An Assessment of Gate-to-Gate Environmental 

Life Cycle Performance of Water-AlternatingGas CO2-Enhanced Oil Recovery in the Permian 

Basin

September 30, 2010

DOE/NETL-2010/1433
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.
An Assessment of Gate-to-Gate Environmental Life Cycle 

Performance of Water-Alternating-Gas CO2-Enhanced Oil 

Recovery in the Permian Basin

DOE/NETL-2010/1433

September 30, 2010

NETL Contact:

Robert M. Dilmore

General Engineer, Situational Analysis Team

Office of Systems, Analyses and Planning

National Energy Technology Laboratory

www.netl.doe.gov
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Acknowledgements

The author would like to acknowledge the efforts of Steven Melzer (Melzer Consulting) and 

Donald Remson (U.S. DOE, NETL), who contributed greatly to the development of this report 

through their expert review of manuscript and underlying modeling approach and assumptions.
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i

Table of Contents

List of Tables..................................................................................................................................v

List of Figures............................................................................................................................... ix

Acronyms and Abbreviations..................................................................................................... xi

Executive Summary................................................................................................................ ES-1

1.0 Introduction........................................................................................................................1

1.1 Overview of CO2-Enhanced Oil Recovery Technology................................................. 1

1.2 Purpose of Study............................................................................................................. 2

1.3 Scope of Assessment....................................................................................................... 2

2.0 Life Cycle Assessment Methodology ................................................................................3

2.1 Assessment Methodology and Assumptions .................................................................. 4

2.1.1 Definition of System Boundary .............................................................................. 4

2.1.1.1 Cut-off Criteria for the System Boundary .......................................................... 6

2.1.1.2 Categorical Exclusions from the System Boundary ........................................... 6

2.1.1.3 Treatment of Secondary Material and Energy Inputs......................................... 6

2.1.2 Definition of Functional Unit.................................................................................. 7

2.1.3 Identification of Function ....................................................................................... 7

2.2 Geographic, Temporal, and Technological Representation............................................ 8

2.3 Life Cycle Assessment Indicators and Metrics............................................................... 9

2.3.1 Greenhouse Gases (GHGs)..................................................................................... 9

2.3.2 Criteria Air Pollutants............................................................................................. 9

2.3.3 Water Consumption .............................................................................................. 10

2.3.4 Land Use ............................................................................................................... 10

2.3.5 Net Energy Yield .................................................................................................. 10

2.4 Allocation Methodology ............................................................................................... 10

2.5 Other Modeling Assumptions....................................................................................... 11

3.0 General Description of CO2-EOR Technology..............................................................12

3.1 CO2-EOR Mechanisms and Methodologies ................................................................. 12

3.1.1 Minimum Miscibility Pressure Calculation.......................................................... 14

3.1.2 Water Alternating Gas (WAG) Tertiary Injection Scheme .................................. 16

3.1.2.1 Advanced Resources International Big Oil Fields Database ............................ 17

3.2 CO2-EOR as CO2 Geologic Sequestration Mechanism................................................ 18
ii

3.2.1 Retention vs. Sequestration in CO2-Flood EOR................................................... 18

3.2.1.1 CO2 Retention in CO2-EOR Operations........................................................... 19

3.2.1.2 CO2 Sequestration in CO2-EOR Operations..................................................... 20

3.3 Review of Relevant Literature ...................................................................................... 22

3.3.1 NETL Characterizations of CO2-EOR Economic and Technical Potential.......... 22

3.3.2 Literature Review of CO2-EOR Environmental Performance.............................. 29

3.4 CO2 Prophet CO2-EOR Screening Model..................................................................... 30

3.4.1 Summary of CO2 Prophet Screening Model......................................................... 31

3.4.1.1 Estimation of CO2-Flood Performance Using CO2 Prophet Screening Model. 35

3.4.2 Results of CO2 Prophet Runs for Individual Flood Pattern .................................. 39

3.5 Phases of CO2-EOR Facility Operation........................................................................ 55

3.5.1 Site Evaluation and Characterization.................................................................... 55

3.5.2 Facility Design and Construction.......................................................................... 56

3.5.2.1 CO2-EOR Facility Overview ............................................................................ 56

3.5.2.2 Overview of Site Preparation for CO2-Flood EOR........................................... 56

3.5.2.3 U.S. EPA UIC Injection Well Classes.............................................................. 57

3.5.2.4 Overview of New Brine Disposal Well Construction....................................... 58

3.5.2.5 Estimation of Brine Disposal Well Injectivity and Storage Capacity............... 58

3.5.2.6 Estimation of Brine Injection Wellhead Pressure............................................. 59

3.5.3 Well Drilling and Completion .............................................................................. 59

3.5.3.1 Drill Rig Description......................................................................................... 60

3.5.3.2 Wellbore Design ............................................................................................... 61

3.5.3.3 Cementing Operations ...................................................................................... 62

3.5.3.4 Rig Delivery and Rig Up .................................................................................. 62

3.5.3.5 Operation of Drill Rig....................................................................................... 63

3.5.3.6 Fluid Distribution and Gathering Lines............................................................ 70

3.5.4 Gas Processing Facility Construction ................................................................... 71

3.5.5 Facility Operation ................................................................................................. 72

3.5.5.1 Pattern-Year Concept........................................................................................ 72

3.5.5.2 CO2-EOR Fluid-Injection Operations.............................................................. 73

3.5.5.3 Production Operations ...................................................................................... 76

3.5.5.4 Produced Liquids Management: Satellite Separation and Tank Battery 

Operations......................................................................................................................... 79
iii

3.6 Crude Oil Storage ......................................................................................................... 86

3.6.1 Estimation of Crude Oil Storage Tank Losses...................................................... 86

3.7 Produced Water Tank CH4 Emissions Estimate ........................................................... 89

3.7.1 Venting/Flaring and Vapor Recovery................................................................... 90

3.7.1.1 Characterization of Vapor Recovery Unit Performance................................... 90

3.8 Desiccant Dehydrators.................................................................................................. 93

3.9 Gas Processing Facility Operation................................................................................ 94

3.9.1 Characterization of Ryan-Holmes CO2 Separation and NGL Recovery............... 95

3.9.1.1 Description of Model Facility Used in Characterization .................................. 95

3.9.1.2 Ryan-Holmes Process Stream Flow Calculations............................................. 96

3.9.1.3 Estimation of Produced Hydrocarbon Gas Composition.................................. 97

3.9.1.4 Gas Processing Facility Emissions Estimate .................................................... 98

3.9.1.5 Estimating Separation Efficiency of the Ryan-Holmes Process..................... 104

3.9.1.6 Displacement Credit for Energy Coproducts.................................................. 107

3.10 Facility Closure and Decommissioning...................................................................... 108

3.11 Plugging and Abandonment of Wells......................................................................... 109

3.11.1 Cementing Operations ........................................................................................ 109

3.12 Site Monitoring, Verification, and Assessment .......................................................... 110

4.0 Results and Discussion...................................................................................................111

4.1 Single CO2-EOR Well Pattern Performance............................................................... 111

4.1.1 CO2 Retention Performance of Single Well Pattern........................................... 112

4.1.2 CO2 Recovery in Historical Scenario ................................................................. 114

4.2 Life Cycle Performance .............................................................................................. 114

4.2.1 Greenhouse Gas Emissions................................................................................. 114

4.2.2 Criteria Air Pollutant Emissions......................................................................... 116

4.2.3 Land Use ............................................................................................................. 117

4.2.4 Water Use............................................................................................................ 118

4.2.5 Gross and Net Energy Yield ............................................................................... 119

4.3 Sensitivity Analysis .................................................................................................... 122

4.3.1 Parameters Considered in Sensitivity Analysis .................................................. 122

4.3.1.1 Global Warming Potential Multiplier............................................................. 123

4.3.1.2 CO2-EOR Scenario ......................................................................................... 123

4.3.1.3 Electricity Source............................................................................................ 124
iv

4.3.1.4 Vapor Recovery Efficiency............................................................................. 124

4.3.1.5 Phase I, II, IV and V Emissions...................................................................... 124

4.3.1.6 Fugitive Loss of Purchased CO2 ..................................................................... 124

4.3.1.7 Displacement Credit for Natural Gas and Natural Gas Liquid Co-Products.. 125

4.3.2 Discussion of Sensitivity Analysis Results......................................................... 125

5.0 Summary of Findings ....................................................................................................127

5.1 Next Steps................................................................................................................... 128

5.1.1 Gate-to-Gate Analysis of Alternative CO2-EOR Scenarios................................ 128

5.1.2 Cradle-to-Grave Life Cycle Analyses................................................................. 129

5.1.3 Other Life Cycle Assessment Considerations..................................................... 129

6.0 References.......................................................................................................................130

Appendix A: CO2 Prophet CO2-EOR Screening Model Definition of Relative Permeability 

Parameters..................................................................................................................... A-1

Appendix B: Cradle-to-Gate GHG Emissions Inventory for Electric Power from the 

ERCOT ISO Region Grid Mix .....................................................................................B-1

Appendix C: Raw Output from CO2 Prophet Model for Historical, Best Practices, and 1.5 

HCPV CO2 WAG CO2-EOR Scenarios. ..................................................................... C-1

Appendix D: United States Environmental Protection Agency AP-42 Emissions Factors for 

the Onshore Oil and Gas Industry .............................................................................. D-1

Appendix E: Summary Output form U.S. EPA TANKS Model of Oil Storage Tanks for 

Historical, Best Practices, and 1.5 HCPV CO2 WAG CO2-EOR Scenarios.............E-1

Appendix F: Drill Rig Specifications.......................................................................................F-1

Appendix G: Life Cycle Emissions Profile of 434-MWelectric (MWe) Existing PC FacilityG-1

Appendix H: Tabular Listing of Summary Data for Three Operational Scenarios..........H-1
v

List of Tables

Table ES-1 Summary Results for CO2 Enhanced Oil Recovery Life Cycle Analysis ............ ES-2

Table 2-1 Life Cycle Goal and Scope Definition for CO2-EOR Gate-to-Gate Environmental Life 

Cycle Assessment ................................................................................................................... 3

Table 2-2 Summary of Life Cycle Boundary and Representativeness of CO2-EOR Life Cycle 

Assessment.............................................................................................................................. 4

Table 2-3: Specifications for CO2 supplied to pipeline as reported in NETL Quality Guidelines 

for Energy System Studies...................................................................................................... 8

Table 2-4 Greenhouse Gases Included in Study Boundary ........................................................... 9

Table 2-5 Criteria Air Pollutants Included in Study Boundary ................................................... 10

Table 2-6 Higher Heating Values for Constituents of Gas Produced from CO2-EOR Activities 11

Table 3-1 Technical Screening Guidelines for CO2 Flooding..................................................... 13

Table 3-2 Simplified Representation of CO2-EOR Fluid Injection Schemes.............................. 17

Table 3-3 Definition of CO2-EOR Technology Scenarios and Data Sources Used in Evaluation 

of CO2-EOR Scenarios in Studies Previously Published by NETL ..................................... 25

Table 3-4 Summary of CO2-EOR Injection Scenarios as Defined in Previously Published 

Reports.................................................................................................................................. 26

Table 3-5: Economically Recoverable Oil and CO2 Sequestration Capacity in the Conterminous 

48 States and Alaska, Estimated Based on Stream-Tube Modeling of Best Practices and 

“Next Generation” CO2-EOR Scenarios............................................................................... 27

Table 3-6 Range of Electricity Use at CO2-EOR Fields by Source............................................. 28

Table 3-7 Summary of Characterizations of CO2-EOR GHG Performance Reported from Other 

Studies................................................................................................................................... 30

Table 3-8 Production Well to Injection Well Ratio for a Series of Common EOR Well Patterns

............................................................................................................................................... 33

Table 3-9 Fluid Parameter Values Used in Modeling of CO2-EOR Scenarios and Mean and 

Standard Deviation Values from ARI Database Permian Basin Reservoirs (n=228)........... 35

Table 3-10 Reservoir Parameter Values Used in Modeling of CO2-EOR Scenarios and Mean and 

Standard Deviation Values from ARI Database for Permian Basin Reservoirs................... 36

Table 3-11: Injection Schedule Parameters Used in Defining “Historical” Miscible CO2-flood 

EOR in the CO2 Prophet Screening Model........................................................................... 37

Table 3-12: Injection schedule parameters used in defining “best practices” miscible CO2-flood 

EOR in the CO2 Prophet screening model............................................................................ 37

Table 3-13 Injection Schedule Parameters Used in Defining 1.5 HCPV CO2 Miscible WAG 

EOR in the CO2 Prophet Screening Model........................................................................... 38

Table 3-14 Oil Recovery Efficiency (Percent of Original Oil in Place Recovered) as Estimated 

Based on CO2 Prophet Screening Model Characterization of Three WAG Scenarios......... 51
vi

Table 3-15 Summary of Model Results for Injection and Production Stream Fluid Flow 

Reported on a per Pattern Year Basis (40-Acre, 5-Spot Pattern Configuration).................. 51

Table 3-16 Emissions Profile from Abandoned Well Plugging Operations Reported per 40-Acre 

Pattern Year Based on Operational Scenarios Described Herein ......................................... 56

Table 3-17 Specifications Used to Characterize Drill Rig........................................................... 60

Table 3-18 Specifications Used to Characterize Injection Well: Casing, Injection Tubing, and 

Drill Pipe............................................................................................................................... 61

Table 3-19 Emissions Estimate for Delivery of Rig Elements to Drilling Site ........................... 62

Table 3-20 New Well Drilling Rig Performance Specifications................................................. 63

Table 3-21 Emissions Estimate for Drill Rig Operated in New Well Construction for Brine 

Disposal................................................................................................................................. 63

Table 3-22 Range of Water-Based Drilling Mud Composition as Reported by Eaton and 

Colleagues (1981), and Average Composition Assumed for Drilling Mud Usage 

Calculations........................................................................................................................... 64

Table 3-23 Estimated Mass of Drilling Mud and Mud Components, and Estimated Mass and 

Composition of Used Mud for Disposal ............................................................................... 65

Table 3-24 Estimation of Number of Well Workovers Required over the Life of CO2-EOR 

Pattern Operations for Each Operational Scenario ............................................................... 66

Table 3-25 Summary of Assumptions Made to Characterize Well Workover Prior to Initiation of 

CO2-EOR Flooding............................................................................................................... 66

Table 3-26 Emissions and Diesel Usage from Workover Rig Operation.................................... 67

Table 3-27 Estimate of Methane Fugitive Emissions from Well Workover over the Life of a 

Single Well Pattern for Each Operational Scenario Under Consideration ........................... 67

Table 3-28 Empirical Constants Used to Estimate Particulate Emissions from Unpaved Roads 68

Table 3-29 Summary of Particulate Emissions (Controlled) from Construction Traffic on 

Unpaved Roads, and Dust Suppression Water Consumption Rate per Pattern Year ........... 70

Table 3-30 Estimation of Mass of ANSI Schedule 80 Stainless Steel Pipe Required per 10 Well 

Patterns for CO2 Distribution................................................................................................ 71

Table 3-31: Estimate of Emissions Associated with Gas Processing Facility Construction 

Materials Upstream Profile ................................................................................................... 72

Table 3-32 Difference Between Cumulative Produced Injected Water (CO2 Prophet model 

results)................................................................................................................................... 74

Table 3-33 Estimated Total Electricity Demand Over the Life of CO2-EOR Flood Operations to 

Pressurize Brine for WAG Injection, Reported for a Single Well Pattern ........................... 75

Table 3-34 Summary of Parameters Used in Calculating CO2 Boost Compression Requirements, 

and Results of Calculation Reported on a per Pattern-Year Basis........................................ 76
vii

Table 3-35 Single Well Pattern Artificial Lift Estimate for CO2-EOR Scenarios Estimated Using 

ARI mMid-range Electricity Estimate of 5 kWh/bbl for Historical CO2-EOR and 10 kWh 

for Best practices and Next-Generation CO2-EOR Scenarios.............................................. 77

Table 3-36 Estimated Electricity Requirement for Artificial Lift for Single Well Pattern as 

Calculated Based on Estimated Artificial Lift Prime Mover Horsepower Requirement...... 78

Table 3-37 Process Element Assumptions Made in Characterization of CO2-EOR Produced 

Liquids Processing................................................................................................................ 80

Table 3-38 Assumptions Used in Estimation of Heater/Treater Firetube Heat Duty. In addition 

to these parameters, the flow of oil to the heater/treater was estimated for each year of CO2-

EOR activity based on the aggregated flow from 10 producing wells feeding a single tank 

battery ................................................................................................................................... 82

Table 3-39 Estimated Energy Requirement of Firetube Used To Heat Heater/Treater Servicing 

10 CO2-EOR Well Patterns................................................................................................... 83

Table 3-40 Estimated Combustion Emissions from Heater/Treater Firetube Operation for a Unit 

Servicing 10 Well Patterns Over the Life of the CO2-EOR Flood ....................................... 83

Table 3-41 Design Assumptions Used in Estimating Heater/Treater Vessel Working, Breathing, 

and Flashing Emissions......................................................................................................... 84

Table 3-42 Estimate of Working, Breathing, and Flashing Emissions from Heater/Treater Vessel 

That Are Collected to the Vapor Recovery Unit .................................................................. 85

Table 3-43 Specifications Used in Calculation of Well Tank Emissions.................................... 87

Table 3-44 Mass of Hydrocarbon Gas Released from Crude Storage Tank Over Lifetime of 10 

Pattern Tank Battery Operations (an estimated 95% of this vapor is collected by a VRU). 87

Table 3-45 Summary of Crude Oil Tank Emissions Estimate (working and breathing losses 

estimated using EPA Tanks model, flashing losses estimated using the Vasquez-Beggs 

equation) ............................................................................................................................... 88

Table 3-46 Methane Produced from Brine Storage Tanks and Collected by VRU or Released to 

Atmosphere—Reported on per Pattern-Year Basis (40-acre, 5-spot well pattern) .............. 89

Table 3-47 Summary of Vapor Recovery Unit Performance for Each Operational Scenario 

Considered, Reported on a per Pattern-Year Basis (40-acre, 5-spot patterns in all cases)... 91

Table 3-48 Summary of Tank Battery Vapor Composition for 2000 Btu/scf HHV Gas Collected 

by Vapor Recovery Unit ....................................................................................................... 92

Table 3-49 Parameter Values Used in eEstimation of Venting Emissions from Solid Desiccant 

Dehydration System.............................................................................................................. 93

Table 3-50 Summary of CO2-EOR Bulk Produced Gas (CO2 + hydrocarbon gas) Supplied to 

Gas Processing Facility......................................................................................................... 97

Table 3-51 Adjusted Average Composition of Hydrocarbon Gas Produced from the Permian 

Basin with API Gravity Between 32.5 ° and 37.5 °.............................................................. 98

Table 3-52 Summary of Combustion Equipment Used to Power Bas Processing Facility or 

Control Hydrocarbon Emissions......................................................................................... 100
viii

Table 3-53 Sources of Fugitive Emissions from Gas-Processing Facility ................................ 101

Table 3-54 Gas-Processing Facility Storage Tank Volumes..................................................... 101

Table 3-55 Gas-Processing Plant Engine Combustion .............................................................. 102

Table 3-56 Estimation of Gas Processing Facility Emissions................................................... 103

Table 3-57 Ryan/Holmes Process Influent Gas and Effluent Vapor and Liquid Molar Flow Rates 

(moles/hr)............................................................................................................................ 104

Table 3-58 Calculated Gas Separation Efficiency of Ryan-Holmes Process (percent mass)..... 105

Table 3-59 Estimate of Mass Allocation of Each Influent Gas Constituent Fraction Between 

Products of the Gas Processing Facility.............................................................................. 105

Table 3-60 Average Mass Composition of Gas Recycled to CO2-EOR Operations................. 106

Table 3-61 Estimation of Natural Gas and Natural Gas Liquids Production from Ryan-Holmes 

Process ................................................................................................................................ 106

Table 3-62 Mass of Constituents Separated from CO2-EOR Recycle Stream Through RyanHolmes Process................................................................................................................... 107

Table 3-63 Displacement Credit for Natural Gas Liquid Coproducts of Oil Production in CO2-

EOR Estimated as the Average of Domestic Refinery Light Ends and NGLs Produced at a 

Gas-Processing Plant .......................................................................................................... 108

Table 3-64 Summary of Cement Pumping Specifications for Well Plugging Operations......... 109

Table 3-65 Emissions from Cementing Truck Deck Engines Reported on a Per-Pattern Basis 

(two wells per pattern) ........................................................................................................ 110

Table 4-1 Summary of CO2-EOR Flood Performance for the Operational Scenarios Defined 

Herein, and Predicted Using the CO2 Prophet Stream-tube Model.................................... 111

Table 4-2 Summary of Single Pattern CO2 Retention Performance. In all operational scenarios, 

75 percent of maximum CO2 storage potential is realized in the first third of flood operation.

............................................................................................................................................. 113

Table 4-3 Estimated Acres of Land Disturbed by CO2-EOR Activity per Barrel of Oil Produced

............................................................................................................................................. 118

Table 4-4 Selected Parameters Used in Sensitivity Analysis of Gate-to-Gate Life Cycle GHG 

Emissions Performance of CO2-flood EOR Operations..................................................... 123

Table 4-5 GHG Constituents Considered Through Sensitivity Analysis Emissions Included in 

Study Boundary and Their 100-year Time Horizon GWP Factors..................................... 123
ix

List of Figures

Figure ES-1 Recovery versus GHG Emissions for CO2-EOR Operational Scenarios............ ES-3

Figure ES-2 CO2 Retained (Metric Tonne CO2) in (a) and Incremental Oil Production 

(MSTB/yr) from (b) a Single 40-Acre, Five-Spot Pattern for Three Operational Scenarios

........................................................................................................................................... ES-4

Figure 1-1 Summary of the Distribution of CO2-EOR Operations in the United States, Reported 

in Barrels of Crude Oil Produced per Day.............................................................................. 1

Figure 2-1 Simplified System Boundary for Operation Phase of “Gate-to-Gate” Life Cycle 

Assessment of CO2-Based Enhanced Oil Recovery. Dotted line indicates study boundary. 5

Figure 3-1 Plot of Cronquist Correlation for a Series of C5+ Molecular Weight Values over the 

Range of Temperatures from 75 to 275 °F ........................................................................... 14

Figure 3-2 Example of Oil Recovery Efficiency vs. CO2 Injection (assumes homogeneous 

reservoir). Sweep Efficiency in Reservoir Pore Volumes (RVPs) of Miscible CO2-EOR 

Flood Increases with Increasing Hydrocarbon Pore Volume (HCPV) Injection.................. 15

Figure 3-3 Tertiary Oil Recovery Increases with Increasing CO2, But Also Increases the 

Required Duration of the CO2 Injection Before Recovery Drops Off.................................. 16

Figure 3-4 Illustration of Several Well Geometries Commonly Used for Enhanced OilRecovery

............................................................................................................................................... 32

Figure 3-5: Surface Area of a 5-Spot Well Pattern and Portion Simulated in Prophet Model.... 34

Figure 3-6 Incremental Water Injection Schedule for WAG Injection Scenarios (MSTB 

water/year) ............................................................................................................................ 40

Figure 3-7: Incremental CO2 Injection Schedule for WAG Injection Scenarios (MMscf 

CO2/year) .............................................................................................................................. 41

Figure 3-8 Cumulative CO2 Injection Profile for WAG Injection Scenarios (MMscf)............... 42

Figure 3-9 Cumulative Water Injection Profile for WAG Injection Scenarios (MSTB)............. 43

Figure 3-10 Cumulative Oil Production Profile for WAG Injection Scenarios (MSTB)............ 44

Figure 3-11 Cumulative Water Production Profile for WAG Injection Scenarios (MSTB) ....... 45

Figure 3-12 Cumulative CO2 Production Profile for WAG Injection Scenarios (MMscf) ......... 46

Figure 3-13 Incremental Oil Production for WAG Injection Scenarios (MSTB/yr)................... 47

Figure 3-14 Incremental Water Production for WAG Injection Scenarios (MSTB/year). Dotted 

line in historical CO2-EOR scenario represents brine production response after initiation of 

water slug.............................................................................................................................. 48

Figure 3-15 Incremental CO2 Production for WAG Injection Scenarios (MMscf/year)............. 49

Figure 3-16 Incremental Hydrocarbon Gas Production for WAG Injection Scenarios (HCPVs)50

Figure 3-17 Incremental Oil Production Data from 10 Well Patterns Operated Under Three 

WAG Scenarios, with Injection Initiated at Six-Month Intervals for Each Pattern 

(MSTB/year)......................................................................................................................... 53
x

Figure 3-18 Incremental Water Production Data from 10 Well Patterns Operated Under Three 

WAG Scenarios, with Injection Initiated at Six-Month Intervals for Each Pattern 

(MSTB/year)......................................................................................................................... 54

Figure 3-19 CO2-PM Model Established a Peak Total Gas Production Threshold of 20 

MMscf/day Above Which a CO2-EOR Operation Was Assumed to Require Construction of 

a Dedicated Gas Processing Facility..................................................................................... 94

Figure 4-1 CO2 retained in a single 40-acre, five-spot CO2-EOR pattern for the three described 

operational scenarios. Retention is greatest in early years of flood operation. Water slug 

applied after WAG in the historical scenario recovers about 23 percent of stored CO2, by 

mass..................................................................................................................................... 112

Figure 4-2 Mass of CO2 Sequestered per 40-Acre, Five-Spot as a Function of the Mass of CO2

Injected. Additional storage benefit decreased with increasing CO2 injection.................. 113

Figure 4-3 Summary of Life Cycle Greenhouse Gas Emissions Associated with Each Phase of 

CO2-EOR Activity, Reported in Units of Metric Tonnes of CO2-Equivalent Generated per 

Barrel of Oil Produced........................................................................................................ 115

Figure 4-4 Total Gate-to-Gate Life Cycle Emissions for Each Operational Scenario and Total 

CO2 Sequestered Through CO2-EOR Activity (both reported per barrel of oil produced) 116

Figure 4-5 Summary of Criteria Air Pollutant Emissions Associated with Each Phase of CO2-

EOR Activity for the Best Practices Operational Scenario, Reported in Units of Metric 

Tonnes of Pollutant Generated per Barrel of Oil Produced................................................ 117

Figure 4-6 Water Consumption Associated with Each Phase of CO2-EOR Activity for Each 

Operational Scenario (barrels of water consumed per barrel of oil produced)................... 119

Figure 4-7 Gross Hydrocarbon Products Generated per 40 Acre Well Pattern in Each CO2-EOR 

Operational Scenario (barrel of oil equivalents per 40 acre pattern).................................. 120

Figure 4-8 Net Hydrocarbon Products Generated per 40-Acre Well Pattern in Each CO2-EOR 

Operational Scenario (barrel of oil equivalents per 40 acre pattern). Bars below zero on the 

ordinate represent natural gas that is purchased to meet energy requirements of CO2-EOR 

operations............................................................................................................................ 121

Figure 4-9 Energy Consumed per Unit of Crude Produced for Three CO2-EOR Operational 

Scenarios............................................................................................................................. 122

Figure 4-10 Tornado Plot Summarizing Impact of Varying Select Model Input Parameter Values 

Away from Base Case Assumptions................................................................................... 126
xi

Acronyms and Abbreviations

AEO Annual Energy Outlook (Energy Information Agency)

API American Petroleum Institute

bbl Barrel

Btu British thermal unit

CCS Carbon capture and storage

cf Cubic feet

CH4 Methane

CO Carbon monoxide

CO2 Carbon dioxide

CO2E Carbon dioxide Equivalent

DOE Department of Energy

EIA Energy Information Administration

EOR Enhanced Oil Recovery

EPA Environmental Protection Agency

GHG Greenhouse gas

GOR Gas Oil Ratio (usually mcf/bbl [surface conditions])

GS Geologic sequestration

GWP Global warming potential

HCPV Hydrocarbon pore volume (subsurface conditions)

HHV Higher heating value

IISI International Iron and Steel Institute

IPCC Intergovernmental Panel on Climate Change

ISO International Organization for Standardization

kg Kilogram

kW Kilowatt

kWh Kilowatt-hour

lb Pound

LCA Life cycle assessment

LCI Life cycle inventory

Mbbl Thousand barrels 

Mcf Thousand cubic feet
xii

MJ Megajoule

MMBtu Million Btu

MMP Minimum miscibility pressure

MMscf Million standard cubic feet (surface conditions)

MMscfd Million standard cubic feet per day (surface conditions)

MMscfy Million standard cubic feet per year (surface conditions)

MMmt

MPa

Million metric tonnes

Megapascal

MVA

MSTB

Monitoring, verification, and accounting

Thousand standard barrels

MWh Megawatt-hour

N2O Nitrous oxide

NETL National Energy Technology Laboratory

NG Natural gas

NGL Natural gas liquid

NOX Nitrogen oxides

OOIP Original Oil in Place

OSAP Office of Systems and Planning

PM Particulate matter

ppm Parts per million

ppmv Parts per million by volume

Psi Pounds per square inch 

Psia Pounds per square inch, absolute

Psig Pounds per square inch, gauge 

RPV Reservoir pore volume (subsurface conditions)

scf Standard cubic feet (surface conditions)

scfd Standard cubic feet per day (surface conditions)

SDW Saltwater disposal well

SOX Sulfur oxides

STB Standard barrel (surface conditions)

THC

UF

Total hydrocarbons

Utilization factor
xiii

UIC Underground Injection Control

U.S. United States

USDW Underground source of drinking water

VMT

VOC

Vehicle mile traveled

Volatile organic compound

WAG Water-alternating-gas
ES-1

Executive Summary

Tertiary recovery of crude oil via carbon dioxide (CO2) flooding, first employed more than thirty 

years ago in the Permian Basin of West Texas as a niche application, now represents 

approximately five percent of domestic crude production. In addition to stimulating oil 

production, CO2 enhanced oil recovery (CO2-EOR) also stores a portion of the injected CO2, 

with the remaining fraction recovered for use in other EOR operations. This technology has the 

potential to grow in the future as the market price of crude oil increases and climate policies 

provide financial incentive for capturing and sequestering CO2. However, CO2-EOR operations 

are relatively energy intensive and have high associated emissions because of the need to 

produce, process, and re-inject produced CO2 and brine. 

This study estimates that current CO2-EOR “best practices” (water-alternating-gas [WAG]

injection in a typical Permian Basin reservoir) generate greenhouse gas (GHG) emissions of 71 

kg CO2 equivalents (CO2E) per barrel of oil extracted - a value nearly three times higher than the 

average GHG emissions for domestic oil extracted in 2005 of 24 kg CO2e per barrel (NETL, 

2009). In this “best practices” case, 53 percent of the total GHG emissions associated with CO2-

EOR activity result from processing of produced gas to separate CO2 from the flashed light 

hydrocarbon fraction (glycol dehydration with Ryan-Holmes type distillative separation), while 

41 percent of GHG emissions result from CO2 compression. The processes to separate brine 

from produced crude and to pump the brine for re-injection each account for less than 3 percent

of total GHG emissions. 

Table ES-1 summarizes the results of the gate-to-gate life cycle assessment of three CO2 EOR 

operational scenarios. Under current “best practices” 2.5 times more CO2 is injected than in the 

historical case, and a high CO2 injection scenario considers performance with 50 percent more 

CO2 injected than in “best practices.” These results show that the amount of CO2 stored per 

barrel of crude oil produced is highest in the “best practices” case and lower in the high CO2

injection scenario. 
ES-2

Table ES-1 Summary Results for CO2 Enhanced Oil Recovery Life Cycle Assessment

CO2-EOR Operational Scenario Historical Current Best 

Practices

High CO2

Scenarioa

CO2 injection duration (single pattern, 

years) 7 25 36

Volume of CO2 injected as a percent of the 

hydrocarbon pore volume in the target 

formationb

0.4 1.0 1.5

Oil recovery as a percent of original oil in 

place (OOIP) 12% 17% 21%

Percent of injected CO2 recycledc 60% 71% 78%

CO2 stored per barrel of oil produced (kg 

CO2/bbl oil)c 200 230 210

GHG emissions per barrel of oil produced 

(kg CO2e/bbl oil)c 51 71 95

a Assumes (1) improved technologies that enable more efficient contact between CO2 and residual oil and (2) 

policy incentives for sequestering CO2

b Hydrocarbon pore volume (HCPV) is the pore volume in a reservoir initially filled with oil, and is often used to 

describe in-formation fluid volumes and discuss normalized performance between reservoirs. HCPV is 

calculated as ΣA*h*φ*(1−Swi) where: A = surface area (40 acres), h = pay thickness (76 ft.), φ = porosity 

(0.11), and Swi = initial oil saturation as fraction (0.8)

c Values are average over the duration of the flood.

Results derived from single injection well modeling of a 40 acre 5-spot tapered WAG injection in a typical 

formation in the Permian basin, using the CO2 Prophet model.

Figure ES-1 illustrates the relationship between crude oil recovery and average GHG emissions 

for the three CO2-EOR scenarios. GHG emissions increase as oil recovery increases from 12

percent in the historical case, to 17 percent in current “best practices,” and to 21 percent in the 

high CO2 case. This increase is greater between “best practices” and high CO2 cases (as 

indicated by a steeper slope) than between historical and current “best practices” scenarios 

because greater energy is expended to recover less incremental oil as higher volumes of CO2 are 

applied, processed, and re-injected.
ES-3

-

Figure ES-1 Recovery versus GHG Emissions for CO2-EOR Operational Scenarios

Figure ES-2 reports cumulative CO2 sequestration and incremental oil production over the life of 

a CO2 flood, for the three cases considered; these are pattern-level stream tube model results. 

The figure shows that most of the CO2 storage and the highest rates of oil production occur in the 

early years of the flood. In the historical case, WAG injection is followed by an eleven-year 

period of water injection to recover remaining mobile oil; as a result of this water injection, CO2

is displaced from the formation and cumulative CO2 storage decreases below peak storage in 

year eight by 23 percent. In contrast, best practices and high CO2 cases continue the WAG 

injection until the end of the flood and cumulative storage increases throughout the flood 

duration in these cases. In practice, the decision to terminate flooding is an economic decision 

based on crude sale price, operational energy costs, and CO2 purchase price.

historical

best 

practices

high CO2

0

10

20

30

40

50

60

70

80

90

100

0% 5% 10% 15% 20% 25%

GHG Emissions ,

kg CO2e/bbl produced, avg

Oil Recovery, incremenal production / OOIP
ES-4

Figure ES-2 CO2 Retained (Metric Tonne CO2) in (a) and Incremental Oil Production 

(MSTB/yr) from (b) a Single 40-Acre, Five-Spot Pattern for Three Operational Scenarios
ES-5

Future efforts will leverage results of this focused “gate-to-gate” assessment with 

characterizations of fossil energy extraction and conversion technologies developed by the 

National Energy Technology Laboratory (NETL) to assess the full “cradle-to-grave” 

performance of composite energy systems in which CO2-EOR is used as a geologic sink for CO2

emissions (e.g., pulverized coal combustion with CO2 capture and sequestration through CO2-

EOR). Also, the methodology used for estimation of Permian Basin WAG injection will be 

applied to estimate “gate-to-gate” CO2-EOR performance of next-generation WAG CO2-EOR 

technologies that improve contact between CO2 and remaining oil, straight CO2 flooding EOR as 

is practiced in the Gulf Coast Basin, and other variations on the CO2-EOR technology paradigm.
1

1.0 Introduction 

1.1 Overview of CO2-Enhanced Oil Recovery Technology

This study is focused on assessing environmental life cycle performance of domestic, on-shore,

CO2-miscible1

 

Texas, 161,324

Wyoming, 20,240

Utah, 3,400 Michigan, 641

Mississippi, 17,780

New Mexico, 14,450

Colorado, 11,600

Oklahoma, 10,875 Louisiana, 0

Kansas, 3.3

WAG-type enhanced oil recovery operations. CO2-miscible operations account 

for the vast majority of currently producing and planned CO2-EOR operations in the United 

States; the Oil & Gas Journal 2010 Worldwide EOR Survey lists 106 producing CO2-miscible 

EOR projects (with total enhanced production of approximately 253,000 barrels per day) and 

only 5 CO2-immiscible projects (with total enhanced production of approximately 9,300 barrels 

per day), accounting for less than four percent of all domestic CO2-EOR (Koottungal, 2009). 

Figure 1 illustrates that approximately 67 percent of all crude produced in the United States by 

CO2-miscible EOR is generated in Texas, and approximately 74 percent of that is produced from 

the San Andres pay zone, Permian Basin (Koottungal, 2009). 

Figure 1-1 Summary of the Distribution of CO2-EOR Operations in the United States, 

Reported in Barrels of Crude Oil Produced per Day

Recent publications by the U.S DOE NETL indicate that significant potential remains for 

domestic incremental oil production from tertiary CO2-flood EOR, with an estimated 45.0 billion 

barrels of additional stranded oil accessible using current CO2-EOR “best practices,” and a 

potential 64.4 billion barrels accessible using “next generation” EOR technology and practices. 

In addition to this estimated total incremental production, the NETL studies report that 

implementation of these technologies has the potential to sequester significant quantities of CO2

in these reservoirs: 12,451 million metric tonnes using “best practices” and 14,477 million 

metric tonnes using “next generation” technology options. 

 

1 “Miscibility” refers to the property of two fluids to form a single homogeneous phase when mixed in any 

proportion. Miscibility of two fluids is observed in a given range of temperatures and pressures, outside of which 

they will, at some proportion, exist as two discrete phases.
2

1.2 Purpose of Study

This study is intended to provide a detailed, bottom-up life cycle inventory of CO2-flood 

enhanced oil recovery (CO2-EOR) operations, considering all associated significant 

infrastructure elements, process flows, and activities. The assessment is based on an inventory 

of all phases of activity for model CO2-EOR operations, and all of the environmental burdens 

attributed to each phase of CO2-EOR activity are summed to estimate a total environmental 

burden of producing crude oil through CO2-EOR. Natural gas and natural gas liquid co-products 

are accounted for by applying a credit equivalent to the upstream emissions profile of a product 

with equivalent function that is available to the market from another source.

In addition, this study is intended to develop an improved understanding of CO2-EOR 

performance with respect to oil production, geologic CO2 storage potential, and environmental 

performance under different operational scenarios. Results of this “gate-to-gate” analysis can be 

integrated with characterizations of other unit processes (e.g., petroleum refinery or integrated 

gasification combined cycle inventories) to generate full “cradle-to-grave” assessments of 

various energy conversion pathways.

Whether used as a stand-alone tool for assessment of CO2-EOR performance or integrated into a 

larger, cradle-to-grave life cycle assessment (LCA) of fossil energy conversion pathways, the 

product developed as a result of this effort is intended to inform policy decision makers, industry 

representatives, and managers of research programs about environmental costs and benefits 

associated with application of this technology. This effort has also been useful to identify areas 

where available data are insufficient to accurately estimate related resource demands or 

environmental emissions and focus future data collection efforts. 

1.3 Scope of Assessment

The scope of this assessment focused on characterizing the environmental performance of all 

phases of CO2-EOR, including (1) site evaluation and characterization, (2) facility design and 

construction, (3) facility startup and operation, (4) facility closure and decomissioning, and (5) 

monitoring, verification, and assessment of CO2 storage permanence. To the extent practicable, 

all significant material and energy flows have been considered for primary activities associated 

with implementation of tertiary CO2-EOR at a reservoir with prior primary oil production, and 

secondary water flood EOR activity. As such, many of the infrastructure elements and activities 

that would be associated with greenfield development of oil production facilities are assumed to 

be pre-existing. Justification is provided throughout for all such modeling assumptions.
3

2.0 Life Cycle Assessment Methodology

Factors considered in establishing appropriate scope and goals for this assessment include (1) 

establishing the purpose of conducting the study and its intended audience and application; (2) 

defining the systems being evaluated; (3) identifying the common function and functional unit;

(4) defining an appropriate system boundary; (5) summarizing allocation procedures; (6) 

identifying data requirements (type and quality); (7) summarizing the modeling assumptions, 

value choices, and optional elements; (8) acknowledging the study limitations, and (9) 

summarizing quality assurance and review procedures.

Table 2-1 Life Cycle Goal and Scope Definition for CO2-EOR Gate-to-Gate Environmental 

Life Cycle Assessment

General Question Specific Goal

Study purpose

To develop life cycle inventory of CO2-flood enhanced oil recovery (CO2-

EOR) operations and use that inventory to develop analysis of 

environmental performance of this CO2 management alternative

Intended audience

Life cycle practitioners interested in evaluating environmental 

performance of CO2-EOR potential as applied to storage of anthropogenic 

CO2 and stimulation of incremental oil production

Intended level of 

assessment detail

This LCA was developed to meet Level II (standard) level of detail per the

three-tiered scale defined in established NETL LCA guidelines

Intended application

This LCA is intended for use to allow relative comparison of gate-to-gate 

environmental performance of different CO2-EOR operational scenarios, 

and for integration into full cradle-to-grave life-cycle analyses associated 

with CO2-producing energy conversion processes
4

Table 2-2 Summary of Life Cycle Boundary and Representativeness of CO2-EOR Life 

Cycle Assessment

Life Cycle Boundary Gate-to-gate (receipt of purchased CO2 thru crude oil 

delivery to sales pipeline)

Temporal Representation 30 years of CO2-EOR active operations to sequester CO2

from one industrial-scale anthropogenic CO2 source

Technological Representation Tertiary, miscible, CO2 water alternating gas-type EOR 

flood 

Geographical Representation Typical Permian Basin (West Texas) reservoir properties 

assumed

Impact Assessment Methodology Global Warming Potential, IPCC 2007, 100-year timeframe

Reporting Metric Mass of CO2E emitted per barrel of oil produced 

Data Quality Objectives

Process-based (“bottom-up”) modeling approach

Full transparency of modeling approach and data 

sources 

Accounting for 99% of mass and energy, and accounting 

for 99% of environmental relevance (see discussion of 

cut-off criteria limitations) 

2.1 Assessment Methodology and Assumptions

2.1.1 Definition of System Boundary

The boundary considered in this study is “gate-to-gate,” meaning that the activity being 

considered is the use of delivered pipeline-quality CO2 at the EOR project location through 

delivery of produced crude to a sales point at the lease boundary. Because petroleum is not 

permitted to enter a pipeline without meeting minimum specifications, any activities, 

infrastructure, or material requirement associated with upgrading the petroleum-to-pipeline 

quality are considered to be within the study boundary. 

This system boundary is considered to be in line with the stated goal of this study: to develop a 

more detailed characterization of process energy and material flows and infrastructure 

requirements associated with CO2-based enhanced oil recovery. Performance of these operations 

is independent of the source from which the CO2 was taken and the distance from which CO2 is 

delivered, and these upstream activities are, therefore, excluded from this gate-to-gate analysis. 

As is detailed in subsequent sections, CO2 injection is alternated with water injection in water 

alternating gas (WAG)–type CO2-EOR flood. For purposes of this study it is assumed that brine 

produced from this or adjacent EOR floods serves as the source of water used to stimulate 

production. As such, it has been assumed that no additional surface/ground water extraction is 

needed to supply the demand for water created by the WAG injection. Disposal of produced 

brine in excess of that which is used to supply the WAG will be required. This is discussed in 

more detail in subsequent sections. Figure 2-1 provides a simplified schematic of the major 

process elements associated with the CO2-EOR operation phase and establishes the LCA

boundary for this system.
5

Figure 2-1 Simplified System Boundary for Operation Phase of “Gate-to-Gate” Life Cycle Assessment of CO2-Based 

Enhanced Oil Recovery. Dotted line indicates study boundary.
6

2.1.1.1 Cut-off Criteria for the System Boundary

A common approach employed in the field of LCA to limit the study boundary is to forego the 

consideration of minor (secondary, tertiary, etc.) activities and flows if their contribution to the 

overall life cycle falls below a practical limit. Generally such limits are established based on the 

contribution of those minor elements to the estimated overall incremental change associated with 

the life cycle of a unit process (for example, limits are commonly set based on accounting for 99

percent of all energy inputs, mass flows, and/or economic activity). However, without fully 

accounting for all flows and activities associated with a life cycle, it is not possible to identify the 

appropriate full life cycle value on which threshold “cut off” values are based. As such, 

establishing cut off criteria can, at best, serve as a guide to the life cycle practitioner who is 

attempting to determine if a system has been sufficiently described (Johnson, et al., 

forthcoming). 

The decision to include or exclude unit processes or material/energy flows should preferably be 

based on coherent, transparent justification of reasons for which specific elements have been 

omitted or included. This justification may be based on consideration of the marginal increase in 

activity external to the described system, as might be performed through consequential economic 

input/output-type boundary analysis. However, for the purposes of this study and the relative 

comparison of different CO2-EOR operational scenarios, such a boundary analysis is considered 

to be unnecessary and attributional; a process-based LCA guided by engineering judgment-based 

cut-off thresholds is considered to be sufficient. 

