Storing CO2 with Enhanced Oil Recovery 

DOE/NETL-402/1312/02-07-08 

February 7, 2008
Disclaimer

This report was prepared as an account of work sponsored by an agency of the 

United States Government. Neither the United States Government nor any 

agency thereof, nor any of their employees, makes any warranty, express or 

implied, or assumes any legal liability or responsibility for the accuracy, 

completeness, or usefulness of any information, apparatus, product, or process 

disclosed, or represents that its use would not infringe privately owned rights. 

Reference therein to any specific commercial product, process, or service by trade 

name, trademark, manufacturer, or otherwise does not necessarily constitute or 

imply its endorsement, recommendation, or favoring by the United States 

Government or any agency thereof. The views and opinions of authors expressed 

therein do not necessarily state or reflect those of the United States Government 

or any agency thereof.
Storing CO2 with Enhanced Oil Recovery 

DOE/NETL-402/1312/02-07-08

February 7, 2008 

NETL Contact: 

Lisa Phares 

Office of Systems, Analyses and Planning 

Prepared by: 

Vello Kuuskraa 

Robert Ferguson 

Advanced Resources International 

National Energy Technology Laboratory 

www.netl.doe.gov 
This page intentionally left blank 
Table of Contents 

1.0 Introduction 1

2.0 Background 3

2.1. Key Feature of This New Report 3

2.2. Addressing Current Misconceptions Surrounding Storing CO2 with EOR 6

2.3. Report Outline 7

3.0 Evaluating the Market for Captured CO2 Emissions Offered by EOR 9

3.1. Study Methodology 9

3.2. The Domestic Oil Resource Base 9

3.3. Technically Recoverable Oil Resources Using CO2-EOR 15

3.3.1. Using CO2-EOR to Recovery “Stranded” Oil 15

3.3.2. Current CO2-EOR Activity and Production 17

3.3.3. Evolution in CO2 Flooding Practices 20

3.3.4. Technically Recoverable Resources 25

3.4. Economically Recoverable Resources 28

3.4.1. Perspective on CO2-EOR Economics 28

3.4.2. Economically Recoverable Resources: Base Case 29

3.4.3. Economically Recoverable Resources: Sensitivity Cases 29

4.0 The Market for Storing CO2 with EOR 34

4.1. The CO2 Injection and Storage Process 34

4.2. Producing “Carbon Free” Domestic Oil 35

4.3. The Market for CO2 35

4.4. Market Demand for CO2: Power Plant Perspective 39

5.0 Using Sale of Captured CO2 Emission for “Early Market Entry” of CCS 

Technology 48

5.1. Economics of CCS 48

5.2. Supporting “Early Market Entry” of CCS Technology 50

5.3. Adding “Learning” to the “Early Market Entry” Opportunity 53

Appendix A Study Methodology 

Appendix B Incorporation of Economically Feasible CO2 Demand for EOR into the 

CarBen Model and the Electricity Market Module 

Appendix C “Next Generation” CO2-EOR 
List of Figures 

Figure 1. U.S. Basins/Regions Studied For Future CO2 Storage and Enhanced Oil Recovery 5 

Figure 2. The Domestic Oil Resource Base 10 

Figure 3. One-Dimensional Schematic Showing the CO2 Miscible Process. 16 

Figure 4. U.S. CO2-EOR Activity 18 

Figure 5. Growth of CO2-EOR Production in the U.S. 19 

Figure 6A. Science Behind Volume of CO2 Injection and Oil Recovery Efficiency: General Theory 21 

Figure 6B. Science Behind Volume of CO2 Injection and Oil Recovery Efficiency: Actual Practice 22 

Figure 7. Overcoming the Effects of Geologic Complexity on CO2-EOR Performance 23 

Figure 8. Evolution of “Industry Standard” for Volume CO2 Injection (“Slug Size”) 24 

Figure 6. Economically Recoverable Domestic Oil Resources from CO2-EOR 32 

Figure 7. NEMS Electricity Market Module 40 

Figure 8. Advanced Coal Plants w/CCS Are Currently Uncompetitive in 2012 and 2020 (EIA’s AEO 

2008 Reference Case) 49 

Figure 9. Sale of Captured CO2 Emissions Can Help Make Coal Plants w/CCS Competitive 52 

Figure 10. Sale of Captured CO2 Emissions Can Help Make Coal Plants w/CCS Competitive. 55

List of Tables 

Table 1. National In-Place, Conventionally Recoverable and “Stranded” Crude Oil Resources 12 

Table 2. Comparison of National and Data Base Domestic Oil Resource Base 13 

Table 3. Major Oil Reservoirs Screened as Favorable for CO2-EOR 14 

Table 4. Technically Recoverable Resources from Applying “State-of-the-Art” CO2-EOR: Data Base 

and National Totals 26

Table 5. Technically Recoverable Resources from Applying “State-of-the-Art” CO2-EOR: National 

Totals 27

Table 6. Illustrative Costs and Economics of a CO2-EOR Project 28 

Table 7. Economically Recoverable Resources from Applying “State-of-the-Art” CO2-EOR: National 

Totals at Base Case Economics* 30 

Table 8. Economically Recoverable Resources from Applying “State-of-the-Art” CO2-EOR: National 

Totals at Base Case and Alternative Oil Prices/CO2 Costs 31 

Table 9. Economically Feasible Market for CO2 for CO2-EOR: Base Case* (Eleven Basins/Areas) 37

Table 10. Economically Feasible Market Demand for CO2 by CO2-EOR: Alternative Cases (Eleven 

Basins/Areas) 38

Table 11. Economically Feasible Market Demand for CO2 by EOR: NEMS/EMM Power Generation 

Regions 41 

Table 12. Simplified Crosswalk Between the EMM Regions and States 42 

Table 13. Economically Feasible Market Demand for CO2 by EOR: NEMS/EMM Power Generation 

Regions 44 

Table 14. Existing CO2 Supplies 45 

Table 15. Comparison of Net CO2 Demand (for EOR) with Potential Captured CO2 Emissions from 

Coal-Fueled Power Plants 47 

Table 16. Relationship of CO2 Sales Price to Cost Offsets in the Coal-Fueled Power Sector (Year 

2020) 50 

Table 17. EIA Reference Case Year 2012 and Year 2020 Costs of Electricity 50 

Table 18. Cost of Electricity in Year 2020 with Sale of CO2 51 

Table 19. Year 2020 Costs of Electricity with Accelerated “Learning” Based Cost Reductions 53 

Table 20. Year 2020 Cost of Electricity with “Learning” and CO2 Sale Offset 54 
Storing CO2 with Enhanced Oil Recovery 

1.0 Introduction 

CO2 enhanced oil recovery (CO2-EOR) offers the potential for storing significant 

volumes of carbon dioxide emissions while increasing domestic oil production. Four 

notable benefits would accrue from integrating CO2 storage and enhanced oil recovery: 

 First, CO2-EOR provides a large, “value added” market for sale of CO2 

emissions captured from new coal-fueled power plants. The size of this 

market is on the order of 7,500 million metric tons between now and 2030. 

Sales of captured CO2 emissions would help defray some of the costs of 

installing and operating carbon capture and storage (CCS) technology. 

These CO2 sales would support “early market entry” of up to 49 (one GW 

size) installations of CCS technology in the coal-fueled power sector; 

 Second, storing CO2 with EOR helps bypass two of today’s most serious 

barriers to using geological storage of CO2 - - establishing mineral (pore 

space) rights and assigning long-term liability for the injected CO2; 

 Third, the oil produced with injection of captured CO2 emissions is 70% 

“carbon-free”, after accounting for the difference between the carbon 

content in the incremental oil produced by EOR and the volume of CO2 

stored in the reservoir . With “next generation” CO2 storage technology 

and a value for storing CO2, the oil produced by EOR could be 100+% 

“carbon free”; 

 Fourth, the 39 to 48 billion barrels of economically recoverable domestic 

oil economically recoverable from storing CO2 with EOR would help 

displace imports, supporting a path toward energy independence. It could 

also help build pipeline infrastructure subsequently usable for storing CO2 

in saline formations. 

 1 
The purpose of this report, which updates and adds to a previously issued series 

of “basin studies”, is to examine and further quantify the benefits of integrating CO2 

storage with enhanced oil recovery. The report also updates the size of the CO2 

market available from EOR and how this market could support “early market entry” of 

CCS technology in the coal-fueled electric power sector. 

 2 
2.0 Background 

2.1. Key Feature of This New Report 

In 2004 and 2005, Advanced Resources International, with sponsorship by the 

U.S. Department of Energy’s Office of Fossil Energy, issued a series of ten “basin 

reports”.∗ These reports examined the domestic CO2 storage and oil recovery potential 

offered by expanded development and application of CO2-EOR technology. This report 

entitled, “Storing CO2 with Enhanced Oil Recovery”, provides a major update to this 

past set of data and information. For example, the initial chapter of the report which 

serves to quantify the size of the CO2 market offered by EOR, contains the following 

new features: 

 A significant number, nearly 500, new oil reservoirs have been added to 

the data base, including oil reservoirs in the Appalachian Basin. The 

assessment now includes 2,012 oil reservoirs accounting for nearly threequarters of the U.S. oil resource base in 27 states, Figure 1. These new 

oil reservoirs were made available for this study from Advanced 

Resources proprietary data base; 

 Improvements and updates have been made to the well spacing and CO2 

injection portions of the model. Oil field cost data have been updated and 

indexed to year 2006-2007. These updates and improvements are based 

on internal work undertaken by Advanced Resources; and 

 An expanded set of oil prices and a revised oil price/CO2 cost relationship 

have been incorporated into the economic analyses, as presented later in 

this report. 

                                                     

∗ The Advanced Resources completed series of ten “basin studies” were the first to comprehensively address CO2

storage capacity from combining CO2 storage and CO2‐EOR.  These ten “basin studies” covered 22 of the oil

producing states plus offshore Louisiana and included 1,581 large (>50 MMBbls OOIP) oil reservoirs, accounting for

two thirds of U.S. oil production.  These reports are available on the U.S. Department of Energy’s web site at:

http://www.fe.doe.gov/programs/oilgas/eor/Ten_Basin‐Oriented_CO2‐EOR_Assessments.html.

 3 
 4 

The later chapters of this report examine how much of the CO2 emissions 

captured by the power and industrial sectors could be sold to the EOR industry and how 

the sale of these captured CO2 emissions would support the “early market entry” of new 

coal-fueled power plants equipped with CO2 capture technologies.
 5 

The 27 states with shading are included in the eleven Advanced Resources International updated “basin stuof CO2 storage with enhanced oil recovery.

JAF02709.PPT

Figure 1. U.S. Basins/Regions Studied For Future CO2 Storage and Enhanced Oil Recovery 
2.2. Addressing Current Misconceptions Surrounding Storing CO2 with EOR 

Various analysts and studies have discussed the potential for storing CO2 with 

enhanced oil recovery but have noted (incorrectly) that this option is quite small or is 

counter productive to reducing CO2 emissions. For example, the “IPCC Special Report 

on Carbon Dioxide Capture and Storage”, while recognizing that depleted oil fields 

could provide an attractive, early option for storing CO2 (particularly with CO2-EOR), 

concluded that oil fields would provide only a relatively small volume of CO2 storage 

capacity. The report states: 

“Enhanced oil recovery operations have the lowest capacity of all 

forms of CO2 geologic storage, estimated globally at 61 to 123 billion tons 

of CO2 . . . it is important to note that CO2 EOR, as practiced today, is not 

engineered to maximize CO2 storage. In fact, it is optimized to maximize 

revenues from oil production, which in many cases requires minimizing the 

amount of CO2 retained in the reservoir. In the future, if storing CO2 has 

an economic value, co-optimizing CO2 storage and EOR may increase 

capacity estimates.” 

