# An Assessment of Gate

- to

- Gate Environmental Life Cycle Performance of Water

- Alternating

Gas C O 2 

# - Enhanced Oil Recovery in the Permian

Basin

September 3 0 , 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 e ndorsement, 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 Assess ment of Gate

- to

- Gate Environmental Life Cycle

Performance of Water

- Alternating

- Gas CO 2 

# - Enhanced Oil Recovery in the Permian Basin

DOE/NETL

- 2010/1433

September 30 , 20 10

NETL Contact:

Robert M. Dilmore

General Engineer, Situational Analysis Team

Office of Systems, Analyses and Planning

National Energy Technology Laboratory

www.netl.doe.gov

### This page intentionally left blank

# Acknowledgements

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

Do nald 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

.

### This page intentionally left blank

### 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 CO 2 

### - Enhanced Oil Recovery Techno logy

................................ ................. 1

1.2 Purpose of Study

................................ ................................ ................................ ............. 2

1.3 Scope of Assessment

................................ ................................ ................................ ....... 2

2.0 Life Cycle As sessment 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 Func tion

................................ ................................ ....................... 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 CO 2 

### - EOR Technology

................................ .............................. 12

3.1 CO 2 

### - EOR Mechanisms and Methodologies

................................ ................................ . 12

3.1.1 Minimum Miscibility Pressure Calculation

................................ .......................... 14

3.1.2 Water Alternating Ga s (WAG) Tertiary Injection Scheme

................................ .. 16

3.1.2.1 Advanced Resources International Big Oil Fields Database

............................ 17

3.2 CO 2 

### - EOR as CO 2 

### Geologic S equestration Mechanism

................................ ................ 18

### ii 3.2.1 Retention vs. Sequestration in CO 2 

### - Flood EOR

................................ ................... 18

3.2.1.1 CO 2 

### Retention in CO 2 

### - EOR Operations

................................ ........................... 19

3.2.1.2 CO 2 

### Sequestration in CO 2 

### - EOR Operations

................................ ..................... 20

3.3 Review of Relevant Literature

................................ ................................ ...................... 22

3.3.1 NETL Characterizations of CO 2 

### - EOR Economic and Technical Potential

.......... 22

3.3.2 Literature Review of CO 2 

### - EOR Environmental Performance

.............................. 29

3.4 CO 2 

### Prophet CO 2 

### - EOR Screening Model

................................ ................................ ..... 30

3.4.1 Summary of CO 2 

### Prophet Screening Model

................................ ......................... 31

3.4.1.1 Estimation of CO 2 

### - Flo od Performance Using CO 2 

### Prophet Screening Model

. 3 5

3.4.2 Results of CO 2 

### Prophet Runs for Individual Flood Pattern

................................ .. 39

3.5 Phases of CO 2 

### - EOR Facility Operation

................................ ................................ ........ 55

3.5.1 Site Evaluation and Characterization

................................ ................................ .... 55

3.5.2 Facility Design and Construction

................................ ................................ .......... 56

3.5.2.1 CO 2 

### - EOR Facility Overview

................................ ................................ ............ 56

3.5.2.2 Overview of Site Preparation for CO 2 

### - 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 B rine 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 CH 4 

### Emissions E stimate

................................ ........................... 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 Characterizat ion of Ryan

- Holmes CO 2 

### Separation and NGL Recovery

............... 95

3.9.1.1 Description of Model Facility Used in Characterization

................................ .. 95

3.9.1.2 Ryan

- H olmes Process Stream Flow Calculations

................................ ............. 96

3.9.1.3 Estimation of Produced Hydrocarbon Gas Composition

................................ .. 97

3.9.1.4 Gas Processing Facilit y 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 CO 2 

### - EOR Well Pattern Performance

................................ ............................... 111

4.1.1 CO 2 

### Retention Performance of Single Well Pattern

................................ ........... 112

4.1.2 CO 2 

### Recovery in Historical Scenario

................................ ................................ . 114

4.2 Life Cycle Performance

................................ ................................ .............................. 114

