Group, 2010). Generally, the Morrison Formation exceeds 100 ft in thickness (more than 95

percent of the SAU area). The SAU covers an area of 46,694,000 acres (with an error of plus or minus 10 

percent), and the top of the reservoir interval extends from subsurface depths of 3,000 to approximately 

7,000 ft.

The gross thickness of the Swift Formation was defined using the database of borehole 

stratigraphic information described above (IHS Energy Group, 2010). Swift Formation tops were 

differenced from the underlying Rierdon Formation at approximately 2,600 sites where both units were 

identified in a single borehole. An isopach map derived from these data suggests that regionally, the 

average gross thickness of the unit is between 300 and 400 feet. In order to evaluate the net thickness of 

porous sandstone in the Swift Formation, we analyzed gamma ray and resistivity logs from a transect of 

seven boreholes that extends from the north-central portion of the SAU area to the northeastern SAU 

boundary (North Dakota Geological Survey, written commun., 2011). This analysis suggests that net 

sandstone thicknesses are, on average, about 50 to 90 feet throughout the SAU. This range is consistent 
24

with a geophysical log-based analysis of net sand thickness in approximately 1,000 boreholes in the Swift 

Formation in eastern Montana, including the western part of Williston Basin (Feltis and others, 1981). 

Regional maps showing TDS concentration as well as TDS concentration measurements at 

individual wells indicate that the Swift Formation contains formation waters with TDS concentrations that 

range from less than 1,000 mg/L (ppm) to several tens of thousands mg/L (ppm) (Whitehead, 1996, and 

references therein; Breit, 2002). Given that areas with formation waters exhibiting TDS concentrations 

less than 10,000 mg/L (ppm) will generally be restricted for CO2 injection (U.S. Environmental Protection 

Agency, 2009, 2010), we estimate that perhaps 30 percent of the SAU contains formation waters that have 

acceptably high salinity for CO2 injection.

We quantified the porosity and permeability of the Swift Formation on a regional scale using a 

combination of data from petroleum fields (Nehring Associates, Inc., 2010) and geophysical logs from 

boreholes (North Dakota Geological Survey, written commun., 2011). There is little petroleum production 

from the Swift Formation in Williston Basin, and in order to compensate for this, we integrated data from 

central Montana, including the Sweetgrass arch and Powder River Basin. Analysis of 23 petroleum 

reservoir porosity measurements, as analogs, from Middle and Upper Jurassic rocks in these nearby 

basins suggests that on a basin scale, the porosity of the Swift Formation is between 13 and 21 percent. 

This range is consistent with foot by foot measurements of Swift Formation porosity, based on 

interpretation of geophysical logs, in a few wells scattered around the Williston Basin region (North 

Dakota Geological Survey, written commun., 2011) and with detailed analysis of the porosity of 

carbonate sands near the base of the Swift Formation in northeastern North Dakota (Schmoker and Hester, 

1983). Six petroleum field average permeabilities range from 0.1 to 500 mD (Nehring Associates, Inc., 

2010). The average permeability for Swift Formation reservoirs appears to be about 100 mD.

There are no major petroleum fields producing from the Swift Formation. This makes the task of 

assessing the volume of pore space enclosed within structural and stratigraphic traps difficult. We suspect 

that the reason that the Swift Formation is not a major petroleum producer is related to charge (potential 

source rocks are thermally immature) rather than to trap or seal quality (petroleum systems terminology 

from Magoon and Dow, 1994). Nevertheless, we assign a lower limit on enclosed pore space at zero, in 

the absence of evidence for robust traps and seals that oil and gas accumulations provide. In order to 

estimate the most likely and maximum enclosed pore space, we sought information from the Muddy 

Sandstone, a stratigraphically similar, but hydrocarbon-saturated and well-explored unit in neighboring 