In a similar vein, the website Climate Progress contains the headline - - “Rule 

Four of Offsets: No Enhanced Oil Recovery”. The website continues by stating: 

 “Capturing CO2 and injecting it into a well to squeeze more oil out 

of the ground is not real carbon sequestration. . . .CO2 used for enhanced 

oil recovery (EOR) does not reduce net carbon emissions and should not 

be sold to the public as a carbon offset.” 

Finally, the ERS/IEA Report: “Carbon Dioxide Capture and Storage in the Clean 

Development Mechanism (CDM)” sets forth two assumptions that shape the report’s 

view of storing CO2 with EOR: 

 As CO2-EOR projects reach the end of their life, greater volumes of CO2 

will be produced (and emitted); and 

 6 
 CO2-EOR projects will result in increased carbon emissions from 

incremental oil production above a No Further Activity (NFA) baseline. 

The ERS/IEA report continues by stating that, to be acceptable, a CO2-EOR 

project would need to provide a full carbon balance across the whole life cycle of the 

project, including emissions from combustion of the incremental oil produced. The 

ERS/IEA report recommends that for acceptance by CDM, CO2-EOR would need to 

demonstrate net emission reductions. 

One of the additional purposes of this new report is to address, and hopefully 

dispel, some of the misconceptions that have arisen around the topic of storing CO2 

with enhanced oil recovery by showing that: (1) for the U.S. (and by extension for the 

world), the CO2 storage capacity offered by CO2-EOR is large, and when innovatively 

engineered, can be larger still; (2) essentially all the purchased CO2 is reinjected and 

thus stored in the original (or an adjacent) oil reservoir; and (3) the incremental oil 

produced is 70% “carbon free”, creating net emission reductions - - and thus 

additionality - - by displacing conventionally produced oil imports that are 0% “carbon 

free” or corn-based ethanol, that is only 10 to 15% “carbon free” (and a net contributor 

of CO2 emissions when coal is used as the process fuel). 

2.3. Report Outline 

The report begins with a summary presentation of three topics central to 

establishing the market for CO2 offered by EOR - - what is the size and nature of the 

domestic oil resource base; how much of this resource base is applicable to and can be 

recovered with CO2-EOR; and, what portion of this technically recoverable resource 

would be economic at alternative oil prices and CO2 costs? 

The report then examines the market opportunity for selling captured CO2 

emissions to the EOR industry and storing these emissions in oil reservoirs using CO2-

EOR, giving particular attention to the capture and productive use of CO2 emissions 

from the nation’s large and growing fleet of coal-fueled power plants. 

 7 
A series of appendices provide supporting data and technical information for the 

analytical results discussed in the main report. Additional discussion of key topics such 

as the oil recovery and cost models and the data bases used in the analyses are 

available in the previously published set of ten “basin studies” and thus are not repeated 

in this updated report. The previously prepared “basin study” reports can be accessed 

at http://www.fe.doe.gov/programs/oilgas/publications/. 

 8 
 9 

                                                     

3.0 Evaluating the Market for Captured CO2 Emissions Offered by 

EOR 

The size and value of the market for captured CO2 emissions offered by 

enhanced oil recovery rests on three pillars: (1) the size and nature of the domestic 

crude oil resource base, particularly the large portion of this resource base 

unrecoverable with existing primary and secondary oil recovery methods; (2) the ability 

of CO2-EOR to recovery a portion of this currently unrecoverable (“stranded”) domestic 

oil, while efficiently storing CO2; and (3) the impact of alternative oil prices and CO2 

costs on the volume of oil that could be economically produced. These three topics are 

examined, in brief, in this section of the report. 

3.1. Study Methodology 

A six part methodology was used to assess the CO2 storage and EOR potential 

of domestic oil reservoirs. The six steps were: (1) assembling the Major Oil Reservoirs 

Data Base; (2) calculating the minimum miscibility pressure; (3) screening reservoirs for 

CO2-EOR; (4) calculating oil recovery; (5) assembling the cost and economic model; 

and, (6) performing economic and sensitivity analyses. 

Appendix A provides additional detail on the methodology used in this study. 

3.2. The Domestic Oil Resource Base 

The U.S. has a large, established oil resource base, on the order of 596 billion 

barrels originally in-place. About one-third of this resource base, nearly 196 billion 

barrels, has been recovered or placed into proved reserves with existing primary and 

secondary oil recovery technologies. This leaves behind a massive target of 400 billion 

barrels of “technically stranded” oil, Figure 2∗

. 

∗ When less established domestic oil resources, such as undiscovered oil, tar sands, and oil trapped in

residual oil zones are included, the “stranded” oil resource approaches 1,000 billion barrels.  For further

information on this topic see Chapter 3 (pages 183 and 184) of the recently issued National Petroleum

Council report “Hard Truths, Facing the Hard Truths about Energy” July, 2007,

http://www.npchardtruthsreport.org/
 10 

Large Volumes Of Domestic Oil Remain “Stranded” After Traditional Primary/Secondary Oil 

Original Oil In-Place: 596 B Barrels*

“Stranded” Oil In-Place: 400 B Barrels*

Proved Reserves

21 Billion Barrels

Future Challenge

400 Billion Barrels

Cumulative Production175 Billion Barrels

*Excludes deep-water GOM.Source: Advanced Resources International (2008)

JAF02709.PPT

Figure 2. The Domestic Oil Resource Base 
Table 1 provides a tabulation of the national in-place, conventionally recoverable 

and “stranded” oil in the eleven “basins” addressed by this study. The table shows that 

much of the “stranded” oil resides in East and Central Texas (74 billion barrels), the 

Mid-Continent (66 billion barrels), and the Permian Basin of West Texas and New 

Mexico (62 billion barrels). California, Alaska, the Gulf Coast and the Rockies also have 

significant volumes of “stranded” oil. 

The Advanced Resources’ Major Oil Reservoirs Data Base of 2,012 distinct oil 

reservoirs contains 74% (437.8 billion barrels of OOIP out of the national total of 595.7 

billion barrels of OOIP), of the domestic oil resource, Table 2. 

The data base coverage for individual basins/areas ranges from 59% for the MidContinent to 97% for Alaska. As such, the Major Oil Reservoir Data Base provides a 

robust foundation for estimating the national oil recovery potential from CO2-EOR. 

Not all of the domestic oil resource is technically amenable to CO2-EOR. 

Favorable reservoir properties for CO2-EOR include sufficiently deep formations with 

lighter (higher gravity) oil favorable for miscible CO2-EOR. A portion of the shallower oil 

reservoirs with heavier (lower gravity) oil may be amenable to immiscible CO2-EOR. 

Table 3 provides a basin/area level tabulation of the 2,012 reservoirs in the Major 

Oil Reservoirs Data Base, showing that only 1,111 reservoirs (containing 319 billion 

barrels of OOIP) screened as being amenable to miscible and immiscible CO2-EOR. 

More than half of the oil reservoirs in California, particularly the shallower heavy oil 

fields, are screened as unfavorable for CO2-EOR while the great bulk (over 80%) of the 

geologically favorable oil reservoirs in the Permian Basin are screened as favorable for 

CO2-EOR. 

 11 
Table 1. National In-Place, Conventionally Recoverable and “Stranded” Crude Oil Resources 

Basin/Area 

OOIP* 

(Billion Barrels) 

Conventionally 

Recoverable 

(Billion Barrels) 

ROIP** 

“Stranded” 

(Billion Barrels) 

1. Alaska 67.3 22.3 45.0

2. California 83.3 26.0 57.3

3. Gulf Coast (AL, FL, MS, LA) 44.4 16.9 27.5

4. Mid-Continent (OK, AR, KS, NE) 89.6 24.0 65.6

5. Illinois/Michigan 17.8 6.3 11.5

6. Permian (W TX, NM) 95.4 33.7 61.7

7. Rockies (CO,UT,WY) 33.6 11.0 22.6

8. Texas, East/Central 109.0 35.4 73.6

9. Williston (MT, ND, SD) 13.2 3.8 9.4

10. Louisiana Offshore 28.1 12.4 15.7

11. Appalachia (WV, OH, KY, PA) 14.0 3.9 10.1

Total 595.7 195.7 400.0

*Original Oil in Place, in all reservoirs in basin/area; 

** Remaining Oil in Place, in all reservoirs in basin/area. 

Source: Advanced Resources Int’l, 2008.

 12 
Table 2. Comparison of National and Data Base Domestic Oil Resource Base 

Basin/Area 

National 

OOIP* 

(Billion Barrels) 

Data Base 

OOIP* 

(Billion Barrels) 

Data Base 

Coverage 

(%) 

1. Alaska 67.3 65.4 97

2. California 83.3 75.2 90

3. Gulf Coast (AL, FL, MS, LA) 44.4 26.4 60

4. Mid-Continent (OK, AR, KS, NE) 89.6 53.1 59

5. Illinois/Michigan 17.8 12.0 67

6. Permian (W TX, NM) 95.4 72.4 76

7. Rockies (CO,UT,WY) 33.6 23.7 70

8. Texas, East/Central 109.0 67.4 62

9. Williston (MT, ND, SD) 13.2 9.4 71

10. Louisiana Offshore 28.1 22.2 79

11. Appalachia (WV, OH, KY, PA) 14.0 10.6 76

Total 595.7 437.8 74

*Original Oil In-Place, in all reservoirs in basin/area; 

Source: Advanced Resources Int’l, 2008.

 13 
Table 3. Major Oil Reservoirs Screened as Favorable for CO2-EOR 

Major Oil Reservoirs Data Base 

Basin/Area 

# of Total 

Reservoirs

# Favorable 

For CO2-EOR 

1. Alaska 42 32 

2. California 187 86 

3. Gulf Coast (AL,FL, MS, LA) 298 155 

4. Mid-Continent (OK, AR, KS, NE) 246 102 

5. Illinois/Michigan 172 72 

6. Permian (W TX, NM) 228 190 

7. Rockies (CO,UT,WY) 187 92 

8. Texas, East/Central 213 161 

9. Williston (MT, ND, SD) 95 54 

10. Louisiana Offshore 156 99 

11. Appalachia (WV, OH, KY, PA) 188 68 

Total 2,012 1,111 

 14 
3.3. Technically Recoverable Oil Resources Using CO2-EOR 

3.3.1. Using CO2-EOR to Recovery “Stranded” Oil 

Numerous scientific as well as practical reasons account for the large volume of 

“stranded” oil, unrecoverable with primary and secondary methods. These include: oil 

that is bypassed due to poor waterflood sweep efficiency; oil that is physically 

unconnected to a wellbore; and, most importantly, oil that is trapped by viscous, 

capillary and interfacial tension forces as residual oil in the pore space. 

Injection of CO2 helps lower the oil viscosity and trapping forces in the reservoir. 

