Geologic Framework for the National Assessment of 

Carbon Dioxide Storage Resources─Denver Basin, 

Colorado, Wyoming, and Nebraska 

By Ronald M. Drake II, Sean T. Brennan, Jacob A. Covault, Madalyn S. Blondes, Philip A. Freeman, 

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

Chapter G 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–G 

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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its natural and living resources, natural hazards, and the environment:

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Suggested citation:

Drake, R.M., II, Brennan, S.T., Covault, J.A., Blondes, M.A., 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—Denver Basin, 

Colorado, Wyoming, and Nebraska, chap. G 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–G, 

17 p., . 

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.

http://dx.doi.org/10.3133/ofr20121024G
iii

Editors’ Preface

By Peter D. Warwick and Margo D. Corum

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

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

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

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

mitigate its effects on climate change.

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

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

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

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

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

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

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

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

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

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

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

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

formation water having a salinity less than 10,000 milligrams per liter (mg/L) of 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 (2010) defines the lower limit of 

10,000 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 mg/L TDS are not assessed (Brennan and others, 

2010; Blondes and others, 2013). 

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

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

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

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

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

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

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

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

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

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

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

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., II, 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., http://pubs.usgs.gov/of/2013/1055/. 
iv

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., 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., 

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

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

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

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

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

U.S. Environmental Protection Agency Web site, accessed January 14, 2009, at 

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

Contents

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

References Cited........................................................................................................................................................... iii

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

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

Hydrocarbon Exploration ................................................................................................................................................1

Geologic History .............................................................................................................................................................2

Denver Basin Carbon Dioxide Storage Resource Assessment ......................................................................................2

Plainview and Lytle Formations SAU C50390101 ..........................................................................................................5

Muddy Sandstone SAU C50390102...............................................................................................................................7

Greenhorn Limestone SAU C50390103 .........................................................................................................................9

Niobrara Formation and Codell Sandstone Member SAU C50390104.........................................................................11

Terry and Hygiene Sandstone Members SAU (C50390105)........................................................................................13

Acknowledgments ........................................................................................................................................................15

References Cited..........................................................................................................................................................15

Figures

Figure 1. Map of the Denver Basin within Colorado, Wyoming, and Nebraska with structure contours on top of 

the Precambrian basement in feet below sea level (contour interval = 1,000 feet) from Sonnenberg (1985).................3

Figure 2. Generalized stratigraphic column of geologic units in the Denver Basin, Colorado, Wyoming, and 

Nebraska (modified from Higley and Cox, 2007)............................................................................................................4

Figure 3. Map of the U.S. Geological Survey storage assessment unit (SAU) boundary for the Plainview and 

Lytle Formations SAU in the Denver Basin ....................................................................................................................6

Figure 4. Map of the U.S. Geological Survey storage assessment unit (SAU) boundary for the Muddy Sandstone 

SAU in the Denver Basin, Colorado, Wyoming, and Nebraska ......................................................................................8

Figure 5. Map of the U.S. Geological Survey storage assessment unit (SAU) boundary for the Greenhorn 

Limestone SAU in the Denver Basin, Colorado, Wyoming, and Nebraska...................................................................10

Figure 6. Map of the U.S. Geological Survey storage assessment unit (SAU) boundary for the Niobrara Formation 

and Codell Sandstone Member SAU in the Denver Basin, Colorado, Wyoming, and Nebraska ..................................12

Figure 7. Map of the U.S. Geological Survey storage assessment unit (SAU) boundary for the Terry and 

Hygiene Sandstone Members SAU in the Denver Basin..............................................................................................14
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)

meter (m) 3.281 foot (ft) 

Area

acre 0.4047 hectare (ha)

acre 0.004047 square kilometer (km2)

Volume

gallon (gal) 3.785 liter (L) 

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)