General cut-off threshold guidelines used in developing this LCA include the following: (1) A

significant material input or output is considered to be a material that has a mass greater than 

0.01 gram (g) per g (one percent, by mass) of the principal product that is produced by the 

corresponding unit process. (2) A material may also be determined to be significant if it has a 

relatively high cost (e.g., compared to the cost of the largest, by mass, material input) or has an 

important environmental relevance (e.g., a high global warming potential [GWP]). (3) A 

significant energy input is defined as one that contributes more than one percent of the total 

energy used by the corresponding unit process. As with materials, a significant energy input is 

also one that has a relatively high cost or has an important environmental relevance.

2.1.1.2 Categorical Exclusions from the System Boundary

Human Activity. There are a number of human activities performed that indirectly contribute to 

enhanced oil recovery operations (e.g., commuting to and from work, worker water consumption 

and utilization, etc.) and could be considered to be within the previously-described system 

boundary. These activities have not been taken into account in the life cycle inventory described 

herein. Catastrophic Releases. In contrast to regular or common losses of material or energy 

that may be inherent to enhanced oil recovery (e.g., material loss during transport or fugitive 

losses), events occurring with low temporal frequency but with high potential associated 

emissions and/or environmental impact (e.g., non-routine accidental releases) are excluded from 

consideration in this study.

2.1.1.3 Treatment of Secondary Material and Energy Inputs

The life cycle inventory of CO2-EOR includes consideration of all significant material and 

energy resources contributing to the overall process life cycle, tracking these flows back to the 
7

point of extraction from the earth (to “elemental flows” in LCA terminology). Therefore, 

secondary material and energy inputs such as concrete and steel for facility construction or grid 

electricity for pump operation have been taken into account in order to develop a complete 

inventory of all life cycle resource demands. Cradle-to-gate environmental profiles have been

taken from other life cycle inventory databases and reports in order to appropriately characterize 

these secondary materials and energy inputs.

2.1.2 Definition of Functional Unit

ISO 14040: 2006 (E) defines functional unit as the “quantified performance of a product system 

for use as a reference unit,” a definition further clarified in ISO 14041 and ISO/TR 14049:2000 

(E). ISO 14041 states that, when defining the functional unit in an LCA, the practitioner must 

bear in mind the stated goal and scope of the study. Furthermore, the functional unit is used to 

provide a reference to which input and output data are normalized, requiring that the functional 

unit be clearly defined and measurable and that the performance characteristics of the product be 

specified explicitly. The amount of product required to fulfill the function needs to be 

quantified—a value referred to as the “reference flow.” ISO/TR 14049:2000 (E) gives further 

clarification by outlining the following steps to be taken in defining a functional unit and 

reference flows: “identifications of functions, selection of functions and definitions of functional 

unit, and identification of performance of the product and determination of the reference flow.”

2.1.3 Identification of Function

The primary function of CO2-EOR operations is the enhanced recovery of oil from underproducing or non-producing target oil-bearing formation(s), with geologic sequestration of CO2

considered to be a secondary function. That is to say, construction and operation of CO2-EOR 

facilities are driven, at present, by the opportunity to produce salable oil (and, to a lesser extent, 

other hydrocarbon gasses and liquids) with operations not focused on maximizing CO2 storage

capacity. In contrast, sequestration of CO2 in brine aquifers would be carried out with the sole 

function of preventing release of anthropogenic CO2 to the atmosphere, with no salable product 

generated from such operations. 

The functional unit that has been adopted is sequestration of CO2 captured from 30 years of 

operations from one thermoelectric generation facility, and sequestration for a period of 100 

years (that CO2 which has been delivered to the injection site, injected over a period of 30 years, 

and remains geologically sequestered 100 years after initial injection). 

For purposes of this study, CO2-EOR operations have been scaled to be of sufficient size to 

accept CO2 from an existing pulverized coal plant that has been retrofitted with amine-based 

capture. The plant performance profile is taken from a forthcoming cradle-to-grave life cycle 

environmental performance and cost analysis (US DOE NETL, 2010) that is based on a previous 

systems analysis of the carbon capture retrofitting of the Conesville, Illinois, plant, entitled 

Carbon Dioxide Capture from Existing Coal-Fired Power Plants (US DOE NETL, 2007b). This 

plant has a single 430-MWe subcritical boiler that fires Midwestern bituminous coal, and has 

been in commercial operation for more than 30 years. From the boiler, flue gas is cooled and 

sent to an electrostatic precipitator and a 94.9 percent efficient lime-based flue gas 

desulfurization system. In the case employed for the present study, the existing pulverized coal 

(PC) -fired plant has been retrofitted with an amine-based CO2 scrubbing process. After 

accounting for the auxiliary power parasitic load, the energy requirements of the CCS system, 

and a seven percent electricity transmission loss, the net power delivered by the plant was 
8

calculated as 336 (megawatt of electricity) MWe (US DOE NETL, forthcoming). Performance

of this existing PC plant with retrofit capture system is not included within the gate-to-gate life 

cycle inventory of CO2-EOR operations. The flowrate of separated CO2 stream estimated from 

this study has been used to estimate the amount of CO2 that would be supplied to CO2-EOR 

operations from a moderately sized coal fired facility with post combustion capture, and to 

estimate the scale of CO2-EOR activity that would be required to accept this volume of CO2. In 

all cases, results have been normalized with respect to barrels of oil produced so that the scale of 

operations is factored out in final reporting.

Per NETL Quality Guidelines for Energy System Studies (McGurl, et al., 2004), “CO2, whether 

being sold for chemical processing or being sequestered, is to be supplied as a liquid and must 

meet the pipeline specification” as shown in Table 2-3. Boosting or reduction of pressure may 

be required prior to injection into the receiving formation.

Table 2-3: Specifications for CO2 supplied to pipeline as reported in NETL Quality 

Guidelines for Energy System Studies

Parameter Value

Pressure 152 bar (2,200 psi)

Water Content 233 K (-40 deg F) dew point

N2 <300 ppmv

O2 <40 ppmv

Ar <10 ppmv

 Referenced from McGurl, et al. (2004)

2.2 Geographic, Temporal, and Technological Representation

This LCA considers CO2-EOR activity that is limited to oil fields that have been depleted 

through primary production and repressured through subsequent secondary water flood enhanced 

oil recovery prior to initiation of tertiary recovery through CO2 WAG injection. Because 

performance is a function of site-specific reservoir properties, fluid characteristics, infrastructure 

configuration, and injection conditions, it was also necessary to establish these parameters 

explicitly in order to develop a credible estimate of flood performance. As described in 

subsequent sections, parameter values were selected that are representative of a typical Permian 

Basin–type miscible CO2 flood scenario, although the values do not correspond to a specific realworld EOR reservoir. Evaluation of CO2-flood EOR performance in target reservoirs with 

different parameter values would require re-evaluation based on a revised prediction of flood 

performance. Alternatively, real, detailed, and site-specific flood performance from an existing 

CO2-EOR flood could be used to develop an inventory performance evaluation. 

Six life cycle stages are considered by NETL in full, “cradle-to-grave” LCAs of energy products: 

raw material acquisition, raw material transport, energy conversion, product transport, product 

use, and end-of life management. For the purposes of this assessment of CO2-EOR, a limited 

“gate-to-gate” scope is considered, focusing on development of a relatively detailed bottom-up 

characterization of activity associated with management of CO2 that is generated as a 

concentrated stream co-product of the third life cycle stage, energy conversion (e.g., a coal-fired 

thermoelectric generation facility). Because this study considers a limited scope, the specific 

process by which the CO2 is generated is not significant and can be omitted from the 

comparative assessment of different CO2-EOR operational scenarios. CO2-EOR is considered to 
9

be a well established and relatively mature technology. CO2-EOR technology represented 

includes tapered WAG injection using a 40-acre five-spot pattern configuration with an 

injection:production well ratio of 1:1. Produced liquid processing is assumed to take place at 

satellite gathering facilities (aerially distributed tank batteries, separation, and metering points) 

that process fluid generated from 10 production wells. Gas processing characterization is based 

on gas stream dehydration and subsequent distillation to separate hydrocarbon from CO2 stream 

before recycling to EOR injection wells. Excess brine is disposed of in brine disposal wells. For 

all unit operations, an assumption has been made that current technology is representative of 

future operations. However, scenarios have been considered with different applications of those 

unit operations to represent historical, current best-practices, and high-CO2 injection CO2-EOR 

scenarios, as described in detail in subsequent sections. The assessment assumes relatively 

large-scale implementation of CO2-EOR to facilitate the sequestration of large flows of CO2 that 

would be generated from capture and sequestration of CO2 from a single coal-fired 

thermoelectric generation facility over a 30-year time frame. 

2.3 Life Cycle Assessment Indicators and Metrics 

A suite of five indicators of life cycle performance have been adopted for characterization of 

technology or policy options: GHG emissions, criteria air pollutants, water use 

(withdrawal/consumption), and net energy yield. Following is a brief summary of each.

2.3.1 Greenhouse Gases (GHGs)

Table 2-4 lists the primary GHGs and their corresponding GWP reported in mass of CO2

equivalents from the Intergovernmental Panel on Climate Change (IPCC) 2007 documents. 

These values have been adopted for all estimates of global warming potential reported in this 

study.

Table 2-4 Greenhouse Gases Included in Study Boundary

Emissions to Air Abbreviation GWP, CO2 Equivalents, 

100-year time horizon

Carbon Dioxide CO2 1

Methane CH4 25

Nitrous Oxide N2O 298

Sulfur Hexafluoride SF6 22,800

2.3.2 Criteria Air Pollutants

Table 2-5 lists six regulated criteria air pollutants as defined in the National Ambient Air Quality 

Standard by the U.S. Environmental Protection Agency (EPA) in response to the Clean Air Act 

of 1990. Analysis will include, but will not be limited to, these criteria pollutants. 
10

Table 2-5 Criteria Air Pollutants Included in Study Boundary

Emissions to Air Abbreviation Comment

Carbon Monoxide CO --

Nitrogen Dioxide/Nitrogen 

Oxides NO2/NOX Includes all forms of nitrogen oxides.

Sulfur Dioxide SO2 Includes SO2 and other forms of sulfur oxides.

Ozone, also reported as 

Volatile Organic Compounds O3, VOCs

VOCs combined with NOx and sunlight form 

ozone in the atmosphere. Releases of VOCs 

are reported as a precursor to ozone formation.

VOCs are reported as non-methane VOCs to 

avoid double counting with reported methane 

emissions.

Particulate Matter PM Includes all forms of PM: PM10, PM2.5, and 

unspecified mean aerodynamic diameter.

Lead Pb --

2.3.3 Water Consumption

In addition to atmospheric emissions, water consumption associated with CO2-EOR activity is 

also considered. This life cycle performance metric is reported in units of volume per volume of 

oil produced and includes consideration of quality of source water, quantity of water used, and/or 

the source/source type from which the water was extracted. Water consumption is the difference 

between the amount of water withdrawn for use and the amount of withdrawn water that is 

returned to the environment after use. Water produced in excess of what is required to maintain 

EOR operations is considered to be a byproduct of those operations, and activities associated 

with management of that byproduct are considered as part of the LCA. 

2.3.4 Land Use 

An inventory of land use has been included to quantify land surface area developed or modified 

as a result of activities being analyzed. Land use is calculated as the total land area on which 

EOR well patterns are in operation plus land used in gas-processing operations. Off-site land 

use, such as land use resulting from coal mining operations that supply power plants at which 

electricity is generated for use in EOR, is not considered in this study. In addition to quantity of 

surface area, a qualitative description of land type being affected with respect to previous use and 

ecosystem type being impacted is provided.

2.3.5 Net Energy Yield

Net energy yield is the difference between the energy content of an energy product and the total 

energy/embodied energy demand associated with its production. When considering gate-to-gate 

CO2-EOR performance, net energy yield is the energy content of oil and other hydrocarbon 

products generated minus the energy demand associated with all activities within the EOR 

facility gate that contribute to generation of those products. 

2.4 Allocation Methodology

Allocation procedures follow those set forth in ISO Document 14044 (ISO, 2006), which details 

a favored hierarchy of allocation methodology giving preference to the most detailed and 

technically rigorous methodology for which sufficient data are available. When possible, 

allocation should be avoided by either dividing a process into sub-processes or expanding the 
11

system boundaries. In cases where sufficient data or resource limitations do not allow 

consideration of the expanded system, inputs and outputs should be allocated between the 

products based on the most appropriate physical/chemical relationships between them. When 

knowledge of physical or chemical relationships is insufficient to establish an appropriate basis 

for allocation, other relationships, such as economic value, should be considered. For CO2-EOR, 

the primary product is crude oil, and secondary products are natural gas and natural gas liquids. 

These co-products are generated in relatively small quantities and are accounted for by taking an 

emissions credit equal to the emissions that would result from producing an equivalent amount 

(by energy) of these energy products generated through alternative means. Excess brine 

generated through CO2-EOR activity is considered to be a byproduct and is treated by system 

expansion to include brine injection disposal.

2.5 Other Modeling Assumptions

In cases where U.S. EPA AP-42 emissions factors (U.S. EPA, 1995) are reported to be below the 

detection limit for a particular constituent, it has been assumed that the emission factor for that 

constituent is half of the reported detection threshold. Therefore, if the emissions factor is 

reported, for example, to be less than 0.001 lb/MMBtu of fuel consumed, the value used for 

emissions estimation will be 0.0005 lb/MBtu fuel consumed. Higher heating values used in 

characterization of mixed hydrocarbon gas are reported in Table 2-6. 

Table 2-6 Higher Heating Values for Constituents of Gas Produced from CO2-EOR 

Activities 

Fuel HHVa Btu/lb 

Hydrogen 61,000

Methane 23,900

Ethane 22,323

Propane 21,699

Butane 21,719

pentane 21,071

hexane 20,966 a higher heating value

Source: Engineering Toolbox (2009)

All electricity demands are characterized in this study using a grid mix profile representative of 

the Electric Reliability Council of Texas (ERCOT) developed based on the U.S. EPA’s 

Emissions & Generation Resource Integrated Database (eGRID) 2005 data set (EPA, 2007). 

This is discussed in more detail in Appendix B. Steel, concrete, natural gas, and natural gas 

liquids were taken from proprietary life cycle inventory datasets, and those profiles are therefore 

not listed in this manuscript.
12

3.0 General Description of CO2-EOR Technology

The purpose of this study is to develop improved characterizations of facilities/operations 

associated with CO2-EOR and brine aquifer sequestration of CO2 to facilitate comparative 

assessment of life cycle inventories of these processes. The following is a brief description of 

major activities and infrastructure elements associated with all phases of these CO2 sequestration 

options.

CO2 flood enhanced oil recovery (CO2-EOR) is the injection of CO2 (often injected in alternation

with water/brine) into an underground oil-bearing formation for the purpose of stimulating 

additional production of crude oil. This technique is considered to be a form of tertiary oil 

recovery, as it is typically employed only after primary extraction and water-flood extraction 

have been used for oil recovery—typically recovering 20-50 percent of a reservoir’s original oil 

in place (OOIP). Tertiary recovery using CO2-EOR can be expected to stimulate recovery of an 

additional 5-20 percent of OOIP (Melzer, 2010). 

Begun in the Permian Basin of West Texas, United States, in the early 1970s, there are now on 

the order of 110 active CO2 projects producing an average of 250,000 barrels of incremental oil 

per day, or approximately 5 percent of domestic crude oil production. Cumulative domestic 

EOR production to date is approximately 1.4 billion barrels and increasing at a rate of 90 mmbbl 

per year. A recent study reported that the remaining domestic potential for EOR could be as high 

as 119 billion barrels of additional technically recoverable oil (NETL, 2008). 

At present, application and growth of CO2-EOR in the Permian Basin is limited by the 

availability of CO2, with 85 percent of CO2 used in EOR operations coming from natural 

sources and 15 percent (20 MMmt per year) coming from industrial and by-product sources

(Melzer, 2010). Capture incentives or proposed climate change legislation calling for large-scale 

capture and sequestration of anthropogenic CO2 would resolve that limitation and create an 

opportunity to realize large increases in incremental oil production, and achieve significant 

geologic sequestration of CO2 (as much as 13 gigatons of CO2 storage capability) (NETL, 2008).

3.1 CO2-EOR Mechanisms and Methodologies

In general, reservoir characteristics required for successful application of any enhanced oil 

recovery technology include porous, permeable formations of carbonates or sandstones; reservoir 

throughput (sufficient injectivity); and continuity between wells. In reservoirs in which 

secondary (water flood) EOR has already been performed, these requisite conditions for tertiary 

(CO2-flood) recovery can be assumed.

The primary mechanisms by which oil is recovered through tertiary CO2 flooding are:

• Generation of miscibility conditions with the oil and CO2

• Swelling crude oil

• Lowering oil viscosity

• Lowering interfacial tension between oil and CO2-oil phase in the near-miscible 

regions
13

Miscibility refers to the property of fluids to mix in all proportions and form a homogeneous 

solution; in situ miscibility of CO2 and crude oil is a function of fluid and formation properties 

such as formation depth, temperature/pressure, and crude oil composition. When CO2/oil 

miscibility is achieved in tertiary EOR operations, displacement efficiency of the miscible fluid 

improves, and the overall flood productivity increases. 

In immiscible CO2 floods, oil swelling and viscosity reduction are the primary mechanisms of 

enhanced recovery, with oil volume increases of as much as 50 percent resulting in incremental 

oil production even below the minimum miscibility conditions, from dead-end pores, and 

viscosity reduction improving relative permeability. While these mechanisms also stimulate 

productivity over secondary recovery methods, the increased incremental oil production will be 

lower as compared to CO2-EOR performed under miscible conditions due to the enhancement of 

sweep efficiency of miscible flooding. Table 3-1 provides a summary of reservoir and crude oil 

characteristics recommended for CO2-EOR operations, as well as approximate oAPI/formation 

depth combinations required to achieve minimum miscibility requirements (temperature and 

pressure are a function of formation depth).

Table 3-1 Technical Screening Guidelines for CO2 Flooding 

Parameter Recommended Current Projects Range

Crude Oil

Gravity,oAPI >22 27 to 44

Viscosity, centipoise (cp) <10 0.3 to 6

Composition High percentage of intermediates (C5 to C12)

Reservoir

Oil Saturation in Waterflooded Swept Zone

>25*a 15 to 70

Type of Formation Thick but relatively thinly bedded sandstone or carbonate 

unless dipping*

Permeability > 1 millidarcy

Bottom Hole 

Depth/Temperature

For miscible displacement, depth must be great enough to 

allow injection pressures greater than the MMPb

, which 

increase with temperature and for heavier oils. 

Recommend depths of CO2 floods of typical Permian Basin 

oils is as follows:

Gravity, oAPI Depth Greater Than (ft)

CO2 miscible

>40 2,500

32 to 39.3 2,800

28 to 31.9 3,300

22 to 27.9 4,000

<22 Fails Miscible CO2 Screening test

CO2 immiscible

13 to 21.9 1,800

<13 Fails CO2 Screening

 a Where noted by an asterisk (*), adapted from Lyons (1996) per comments of Melzer (2010) b MMP=minimum miscibility pressure
14

3.1.1 Minimum Miscibility Pressure Calculation

Minimum miscibility pressure (MMP) refers to the pressure at which injected CO2 becomes 

miscible with the oil in place in the reservoir; it is important to determine this threshold to 

effectively identify reservoirs that are candidates for miscible CO2 flooding. A number of 

correlations have been established to estimate the minimum miscibility pressure (Emera and

Sarma 2005); Equation (1) illustrates a simplified Cronquist correlation, which provides a simple 

means of estimating the miscibility threshold as a function of temperature and oil pentane plus

fraction molecular weight (Cronquist, 1978). An expanded form of the Cronquist correlation 

also takes into account methane and nitrogen gas molar fraction. It is not applied in this study, 

but may be appropriate for use in future work considering CO2-EOR operations employing direct 

CO2 recycle (without gas processing for CO2/hydrocarbon separation). This correlation has been 

applied in earlier NETL studies to establish MMP (U.S. DOE, 2006; U.S. DOE NETL, 2008; 

U.S. DOE NETL, 2009), and is used again in this work for consistency.

MMP = 15.988*T(0.744206 + 0.0011038*MW C5+) (1)

where

MMP = minimum miscibility pressure, pounds per square inch absolute (psia)

T = reservoir temperature, °F

MW C5+ = molecular weight of pentanes and heavier fractions in the reservoir oil

A plot of forecasted MMP as a function of reservoir temperature for a range of molecular weight 

of the pentanes and heavier fractions from 180 to 340 g/mole) is shown in Figure 3-1. 

Figure 3-1 Plot of Cronquist Correlation for a Series of C5+ Molecular Weight Values over the Range of 

Temperatures from 75 to 275 °F
15

Increased tertiary incremental oil production observed with increasing CO2 injection and market 

incentives created by high crude prices have, in recent years, driven operators to inject higher 

CO2 hydrocarbon pore volume (HCPV3

) fractions. In one case, at the Means CO2-EOR WAG 

injection in the San Andres Unit, original CO2 injection targets of 0.55 hydrocarbon pore 

volume2

Figure 3-2

(HCPV) (0.4 HCPV purchased CO2, and 0.15 HCPV recycled CO2) were increased to 

approximately one HCPV. Results of reservoir engineering models that demonstrate increased 

volumes of CO2 injection show improved reservoir sweep efficiency ( ), which 

corresponds to higher incremental oil recovery from tertiary EOR (Figure 3-3). 

Figure 3-2 Example of Oil Recovery Efficiency vs. CO2 Injection (assumes homogeneous 

reservoir). Sweep Efficiency in Reservoir Pore Volumes (RVPs) of Miscible CO2-EOR Flood 

Increases with Increasing Hydrocarbon Pore Volume (HCPV) Injection.

 

2 Hydrocarbon pore volume (HCPV) is the pore volume in a reservoir initially filled with oil, and is often used to 

describe in-formation fluid volumes and discuss normalized performance between reservoirs. HCPV is calculated as 

ΣA*h*φ*(1−Swi), where A is surface area, h is gross pay thickness, φ is porosity as fraction, and Swi is initial 

water saturation as fraction.
16

Figure 3-3 Tertiary Oil Recovery Increases with Increasing CO2, But Also Increases the Required 

Duration of the CO2 Injection Before Recovery Drops Off.

3.1.2 Water Alternating Gas (WAG) Tertiary Injection Scheme

Viscosity of CO2 at formation conditions is significantly lower than that of crude oil (CO2

viscosity at 123 °F was calculated per Crane [1988] to be 0.0162 cp, while the median viscosity 

of 228 Permian Basin samples from the ARI Big Reservoir Database [2009] is 1.76 cp). The 

less viscous pressure-driven fluid forms channels through the oil that is present in the formation. 

As a result of this channeling, a significant quantity of injected fluid can bypass the oil in the 

formation and “break through” to the production well without contacting formation oil and 

without stimulating its production. Any subsequently injected CO2 will also follow previously 

established channels, causing poor overall sweep efficiency within the reservoir. 

One technology that has been developed to address this channeling and breakthrough of low 

viscosity CO2 is alternate injection of water as a higher viscosity drive fluid in a water alternating 

gas (WAG) injection process. In WAG injection, the alternate injection of water (typically brine 

that has been produced from adjacent EOR patterns) and CO2 aids in inhibiting the channeling of 

less viscous CO2 through the reservoir from injection to production well, thereby increasing CO2

residence time and improving contact between CO2 and the oil remaining in the reservoir. Table 

3-2 provides a simplified representation of selected injection options: continuous CO2 injection, 

continuous CO2 followed by water sweep, WAG injection followed by water sweep, tapered 
17

WAG followed by water sweep, and WAG followed by hydrocarbon gas injection and water 

sweep.

Table 3-2 Simplified Representation of CO2-EOR Fluid Injection Schemes 

Injection Type Injection Increment (time or injection volume) 

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16

Continuous CO2 injection 

Continuous CO2 followed by water 

sweep

WAG injection followed by water 

sweep

Tapered WAG followed by water 

sweep

WAG followed by HC gas injection 

and water sweep

Color key:

CO2 Injection

Water Injection

HC Gas Injection

Adapted from Jarrell et al. (2002)

3.1.2.1 Advanced Resources International Big Oil Fields Database

The Big Oil Fields Database contains detailed reservoir-specific parameter data for over 2,000 

domestic oil reservoirs, accounting for over 70 percent of the anticipated ultimate remaining 

production in the United States (ARI, 2009). This database has been developed and is 

maintained by Advanced Resources International, and is licensed for use by the U.S. 

DOE/National Energy Technology Laboratory. The database contains reservoir-specific data 

for 34 parameters, including:

• Reservoir depth, temperature, and pressure 

• Volumetrically-consistent original oil in-place3

• Up-to-date cumulative oil production and remaining oil reserves (“stranded” oil that is 

targeted by EOR technologies)

(OOIP) endowment 

 

3 Original oil in place (OOIP) refers to the original hydrocarbon content in place in a formation, by volume 

atstandard surface conditions and not real formation conditions), before initiation of oil production operations. 

This value is always greater than the technically and economically recoverable oil reserves in a reservoir. 

OOIP at standard conditions (sometimes referred to as STOOIP) is defined by the equation: 

 where N is OIIP in stock tank barrels, Vb is bulk reservoir volume in acre-feet, φ is 

fraction of bulk reservoir volume that is fluid-filled porosity, Sw is the fraction of fluid-filled porosity that is 

saturated with water, Boi is the ratio between volume of a unit mass of oil at reservoir conditions (real barrels), and 

the volume of the same unit mass at surface conditions (stock tank barrels), and 7758 is a conversion factor 

between acre-feet and stock tank barrels.
18

• Existing field infrastructure and activities that influence costs of implementing CO2-EOR 

(active and shut-in injection and producing wells, and volumes of water injection and 

production)

• Up-to-date summary of cumulative EOR production, production rate, and estimated 

remaining CO2-EOR reserves

The database also contains sub-routines containing logic to screen reservoirs based on parameter 

data to:

• Determine reservoir suitability for CO2-miscible flooding

• Ensure volumetric consistency of reported data

• Summarize reservoir miscible and immiscible CO2-EOR activity and flood volumes

These data were used in the development of several reports for the U.S. DOE on potential for 

domestic CO2-EOR technology development, including a series of reports entitled Basin

Oriented Strategies for CO2 Enhanced Oil Recovery for domestic resource basins/areas and two 

technology analysis reports entitled Storing CO2 with Enhanced Oil Recovery, and Storing CO2

and Producing Domestic Crude Oil with Next Generation CO2-EOR Technology.

3.2 CO2-EOR as CO2 Geologic Sequestration Mechanism

In addition to the primary function of CO2-EOR to stimulate incremental oil production with the 

benefit of increasing the security of the domestic oil supply, CO2-EOR may also serve to store 

anthropogenic CO2 through geologic sequestration. A set of “next generation” CO2-EOR 

techniques and practices have been proposed to accomplish significant geologic storage of CO2

while stimulating oil recovery beyond that which has historically been observed or can be 

realized with current best practices. Historical, current best practices, and next-generation CO2-

EOR operational scenarios are described in detail in the following sections. As discussed above, 

CO2-EOR operations are, at present, supplied primarily from naturally-occurring reservoirs of 

CO2; proposed legislation on emission of greenhouse gasses could dramatically increase the 

supply of CO2 from anthropogenic sources available for CO2-EOR with concomitant 

sequestration.

3.2.1 Retention vs. Sequestration in CO2-Flood EOR 

Terminology used to discuss the fate of CO2 used in EOR operations can be somewhat 

confusing, and warrants discussion. This confusion stems from differences in understanding and 

use of the word CO2 “retention.” The EPA’s Proposed Mandatory Reporting Rule (75 FR 16584 

[2009-4-10]) states:

The objective of EOR operations is not to maximize reservoir CO2 retention rates, 

but to maximize oil production and the amount of CO2 trapped underground 

would be a function of site specific and operational factors. There are several 

EOR operations in the Permian Basin of Texas. One study showed that retention 

rates for eight reservoirs ranged from 38 to 100 percent with an average of 71 

percent, but many of these projects are not mature enough to predict final 

retention (see Suppliers of CO2 TSD [EPA–HQ–OAR–2008–0508–044]).
19

While it is true that CO2-EOR has, traditionally, been concerned with resource production and 

not maximizing CO2 retention, and retention rates are often well below 100 percent, the 

statement implies that the fraction of CO2 not retained underground is released to the 

atmosphere. In response to this proposed rule, representatives of the oil and gas industry 

expressed concern that the term of art “retention” was being used out of context. Several 

comments to the Proposed Rule responded to call out this issue; for example, a comment from 

the American Petroleum Institute (API) states: 

The “retention rate” EPA refers to in the Preamble does not adequately capture 

the fact that EOR is a “closed system.” In fact, the report that EPA cites in their 

discussion of retention rates recognizes this fact and states that, regarding a 

reservoir with 38% retention, “Essentially 100% of the purchased CO2 is still in 

the system. At the end essentially 100% of the fluid will be stored in a reservoir.” 

Additionally, evidence suggests that CO2 injected via EOR wells in compliance 

with the UIC regulations does not leak into the surrounding groundwater (Smyth 

et al, 2008; Wilson and Monea, 2004) let alone the atmosphere (Klusman, 2003; 

Wilson and Monea, 2004).

The first portion of this quotation states that essentially all of the acquired (purchased) CO2 is 

stored geologically, and the second portion refers to studies suggesting that this storage might 

reasonably be expected to exhibit favorable permanence of storage that will meet geologic 

sequestration permanence goals. Oil and gas industry representatives have since expressed 

interest in further clarifying the definition of “retention” as it relates to geologic “sequestration” 

and providing real-world, inventory-based examples. To contribute to this clarification, 

definitions of CO2 “retention” and “sequestration” in CO2-EOR are provided, and, in lieu of 

presentation of case study-based evidence, a simplified example is provided. 

3.2.1.1 CO2 Retention in CO2-EOR Operations 

The distinction between CO2 “retention” and CO2 “sequestration” is both one of physical system 

boundary (around which mass balance is performed), and one of temporal extent of activities 

included. Jarrell and colleagues (2002) defined “retention” to be

the amount of CO2 remaining in the reservoir at any given time, which equals the 

amount of CO2 injected less the amount of CO2 produced.

Expressed as a fraction (as in the previously referenced Proposed EPA Rule), this definition 

could be written as:

where injection includes both the newly purchased plus recycled CO2. To calculate this fraction, 

units of standard volume or units of mass can be used. CO2 retention is used in evaluating the 

efficiency of CO2 flooding operations. As referenced therein, this term is effectively a 

cumulative retention definition. Some companies have adopted an instantaneous retention 

definition, which is simply the ratio of current injected less produced CO2 to injected CO2. In 

both cases, the injected CO2 is the sum of purchased and recycled CO2. For purposes of this 

report, cumulative quantities will be used. 
20

From the operator’s perspective, CO2 retention during CO2-EOR operations is considered to be a 

detrimental factor, as it requires purchase of additional CO2 to accomplish the same total CO2

cumulative injection per well pattern (and the same oil production per well pattern): more CO2

retention can correspond to less efficient utilization of purchased CO2 resource. As defined by 

industry, “retention” does not consider the disposition of the CO2 that is not retained in the 

reservoir. However, it is important to note that CO2 that is not retained in the flooded area is not 

emitted to the atmosphere, but only produced from the reservoir (pattern or field) and available 

for reuse in the same or adjacent CO2-EOR operations. While the amount of CO2 “retained” per 

well pattern may be as low as 38 percent (U.S. EPA, 2009), the amount of purchased CO2 that is 

geologically stored through the period of active injection will approach 100 percent (assumes 

negligible loss in recycling4

3.2.1.2 CO2 Sequestration in CO2-EOR Operations 

). Furthermore, the term “retention” refers to the storage of CO2 in 

the subsurface over the cumulative period of active injection (per pattern or field) at some point 

during the period of active injection; it does not consider the amount of CO2 that is permanently 

sequestered—which considers the amount of retained CO2 that remains stored in the subsurface 

at some period after completion of active injection. However, the experience in many reservoirs 

suggests that the two may be very close (Melzer, 2010).

The definition of geologic CO2 sequestration given by the U.S. Department of Energy, National 

Energy Technology Laboratory (NETL) is as follows:

the placement of CO2 into a subsurface formation in such a way that it will remain 

permanently stored.

The U.S. DOE further defines “permanence” as sequestration after 100 years of storage (postinjection), and has set a goal of 99 percent storage permanence. Sequestration is the geologic 

storage of CO2 100 years after the completion of active injection. Storage impermanence takes 

into account the amount of CO2 lost to the atmosphere both during the period of active injection 

and through 100 years of post-injection monitoring, verification, and accounting (MVA) of CO2

storage. For CO2-EOR, CO2 sequestration is the amount of gross CO2 retained through the 

period of active injection minus losses. Described as a fraction, this is:

To calculate this fraction, units of standard volume or units of mass can be used. The term 

“losses” includes all losses to the atmosphere (storage impermanence) through the period of 

active injection and for 100 years following completion of active injection, and includes potential 

CO2 leakage to the atmosphere through cap rock and compromised wellbores or plugs5

 

4 CO2 separation and recycle operations are considered as a “tight” chemical process with significant effort made to 

minimize venting and fugitive losses from the system, since such losses have associated loss of hydrocarbon and 

other tightly regulated gases, and would require that additional CO2 be purchased.

. 

5 Fugitive losses from gas recycling operations, as well as direct and indirect (e.g., electricity grid mix emissions) 

will contribute to overall greenhouse gas emissions, but do not impact gross geologic sequestration performance. 

Such operational emissions are accounted for separately and used to estimate “net sequestration” performance.
21

In summary, CO2 that is “retained” in a single pattern is not available for reinjection into the 

same or adjacent pattern, as it is stored in the subsurface. CO2 that is not “retained” in one 

pattern is, therefore, available for reinjection into the same or adjacent patterns. CO2 that is 

retained in the subsurface at the end of a period of active injection is geologically stored; that 

which remains geologically stored 100 years after completion of active injection is considered to 

be sequestered. In CO2-EOR operations, nearly 100 percent of the purchased CO2 will be 

geologically stored at the end of the period of active injection and, with sufficient permanence of 

CO2 storage, at least 99 percent of the stored CO2 will be sequestered. Retention and 

sequestration are discussed in relation to results of this study in Section 4. 
22

3.3 Review of Relevant Literature

3.3.1 NETL Characterizations of CO2-EOR Economic and Technical Potential

Recent studies published by U.S. DOE NETL and prepared by Advanced Resources 

International, Inc. (NETL, 2008; NETL, 2009) have defined three CO2-EOR technology 

implementation scenarios descriptive of past, present, and likely future CO2-EOR technology 

application. In those reports these scenarios are referred to as:

• “Historical” CO2-EOR Flood Practices

• “Best Practices” CO2-EOR

• “Next Generation” CO2-EOR

Progression of CO2-EOR practices have generally trended toward increased total CO2 injection 

volumes to achieve increased oil recovery. While, in the past, CO2-EOR operations took

measures to minimize the purchase of CO2 by applying modest amounts of CO2 and water 

sweeping the flood after CO2 application to maximize CO2 recovery for reuse, best-practices 

reservoir management calls for additional CO2 injection and allowing retained CO2 to remain in 

situ without water slug recovery, and the “next-generation” CO2-EOR operational scenario

further increases formation oil production by increasing CO2 injection, modification of reservoir 

fluid properties, and modification of injection well pattern. Each of these three CO2-EOR 

operational scenarios is described in greater detail below, and details of each operational scenario 

are summarized in Table 3-3 and Table 3-4.

“Historical” CO2-EOR. Historically, the amount of CO2 injected for tertiary oil recovery has 

been limited by the cost of CO2 that is purchased for injection. As such, relatively small total 

injection volumes (as compared with current “best practices” and “next generation” scenarios as 

defined herein) were used in early CO2-EOR. In addition, CO2 contained in the produced fluid 

was (and still is) separated, recompressed, and reused. Finally, a slug of water is injected into 

the formation at the end of the CO2 flood to recover residual CO2 remaining in the formation, 

and the recovered CO2 is transported to an adjacent field for use as tertiary EOR solvent. 

Following water slug injection for CO2 recovery, an estimated 2,000-4,000 standard cubic feet 

(scf) of CO2 would remain trapped in the target formation for each barrel of incremental oil 

produced. While some CO2 remains trapped following historical CO2-EOR flood, geologic 

sequestration of CO2 is not a goal of CO2-EOR. Rather, the primary function of CO2 in 

historical CO2-EOR was to maximize tertiary production of oil at a minimum purchased CO2

cost.

For purposes of this study, and in keeping with the definition of historical CO2-EOR as defined 

in previous CO2-EOR studies, total cumulative CO2 injected over the flood lifetime is assumed 

to be 40 percent of total hydrocarbon pore volume (HCPV) in the target formation. Following 

completion of CO2-EOR WAG injection, it is assumed that one HCPV of brine is injected to 

recover as much of the injected CO2 as possible for use at adjacent operations.

“Best Practices” CO2-EOR Operational Scenario. High prices of crude oil observed in recent 

years—on July 11, 2008, light crude prices temporarily reached $147.27/bbl on the New York 

Mercantile Exchange - symbol CL— have led to the injection of higher total volumes of CO2 to 

increase incremental oil production. A series of studies sponsored by the U.S. DOE have 
23

evaluated the magnitude of CO2-EOR potential in 10 domestic basins (in 22 states) using best 

practices CO2-EOR technology and “best practices.”

A follow-on study sponsored by NETL entitled Storing CO2 with Enhanced Oil Recovery

(NETL, 2008) built on the series of basin studies, adding an additional 500 reservoirs to the 

database of domestic CO2-EOR potential resources, considering a greater variety of oil and CO2

price scenarios, and addressing, for the first time, the domestic CO2 storage capacity using a 

CO2-EOR “best practices” injection scenario. In these studies, “best practices” CO2 flood is 

defined based on a dramatically increased volumetric injection of 1.0 hydrocarbon pore volumes 

(as compared to 0.4 HCPV total CO2 injection representative of “historical” CO2-EOR 

operations). In addition to the increase in volume of CO2 injected, the injection schedule 

representative of “best practices” is significantly modified—using a tapered water alternating gas 

(WAG) injection process. As with the historical injection scenario, “best practices” CO2-EOR 

includes separation of CO2 from the produced fluid and recycling if for further injection. In 

contrast to “historical” CO2-EOR operations, “best practices” assumes that a water slug is not 

injected at the end of the CO2 flood, and the injected CO2 is not recovered. 

“Next Generation” CO2-EOR Operational Scenario. “Next generation” CO2-EOR comprises a 

set of technologies and practices that can be used individually or in combination to improve the 

productivity of a reservoir over that which would be realized with “best practices” CO2-EOR 

and/or to increase the total number of reservoirs that meet criteria to be considered as a viable 

candidate for miscible CO2-EOR. Technology/operational alternatives considered to represent 

“next generation” CO2-EOR include:

1. Increase volume of CO2 injection to 1.5 HCPV

2. Application of innovative flood design and well placement:

– Targeted horizontal wells

– Modified well alignment

– Injection of physical or chemical diversion materials

– Infilling (infilling or infill drilling is the practice of drilling wells to decrease well 

spacing/increase well density) (Fanchi, 2006)

3. Improving the mobility ratio:

– Polymers in water (polymer addition to water increases the viscosity of the 

injected aqueous phase, improving mobility ratio and fluid flow patterns of the 

flood) (Fanchi, 2006)

4. Extending miscibility (decreasing minimum miscibility pressure)

– Liquefied petroleum gas, H2S, or other interfacial tension reduction elements

– Reduce miscibility requirements by 500 psi (21 reservoirs) 

In the report entitled Storing CO2 with Next Generation Technology (NETL, 2008), this 

definition of “next generation” CO2-EOR is used to evaluate magnitude of potential to produce

incremental oil. 

Evaluation of Domestic Technically- and Economically-Recoverable Incremental Oil 

Resource. Over 6000 oil-bearing reservoirs in the lower 48 states and Alaska were screened to 

identify those meeting minimum criteria to be further evaluated to determine potential technical 

and economic incremental oil recovery potential through application of CO2-EOR. These 

minimum criteria were minimum field size of 50 million barrels of original oil in place, 
24

minimum reservoir depth of 3,000 feet, and minimum crude API gravity of 17.5. Of all 

reservoirs considered, a subset of 1,600 was identified as meeting these size, depth, and density 

criteria. These candidate reservoirs were then evaluated using a stream-tube CO2-EOR model to 

estimate technical incremental oil under each of the three CO2-EOR flood operational scenarios. 

The results from the stream tube model were fed to a cash flow model to estimate the amount 

of economically recoverable resource at different market prices for crude oil and values for 

carbon storage. Under the best practices scenario and at a crude oil price of $70 per barrel and a 

value for CO2 storage of $45 per metric tonne of CO2, 60 billion barrels of economically 

recoverable oil was estimated. This amount of CO2-EOR corresponds to an estimated nine 

billion metric tonnes of CO2 sequestration. This volume of CO2 is roughly equal to captured 

CO2 emissions from 50 gigawatts of coal-fired power plants over a 30-year life. Results of this 

analysis are summarized in Table 3-4 and Table 3-5.
25

Table 3-3 Definition of CO2-EOR Technology Scenarios and Data Sources Used in Evaluation of CO2-EOR Scenarios in Studies 

Previously Published by NETL 

Parameter Description Historical 

CO2-EOR

Best 

Practices

CO2-EOR

Next-Gen 

CO2-EOR

Tech 1

Increase 

CO2 HCPV

Tech 2

Innovative 

flood design

Tech 3

Increase 

Water 

Viscosity

Tech 4

Miscibility 

extenders

Tech 1-4

All Nextgen 

options

Incremental hydrocarbon 

pore volumes injected 0.4 1 1.5 1a 1 1 1.5

Number of injectors 1 1 1 1 1 1 1

Number of producers 1 1 1 2 1 1 2

Viscosity of water (cp) ARI DBb ARI DB ARI DB ARI DB 3 cp ARI DB 3 cp

Minimum miscibility pressure 

(psia) ARI DB ARI DB ARI DB ARI DB ARI DB ARI DB - 500 ARI DB –500

WAG type Normal Tapered Tapered Tapered Tapered Tapered Tapered

Water chase? Yes No No No No No No

(Adapted from U.S. DOE, 2006; NETL 2008a; NETL 2008b; NETL 2009).

a

Grey cells identify next-generation CO2-EOR technologies that are not considered in this study. b ARI DB=Advanced Resources International Big Oil Fields Database
26

Table 3-4 Summary of CO2-EOR Injection Scenarios as Defined in Previously Published Reports 

Pore volume 

injection

CO2 storage rate

(mtCO2/bbl)a

Aggregate impacts of CO2-EOR in the U.S.

Crude Oil recovery, (Billion 

barrels)

b

CO2 stored

(Bmt CO2)

Historic CO2-EORc 0.4 0.11-0.22 10-20 1.0 – 5.0

Best Practicesd 1.0 0.28 45 12.5e

Next Generationf 1.5 0.22 64 14.5

a

Economically recoverable resource based on a market price for crude oil of $70 per barrel and a CO2 cost of $45 per metric ton, delivered to 

the field, and a project IRR of 15% before tax. b

Conversion factor is 56 MMmt/scf; equivalent values in scf/bbl for historic, best practices, and next generation are 2,000 – 4,000 scf/bbl, 5,000 

scf/bbl, and 4,000 scf/bbl respectively. 

c Not modeled as a part of this analysis. Numbers are estimated from industry heuristics d “Best Practices” entails 1.0 pore volume CO2 injection, tapered WAG process, reinjection of CO2 produced with oil, and a water slug at the 

end of the flood recovers residual CO2. e ARI estimates that 3.5 billion metric tons of total will be supplied by natural sources and industrial vents. A net of 9 billion mt is the capacity 

that will motivate advanced coal with CO2 capture. f

“Next Generation” entails 1.5 pore volume CO2 injection, advanced flood design and well placement to improve reservoir contact, increased 

water viscosity to 3 cps, use of miscibility extenders to reduce the minimum miscibility pressure by 500 psi, and no water slug at the end of the 

flood to recover CO2.