Additional well drilling and pattern realignment for the EOR project helps contact 

bypassed and occluded oil. These actions enable a portion of this “stranded oil” to 

become mobile, connected to a wellbore and thus recoverable. 

Miscible CO2-EOR is a multiple contact process involving interactions between 

the injected CO2 and the reservoir’s oil. During this multiple contact process, CO2 

vaporizes the lighter oil fractions into the injected CO2 phase and CO2 condenses into 

the reservoir’s oil phase. This leads to two reservoir fluids that become miscible (mixing 

in all parts), with favorable properties of low viscosity, enhanced mobility and low 

interfacial tension. 

The primary objective of miscible CO2-EOR is to remobilize and dramatically 

reduce the after-waterflooding residual oil saturation in the reservoir’s pore space. 

Figure 3 provides a one-dimensional schematic showing the various fluid phases 

existing in the reservoir and the dynamics of the CO2 miscible process. 

 15 
Pure

CO2

CO2 Vaporizing

Oil Components

CO2

Condensing

Into Oil

Original 

Oil

Miscibility is Developed in This Region

(CO2 and Oil Form Single Phase)

Direction of Displacement

JAF02709.PPT

Figure 3. One-Dimensional Schematic Showing the CO2 Miscible Process. 

 16 
 17 

3.3.2. Current CO2-EOR Activity and Production 

According to the latest tabulation of CO2-EOR activity in the U.S., the 2006 EOR 

Survey published by the Oil and Gas Journal, approximately 237 thousand barrels per 

day of incremental domestic oil is being produced by 86 CO2-EOR projects, distributed 

broadly across the U.S. 

Figure 4 provides the location of the currently active 86 CO2-EOR projects, 

noting their CO2 supply sources. Figure 5 tracks the steady growth in CO2-EOR 

production for the past 20 years, noting that although new activities are underway in the 

Gulf Coast and the Rockies, the great bulk of CO2-EOR is still being produced from the 

Permian Basin. 

Given the significant number of new and expanded CO2-EOR projects launched 

in 2006 and 2007, we anticipate that the next EOR Survey, due to be published in the 

spring of 2008, will show substantial increases in domestic CO2-EOR activity and oil 

production. 
JAF0 1994 .C DR

LaBarge

Gas Plant

LaBarge

Gas Plant

Val Verde

Gas Plants

Val Verde

Gas Plants

Enid Fertilizer

Plant

Enid Fertilizer

Plant

Jackson

Dome

Jackson

Dome

McElmo Dome

Sheep Mountain

Bravo Dome

McElmo Dome

Sheep Mountain

Bravo Dome

9

6

6

57

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Dakota Coal

Gasification

Plant

Dakota Coal

Gasification

Plant

Antrim Gas

Plant

Antrim Gas

Plant

2

1

1

Number of CO2-EOR Projects

Natural CO2 Source

Industrial CO2 Source

CO2 Pipeline

86

JAF02709.PPT

Figure 4. U.S. CO2-EOR Activity 

 18 
 19 

Source: Oil and Gas Journal, April, 2006. Year

0

50,000

100,000150,000200,000250,000

1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 

Enhanced Oil Recovery (barrels/day) Gulf Coast/Other Mid-Continent Rocky Mountains Permian Basin

JAF20060

JAF02709.PPT

Figure 5. Growth of CO2-EOR Production in the U.S. 
 20 

3.3.3. Evolution in CO2 Flooding Practices 

Considerable evolution has occurred in the design and implementation of CO2-

EOR technology since it was first introduced. Notable changes include: (1) use of much 

larger (up to 1 HCPV) volumes of CO2; (2) incorporation of tapered WAG (water 

alternating with gas) and other methods for mobility control; and (3) application of 

advanced well drilling and completion strategies to better contact previously bypassed 

oil. As a result, the oil recovery efficiencies of today’s better designed “state-of-the-art” 

CO2-EOR projects have steadily improved. 

Two key assumptions underlie the oil recovery performance calculated for this 

study by the ARI/PROPHET model (see Appendix A) for “state-of-the-art” CO2-EOR: 

 First is the injection of much larger volumes of CO2 (1 HCPV), rather than 

the smaller (0.4 HCPV) volumes used in the past; 

 Second are the rigorous CO2-EOR monitoring, management and, where 

required, remediation activities that help assure that the larger volumes of 

injected CO2 contact more of the reservoir’s pore volume and residual oil 

rather than merely channel through high permeability streaks in the 

reservoir. 

In addition to these two central assumptions, the calculated oil recovery in the 

ARI/PROPHET model assumes appropriate well spacing (including the drilling of new 

infill wells), the use of a tapered WAG process, the maintenance of miscibility pressure 

throughout the reservoir, and the reinjection of CO2 produced with oil. 

Figures 6A and 6B provide the scientific and practical basis for using larger 

volumes of CO2 injection. Figure 7 illustrates how rigorous monitoring and well 

remediation can be used to target injected CO2 to reservoir strata with high remaining 

oil saturation, helping reduce ineffective CO2 channeling. 

Figure 8, using information from Occidental Petroleum (Oxy Permian), provides a 

17 year snapshot of the evolution of the “industry standard” for the most effective 

volume of CO2 injection (the optimum “slug size”).
Source: Claridge, E.L., “Prediction of Recovery in Unstable Miscible 

Displacement”, SPE (April 1972).

Note: VpD is displaceable fluid pore volumes of CO2 injected. 

1.00.90.80.70.6

0.50.40.30.20.1

0

0 0.5 0.2 1 2 10 5 5 20 0 100 200 500 1000

5.02.0

3.0

1.0V pD0.10.21.50.6

Sweep Efficiency, EA

Mobility Ratio, M

V

at B

.T.

vs

. M

pD

Sweep Efficiency in Miscible Flooding 

Petroleum engineering science confirms that using increased volumes of 

CO2 leads to increased reservoir sweep efficiency.

0.80 0.515 

Source: After Claridge (April 1972) (Mobility Ratio of 25)

1.00 0.570 0.60 0.440 0.40 0.345

Incr

S

Eff

Sweep Efficiency (RPV) Injected CO2 (HCPV)

Oil Recovery Efficiency 

vs. CO2 Injection

0.80 0.515 

Source: After Claridge (April 1972) (Mobility Ratio of 25)

1.00 0.570 0.60 0.440 0.40 0.345

Incr

S

Eff

Sweep Efficiency (RPV) Injected CO2 (HCPV)

Oil Recovery Efficiency 

vs. CO2 Injection

0.4

JAF02709.PPT

Figure 6A. Science Behind Volume of CO2 Injection and Oil Recovery Efficiency: General Theo

 21 
The CO2-EOR WAG project at Me

(San Andres Unit) was implementpart of an integrated reservoir development plan and involve the of 205 new producers and 158 neinjectors.Initial objective was to inject 260 BCO2, equal to 55% HCPV, (0.4 HC

purchased; 0.15 HCPV recycled) WAG ratio. Latest objective is to inject 480 BcHCPV) of CO2.

Effect of Solvent Bank Size on Oil Recovery

Means (San Andres) @ 2:1 WAG Ratio

Source: SPE 24928 (1992)

20

15

10

5

0

25

0 10 20 30 40 50

Years

Incremental Tertiary Recovery - % OOIP 0.8 HCPV 0.6 HCPV 0.4 HCPV 0.2 HCPV

JAF02709.PPT

Figure 6B. Science Behind Volume of CO2 Injection and Oil Recovery Efficiency: Actual Practic

 22 
Rigorous monitoring and well remediation can be used to help target injected CO2 to reservoir strat

residual oil saturation. 

0 20 40 60 80 100 6,900

Depth

6,350

% Injected Before

0 20 4

% Inj

Well 27-6 Injection Profile

(Before) (

Source: “SACROC Unit CO2 Flood: Multidisciplinary Team Improves Reservo

Decreases Operating Costs”, J.T. Hawkins, et al., SPE Reservoir Engineerin

1839 Days(Channeling in Layer 2)478 Days(BreakthroughIn Layer 2)

368 Days

Source: Adapted by Advanced Resources Int’l from “Enhanced Oil Recovery”, D.W. Green and G. P. Willhite, SPE, 1998.

Relative Location of the CO2/Water Front

0 100 200 300

Distance, ft

Layer 1 (High Sor, Low k)

Layer 2 (Low Sor, High k) Water

• Higher oil saturation portion of reservoir is 

inefficiently swept.

• CO2 channeling reduced with well workove

JAF02709.PPT

Figure 7. Overcoming the Effects of Geologic Complexity on CO2-EOR Performance 

 23 
 24 

Source: OXY Permian 2006

EDU 80% to 100% CO2 slug size increase approved 

EDU 60% to 80% CO2 slug size increase approved 

EDU 40% to 60% CO2 slug size increase approved Non performing FIA patterns stopped (~20% slug size) EDU WAG & start off CO2 injection in WAC, FIA, B8 FIA 

Start of CO2 injection in EDU with 40% slug size 

Eastern Denver Unit (Wasson Oil Field) CO2-EOR Project 

Source: OXY Permian 2006

EDU 80% to 100% CO2 slug size increase approved 

EDU 60% to 80% CO2 slug size increase approved 

EDU 40% to 60% CO2 slug size increase approved Non performing FIA patterns stopped (~20% slug size) EDU WAG & start off CO2 injection in WAC, FIA, B8 FIA 

Start of CO2 injection in EDU with 40% slug size 

Eastern Denver Unit (Wasson Oil Field) CO2-EOR Project 

Occidental Petroleum (Oxy Permian) is the industry leader for CO2-EOR, in terms of num

projects, volume of CO2 used, and volumes of oil production.

JAF02709.PPT

Figure 8. Evolution of “Industry Standard” for Volume CO2 Injection (“Slug Size”) 
The oil recovery calculations contained in this study rely on these “state-of-theart” practices. As such, the calculated oil recovery efficiencies expected from CO2-EOR 

are somewhat higher than have been achieved by older CO2-EOR projects. However, 

they are representative of the “best practices” being employed by technically 

sophisticated operations and current CO2-EOR projects. 

3.3.4. Technically Recoverable Resources 

Our reservoir-by-reservoir assessment of the 1,111 large oil reservoirs amenable 

to CO2-EOR shows that a significant volume, 64 billion barrels, of domestic oil may be 

recoverable with state-of-the-art application of CO2-EOR. Extrapolating the data base 

to national-level results indicates that 87.1 billion barrels of domestic oil may become 

recoverable by applying “state-of-the-art” CO2-EOR, Table 4. 

Subtracting the 2.3 billion barrels of oil that has already been produced and 

proven by CO2-EOR (as of 2004), the application of CO2-EOR would add 84.8 billion 

barrels of incremental domestic oil supplies, Table 5. For perspective, the current 

domestic proved crude oil reserves are 21 billion barrels, as of the end of 2006. 

Not surprisingly, the Permian Basin of West Texas and New Mexico tops the list 

with its world class size, favorable geology and carbonate reservoirs. In addition, 

significant technically recoverable resource potential also exists in East and Central 

Texas, Alaska and the Mid-Continent as well as the Gulf Coast, California and the 

Louisiana offshore. 