Abbreviations

CO2 carbon dioxide 

SAU storage assessment unit

TDS total dissolved solids 

USGS U.S. Geological Survey 
1

Geologic Framework for the National Assessment of 

Carbon Dioxide Storage Resources─Denver Basin, 

Colorado, Wyoming, and Nebraska

By Ronald M. Drake II, Sean T. Brennan, Jacob A. Covault, Madalyn S. Blondes, Philip A. Freeman, 

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

Abstract

This is a report about the geologic characteristics of five storage assessment units (SAUs) within 

the Denver Basin of Colorado, Wyoming, and Nebraska. These SAUs are Cretaceous in age and include 

(1) the Plainview and Lytle Formations, (2) the Muddy Sandstone, (3) the Greenhorn Limestone, (4) the 

Niobrara Formation and Codell Sandstone, and (5) the Terry and Hygiene Sandstone Members. The 

described characteristics, as specified in the methodology, affect the potential carbon dioxide storage 

resource in the SAUs. The specific geologic and petrophysical properties of interest include depth to the 

top of the storage formation, average thickness, net-porous thickness, porosity, permeability, groundwater 

quality, and the area of structural reservoir traps. Descriptions of the SAU boundaries and the overlying 

sealing units are also included. Assessment results are not contained in this report; however, the geologic 

information included here will be used to calculate a statistical Monte Carlo-based distribution of 

potential storage volume in the SAUs.

Introduction

The Denver Basin is a Laramide-age, asymmetric structural foreland basin located east of the 

Rocky Mountain Front Range (Higley and others, 1995). The basin extends from southeastern Colorado, 

north to the Nebraska-South Dakota border and from the eastern edge of the Front Range to about the 

Colorado-Kansas border (fig. 1). The basin is elongated north–south and is about 330 miles (mi) long and 

about 180 mi wide. It is bounded on the northwest and northeast by the Hartville uplift and the Chadron 

arch, respectively, on the southeast by the Las Animas arch, on the southwest by the Apishapa uplift, and 

on the west by the Rocky Mountain Front Range. The basin is more than 13,000 ft deep near Denver 

(Martin, 1965) and is steeply dipping along the western flank and gently dipping along the eastern flank 

of the basin. Most of the thickness of deposits in the basin is from stratigraphic units ranging in age from 

Pennsylvanian to Tertiary (fig. 2). 

Hydrocarbon Exploration 

Wells within the Denver Basin have produced more than 1.05 billion barrels of oil and 3.67 

trillion cubic feet of natural gas (Higley and Cox, 2007). Most of the oil and gas has been produced from 

Cretaceous rocks in the basin with most oil production from the Lower Cretaceous Muddy (“J”) 

Sandstone and the Upper Cretaceous “D” sandstone (Higley and Cox, 2007), which are mainly from

fluvial, incised-valley, and deltaic environments. The “D” and “J” sandstones are informal economic 

units. There has also been production from Paleozoic-age deposits, for example, the Permian Lyons 

Sandstone, and there is some potential for gas from coals in the Upper Cretaceous Laramie Formation and 

lower Tertiary and Upper Cretaceous Denver Formation (Higley and Cox, 2007). 
2

Geologic History

During Late Cambrian to Early Ordovician, sediments in the area of the Denver Basin were 

deposited in a shallow marine environment (Kent, 1972) and consisted of sands, calcareous deposits, and 

dolomites. The conformable Ordovician sequence (Graffin, 1992) includes, from oldest to youngest, the 

Manitou Formation, Harding Sandstone, and Fremont Dolomite. The Harding Sandstone was deposited in 

the southern portion of the basin during the Middle Ordovician and the Fremont Dolomite was deposited 

in western and south-central Colorado during the Late Ordovician. Some Upper Devonian shales, 

sandstones, and thin limestones were deposited indicating widespread shallow seas. Limestone and shale 

units (for example, Leadville Limestone) were deposited in the southern portion of the basin during the 

Mississippian. The Ancestral Rocky Mountains formed along the west side of the Denver Basin during 

the Pennsylvanian and subsequent deposition of great thicknesses of coarse arkosic clastic sediments (the 

Pennsylvanian part of the Fountain Formation) were deposited in the basin (Kent, 1972). The Ancestral

Rocky Mountains continued to be eroded during the Permian and thick deposits of coarse material 

continued to collect adjacent to the uplift, while finer material accumulated farther away from the uplift. 