Adapted from U.S. DOE, 2006; NETL 2008a; NETL 2008b; NETL 2009.
27

Table 3-5: Economically Recoverable Oil and CO2 Sequestration Capacity in the Conterminous 48 States and Alaska, Estimated Based on 

Stream-Tube Modeling of Best Practices and “Next Generation” CO2-EOR Scenarios

Basin/Area

Best Practicesa Next Generationb

Oil produced, 

Bbblsc

CO2 stored, 

MMmtCO2

Oil produced, 

Bbbls CO2 stored, MMmtCO2

1. Alaska 9.5 2,094 9.5 2,094

2. California 5.4 1,375 8.1 1,556

3. Gulf Coast (AL, FL, MS, LA) 2.2 652 2.7 691

4. Mid-Continent (OK, AR, KS, NE) 5.6 1,443 8.8 1,845

5. Illinois/Michigan 0.5 127 1.7 329

6. Permian (W TX, NM) 7.1 2,712 15.1 3,598

7. Rockies (CO,UT,WY) 1.9 574 3.8 759

8. Texas, East/Central 8.3 1,940 9.9 2,099

9. Williston (MT, ND, SD) 0.5 130 0.6 122

10. Louisiana Offshore 3.9 1,368 3.9 1,368

11. Appalachia (WV, OH, KY, PA) 0.1 36 0.1 18

Total United States 45.0 12,451 64.4 14,477

a “Best Practices” entails 1.0 pore volume CO2 injection, tapered WAG process, reinjection of CO2 produced with oil, and no water slug at the end of the flood to recover 

CO2 b “Next Generation” entails 1.5 pore volume CO2 injection, advanced flood design and well placement to improve reservoir contact, increased water viscosity to 3 cps, 

use of miscibility extenders to reduce the minimum miscibility pressure by 500 psi, and no water slug at the end of the flood to recover CO2. c Economically recoverable resource based on a market price for crude oil of $70 per barrel and a CO2 cost of $45 per metric ton, delivered to the field, and a project IRR 

of 15% before tax

Source: NETL, 2009
28

ARI Report on CO2-EOR Electricity Requirements

A report published by NETL and prepared by Advanced Resources International, Inc. entitled 

Electricity Use of Enhanced Oil Recovery with Carbon Dioxide (CO2-EOR) provides ranges of 

unit process electricity demand based largely on input from field operators of existing CO2-EOR 

operations (Van Leeuwen and Ferguson, 2009). Table 3-6 summarizes ranges of electricity 

demands for three major operations: CO2 re-compression, artificial lifting of produced fluids 

from CO2-EOR producing wells, and separation of natural gas liquid (NGL) from CO2 stream 

following gas/liquid separation. A fourth range is provided as an estimate of the sum of 

electricity demands from all other processing activities taking place during CO2-EOR facility 

operation. 

Table 3-6 Range of Electricity Use at CO2-EOR Fields by Source

Project Component Low Bound Electricity 

Consumptiona

Mid Range 

Electricity 

Consumptionb

High Bound 

Electricity 

Consumptionc

Compression 26 kWh/Bbl 40 kWh/Bbl 70 kWh/Bbl

Artificial Lifting 0 kWh/Bbl 5 kWh/Bbl 10 kWh/Bbl

NGL Separation 0 kWh/Bbl 0 kWh/Bbl 10 kWh/Bbl

Other 1 kWh/Bbl 5 kWh/Bbl 8 kWh/Bbl

Total 35 kWh/Bbl 60 kWh/Bbl 98 kWh/Bbl

a This estimate represents a field with a permeable reservoir, optimized compression equipment, free flowing 

wells, no additional hydrocarbon separation equipment and that injects straight CO2.

b A mid-range field injects greater volumes of CO2 into the reservoir, or has somewhat inefficient 

compression equipment. It requires artificial lift equipment to produce its oil and injects some of its produced 

water in a WAG flood.

c A high-electricity use field injects large amounts of CO2 into its reservoir. This flood is likely producing large 

amounts of oil from a deep reservoir, which requires powerful, somewhat inefficient artificial lifting equipment. 

This field also employs a hydrocarbon separation facility that requires additional energy to compress the 

refrigerant used in the Ryan Holmes process. Finally, it injects its produced water in a WAG process.

Source: Van Leeuwen and Ferguson (2009)

These data provide a useful example of the variability in the type of operation and efficiency of 

performance that may be expected from CO2-EOR operations. The report also highlights the 

scarcity of this type of performance data. The way in which these data are reported is not 

conducive to development of more than a screening-level life cycle inventory for enhanced oil 

recovery. All data are reported in terms of barrels of crude oil produced, while the scale of 

operations cannot be directly correlated to oil flow (CO2 compression electricity requirements, 

for example, are reported in terms of kWh/barrel of oil produced even though the compression 

requirements are more a function of volume or mass of gas compressed than oil produced). 
29

3.3.2 Literature Review of CO2-EOR Environmental Performance

Several assessments of CO2-EOR have been reported at technical conferences or in peerreviewed literature. Table 3-7 provides a summary of characterizations that endeavor to describe 

CO2-EOR operations in basins or a specific field the Permian Basin, West Texas. The broad 

range of estimated CO2 storage potential per barrel of oil produced and EOR facility operational 

emissions reflects the high degree of variability in flood performance resulting in variability in 

reservoir continuity from well to well, and differences in CO2-EOR practice. CO2-EOR field 

operation and performance vary significantly from basin to basin, field to field, operator to 

operator, and even well pattern to well pattern. This variability also reflects differences in how 

the LCA practitioner models activities and related resource demands and environmental 

emissions; such differences could result from differing study scopes or differences in complexity 

of model structure. 

The most reliable estimates of emissions associated with CO2-EOR operations are those that are 

based on real inventory of site-specific material flows, energy flows, and unit process 

performance. For example, values reported for the Scurry Area Canyon Reef Operators 

(SACROC) facility near Snyder, Texas (unpublished presentation Kinder-Morgan CO2

Company, 2009) are based on a detailed inventory of 2007 operations at that facility. This type 

of analysis can be reasonably assumed to provide a robust characterization of performance at the 

SACROC facility, but these results cannot be used to characterize performance for individual 

well patterns within the SACROC field, nor all fields in the Permian Basin, let alone in all basins 

in the United States. 

One key factor that will impact operational emissions for CO2-EOR scenarios with gas 

processing and recycle is the cumulative injection volume of CO2—commonly reported as 

HCPVs of CO2 injected. In current best practice, cumulative CO2 injection in WAG operations 

is typically in the range of 0.8 to 1.0 HCPV, but real cumulative injection volumes vary as a 

function of field properties, economic conditions, and operator judgment (Melzer, 2010). 

Cumulative CO2 injection often varies on a pattern-by-pattern basis and, as such, field-level CO2

cumulative injection volumes are not typically reported. 

Choice of study boundary can also significantly impact results of an LCA. Assessments 

summarized in Table 3-7 consider only activity during the operational phase, and do not consider 

site evaluation, construction and workover requirements, well plugging and abandonment, or 

post-closure monitoring. While most environmental emissions associated with CO2-EOR occur 

during EOR operations, a more complete characterization should also consider phases of 

operation. The present study attempts to estimate emissions associated with all phases of 

operation. 
30

Table 3-7 Summary of Characterizations of CO2-EOR GHG Performance Reported from 

Other Studies

Source Scope Location 

Gross 

Storage 

Capacity 

(kg CO2/bbl) 

GHG 

Emissions

(kg 

CO

2

E/bbl) 

Net GHG 

Storage (kg 

CO2E/bbl) 

(Jaramillo et 

al., 2009) 

Operation

Northeast 

Purdy Unit, Mid 

Continent, OK,

USA

172 57 115 

Operation

Kelly Snyder 

Field, Permian 

Basin, W. TX

218 57 161 

Operation

Ford Geraldine 

Unit, Permian 

Basin, W. TX

182 57 125 

Operation

Joffe Viking 

Unit, 

Alberta,CAN

157 57 100 

Operation

Weyburn Unit, 

Williston Basin, 

SK, CAN

154 57 97 

(Fox, 2009)

a Operation

Kelly Snyder 

Field, Permian 

Basin, W. TX

404 100 304 

Estimated from 

Aycaguer & 

Lev-On (2000) 

Operation Permian Basintype reservoir 409 56 353 

Kovscek (2002) Operation Non-specific 360 n/rb n/r a

Kinder-Morgan inventory of SACROC facility operations was presented but not published or 

approved for distribution. As such, it should be noted that values reported herein are not 

sanctioned by the authors of that study.

b

n/r - not reported

3.4 CO2 Prophet CO2-EOR Screening Model

In 1986, a Fortran-based model was developed by researchers at the Texaco Exploration and 

Production Technology Department, as part of the U.S. DOE Class I cost-shared project Post 

Waterflood, CO2 Flood in a Light Oil, Fluvial Dominated Deltaic Reservoir, under U.S. DOE 

ContractDE-FC22-93BC14960. The CO2 Prophet model was recompiled by Dr. S. M. Avasthi

(Avasthi & Associates) to run on 32-bit PCs operating Microsoft Windows XP, and has been 

reviewed and validated by NETL staff (Remson, 2006). The CO2 Prophet model has also been 

used in a series of basin-specific evaluations of CO2-EOR potential, and for evaluation of “best 

practices” and “next-generation” practices technology scenario evaluation studies published by 

NETL and summarized in the body of this report. Finally, the electricity demand for three 

general geographic CO2-EOR scenarios (W. Texas, Gulf Coast/Mississippi, and California) 

were estimated based on production estimates developed using CO2 Prophet and partially 

described in a fourth report published by NETL and summarized in the body of this text. 
31

3.4.1 Summary of CO2 Prophet Screening Model

The CO2 Prophet model performs two main operations. The model generates streamlines to 

describe fluid flow between injection and production wells, and then performs oil displacement 

and recovery calculations along the streamlines using a finite difference routine to calculate oil 

displacement. CO2 Prophet handles areal sweep efficiency by incorporating streamlines that are 

a function of well spacing, mobility ratio, and reservoir heterogeneity. 

Required input parameters for the CO2 Prophet model fall into the following broad categories:

•Fluid property parameters 

•Reservoir property parameters

•Relative permeability parameters 

•Flood pattern configuration specifications

•Injection scenario parameters

Fluid properties that need to be defined before running the model include viscosity of oil, 

viscosity of water, solution gas-oil ratio, API gravity of oil, water salinity, and gas-specific 

gravity. Key reservoir properties that directly influence oil recovery are initial residual oil 

saturation, Dykstra-Parsons coefficient, oil and water viscosity, reservoir pressure and 

temperature, and minimum miscibility pressure (assuming flooding operations are to be carried 

out about the MMP). Mixing parameters, as defined by Todd and Longstaff (1972) and detailed 

in Appendix A, are used in CO2 Prophet for simulation of the miscible CO2 process, particularly 

CO2/oil mixing and the viscous fingering of CO2.

The CO2 Prophet model contains a set of standard reservoir patterns, including 5-spot, line-drive, 

and inverted 9-spot (commonly used injection patterns are summarized in Figure 3-4 and Table 

3-8); custom well patterns can also be defined by the user in the Prophet model. CO2 Prophet

injection parameters can be modified to simulate a variety of recovery processes, including 

continuous miscible CO2, WAG miscible CO2 and immiscible CO2, as well as waterflooding. 

Performance of the CO2 Prophet model in prediction of miscible flooding (1 HCPV, California 

San Joaquin Basin, Elk Hills reservoir) was previously reported to compare favorably with 

modeling results derived from an industry standard reservoir simulator, GEM. Despite the 

absence of a gravity override parameter in the Prophet model, it was demonstrated to provide an 

oil recovery prediction that is neither overly pessimistic nor overly optimistic, and was therefore 

determined to be an acceptable tool for scoping of reservoir performance (NETL, 2008). 
32

Adapted from Manning and Thompson (1995)

Figure 3-4 Illustration of Several Well Geometries Commonly Used for Enhanced 

OilRecovery
33

Table 3-8 Production Well to Injection Well Ratio for a Series of Common EOR Well 

Patterns

Pattern type Drilling Pattern Well Ratio

Producers : injectors

Direct Line Drive Rectangle 1

Staggered Line Drive Offset 1

Five-Spot Square 1

Inverted Five-Spot Square 1

Seven-Spot Equilateral Triangle 0.5

Inverted Seven-Spot Equilateral Triangle 2

Normal Nine-Spot Square 0.33

Inverted Nine-Spot Square 3

Referenced from Manning and Thompson (1995)

Finally, injection schedule is a function of operator preference and reservoir injectivity 

limitations. As detailed above, the rate and order in which CO2 and brine are injected in a WAG

injection scenario will affect the rate of oil and gas production, time to CO2 breakthrough, and 

ultimate resource recovery efficiency of the flood. 
34

 

(a) area of 5-spot well pattern (b) portion of 5-spot pattern simulated in CO2 Prophet model

Figure 3-5: Surface Area of a 5-Spot Well Pattern and Portion Simulated in Prophet Model

Source: CO2 Prophet Model Documentation (1986)
35

3.4.1.1 Estimation of CO2-Flood Performance Using CO2 Prophet Screening Model

Reservoir parameter values used to define the CO2-EOR base case considered in this study were 

taken from the average values reported in the proprietary database developed by ARI, Inc., and 

provided to NETL under a license agreement (ARI, Inc., 2009). This database reports reservoir 

characteristics, reservoir fluid property, well count, cumulative historical production data for 228 

reservoir cases within the Permian Basin, as well as data for Mid Continent (OK, AR, KS, NE), 

Rockies (WY, UT, CO), California, Gulf Coast, Williston Basin, East and Central Texas, 

Illinois, and Appalachian basins. Permian Basin-type parameter values were selected because 

the Permian Basin is both the location of the majority of current CO2-EOR activity, and because 

it holds significant potential for future domestic tertiary incremental oil production.

Identifying Representative Reservoir and Fluid Properties for Use in Analysis Scenarios. 

Data reported in the ARI “Big Oil Fields Database” were not used directly to define the reservoir 

scenario used in base case and subsequent scenario analyses of CO2-EOR Operations. Because 

this database is a proprietary resource, direct reporting of these data was not permitted. In 

addition, evaluation of a particular reservoir was not necessary, given that the goal of this effort 

was to more generally evaluate CO2-EOR relative performance under different operational 

scenarios. The database was, however, used to identify acceptable ranges of parameter values 

for a single basin. Distribution metrics (mean, standard deviation, median, minimum value, 

maximum value) for a number of reservoir and reservoir-associated fluid parameter values were 

considered and basin-representative values within the range of observed values were selected. 

Selected parameter values for reservoir and fluid properties are listed in Table 3-9 and Table 

3-10, along with mean, standard deviation, and median values for the Permian basin from the 

ARI “Big Oil Fields” database (based on a nominal sample size of 228 reservoirs).

Table 3-9 Fluid Parameter Values Used in Modeling of CO2-EOR Scenarios and Mean and 

Standard Deviation Values from ARI Database Permian Basin Reservoirs (n=228)

Parameter 

Description

Parameter 

Value Used in 

This Study

ARI 

Database 

Mean

Standard 

Deviation Median Units

Viscosity of oil 1.76 4.67 24.78 1.76 cp

Viscosity of water 0.72 0.721 0.228 0.72 cp

Oil formation volume 

factor 1.2 1.199 0.156 1.16 (RB/STB)

Solution gas-oil ratio 805 804.5 1138.9 500 scf/STB

API Gravity of Oil 36 36.29 5.55 36 oAPI

WATER SALINITY 96,000 95,934 62,480 90,000 parts per million

Gas specific gravity 0.65 0.650 0.003 0.65 (Air = 1.0)

C5+ 183 * * * g/mole

* Calculated from ° API
36

Table 3-10 Reservoir Parameter Values Used in Modeling of CO2-EOR Scenarios and 

Mean and Standard Deviation Values from ARI Database for Permian Basin Reservoirs 

Parameter Description

Parameter 

Value Used 

in This 

Study

ARI Database

Units No. of 

samples Mean Std. Dev. Median

Reservoir temperature 123 228 123.5 35.6 112 oF

Reservoir pressure 2,368 205 2,368.5 1,124.7 2,100 psia

Minimum miscibility 

pressure 

1523 - b b b psia

Dykstra-Parson 

Coefficient in the 

production zone

0.73 224 0.73 0.151 0.75 dimension

-less

Average permeability of 

the reservoir production 

zone

29 228 28.97 135.5 8 md

Total vertical depth 5,826 224 5,826.4 2,665.7 4,700

Feet to 

top of 

reservoir

Net pay (thickness) of 

reservoir 76 228 76.1 72.5 55 Feet

Actual porosity of field 0.11 228 0.11 0.0428 0.105 fraction 

(0-1)

Swept oil saturation 

value in all segments 0.32 228 0.306 0.054 0.30 fraction 

(0-1)

Initial gas saturation 

value in all segments 0 - a a a fraction (0-1)

a

 Not reported in ARI database, default value from CO2 Prophet used b

 Calculated from C5+ (calculated value) and mean reservoir temperature

Fluid relative permeability parameter values are not provided in the database and default values 

from the CO2 Prophet model are used except where noted. A complete list of relative 

permeability parameter assumptions are listed in Appendix A. 

Defining Flood Schedule in “Historical,” “State-of-Art,” and High CO2 WAG CO2-EOR 

Scenarios. In addition to fluid, reservoir, and relative permeability parameters, it was also 

necessary to specify the volumes and timing of injection of water and CO2 for each CO2-EOR 

operational scenario. The specific injection schedules used in previous studies to evaluate each 

CO2-EOR operational scenario were not explicitly defined. Injection schedule parameters were 

selected based on the author’s best understanding of descriptions given in previously published 

reports. 

“Historical” CO2-EOR, as defined in DOE Basin-Specific CO2-EOR studies and subsequent 

NETL studies, assumes a WAG injection of 0.4 HCPVs. Table 3-11 summarizes model 

parameters that have been used to define a “historical” CO2- EOR flood. This scenario calls for 

injection of a water slug following completion of CO2 WAG injection in order to recover 

remaining mobile oil and a small amount of CO2 that will be used in less mature and nearby 

patterns. 
37

Table 3-11: Injection Schedule Parameters Used in Defining “Historical” Miscible CO2-

flood EOR in the CO2 Prophet Screening Model

Parameter Description CycleaUnits

1 2 3 4

Water/CO2 Injection Ratio - 1.0 2.0 inf. HCPV:HCPV

Incremental hydrocarbon pore 

volumes CO2 injected. 0.2 0.1 0.1 0 HCPVs of CO2

Injection rate of water, in surface 

units (SURF BBL/D) - 562 562 562 surface bbl/day

Injection rate of CO2, in surface 

units (MMscf/D) 1.24 1.24 1.24 - MMscf CO2/day

a All injection cycles reported in terms of volume, as opposed to time.

As defined in previous studies (NETL, 2008) and summarized earlier, “best practices” CO2-EOR 

operational scenario involves injection of significantly higher volumes of CO2 to increase sweep 

efficiency and improve incremental oil recovery over that which could be accomplished using 

“historical” injection design. To model this scenario, a total CO2 injection of 1.0 HCPV was 

specified, with injection performed using WAG process. In contrast to the historical CO2-EOR 

scenario, no water slug is applied at the end of WAG injection. Model parameters selected to 

describe “best practices” WAG injection scenario are summarized in Table 3-12.

Table 3-12: Injection schedule parameters used in defining “best practices” miscible 

CO2-flood EOR in the CO2 Prophet screening model

Parameter Description CycleaUnits

1 2 3 4

Water/CO2 injection ratio - 1.0 2.0 3.0 HCPV:HCPV

Incremental hydrocarbon pore 

volumes CO2 injected 0.25 0.25 0.25 0.25 HCPVs of CO2

Injection rate of water, in surface 

units (SURF BBL/D) - 562 500 562 surface bbl/day

Injection rate of CO2, in surface 

units (MMscf/D) 1.24 1.24 1.24 1.24 MMscf CO2/day

a All injection cycles reported in terms of volume, as opposed to time.

Modeling High-CO2 Injection Scenario

As described above and detailed in a previously published NETL report entitled Storing CO2

with Next Generation Technology, the “next generation” CO2-EOR technology scenario calls for 

increased injection above the “best practices” scenario of 1.0 HCPV, to 1.5 HCPV. As with the 

“best practices” scenario, a tapered WAG is also employed, with CO2 recycling. “Next 

generation” CO2-EOR scenarios requiring infill well placement, or polymer addition to increase 

water viscosity to 3 centipoise, or miscibility extenders are not considered in this study. As with 

“best practices” CO2-EOR (and in contrast to “historic” CO2-EOR), the “next generation” 

scenario does not call for a water slug to be injected following completion of the CO2 slug, 

allowing more CO2 retention in the formation than would be observed with “chase” water sweep. 

Injection schedule defining the high CO2 injection scenario considered in this study is detailed in 

Table 3-13.
38

Table 3-13 Injection Schedule Parameters Used in Defining 1.5 HCPV CO2 Miscible WAG 

EOR in the CO2 Prophet Screening Model

Parameter Description CycleaUnits

1 2 3 4

Water/CO2 injection ratio - 1.0 2.0 3.0 HCPV:HCPV

Incremental hydrocarbon pore 

volumes CO2 injected. 1 0.4 0.4 0.4 0.3 HCPVs of CO2

Injection rate of water, in surface 

units (SURF BBL/D)1 - 562 562 562 surface bbl/day

Injection rate of CO2, in surface 

units (MMscf/D)1 1.24 1.24 1.24 1.24 MMscf CO2/day

a All injection cycles reported in terms of volume, as opposed to time.

Definition of Well Pattern and Injection Characteristics

For this study, a forty-acre, five-spot pattern has been for all CO2-EOR scenarios. The 

assumption of a 40-acre, five-spot well pattern is in line with that which was made for historic 

and best practices scenarios in previous NETL CO2-EOR studies (U.S. DOE NETL, 2008). This 

well configuration has a corresponding injection/production well ratio of 1:1. 
39

3.4.2 Results of CO2 Prophet Runs for Individual Flood Pattern

The following series of figures provide illustration of single-well pattern fluid injection and 

production profiles for the three previously described injection scenarios: historical, best 

practices, and 1.5 HCOV CO2 WAG injection. Plots of incremental and cumulative injection of 

water (thousands of standard barrels [MSTB] per year) and CO2 (millions of standard cubic feet 

[MMscf] per year) define the injection schedule appropriate for each scenario. Incremental 

production estimates for all fluids (oil, brine, CO2, and hydrocarbon gas) are also plotted. These 

model inputs and outputs serve as the basis on which estimates of incremental oil and gas 

production, CO2 storage potential, fluid processing infrastructure requirements, processing 

resource demands, and environmental emissions have been developed.
40

Figure 3-6 Incremental Water Injection Schedule for WAG Injection Scenarios (MSTB water/year)
41

Figure 3-7: Incremental CO2 Injection Schedule for WAG Injection Scenarios (MMscf CO2/year)
42

Figure 3-8 Cumulative CO2 Injection Profile for WAG Injection Scenarios (MMscf)
43

Figure 3-9 Cumulative Water Injection Profile for WAG Injection Scenarios (MSTB)
44

Figure 3-10 Cumulative Oil Production Profile for WAG Injection Scenarios (MSTB)
45

Figure 3-11 Cumulative Water Production Profile for WAG Injection Scenarios (MSTB)
46

Figure 3-12 Cumulative CO2 Production Profile for WAG Injection Scenarios (MMscf)
47

Figure 3-13 Incremental Oil Production for WAG Injection Scenarios (MSTB/yr)
48

Figure 3-14 Incremental Water Production for WAG Injection Scenarios (MSTB/year). Dotted line in historical CO2-EOR 

scenario represents brine production response after initiation of water slug.
49

Figure 3-15 Incremental CO2 Production for WAG Injection Scenarios (MMscf/year)
50

Figure 3-16 Incremental Hydrocarbon Gas Production for WAG Injection Scenarios (HCPVs)
51

Results will be discussed in greater detail in later sections, but it should be noted that modeling 

results show incremental oil production to increase with increasing CO2 injection (Table 3-14), 

in agreement with the previously discussed field observations and the adopted definition of CO2-

EOR scenarios. 

Table 3-14 Oil Recovery Efficiency (Percent of Original Oil in Place Recovered) as 

Estimated Based on CO2 Prophet Screening Model Characterization of Three WAG 

Scenarios

CO2-EOR Scenario HCPV CO2

Injected

Oil Recovery, % 

OOIP

Single Pattern 

Flood Duration (years)

Historical 0.4 11.6 17

Best Practices 1 17.4 25

1.5 HCPV CO2 WAG 

Injection 1.5 20.9 36

Average fluid flow values for the proceeding set of model output plots are summarized in Table 

3-15. Because flood duration differs between operational scenarios, values are reported on the 

average of the life cycle values (a per-pattern year basis) to facilitate direct comparison (all 

scenarios assume a 40-acre, 5-spot configuration). 

Table 3-15 Summary of Model Results for Injection and Production Stream Fluid Flow 

Reported on a per Pattern Year Basis (40-Acre, 5-Spot Pattern Configuration)

Parameter

CO2-EOR Operational Scenario

Units

Historical Best 

Practices

1.5 HCPV CO2

WAG

Water Injected 157.0 123.3 119.8 MSTB/(pattern-yr)

CO2 Injected 106.4 180.9 185.5 MMscf/(pattern-yr)

Brine Produced 163.0 133.1 126.5 MSTB/(pattern-yr)

Crude Oil Produced 11.3 12.1 10.0 MSTB/(pattern-yr)

Total Liquids Produced 174.3 145.2 136.6 MSTB/(pattern-yr)

CO2 Produced 63.9 127.7 147.6 MMscf/(pattern-yr)

HC Gas Produced 9.1 9.7 8.1 MMscf/(pattern-yr)

Total Gas Produced 73.0 137.4 155.7 MMscf/(pattern-yr)

Produced fluids are rarely treated at the production well or on an individual pattern basis, but 

generally are transported to a sattellite or central facility where fluids from multiple wells are 

combined and treated. As is described in the following section, the oil, hydrocarbon gas, CO2, 

and brine production estimates developed for a single well pattern are used to develop life cycle 

performance estimates for those operations located downstream of the production well that 

processes flow from a number of producing wells. 
52

Calculated Produced Fluid Loading to Tank Battery from 10 CO2-EOR Patterns

It is assumed that produced fluid from ten CO2-EOR patterns is collected to and processed at a 

single tank battery. Size, throughput, and quantity of unit process elements (equipment) have 

been determined based on the total fluid flow entering each process element. Resource 

requirements and emissions for each process element were then calculated based on equipment 

size, throughput, and estimated fluid properties.

Central tank batteries collect and process fluid that is produced from more than one production 

well. For purposes of this study, it has been assumed that each well pattern feeding a single tank 

battery initiates fluid injection at six-month intervals, thereby distributing predicted peak fluid 

injection and production over 4.5 years for the assumed 10-pattern tank battery. This assumption 

is in line with established rules of thumb for assumed (roll out) of CO2-EOR patterns of 

approximately 10-20 percent of the total flood duration (approximately 3-6 years for the nextgeneration EOR scenario considered herein). Figure 3-17, 3-21, 3-22, and 3-23 illustrate the 

incremental production rates of total fluid, oil, water, CO2 and hydrocarbon gas production from 

ten wells (as a function of time) when injections for each pattern are initiated at six-month 

intervals and all patterns are operated according to “historical” CO2-EOR practices. 
53

Figure 3-17 Incremental Oil Production Data from 10 Well Patterns Operated Under Three WAG Scenarios, 

with Injection Initiated at Six-Month Intervals for Each Pattern (MSTB/year)
54

Figure 3-18 Incremental Water Production Data from 10 Well Patterns Operated Under Three WAG Scenarios, 

with Injection Initiated at Six-Month Intervals for Each Pattern (MSTB/year)
55

3.5 Phases of CO2-EOR Facility Operation

Five phases of CO2-EOR facility life have been considered:

• Site Evaluation and Characterization

• Facility Design and Construction

• Facility Startup and Operation

• Site Monitoring, Verification, and Accounting

• Facility Closure and Decommissioning

An attempt has been made to quantify material and energy flows associated with each of these 

phases of site operation, including resource demands, environmental emissions, and incremental 

hydrocarbon production. 

3.5.1 Site Evaluation and Characterization

Enhanced oil recovery operations have taken place at sites where extensive disturbance to the 

subsurface has already occurred, where many penetrations into the target formation or confining 

strata are likely to exist. In many cases, the location of these wells is known, but it is also 

common to encounter abandoned fields or some very old fields with some abandoned wells that 

may or may not be locatable using traditional physical survey techniques. These penetrations 

could serve as a conduit for leakage of CO2 from target formations, thereby decreasing CO2-

EOR effectiveness, decreasing overall CO2 storage, and creating a hazard to human health. 

Therefore, it will be appropriate to review well files, regulatory maps and any available well log 

and surveying databases to locate these penetrations. It will also be prudent to conduct new 

reconnaissance land surveys, and to use ground or airborne magnetometry geophysical surveying 

techniques to locate wells that may be buried below the surface of the ground. 

Following location of all wells, a determination must be made on whether or not an existing well 

can be used as a CO2/water injection well or production well in proposed CO2-EOR operations. 

In addition, to visual inspection, mechanical integrity testing of old wells may be performed to 

establish utility of existing wells for such applications. It will be necessary to establish baseline 

conditions above or adjacent to the target formation to facilitate future monitoring, verification, 

and accounting efforts. This may involve testing of the vadose zone, groundwater, or surface 

water to capture information on trends such as seasonal variations. Similarly, baseline 

geophysical surveys will likely also be required so that change can be observed during the 

injection phase or during post-injection MVA.

For purposes of this study, it has been assumed that one airborne geophysical/remote sensing 

survey is performed over the full surface area of CO2-EOR activity, using light detection and 

ranging (LIDAR) and magnetometry to collect detailed site elevation and surface feature survey 

and screening for abandoned wells with no surface features, respectively. It has also been 

assumed that one legacy well that penetrates the target injection formation is located per square 

mile of survey area, and that that identified well is not reused in CO2-EOR operations (U.S. EPA, 

2008). Emissions associated with airborne and survey have been considered. It is assumed that 

abandoned wells located within the area of review are plugged to prevent CO2 leakage from the 
56

target formation and prevent deterioration of overlying underground sources of drinking water 

(USDWs). Well plugging activities often include pulling lower portions of the well’s 

(longstring) casing and cementing the abandoned well, but only cementing of the abandoned well 

is considered herein. The assumed number of legacy wells for which re-plugging is required 

corresponds to 0.0625 abandoned wells per 40-acre pattern. Values of abandoned well per 

pattern year are, then, estimated as 0.0625 divided by the number of years of operation per 

pattern, which varies as a function of CO2-EOR scenario. Values are 0.00368, 0.00250, and 

0.00184 abandoned wells per pattern year for historical, best practices, and 1.5 HCPV CO2 WAG 

injection scenarios, respectively. Well-plugging diesel- fuel demand and emissions per patternyear are reported in Table 3-16 for each operational scenario.

Table 3-16 Emissions Profile from Abandoned Well Plugging Operations Reported per 

40-Acre Pattern Year Based on Operational Scenarios Described Herein

Historical Best 

Practices

1.5 HCPV CO2

WAG Injection Units

HC 1.05E-02 7.13E-03 5.25E-03 kg per pattern year

CO 8.34E-02 5.67E-02 4.17E-02 kg per pattern year

NOX 1.57E-01 1.07E-01 7.86E-02 kg per pattern year

PM Total 4.00E-03 2.72E-03 2.00E-03 kg per pattern year

PM10 3.88E-03 2.64E-03 1.94E-03 kg per pattern year

PM2.5 1.20E-04 8.16E-05 6.00E-05 kg per pattern year

SO2 2.25E-06 1.53E-06 1.12E-06 kg per pattern year

CO2 33.35 22.7 16.7 kg per pattern year

Diesel Fuel 10.47 7.12 5.23 kg per pattern year

Diesel Fuel 3.30 2.24 1.65 gallons per pattern year

3.5.2 Facility Design and Construction

3.5.2.1 CO2-EOR Facility Overview

The CO2-EOR facility is considered to include all surface infrastructure elements associated with 

fluid injection and injectate transport, fluid production and transport, and produced fluid 

processing (including both liquids processing at tank batteries and gas processing plant to 

separate hydrocarbon gas and natural gas liquids from CO2 recycle stream). Infrastructure 

elements associated with delivery of CO2 to the oil field and those associated with transport of 

products from the site are not included within the study scope. A standard 5 spot well 

configuration with 40 acre pattern surface area has been assumed for all scenarios (with an 

injection: production well ratio of 1:1, as described in Table 3-8). In addition, it should be noted 

that a number of process elements have been assumed to be pre-existing. The pre-existing 

infrastructure elements have been excluded from consideration in this LCA.

3.5.2.2 Overview of Site Preparation for CO2-Flood EOR

It has been assumed that the reservoirs for which CO2 flood tertiary EOR would be considered

are sites that have already undergone water flood secondary EOR operations. As such, many of 

the infrastructure elements and fluid processing/management components are assumed to be
57

already present on site at the initiation of tertiary recovery site preparation. Those infrastructure 

elements and fluid processing components that are assumed to be pre-existing include:

• Water tanks

• Crude oil tanks

• Injection wells 

• Production wells

• Produced fluid collection lines

• Water distribution lines

New process elements for which construction has been included are:

• CO2 distribution lines

• Gas processing facility

• Recycle CO2 compressors

• Tank battery vapor recovery unit

It is assumed that pre-existing secondary EOR injection and production wells can be reused for 

tertiary recovery operations, but that significant refurbishment will be required, in the form of 

well workover and recompletion, before fluid injection for tertiary recovery is initiated. 

Because the site is assumed to be maintained up to the time of initiation of tertiary recovery 

operation as part of secondary EOR operations, site clearing and preparation are assumed to not 

be required. Similarly, necessary access roads and utility right-of-way are assumed to already be 

in place.

3.5.2.3 U.S. EPA UIC Injection Well Classes

EPA-promulgated rules establish Underground Injection Control (UIC) regulations (40 CFR 

144.6) for protection of USDWs. In this regulation, five classes of wells have been established 

(with a sixth proposed) based on types of fluid injected, construction specifications, injection 

depth, and operating techniques (including related monitoring and verification activities). Class I 

wells are used for safe disposal of hazardous and nonhazardous fluids (both industrial and 

municipal wastes) into isolated formulations below the lowermost USDW, and are subject to 

stipulations of both the Safe Drinking Water Act and the Resource Conservation Recovery Act. 

Class II wells describe wells used for fluid injection in relation to conventional oil or natural gas 

production, enhanced oil or gas production, and storage of hydrocarbons that are liquid at 

standard temperature and pressure. Class III wells are used for solution mining. Class IV wells 

are specified in rare cases where hazardous or radioactive wastes are approved for injection into 

or above USDWs (typically groundwater remediation scenarios). Class V wells are those not 

covered in Classes I through IV; this class includes shallow, onsite disposal of nonhazardous 

fluids into or above USDWs such as floor and sink drain disposal. Class V wells have also been 

employed for experimental injection of CO2 into reservoirs that do not contain significant 

quantities of hydrocarbons to demonstrate geologic sequestration of anthropogenic CO2 (for 

example, in brine aquifers). A Class VI well type has been proposed by the EPA to formalize 

regulatory requirements of dedicated anthropogenic CO2 disposal through geologic sequestration 

(GS) not associated with oil and gas production. In July 2008, the EPA published the federal 
58

requirements for CO2 GS wells under the UIC Program, and public comment period ended on 

December 24, 2008. In August, 2009, Notice of Data Availability and Request for Comment (45 

day public review and comment period) was issued. Final rule on Class VI wells has not yet 

been issued (U.S. EPA, 2009). 

3.5.2.4 Overview of New Brine Disposal Well Construction

Excess brine is generated through CO2-EOR activity, and it is assumed that new wells must be 

constructed for disposal of this byproduct stream. Saltwater disposal wells (SWD wells) may be 

constructed to inject into either non-commercial portion of the hydrocarbon-bearing reservoir, or 

a hydrocarbon bearing reservoir that is sufficiently distant from active CO2-EOR operations as to 

not impact fluid production in active flood patterns (U.S. EPA, 2006). It is, therefore, assumed 

that excess brine is disposed of in a formation that is at the same depth as the formation targeted 

for CO2-EOR activity. New well construction is carried out using drill rigs of scale and 

specification typical of those commonly used in oil field infrastructure placement in the Permian 

Basin. 

Injection wells are designed to confine injected fluids to the targeted injection zone and prevent 

migration of injectate (e.g., brine) into penetrated USDWs. In CO2-EOR operations, injection 

wells are drilled into oil bearing reservoirs capable of accepting injection fluids (i.e., CO2, water) 

to stimulate oil production. Brine and acid gas disposal wells are also sometimes required to 

manage the production of unwanted fluids. Low- permeability confining zones overlie the 

injection target formation and restrict the upward migration of the injected fluids. Injection 

pressure must be controlled at the surface to avoid fracturing these confining zones. New 

injection wells are drilled and cased with steel pipe, and the steel casing pipe is cemented into 

place to prevent catastrophic well blowout and gradual migration of fluids to the surface or into 

USDWs. A typical injection well will also have a string of tubing located inside of the casing 

through which fluid injection takes place. Fluid is isolated to the targeted injection zone by a 

packer, which seals off flow into the innermost casing and facilitates leak detection. The 

following sections provide more detailed consideration of brine-disposal injection-well design 

and construction. In cases of new well construction, drilling operations, casing material (all wells 

are assumed to be cased, as compared to open-hole, completions), cement, and associated well 

components have been considered in the life cycle environmental inventory. As described 

elsewhere, some old or abandoned wells may be acceptable for repair or reuse in newly 

commissioned CO2-EOR operations. 

3.5.2.5 Estimation of Brine Disposal Well Injectivity and Storage Capacity 

Lyons (1996) reports a range of typical injectivity index values between 8 and 15 barrels per 

(day-net feet). Using this range and the target formation net thickness of 76 feet gives a range of 

between 600 and 1140 barrels per day. A survey of water injection practices near the Waste 

Isolation Pilot Plant in southeastern New Mexico (US DOE, 2003) reports that of 39 salt water 

disposal well (SDW) injection wells near the facility, the average injection rate was 1,250 barrels 

per day per well. A report by the Texas Water Development Board and the Texas Bureau of 

Economic Geology cites a mean injection rate of 10 gallons per minute (approximately 340 

barrels per day) in the Permian basin (calculated based on estimated formation and fluid 

properties, and a maximum surface injection pressure gradient of 0.5 psi/ft to top of injection 

interval). 
59

A robust resource for data on the cumulative capacity of brine disposal wells in the Permian 

Basin was not identified. One report considering the storage capacity of wells near the U.S. 

DOE Waste Isolation Pilot Plant cited cumulative injection volume into David Ross AIT Federal 

Number 1 of 1.3 x 106 cubic meters (1.3 billion liters, or 8.2 million barrels, and assuming a 

brine density of 1.1 kg/liter, 1.5 million metric tonnes). Dedicated disposal wells in Ohio are 

reported to have capacities of up to 20 million tonnes of injectate—a capacity significantly larger

than referenced for the New Mexico well. A brine-disposal cumulative storage capacity of 1.3 

billion liters is assumed, but this characterization would benefit from more robust and 

geographically appropriate sources of data; this is noted as a data limitation. The capacity and 

injectivity estimates reported herein have been employed to estimate the number of brineinjection wells that will be required to accept excess brine produced as a result of CO2-EOR 

activity. 

3.5.2.6 Estimation of Brine Injection Wellhead Pressure 

Brine-injection well head pressure, the pressure to which brine must be pressurized to maintain 

fluid injectivity, is estimated by back-calculating from maximum bottom hole pressure. 

Wellhead pressure is calculated as the bottom hole pressure minus allowable static fluid pressure 

plus the sum of all frictional losses through the well. Static water pressure is estimated by 

multiplying the depth to formation midpoint (5826 + 76/2, or 5864 feet) feet by an assumed 

hydrostatic gradient of brine of a density of 64.8 lbs/ft3 (0.45 lb/psi) to get 2,638 psi. Pressure 

drop in the tubing is relatively small given the prescribed tubing internal diameter of 2 7/8 

inches—on the order of 10 psi per thousand feed of tubing. This corresponds to a pressure drop 

of approximately 60 psi along the full tubing length. Applying the default fracture gradient of 

0.5 psi/ft to the top of the injection reservoir that is prescribed by the Texas Railroad 

Commission, the associated maximum bottomhole pressure would be 2,914 psig; taking into 

account previously calculated hydrostatic pressure and pressure drop, this corresponds to a 

maximum wellhead pressure of 335 psig. Because injection wells are typically operated at or 

near the maximum permitted injection pressure, a brine injection wellhead pressure (and the 

pressure to which produced brine must be pressured before injection into the reservoir) of 300 

psi is assumed for this study. Injection at higher pressure may be an option, but the operator 

would first need to demonstrate that the formation and infrastructure elements are capable of 

accommodating higher pressure (brine disposal at pressures greater than the fracture threshold is 

typically permitted if the injection well passes a fracture step rate test). It is worth noting that, 

throughout the history of CO2-EOR in the Permian Basin, fields have safely accommodated 

higher surface injection pressure than that specified by the default fracture gradient, whereas

operations in other basins have not (Melzer, 2010).

3.5.3 Well Drilling and Completion

Oil production, injection, and fluid disposal wells are drilled using similar technology and 

equipment. Modern drill rigs are designed to perform four main tasks:

• Produce and transfer power

• Hoist equipment used in well completion, including drill string, casing, and tubing used 

for fluid transfer

• Rotate the drill string and bit to drill the well bore
60

• Circulate drilling mud that is used to remove cuttings from the drilling front and maintain 

pressure in the well bore

Diesel fuels are the most common source of power used in drilling operations. Diesel is 

combusted in large engines to drive electric generators that produce electric power that is used 

by electric motor-driven elements of the mechanical system (including drawworks that are used 

for hoisting, the turntable that is used to turn the kelly to rotate the drill string and bit, and mud 

pumps used to circulate drilling mud to the bit). For more detailed consideration of drilling 

operations, the interested reader is directed to any of a number of texts dedicated to the topic.

Consideration of new well construction in this report is limited to the following elements:

• Delivery of drill rig elements to the well site, including power station, mechanical 

systems, drill string, dog house, steel casing, derrick, and substructure (includes diesel 

used to deliver drill rig elements, particulate emissions from off-road travel, and 12,000 

gallon diesel storage tank emissions)

• Assembly of drill rig elements

• Operation of drill rig (diesel consumption, cooling water use, mud, cuttings from drilling 

operation)

• Break-down of drilling elements 

• Construction of permanent well elements, including steel used in casing, cement used to 

secure and seal casing, tubing used in operation, and water used in producing cement)

3.5.3.1 Drill Rig Description 

Sub-6,000 foot rigs generally employ sub-500 horsepower rigs (Land Rig Newsletter, February 

2009), but a cursory review of rigs operating in the Permian Basin play suggest that a rig with 

drilling capacity of 550 horsepower may be appropriate. Performance of the drilling rig is 

estimated using rig number 472 (http://patdrilling.com/pdf/rigs/472.pdf), which operates with 

two Caterpillar 3408 engines (475 HP each). Specifications for major rig elements are 

summarized in Table 3-17; additional detail is provided in 

Appendix F.

Table 3-17 Specifications Used to Characterize Drill Rig

Rig Element Equipment Description

Power plant (2) Caterpillar 3408 engines (475HP each)

Drawworks National 370-M (550HP)

1 1/8” drill line, Parmac 22-SR auxiliary brake

Mast DSI 132’ w/ 322,000# capacity on 8 lines

construction

Substructure DSI 14’ box

KB 13’ 6” Rotary beam clearance 9’ 4”

Mud Pumps

(2) Continental Emsco DB-550 (550HP each) duplex

pumps

(1) Powered by a Caterpillar 379 engine

(1) Powered by a Caterpillar 353 engine

Rotary table Gardner Denver (17 1/2”)

Drill pipe 4 1/2” drill pipe
61

3.5.3.2 Wellbore Design 

The wellbore consists of three primary components: casing, cement, and the wellhead assembly. 

The wellbore casing is a set of steel pipes that are cemented in place during the construction 

process in order to stabilize the wellbore, prevent caving into the wellbore, isolate near-surface 

formations to prevent fluid contamination into USDWs, seal off permeable formations from 

cross-flowing into others, and to facilitate maintenance of fluid pressure during well operation. 

Sometimes as many as four to five casing strings are emplaced with the smallest diameter one, 

called the long-string, set to the maximum depth of the well (Melzer, 2010). A wellhead 

assembly is located at the surface termination of a wellbore, and includes functionality to install 

casing hangers during well construction, hang the production (or injection) tubing, and install the 

“christmas tree” and surface flow control facilities in preparation for the production phase of the 

well. Cement used to secure well casing and prevent cross-flow of pressurized fluids has 

traditionally been made from a variety of ingredients, including Portland cement, fly ash, and 

clay admixtures. These cements have been required to perform in highly acidic fluid 

environments, much more acidic than those expected with CO2 injection. 

Injection well design is assumed to be the same as that used for CO2 injection in the Frio 

Sandstone Formation as defined by Hovorka and colleagues (2003). Prior to initiation of drilling 

activities, 14-inch conductor casing is installed to approximately100 ft in a hole of 171⁄2 inches in 

diameter. After setting the conductor pipe, the surface hole is drilled to a depth of approximately 

2,600 ft at a diameter of 121⁄4 inches, and a 95/8-inch surface casing is cemented along the full 

length. The injection well is completed with a 51⁄2-inch production casing string (also cemented 

between outside of casing pipe and 71/8 inch drill hole wall along the deep-section length of 

5,826 feet), and 27⁄8 -inch tubing installed inside the protection casing through which injected 

fluid is conveyed to the target reservoir.