 25 
Table 4. Technically Recoverable Resources from Applying “State-of-the-Art” CO2-EOR: 

Data Base and National Totals 

 

DATA BASE NATIONAL 

Basin/Area 

OOIP 

 (Billion 

Barrels) 

OOIP 

Favorable 

for 

CO2-EOR 

(Billion 

Barrels) 

Technically 

Recoverable 

(Billion 

Barrels) 

OOIP 

 (Billion 

Barrels) 

Technically 

Recoverable 

(Billion 

Barrels) 

1. Alaska 65.4 64.5 12.0 67.3 12.4

2. California 75.2 31.6 5.7 83.3 6.3

3. Gulf Coast (AL, FL, MS, LA) 26.4 20.2 4.2 44.4 7.0

4. Mid-Continent (OK, AR, KS, NE) 53.1 28 6.4 89.6 10.7

5. Illinois/Michigan 12.0 4.6 0.8 17.8 1.2

6. Permian (W TX, NM) 72.4 63.1 13.5 95.4 17.8

7. Rockies (CO,UT,WY) 23.7 18.0 2.9 33.6 4.2

8. Texas, East/Central 67.4 52.4 10.9 109.0 17.6

9. Williston (MT, ND, SD) 9.4 7.2 1.8 13.2 2.5

10. Louisiana Offshore 22.2 22.1 4.6 28.1 5.8

11. Appalachia (WV, OH, KY, PA) 10.6 7.4 1.2 14.0 1.6

Total 437.8 319.1 64 595.7 87.1

 26 
Table 5. Technically Recoverable Resources from Applying “State-of-the-Art” CO2-EOR: 

National Totals 

 

Existing Incremental 

CO2-EOR 

Production/ 

Technically 

Recoverable 

 

Technically 

Recoverable 

(Billion Barrels) Reserves (Billion Barrels) 

1. Alaska 12.4 - 12.4

2. California 6.3 - 6.3

3. Gulf Coast (AL, FL, MS, LA) 7 * 7

4. Mid-Continent (OK, AR, KS, NE) 10.7 -0.1 10.6

5. Illinois/Michigan 1.2 - 1.2

6. Permian (W TX, NM) 17.8 -1.9 15.9

7. Rockies (CO,UT,WY) 4.2 -0.3 3.9

8. Texas, East/Central 17.6 - 17.6

9. Williston (MT, ND, SD) 2.5 - 2.5

10. Louisiana Offshore 5.8 - 5.8

11. Appalachia (WV, OH, KY, PA) 1.6 - 1.6

Total 87.1 -2.3 84.8

 27 
3.4. Economically Recoverable Resources 

3.4.1. Perspective on CO2-EOR Economics 

Conducting a CO2-EOR project is capital intensive and costly, entailing the 

drilling and/or reworking of wells, installing a CO2 recycle plant, and constructing CO2 

gathering and transportation pipelines. However, in general, the single largest cost of 

the project is the purchase of CO2. As such, operators strive to optimize and reduce its 

purchase and injection, where possible. 

The recent increases in domestic oil prices have significantly improved the 

economics outlook for conducting CO2-EOR. However, oil field costs have also 

increased sharply, reducing the economic margin essential for justifying this still 

emerging (and to many operators, novel and risky) oil recovery option. 

The cost and economic margins of a representative, reasonably favorable CO2-

EOR project are provided, for illustrative purposes, in Table 6 below. (The reader is 

advised that considerable reservoir-specific variations exist around the cost and 

economic margin values shown in the illustrative CO2-EOR project.) 

Table 6. Illustrative Costs and Economics of a CO2-EOR Project 

Assumed Oil Price ($/B) $70

Less: 

 Gravity/Basis Differentials, Royalties and Production Taxes ($15)

Net Wellhead Revenues ($/B) $55

Less: 

 Capital Costs ($5 to $10)

 CO2 Costs (@ $2/Mcf for purchase; $0.70/Mcf for recycle) ($15)

 Well/Lease O&M ($10 to $15)

Economic Margin, Pre-Tax ($/B) $15 to $25

 28 
Given the significant front-end investment in wells, recycle equipment and 

purchase of CO2 (equivalent to $20 to $25 per barrel) and the time delay in reaching 

peak oil production, pre-tax economic margins on the order of the front-end investment 

will be required to achieve economically favorable rates of return. Oil reservoirs with 

higher capital cost requirements and less favorable CO2 to oil ratios would not achieve 

an economically justifiable return on investment, requiring advanced, more efficient 

CO2-EOR technology and/or credits for storing CO2. 

3.4.2. Economically Recoverable Resources: Base Case 

In the Base Case, 45 billion barrels of incremental oil become economically 

recoverable from applying CO2-EOR. The Base Case evaluates the CO2-EOR 

potential using an oil price of $70 per barrel (constant, real) and a CO2 cost of $45 per 

metric ton ($2.38 per Mcf) (delivered at pressure to the field, constant and real). 

The $70 per barrel oil price is used as the project investment oil price, 

established using the average price of crude oil over the past three years, consistent 

with the investment oil price methodology used in NEMS. 

Table 7 presents the basin-by-basin tabulation of economically recoverable 

resources from applying “state-of-the-art” CO2-EOR technology under Base Case 

economics. 

3.4.3. Economically Recoverable Resources: Sensitivity Cases 

To gain insights as to how changes in oil prices would influence the volumes of 

economically recoverable resources from applying CO2-EOR, the story examined one 

lower and two higher oil price cases (and their associated CO2 costs). 

Table 8 presents the 45 billion barrels of domestic oil recovery potentially 

available from CO2-EOR at the Base Case oil price and CO2 cost. This increases to 

47.9 to 48.3 billion barrels of higher ($90 to $100/B) oil prices and drops to 39.1 billion 

barrels at lower ($50/B) oil price. 

 29 
Table 7. Economically Recoverable Resources from Applying “State-of-the-Art” CO2-EOR: 

National Totals at Base Case Economics* 

Basin/Area 

Incremental 

Technically 

Recoverable (Billion 

Barrels) 

Incremental 

Economically 

Recoverable* (Billion 

Barrels) 

1. Alaska 12.4 9.5

2. California 6.3 5.4

3. Gulf Coast (AL, FL, MS, LA) 7.0 2.2

4. Mid-Continent (OK, AR, KS, NE) 10.6 5.6

5. Illinois/Michigan 1.2 0.5

6. Permian (W TX, NM) 15.9 7.1

7. Rockies (CO,UT,WY) 3.9 1.9

8. Texas, East/Central 17.6 8.3

9. Williston (MT, ND, SD) 2.5 0.5

10. Louisiana Offshore 5.8 3.9

11. Appalachia (WV, OH, KY, PA) 1.6 0.1

Total 84.8 45.0

*Base Case Economics use an oil price of $70 per barrel (constant, real) and a CO2 cost of $45 per metric ton ($2.38/Mcf), 

delivered at pressure to the field. 

 30 
 31 

Table 8. Economically Recoverable Resources from Applying “State-of-the-Art” CO2-EOR: 

National Totals at Base Case and Alternative Oil Prices/CO2 Costs 

Oil Prices CO2 Costs 

($ per Bbl) ($ per metric ton) 

$35 $45* $55 $60 

Lower Prices 

$50 39.1 BBbls 

Base Case 

$70 45.0 BBbls 

Higher Prices 

$90 47.9 BBbls 

$100 48.3 BBbls 

*A CO2 cost of $45 per metric ton (mt) is equal to $2.38 per Mcf 

The estimates of economically recoverable domestic oil from applying CO2-EOR 

have been calculated using a minimum financial hurdle rate of 15% (real, before tax). 

Higher financial hurdle requirements, appropriate for rapidly installing “state-of-the-art” 

CO2-EOR technology in new basins and geologic settings, would reduce the above 

(Table 8) volumes of economically recoverable oil. 

To examine the impact of a higher financial return on economically recoverable 

oil from CO2-EOR, the study applied a higher, 25% (real, before tax) financial hurdle 

rate. Under this higher hurdle rate, but still at Base Case oil prices and CO2 costs, the 

economically recoverable oil decreases to 38.2 billion barrels. While the higher financial 

hurdle rate eliminates a number of economically marginal CO2-EOR prospects, the 

great bulk of the fields remain economic, supporting the financial robustness of this oil 

recovery technology. 

Figure 6 illustrates the volumes of domestic oil recovery potentially available from 

applying CO2-EOR technology at alternative oil prices and CO2 costs (using the 

assumed relationship in the economic model between oil prices and CO2 costs, shown 

in Table 8). 
 32 

Figure 6. Economically Recoverable Domestic Oil Resources from Applying CO2-EOR 
It is instructive to note that the oil recovery potential from CO2-EOR remains 

significant, at 39.1 billion barrels, even under the lower, $50 per barrel, oil price case. 

Equally instructive to note is that higher oil prices, by themselves, will not unlock much 

more of the large 84.8 billion barrel technically recoverable oil resource available from 

state-of-the-art CO2-EOR. 

Advances in CO2-EOR technology, as discussed in the previously published 

Advanced Resources/DOE report, “Evaluating The Potential For ‘Game Changer’ 

Improvements In Oil Recovery Efficiency From CO2 Enhanced Oil Recovery”, will be 

required to make more of this technically recoverable resource economic. 

 33 
4.0 The Market for Storing CO2 with EOR 

The primary purpose of this report is to establish how much CO2, particularly 

CO2 emissions captured by power plants, could be stored with enhanced oil recovery. 

Chapter 3 established that 39 to 48 billion barrels of economic, incremental 

domestic oil could be produced by timely application of CO2-EOR technology. This 

chapter draws on this oil recovery assessment to estimate how much CO2, particularly 

CO2 emissions captured from new coal-fueled power plants, would be required to 

produce this volume of economically recoverable oil, helping establish the market for 

captured CO2 emissions. 

4.1. The CO2 Injection and Storage Process 

The analysis shows that significant volumes of CO2 (ranging from 10 to 13 billion 

metric tons depending on oil price) can be stored with enhanced oil recovery. The 

sequence for doing so is as follows: 

 Initially, purchased CO2, equal to 1 HCPV, is injected along with water for 

mobility control. 

 As oil with CO2 begins to be produced, the CO2 is separated from the oil 

and reinjected. As the produced volumes of CO2 increase, these larger 

volumes of CO2 are reinjected, continuing the life of the CO2-EOR 

project. 

 Near the end of the CO2-EOR project, the operator may choose to close 

the field at pressure, storing essentially all of the injected CO2, or may 

inject a large (1 to 2 HCPV) slug of water to recover any remaining mobile 

oil and CO2. This CO2 may then be used in another portion of the 

reservoir or sold to another oil field. 

 34 
In general, about 5 to 6 Mcf (0.26 to 0.32 metric tons (mt)) of purchased CO2 per 

barrel of oil is used and stored as part of CO2-EOR. This is augmented with 5 to 10 Mcf 

(0.26 mt to 0.52 mt) of recycled CO2 during the latter stages of a CO2-EOR process. 

With incentives for storing CO2 emissions and “next generation” CO2 storage 

technology, considerably larger volumes of CO2 could be stored. Additional discussion 

of “next generation” storage of CO2 with EOR is provided in Appendix C. 

4.2. Producing “Carbon Free” Domestic Oil 

A typical barrel of crude oil contains 0.42 metric tons (mt) of releasable CO2 

(assuming that 3% of the produced and refined oil barrel remains as asphalt or coke). 

