# Storing CO2 with Enhanced Oil Recovery

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

Februar y 7
, 2008

# Disclaimer

This report was prepared as an account of work sponsored by an agency of the United States Government. Neither th e United States Government nor any agency thereof, nor any of their empl oyees, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any info rmation, 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 th e United States Government or any agency thereof. Th e 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.govThis 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 “Ear ly 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 G eneration” 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 Alte rnative 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 E nhanced 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 capt ure 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 geologica l storage of CO2 - - es tablishing 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 pro duced 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 to ward 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 an d adds to a previously issued series of “basin studies”, is to examine and fu rther quantify the benefit s of integrating CO2 storage with enhanced oil recovery. The r eport also updates the size of the CO2
market available from EOR and how this mark et could support “early market entry” of CCS technology in the coal-fuel ed electric power sector.

2

## 2.0 Background
2.1. Key Feature of This New Report
In 2004 and 2005, Advanced Resources Inte rnational, with sponsorship by the U.S. Department of Energy’s Office of Foss il Energy, issued a series of ten “basin reports”. ∗ 

### These reports examined the domestic CO2 storage and oil recovery potential offered by expanded developm ent and application of CO2-EOR technology. This report entitled, “Storing CO2 with Enhanced Oil Reco very”, provides a major update to this past set of data and information. For example, the initial c hapter 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 rese rvoirs accounting for nearly threequarters of the U.S. oil resource base in 27 states, Figure 1. These new
oil reservoirs were made availabl e for this study from Advanced Resources proprietary data base;

 Improvements and updates have been m ade to the well spacing and CO2 injection portions of the model. O il 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 re vised 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/progr ams/oilgas/eor/Ten_Basin

‐ Oriented_CO2

‐ EOR_Assessments.html

.

34 

### The later chapters of this report exam ine 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 CO 2 emissions would support the “early market entry” of new coal-fueled power plants equipp ed with CO2 capture technologies.5The 27 states with shading are included in the elevenAdvanced Resources International updated “basin studies”of CO2storage with enhanced oil recovery.JAF02709.PPTFigure 1. U.S. Basins/Regions Studied For Future CO2 Storage and Enhanced Oil Recovery

### 2.2. Addressing Current Misconcepti ons Surrounding Storing CO2 with EOR
Various analysts and studies have discusse d 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 Captur e and Storage”, while recognizi ng that depleted oil fields could provide an attractive, early option fo r storing CO2 (particu larly 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 hav e the lowest capacity of all forms of CO2 geologic storage, estimat ed globally at 61 to 123 billion tons of CO2 . . . it is import ant 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-optimizi ng 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 seques tration. . . .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 r each 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 Furt her Activity (NFA) baseline.

The ERS/IEA report continues by stati ng 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 fr om combustion of the incr emental oil produced. The ERS/IEA report recommends that for acc eptance by CDM, CO2-EOR would need to
demonstrate net emission reductions.
One of the additional purpos es of this new report is to address, and hopefully dispel, some of the misconceptions that have arisen around the t opic of storing CO2 with enhanced oil recovery by showing that: (1 ) for the U.S. (and by extension for the world), the CO2 storage capacit y offered by CO2-EOR is la rge, and when innovatively engineered, can be larger still; (2) essentia lly 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 pr oduced 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 pres entation 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 techni cally recoverable resource
would be economic at alternativ e 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 repor t. Additional discussi on 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 t en “basin studies” and thus are not repeated in this updated report. The previously prepared “basin st udy” reports can be accessed
at http://www.fe.doe.gov/programs/oilgas/publications/

.

89 

## 3.0 Evaluating the Market for Capt ured 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 t he large portion of this resource base unrecoverable with existing primary and sec ondary 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) t he impact of alternative oil prices and CO2
costs on the volume of oil that could be ec onomically 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 a ssess the CO2 storage and EOR potential of domestic oil reservoirs. The six steps we re: (1) assembling the Major Oil Reservoirs Data Base; (2) calculating the minimum miscibi lity 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 re source base, on the order of 596 billion barrels originally in-place. About one-third of this res ource base, nearly 196 billion barrels, has been recovered or placed into proved reserves with existing primary and secondary oil recovery technologies. This l eaves 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/10Large Volumes Of Domestic Oil Remain “Stranded” After Traditional Primary/Secondary Oil RecoveryOriginal Oil In-Place: 596 B Barrels*“Stranded” Oil In-Place: 400 B Barrels*Proved Reserves21 Billion BarrelsFuture Challenge400 Billion BarrelsCumulative Production175 Billion Barrels*Excludes deep-water GOM.Source: Advanced Resources International (2008)JAF02709.PPTFigure 2. The Domestic Oil Resource Base