Table 3-18 Specifications Used to Characterize Injection Well: Casing, Injection Tubing, 

and Drill Pipe

Tubular Depth

(ft)

Nominal 

Size

(inches)

Weight

(lb/ft) Grade

Estimated 

mass of 

steel 

(short 

tons)

Number of 

30 ft.

segments

Estimated 

number 

of tri-axle 

truck 

loads

Conductor 1–100 14 54.6 A-36 54.6 2 1

Surface 

casing 

0–

2,600 95⁄8 36 J-55 45 87 3

Protection 

casing 

0–

5,826 51⁄2 15.5 J-55 45 195 3

Injection 

tubing 

0–

5,826 27⁄8 6.5 API N-80 19 195 1

Drill Pipe 0–

5,826 5 14.87 API Spec 

5D 43 195 3
62

3.5.3.3 Cementing Operations 

Cement is pumped (“squeezed”) from the bottom of the hole using a one-way valve between the 

external wall of casing pipe and the drilled well hole. This affords additional protection to 

prevent gradual leakage of deep fluids from the injection target formation to overlying drinking 

water aquifers and the surface, as well as providing isolation of the pressured formations from 

anything but the wellbore. The volume of cement slurry required to cement the casing was 

estimated based on standard recipe for API Class A cement, requiring 5.2 gallons of water per 

94-lb sack of dry cement. Assuming standard porosity of dry cement of 52 percent (Chilingar et 

al., 1989), the resulting slurry has a density of 1.18 ft3

/sack of cement. Volume of the cement is 

estimated to be approximately 1,722 ft3 (49 m3)—the space between each casing and the drill 

hole wall or the space between each casing and the inner wall of the next larger diameter 

concentric casing pipe. Based on well specifications provided in Table 3-18, an estimated 1,466 

sacks of cement (69 short tons or 62.5 metric tonnes of cement) and 8,500 gallons of water (32 

short tons or 29 metric tonnes of water) are required.

3.5.3.4 Rig Delivery and Rig Up 

Resource demands and emissions related to delivery of drilling rig elements are characterized by 

estimating the number of heavy-rig truck round trips to deliver all drill rig elements, assuming a 

round trip distance of 50 miles. The rig is assumed to be of modular design, with each module 

delivered to the well site in a single tractor trailer load. Based on drill rig layout blueprints 

available online (Integrated Drilling Equipment, 2004), an estimated 25 skid-mounted rig 

elements are delivered by a single tractor trailer. This count is assumed to include drill pipe 

required for drilling, but not other tubular elements of the wellbore casing. Based on estimates 

listed in Table 3-18, an additional eight round trips will be required to deliver well casing and 

tubing. Delivery of drilling mud, Portland cement, and fresh water to the well site are not 

considered. Assuming a fuel efficiency of 6.21 miles per gallon and a round trip distance of 50 

miles, approximately 8 gallons of ultra-low sulfur diesel fuel are used per round trip. An 

estimated 48 50-mile round trips are required to deliver rig elements and well components, using 

approximately 386 gallons of diesel fuel. It is assumed that this volume of diesel fuel includes

removal of rig elements after drilling operations are complete.

Emissions from diesel fuel combustion associated with tractor trailer delivery of rig elements are 

calculated based on emissions levels at low altitude (Midland-Odessa, TX elevation of 2,782 feet 

[848 meters]) for heavy-duty diesel powered vehicles of model years after 2001 as specified in 

EPA AP-42, Appendix H, and reported in Table 3-19.

Table 3-19 Emissions Estimate for Delivery of Rig Elements to Drilling Site

Pollutant Emissions 

Factor Estimated Emissions (kg) Source

Non-methane 

hydrocarbon 2.1 g/mile 5.04 U.S. EPA AP-42

Carbon monoxide 10.320 g/mile 24.8 U.S. EPA AP-42

NOX 6.490 g/mile 15.6 U.S. EPA AP-42

CO2

10,084 g/gallon 

diesel 3,899

U.S. EPA 

“Emissions Facts” 

(2009)
63

3.5.3.5 Operation of Drill Rig 

Operational parameters for the drill rig specified above with two 475-horsepower diesel engines

are summarized in Table 3-20.

Table 3-20 New Well Drilling Rig Performance Specifications

Parameter Value Units

Drilling time 10 days of continuous 

operation (504) Days (hours)

Rig power plant 2 x 475 No. engines x 

horsepower

Engine load factor 0.75 unitless

Break-specific fuel 

consumption 0.367 lb/hp-hr

Emissions 

performance

Meets Tier 2 emissions 

standards -

A California Air Resources Board document reports an average drill rig diesel demand of 1.55 

gallons per foot drilled (with a reported range of between 1.4 and 1.7 gallons per foot). 

Assuming that the reservoir is drilled to the bottom of the target reservoir (5,902 feet), an 

estimated per-well diesel demand of approximately 9,150 gallons is calculated. An alternative 

calculation method calculates fuel demand per well based on the number of diesel engines used 

in a drill rig, brake-specific fuel consumption estimates of each engine, and the estimated number 

of hours of rig operation per well drilled. Two 475-horsepower engines are specified in the rig 

package, and during the period of operation, it is assumed that both engines are in operation at a 

capacity factor of 0.75. The length of operation is estimated based on a reported spud-to-takedown period of 10 days. Using a brake-specific fuel consumption value of 0.367 lb/hp-hr, a drill 

rig diesel fuel usage rate of 8,964 gallons per well drilled is estimated. 

Combustion emissions from the drill rig are estimated based on the EPA Office of Transportation 

and Air Quality document entitled Exhaust and Crankcase Emission Factors for Nonroad 

Engine Modeling--Compression-Ignition (2004). Rig combustion emissions per well drilled 

were estimated based on methodology outlined in the EPA report, and results are shown in Table 

3-21. 

Table 3-21 Emissions Estimate for Drill Rig Operated in New Well Construction for Brine 

Disposal

Constituent Metric Tonnes (Short 

Ton) per Well Erilled

Total 

Hydrocarbon 0.0285 (0.0315)

CO 0.131 (0.144)

NOX 1.05 (1.16)

PM Total 0.0221 (0.0243)

PM10 0.0214 (0.0236)

PM2.5 0.000662 (0.000730)

CO2 90.7 (100)

SO2 0.139 (0.153)
64

Drilling Mud. Drilling fluid is employed during well-drilling operations for drill bit lubrication 

and cooling, removing cuttings from the drilling front, and borehole stability. It is assumed that 

water-based mud is used in all drilling operations. The composition of the assumed drill mud is 

reported in Table 3-22.

Table 3-22 Range of Water-Based Drilling Mud Composition as Reported by Eaton and

Colleagues (1981), and Average Composition Assumed for Drilling Mud Usage 

Calculations

Component

Concentration Range, kg/m3

(lb/bbl) per Eaton et al. 

(1981)

Average Mud Concentration 

(value assumed for this 

study), kg/m3 (lb/bbl)

Water 570 to 970 (200 to 340) 770 (270)

Bentonite 43-86 (15-30) 64.5 (22.5)

Lignosulfonate 5.7 to 29 (2 to 10) 17 (6)

Lignite 2.9 to 17 (1 to 6) 10 (3.5)

Sodium Hydroxide 2.9 to 14 (1 to 5) 8.5 (3)

Barite 0 to 1430 (0 to 500) 715 (250)

Based on an assumption that the volume of drill mud required is 1.5 times that of the total drilled 

volume of 3,100 ft3 (88 m3

) per well, the following total mass of mud components is estimated.

The mass of mud assumed to be managed as waste is estimated as the sum of all solids plus 50 

percent water, by mass (assuming 50 percent on-site dewatering before disposal).
65

Table 3-23 Estimated Mass of Drilling Mud and Mud Components, and Estimated Mass 

and Composition of Used Mud for Disposal

Component

Estimated Mass of Water-Based 

Mud Required to Drill a Single 

Well, Metric Tonne (Short Ton)

Estimated Mass of 

Dewatered Used Mud 

Managed as Waste 

Following Drilling of a 

Single Well, kg (lb)

Water 102 (112) 51 (56)

Bentonite 8 (9) 8 (9)

Lignosulfonate 2 (2) 2 (2)

Lignite 1 (1) 1 (1)

Sodium Hydroxide 1 (1) 1 (1)

Barite 94 (104) 94 (104)

Total 209 (230) 158 (174)

Solids Management. Used drilling mud that is produced from drilling operations is assumed to 

be directed to solids-control equipment consisting of a shale shaker and desander/desilter to 

remove drill cutting from the circulating mud. Cleaned mud is then returned to the mud pit for 

recirculation into the drill hole, and separated cuttings are characterized and disposed of 

appropriately (non-hazardous solids may be disposed of onsite, but solids exceeding Federal and 

state threshold concentrations of constituents of concern will require disposal at an approved 

facility). It is also assumed that solids generated as a result of drilling operations have 

concentrations below such thresholds and all solids are disposed of onsite. The volume of total 

drilling solids is assumed to be the same as the total well-hole volume, which is estimated as the 

sum of volumes of the holes drilled for conductor, surface casing, and production casing to be 

approximately 3,100 ft3. At the end of drilling operations, it is assumed that drilling mud is 

dewatered, characterized, and disposed of in accordance with Federal and state requirements. 

Separated water will be sent to tank battery water storage and either injected as part of CO2-EOR 

WAG injection or disposed of in adjacent brine disposal well.

Drilling Mud Degassing CH4 Emissions. Drilling fluid employed during well drilling 

operations for drill bit lubrication and cooling, removing cuttings from drilling front, and 

pressure maintenance accumulates gas at pressure and degasses when removed to atmospheric 

pressure. These gases are typically very small in volume and, as such, are vented, constituting 

atmospheric emissions of methane and other hydrocarbons. If larger volumes of hydrocarbon 

gasses are encountered, flaring is carried out. API GHG emissions methodology reports default 

factors for total hydrocarbons (THC) and methane emissions per day of active drilling. 

Degassing emissions from water-based muds are reported to be 881.84 lb THC per drilling day 

(0.4 metric tonnes per drilling day) and 574.30 lb CH4 per drilling day (0.2605 metric tonnes 

CH4 per drilling day) (API, 2009). Non-methane hydrocarbon emissions are, therefore, 307.53 

lb non-methane hydrocarbons per drilling day (0.1395 metric tonnes non-methane hydrocarbons

per drilling day). Using the aforementioned 10-day drilling time, emissions per well drilled are

estimated at 2.605 metric tonnes of CH4 and 1.395 metric tonnes of non-methane VOC.

Existing Well Recompletion Prior to CO2-EOR Flooding. Recompletion of wells can be 

accomplished using a variety of techniques requiring a range of surface and down-hole 

equipment and activities. Because of the highly variable nature of workover activity associated 

with well recompletion for CO2-EOR, it is not possible to develop a single characterization that 

appropriately represents all cases. For purposes of this study it has been assumed that reworking 

of existing waterflood production and injection wells for CO2-EOR (the first rework following 
66

waterflood operations and prior to initiation of CO2-EOR operations) requires pulling and 

replacing tubing string and pumping. This activity is assumed to be performed with a workover 

rig, which is smaller than a drilling rig and has lower associated power requirements and 

emissions.

In addition to the workovers performed on all wells before initiation of CO2-EOR operations, it 

is assumed that all wells (one injection and one producing well per pattern) will require 

workover during CO2-EOR flood operations at a rate of one workover per four years (this 

workover rate is specified in by the National Petroleum Council [Bailey and Curtis, 1984]). 

Table 3-24 Estimation of Number of Well Workovers Required over the Life of CO2-EOR 

Pattern Operations for Each Operational Scenario

CO2-

EORScenario

Years of 

Operation 

of SingleWell 

Pattern

Number of 

Initial 

Workovers 

per Pattern

Number of Maintenance 

Workovers Required 

over Operational Lifetime 

(excludes initial 

workover)

Total Number of 

Workovers Required 

Over Life of CO2-EOR 

Pattern Operation

Historical 17 1 (x 2) 4 (x 2) 10

Best Practices 25 1 (x 2) 6 (x 2) 14

1.5 HCPV 

CO2 Injection 36 1 (x 2) 8 (x 2) 18

Assumptions that have been made in characterizing workover activities are summarized in Table 

3-25. 

Table 3-25 Summary of Assumptions Made to Characterize Well Workover Prior to 

Initiation of CO2-EOR Flooding

Workover Parameter Value Units

Workover rig horsepower 475 hp

Workover rig load factor 0.75 unitless

Assumed average 

workover duration

36 (3 days @ 

12 hours/day) hours

Environmental 

performance

Meets Tier 3 

emissions 

standards

-

Brake-specific fuel 

consumption 0.367 Lb/hp-hr

Number of workovers per 

flood pattern 2 Workovers/pattern

Based on these assumptions, a total diesel fuel demand per workover of 8,483 liters (2,241

gallons) has been estimated. Emissions associated with consumption of this volume of diesel in 

the specified workover rig are reported in Table 3-26.
67

Table 3-26 Emissions and Diesel Usage from Workover Rig Operation

Constituent

Emission from 

Single Well 

Workover prior 

to Initiation of 

CO2-EOR

Units

HC 2.14E-03

(2.36E-03)

Metric tonnes 

(short tons)

CO 1.70E-02

(1.88E-02)

Metric tonnes 

(short tons)

NOX

3.21E-02

(3.53E-02)

Metric tonnes 

(short tons)

PMTotal

1.66E-03

(1.82E-03)

Metric tonnes 

(short tons)

PM10

1.61E-03

(1.77E-03)

Metric tonnes 

(short tons)

PM2.5

4.97E-05

(5.47E-05)

Metric tonnes 

(short tons)

CO2

6.80

(7.50)

Metric tonnes 

(short tons)

SO2

1.04E-2

(1.15E-2)

Metric tonnes 

(short tons)

Low Sulfur 

Diesel

2,545

(672.3) Liters (Gallons)

In addition to direct emissions from diesel fuel combustion to power the workover rig, indirect 

emissions from well workover include particulate emissions from traffic on unpaved lease and 

public access roads, emissions from rig delivery and workover operations, and fugitive emissions 

from the well occurring during workover operations. Fugitive emissions associated with 

workover operations were estimated using the US. EPA AP-42 emissions factor of 96 scf of 

CH4/workover (U.S. EPA, 1995). 

Table 3-27 Estimate of Methane Fugitive Emissions from Well Workover over the Life of 

a Single Well Pattern for Each Operational Scenario Under Consideration

CO2-EOR 

Scenario

Number of 

Workovers per 

Well pattern over 

Lifetime of Single 

EOR Flood

Fugitive Methane 

Emissions from 

Workovers over 

Lifetime of Single 

EOR Flood Pattern 

(scf Methane/Pattern)

Mass of Methane, kg

(lbs) per EOR Patterna

Historical 6 576 10.9 (24.02)

Best Practices 10 960 18.17 (40.03)

1.5 HCPV CO2

WAG 14 1,344 25.44 (56.05)

 a Based on 0.0417 lb/ft3 at 20 °C, 1 atmosphere

Unpaved Road Dust Emissions and Wet Suppression. It has been assumed that particulate 

emissions from road traffic on unpaved roads at the CO2-EOR flood site are controlled using 

“wet suppression” practices—applying water to the road surface to keep it wet. In contrast, 
68

methods of “chemical stabilization” require chemical application to modify the physical 

properties of the unpaved road surface to decrease particulate emissions. Water application 

conglomerates particles on the unpaved road surface and reduces availability of small particles to 

become suspended; the effectiveness of this method decreases as surface moisture content 

decreases. The required frequency of water application is a function of factors such as the 

amount of water applied per unit surface area at each application, speed and frequency of road 

traffic between applications, and site meteorological conditions that influence water evaporation 

rate. 

Estimation of Site Operation Particulate Emissions. The following empirical expressions 

provided by the U.S. EPA (EPA, AP-42: Section 13.2.2) on emissions from unpaved roads 

(1995) were used to estimate the quantity in pounds (lb) of size-specific particulate emissions 

from an unpaved road, per vehicle mile traveled (VMT). For vehicles traveling on unpaved 

surfaces at industrial sites, emissions were estimated using the following equation:

 (2a)

and, for vehicles traveling on publicly accessible roads, emissions have been estimated using the 

equation:

 (2b)

where 

k, a, b, c, and d = empirical constants (Reference 6) provided in Table 3-28

E = size-specific emission factor (lb/VMT)

s = surface material silt content (percent)

W = mean vehicle weight (tons)

M = surface material moisture content (percent)

S = mean vehicle speed (mph)

C = emission factor for 1980s vehicle fleet exhaust, brake wear. and tire wear.

Table 3-28 Empirical Constants Used to Estimate Particulate Emissions from Unpaved Roads

Constant

Industrial Roads (Equation 1a) Public Roads (Equation 1b)

PM-2.5 PM-10 PM-2.5 PM-10

k (lb/VMT) 0.15 1.5 0.18 1.8

a 0.9 0.9 1 1

b 0.45 0.45 - -

c - - 0.2 0.2

d - - 0.5 0.5

Finally, emissions were adjusted to the region based on the average fraction of the year with days 

with precipitation events using the following equation:
69

 (3) 

A map provided by the EPA sets the number of days with precipitation events in the Permian 

Basin at approximately 60 days. Based on this method, 10-micron particulate emissions are 

estimated to be 631 lb over the life of one well pattern, and 2.5-micron particulate emissions are 

estimated to be 28.3 lb over the life of one well pattern. This corresponds to a total particulate 

emissions rate of 659.3 lb over the life of one well pattern. Assuming that this dust emission rate 

is appropriate for all operational scenarios, the particulate emission rates per well pattern year are 

reported in Table 3-29.
70

Table 3-29 Summary of Particulate Emissions (Controlled) from Construction Traffic on 

Unpaved Roads, and Dust Suppression Water Consumption Rate per Pattern Year

Parameter Historical Best 

Practices

1.5 HCPV CO2

WAG Injection Units

PM10 61.70 33.96 22.43 kg/(pattern-yr)

PM2.5 2.76 1.52 1.01 kg/(pattern-yr)

Total Particulates 64.46 35.48 23.44 kg/(pattern-yr)

Water 

Consumption for 

Dust Suppression

14,389 7,920 5,231 kg/(pattern-yr)

Estimation of Unpaved Dust Suppression Water Requirements. Based on an assumed 

unpaved road length of 0.5 miles (805 meters) per pattern, road width of 10 feet, water 

application intensity of 0.2 liters per m2, time between application of 2 hours, average potential 

evaporation of 0.23 mm/hr, average number of days per pattern during which dust suppression is 

required of 60 days/pattern, and a dust suppression control efficiency of 69 percent, 

approximately 147 metric tonnes of fresh water are consumed per well pattern (U.S. EPA, 2004). 

Assuming that this water demand estimate is appropriate for all operational scenarios, fresh 

water requirement per well-pattern year was calculated and is reported in Table 3-29. 

3.5.3.6 Fluid Distribution and Gathering Lines

CO2 Distribution System. The CO2 distribution system is analogous in scale and infrastructure 

makeup to the gathering systems used for natural gas, with CO2 distributed from a central “hub” 

to the CO2 injection site through a system of smaller pipelines (ARI, 2006). Typical pipeline 

size (diameter and wall thickness) is a function of the maximum injection requirements for a site

(Melzer, 2010). 

• 4” pipe (CO2 rate less than 40MMcf/d)

• 6” pipe (CO2 rate of 40 to 60 MMcf/d)

• 8” pipe (CO2 rate of 60 to 80 MMcf/d)

• Pipe greater than 8” diameter (CO2 rate greater than 80 MMcf/d)

• Distance from the CO2 “hub” (transfer point) to the oil field

• From hub to oil field, the distance is assumed to be 10 miles.

As a means of determining appropriate pipe schedule to transport compressed CO2, required CO2

distribution line wall thickness was estimated based on the simplified equation for stainless steel 

pipe and tubing pressure rating, as provided by Aalco Metals Limited (2009).

(4)

where

P = pipe internal design pressure, thousand psi (kpsi), (2.2 kpsi)

D = pipe outside diameter, inches (assuming 4 inch nominal pipe, with 4.5 inch OD)

S = stress value for material (in tension) as a function of operating temperature, kpsi (for 

A312 steel tubing operating between -325 and 100 °F, a stress value of 16.7 kpsi is 

reported)
71

E =manufacturer-specified quality factor (for ASTM A312 TP 316L seamless piping, E = 

1.0)

Assuming a maximum distribution pressure of 2,200 psi, nominal steel piping of A312 steel 

(seamless) requires a wall thickness of 0.296 inches, and ANSI schedule 80 piping with wall 

thickness of 0.337 inches is specified.

A report by the U.S. EPA entitled Geologic CO2 Sequestration Technology and Cost Analysis

(2008) assumes 4.5 miles of four-inch pipe and 4.5 miles of 6-inch pipe are required to 

accommodate CO2-EOR field operations over a developed area of 20 square miles; this length of 

pipeline is approximately the square root of the development area. Based on this observation, it 

is assumed that the length of 4 and 6 inch CO2 distribution pipeline can be approximated to be 

the square root of the developed CO2 study area. 

Table 3-30 Estimation of Mass of ANSI Schedule 80 Stainless Steel Pipe Required per 10 

Well Patterns for CO2 Distribution

CO2

Distribution 

Element

Pipe 

Thickness, 

Inches (ANSI 

Schedule)

Unit Weight of 

Piping

Estimated Mass of Pipe, Metric Tonnes 

(Short Tons)

lb/ft lb/mile

per 20 square miles 

(based on 4.5 miles of 

each size pipe)

per square mile

4” stainless 

steel pipe 0.337 14.9 78,672 161 (177) 8.0 (8.85)

6” stainless 

steel pipe 0.432 18.6 151,008 308 (340) 15 (17)

Total Mass - - - 469 (517) 23 (25.8)

Based on this mass of steel, a proprietary life cycle emissions profile for stainless steel (80

percent recycled) was applied to estimate emissions associated with production of these steel 

CO2-EOR infrastructure elements. Emissions associated with installation of CO2 distribution

pipeline have been neglected.

Brine Distribution Lines. Pipelines used for brine distribution to EOR injection wells from 

tank batteries are assumed to be pre-existing to CO2-EOR activity because these infrastructure 

elements are required for secondary water flood EOR that would have already taken place at 

sites where tertiary CO2-EOR activity is being initiated. As such, inventory of resource demands 

and emissions for brine distribution infrastructure are considered to be negligible. 

3.5.4 Gas Processing Facility Construction

Construction of the gas processing facility is characterized based on an estimate of the mass of 

steel and concrete of which the gas processing facility is composed. A large LNG processing 

facility located in Qalhat, Oman, with a design throughput of 160 Bcf/year (about 438 

MMcf/day) (EIA, 2009) was constructed with an estimated 10,000 tons of steel, and 100,000 

cubic meters of concrete (concrete for plant foundation) (Energy Dynamics, 2009). Based on 

these reported values, plant construction has standard construction material requirements of 22.8 

tons of steel per MMcf/day and 228 cubic meters of concrete per MMcf/day. This corresponds 

to estimated steel and concrete requirements, for a gas processing facility designed to handle 

45MMcf/day (plant size assumed for this study), of 1,027 metric tonnes of steel and 10,266 cubic 
72

meters of concrete. Material and energy requirements and emissions associated with production 

of this amount of construction material were calculated using life cycle profiles not detailed 

herein; results are detailed in Table 3-31. It is recognized that a LNG plant differs in design and 

construction significantly from a natural gas processing plant. However, construction material 

upstream emissions are expected to contribute a relatively small amount to environmental 

emissions as compared to plant operation, such that using these numbers to characterize natural 

gas processing plant construction is considered to be adequate. This is noted as data limitation.

Table 3-31: Estimate of Emissions Associated with Gas Processing Facility 

Construction Materials Upstream Profile

Pollutant

Mass of Pollutant, 

Metric Tonnes 

(Short Tons)

CO2 8,946 (9,861)

CO 14 (16)

Particulate (total) 113 (124)

Methane 0.15 (0.17) 

Nitrogen oxides 23 (25)

Sulfur dioxide 33 (37)

VOC 0.38 (0.42)

Water required to produce this mass of construction materials is estimated to be approximately 

17.4 million liters (66 million gallons).

3.5.5 Facility Operation

Characterization of the CO2-EOR facility operations phase is based on modeled flood 

performance under historical, best practices, and next-generation scenarios designed previously. 

Fluid production rates and compositions estimated as a result of specified CO2 and brine 

injection schedules serve as the basis from which infrastructure size, throughput, process energy 

input requirements, and emissions were estimated. Four major areas of operation were 

considered based on these estimated process flows:

• Fluid injection operations

• Fluid production operations

• Tank battery (liquid processing operations)

• Gas processing facility and compression operations

It should be noted that the scope of this LCA as described above does not include bulk CO2

transport to the EOR reservoir site from the CO2 source. Each of these four areas of operation is 

considered in more detail below.

3.5.5.1 Pattern-Year Concept

Total gate-to-gate emissions associated with CO2-EOR activity can be estimated through a 

relatively straightforward summation of emissions from individual activities contributing to the 
73

overall life cycle profile. However, relating the activity and material flows from a single well 

pattern to larger-scale unit processes (e.g., gas processing facility) must be carried out with 

careful attention to units to ensure that emissions are appropriately accounted for. To do this, the 

simple concept of the pattern-year is introduced. Pattern-year describes the number of years of 

operation of each CO2-EOR well pattern. As described earlier, the length of CO2 WAG injection 

for each scenario varies as a function of the total volume of fluid (CO2 and water) injected and 

injection rate. For the historical, best practices, and 1.5 HCPV CO2 WAG injection scenarios as 

defined in this report, each pattern flood operates for 17, 25, and 36 years, respectively. 

Operation of one well pattern as a historical CO2-EOR flood corresponds to 17 pattern years. 

Each tank battery is assumed to accept fluid from 10 well patterns for the life of those patterns, 

such that a single tank battery under the historical CO2-EOR scenario accepts 170 pattern-years 

of produced liquids. When operated under a 1.5 HCPV CO2 WAG scenario, the tank battery 

accepts 360 pattern-years of produced fluid. Finally, a well pattern operated under the historical 

CO2-EOR scenario produces an average of 73.0 MMscf of total gas per pattern year (0.2 MMscf

per pattern day) over the pattern flood lifetime. At this production rate a gas processing facility 

accepting 45 MMscf of total gas per day is capable of accepting gas from approximately 225

well patterns operated under the historical CO2-EOR scenario. Normalizing performance to the 

pattern-year for each operation scenario allows unit operations performing at different scales to 

be described in common terms, and simplifies accounting of emissions and other material/energy 

flows.

3.5.5.2 CO2-EOR Fluid-Injection Operations

Water Supplied to EOR Field

It is assumed that water injected into the producing pattern as part of a WAG CO2-EOR injection 

is provided by water produced from EOR activity within the oil field (stored produced brine 

from adjacent EOR tank batteries). Validity of this assumption has been evaluated by comparing 

the total volume of brine produced from each injection scenario with the total volume of brine 

required to satisfy the WAG injection. These data (Table 3-32) show that, for all three scenarios, 

the production of brine is greater than the demand for brine over the lifetime of the CO2-EOR 

operations except for the end (chase water) period. This justifies that, in the case of the average 

basin considered in this report and under the assumed operational scenarios, CO2-EOR 

operations can be assumed to be self-sufficient—requiring no water delivery from out-of-field 

surface or groundwater sources. The excess water produced through CO2-EOR operations will 

require management. It is assumed that brine that is produced in excess of that which is used in 

the CO2-EOR WAG or post-injection water slug is injected for disposal at a location adjacent to 

the EOR reservoir, but outside the active EOR well pattern array. 
74

Table 3-32 Difference Between Cumulative Produced Injected Water (CO2 Prophet model 

results)

CO2-EOR 

Scenario

Volume of Excess Produced 

Brine (Cumulative Over Lifetime 

of Single Pattern Flood) (MSTB)

Historical 100.8

State-of-art 246.0

1.5 HCPV CO2

WAG Injection 240.0

Brine Injection Operations

Statistical analysis of a Texas Railroad Commission dataset of injection wells (heavily biased 

toward Permian Basin wells) performed by the University of Texas at Austin Bureau of 

Economic Geology (Hovorka et al., 2003) shows that half of the currently operating Class II 

injection wells are cased and perforated, the majority of injection systems are closed to the

atmosphere, and the majority of wells having a hole size of 77/8 inches in diameter and tubing 

between 23/8 and 27/8 inches. Their analysis of reported maximum injection pressure gradient 

(injection pressure/tubing depth) demonstrated that essentially all wells operate below or near 

hydrostatic gradient. (The maximum surface injection pressure is a function of desired 

bottomhole pressure and tubing diameter and length, with smaller diameter tubing having greater 

frictional loss because a greater proportion of the fluid is in contact with tube.) 

Water Injection Pump Electricity Requirements

The simple equation to estimate pump brake horsepower requirement shown below (Perez et al., 

2009) was applied based on an assumed suction pressure of 14.7 psia, an assumed wellhead 

discharge pressure of 314.7 psia (300 psig), and a mechanical efficiency of 70 percent. Volume 

of fluid flowing to the injection well is estimated by results of CO2 Prophet model runs of 

historical, best practices, and high CO2 WAG scenarios. 

(5)

where

BHP = pump brake horsepower

Q = volume of fluid pumped

Pd = discharge pressure

Ps = suction pressure

ME = mechanical efficiency (typically between 65-75 percent)
75

Table 3-33 Estimated Total Electricity Demand Over the Life of CO2-EOR Flood 

Operations to Pressurize Brine for WAG Injection, Reported for a Single Well Pattern

CO2-EOR 

Scenario

Estimated Electricity Demand for 

Water Injection Over Lifetime of 

CO2-EOR Operations for Single 

Pattern (40-acre, 5-spot)

Historical 3,832

Best Practices 4,756

1.5 HCPV CO2

WAG Injection 6,463

Emissions associated with production of electricity that is used in brine compression were 

calculated assuming the national average grid emissions profile described in Appendix B.

Boost Compression of Purchased/Recycled CO2 for Injection

Initially, CO2 is assumed to be supplied to the site by a pipeline that transports CO2 from 

naturally-occurring CO2 reservoirs, large anthropogenic CO2 point sources, or a combination 

thereof. As CO2-EOR floods progress and CO2 breakthrough is observed, CO2 will increasingly 

be supplied by that which is separated from produced hydrocarbon gas, recompressed, and 

recycled to injection wells. Compression is, therefore, assumed to occur centrally at or near the 

gas processing facility and that pressure used to drive distribution and injection operations. 

Boost compression is required to raise the CO2 feed stream to target injection pressure of 2200 

psig (Meyer, no year referenced). CO2 is supplied to the flood from a combination of two 

sources: CO2 that is purchased from a large pipeline, and CO2 that is recycled from produced 

fluid stream. The purchased CO2 is assumed to arrive at the site at a pressure of 1,500 psig 

(Meyer, no year referenced), and the CO2 recycled from CO2-EOR operations leaves the gas 

processing plant at a pressure of 2,000 psig. The pressure of the CO2 feed stream is, therefore, 

calculated as the weighted average pressure as a function of the fraction of CO2 supplied from 

each source. These fractions are given in the equations below:

(6)

(7)

Based on this calculation method, mean supplied CO2 pressures for historical, best practices, and 

high-CO2 volume injection scenarios were 1690, 1800, and 1850 psi, respectively. Boost 

compression electricity requirements were, therefore, highest on a per-tonne of CO2 injected 

basis in historic cases, but the smaller amount of CO2 injected in historical cases as compared to 

other scenarios means that the total compression energy requirements will be lower on a perflood pattern basis. Boost compression energy requirements were estimated simply as the 

change in pressure divided by the product of CO2 density at midpoint between feed and injection 
76

pressure times an assumed pump efficiency of 0.75. Table 3-34 summarizes the results of these 

calculations.

Table 3-34 Summary of Parameters Used in Calculating CO2 Boost Compression 

Requirements, and Results of Calculation Reported on a per Pattern-Year Basis

CO2-EOR Scenario Historical Best Practices 1.5 HCPV CO2 WAG 

Injection

Fraction of stored to 

injected CO2 (%) 51.4 33.7 25.2

CO2 feed pressure 

(psig) 1,800 1,853 1,891

Pressure at injection 

wellhead (psig) 2,200 2,200 2,200

Average flood CO2

feed rate 

(tonnes/pattern year)

5,629 9,573 9,972

Estimated average 

electricity demand to 

boost compression 

(MJ/pattern-year)

51,600 74,400 67,300

3.5.5.3 Production Operations

Production operations involve reservoir fluid extraction, either by artificial lifting or by freeflowing well production. Artificial lifting is assumed with a mid-range electricity requirement 

assumed as noted in Table 3-6. Following production, the produced fluid will be collected for 

gas/liquid separation (gas expansion chamber), water/oil separation (water knock out), and 

oil/water emulsion separation (heater treater). In CO2-EOR fields that produce relatively large 

volumes of hydrocarbon gases in their produced gas streams, operators may choose to install 

equipment to separate hydrocarbon gas from CO2 so that the separated hydrocarbon stream can 

be sold. In this study it has been assumed that CO2/hydrocarbon separation will be carried out 

using the Ryan-Holmes process for distillative separation to remove acid gasses (CO2 and H2S) 

with a propane or butane additive. 

Artificial Lift

Under favorable conditions, it may be possible for fluid to be produced, in CO2-EOR operations, 

from free-flowing wells. While free-flowing production wells offer obvious cost, energy 

demand, and maintenance advantages, artificial fluid lifting is, more often, required, with 

approximately 80 percent of all CO2-EOR operations employing artificial lift to achieve 

economic production levels (van Leeuwen et al. 2009). In artificial lifting, pumps are employed 

to pull reservoir fluid to the surface that would otherwise be too deep and/or viscous to be 

pushed to the surface by the pressure of the reservoir. Pumps used to achieve artificial lift of 

fluid in a producing well can be driven by electric (DC or AC) motor or gas engine prime 

movers, with gas engine drives an attractive alternative when sufficient quantities of gas are 

generated on site as a result of CO2-EOR activity. While in practical application the selection of 

artificial lift pump driver would be based on a detailed analysis of purchase, installation, 

maintenance, and power costs, it is assumed, for purposes of this study, that AC electric motor 

prime mover is present on site prior to tertiary recovery operations (remaining from secondary, 
77

water-flood recovery operations), and has sufficient capacity for use in tertiary recovery 

operations. This type of motor has been demonstrated to be resilient in field operation and, while 

such equipment requires regular repair and maintenance, it can, with proper care, remain in 

operation indefinitely (Mistry, 2003). 

 

Electricity demand for artificial lift varies as a function of a number of reservoir, fluid, and well 

parameters, including reservoir depth, reservoir operating pressure, produced fluid viscosity and 

density (a function of composition and temperature), well tubing diameter and internal 

roughness. Fluid volumes and properties and formation pressures can also be expected to vary as 

a function of time as the WAG flood progresses.

Artificial Lift Electricity Demand Estimated Using ARI Reported Value

Results of an informal survey of CO2-EOR flood operators reveals that electricity-driven lifting 

power accounts for between 10 and 30 percent of the electricity use by a CO2-EOR project, and a 

recent report estimates electricity consumption to be between 0 and 10 kWh per barrel of 

incremental oil produced, with a mid range of 5 kWh/bbl of incremental oil produced (van 

Leeuwen et al. 2009). Artificial lift electricity requirements for CO2-EOR operations were 

estimated for the three defined scenarios using oil production values for a single well pattern as 

reported in Section 3.4.1.1, and using the referenced 5 kWh/bbl of incremental oil produced.

Table 3-35 Single Well Pattern Artificial Lift Estimate for CO2-EOR Scenarios Estimated 

Using ARI mMid-range Electricity Estimate of 5 kWh/bbl for Historical CO2-EOR and 10 

kWh for Best practices and Next-Generation CO2-EOR Scenarios

CO2-EOR Scenario

Single Pattern 

Total Oil 

Production 

(MSTB)

Assumed ARIReported Artificial 

Lift Electricity 

Demand (kWh/bbl)

Cumulative Single 

Pattern Electricity 

Demand (MWh)

Historical 191.5 5 (mid-range) 957.5

Best Practices 301.8 5 (mid-range) 1509

1.5 HCPV CO2 WAG 

Injection 361.2 5 (mid-range) 1806

This method of artificial lift electricity production estimation may not adequately account for the 

decreasing ratio of oil produced to total fluid produced that is expected in high fluid injection 

scenarios. As a result, a second method was considered for estimation of electricity requirements 

to drive artificial lifting based on estimation of horsepower demand.

Artificial Lift Electricity Demand Characterization by Prime Mover Horsepower Estimate

Prime mover size for artificial lift can be estimated by applying an empirical equation of the 

general form shown in the following equation (Manning and Thompson, 1995):

HPpm = qxD/PMF (8)

where

q = oil and water daily production (bbls/day)
78

HPPM = horsepower of prime mover

D = net lift of liquid in feet

PMF = prime mover factor, with

PMF = 135,735 when SG is 1 and lifting with 100 percent efficiency

Generally PMFs are 1.8 to 3 times smaller than 135,735. For high slip NEMA D motors or 

slow-speed internal combustion engines, recommended prime mover HP can be calculated from:

HPPM = q*D/56000. For high-speed internal combustion engines or normal slip NEMA C 

motors, prime mover HP suggested is: HPPM = 45,000

For purposes of this study, the depth from which fluid is assumed to be lifted is half of the 

vertical depth (depth to top of producing formation) (5,826 feet, per Table 3-9), or 2,913 feet. 

The daily fluid production is estimated as the sum of the oil and water produced. Because the 

fluid flow rate will vary as the CO2-EOR flood progresses, the required horsepower to lift fluid 

will also vary. To address this, the volume of total fluid was estimated for each year in which 

the CO2-EOR flood is produced, the horsepower requirement calculated for each one year

increment, and lift requirements from all years of pattern operation summed to develop an 

estimate of total lift requirement over the life of each production well. Results of this calculation 

are shown in Table 3-36.

Table 3-36 Estimated Electricity Requirement for Artificial Lift for Single Well Pattern as 

Calculated Based on Estimated Artificial Lift Prime Mover Horsepower Requirement

CO2-EOR Scenario

Single Well 

Electricity Demand 

for Artificial Lift

(GWh per well 

pattern)

Per-Stock Tank 

Barrel of Crude 

Produced Electricity 

Requirement

(kWh/ bbl oil)

Per-Surface Barrel of 

Liquid Produced 

(kWh / bbl liquid)

Historical 3.83 20.0 1.3

Best practices 4.76 15.8 1.3

1.5 HCPV CO2 WAG 6.46 17.8 1.3

These results are significantly higher, on a kWh/bbl oil produced basis, than the high electricity 

demand estimate for artificial lift reported by van Leeuwen (2009). Using values listed in Table 

3-36, indirect emissions associated with electricity production that is used in artificial lift activity 

were calculated assuming national average grid emissions profile described in Appendix A.

Fluid Gathering Lines

Total fluid collected from a producing well is transported to a nearby satellite separation unit 

where bulk gas is separated from liquid. Bulk gas is transported to an in-field gas processing 

facility and liquid produced from EOR well pattern is transported via pipeline to the central 

battery location. It is assumed that relatively high pressure flow lines from the well are made of 

steel (Langston, 2003), and that production lines from previous water-flood secondary EOR 

activity in the same field are pre-existing and of adequate integrity and flow volume to 

accommodate CO2-flood tertiary EOR fluid flow. In all scenarios considered in this report, it is 

assumed that the liquid-gathering lines that are used for CO2-EOR operations are the same as 

those that were used in secondary recovery operations. 
79

3.5.5.4 Produced Liquids Management: Satellite Separation and Tank Battery

Operations

A tank battery is a collection of fluid flow lines, processing equipment, and storage tanks that is

designed to process and store liquid that is received from one or more oil producing wells before 

the oil is transferred to a pipeline or tanker truck for sale. The fluid produced from each EOR 

pattern varies as a function of reservoir characteristics, fluid characteristics, injection schedule 

and flow rates. Tank batteries are therefore designed to accommodate the particular conditions 

and production performance of a specific EOR pattern or set of patterns that make up a lease. 

The primary factor influencing this design is the amount of fluid that is produced and processed 

through the system. For purposes of this study it is assumed that fluid produced from 10 well patterns 

are collected to and processed in a single central tank battery facility. Approximate size, processing 

capacity, and emissions from elements of a tank batter are estimated based on maximum average fluid 

production flowrate as estimated using CO2 Prophet CO2-EOR scoping model and detailed elsewhere. 

Major functions performed in a tank battery are: gas/liquid separation, water/oil emulsion 

separation, oil storage, water storage, and vapor recovery. Tank battery process elements that 

perform these functions include:

• Heater/treater - Heats water/oil emulsion to separate oil, water, and gas. (atmospheric 

or pressurized three-phase vessel.)

• Gun barrel or wash tank - Separates oil, water, and small amounts of gas. 

 (atmospheric, three-phase vessel)

• Stock tank - Stores crude oil that is to be sold (atmospheric pressure)

• Water storage tank - Stores produced water prior to disposed or re-injection 

 (atmospheric pressure)

Parameters listed in Table 3-37 have been selected to represent mean conditions observed at each 

unit process. Temperature and pressure conditions will vary from facility to facility and 

significant variability can be expected as a function of fluid properties, site conditions, and 

facility configuration. These values will impact facility performance and environmental 

emissions, and are used in this LCA to estimate performance of each unit process.
80

Table 3-37 Process Element Assumptions Made in Characterization of CO2-EOR 

Produced Liquids Processing

Unit Process Number 

of Units Flow Location

Estimated 

Temperature, 

°F 

Estimated 

Pressure, 

psig

High pressure 

separator 1

Total 

produced 

fluid

Satellite Facility 126 300

Low Pressure 

Separator 1

All but 

separated 

gas

Tank Battery 110 100

Heater/Treater 1 Water/oil 

emulsion Tank Battery 140 50

Stock tanks (Oil 

Storage) 2x Oil Tank Battery 64 atm

Water Storage 

Tanks 2x Produced Water Tank Battery 64 atm

Estimation of Fluid Separation Performance

Separator facilities can be located at centralized facilities (central batteries), strategically-located 

decentralized facilities (satellites), or they may be located at both satellite and central separation 

facilities. A satellite facility can be designed to direct all produced fluid to a central facility or to 

separate bulk gas before sending liquid water and oil stream on to central battery and bulk gas 

(CO2 and hydrocarbon gas) to a gas processing facility. Foregoing satellite separation of bulk 

gas has the advantage of consolidating operation and maintenance within a relatively small area

around the tank battery, but also may create issues with slugging and higher frictional pressure 

drop over that which would be observed in production systems with gas/liquid satellite 

production separation. Selection of a separation alternative is best made on a case-by-case basis 

after site-specific analysis based on such factors as gas-processing facility inlet pressure, crude 

oil properties, produced gas composition, crude oil sales specifications, water quality 

specifications, and site layout.

For purposes of this study, it is assumed that fluid produced from five CO2-EOR well patterns 

passes through a primary satellite separator where bulk gas is separated from liquid (oil and 

water). Fluid flow through the separator is driven by fluid pressure and does not require 

additional electricity for pumping. Liquid is conveyed by pipeline from the satellite separator to 

the central battery manifold where flow from satellite separators servicing ten tank batteries is 

collected to a secondary water/oil/gas separator. At this stage nearly all of the free water6

 

6 “Free water” is a term used to describe the fraction of water contained in fluid produced from 

an oil well that will freely separate from oil, with discrete water droplets separating according to 

behavior described by Stokes' Law.

in the 

fluid is separated and transported to water storage tank. Oil, water/oil emulsion, and a small 

fraction of the total free water are transported to a heated vessel to break the water/oil emulsion 

and complete water/oil separation. 
81

Characterization of the construction of two-phase gas/liquid production satellite separators is 

limited to estimation of the mass of steel of which each separator is composed, emissions 

associated with production of that mass of steel, and an estimation of the overall number of 

satellite separation units. Assuming a gas/liquid separator 9 feet in length, 3 feet in outer 

diameter, and with 0.75-inch vessel thickness, the mass of steel was estimated to be about 1.2 

metric tonnes. Based on the guideline that for oil gravity above 35 ° API one minute liquid 

retention time is recommended, average flow from five patterns can be processed through a 

gas/liquid separator (also assuming effective volume of half of the total vessel volume).

Water/Oil Emulsion Separation: Heater/Treater Vessel

Following gas, and liquid separation, the oil stream (including free oil, oil/water emulsion, and a 

small fraction of free water) is moved to a heater/treater vessel in which heat is applied to break 

the water/oil emulsion and separate water from the product oil. Heating also serves to remove 

additional gas which is collected for further processing. Natural gas-fired fire tubes provide the 

heat that is used to achieve this secondary separation. The required number and size of fire tubes 

is a function of volume of fluid being processed. Required fluid residence time is a function of 

crude oil API gravity, heater/treater temperature, and desired separation efficiency.

Typical retention time in a vertical or horizontal heater/treater is between 0.5 and 4 hours 

(Manning and Thompson, 1995), and for loose emulsions with gravity greater than 35 o, 

emulsion heating for mechanical separation is typically in the range of 100 to 120 °F. The wateroil emulsion for oil with gravity of 36 o API is estimated to contain entrained water at 

approximately 11 percent by volume (Manning and Thompson, 1995). In addition to entrained 

water, a small fraction of free water is drawn into the heater/treater vessel (free water knock out 

separation efficiency is assumed to be 98 percent of free water). It is assumed that a single 

heater/treater vessel is required to service a single tank battery.

