U.S. Department of the Interior

U.S. Geological Survey

Open-File Report 2015–1239

Play-Level Distributions of Estimates of Recovery Factors for 

a Miscible Carbon Dioxide Enhanced Oil Recovery Method 

Used in Oil Reservoirs in the Conterminous United States

Play-Level Distributions of Estimates of 

Recovery Factors for a Miscible Carbon 

Dioxide Enhanced Oil Recovery Method 

Used in Oil Reservoirs in the Conterminous 

United States

By E.D. Attanasi and P.A. Freeman

Open-File Report 2015–1239

U.S. Department of the Interior

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

SALLY JEWELL, Secretary

U.S. Geological Survey

Suzette M. Kimball, Director

U.S. Geological Survey, Reston, Virginia: 2016

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Suggested citation:

Attanasi, E.D., and Freeman, P.A., 2016, Play-level distributions of estimates of recovery factors for a miscible carbon 

dioxide enhanced oil recovery method used in oil reservoirs in the conterminous United States: U.S. Geological Survey 

Open-File Report 2015–1239, 36 p., http://dx.doi.org/10.3133/ofr20151239.

ISSN 2331-1258 (online)
iii

Contents

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

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

Calculation of Reservoir-Specific Recovery Factors and Net CO2 Utilization .....................................2

Calculation Algorithm...........................................................................................................................2

Data Required for Calculation of Recovery Factors and Assumptions .......................................3

Distributions of Recovery Factors and Estimates of Net CO2 Utilization ..............................................4

Format of Results ..................................................................................................................................4

Discussion of Play-Level Recovery-Factor Distributions for Regions .........................................6

Summary and Conclusions...........................................................................................................................7

Acknowledgments.........................................................................................................................................8

References Cited............................................................................................................................................8

Figures

1. Map of the conterminous United States showing the petroleum province 

boundaries in seven of the eight regions used in the U.S. Geological Survey’s 

1995 National Oil and Gas Assessment (NOGA)......................................................................5

2. Boxplots of recovery factors for technically recoverable oil that might be 

produced by use of a miscible carbon dioxide enhanced oil recovery (CO2-EOR) 

method from clastic oil reservoirs in plays within Region 2, the Pacific Coast 

Region...........................................................................................................................................11

3. Boxplots of recovery factors for technically recoverable oil that might be 

produced by use of a miscible carbon dioxide enhanced oil recovery (CO2-EOR) 

method from (A) clastic and (B) carbonate oil reservoirs in plays within Region 3, 

the Colorado Plateau and Basin and Range Region.............................................................13

4. Boxplots of recovery factors for technically recoverable oil that might be 

produced by use of a miscible carbon dioxide enhanced oil recovery (CO2-EOR) 

method from (A) clastic and (B) carbonate oil reservoirs in plays within Region 4, 

the Rocky Mountains and Northern Great Plains Region, excluding plays in the 

Powder River Basin Province...................................................................................................16

5. Boxplots of recovery factors for technically recoverable oil that might be 

produced by use of a miscible carbon dioxide enhanced oil recovery (CO2-EOR) 

method from clastic oil reservoirs in plays within the Powder River Basin 

Province of Region 4 ..................................................................................................................17

6. Boxplots of recovery factors for technically recoverable oil that might be 

produced by use of a miscible carbon dioxide enhanced oil recovery (CO2-EOR) 

method from (A) clastic and (B) carbonate oil reservoirs in plays within the 

Permian Basin Province of Region 5 .......................................................................................20

7. Boxplots of recovery factors for technically recoverable oil that might be 

produced by use of a miscible carbon dioxide enhanced oil recovery (CO2-EOR) 

method from (A) clastic and (B) carbonate oil reservoirs in plays within the 

Bend Arch-Fort Worth Basin Province of Region 5 ..............................................................21
iv

Tables

1. Numbers of clastic and carbonate oil reservoirs that are candidates for the 

application of a miscible CO2-EOR method in plays of Region 2, the Pacific 

Coast Region................................................................................................................................10

2. Distributions of recovery factors for technically recoverable oil that might be 

produced by use of a miscible carbon dioxide enhanced oil recovery (CO2-EOR) 

method and the median net CO2 utilization for plays in Region 2, the Pacific 

Coast Region................................................................................................................................11

3. Numbers of clastic and carbonate oil reservoirs that are candidates for the 

application of a miscible CO2-EOR method in plays of Region 3, the Colorado 

Plateau and Basin and Range Region.....................................................................................12

4. Distributions of recovery factors for technically recoverable oil that might be 

produced by use of a miscible carbon dioxide enhanced oil recovery (CO2-EOR) 

method and the median net CO2 utilization for plays in Region 3, the Colorado 

Plateau and Basin and Range Region.....................................................................................12

5. Numbers of clastic and carbonate oil reservoirs that are candidates for the 

application of a miscible CO2-EOR method in plays of Region 4, the Rocky 

Mountains and Northern Great Plains Region.......................................................................14

8. Boxplots of recovery factors for technically recoverable oil that might be 

produced by use of a miscible carbon dioxide enhanced oil recovery (CO2-EOR) 

method from (A) clastic and (B) carbonate oil reservoirs in plays within the 

Western Gulf Province of Region 6..........................................................................................25

9. Boxplots of recovery factors for technically recoverable oil that might be 

produced by use of a miscible carbon dioxide enhanced oil recovery (CO2-EOR) 

method from (A) clastic and (B) carbonate oil reservoirs in plays within the 

Louisiana-Mississippi Salt Basins Province of Region 6 .....................................................27

10. Boxplots of recovery factors for technically recoverable oil that might be 

produced by use of a miscible carbon dioxide enhanced oil recovery (CO2-EOR) 

method from (A) clastic and (B) carbonate oil reservoirs in plays within Region 7, 

the Midcontinent Region, excluding plays in the Anadarko Basin Province ...................31

11. Boxplots of recovery factors for technically recoverable oil that might be 

produced by use of a miscible carbon dioxide enhanced oil recovery (CO2-EOR) 

method from (A) clastic and (B) carbonate oil reservoirs in plays within the 

Anadarko Basin Province of Region 7.....................................................................................33

12. Boxplots of recovery factors for technically recoverable oil that might be 

produced by use of a miscible carbon dioxide enhanced oil recovery (CO2-EOR) 

method from carbonate oil reservoirs in plays within Region 8, the Eastern 

Region...........................................................................................................................................35

13. Histograms representing the distribution of recovery factors for (A) 2,018 clastic 

and (B) 1,681 carbonate conventional oil reservoirs in the conterminous 

United States ...............................................................................................................................36

14. Histograms representing the distribution of CO2 retention factors for (A) 2,018 

clastic and (B) 1,681 carbonate conventional oil reservoirs in the conterminous 

United States ...............................................................................................................................36
v

6. Distributions of recovery factors for technically recoverable oil that might be 

produced by use of a miscible carbon dioxide enhanced oil recovery (CO

2

-EOR) 

method and the median net CO

2

 utilization for plays in Region 4, the Rocky 

Mountains and Northern Great Plains Region, excluding plays in the Powder 

River Basin Province..................................................................................................................15

7. Distributions of recovery factors for technically recoverable oil that might be 

produced by use of a miscible carbon dioxide enhanced oil recovery (CO

2

-EOR) 

method and the median net CO

2

 utilization for plays in the Powder River Basin 

Province of Region 4 ..................................................................................................................17

8. Numbers of clastic and carbonate oil reservoirs that are candidates for the 

application of a miscible CO

2

-EOR method in plays of Region 5, the West Texas 

and Eastern New Mexico Region ............................................................................................18

9. Distributions of recovery factors for technically recoverable oil that might be 

produced by use of a miscible carbon dioxide enhanced oil recovery (CO

2

-EOR) 

method and the median net CO

2

 utilization for plays in the Permian Basin 

Province of Region 5 ..................................................................................................................19

10. Distributions of recovery factors for technically recoverable oil that might be 

produced by use of a miscible carbon dioxide enhanced oil recovery (CO

2

-EOR) 

method and the median net CO

2

 utilization for plays in the Bend Arch-Fort Worth 

Basin Province of Region 5 .......................................................................................................21

11. Numbers of clastic and carbonate oil reservoirs that are candidates for the 

application of a miscible CO

2

-EOR method in plays of Region 6, the Gulf Coast 

Region...........................................................................................................................................22

12. Distributions of recovery factors for technically recoverable oil that might be 

produced by use of a miscible carbon dioxide enhanced oil recovery (CO

2

-EOR) 

method and the median net CO

2

 utilization for plays in the Western Gulf Province 

of Region 6 ...................................................................................................................................24

13. Distributions of recovery factors for technically recoverable oil that might be 

produced by use of a miscible carbon dioxide enhanced oil recovery (CO

2

-EOR) 

method and the median net CO

2

 utilization for plays in the Louisiana-Mississippi 

Salt Basins Province of Region 6 .............................................................................................26

14. Numbers of clastic and carbonate oil reservoirs that are candidates for the 

application of a miscible CO

2

-EOR method in plays of Region 7, the Midcontinent 

Region...........................................................................................................................................28

15. Distributions of recovery factors for technically recoverable oil that might be 

produced by use of a miscible carbon dioxide enhanced oil recovery (CO

2

-EOR) 

method and the median net CO

2

 utilization for plays in Region 7, the Midcontinent 

Region, excluding plays in the Anadarko Basin Province...................................................30

16. Distributions of recovery factors for technically recoverable oil that might be 

produced by use of a miscible carbon dioxide enhanced oil recovery (CO

2

-EOR) 

method and the median net CO

2

 utilization for plays in the Anadarko Basin 

Province of Region 7 ..................................................................................................................32

17. Numbers of clastic and carbonate oil reservoirs that are candidates for the 

application of a miscible CO

2

-EOR method in plays of Region 8, the Eastern 

Region...........................................................................................................................................34

18. Distributions of recovery factors for technically recoverable oil that might be 

produced by use of a miscible carbon dioxide enhanced oil recovery (CO

2

-EOR) 

method and the median net CO

2

 utilization for plays in Region 8, the Eastern 

Region...........................................................................................................................................34
vi

Conversion Factors

Multiply By To obtain

Length

foot (ft) 0.3048 meter (m)

Volume

cubic foot (ft3) 0.02832 cubic meter (m3)

gallon (gal) 0.003785 cubic meter (m3)

barrel (bbl; petroleum, 

1 barrel=42 gal)

0.1590 cubic meter (m3)

thousands of cubic feet (mcf) of 

CO2 per barrel of produced 

oil at the surface at standard 

conditions of 14.7 psi and 60 °F

0.3506 metric ton of CO2 per cubic meter 

of produced oil at the surface at 

standard conditions of 14.7 psi 

and 60 oF

Pressure

Pound-force per square inch (psi) 6.895 kilopascal (kPa)

Permeability

millidarcy (mD) 9.869 x 10−16 square meter (m2)

Viscosity

centipoise (cP) 1 millipascal second (mPa · s)
vii

Abbreviations

API American Petroleum Institute

ARI Advanced Resources International

bbl barrel

CO2 carbon dioxide

CO2-EOR carbon dioxide (CO2) enhanced oil recovery (EOR)

CRD Comprehensive Resource Database

EIA U.S. Energy Information Administration

EOR enhanced oil recovery

ft feet

HCPV hydrocarbon pore volume

mcf thousand cubic feet

mcf/bbl thousand cubic feet per barrel

mD millidarcy

MMP minimum miscibility pressure

NPC National Petroleum Council

psi pound-force per square inch

USGS U.S. Geological Survey

WAG water-alternating-gas

Play-Level Distributions of Estimates of Recovery Factors for 

a Miscible Carbon Dioxide Enhanced Oil Recovery Method 

Used in Oil Reservoirs in the Conterminous United States

By E.D. Attanasi and P.A. Freeman

Abstract

In a U.S. Geological Survey (USGS) study, recovery-factor estimates were calculated by using a publicly available reservoir simulator (CO2

 Prophet) to estimate how much oil might be recovered with the application of a miscible carbon dioxide 

(CO2) enhanced oil recovery (EOR) method to technically screened oil reservoirs located in onshore and State offshore areas in 

the conterminous United States. A recovery factor represents the percentage of an oil reservoir’s original oil in place estimated 

to be recoverable by the application of a miscible CO2-EOR method. The USGS estimates were calculated for 2,018 clastic and 

1,681 carbonate candidate reservoirs in the “Significant Oil and Gas Fields of the United States Database” prepared by Nehring 

Associates, Inc. (2012).