### Table 1 provides a tabulation of the nati onal 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 t he Permian Basin of West Texas and New Mexico (62 billion barrels). California, Al aska, the Gulf Coast and the Rockies also have significant volumes of “stranded” oil.
The Advanced Resources’ Major Oil Reserv oirs 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 do mestic 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 fa vorable 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 tabulatio n of the 2,012 reservoirs in the Major Oil Reservoirs Data Base, showing that onl y 1,111 reservoirs (containing 319 billion barrels of OOIP) screened as being amenabl e to miscible and immiscible CO2-EOR.
More than half of the oil reservoirs in Ca lifornia, 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 t he Permian Basin are screened as favorable for
CO2-EOR.

11

### Table 1. National In-Place, Conventionally R ecoverable 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

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### 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 met hods. These include: oil that is bypassed due to poor waterflood sw eep efficiency; oil that is physically unconnected to a wellbore; and, most importantly, oil t hat is trapped by viscous, capillary and interfacial tension forces as residual oil in the pore space.
Injection of CO2 helps lower the oil viscosi ty and trapping forces in the reservoir. Additional well drilling and pattern reali gnment for the EOR pr oject helps contact bypassed and occluded oil. These actions enable a portion of this “stranded oil” to become mobile, connected to a well bore 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 satu ration in the reservoir’s pore space. Figure 3 provides a one-dimensional schem atic showing the various fluid phases existing in the reservoir and the dynam ics of the CO2 miscible process.

15

### Pure CO 2 

### CO 2 

### Vaporizing Oil Components CO 2 

### Condensing Into Oil Original Oil Miscibility is Developed in This Region (CO 2 and Oil Form Single Phase)

Direction of Displacement

JAF02709.PPT


### Figure 3. One-Dimensional Schemati c Showing the CO2 Miscible Process.

1617 

### 3.3.2. Current CO2-EOR Activity and Production
According to the latest tabulation of CO 2-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 source s. Figure 5 tracks the st eady growth in CO2-EOR production for the past 20 years, noting that although new acti vities 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 increas es in domestic CO2-EOR activity and oil production.J A F 0 1 9 9 4

. C D RLaBargeGas PlantLaBargeGas PlantVal VerdeGas PlantsVal VerdeGas PlantsEnid FertilizerPlantEnid FertilizerPlantJacksonDomeJacksonDomeMcElmo DomeSheep MountainBravo DomeMcElmo DomeSheep MountainBravo Dome966573Dakota CoalGasificationPlantDakota CoalGasificationPlantAntrim GasPlantAntrim GasPlant211Number of CO2-EOR ProjectsNatural CO2SourceIndustrial CO2SourceCO2Pipeline86JAF02709.PPTFigure 4. U.S.CO2-EOR Activity1819Source: Oil and Gas Journal, April, 2006.Year050,000100,000150,000200,000250,0001986 1988 1990 1992 1994 1996 1998 2000 2002 2004 2006

Enhanced Oil Recovery (barrels/day)Gulf Coast/OtherMid-ContinentRocky MountainsPermian BasinJAF2006016.XLSJAF02709.PPTFigure 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 efficienc ies of today’s better designed “state-of-the-art” CO2-EOR projects have steadily improved.
Two key assumptions underlie the oil reco very performance calculated for this study by the ARI/PROPHET model (see Appendi x 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 activi ties that help assure that the larger volumes of injected CO2 contact more of the re servoir’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 maint enance of miscibility pressure throughout the reservoir, and the rein jection of CO2 produced with oil.
Figures 6A and 6B provide the scientific and practical basis for using larger volumes of CO2 injection. Figure 7 illu strates how rigorous monitoring and well remediation can be used to target injected CO 2 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 MiscibleDisplacement”, SPE (April 1972).Note: VpDis displaceable fluid pore volumes of CO2injected.1.00.90.80.70.60.50.40.30.20.100.20 0.512 105 502020010010005005.02.03.01.0VpD0.10.21.50.6

Sweep Efficiency, E AMobility Ratio, M

V a t B .

T

. v s .