Powder River Basin. Based on information from a commercial petroleum production database, we 

estimate that on average, petroleum reservoirs in the Muddy Sandstone in the Powder River Basin (and by 

analogy, our SAU) have an area of about 2,500 acres (Nehring Associates, Inc., 2010). Based on the 

distribution of Muddy Sandstone fields across Powder River Basin, we estimate that there is most likely 

about 100, but no more than 300 similar traps in Williston Basin. We estimate that about 50 percent of 

these traps are filled with formation waters that are too fresh for CO2 injection (U.S. Environmental 

Protection Agency, 2009, 2010), and we combine these areas with most likely and maximum bounds on 

formation thickness and porosity to estimate the volume of enclosed pore space within the SAU.
25

Figure 9. Map showing the Lower Swift Formation Storage Assessment Unit (SAU) in the Williston Basin, North 

Dakota, South Dakota, and Montana. Grid cells (one square mile) represent counts of wells derived from 

ENERDEQ well database (IHS Energy Group, 2011) that have penetrated the storage-formation top. Study area 

boundaries were modified from the U.S. Geological Survey national oil and gas assessment (NOGA) (Anna and 

others, 2011).
26

Inyan Kara Group SAU C50310108

By William H. Craddock

The Inyan Kara Group was deposited in the earliest Cretaceous in the Sevier foreland basin, and it 

unconformably overlies the Jurassic Morrison Formation (Hansen, 1955; DeCelles, 2004) (fig. 3). The 

Inyan Kara Group includes three formations, which from oldest to youngest are the Lakota Sandstone, the 

Fuson Shale, and the Fall River Sandstone. The Lakota Sandstone and Fuson Shale are marine sandstones 

and shales, respectively (Hansen, 1955). The Fall River Sandstone, also known as the Dakota Formation

outside of the Black Hills area, is a regionally extensive sandstone that was deposited in both shallow 

marine (southern Williston) and fluvio-deltaic settings (northern Williston) (Russell 1927; Gries, 1954; 

Hansen, 1955). The Inyan Kara Group is conformably overlain by the Skull Creek Shale, which is an 

open marine shale, also deposited in the Sevier foreland basin (Hansen, 1955; Mallory, 1972; DeCelles, 

2004). A stratigraphic database, containing approximately 2,400 borehole penetrations of the Skull Creek 

Shale, indicates that the shale is hundreds of feet thick and extensive across all of Williston Basin (IHS 

Energy Group, 2010). Subsurface correlations of geophysical logs from several boreholes indicate that the 

formation is homogeneous shale and corroborate the previous evidence for the large lateral extent of the 

unit (Hansen, 1955). The thickness and lithologic character of the Skull Creek Shale suggest that it should 

serve as a robust top seal for prospective reservoirs in the coarse-grained intervals of the Inyan Kara 

Group (see Magoon and Dow, 1994; Brennan and others, 2010) (fig. 3). Analysis of formation tops 

suggest that the Fuson Shale may also serve as a robust, internal seal for lower Inyan Kara Group 

reservoirs because it is in excess of 100 feet thick across northern Williston Basin. However, in southern 

Williston Basin, the Fuson Shale thins to a few tens of feet, such that it may not be considered a regional 

seal for the purpose of this assessment (see Brennan and others, 2010; Blondes and others, 2013).

The SAU area for the Inyan Kara Group was defined on the basis of the 3,000-ft overburden 

contour (see Brennan and others, 2010) (fig. 10). An overburden contour map was generated from a 

stratigraphic database containing more than 16,000 borehole penetrations in the Inyan Kara Group with 

data widely distributed across the entire study area (IHS Energy Group, 2010). Additionally, the western 

SAU boundary is defined by the limit of the Williston Basin Province (Anna and others, 2008), and the 

northern SAU boundary is defined by the international border with Canada. The SAU covers an area of 

about 44,326,000 acres (with an error of plus or minus 10 percent) and extends from subsurface depths of

3,000 to approximately 6,500 ft.