This report presents distributions of estimated recovery factors organized by plays in seven U.S. regions. The distributional 

parameters for plays containing at least three candidate reservoirs are presented in tables, and parameters for plays containing 

at least six candidate reservoirs are presented in boxplots. Over all the reservoirs evaluated, 90 percent of the recovery-factor 

estimates for clastic reservoirs fell within the range from 8.7 to 16.2 percent, and the median value of the distribution was 9.5 

percent. Similarly, 90 percent of the recovery-factor estimates for carbonate reservoirs were within the range from 11.8 to 27.5 

percent, and the median value of the distribution was 13.6 percent. Both distributions were right skewed.

The retention factor is the percentage of injected CO2 that is naturally retained in the reservoir. Retention factors were also 

estimated in this study. For clastic reservoirs, 90 percent of the estimated retention factors were between 21.7 and 32.1 percent, 

and for carbonate reservoirs, 90 percent were between 23.7 and 38.2 percent. The respective median values were 22.9 for clastic 

reservoirs and 26.1 for carbonate reservoirs. Both distributions were right skewed. The recovery and retention factors that were 

calculated are consistent with the corresponding factors reported in the literature.

Introduction

Studies by the National Petroleum Council (1984), by Advanced Resources International (ARI, 2006a, b, c, d), and by ARI 

and the U.S. Department of Energy, National Energy Technology Laboratory (Wallace and others, 2013) have yielded estimates 

of the volume of oil that could potentially be produced with the application of a miscible carbon dioxide (CO2) enhanced oil 

recovery (EOR) method to selected reservoirs in the United States. The results of these studies were reported at the national 

and regional levels, and some estimates were reported at the petroleum province level. These sources suggested that significant 

volumes of oil could be recovered if this tertiary recovery method had widespread application. The Oil and Gas Journal’s 2014 

EOR survey (Koottungal, 2014) showed that gas injection projects outnumbered projects using other tertiary recovery methods 

in the United States and that carbon dioxide was the most commonly used injection fluid for miscible operations.

The miscible CO2 enhanced oil recovery process is implemented by injecting CO2 and water into an oil reservoir where 

conditions of miscibility are maintained. This process is most commonly initiated after the reservoir has undergone a waterflood 

secondary recovery program. Under conditions of miscibility, the injected CO2 dissolves into oil to vaporize lighter fractions of 

the oil and also reduce the viscosity of the residual oil (Teletzke and others, 2005).
2 Play-Level Distributions of Estimates of Recovery Factors for a Miscible CO2

-EOR Method

This report presents estimates by petroleum play of recovery factors for technically recoverable oil that could be produced 

by the use of a miscible CO2-EOR method. The CO2-EOR recovery factor, as defined here, represents the fraction of the producing pattern’s1

 original oil in place that would be recovered over the duration of the EOR project. For this study, it is interpreted 

to represent technically recoverable2 oil because no economic screen or cutoff is applied. In particular, the recovery factors 

represent the percentage of original oil in place that could be recovered from the application of a miscible CO2-EOR method, 

irrespective of oil prices or input costs, by using current recovery technology.

Enhanced oil recovery processes are applied at the reservoir level. According to the U.S. Energy Information Administration (EIA, 2000), a conventional oil reservoir is defined as an underground formation containing an individual and separate pool 

of producible oil that is confined by impermeable rock or water barriers and is characterized by a single natural pressure system. 

A field may consist of a single reservoir or multiple reservoirs that are not in communication but which may be associated with 

or related to a single structural or stratigraphic feature (U.S. Energy Information Administration, 2000). For this study, an oil 

reservoir is defined as having a gas-to-oil ratio of no more than 10,000 cubic feet of natural gas/1 barrel of oil at standard surface 

conditions (14.7 pound-forces per square inch and 60 °F).

During the CO2-EOR process, the injected CO2 will be miscible with the oil if the reservoir pressure is maintained at least 

as high as the minimum miscibility pressure (MMP) of the oil. The MMP depends on the composition of the oil and the reservoir temperature (Mungan, 1981). The formation fracture pressure, which is calculated by using an appropriate pressure gradient 

and depth, must also be greater than the MMP to assure that miscibility can actually be attained. In the implementation of actual 

CO2-EOR programs, the reservoir pressure at completion of the waterflood stage is commonly increased to the MMP by shutting 

in all production wells and then injecting water into the reservoir.

For this U.S. Geological Survey (USGS) analysis, miscible candidate reservoirs were required to pass the following screening criteria originally based on the 1984 “Enhanced Oil Recovery” study by the National Petroleum Council (NPC, 1984). The 

minimum miscibility pressure was required to be at least 400 pound-forces per square inch (psi) below the reservoir fracture 

pressure, the API (American Petroleum Institute) gravity of the oil had to be at least 25 degrees API (oAPI), the depth of the 

reservoir had to be at least 2,500 feet, and the viscosity of the oil had to be less than 10 centipoise (National Petroleum Council, 1984).3

 The set of feasible carbonate and clastic candidate reservoirs was further reduced by eliminating reservoirs with a 

net pay (interval of productive reservoir rock) of less than 5 feet or permeability values of less than 2 millidarcies (mD) or an 

amount of original oil in place that was less than 5 million barrels. Recovery factors for implementation of a miscible CO2-EOR 

tertiary recovery method were evaluated for 2,018 clastic reservoirs and 1,681 carbonate reservoirs.4

Calculation of Reservoir-Specific Recovery Factors and Net CO2 Utilization

Calculation Algorithm

CO2 Prophet is a pattern-level oil reservoir simulator used in this USGS study to predict an individual reservoir’s responses 

to injection of CO2 and water. This simulator was developed for the U.S. Department of Energy by Texaco Inc. under contract 

No. DE–FC22–93BC14960 and was described by Dobitz and Prieditis (1994). It predicts the reservoir’s response to injection of 

CO2 and water by generating fluid flow streamlines between injection and production wells and models the physical displacement and recovery of oil along streamtubes formed when the streamlines are used as boundaries (Willhite, 1986; Green and 

Willhite, 1998). A version of this simulator has been applied to regional and national assessments for the U.S. Department of 

Energy by Advanced Resources International (2006a, b, c, d; Wallace and others, 2013). Analysts in the petroleum industry use 

the CO2 Prophet simulator as a scoping tool to evaluate potential candidate reservoirs (Hsu and others, 1995).

The recovery factors are computed on the basis of a single pattern of injection and production wells that is assumed to 

represent the average for the reservoir.5 The recovery factor for the CO2-EOR method as reported here represents the fraction, in 

1

A pattern is a configuration of injection and production wells.

2

Technically recoverable resources are resources in accumulations producible by using current recovery technology and industry practices but without 

reference to economic profitability.

3

The list of candidates evaluated included four reservoirs with operating CO2-EOR programs that failed to meet one of the screening criteria.

4

Reservoirs were defined according to lithologic type, either clastic or carbonate. Clastic reservoirs are composed of clastic sedimentary rocks, which consist 

principally of broken rock fragments from preexisting rocks of any kind. Carbonate reservoirs are composed of carbonate sedimentary rocks formed by aqueous 

solution of calcium, magnesium, or iron that formed limestone and dolomites (Jackson, 1997).

5

In commercial applications of CO2 Prophet where pattern-specific data are available, computations for individual patterns across a reservoir could be modeled 

and then aggregated to arrive at an average recovery factor for the reservoir.
Calculation of Reservoir-Specific Recovery Factors and Net CO2

 Utilization 3

percent, of the pattern’s original oil in place that is recovered over the duration of the EOR project and is interpreted to represent 

technically recoverable oil because no economic screen or cutoff is applied. Net utilization of CO2, measured in thousands of 

cubic feet (mcf) of CO2 per barrel (bbl) of oil produced (at the surface), as defined here, is the amount of CO2 calculated that is 

retained in the reservoir per barrel of oil produced. It is computed as the difference between the volume of CO2 injected at the 

surface and the volume of CO2 recovered from production wells divided by the volume of oil produced. The gross amount of 

CO2 injected per barrel of produced oil at the surface is sometimes referred to as gross CO2 utilization. An estimate of the volume of CO2

 retained in the reservoir is given by the product of the net CO2 utilization and the volume of oil produced. The retention factor is the percentage of injected CO2

 that is naturally retained in the reservoir. This percentage is calculated by dividing 

the amount retained (at standard surface conditions) by the amount of CO2 injected (at surface conditions). To summarize, in this 

report, recovery factors and retention factors are percentages of oil recovered and CO2 retained in the reservoir, respectively, and 

net CO2 utilization is the amount of CO2 per barrel that is retained in the reservoir and is measured in thousands of cubic feet per 

barrel (mcf/bbl) under standard conditions.

The objective of this report is to put into the public domain estimates of recovery factors, net CO2 utilization values, and 

retention factors for the application of the miscible CO2-EOR method to a wide range of petroleum provinces and petroleum 

plays. These estimates may provide the basis for subjective reconnaissance-level assessments that may be useful to industry 

decision makers and government policy makers.

Data Required for Calculation of Recovery Factors and Assumptions

The data demands of simulators and the scope of the national and regional assessments requiring calculation of oil recoverable from EOR methods (and the associated recovery factors) for thousands of reservoirs entail tradeoffs between the reservoirspecific data that can be assembled versus the need for simplifying assumptions that allow the assignment of default values for 

some reservoir parameters. The data to calculate reservoir-specific recovery factors with CO2 Prophet were taken from the Comprehensive Resource Database (CRD) that was prepared by INTEK, Inc. under contract to the USGS. The algorithms described 

by M. Carolus (of INTEK, Inc.) and others (written commun., 2015) were used to estimate the values of variables needed for 

projecting EOR performance at the reservoir level and to complete some partial reservoir records of the “Significant Oil and Gas 

Fields of the United States Database” prepared by Nehring Associates, Inc. (2012). Along with augmenting the original database, 

the CRD includes estimates of reservoir and fluid properties used by CO2 Prophet to compute recovery factors. In particular, the 

derived reservoir-specific engineering parameters included estimates of the minimum miscibility pressures, fracture pressure, 

formation volume factors, and pseudo-Dykstra-Parsons coefficients. The calculation of the pseudo-Dykstra-Parsons coefficient, 

which is a measure of reservoir heterogeneity, followed the procedure of Hirasaki, Morra, and Wilhite (1984) and Hirasaki and 

others (1989).

The miscible CO2-EOR process requires reservoir pressures of at least the MMP, so the reservoir fracture pressure was 

required to be at least 400 psi above the MMP; otherwise, the reservoir was not evaluated. The residual oil saturation, that is, 

the oil saturation remaining after completion of the waterflood phase of reservoir development, is an important initial condition because it constrains the volume of oil that can be accessed by the CO2

-EOR process. For clastic reservoirs, the residual oil 

saturation was assumed to be 0.25 (Robl and others, 1986) and, for carbonate reservoirs, the residual oil saturation value was 

assumed to be 0.305 (Donald Remson, U.S. Department of Energy, written commun., 2015).

Water and CO2 injection rates and the injection scheme over time also represent initial conditions that were required by the 

simulator. Injection rates for water and CO2 were set so that the reservoir pressure remained at or above the MMP but 400 psi 

below the fracture pressure, and a 5-spot pattern of one production well and four injection wells was assumed (Lyons, 1996). 

Holtz (2014) reported that field studies show that after the initial injection of CO2, reservoir injectivity may increase, decline, or 

stay unchanged. However, both Holtz (2014) and Wallace and others (2013) discussed several treatments commercially available to remediate losses in injectivity. For the computation of technically recoverable oil from the applications of a miscible 

CO2-EOR method, it was assumed that any decline in injectivity was remediated.