The Permian deposits include the upper part of the Fountain, Ingleside, and Owl Canyon Formations, 

Lyons Sandstone, and lower part of the Lykins Formation. 

During the Triassic, mostly subaerial deposits, such as the upper part of the Lykins Formation and 

the Jelm Formation, were deposited in the central and northern portion of the Denver Basin (McCoy, 

1953). In the Jurassic, Morrison Formation nonmarine variegated shales, freshwater limestones, and 

sandstones were deposited. During the Cretaceous, the Western Interior Seaway covered the basin and 

there were several sea level fluctuations that led to varied depositional environments and strata. The 

Cretaceous deposits (fig. 2) compose the majority of the Denver Basin sediment thickness, and the 

formations analyzed in this paper are all Cretaceous age. In the latest Cretaceous to Tertiary time, the 

Laramide orogeny began, and uplift occurred from Mexico to Canada (English and Johnston, 2004) and 

along the western edge of the Denver Basin. During the earliest of Tertiary time, the Western Interior 

Seaway regressed and marked the end of marine deposition in the Denver Basin. 

Denver Basin Carbon Dioxide Storage Resource Assessment

Reservoirs assessed for carbon dioxide (CO2) storage in the Denver Basin include (1) Lower 

Cretaceous Plainview and Lytle Formations, (2) Lower Cretaceous Muddy Sandstone, (3) Upper 

Cretaceous Greenhorn Limestone, (4) Upper Cretaceous Niobrara Formation and Codell Sandstone 

Member of the Carlile Shale, and (5) Upper Cretaceous Terry and Hygiene Sandstone Members of the 

Pierre Shale (fig. 2). The extents of storage formations are defined by the geologic characteristics of the 

reservoirs and overlying seals and the subsurface physical properties of CO2 as described in Burruss and 

others (2009) and Brennan and others (2010). The following sections describe each of the SAUs in the 

Denver Basin.
3

Figure 1. Map of the Denver Basin within Colorado, Wyoming, and Nebraska with structure contours on top of the 

Precambrian basement in feet below sea level (contour interval = 1,000 feet) from Sonnenberg (1985). Denver 

Basin study area boundary modified from U.S. Geological Survey National Oil and Gas Assessment project

(Higley and others, 2007).
4

Figure 2. Generalized stratigraphic column of geologic units in the Denver Basin, Colorado, Wyoming, and 

Nebraska (modified from Higley and Cox, 2007). Storage assessment units consist of a reservoir (red) and 

regional seal (blue). Wavy lines indicate unconformable contacts, and gray sections represent nonpreserved

lithology. In some cases, subdivisions of units are not shown. Gp., Group; Ss., Sandstone; SAU, storage 

assessment unit.
5

Plainview and Lytle Formations SAU C50390101

By Jacob A. Covault

The Lower Cretaceous Plainview and Lytle Formations of the Dakota Group (fig. 2) average 140 ft in 

thickness and are predominantly very fine to medium-grained, quartz-rich, siliciclastic sandstone and 

conglomerate interbedded with mudstone (Haun, 1963; Gabarini and Veal, 1968; Moredock and others, 1977; 

Ladd, 2001; Higley and Cox, 2007). The Plainview and Lytle Formations are equivalent to the “Dakota” of 

driller usage, Fall River Sandstone, the “Lakota” of driller usage, and the Cheyenne Sandstone and compose 

the lower part of the Lower Cretaceous Dakota Group (Haun, 1963; Ladd, 2001; Higley and Cox, 2007). 