The gross thickness of the Inyan Kara Group was defined using the aforementioned stratigraphic 

database (IHS Energy Group, 2010). The stratigraphic thickness was determined in boreholes in which 

both the Inyan Kara Group and the immediately underlying formation were identified, and isopach maps 

were derived from the resulting data. Each of the individual isopach maps was constrained by tens of

hundreds of evenly distributed measurements. Across Williston Basin, the Inyan Kara Group ranges from 

200 to 300 ft in thickness. In order to evaluate the net thickness of porous sandstone in the Inyan Kara 

Group, we analyzed gamma ray and resistivity logs from a network of 12 boreholes distributed across the 

central portion of the SAU (Hansen, 1955). This analysis suggests that net sandstone thicknesses are, on 

average, about 110 to 150 ft across the SAU. This range is consistent with a geophysical log-based 

analysis of net sand thickness in approximately 1,000 boreholes in the Inyan Kara Group in eastern 

Montana, including the western part of Williston Basin (Feltis and others, 1981).

Regional maps showing the TDS concentration contours along with measurements at individual 

wells indicate that the Inyan Kara Group contains formation waters with TDS concentrations from less 

than 1,000 mg/L (ppm) to several tens of thousands mg/L (ppm) (Whitehead, 1996, and references 
27

therein; Breit, 2002). Given that areas with formation waters exhibiting concentrations of TDS less than 

10,000 mg/L (ppm) will generally be restricted for CO2 injection (U.S. Environmental Protection Agency, 

2009, 2010), we estimate that perhaps 25 percent of the SAU contains formation waters that have 

acceptably high salinity for CO2 injection and disposal.

We quantified the porosity and permeability of the Inyan Kara on a regional scale using a 

combination of data from petroleum fields (Nehring Associates, Inc., 2010) and geophysical logs from 

boreholes (North Dakota Geological Survey, written commun., 2011). There is little petroleum production 

from the Inyan Kara Group in Williston Basin, and in order to compensate for this, we integrated data 

from central Montana, including the Sweetgrass arch, and Powder River Basin. This analysis includes 

about 100 porosity measurements for Inyan Kara Group reservoirs from the nearby basins and suggests 

that on a basin scale, the average porosity of the Swift Formation is between 14 and 22 percent. This 

range is consistent with foot by foot measurements of Inyan Kara Group porosity, based on interpretation 

of geophysical logs, in a few wells scattered around the Williston Basin region (North Dakota Geological 

Survey, written commun., 2011). For a similar number of petroleum reservoir permeability measurements 

from the nearby basins, values range from 0.01 to 2,000 mD (Nehring Associates, Inc., 2010). The 

average permeability of the Inyan Kara Group appears to be about 100 mD.

There are no major petroleum fields producing from the Inyan Kara Group, and we estimate the 

minimum, most likely, and maximum enclosed pore volume (analogous to structural and [or] stratigraphic 

hydrocarbon traps) following the methods described for the Lower Swift Formation SAU.
28

Figure 10. Map showing the Inyan Kara Group Storage Assessment Unit (SAU) in the Williston Basin, North Dakota, 

South Dakota, and Montana. Grid cells (one square mile) represent counts of wells derived from ENERDEQ well 

database (IHS Energy Group, 2011) that have penetrated the storage-formation top. Study area boundaries were 

modified from the U.S. Geological Survey national oil and gas assessment (NOGA) (Anna and others, 2011).
29

Newcastle Formation SAU C50310109

By William H. Craddock

The Lower Cretaceous Newcastle Formation was deposited in a shallow marine setting in the 

Sevier foreland basin, consists primarily of sandstone, and now extends across much of the northern 

Rocky Mountains, including Williston Basin (for example see Hansen, 1955; Reishus, 1968; Mallory, 

1972; DeCelles, 2004) (fig. 2). The Newcastle Formation is conformably overlain by the Graneros Shale

(fig. 3), which primarily consists of shale that was deposited in an open marine environment, also in the 

Sevier Foreland (Hansen, 1955; Mallory, 1972; DeCelles, 2004). Subsurface correlations of geophysical 

logs from several boreholes indicate that the Graneros Shale is a homogeneous shale and hundreds of feet 

thick (Hansen, 1955). The thickness and lithologic character of the shale suggests that it should serve as a 

robust top seal for prospective reservoirs in the coarse-grained intervals of the Newcastle Formation (see 

Magoon and Dow, 1994; Brennan and others, 2010). 