EPA AP-42 Method to Estimate Heater/Treater Fugitive Emissions

AP-42 specifies methane emissions from heater-treater to be 19 scf of CH4 per day per heater, 

and 0.319 scf CO2 per day per heater. This corresponds to production rates of 6935 scf of CH4

per year for a single heater treater, and 116 scf of CO2 per year. It is assumed that the gas 

generated in the heater treater is collected by a vapor recovery unit (VRU), sent to a TEG unit for 

dehydration, and then sold or recombined with new CO2 and reinjected (this option is not 

considered in this report). 

These emissions estimates offer only a coarse estimate of CO2 and methane emissions, and do 

not take into account vessel flow rate, temperature/pressure conditions, or emulsion 

characteristics. They are therefore considered to be insufficiently rigorous to serve the purposes 

of this study and are offered only for comparison with results arrived at using the U.S. EPA 

TANKS model. Even then, real process, stream composition, and flow rate data would 

significantly improve the estimates beyond what is estimated using the TANKS methodology.

Estimation of Heater/Treater Firetube Heat Duty and Boiler Emissions
82

Estimation of crude treating temperatures and rates based on tables provided by Manning and 

Thompson (1995) suggest a required emulsion heating temperature and treating rate (assuming 

mechanical emulsion separation) of 140 °F and 57 bpd/ft2

. Based on this treatment rate, 

calculated heat duty for a heater treater firetube burner is on the order of 1 MMBtu/hour. In all 

CO2-EOR scenarios, heater/treater firetube heat duty is below the threshold set by the EPA for 

application of uncontrolled, small boiler emissions factors (<100 MMBTU/hour heat input), and 

these emissions factors have been applied to all heater/treater natural gas combustion equipment.

Emissions of heater/treater firetube boiler were estimated based on U.S. EPA AP-42 emissions 

factors for common criteria air pollutants, greenhouse gasses, organic compounds, and metals, 

taken from the U.S. EPA AP 42 section 1.4: Natural Gas Combustion, Emission Factors for an 

uncontrolled boiler. The amount of natural gas combusted to heat fluids in the heater/treater was 

estimated using the heat duty equation my Manning and Thompson (1995) presented below:

Heat Duty (btu/day) = (Qoil* Cpoil + Qwater* Cpwater)* ΔT * (1 + heat loss) (9)

where

Heat duty = heat duty of heater/treater in btu of natural gas per day

Qoil = daily flow of oil to heater/treater, barrel of oil per day

Qwater=daily flow of water to heater/treater, barrel of oil per day

ΔT = change in temperature between influent stream and vessel, °F 

Cpoil = Saybolt viscosity of oil, Saybolt second units (SSU)

Cpwater = Saybolt viscosity of water, SSU

Heat loss = percent vessel heat loss (for a well-insulated vessel, assumed to be 2 percent)

To estimate total emissions over the life of CO2-EOR operations from natural gas combustion to 

heat water/oil emulsion at a single tank battery (for each operational scenario), an average annual 

heat duty was calculated for each year of operation for each CO2-EOR operational scenario using 

assumptions listed in Table 3-38.

Table 3-38 Assumptions Used in Estimation of Heater/Treater Firetube Heat Duty. In 

addition to these parameters, the flow of oil to the heater/treater was estimated for each 

year of CO2-EOR activity based on the aggregated flow from 10 producing wells feeding a 

single tank battery

Parameter Value Units

Oil/water emulsion treatment 

temperature 140 °F

Temperature of influent stream 110 °F 

Δ Temperature across 

heater/treater 30 °F

Saybolt viscosity of oil 150 SSU

Saybolt viscosity of water 350 SSU

Heat loss of well-insulated 

vessel 0.02 fraction

Annual heat duty requirement was summed for all years of tank battery operation (all years of 

CO2-EOR flood operation) to determine the total heat duty (calculated for each CO2-EOR 
83

operational scenario). Based on the calculated heat duty over the life of the tank battery, natural 

gas combustion emissions were estimated for the full life of CO2-EOR operation from 10 CO2-

EOR flood patterns (one tank battery). These data are summarized in Table 3-39, and 

corresponding combustion emissions data are shown in Table 3-40.

Table 3-39 Estimated Energy Requirement of Firetube Used To Heat Heater/Treater 

Servicing 10 CO2-EOR Well Patterns

Parameter Historical Best Practices 1.5 HCPV CO2

WAG Injection Units

MMBtu required 

over life of CO2-

EOR operations 

for heater/treater 

firetube (tank 

battery supplies 

10 CO2-EOR well 

patterns)

46,200 63,000 81,300 MMBtu

MMscf natural 

gas equivalent 

(1020 btu/scf 

natural gas)

45.3 61.7 79.7

MMscf natural 

gas at 1020 

btu/scf

Table 3-40 Estimated Combustion Emissions from Heater/Treater Firetube Operation for 

a Unit Servicing 10 Well Patterns Over the Life of the CO2-EOR Flood

Constituent Historical Best Practices 1.5 HCPV CO2

WAG Injection Units

GHGs

CO2 14,500 13,500 12,100 kg/(pattern*year)

Methane 0.28 0.26 0.23 kg/(pattern*year)

N2O 0.27 0.25 0.22 kg/(pattern*year)

Criteria Air Pollutants

NOX 12.1 11.1 10.1 kg/(pattern*year)

CO 10.2 9.42 8.45 kg/(pattern*year)

PM (Total) 0.92 0.85 0.76 kg/(pattern*year)

SO2 0.07 0.07 0.06 kg/(pattern*year)

VOC 0.67 0.62 0.55 kg/(pattern*year)

In addition to combustion emissions from the heater/treater, the vessel also has emissions 

associated with working, breathing, and flashing losses. As discussed elsewhere, these emissions 

are assumed to be controlled largely through installation and operation of a vapor recovery unit 

at the stock tank battery. Uncontrolled tank working and breathing losses were calculated using 

the U.S. EPA Tanks models with the tank assumptions specified in Table 3-41. Estimation of 

uncontrolled flashing emissions was estimated using the Vazquez-Beggs equation. Results of 

estimated uncontrolled and controlled working, breathing, and flashing losses from the 

heater/treater are summarized in Table 3-41.
84

Table 3-41 Design Assumptions Used in Estimating Heater/Treater Vessel Working, 

Breathing, and Flashing Emissions

Parameter Value Units

Vessel diameter 6 ft

Vessel height 12 ft

Maximum heat duty 500 Mbtu/hr

Target liquid residence time range 1-4 hours

Total volume of heater/treater vessel 60 ft3

Fraction of total volume as working volume 0.66 ft

Effective working volume of heater/treater 40 ft3
85

Table 3-42 Estimate of Working, Breathing, and Flashing Emissions from Heater/Treater Vessel That Are Collected to the 

Vapor Recovery Unit

CO2-EOR 

Scenario

Tank 

Contents

Flash Losses 

(kg/tank-year)

Working 

Losses 

(kg/tankyear)

Breathing 

Losses 

(kg/tankyear)

Total Losses 

per Tank per 

Year (kg/tankyear)

Historical Water Oil 

Emulsion 125,900 3062 58.4 129,000

Best Practices Water Oil 

Emulsion 132,300 3059 58.4 135,400

1.5 HCPV CO2

WAG Injection

Water Oil 

Emulsion 122,700 3064 58.4 125,800
86

3.6 Crude Oil Storage

Oil storage tanks are designed to hold oil that has been collected from producing wells and 

separated from water, CO2, and hydrocarbon gas within the tank battery prior to transfer from 

lease operations to the pipeline or tanker truck. Storage provided by these tanks also provides a 

buffer to stabilize flow between production operations and sales. For purposes of this study, it 

has been assumed that all oil storage tanks meet American Petroleum Institute API-650 

Specification, and that there is redundancy in both oil and water storage tanks. 

Size of tanks required to store produced oil from 10 wells was estimated based on the maximum 

flow of oil generated from 10 producing wells, as described in the above section on estimation of 

reservoir production, the number of tanks in use, and the specified range of tank annual 

turnovers (tank volumetric throughput per year divided by tank working volume). Assuming that 

two crude oil storage tanks are located at each tank battery, tanks with a diameter of 12 feet, and 

a shell height of 15 feet with capacity of 12,600 gallons (300 barrels) are specified. It is 

assumed that a single crude storage tank is used unless the number of tank turnovers per year 

exceeds 1000 (Oklahoma DEQ, 2006). In cases where turnover for a single crude storage tank 

exceeds this threshold, a second crude storage tank is assumed to be brought online to cut in half 

the number of turnovers per year during those years of peak tertiary oil production. Assuming a 

mean working crude oil height of 12 feet (corresponding to 80 percent total volume), the average 

number of turnovers is between 450 and 550 for all CO2-EOR scenarios, a range that is well 

within that which is considered to be appropriate for tank battery crude storage tanks—100 –

1,000 per year (Oklahoma DEQ, 2006).

3.6.1 Estimation of Crude Oil Storage Tank Losses

Flashing losses result from sudden decreases in gas solubility when fluid is transferred from 

higher to lower pressure and/or lower to higher temperature conditions. Standing losses (also 

called storage or breathing losses) occur when the liquid in the tank expands and contracts due to 

changes in ambient temperature or barometric pressure. Working losses describe the fraction of 

total losses that occur as result of headspace gas displacement resulting from changes in storage 

tank volume (those that occur as a tank is emptied or filled). Oil storage tank standing and 

working losses were estimated using EPA TANKS model version 4.0.9d; flashing losses were 

estimated using the Vasquez - Beggs Solution Gas/Oil Ratio (GOR) correlation method using the 

mean Permian basin GOR as reported in Table 3-9. 

The EPA Tanks model calculates estimated storage tank losses based on tank dimensions, 

throughput of stored fluid per unit time, fluid speciation and vapor pressure characteristics, and 

environmental conditions to which the vessel is exposed (determined as a function of site 

location). Crude oil storage tank specifications used in development of standing and working 

loss estimates are summarized in Table 3-43. It has been assumed that the vessel contains crude 

oil with a Reid vapor pressure (RVP) of 5 psi. RVP is a commonly used measure of the volatility 

of petroleum and petroleum products, and is defined as the absolute vapor pressure exerted by a 

liquid at 100 °F (37.8 °C) as determined by the test method ASTM-D-323—a value differing 

slightly from a liquid’s true vapor pressure. 
87

Table 3-43 Specifications Used in Calculation of Well Tank Emissions

Parameter Value Units

City, State Midland-Odessa, 

Texas -

Type of Tank: Vertical Fixed 

Roof Tank -

Shell Height (ft): 15 Feet

Diameter (ft): 12 Feet

Max Liquid Height (ft) : 15 Feet

Avg. Liquid Height (ft): 12 Feet

Total Volume (gallons): 12,690 Gallons

Paint Characteristics

Shell Color/Shade: Whte/White -

Shell Condition: Good -

Roof Color/Shade: Grey/Light -

Roof Condition: Good -

Roof Characteristics

Type: Dome -

Height (ft) 2.00 Feet

Radius (ft) (Dome Roof) 12 Feet

Breather Vent Settings

Vacuum Settings (psig): -0.03 psig

Pressure Settings (psig) 0.03 psig

Meteorological Data used in Emissions Calculations: Midland-Odessa, Texas (Avg Atmospheric Pressure 

= 13.28 psia)

The average crude oil annual throughput for a single tank was estimated for each CO2-EOR 

scenario, and that flow rate was applied to a tank of the design specification to estimate the 

average total annual losses (sum of annual flashing, breathing, and working losses) per tank. 

This estimate of scenario-specific total annual per-tank loss was multiplied by the total number 

of operational tank-years (number of tanks in operation per year times the number of years each 

tank is in operation) over the life of the CO2-EOR flood (a value that varies for each CO2-EOR 

scenario). One shortcoming of this methodology is that the EPA TANKS model cannot estimate 

the specific composition of the released vapor unless the specific composition of the liquid stored 

in the vessel is known. In the absence of specific tank vent gas composition data, sampled data 

were used from a 2000 Btu/scf vapor gas sample reported by Southern Research Institute (2002), 

and summarized in Table 3-48. Results of these calculations are shown in Table 3-44. 

Table 3-44 Mass of Hydrocarbon Gas Released from Crude Storage Tank Over Lifetime 

of 10 Pattern Tank Battery Operations (an estimated 95% of this vapor is collected by a 

VRU)

CO2-EOR 

Scenario

Total Tank Releases 

Throughout CO2-

EOR Operation, lb 

VOC

Historical 1,404,000

Best Practices 2,187,000

1.5 HCPV 

CO2 WAG 

Injection

2,689,000
88

Table 3-45 Summary of Crude Oil Tank Emissions Estimate (working and breathing losses estimated using EPA Tanks 

model, flashing losses estimated using the Vasquez-Beggs equation)

CO2-EOR 

Scenario

Tank 

Contents

Tank-Years 

in 10-well 

Tank Battery 

Full EOR 

Performance

Average 

Number of 

Turnovers

per Year per 

Tank

Average 

Throughput 

per Tank per 

Year

(stb/tank 

year)

Estimated Tank Emissions (kg/tank-year)

Flash 

Losses

Working 

Losses

Breathing 

Losses

Total 

Losses 

per Tank 

per Year 

Historical Crude oil, 

RVP-5 22 467 173,100 26,900 1,890 171 29,000

Best 

Practices

Crude oil, 

RVP-5 30 496 199,500 30,000 1,830 171 32,000

1.5 HCPV 

CO2 WAG 

Injection

Crude oil, 

RVP-5 41 521 179,300 28,600 1,860 171 30,600
89

It should be noted that, in addition to the two tanks considered to be in active use for crude oil 

storage, there are expected to be one or more additional crude oil storage tanks that provide an 

engineering safety measure that would prevent shut-in of production or stoppage of operations in 

the event of post-production interruption. However, any redundant storage tanks would not be in 

regular use and emissions associated with fluid storage in those vessels have not been considered.

3.7 Produced Water Tank CH4 Emissions Estimate

After water produced to the surface from CO2-EOR flood operations is separated from produced 

oil with which it is comingled, it is stored within the tank battery in a brine storage tank or tanks. 

The produced brine contains dissolved and entrained methane that is released as the brine is 

depressurized through post-production operations. Methane contained in produced water is of a 

significantly smaller concentration than that entrained in an equivalent volume of produced oil, 

since CH4 has a stronger affinity for hydrocarbon than for water. However, the methods used to 

estimate flashing emissions losses from oil are based on properties specific to the produced oil 

and cannot, therefore, be modified to describe similar losses from produced water. In the absence 

of measured data, emissions factors can be estimated from produced saline water that is delivered 

to storage tanks. As reported in Table 3-9, the model brine saline content for produced water is 

96,000 parts per million (ppm) by volume, or approximately 10 percent. The separator vessel 

immediately upstream of the water tank was reported earlier to be 100 psig. Based on this, the 

most appropriate value listed in the API GHG emissions methodology manuscript is between the 

value reported for upstream separator pressure of 250 psig and produced water salt content of 10

percent (0.0150 tonnes CH4 per 1000 bbl produced water) and the value reported for upstream 

separator pressure of 50 psig and produced water salt content of 20 percent (0.0015 tonnes 

CH4/1000 bbl produced water). In the absence of a better estimation method, it is assumed that 

the lower of the two reported values is an appropriate estimate of CH4 emissions from the water 

storage tank. It is assumed that 95 percent (by volume) of the generated methane emissions are 

collected by the vapor recovery unit, and that only 5 percent are released to the atmosphere.

Table 3-46 Methane Produced from Brine Storage Tanks and Collected by VRU or 

Released to Atmosphere—Reported on per Pattern-Year Basis (40-acre, 5-spot well 

pattern)

Parameter Historical Best 

Practices

1.5 HCPV CO2

WAG Injection Units

Volume methane 

from brine tanks 12,900 10,600 10,000 scf CH4/pattern-yr

Mass of recovered 

methane 232 190 180 kg per pattern-yr

MJ HHV of recovered 

methane 12,900 10,500 10,000 MJ/pattern-yr

Methane emitted to 

atmosphere 12.2 10.0 9.5 kg per pattern-yr
90

3.7.1 Venting/Flaring and Vapor Recovery

According to the Natural Gas STAR Partners, a voluntary partnership between the U.S. 

Environmental Protection Agency and the oil and gas industry, 26.6 billion cubic feet of gas is 

lost each year in the U.S. from the approximately 573,000 crude oil storage tanks that are in use. 

Constituents including methane, non-methane VOCs, natural gas liquids (NGLs), other hazardous 

air pollutants, and inert gasses that are dissolved or physically entrained in produced crude oil 

evolve or “flash out” of the crude as pressures and temperatures to which the crude oil is exposed 

change. These vapors collect in the space between the liquid level and the fixed tank roof, and are 

often vented to the atmosphere as the tank liquid level fluctuates (commonly referred to as 

“breathing losses”) (U.S. EPA, 2006). One means of avoiding these losses and generating a 

valuable product stream is installation of vapor recovery units (VRUs) that capture vapors 

evolved from oil storage tanks. 

VRUs are relatively simple systems that capture approximately 95 percent of the Btu-rich vapors 

that are released from crude oil stored in stock tanks. There are between 8,000 and 10,000 VRU 

units installed in the U.S. and, on average, each unit recovers vapors from four tanks (U.S. EPA, 

2006). A VRU system comprises manifolds connecting one or more tanks to a common suction 

line and piped to the VRU suction scrubber, an independent sensing line from the most active or 

farthest tank to the sensing unit on the VRU, discharge piping from the VRU to the gas gathering

line, a meter run, or the suction of the field gas compressor (U.S. EPA, 2006). Condensates that 

precipitate in the suction scrubber are typically returned to the stock tanks. The VRU operation is 

automated as a function of the headspace pressure observed in the tank, and includes systems to 

bypass flow and/or automatically shut down compression to avoid issues such as fugitive 

emission, introduction of oxygen, and implosion of tanks. Compression in the VRU is achieved 

using either rotary screw or rotary vane compressors, since they are best suited to handle wet gas. 

It is assumed that VRU is driven by variable speed electric compressors that can be adjusted to 

meet the vapor production rates that will vary as a function of production rates that change with 

flood maturity, and environmental conditions that vary on a daily and seasonal basis. 

3.7.1.1 Characterization of Vapor Recovery Unit Performance

It is assumed that operators will use the transition from secondary to tertiary EOR flood 

operations as an opportunity to install VRU technology, both as a means of voluntarily reducing 

tank battery emissions, and to generate a valuable, Btu-rich gas product for sale or use onsite 

(Natural Gas STAR partners report VRU system payback periods of as little as six months). As 

such, it is assumed that venting practices will be eliminated, and flaring will only be used in 

instances of system upset/failure. Because catastrophic events are not considered within the 

scope of this analysis, both flaring emissions will be neglected. The choice to consider VRU as 

new infrastructure is considered to be conservative, since most oil production systems currently in 

operation are already equipped with VRUs (Melzer, 2010).

In general, the volume of vapor captured is a function of the volume of oil passing through the 

tanks, the composition of the crude oil, the pressure at which separators discharge to the tank, the 

tank configuration, and seasonal daily temperatures. VRU performance has been characterized 

based on tank throughputs as estimated using volumetric flows to a single tank battery from ten 

producing wells. Working and breathing losses were estimated for oil storage tanks and 

heater/treater vessels using the U.S EPA TANKS version 4.0.9d, as described above. Flashing 
91

losses resulting from sudden decreases in gas solubility when fluid is transferred from higher to 

lower pressure and/or lower to higher temperature conditions are estimated using the VazquezBeggs equation, as described previously. For all vessels from which vapors are recovered, a 

recovery efficiency of 95 percent by volume has been assumed. Based on this recovery 

efficiency, a total volume of gas collected by the VRU is estimated to be 524, 328, and 346 Mscf

per pattern year of 2000 btu/scf vapor for historical, best practices, and high CO2-EOR

operational scenarios, respectively. Table 3-47 summarizes vapor recovery and methane/nonmethane VOC emissions. Table 3-44 summarizes composition and constituent properties for the 

2000 btu/scf HHV; this composition is assumed for all tank battery vapor calculations. 

Following recovery, vapor is transported to a solid desiccant dehydration unit prior to sale, or for 

on-site use, (Sidebottom and Richards, 2009) or recycling (Melzer, 2010).

Table 3-47 Summary of Vapor Recovery Unit Performance for Each Operational Scenario 

Considered, Reported on a per Pattern-Year Basis (40-acre, 5-spot patterns in all cases)

Parameter Historical Best Practices

1.5 HCPV 

CO2 WAG 

Injection

Units

Volume vapor 

recovered 486 538 492 Mscf 2000 btu/cft gas per (pattern-yr)

VRU electricity use 15,200 14,100 13,400 MJ electricity used per 

pattern-yr

HHV of recovered 

vapor 1,025,000 1,134,000 1,038,000 MJ recovered vapor per pattern-yr

Mass vapor 

released 3,483 3,854 3,528 lb vapor released per pattern-yr

Mass CH4

released to atm. 954 1,056 967 kg CH4/(pattern-yr)

Mass NMVOC 

released to atm. 2,529 2,798 2,562 kg NM-VOC/(pattern-yr)
92

Table 3-48 Summary of Tank Battery Vapor Composition for 2000 Btu/scf HHV Gas Collected by Vapor Recovery Unit

Constituent Mol % Volume % Weight % MW 

(g/mole)

HHV 

(MJ/kg)

Density

(lb/ft3)

N2 4.7 4.7 3.7 28.01 0 0.0727

O2 0.7 0.7 0.6 32.00 0 0.0831

CO2 0.2 0.2 0.2 44.01 0 0.1142

CH4 46.3 46.5 21.0 16.04 55.5 0.0416

Ethane 10.1 10.1 8.6 30.07 51.9 0.0780

Propane 12.0 12.0 15.0 44.1 50.35 0.1144

Isobutane 5.7 5.7 9.4 44.1 49.5 0.1509

n-butane 6.2 6.2 10.2 58.12 49.5 0.1509

Isopentane 3.5 3.5 7.1 72.15 49.01 0.1870

n-Pentane 2.5 2.5 5.1 72.15 49.01 0.1870

Hexanes plus 7.9 7.9 19.1 86.17 48.77 0.2236

Tank Battery Vapor 99.7 100.0 100.0 35.47 49.64 0.0937

Tank Battery NM-VOC 

fraction 47.8 48 74 53.36 49.68 0.1389

 Calculated from reported as-received vent gas sample (Southern Research Institute, 2002)
93

3.8 Desiccant Dehydrators

Desiccant dehydration is an alternative to glycol dehydration systems that is appropriate for 

applications in smaller throughput conditions. Based on the design assumptions made for 

characterization of tank battery operations (accepting liquids from 10 specified CO2-EOR 

patterns), the calculated required triethylene glycol circulation rate was sufficiently low to justify 

replacement of a liquid desiccant system with a solid desiccant dehydration unit. Solid desiccant 

dehydrators remove moisture from process gasses by passing moist gas through a packed bed of 

solid desiccant beads or pellets (typically composed of salts such as calcium, potassium, or 

lithium chlorides) (API, 2009). Because solid desiccant systems are fully enclosed, they have 

significantly lower overall emissions, only releasing CO2 and CH4 when the system is opened to 

replace spent desiccant. API greenhouse gas emissions methodology document cites a 2003 

EPA Gas STAR Lessons Learned document equation for estimating annual emissions from this 

intermittent source: 

(10)

where

GLD = gas loss from desiccant dehydrator, scf/year

H = dehydrator vessel height, ft

D = dehydrator vessel inside diameter, feet

P2 = gas pressure, psia

P1 = atmospheric pressure, psia

G = fraction of packed vessel volume that is gas, and

N = number of desiccant change outs per year.

Table 3-49 Parameter Values Used in eEstimation of Venting Emissions from Solid 

Desiccant Dehydration System

Parameter Value (units)

Height 6.4 (feet)

Internal diameter 1.6 (feet)

Pressure of gas inside the vessel 450 (psig) – 4513.28 (psia)

Atmospheric pressure 13.28 (psia)

Desiccant bed replacement rate 52 (replacements/year)

Volumetric packing efficiency, % 45

Vessel gas CH4 content, vol.% 46.5

Vessel gas NMVOC, vol.% 48

Based on this set of assumptions, the total estimated volume of gas produced per tank battery 

solid desiccant system per year is estimated to be 10.5 Mscf/year. Assuming the gas densities 

listed in Table 3-44 for methane and non-methane VOC fractions, and noting that desiccant

systems process vapor from liquid produced from 10 well patterns, emissions values of 9.2 kg 

CH4/pattern-year, and 31.8 kg NMVOC/pattern-year were calculated for all operational 

scenarios.
94

3.9 Gas Processing Facility Operation 

Gas that is produced from CO2-EOR operations contains both CO2 and hydrocarbon (HC) gas. 

The fraction of HC gas contained in the total bulk gas that is separated from liquids (oil and 

water) at production satellite facility varies as the flood progresses, but is generally high in initial 

phases of CO2-EOR production and tapers off as CO2 breakthrough increases and total 

hydrocarbon production decreases. The handbook of the CO2 Predictive Model (Ray and 

Muñoz, 1986) specifies a threshold gas production rate of 5.0 MMCF/day, below which CO2-

EOR operations gas processing is assumed to include only dehydration and recompression of 

whole gas. However, modern floods have examples in which the volumes of recycle gas are 

dramatically higher and no NGLs are removed. Nonetheless, CO2-EOR operations with daily 

flows greater than this threshold were assumed to process produced gas by full hydrocarbon gas 

separation and recycle of concentrated CO2 for reinjection. An early summary report on CO2-

EOR prepared by the National Petroleum Council (Bailey and Curtis, 1984) identifies a peak 

total gas production rate threshold of approximately 20 MMscf/day above which CO2-EOR 

operations for a single reservoir justify installation of a dedicated gas processing plant (Figure 

3-19). Based on these reported values, it has been assumed that a gas-processing plant will 

include full CO2 stream separation and recycle, and that CO2-EOR operations will require 

construction of a dedicated gas- processing facility with separation of CO2, recycle of 

concentrated CO2, dehydration and sale or combustion of gas, and recovery of NGL. 

Figure 3-19 CO2-PM Model Established a Peak Total Gas Production Threshold of 20 

MMscf/day Above Which a CO2-EOR Operation Was Assumed to Require Construction of 

a Dedicated Gas Processing Facility

Figure source: Bailey and Curtis (1984)
95

3.9.1 Characterization of Ryan-Holmes CO2 Separation and NGL Recovery

The Ryan-Holmes process is a distillation separation process that separates natural gas liquids 

(NGLs) from a CO2 stream by taking advantage of the difference in dew point between CO2 and 

different hydrocarbon fractions—selectively separating fractions as they condense at distinct 

points in a vertical fractionation column or series of columns. The primary energy demand for a 

Ryan-Holmes process results from the compression of refrigerant that is used to cool the 

separation column. In CO2-EOR operations, the primary function served by the Ryan-Holmes 

process is considered to be the separation of CO2 from mixed gas stream, while generation of 

NGL product represents a secondary function; the primary product is CO2 that is recycled to 

CO2-EOR injection and the NGL is a secondary co-product. Depending on the number of 

separation columns used and the tolerance of process control, operations can be tuned to separate 

other products including ethane and sulfur from the fluid stream.

3.9.1.1 Description of Model Facility Used in Characterization

Gas processing facility emissions and resource requirements were characterized based on a CO2-

EOR carbon dioxide separation and natural gas processing plant operating permit renewal 

application submitted by Whiting Oil and Gas Corporation Operating Dry Trail Gas Plant, 

Texas County, Oklahoma (Milligan, 2007). The facility is designed to accept 45 MMscfd low 

sulfur gas produced from CO2-EOR flood operations, and processes that gas by dehydrating, 

compressing, and separating various fractions through the patented Ryan-Holmes separation 

process (Process Systems International). Recovered CO2 is recycled to CO2-EOR operations 

where it is re-injected into the target reservoir to stimulate additional oil production. Separated 

hydrocarbon gas is largely used on site to fuel gas processing plant operations, with the 

remainder delivered to pipeline for off-site sales. Natural gas liquids (NGLs) are collected to a 

storage tank and transported periodically offsite by truck for sales.

Bulk gas produced from CO2-EOR operations enters the facility through a metering facility, 

undergoes primary gas filtration/separation to remove any entrained solids or free liquids, and 

then enters a dehydration unit where wet gas is contacted with the liquid desiccant tri-ethylene 

glycol (TEG). Moisture-lean TEG absorbs water from the CO2-EOR product gas stream before 

being cycled to a second vessel where moisture-rich TEG is thermally regenerated using heat 

supplied by a hot oil heater. Emissions from the still vent and flash tank of the TEG unit are 

collected by a VRU and returned to the facility inlet; TEG unit emissions are therefore 

considered to be negligible. Dehydrated CO2-EOR product gas is then compressed; compressor 

discharge is cooled; and cooled, compressed gas is moved to the propane recovery column 

(PRC) of the Ryan-Holmes CO2 purification unit.

The Ryan-Holmes process involves three vessels; the PRC, a de-methanizer, and a gas/gas 

exchanger. Dehydrated, compressed, and cooled inlet gas is introduced at the middle of the 

trayed PRC column and is partially condensed by the propane refrigerant. The lighter 

“overhead” fraction is moved to a PRC reflux accumulator wherein liquids and vapor are 

separated. CO2-rich vapor is compressed and combined with liquid CO2 product, while light 

hydrocarbon-rich vapor is sent to the de-methanizer. Liquid from the PRC reflux accumulator is 

either sent to CO2 recycle pipeline pumps, or returned to reflux the PRC. The PRC column 

bottoms are composed of heavier components (mostly C5+) that are transported to the gas/gas 

exchanger for use as an additive to facilitate hydrocarbon separation. Natural gas liquids drawn 

from the middle of the PRC column are cooled to 120 °F, combined with excess C5+ additive, 
96

and sent to the NGL storage tank. Natural gas used to power the plant is drawn from the demethanizer overhead

The Ryan/Holmes Process uses a propane refrigeration system that is capable of cooling the 

process stream to low temperature levels required for distillative separation. Propane vapor is 

compressed by primary refrigerant compressors, then combined with propane refrigerant vapors 

from the refrigerant economizer overhead moved to a second stage of compression, before being 

condensed in a refrigerant condenser and stored in a refrigerant surge tank. Liquid propane is 

sent to cool the process stream in the PRC condenser and the gas/gas exchanger columns, and 

propane vapors are returned to the refrigerant compressor array. 

A closed-loop oil system is used to heat and regenerate moisture-rich TEG in the gas dehydration 

unit. The oil stream moves through a series of heat exchangers where process waste heat is 

recovered to preheat the oil before final heating to 450 °F by a natural gas-fired hot oil heater. 

Hot oil is moved to the dehydration plant to thermally regenerate the moisture-rich liquid 

desiccant stream. 

The gas processing facility uses five compressors driven by natural gas-fired Superior 2416G 

engines and one electric compressor. Two of the six compressors compress inlet gas and four 

compress propane used as refrigerant in the Ryan-Holmes process. Two natural gas-fired Solar 

Saturn T-1,300 turbine generator sets produce electrical power for on-site use. Finally, a 

Katolite 8163-7405 diesel-fueled generator set is maintained for standby power generation and, 

as such, is not in regular use. Table 3-52 summarizes major process components and related fuel 

use.

3.9.1.2 Ryan-Holmes Process Stream Flow Calculations

Estimations of energy feedstock demand, NG and NGL production are based on the assumptions 

that the volume of gas mixture entering the combined Ryan-Holmes separation/compression

process is approximately the sum of produced CO2 and produced hydrocarbon gas from CO2-

EOR operations, and that the density of this gas mixture is comparable to that observed in the 

Ryan-Holmes process as reported by Simpson (2008)—0.117 lbm/ft3. 

Based on CO2-EOR flood screening model results summarized in Section 3.4.2, the volumes of 

CO2 and hydrocarbon gas generated (MMscf) over the life of flood operation were predicted for 

a single well pattern. From these data, the average total gas production per year of pattern 

operation were calculated for each operational scenario. As mentioned previously, the Whiting 

Dry Trail Gas Plant has a reported plant throughput capacity of 45 MMscf per day (Milligan, 

2007). The average rate of total gas production (CO2 + hydrocarbon gas) and the estimated 

number of well patterns that can be accommodated by a gas processing plant of this size are

reported in Table 3-50. 
97

Table 3-50 Summary of CO2-EOR Bulk Produced Gas (CO2 + hydrocarbon gas) Supplied 

to Gas Processing Facility

CO2-EOR

Scenario

Average Daily 

Gas Production 

(CO2 + HC gas) 

per Well Pattern 

Day, 

MMscf/PatternDay

Average Annual 

Gas Production 

(CO2 + HC gas) 

per Well Pattern 

per Year, 

MMscf/PatternYear

Number of Well 

Patterns Served by 

Single 45 

MMscf/day Gas 

Processing Plant

Historical 0.200 73 225

Best 

Practices 0.376 137.4 120

1.5 HCPV 

CO2 WAG 

Injection

0.426 157.7 106

3.9.1.3 Estimation of Produced Hydrocarbon Gas Composition

Results of CO2 Prophet model runs provide estimates of the volume hydrocarbon gas generated 

as a result of CO2-EOR operations, but do not provide details on properties of the mixed 

hydrocarbon gas. To estimate an appropriate gas composition, molecular weight, and heating 

value of the produced gas, the Nehring Database was filtered to identify wells located in the 

Permian Basin that produce oil with API gravity values similar to that of the model reservoir. 

Adjusted average gas composition values were estimated in this manner: Nehring well database 

(2007) was filtered to identify a subset of reservoirs located in the Permian Basin, producing oil 

with corresponding API gravity between 32.5 ° and 37.5 °, and for which gas composition values

are provided for methane, ethane, propane, butanes, pentanes, hexanes, carbon dioxide, hydrogen 

sulfide, nitrogen, and helium. Mean values were calculated for these 53 samples. Because 

average values were taken for each parameter, the sum was slightly less than 100 percent gas 

composition (98.5 percent). To account for this, the mean value and standard deviation for each 

constituent were multiplied by (100 percent /98.5 percent) to adjust to 100 percent total volume. 

Calculated adjusted average gas composition from wells meeting these criteria are reported in 

Table 3-51. 
98

Table 3-51 Adjusted Average Composition of Hydrocarbon Gas Produced from the Permian Basin 

with API Gravity Between 32.5 ° and 37.5 ° 

Hydrocarbon 

Gas Constituent Formula

Mean 

Composition 

(wt %)a

Standard 

Deviation

Methane CH4 72.34 18.73

Ethane C2H6 12.21 10.33

Propane C3H8 4.02 4.05

Butanes C4H10 1.27 1.48

Pentanes C5H12 0.50 0.62

Hexanes Plus C6H14 0.24 0.45

Carbon Dioxide CO2 1.75 6.55

Hydrogen Sulfide H2S 0.62 3.14

Nitrogen N2 7.01 13.25

Helium He 0.03 0.07 a Database does not specify composition as percent by weight or volume. 

Weight percent is assumed. Sample size of 53.

The mean higher heating value from these 53 samples was 1141.6 btu/ft3, with a standard 

deviation of 217.0 btu/ft3 (Database does not specify lower or higher heating value—reported

values are assumed to be higher heating values.). This estimated gas composition corresponds to 

molecular weight average of 21.3 and a calculated gas specific gravity of 0.70 (air specific 

gravity is 1.0). The gas composition estimate arrived at in this manner is assumed to be 

representative of the hydrocarbon gas composition generated by CO2-EOR activity in the model 

reservoir. As is shown in reservoir production estimates, the fraction of whole produced gas that 

is hydrocarbon gas of this composition will change over time as CO2 breakthrough increases and 

hydrocarbon production trails off. The gas composition specified above and the degree of 

dilution with CO2 as specified by CO2 Prophet model results are used to estimate gas processing 

facility influent composition and heating value. 

3.9.1.4 Gas Processing Facility Emissions Estimate

Emissions from the gas processing facility were developed by Milligan (2007) based on 

previously detailed combustion equipment specifications, manufacturer emissions data, EPA AP42 emissions factors for fugitive emissions, and estimated process stream properties. Engine 

emissions were estimated based on continuous operation (8,760 hours/year). Formaldehyde 

emission estimates were assumed to be reduced by 75 percent of untreated emissions in cases 

where post-combustion oxidation catalysts are used. Emission estimates for the 13.48 

MMBtu/hour hot oil heater were based on manufacturer’s data, which report emissions factors of 

0.08 lb NOX /MMBTU, 0.04 lb CO/MMBTU, and 0.015 lb VOC /MMBTU, and assume fuel 

heat content of 924 BTU/scf (gas provided from the Ryan/Holmes process de-methanizer). 

Emissions estimate for the emergency diesel generator were based on 960 hours of operation per 

year, emission factors listed in Table 3-52, a diesel fuel heat content of 137 MBTU/gal, and a 

fuel sulfur content of 0.5 weight percent. Diesel combustion CO2 emissions were based on an 

EPA emission factor of 2778 grams of CO2 per gallon of diesel combusted and an assumed 

combustion efficiency of 99 percent. Emissions from the flare were estimated based on an 

assumed combustion efficiency of 98 percent, AP-42 (1/95), emissions factors, and combustion 

of 16.85 MMscfy of pilot, purge, and residue gas with a heating value of 1,056 BTU/scf, and 
99

0.33 MMscfy of propane with a heating value of 2,315 BTU/scf (Milligan, 2007). CO2

emissions for flare gas combustion also assume 98 percent combustion efficiency, and use an 

emission factor of 134.46 lb CO2 per MMBtu gas combusted. Condensate tank flashing 

emissions were estimated using the Vasquez-Beggs equation and a slop oil (water + oil) 

throughput of 9,400 barrels per year (70 percent H2O). Milligan (2007) estimated that emissions 

from the other tanks were insignificant and those values were not quantified; this assumption has 

been maintained in this work. Condensate loading emissions (loading to tanker trucks) were 

estimated using a slop oil throughput of 9,400 barrels per year and an emission factor of 4.96 

lb/1,000 gallons. Fugitive VOC emissions estimates were developed using the EPA’s 1995 

Protocol for Equipment Leak Emission Estimates (EPA-453/R-95-017) and the inventory of 

fugitive emissions sources listed in Table 3-53. It was assumed that emissions from the TEG 

dehydration unit are negligible since all vapors are recovered by a VRU and returned to the 

process inlet. Process blowdown emissions were developed based on an estimated 144 

blowdowns with 8 Mscf fugitive emissions per blowdown, a molecular weight of 41.81 lb/lbmole, and an estimated VOC content of 3.8 percent (Milligan, 2007).
100

Table 3-52 Summary of Combustion Equipment Used to Power Bas Processing Facility or Control Hydrocarbon Emissions

Description Number 

of Units Description

Hours of 

Operation 

Per Year

Fuel Type

Fuel

Usage 

Rate

MMBtu/

Year/Uni

t

MMBtu/ 

Year For 

All Units

Height, 

(feet)

Diameter 

(inches)

Flare 1

Intermittent 

off-spec gas 

and blowdown 

combustion

N/A Flare gas 1,209 

MMscf/year

Not used 

for work

Not used 

for work Not reported

Turbine: Solar 

Saturn T-1300

(0perated at 465 °F)

2

1,151-hp

(950 kW) 

rating

8,760

Natural 

Gas (924 

Btu/scf)

12,900 

scf/hr 104,416 208,831 40 54

Katolight Generator 

w/

Detroit Diesel 

Engine

(operated at 825 °F)

1

1,096-hp

(817 kW) 

rating

960 Low sulfur 

Diesela 57 gal/hr 7,497 7,497 30 12

Hot Oil Heater 1 13.48 

MMBtu/hr 8,760

Natural 

Gas (924 

Btu/scf)

13.48 

MMBtu/hr

Superior 2416G 

Compressor Engine

(operated at 728 °F 

w/OC)

2 3,200 hp 8,760

Natural 

Gas (924 

Btu/scf)

23,896 

scf/hr 118,085 118,085 45 24

Superior 2416G 

Compressor Engine

(operated at 728 °F 

w/OC)b

3 2,800 hp 8,60

Natural 

Gas (924 

Btu/scf)

20,909 

scf/hr 193,420 386,840 45 24

a

Diesel fuel higher heating value of 137 Mbtu/gallon, 500 ppm sulfur

b

W/OC - with oxidation catalyst
101

Table 3-53 Sources of Fugitive Emissions from Gas-Processing Facility

Type of Equipment Type of Service Number Items

Valves

Gas/Vapor 1,592

Light Liquid 837

Heavy Liquid 186

Connectors

Gas/Vapor 6,368

Light Liquid 3,348

Heavy Liquid 744

Flanges

Gas/Vapor 1,592

Light Liquid 837

Heavy Liquid 186

Pump Seals Light Liquid 9

Heavy Liquid 6

Othersa

Gas/Vapor 83

Light Liquid 0

Heavy Liquid 0 a

Others include compressor seals, pressure relief valves, relief valves, diaphragms, drains, 

dump arms, hatches, instruments, meters, polished rods, and vents.

Table 3-54 Gas-Processing Facility Storage Tank Volumes

Description Size (Gal.)

Process Drain Sump Tank 1,000

Diesel Tank 4,200

Lube Oil Tank 8,820

Ambitrol Tank 8,814

TEG Tank 4,200

Slop Oil Tank 19,740

Lube Oil (Day) Tank 1,000

Methanol 500

Methanol 500

Gasoline 500

Synthetic Lube Oil 500
102

Table 3-55 Gas-Processing Plant Engine Combustion 

Emission Factors

Name/Model NOX

(g/hp-hr)

CO

(g/hp-hr)

VOC

(g/hp-hr)

1,151-hp Solar Saturn T-1300 2.30 2.60 0.05

1,096-hp Katolight Generator 10.78 3.42 0.28

3,200-hp Superior 2416G W/OCa 1.0 0.27 0.50

2,800-hp Superior 2416G W/OC 1.0 0.27 0.50

Superior 2416G W/O Controls 1.0 2.10 0.50 a

W/OC - with oxidation catalyst; W/O – without.
103

Table 3-56 Estimation of Gas Processing Facility Emissions

Emissions Source NOX CO VOC SO2

a CO2b

lb/hr TPY lb/hr TPY lb/hr TPY lb/hr TPY TPY

Flarec --- 0.63 --- 3.43 --- 1.30 --- 0.53 1,223

NG Turbine 5.83 25.55 6.60 28.89 0.13 0.56 0.74 3.22 7,020

NG Turbine 5.83 25.55 6.60 28.89 0.13 0.56 0.74 3.22 7,020

Hot Oil Heater 1.08 4.72 0.54 2.39 0.20 0.89 0.83 3.64 7,939

Diesel emergency 

generator 26.04 12.50 8.26 3.97 0.68 0.32 4.01 1.93 166

3,200 hp 

Compressor Engine 7.05 30.90 1.90 8.34 3.53 15.45 1.36 5.97 13,004

3,200 hp 

Compressor Engine 7.05 30.90 1.90 8.34 3.53 15.45 1.36 5.97 13,004

2,800 hp 

Compressor Engine 6.17 27.04 1.67 7.31 3.09 13.52 1.19 5.22 11,378

2,800 hp 

Compressor Engine

6.17 27.04 1.67 7.31 3.09 13.52 1.19 5.22 11,378

2,800 hp 

Compressor Engine 6.17 27.04 1.67 7.31 3.09 13.52 1.19 5.22 11,378

Tank Working, 

Breathing, Venting 

Emissions

--- --- --- --- --- 30.96 --- --- ---

Blowdowns --- --- --- --- --- 2.41 --- --- ---

Fugitives --- --- --- --- --- 56.99 --- --- ---

Loading --- --- --- --- --- 0.98 --- --- ---

Total 71.23 211.09 30.59 105.30 17.45 166.43 12.61 40.14 83,343 a Based on a fuel sulfur content of 343 ppmv (57 lb SO2/MMscf) except for the diesel engine which is based on fuel sulfur content of

0.5 %S.

b Based on CO2 emissions factor of 13.446 lb CO2 /BTU of natural gas and 2778 grams CO2 per gallon of diesel consumed with 99% 

diesel combustion efficiency c Natural gas flare CO2 emissions assumes combustion efficiency of 98% as estimated by Milligan (2007)
104

3.9.1.5 Estimating Separation Efficiency of the Ryan-Holmes Process 

Removal efficiency of hydrocarbon constituents through the Ryan Holmes process is estimated 

based on data provided in n report entitled List of Acid Gas Removal Processes (no authors 

listed) and citing a presentation by Ryan and Schaffert (1984). Based on these data, reported in 

Table 3-57, an estimated methane recovery to fuel gas of 93 percent, CO2 recovery to recycle 

stream of over 90 percent, and hydrogen, ethane, propane, and butanes fraction recoveries to 

NGL product of about 100 percent, 93 percent, 100 percent, and 99 percent, respectively. A two 

column Ryan-Holmes propane recovery process at the Chevron Buckeye CO2 Plant (Garner, 

2008) has a reported methane recovery rate of 7 percent, by mass (estimated by dividing the 

difference between PRC inlet and outlet mole percentage of each constituent by the inlet mole 

percent composition). This low methane recovery efficiency is considered to be too low to be 

applied to gas streams with significant recoverable methane content. 