M

p DSweep Efficiency in Miscible FloodingPetroleum engineering science confirms that using increased volumes ofCO2leads to increased reservoir sweep efficiency.+49%0.5150.80Source: After Claridge (April 1972) (Mobility Ratio of 25)+65%0.5701.00+28%0.4400.600.3450.40IncrementalSweepEfficiency(%)SweepEfficiency(RPV)Injected CO2(HCPV)Oil Recovery Efficiencyvs. CO2Injection+49%0.5150.80Source: After Claridge (April 1972) (Mobility Ratio of 25)+65%0.5701.00+28%0.4400.600.3450.40IncrementalSweepEfficiency(%)SweepEfficiency(RPV)Injected CO2(HCPV)Oil Recovery Efficiencyvs. CO2Injection0.4JAF02709.PPTFigure 6A. Science Behind Volume of CO2 Injection and Oil Recovery Efficiency: General Theory21The CO2-EOR WAG project at Means(San Andres Unit) was implemented aspart of an integrated reservoirdevelopment plan and involve the drillingof 205 new producers and 158 newinjectors.Initial objective was to inject 260 Bcf ofCO2, equal to 55% HCPV, (0.4 HCPVpurchased; 0.15 HCPV recycled) at a 2:1WAG ratio.Latest objective is to inject 480 Bcf (~1HCPV) of CO2.Effect of Solvent Bank Size on Oil RecoveryMeans (San Andres) @ 2:1 WAG RatioSource: SPE 24928 (1992)201510502540302050100Years

Incremental Tertiary Recovery - % OOIP0.8 HCPV0.6 HCPV0.4 HCPV0.2 HCPVJAF02709.PPTFigure 6B. Science Behind Volume of CO2 Injection and Oil Recovery Efficiency: Actual Practice22Rigorous monitoring and well remediation can be used to help target injected CO2to reservoir strata with highresidual oil saturation.0 20 40 60 80 1006,900 Depth6,350% Injected Before0 20 40 60 80 100% Injected AfterWell 27-6 Injection Profile(Before)(After)Source: “SACROC Unit CO2Flood: Multidisciplinary Team Improves Reservoir Management andDecreases Operating Costs”, J.T. Hawkins, et al., SPE Reservoir Engineering, August 1996.1839 Days(Channeling inLayer 2)478 Days(BreakthroughIn Layer 2)368 DaysSource: 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 Front0100 200 300Distance, ftLayer 1 (High Sor, Low k)Layer 2(Low Sor, High k)Water• Higher oil saturation portion of reservoir isinefficiently swept.• CO2channeling reduced with well workover.JAF02709.PPTFigure 7. Overcoming the Effects of Geologic Complexity on CO2-EOR Performance2324Source: OXY Permian 20062001EDU 80% to 100% CO2slug size increase approved1996EDU 60% to 80% CO2slug size increase approved1994EDU 40% to 60% CO2slug size increase approved1992Non performing FIA patterns stopped (~20% slug size)1989EDU WAG & start off CO2injection in WAC, FIA, B8 FIA1984Start of CO2injection in EDU with 40% slug sizeStartedEastern Denver Unit (Wasson Oil Field) CO2-EOR ProjectSource: OXY Permian 20062001EDU 80% to 100% CO2slug size increase approved1996EDU 60% to 80% CO2slug size increase approved1994EDU 40% to 60% CO2slug size increase approved1992Non performing FIA patterns stopped (~20% slug size)1989EDU WAG & start off CO2injection in WAC, FIA, B8 FIA1984Start of CO2injection in EDU with 40% slug sizeStartedEastern Denver Unit (Wasson Oil Field) CO2-EOR ProjectOccidental Petroleum (Oxy Permian) is the industry leader for CO2-EOR, in terms of number of largeprojects, volume of CO2used, and volumes of oil production.JAF02709.PPTFigure 8. Evolution of “Industry Standard” for VolumeCO2 Injection (“Slug Size”)

### The oil recovery calculations contained in this study rely on these “state-of-theart” practices. As such, the calculated o il 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” bei ng employed by technically sophisticated operations and cu rrent 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-t he-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 b illion barrels, as of the end of 2006.
Not surprisingly, the Permian Basin of We st 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 fr om 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, insta lling a CO2 recycle plant, and constructing CO2 gathering and transportation pipelines. However, in general, the single largest cost of the project is the purc hase of CO2. As such, operators st rive to optimize and reduce its purchase and injection, where possible.
The recent increases in domestic oil prices have significantly improved the
economics outlook for conducti ng CO2-EOR. However, o il 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 repr esentative, reasonably favorable CO2- EOR project are provided, for illustrative pur poses, 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 a nd 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 purc hase; $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 invest ment 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 fr ont-end investment will be required to achieve economically favor able rates of return. Oil reservoirs with higher capital cost requirements and less favor able CO2 to oil ratios would not achieve an economically justifiable return on invest ment, requiring advanced, more efficient CO2-EOR technology and/or cr edits 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. T he Base Case eval uates 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-ar t” CO2-EOR technology under Base Case
economics.