4.2.1 G reenhouse 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 CO 2 

### - 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 CO 2



### ................................ ................................ ..... 124

4.3.1.7 Displacement C redit for Natural Gas and Natural Gas Liquid Co

- Products

.. 125

4.3.2 Discussion of Sensitivity Analysis Results

................................ ......................... 125

5.0 Summary of Findi ngs

................................ ................................ ................................ .... 127

5.1 Next Steps

................................ ................................ ................................ ................... 128

5.1.1 Gate

- to

- Gate Analysis of Alternative CO 2 

### - 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: CO 2 

### Prophet CO 2 

### - 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 CO 2 

### Prophet Model for Historical, Best Practices, and 1.5

HCPV CO 2 

### WAG CO 2 

### - EOR Scenario s.

................................ ................................ ..... C

- 1

Appendix D: United States Environmental Protection Agency AP

- 42 Emissions Factors for the Onshore Oil and Gas Industry

................................ ................................ .............. D

- 1

App endix E: Summary Output form U.S. EPA TANKS Model of Oil Storage Tanks for Historical, Best Practices, and 1.5 HCPV CO 2 

### WAG CO 2 

### - EOR Scenarios.

............ E

- 1

Appendix F: Drill Rig Specifications

................................ ................................ ....................... F

- 1

Appendix G: Life Cycle Emissions Profile of 434

- MW electric 

### (MWe) Existing PC Facility G

- 1

Appendix H: Tabular Listing of Summary Data for Three Operational Scenarios

.......... H

- 1

### v 

## List of Tables

Table ES

- 1 Summary Results for CO 2 

### Enhanced Oil Recovery Life Cycle Analysis

............ ES

- 2

Table 2

- 1 Life Cycle Goal and Scope Definition for CO 2 

### - EOR Gate

- to

- Gate Environmental Life Cycle Assessment

................................ ................................ ................................ ................... 3

Table 2

- 2 Summary of Life Cycle Boundary and Representativene ss of CO 2 

### - EOR Life Cycle

Assessment

................................ ................................ ................................ .............................. 4

Table 2

- 3: Specifications for CO 2 

### 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 CO 2 

### - EOR Activities 11

Table 3

- 1 Technical Screening Guidelines for CO 2 

### Flooding

................................ ..................... 13

Table 3

- 2 Simplified Representation of CO 2 

### - EOR Fluid Injection Schemes

.............................. 17

Table 3

- 3 Definition of CO 2 

### - EOR Technology Scenarios and Data Sources Used in Evalu ation

of CO 2 

### - EOR Scenarios in Studies Previously Published by NETL

................................ ..... 25

Table 3

- 4 Summary of CO 2 

### - EOR Injection Scenarios as Defined in Previously Published Reports

................................ ................................ ................................ ................................ .. 26

Table 3

- 5: Economically Recoverable Oil and CO 2 

### Sequestration Capacity in the Conterminous 48 States and Alaska, Estimated Based on Stream

- Tube Modeling of Best Practices and

“Next Generation” CO 2 

### - EOR Scenarios

................................ ................................ ............... 27

Table 3

- 6 Range of Electricity Use at CO 2 

### - EOR Fields by Source

................................ ............. 28

Table 3

- 7 Summary of Characterizations of CO 2 

### - 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 CO 2 

### - 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 CO 2 

### - 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” Mis cible CO 2 

### - flood

EOR in the CO 2 

### Prophet Screening Model

................................ ................................ ........... 37

Table 3

- 12: Injection schedule parameters used in defining “best practices” miscible CO 2 

### - flood

EOR in the CO 2 

### Prophet screening model

................................ ................................ ............ 37

Table 3

- 13 Injection Schedule Parameters Used in Defining 1.5 HCPV CO 2 

### Miscible WAG

EOR in the CO 2 

### Prophet Screening Model

................................ ................................ ........... 38

Table 3

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

Based on CO 2 

### Prophet Screening Model Characterization of Three WAG Scenarios

......... 51

### vi Table 3

- 15 Summary of Mode l 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 Operate d 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 CO 2 

### - EOR Pattern Operations for Each Operational Scenario

................................ ............................... 66

Table 3

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

CO 2 

### - 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 C onstants 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 Wa ter 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 CO 2 