The total injected volume of CO2 during the EOR project was assumed to amount to 100 percent of the hydrocarbon pore 

volume (HCPV). The assumed injection regime had three phases: in phase 1, injected CO2 was equivalent to 25 percent of the 

HCPV; in phase 2, injected CO2 was equivalent to 35 percent of the HCPV; and in phase 3, injected CO2 was equivalent to 40 

percent of the HCPV. The ratio of water volumes injected to gas (CO2) volumes injected during water-alternating-gas (WAG) 

injections in phase 1 was 1:3; the ratio in phase 2 was 1:2; and the ratio in phase 3 was 1:1.5. When the WAG ratio was tapered 

over the three phases, as indicated here, water was injected in greater cumulative amounts in each phase relative to the CO2

injected.

The following additional initial conditions were assumed. Connate water and irreducible water saturation values were set 

to 0.2 for all reservoirs. The specific gravity for casing-head gas, with respect to air (where the specific gravity of air equals 1.0), 

was assumed to be 0.7. On the basis of experimental data presented in graphs by Lange (1998), a value of 0.08 was selected for 
4 Play-Level Distributions of Estimates of Recovery Factors for a Miscible CO2

-EOR Method

the parameter representing residual oil saturation to the CO2 solvent for all miscible CO2-EOR reservoirs. The values of the endpoints of the relative permeability functions were based on default values for mildly water wet6

 reservoirs suggested by Michael 

Stein (BP [retired], written commun., 2014).7

The CO2 Prophet simulator represents a simplification of the actual physical processes and does not capture the chemical 

processes that would be described by a sophisticated compositional model. Nor does the modeling capture the unanticipated 

operational factors such as fractures or thief zones that affect the actual recovery factors. The advantage of applying even 

rudimentary simulators such as CO2 Prophet for calculating recovery by the CO2-EOR method is that oil attributed to the EOR 

program is clearly delineated from the oil produced under a secondary recovery program.

Distributions of Recovery Factors and Estimates of Net CO2 Utilization

Format of Results

The evaluated oil reservoirs were grouped according to lithologic type, either clastic or carbonate, and by play within 

petroleum provinces of seven regions in the conterminous United States. Plays were defined according to the scheme used in the 

U.S. Geological Survey’s 1995 National Oil and Gas Assessment (NOGA; Beeman and others, 1996; Gautier and others, 1996). 

The beginning of the 3- or 4-digit play code identifies the 1- or 2-digit province code (for example, play 1003, Lower Bakersfield Arch, is in province 10, the San Joaquin Basin Province). Figure 1 shows petroleum provinces identified as containing oil 

reservoirs that are potential candidates for the application of a miscible CO2-EOR method.

Candidate oil reservoirs for miscible CO2-EOR that were evaluated were located in onshore and State offshore areas in the 

conterminous United States.8 Reservoirs located in Federal offshore areas were excluded, as were unconventional oil reservoirs 

such as those in the Bakken and the Eagle Ford plays. The results are presented by region. For each region, the initial table 

(tables 1, 3, 5, 8, 11, 14, 17) lists the play number, the count of clastic and carbonate candidate reservoirs, the province name, 

and the formal play name as used by Beeman and others (1996). The next tables (tables 2, 4, 6, 7, 9, 10, 12, 13, 15, 16, 18) list 

the characteristics of the distributions of recovery factors and the median value of the associated net CO2 utilization estimates for 

each play containing at least three candidate oil reservoirs. Boxplots characterize the recovery-factor distributions and provide a 

visual representation of the tabular data (figs. 2–12). Boxplots show only plays that have at least six candidate oil reservoirs.

Recovery-factor estimates calculated by CO2 Prophet for each of the candidate reservoirs are presented by play as a distribution that characterizes the play. The median values in the tables represent the central tendency of the distributions. The difference between the first and third quartile in the table is called the interquartile range, and it should be interpreted to represent the 

dispersion or spread of the recovery-factor distribution. In the boxplots, the interquartile range is represented as the height of the 

box; that is, the distance between the 25th percentile (bottom of box) and the 75th percentile (top of box). The median value is 

the thick line. The minimum value of the dashed line outside the box is the smallest value of the data within 1.5 times the interquartile range below the 25th percentile, and the maximum value of the dashed vertical line is the largest value within 1.5 times 

the interquartile range above the 75th percentile. Play-level distributions of simulated recovery factors were computed for clastic 

and (or) carbonate reservoirs.

The nature of the skewness of the distribution can be inferred from the position of the median on the boxplots. An idealized symmetric distribution would display the darkened median line midway between the ends of the rectangular box with the 

minimum and maximum values extending out an equal distance from the 1st and 3d quartiles, respectively. A right-skewed 

distribution has many small values and a few large values, with the average of all values being larger than the median value. For 

a right-skewed-distribution boxplot, the vertical distances between the minimum and first quartile to the median value are much 

smaller than the vertical distances from the median to the third quartile and maximum value. A left-skewed distribution is just 

the opposite of a right-skewed distribution.

Because some of the provinces have only a small number of plays, the play distribution properties were grouped into the 

region for displaying in tabular form and as play boxplots.

6

A water-wet reservoir denotes a condition in which a thin film of water coats the formation and aids in oil transport (Schlumberger Oilfield Glossary, 2015).

7

In particular, the following parameters were specified: the endpoint relative permeability of oil at connate water was 1, the endpoint relative permeability of 

water at residual oil saturation was 0.3, the endpoint relative permeability of CO2 at CO2 saturation was 0.4, the endpoint relative permeability of gas-to-connatewater saturation was 0.4, and the exponents on the relative permeability equations were 2.0.

8

Reservoirs in Alaska (Region 1) were excluded because North Slope reservoirs are developed with horizontal injection and production wells and the 

calculations of CO2 Prophet assume vertical injection and production wells. According to available data, Hawaii has no oil reservoirs.
Distributions of Recovery Factors and Estimates of Net CO2

 Utilization 5

31

63

47

19

64

44 49

66

39

50

58

45

28

37

53

21

33

62

56 20

7

43

60

9

22

29

10

34

35

59

55

36

46

11

61

38

40

8

13

12

14

120°W 110°W 100°W 90°W 80°W 70°W

40°N

30°N

20°N

0 250 500 MILES

0 250 500 KILOMETERS

Region

2 - Pacific Coast

3 - Colorado Plateau and Basin and Range

5 - West Texas and Eastern New Mexico

6 - Gulf Coast

7 - Midcontinent

8 - Eastern

4 - Rocky Mountains and Northern Great Plains

EXPLANATION

Province boundary

50 Province having conventional oil reservoirs

Province having candidate reservoirs

Figure 1. Map of the conterminous United States showing the petroleum province boundaries in seven of the eight regions used in 

the U.S. Geological Survey’s 1995 National Oil and Gas Assessment (NOGA); boundaries are from Beeman and others (1996). Provinces 

labeled by codes contain conventional oil reservoirs; that is, reservoirs that have a gas-to-oil ratio of no more than 10,000 cubic feet 

of natural gas/1 barrel of oil at standard surface conditions and that are listed in the database by Nehring Associates, Inc. (2012). See 

tables 1, 3, 5, 8, 11, 14, and 17 for province names; play numbers in these tables begin with a 1- or 2-digit province code corresponding 

to the codes on this map. Stripes designate provinces having oil reservoirs that are candidates for miscible carbon dioxide enhanced 

oil recovery (CO2-EOR) as indicated by use of the reservoir simulator CO2 Prophet. Alaska (Region 1) is not shown because North Slope 

reservoirs are developed with horizontal injection and production wells, whereas the calculations of CO2 Prophet assume vertical 

injection and production wells.
6 Play-Level Distributions of Estimates of Recovery Factors for a Miscible CO2

-EOR Method

Discussion of Play-Level Recovery-Factor Distributions for Regions

Table 1 lists the plays in Region 2, the Pacific Coast Region, that contain candidate oil reservoirs. Region 2 has 103 clastic 

candidate reservoirs and no carbonate candidate reservoirs. Table 2 provides the median net CO2 utilization factor and the distributional parameters for recovery factors for plays that contain at least three candidate reservoirs for a lithology type. Figure 2 

shows boxplots of recovery-factor data for the five Pacific Coast Region plays that contain at least six candidate reservoirs for a 

lithology type. The median values of the recovery factors across the five plays are remarkably close, and the shapes of the distributions in figure 2 are roughly symmetric or right skewed. The variability of the recovery-factor distributions as represented 

by the height of the box is directly related to the variability of the reservoir characteristics that affect the CO2 Prophet recoveryfactor computations.

Table 3 lists the plays in Region 3, the Colorado Plateau and Basin and Range Region, that contain candidate oil reservoirs. 

Table 4 provides the median net CO2 utilization factor and the distributional parameters for recovery factors for plays that contain at least three candidate reservoirs for a lithology type. Figures 3A and 3B show boxplots for the plays containing the clastic 

and carbonate reservoirs, respectively. Within this region, the median recovery factor for carbonate reservoirs in one play (13.06 

percent) exceeds those for clastic reservoirs in three plays (8.88–11.12 percent).

Table 5 lists the plays in Region 4, the Rocky Mountains and Northern Great Plains Region, that contain candidate oil 

reservoirs. Table 6 provides the median net CO2 utilization factor and the distributional parameters for recovery factors for plays 

in Region 4, excluding those in the Powder River Basin Province (which are described below). Figures 4A and 4B show boxplots of recovery-factor data for the clastic and carbonate reservoirs, respectively, in Region 4 plays outside of the Powder River 

Basin Province. Generally, the median recovery factors for the clastic reservoirs are lower than the median recovery factors for 

the carbonate reservoirs in Region 4. This result was not unexpected because the assumed residual oil saturation after waterflood 

for carbonate reservoirs (0.305, as described above) is 22 percent greater than the assumed value for clastic reservoirs (0.25).

Table 7 and figure 5 show the distributional parameters of recovery-factor data and boxplots for the clastic reservoirs in the 

plays of the Powder River Basin Province. The province lacked a carbonate reservoir that could be a candidate. With the exception of play 3309, the values of the median recovery factors are consistent across the province, and the shapes are either roughly 

symmetric or right skewed. Play 3309 has only a few reservoirs, and two or three of them have high recovery factors that affect 

the median.

The plays containing candidate reservoirs in Region 5, the West Texas and Eastern New Mexico Region, are listed in 

table 8 and are identified as being in either the Permian Basin Province (province 44) or the Bend Arch-Fort Worth Basin 

Province (province 45). Table 9 and figures 6A and 6B present the results for the Permian Basin Province. For the Permian 

Basin Province, with the exception of plays 4409 and 4410, the median recovery factors for the clastic reservoirs are remarkably 

similar. Figure 6 shows that there is slightly more variability in recovery factors computed for the carbonate reservoirs. With 

the exception of play 4410, the shapes of the recovery-factor distributions for both clastic and carbonate reservoirs are either 

roughly symmetric or right skewed. The high recovery factors for play 4410 are explained by data from the CRD that show a 

relatively large number of reservoirs with favorable (low) pseudo-Dykstra-Parsons coefficients.

Table 8 lists the plays in the Bend Arch-Fort Worth Basin Province that contain candidate reservoirs, and table 10 and 

figures 7A and 7B present distributional parameters. Figures 7A and 7B show that recovery-factor distributions as roughly symmetric or right skewed. Median values of the recovery-factor distributions for carbonate reservoirs are generally greater than the 

median values of the recovery-factor distributions for clastic reservoirs.

Table 11 lists the plays in Region 6, the Gulf Coast Region, that contain candidate reservoirs. Table 12 and figures 8A and 

8B relate to candidate reservoirs in the Western Gulf Province (province 47), and table 13 and figures 9A and 9B relate to the 

Louisiana-Mississippi Salt Basins Province (province 49). Figure 8A shows a very small range in the median values across 

the recovery-factor distributions for clastic reservoirs. The shapes of these distributions are either roughly symmetric or right 

skewed.