Within this report, the Plainview and Lytle Formations will be referred to as the lower part of the Dakota 

Group or the Dakota. The Dakota locally rests unconformably on the Upper Jurassic Morrison Formation 

(Haun, 1963). Overlying the Dakota is the Skull Creek Shale, which is equivalent to the Thermopolis Shale, 

and is greater than 100 ft thick across much of the Denver Basin (Haun, 1963; Moredock and others, 1977; 

IHS Energy Group, 2011). The Skull Creek Shale is locally thinner than 50 ft in the southern part of the 

Denver Basin and generally is between 50 and 100 ft thick along the western basin margin (Moredock and 

others, 1977; IHS Energy Group, 2011). The Skull Creek Shale is a potential hydrocarbon source rock for 

overlying sandstone reservoirs (for example, the Muddy Sandstone; Higley and others, 1995; Ladd, 2001; 

Higley and Cox, 2007) and is interpreted to be a sealing unit for the underlying Dakota. Both the Dakota and 

Skull Creek Shale are regionally extensive across the Denver Basin (Haun, 1963; Moredock and others, 1977; 

IHS Energy Group, 2011). There is a paucity of data relevant to the Dakota compared to overlying reservoir 

units (for example, the Muddy Sandstone). This is a result of physical separation from major petroleum source 

rocks and, consequently, limited production (Ladd, 2001). The Dakota and overlying Skull Creek Shale

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

nonmarine and marginal marine channel-filling systems (Dakota) to a fully marine system (Skull Creek Shale) 

in the Cretaceous Western Interior Seaway and foreland basin (Haun, 1963; Martin, 1965; Gabarini and Veal, 

1968; Ladd, 2001). 

The Plainview and Lytle Formations (Dakota) SAU (C50390101) is a potential reservoir unit for 

CO2 storage in the Denver Basin (fig. 2) between 3,000- and 11,000-ft subsurface depths. The SAU 

boundary is defined by the 3,000-ft drilling depth, based on greater than 2,300 well penetrations (IHS 

Energy Group, 2011), and faults bounding the Denver Basin (Stoeser and others, 2007) (fig. 3). The area 

of the Plainview and Lytle Formations SAU is about 24,400,000 acres. The range of total storageformation thickness for the reservoir unit was determined from using regional subsurface stratigraphic 

correlations of Moredock and others (1977) and isopach and net-sandstone thickness maps of Haun 

(1963). The thickness of the net-porous interval was from a net-sandstone thickness map of Haun (1963). 

Reservoir quality data for the Dakota are localized in the west-central part of the Denver Basin (Ladd, 

2001). Within the Wattenberg field, porosity ranges from 1 to 13 percent and permeability ranges between 

0.001 and 100 millidarcys (mD) (Ladd, 2001). Nehring Associates, Inc. (2010) indicates a single fieldaveraged porosity measurement of 18 percent and a permeability measurement of 150 mD. Water-quality 

measurements indicate that groundwater in the Dakota ranges from fresh to saline (greater than 10,000 

parts per million (ppm) of total dissolved solids) (Leonard and others, 1983; Breit, 2002; Wyoming Oil 

and Gas Conservation Commission, 2010; U.S. Geological Survey, 2011). The minimum and central 

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

(2010) and Blondes and others (2013). Maximum buoyant-trapping pore volume was calculated from the 

product of (1) the combined areas of stratigraphically analogous, overlying Muddy Sandstone reservoirs 

mapped by Hemborg (1993) and reservoirs of producing fields (Nehring Associates, Inc., 2010); (2) the 

maximum net-porous-interval thickness; and (3) the maximum porosity (Brennan and others, 2010). 
6

Figure 3. Map of the U.S. Geological Survey storage assessment unit (SAU) boundary for the Plainview and Lytle 

Formations SAU in the Denver Basin. Grid cells (one square mile) represent counts of wells derived from the 

ENERDEQ well database (IHS Energy Group, 2011) that have penetrated the reservoir-formation top. Denver 

Basin study area boundary modified from National Oil and Gas Assessment project unit boundaries (Higley and 

others, 2007).
7

Muddy Sandstone SAU C50390102

By Jacob A. Covault

The Lower Cretaceous Muddy Sandstone averages approximately 200 ft in thickness and 

predominantly includes fine- to medium-grained, siliciclastic sandstone interbedded with mudstone (fig. 