As such, netting the injection and storage of 0.26 to 0.32 mt of CO2 emissions against 

the 0.42 mt of CO2 in the produced oil, makes the domestic oil produced by CO2-EOR 

about 70% (62% to 76%) “carbon free”. 

Two of the alternatives to using domestic oil produced by CO2-EOR have a 

much less favorable net CO2 balance. Imported oil is 0% “carbon free” (and results in 

additional CO2 emissions from ocean transportation). Domestic corn ethanol is only 10 

to 15% “carbon free”, as significant volumes of energy are required for producing the 

corn feedstock and final product. When coal is used as the dominant energy source in 

ethanol production, corn-based ethanol drops to below 0% “carbon free” and becomes a 

contributor to the CO2 emissions problem. 

4.3. The Market for CO2 

The market for CO2 from power plant and industrial sources is substantial, 

depending on oil prices and CO2 costs. (The CO2 costs used in this study assume that 

the CO2 is delivered to the oil field, at pressure.) 

Table 9 provides a basin-by-basin tabulation of the volumes of CO2 that would 

be required to produce the incremental volumes of economically recoverable domestic 

oil from applying CO2-EOR in the Base Case ($70 per barrel oil price and $45 per 

metric ton CO2 cost, delivered at pressure). 

 35 
Table 10 provides the aggregate tabulation of the market for CO2 for EOR as a 

function of the Base Case oil price and CO2 cost, as well as for three alternative oil 

prices (assuming the relationships between oil prices and CO2 costs established in the 

economic model). A review of the past history of CO2 costs shows that they have been, 

in general, linked to oil prices. 

 36 
Table 9. Economically Feasible Market for CO2 for CO2-EOR: Base Case* 

(Eleven Basins/Areas) 

 

Gross Market for 

CO2 

CO2 Already or 

Scheduled to be 

Injected 

Net New Market for 

CO2 

Basin/Area 

(million metric 

tons) 

(million metric 

tons) 

(million metric 

tons) 

1. Alaska 2,094 - 2,094 

2. California 1,375 - 1,375 

3. Gulf Coast (AL, FL, MS, LA) 652 ** 652 

4. Mid-Continent (OK, AR, KS, NE) 1,443 20 1,423 

5. Illinois/Michigan 127 - 127 

6. Permian (W TX, NM) 2,712 570 2,142 

7. Rockies (CO,UT,WY) 574 74 500 

8. Texas, East/Central 1,940 - 1,940 

9. Williston (MT, ND, SD) 130 - 130 

10. Louisiana Offshore 1,368 - 1,368 

11. Appalachia (WV, OH, KY, PA) 36 - 36 

Total 12,451 664 11,787 

*Base Case: Oil price of $70 per barrel; CO2 cost of $45 per metric ton. 

 37 
Table 10. Economically Feasible Market Demand for CO2 by CO2-EOR: Alternative Cases 

(Eleven Basins/Areas) 

 

Lower Oil 

Base Case Price Case* Higher Oil Price Cases** 

($70/Bbl) ($50/Bbl) ($90/Bbl) ($100/Bbl) 

Basin/Area 

(million metric 

tons) 

(million metric 

tons) 

(million 

metric tons) 

(million metric 

tons) 

1. Alaska 2,094 1,740 2,214 2,235 

2. California 1,375 1,350 1,405 1,405 

3. Gulf Coast (AL, FL, MS, LA) 652 465 805 823 

4. Mid-Continent (OK, AR, KS, NE) 1,423 1,403 1,430 1,430 

5. Illinois/Michigan 127 112 141 142 

6. Permian (W TX, NM) 2,142 1,696 2,384 2,438 

7. Rockies (CO,UT,WY) 500 436 512 514 

8. Texas, East/Central 1,940 1,810 2,069 2,069 

9. Williston (MT, ND, SD) 130 125 148 158 

10. Louisiana Offshore 1,368 904 1,599 1,599 

11. Appalachia (WV, OH, KY, PA) 36 9 46 46 

Total 11,787 10,050 12,753 12,859 

*Lower Oil Price Case: Oil price of $50 per barrel; CO2 cost of $35 per metric ton. 

**Higher Oil Price Cases: Oil price of $90 and $100 per barrel; CO2 costs of $55 and $60 per metric ton. 

 38 
 39 

4.4. Market Demand for CO2: Power Plant Perspective 

So far, the report has examined the market demand for CO2 from the 

perspective of the enhanced oil recovery industry. In this section of the report, we 

examine in more detail the market demand for CO2 from the power plant perspective, 

giving priority to market demand that might be met by capture and sale of CO2 

emissions from the coal-fueled power sector. 

The overall demand for CO2 by the CO2-EOR industry can be met by three 

potential sources of CO2 supply, namely: 

 Natural CO2 supplies already found and defined in geological structures; 

 Industrial, high concentration sources of CO2 that are currently being 

captured and used by the CO2-EOR industry; and 

 The large volumes of power plant and industrial emissions of CO2 that 

may need to be captured and stored to meet CO2 management goals. 

To better align the CO2 market demand information in this report with the power 

sector, the aggregate demand for CO2 of 11,787 million metric tons (223 Tcf) is 

presented according to the 14 EIA National Energy Modeling System (NEMS) Electricity 

Market Module (EMM),Table 11. 

Excluding Alaska, which is not projected to build new coal-fueled power plants to 

any great extent, the demand for CO2 in the lower-48 states offered by the EOR 

industry is 9,694 million metric tons (183.4 Tcf), Table 11. Figure 7 provides the outline 

for the 14 EMM regions; Table 12 provides a simplified crosswalk between the 14 EMM 

regions and their included states.
 40 

NEMS Regions: CO2 supply and demand have been organized according to the 1

NEMS regions (13 lower-48 plus Alaska) in the Electricity Market Module

JAF02709.PPT

Figure 7. Geographical Regions in the NEMS Electricity Market Module 
Table 11. Economically Feasible Market Demand for CO2 by EOR: NEMS/EMM Power 

Generation Regions 

NEMS EMM Demand for CO2 for EOR 

Region Million Metric Tons Tcf 

Region 1 - ECAR 58 1.1 

Region 2 – ERCOT 3,820 72.3 

Region 3 – PJM (MAAC) 4 0.1 

Region 4 – MAIN 100 1.9 

Region 5 – MAPP 109 2.1 

Region 6 – NY ISO - - 

Region 7 – NW ISO - - 

Region 8 – Florida 9 0.2 

Region 9 – SERC 2,116 40.0 

Region 10 – SWPP 1,570 29.7 

Region 11 – WECC/NWPP 411 7.8 

Region 12 – WECC/RMPP 120 2.3 

Region 13 – WECC/CA 1,376 26.0 

Region 14 - Alaska 2,093 39.6 

Total U.S. 11,787 223.0 

Lower-48 9,694 183.4 

*Base Case: $70/Bbl oil and $45/mt CO2.

 41 
Table 12. Simplified Crosswalk Between the EMM Regions and States 

NEMS EMM 

Region Associated State(s) 

Region 1 - ECAR Kentucky, West Virginia, Ohio, Indiana, Michigan 

Region 2 – ERCOT Texas 

Region 3 – PJM (MAAC) Pennsylvania, Delaware, New Jersey, Maryland 

Region 4 – MAIN Illinois, Missouri, Iowa, Wisconsin 

Region 5 – MAPP North Dakota, South Dakota, Nebraska, Minnesota 

Region 6 – NY ISO New York 

Vermont, New Hampshire, Maine, Massachusetts, 

Region 7 – NW ISO Connecticut, Rhode Island 

Region 8 – Florida Florida 

Arkansas, Louisiana, Mississippi, Alabama, Tennessee, 

Region 9 – SERC Georgia, South Carolina, North Carolina 

Region 10 – SWPP Oklahoma, Kansas and New Mexico 

Washington, Oregon, Idaho, Montana, Wyoming, Utah, 

Region 11 – WECC/NWPP Nevada 

Region 12 – WECC/RMPP New Mexico, Colorado, Arizona 

Region 13 – WECC/CA California 

Region 14 - Alaska Alaska 

 42 
Table 13 sets forth the net remaining demand for CO2 by the EOR industry of 

7,470 million metric tons for the lower-48 states, after subtracting the 2,224 million 

metric tons (42.2 Tcf) of CO2 available, in the next 30 years, from natural CO2 deposits 

and high concentration industrial CO2 sources (e.g., natural gas processing plants, 

fertilizer plants) already being captured and used for enhanced oil recovery. 

Table 14 tabulates the existing sources of CO2, both natural and anthropogenic, 

that are currently injected for EOR. 

 43 
Table 13. Economically Feasible Market Demand for CO2 by EOR: NEMS/EMM Power 

Generation Regions* 

Purchased 

CO2 

Requirements

Natural

CO2** 

Industrial 

CO2** 

Unmet (Net) 

Demand for CO2 NEMS EMM 

Region (Tcf) (Tcf) (MMcfd) (Tcf) (Tcf) (Million mt)

Region 1 - ECAR 1.1 - 15 *** 1.1 58

Region 2 – ERCOT 72.2 25 110 1.2 46.0 2,436

Region 3 – PJM (MAAC) 0.1 - - - 0.1 4

Region 4 – MAIN 1.9 - - - 1.9 100

Region 5 – MAPP 2.1 - - - 2.1 109

Region 6 – NY ISO - - - - - -

Region 7 – NW ISO - - - - - -

Region 8 – Florida 0.2 - - - 0.2 9

Region 9 – SERC 40.0 8 - - 32.0 1,695

Region 10 – SWPP 29.7 5 35 0.4 24.3 1,286

Region 11 – WECC/NWPP 7.8 - 175 1.9 5.9 311

Region 12 – WECC/RMPP 2.3 - 65 0.7 1.6 83

Region 13 – WECC/CA 26.0 - - - 26.0 1,377

Region 14 - Alaska 39.6 5 - - 34.6 1,831

TOTAL U.S. 223.0 43 400 4.2 175.8 9,301

TOTAL Lower-48 183.4 38 400 4.2 141.2 7,470

*Base Case: $70/Bbl oil and $45/mt CO2

**Assumed available to be produced and productively used by the CO2‐EOR industry in the next 30

years.

***Less than 0.01 Tcf and thus not included in totals.

 44 
Table 14. Existing CO2 Supplies 

(Volumes of CO2 Injected for EOR*) 

CO2 Supply MMcfd** State/ Province 

(storage location) 

 Source Type 

(location) Natural Anthropogenic 

Texas-Utah-New MexicoOklahoma Geologic (Colorado-New Mexico) 

Gas Processing (Texas) 1,700 110 

Colorado-Wyoming Gas Processing (Wyoming) - 240 

Mississippi Geologic (Mississippi) 400 - 

Michigan Ammonia Plant (Michigan) - 15 

Oklahoma Fertilizer Plant (Oklahoma) - 35 

Saskatchewan Coal Gasification (North Dakota) - 145 

TOTAL 2,100 545 

* Source: 12th Annual CO2 Flooding Conference, Dec. 2006 

** MMcfd of CO2 can be converted to million metric tons per year by first multiplying by 365 (days per year) and then dividing

by 18.9 * 103 (Mcf per metric ton).