Table 13 and figures 9A and 9B show parameters of the recovery factors for candidate clastic and carbonate reservoirs 

within plays in the Louisiana-Mississippi Salt Basins Province. With the exception of the clastic reservoirs in plays 4901 and 

4938, the distribution shape of all other plays with candidate reservoirs in the province is either roughly symmetric or right 

skewed. Play 4901 has only six candidate reservoirs, so two or three reservoirs with high recovery factors are influential. A similar pattern is shown for play 4938, which has only 16 candidate reservoirs. Median values of the recovery-factor distributions for 

carbonate reservoirs are generally greater than the median values of the recovery-factor distributions for clastic reservoirs.

Table 14 lists the plays in Region 7, the Midcontinent Region, that contain candidate reservoirs. Table 15 provides the 

median net CO2 utilization and the distributional parameters for recovery factors for Region 7 plays, excluding plays in the 

Anadarko Basin Province (province 58). Figures 10A and 10B show boxplots of recovery-factor data for the clastic and carbonate reservoirs in Region 7 plays outside of the Anadarko Basin Province (province 58). Table 16 and figures 11A and 11B show 

data for the Anadarko Basin Province. For the plays outside of the Anadarko Basin Province, median values of the recovery-factor distributions for carbonate reservoirs are larger than median values of the recovery-factor distributions for clastic reservoirs. 
Summary and Conclusions 7

The distributional shapes for clastic and carbonate reservoirs are either roughly symmetric or right skewed. The same remarks 

apply to the distributional properties of the Anadarko Basin Province as shown in table 16 and figures 11A and 11B.

Table 17 lists plays having candidate reservoirs in Region 8, the Eastern Region. Table 18 and figures 12A and 12B show 

the recovery-factor distributional parameters for clastic and carbonate candidate reservoirs. Reservoirs are located in the Michigan Basin Province (province 63) and the Illinois Basin Province (province 64). Once again, the shapes of the recovery-factor 

distributions are either roughly symmetric or right skewed.

Summary and Conclusions

Baseline estimates of recovery factors for the application of a miscible CO2-EOR method to technically suitable oil reservoirs located in onshore and State offshore areas in the conterminous United States were calculated by using the CO2

 Prophet 

reservoir simulator (Dobitz and Prieditis, 1994). Calculations included 2,018 clastic reservoirs and 1,681 carbonate reservoirs 

that were screened as potential miscible CO2-EOR candidates by using the criteria published by the National Petroleum Council 

(NPC, 1984). Reservoir data were from the database by Nehring Associates, Inc. (2012), and supplemental engineering parameters were computed according to algorithms described by M. Carolus (of INTEK, Inc.) and others (written commun., 2015). 

The estimates are presented in this report as distributions categorized by plays from Beeman and others (1996) and Gautier and 

others (1996). The play distribution properties are presented in tabular form and as boxplots. Most of the distributions are right 

skewed or roughly symmetrical. The right-skewed distributions show a concentration of the number of reservoirs at the lower 

end of the spectrum of recovery factors and few reservoirs having high recovery factors. Overall, 90 percent of the recoveryfactor estimates for clastic reservoirs fell within the range from 8.7 to 16.2 percent, and, similarly, 90 percent of the recoveryfactor estimates for carbonate reservoirs were within the range from 11.8 to 27.5 percent. Figures 13A and 13B show the overall 

distributions to be right skewed. The median recovery-factor value for all of the clastic reservoirs evaluated was 9.5 percent, 

and the median value for all of the carbonate reservoirs evaluated was 13.6 percent. The higher recovery factors for carbonate reservoirs when compared with recovery factors for clastic reservoirs are consistent with data reported by Christensen and 

others (2001). The corroboration of the results with empirical observations seems to imply that the recovery-factor distributions 

presented here should be considered to be relatively robust.

Recall that net CO2 utilization is an estimate of the CO2 in thousands of cubic feet (mcf) at the surface per barrel (bbl) 

produced that is retained in the reservoir. Overall, the median net CO2 utilization value estimated for clastic reservoirs is 

5.95 mcf/bbl and the value estimated for carbonate reservoirs is 5.24 mcf/bbl. The retention factor is the percentage of the CO2

injected into the reservoir that is not produced and that is assumed to be retained in the formation. For clastic reservoirs, 90 

percent of the estimated retention factors were between 21.7 and 32.1 percent, and, for carbonate reservoirs, 90 percent were 

between 23.7 and 38.2 percent. The respective median values were 22.9 for clastic reservoirs and 26.1 for carbonate reservoirs. 

With the exception of a few outlier carbonates (less than 0.7 percent), the retention estimates are consistent with empirical data 

published by Olea (2015). Figures 14A and 14B indicate that both retention-factor distributions are right skewed.

The higher carbonate recovery factors are directly attributable to the assumptions about the residual oil saturation after 

waterflooding. The assumptions implied that for carbonate reservoirs, such as those found in the Permian Basin, the primary 

and waterflood recovery processes were much less efficient in recovering oil in place than the same primary and waterflood 

processes were for clastic reservoirs, resulting in a higher residual oil saturation for carbonate reservoirs. The difference was 

about 22 percent higher than for similar clastic reservoirs. Consequently, the miscible CO2-EOR recovery factors for carbonate 

reservoirs are generally higher than those for clastic reservoirs.

Another assumption that affects the recovery factor is the amount of CO2 that is injected into the reservoir relative to 

the amount of the HCPV. The past practices (Merchant, 2010) rarely reached 100 percent as assumed in this study; however, 

industry practices seem to be moving toward higher amounts. If the relative cost of CO2 were to decline substantially, injection 

volumes could exceed 100 percent of the HCPV on a regular basis. Numerical sensitivity studies showed that going from injections equivalent to 100 percent of the HCPV to injections equivalent to 150 percent added about 2 to 3 percentage points to the 

recovery factor. Overall, this increment represented about a 14-percent increase in the mean recovery factor for the representative reservoir. However, the increase extends the duration of the EOR program by about 50 percent, and oil production rates 

during the latter years are substantially reduced.

The recovery-factor estimates lead to a number of possibilities for further study. For example, can one identify specific play 

characteristics among the reservoir conditions or fluid properties that have an influence on the recovery factor? Can the relative 

strength of these specific characteristics be ascertained? The limitations of the recovery factors presented here, however, should 

be kept in mind. The limitations relate to the data that support the estimates being based on the characteristics of a representative 

pattern. Within an individual reservoir, there will be spatial variations in the reservoir characteristics leading a distribution of 

recovery-factor estimates across patterns that should be probabilistically aggregated to the reservoir level.
8 Play-Level Distributions of Estimates of Recovery Factors for a Miscible CO2

-EOR Method

Acknowledgments

The authors thank Peter Warwick and Richard Olea (both of the U.S. Geological Survey) for their reviews and suggestions, 

and we also thank Elizabeth Good (USGS) for excellent and comprehensive editorial work and Jeannette Foltz (USGS) for 

layout and production.

References Cited

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Oriented%20Strategies%20-%20Illinois_Michigan_Basin.pdf.

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Prepared for U.S. Department of Energy, Office of Fossil Energy–Office of Oil and Natural Gas, variously paged [117 p.], 

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Strategies%20-%20Williston_Basin.pdf.

Beeman, W.R., Obuch, R.C., and Brewton, J.D., comps., 1996, Digital map data, text, and graphical images in support of 

the 1995 national assessment of United States oil and gas resources: U.S. Geological Survey Digital Data Series DDS–35, 

1 CD-ROM.

Christensen, J.R., Stenby, E.H., and Skauge, A., 2001, Review of WAG field experience: SPE Reservoir Evaluation and Engineering, v. 4, no. 2, p. 97–106, SPE paper 71203–PA, http://dx.doi.org/10.2118/71203-PA.

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Tulsa, Oklahoma, 17–20 April 1994, paper SPE–27750–MS, 8 p., http://dx.doi.org/10.2118/27750-MS.

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gas resources; Results, methodology, and supporting data (release 2): U.S. Geological Survey Digital Data Series DDS–30, 

1 CD-ROM.

Green, D.W., and Willhite, G.P., 1998, Enhanced oil recovery: Society of Petroleum Engineers Textbook Series, v. 6, 545 p.

Hirasaki, G.J., Morra, Frank, and Willhite, G.P., 1984, Estimation of reservoir heterogeneity from waterflood performance: Society of Petroleum Engineers, SPE–13415–MS, 10 p., https://www.onepetro.org/general/SPE-13415-MS.

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studies on EOR: Journal of Petroleum Technology, v. 41, no. 11, p. 1218–1222.

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Casper, Wyoming, July 8–10, 2014, presentation, 42 p., accessed August 17, 2015, at http://www.uwyo.edu/eori/_files/

co2conference14/holtz.pdf.

Hsu, C.-F., Koinis, R.L., and Fox, C.E., 1995, Technology, experience speed CO2 flood design: Oil and Gas Journal, v. 93, no. 

43, p. 51–59.

IHS Inc., 2012, PIDM [Petroleum Information Data Model] relational U.S. well data [data current as of December 23, 2012]: 

Englewood, Colo., IHS Inc., database.
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Jackson, J.A., ed., 1997, Glossary of geology (4th ed.): Alexandria, Va., American Geological Institute, 768 p.

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Lange, E.A., 1998, Correlation and prediction of residual oil saturation for gas injection EOR processes: SPE Reservoir Evaluation and Engineering, v. 1, no. 2, p. 127–133, SPE paper 35425–PA, http://dx.doi.org/10.2118/35425-PA.

Lyons, W.C., ed., 1996, Standard handbook of petroleum and natural gas engineering, volume 2: Houston, Texas, Gulf Publishing Company, 1,090 p., http://dx.doi.org/10.1016/B978-088415643-7/50007-8.

Merchant, D.H., 2010, Life beyond 80; A look at conventional WAG recovery beyond 80% HCPV injected in CO2 tertiary 

floods: SPE International Conference on CO2 Capture, Storage, and Utilization, New Orleans, Louisiana, 10–12 November 

2010, paper, 14 p., SPE–139516–MS, 14 p., http://dx.doi.org/10.2118/139516-MS.

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Willhite, G.P., 1986, Waterflooding: Society of Petroleum Engineers Textbook Series, v. 3, 326 p.
10 Play-Level Distributions of Estimates of Recovery Factors for a Miscible CO2

-EOR Method

Table 1. Numbers of clastic and carbonate oil reservoirs that are candidates for the application of a miscible CO2-EOR method in 

plays of Region 2, the Pacific Coast Region.

[Candidate reservoirs must have permeability values of at least 2 millidarcies, a net pay at least 5 feet thick, and at least 5 million barrels of original oil in 

place. Petroleum province boundaries and codes are shown in figure 1; province codes are the first 1 or 2 digits of the play numbers. For example, play 903 is 

in province 9, the Sacramento Basin Province. CO2-EOR, carbon dioxide enhanced oil recovery; dash (–), zero]

Play 

number

Number of oil 

reservoirs that are 

candidates for 

CO2-EOR

Province name Play name

Clastic Carbonate

903 1 – Sacramento Basin Western Winters through Domingene.

1002 4 – San Joaquin Basin Southeast Stable Shelf.

1003 18 – San Joaquin Basin Lower Bakersfield Arch.

1004 5 – San Joaquin Basin West Side Fold Belt Sourced by Post-Lower Miocene Rocks.

1005 17 – San Joaquin Basin West Side Fold Belt Sourced by Pre-Middle Miocene Rocks.

1006 5 – San Joaquin Basin Northeast Shelf of Neogene Basin.

1007 1 – San Joaquin Basin Northern Area Non-Associated Gas.

1008 6 – San Joaquin Basin Tejon Platform.

1107 3 – Central Coastal Western Cuyama Basin.

1301 4 – Ventura Basin Paleogene-Onshore.

1302 21 – Ventura Basin Neogene-Onshore.

1303 1 – Ventura Basin Pliocene Stratigraphic.

1401 3 – Los Angeles Basin Santa Monica Fault System and Las Cienegas Fault and Block.

1403 6 – Los Angeles Basin Newport-Inglewood Deformation Zone and Southwestern Flank of 

Central Syncline.

1404 2 – Los Angeles Basin Whittier Fault Zone and Fullerton Embayment.

1405 5 – Los Angeles Basin Northern Shelf and Northern Flank of Central Syncline.