3.4.3. Economically Recoverable Resources: Sensitivity Cases
To gain insights as to how changes in o il prices would influence the volumes of economically recoverable resources from appl ying CO2-EOR, the story examined one lower and two higher oil price case s (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 (const ant, real) and a CO2 cost of $45 per metric ton ($2.38/Mcf), delivered at pressure to the field.

3031 

### 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 recove rable domestic oil fr om applying CO2-EOR have been calculated using a minimum financial hur dle 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 geol ogic settings, would reduce the above (Table 8) volumes of economically recoverable oil.
To examine the impact of a higher financ ial 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, s upporting the financial robustness of this oil recovery technology.
Figure 6 illustrates the volumes of domesti c oil recovery potentially available from applying CO2-EOR technology at alternativ e oil prices and CO2 costs (using the assumed relationship in the economic model between oil prices and CO2 costs, shown in Table 8).32Figure 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 t he lower, $50 per barrel, oil price case. Equally instructive to note is that higher oi l 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, “Eval uating The Potential For ‘Game Changer’ Improvements In Oil Recovery Efficiency From CO2 Enhanced Oil Recovery”, will be required to make more of this techni cally recoverable resource economic.

33

## 4.0 The Market for Storing CO2 with EOR
The primary purpose of this report is to establish ho w much CO2, particularly CO2 emissions captured by power plants, could be stored with enhanced oil recovery.
Chapter 3 established that 39 to 48 bi llion barrels of economic, incremental domestic oil could be produced by timely app lication of CO2-EOR technology. This chapter draws on this oil recovery assessment to estimate how much CO2, particularly CO2 emissions captured from new coal-f ueled power plants, would be required to produce this volume of economically recovera ble oil, helping establish the market for captured CO2 emissions.



### 4.1. The CO2 Injecti on and Storage Process
The analysis shows that significant volu mes of CO2 (ranging fr om 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 volume s of CO2 increase, these larger volumes of CO2 are reinjected, c ontinuing the life of the CO2-EOR project.

 Near the end of the CO2-EOR projec t, the operator may choose to close the field at pressure, stor ing essentially all of t he 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 me tric tons (mt)) of purchased CO2 per barrel of oil is used and stored as part of CO 2-EOR. This is augmented with 5 to 10 Mcf (0.26 mt to 0.52 mt) of recycl ed CO2 during the latter stages of a CO2-EOR process.
With incentives for storing CO2 emissi ons and “next generat ion” CO2 storage technology, considerably larger volumes of CO2 could be stored. Additional discussion of “next generation” storage of CO2 wit h 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 o il 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. Import ed 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 volume s 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-bas ed ethanol drops to below 0% “carbon free” and becomes a
contributor to the CO 2 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 cost s. (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 volu mes 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, deliv ered 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 histor y of CO2 costs shows t hat they have been, in general, linked to oil prices.

36

### Table 9. Economically Feasible Mar ket for CO2 for CO 2-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 De mand 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.

3839 

### 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 indust ry. In this secti on of the report, we
examine in more detail the market demand fo r CO2 from the power plant perspective, giving priority to market demand that mi ght be met by capture and sale of CO2
emissions from the coal -fueled power sector.
The overall demand for CO2 by the CO 2-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 source s 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 in formation 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 E nergy 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 t he 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.40NEMS Regions:CO2 supply and demand have been organized according to the 14NEMS regions (13 lower-48 plus Alaska) in the Electricity Market ModuleJAF02709.PPTFigure 7. Geographical Regions inthe 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 Be tween 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, Connecticut, Rhode Island Region 7 – NW ISO Region 8 – Florida Florida Arkansas, Louisiana, Mississippi, Alabama, Tennessee, Georgia, South Carolina, North Carolina Region 9 – SERC Region 10 – SWPP Oklahoma, Kansas and New Mexico Washington, Oregon, Idaho, Montana, Wyoming, Utah, Nevada Region 11 – WECC/NWPP 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 dem and 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 CO 2 available, in the next 30 y ears, from natur al CO2 deposits and high concentration industrial CO2 source s (e.g., natural gas processing plants, fertilizer plants) already being captured and used for enhanced oil recovery.
Table 14 tabulates the existing source s 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 AnthropogenicTexas-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 y ear by first multiplying by 365 (days per year) and then dividing by 18.9 * 10 3 (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 co me on stream between now and 2030. If these 121 GWs of coal-fueled power generati on 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 (lowe r-48) from the installation of these new coal-fueled power plants.
A closer look at CO2 demand (net, after subtracting CO2 supp lies available from natural and already captured i ndustrial CO2 sources) for EO R shows: (1) there is unmet (net) demand for CO2 in eleven of the EMM r egions 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 fu lfill 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-f ueled power plant capacity. (Mo st likely, installation of