The EIA NEMS Electricity Market Model in AEO 2008 projects that 121 new, one 

GW size, coal-fueled power plants will come on stream between now and 2030. If 

these 121 GWs of coal-fueled power generation capacity were equipped with CCS, they 

would provide 20.5 billion metric tons of captured CO2 emissions, assuming 90% CO2 

capture, 38% power plant efficiency, 85% operating capacity, and 30 years of 

operations. Table 15 sets forth the volumes of CO2 emissions that theoretically would 

be available in each of the EMM regions (lower-48) from the installation of these new 

coal-fueled power plants. 

A closer look at CO2 demand (net, after subtracting CO2 supplies available from 

natural and already captured industrial CO2 sources) for EOR shows: (1) there is unmet 

(net) demand for CO2 in eleven of the EMM regions that could be filled in part or in 

whole by captured CO2 emissions from power plants; and (2) while the overall supply of 

CO2 from power plants would more than fulfill the overall (net) CO2 demand from the 

EOR industry, Region #13 (WECC, CA) appears to be “short” in terms of CO2 supplies, 

due to the absence of new coal-fueled power plant capacity. (Most likely, installation of 

 45 
 46 

CO2 pipelines crossing EMM regional boundaries would be used to match CO2 

demand with available supply.) 

The overall conclusion from the analysis is that CO2-EOR may provide a 7,500 

million metric ton market for captured CO2 emissions by the coal-fueled power 

generation industry. While the actual revenues afforded by this market will be 

established, in the main, by one-on-one negotiations between individual power 

companies and oil field operators, the potential size of this market could be large. 

Using an oil price of $70 per barrel (Base Case), assuming a delivered CO2 cost 

of $45 per metric ton, and subtracting $10 per metric ton for transportation and 

handling, the revenue potential offered by the CO2-EOR market could reach $260 

billion. In addition, the sale of captured CO2 emissions to the CO2-EOR industry would 

enable power companies to avoid the costs and challenges of storing CO2.
 47 

EMM 

Region Region States

Coal 

Deployment 

2007-2030 

Available 

CO2 From 

Coal*

Demand fo

CO2 @ $45/m

$70/B Oi

# (GW) (MMmt) (MMmt) 

2 ERCOT TX 21.0 3,570 2,

9 SERC AR, LA, MS, AL, TN, GA, SC, NC 32.7 5,559 1,

13 WECC/CA CA 0.0 - 1,

10 SWPP OK, KS, NM 9.3 1,581 1,

11 WECC/NWPP WA, OR, ID, MT, WY, UT, NV 6.4 1,088 

5 MAPP ND, SD, NE, MN 2.5 425 

4 MAIN IL, MO, IA, WI 3.3 561 

12 WECC/RMPP CO, AZ 17.4 2,958 

1 ECAR KY, WV, OH, IN, MI 2.5 425 

8 Florida FL 12.5 2,125 

3 PJM (MAAC) PA, DE, NJ, MD 8.2 1,394 

6 NY ISO NY 5.1 867 

7 NE ISO VT, NH, ME, MA, CT, RI 0.0 - 

U.S. Total 120.9 20,553 7,

*Assuming all new Coal Plants capture 90% of CO2, operate at 85% capacity and 38% efficiency (8,876 Btu/kWh); includes 30 years of COemissions.

Table 15. Comparison of Net CO2 Demand (for EOR) with Potential Captured CO2 Emissions from Coal-Fuele
 48 

                                                     

5.0 Using Sale of Captured CO2 Emission for “Early Market Entry” 

of CCS Technology 

As discussed in the previous chapter, CO2-EOR may provide a large, “value 

added” market for sale of captured CO2 emissions from power plants and other 

industrial sources. Should this market develop in a timely fashion, it would support 

“early market entry” of carbon capture and storage (CCS) technology, particularly by 

coal-fueled power plants. 

5.1. Economics of CCS 

A common feature of EIA carbon management studies is that, in general, CCS is 

not considered, as of yet, a key part of the solution1, , 2 3. The reason, according to EIA’s 

EMM cost model, is that using CCS with coal- or gas-fired power is not economically 

competitive with other options for generating power with low CO2 emissions, as shown 

on Figure 8. 

As set forth in EIA’s cost model, incorporation of CCS with new advanced coalfueled power plant currently adds over $20 per MWh of costs, making this a higher cost 

option than advanced nuclear power and subsidized wind- or biomass-based electricity 

generation. Even by 2020, assuming modest technology progress for advanced coal 

and CCS, adding CCS to a coal-fueled power plant would increase electricity generation 

and transmission costs by nearly $19 per MWh, keeping this a high cost option. 

Figure 8 shows that, according to EIA’ Reference Case for 2020, Advanced Coal 

with CCS would entail costs of $81 per MWh of electricity compared to $60 per MWh for 

Pulverized Coal without CCS and $66 per MWh for Advanced Nuclear. 

1 Energy Market and Economic Impacts of a Proposal to Reduce Greenhouse Gas Intensity with a Cap and Trade Systems, U.S. 

DOE, Energy Information Administration, January, 2007. 

2 Energy Market Impacts of Alternative Greenhouse Gas Intensity Reduction Goals, U.S. DOE, Energy Information 

Administration, March, 2006. 

3 Energy Market Impacts of a Clean Energy Portfolio Standard - Follow-up, U.S. DOE, Energy Information Administration, 

February, 2007. 
 49 

Cost of Electricity ($/MWh)*

*Cost of electricgeneration and Source: AEO 20Case (Electricity CarBen 2008

2012 2020

Pulverized CAdvanced CAdvanced CAdvanced N

Reference Case Reference Case

JAF02709.PPT

57

6620

405060708090

60 62

19

66

86

81

Figure 8. Advanced Coal Plants w/CCS Are Currently Uncompetitive in 2012 and 2020 (EIA’s AEO 2008 Ref
However, revenues from selling captured CO2 emissions into the CO2-EOR 

market can change the competitive outlook. For example, as shown in Table 16, the 

sale of captured CO2 emissions at $25 to $35 per metric ton can reduce the costs of 

power generation with CCS by $17 to $24 per MWh, significantly offsetting the costs of 

installing CCS with new coal-fueled power plants. 

Table 16. Relationship of CO2 Sales Price to Cost Offsets in the Coal-Fueled 

Power Sector (Year 2020) 

Sale of CO2 Sale of CO2

@ $25/mt CO2 @ $35/mt CO2 

7,920 btu/kWh x 7,920 btu/kWh x 

94 MMmt CO2/QBtu x 94 MMmt CO2/QBtu x 

90% Capture 90% Capture

Cost Offset: $16.80/MWh Cost Offset: $23.50/MWh 

5.2. Supporting “Early Market Entry” of CCS Technology 

To examine just how much contribution to “early market entry” of CCS may be 

possible from sale of captured CO2 emissions into the EOR market, the study 

integrated the previously presented CO2 demand information into the CarBen Model’s 

version of the DOE/EIA NEMS Electricity Market Module. 

The CarBen and EIA EMM Models provide the year 2012 and year 2020 cost 

and competitive positions for three coal-fueled power generation options, Table 17. 

Table 17. EIA Reference Case Year 2012 and Year 2020 Costs of Electricity 

Cost of Electricity $/MWh* 

Power Generation Option Year 2012 Year 2020 

1. Pulverized Coal without CCS $56.60 $59.70 

2. Advanced Coal without CCS $65.70 $62.00 

3. Advanced Nuclear - $66.00 

4. Advanced Coal with CCS $86.30 $80.80 

*Costs include generation and transmission 

 50 
 51 

Sale of captured CO2 emissions at $35 per metric ton ($1.85/Mcf) at the plant 

gate, equal to $45 per mt ($2.38/Mcf) at the oil field lease line (assuming $10 per mt 

($0.53/Mcf) for transportation), would provide a cost offset of $23.50/MWh. 

In 2012, the revenue offset of $23.50/MWh from sale of captured CO2 emissions 

is not sufficient to make CCS cost competitive. By 2020, however, with assured, longterm sale of captured CO2 emissions at $35 per metric ton (at the plant gate) providing 

$23.80/MWh of revenue offsets, new advanced coal plans with CCS would become cost 

competitive with alternative, non-CCS coal based power generation options, as shown 

in Table 18 and in Figure 9. 

Table 18. Cost of Electricity in Year 2020 with Sale of CO2 

Cost of Electricity (2020) 

Power Generation Option Initial* 

Cost 

CO2 

Sale Offset 

Final* 

Cost 

($/MWh) ($/MWh) ($/MWh) 

1. Pulverized Coal without CCS $59.70 - $59.70 

2. Advanced Coal without CCS $62.00 - $62.00 

3. Advanced Nuclear $66.00 - $66.00 

4. Advanced Coal with CCS $80.80 ($23.50) $57.30 

*Costs are for 2020 and include transmission

The CarBen and EIA EMM models project that 29 new coal-fueled power plants 

would be placed into operation between 2013 and 2020 in the lower-48. Assuming that 

half of these power plants are favorably located with respect to oil fields attractive for 

CO2-EOR and are able to sell CO2 at $35/mt at the plant gate, the integration of CO2 

storage and EOR would support the construction of 15 new advanced coal w/CCS 

power plants, each with 1 GW of capacity. (A 1 GW advanced coal-fueled power plant 

built by 2020 is estimated to be able to sell about 5.1 million metric tons of captured 

CO2 emissions per year; 15 plants would be able to provide 2,300 million metric tons in 

30 years). Additional sales of captured CO2 emissions by power plants built after 2020 

would support additional installations of CCS, as discussed below. 
 52 

Cost of Electricity ($/MWh)*

*Cost of electricgeneration and Source: AEO 20Case (Electricity CarBen 2008

Pulverized CAdvanced CAdvanced CAdvanced Cand Sale of Advanced N

Reference Case

2020

JAF02709.PPT

405060708090

60 62

19

81

Advanced 

Coal w/EOR 

Revenues

81

@ $35/mt

for CO2

2020

57 66

Figure 9. Sale of Captured CO2 Emissions Can Help Make Coal Plants w/CCS Competitive
5.3. Adding “Learning” to the “Early Market Entry” Opportunity 

The CarBen and EIA EMM models contain a “learning” function which reduces 

the costs of installing new technology as a function of the number of CCS installations. 

As such, the costs of producing advanced coal-fueled electricity with CCS decline. 

The “early market entry” of 15 CCS installations, made possible by the sale of 

captured CO2 emissions into the EOR market, helps accelerate the “learning” process. 

As such, the costs of producing electricity using advanced coal with CCS are expected 

to decline to $74.50/MWh by 2020, as shown in Table 19. 

Table 19. Year 2020 Costs of Electricity with Accelerated “Learning” 

Based Cost Reductions 

Cost of Electricity $/MWh* 

Power Generation Option Year 2020 

1. Pulverized Coal without CCS $59.70 

2. Advanced Coal without CCS $62.00 

3. Advanced Nuclear $66.00 

4. Advanced Coal with CCS** $74.50 

*Costs include transmission 

**Accelerated “learning” only applied to Advanced Coal with CCS

The significance of the “learning” based cost reductions for advanced coal-fueled 

power w/CCS is that now a lower sales price for captured CO2 emissions, at $25/mt 

($1.32/Mcf) at the plant gate, equal to $35/mt ($1.85/Mcf) at the oil field lease line, 

(assuming $10/mt ($0.53/Mcf) for transportation), would provide sufficient cost offsets of 

$16.80/MWh to make advanced coal w/CCS cost competitive. 