1407 1 – Los Angeles Basin Chino Marginal Basin, Puente and San Jose Hills, and San Gabriel 

Valley Marginal Basin.
Tables and Figures, Region 2 11

Table 2. Distributions of recovery factors for technically recoverable oil that might be produced by 

use of a miscible carbon dioxide enhanced oil recovery (CO2-EOR) method and the median net CO2

utilization for plays in Region 2, the Pacific Coast Region.

[Estimates were made by using the CO2 Prophet simulator for candidate oil reservoirs. Play names and numbers are 

in table 1. Only plays containing at least three candidate reservoirs by lithology type are shown here. Only clastic 

reservoirs were identified in Region 2, and so no carbonate reservoirs are listed. Recovery factors are in percent, and 

the median net CO2 utilization is in thousands of cubic feet of CO2 per barrel of produced oil at the surface (mcf/bbl)]

Play 

number

Number 

of oil 

reservoirs

Recovery factor (percent) Median 

net CO2

utilization 

(mcf/bbl)

Minimum 1st 

quartile Median 3d quartile Maximum

Clastic reservoirs

1002 4 8.46 8.63 8.85 9.12 9.42 5.56

1003 18 8.78 9.01 9.26 9.49 13.15 6.42

1004 5 8.60 8.85 8.91 9.47 9.59 5.68

1005 17 8.70 9.17 9.71 12.40 13.53 5.99

1006 5 8.36 9.06 9.18 9.36 13.51 5.36

1008 6 8.18 8.72 9.18 11.72 12.90 5.85

1107 3 8.54 9.07 9.60 10.94 12.29 4.70

1301 4 8.76 9.20 9.36 10.17 12.57 5.34

1302 21 8.71 9.35 9.52 10.12 18.85 6.15

1401 3 8.17 8.66 9.15 9.66 10.17 5.48

1403 6 8.72 9.10 9.24 11.71 19.30 5.28

1405 5 8.16 8.80 12.33 12.45 17.06 4.68

Figure 2. Boxplots of recovery factors for technically 

recoverable oil that might be produced by use of a miscible 

carbon dioxide enhanced oil recovery (CO2-EOR) method from 

clastic oil reservoirs in plays within Region 2, the Pacific Coast 

Region. Estimates were made by using the CO2 Prophet simulator 

for candidate reservoirs. Play names and numbers are in table 1. 

Only plays containing at least six candidate reservoirs by lithology 

type have recovery factors plotted here. Only clastic reservoirs 

were identified in this region.

Clastic reservoirs
12 Play-Level Distributions of Estimates of Recovery Factors for a Miscible CO2

-EOR Method

Table 3. Numbers of clastic and carbonate oil reservoirs that are candidates for the application of a miscible CO2-EOR method in 

plays of Region 3, the Colorado Plateau and Basin and Range Region.

[Candidate reservoirs must have permeability values of at least 2 millidarcies, a net pay at least 5 feet thick, and at least 5 million barrels of original oil in 

place. Petroleum province boundaries and codes are shown in figure 1; province codes are the first 2 digits of the play numbers. CO2-EOR, carbon dioxide 

enhanced oil recovery; dash (–), zero]

Play 

number

Number of oil 

reservoirs that are 

candidates for 

CO2-EOR

Province name Play name

Clastic Carbonate

2002 10 – Uinta-Piceance Basin Uinta Tertiary Oil and Gas.

2005 2 – Uinta-Piceance Basin Permian-Pennsylvanian Sandstones and Carbonates.

2102 – 15 Paradox Basin Porous Carbonate Buildup.

2204 3 – San Juan Basin Entrada.

2206 1 – San Juan Basin Basin Margin Dakota Oil.

2207 10 – San Juan Basin Tocito/Gallup Sandstone Oil.

Table 4. Distributions of recovery factors for technically recoverable oil that might be produced by 

use of a miscible carbon dioxide enhanced oil recovery (CO2-EOR) method and the median net CO2

utilization for plays in Region 3, the Colorado Plateau and Basin and Range Region.

[Estimates were made by using the CO2 Prophet simulator for candidate oil reservoirs. Play names and numbers are in 

table 3. Only plays containing at least three candidate reservoirs by lithology type are shown here. Recovery factors 

are in percent, and the median net CO2 utilization is in thousands of cubic feet of CO2 per barrel of produced oil at the 

surface (mcf/bbl)]

Play 

number

Number of 

oil 

reservoirs

Recovery factor (percent) Median 

net CO2

utilization 

(mcf/bbl)

Minimum 1st 

quartile Median 3d quartile Maximum

Clastic reservoirs

2002 10 8.15 9.06 9.78 11.20 18.17 6.58

2204 3 8.84 8.86 8.88 9.48 10.07 6.41

2207 10 9.23 9.34 11.12 12.87 13.51 6.15

Carbonate reservoirs

2102 15 12.25 12.62 13.06 17.81 18.35 5.59
Tables and Figures, Region 3 13

A. Clastic reservoirs B. Carbonate reservoirs

Figure 3. Boxplots of recovery factors for technically recoverable oil that might be produced by use of a miscible carbon dioxide 

enhanced oil recovery (CO2-EOR) method from (A) clastic and (B) carbonate oil reservoirs in plays within Region 3, the Colorado Plateau 

and Basin and Range Region. Estimates were made by using the CO2 Prophet simulator for candidate reservoirs. Play names and 

numbers are in table 3. Only plays containing at least six candidate reservoirs by lithology type have recovery factors plotted here.
14 Play-Level Distributions of Estimates of Recovery Factors for a Miscible CO2

-EOR Method

Table 5. Numbers of clastic and carbonate oil reservoirs that are candidates for the application of a miscible CO2-EOR method in 

plays of Region 4, the Rocky Mountains and Northern Great Plains Region.

[Candidate reservoirs must have permeability values of at least 2 millidarcies, a net pay at least 5 feet thick, and at least 5 million barrels of original oil in 

place. Petroleum province boundaries and codes are shown in figure 1; province codes are the first 2 digits of the play numbers. CO2-EOR, carbon dioxide 

enhanced oil recovery; dash (–), zero]

Play 

number

Number of oil 

reservoirs that are 

candidates for 

CO2-EOR

Province name Play name

Clastic Carbonate

2805 – 5 North-Central Montana Devonian-Mississippian Carbonates.

2806 11 – North-Central Montana Tyler Sandstone.

2808 2 – North-Central Montana Jurassic-Cretaceous Sandstones.

3101 – 115 Williston Basin Madison (Mississippian).

3102 – 50 Williston Basin Red River (Ordovician).

3103 – 31 Williston Basin Middle and Upper Devonian (Pre-Bakken-Post-Prairie Salt).

3105 – 11 Williston Basin Pre-Prairie Middle Devonian and Silurian.

3106 11 – Williston Basin Post-Madison through Triassic Clastics.

3107 1 – Williston Basin Pre-Red River Gas.

3302 21 – Powder River Basin Basin Margin Anticline.

3304 45 – Powder River Basin Upper Minnelusa Sandstone.

3306 14 – Powder River Basin Fall River Sandstone.

3307 27 – Powder River Basin Muddy Sandstone.

3309 11 – Powder River Basin Deep Frontier Sandstone.

3310 2 – Powder River Basin Turner Sandstone.

3312 9 – Powder River Basin Sussex-Shannon Sandstone.

3313 16 – Powder River Basin Mesaverde-Lewis.

3402 10 13 Big Horn Basin Basin Margin Anticline.

3406 – 3 Big Horn Basin Phosphoria Stratigraphic.

3502 6 1 Wind River Basin Basin Margin Anticline.

3503 1 – Wind River Basin Deep Basin Structure.

3504 3 – Wind River Basin Muddy Sandstone Stratigraphic.

3515 1 – Wind River Basin Shallow Tertiary-Upper Cretaceous Stratigraphic.

3604 1 2 Wyoming Thrust Belt Absaroka Thrust.

3701 2 – Southwestern Wyoming Rock Springs Uplift.

3702 1 – Southwestern Wyoming Cherokee Arch.

3703 9 – Southwestern Wyoming Axial Uplift.

3704 3 – Southwestern Wyoming Moxa Arch-LaBarge.

3707 9 2 Southwestern Wyoming Platform.

3801 1 – Park Basins Cretaceous-Upper Jurassic Structural.

3901 3 – Denver Basin Pierre Shale Sandstones.

3905 146 – Denver Basin Dakota Group (Combined J and D Sandstones).

3907 2 – Denver Basin Basin-Margin Structural.

3908 2 – Denver Basin Permian-Pennsylvanian.

4004 1 – Las Animas Arch Lower Pennsylvanian (Morrowan) Sandstone Oil, Gas, and Natural 

Gas Liquids.

4005 – 6 Las Animas Arch Mississippian Carbonate.
Tables and Figures, Region 4 15

Table 6. Distributions of recovery factors for technically recoverable oil that might be produced by 

use of a miscible carbon dioxide enhanced oil recovery (CO2-EOR) method and the median net CO2

utilization for plays in Region 4, the Rocky Mountains and Northern Great Plains Region, excluding 

plays in the Powder River Basin Province.

[Estimates were made by using the CO2 Prophet simulator for candidate oil reservoirs. Play names and numbers are in 

table 5. Only plays containing at least three candidate reservoirs by lithology type are shown here. Recovery factors 

are in percent, and the median net CO2 utilization is in thousands of cubic feet of CO2 per barrel of produced oil at the 

surface (mcf/bbl)]

Play 

number

Number of 

oil 

reservoirs

Recovery factor (percent) Median 

net CO2

utilization 

(mcf/bbl)

Minimum 1st 

quartile Median 3d quartile Maximum

Clastic reservoirs

2806 11 8.70 8.86 8.93 9.06 9.20 5.59

3106 11 8.99 9.56 9.77 13.17 16.29 5.29

3402 10 8.55 9.45 9.56 10.44 14.00 5.85

3502 6 9.09 9.32 9.60 9.89 17.10 5.18

3504 3 9.50 9.51 9.51 9.68 9.84 6.68

3703 9 9.11 9.46 9.65 10.12 12.83 6.16

3704 3 9.62 13.62 17.63 17.79 17.95 5.03

3707 9 8.38 9.12 9.22 9.52 11.19 5.79

3901 3 8.98 9.10 9.22 9.26 9.29 6.20

3905 146 8.50 8.93 9.22 9.62 16.99 5.92

Carbonate reservoirs

2805 5 12.00 12.26 12.28 12.35 16.77 4.92

3101 115 11.21 12.55 13.02 15.24 26.77 6.05

3102 50 12.54 12.92 13.19 17.88 18.67 6.38

3103 31 12.33 12.96 13.32 17.75 24.33 6.13

3105 11 12.39 12.98 13.23 13.47 18.27 5.66

3402 13 10.97 11.67 13.42 14.59 22.33 4.86

3406 3 12.94 12.95 12.96 15.80 18.64 4.80

4005 6 12.58 12.64 14.61 16.83 24.11 5.30
16 Play-Level Distributions of Estimates of Recovery Factors for a Miscible CO2

-EOR Method

A. Clastic reservoirs B. Carbonate reservoirs

Figure 4. Boxplots of recovery factors for technically recoverable oil that might be produced by use of a miscible carbon dioxide 

enhanced oil recovery (CO2-EOR) method from (A) clastic and (B) carbonate oil reservoirs in plays within Region 4, the Rocky Mountains 

and Northern Great Plains Region, excluding plays in the Powder River Basin Province. Estimates were made by using the CO2 Prophet 

simulator for candidate reservoirs. Play names and numbers are in table 5. Only plays containing at least six candidate reservoirs by 

lithology type have recovery factors plotted here.
Tables and Figures, Region 4 17

Table 7. Distributions of recovery factors for technically recoverable oil that might be produced by 

use of a miscible carbon dioxide enhanced oil recovery (CO2-EOR) method and the median net CO2

utilization for plays in the Powder River Basin Province of Region 4.