### 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 (CO 2 

### Prophet model results)

................................ ................................ ................................ ................................ ... 74

Table 3

- 33 Estimated Total Electricity Demand Over the Life of CO 2 

### - 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 CO 2 

### 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 CO 2 

### - EOR Scenarios Estimated Using

ARI mMid

- range Electricity Estimate of 5 kWh/bbl for Historical CO 2 

### - EOR and 10 kWh for Best practices and Next

- G eneration CO 2 

### - 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 Re quirement

...... 78

Table 3

- 37 Process Element Assumptions Made in Characterization of CO 2 

### - EOR Produced Liquids Processing

................................ ................................ ................................ ................ 80

Table 3

- 38 As sumptions 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 CO 2 

### - 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 CO 2 

### - 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 CO 2 

### - 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 Hydrocarbo n 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 Emission s 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 Scenari o 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 Rec overy Unit

................................ ................................ ................................ ....... 92

Table 3

- 49 Parameter Values Used in eEstimation of Venting Emissions from Solid Desiccant Dehydration System

................................ ................................ ................................ .............. 93

Table 3

- 50 Summary of CO 2 

### - EOR Bulk Produced Gas (CO 2 

### + hydrocarbon gas) Supplied to Gas Processing Facility

................................ ................................ ................................ ......... 97

Table 3

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

Basi n 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 Proce ss (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 CO 2 

### - EOR Operations

................. 106

Table 3

- 61 Estimation of Natural Gas and Natural Gas Liquids Production from Ryan

- Holmes

Proce ss

................................ ................................ ................................ ................................ 106

Table 3

- 62 Mass of Constituents Separated from CO 2 

### - EOR Recycle Stream Through Ryan

Holmes Process

................................ ................................ ................................ ................... 107

Table 3

- 63 Displacement Credit for Natural Gas Liquid Coproducts of Oil Production in CO 2 

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

Gas

- Processing Plant

................................ ................................ ................................ .......... 108

Table 3

- 64 Summary o f 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 CO 2 

### - EOR Flood Performance for the Operational Scenarios Defined Herein, and Predicted Using the CO 2 

### Prophet Stream

- tube Model

................................ .... 111

Table 4

- 2 Summary of Single Pattern CO 2 

### Retention Performance. In all operational scenarios, 75 percent of maximum CO 2 

### storage potential is realized in the first third of flood operation.

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

Table 4

- 3 Estimated Acres of Land Disturbed by CO 2 

### - EOR Activity per Barrel of Oil Produced

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

Table 4

- 4 Selected Parameters Used in Sensitivity Analysis of Gate

- to

- Gate Life Cycle GHG

Emission s Performance of CO 2 

### - 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 CO 2 

### - EOR Operational Scenarios

............ ES

- 3

Figur e ES

- 2 CO 2 

### Retained (Metric Tonne CO 2 

### ) 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 th e Distribution of CO 2 

### - 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 Cy cle

Assessment of CO 2 

### - 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. CO 2 

### Injection (assumes homogeneous reservoir). Sweep Efficiency in Reservoir Pore Volumes (RVPs) of Miscible CO 2 

### - EOR Flood Increases with Increasing Hydrocarbon Pore Volume (HCPV) Injection.

................. 15

Figure 3

- 3 Tertiary Oil Recovery Increases with Increasing CO 2 

### , But Also Increases the Required Duration of the CO 2 

### 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 CO 2 

### Injection Schedule for WAG Injection Scenarios (MMscf

CO 2 

### /year)

................................ ................................ ................................ .............................. 41

Figure 3

- 8 Cumulative CO 2 

### Injecti on 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 CO 2 

### Production Profile for WAG Injection Scenarios (MMscf)

......... 46

Figure 3

- 13 Incremental Oil Production for WAG Injection Scenarios (M STB/yr)

................... 47

Figure 3

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

line in historical CO 2 

### - EOR scenario represents brine production response after initiation of water slug.

................................ ................................ ................................ ............................. 48