Table 3-57 Ryan/Holmes Process Influent Gas and Effluent Vapor and Liquid Molar Flow Rates 

(moles/hr) 

Constituent

Feed Gas 

Flow Rate, 

moles/hr

Fuel Gas 

Product Flow 

rate, moles/hr

CO2 Recycle 

Stream Flow 

rate, moles/hr

NGL 

Production 

Rate, 

moles/hr

CO2 793.3 4.2 715.1a 20

H2 5 - 4 ppm 5

CH4 214.2 199.2 15 -

C2H6 110.9 8 102.9

C3H8 94.8 0.1 0.3 94.4

C4 116.8 0.7 - 116.1

N2 3.1 3.1 - -

Total 1338.1 207.3 738.4 338.4

Referenced from Ryan and Schaffert a

Reported value of 715.1 moles/hour was adjusted to 769.1 moles per hour to 

ensure molar balance between process streams.

These values were used to estimate gas-processing plant mass separation efficiency. Table 3-58

reports mass percent of influent flow reporting to each process stream.
105

Table 3-58 Calculated Gas Separation Efficiency of Ryan-Holmes Process (percent mass)

Constituent

Mass Percent of 

Influent Stream 

Reporting to Fuel 

Gas (% mass)

Mass % 

Influent 

Stream 

Reporting to 

CO2 Recycle 

Gas (% mass)

Mass Percent of 

Influent Stream 

Reporting to 

NGL Stream (% 

mass)

Carbon Dioxide (CO2) 0.5 97.0 2.5

H2 0.0 0.00 100.0

Methane (C1) 93.0 7.00 0.00

Ethane (C2H6) 0.0 7.2 92.8

Propane (C3H8) 0.1 0.3 99.6

Butanes(C4) 0.6 0.0 99.4

Nitrogen (N2) 100.0 0.0 0.0

These calculated percent recovery estimates were modified to include other constituents that are 

in the previously-reported gas analysis estimate developed from the Nehring Database (2007). 

Modifications include addition of pentane and hexane plus fractions based on an assumption of 

100 percent of these heavy fractions reporting to the NGL product stream, removal of H2 (no H2

content is reported in Nehring Database), and addition of helium based on the assumption that 

100 percent, by mass, of helium is retained in the gas fraction and returned to the CO2-EOR 

flood in the CO2 stream.

Table 3-59 Estimate of Mass Allocation of Each Influent Gas Constituent Fraction Between 

Products of the Gas Processing Facility

Constituent

Mass Percent of 

Influent Reporting 

to Fuel Gas (% 

mass)

Mass Percent 

Influent 

Reporting to 

CO2 Recycle 

Stream (% 

mass)

Mass Percent of 

Influent

Reporting to 

NGL Stream (% 

mass)

Carbon dioxide (CO2) 0.5 97 2.5

Helium (He) 0.0 100 0.0

Methane (C1) 93 7 0.0

Ethane (C2H6) 0.0 7 93

Propane (C3H8) 0.1 0.3 99.6

Butanes(C4) 0.6 0.0 99.4

Pentanes (C5) 0 0 100

Hexanes Plus (C6+) 0 0 100

Nitrogen (N2) 100 0.0 0.0

It is assumed that the H2S concentration in the CO2-EOR produced gas is negligible in all 

scenarios considered in this report. In cases where significant concentrations of H2S are present 

in the produced gas, it would be possible to separate it as a pure stream in the gas-processing 

facility, and dispose of it in a UIC Class I disposal well. An alternative to disposal would be 
106

oxidation in a Claus plant to produce elemental sulfur and water. Neither option is considered 

further herein. Based on these estimates of gas mass percent composition, and calculated mass

flow of total gas (hydrocarbon gas + CO2) collected from CO2-EOR operations, estimates of gas 

processing plant product mass flow rates and compositions were developed (Table 3-60).

Table 3-60 Average Mass Composition of Gas Recycled to CO2-EOR Operations 

Constituent

Recycled CO2

Stream Mass 

Fraction (%)

Methane 0.7

Ethane 0.7

Propane 0.0

Butane 0.0

Pentane 0.0

Hexane 0.0

Nitrogen 0.0

Carbon Dioxide 98.6

Helium 0.0

Table 3-61 Estimation of Natural Gas and Natural Gas Liquids Production from Ryan-Holmes 

Process

HC Stream Units Historical Best Practices 1.5 HCPV WAG

Fuel Gas

Btu/lb, HHV 19,600 18,200 17,100

MMBtu/short ton 39.3 36.3 34.2

btu/scfa 818 758 713

MMBtu of natural gas 

produced per patternyear7,690 8,260 6,860

MMscf natural gas 

equivalent produced 

per pattern-yearb

7.54 8.09 6.72

Natural Gas 

Liquids

Btu/lbm, HHV 6,900 4,300 3,300

MMBtu/short ton 13.8 8.67 6.60 a

Assumes density of 0.417 lb/ft3 at 20 °C, 1 atmosphere b

Based on natural gas higher heating value of 1020 btu/scf

All values reported as higher heating value unless otherwise noted.
107

Table 3-62 Mass of Constituents Separated from CO2-EOR Recycle Stream Through Ryan-Holmes 

Process 

Constituent

Mass Separated Over Life of CO2-EOR Flood per Well 

Pattern, Short Tons 

Historical 

CO2-EOR

Best Practices 

CO2-EOR

1.5 HCPV WAG 

CO2-EOR

Natural Gas

Methane 18,500 25,300 29,900

Carbon Dioxide 700 2,100 3,500

Helium 0 - -

Nitrogen 1,900 2,600 3,100

Average HHV of 

NG mix over 

lifetime of flood

(MMbtu/ton)

41.9 40.2 39.1

Natural Gas Liquids

Propane 1,160 1,583 1,869

Butane 377 514 607

Pentane 151 206 243

Hexane 74 101 119

Hydrogen Sulfide Product

Hydrogen Sulfide 19 26 30

3.9.1.6 Displacement Credit for Energy Coproducts

In addition to production of the primary crude oil product of CO2-EOR activity, natural gas and 

natural gas liquids are also generated as coproducts. In determining the environmental life cycle 

profile associated with gate-to-gate activities associated with production of crude oil, the benefit 

associated with production of these coproducts should be credited to the profile of the primary 

product. The credit associated with each coproduct is equivalent to the environmental profile 

associated with production and delivery of a product of equivalent function that is obviated by 

the production of the coproduct. For purposes of this study, it has been assumed that natural gas 

liquids generated as a coproduct of CO2 recycle/gas processing activity displace production of 

natural gas liquids generated through natural gas processing and “light ends” generated from 

refinery operations, and that natural gas coproduct is accounted for by taking a credit for the 

displaced production of natural gas generated from domestic offshore production. Amounts of 

coproduct generated are reported on a MJ basis; emissions credits for the production of these 

amounts of coproducts are incorporated into reported gate-to-gate environmental profile of crude

oil production. As an alternative to displacement, one could describe the CO2-EOR performance 

in terms of emissions per unit of total energy product generated (the sum of crude, natural gas, 

and natural gas liquids production). In this case, the primary product is total hydrocarbon energy 

products (reported in units of MJ or barrels of oil equivalent), and no displacement credit for 

coproducts would be applied.

Accounting for Natural Gas Liquids Coproduct 
108

Characterization of natural gas liquids for development of displacement credit estimate is based 

on the 2008 NETL Petroleum Baseline report data and assumes a 50/50 mix of natural gas 

liquids and refinery "light ends" based on EIA estimates that U.S. Production of 

propane/propylene is approximately half from refinery and half from natural gas production 

operations. NGL includes butane, propane, ethane, etc. produced along with natural gas.

Refinery "light ends" includes LPG, refinery still gas and some chemical plant feedstocks. Both 

are appropriate representations of LPG. Density of LPG is assumed to be 86.2 kg/bbl (U.S. 

DOE, 2008). Table 3-63 provides a summary of GHG emissions associated with production and 

delivery of these two comparable products. Averaging these two GHG emissions profiles, the 

cradle-to-gate GHG emissions value for use as an NGL displacement credit is calculated to be 

41.1 kg CO2-E per bbl of LPG or 0.477 kg CO2-E per kg of LPG.

Table 3-63 Displacement Credit for Natural Gas Liquid Coproducts of Oil Production in 

CO2-EOR Estimated as the Average of Domestic Refinery Light Ends and NGLs Produced 

at a Gas-Processing Plant

Pollutant Units

Refinery Light 

Ends Cradle-toGate of refinery

Natural Gas Liquids 

Cradle-to-Gate of natural 

gas processing plant

CO2 kg / bbl liquefied gas 60.9 5.33

CH4 kg / bbl liquefied gas 0.515 0.105

N2O kg / bbl liquefied gas 1.30E-3 2.88E-4

CO2E kg / bbl liquefied gas 74.2 8.04

CO2E kg / kg LPG 0.861 0.0933

Contribution to 

overall (national 

average) profile

% 50 50

Accounting for Natural Gas Coproduct 

Composition and volume of natural gas generated as a coproduct of CO2-EOR operations is the 

sum of gas collected from tank battery vapor and gas processing facility minus that which is used 

in CO2-EOR operations. Any amount not consumed in CO2-EOR operations is considered to be 

coproduct, and a credit is taken based on the amount of coproduct that is sold to the market. 

Only the historical CO2-EOR operational scenario results in excess natural gas production, with 

0.75 million standard cubic feet of 1020 btu/scf HHV net natural gas production per pattern year. 

Best practices and high-CO2 injection scenarios consume more natural gas than they produce, 

requiring 0.66 MMscf and 1.38 MMscf 1020 btu/scf HHV net natural gas, respectively. In these 

scenarios, the same emissions profile as used to apply a credit in the historical case would be 

used to calculate upstream emissions associated with natural gas that would need to be purchased 

to supply CO2-EOR operations. The emissions profile for natural gas is based on a purchased, 

proprietary dataset and cannot, therefore, be reported.

3.10Facility Closure and Decommissioning

Following CO2-EOR, it is assumed that no additional oil recovery or CO2 sequestration 

operations will be carried out at the site. Facility closure operations include plugging and 

abandonment of wells, removal of injection and production equipment, re-contouring of well 
109

pad, removal of unneeded access roads, and site re-vegetation. In this analysis, resource 

requirements and emissions associated with well plugging operations; emissions and resource 

requirements associated with EOR infrastructure removal and site reclamation (regarding any revegetation) have not been considered. Also, it has been assumed that no spills or subsurface 

contamination occurred as a result CO2-EOR operations, and no site remediation is required.

3.11 Plugging and Abandonment of Wells

Potential conduits for leakage of CO2 to the surface or subsurface water resources must be 

plugged following completion of injection operations, including any injection wells or extraction 

wells. Monitoring wells should also be plugged following completion of the monitoring and 

verification period. Plugging wells involves placement of cement plugs in areas along the depth 

of the well that are considered to be critical to the protection of drinking water zones (USDWs),

prevention of injectate leakage to the surface, prevention of subsurface crossflow of fluids, and

protection of correlative rights. Because of the required permanence of storage, a more complete 

plugging may be required as compared to other types of wells, such as traditional oil wells. 

3.11.1 Cementing Operations 

Cement is applied to the well using a truck-, trailer-, or skid-mounted cement pumping system. It 

has been assumed that a double pump, trailer-mounted system is delivered to and used onsite for 

all well cementing operations. Review of specifications for commercially available cement 

pumping systems suggests that a system with two 475 horsepower diesel deck engines is 

appropriate (Rolligon, CPF-800D Double Pump Cementing Trailer). To estimate emissions 

from cementing operations, it is assumed that both of the cement truck deck engines will be in 

operation 12 hours a day for an estimated 3 days of cementing per well (Watson et al., 2002). 

For wells 5,826 feet in depth, and reservoirs of 123 °F, API Class A Portland Cement is specified 

with 46 percent water by weight (5.2 gallons of water per 94 lb sack of cement). Mass of cement 

required for plugging operations is estimated based on the assumption that the volume inside the 

innermost casing is filled with cement for a column height of double the target interval thickness, 

plus a surface plug of 200 feet thick.

Table 3-64 Summary of Cement Pumping Specifications for Well Plugging Operations

Parameter Value Units

Days of cementing per well plug 3 days

Hours of cementing per well plugged 36 hours per well 

plugged

Number of engines per cement rig 2 engines

HP of cementing deck engines 475 HP/engine

Load Factor 0.75 Unitless

Wells per pattern 2 Wells

Diesel fuel used per plugged pattern 10,180 (2,690) Liters (gallons)
110

Table 3-65 Emissions from Cementing Truck Deck Engines Reported on a Per-Pattern Basis (two 

wells per pattern)

Constituent Value Units

Total 

Hydrocarbon 8.6 kg HC per pattern

CO 68.1 kg CO per pattern

NOX 128.2 kg NOX per pattern

PM Total 3.3 kg PM Total per 

pattern

PM10 3.2 kg PM10 per pattern

PM2.5 0.1 kg PM2.5 per pattern

CO2 27,215 kg CO2 per pattern

SO2 0.0018 kg SO2 per pattern

Cement 

Demand 56.7 Metric tonnes cement per pattern

Water 

Consumed 26.1 Metric tonnes water per pattern

3.12 Site Monitoring, Verification, and Assessment

NETL has established geologic storage permanence goals of demonstrating 95 percent and 99 

percent CO2 retention by 2008 and 2012, respectively. This corresponds to maximum leakage of one and 

five percent of injected CO2 after 100 years of storage. Demonstrating that geologic sequestration can 

meet these goals requires that effective techniques be available to measure any potential leakage. A 

number of techniques have been developed to monitor CO2 plume migration, verify CO2

reservoir storage integrity, and account for the amount of CO2 that remains sequestered in a 

target geologic formation. These site monitoring, verification, and accounting (MVA) methods 

involve application of atmospheric, near-surface, and subsurface monitoring techniques that, in 

combination, demonstrate to both regulatory oversight bodies and the general public that 

geologic sequestration of CO2 can serve as a safe and effective GHG control strategy.

While CO2-EOR methodology has employed some sophisticated reservoir surveillance to assure 

that CO2 was performing its intended function, it has not historically employed MVA techniques 

to a degree that may be required for sequestration. Thus, it is assumed that, going forward, 

increased monitoring of CO2-EOR facilities will become more robust so that the operator can 

claim a credit for storage of CO2. As such, a simplified characterization of CO2-EOR monitoring 

has been incorporated. This characterization assumes that the same technologies and areas of 

review are used to survey the site as was detailed in the site characterization description, but that 

two surveys are performed instead of one: one at the time of site closure, and a second survey at 

some point after site closure. A revised characterization of MVA activity should be considered 

as additional detail on likely techniques and monitoring schedules become available. 
111

4.0 Results and Discussion

Results of modeled single well performance and full EOR facility performance for three CO2-

EOR operational scenarios are discussed with respect to environmental performance, resource 

demand, crude oil production, byproduct and coproduct production, and trends observed with 

increasing CO2 injection.

4.1 Single CO2-EOR Well Pattern Performance

For each CO2-EOR operational scenario, performance was estimated based on stream-tube 

modeling of tapered water alternating gas (WAG) CO2/brine injection in a post-water flood, 

Permian Basin-type reservoir conditions. The model is based on a tapered WAG CO2/brine 

injection using a standard 40-acre, five-spot well pattern (1:1 injection: production well ratio) 

using reservoir, fluid, and injection parameters as detailed in Section 3. Fluid injection and 

production performance profiles generated from the stream-tube model have been used as the 

foundation on which surface activity estimates are based. For example, the volume of liquids 

(crude oil and brine) produced from a single CO2-EOR pattern is used to estimate the size of 

processing equipment required. Emissions and energy requirements of this processing 

equipment were estimated based on equipment size and volumetric throughput. Table 4-1

provides a summary of CO2-EOR 40-acre, 5-spot well pattern performance for each operational 

scenario. On an absolute basis, both crude oil production and CO2 retention are shown to 

increase with increasing CO2 injection. Considering only flood performance data suggests that 

increased CO2 injection will provide the best option for both CO2 storage and oil production. 

Subsequent discussion of gate-to-gate life cycle environmental performance provides a more 

complete perspective on CO2-EOR flood performance, which leads to a different conclusion 

about the relative merit of these CO2-EOR operational scenarios for crude oil production and 

environmental performance.

Table 4-1 Summary of CO2-EOR Flood Performance for the Operational Scenarios 

Defined Herein, and Predicted Using the CO2 Prophet Stream-tube Model

CO2-EOR 

Scenario

HCPV

CO2

Injected

Oil Recovery Cumulative Excess 

Brine Production, 

MSTB per Well 

Pattern

CO2 Stored 

Per Pattern, 

Metric Tonnes

% OOIP

MSTB 

per Well 

Pattern

Historical 0.4 11.6 191.4 100.8 38,200

Best 

Practices 1 17.4 301.7 246.0 70,300

High CO2

Injection 1.5 20.9 360.9 240.0 77,800
112

4.1.1 CO2 Retention Performance of Single Well Pattern

Performance of the CO2-EOR flood as predicted by the CO2 Prophet model shows that the

stimulation of oil production is greatest in early years of flooding. Similarly, storage of CO2 in 

the formation is greatest early in the CO2-EOR flood, with very little additional storage achieved 

in later years (for the CO2-EOR operational scenarios considered). In Figure 4-1, cumulative 

mass of CO2 sequestered (calculated as the difference between cumulative CO2 injected and 

produced) is plotted as a function of time for each of the three CO2-EOR operational scenarios 

considered. 

Figure 4-1 CO2 retained in a single 40-acre, five-spot CO2-EOR pattern for the three described 

operational scenarios. Retention is greatest in early years of flood operation. Water slug applied 

after WAG in the historical scenario recovers about 23 percent of stored CO2, by mass.

In all CO2-EOR operational scenarios, the bulk of the geologic storage potential is realized early 

in the WAG injection; data reported in Table 4-2 further detail this observation.
113

Table 4-2 Summary of Single Pattern CO2 Retention Performance. In all operational scenarios, 75 

percent of maximum CO2 storage potential is realized in the first third of flood operation.

Historical Best Practices 1.5 HCPV CO2 WAG

Years to 50% of max.

retention 1 2 2

Years to 75% of max. 

retention 2 6 8

Pattern Life (years) 17 25 36

Max retention (metric 

tonnes CO2) 49,500 70,300 77,800

Ultimate retentiona 38,200 70.300 77,800 a

Historical CO2-EOR scenario includes post WAG injection water slug to recover CO2, so 

the mass of CO2 ultimately retained is less than the maximum that was stored prior to water 

slug injection.

Figure 4-2 illustrates the CO2 sequestered at the end of the flood as a function of the total amount 

of CO2 injected. This plot illustrates the trend of diminishing CO2 storage benefit with higher 

CO2 throughput. Portions of the reservoir that have been swept with CO2 earlier in the flood take 

up less additional CO2 as the injection proceeds. Since high CO2 throughput is also associated 

with increased gas processing activity, higher CO2 injection scenarios also tend to have higher 

operational GHG emissions. Based on these preliminary observations, reconsideration of high 

HCPV WAG CO2 injection alone as a scheme to enhance CO2 storage may be warranted. 

Figure 4-2 Mass of CO2 Sequestered per 40-Acre, Five-Spot as a Function of the Mass of 

CO2 Injected. Additional storage benefit decreased with increasing CO2 injection.

This figure shows that about forty percent of the injected CO2 is retained per pattern in the 0.4 

HCPV CO2 injection historical scenario, about 29 percent of injected CO2 is retained per pattern

in 1.0 HCPV “best practices” scenario, and about 22 percent of injected CO2 is retained in the 
114

1.5 HCPV CO2-EOR scenario. The volume not retained is not vented to the atmosphere, but 

rather recycled for use in CO2-EOR operations. Ultimately, close to 100 percent of purchased 

CO2 will be stored geologically. 

4.1.2 CO2 Recovery in Historical Scenario

In the historical CO2-EOR scenario, CO2 use is kept low in order to minimize the expense of 

purchased CO2. In addition, at the end of the CO2 WAG injection, an additional slug of water is 

injected (assumed 1 HCPV of water) in order to recover as much of the oil and CO2 as 

economically possible from the reservoir. The oil is sold and the CO2 is reused in nearby 

patterns still undergoing active injection. The cumulative storage profile of the historical CO2-

EOR scenario illustrates the effect of this water slug injection to recover CO2. Approximately 27

percent of the sequestered CO2 is recovered by post-WAG injection of a 1.0 HCPV water slug. 

From a CO2 sequestration perspective, this technique both decreases the storage of CO2 per 

pattern and has associated emissions from production and delivery of electricity used to 

compress and inject water, and would not be applied in situations where maximizing 

sequestration of CO2 is a goal. 

4.2 Life Cycle Performance

Modeled single well performance results were used as the basis on which CO2 and brine 

injection, fluid production, and processing activity estimates were based. The amount of CO2

and brine injected were estimated based on the prescribed WAG injection schedule detailed in 

Section 3, and the ratio of recycled to purchased CO2 feeding CO2-EOR operations was 

estimated based on the difference between what was required for injection and what was 

produced for recycle. Based on the volume and pressure of each CO2 feed stream, CO2 boost 

compression energy requirements were estimated as described in Section 4. Similarly, volume 

of brine required for WAG operations and volume of brine produced through WAG operations 

were used as the basis for estimation of brine compression energy requirements both to feed 

WAG operations and to dispose of excess brine through injection well disposal. Liquid and gas 

products were assumed to be separated at a satellite separation facility and liquid products (oil 

and brine) are assumed to be collected from 10 well patterns to be processed at a tank battery. 

Produced gas moves from the separation satellite to a gas-processing facility located adjacent to 

CO2-EOR flood operations where the gas stream undergoes distillative separation to remove HC 

as natural gas and natural gas liquids from CO2. 

The following sections summarize results of a gate-to-gate characterization of tapered water 

alternating gas CO2-EOR operations. Environmental performance parameters considered include 

GHG emissions, criteria air pollutant emissions, water consumption, land use, and net energy 

yield.

4.2.1 Greenhouse Gas Emissions

Estimates of CO2-EOR flood GHG performance were developed based on procedures outlined in 

Sections 3 and 4. Figure 4-3 illustrates the life cycle GHG emissions performance of each CO2-

EOR operational scenario broken out on a per-phase basis. (Phases of operation are here defined 

as site evaluation and characterization, facility construction, CO2-EOR flood operation, site 

closure, and post-closure MVA.) These results are presented on a per-barrel of oil basis. Natural 
115

gas and natural gas liquids coproducts have been accounted for by applying an emissions credit 

for displacement of equivalent product, as described in Section 3.5.3.5. 

Figure 4-3 Summary of Life Cycle Greenhouse Gas Emissions Associated with Each 

Phase of CO2-EOR Activity, Reported in Units of Metric Tonnes of CO2-Equivalent 

Generated per Barrel of Oil Produced

From this figure it can be seen that nearly all (99%) GHG emissions associated with CO2-EOR 

overall activity occur during the operational phase, for all operational scenarios considered. In 

addition, this figure also shows a correlation between the amount of CO2 injected and the 

operational phase GHG emissions. This correlation can be attributed, in large part, to the 

increase in emissions associated with increased gas processing required when larger volumes of 

CO2 are loaded to, and recycled from, the CO2-EOR flood. Figure 4-4 illustrates the total life 

cycle emissions for each operational scenario as compared to total CO2 sequestered through 

CO2-EOR activity, reported per barrel of oil produced. Life cycle emissions include credit taken 

for any natural gas liquids and natural gas coproducts that are not consumed onsite in CO2-EOR 

operations.
116

Figure 4-4 Total Gate-to-Gate Life Cycle Emissions for Each Operational Scenario and 

Total CO2 Sequestered Through CO2-EOR Activity (both reported per barrel of oil 

produced)

From Figure 4-4 we see that net and gross CO2 storage per barrel of oil produced is greatest in 

current “best practices” WAG scenario and the 1.5 HCPV CO2 WAG exhibits the lowest net 

sequestration benefit per barrel of oil produced.

4.2.2 Criteria Air Pollutant Emissions

Similar to GHG emissions, criteria air pollutants associated with the operational phase of CO2-

EOR activity are significantly higher than those of other phases of activity. Results of the 

criteria air pollutant inventory for the Best Practices operational scenario are plotted in Figure 

4-5. The other two operational scenarios show similar trends, with emissions being less in the 

historical (low-CO2 injection), and greater in the 1.5 HCPV CO2 injection scenario. Plots of 

these data are not shown, but results are summarized in tabular form in Appendix H. One 

noteworthy exception is the total particulate matter emissions, which are greatest in the 

construction phase as a result of dust generated from construction, well workover, and related 

equipment mobilization activities. Volatile organic carbon (non-methane) emissions are 

primarily from working, breathing, and venting losses in the tank battery operations, and fugitive 

losses in the satellite separator, tank battery, and gas processing facility.
117

Figure 4-5 Summary of Criteria Air Pollutant Emissions Associated with Each Phase of 

CO2-EOR Activity for the Best Practices Operational Scenario, Reported in Units of Metric 

Tonnes of Pollutant Generated per Barrel of Oil Produced

Relative magnitude of emissions of different criteria air pollutants cannot be directly compared 

because the impact on human health or the natural environment associated with each constituent 

may be significantly different. This type of impact analysis is not within the scope of this study.

4.2.3 Land Use

Only land directly affected by CO2-EOR activity is included in this estimate, including all land 

occupied by CO2-EOR flood patterns plus an estimated 8 hectares (20 acres) of land on which 

the gas processing facility is constructed. Land use associated with upstream activities, such as 

coal mining performed to generate coal that is used to produce electricity delivered to and used 

in CO2-EOR operations, is not included. It should be noted that a large fraction of the land 

below which a CO2-EOR flood is in operation can remain functional for a variety of activities 

such as farming and grazing. As such, the estimates of direct land use reported herein are 

considered to be conservative. Table 4-3 summarizes estimated land in service for EOR flood 

and related processing activities, reported on an acres/bbl of crude oil basis.
118

Table 4-3 Estimated Acres of Land Disturbed by CO2-EOR Activity per Barrel of Oil 

Produced

CO2-EOR Scenario Land Use, 

Acres/bbl Crude

Historical 2.09 x 10-4

Best Practices 1.33 x 10-4

1.5 HCPV CO2 WAG 1.17 x 10-4

Because a specific reservoir within the Permian Basin was not identified for this study, specific 

land type impacted as a result of CO2-EOR activity could not be specified. United States 

Department of Agriculture land resource type designation for the Permian Basin is either Central 

Great Plains or Western Range. 

4.2.4 Water Use

Total water consumption in CO2-EOR operations is estimated to be in the range of 0.2 - 0.25

times the volume of produced oil (on a volume/volume basis). Figure 4-6 shows that water is 

consumed primarily in the operational phase of CO2-EOR activity, with small amounts of water 

consumption associated with workover and well plugging operations in the construction and site 

closure phases, respectively. Nearly all of this water consumption (greater than 95% in all cases) 

is associated with electricity production as purchased from the grid; direct water consumption 

associated with on-site activity at the CO2-EOR facility is very low. 
119

Figure 4-6 Water Consumption Associated with Each Phase of CO2-EOR Activity for Each 

Operational Scenario (barrels of water consumed per barrel of oil produced)

4.2.5 Gross and Net Energy Yield

Energy products of CO2-EOR activity are crude oil, natural gas and natural gas liquids produced 

in the gas processing plant, and higher energy content hydrocarbon gas collected from tank 

battery vapors. A portion of the gross energy products generated through CO2 EOR activity will 

be consumed in the operation of the liquid and gas processing operations, as detailed in Section 

4. Specifically, some or all of the natural gas generated through gas processing and some of the 

hydrocarbon vapor collected by tank battery vapor recovery units will be used for operations 

such as gas compression, on-site electricity (electricity used in the gas- processing facility), and 

fueling of the fire tube boiler used in heater/treater operations. Net energy products are, 

therefore, the difference between gross energy products generated on site, and the amount of 

natural gas products that are consumed in the course of facility operations. Figure 4-7 and 

Figure 4-8 show the gross and net energy product slate, respectively, for the three operational 

scenarios.
120

Figure 4-7 Gross Hydrocarbon Products Generated per 40 Acre Well Pattern in Each CO2-EOR 

Operational Scenario (barrel of oil equivalents per 40 acre pattern)
121

Figure 4-8 Net Hydrocarbon Products Generated per 40-Acre Well Pattern in Each CO2-EOR 

Operational Scenario (barrel of oil equivalents per 40 acre pattern). Bars below zero on the 

ordinate represent natural gas that is purchased to meet energy requirements of CO2-EOR 

operations.

These figures show that the primary energy product is indeed crude oil. A significant fraction 

(approximately 11 percent for all operational scenarios) of gross hydrocarbon product is natural 

gas (by energy content), but, in best practices and high CO2 injection scenarios, this produced 

gas is completely consumed as a feedstock in fluid processing operations and additional natural 

gas is purchased to meet operational demands. Crude oil and natural gas liquids are not 

consumed in CO2-EOR operations. 

Complete accounting of all energy inputs into CO2-EOR operations (not only hydrocarbon fuel 

use as described above) is provided in Figure 4-9. While natural gas (primarily used in gasprocessing plant operations) is the primary energy source, a substantial amount of electricity is 

used for artificial lift of produced fluid, CO2 compression, and brine pressurization for WAG 

injection, and diesel is used in workover rig and well-plugging operations, and to a limited extent 

in the gas-processing plant (backup electricity generation). Energy requirements for the tank 

battery are small as compared to those of gas processing.
122

Figure 4-9 Energy Consumed per Unit of Crude Produced for Three CO2-EOR Operational 

Scenarios

4.3 Sensitivity Analysis

Uncertainty in appropriateness and quality of data, model structure, and defined scenario used in 

inventory development affect confidence in the final results. To improve understanding of the 

potential impact of such uncertainty on the base case emissions estimate, sensitivity of CO2-EOR 

gate-to-gate life cycle GHG emissions performance was considered for a select subset of input 

parameters. The “best practices” CO2-EOR scenario was selected as a base case, with all of the 

modeling assumptions detailed in previous sections of this report. Below is a brief description of 

parameters that were selected for perturbation in the sensitivity analysis. Results of this 

sensitivity analysis are summarized in Figure 4-10.

4.3.1 Parameters Considered in Sensitivity Analysis

Seven model input parameters were selected to evaluate the sensitivity of CO2-equivalent 

emissions per barrel of crude oil. Base case assumptions and sensitivity analysis parameter 

values and assumptions are summarized in Table 4-4, and discussed in greater detail in subsequent 

text. 
123

Table 4-4 Selected Parameters Used in Sensitivity Analysis of Gate-to-Gate Life Cycle GHG 

Emissions Performance of CO2-flood EOR Operations

Low Value Base Case High Value

GWP Factors 1996 IPCC, 100-

year time horizon

2007 IPCC, 100-

year time horizon

2007 IPCC, 100 yeartime horizon

CO2-EOR Operational 

Scenario Historical Best Practices 1.5 HCPV CO2 WAG

Electricity Profile

(kg CO2E)

100% natural gas

(0.72)

ERCOT Mix

(0.76)

100% coal 

(1.07)

Tank Battery Vapor 

Recovery Unit Efficiency

(%)

50 95 100

Phase I, II, IV, and V 

GHG emissions 1 x base case 1 x base case 10 x base case

Displacement Credit for 

Co-products (NG, NGL) 1.5x base case 1x base case None

Fugitive Loss (% of CO2

initially purchased) 0 0 1

4.3.1.1 Global Warming Potential Multiplier

One assumption applied throughout all calculations is that the most recently published 100-year 

time horizon, the 2007 IPCC global warming potential CO2 equivalency factors, are most 

appropriate for estimation of CO2 -equivalent GHG emissions. These factors, taken from the 

fourth IPCC Assessment Report (2007) differ slightly from those reported in the Second and 

Third Assessment Reports (1996 and 2001, respectively) as summarized in Table 4-5. CO2E 

emissions per barrel of oil produced under the “best practices” CO2-EOR scenario was estimated 

using each set of global warming potential factors. Results show little variance in calculated 

CO2 equivalent emissions, with the base case giving the most conservative (highest) result, and

1996 IPCC factors giving the lowest calculated result.

Table 4-5 GHG Constituents Considered Through Sensitivity Analysis Emissions Included in 

Study Boundary and Their 100-year Time Horizon GWP Factors

Constituent

Emitted

Chemical 

Formula

Global Warming Potential

(CO2-Equivalents)

IPCC Second 

Assessment 

Report (1996)

IPCC Third 

Assessment 

Report (2001)

IPCC Fourth 

Assessment 

Report (2007)

a

Carbon Dioxide CO2 1 1 1 

Methane CH4 21 23 25 

Nitrous Oxide N2O 310 296 298 

Sulfur Hexafloride SF6 23,900 22,200 22,800 a

Base case for this study

4.3.1.2 CO2-EOR Scenario 

As is detailed throughout this document, three CO2-EOR scenarios were considered: 

“historical,” “best practices,” and “high CO2 WAG” scenarios. Gate-to-gate life cycle 

performance (GHG emissions per barrel of oil produced basis) of each of these CO2-EOR 

operational scenarios is considered in this sensitivity analysis. Figure 4-10 illustrates that the 

choice of flood scenario selected to characterize CO2-EOR flood performance substantially 
124

affects the calculated emissions associated with this activity. This sensitivity is a function of a 

scenario choice as opposed to model or data uncertainty, and the reported variance is considered 

to be resolved through the identification of “best practices” CO2-flood EOR as the representative 

base scenario. It is reported in this context primarily to convey the relative scale of calculated 

sensitivity to this scenario choice. 

4.3.1.3 Electricity Source

In the base case, electricity used in CO2-EOR operations is characterized as a mix representative 

of the ERCOT Independent System Operator region using data collected from EPA’s eGRID 

2007 data (representative of 2005), as described in Appendix B. Sensitivity of gate-to-gate GHG 

emissions per barrel of oil produced to this parameter was considered by varying the cradle-togate GHG emissions above and below this baseline characterization based on characterizations 

of 100 percent coal-derived electricity and 100 percent natural gas fired electricity, respectively. 

When 100 percent coal-derived electricity is used, CO2 equivalent emissions per barrel of crude 

oil produced increases significantly, while when natural gas-derived electricity is assumed to be 

used, emissions are slightly lower than in the base case. The resulting range in CO2 equivalent 

emissions per barrel of oil produced is believed to be conservatively skewed toward higher 

emissions, since the likelihood that the ERCOT region would resort to 100 percent coal fired 

generation is negligible, and the potential emissions benefit of increased application of wind 

energy in the region is not captured.

4.3.1.4 Vapor Recovery Efficiency

In the base case, it is assumed that vapor is collected from separator vessels, heater/treater 

vessels, and oil and brine storage tanks at a recovery efficiency of 95 percent. To better 

understand the impact that this assumption has on the calculated GHG emissions per barrel of 

crude oil produced, this efficiency factor was varied from 50 percent to 100 percent (with no 

assumed change in VRU electricity demand). At higher vapor recovery efficiency, less CH4 is 

emitted to the atmosphere and additional high BTU hydrocarbon gas is produced (displacing 

equivalent amount of natural gas, on a higher heating value basis); these two trends serve to 

decrease overall GHG emissions per barrel below the base case. Decreasing VRU efficiency 

allows more GHG emissions to the atmosphere and captures less high Btu hydrocarbon gas, as 

compared to the base case with 95 percent VRU efficiency; these two trends result in 

significantly higher CO2 equivalent emissions per barrel of crude oil produced. 

4.3.1.5 Phase I, II, IV and V Emissions

Base case characterizations of site evaluation and characterization, site preparation, post EOR 

site closure, and post-closure MVA include a significant number of modeling choices and 

assumptions that could result in significant underestimation of the contribution of those (nonoperational) phases of activity. To address this concern, the total GHG emissions (kg CO2E 

emissions per barrel of oil produced) were increased by an order of magnitude to determine the 

impact to total emissions from CO2-EOR activity. 

4.3.1.6 Fugitive Loss of Purchased CO2

In the base case, it is assumed that loss of CO2 from the flooding activities approaches zero and 

can be neglected. The influence of this assumption on estimated CO2 equivalent emissions per 
125

barrel of crude oil produced was considered through sensitivity analysis, with the base case of no 

fugitive loss considered as the low bound input value, and a cumulative fugitive loss of 1 percent

(the maximum amount considered to be acceptable to meet the U.S. DOE Sequestration program 

goal of 99 percent storage permanence) as the high input for sensitivity analysis. Based on this 

specified loss rate, increased emissions associated with fugitive loss of CO2 used in CO2-EOR 

operations is relatively small as compared to variance as a function of flooding scenario, vapor 

recovery unit efficiency, or electricity source.

4.3.1.7 Displacement Credit for Natural Gas and Natural Gas Liquid CoProducts

In the gate-to-gate analysis, it is assumed that natural gas and natural gas liquids produced as a 

coproduct of gas processing operations (and CO2-EOR activity, more generally) displace natural 

gas and natural gas liquids, respectively, from the market. As such, a displacement credit is 

assigned for the CO2E emissions of an equivalent amount of those products, based on cradle-togate profile of those energy products. To consider the sensitivity of the gate-to-gate GHG 

emissions per barrel of oil to that modeling decision, the displacement credit is varied from zero 

(no credit given for energy co-products) to 1.5 times the credit assigned based on cradle-to-gate 

profile of those energy products in the base case. 

4.3.2 Discussion of Sensitivity Analysis Results

A Tornado plot shows the results of the sensitivity analysis (Figure 4-10), indicating that choice in 

CO2-EOR scenario leads to the largest variance in resulting GHG emissions per barrel of oil 

produced—a range of variance of 62 percent around the baseline “best practices” result. This 

variance is reflective of decisions by reservoir engineers and operators on how to run CO2-EOR 

operations, in contrast to a bounding analysis of data or model uncertainty. As such, variance 

resulting from scenario choice should be considered differently than that reported for other 

parameters. Vapor recovery efficiency is the second largest contributor to variance of the input 

parameters considered, with a range variance of 13% given the sensitivity range of 50 to 100 

percent vapor recovery efficiency. CO2 equivalent emissions per barrel of oil produced were 

also sensitive to the source of electricity used in CO2-EOR operations, with variance of eight 

percent exhibited by replacing the ERCOT grid mix assumed in the base case with coal- and 

natural gas-derived electricity (higher and lower upstream GHG emissions, respectively). 

Assumption of 100 percent coal-derived electricity is considered to be a conservative choice for 

sensitivity analysis, since it is unlikely that all electricity in the ERCOT region would be

provided from higher GHG emitting coal pathways. To consider the potential impact of data 

deficiencies and limitations in characterization of non-operational activities, the impact of 

varying all non-operational emissions to a value 10 times as great as the baseline case was 

considered. This resulted in only a six percent variance in total GHG emissions estimate, 

emphasizing the observation made previously that operational emissions dominate the life cycle 

footprint of CO2-EOR. Potential fugitive loss of purchased CO2 could also increase CO2

equivalent emissions of CO2-EOR activity, but a one percent leakage of purchased CO2

corresponding with U.S. DOE minimum geologic sequestration storage permanence of 99

percent results in only a 3 percent increase from base case emissions. Displacement credit 

choice for natural gas and natural gas liquids co-products and choice in 100-year horizon IPCC 

global warming potential CO2 equivalent values were found to contribute little to CO2-EOR 

activity GHG emissions (three and 0.4 percent, respectively).
126

Figure 4-10 Tornado Plot Summarizing Impact of Varying Select Model Input Parameter 

Values Away from Base Case Assumptions
127

5.0 Summary of Findings

CO2-EOR is available technological option to produce incremental oil from reservoirs depleted 

through primary and water flood secondary oil recovery, while concomitantly geologically 

storing injected CO2. Stream-tube models were carried out to estimate flood performance for a

set of three CO2-flood operational scenarios. These model results served as the foundation on 

which an inventory of ”gate-to-gate” CO2-EOR activity and analysis of environmental life cycle 

performance were developed. The assessments considered GHG and criteria air pollutant 

emissions, water and land use, and energy performance for five phases of CO2-EOR facility 

activity: site characterization; site preparation; CO2-EOR flood operation; well abandonment;

and post-closure monitoring, verification, and accounting.

Significant findings of this effort include:

• Stream-tube modeling of low, moderate, and high CO2 injection volume scenarios revealed 

that both hydrocarbon production and CO2 storage increase with increasing volume of 

CO2 injection.

• Higher volumes of CO2 injection correspond to longer flood durations and recycle of larger 

volumes of total gas that, in the scenarios considered, require energy intensive processing 

and compression before reinjection. 

• The majority of incremental oil production and CO2 geologic retention is accomplished 

early in the injection, and longer duration, higher CO2 volume injection corresponds with 

lower volume of oil produced and CO2 sequestered per volume of CO2 injected.

• Between 22 and 40 percent of injected CO2 is retained cumulatively over the life of each

well pattern. CO2 that is not retained in one pattern is produced and re-injected in the same 

or adjacent patterns such that essentially all CO2 will eventually be geologically stored.

• For every barrel of crude oil extracted through WAG CO2-EOR, energy feedstocks 

equivalent to between 13 and 27 percent of the energy content of that oil are consumed.

• Greater than 99 percent of CO2-EOR energy demand is associated with the operational 

phase, and gas processing is responsible for between 66 and 73 percent of operational 

phase energy consumption. 

• Greenhouse gas emissions from “gate-to-gate” CO2-EOR activity are between 51 and 95 kg 

CO2e/bbl crude produced for CO2 injection scenarios considered.

• Gross storage values range between 195 and 228 kg/bbl oil produced.

• Net GHG storage performance (geologic storage minus GHG emissions) range from 116

kg CO2E/bbl crude oil produced for the highest CO2 injection scenario, to 157 kg CO2E/bbl 

crude oil for the best practices CO2-EOR scenario. 

• Brine production in excess of that which is re-injected through the water-alternating-gas 

injection ranges from about 1.5 barrels of brine per barrel of oil produced to about 1 barrel 

of brine per barrel of oil. 
128

Therefore, while oil recovery and CO2 storage potential may increase on an absolute basis with 

increasing CO2 injection, these benefits are weighted heavily to early years of flooding and 

earlier volumes of CO2 injection. Longer, higher cumulative volume CO2 injections effectively 

dilute benefits over longer periods of injection and erode energy production and CO2 storage

through higher parasitic energy load and increased emissions associated with processing of high 

volumes of produced gas. Considered together, stream tube model results and related life cycle 

performance data suggest that, of the three scenarios considered, current “best practices” WAG 

CO2-EOR scenario performs best. High-volume CO2 injection is not favorable from an 

environmental and energy performance standpoint, but consideration of alternative “next 

generation” technologies and practices is warranted. 

5.1 Next Steps

The work detailed herein develops a framework for detailed process-based characterization of 

activities associated with CO2-EOR. The three operational scenarios considered are intended to 

represent performance of technology as it was performed in its infancy, as it is performed in 

present application, and as it might be performed in one possible future scenario. This set of 

scenario choices is by no means exhaustive of alternatives that might reasonably be employed. 

Furthermore, consideration of gate-to-gate activities associated with CO2-flood EOR does not 

provide a complete picture of the technology’s environmental performance when integrated into 

a full LCA. Following is a brief consideration of future work that would help to advance 

understanding of CO2-EOR activity and its performance within a larger cradle-to-grave life cycle 

of CO2-generating energy systems.

5.1.1 Gate-to-Gate Analysis of Alternative CO2-EOR Scenarios

There are a number of alternative CO2-flood EOR scenarios that would be of value to consider to 

facilitate comparison between current best practices as described herein, and other viable CO2-

EOR schemes. Several conceivable scenarios fall within the general framework of the current 

CO2-flood EOR paradigm and would be relatively straightforward to characterize, including 

considering the following: applying CO2-EOR technology in reservoirs other than the Permian 

Basin, using alternative gas-processing technologies, assessing cases with no hydrocarbon gas 

separation (straight recycle), using large-scale electricity to power CO2-EOR operations, 

applying CO2 re-pressuring (“soak”) or CO2EOR WAG injection before water flood is applied, 

implementing large-scale infill well placement to enhance tertiary flood oil production, and 

considering short CO2 injection periods to maximize CO2 storage per unit energy input as 

opposed to maximizing oil production.

There are also scenarios that would require more-aggressive modification or reworking of the 

model described in this report.. These scenarios would characterize schemes that serve as 

transitions between straight “business-as-usual” CO2-flood EOR activity and dedicated brine 

sequestration, such as is being considered in flooding residual oil zones and/or deep brine 

aquifers. These alternative CO2-EOR technologies include:

• CO2-flood stimulation of residual oil zones - naturally water-flooded residual resources that 

are believed to underlie primary oil production zones in extensive “freeway” aquifers. 

These 
129

• Stacked storage of CO2 – a scenario that allows for CO2-flood EOR with storage in 

dedicated storage in adjacent or underlying brine aquifers. This technology alternative has 

the potential to address issues of intermittency in CO2 demand associated with traditional 

CO2-EOR operations.

