Geologic Framework for the National Assessment of 

Carbon Dioxide Storage Resources─Arkoma Basin,

Kansas Basins, and Midcontinent Rift Basin Study Areas

By Marc L. Buursink, William H. Craddock, Madalyn S. Blondes, Philip A. Freeman, Steven M. Cahan, 

Christina A. DeVera, and Celeste D. Lohr

Chapter F 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–F

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: 2013

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Suggested citation:

Buursink, M.L., Craddock, W.H., Blondes, M.S., Freeman, P.A., Cahan, S.M., DeVera, C.A., and Lohr, C.D., 2013, 

Geologic framework for the national assessment of carbon dioxide storage resources—Arkoma Basin, Kansas basins,

and Midcontinent Rift Basin, chap. F 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–F, 35 p., 

http://dx.doi.org/10.3133/ofr20121024f.

ISSN 2331-1258 (online)

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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) directs the U.S. 

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

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

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

mitigate its effects on climate change.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

storage resource. Although assessment results are not contained in these chapters, 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. Cell maps show the number of penetrating wells within a quarter 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

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/. 
iv

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. 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

Conversion Factors and Abbreviations......................................................................................................................... vii

Abbreviations............................................................................................................................................................... viii

Report Overview............................................................................................................................................................ix

Abstract ..........................................................................................................................................................................x

Geologic Framework for the National Assessment of Carbon Dioxide Storage Resources─Arkoma Basin...... 1

Arkoma Basin Introduction............................................................................................................................................. 1

Ordovician Composite SAU C50620101........................................................................................................................ 5

Hunton Group SAU C50620102 .................................................................................................................................... 8

Batesville Sandstone and Wedington Sandstone Member SAU C50620103 ...............................................................12

Geologic Framework for the National Assessment of Carbon Dioxide Storage Resources─Kansas Basins ...15

Kansas Basins Introduction ..........................................................................................................................................15

Basin Physiography...............................................................................................................................................15

Geologic History....................................................................................................................................................16

Hydrocarbon Exploration and Production..............................................................................................................16

Storage Resource Assessment.............................................................................................................................17

Lower Paleozoic Composite SAU C50560101..............................................................................................................20

Hunton Group SAU C50560102 ...................................................................................................................................23

Geologic Framework for the National Assessment of Carbon Dioxide Storage Resources─Midcontinent 

Rift Basin.....................................................................................................................................................................26

Midcontinent Rift Basin Introduction .............................................................................................................................26

Basin Physiography...............................................................................................................................................26

Geologic History....................................................................................................................................................26

Hydrocarbon Exploration and Production..............................................................................................................27

Storage Resource Assessment.............................................................................................................................27

Acknowledgments ........................................................................................................................................................29

References Cited..........................................................................................................................................................29
vi

Figures

1. Map of the Arkoma Basin study area including major tectonic elements ................................................................ 3

2. Generalized stratigraphic column of geologic units in the Arkoma Basin study area .............................................. 4

3. Map of the Ordovician Composite Storage Assessment Unit (SAU) C50620101 in the 

Arkoma Basin study area ........................................................................................................................................ 7

4. Map of the Hunton Group Storage Assessment Unit (SAU) C50620102 in the Arkoma Basin study area............ 11

5. Map of the Batesville Sandstone and Wedington Sandstone Member Storage Assessment Unit (SAU) 

C50620103 boundary in the Arkoma Basin study area ......................................................................................... 14

6. Map of the Kansas Basins study area including major tectonic elements ............................................................. 18

7. Generalized stratigraphic column of geologic units in Kansas Basins study area................................................. 19

8. Map of the Lower Paleozoic Composite Storage Assessment Unit (SAU) C50560101 in the 

Kansas Basins study area..................................................................................................................................... 22

9. Map of the Hunton Group Storage Assessment Unit (SAU) C50560102 in the Kansas Basins study area .......... 25

10. Map of the Midcontinent Rift Basin study area including major tectonic elements ................................................ 28
vii

Conversion Factors and Abbreviations

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)
viii

Abbreviations

BBO billion barrels of oil

BCFG billion cubic feet of gas

CO2 carbon dioxide

MCRB Midcontinent Rift Basin

mD millidarcy

mg/L milligrams per liter

MMBO million barrels of oil

MMBOE million barrels of oil equivalent

NOGA national oil and gas assessment

OFR open-file report

ppm parts per million

SAU storage assessment unit

TCFG trillion cubic feet of gas

TDS total dissolved solids

USDW underground source of drinking water

USGS U.S. Geological Survey
ix

Report Overview

This three-part open file report (OFR) contains the geologic framework for three adjacent study 

areas, including the Arkoma Basin, multiple Kansas basins, and the Midcontinent Rift Basin (MCRB). 

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

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

assessed separately. The Arkoma Basin is situated in central Arkansas and Oklahoma and contains a 

continuous succession of Paleozoic strata. It is overridden along its southern margin by the Ouachita 

orogenic belt, and it is bound to the north by two broad basement highs, the Ozark uplift in northern 

Arkansas and southern Missouri and the Cherokee platform in northeastern Oklahoma. The Kansas 

Basins study area includes the Salina and Sedgwick Basins, along with the Forest City Basin, Nemaha 

uplift, and Cherokee platform. The Salina Basin may be characterized as a simple asymmetric syncline 

with the basin deep along the southwestern flank adjacent to the Central Kansas uplift. The Sedgwick 

Basin is a broad south-plunging shallow embayment of the Anadarko Basin. Sections of the generalized 

stratigraphic columns for the Anadarko and Kansas Basins are similar, whereas the rocks and setting of 

the MCRB differs. The MCRB is a large, arcuate Mesoproterozoic rift zone, which extends from 

southeastern Ontario, Canada, to northern Michigan and terminates in northeast Kansas. As in previous 

OFR chapters of the National Assessment of Carbon Dioxide Storage Resources, geologists describe their 

investigation of the study areas and work on unique storage assessments units (SAUs). Furthermore, to 

preserve a consistent format across report chapters, these individual SAU descriptions are treated as toplevel sections. Lastly, each study area requires a separate introduction to develop the geologic assessment 

framework, as in prior OFR chapters.
x

Abstract

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

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

carbon dioxide (CO2). The methodology used by the USGS for the national CO2 assessment follows that 

of previous USGS work. This methodology is non-economic and intended to be used at regional to 

subbasinal scales.

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

in Upper Cambrian to Mississippian sedimentary rocks within the Arkoma Basin study area, and two

SAUs in Upper Cambrian to Mississippian sedimentary rocks within the Kansas Basins study area. The 

Arkoma Basin and Kansas Basins are adjacent with very similar geologic units; although the Kansas 

Basins area is larger, the Arkoma Basin is more structurally complex. 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. Although assessment results are not contained in this report, the geologic 

information herein was employed, as specified in the USGS methodology, to calculate a probabilistic

distribution of potential storage resources in each SAU. The Midcontinent Rift Basin study area was

evaluated, but not assessed, because no suitable storage formations meeting our size, depth, reservoir 

quality, and regional seal guidelines were found.

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

well penetrations through sealing units into the top of the storage formations. The cell maps show the 

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

attributed well data and from a digital compilation that is known not to include all drilling.
1

Geologic Framework for the National Assessment of Carbon 

Dioxide Storage Resources─Arkoma Basin

By William H. Craddock, Marc L. Buursink, Madalyn S. Blondes, Philip A. Freeman, Steven M. Cahan, and 

Celeste D. Lohr

Arkoma Basin Introduction

Arkoma Basin, which is situated in central Arkansas and Oklahoma, contains a continuous 

succession of Paleozoic strata. It is overridden along its southern margin by the Ouachita orogenic belt, and 

it is bound to the north by two broad basement highs, the Ozark uplift in northern Arkansas and southern 

Missouri and the Cherokee platform in northeastern Oklahoma (fig. 1). The basin was part of a larger, 

south-facing (present-day coordinates) passive continental margin throughout most of the Paleozoic (Lowe, 

1989), and many of the key physiographic boundaries were established during Pennsylvanian AppalachianOuachitan orogeny (Viele and Thomas, 1989). Arkoma Basin exhibits a typical foreland basin geometry, 

wherein stratal thicknesses diminish (or pinch out) toward northern basement highs and increase 

dramatically toward the Pennsylvanian Ouachita foredeep to the south (Nelson and others, 1982; Lillie and 

others, 1983; DeCelles and Giles, 1996; Ye and others, 1996; Miall, 2008). Whereas pre-Carboniferous 

strata attain a maximum thickness of around 10,000 feet (ft), the upper Paleozoic synorogenic strata may be 

in excess of 40,000 ft in the Ouachita foredeep in the southern part of the basin (Nelson and others, 1982; 

Lillie and others, 1983; Houseknecht, 1987). Formally, our study area includes Arkoma Basin, as well as a 

broad region extending to the south, which includes a portion of the Ouachita orogenic belt as well as a 

Permian successor basin that extends southward into the Louisiana-Texas border region (fig. 1) (Arkoma 

Basin Province Assessment Team, 2010). However, prospective rocks for carbon storage were only 

identified within the Arkoma Basin portion of the broader study area.