With assured, long-term sale of captured CO2 at $25 per metric ton at the plant 

gate, and assuming cost reductions due to “learning”, new advanced coal plants with 

CCS providing electricity at a cost of $58 per MWh would be the preferred economic 

choice for the post-2020 time period, as shown in Table 20 and Figure 10. 

 53 
 54 

Table 20. Year 2020 Cost of Electricity with “Learning” and CO2 Sale Offset 

Cost of Electricity (2020) 

Power Generation Option 

Initial* 

Cost 

CO2 

Sale Offset 

Final* 

Cost 

($/MWh) ($/MWh) ($/MWh) 

1. Pulverized Coal without CCS $59.70 - $59.70 

2. Advanced Coal without CCS $62.00 - $62.00 

3. Advanced Nuclear $66.00 - $66.00 

4. Advanced Coal with CCS $74.50 ($16.80)** $57.70 

*Costs include transmission 

**CO2 sale for a plant with EIA Reference Case efficiency and $25/mt CO2 price, at the plant gate.

An additional 80 new (1 GW size) coal-fueled power plants are expected in the 

lower-48 between 2020 and 2030. Subtracting the purchase of 2,300 million metric tons 

of captured CO2 emissions from 15 plants, the lower-48 EOR market has a remaining 

demand for an additional 5,170 million metric tons of CO2. Assuming that a sufficient 

number of these plants are favorably located, the unmet demand for CO2 by the EOR 

market would support the installation of 34 advanced coal power plants with CCS 

between years 2020 and 2030, bringing the total to 49 new power plants with CCS. 

The sale of captured CO2 emissions could enable 40% (49 out of 121) of the 

new coal-fueled power plants expected to be built between now and 2030 to install 

CCS, providing significant assistance toward addressing CO2 emissions in this sector 

and helping further drive down the costs of CCS technology. 

Additional information on the incorporation of sales of captured CO2 emissions 

by power plant into the Electricity Generation Module of the CarBen Model (a simplified 

component of the EIA NEMS EMM) is provided in Appendix B.
 55 

Cost of Electricity ($/MWh)*

*Cost of electricity ingeneration and transSource: AEO 2008, Case (Electricity MaCarBen 2008

Advanced Coal Advanced Coal and Sale of COAdvanced Coal and “Learning”Advanced Coal “Learning” and CO2

JAF02709.PPT

405060708090

Advanced Coal 

w/EOR Revenues

2020

81

75

Advanced Coal 

w/EOR Revenues 

and “Learning”

2020

@ $35/mt 

for CO2

@ $25/mt 

for CO2

57 58

Figure 10. Sale of Captured CO2 Emissions Can Help Make Coal Plants w/CCS Competitive. 
Appendix A 

Study Methodology 

A‐1 
A‐2 

A. STUDY METHODOLOGY 

A.1 OVERVIEW. A six part methodology was used to assess the CO2 storage and 

EOR potential of domestic oil reservoirs. The six steps were: (1) assembling the Major Oil 

Reservoirs Data Base; (2) calculating the minimum miscibility pressure; (3) screening reservoirs 

for CO2-EOR; (4) calculating oil recovery; (5) assembling the cost and economic model; and, (6) 

performing economic and sensitivity analyses. 

A.2 ASSEMBLING THE MAJOR OIL RESERVOIRS DATA BASE. The study 

started with the data base used in the previous set of “basins studies”. The study updated and 

augmented this data base by incorporating the internally prepared Appalachian Basin Data 

Base and by incorporating other improvements to this data base previously performed by 

Advanced Resources. 

Table A-1 illustrates the oil reservoir data recording format developed by the study. The 

data format readily integrates with the input data required by the CO2-EOR screening and oil 

recovery models, discussed below. Overall, the Major Oil Reservoirs Data Base contains 2,012 

reservoirs, accounting for 74% of the oil expected to be ultimately produced in the U.S. by 

primary and secondary oil recovery processes. 
Basin Name

Field NameReservoirReservoir Parameters: ARI Oil Production ARI Volumes 

Area (A) Producing Wells (active) OOIP (MMbl)Net Pay (ft) Producing Wells (shut-in) P/S Cum Oil (MMDepth (ft) 2002 Production (Mbbl) EOY P/S 2002 R

Porosity Daily Prod - Field (Bbl/d) P/S Ultimate ReReservoir Temp (deg F) Cum Oil Production (MMbbl) Remaining (MMInitial Pressure (psi) EOY 2002 Oil Reserves (MMbbl) Ultimate Recove

Pressure (psi) Water Cut

OOIP Volu

Boi Water Production Reservoir Volum

Bo @ So, swept 2002 Water Production (Mbbl) Bbl/AF

Soi Daily Water (Mbbl/d) OOIP Check (M

Sor

Swept Zone So Injection SROIP VolSwi Injection Wells (active) Reservoir Volum

Sw Injection Wells (shut-in) Swept Zone Bbl/

2002 Water Injection (MMbbl) SROIP Check (M

API Gravity Daily Injection - Field (Mbbl/d)Viscosity (cp) Cum Injection (MMbbl)

Daily Inj per Well (Bbl/d) ROIP Volum

Dykstra-Parsons ROIP Check (M

EOR 

Type2002 EOR Production (MMbbl)Cum EOR Production (MMbbl)EOR 2002 Reserves (MMbbl)Ultimate Recovered (MMbbl)

Table A-1. Reservoir Data Format: Major Oil Reservoirs Data Base 

A‐3 
Considerable effort was required to construct an up-to-date, volumetrically consistent 

data base that contained all of the essential data, formats and interfaces to enable the study to: 

(1) develop an accurate estimate of the size of the original and remaining oil in-place; (2) 

reliably screen the reservoirs as to their amenability for miscible and immiscible CO2-EOR; and, 

(3) provide the CO2-PROPHET Model the essential input data for calculating CO2 injection 

requirements and oil recovery. 

A.3 CALCULATING MINIMUM MISCIBILITY PRESSURE. The miscibility of a 

reservoir’s oil with injected CO2 is a function of pressure, temperature and the composition of 

the reservoir’s oil. The study’s approach to estimating whether a reservoir’s oil will be miscible 

with CO2, given fixed temperature and oil composition, was to determine whether the reservoir 

would hold sufficient pressure to attain miscibility. Where oil composition data was missing, a 

correlation was used for translating the reservoir’s oil gravity to oil composition. 

To determine the minimum miscibility pressure (MMP) for any given reservoir, the study 

used the Cronquist correlation, Figure A-1. This formulation determines MMP based on 

reservoir temperature and the molecular weight (MW) of the pentanes and heavier fractions of 

the reservoir oil, without considering the mole percent of methane. (Most Gulf Coast oil 

reservoirs have produced the bulk of their methane during primary and secondary recovery.) 

The Cronquist correlation is set forth below: 

MMP = 15.988*T (0.744206+0.0011038*MW C5+)

Where: T is Temperature in °F, and MW C5+ is the molecular weight of pentanes 

and heavier fractions in the reservoir’s oil. 

A‐4 
Figure A-1. Estimating CO2 Minimum Miscibility Pressure 

Mole Weight C5+

70 110 150 190 230 270

0

1000

2000

3000

4000

5000

6000

Miscibility Pressure, psi

Temperature, oF

340 300 280 260 240 220 200

180

Correlation for CO2 Minimum Pressure as a Function of Temperature

(Mungan, N., Carbon Dioxide Flooding Fundamentals, 1981)

Mole Weight C5+

70 110 150 190 230 270

0

1000

2000

3000

4000

5000

6000

Miscibility Pressure, psi

Temperature, oF

340 300 280 260 240 220 200

180

Correlation for CO2 Minimum Pressure as a Function of Temperature

(Mungan, N., Carbon Dioxide Flooding Fundamentals, 1981)

The temperature of the reservoir was taken from the data base or estimated from the 

thermal gradient in the basin. The molecular weight of the pentanes and heavier fraction of the 

oil was obtained from the data base or was estimated from a correlative plot of MW C5+ and oil 

gravity, shown in Figure A-2. 

The next step was calculating the minimum miscibility pressure (MMP) for a given 

reservoir and comparing it to the maximum allowable pressure. The maximum pressure was 

determined using a pressure gradient of 0.6 psi/foot. If the minimum miscibility pressure was 

below the maximum injection pressure, the reservoir was classified as a miscible flood 

candidate. Oil reservoirs that did not screen positively for miscible CO2-EOR were selected for 

consideration by immiscible CO2-EOR. 

A‐5 
Figure A-2. Correlation of MW C5+ to Tank Oil Gravity 

A.4 SCREENING RESERVOIRS FOR CO2-EOR. The data base was screened for 

reservoirs that would be applicable for CO2-EOR. Five prominent screening criteria were used 

to identify favorable reservoirs. These were: reservoir depth, oil gravity, reservoir pressure, 

reservoir temperature, and oil composition. These values were used to establish the minimum 

miscibility pressure for conducting miscible CO2-EOR and for selecting reservoirs that would be 

amenable to this oil recovery process. Reservoirs not meeting the miscibility pressure standard 

were considered for immiscible CO2-EOR. 

The preliminary screening steps involved selecting the deeper oil reservoirs that had 

sufficiently high oil gravity. A minimum reservoir depth of 3,000 feet, at the mid-point of the 

reservoir, was used to ensure the reservoir could accommodate high pressure CO2 injection. A 

minimum oil gravity of 17.5 o

API was used to ensure the reservoir’s oil had sufficient mobility, 

without requiring thermal injection. 

A.5 CALCULATING OIL RECOVERY.    The study utilized CO2-PROPHET to 

calculate incremental oil produced using CO2-EOR. CO2-PROPHET was developed as an 

alternat

y = 4247.98641x-0.87022

R2 = 0.99763

0

100

200

300

400

500

0 20 40 60 80 100

Tank Oil Gravity, oAPI

Molecular WT C5+

y = 4247.98641x-0.87022

R2 = 0.99763

0

100

200

300

400

500

0 20 40 60 80 100

Tank Oil Gravity, oAPI

Molecular WT C5+

ive to the DOE’s CO2 miscible flood predictive model, CO2PM. According to the 

developers of the model, CO2-PROPHET has more capabilities and fewer limitations than 

A‐6 
CO2PM. For example, according to the above cited report, CO2-PROPHET performs two main 

operations that provide a more robust calculation of oil recovery than available from CO2PM: 

• CO2-PROPHET generates streamlines for fluid flow between injection and 

production wells, and 

• The model performs oil displacement and recovery calculations along the 

s, it is important to note the CO2-PROPHET is still primarily 

a “scre

d, 

(5) vari

The nts for normal well operation and maintenance (O&M), for 

lifting c the 

produced C ilable to the 

model user

.7 CONSTRUCTING AN ECONOMICS MODEL. The economic model used by 

the study is 

wide basis. The economic model accounts for royalties, severance and ad valorem taxes, as 

established streamlines. (A finite difference routine is used for oil 

displacement calculations.) 

Even with these improvement

ening-type” model, and lacks some of the key features, such as gravity override and 

compositional changes to fluid phases, available in more sophisticated reservoir simulators. 