4546 

### CO2 pipelines crossing EMM regional bou ndaries 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 re venues afforded by this market will be established, in the main, by one-on- one negotiations betw een 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 co sts and challenges of storing CO2.47EMMRegionRegionStatesCoalDeployment2007-2030AvailableCO2 FromCoal*Demand forCO2 @ $45/mt &$70/B OilShortfall(Excess) inCO2 Supply#(GW) (MMmt) (MMmt) (MMmt)2 ERCOTTX21.0 3,5702,438(1,132)9 SERCAR, LA, MS, AL, TN, GA, SC, NC32.7 5,5591,695(3,864)13 WECC/CACA0.0 -1,3771,37710 SWPPOK, KS, NM9.3 1,5811,286(295)11 WECC/NWPPWA, OR, ID, MT, WY, UT, NV6.4 1,088311(777)5 MAPPND, SD, NE, MN2.5 425109(316)4 MAINIL, MO, IA, WI3.3 561100(461)12 WECC/RMPPCO, AZ17.4 2,95883(2,875)1 ECARKY, WV, OH, IN, MI2.5 42558(367)8 FloridaFL12.5 2,1259(2,116)3 PJM (MAAC)PA, DE, NJ, MD8.2 1,3944(1,390)6 NY ISONY5.1 867-(867)7 NE ISOVT, NH, ME, MA, CT, RI0.0 ---U.S. Total120.9 20,5537,471(13,082)*Assuming all new Coal Plants capture 90% of CO2, operate at 85%capacity and 38% efficiency (8,876 Btu/kWh); includes 30 yearsof CO2emissions.Table 15. Comparison of Net CO2 Demand (for EOR) with Potential Captured CO2 Emissions from Coal-Fueled Power Plants48 

## 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 dev elop in a timely fashion, it would support “early market entry” of ca rbon 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 solution 1 , , 2 3 

### . The reason, according to EIA’s EMM cost model, is that using CCS with co al- 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, inco rporation 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 subsid ized 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 electricit y 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 R educe 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 Int ensity 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 electricity includesgeneration and transmission.Source: AEO 2008, ReferenceCase (Electricity Market Module);CarBen 200820122020Pulverized CoalAdvanced Coal (IGCC)Advanced Coal w/CCSAdvanced NuclearReference CaseReference CaseJAF02709.PPT576620405060708090606219668681Figure 8. Advanced Coal Plants w/CCS Are CurrentlyUncompetitive in 2012 and 2020 (EIA’s AEO 2008 Reference Case)

### However, revenues from selling captur ed 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 MW h, significantly offsetting the costs of installing CCS with new c oal-fueled power plants.

Table 16. Relationship of CO2 Sales Price to Cost O ffsets 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 emi ssions 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-f ueled power generation options, Table 17.

Table 17. EIA Reference Case Year 20 12 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

5051 

### 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 pr ovide a cost offset of $23.50/MWh.
In 2012, the revenue offset of $23.50/MWh fr om sale of captured CO2 emissions is not sufficient to make CCS cost compet itive. By 2020, howev er, with assured, longterm sale of captured CO2 emissions at $35 per metric ton (a t 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 lo wer-48. Assuming that half of these power plants are favorably locat ed with respect to oil fields attractive for
CO2-EOR and are able to sell CO 2 at $35/mt at the plant gat e, the integration of CO2 storage and EOR would support the construc tion 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 se ll about 5.1 million metric tons of captured CO2 emissions per year; 15 plants would be abl e 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 installati ons of CCS, as discussed below.52

Cost of Electricity ($/MWh)**Cost of electricity includesgeneration and transmission.Source: AEO 2008, ReferenceCase (Electricity Market Module);CarBen 2008Pulverized CoalAdvanced Coal (IGCC)Advanced Coal w/CCSAdvanced Coal w/CCSand Sale of CO2Advanced NuclearReference Case2020JAF02709.PPT40506070809060621981AdvancedCoal w/EORRevenues81@ $35/mtfor CO220205766Figure 9. Sale of Captured CO2 EmissionsCan Help Make Coal Plants w/CCS Competitive

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

The CarBen and EIA EMM models contai n 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 electricit y 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 Electri city with Accelerated “Learning” Based Cost Reductions

Cost of Electricity $/MWh* Power Generation Option Year 2020
1. Pulverized C oal 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 pl ant 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 t he preferred economic choice for the post-2020 time period, as shown in Table 20 and Figure 10.