A synthesis of petroleum production in Arkoma Basin shows that it has a prolific history of oil and 

gas production. Known oil and gas reserves, which include produced and proven reserves, are greater than 

288 million barrels of oil (MMBO) and greater than 23,346 billion cubic feet of gas (BCFG) (Nehring 

Associates, Inc., 2010). Moreover, the U.S. Geological Survey (USGS) estimates that about an additional 

159 MMBO and 38,021 BCFG remain undiscovered in the basin (Arkoma Basin Province Assessment 

Team, 2010). Although many of the estimated undiscovered resources are thought to be in continuoustype plays, the historically produced volume of hydrocarbons suggests that a large amount of pore space 

may be available for storage in both active and depleted hydrocarbon reservoirs. 

The tectonic history of Arkoma Basin can be characterized as a transition from a rifted continental 

margin to foreland basin extending through the Paleozoic Era with an intervening passive margin phase 

(Houseknecht, 1986). The basin initiated during the breakup of the supercontinent Rodinia, and the 

conjugate margin is thought to be located in the modern Argentinian Precordillera (see Ramos and others, 

1986; Thomas and Astini, 1999, and references therein). The precise timing of basin-initiation in Arkoma 

is controversial with some authors invoking a late Neoproterozoic age based on inferred continuity with 

the Appalachian margin to the east (present-day orientation; see Thomas, 1977; Lowe, 1989) and others 

invoking a Middle or Late Cambrian age based on the age of the oldest exposed sedimentary rocks in the 

region (Lowe, 1985, 1989). Following breakup, Arkoma Basin occupied part of a broad, south-facing 

passive continental margin extending from present-day Alabama to northeastern Mexico and adjoining an 

east-facing passive margin in the eastern United States and Canada (see Thomas, 1991; Thomas and 
2

Astini, 1999; Miall, 2008, and references therein). The basin remained in a passive margin setting 

throughout much of the Paleozoic, but eventually, from the Middle Mississippian to Middle 

Pennsylvanian, a series of island-arc terranes, and finally the Gondwanan continent, were sutured to the 

southern margin of North America during the assembly of the supercontinent Pangaea (Sutherland, 1988; 

Miall, 2008, and references therein). Sedimentary rocks in Arkoma Basin may be divided into four 

tectonostratigraphic units, which correspond to the basic stages of tectonic evolution (Houseknecht, 

1986): (1) the basin is floored by Middle, or perhaps Upper, Cambrian and Lower Ordovician 

siliciclastics and carbonates that were deposited during continental breakup (fig. 2) (Lowe, 1989; Miall, 

2008); ( 2) these basal strata are covered by Ordovician to Silurian platform carbonates and laterally 

equivalent basinal shales and sandstones (fig. 2) (Amsden, 1980; Lowe, 1989); (3) the various lower 

Paleozoic strata are overlain by Devonian and Lower Mississippian siliciclastics, which were generally 

deposited in a passive margin setting, although island arcs approached the southern continental margin at 

this time (fig. 2) (Sutherland, 1988; Lowe, 1989); and (4) the basin is capped by a thick succession of 

synorogenic flysch and molasse deposited during the Carboniferous Appalachian-Ouachitan orogeny 

(fig. 2) (Houseknecht, 1986; Sutherland, 1988; Ye and Kerr, 2000; Miall, 2008). Rather than reviewing 

the large number of formations that have been defined within the Carboniferous flysch succession in 

Arkoma Basin, we present a simplified stratigraphy wherein rocks of the Pennsylvanian System are 

subdivided into the Morrowan, Atokan, and Desmoinesian Provincial Series (fig. 2).

Three storage assessment units (SAUs) within the Arkoma Basin meet criteria for conducting a 

regional assessment for carbon dioxide (CO2) storage capacity, as defined in Burruss and others (2009), 

Brennan and others (2010), and Blondes and others (2013). All three SAUs are in the middle part of the 

Paleozoic passive margin stratigraphic sequence. From oldest to youngest, the SAUs include (1) a 

composite of the various Ordovician carbonates, (2) a composite of the Silurian and Devonian Hunton 

Group and the overlying Devonian informal Misener sandstone, and (3) the Mississippian Batesville 

Sandstone and Wedington Sandstone Member of the Fayetteville Shale. Pennsylvanian synorogenic 

flysch deposits were not assessed despite the fact that this stratigraphic interval accounts for the vast 

majority of the overall hydrocarbon production in the basin (Boyd, 2002). Although there are thick 

accumulations of Pennsylvanian flysch in the foredeep position of the Arkoma Basin, we were unable to 

define lithostratigraphic units well enough to characterize regional reservoir and seal formations within 

this stratigraphic package. We must emphasize, however, that detailed site characterization may identify 

many highly prospective CO2 reservoirs within Pennsylvanian strata. 

In the following sections, we characterize the distribution and stratigraphic character of each 

prospective SAU. We briefly summarize the key information that provides the basis for calculating the 

capacity of each of the SAUs for buoyant and residual CO2 storage (as described in Burruss and others, 

2009; Brennan and others, 2010; Blondes and others, 2013; a function of SAU area, thickness, and porosity) 

as well as information that relates to the reservoir characteristics for each unit. Due to the fact that the U.S. 

Environmental Protection Agency (2009, 2010) stipulates that aquifers must contain groundwater with a 

total dissolved solids (TDS) concentration greater than 10,000 milligrams per liter (mg/L) in order to be 

used for CO2 storage, we characterize regional trends in groundwater quality. Finally, we defined the 

portion of the overall pore volume that may be contained within buoyant traps (terminology from Brennan 

and others, 2010) for the various SAUs that are analogous to stratigraphic and (or) structural hydrocarbon 

traps. For each SAU, the minimum and most likely pore volumes enclosed within buoyant traps were 

constrained on the basis of (1) the sum of the cumulative oil and gas production and the known hydrocarbon 

reserve volume and (2) the minimum buoyant volume plus the estimated volume of undiscovered resources 

(see Brennan and others, 2010). Due to the fact that this method was applied to all SAUs, it is not discussed 

on a case-by-case basis. An upper bound for enclosed pore volume was also determined for each unit, and 

we describe our methods for the various SAUs on a case-by-case basis. The information derived from the 

data sources and methods described herein will be used in accordance with the USGS Carbon Sequestration 

Assessment Methodology (Burruss and others, 2009; Brennan and others, 2010; Blondes and others, 2013) 

to calculate the available storage space for CO2 within the SAU.
3

Figure 1. Map of the Arkoma Basin study area including major tectonic elements (adapted from Arkoma Basin 

Province Assessment Team, 2010).
4

Figure 2. Generalized stratigraphic column of geologic units in the Arkoma Basin study area (adapted from Perry, 

1995; Sutherland, 1988; and Fritz and Medlock, 1994). Storage assessment units (SAUs) consist of a reservoir 

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

unconformities or hiatuses. In some cases, subdivisions of units or lesser known correlative units are not shown.