• Consideration of the application of directional drilling technology to stimulate additional 

oil production

5.1.2 Cradle-to-Grave Life Cycle Analyses 

Gate-to-gate characterization of CO2-EOR described in this work will be incorporated with life 

cycle inventories of other primary activities to develop full cradle-to-grave life cycle analyses of 

energy production pathways of interest. For example, cradle-to-grave analyses of electricity 

production and liquid fuel production recently published by NETL include scenarios with carbon 

capture and sequestration. These studies employ simplified characterizations of dedicated brine 

sequestration as the CO2 sequestration technology. Additional scenarios could be considered in 

which these energy product pathways incorporate CO2-flood EOR in place of brine sequestration 

as a sink for captured CO2. In addition, there may be interest in coupling CO2-EOR not with 

anthropogenic CO2, but rather with CO2 from natural sources—the primary source of CO2 used 

today for CO2-flood EOR. These natural geologic CO2 sources could also be considered as 

intermediate storage locations for anthropogenic CO2 to buffer intermittency of supply and 

demand in anthropogenic CO2 capture/geologic sequestration scenarios. It should be noted that 

incorporating CO2-EOR gate-to-gate activity into larger cradle-to-grave pathways will create a 

source of uncertainty associated with methods of allocation. Fortunately, there exists a 

substantial body of literature considering this topic in some detail.

5.1.3 Other Life Cycle Assessment Considerations

The present study is limited to considering only the environmental performance of CO2-EOR 

activity, including GHG emissions, criteria pollutant emissions, water use, land use, and energy 

performance. In addition to consideration of these process parameters, it would also be of value 

to integrate life cycle cost analysis of CO2-EOR. Also, the life cycle performance of CO2-EOR 

has been characterized based on single point data for a number of parameters that would be 

better characterized stochastically. Future work might consider establishing probability 

distributions of key model parameters for application in uncertainty analysis of the life cycle 

model. Such an effort would be facilitated by collaborative involvement and peer review by 

individuals and institutions with expertise in the oil and gas industry and other related fields. 
130

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DRAFT A-1

Appendix A: CO2 Prophet CO2-EOR Screening Model Definition 

of Relative Permeability Parameters

Relative Permeability of Water

Expw

Swir Sorw

Sw Swir Krw Kwro 



 





− −

− = 1

where:

Krw is the relative permeability of water

Sw is the water saturation

Expw is the water equation exponent The default is 2.0

Swir is the irreducible water saturation. The default is 0.2 which is also the same as Swc

Sorw is the residual oil to waterflood. The default is 0.37.

Kwro is the endpoint (maximum) relative permeability of water at the residual oil 

saturation. The default is 0.30.

Relative Permeability of Oil

Expow

Swc Sorw

Sw Sorw Krow Krocw 



 





− −

− − = 11

where:

Krow is the relative permeability of oil

Sw is the water saturation

Expow is the oil equation exponent. The default is 2.0.

Swc is the connate water saturation. The default is 0.2.

Sorw is the residual oil to waterflood. The default is 0.37.

Krocw is the endpoint (maximum) relative permeability of oil at the irreducible water 

saturation. The default is 0.40.

Relative Permeability of Gas

Expg

Swc Sgr

Sg Sgr Krg Krgcw 















− −

− = 1

where: 

Krg is the relative permeability of gas 

Sg is the gas saturation

Expg is the gas equation exponent. The default is 2.0. 

Swc is the connate water saturation. The default is 0.2

Sgr is the residual gas saturation to an oilflood. The default is 0.37 which is the value for 

Sorw

Krgcw is the endpoint (maximum) relative permeability of gas at the connate water 

saturation. The default is 0.40.
DRAFT A-2

Relative Permeability of Oil

Expog

Swc Sorg

Swc Sorg Sg Krog Krocw 















− −

− − − = 11

where: 

Krog is the relative permeability of oil

Sg is the gas saturation

Expog is the oil equation exponent. The default is 2.0.

Swc is the connate water saturation. The default is 2.0.

Sorg is the residual oil to a gas flood. The default is 0.37 which is also the value for 

Sorw

Krocw is the endpoint (maximum) relative permeability of oil at irreducible water 

saturation. The default is 0.4.

Relative Permeability of Solvent (CO2)

Exps

Swir Ssr Sorm

Sg Ssr 



 





− − −

−

1

Krs = Krsmax

where:

Krs is the relative permeability of solvent

Sg is the gas (i.e., solvent) saturation

Exps is the solvent equation exponent. The default value is Expg which is 2.0.

Swir is the irreducible water saturation. The default is Swc which is 0.2.

Ssr is the residual gas (i.e., solvent) saturation. The default value is Sgr which is 0.37.

Sorm is the residual oil saturation to solvent. The default value is 0.001.

Krsmax is the endpoint (maximum) relative permeability of solvent at the irreducible 

water saturation. The default value is Krogcw which is 0.4.
DRAFT A-3

Table A-1: CO2 Prophet model parameters and default values used in CO2 Prophet model 

to characterize relative permeability of fluids that interact in a CO2-EOR miscible flood. 

These values are used in all CO2-EOR scenarios developed herein.

Parameter Description CO2 Prophet

Variable

CO2

Prophet 

Default

Units

Residual oil saturation to water SORW 0.32 fraction (0-1)

Residual oil saturation to gas SORG 0.32 fraction (0-1)

Residual oil saturation to miscible gas 

solvent flood SORM 0.05 fraction (0-1)

Residual gas saturation SGR 0.32 fraction (0-1)

Residual solvent (CO2) saturation SSR 0.32 fraction (0-1)

Connate water saturation SWC 0.2 fraction (0-1)

Irreducible water saturation as water 

saturation is decreasing SWIR 0.2 fraction (0-1)

Relative permeability of oil at connate 

water saturation KROCW 0.4 fraction (0-1)

Relative permeability of water at 

residual oil - no gas saturation KWRO 0.3 fraction (0-1)

End point relative permeability of 

solvent at a solvent saturation of 1 -

SWIR - SORM

KRSMAX 0.4 fraction (0-1)

Relative permeability of Gas at connate 

water saturation KRGCW 0.4 fraction (0-1)

Exponent for oil curve from water-oil 

relative permeabilities EXPOW 2 unitless

Exponent for water curve from water-oil 

relative permeabilities EXPW 2 unitless

Exponent for solvent from relative 

permeability curve

EXPS 2 unitless

Exponent for gas curve from gas-oil 

relative permeability EXPG 2 unitless

Exponent for oil curve from gas-oil 

relative permeabilities EXPOG 2 unitless

Options for miscible oleic phase 

permeability KRMSEL 2 -

Degree of mixing parameter - ranges 

from 0.0 to 1.0 W 0.666 fraction (0-1)
DRAFT B-1

Appendix B: Cradle-to-Gate GHG Emissions Inventory for 

Electric Power from the ERCOT ISO Region Grid Mix

Certain emissions from electricity generating facilities are tracked by EPA (EPA 2007a) and are

publically available in the Emissions & Generation Resource Integrated Database (eGRID).

While this database includes comprehensive coverage of CO2 emissions from these generating

facilities, it does not address other GHG constituents such as N2O and CH4 in its inventory.8

The emissions data within e-GRID only includes that attributable to operations and does not

represent construction or upstream emissions. Therefore, GaBi 4 modeling data were modified

to generate a profile more inclusive of upstream and construction emissions not represented

within eGRID. An ERCOT ISO region grid mix was generated where the individual electricity 

source profiles (solar, wind, hydro, etc.) were aggregated into a mix consistent with the 2005

U.S. electricity source mix. In this mix, a small fraction of electricity generated from “other 

fossil” feedstock is assumed to be adequately represented by an oil-fired generation pathway. 

Figure B-1 shows the source mix as a percentage of total U.S. electricity generation.

Figure B-1: Year 2005 Electricity Sources for the Average U.S. Grid Mix

The cradle-to-gate GHG emissions profile estimated using this assumed electricity grid mix in 

the ERCOT ISO region is reported in Table B-1.
DRAFT B-2

Table B-1. Estimated cradle-to-gate electricity grid mix emissions from 2005 Electric Reliability 

Council of Texas Independent System Operator.

Pollutant

Output 

Emission 

Rates

Units

CO2 0.736 kg/MWh

SO2 2.84 x 10-3 kg/MWh

NOx 1.26 x 10-3 kg/MWh

Dust (unspecified) 5.34 x 10-5 kg/MWh

Non-Methane VOCs 1.02 x 10-4 kg/MWh

Lead (II) 2.54 x 10-8 kg/MWh

CH4 9.76 x 10-4 kg/MWh

N2O 9.46 x 10-6 kg/MWh

SF6 8.95 x 10-13 kg/MWh
DRAFT C-1

Appendix C: Raw Output from CO2 Prophet Model for Historical, 

Best Practices, and 1.5 HCPV CO2 WAG CO2-EOR 

Scenarios.

Historical CO2-EOR Scenario

"Historical" Tapered WAG, 0.4 HCPV Permian 

 ************** RESERVOIR DATA **************

 PRESSURE PATTERN

 TEMP OPERATING MMP POROSITY THICKNESS AREA

 F PSIA PSIA FRACTION FEET ACRES

 123.0 2368.0 1523.0 0.1100 76.0 40.00

 INITITAL HC

 FLOOD START SATURATIONS PORE VOLUME DYKSTRA-

 OIL WATER GAS HCPV - OOIP PARSONS HORIZONTAL

 SOINIT SWINIT SGINIT MMRB FACTOR LAYERS

 0.3200 0.6800 0.0000 2.0755 0.7300 5

 *************** FLUID DATA ***************

 STOCK SOLUTION SPECIFIC FORMATION VOLUME FACTOR

 TANK OIL GOR GRAVITY OIL WATER SOLVENT

 GRAVITY (Rs) SG Bo Bw Bco2

 API ft3/STB (Air=1.0) RB/STB RB/STB RB/MMSCF

 36.0 805.0 0.6500 1.2000 1.0119 459.557

 FLUID DENSITIES AT RES T&P FLUID VISCOSITIES AT RES T&P WATER

 RES OIL WATER SOLVENT OIL WATER SOLVENT SALINITY

 GMS/CC GMS/CC GMS/CC cp cp cp ppm

 0.7980 1.0550 0.7248 1.760 0.720 0.068 96000.

 ********** RELATIVE PERMEABILITY PARAMETERS **********

 WTR FLD GAS FLD MISC FLD

 SORW SORG SORM

 0.3200 0.3200 0.0500

 SGR SSR SWC SWIR

 0.3200 0.3200 0.2000 0.2000

 KROCW KWRO KRSMAX KRGCW

 0.4000 0.3000 0.4000 0.4000
DRAFT C-2

 EXPOW EXPW EXPS EXPG EXPOG

 2.000 2.000 2.000 2.000 2.000

 MIX PARAMETER

 OMEGA MISCIBLE RELATIVE PERMEABILITY

 0.6660 EQUAL TO Krow

 *********** INJECTION/PRODUCTION PARAMETERS *********

 OUTPUT

 INJECTION WAG EXPRESSED PATTERN INJECTION TIME STEPS

 SEQUENCES AS TIME OR VOL TYPE WELLS YEARS

 4 V 5S 1 1.000

 AVGE (TOTAL WELLS)

 CUM. INCRE CUM. SEQUENCE INJECTION FLUID

 INJECT TIME TIME RATE FRACTIONAL CONTENT WAG

 HCPV YEARS YEARS RB/D WATER SOLVENT WTR:GAS

 0.2000 1.994 1.994 569.86 0.0000 1.0000 .0000E+00

 0.4000 1.996 3.991 569.28 0.5000 0.5000 .1000E+01

 0.7000 2.996 6.986 569.08 0.6667 0.3333 .2000E+01

 1.7000 9.992 16.979 568.70 1.0000 0.0000 .1000E+07

 TOTAL PATTERN

 INCRE CUM. AVGE RATE FOR PATTERN SURFACE RATES

 TIME TIME ****** SEQUENTIAL ****** WATER SOLVENT

 YEARS YEARS RB/D HCPV/D HCPV/YR STB/D MMSCF/D

 1.994 1.994 569.86 0.27456E-03 0.10028 0.0 1.24

 1.996 3.991 569.28 0.27428E-03 0.10018 562.0 1.24

 2.996 6.986 569.08 0.27418E-03 0.10015 562.0 1.24

 9.992 16.979 568.70 0.27400E-03 0.10008 562.0 0.00

   INJECTION ** ** INJECTION   INJECTION ** ** INJECTION   

INJECTION

 SUMMARY OF FLUID INJECTION

 CUMULATIVE DATA

 TIME ** *** HCPV INPUT ***** WATER SOLVENT

 YRS TOTAL WATER SOLVENT MSTB MMSCF

 0.000 0.0000 0.0000 0.0000 0.0 0.0

 1.000 0.1003 0.0000 0.1003 0.0 452.9

 1.994 0.2000 0.0000 0.2000 0.0 903.3

 2.000 0.2006 0.0003 0.2003 0.6 904.6
DRAFT C-3

 3.000 0.3007 0.0504 0.2504 103.3 1130.8

 3.991 0.4000 0.1000 0.3000 205.1 1354.9

 4.000 0.4009 0.1006 0.3003 206.4 1356.3

 5.000 0.5011 0.1674 0.3337 343.3 1507.1

 6.000 0.6012 0.2341 0.3671 480.3 1657.8

 6.986 0.7000 0.3000 0.4000 615.3 1806.6

 7.000 0.7014 0.3014 0.4000 618.1 1806.6

 8.000 0.8014 0.4014 0.4000 823.4 1806.6

 9.000 0.9015 0.5015 0.4000 1028.7 1806.6

 10.000 1.0016 0.6016 0.4000 1234.0 1806.6

 11.000 1.1017 0.7017 0.4000 1439.2 1806.6

 12.000 1.2017 0.8017 0.4000 1644.5 1806.6

 13.000 1.3018 0.9018 0.4000 1849.8 1806.6

 14.000 1.4019 1.0019 0.4000 2055.1 1806.6

 15.000 1.5020 1.1020 0.4000 2260.3 1806.6

 16.000 1.6021 1.2021 0.4000 2465.6 1806.6

 16.979 1.7000 1.3000 0.4000 2666.5 1806.6

 *** PRODUCTION ***** PRODUCTION ***** PRODUCTION ***** PRODUCTION ***

 SUMMARY OF FLUID PRODUCTION

 CUMULATIVE DATA

 ********** HCPV OUTPUT ********** OIL RECOVERY

 TIME HYDROCARBON PORE VOLUMES OUTPUT RECOVERY % OF INJECTANT

 YRS TOTAL OIL WATER SOLVENT %OOIP WATER SOLVENT

 0.000 0.0000 0.0000 0.0000 0.0000 0.00 0.00 0.00

 1.000 0.1003 0.0000 0.1002 0.0000 0.00 0.00 0.05

 1.994 0.2000 0.0147 0.1579 0.0274 1.47 0.00 13.71

 2.000 0.2006 0.0148 0.1581 0.0277 1.48 ****** 13.83

 3.000 0.3007 0.0299 0.1989 0.0719 2.99 394.91 28.73

 3.991 0.4000 0.0440 0.2450 0.1110 4.40 244.99 37.01

 4.000 0.4009 0.0441 0.2455 0.1113 4.41 243.96 37.07

 5.000 0.5011 0.0564 0.3016 0.1431 5.64 180.17 42.89

 6.000 0.6012 0.0661 0.3668 0.1682 6.61 156.67 45.84

 6.986 0.7000 0.0752 0.4317 0.1930 7.52 143.91 48.26

 7.000 0.7014 0.0754 0.4326 0.1934 7.54 143.55 48.35

 8.000 0.8014 0.0839 0.5037 0.2138 8.39 125.47 53.46

 9.000 0.9015 0.0898 0.5898 0.2219 8.98 117.60 55.48

 10.000 1.0016 0.0943 0.6803 0.2269 9.43 113.09 56.73

 11.000 1.1017 0.0979 0.7733 0.2304 9.79 110.22 57.61

 12.000 1.2017 0.1008 0.8679 0.2330 10.08 108.25 58.25

 13.000 1.3018 0.1035 0.9631 0.2352 10.35 106.79 58.81

 14.000 1.4019 0.1058 1.0592 0.2369 10.58 105.72 59.22

 15.000 1.5020 0.1077 1.1560 0.2383 10.77 104.90 59.57

 16.000 1.6021 0.1093 1.2534 0.2393 10.93 104.27 59.83

 16.979 1.7000 0.1106 1.3492 0.2402 11.06 103.78 60.05

 CUMULATIVE
DRAFT C-4

 ER OIL OIL WATER HC GAS SOLVENT GOR WOR

 YRS %OOIP MSTB MSTB MMSCF MMSCF MSCF/STB STB/STB

 0.000 0.00 0.0 0.0 0.0 0.0 0.000E+00 0.000E+00

 1.000 0.00 0.1 205.5 0.1 0.2 0.383E+01 0.287E+04

 1.994 1.47 25.4 323.9 20.4 123.9 0.569E+01 0.128E+02

 2.000 1.48 25.6 324.3 20.6 125.1 0.570E+01 0.127E+02

 3.000 2.99 51.7 408.0 41.6 324.9 0.709E+01 0.790E+01

 3.991 4.40 76.1 502.5 61.3 501.4 0.739E+01 0.660E+01

 4.000 4.41 76.3 503.5 61.4 502.8 0.739E+01 0.660E+01

 5.000 5.64 97.5 618.6 78.5 646.4 0.744E+01 0.634E+01

 6.000 6.61 114.4 752.5 92.1 759.9 0.745E+01 0.658E+01

 6.986 7.52 130.1 885.5 104.8 871.8 0.750E+01 0.680E+01

 7.000 7.54 130.4 887.3 104.9 873.5 0.751E+01 0.681E+01

 8.000 8.39 145.2 1033.1 116.8 965.8 0.746E+01 0.712E+01

 9.000 8.98 155.3 1209.8 125.0 1002.3 0.726E+01 0.779E+01

 10.000 9.43 163.1 1395.5 131.3 1024.9 0.709E+01 0.855E+01

 11.000 9.79 169.3 1586.3 136.3 1040.7 0.695E+01 0.937E+01

 12.000 10.08 174.4 1780.2 140.4 1052.4 0.684E+01 0.102E+02

 13.000 10.35 179.1 1975.4 144.2 1062.4 0.674E+01 0.110E+02

 14.000 10.58 183.0 2172.6 147.3 1069.9 0.665E+01 0.119E+02

 15.000 10.77 186.3 2371.1 150.0 1076.1 0.658E+01 0.127E+02

 16.000 10.93 189.1 2571.0 152.2 1080.9 0.652E+01 0.136E+02

 16.979 11.06 191.4 2767.3 154.0 1084.9 0.647E+01 0.145E+02

 ***********************************************

 SUMMARY OF FLUID PRODUCTION

 INCREMENTAL DATA

 ********** HCPV OUTPUT ********** OIL

 TIME HYDROCARBON PORE VOLUMES OUTPUT RECOVERY

 YRS TOTAL OIL WATER SOLVENT %OOIP

 0.000 0.0000 0.0000 0.0000 0.0000 0.00

 1.000 0.1003 0.0000 0.1002 0.0000 0.00

 1.994 0.0997 0.0146 0.0577 0.0274 1.46

 2.000 0.0006 0.0001 0.0002 0.0003 0.01

 3.000 0.1002 0.0151 0.0408 0.0442 1.51

 3.991 0.0993 0.0141 0.0461 0.0391 1.41

 4.000 0.0009 0.0001 0.0005 0.0003 0.01

 5.000 0.1001 0.0122 0.0561 0.0318 1.22

 6.000 0.1001 0.0098 0.0653 0.0251 0.98

 6.986 0.0988 0.0091 0.0649 0.0248 0.91

 7.000 0.0014 0.0001 0.0009 0.0004 0.01

 8.000 0.1001 0.0086 0.0711 0.0204 0.86

 9.000 0.1001 0.0059 0.0861 0.0081 0.59

 10.000 0.1001 0.0045 0.0905 0.0050 0.45

 11.000 0.1001 0.0036 0.0930 0.0035 0.36

 12.000 0.1001 0.0029 0.0946 0.0026 0.29

13.000 0.1001 0.0027 0.0952 0.0022 0.27

 14.000 0.1001 0.0022 0.0962 0.0017 0.22

 15.000 0.1001 0.0019 0.0968 0.0014 0.19

 16.000 0.1001 0.0016 0.0974 0.0011 0.16
DRAFT C-5

 16.979 0.0979 0.0013 0.0957 0.0009 0.13

 INCREMENTAL

 ER OIL OIL WATER HC GAS SOLVENT GOR WOR

 YRS %OOIP MSTB MSTB MMSCF MMSCF MSCF/STB STB/STB

 0.000 0.00 0.0 0.0 0.0 0.0 0.000E+00 0.000E+00

 1.000 0.00 0.1 205.5 0.1 0.2 0.383E+01 0.287E+04

 1.994 1.46 25.3 118.4 20.4 123.7 0.569E+01 0.468E+01

 2.000 0.01 0.2 0.4 0.1 1.2 0.757E+01 0.205E+01

 3.000 1.51 26.1 83.8 21.0 199.8 0.846E+01 0.321E+01

 3.991 1.41 24.4 94.5 19.7 176.5 0.803E+01 0.387E+01

 4.000 0.01 0.2 1.0 0.2 1.4 0.744E+01 0.450E+01

 5.000 1.22 21.2 115.1 17.1 143.6 0.758E+01 0.543E+01

 6.000 0.98 16.9 133.9 13.6 113.4 0.753E+01 0.794E+01

 6.986 0.91 15.8 133.1 12.7 112.0 0.790E+01 0.843E+01

 7.000 0.01 0.2 1.8 0.2 1.7 0.861E+01 0.846E+01

 8.000 0.86 14.8 145.8 11.9 92.3 0.704E+01 0.985E+01

 9.000 0.59 10.2 176.6 8.2 36.5 0.440E+01 0.174E+02

 10.000 0.45 7.8 185.7 6.3 22.6 0.370E+01 0.237E+02

 11.000 0.36 6.2 190.8 5.0 15.7 0.335E+01 0.309E+02

 12.000 0.29 5.1 193.9 4.1 11.7 0.311E+01 0.382E+02

 13.000 0.27 4.7 195.2 3.8 10.0 0.293E+01 0.416E+02

 14.000 0.22 3.9 197.3 3.1 7.6 0.276E+01 0.510E+02

 15.000 0.19 3.3 198.5 2.7 6.2 0.265E+01 0.594E+02

 16.000 0.16 2.8 199.8 2.2 4.8 0.257E+01 0.726E+02

 16.979 0.13 2.3 196.4 1.9 3.9 0.252E+01 0.851E+02
DRAFT C-6

Best-Practices CO2-EOR Scenario

 "State-of-art" Tapered WAG, 1.0 HCPV Permian mean re

 ************** RESERVOIR DATA **************

 PRESSURE PATTERN

 TEMP OPERATING MMP POROSITY THICKNESS AREA

 F PSIA PSIA FRACTION FEET ACRES

 123.0 2368.0 1523.0 0.1100 76.0 40.00

 INITITAL HC

 FLOOD START SATURATIONS PORE VOLUME DYKSTRA-

 OIL WATER GAS HCPV - OOIP PARSONS HORIZONTAL

 SOINIT SWINIT SGINIT MMRB FACTOR LAYERS

 0.3200 0.6800 0.0000 2.0755 0.7300 5

 *************** FLUID DATA ***************

 STOCK SOLUTION SPECIFIC FORMATION VOLUME FACTOR

 TANK OIL GOR GRAVITY OIL WATER SOLVENT

 GRAVITY (Rs) SG Bo Bw Bco2

 API ft3/STB (Air=1.0) RB/STB RB/STB RB/MMSCF

 36.0 805.0 0.6500 1.2000 1.0119 459.557

 FLUID DENSITIES AT RES T&P FLUID VISCOSITIES AT RES T&P WATER

 RES OIL WATER SOLVENT OIL WATER SOLVENT SALINITY

 GMS/CC GMS/CC GMS/CC cp cp cp ppm

 0.7980 1.0550 0.7248 1.760 0.720 0.068 96000.

 ********** RELATIVE PERMEABILITY PARAMETERS **********

 WTR FLD GAS FLD MISC FLD

 SORW SORG SORM

 0.3200 0.3200 0.0500

 SGR SSR SWC SWIR

 0.3200 0.3200 0.2000 0.2000

 KROCW KWRO KRSMAX KRGCW

 0.4000 0.3000 0.4000 0.4000

 EXPOW EXPW EXPS EXPG EXPOG

 2.000 2.000 2.000 2.000 2.000

 MIX PARAMETER

 OMEGA MISCIBLE RELATIVE PERMEABILITY

 0.6660 EQUAL TO Krow
DRAFT C-7

 *********** INJECTION/PRODUCTION PARAMETERS *********

 OUTPUT

 INJECTION WAG EXPRESSED PATTERN INJECTION TIME STEPS

 SEQUENCES AS TIME OR VOL TYPE WELLS YEARS

 4 V 5S 1 1.000

 AVGE (TOTAL WELLS)

 CUM. INCRE CUM. SEQUENCE INJECTION FLUID

 INJECT TIME TIME RATE FRACTIONAL CONTENT WAG

 HCPV YEARS YEARS RB/D WATER SOLVENT WTR:GAS

 0.2500 2.493 2.493 569.86 0.0000 1.0000 .0000E+00

 0.7500 4.991 7.484 569.28 0.5000 0.5000 .1000E+01

 1.5000 7.489 14.973 569.08 0.6667 0.3333 .2000E+01

 2.5000 9.987 24.960 568.99 0.7500 0.2500 .3000E+01

 TOTAL PATTERN

 INCRE CUM. AVGE RATE FOR PATTERN SURFACE RATES

 TIME TIME ****** SEQUENTIAL ****** WATER SOLVENT

 YEARS YEARS RB/D HCPV/D HCPV/YR STB/D MMSCF/D

 2.493 2.493 569.86 0.27456E-03 0.10028 0.0 1.24

 4.991 7.484 569.28 0.27428E-03 0.10018 562.0 1.24

 7.489 14.973 569.08 0.27418E-03 0.10015 562.0 1.24

 9.987 24.960 568.99 0.27414E-03 0.10013 562.0 1.24

   INJECTION ** ** INJECTION   INJECTION ** ** INJECTION   

INJECTION

 SUMMARY OF FLUID INJECTION

 CUMULATIVE DATA

 TIME ** *** HCPV INPUT ***** WATER SOLVENT

 YRS TOTAL WATER SOLVENT MSTB MMSCF

 0.000 0.0000 0.0000 0.0000 0.0 0.0

 1.000 0.1003 0.0000 0.1003 0.0 452.9

 2.000 0.2006 0.0000 0.2006 0.0 905.8

 2.493 0.2500 0.0000 0.2500 0.0 1129.1

 3.000 0.3008 0.0254 0.2754 52.1 1243.8

 4.000 0.4010 0.0755 0.3255 154.8 1470.0

 5.000 0.5012 0.1256 0.3756 257.6 1696.3

 6.000 0.6013 0.1757 0.4257 360.3 1922.5

 7.000 0.7015 0.2258 0.4758 463.1 2148.7

 7.484 0.7500 0.2500 0.5000 512.8 2258.2

 8.000 0.8017 0.2845 0.5172 583.5 2336.0

 9.000 0.9018 0.3512 0.5506 720.4 2486.8
DRAFT C-8

 10.000 1.0020 0.4180 0.5840 857.3 2637.5

 11.000 1.1021 0.4847 0.6174 994.3 2788.3

 12.000 1.2023 0.5515 0.6508 1131.2 2939.1

 13.000 1.3024 0.6183 0.6841 1268.2 3089.8

 14.000 1.4026 0.6850 0.7175 1405.1 3240.6

 14.973 1.5000 0.7500 0.7500 1538.4 3387.3

 15.000 1.5027 0.7520 0.7507 1542.5 3390.4

 16.000 1.6028 0.8271 0.7757 1696.6 3503.4

 17.000 1.7030 0.9022 0.8007 1850.6 3616.5

 18.000 1.8031 0.9773 0.8258 2004.6 3729.5

 19.000 1.9032 1.0524 0.8508 2158.7 3842.6

 20.000 2.0033 1.1275 0.8758 2312.7 3955.6

 21.000 2.1035 1.2026 0.9009 2466.7 4068.7

 22.000 2.2036 1.2777 0.9259 2620.8 4181.7

 23.000 2.3037 1.3528 0.9509 2774.8 4294.8

 24.000 2.4039 1.4279 0.9760 2928.8 4407.9

 24.960 2.5000 1.5000 1.0000 3076.7 4516.4

 *** PRODUCTION ***** PRODUCTION ***** PRODUCTION ***** PRODUCTION ***

 SUMMARY OF FLUID PRODUCTION

 CUMULATIVE DATA

 ********** HCPV OUTPUT ********** OIL RECOVERY

 TIME HYDROCARBON PORE VOLUMES OUTPUT RECOVERY % OF INJECTANT

 YRS TOTAL OIL WATER SOLVENT %OOIP WATER SOLVENT

 0.000 0.0000 0.0000 0.0000 0.0000 0.00 0.00 0.00

 1.000 0.1003 0.0000 0.1002 0.0000 0.00 0.00 0.05

 2.000 0.2006 0.0148 0.1581 0.0277 1.48 0.00 13.81

 2.493 0.2500 0.0231 0.1725 0.0544 2.31 0.00 21.76

 3.000 0.3008 0.0298 0.1894 0.0816 2.98 745.85 29.62

 4.000 0.4010 0.0435 0.2275 0.1300 4.35 301.41 39.93

 5.000 0.5012 0.0559 0.2768 0.1685 5.59 220.40 44.86

 6.000 0.6013 0.0668 0.3298 0.2047 6.68 187.74 48.09

 7.000 0.7015 0.0773 0.3829 0.2414 7.73 169.60 50.73

 7.484 0.7500 0.0823 0.4077 0.2600 8.23 163.08 51.99

 8.000 0.8017 0.0878 0.4339 0.2801 8.78 152.52 54.15

 9.000 0.9018 0.0969 0.4939 0.3110 9.69 140.64 56.48

 10.000 1.0020 0.1047 0.5582 0.3391 10.47 133.55 58.06

 11.000 1.1021 0.1117 0.6239 0.3666 11.17 128.70 59.38

 12.000 1.2023 0.1179 0.6901 0.3942 11.79 125.13 60.57

 13.000 1.3024 0.1242 0.7558 0.4224 12.42 122.25 61.74

 14.000 1.4026 0.1301 0.8219 0.4506 13.01 119.98 62.80

 14.973 1.5000 0.1355 0.8862 0.4782 13.55 118.16 63.77

 15.000 1.5027 0.1357 0.8880 0.4790 13.57 118.08 63.81

 16.000 1.6028 0.1410 0.9565 0.5054 14.10 115.64 65.15

 17.000 1.7030 0.1458 1.0289 0.5283 14.58 114.04 65.97

 18.000 1.8031 0.1503 1.1021 0.5507 15.03 112.77 66.69

 19.000 1.9032 0.1544 1.1759 0.5729 15.44 111.73 67.34

 20.000 2.0033 0.1583 1.2499 0.5952 15.83 110.85 67.95

 21.000 2.1035 0.1619 1.3241 0.6174 16.19 110.11 68.53
DRAFT C-9

 22.000 2.2036 0.1653 1.3987 0.6396 16.53 109.47 69.08

 23.000 2.3037 0.1685 1.4733 0.6619 16.85 108.91 69.60

 24.000 2.4039 0.1716 1.5482 0.6841 17.16 108.42 70.10

 24.960 2.5000 0.1744 1.6199 0.7056 17.44 108.00 70.56

 CUMULATIVE

 ER OIL OIL WATER HC GAS SOLVENT GOR WOR

 YRS %OOIP MSTB MSTB MMSCF MMSCF MSCF/STB STB/STB

 0.000 0.00 0.0 0.0 0.0 0.0 0.000E+00 0.000E+00

 1.000 0.00 0.1 205.5 0.1 0.2 0.383E+01 0.287E+04

 2.000 1.48 25.6 324.2 20.6 125.1 0.570E+01 0.127E+02

 2.493 2.31 39.9 353.9 32.1 245.6 0.696E+01 0.886E+01

 3.000 2.98 51.5 388.6 41.5 368.4 0.796E+01 0.754E+01

 4.000 4.35 75.2 466.7 60.6 586.9 0.861E+01 0.620E+01

 5.000 5.59 96.7 567.7 77.8 760.9 0.867E+01 0.587E+01

 6.000 6.68 115.6 676.5 93.0 924.5 0.880E+01 0.585E+01

 7.000 7.73 133.6 785.4 107.6 1090.1 0.896E+01 0.588E+01

 7.484 8.23 142.4 836.2 114.7 1174.1 0.905E+01 0.587E+01

 8.000 8.78 151.8 889.9 122.2 1264.9 0.914E+01 0.586E+01

 9.000 9.69 167.6 1013.2 134.9 1404.5 0.918E+01 0.604E+01

 10.000 10.47 181.0 1145.0 145.7 1531.4 0.926E+01 0.633E+01

 11.000 11.17 193.1 1279.6 155.5 1655.7 0.938E+01 0.663E+01

 12.000 11.79 204.0 1415.5 164.2 1780.3 0.953E+01 0.694E+01

 13.000 12.42 214.9 1550.3 173.0 1907.6 0.968E+01 0.721E+01

 14.000 13.01 225.0 1685.8 181.2 2035.0 0.985E+01 0.749E+01

 14.973 13.55 234.4 1817.7 188.7 2160.0 0.100E+02 0.775E+01

 15.000 13.57 234.7 1821.4 188.9 2163.4 0.100E+02 0.776E+01

 16.000 14.10 243.8 1961.9 196.3 2282.5 0.102E+02 0.805E+01

 17.000 14.58 252.2 2110.4 203.0 2385.9 0.103E+02 0.837E+01

 18.000 15.03 259.9 2260.6 209.2 2487.2 0.104E+02 0.870E+01

 19.000 15.44 267.1 2411.8 215.0 2587.7 0.105E+02 0.903E+01

 20.000 15.83 273.8 2563.7 220.4 2688.0 0.106E+02 0.936E+01

 21.000 16.19 280.1 2716.0 225.5 2788.3 0.108E+02 0.970E+01

 22.000 16.53 285.9 2868.9 230.2 2888.6 0.109E+02 0.100E+02

 23.000 16.85 291.5 3022.0 234.7 2989.2 0.111E+02 0.104E+02

 24.000 17.16 296.7 3175.5 238.9 3089.9 0.112E+02 0.107E+02

 24.960 17.44 301.7 3322.7 242.9 3187.0 0.114E+02 0.110E+02

 ***********************************************

 SUMMARY OF FLUID PRODUCTION

 INCREMENTAL DATA

 ********** HCPV OUTPUT ********** OIL

 TIME HYDROCARBON PORE VOLUMES OUTPUT RECOVERY

 YRS TOTAL OIL WATER SOLVENT %OOIP

 0.000 0.0000 0.0000 0.0000 0.0000 0.00

 1.000 0.1003 0.0000 0.1002 0.0000 0.00

 2.000 0.1003 0.0147 0.0579 0.0277 1.47

 2.493 0.0494 0.0083 0.0145 0.0267 0.83
DRAFT C-10

 3.000 0.0508 0.0067 0.0169 0.0272 0.67

 4.000 0.1002 0.0137 0.0381 0.0484 1.37

 5.000 0.1002 0.0124 0.0492 0.0385 1.24

 6.000 0.1002 0.0109 0.0530 0.0362 1.09

 7.000 0.1002 0.0104 0.0531 0.0367 1.04

 7.484 0.0485 0.0051 0.0248 0.0186 0.51

 8.000 0.0517 0.0054 0.0262 0.0201 0.54

 9.000 0.1001 0.0091 0.0601 0.0309 0.91

 10.000 0.1001 0.0078 0.0643 0.0281 0.78

 11.000 0.1001 0.0070 0.0656 0.0275 0.70

 12.000 0.1001 0.0063 0.0663 0.0276 0.63

 13.000 0.1001 0.0063 0.0657 0.0282 0.63

 14.000 0.1001 0.0059 0.0661 0.0282 0.59

 14.973 0.0974 0.0054 0.0643 0.0277 0.54

 15.000 0.0027 0.0001 0.0018 0.0008 0.01

 16.000 0.1001 0.0053 0.0685 0.0264 0.53

 17.000 0.1001 0.0048 0.0724 0.0229 0.48

 18.000 0.1001 0.0045 0.0732 0.0224 0.45

 19.000 0.1001 0.0042 0.0737 0.0222 0.42

 20.000 0.1001 0.0039 0.0740 0.0222 0.39

 21.000 0.1001 0.0036 0.0743 0.0222 0.36

 22.000 0.1001 0.0034 0.0746 0.0222 0.34

 23.000 0.1001 0.0032 0.0746 0.0223 0.32

 24.000 0.1001 0.0030 0.0748 0.0223 0.30

 24.960 0.0961 0.0029 0.0718 0.0215 0.29

 INCREMENTAL

 ER OIL OIL WATER HC GAS SOLVENT GOR WOR

 YRS %OOIP MSTB MSTB MMSCF MMSCF MSCF/STB STB/STB

 0.000 0.00 0.0 0.0 0.0 0.0 0.000E+00 0.000E+00

 1.000 0.00 0.1 205.5 0.1 0.2 0.383E+01 0.287E+04

 2.000 1.47 25.5 118.7 20.5 124.9 0.571E+01 0.466E+01

 2.493 0.83 14.4 29.6 11.6 120.5 0.920E+01 0.206E+01

 3.000 0.67 11.6 34.7 9.3 122.8 0.114E+02 0.299E+01

 4.000 1.37 23.7 78.1 19.1 218.5 0.100E+02 0.330E+01

 5.000 1.24 21.5 101.0 17.3 174.0 0.891E+01 0.470E+01

 6.000 1.09 18.9 108.8 15.2 163.6 0.947E+01 0.576E+01

 7.000 1.04 18.0 108.9 14.5 165.6 0.998E+01 0.604E+01

 7.484 0.51 8.8 50.9 7.1 84.0 0.104E+02 0.579E+01

 8.000 0.54 9.4 53.7 7.5 90.8 0.105E+02 0.572E+01

 9.000 0.91 15.8 123.3 12.7 139.6 0.964E+01 0.780E+01

 10.000 0.78 13.4 131.9 10.8 126.9 0.103E+02 0.982E+01

 11.000 0.70 12.1 134.6 9.7 124.3 0.111E+02 0.111E+02

 12.000 0.63 10.9 135.9 8.8 124.7 0.123E+02 0.125E+02

 13.000 0.63 10.9 134.7 8.7 127.3 0.125E+02 0.124E+02

 14.000 0.59 10.2 135.5 8.2 127.4 0.133E+02 0.133E+02

 14.973 0.54 9.4 132.0 7.6 125.0 0.141E+02 0.140E+02

 15.000 0.01 0.3 3.7 0.2 3.5 0.147E+02 0.146E+02

 16.000 0.53 9.1 140.5 7.3 119.0 0.139E+02 0.154E+02

 17.000 0.48 8.3 148.5 6.7 103.4 0.132E+02 0.178E+02

 18.000 0.45 7.7 150.2 6.2 101.4 0.139E+02 0.194E+02

 19.000 0.42 7.2 151.2 5.8 100.4 0.148E+02 0.210E+02
DRAFT C-11

 20.000 0.39 6.7 151.8 5.4 100.4 0.157E+02 0.225E+02

 21.000 0.36 6.3 152.4 5.1 100.3 0.168E+02 0.242E+02

 22.000 0.34 5.8 152.9 4.7 100.3 0.180E+02 0.262E+02

 23.000 0.32 5.6 153.1 4.5 100.6 0.189E+02 0.275E+02

 24.000 0.30 5.2 153.5 4.2 100.7 0.201E+02 0.294E+02

 24.960 0.29 5.0 147.2 4.0 97.1 0.204E+02 0.297E+02
DRAFT C-12

1.5 HCPV CO2 WAG CO2-EOR Scenario

 ************** RESERVOIR DATA **************

 PRESSURE PATTERN

 TEMP OPERATING MMP POROSITY THICKNESS AREA

 F PSIA PSIA FRACTION FEET ACRES

 123.0 2368.0 1523.0 0.1100 76.0 40.00

 INITITAL HC

 FLOOD START SATURATIONS PORE VOLUME DYKSTRA-

 OIL WATER GAS HCPV - OOIP PARSONS HORIZONTAL

 SOINIT SWINIT SGINIT MMRB FACTOR LAYERS

 0.3200 0.6800 0.0000 2.0755 0.7300 5

 *************** FLUID DATA ***************

 STOCK SOLUTION SPECIFIC FORMATION VOLUME FACTOR

 TANK OIL GOR GRAVITY OIL WATER SOLVENT

 GRAVITY (Rs) SG Bo Bw Bco2

 API ft3/STB (Air=1.0) RB/STB RB/STB RB/MMSCF

 36.0 805.0 0.6500 1.2000 1.0119 459.557

 FLUID DENSITIES AT RES T&P FLUID VISCOSITIES AT RES T&P WATER

 RES OIL WATER SOLVENT OIL WATER SOLVENT SALINITY

 GMS/CC GMS/CC GMS/CC cp cp cp ppm

 0.7980 1.0550 0.7248 1.760 0.720 0.068 96000.