5354 

### 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-f ueled power plants are expected in the lower-48 between 2020 and 2030. Subtracting t he purchase of 2,300 m illion metric tons of captured CO2 emissions fr om 15 plants, the lower-48 EO R 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 locat ed, 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, bringi ng the total to 49 new power plants with CCS.
The sale of captured CO2 emissions c ould 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 t he costs of CCS technology.
Additional information on the incorporati on of sales of captured CO2 emissions by power plant into the Elec tricity Generation Module of t he CarBen Model (a simplified component of the EIA NEMS E MM) is provided in Appendix B.55

Cost of Electricity ($/MWh)**Cost of electricity includesgeneration and transmission.Source: AEO 2008, ReferenceCase (Electricity Market Module);CarBen 2008Advanced Coal w/CCSAdvanced Coal w/CCSand Sale of CO2Advanced Coal w/CCSand “Learning”Advanced Coal w/CCS,“Learning” and Sale ofCO2JAF02709.PPT405060708090Advanced Coalw/EOR Revenues20208175Advanced Coalw/EOR Revenuesand “Learning”2020@ $35/mtfor CO2@ $25/mtfor CO25758Figure 10. Sale of Captured CO2 Emissions Can Help Make Coal Plants w/CCS Competitive.

## Appendix A Study Methodology

A

‐ 1A

‐ 2 

### A. STUDY METHODOLOGY

A.1 OVERVIEW. A six part methodology was used to assess the CO 2 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 CO 2 -EOR; (4) calculating oil recovery; (5) assembling the cost and economic model; and, (6) performing economic and sensitivity analyses.



### A.2 ASSEMBLING THE MAJO R 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 re cording format developed by the study. The data format readily integrates with the input data required by the CO 2 -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 NameField NameReservoirReservoir Parameters:ARIOil ProductionARIVolumesARI P/SArea (A)Producing Wells (active)OOIP (MMbl)Net Pay (ft)Producing Wells (shut-in)P/S Cum Oil (MMbl)Depth (ft)2002 Production (Mbbl)EOY P/S 2002 Reserves (MMbl)PorosityDaily Prod - Field (Bbl/d)P/S Ultimate Recovery (MMbl)Reservoir Temp (deg F)Cum Oil Production (MMbbl)Remaining (MMbbl)Initial Pressure (psi)EOY 2002 Oil Reserves (MMbbl)Ultimate Recovered (%)Pressure (psi)Water CutOOIP Volume CheckBoiWater ProductionReservoir Volume (AF)Bo@ So, swept2002 Water Production (Mbbl)Bbl/AFSoiDaily Water (Mbbl/d)OOIP Check (MMbl)SorSwept Zone SoInjectionSROIP Volume CheckSwiInjection Wells (active)Reservoir Volume (AF)SwInjection Wells (shut-in)Swept Zone Bbl/AF2002 Water Injection (MMbbl)SROIP Check (MMbbl)API GravityDaily Injection - Field (Mbbl/d)Viscosity (cp)Cum Injection (MMbbl)Daily Inj per Well (Bbl/d)ROIP Volume CheckDykstra-ParsonsROIP Check (MMbl)EORType2002 EOR Production (MMbbl)Cum EOR Production (MMbbl)EOR 2002 Reserves (MMbbl)Ultimate Recovered (MMbbl)Print SheetsTable A-1. Reservoir Data Format: Major Oil Reservoirs Data BaseA‐3Considerable 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 CO 2 -EOR; and, (3) provide the CO 2 -PROPHET Model the essential input data for calculating CO 2 injection requirements and oil recovery.



### A.3 CALCULATING MINIMUM MISCIBILITY PRESSURE. The miscibility of a reservoir’s oil with injected CO 2 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 CO 2 , 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 C 5 +

70 110 150 190 230 270 0 1000 2000 3000 4000 5000 6000Miscibility Pressure, psi

Temperature, o F 340 300 280 260 240 220 200

180 

### Correlation for CO 2 

### Minimum Pressure as a Function of Temperature (Mungan, N., Carbon Dioxide Flooding Fundamentals, 1981)

Mole Weight C 5 +

70 110 150 190 230 270 0 1000 2000 3000 4000 5000 6000Miscibility Pressure, psi

Temperature, o F 340 300 280 260 240 220 200

180 

### Correlation for CO 2 

### 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 CO 2 -EOR were selected for consideration by immiscible CO 2 -EOR.