[Estimates were made by using the CO2 Prophet simulator for candidate oil reservoirs. Play names and numbers are 

in table 5. Only plays containing at least three candidate reservoirs by lithology type are shown here. Only clastic 

reservoirs were identified in the Powder River Basin Province, and so no carbonate reservoirs are listed. Recovery 

factors are in percent, and the median net CO2 utilization is in thousands of cubic feet of CO2 per barrel of produced 

oil at the surface (mcf/bbl)]

Play 

number

Number of 

oil 

reservoirs

Recovery factor (percent) Median 

net CO2

utilization 

(mcf/bbl)

Minimum 1st 

quartile Median 3d quartile Maximum

Clastic reservoirs

3302 21 8.43 9.25 9.50 9.83 17.33 5.31

3304 45 8.90 9.23 9.65 11.86 18.44 5.73

3306 14 9.16 9.64 9.79 12.74 18.42 6.44

3307 27 8.37 9.54 9.91 10.24 17.83 6.48

3309 11 9.74 10.02 13.43 13.92 14.15 6.27

3312 9 9.61 9.96 10.05 10.11 14.29 7.13

3313 16 9.45 9.61 9.85 11.46 13.75 6.34

Figure 5. Boxplots of recovery factors for technically 

recoverable oil that might be produced by use of a miscible 

carbon dioxide enhanced oil recovery (CO2-EOR) method from 

clastic oil reservoirs in plays within the Powder River Basin 

Province of Region 4. Estimates were made by using the CO2

Prophet simulator for candidate reservoirs. Play names and 

numbers are in table 5. Only plays containing at least six 

candidate reservoirs by lithology type have recovery factors 

plotted here. Only clastic reservoirs were identified in this 

province.

Clastic reservoirs
18 Play-Level Distributions of Estimates of Recovery Factors for a Miscible CO2

-EOR Method

Table 8. Numbers of clastic and carbonate oil reservoirs that are candidates for the application of a miscible CO2-EOR method in 

plays of Region 5, the West Texas and Eastern New Mexico Region.

[Candidate reservoirs must have permeability values of at least 2 millidarcies, a net pay at least 5 feet thick, and at least 5 million barrels of original oil in 

place. Petroleum province boundaries and codes are shown in figure 1; province codes are the first 2 digits of the play numbers. CO2-EOR, carbon dioxide 

enhanced oil recovery; dash (–), zero]

Play 

number

Number of oil 

reservoirs that are 

candidates for 

CO2-EOR

Province name Play name

Clastic Carbonate

4401 – 1 Permian Basin Pre-Pennsylvanian, Delaware-Val Verde Basins.

4402 17 107 Permian Basin Pre-Pennsylvanian, Central Basin Platform.

4403 1 58 Permian Basin Pre-Pennsylvanian, Northwestern and Eastern Shelves.

4404 3 4 Permian Basin Lower Pennsylvanian (Bend) Sandstone.

4405 2 31 Permian Basin Horseshoe Atoll, Upper Pennsylvanian-Wolfcampian.

4406 39 111 Permian Basin

Upper Pennsylvanian, Northwestern and Eastern Shelves, Northern 

Delaware and Midland Basins and Northern Central Basin 

Platform.

4407 13 16 Permian Basin Upper Pennsylvanian and Lower Permian Shelf, Slope and Basin 

Sandstones.

4408 – 20 Permian Basin Wolfcampian Carbonate, Eastern and Southern Margins of the 

Central Basin Platform.

4409 30 2 Permian Basin Spraberry-Dean.

4410 21 164 Permian Basin San Andres-Clearfork, Central Basin Platform and Ozona Arch.

4411 49 193 Permian Basin San Andres-Clearfork, Northwestern and Eastern Shelves.

4412 102 5 Permian Basin Delaware Sandstones.

4501 4 16 Bend Arch-Fort Worth Basin Pre-Mississippian Carbonate.

4502 1 26 Bend Arch-Fort Worth Basin Mississippian Carbonate.

4504 50 1 Bend Arch-Fort Worth Basin Lower Pennsylvanian (Bend) Sandstone and Conglomerate.

4505 150 51 Bend Arch-Fort Worth Basin Strawn (Desmoinesian).

4506 12 10 Bend Arch-Fort Worth Basin Post-Desmoinesian.
Tables and Figures, Region 5 19

Table 9. Distributions of recovery factors for technically recoverable oil that might be produced by 

use of a miscible carbon dioxide enhanced oil recovery (CO2-EOR) method and the median net CO2

utilization for plays in the Permian Basin Province of Region 5.

[Estimates were made by using the CO2 Prophet simulator for candidate oil reservoirs. Play names and numbers are in 

table 8. Only plays containing at least three candidate reservoirs by lithology type are shown here. Recovery factors 

are in percent, and the median net CO2 utilization is in thousands of cubic feet of CO2 per barrel of produced oil at the 

surface (mcf/bbl)]

Play 

number

Number of 

oil 

reservoirs

Recovery factor (percent) Median 

net CO2

utilization 

(mcf/bbl)

Minimum 1st 

quartile Median 3d quartile Maximum

Clastic reservoirs

4402 17 9.31 9.58 10.18 11.76 14.76 6.96

4404 3 9.30 9.71 10.11 10.86 11.60 6.56

4406 39 8.96 9.53 9.90 13.58 19.36 6.61

4407 13 8.91 9.30 9.60 13.39 18.09 6.08

4409 30 8.67 10.04 11.83 13.93 14.53 7.20

4410 21 9.15 10.72 19.29 19.36 19.65 4.95

4411 49 8.79 9.10 9.50 12.48 19.35 6.38

4412 102 9.10 9.66 9.87 13.48 18.10 6.89

Carbonate reservoirs

4402 107 12.19 12.94 13.52 16.62 26.94 5.89

4403 58 11.95 12.98 13.40 17.65 25.68 5.43

4404 4 12.10 12.63 15.36 18.12 18.71 5.86

4405 31 12.20 13.00 13.22 13.76 25.04 5.71

4406 111 11.82 12.99 13.33 14.46 26.92 5.91

4407 16 11.84 12.27 12.50 13.03 17.49 5.27

4408 20 12.47 13.01 13.36 15.45 24.88 5.84

4410 164 10.78 14.08 25.42 25.59 25.93 4.52

4411 193 10.70 12.55 13.43 17.31 25.72 5.39

4412 5 12.41 12.45 13.32 19.09 19.55 6.06
20 Play-Level Distributions of Estimates of Recovery Factors for a Miscible CO2

-EOR Method

A. Clastic reservoirs B. Carbonate reservoirs

Figure 6. Boxplots of recovery factors for technically recoverable oil that might be produced by use of a miscible carbon dioxide 

enhanced oil recovery (CO2-EOR) method from (A) clastic and (B) carbonate oil reservoirs in plays within the Permian Basin Province 

of Region 5. Estimates were made by using the CO2 Prophet simulator for candidate reservoirs. Play names and numbers are in table 8. 

Only plays containing at least six candidate reservoirs by lithology type have recovery factors plotted here.
Tables and Figures, Region 5 21

Table 10. Distributions of recovery factors for technically recoverable oil that might be produced 

by use of a miscible carbon dioxide enhanced oil recovery (CO2-EOR) method and the median net 

CO2 utilization for plays in the Bend Arch-Fort Worth Basin Province of Region 5.

[Estimates were made by using the CO2 Prophet simulator for candidate oil reservoirs. Play names and numbers are in 

table 8. Only plays containing at least three candidate reservoirs by lithology type are shown here. Recovery factors 

are in percent, and the median net CO2 utilization is in thousands of cubic feet of CO2 per barrel of produced oil at the 

surface (mcf/bbl)]

Play 

number

Number of 

oil 

reservoirs

Recovery factor (percent) Median 

net CO2

utilization 

(mcf/bbl)

Minimum 1st 

quartile Median 3d quartile Maximum

Clastic reservoirs

4501 4 9.41 9.46 10.23 12.60 17.51 6.61

4504 50 8.83 9.46 10.28 13.37 18.15 6.20

4505 150 8.48 9.30 9.57 12.77 18.91 5.90

4506 12 8.68 9.46 9.72 12.99 19.24 5.66

Carbonate reservoirs

4501 16 11.82 12.41 12.70 15.29 18.20 5.56

4502 26 11.39 12.69 15.22 17.62 18.16 5.26

4505 51 11.61 12.30 12.91 17.01 25.55 4.81

4506 10 11.64 12.41 14.67 16.76 17.84 4.46

A. Clastic reservoirs B. Carbonate reservoirs

Figure 7. Boxplots of recovery factors for technically recoverable oil that might be produced by use of a miscible carbon dioxide 

enhanced oil recovery (CO2-EOR) method from (A) clastic and (B) carbonate oil reservoirs in plays within the Bend Arch-Fort Worth 

Basin Province of Region 5. Estimates were made by using the CO2 Prophet simulator for candidate reservoirs. Play names and numbers 

are in table 8. Only plays containing at least six candidate reservoirs by lithology type have recovery factors plotted here.
22 Play-Level Distributions of Estimates of Recovery Factors for a Miscible CO2

-EOR Method

Table 11. Numbers of clastic and carbonate oil reservoirs that are candidates for the application of a miscible CO2-EOR method in 

plays of Region 6, the Gulf Coast Region.—Continued

[Candidate reservoirs must have permeability values of at least 2 millidarcies, a net pay at least 5 feet thick, and at least 5 million barrels of original oil in 

place. Petroleum province boundaries and codes are shown in figure 1; province codes are the first 2 digits of the play numbers. CO2-EOR, carbon dioxide 

enhanced oil recovery; dash (–), zero; Louis.-Miss. Salt Basins, Louisiana-Mississippi Salt Basins]

Play 

number

Number of oil 

reservoirs that are 

candidates for 

CO2-EOR

Province name Play name

Clastic Carbonate

4701 19 – Western Gulf Houston Salt Dome Flank Oil and Gas.

4705 – 9 Western Gulf Lower Cretaceous Carbonate Shelf/Shelf Edge Gas and Oil.

4708 – 1 Western Gulf Buda Downdip Oil.

4710 8 – Western Gulf Woodbine South Angelina Flexure Oil and Gas.

4715 3 – Western Gulf Upper Cretaceous Sandstones Fault Zone Oil.

4716 – 1 Western Gulf Upper Cretaceous Sandstones Maverick Basin Oil.

4719 9 – Western Gulf Lower Wilcox Fluvial Oil and Gas

4722 29 – Western Gulf Upper Wilcox Shelf-Edge Gas and Oil.

4724 2 – Western Gulf Middle Eocene Sandstones Downdip Gas.

4725 11 – Western Gulf Middle Eocene Sandstones Updip Fluvial Oil and Gas.

4726 33 – Western Gulf Yegua Updip Fluvial-Deltaic Oil and Gas.

4728 2 – Western Gulf Jackson Updip Gas and Oil.

4730 5 – Western Gulf Vicksburg Updip Gas.

4731 2 – Western Gulf Vicksburg Downdip Gas.

4732 1 – Western Gulf Frio South Texas Downdip Gas.

4733 49 – Western Gulf Frio South Texas Mid-Dip Oil and Gas.

4734 5 – Western Gulf Frio Updip Fluvial Gas and Oil.

4735 66 – Western Gulf Frio SE Texas/S. Louisiana Mid-Dip Gas and Oil.

4736 18 – Western Gulf Frio SE Texas/S. Louisiana Downdip Gas.

4737 9 – Western Gulf Hackberry Sandstone Gas and Oil.

4738 32 – Western Gulf Anahuac Sandstone Gas and Oil.

4739 1 – Western Gulf Lower Miocene Fluvial Sandstone Oil and Gas.

4740 15 – Western Gulf Lower Miocene Deltaic Sandstone Gas and Oil.

4741 7 – Western Gulf Lower Miocene Slope and Fan Sandstone Gas.

4743 68 – Western Gulf Middle Miocene Deltaic Sandstone Gas and Oil.

4745 34 – Western Gulf Upper Miocene Deltaic Sandstone Gas and Oil.

4746 1 – Western Gulf Plio-Pleistocene Fluvial Sandstone Oil.

4901 6 – Louis.-Miss. Salt Basins Piercement Salt Dome Flanks Oil and Gas.

4905 2 – Louis.-Miss. Salt Basins Norphlet Salt Basin Oil and Gas.