2) (Weimer and others, 1998; Higley and Cox, 2007). The Muddy Sandstone SAU includes Mowry Shale 

or the Huntsman Shale (which is not uniformly present in the subsurface of the Denver Basin) (Haun, 

1963; Higley and Cox, 2007) and the overlying Graneros Shale (fig. 2). The lower part of the Muddy 

Sandstone SAU includes the informal “J” sandstone, and the upper part includes the informal “D” 

sandstone (Haun, 1963; Weimer and others, 1998; Higley and Cox, 2007). The Muddy Sandstone overlies 

the regionally extensive Skull Creek Shale (Haun, 1963). Overlying the Mowry Shale is the Graneros 

Shale, which is greater than 100 ft thick across much of the Denver Basin (Moredock and others, 1977; 

IHS Energy Group, 2011). The Mowry and Graneros Shales are interpreted to be the sealing units for the 

Muddy Sandstone SAU and are source rocks in the Denver Basin (Higley and Cox, 2007). Both the 

Muddy Sandstone and Graneros Shale are regionally extensive across the Denver Basin (Haun, 1963; 

Moredock and others, 1977; IHS Energy Group, 2011). Most of the oil and gas exploration and 

production in the Denver Basin has focused on the Muddy Sandstone (Higley and Cox, 2007). Muddy 

Sandstone reservoir strata were mainly interpreted to represent deposition in deltaic and incised-valley 

environments in response to shoreline regression of the Cretaceous Western Interior Seaway and foreland 

basin (Haun, 1963; Weimer, 1992; Weimer and others, 1998; Higley and Cox, 2007). The overlying 

Graneros Shale has been interpreted to represent relatively fine grained, fully marine deposition as a result 

of shoreline transgression (Haun, 1963; Weimer and others, 1998). 

The Muddy Sandstone SAU (C50390102) is a potential reservoir unit (fig. 2) for CO2 storage in 

the Denver Basin at depths between 3,000 and 10,000 ft. The SAU boundary (fig. 4) is defined by the 

3,000-ft drilling depth from greater than 30,000 well penetrations (IHS Energy Group, 2011) and faults 

bounding the Denver Basin (Stoeser and others, 2007). The area of the Muddy Sandstone SAU is about 

23,500,000 acres. The range of total storage-formation thickness for the reservoir unit was determined 

from more than 6,000 well penetrations (fig. 4) of the tops of the Muddy Sandstone and Skull Creek Shale 

(IHS Energy Group, 2011), regional subsurface stratigraphic correlations of Moredock and others (1977), 

and isopach and net-sandstone thickness maps of Haun (1963). The thickness of the net-porous interval 

was from net-sandstone thickness maps of Haun (1963). Greater than 200 reservoir-quality measurements 

from Nehring Associates, Inc. (2010) show an average porosity of 18 percent, with a standard deviation of 

5 percent (see also Higley and Schmoker, 1989; and Schmoker and Higley, 1991). Higley and Schmoker 

(1989) provide constraints on the distribution of Muddy Sandstone permeability, which ranges from 

approximately 0.01 to 2,000 mD in their study. Water-quality measurements indicate that groundwater in 

the formation ranges from fresh to saline (greater than 10,000 ppm of total dissolved solids) (Leonard and 

others, 1983; Breit, 2002; Wyoming Oil and Gas Conservation Commission, 2010; U.S. Geological 

Survey, 2011). The minimum and central tendency buoyant-trapping pore volumes were determined using 

methods described in Brennan and others (2010) and Blondes and others (2013). Maximum buoyanttrapping pore volume was calculated from the product of (1) combined areas of Muddy Sandstone 

reservoirs mapped by Hemborg (1993) and reservoirs of producing fields (Nehring Associates, Inc., 

2010), (2) maximum net-porous-interval thickness, and (3) maximum porosity (Brennan and others, 