A

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



### A.4 SCREENING RESERVOIRS FOR CO 2 

### -EOR. The data base was screened for reservoirs that would be applicable for CO 2 -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 CO 2 -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 CO 2 -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 CO 2 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 CO 2 -PROPHET to calculate incremental oil produced using CO 2 -EOR. CO 2 -PROPHET was developed as an
alternat y = 4247.98641x -0.87022
R 2 = 0.99763

0 100 200 300 400 500

0 2 0 4 0 6 0 8 0 1 0 0 Tank Oil Gravity, o APIMolecular WT C5+ y = 4247.98641x -0.87022
R 2 = 0.99763

0 100 200 300 400 500

0 2 0 4 0 6 0 8 0 1 0 0 Tank Oil Gravity, o APIMolecular WT C5+

ive to the DOE’s CO 2 miscible flood predictive model, CO 2 PM . According to the developers of the model, CO 2 -PROPHET has more capabilities and fewer limitations than

A

‐ 6CO 2 PM . For example, according to the above cited report, CO 2 -PROPHET performs two main operations that provide a more robust calculation of oil recovery than available from CO 2 PM :



### • CO 2 

### -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 CO 2 -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 CO 2 -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 CO 2 recycle plant; (4) constructing a CO 2 spur-line from the main CO 2 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
O 2 . A variety of CO 2 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 discount s (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 Feas ible CO2 Demand for EOR into the CarBen Model and the Elect ri

Appendix BB-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 Refer ence Case of new coal-fueled power plant builds (with and without CCS) with the Alter native Case involving capture and sale of CO2 by the power industry to the CO 2-EOR industry. Table B-2 then summarizes how cost offsets from sale of CO2 (plus “learning”) in the Alternative Case w ould 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) plTable B-1WithoutEconomic Implications of Sale of CO2Ac elerated “Learnin f d Cow/CCS in the CarBen Electricity Market Model•Revenues (cos fs ) fen ledplanw/CCS more e o thor dOffset RevenSa f C2cwithout “Advanceg”arning”, can make ACoal w/o CCS201220or Advancevanced Coal02030altst ofconue frometsmicle orom saleof CO2, evan Pulverized CoalO2 ($/MWh)CO2-EOR Reven ffs 5/m5ue Oet $3t$ 23.0 $ 23.50CO2-EOR Reven ffs 5/m8ue Oet $2t$ 16.0 $ 16.80Competition Among Coal-Fuelnsed PowerGeneration Optio22012 200 2030Price of Electricity w/o and w/CCS ($/MWh)Pulverized Coal$ 56.60*$ 59.70$ 59.10Advanced Coal$ 65.70$ 62.00$ 59.30Advanced Coal w/CCS$ 86.30$ 80.80$ 75.50Price of Electricity w/CCSandSale of CO2 ($/MWh)Advanced Coal w/CCS & Sale of3*$ 59.60$ 57.0* $ 52.00CO2 at $35/mtAdvanced Coal w/CCS & Sale of0*0$ 58.70CO2 at $25/mt$ 64.*Least-cost, competitive preferred power generation optionB-1Table B-2Economic Implications of Sale of CO2 andWithAccelerated “Learning” for Advanced Coalw/CCS in the CarBen Electricity Market Model•Revenues (cost offsets) from sale of CO2, plus “learning”, can make Advanced Coalplants w/CCSmore economic than PulverizedCoal or Advanced Coal w/o CCSOffset Revenue fromSale of CO2 ($/MWh)201220202030CO2-EOR Revenue Offset $35/mt$ 23.50$ 23.80CO2-EOR Revenue Offset $25/mt$ 16.80$ 16.80Competition Among Coal-Fueled PowerGeneration Options201220202030Price of Electricity w/o and w/CCS ($/MWh)Pulverized Coal$ 56.60*$ 59.70$ 59.10Advanced Coal$ 65.70$ 62.00$ 59.30Advanced Coal w/CCS$ 86.30$ 74.50$ 71.60Price of Electricity w/CCSand Sale of CO2 ($/MWh)Advanced Coal w/CCS & Sale ofCO2 at $35/mt$ 59.60$ 51.00*$ 48.10*Advanced Coal w/CCS & Saleof CO2 at $25/mt$ 57.70*$ 54.80**Least-cost, competitive preferred power generation optionB-2Table B-3Incorporation of CO2 Sales into the CarBen Electricity Market ModelReference Case2012∆2013-20 2020∆2021-30 2030Cumulative Coal Additions (GW) 12294180121Pulverized Coal1222344175Advanced Coal (IGCC)-773946Advanced Coal (IGCC) w/CCS-----After CO2-Sale2012∆2013-20 2020∆2021-30ditions (G ) 1229411121123Advanced Coal (IGC )-3322151534Coal Power PlantBuilds with Sal CO2 to E2030Cumulative Coal AdW8021Pulverized Coal2447C2549B-3Advanced Coal (IGCC) w/CCS-Reference Case: CoalPower Plant BuildsAlternative Case:es ofOR