The SAU area for the Newcastle Formation was defined on the basis of the 3,000-ft overburden 

contour (see Brennan and others, 2010) (fig. 11). An overburden contour map was generated from a 

stratigraphic database containing more than 5,200 borehole penetrations (IHS Energy Group, 2010), with 

data widely distributed across the entire study area. Additionally, the western SAU boundary is defined by 

the limit of the Williston Basin Province (Anna and others, 2008) and the northern SAU boundary is 

defined by the international border with Canada. Sandstones of the Newcastle pinch out across northcentral North Dakota (for example see Hansen, 1955; Reishus, 1968). The SAU extends across an area of 

34,223,000 acres (with an error of plus or minus 10 percent), and it extends from subsurface depths of 

3,000 to about 6,000 ft.

The gross thickness of the Newcastle Formation was defined using the previously mentioned 

stratigraphic database (IHS Energy Group, 2010). Formation top depths were subtracted from 

immediately underlying formation-top depths from more than 1,600 boreholes where both units were 

identified, and an isopach map was derived from the resulting data. Across Williston Basin, the average 

gross thickness of the Newcastle Formation is between 200 and 300 feet. In order to evaluate the net 

thickness of porous sandstone in the Newcastle Formation, we analyzed gamma ray and resistivity logs 

from a network of 15 boreholes distributed across the central portion of the SAU (Reishus, 1968). This 

analysis suggests that net sandstone thickness for the formation, is, on average, about 20 to 60 feet across 

the SAU. This range is consistent with a geophysical log-based analysis of net sand thickness in 

approximately 1,000 boreholes in the Newcastle Formation (Muddy Sandstone equivalent) in eastern 

Montana, including the western part of Williston Basin (Feltis and others, 1981).

Regional maps show that TDS concentrations range from less than 1,000 mg/L (ppm) to several 

tens of thousands mg/L (ppm) for the Newcastle Formation (Whitehead, 1996, and references therein). 

Given that areas with formation waters exhibiting concentrations of total dissolved solids less than 10,000 

mg/L (ppm) will generally be restricted for CO2 injection (U.S. Environmental Protection Agency, 2009,

2010), we estimate that perhaps 25 percent of the SAU contains formation waters that have acceptably 

high salinity for CO2 injection.

We quantified the porosity and permeability of the Newcastle Formation on a regional scale using 

a combination of petroleum production data (Nehring Associates, Inc., 2010) and geophysical logs from 

boreholes (North Dakota Geological Survey, written commun., 2011). There is little petroleum production 

from the Newcastle Formation in Williston Basin, and in order to compensate for this lack of data, we 

compiled Newcastle Formation porosity data from nearby basins, including the Sweetgrass arch and 

Powder River Basin. Approximately 20 petroleum reservoir porosity measurements from these nearby 
30

basins suggest that on a basin scale, the porosity of the Newcastle Formation ranges between 13 and 19 

percent. This range is consistent with foot-by-foot measurements of the Newcastle Formation porosity, 

based on interpretation of geophysical logs, in a few wells scattered around the Williston Basin region 

(North Dakota Geological Survey, written commun., 2011). About 15 petroleum reservoir permeability

measurements from these two basins range from 0.01 to 100 mD (Nehring Associates, Inc., 2010). We 

estimate that the average permeability for potential Newcastle Formation reservoirs is about 50 mD.