Ss., Sandstone; Ls., Limestone; Mbr., Member.
5

Ordovician Composite SAU C50620101

By Marc L. Buursink

The Ordovician Composite SAU consists of those portions of the preserved siliciclastic and 

carbonate lithology deemed suitable as reservoirs for CO2 storage and occurring beneath a regionally 

extensive seal limited to the Arkoma Basin in Oklahoma. The Arbuckle Group, Simpson Group, and 

Viola Limestone make up this composite SAU (figs. 2 and 3). The Upper Cambrian and Lower 

Ordovician Arbuckle Group comprises thick, almost pure carbonate successions that are often 

dolomitized from subaerial and subsurface diagenesis with permeability enhanced by fracturing and 

karstification (Henry and Hester, 1995; Johnson and Merriam, 2001). A relatively large carbonate 

platform with cyclical sea-level variation was the depositional setting for the Arbuckle Group (Johnson 

and Merriam, 2001). The Middle Ordovician Simpson Group comprises sandstone, interbedded shale, and 

carbonate beds occurring above Arbuckle rocks and beneath Viola Limestone, which are separated from 

the Simpson by minor unconformities (Cole, 1975; Lee and others, 1946; Taff, 1902). The Simpson 

Group sandstones are unique in this otherwise carbonate and shale dominated section, and their deposition 

was complicated through changes in subsidence rate, quartz sand supply, and regional tectonics (Henry 

and Hester, 1995; Johnson, 1997). The Upper Ordovician Viola Limestone is a massive white and bluish 

limestone with concretions in the lower and middle sections (Taff, 1902). Self-sourced hydrocarbons are 

produced from both fracture porosity and primary porosity zones in the Viola Limestone (Evans, 1984; 

Henry and Hester, 1995). The Sylvan Shale overlies the Viola Limestone and functions as the regionally 

thick sealing formation (Adler and others, 1971; Henry and Hester, 1995; IHS Energy Group, 2010) 

(fig. 2). The Upper Ordovician Sylvan Shale of Oklahoma is laterally equivalent to the Cason Shale of 

Arkansas, where it is thinner (Perry, 1995). These shales were deposited in relatively deep and calm 

waters (Blakey, 2011; Johnson, 1997; Ham, 1973). Regionally the Sylvan Shale is a soft, green, fissile 

shale that forms swales between the Viola Limestone and overlying Hunton Group limestones (Taff, 

1902; Adler and others, 1971). Ultimately, the SAU was limited to the Arkoma Basin in Oklahoma 

because the minimum seal-thickness requirement of this assessment is met only in this part of the study 

area.

The composite SAU boundaries are defined by the depth below the surface of the uppermost 

storage formation. Here formation picks, reported in a commercial database (IHS Energy Group, 2010), 

for the Viola Limestone help define the top of the storage interval. The Ordovician Composite SAU 

C50620101 sits between 3,000 and 13,000 ft in depth and has a most likely area of about 2,297,000 acres

(fig. 3). These interpretations are supported by the cross sections and isopach maps from Adler and others 

(1971). Analyses of the stratigraphy, net-to-gross ratio, and net-porous intervals for the three storage 

formations within the composite SAU were obtained mainly from Mairs (1966) and Ramondetta (1990) 

for the Viola Limestone, from Statler (1965) and Holden (1965) for the Simpson Group, and from Latham 

(1968) and Ching and Friedman (2000) for the Arbuckle Group. The Ordovician Composite SAU gross 

thickness ranges between 3,500 and 6,000 ft with a net thickness between 800 and 1,400 ft.

The Ordovician rocks are a productive hydrocarbon interval in the Arkoma Basin, and reservoirquality data is reported in multiple forms. Besides published porosity values (Ramondetta, 1990; Sykes, 

1997) and permeability values (Read and Richmond, 1993; Carr and others, 2005), additional average 

field values were obtained from Nehring Associates, Inc. (2010), a commercial oil and gas database. The 

Ordovician Composite SAU porosity ranges between 5 and 15 percent, and permeability ranges between 

0.001 and 1,000 millidarcies (mD).
6

In addition to the storage-formation thicknesses and reservoir quality, the groundwater quality was 

investigated and buoyant storage was assessed. Water-quality data obtained for the SAU area from 

published databases and tables (Carr and others, 2005; Breit, 2002; Carr and others, 1986) indicated saline 

groundwater. Therefore, the entire area of the SAU was assessed to have a groundwater TDS value 

greater than the U.S. Environmental Protection Agency (2009, 2010) underground source of drinking 

water (USDW) limit of 10,000 mg/L. To create a probabilistic maximum volume for buoyant trapping for 

each SAU, both the size and location of hydrocarbon plays (Arkoma Basin Province Assessment Team, 

2010; Perry, 1995), along with the Nehring Associates, Inc. (2010) average field size and location, were 

used.
7

Figure 3. Map of the Ordovician Composite Storage Assessment Unit (SAU) C50620101 in the Arkoma Basin study 

area. Grid cells (one-square mile) display counts of wells derived from the IHS Energy Group (2011) well 

database that have penetrated the storage-formation top. Study area adapted from the Arkoma Basin Province 

Assessment Team (2010).
8

Hunton Group SAU C50620102

By William H. Craddock

The Hunton Group (fig. 2) is a succession of carbonates that was deposited across the southern 

midcontinent region during the Silurian and Early Devonian (Amsden, 1949, 1951, 1958a,b).

Paleogeographic reconstructions suggest that modern Arkoma Basin was located updip of the continental 

shelf edge of the Silurian and Devonian passive southern continental margin (Fritz and Medlock, 1994) 

such that the Hunton Group was deposited in a shelfal setting. Interpretation of geophysical logs from 

several transects across the Arkoma Basin region, as well as outcrop studies from the Cherokee platform, 

suggest that facies represented within the Hunton Group include supratidal carbonate mudstones, 

intertidal mudstones and skeletal wackestones, and subtidal wackestones, packstones, and mudstones 

(England, 1964; Fritz and Medlock, 1994; Rechlin, 2005). In general, the water depth of Hunton Group 

strata increases to the south, across the Arkoma Basin (Fritz and Medlock, 1994), toward the SilurianDevonian continental shelf margin. The Hunton Group is unconformably overlain by the informal 

Devonian Misener sandstone, which is thought to be an incised valley-fill deposit related to the early 

stages of a major eustatic transgression in the Middle Devonian (where present in Arkansas, this unit is 

referred to as the Sylamore Sandstone) (Amsden and Klapper, 1972; Kuykendall and Fritz, 2001). The 

Hunton and Misener interval is in turn overlain by a thick stratigraphic succession dominated by shales 

that accumulated in an open-marine setting during Devonian and Mississippian. These Devonian and 

Mississippian shales include the Woodford, Chattanooga, Caney, and Fayetteville Shales, and the 

Moorefield Formation shales (see Huffman, 1959; Sutherland, 1988; Handford, 1995; Perry, 1995).

Inspection of a basin-wide network of geophysical logs indicates that, in aggregate, these rocks are 

hundreds of feet thick across the entire Arkoma Basin region and may be greater than 1,000 ft below the 

Cretaceous and Tertiary fill of the Mississippi embayment. As such, the Devonian and Mississippian 

stratigraphic interval may constitute an excellent topseal for CO2 containment. Recent hydrocarbon 

exploration in the Devonian and Mississippian shales has been accompanied by hydraulic fracturing of 

these units, including the Woodford and the Fayetteville in Arkoma Basin. On a local scale, this activity 

may have the potential to compromise topseal quality.

The SAU boundaries are defined by the 3,000- and 13,000-ft overburden contours determined 

from a network of borehole penetrations of the Hunton Group and (or) the Misener sandstone (IHS 

Energy Group, 2010) and the Ouachita thrust-fault network along the southern basin margin (fig. 4). The 

SAU covers an area of 7,704,000 acres (± 10 percent), and the mean reservoir depth within this broad 

SAU is about 8,000 ft. Along the southern basin margin, there are several 3- to 5-mile- (mi-) wide swaths 

of rock adjacent to the Ouachita fault network, which are buried to depths greater than 13,000 ft. These 

regions were not included in our SAU (see Brennan and others, 2010). We extended the boundary of this 

SAU eastward to the edge of the Reelfoot rift (fig. 1) for a variety of reasons. First, Misener sandstone 

incised valley-fill deposits are thought to exist as far east as the Reelfoot rift (Kuykendall and Fritz, 

2001), and although there is little to no historical petroleum production across this region (Boyd, 2002), 

reservoir-quality sandstones may exist. Moreover, Hunton Group carbonates share a common marineshelf depositional setting (Fritz and Medlock, 1994) and structural history across the Arkoma region, such 

that there is a possibility of similar primary, secondary, and (or) fracture porosity in Hunton Group rocks 

in Arkansas as compared to Oklahoma, despite the lack of historical petroleum production (Kunsman, 

1967). We note that some east–west changes in depositional setting within the Hunton Group are 

probable, as indicated by the apparent lateral equivalence between the Sallisaw or Frisco Formations and 

the Penters Chert (Fritz and Medlock, 1994).
9

The Hunton Group consists of several geologic formation-rank units (see Jones, 1960; Amsden, 

1980; Campbell, 1993; and Northcutt, 1993, for details of Hunton Group stratigraphy). The group is 

thickest within a depocenter in central Arkansas, in the central part of Arkoma Basin, and generally thins 

to the west, north, and northeast (Rascoe and Hyne, 1987). The unit pinches out near the northern margin 

of Arkoma Basin. The unit is also eroded above the Arbuckle Mountain uplift in the southeastern corner 

of Arkoma Basin. Furthermore, in many places, the Hunton Group is entirely excised below the contact 

with the Devonian shale units which are the seal for the SAU (Shannon, 1962; Rascoe and Hyne, 1987). 