## 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 placem ent, including the application of vertical (gravity stable) CO2 floods, w here 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 inje ction, 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/resi dual oil zone (TZ/ROZ) and the saline
water zone below the main reservoir se ction, as shown on Figure C-1;

 Making significant investments in “real-time” flood performance diagnostics and control, as illust rated 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 mo re CO2 could be st ored with EOR, the study used reservoir simulation to examine the application of CO 2 storage and EOR in an example for Gulf Coast oil reservoir, geologically favorable for either horizontal (“state-of-the-art”) or gravit y stable (“next generation”) CO2- EOR. Table C-1 provides background information on this example oil rese rvoir. Table C-2 s hows that over six
times as much CO2 could be stored in this re servoir using “next generation” technology, r vo lumes 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 and EORCO2InjectionCO2Injection2CO2SourceOil toMarketOil toMarketProduction WellProduction WellCO2RecycledCO2RecycledCurrent WaterOil ContactCurrent WaterOil ContactOriginalWaterOil ContactOriginalWaterOil ContactStage #1Stage #1Stage #2Stage #2Stage #3Stage #3TZ/ROZUnswept AreaUnswept AreaOil BankOil BankSwept AreaSwept AreaSaline ReservoirSaline ReservoirC‐3Figure C-2. Impact Of Advanced Mobility Control On CO2-EOR PerformanceInjected CO2achievesonly limited contact with thereservoir due to:• Viscous fingering• Gravity overrideAddition of viscosityenhancers would improvemobility ratio and reservoircontact.Source: Adapted by Advanced Resources Int’l from “EnhancedOil Recovery”, D.W. Green and G. P. Willhite, SPE, 1998.Oil and WaterWaterOil and WaterWaterPolymerIn WaterWaterflood(High Mobility Ratio)Viscosity Enhanced Flood(Improved Mobility Ratio)JAF02709.PPTC‐4Figure C-3. Impact Of Increased CO2 Injection On CO2-EOR PerformanceMeans (San Andres) @ 2:1 WAG RatioSource: Claridge, E.L., “Prediction of Recovery in Unstable MiscibleDisplacement”, SPE (April 1972).Note: VpDis displaceable fluid pore volumes of CO2injected.1.00.90.80.70.60.50.40.30.20.100.20 0.5 12 105502020010010005005.02.03.01.0VpD0.10.21.50.6

Sweep Efficiency, E AMobility Ratio, M

V a t B .

T

. v s .

M

p DInjected CO2vs Oil RecoverySweep Efficiency in Miscible FloodingSource: SPE 24928 (1992)201510502540302050100Years

Incremental Tertiary Recovery - % OOIP0.8 HCPV0.6 HCPV0.4 HCPV0.2 HCPVC‐5TaRCase Study: Large Gulf Coast oil reservoir with 340 million barrels (OOIP) in themain pay zone has been selected as the “case study”.•The primary/secondary oil recovery in this oil reservoir is favorable at 153million barrels, equal to 45% of OOIP. Even with this favorable oil recoveryusing conventional practices, 187 million barrels is left behind (“stranded”).•In addition, another 100 million barrels of essentially immobile residual oil existsin the underlying 130 feet of the transition/residual oil zone (TZ/ROZ).•Below the TZ/ROZ is an underlying salinereservoir with 195 feet of thickness,holding considerable CO2 storage capacity.Based on the above, the theoretical CO2 storage capacity of this oil reservoir andstructural closure is 2,710 Bcf (143 million tonnes).ble C-1. Case Study: Integration of“Next Generation” CO2 Storage with EOC‐6Table C-2. Case Study: Integration of “Next Generation” CO2 Storage with EORProducing “Green Oil”: Integrating CO2-EOR and CO2 Storage.Withalternative CO2 storage and EOR design, much more CO2 can be stored andmore oil becomes potentially recoverable.18064Oil Recovery (barrels)o10919COStorage (tonnes)The additional oil produced is “GREEN OIL”*.76%13%St rage Capacity Utilization2160%80%% Carbon Neutral (“Green Oil”)(millions)(millions)“State of the Art”“Next Generation”18064Oil Recovery (barrels)o10919COStorage (tonnes)76%13%St rage Capacity Utilization2160%80%% Carbon Neutral (“Green Oil”)(millions)(millions)“State of the Art”“Next Generation” 9.PPT*”Green Oil” means that more CO2is injected and stored underground than the volume of CO2contained in theroduced oil, once burned. JAF0270pC‐7