There are no major petroleum fields producing from the Newcastle Formation, and we estimate 

the minimum, most likely, and maximum enclosed pore volume (analogous to structural and [or]

stratigraphic hydrocarbon traps) following the methods described for the Lower Swift Formation SAU 

(see previous section).
31

Figure 11. Map showing the Newcastle Formation Storage Assessment Unit (SAU) in the Williston Basin, North 

Dakota, South Dakota, and Montana. Grid cells (one square mile) represent counts of wells derived from 

ENERDEQ well database (IHS Energy Group, 2011) that have penetrated the storage-formation top. Study area 

boundaries were modified from the U.S. Geological Survey national oil and gas assessment (NOGA) (Anna and 

others, 2011).
32

Eagle Sandstone

By William H. Craddock

The Eagle Sandstone (fig. 3) of the Montana Group in Williston Basin was deposited in the Late 

Cretaceous in a shallow marine setting in the Sevier foreland basin (DeCelles, 2004). It is overlain by the 

Pierre Shale, which is a homogeneous, open marine shale with a thickness on the order of 2,000 feet 

across Williston Basin (Murphy and others, 2009). The coarse-grained Eagle Sandstone is likely to have

reservoir properties (for example, porosity and permeability) that are suitable for CO2 injection and 

storage, and the overlying Pierre Shale is likely to be a robust seal; both units are present in Williston 

Basin and across much of the northeastern Rocky Mountain region. However, the reservoir and seal 

quality of the Eagle Sandstone in Williston Basin, required for designation as an SAU (Brennan and 

others, 2010; Blondes and others, 2013), remains largely untested because there has been no significant 

petroleum production to date from the interval (Nehring Associates, Inc., 2010). The Eagle Sandstone is 

thought to contain formation waters with concentrations of TDS of 3,000 mg/L (ppm) or less (Whitehead, 

1996). Because of the potential for this formation to serve as a drinking water source, it is unlikely that 

CO2 disposal would be permitted within this formation (U.S. Environmental Protection Agency, 2009,

2010). For this reason, we have not assessed the storage potential of the Eagle Sandstone.
33

Central Montana Basins

By Matthew D. Merrill

USGS assessment geologists investigated the CO2 storage potential in the Central Montana Basins 

study area (fig. 1), a region bounded to the north by the Canadian border, to the west by the Montana 

Thrust Belt study area (see next section in this report), to the south by the northern extents of the Bighorn 

and Powder River Basins, and to the east by the Williston Basin (see prior section in this report). This 

area resides completely within the State of Montana and includes or partially includes numerous geologic 

structures that, while diverse, were grouped together as the single Central Montana Basins study area for 

national-scale investigation purposes. The aforementioned structures include, but are not limited to, the 

Sweetgrass arch, the Little Belt uplift, the Beartooth uplift, the Bears Paw uplift, Bull Mountains Basin, 

the Bowdoin dome, and the Porcupine dome (Dyman, 1987; Vuke and others, 2007) (fig. 1). Numerous 

smaller features such as domes, faulted zones, and intrusions are also present but not mentioned herein.

The Central Montana Basins study area contains many of the same Cambrian through Tertiary age 

formations found to the south in other sedimentary basins east of the Rocky Mountain Cordillera, such as 

the Bighorn, Powder River and Wind River Basins. Paleozoic sedimentary rocks represent a cratonic 

boundary area that was marine-dominated with pulses of regressive sediments throughout the record. 

Notably, though much of the northern Central Montana Basins study area is absent of Pennsylvanian, 

Permian, and Triassic rocks, they are, however, present to the south in the Central Montana trough 

(Maughan, 1966; Dyman, 1987). Mesozoic formations record the retro-arc foreland deposits shed from an 

active convergent tectonic boundary to the east. During the Late Cretaceous and Tertiary, the Laramide 

orogeny produced much of the modern structural features seen across the study area as well as a shift 

from foreland style deposits to more terrigenous orogenic ones.