Based on a regional compilation of isopachs for the Hunton Group (Rascoe and Hyne, 1987), we estimate 

that the average gross thickness of the Hunton Group across the SAU is 270 ± 50 ft. 

Due to a paucity of published reservoir information about the Hunton in the Arkoma Basin, it is 

difficult to constrain the net-porous thickness on a regional level. Two intervals within the Hunton that 

may be relatively porous regionally are the Devonian Sallisaw Formation and the Silurian St. Clair (also 

called Clarita) Limestone and Quarry Mountain Formation (fig. 2) (Fritz and Medlock, 1994). These 

intervals appear to be the most common zones of hydrocarbon production within the Hunton Group 

(Nehring Associates, Inc., 2010). The Sallisaw and equivalents may be separated from the St. Clair 

Limestone and the Quarry Mountain Formation by a zone of tight carbonate (Fritz and Medlock, 1994). 

Parts of the Hunton Group are erosionally truncated, adding to the complication of estimating the regional 

mean stratigraphic thickness (Shannon, 1962). Based on inspection of regional subsurface correlations of 

borehole data, however, we estimate that the Hunton Group may contain on the order of 10 to 20 ft of 

porous rock, on average, across the region.

The Misener sandstone produces oil and gas from conventional reservoirs around the midcontinent 

region, so we also augment the gross and net thickness of the Sallisaw reservoir interval by that of the 

overlying Misener. Locally, the Misener sandstone may approach 100 ft in thickness (Amsden and 

Klapper, 1972; Kuykendall and Fritz, 2001), but most commonly it is a few to a few tens of feet thick 

where it has been penetrated in boreholes (Amsden and Klapper, 1972; Kuykendall and Fritz, 2001; 

Rechlin, 2005). Moreover, the Misener sandstone is restricted to incised valleys separated by interfluvial 

areas of nondeposition (Kuykendall and Fritz, 2001). We estimate that across the SAU, the Misener

sandstone is on the order of 10 to 20 ft thick, which slightly increases the gross thickness of the composite 

reservoir interval (Amsden and Klapper, 1972). At the scale of the entire Arkoma Basin, we estimate that 

the Hunton Group and Misener sandstone composite-reservoir interval contains a combined average of 

about 20 to 40 ft of net-porous reservoir rock.

In general, the porosity of the potential reservoir rocks appears to be relatively low and spatially 

heterogeneous. The Sallisaw Formation, for example, exhibits a combination of intercrystalline and vuggy 

porosity, and it also exhibits significant fracture porosity, particularly where strata have been faulted or 

folded (Kunsman, 1967). Average porosity for five Hunton Group reservoirs in Arkoma, distributed 

across the north-central part of Arkoma Basin, is about 12 percent with individual measurements ranging 

from 10 to 15 percent (Campbell, 1993). Because so few porosity measurements are available for Hunton 

Group reservoirs in Arkoma Basin, we also examined porosity values from the closest correlative strata 

that we could find, which were in the adjacent Anadarko Basin, despite the potential for differing 

diagenetic histories between the two basins. Measurements from six fields in the Anadarko Basin suggest 

that porosity ranges from 3 to 11 percent (Northcutt, 1993). The porosity of the Misener sandstone 

appears to be slightly greater. Although we were not able to find measurements of Misener sandstone 

porosity within Arkoma, porosity from 12 fields on the Cherokee platform, to the northwest of Arkoma 

Basin, ranges from 8 to 14 percent (Busanus, 1987). This is broadly consistent with measurements from 

the Misener sandstone in central Kansas where porosity in a Misener oil field is about 10 ± 4 percent 

(Newell and others, 2001). In light of all of this information, we estimate that about 7 ± 3 percent is the 

average porosity of the composite Hunton-Misener reservoir unit across the SAU area. 

No permeability measurements could be found for the Hunton or the Misener in Arkoma Basin, so 

again, we employed correlative rocks as analogs. Based on permeability measurements from other 

Paleozoic carbonate reservoir rocks around the United States (Nehring Associates, Inc., 2010), we assume 
10

that a reasonable lower limit on permeability for the Sallisaw is about 0.01 mD and that this is a lower 

limit on permeability for the composite reservoir interval. In neighboring Anadarko Basin, permeability of 

the Hunton Group appears to be relatively low, and measurements from the petroleum fields described 

above range from 1 to 20 mD with a modal value of about 5 mD (Northcutt, 1993). This modal 

permeability appears to be fairly similar to measurements from the Misener sandstone from central 

Kansas (Newell and others, 2001), so we suggest that 5 mD approximately describes the most likely 

permeability of this composite reservoir interval. Although Hunton Group reservoirs seem to be 

characterized by permeability values of no more than about 20 mD, the Misener exhibits permeability of 

up to about 200 mD in central Kansas (Newell and others, 2001), and we use this as an upper limit on 

permeability of the reservoir interval. We note that highly fractured reservoirs could have permeability 

significantly higher than the range of values we reported above.

The salinity of formation waters within the Hunton Group has been measured at a few locations 

across Arkoma Basin, and the waters are uniformly characterized by TDS concentrations of greater than 

100,000 mg/L (Breit, 2002). This is similar to measurements for overlying and underlying formations,

and the extremely high salinity of formation waters within the lower Paleozoic section suggests that 

deeper formations of the Arkoma Basin may be relatively good intervals to dispose of CO2 without any

risk of contaminating potential underground drinking-water sources.

The maximum pore volume available for buoyant storage was determined by multiplying the area 

of structural and (or) stratigraphic enclosure by upper bounds on the basin-averaged net-sand thickness 

and porosity (the last two parameters are described above). Oil accumulations in the Hunton Group are 

found in a combination of structural- and stratigraphic-type traps (Northcutt, 1993; Nehring Associates, 

Inc., 2010), and most oil fields are confined to the western part of the basin (Nehring Associates, Inc., 

2010). In order to estimate the total closure area within the Hunton Group, we consulted maps of 

petroleum field distribution for the western half of the basin (Boyd, 2002). Although there appears to be 

no production from Silurian or Lower Devonian strata in the eastern part of the basin, we inferred that a 

similar closure area might exist within multiple, uncharged traps based on the trap distribution in 

Oklahoma and increased the maximum closure area accordingly.
11

Figure 4. Map of the Hunton Group Storage Assessment Unit (SAU) C50620102 in the Arkoma Basin study area. 

Grid cells (one-square mile) display counts of wells derived from the IHS Energy Group (2011) well database that 

have penetrated the storage-formation top. Study area adapted from the Arkoma Basin Province Assessment 

Team (2010).
12

Batesville Sandstone and Wedington Sandstone Member SAU C50620103

By William H. Craddock

The Batesville Sandstone and the Wedington Sandstone Member of Fayetteville Shale (fig. 2) are 

sandstone lenses that are interbedded with the Mississippian Fayetteville and Caney Shales of Arkoma 

Basin. The Batesville Sandstone was deposited within a broad, delta complex that originated along the 

northeastern margin of Arkoma Basin and prograded south and west across a continental shelf that 

occupied much of present-day Arkoma Basin (Sutherland, 1988; Handford, 1995). Specific depositional 

environments represented in the Batesville include wave-dominated delta-front and shoreface (Handford, 

1995). Although the overlying Wedington Sandstone Member of Fayetteville Shale is poorly described in 

the literature, it is also thought to be a deltaic deposit, and regional patterns in Wedington thickness 

(increasing to the east) suggest that it also originated from a source along the northeastern margin of 

Arkoma Basin (Fabian, 1984; Sutherland, 1988). The encasing shales were deposited in an openmarine/prodeltaic setting (Ogren, 1968; Handford, 1995), and inspection of a regional network of well 

logs suggests that the Fayetteville-Caney interval is several hundreds of feet thick across the Arkoma 

region. These thick, open-marine shales should form robust topseals for the intercalated sandstone lenses. 