2010). 
8

Figure 4. Map of the U.S. Geological Survey storage assessment unit (SAU) boundary for the Muddy Sandstone 

SAU in the Denver Basin, Colorado, Wyoming, and Nebraska. Grid cells (one square mile) represent counts of 

wells derived from ENERDEQ well database (IHS Energy Group, 2011) that have penetrated the reservoirformation top. Denver Basin study area boundary modified from Higley and others (2007).
9

Greenhorn Limestone SAU C50390103

By Ronald M. Drake II

The Upper Cretaceous Greenhorn Limestone (fig. 2) is one of the most widespread units in the 

Rocky Mountain region extending northward from New Mexico to Canada and from western New 

Mexico eastward to the South Dakota-Minnesota boundary (Hattin, 1975; Weimer and others, 1986). In 

central Colorado, the Greenhorn Limestone is composed of (in ascending order) the Lincoln Limestone, 

Hartland Shale, and the Bridge Creek Limestone Members (Sageman, 1996). Within the SAU, the 

Greenhorn Limestone averages approximately 125 ft in thickness (IHS Energy Group, 2010) and is 

composed predominantly of thin limestones, dark-gray to black organic-rich shales, and thin bentonite 

beds (Weimer and others, 1986; IHS Energy Group, 2011). The Greenhorn Limestone and overlying 

Carlile Shale were deposited in the Cretaceous Western Interior Seaway primarily as offshore muds and 

carbonate-rich muds deposited on a marine shelf, shelf slope, and in the deep basin (Hattin, 1975; Weimer

and others, 1986). The Carlile Shale overlies the Greenhorn Limestone, and this regionally extensive unit 

averages about 140 ft in thickness within the SAU (IHS Energy Group, 2011); however, north and 

northeast of Denver, the Carlile Shale thins to less than 50 ft. 

The Greenhorn Limestone SAU (C50390103) is a potential reservoir unit for CO2 storage in the 

Denver Basin at depths greater than 3,000 ft below the surface. More than 1,100 well penetrations (IHS 

Energy Group, 2011) were used to define the SAU boundary, which is based on the top of the Greenhorn 

Limestone being at least 3,000 ft below the surface and the overlying sealing unit being at least 50 ft 

thick. There were no tops below 13,000 ft; therefore, there is no deep SAU. The area of the Greenhorn 

Limestone SAU is about 20,024,000 acres (fig. 5). The storage-formation thickness was calculated from 

boreholes penetrating both the top of Greenhorn Limestone and the top of the underlying Graneros Shale 

(IHS Energy Group, 2011). Regional subsurface stratigraphic correlations by Moredock and others (1977) 

and Weimer and others (1986), as well as an isopach map from Weimer and others (1986), were utilized 

to determine unit thickness. Porosity data for the Greenhorn Limestone are scarce, but available sources 

indicate that average porosity is about 9 percent (Hoffman and Chang, 2009; URS Corporation and others, 

2009). The average net-porous thickness of 13 ft was derived from applying a net-porous thickness to 

gross thickness ratio estimated from available well logs (MacQuown and Millikan, 1955; Monson, 1995; 

Sonnenberg and Weimer, 2006). Permeability data were also scarce for the Greenhorn Limestone; 

therefore, permeability data were used from a report by URS Corporation and others (2009) and by using 

data from the overlying Niobrara Formation as an analogy with resulting permeability ranging from 

approximately 0.01 to 2 mD (Nehring Associates, Inc., 2010). Because of the lack of water-quality 

measurements from the Greenhorn Limestone, water-quality data from adjacent units were utilized and 

indicate that groundwater in and adjacent to the formation ranges from fresh to saline (greater than 10,000 

ppm of total dissolved solids) (Breit, 2002; U.S. Geological Survey, 2011). The area of the SAU available 

for storage (based on water-quality restrictions) ranges between 10 and 50 percent, and the most likely 

value is 30 percent. The maximum buoyant-trap volume was calculated based on (1) the area of existing 

hydrocarbon fields and potential structures mapped within the Denver Basin, (2) maximum net-porousinterval thickness, and (3) maximum porosity (Brennan and others, 2010; Blondes and others, 2013). 
10