Assessment geologists selected four intervals for potential CO2 storage assessments. The potential 

reservoirs included a composite reservoir of many Mississippian formations and three reservoirs in the 

Cretaceous section. Sandstones in the Newcastle, Muddy, and (or) Frontier Formations, and (or) the Eagle 

Sandstone were all potential candidates. An abundance of groundwater with TDS contents within ranges 

defined by the U.S. Environmental Protection Agency (2009) as an USDW is, however, an issue. The 

methodology does not allow CO2 storage in these waters (Brennan and others, 2010; Blondes and others, 

2013). Waivers allowing for CO2 storage in USDWs would not be available because existing oil and gas 

production is not present (U.S. Environmental Protection Agency, 2010) where formations of interest are 

at the depths required by the method. Therefore, because of water-quality concerns, no SAUs were 

assessed in the Central Montana Basins study area.

Montana Thrust Belt

By Matthew D. Merrill

The Montana Thrust Belt (MTB) study area, as investigated by the assessment team, includes 

Paleozoic to Tertiary age sedimentary units along the eastern side of the Rocky Mountain Cordillera from 

northern Montana to the Beartooth uplift to the south (fig. 1). Western Montana has been divided by 

Peterson (1981) into five provinces, including a northwestern area of Precambrian Belt Supergroup 
34

exposures, a west-central region of Mesozoic intrusives, an east-central area of upper Mesozoic and lower

Tertiary volcanic and conglomerate deposits, a south-central area of Precambrian rocks, and a Laramide 

thrust and fold belt in the east. The study area is based on a combination of five assessment units 

boundaries from the 2002 USGS National Oil and Gas Assessment (Schenk and others, 2002) located 

mostly within the Laramide thrust and fold belt.

Much like the Wyoming-Idaho-Utah Thrust Belt, the MTB includes numerous eastward thrusted 

Paleozoic through Tertiary rocks. A long interval of tectonic thrusting occurred from 200 to 60 Ma 

(mega-annum [million years]) (Monger and Price, 1979). Specifically in the northern MTB area, thrusting 

occurred during the Late Cretaceous through Paleocene time (Mudge, 1982). To the south thrusting began 

around 77 Ma (Harlan and others, 2008), and to the west, just outside the MTB study area, thrusting 

began around 100 Ma (Harrison and Cressman, 1993). 

Within the thrusted area, Proterozoic and Paleozoic rocks are exposed in the central and western 

parts, Paleozoic rocks in the central part, and Mesozoic rocks in the central and eastern parts of the study 

area (Mudge, 1982). During Paleozoic and Mesozoic time, the MTB was part of a boundary zone on the 

western side of North America that separated the craton from the open marine environment (Peterson, 

1981). Accordingly, the rocks deposited in the MTB study area and the rest of the Rocky Mountain region 

are mainly marine with regressive pulses of clastic deposits from the craton or local topographic highs 

(Peterson, 1981).

Potential SAUs were investigated by assessment geologists for the presence of adequate sealing 

and reservoir formations. Initial investigations resulted in the pre-selection of SAUs in the Mississippian 

Madison Limestone, Devonian Jefferson Formation, Cretaceous Colorado Group sandstones, and the 

Cretaceous Kootenai Formation. However, further research indicated that waters in these formations 

contained TDS contents within the U.S. Environmental Protection Agency (2009) definition of waters that 

are a potential USDW. The methodology does not allow CO2 storage in these waters (Brennan and others, 

2010; Blondes and others, 2013). Waivers allowing for CO2 storage in USDWs would not be available 

because existing oil and gas production is absent (U.S. Environmental Protection Agency, 2010) from the 

study area in the formations of interest. Therefore because of water-quality concerns, no SAUs were 

assessed in the MTB.
35

Acknowledgments

The authors acknowledge Troy Cook, Mahendra Verma, and Hossein Jahediesfanjani who helped 

to interpret the petroleum engineering data for the study areas at the USGS. Furthermore, Edward C. 

Murphy, State Geologist, and Timothy Nesheim from the North Dakota Geological Survey, and Jay A. 

Gunderson from the Montana Bureau of Mines and Geology helped by supplying geologic information

and interpretations for the study areas. We thank Joe East for administering the USGS State Cooperative 

Agreements. The content and presentation of this report benefited greatly from the technical peer reviews 

by Stephanie Gaswirth and Robert Milici.

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