Recent hydrocarbon exploration in the Devonian and Mississippian shales in the southern midcontinent 

region has been accompanied by hydraulic fracturing of these units, including Fayetteville and Caney 

Shales in Arkoma. At least on a local scale, this activity may have the potential to compromise the quality 

of the seal.

SAU boundaries for the units are defined by the 3,000- and 13,000-ft overburden contours, the 

depositional limits of sandstones of Batesville and Wedington, and the Ouachita thrust-fault network 

along the southern basin margin (fig. 5). The SAU covers an area of about 1,781,000 acres, and the mean 

depth of the reservoir interval across this broad area appears to be about 9,000 ft. Overburden contours 

were built based on data from a regional network of borehole penetrations (IHS Energy Group, 2010), and 

the updip northern SAU limit follows the 3,000-ft overburden contour. The limit of sandstone in the 

Batesville and Wedington was based on regional correlation of well logs as well as formation tops in a 

proprietary well database (IHS Energy Group, 2010). In general, sandstone pinchouts define the eastern 

and western edges of the SAU. Importantly, most penetrations of the Batesville and the Wedington appear 

to be updip and north of the 3,000-ft contour; however, analysis of well logs indicates the potential for 

Batesville and Wedington sandstones to extend into the central and southern portion of the SAU. The 

western edge of the SAU also corresponds to an area where the gross thickness of the reservoir-seal 

interval is below 100 ft, such that topseals, particularly for the Wedington Sandstone Member, may be 

thin. We note the possibility that a Mississippian continental shelf margin may have crossed some portion 

of the SAU, such that there is a risk of major changes in reservoir stratigraphy across the southern portion 

of the SAU from shallow marine, continental shelf strata to continental shelf or basin-floor strata. Because 

any potential continental shelf margin is poorly defined, the southern SAU boundary generally 

corresponds to the Ross Creek thrust, a major thrust fault that defines the northern edge of the Ouachita 

orogenic belt locally (fig. 1) (also see Vanarsdale and Schweig, 1990). Along the southern basin margin, 

there are several 3- to 5-mi-wide swaths of rock adjacent to the Ouachita fault network that are buried at 

depths greater than 13,000 ft. These regions were not included in our SAU (see Brennan and others, 

2010). 

Analysis of a regional network of well logs suggests that the gross stratigraphic thickness of the 

Fayetteville-Caney interval, which encases the potential storage formations, increases from west to east 

across the SAU, and that the average thickness is about 250 ± 50 ft. Analysis of the same set of well logs 
13

suggests that the average net-sandstone thickness (Batesville and Wedington) within this stratigraphic 

interval is relatively small at about 10 –5/+10 ft. Regional patterns in lithofacies for the reservoir units are 

poorly described, and we again caution that there is the potential for a Mississippian continental shelf 

margin to cross the southern half of the SAU, which would likely correspond to a transition to primarily 

fine-grained rocks in the southern part of the SAU.

There is little published information addressing the rock properties of the Batesville Sandstone or 

Wedington Sandstone Member in Arkoma Basin, so we relied on data from the analogous Morrowan 

sandstones that overlie the Mississippian strata. The overlying Lower Pennsylvanian (Morrowan Series;

see Sutherland, 1988) sandstones were derived from a similar, northeasterly source area (Sutherland, 

1988), and they experienced a similar burial history to the Mississippian sandstones (Arbenz, 1989). A 

compaction curve (reservoir-averaged porosity plotted against burial depth) constructed for Lower 

Pennsylvanian sandstones suggests basin-average porosity in the reservoir interval of 11 ± 3 percent 

(Nehring Associates, Inc., 2010). Permeability measurements from the same set of sandstones suggest that 

permeability for the reservoir interval ranges from 0.01 to 100 mD, and the most likely permeability for 

the units is about 10 mD.

Although there is little empirical evidence bearing on the quality of the formation waters in the 

Mississippian stratigraphic interval, a compilation of water-quality measurements (Breit, 2002) for both 

overlying and underlying stratigraphic intervals suggests that salinities approach, or exceed, 100,000 

mg/L, even at shallow depths. Because the Mississippian strata deeper than 3,000 ft in Arkoma Basin 

appear to be too saline to be a source of potable water, Arkoma Basin may be a relatively favorable site 

for CO2 storage. 

In order to place an upper limit on the enclosed pore volume within the SAU, we first attempted to 

bracket the area of stratigraphic and (or) structural closure. This is difficult to quantify in Arkoma Basin 

because there is very little historical oil and gas production from the Batesville and the Wedington. Given 

that the northern half of Arkoma Basin is neither highly faulted nor folded, we assumed that the greatest 

potential for enclosed pore space is within stratigraphic traps or combination structural-stratigraphic traps 

over open fault-related folds. We relied on information about the size of stratigraphic traps within Upper 

Mississippian deltaic strata from the nearby Black Warrior Basin of Mississippi and Alabama to infer the 

size of potential stratigraphic traps (Nehring Associates, Inc., 2010). The Upper Mississippian interval in 

Black Warrior Basin is not only highly productive with respect to oil and gas (and therefore well 

described), it shares a similar depositional setting and burial history to the equivalent section in Arkoma 

Basin (Cleaves and Bat, 1988; Nehring Associates, Inc., 2010) making it a potentially valid analog. In 

Black Warrior Basin, Upper Mississippian deltaic stratigraphic traps typically span about 3,000 acres of 

closure area, and given the density of fields producing within these types of traps in Black Warrior, we 

speculate that as many as 30 such enclosures could exist in the Batesville Sandstone and Wedington 

Sandstone Member SAU. In order to convert this closure area to a pore volume, we multiplied by a 

reservoir thickness and an upper limit on reservoir porosity. Typically, Chesterian deltaic stratigraphic 

traps in Black Warrior Basin involve a few tens of feet of net-porous reservoir (Nehring Associates, Inc., 

2010). We derive an upper limit for reservoir porosity from the rock-property analysis described above.
14

Figure 5. Map of the Batesville Sandstone and Wedington Sandstone Member Storage Assessment Unit (SAU) 

C50620103 boundary in the Arkoma Basin study area. Grid cells (one-square mile) display counts of wells 

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

area adapted from the Arkoma Basin Province Assessment Team (2010). 
15

Geologic Framework for the National Assessment of Carbon 

Dioxide Storage Resources─Kansas Basins

By Marc L. Buursink, Madalyn S. Blondes, Philip A. Freeman, Steven M. Cahan, and Christina A. DeVera

Kansas Basins Introduction

Basin Physiography

The Kansas Basins study area (fig. 6) for the national assessment of geologic CO2 storage 

encompasses the Salina and Sedgwick Basins, along with the Forest City Basin, Nemaha uplift, and 

Cherokee platform (Barrett, 1963; Busanus, 1987). The study area boundaries were delineated to the 

southwest of the Las Animas arch and along the Cambridge arch, Central Kansas uplift, Pratt anticline 

and southern Nemaha uplift (Barrett, 1963; Busanus, 1987; Higley, 1987). The Salina Basin (fig. 6) 

covers a large area (about 10,700 mi2) including an eastern portion of Nebraska and a north-central

portion of Kansas (Coleman and Cahan, 2012). The basin is bounded to the west by the Cambridge arch 

and Central Kansas uplift, to the north by the Sioux arch, and to the east by the Nemaha uplift, whereas 

the southern boundary is a poorly defined structural saddle that separates it from the Sedgwick Basin 

(Evans, 1987; Prensky, 1995). The Salina Basin is characterized by Edmund and Goebel (1968) as a 

simple asymmetric syncline with a fairly uniform and gentle axial tilt from north to south; the basin deep 

is along the southwestern flank adjacent to the Central Kansas uplift. Though the basin contains units

from the Precambrian basement to Quaternary alluvium, the Paleozoic rocks (Ordovician through 

Pennsylvanian) comprise the bulk of the stratigraphic section and the known hydrocarbon reservoirs 

(Powers, 1994). The Sedgwick Basin (fig. 6) is a broad south-plunging shallow embayment of the 

Anadarko Basin and covers an area of about 9,900 mi2 in south-central Kansas (Prensky, 1995; Coleman 

and Cahan, 2012). The basin is bounded to the west by the Central Kansas uplift, to the south by the 

Anadarko Basin, and to the east by the Nemaha anticline, whereas the northern boundary is poorly 

defined by the structural saddle dividing it from the Salina Basin (Prensky, 1995; Evans, 1987). The basin 

contains sedimentary rocks from the Cambrian through Tertiary, which are about 6,000 ft thick (Powers, 

1994).