A.6 ASSEMBLING THE COST MODEL. A detailed, up-to-date CO2-EOR Cost 

Model was developed by the study. The model includes costs for: (1) drilling new wells or 

reworking existing wells; (2) providing surface equipment for new wells; (3) installing the CO2

recycle plant; (4) constructing a CO2 spur-line from the main CO2 trunkline to the oil field; an

ous miscellaneous costs. 

 cost model also accou

osts of the produced fluids, and for costs of capturing, separating and reinjecting 

O2. A variety of CO2 purchase and reinjection costs options are ava

. 

A

an industry standard cash flow model that can be run on either a pattern or a fieldwell as any oil gravity and market location discounts (or premiums) from the “marker” oil price. 

A variety of oil prices are available to the model user. 

A‐7 
city Market Module 

Appendix B 

Incorporation of Economically Feasible CO2 Demand for EOR into the 

CarBen Model and the Electri

Appendix B
 B-1 

Enabling “Early Market Entry” of CCS Technology in the Electric 

Power Sector 

The following three tables in Appendi

Electricity Market Model (that emulates the EIA NEMS Electricity Market Module) and 

how revenues from sale of CO2 into the EOR industry could help stimulate “early 

market entry” of CO2 capture and storage (

ants (with 

and without CCS) changes with time, from 2012 through 2030. Table B-1 

then illustrates how the cost offsets from sale of captured CO2 would help 

reduce the cost of electricity and help make the Advanced Coal with CCS 

option competitive with coal generated power without CCS. 

 Table B-2 illustrates the same changes in costs of electricity now with 

“accelerated” learning included, from the installation of 49 new advanced 

coal plants with CCS. 

 Table B-3 compares the EIA Reference Case of new coal-fueled power 

plant builds (with and without CCS) with the Alternative Case involving 

capture and sale of CO2 by the power industry to the CO2-EOR industry. 

Table B-2 then summarizes how cost offsets from sale of CO2 (plus 

“learning”) in the Alternative Case would enable a significant number of 

“early market entries” of power plants with CCS (cumulative): 

 2020 - - 15 GW size plants w/CCS 

 2030 - - 48 GW size plants w/CCS 

x B provide a synopsis of CarBen’s 

CCS) by the coal-fueled power sector. 

 Table B-1 illustrates how the cost of generating and transmitting electricity, 

from advanced coal plants (IGCC) and pulverized coal (PC) pl
Table B-1 

Economic Implications of Sale of CO2 Without Ac elerated “Learnin f 

w/CCS in the CarBen Electricity Market Model 

• Revenues (cos fs ) f en le d 

w/CCS more e o th or d 

Offset Reven Sa f C 2

c

 without “

 Advance

g” 

arning”, can make A

Coal w/o CCS 

2012 20

or A

van

0 

t of 

con

ue from 

ets

mic 

le o

rom sale of CO2, ev

an Pulverized Coal 

O2 ($/MWh)

CO2-EOR Reven ffs 5/m ue O et $3 t $ 23.50 CO2-EOR Reven ffs 5/m ue O et $2 t $ 16.80 Competition Among Coal-Fueled Power Generation Options 

2012 2020 

Price of Electricity w/o and w/CCS ($/MWh)Pulverized Coal $ 56.60* $ 59.70 Advanced Coal $ 65.70 $ 62.00 Advanced Coal w/CCS $ 86.30 $ 80.80 Price of Electricity w/CCS and Sale of CO2 ($/MWh) Advanced Coal w/CCS & Sale of CO2 at $35/mt $ 59.60 $ 57.30* Advanced Coal w/CCS & Sale of CO2 at $25/mt $ 64.00 *Least-cost, competitive preferred power generation option 

 B-1 
Table B-2 

Economic Implications of Sale of CO2 and With Accelerated “Learning” for A

w/CCS in the CarBen Electricity Market Model 

• Revenues (cost offsets) from sale of CO2, plus “learning”, can make Advanced Coal 

more economic than Pulverized Coal or Advanced Coal w/o CCS 

Offset Revenue from Sale of CO2 ($/MWh) 2012 2020 CO2-EOR Revenue Offset $35/mt $ 23.50 CO2-EOR Revenue Offset $25/mt $ 16.80 Competition Among Coal-Fueled Power Generation Options 

2012 2020 

Price of Electricity w/o and w/CCS ($/MWh)Pulverized Coal $ 56.60* $ 59.70 Advanced Coal $ 65.70 $ 62.00 Advanced Coal w/CCS $ 86.30 $ 74.50 Price of Electricity w/CCS and Sale of CO2 ($/MWh) Advanced Coal w/CCS & Sale of CO2 at $35/mt $ 59.60 $ 51.00* Advanced Coal w/CCS & Sale of CO2 at $25/mt $ 57.70* *Least-cost, competitive preferred power generation option 

 B-2 
Table B-3 

Incorporation of CO2 Sales into the CarBen Electricity Market Mo

Reference Case 2012 ∆ 2013-20 2020 ∆ 2021-30 2

Cumulative Coal Additions (GW) 12 29 41 80 

Pulverized Coal 12 22 34 41 

Advanced Coal (IGCC) - 7 7 39 

Advanced Coal (IGCC) w/CCS - - - - 

After CO2-Sale 2012 ∆ 2013-20 2020 ∆ 2021-30

ditions (G ) 12 29 41 

12 11 23

Advanced Coal (IGC ) - 3 3 22

15 15 34

 Coal Power Plant Builds with Sal CO2 to E

2

Cumulative Coal Ad W 80 

Pulverized Coal 24 

C 

 B-3 

Advanced Coal (IGCC) w/CCS -

Reference Case: Coal Power Plant Builds

Alternative Case: es of OR
Appendix C 

“Next Generation” CO2 Storage and EOR Technology

Appendix C
“Next Generation” CO2 Storage and EOR Technology 

“Next generation” CO2 storage and enhanced oil recovery technology offers the 

potential for storing significantly large 2 than possible using current 

practices. Four key technology advanc

technology

 Innovative flood design and well placement, including the application of 

vertical (gravity stable) CO2 floods, where geologically feasible, as shown 

on Figure C-1; 

 Extensive use of mobility control techniques, to improve the CO2 flood 

mobility ratio and reservoir contact, in both horizontal and vertical CO2 

floods, as illustrated in Figure C-2; 

 Even higher volumes of CO2 injection, beyond the 1 HCPV “standard” 

used in “state-of-the-art” CO2 floods, Figure C-3. This would also entail 

injecting CO2 into the transition/residual oil zone (TZ/ROZ) and the saline 

water zone below the main reservoir section, as shown on Figure C-1; 

 Making significant investments in “real-time” flood performance 

diagnostics and control, as illustrated in Figure C-2, using: 

– 4-D seismic; 

– Instrumented observation wells; 

– Zone-by-zone performance information; and 

– Inter-disciplinary technical teams. 

To provide an example of how much more CO2 could be stored with EOR, the 

study used reservoir simulation to examine the application of CO2 storage and EOR in 

an example for Gulf Coast oil reservoir, geologically favorable for either horizontal 

(“state-of-the-art”) or gravity stable (“next generation”) CO2-EOR. Table C-1 provides 

background information on this example oil reservoir. Table C-2 shows that over six 

times as much CO2 could be stored in this reservoir using “next generation” technology, 

r volumes of CO

es form the heart of “next generation” 

: 

C‐1 
e

C‐2 

nabling t CO2 

conten

he operator to store 1.6 times as much CO2 in the oil reservoir as the

t in the recovered oil. 
Figure C-1. Illustration of “Next Generation” Integration of CO2 Storage 

CO2 Injection CO2 Injection

CO22 Source

Oil to 

Market

Oil to 

Market Production Well Production Well

CO2 Recycled CO2 Recycled

Current Water 

Oil Contact

Current Water 

Oil Contact

Original Water

Oil Contact

Original Water

Oil Contact

Stage #1 Stage #

Stag

Stag

TZ/ROZ

Unswept Area Unswept Area

Oil Bank Oil Bank

Swept Area Swept Area

Saline Reservoir Saline Reservoir

C‐3 
Figure C-2. Impact Of Advanced Mobility Control On CO2-EOR Perfor

Injected CO

2 achie

only limited contact witreservoir due to:

• Viscous fingering • Gravity override 

Addition of viscos

enhancers would impromobility ratio and resercontact. 

Source: Adapted by Advanced Resources Int’l from “Enhanced Oil Recovery”, D.W. Green and G. P. Willhite, SPE, 1998.

Oil and Water

Water

Oil and Water

Water

PolymerIn Water

Waterflood

(High Mobility Ratio)

Viscosity Enhanced Flood

(Improved Mobility Ratio)

JAF02709.PPT

C‐4 
Figure C-3. Impact Of Increased CO2 Injection On CO2-EOR Perform

Means (San Andres) @ 2:1 WA

Source: Claridge, E.L., “Prediction of Recovery in Unstable Miscible Displacement”, SPE (April 1972).

Note: VpD is displaceable fluid pore volumes of CO2 injected. 

1.00.90.80.70.6

0.50.40.30.20.1

0

0 0.5 1 0.2 2 10 5 20 50 100 200 500 1000

5.02.0

3.0

1.0V pD0.10.21.50.6

Sweep Efficiency, EA

Mobility Ratio, M

V

at B.T. vs. M pD

Sweep Efficiency in Miscible Flooding Injected CO

2 vs Oil Re

Source: SPE 24928 (1992)

2015

10

5

0

25

0 10 20 30 

Years

Incremental Tertiary Recovery - % OOIP 

C‐5 
Ta 

Case Study: Large Gulf Coast oil reservoir with 340 million barrels (main pay zone has been selected as the “case study”. 

• The primary/secondary oil recovery in this oil reservoir is favora

million barrels, equal to 45% of OOIP. Even with this favorable using conventional practices, 187 million barrels is left behind (“

• In addition, another 100 million barrels of essentially immobile re

in the underlying 130 feet of the transition/residual oil zone (TZ/

• Below the TZ/ROZ is an underlying saline reservoir with 195 fee

holding considerable CO2 storage capacity. 

Based on the above, the theoretical CO2 storage capacity of this oil structural closure is 2,710 Bcf (143 million tonnes). 

ble C-1. Case Study: Integration of “Next Generation” CO2 Storage w

C‐6 
Table C-2. Case Study: Integration of “Next Generation” CO2 S

Producing “Green Oil”: Integrating CO2-EOR and CO2 Sto

alternative CO2 storage and EOR design, much more CO2 can 

more oil becomes potentially recoverable. 

Oil Recovery (barrels) 64 18

o

CO Storage (tonnes) 19 10

The additional oil produced is “GREEN OIL”*. 

St rage Capacity Utilization 13% 76

2

% Carbon Neutral (“Green Oil”) 80% 160

(millions) (milli

“State of the Art” “Next Ge

Oil Recovery (barrels) 64 18

o

CO Storage (tonnes) 19 10

St rage Capacity Utilization 13% 76

2

% Carbon Neutral (“Green Oil”) 80% 160

(millions) (milli

“State of the Art” “Next Ge

*”Green Oil” means that more CO2 is injected and stored underground than the volume of CO2 con

roduced oil, once burned.

p

C‐7