Figure 5. Map of the U.S. Geological Survey storage assessment unit (SAU) boundary for the Greenhorn 

Limestone SAU in the Denver Basin, Colorado, Wyoming, and Nebraska. Grid cells (one square mile) represent 

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

reservoir-formation top. Denver Basin study area modified from Higley and others (2007).
11

Niobrara Formation and Codell Sandstone Member SAU 

C50390104

By Ronald M. Drake II

The Upper Cretaceous Niobrara Formation and Codell Sandstone SAU (C50390104) includes the 

Codell Sandstone Member of the Carlile Shale and the overlying Fort Hayes Limestone and Smoky Hill 

Shale Members of the Niobrara Formation (fig. 2). The Codell Sandstone Member was deposited in a 

shallow marine or brackish environment near the shoreline or on the shelf of the Cretaceous Western 

Interior Seaway (Weimer and Sonnenberg, 1983). Deposition of the overlying unconformable Niobrara 

Formation marks a sea level rise and regionally comprises four limestone (chalk) units and intervening 

shale units (Weimer and others, 1986). The Codell Sandstone Member and Niobrara Formation are 

overlain by the thick, deep-water marine Pierre Shale that seals the SAU.

The Niobrara Formation and Codell Sandstone Member SAU boundary was created using well 

penetration data for the top of the Niobrara Formation (IHS Energy Group, 2011). These data were used 

to identify the extent of the SAU where the top of the Niobrara Formation is at least 3,000 ft deep. There 

were no tops below 13,000 ft; therefore, there is no deep SAU. The area of the Niobrara Formation and 

Codell Sandstone Member SAU is about 17,039,000 acres (fig.6). Water-quality measurements from the 

Codell Sandstone Member and Niobrara Formation are limited; therefore, water-quality data from 

adjacent stratigraphic units were utilized and indicate that groundwater in and adjacent to the Codell and 

Niobrara ranges from fresh to saline (greater than 10,000 ppm of total dissolved solids) (Breit, 2002). The 

most likely percentage of the amount of the SAU available for storage is 30 percent, with a range of 

uncertainty between 50 and 10 percent of the SAU area. 

Within the SAU, the thickness of the Niobrara Formation and Codell Sandstone Member averages 

350 ft based on isopach data (Weimer and others, 1986), National Oil and Gas Assessment project data 

(Higley and others, 1995), and by calculating thicknesses from subtracting the top depth of the Niobrara 

Formation from the top depth of the underlying Carlile Shale (IHS Energy Group, 2011). The average netporous thickness of 20 ft was derived from literature and well logs (MacQuown and Millikan, 1955; 

Weimer and others, 1986; Higley and others, 1995; Sonnenberg and Weimer, 2006; Higley and Cox, 

2007). The porosity of the net-porous interval has a most likely value of 10 percent, with a minimum of 8 

percent and a maximum of 12 percent, and the permeability values range from 0.01 to 2 mD, with a most 

likely value of 0.1 mD (Weimer and others, 1986; Hemborg, 1993; Higley and Cox, 2007; Nehring 

Associates, 2010). The maximum buoyant-trap-volume calculation was based on (1) area of existing 

hydrocarbon fields and potential structures mapped within the Denver Basin, (2) maximum net-porousinterval thickness, and (3) maximum porosity (Brennan and others, 2010; Blondes and others, 2013). 
12

Figure 6. Map of the U.S. Geological Survey storage assessment unit (SAU) boundary for the Niobrara Formation 

and Codell Sandstone Member SAU in the Denver Basin, Colorado, Wyoming, and Nebraska. Grid cells (one

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

have penetrated the reservoir-formation top. Denver Basin study area modified from Higley and others (2007).
13

Terry and Hygiene Sandstone Members SAU (C50390105)