Besides the Salina and Sedgwick Basins, the Forest City Basin (fig. 6) extends from southwestern 

Iowa and northeastern Kansas to central Missouri (Charpentier, 1995a) with the Nemaha uplift at the 

southwest corner. The Forest City Basin is a shallow, intracratonic basin that contains Paleozoic 

sedimentary rocks (with a maximum thickness of 5,200 ft in southwestern Iowa) (Powers, 1994). The 

Nemaha uplift (fig. 6) is a regional paleostructural high that extends more than 500 mi from southeastern 

Nebraska to south-central Oklahoma (Dolton and Finn, 1989; Powers, 1994; Charpentier, 1995b). The 

uplift is composed of multiple fault blocks and structural intersections; relief on the Precambrian 

basement surface locally exceeds 3,000 ft and regionally diminishes to the south (Sims, 1985; Powers, 

1994). The 1995 USGS oil and gas assessment estimates that the Nemaha Uplift Province is about 16,100 

mi2 (Charpentier, 1995b). The Cherokee platform (fig. 6) extends from southeastern Kansas and part of 

southwestern Missouri to northeastern Oklahoma (Charpentier, 1995c). The platform is bounded to the 

east by the Ozark uplift, to the north by the Bourbon arch, to the west by the Nemaha uplift, and to the 

south by the Arkoma Basin. Although the Kansas Basins study area encompasses more physiography than 
16

just the Salina and Sedgwick Basins, these basins along with the Forest City Basin, Nemaha uplift, and 

Cherokee platform, were the focus areas for this assessment.

Geologic History

The Salina Basin was developed after the uplifting of the Nemaha anticline bisected the north 

Kansas Basins area and formed the Salina Basin on the west and the Forest City Basin on the east (Lee 

and others, 1948). Initially these basins were structural, but during the Pennsylvanian, they subsided and 

accumulated Pennsylvanian sediment (Lee and others, 1948). Three principal periods of folding are 

identified in the Salina Basin by thickness maps, and two secondary periods of folding are indicated by 

structural maps (Lee, 1956). The first folding episode occurred between Neoproterozoic and Middle 

Ordovician time, the second folding episode occurred between Middle Ordovician and Early

Mississippian, and the third folding episode occurred after Early Mississippian and was of maximum 

intensity during Late Mississippian and Early Pennsylvanian (Lee, 1956). There is faulting along the 

southwestern and southern flanks of the Salina Basin, but there is very little to no faulting within the basin 

(Edmund and Goebel, 1968).

The Sedgwick Basin is a major post-Mississippian and pre-Desmoinesian structural feature 

(Merriam, 1963). The basin, which is relatively shallow and southerly plunging, may be considered an 

extension of the Anadarko Basin, and the rocks in the basin are characterized by facies change and by 

increased thickness southward from the shallower shelf area into the deeper part of the Anadarko Basin 

proper (Merriam, 1963). Furthermore, according to Puyear and Mazzullo (2009), the Sedgwick Basin was 

an embayment of the epicontinental Permian sea (Blakey, 2011), and tectonic compression occurred in the 

basin during Mississippian time when large-scale anticlines were formed. For additional details on the 

Salina and Sedgwick Basins, along with the Forest City Basin, Nemaha uplift, and Cherokee platform and 

also for the geologic history for surrounding areas, please refer to Merriam (1963), Anderson and Wells 

(1968), Adkison (1972), and Newell and others (1987).

Hydrocarbon Exploration and Production 

Most of the Salina Basin is nonproductive for hydrocarbons because of the lack of sufficiently rich 

and mature source rocks (Prensky, 1995; Newell and Hatch, 2000). Potential hydrocarbon source rock 

maturity decreases in a northwest direction from the Forest City Basin (Prensky, 1995). Large areas of the 

Salina Basin remain untested, though about 600 wildcat wells have been drilled, and there have been no 

commercial discoveries in more than 60 years of exploration up to 1995 despite numerous oil shows 

(Prensky, 1995). In the Sedgwick Basin, the southward plunge of the productive horizons results in their 

increasing depth toward the Anadarko Basin (Prensky, 1995). In the Forest City Basin hydrocarbon 

province, exploration began in 1860 with drilling in Miami County, Kansas, resulting in the discovery of 

oil near Paola; the first discovery larger than 1 million barrels of oil equivalent (MMBOE) occurred in 

1882, also in Miami County, Kansas (Paola-Rantoul field) (Charpentier, 1995a). Up to 1995, more than

10,000 wells have been drilled, and 21 fields larger than 1 MMBOE have been discovered. Discovered 

resources as of the end of 1990 in the province total more than 100 MMBO and more than 15 BCFG 

(Charpentier, 1995a). In the Nemaha uplift hydrocarbon province, exploration began before the turn of the 

century with gas discovered in 1902, and the first discovery larger than 1 MMBOE occurred in 1903 in 

Cowley County, Kansas (Dexter field) (Charpentier, 1995b). Up to 1995, more than 45,000 wells have 

been drilled, and 194 fields larger than 1 MMBOE have been discovered, and up to 1990, discovered 

resources have been more than 2.4 billion barrels of oil (BBO) and more than 6.1 trillion cubic feet of gas 

(TCFG) (Charpentier, 1995b). In the Cherokee platform hydrocarbon province, exploration began in the 

1860s, and the first discovery took place in 1873 in Allen County, Kansas (Iola field) (Charpentier, 

1995c). Up to 1995, more than 200,000 wells have been drilled, and 431 fields larger than 1 MMBOE 

have been discovered, and discovered resources as of 1990 in the province were more than 5.3 BBO and 
17

4.3 TCFG (Charpentier, 1995c). “This part of the Mid-Continent region is one of the oldest oil and gas 

producing areas of the United States” (Powers, 1994).

Storage Resource Assessment

The regional CO2 storage resource assessment of the Kansas Basins resulted in two SAUs located 

in the Salina and Sedgwick Basins only. Each SAU is described in the following sections, and each 

includes a regional seal and storage formation(s) pair. The SAU name is typically based on the whole 

stratigraphic interval or lithology considered for storage (fig. 7). The geographic extents of the SAUs are 

defined by the storage-formation-top depth and by the geologic characteristics of the reservoir and the 

overlying caprock. The geologic characteristics described or considered for each SAU include both the 

seal and reservoir thickness distribution and 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 aquifers with a TDS concentration less 

than 10,000 mg/L may not be used for CO2 storage. For the Kansas Basins assessment, groundwater 

quality, based on TDS content, was assembled from multiple sources as described in subsequent sections.

The assessment is conducted following the methodology of Burruss and others (2009), Brennan 

and others (2010), and Blondes and others (2013), which prescribe the appropriate geologic model 

detailed above, 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, we differentiate our assessed storage 

resource 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 hydrocarbon production with the known hydrocarbon reserve volume, 

whereas the most likely buoyant-trapping volume adds the minimum volume and the estimated volume of 

undiscovered resources (Gautier and others, 1995; 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 in parentheses, are described: Lower Paleozoic Composite SAU 

(C50560101) and Hunton Group SAU (C50560102) (fig. 7).
18

Figure 6. Map of the Kansas Basins study area including major tectonic elements (after Busanus, 1987; Barrett, 

1963) and boundaries adapted from the U.S. Geological Survey national oil and gas assessment (NOGA) 

(Prensky, 1995; Charpentier, 1995a,b,c).
19

Figure 7. Generalized stratigraphic column of geologic units in Kansas Basins study area (adapted from Prensky, 

1995). Storage assessment units (SAUs) consist of a reservoir (red) and a regional seal (blue). Wavy lines 