 ********** RELATIVE PERMEABILITY PARAMETERS **********

 WTR FLD GAS FLD MISC FLD

 SORW SORG SORM

 0.3200 0.3200 0.0500

 SGR SSR SWC SWIR

 0.3200 0.3200 0.2000 0.2000

 KROCW KWRO KRSMAX KRGCW

 0.4000 0.3000 0.4000 0.4000

 EXPOW EXPW EXPS EXPG EXPOG

 2.000 2.000 2.000 2.000 2.000

 MIX PARAMETER

 OMEGA MISCIBLE RELATIVE PERMEABILITY

 0.6660 EQUAL TO Krow
DRAFT C-13

 *********** INJECTION/PRODUCTION PARAMETERS *********

 OUTPUT

 INJECTION WAG EXPRESSED PATTERN INJECTION TIME STEPS

 SEQUENCES AS TIME OR VOL TYPE WELLS YEARS

 4 V 5S 1 1.000

 AVGE (TOTAL WELLS)

 CUM. INCRE CUM. SEQUENCE INJECTION FLUID

 INJECT TIME TIME RATE FRACTIONAL CONTENT WAG

 HCPV YEARS YEARS RB/D WATER SOLVENT WTR:GAS

 0.4000 3.989 3.989 569.86 0.0000 1.0000 .0000E+00

 1.2000 7.986 11.974 569.28 0.5000 0.5000 .1000E+01

 2.4000 11.983 23.957 569.08 0.6667 0.3333 .2000E+01

 3.6000 11.985 35.941 568.99 0.7500 0.2500 .3000E+01

 TOTAL PATTERN

 INCRE CUM. AVGE RATE FOR PATTERN SURFACE RATES

 TIME TIME ****** SEQUENTIAL ****** WATER SOLVENT

 YEARS YEARS RB/D HCPV/D HCPV/YR STB/D MMSCF/D

 3.989 3.989 569.86 0.27456E-03 0.10028 0.0 1.24

 7.986 11.974 569.28 0.27428E-03 0.10018 562.0 1.24

 11.983 23.957 569.08 0.27418E-03 0.10015 562.0 1.24

 11.985 35.941 568.99 0.27414E-03 0.10013 562.0 1.24

   INJECTION ** ** INJECTION   INJECTION ** ** INJECTION   

INJECTION

 SUMMARY OF FLUID INJECTION

 CUMULATIVE DATA

 TIME ** *** HCPV INPUT ***** WATER SOLVENT

 YRS TOTAL WATER SOLVENT MSTB MMSCF

 0.000 0.0000 0.0000 0.0000 0.0 0.0

 1.000 0.1003 0.0000 0.1003 0.0 452.9

 2.000 0.2006 0.0000 0.2006 0.0 905.8

 3.000 0.3008 0.0000 0.3008 0.0 1358.8

 3.989 0.4000 0.0000 0.4000 0.0 1806.6

 4.000 0.4011 0.0006 0.4006 1.2 1809.1

 5.000 0.5013 0.0507 0.4507 103.9 2035.3

 6.000 0.6015 0.1007 0.5007 206.6 2261.6

 7.000 0.7017 0.1508 0.5508 309.4 2487.8

 8.000 0.8019 0.2009 0.6009 412.1 2714.0

 9.000 0.9020 0.2510 0.6510 514.9 2940.3

 10.000 1.0022 0.3011 0.7011 617.6 3166.5

 11.000 1.1024 0.3512 0.7512 720.4 3392.7

 11.974 1.2000 0.4000 0.8000 820.5 3613.1
DRAFT C-14

 12.000 1.2026 0.4017 0.8009 824.0 3617.0

 13.000 1.3027 0.4685 0.8342 960.9 3767.8

 14.000 1.4029 0.5352 0.8676 1097.9 3918.5

 15.000 1.5030 0.6020 0.9010 1234.8 4069.3

 16.000 1.6032 0.6688 0.9344 1371.7 4220.1

 17.000 1.7033 0.7355 0.9678 1508.7 4370.8

 18.000 1.8034 0.8023 1.0011 1645.6 4521.6

 19.000 1.9036 0.8691 1.0345 1782.6 4672.4

 20.000 2.0037 0.9358 1.0679 1919.5 4823.1

 21.000 2.1039 1.0026 1.1013 2056.5 4973.9

 22.000 2.2040 1.0694 1.1347 2193.4 5124.7

 23.000 2.3042 1.1361 1.1681 2330.3 5275.4

 23.957 2.4000 1.2000 1.2000 2461.4 5419.7

 24.000 2.4043 1.2032 1.2011 2468.0 5424.6

 25.000 2.5044 1.2783 1.2261 2622.1 5537.6

 26.000 2.6046 1.3534 1.2511 2776.1 5650.7

 27.000 2.7047 1.4285 1.2762 2930.1 5763.7

 28.000 2.8048 1.5036 1.3012 3084.2 5876.8

 29.000 2.9050 1.5787 1.3262 3238.2 5989.8

 30.000 3.0051 1.6538 1.3513 3392.2 6102.9

 31.000 3.1052 1.7289 1.3763 3546.3 6216.0

 32.000 3.2053 1.8040 1.4013 3700.3 6329.0

 33.000 3.3055 1.8791 1.4264 3854.3 6442.1

 34.000 3.4056 1.9542 1.4514 4008.4 6555.1

 35.000 3.5057 2.0293 1.4764 4162.4 6668.2

 35.941 3.6000 2.1000 1.5000 4307.4 6774.6

 *** PRODUCTION ***** PRODUCTION ***** PRODUCTION ***** PRODUCTION ***

 SUMMARY OF FLUID PRODUCTION

 CUMULATIVE DATA

 ********** HCPV OUTPUT ********** OIL RECOVERY

 TIME HYDROCARBON PORE VOLUMES OUTPUT RECOVERY % OF INJECTANT

 YRS TOTAL OIL WATER SOLVENT %OOIP WATER SOLVENT

 0.000 0.0000 0.0000 0.0000 0.0000 0.00 0.00 0.00

 1.000 0.1003 0.0000 0.1002 0.0000 0.00 0.00 0.05

 2.000 0.2006 0.0148 0.1581 0.0277 1.48 0.00 13.81

 3.000 0.3008 0.0295 0.1852 0.0861 2.95 0.00 28.61

 3.989 0.4000 0.0394 0.2036 0.1570 3.94 0.00 39.25

 4.000 0.4011 0.0395 0.2038 0.1578 3.95 ****** 39.41

 5.000 0.5013 0.0504 0.2282 0.2228 5.04 450.51 49.43

 6.000 0.6015 0.0618 0.2635 0.2762 6.18 261.58 55.15

 7.000 0.7017 0.0720 0.3122 0.3174 7.20 207.00 57.63

 8.000 0.8019 0.0818 0.3634 0.3567 8.18 180.87 59.35

 9.000 0.9020 0.0917 0.4132 0.3971 9.17 164.60 61.00

 10.000 1.0022 0.1007 0.4634 0.4381 10.07 153.91 62.49

 11.000 1.1024 0.1090 0.5140 0.4793 10.90 146.37 63.81

 11.974 1.2000 0.1165 0.5639 0.5196 11.65 140.98 64.95

 12.000 1.2026 0.1167 0.5652 0.5207 11.67 140.70 65.01

 13.000 1.3027 0.1241 0.6201 0.5585 12.41 132.36 66.95
DRAFT C-15

 14.000 1.4029 0.1314 0.6815 0.5900 13.14 127.32 68.01

 15.000 1.5030 0.1378 0.7444 0.6208 13.78 123.66 68.90

 16.000 1.6032 0.1436 0.8089 0.6507 14.36 120.95 69.64

 17.000 1.7033 0.1487 0.8744 0.6802 14.87 118.88 70.28

 18.000 1.8034 0.1535 0.9401 0.7098 15.35 117.18 70.90

 19.000 1.9036 0.1581 1.0059 0.7396 15.81 115.74 71.49

 20.000 2.0037 0.1624 1.0721 0.7692 16.24 114.57 72.03

 21.000 2.1039 0.1664 1.1385 0.7990 16.64 113.55 72.55

 22.000 2.2040 0.1701 1.2050 0.8289 17.01 112.68 73.06

 23.000 2.3042 0.1736 1.2716 0.8590 17.36 111.93 73.54

 23.957 2.4000 0.1769 1.3355 0.8877 17.69 111.29 73.97

 24.000 2.4043 0.1770 1.3384 0.8889 17.70 111.23 74.01

 25.000 2.5044 0.1806 1.4066 0.9172 18.06 110.04 74.81

 26.000 2.6046 0.1839 1.4788 0.9418 18.39 109.27 75.28

 27.000 2.7047 0.1870 1.5522 0.9655 18.70 108.66 75.66

 28.000 2.8048 0.1898 1.6260 0.9890 18.98 108.14 76.00

 29.000 2.9050 0.1925 1.7001 1.0123 19.25 107.69 76.33

 30.000 3.0051 0.1951 1.7744 1.0356 19.51 107.29 76.64

 31.000 3.1052 0.1976 1.8487 1.0589 19.76 106.93 76.94

 32.000 3.2053 0.2000 1.9232 1.0822 20.00 106.61 77.22

 33.000 3.3055 0.2023 1.9977 1.1055 20.23 106.31 77.50

 34.000 3.4056 0.2045 2.0723 1.1288 20.45 106.04 77.78

 35.000 3.5057 0.2067 2.1468 1.1523 20.67 105.79 78.04

 35.941 3.6000 0.2087 2.2170 1.1743 20.87 105.57 78.29

 CUMULATIVE

 ER OIL OIL WATER HC GAS SOLVENT GOR WOR

 YRS %OOIP MSTB MSTB MMSCF MMSCF MSCF/STB STB/STB

 0.000 0.00 0.0 0.0 0.0 0.0 0.000E+00 0.000E+00

 1.000 0.00 0.1 205.5 0.1 0.2 0.383E+01 0.287E+04

 2.000 1.48 25.6 324.2 20.6 125.1 0.570E+01 0.127E+02

 3.000 2.95 51.1 379.9 41.1 388.8 0.841E+01 0.744E+01

 3.989 3.94 68.1 417.7 54.8 709.0 0.112E+02 0.613E+01

 4.000 3.95 68.3 418.0 55.0 712.9 0.112E+02 0.612E+01

 5.000 5.04 87.1 468.1 70.1 1006.0 0.124E+02 0.537E+01

 6.000 6.18 106.9 540.5 86.0 1247.3 0.125E+02 0.506E+01

 7.000 7.20 124.5 640.4 100.2 1433.7 0.123E+02 0.514E+01

 8.000 8.18 141.4 745.4 113.9 1610.8 0.122E+02 0.527E+01

 9.000 9.17 158.7 847.5 127.7 1793.6 0.121E+02 0.534E+01

 10.000 10.07 174.1 950.6 140.2 1978.7 0.122E+02 0.546E+01

 11.000 10.90 188.6 1054.4 151.8 2164.8 0.123E+02 0.559E+01

 11.974 11.65 201.5 1156.7 162.2 2346.7 0.125E+02 0.574E+01

 12.000 11.67 201.8 1159.4 162.5 2351.5 0.125E+02 0.574E+01

 13.000 12.41 214.7 1271.9 172.8 2522.5 0.126E+02 0.592E+01

 14.000 13.14 227.2 1397.8 182.9 2664.9 0.125E+02 0.615E+01

 15.000 13.78 238.4 1526.9 191.9 2803.6 0.126E+02 0.640E+01

 16.000 14.36 248.4 1659.2 199.9 2938.7 0.126E+02 0.668E+01

 17.000 14.87 257.3 1793.5 207.1 3071.9 0.127E+02 0.697E+01

 18.000 15.35 265.6 1928.3 213.8 3205.7 0.129E+02 0.726E+01

 19.000 15.81 273.5 2063.2 220.2 3340.3 0.130E+02 0.754E+01

 20.000 16.24 280.9 2199.1 226.1 3474.1 0.132E+02 0.783E+01

 21.000 16.64 287.7 2335.2 231.6 3608.8 0.133E+02 0.812E+01
DRAFT C-16

 22.000 17.01 294.2 2471.6 236.8 3743.9 0.135E+02 0.840E+01

 23.000 17.36 300.2 2608.3 241.7 3879.4 0.137E+02 0.869E+01

 23.957 17.69 305.9 2739.2 246.3 4009.1 0.139E+02 0.895E+01

 24.000 17.70 306.2 2745.2 246.5 4014.8 0.139E+02 0.897E+01

 25.000 18.06 312.3 2885.2 251.4 4142.6 0.141E+02 0.924E+01

 26.000 18.39 318.1 3033.3 256.1 4253.6 0.142E+02 0.954E+01

 27.000 18.70 323.4 3183.8 260.3 4360.8 0.143E+02 0.984E+01

 28.000 18.98 328.3 3335.2 264.3 4466.6 0.144E+02 0.102E+02

 29.000 19.25 333.0 3487.2 268.1 4571.9 0.145E+02 0.105E+02

 30.000 19.51 337.5 3639.5 271.7 4677.1 0.147E+02 0.108E+02

 31.000 19.76 341.8 3792.0 275.2 4782.3 0.148E+02 0.111E+02

 32.000 20.00 345.9 3944.8 278.4 4887.5 0.149E+02 0.114E+02

 33.000 20.23 349.8 4097.6 281.6 4992.8 0.151E+02 0.117E+02

 34.000 20.45 353.7 4250.5 284.7 5098.3 0.152E+02 0.120E+02

 35.000 20.67 357.5 4403.4 287.8 5204.1 0.154E+02 0.123E+02

 35.941 20.87 360.9 4547.4 290.5 5303.8 0.155E+02 0.126E+02

 ***********************************************

 SUMMARY OF FLUID PRODUCTION

 INCREMENTAL DATA

 ********** HCPV OUTPUT ********** OIL

 TIME HYDROCARBON PORE VOLUMES OUTPUT RECOVERY

 YRS TOTAL OIL WATER SOLVENT %OOIP

 0.000 0.0000 0.0000 0.0000 0.0000 0.00

 1.000 0.1003 0.0000 0.1002 0.0000 0.00

 2.000 0.1003 0.0147 0.0579 0.0277 1.47

 3.000 0.1003 0.0148 0.0272 0.0584 1.48

 3.989 0.0992 0.0098 0.0184 0.0709 0.98

 4.000 0.0011 0.0001 0.0002 0.0009 0.01

 5.000 0.1002 0.0109 0.0244 0.0649 1.09

 6.000 0.1002 0.0114 0.0353 0.0534 1.14

 7.000 0.1002 0.0102 0.0487 0.0413 1.02

 8.000 0.1002 0.0098 0.0512 0.0392 0.98

 9.000 0.1002 0.0099 0.0498 0.0405 0.99

 10.000 0.1002 0.0089 0.0503 0.0410 0.89

 11.000 0.1002 0.0084 0.0506 0.0412 0.84

 11.974 0.0976 0.0074 0.0499 0.0403 0.74

 12.000 0.0026 0.0002 0.0013 0.0011 0.02

 13.000 0.1001 0.0075 0.0548 0.0378 0.75

 14.000 0.1001 0.0072 0.0614 0.0315 0.72

 15.000 0.1001 0.0065 0.0630 0.0307 0.65

 16.000 0.1001 0.0057 0.0645 0.0299 0.57

 17.000 0.1001 0.0052 0.0655 0.0295 0.52

 18.000 0.1001 0.0048 0.0657 0.0296 0.48

 19.000 0.1001 0.0046 0.0658 0.0298 0.46

 20.000 0.1001 0.0042 0.0663 0.0296 0.42

 21.000 0.1001 0.0040 0.0664 0.0298 0.40

 22.000 0.1001 0.0037 0.0665 0.0299 0.37

 23.000 0.1001 0.0035 0.0666 0.0300 0.35

 23.957 0.0958 0.0033 0.0638 0.0287 0.33
DRAFT C-17

 24.000 0.0043 0.0001 0.0029 0.0013 0.01

 25.000 0.1001 0.0036 0.0683 0.0283 0.36

 26.000 0.1001 0.0033 0.0722 0.0246 0.33

 27.000 0.1001 0.0030 0.0733 0.0237 0.30

 28.000 0.1001 0.0029 0.0738 0.0234 0.29

 29.000 0.1001 0.0027 0.0741 0.0233 0.27

 30.000 0.1001 0.0026 0.0742 0.0233 0.26

 31.000 0.1001 0.0025 0.0743 0.0233 0.25

 32.000 0.1001 0.0024 0.0745 0.0233 0.24

 33.000 0.1001 0.0023 0.0745 0.0233 0.23

 34.000 0.1001 0.0022 0.0745 0.0234 0.22

 35.000 0.1001 0.0022 0.0745 0.0234 0.22

 35.941 0.0943 0.0020 0.0702 0.0221 0.20

 INCREMENTAL

 ER OIL OIL WATER HC GAS SOLVENT GOR WOR

 YRS %OOIP MSTB MSTB MMSCF MMSCF MSCF/STB STB/STB

 0.000 0.00 0.0 0.0 0.0 0.0 0.000E+00 0.000E+00

 1.000 0.00 0.1 205.5 0.1 0.2 0.383E+01 0.287E+04

 2.000 1.47 25.5 118.7 20.5 124.9 0.571E+01 0.466E+01

 3.000 1.48 25.5 55.7 20.6 263.6 0.111E+02 0.218E+01

 3.989 0.98 17.0 37.7 13.7 320.3 0.196E+02 0.222E+01

 4.000 0.01 0.2 0.4 0.1 3.9 0.232E+02 0.208E+01

 5.000 1.09 18.8 50.1 15.1 293.1 0.164E+02 0.266E+01

 6.000 1.14 19.8 72.5 15.9 241.3 0.130E+02 0.366E+01

 7.000 1.02 17.7 99.9 14.2 186.4 0.114E+02 0.566E+01

 8.000 0.98 16.9 105.0 13.6 177.1 0.113E+02 0.620E+01

 9.000 0.99 17.2 102.1 13.9 182.8 0.114E+02 0.593E+01

 10.000 0.89 15.5 103.1 12.4 185.1 0.128E+02 0.667E+01

 11.000 0.84 14.5 103.8 11.7 186.1 0.136E+02 0.716E+01

 11.974 0.74 12.9 102.3 10.4 181.9 0.149E+02 0.795E+01

 12.000 0.02 0.3 2.7 0.3 4.8 0.154E+02 0.820E+01

 13.000 0.75 12.9 112.5 10.4 170.9 0.141E+02 0.873E+01

 14.000 0.72 12.5 125.9 10.1 142.4 0.122E+02 0.101E+02

 15.000 0.65 11.2 129.1 9.0 138.7 0.132E+02 0.115E+02

 16.000 0.57 9.9 132.3 8.0 135.1 0.144E+02 0.133E+02

 17.000 0.52 8.9 134.4 7.2 133.2 0.157E+02 0.151E+02

 18.000 0.48 8.3 134.8 6.7 133.9 0.170E+02 0.163E+02

 19.000 0.46 8.0 134.9 6.4 134.6 0.177E+02 0.170E+02

 20.000 0.42 7.4 135.9 5.9 133.9 0.190E+02 0.185E+02

 21.000 0.40 6.9 136.1 5.5 134.6 0.204E+02 0.198E+02

 22.000 0.37 6.4 136.4 5.2 135.1 0.218E+02 0.212E+02

 23.000 0.35 6.1 136.7 4.9 135.5 0.232E+02 0.226E+02

 23.957 0.33 5.7 130.9 4.6 129.7 0.236E+02 0.230E+02

 24.000 0.01 0.3 5.9 0.2 5.8 0.231E+02 0.229E+02

 25.000 0.36 6.2 140.1 5.0 127.8 0.216E+02 0.228E+02

 26.000 0.33 5.8 148.1 4.7 111.0 0.200E+02 0.256E+02

 27.000 0.30 5.3 150.4 4.2 107.2 0.211E+02 0.285E+02

 28.000 0.29 4.9 151.5 4.0 105.8 0.222E+02 0.307E+02

 29.000 0.27 4.7 152.0 3.8 105.3 0.233E+02 0.324E+02

 30.000 0.26 4.5 152.3 3.6 105.2 0.241E+02 0.338E+02

 31.000 0.25 4.3 152.5 3.5 105.2 0.253E+02 0.355E+02
DRAFT C-18

 32.000 0.24 4.1 152.8 3.3 105.2 0.266E+02 0.375E+02

 33.000 0.23 3.9 152.9 3.2 105.3 0.275E+02 0.388E+02

 34.000 0.22 3.9 152.9 3.1 105.5 0.281E+02 0.395E+02

 35.000 0.22 3.8 152.8 3.1 105.8 0.286E+02 0.402E+02

 35.941 0.20 3.4 144.0 2.8 99.7 0.299E+02 0.421E+02
DRAFT D-1

Appendix D: United States Environmental Protection Agency 

AP-42 Emissions Factors for the Onshore Oil and Gas Industry

Table D-1: AP-42 Methane CH4 Emissions Factors for the Oil and Gas Industry

Activity/Equipment Emission Factor EF Units

Vented Emissions 

Oil Tanks 5.28 scf of CH4/bbl crude 

Pneumatic Devices, High Bleed 330 scfd CH4/device 

Pneumatic Devices, Low Bleed 52 scfd CH4/device 

Chemical Injection Pumps 248 scfd CH4 /pump 

Vessel Blowdowns 78 scfy CH4/vessel 

Compressor Blowdowns 3,775 scf/yr of CH4/compressor 

Compressor Starts 8,443 scf/yr. of CH4/compressor 

Stripper wells 2,345 scf/yr of CH4/stripper well 

Well Completion Venting 733 scf/completion 

Well Workovers 96 scf CH4/workover 

Pipeline Pigging 2.4 scfd of CH4/pig station 

Fugitive Emissions 

Oil Wellheads (heavy crude) 0.13 scfd/well 

Oil Wellheads (light crude) 16.6 scfd/well 

Separators (heavy crude) 0.15 scfd CH4/separator 

Separators (light crude) 14 scfd CH4/separator 

Heater/Treaters (light crude) 19 scfd CH4/heater 

Headers (heavy crude)1 0.08 scfd CH4/header 

Headers (light crude) 11 scfd CH4/header 

Floating Roof Tanks 338,306 scf CH4/floating roof tank/yr. 

Compressors 100 scfd CH4/compressor 

Large Compressors 16,360 scfd CH4/compressor 

Sales Areas 41 scf CH4/loading 

Pipelines NE scfd of CH4/mile of pipeline 

Well Drilling NE scfd of CH4/oil well drilled 

Battery Pumps 0.24 scfd of CH4/pump 

Combustion Emissions 

Gas Engines 0.24 scf CH4/HP-hr 

Heaters 0.52 scf CH4/bbl 

Well Drilling 2,453 scf CH4/well drilled 

Flares 20 scf CH4/Mcf flared 

Process Upset Emissions 

Pressure Relief Valves 35 scf/yr/PR valve 

Well Blowouts Onshore 2.5 MMscf/blowout 
DRAFT D-2

Table D-2: AP-42 CO2 Emissions Factors for the Oil and Gas Industry

CO2 Emissions

Activity/Equipment Emission Factor EF Units

Vented Emissions 

Oil Tanks 3.53 scf of CO2/bbl crude 

Pneumatic Devices, High Bleed 6.704 scfd CO2/device 

Pneumatic Devices, Low Bleed 1.055 scfd CO2/device 

Chemical Injection Pumps 5.033 scfd CO2/pump

Vessel Blowdowns1 1.583 scfy CO2/vessel 

Compressor Blowdowns1 77 scf/yr of CO2/compressor 

Compressor Starts1 171 scf/yr of CO2/compressor 

Stripper wells 48 scf/yr of CO2/stripper well 

Well Completion Venting1 14.87 Scf CO2/completion 

Well Workovers 1.95 scf CO2/workover 

Pipeline Pigging NE scfd of CO2/pig station 

Fugitive Emissions 

Oil Wellheads (heavy crude)1 0.003 scfd/well 

Oil Wellheads (light crude) 0.337 scfd/well 

Separators (heavy crude)1 0.003 scfd CO2/separator 

Separators (light crude) 0.281 scfd CO2/separator 

Heater/Treaters (light crude) 0.319 scfd CO2/heater 

Headers (heavy crude)1 0.002 scfd CO2/header 

Headers (light crude) 0.22 scfd CO2/header 

Floating Roof Tanks1 17,490 scf CO2/floating roof 

tank/yr. 

Compressors 2.029 scfd CO2/compressor 

Large Compressors 332 scfd CO2/compressor 

Sales Areas 2.096 scf CO2/loading 

Pipelines NE scfd of CO2/mile of pipeline 

Well Drilling NE scfd of CO2/oil well drilled 

Battery Pumps 0.012 scfd of CO2/pump 

Process Upset Emissions 

Pressure Relief Valves1 1.794 scf/yr/PR valve 

Well Blowouts Onshore 0.051 MMscf/blowout 
DRAFT E-1

Appendix E: Summary Output form U.S. EPA TANKS Model of Oil Storage Tanks for 

Historical, Best Practices, and 1.5 HCPV CO2 WAG CO2-EOR Scenarios.

Historical CO2-EOR

a)Estimated Annual Working and Breathing Losses of Single Oil Tank Under Historical CO2-EOR Scenario Conditions

TANKS 4.0.9d

Emissions Report - Summary Format 

Tank Indentification and Physical Characteristics

Identification

User Identification: 1.0 HCPV WAG

City: Midland-Odessa

State: Texas

Company:

Type of Tank: Vertical Fixed Roof Tank

Description: Working and Breathing losses for 1.5 HCPV CO2 WAG Scenario

Tank Dimensions

Shell Height (ft): 15.00

Diameter (ft): 12.00

Liquid Height (ft) : 15.00

Avg. Liquid Height (ft): 12.00

Volume (gallons): 12,690.44

Turnovers: 467.00

Net Throughput(gal/yr): 6,299,743.00

Is Tank Heated (y/n): N

Paint Characteristics

Shell Color/Shade: White/White

Shell Condition Good

Roof Color/Shade: White/White

Roof Condition: Good

Roof Characteristics

Type: Dome

Height (ft) 2.00

Radius (ft) (Dome Roof) 12.00

Breather Vent Settings

Vacuum Settings (psig): -0.03

Pressure Settings (psig) 0.03

Meterological Data used in Emissions Calculations: Midland-Odessa, Texas (Avg Atmospheric Pressure = 13.28 psia)

TANKS 4.0.9d
DRAFT E-2

Emissions Report - Summary Format 

Liquid Contents of Storage Tank

i)1.0 HCPV WAG - Vertical Fixed Roof Tank

Midland-Odessa, Texas

Daily Liquid Surf.

Temperature (deg F)

Liquid

Bulk

Temp Vapor Pressure (psia)

Vapor

Mol.

Liquid

Mass

Vapor

Mass Mol. Basis for Vapor Pressure

Mixture/Component Month Avg. Min. Max. (deg F) Avg. Min. Max. Weight. Fract. Fract. Weight Calculations

Crude oil (RVP 5) All 65.56 58.52 72.59 63.30 3.2058 2.7953 3.6634 50.0000 207.00 Option 4: RVP=5

TANKS 4.0.9d

Emissions Report - Summary Format 

Individual Tank Emission Totals

k)Emissions Report for: Annual 

l)1.0 HCPV WAG - Vertical Fixed Roof Tank

Midland-Odessa, Texas

Losses(lbs)

Components Working Loss Breathing Loss Total Emissions

Crude oil (RVP 5) 4,163.72 376.04 4,539.76

b) Estimated Annual Working and Breathing Losses of Heater/Treater Under Historical CO2-EOR Scenario Conditions

TANKS 4.0.9d

Emissions Report - Summary Format 

Tank Indentification and Physical Characteristics

Identification

User Identification: 1HCPV__HT_TANK_1

City: Midland-Odessa

State: Texas

Company:
DRAFT E-3

Type of Tank: Vertical Fixed Roof Tank

Description: Estimation of Working and Standing Losses for 0.4 HCPV CO2_EOR Scenario

Tank Dimensions

Shell Height (ft): 12.00

Diameter (ft): 6.00

Liquid Height (ft) : 8.00

Avg. Liquid Height (ft): 8.00

Volume (gallons): 1,692.06

Turnovers: 7,399.00

Net Throughput(gal/yr): 13,020,395.90

Is Tank Heated (y/n): Y

Paint Characteristics

Shell Color/Shade: Gray/Medium

Shell Condition Good

Roof Color/Shade: Gray/Medium

Roof Condition: Good

Roof Characteristics

Type: Dome

Height (ft) 2.00

Radius (ft) (Dome Roof) 6.00

Breather Vent Settings

Vacuum Settings (psig): 0.00

Pressure Settings (psig) 0.00

Meterological Data used in Emissions Calculations: Midland-Odessa, Texas (Avg Atmospheric Pressure = 13.28 psia)

TANKS 4.0.9d

Emissions Report - Summary Format 

Liquid Contents of Storage Tank

1HCPV__HT_TANK_1 - Vertical Fixed Roof Tank

Midland-Odessa, Texas

Daily Liquid Surf.

Temperature (deg F)

Liquid

Bulk

Temp Vapor Pressure (psia)

Vapor

Mol.

Liquid

Mass

Vapor

Mass Mol. Basis for Vapor Pressure

Mixture/Component Month Avg. Min. Max. (deg F) Avg. Min. Max. Weight. Fract. Fract. Weight Calculations

Crude oil (RVP 5) All 68.65 59.43 77.87 140.00 3.4009 2.8455 4.0400 50.0000 207.00 Option 4: RVP=5

TANKS 4.0.9d

Emissions Report - Summary Format 

Individual Tank Emission Totals

Emissions Report for: Annual 
DRAFT E-4

1HCPV__HT_TANK_1 - Vertical Fixed Roof Tank

Midland-Odessa, Texas

Losses(lbs)

Components Working Loss Breathing Loss Total Emissions

Crude oil (RVP 5) 6,749.82 128.78 6,878.59

a)Estimated Annual Working and Breathing Losses of Single Oil Tank Under Best Practices CO2-EOR Scenario

Conditions

Best Practices CO2-EOR

TANKS 4.0.9d

Emissions Report - Summary Format 

Tank Indentification and Physical Characteristics

Identification

User Identification: 1.0 HCPV WAG

City: Midland-Odessa

State: Texas

Company:

Type of Tank: Vertical Fixed Roof Tank

Description: Working and Breathing losses for 1.5 HCPV CO2 WAG Scenario

Tank Dimensions

Shell Height (ft): 15.00

Diameter (ft): 12.00

Liquid Height (ft) : 15.00

Avg. Liquid Height (ft): 12.00

Volume (gallons): 12,690.44

Turnovers: 521.00

Net Throughput(gal/yr): 6,299,743.00

Is Tank Heated (y/n): N

Paint Characteristics

Shell Color/Shade: White/White

Shell Condition Good

Roof Color/Shade: White/White

Roof Condition: Good

Roof Characteristics

Type: Dome

Height (ft) 2.00
DRAFT E-5

Radius (ft) (Dome Roof) 12.00

Breather Vent Settings

Vacuum Settings (psig): -0.03

Pressure Settings (psig) 0.03

Meterological Data used in Emissions Calculations: Midland-Odessa, Texas (Avg Atmospheric Pressure = 13.28 psia)

TANKS 4.0.9d

Emissions Report - Summary Format 

Liquid Contents of Storage Tank

1.0 HCPV WAG - Vertical Fixed Roof Tank

Midland-Odessa, Texas

Daily Liquid Surf.

Temperature (deg F)

Liquid

Bulk

Temp Vapor Pressure (psia)

Vapor

Mol.

Liquid

Mass

Vapor

Mass Mol. Basis for Vapor Pressure

Mixture/Component Month Avg. Min. Max. (deg F) Avg. Min. Max. Weight. Fract. Fract. Weight Calculations

Crude oil (RVP 5) All 65.56 58.52 72.59 63.30 3.2058 2.7953 3.6634 50.0000 207.00 Option 4: RVP=5

TANKS 4.0.9d

Emissions Report - Summary Format 

Individual Tank Emission Totals

Emissions Report for: Annual 

1.0 HCPV WAG - Vertical Fixed Roof Tank

Midland-Odessa, Texas

Losses(lbs)

Components Working Loss Breathing Loss Total Emissions

Crude oil (RVP 5) 4,043.66 376.04 4,419.70

b)Estimated Annual Working and Breathing Losses of Heater/Treater Under Best Practices CO2-EOR Scenario

Conditions

TANKS 4.0.9d
DRAFT E-6

Emissions Report - Summary Format 

Tank Indentification and Physical Characteristics

Identification

User Identification: 1HCPV__HT_TANK_1

City: Midland-Odessa

State: Texas

Company:

Type of Tank: Vertical Fixed Roof Tank

Description: Estimation of Working and Standing Losses for 1.0 HCPV CO2_EOR Scenario

Tank Dimensions

Shell Height (ft): 12.00

Diameter (ft): 6.00

Liquid Height (ft) : 8.00

Avg. Liquid Height (ft): 8.00

Volume (gallons): 1,692.06

Turnovers: 7,695.00

Net Throughput(gal/yr): 13,020,395.90

Is Tank Heated (y/n): Y

Paint Characteristics

Shell Color/Shade: Gray/Medium

Shell Condition Good

Roof Color/Shade: Gray/Medium

Roof Condition: Good

Roof Characteristics

Type: Dome

Height (ft) 2.00

Radius (ft) (Dome Roof) 6.00

Breather Vent Settings

Vacuum Settings (psig): 0.00

Pressure Settings (psig) 0.00

Meterological Data used in Emissions Calculations: Midland-Odessa, Texas (Avg Atmospheric Pressure = 13.28 psia)

TANKS 4.0.9d

Emissions Report - Summary Format 

Liquid Contents of Storage Tank

1HCPV__HT_TANK_1 - Vertical Fixed Roof Tank

Midland-Odessa, Texas

Daily Liquid Surf.

Temperature (deg F)

Liquid

Bulk

Temp Vapor Pressure (psia)

Vapor

Mol.

Liquid

Mass

Vapor

Mass Mol. Basis for Vapor Pressure

Mixture/Component Month Avg. Min. Max. (deg F) Avg. Min. Max. Weight. Fract. Fract. Weight Calculations

Crude oil (RVP 5) All 68.65 59.43 77.87 140.00 3.4009 2.8455 4.0400 50.0000 207.00 Option 4: RVP=5
DRAFT E-7

TANKS 4.0.9d

Emissions Report - Summary Format 

Individual Tank Emission Totals

Emissions Report for: Annual 

1HCPV__HT_TANK_1 - Vertical Fixed Roof Tank

Midland-Odessa, Texas

Losses(lbs)

Components Working Loss Breathing Loss Total Emissions

Crude oil (RVP 5) 6,743.65 128.78 6,872.43

1.5 HCPV CO2 WAG CO2-EOR

a) Estimate Annual Working and Breathing Losses of Oil Tank Under 1.5 HCPV CO2 WAG CO2-EOR Scenario

TANKS 4.0.9d

Emissions Report - Summary Format 

Tank Indentification and Physical Characteristics

Identification

User Identification: 1.5 HCPV WAG

City: Midland-Odessa

State: Texas

Company:

Type of Tank: Vertical Fixed Roof Tank

Description: Working and Breathing losses for 1.5 HCPV CO2 WAG Scenario

Tank Dimensions

Shell Height (ft): 15.00

Diameter (ft): 12.00

Liquid Height (ft) : 15.00

Avg. Liquid Height (ft): 12.00

Volume (gallons): 12,690.44

Turnovers: 496.00

Net Throughput(gal/yr): 6,299,743.00

Is Tank Heated (y/n): N

Paint Characteristics

Shell Color/Shade: White/White

Shell Condition Good
DRAFT E-8

Roof Color/Shade: White/White

Roof Condition: Good

Roof Characteristics

Type: Dome

Height (ft) 2.00

Radius (ft) (Dome Roof) 12.00

Breather Vent Settings

Vacuum Settings (psig): -0.03

Pressure Settings (psig) 0.03

Meterological Data used in Emissions Calculations: Midland-Odessa, Texas (Avg Atmospheric Pressure = 13.28 psia)

TANKS 4.0.9d

Emissions Report - Summary Format 

Liquid Contents of Storage Tank

1.5 HCPV WAG - Vertical Fixed Roof Tank

Midland-Odessa, Texas

Daily Liquid Surf.

Temperature (deg F)

Liquid

Bulk

Temp Vapor Pressure (psia)

Vapor

Mol.

Liquid

Mass

Vapor

Mass Mol. Basis for Vapor Pressure

Mixture/Component Month Avg. Min. Max. (deg F) Avg. Min. Max. Weight. Fract. Fract. Weight Calculations

Crude oil (RVP 5) All 65.56 58.52 72.59 63.30 3.2058 2.7953 3.6634 50.0000 207.00 Option 4: RVP=5

TANKS 4.0.9d

Emissions Report - Summary Format 

Individual Tank Emission Totals

Emissions Report for: Annual 

- Vertical Fixed Roof Tank

Midland-Odessa, Texas

Losses(lbs)

Components Working Loss Breathing Loss Total Emissions

Crude oil (RVP 5) 4,095.99 376.04 4,472.03
DRAFT E-9

b)Estimated Annual Working and Breathing Losses of Heater/Treater Under 1.5 HCPV CO2 WAG CO2-EOR Scenario

Conditions

TANKS 4.0.9d

Emissions Report - Summary Format 

Tank Indentification and Physical Characteristics

Identification

User Identification: 1HCPV__HT_TANK_1

City: Midland-Odessa

State: Texas

Company:

Type of Tank: Vertical Fixed Roof Tank

Description: Estimation of Working and Standing Losses for 1.0 HCPV CO2_EOR Scenario

Tank Dimensions

Shell Height (ft): 12.00

Diameter (ft): 6.00

Liquid Height (ft) : 8.00

Avg. Liquid Height (ft): 8.00

Volume (gallons): 1,692.06

Turnovers: 7,137.00

Net Throughput(gal/yr): 13,020,395.90

Is Tank Heated (y/n): Y

Paint Characteristics

Shell Color/Shade: Gray/Medium

Shell Condition Good

Roof Color/Shade: Gray/Medium

Roof Condition: Good

Roof Characteristics

Type: Dome

Height (ft) 2.00

Radius (ft) (Dome Roof) 6.00

Breather Vent Settings

Vacuum Settings (psig): 0.00

Pressure Settings (psig) 0.00

Meterological Data used in Emissions Calculations: Midland-Odessa, Texas (Avg Atmospheric Pressure = 13.28 psia)

TANKS 4.0.9d

Emissions Report - Summary Format 

Liquid Contents of Storage Tank

1HCPV__HT_TANK_1 - Vertical Fixed Roof Tank

Midland-Odessa, Texas
DRAFT E-10

Daily Liquid Surf.

Temperature (deg F)

Liquid

Bulk

Temp Vapor Pressure (psia)

Vapor

Mol.

Liquid

Mass

Vapor

Mass Mol. Basis for Vapor Pressure

Mixture/Component Month Avg. Min. Max. (deg F) Avg. Min. Max. Weight. Fract. Fract. Weight Calculations

Crude oil (RVP 5) All 68.65 59.43 77.87 140.00 3.4009 2.8455 4.0400 50.0000 207.00 Option 4: RVP=5

TANKS 4.0.9d

Emissions Report - Summary Format 

Individual Tank Emission Totals

Emissions Report for: Annual 

1HCPV__HT_TANK_1 - Vertical Fixed Roof Tank

Midland-Odessa, Texas

Losses(lbs)

Components Working Loss Breathing Loss Total Emissions

Crude oil (RVP 5) 6,755.70 128.78 6,884.48
DRAFT F-1

Appendix F: Drill Rig Specifications

http://patdrilling.com/pdf/rigs/472.pdf

RIG #472 

DRAWWORKS BOP’S 

National 370-M (550HP) 11” X 3,000 psi Shaffer double 

1 1/8” drill line, Parmac 22-SR auxiliary brake 

ACCUMULATOR 

POWER Koomey 5-Station, 80 gallon accumulator 

(2) Caterpillar 3408 engines (475HP each) 

CHOKE MANIFOLD 

LIGHT PLANTS 3,000 psi choke manifold 

(2) Caterpillar 3406 engines w/ 210 KW generators 

SWIVEL 

MAST Ideco (300 Ton) 

DSI 132’ w/ 322,000# capacity on 8 lines 

ROTARY TABLE 

SUBSTRUCTURE Gardner Denver (17 1/2”) 

DSI 14’ box 

KB 13’ 6” Rotary beam clearance 9’ 4” DRILL PIPE 4 1/2” drill pipe 

BLOCK HOOK 

McKissick (250 Ton) block DRILL COLLARS 

Web Wilson (200 Ton) hook 8” and 6 1/2” drill collars *quantity subject 

to availibility 

PUMPS 

(2) Continental Emsco DB-550 (550HP each) duplex AUXILIARY EQUIPMENT 

pumps Pason EDR (base system) 

(1) Powered by a Caterpillar 379 engine Water Tank - (2) 500 barrel capacity each 

(1) Powered by a Caterpillar 353 engine Rig Manager Quarters Satellite automatic 

driller 

Mathey survey unit 
DRAFT G-1

Appendix G: Life Cycle Emissions Profile of 434-MWelectric

(MWe) Existing PC Facility

Table G-1: Life Cycle Emissions Profile of 434-megawatt electric (MWe) Existing PC 

Thermoelectric generation facility with and without 90 percent CO2 Capture.

Emissions (kg 

CO2e /MWh)

Stage #1: Raw 

Material 

Acquisition

Stage #2: Raw 

Material 

Transport

Stage #3: 

Power Plant

Stage #4: 

Transmission & 

Distribution

Total

Case 1-EXPC Without CCS

CO2 3.2 5.2 1.0E+03 0 1020

N2O 1.4E-02 3.7E-02 5.1 0 5.1

CH4 80 1.9E-01 2.8E-01 0 80

SF6 4.3E-07 6.0E-08 6.3E-03 3.3 3.3

Total GWP 83 5.4 1017 3.3 1109

Case 2-EXPC With CCS

CO2 3.2 5.2 340 0 348

N2O 1.4E-02 3.7E-02 6.0 0 6.0

CH4 8.0E+01 1.9E-01 6.6 0 87

SF6 4.3E-07 6.0E-08 4.5E-03 3.3 3.3

Total GWP 83 5.4 353 3.3 444
DRAFT H-1

Appendix H: Tabular Listing of Summary Data for Three Operational Scenarios

Table H-1: Summary of emissions and resource demands for historical CO2-EOR scenario.

Parameter Units Site Eval. & Char. Construction Operation Closure MVA Total

Greenhouse Gas Emissions

CO2 kg/bbl crude 3.49E-03 3.24E-01 4.88E+01 1.83E-01 6.99E-03 4.93E+01

CH4 kg/bbl crude 0.00E+00 5.79E-05 8.84E-02 1.87E-06 0.00E+00 8.85E-02

N2O kg/bbl crude 0.00E+00 0.00E+00 2.13E-04 0.00E+00 0.00E+00 2.13E-04

SF6 kg/bbl crude 0.00E+00 0.00E+00 2.18E-11 0.00E+00 0.00E+00 2.18E-11

CO2E* kg/bbl crude 3.67E-03 3.36E-01 5.01E+01 1.90E-01 7.35E-03 5.06E+01

Criteria Air Pollutants

NOX kg/bbl crude 1.61E-05 1.29E-03 2.90E-02 7.95E-04 3.22E-05 3.11E-02

CO kg/bbl crude 8.55E-06 7.22E-04 4.28E-02 4.09E-04 1.71E-05 4.40E-02

PM (Total) kg/bbl crude 4.09E-07 3.38E-03 1.27E-03 1.22E-04 8.18E-07 4.77E-03

Lead kg/bbl crude 0.00E+00 0.00E+00 6.36E-07 0.00E+00 0.00E+00 6.36E-07

SO2 kg/bbl crude 2.92E-10 7.68E-04 8.37E-02 9.55E-05 5.84E-10 8.46E-02

VOC kg/bbl crude 1.08E-06 7.10E-05 1.32E-01 4.94E-05 2.15E-06 1.32E-01

Water Use

Fresh water 

consumption bbl/bbl crude 0.00E+00 4.49E-03 2.47E-01 9.70E-04 0.00E+00 2.52E-01

Excess Brine

for Injection 

Disposal

barrel excess 

brine per bbl 

crude

- - 5.27E-01 - - 5.27E-01

CO2 Sequestered (gross)

CO2 stored kg/bbl crude - - 195 - - 195

Land Use

Pattern Area Acres/bbl crude - - 2.09E-04 - - 2.09E-04

* CO2 equivalent values are aggregate values including credits and upstream emissions for which only CO2E values are available. Individual GHG 

constituent values will not correspond directly with the reported total global warming potential.
DRAFT H-2

Table H-2: Summary of emissions and resource demands for best practices CO2-EOR scenario.

Parameter Units Site Eval. & Char. Construction Operation Closure MVA Total

Greenhouse Gas Emissions

CO2 kg/bbl crude 2.22E-03 2.99E-01 6.88E+01 1.16E-01 4.44E-03 6.92E+01

CH4 kg/bbl crude 0.00E+00 6.08E-05 7.95E-02 1.19E-06 0.00E+00 7.96E-02

N2O kg/bbl crude 0.00E+00 0.00E+00 2.01E-04 0.00E+00 0.00E+00 2.01E-04

SF6 kg/bbl crude 0.00E+00 0.00E+00 1.84E-11 0.00E+00 0.00E+00 1.84E-11

CO2E* kg/bbl crude 2.33E-03 3.12E-01 7.03E+01 1.21E-01 4.67E-03 7.07E+01

Criteria Air Pollutants

NOX kg/bbl crude 1.02E-05 1.26E-03 2.77E-02 5.05E-04 2.04E-05 2.95E-02

CO kg/bbl crude 5.43E-06 6.90E-04 7.31E-02 2.59E-04 1.09E-05 7.41E-02

PM (Total) kg/bbl crude 2.60E-07 3.11E-03 1.21E-03 7.76E-05 5.19E-07 4.39E-03

Lead kg/bbl crude 0.00E+00 0.00E+00 5.17E-07 0.00E+00 0.00E+00 5.17E-07

SO2 kg/bbl crude 1.95E-10 6.41E-04 8.35E-02 6.06E-05 3.90E-10 8.42E-02

VOC kg/bbl crude 6.83E-07 7.35E-05 5.20E-02 3.13E-05 1.37E-06 5.21E-02

Water Use

Fresh water 

consumption kg/bbl crude 0.00E+00 4.17E-03 2.07E-01 6.15E-04 0.00E+00 2.12E-01

Excess Brine

for Injection 

Disposal

barrel excess 

brine per bbl 

crude

- - 8.15E-01 - - 8.15E-01

CO2 Sequestered (gross)

CO2 stored kg CO2/bbl crude - - 228 - - 228

Land Use

Land use Acres/bbl crude - - 1.33E-04 - - 1.33E-04

* CO2 equivalent values are aggregate values including credits and upstream emissions for which only CO2E values are available. Individual GHG 

constituent values will not correspond directly with the reported total global warming potential.
DRAFT H-3

Table H-3: Summary of emissions and resource demands for 1.5 HCPV CO2 WAG EOR scenario.

Parameter Units Site Eval. & Char. Construction Operation Closure MVA Total

Greenhouse Gas Emissions

CO2 kg/bbl crude 1.97E-03 3.45E-01 9.09E+01 9.72E-02 3.93E-03 9.13E+01

CH4 kg/bbl crude 0.00E+00 7.50E-05 1.41E-01 9.93E-07 0.00E+00 1.41E-01

N2O kg/bbl crude 0.00E+00 0.00E+00 2.54E-04 0.00E+00 0.00E+00 2.54E-04

SF6 kg/bbl crude 0.00E+00 0.00E+00 2.15E-11 0.00E+00 0.00E+00 2.15E-11

CO2E* kg/bbl crude 2.07E-03 3.61E-01 9.42E+01 1.01E-01 4.13E-03 9.46E+01

Criteria Air Pollutants

NOX kg/bbl crude 9.04E-06 1.49E-03 3.53E-02 4.22E-04 1.81E-05 3.72E-02

CO kg/bbl crude 4.81E-06 8.12E-04 1.01E-01 2.17E-04 9.62E-06 1.02E-01

PM (Total) kg/bbl crude 2.30E-07 3.71E-03 1.53E-03 6.49E-05 4.60E-07 5.30E-03

Lead kg/bbl crude 0.00E+00 0.00E+00 5.86E-07 0.00E+00 0.00E+00 5.86E-07

SO2 kg/bbl crude 1.74E-10 6.92E-04 1.02E-01 5.06E-05 3.47E-10 1.03E-01

VOC kg/bbl crude 6.05E-07 9.02E-05 1.83E-01 2.62E-05 1.21E-06 1.84E-01

Water Use

Fresh water 

consumption kg/bbl crude 0.00E+00 5.01E-03 2.41E-01 5.14E-04 0.00E+00 2.47E-01

Excess Brine

for Injection 

Disposal

barrel excess 

brine per bbl 

crude

- - 6.65E-01 - - 6.65E-01

CO2 Sequestered (gross)

Injected -

produced kg/bbl crude - - 211 - - 211

Land Use

Total Pattern 

Coverage Acres/bbl crude - - 1.17E-04 - - 1.17E-04

* CO2 equivalent values are aggregate values including credits and upstream emissions for which only CO2E values are available. 

Individual GHG constituent values will not correspond directly with the reported total global warming potential.