4910 – 8 Louis.-Miss. Salt Basins Smackover Alabama/Florida Peripheral Fault Zone Oil and Gas.

4911 – 1 Louis.-Miss. Salt Basins Smackover Alabama/Florida Updip Oil.

4912 – 31 Louis.-Miss. Salt Basins Smackover Salt Basins Gas and Oil.

4916 – 10 Louis.-Miss. Salt Basins Smackover East Texas-Southern Arkansas Fault Zone Oil and Gas.

4917 – 3 Louis.-Miss. Salt Basins Smackover East Texas-South Arkansas Updip Oil.

4918 5 – Louis.-Miss. Salt Basins Haynesville Salt Basins Gas and Oil.

4919 1 – Louis.-Miss. Salt Basins Haynesville Updip Alabama-Florida Oil.

4921 15 – Louis.-Miss. Salt Basins Cotton Valley Updip Oil.
Tables and Figures, Region 6 23

Table 11. Numbers of clastic and carbonate oil reservoirs that are candidates for the application of a miscible CO2-EOR method in 

plays of Region 6, the Gulf Coast Region.—Continued

[Candidate reservoirs must have permeability values of at least 2 millidarcies, a net pay at least 5 feet thick, and at least 5 million barrels of original oil in 

place. Petroleum province boundaries and codes are shown in figure 1; province codes are the first 2 digits of the play numbers. CO2-EOR, carbon dioxide 

enhanced oil recovery; dash (–), zero; Louis.-Miss. Salt Basins, Louisiana-Mississippi Salt Basins]

Play 

number

Number of oil 

reservoirs that are 

candidates for 

CO2-EOR

Province name Play name

Clastic Carbonate

4925 12 – Louis.-Miss. Salt Basins Hosston Updip Oil.

4926 2 – Louis.-Miss. Salt Basins Hosston/Travis Peak Salt Basins Gas.

4928 7 11 Louis.-Miss. Salt Basins Sligo/Pettet Updip Oil.

4929 – 6 Louis.-Miss. Salt Basins Sligo/Pettet Salt Basins Gas.

4930 – 13 Louis.-Miss. Salt Basins Pettet Southern Sabine Uplift Gas and Oil.

4931 – 1 Louis.-Miss. Salt Basins James Limestone Gas.

4932 25 13 Louis.-Miss. Salt Basins Glen Rose/Rodessa Updip Oil.

4934 27 – Louis.-Miss. Salt Basins Paluxy Updip Oil.

4935 4 – Louis.-Miss. Salt Basins Paluxy Downdip Gas.

4936 4 – Louis.-Miss. Salt Basins Tuscaloosa Peripheral Fault Zone Oil.

4937 29 – Louis.-Miss. Salt Basins Tuscaloosa/Woodbine Structural Oil and Gas.

4938 16 – Louis.-Miss. Salt Basins Tuscaloosa Stratigraphic Oil and Gas.

4939 2 – Louis.-Miss. Salt Basins Woodbine/Tuscaloosa Sabine Flanks Oil.

4940 3 – Louis.-Miss. Salt Basins Eutaw/Tokio Updip Oil.

4945 80 – Louis.-Miss. Salt Basins Wilcox Salt Basins Oil.
24 Play-Level Distributions of Estimates of Recovery Factors for a Miscible CO2

-EOR Method

Table 12. Distributions of recovery factors for technically recoverable oil that might be produced 

by use of a miscible carbon dioxide enhanced oil recovery (CO2-EOR) method and the median net 

CO2 utilization for plays in the Western Gulf Province of Region 6.

[Estimates were made by using the CO2 Prophet simulator for candidate oil reservoirs. Play names and numbers are in 

table 11. Only plays containing at least three candidate reservoirs by lithology type are shown here. Recovery factors 

are in percent, and the median net CO2 utilization is in thousands of cubic feet of CO2 per barrel of produced oil at the 

surface (mcf/bbl)]

Play 

number

Number of 

oil 

reservoirs

Recovery factor (percent) Median 

net CO2

utilization 

(mcf/bbl)

Minimum 1st 

quartile Median 3d quartile Maximum

Clastic reservoirs

4701 19 8.54 8.99 9.22 12.09 20.34 5.18

4710 8 9.11 9.28 9.53 9.70 9.93 6.63

4715 3 8.82 8.93 9.03 11.00 12.97 5.23

4719 9 8.78 8.85 8.95 9.34 12.76 4.86

4722 29 8.69 9.11 9.23 10.20 17.61 6.55

4725 11 8.52 9.00 9.28 9.44 10.59 5.42

4726 33 8.64 8.75 8.86 9.23 16.82 5.58

4730 5 8.60 8.63 8.64 8.64 8.73 5.58

4733 49 8.62 8.92 9.17 9.48 18.87 5.56

4734 5 8.80 9.18 9.22 9.46 9.60 5.20

4735 66 8.30 8.88 9.00 9.22 19.59 5.91

4736 18 8.76 8.96 9.44 10.11 17.34 6.53

4737 9 8.73 8.89 9.16 9.31 10.70 6.03

4738 32 8.71 8.80 8.91 9.07 17.01 5.89

4740 15 8.56 8.87 8.97 9.04 13.97 5.68

4741 7 8.99 9.01 9.02 9.43 9.48 5.30

4743 68 8.52 8.93 9.12 9.33 10.06 6.25

4745 34 8.62 8.83 8.95 9.12 9.46 5.61

Carbonate reservoirs

4705 9 12.05 12.43 12.58 13.56 22.76 6.03
Tables and Figures, Region 6 25

A. Clastic reservoirs B. Carbonate reservoirs

Figure 8. Boxplots of recovery factors for technically recoverable oil that might be produced by use of a miscible carbon dioxide 

enhanced oil recovery (CO2-EOR) method from (A) clastic and (B) carbonate oil reservoirs in plays within the Western Gulf Province of 

Region 6. Estimates were made by using the CO2 Prophet simulator for candidate reservoirs. Play names and numbers are in table 11. 

Only plays containing at least six candidate reservoirs by lithology type have recovery factors plotted here.
26 Play-Level Distributions of Estimates of Recovery Factors for a Miscible CO2

-EOR Method

Table 13. Distributions of recovery factors for technically recoverable oil that might be produced 

by use of a miscible carbon dioxide enhanced oil recovery (CO2-EOR) method and the median net 

CO2 utilization for plays in the Louisiana-Mississippi Salt Basins Province of Region 6.

[Estimates were made by using the CO2 Prophet simulator for candidate oil reservoirs. Play names and numbers are in 

table 11. Only plays containing at least three candidate reservoirs by lithology type are shown here. Recovery factors 

are in percent, and the median net CO2 utilization is in thousands of cubic feet of CO2 per barrel of produced oil at the 

surface (mcf/bbl)]

Play 

number

Number of 

oil 

reservoirs

Recovery factor (percent) Median 

net CO2

utilization 

(mcf/bbl)

Minimum 1st 

quartile Median 3d quartile Maximum

Clastic reservoirs

4901 6 8.56 9.51 12.48 12.92 17.36 5.62

4918 5 9.06 9.20 9.69 12.75 13.58 5.67

4921 15 9.11 9.41 9.48 11.30 13.72 6.06

4925 12 9.07 9.16 10.34 12.61 17.27 5.44

4928 7 9.29 9.44 9.52 9.78 13.05 6.00

4932 25 8.31 8.99 9.27 9.60 17.91 5.94

4934 27 8.85 9.01 9.29 9.98 17.41 5.51

4935 4 9.04 9.06 9.19 10.24 13.03 6.06

4936 4 9.14 9.57 10.00 11.92 16.84 5.23

4937 29 8.53 9.05 9.34 12.53 17.41 5.63

4938 16 8.94 9.09 12.73 13.00 17.63 5.76

4940 3 8.89 10.12 11.35 13.90 16.46 4.44

4945 80 8.58 8.92 9.12 9.59 18.20 4.98

Carbonate reservoirs

4910 8 12.30 12.66 13.10 13.40 24.17 6.80

4912 31 11.76 12.36 12.57 13.64 23.82 5.44

4916 10 11.55 12.15 12.54 12.96 24.09 5.32

4917 3 11.74 11.92 12.11 12.31 12.51 5.12

4928 11 11.43 12.16 12.42 17.35 22.84 4.84

4929 6 12.00 12.98 13.05 16.41 17.84 5.63

4930 13 11.76 12.28 12.55 15.66 23.14 5.26

4932 13 11.13 12.49 13.09 16.84 22.74 4.90
Tables and Figures, Region 6 27

A. Clastic reservoirs B. Carbonate reservoirs

Figure 9. Boxplots of recovery factors for technically recoverable oil that might be produced by use of a miscible carbon dioxide 

enhanced oil recovery (CO2-EOR) method from (A) clastic and (B) carbonate oil reservoirs in plays within the Louisiana-Mississippi (L-M) 

Salt Basins Province of Region 6. Estimates were made by using the CO2 Prophet simulator for candidate reservoirs. Play names and 

numbers are in table 11. Only plays containing at least six candidate reservoirs by lithology type have recovery factors plotted here.
28 Play-Level Distributions of Estimates of Recovery Factors for a Miscible CO2

-EOR Method

Table 14. Numbers of clastic and carbonate oil reservoirs that are candidates for the application of a miscible CO2-EOR method in 

plays of Region 7, the Midcontinent Region.—Continued

[Candidate reservoirs must have permeability values of at least 2 millidarcies, a net pay at least 5 feet thick, and at least 5 million barrels of original oil in 

place. Petroleum province boundaries and codes are shown in figure 1; province codes are the first 2 digits of the play numbers. CO2-EOR, carbon dioxide 

enhanced oil recovery; dash (–), zero]

Play 

number

Number of oil 

reservoirs that are 

candidates for 

CO2-EOR

Province name Play name

Clastic Carbonate

5304 2 6 Cambridge Arch-Central 

Kansas Uplift Mississippian and Devonian.

5305 6 57 Cambridge Arch-Central 

Kansas Uplift Pennsylvanian Cyclical Carbonates and Sandstones.

5308 5 4 Cambridge Arch-Central 

Kansas Uplift Ordovician.

5309 2 56 Cambridge Arch-Central 

Kansas Uplift Early Ordovician/Cambrian Arbuckle.

5501 36 21 Nemaha Uplift Pre-Woodford Paleozoic.

5503 – 23 Nemaha Uplift Mississippian.

5504 15 2 Nemaha Uplift Pennsylvanian-Permian Structural.

5505 35 7 Nemaha Uplift Pennsylvanian Stratigraphic.

5801 1 1 Anadarko Basin Deep Structural Gas.

5802 – 1 Anadarko Basin Uppermost Arbuckle.

5804 1 – Anadarko Basin Wichita Mountains Uplift.

5805 3 – Anadarko Basin Simpson Oil and Gas.

5809 – 5 Anadarko Basin Hunton Stratigraphic-Unconformity Gas and Oil.

5810 5 – Anadarko Basin Misener Oil.

5812 1 – Anadarko Basin Deep Stratigraphic Gas.

5813 2 35 Anadarko Basin Lower Mississippian Stratigraphic Oil and Gas.

5814 1 26 Anadarko Basin Upper Mississippian Stratigraphic Gas and Oil.

5815 1 – Anadarko Basin Springer Stratigraphic Gas and Oil.

5816 64 – Anadarko Basin Morrow Sandstone Gas and Oil Stratigraphic.

5819 14 – Anadarko Basin Lower Desmoinesian Stratigraphic Gas and Oil.

5820 – 24 Anadarko Basin Upper Desmoinesian Oil and Gas.

5821 11 1 Anadarko Basin Lower Missourian Stratigraphic Oil and Gas.

5822 – 19 Anadarko Basin Upper Missourian Oil and Gas.

5823 14 – Anadarko Basin Lower Virgilian Sandstone Gas and Oil.

5824 – 5 Anadarko Basin Upper Virgilian Stratigraphic Oil and Gas.

5827 3 – Anadarko Basin Washes.

5901 5 9 Sedgwick Basin Lower Paleozoic Combination Traps.

5902 1 20 Sedgwick Basin Mississippian Combination Traps.