By Sean T. Brennan

The Terry and Hygiene Sandstone Members SAU (C50390105) is composed of thin linear sands 

within the Pierre Shale (fig. 2) of the Denver Basin. The Pierre Shale, which both hosts and seals the 

sandstone members, is a thick, deep-water marine shale deposited during the Late Cretaceous within the 

Cretaceous Western Interior Seaway (McGookey and others, 1972). The Pierre Shale is broadly 

correlative with other Upper Cretaceous marine shales throughout the Rocky Mountain region, such as the 

Cody, Steele, Hilliard, Baxter, and Mancos Shales (McGookey and others, 1972). The Pierre Shale 

averages 6,000 to 8,000 ft thick within the Denver Basin (Higley and Cox, 2007). The Terry and Hygiene 

Sandstone Members are thin, laterally continuous sandstone units that have been described as offshore 

shelf deposits formed during regressive shoaling events (Porter, 1989) and as stacked nearshore, highenergy beach deposits (Slatt and others, 1997). 

The SAU boundaries of the Terry and Hygiene Sandstone Members (fig. 7) were defined by the 

well penetration data for the top of the Hygiene (IHS Energy Group, 2011). However, the stratigraphicunit names that most drillers use in the basin are the “Sussex” for the Terry and the “Shannon” for the 

Hygiene (Higley and Cox, 2007). The Sussex and Shannon Sandstone Members are found within the 

thick, Upper Cretaceous marine shale units elsewhere throughout the Rocky Mountain basins, and they 

appear broadly similar, though they can have very different depositional environments (Higley and Cox, 

2007). The locations of these mislabeled “Sussex” or “Shannon” tops greater than 3,000 ft (IHS Energy 

Group, 2011), along with isopach maps and sand extent maps of the Terry and Hygiene Sandstone 

Members (Kiteley, 1977), were used to identify the extent of the SAU. There were no tops below 13,000 

ft; therefore, there is no deep SAU. The area of the Terry and Hygiene Sandstone Members SAU is about 

6,400,000 acres. However, based on the salinity data available (Breit, 2002), there are formation waters 

within the SAU that are greater than and less than 10,000 ppm TDS. The average percentage of the 

amount of the SAU available for storage is 30 percent, with a wide range of uncertainty, with a 50-percent

maximum and a 10-percent minimum value. 

Within the SAU the total thickness of the Terry and Hygiene Sandstone Members averages 500 ft 

based on isopach thickness maps (Kiteley, 1977), with an average net-porous thickness of 35 ft. The netporous value is derived from applying a net-porous thickness to gross thickness ratio estimated from 

available well logs (Pittman, 1989; Porter, 1989; Al-Raisi and others, 1996; Slatt and others, 1997), cross 

sections (Kiteley, 1977; Pittman, 1989; Porter, 1989), and sand extent maps (Kiteley, 1977). The porosity 

of the sandstone units has a most likely value of 8 percent, with a minimum of 6 percent and a maximum 

of 10 percent, whereas the permeability values range from 0.01 to 10 mD, with central tendency of 1 mD 

(Pittman, 1988; Al-Raisi and others, 1996; Slatt and others, 1997; Nehring Associates, Inc., 2010). The 

maximum buoyant-trap volume was determined based on existing and potential undiscovered 

hydrocarbon fields and structure maps within the Denver Basin. 
14

Figure 7. Map of the U.S. Geological Survey storage assessment unit (SAU) boundary for the Terry and Hygiene 

Sandstone Members SAU in the Denver Basin. Grid cells (one square mile) represent counts of wells derived 

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

Denver Basin study area modified from Higley and others (2007).
15

Acknowledgments

The authors thank several U.S. Geological Survey employees for their efforts in preparing this 

report. James L. Coleman, Jr., compiled water-quality data and Paul G. Schruben and Brian Varela helped 

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

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

Geological Survey for their help in supplying geologic information used in this review. The content and 

presentation of this report benefited greatly from the technical reviews of Debra Higley, David Scott, 

Thomas Judkins, Joe East, and Michael Trippi. 

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