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

subdivisions of units or lesser known correlative units are not shown.
20

Lower Paleozoic Composite SAU C50560101

By Marc L. Buursink

The Lower Paleozoic Composite SAU consists of those portions of the preserved siliciclastic and 

carbonate lithology deemed suitable as reservoirs for CO2 storage occurring beneath a regionally 

extensive seal in the Kansas Basins (fig. 8). The Arbuckle Group, Simpson Group, and Viola Limestone 

make up this composite SAU (fig. 7). The Upper Cambrian and Lower Ordovician Arbuckle Group 

includes thick, almost pure carbonate successions, which are often dolomitized from subaerial and 

subsurface diagenesis and are enhanced by fracturing (Prensky, 1995; Johnson and Merriam, 2001; 

Franseen and others, 2004). A very large carbonate platform with cyclical sea-level variation was the 

depositional setting for the Arbuckle Group (Johnson and Merriam, 2001). The Middle Ordovician 

Simpson Group comprises sandstone, interbedded shale, and carbonate beds occurring above Arbuckle 

rocks and beneath Viola Limestone, which are separated by minor unconformities (Taff, 1902; Lee and 

others, 1946; Cole, 1975). The Simpson Group sandstones are exceptional in this carbonate and shale 

dominated section because their composition and deposition were complicated through changes in 

subsidence, quartz sand supply, and tectonics (Prensky, 1995; Johnson, 1997). The Upper Ordovician 

Viola Limestone is a massive white and bluish limestone with concretions in the lower and middle 

sections (Taff, 1902). Self-sourced hydrocarbons are produced from both fracture porosity and primary 

porosity zones in the Viola Limestone (Prensky, 1995; Evans, 1984). The Sylvan Shale overlies the Viola 

Limestone and functions as the regionally thick sealing formation (Adler and others, 1971; Adkison, 

1972; IHS Energy Group, 2010) for the purpose of this assessment. The Upper Ordovician Sylvan Shale 

is equivalent to the Maquoketa and Cason Shales, and these were all deposited in relatively deep and calm 

waters (Johnson, 1997; Blakey, 2011). Regionally the Sylvan Shale is a soft, green, fissile shale that 

forms swales between the harder under- and overlying limestone formations (Taff, 1902; Adler and 

others, 1971).

The composite SAU boundaries are defined by the depth below the surface of the uppermost 

storage formation. Here formation picks for the Viola Limestone, reported in a commercial database (IHS 

Energy Group, 2010), help define the top of the storage interval. The Lower Paleozoic Composite SAU 

C50560101 occurs between 3,000 and 4,000 ft in depth and has a most likely area of about 2,415,000 

acres (fig. 8). These interpretations are supported by the cross sections and isopach maps from Adler and 

others (1971) and Rascoe and Hyne (1987) and by descriptions and maps from Cole (1975). Analyses of 

the stratigraphy, net-to-gross ratio, and net-porous intervals for the three formations within the composite 

SAU were obtained mainly from Mairs (1966) and Ramondetta (1990) for the Viola Limestone, from 

Holden (1965) and Statler (1965) for the Simpson Group, and from Latham (1968) and Ching and 

Friedman (2000) for the Arbuckle Group. The Lower Paleozoic Composite SAU gross thickness ranges 

from 200 to 800 ft with a net thickness between about 70 and 250 ft. Ultimately, the SAU was limited to 

the Salina and Sedgwick Basins because the minimum assessment seal-thickness and depth requirements

are met only in this part of the study area.

The lower Paleozoic rocks are a somewhat productive hydrocarbon interval in the Kansas Basins 

and reservoir-quality data is reported in multiple forms. Besides published porosity values (Walters, 1958; 

Ramondetta, 1990; Ching and Friedman, 2000) and permeability values (Read and Richmond, 1993; Carr 

and others, 2005), additional average field values were obtained from Nehring Associates, Inc. (2010), a 

commercial oil and gas database. The Lower Paleozoic Composite SAU porosity ranges from 5 to 15

percent, and permeability ranges between 0.01 and 1,000 mD.
21

In addition to the storage-formation thicknesses and reservoir quality, the groundwater quality and 

buoyant storage were also assessed. Water-quality data obtained for the SAU area from multiple 

published databases and tables (Jorgensen and others, 1993; Breit, 2002; Carr and others, 2005) indicated 

mostly saline groundwaters. Therefore, a large area fraction of the SAU has a groundwater TDS value 

greater than the USDW limit of 10,000 mg/L. To create a probabilistic maximum volume for buoyant 

trapping for each SAU, both the size and location of hydrocarbon plays (Prensky, 1995), field size 

information from the Kansas Geological Survey (2012), along with the Nehring Associates, Inc. (2010) 

average field size and location, were used.
22

Figure 8. Map of the Lower Paleozoic Composite Storage Assessment Unit (SAU) C50560101 in the Kansas 

Basins study area. Grid cells (one-square mile) display counts of wells derived from the IHS Energy Group 

(2011) well database that have penetrated the storage-formation top. Study area adapted from the U.S. 

Geological Survey national oil and gas assessment (NOGA) (Prensky, 1995; Charpentier, 1995a,b,c).
23

Hunton Group SAU C50560102

By Marc L. Buursink

The Hunton Group SAU consists of those portions of the preserved siliciclastic and carbonate 

lithology deemed suitable as reservoirs for CO2 storage occurring beneath a regionally extensive seal in 

the Kansas Basins (fig. 9). Included in this assessment are the informal Misener sandstone and Hunton 

Group intervals (fig. 7). The Misener sandstone comprises quartz grains in a carbonate cement and tends

to produce in abundant quantity but is elusive to oil discovery (Francis, 1991). These Devonian rocks of 

the Misener were deposited during minor changes in sea level, and the reservoir distribution consists of

lenses within incised-valley fills (Busanus, 1987; Kuykendall and Fritz, 2001). For the purpose of this 

SAU, these widely scattered rocks are not included in the SAU name. The Misener sandstone 

unconformable overlies the Hunton Group (Amsden and Klapper, 1972). The Hunton Group, first 

identified as a limestone by Taff (1902), now includes limestone and dolomite strata of Silurian and Early

Devonian ages (Zeller, 1968). The Hunton Group consists of, in descending order, the Bois d'Arc 

Limestone, the Haragan Shale, Henryhouse Formation (dolomite and calcareous shale), and the 

Chimneyhill Limestone (limestone with dolomite and calcareous shale) (Amsden, 1980; Fritz and

Medlock, 1995). The carbonate rocks were deposited on a shallow ramp where sea-level changes caused 

migration of facies and generated multiple disconformities, which are now used to define the stratigraphic 

divisions above (Johnson and Merriam, 2001; Blakey, 2011). The Chattanooga (Woodford equivalent) 

Shale overlies the Hunton Group and functions as the regionally thick sealing formation (Conant and 

Swanson, 1961; Amsden and others, 1967; Isom, 1976) for the purpose of this assessment. This shale is 

dark gray to black throughout its areal extent; the lower part is commonly siliceous with phosphate 

nodules and lenses and locally contains thin beds of chert and is generally considered to be a good source 

rock (Kuykendall and Fritz, 2001). The Chattanooga Shale is Late Devonian and Early Mississippian in 

age, is equivalent to the Kinderhook Shale and the Woodford Shale of Oklahoma, and is typically picked 

at the top of a strong positive gamma-ray response in well logs in Oklahoma (Swanson, 1961; Hester and 

others, 1990; IHS Energy Group, 2011). The Chattanooga Shale was deposited in a low-energy marine 

environment, though relatively deep sea or restricted basin deposition are possible (Conant and Swanson, 

1961; Ettensohn, 1995; Blakey, 2011). 

The SAU boundaries are defined by the depth below the surface of both the Hunton Group and the 

Misener sandstone. Here rock-unit picks, reported in a commercial database (IHS Energy Group, 2010), 

for the two units help define the top of the storage interval. The Hunton Group SAU occurs between 

3,000 and 3,700 ft in depth and has about a 1,027,000-acre most likely area (fig. 9). These interpretations 

are supported by the cross sections and isopach maps from Merriam (1963), Adler and others (1971), and 

Rascoe and Hyne (1987). Analyses of the stratigraphy, net-to-gross ratio, and net-porous intervals for the 

two units within the SAU were obtained through published logs and cross sections (Francis, 1991; Fritz 

and Medlock, 1995; Kuykendall and Fritz, 2001). The Hunton Group SAU gross thickness ranges from 

55 to 210 ft with a net thickness between 20 and 90 ft. Ultimately, the SAU was limited to the Salina and 

Sedgwick Basins because the minimum assessment seal-thickness and depth requirements are met only in 

this part of the study area.