5903 4 2 Sedgwick Basin Pennsylvanian Combination Traps.

6001 50 55 Cherokee Platform Pre-Woodford Paleozoic.

6003 – 5 Cherokee Platform Mississippian.

6004 12 1 Cherokee Platform Pennsylvanian Structural.

6005 21 – Cherokee Platform Pennsylvanian Stratigraphic.

6101 1 – Southern Oklahoma Deep Gas.
Tables and Figures, Region 7 29

Table 14. Numbers of clastic and carbonate oil reservoirs that are candidates for the application of a miscible CO2-EOR method in 

plays of Region 7, the Midcontinent Region.—Continued

[Candidate reservoirs must have permeability values of at least 2 millidarcies, a net pay at least 5 feet thick, and at least 5 million barrels of original oil in 

place. Petroleum province boundaries and codes are shown in figure 1; province codes are the first 2 digits of the play numbers. CO2-EOR, carbon dioxide 

enhanced oil recovery; dash (–), zero]

Play 

number

Number of oil 

reservoirs that are 

candidates for 

CO2-EOR

Province name Play name

Clastic Carbonate

6102 – 8 Southern Oklahoma Arbuckle Oil.

6103 14 – Southern Oklahoma Simpson Structural Oil.

6104 1 12 Southern Oklahoma Viola Oil and Gas.

6105 – 4 Southern Oklahoma Hunton Oil.

6107 2 6 Southern Oklahoma Misener-Woodford-Sycamore Gas and Oil.

6108 2 – Southern Oklahoma Springer Sandstone Oil and Gas.

6109 1 – Southern Oklahoma Atokan Sandstone Oil.

6110 12 – Southern Oklahoma Desmoinesian Sandstone Oil.

6111 2 – Southern Oklahoma Missourian Sandstone Oil and Gas.

6204 1 – Arkoma Basin Morrowan Shallow Marine Sandstone and Limestone Gas.

6205 1 2 Arkoma Basin Arbuckle through Misener Basement Fault and Shelf Gas.
30 Play-Level Distributions of Estimates of Recovery Factors for a Miscible CO2

-EOR Method

Table 15. Distributions of recovery factors for technically recoverable oil that might be produced 

by use of a miscible carbon dioxide enhanced oil recovery (CO2-EOR) method and the median net 

CO2 utilization for plays in Region 7, the Midcontinent Region, excluding plays in the Anadarko Basin 

Province.

[Estimates were made by using the CO2 Prophet simulator for candidate oil reservoirs. Play names and numbers are in 

table 14. Only plays containing at least three candidate reservoirs by lithology type are shown here. Recovery factors 

are in percent, and the median net CO2 utilization is in thousands of cubic feet of CO2 per barrel of produced oil at the 

surface (mcf/bbl)]

Play 

number

Number of 

oil 

reservoirs

Recovery factor (percent) Median 

net CO2

utilization 

(mcf/bbl)

Minimum 1st 

quartile Median 3d quartile Maximum

Clastic reservoirs

5305 6 8.14 8.72 8.85 8.96 12.23 5.86

5308 5 8.93 9.15 9.24 10.83 12.12 6.22

5501 36 8.78 9.13 9.36 9.69 18.96 5.89

5504 15 8.71 9.61 9.85 10.10 13.73 7.45

5505 35 8.84 9.55 9.65 11.42 17.72 4.86

5901 5 9.09 9.66 10.24 10.67 19.38 6.01

5903 4 8.83 8.86 8.93 8.99 9.00 5.89

6001 50 8.31 8.95 9.13 9.31 17.65 5.80

6004 12 8.71 8.88 9.03 9.25 12.54 5.65

6005 21 8.78 8.91 9.09 12.15 13.18 5.88

6103 14 8.98 9.62 12.80 13.37 20.45 5.35

6110 12 8.84 9.25 9.47 12.73 12.83 6.42

Carbonate reservoirs

5304 6 11.52 12.21 16.80 21.58 22.08 4.49

5305 57 10.40 11.35 14.91 16.83 22.59 4.71

5308 4 12.96 13.50 14.12 14.66 14.98 4.82

5309 56 10.03 14.76 15.52 16.88 22.30 4.55

5501 21 11.67 12.34 14.84 17.18 25.29 5.07

5503 23 11.45 12.66 13.42 15.36 17.70 4.76

5505 7 11.91 12.46 12.55 12.65 12.69 4.19

5901 9 21.68 22.41 22.69 23.04 23.44 4.00

5902 20 11.05 11.66 12.43 22.53 24.22 5.24

6001 55 11.32 12.66 13.45 13.78 22.84 4.73

6003 5 11.47 12.33 12.73 16.68 16.87 4.60

6102 8 11.44 11.90 12.07 12.35 12.88 4.81

6104 12 11.80 11.82 12.02 12.24 16.67 4.16

6105 4 12.54 12.55 12.57 12.65 12.86 5.59

6107 6 11.91 12.20 12.68 13.06 13.38 5.54
Tables and Figures, Region 7 31

A. Clastic reservoirs B. Carbonate reservoirs

Figure 10. Boxplots of recovery factors for technically recoverable oil that might be produced by use of a miscible carbon dioxide 

enhanced oil recovery (CO2-EOR) method from (A) clastic and (B) carbonate oil reservoirs in plays within Region 7, the Midcontinent 

Region, excluding plays in the Anadarko Basin Province. Estimates were made by using the CO2 Prophet simulator for candidate 

reservoirs. Play names and numbers are in table 14. Only plays containing at least six candidate reservoirs by lithology type have 

recovery factors plotted here.
32 Play-Level Distributions of Estimates of Recovery Factors for a Miscible CO2

-EOR Method

Table 16. Distributions of recovery factors for technically recoverable oil that might be produced 

by use of a miscible carbon dioxide enhanced oil recovery (CO2-EOR) method and the median net 

CO2 utilization for plays in the Anadarko Basin Province of Region 7.

[Estimates were made by using the CO2 Prophet simulator for candidate oil reservoirs. Play names and numbers are in 

table 14. Only plays containing at least three candidate reservoirs by lithology type are shown here. Recovery factors 

are in percent, and the median net CO2 utilization is in thousands of cubic feet of CO2 per barrel of produced oil at the 

surface (mcf/bbl)]

Play 

number

Number of 

oil 

reservoirs

Recovery factor (percent) Median 

net CO2

utilization 

(mcf/bbl)

Minimum 1st 

quartile Median 3d quartile Maximum

Clastic reservoirs

5805 3 9.55 9.65 9.74 11.76 13.79 6.31

5810 5 9.48 9.52 9.67 9.74 11.56 6.86

5816 64 8.57 9.31 9.55 12.86 13.91 6.07

5819 14 8.99 9.41 9.59 12.35 19.30 6.24

5821 11 9.70 9.83 10.02 10.78 14.15 7.46

5823 14 9.40 9.64 9.71 9.92 14.58 7.06

5827 3 9.31 9.54 9.77 11.91 14.05 7.68

Carbonate reservoirs

5809 5 11.97 12.22 12.65 17.87 18.10 4.39

5813 35 11.79 12.30 16.60 22.14 23.04 4.90

5814 26 11.20 12.90 13.88 14.59 23.64 5.48

5820 24 11.36 12.73 13.68 14.70 22.03 5.34

5822 19 11.31 11.72 11.91 12.40 14.91 5.19

5824 5 11.57 12.54 13.88 13.97 14.42 5.57
Tables and Figures, Region 7 33

A. Clastic reservoirs B. Carbonate reservoirs

Figure 11. Boxplots of recovery factors for technically recoverable oil that might be produced by use of a miscible carbon dioxide 

enhanced oil recovery (CO2-EOR) method from (A) clastic and (B) carbonate oil reservoirs in plays within the Anadarko Basin Province 

of Region 7. Estimates were made by using the CO2 Prophet simulator for candidate reservoirs. Play names and numbers are in table 14. 

Only plays containing at least six candidate reservoirs by lithology type have recovery factors plotted here.
34 Play-Level Distributions of Estimates of Recovery Factors for a Miscible CO2

-EOR Method

Table 17. Numbers of clastic and carbonate oil reservoirs that are candidates for the application of a miscible CO2-EOR method in 

plays of Region 8, the Eastern Region.

[Candidate reservoirs must have permeability values of at least 2 millidarcies, a net pay at least 5 feet thick, and at least 5 million barrels of original oil in 

place. Petroleum province boundaries and codes are shown in figure 1; province codes are the first 2 digits of the play numbers. CO2-EOR, carbon dioxide 

enhanced oil recovery; dash (–), zero]

Play 

number

Number of oil 

reservoirs that are 

candidates for 

CO2-EOR

Province name Play name

Clastic Carbonate

6301 – 27 Michigan Basin Anticline.

6307 – 31 Michigan Basin Northern Niagaran Reef.

6308 – 9 Michigan Basin Southern Niagaran Reef.

6311 – 3 Michigan Basin Trenton-Black River.

6401 3 10 Illinois Basin Illinois Basin-Post-New Albany.

6402 – 4 Illinois Basin Illinois Basin-Hunton.

6404 – 2 Illinois Basin Illinois Basin-Middle and Upper Ordovician Carbonate.

Table 18. Distributions of recovery factors for technically recoverable oil that might be produced 

by use of a miscible carbon dioxide enhanced oil recovery (CO2-EOR) method and the median net 

CO2 utilization for plays in Region 8, the Eastern Region.

[Estimates were made by using the CO2 Prophet simulator for candidate oil reservoirs. Play names and numbers are in 

table 17. Only plays containing at least three candidate reservoirs by lithology type are shown here. Recovery factors 

are in percent, and the median net CO2 utilization is in thousands of cubic feet of CO2 per barrel of produced oil at the 

surface (mcf/bbl)]

Play 

number

Number 

of oil 

reservoirs

Recovery factor (percent) Median 

net CO2

utilization 

(mcf/bbl)

Minimum 1st 

quartile Median 3d quartile Maximum

Clastic reservoirs

6401 3 8.76 8.81 8.86 9.05 9.24 5.69

Carbonate reservoirs

6301 27 11.73 12.60 13.22 15.99 24.52 5.51

6307 31 12.64 13.30 13.58 19.54 24.83 6.73

6308 9 11.85 12.16 12.59 17.16 23.91 5.38

6311 3 12.53 14.46 16.39 18.81 21.23 4.98

6401 10 11.35 11.67 11.79 12.32 22.51 4.92

6402 4 11.83 11.91 12.15 12.40 12.52 5.19
Tables and Figures, Region 8 35

Figure 12. Boxplots of recovery factors for technically 

recoverable oil that might be produced by use of a miscible 

carbon dioxide enhanced oil recovery (CO2-EOR) method from 

carbonate oil reservoirs in plays within Region 8, the Eastern 

Region. Estimates were made by using the CO2 Prophet simulator 

for candidate reservoirs. Play names and numbers are in table 17. 

Only plays containing at least six candidate reservoirs by lithology 

type have recovery factors plotted here.

Carbonate reservoirs
36 Play-Level Distributions of Estimates of Recovery Factors for a Miscible CO2

-EOR Method

A. Clastic reservoirs B. Carbonate reservoirs

Figure 14. Histograms representing the distribution of CO2 retention factors for (A) 2,018 clastic and (B) 1,681 carbonate conventional 

oil reservoirs in the conterminous United States. Retention factors were computed from the results of miscible carbon dioxide enhanced 

oil recovery (CO2-EOR) simulations with the CO2 Prophet simulator.

Figure 13. Histograms representing the distribution of recovery factors for (A) 2,018 clastic and (B) 1,681 carbonate conventional oil 

reservoirs in the conterminous United States. Recovery factors are for technically recoverable oil that might be produced by use of a 

miscible carbon dioxide enhanced oil recovery (CO2-EOR) method and were computed with the CO2 Prophet simulator.

A. Clastic reservoirs B. Carbonate reservoirs

Attanasi and Freeman—Play-Level Distributions of Estimates of Recovery Factors for a Miscible CO2-EOR Method—Open-File Report 2015–1239

ISSN 2331-1258 (online)

http://dx.doi.org/10.3133/ofr20151239