The Hunton Group rocks are a somewhat productive hydrocarbon interval in the Kansas Basins,

and reservoir-quality data is reported in multiple forms. Besides published porosity values (Francis, 1991; 

Busanus, 1987) and permeability values (Newell and others, 2001; Northcutt, 1993), additional average 

field values were obtained from Nehring Associates, Inc. (2010), a commercial oil and gas database. The 
24

Hunton Group SAU porosity ranges from 6 to 10 percent, and the permeability ranges from 0.01 to 120 

mD.

In addition to the storage-formation thicknesses and reservoir quality, the groundwater quality and 

buoyant storage were also assessed. Water-quality data obtained for the SAU area from a published 

database (Breit, 2002) indicated saline groundwaters. Furthermore, evaporite beds in the Kansas Basins 

yield brackish groundwaters (Merriam, 1963; Lane and Miller, 1965). Therefore, the entire area fraction 

of the SAU has a groundwater TDS value greater than the USDW limit of 10,000 mg/L. To create a 

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

hydrocarbon plays (Prensky, 1995), field size information from the Kansas Geological Survey (2012) and 

from Newell and others (1987), and the Nehring Associates, Inc. (2010) average field size and location 

were used.
25

Figure 9. Map of the Hunton Group Storage Assessment Unit (SAU) C50560102 in the Kansas Basins study area. 

Grid cells (one-square mile) display counts of wells derived from the IHS Energy Group (2011) well database that 

have penetrated the storage-formation top. Study area adapted from the U.S. Geological Survey national oil and 

gas assessment (NOGA) (Prensky, 1995; Charpentier, 1995a,b,c).
26

Geologic Framework for the National Assessment of Carbon 

Dioxide Storage Resources─Midcontinent Rift Basin

By Marc L. Buursink, Steven M. Cahan, and Celeste D. Lohr

Midcontinent Rift Basin Introduction

Basin Physiography

The Midcontinent Rift Basin (MCRB) is a large arcuate Mesoproterozoic rift zone that extends 

from southeastern Ontario, Canada, to northern Michigan and terminates in northeast Kansas and has an 

area of about 100,515 mi2 (Coleman and Cahan, 2012) (fig. 10). The boundary for this study area is 

derived from the basin outlines shown in Ojakangas and others (2001) and in Van Schmus and Hinze 

(1985). For most of its extent, the MCRB does not have a surface expression as a rift basin, and thus its 

boundaries and structure has been determined by gravity and aeromagnetic maps (Chandler and others, 

1989), seismic profiles, and infrequent well penetrations; however, it is exposed in western Michigan, 

northern Wisconsin, and southeastern Minnesota (Coleman and Cahan, 2012). The MCRB is 

characterized by broad medial horsts, mainly comprising layered basaltic volcanic rock, bounded by highangle normal or reverse faults, and flanked by asymmetric half-graben-style basins mostly filled with 

sedimentary clastic rock, which may be as much as 30,000 ft thick (Palacas, 1995). The depths calculated 

for these basins depend on the densities assumed for the sedimentary rocks interpreted from geophysical 

surveys (McSwiggen and others, 1987).

Geologic History

The main MCRB section is a failed continental rift of Mesoproterozoic age (about 1.1 billion 

years ago); a related arm of the rift extends from eastern Lake Superior southeastward to the southern 

boundary of Michigan (Palacas, 1995). A new ocean basin nearly formed before rifting ceased, likely 

because of the distant Grenville continental collision to the east. Broad sagging and subsidence, combined 

with a system of axial half-grabens, provided accommodation space along the length of the MCRB 

(Ojakangas and others, 2001). Four interpreted geophysical surveys show the basin asymmetry and the 

off-axis placement of mafic rocks, along with the positions of the interpreted growth faults (Chandler and 

others, 1989). For example, seismic-reflection surveys by the Great Lakes International Multidisciplinary 

Program on Crustal Evolution (GLIMPCE) (Behrendt and others, 1988) in 1986 imaged the deep 

structure of the rift beneath the Great Lakes and revealed an asymmetrical graben whose existence and 

magnitude was previously unknown (Cannon and others, 1989). Early sedimentation in the MCRB was 

followed by further broad crustal sagging and deposition of progressively more mature red-bed, fluvial 

sediments with a distant source (Ojakangas and others, 2001).

Specifically, only Keweenawan age rocks are exposed in the Lake Superior region and can be 

roughly divided into two groups: rift-basin igneous rocks (Duluth Complex of the Keweenawan 

Supergroup) and the overlying upper Keweenawan Supergroup sedimentary rocks (Dickas, 1986; Van 

Schmus and Hinze, 1985). These clastic rocks comprise an older Oronto Group and a younger Bayfield 

Group. The Nonesuch Formation is the primary formation of the Oronto Group and is composed of 

porous fluvial, deltaic, and shoreline sandstones (Thorleifson, 2008). The underlying Copper Harbor 

Conglomerate also has acceptable porosity (Thorleifson, 2008). Ultimately, geophysical surveys provide 
27

the key results on sedimentary rock depth and distribution (Thorleifson, 2008; Chandler and others, 

1989).

Hydrocarbon Exploration and Production

No commercial hydrocarbons have been found in the MCRB. Nevertheless, NOGA identified one 

hypothetical conventional play (Precambrian Midcontinent Rift System Play) in their Superior Province 

oil and gas system (Palacas, 1995). Basin modeling and source rock studies have indicated the possibility 

of hydrocarbons in this province (Thorleifson, 2008; Palacas, 1995). For example, in the Nonesuch 

Formation, live oil seeps in the White Pine Copper Mine in Michigan confirm that liquid hydrocarbons 

have been generated (Thorleifson, 2008). Limited wildcat drilling has been documented in the MCRB. 

For example, in 1987, Amoco Production Company drilled the Eischeid No. 1 petroleum exploration well 

in west-central Carroll County, Iowa, to a total depth of 17,851 ft (Thorleifson, 2008). The well had minor 

occurrences of gaseous hydrocarbons detected in the Proterozoic section (Thorleifson, 2008). In 1992, the 

Terra-Patrick No. 7-22 deep hydrocarbon test was completed in Bayfield County, Wisconsin, to a depth of 

4,966 ft and had very minor occurrences of natural gas detected within carbonaceous shale of the 

Nonesuch Formation (Thorleifson, 2008). This well marked the end of about nine years of hydrocarbon 

exploration in Mesoproterozoic rocks of the midcontinent rift trend of Wisconsin and may likely be the 

last well drilled in the trend until geologic interpretations and regulatory procedures improve (Thorleifson, 

2008).

Storage Resource Assessment

The regional CO2 storage resource investigation of the MCRB resulted in no SAUs. The 

investigation was conducted following the methodology of Blondes and others (2013), Brennan and 

others (2010), and Burruss and others (2009), which prescribe the appropriate geologic model, a 

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

(2008) concluded that the limited available information (on MCRB sediment lithostratigraphy, 

depositional history, physical properties, and hydrogeology) indicates that the MCRB has attributes that 

make it far less suitable for storage than other sites currently being considered across the country.

Furthermore, permeability loss of the Copper Harbor Conglomerate at high pressure makes it an unlikely 

candidate for storage (Hart and LaMaskin, 2011). Ultimately, because suitable storage formations meeting 

our size, depth, reservoir-quality, and regional-seal guidelines were not found, SAUs were not generated

for the MCRB study area.
28

Figure 10. Map of the Midcontinent Rift Basin study area including major tectonic elements (after Thorleifson, 2008; 

Huber, 1975) and boundaries adapted from the U.S. Geological Survey national oil and gas assessment (NOGA) 

(Gautier and others, 1995).
29

Acknowledgments

Paul Schuben and Brian Varela helped to compile the drilling and hydrocarbon production data for 

the study areas. Troy Cook, Mahendra Verma, and Hossein Jahediesfanjani helped to interpret the 

petroleum engineering data for the study areas. The Oklahoma Geological Survey, the Southwest 

Regional Partnership on Carbon Sequestration, David Hart from the Wisconsin Geological and Natural 

History Survey, and Harvey Thorleifson and Val Chandler from the Minnesota Geological Survey helped 

by supplying geologic information and interpretations for the study areas. The content and presentation of 

this report benefited greatly from the technical reviews by James Coleman and Philip Nelson.

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