Figure 3

- 15 Incremental CO 2 

### Production for WAG Injection Scenarios (MMscf/year)

............. 49

Figure 3

- 16 Incremental Hydrocarbo n 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

- Mont h 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 Interval s for Each Pattern (MSTB/year)

................................ ................................ ................................ ......................... 54

Figure 3

- 19 CO 2 

### - PM Model Established a Peak Total Gas Production Threshold of 20 MMscf/day Above Which a CO 2 

### - EOR Operation Was Assumed to Require Construction of a Dedicated Gas Processing Facility

................................ ................................ ..................... 94

Figure 4

- 1 CO 2 

### retained in a single 40

- acre, five

- spot CO 2 

### - EOR pattern for the three described operational scenarios. Retention is greatest in early ye ars of flood operation. Water slug applied after WAG in the historical scenario recovers about 23 percent of stored CO 2 

### , by

mass

. ................................ ................................ ................................ ................................ .... 112

Figure 4

- 2 Mass of CO 2 

### Sequestered per 40

- Acre, Five

- Spot a s a Function of the Mass of CO 2 

### Injected. Additional storage benefit decreased with increasing CO 2 

### injection.

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

Figure 4

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

CO 2 

### - EOR Activity, Reported in Units of Metric Tonnes of CO 2 

### - Equivalent Generated per

Barrel of Oil Produced

................................ ................................ ................................ ........ 115

Figure 4

- 4 Total Gate

- to

- Gate Life Cycle Emissions for Each Operational S cenario and Total

CO 2 

### Sequestered Through CO 2 

### - EOR Activity (both reported per barrel of oil produced) 116

Figure 4

- 5 Summary of Criteria Air Pollutant Emissions Associated with Each Phase of CO 2 

### - 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 E ach Phase of CO 2 

### - 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 CO 2 

### - 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 CO 2 

### - 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 CO 2 

### - EOR operations.

................................ ................................ ................................ ........................... 121

Figure 4

- 9 Energy Consumed per Unit of Crude Produced for Three CO 2 

### - EOR Operational

Scenarios

................................ ................................ ................................ ............................. 122

Figure 4

- 10 Tornado Plot Summarizing Impact of Varying Select Model Input Parameter Values Away from Base Case As sumptions

................................ ................................ ................... 126

### xi 

## Acronyms and Abbreviations

AEO Annual Energy Outlook (Energy Information Agency)

API American Petroleum Institute

b bl Barrel

Btu British t hermal u nit

CCS Carbon capture and storage

cf Cubic feet

CH 4 

### Metha ne

CO Carbon m onoxide

CO 2 

### Carbon d ioxide

CO 2 

### E Carbon d ioxide Equivalent

DOE Department of Energy

EIA Energy Information Administration

EOR Enhanced Oil Recovery

EPA Environmental Protection Agency

GHG Greenhouse g as

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 Li fe cycle assessment

LCI Life cycle inventory

Mbbl Thousand barrels

Mcf Thousand cubic feet

### xii MJ Megajoule

MMBtu Million Btu

MMP Minimum m iscibility 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

N 2 

### O Nitrous oxide

NETL National Energy Technology Laboratory

NG Natural gas

NGL Natural gas liquid

NO X 

### 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 conditio ns)

scf Standard cubic feet (surface conditions)

scfd Standard cubic feet per day (surface conditions)

SDW Saltwater disposal well

SO X 

### Sulfur o xides

STB Standard barrel (surface conditions)

THC

UF Total hydrocarbons

Utilization factor

### xiii UIC Undergroun d 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 ( CO 2 

### ) 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, CO 2 

### enhanced oil recovery ( CO 2 

### - EOR) als o stores a portion of the injected CO 2 

### , 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 ince ntive for capturing and sequestering CO 2 

### . However, CO 2 

### - EOR operations are relatively energy intensive and have high associated emissions because of the need to produce, process, and re

- inject produced CO 2 

### and brine.

This study estimates that current CO 2 

### - EOR “best practices” (water

- alternating

- gas [ WAG ] injection in a typical Permian Basin reservoir) g enerate greenhouse gas (GHG) emissions of 71 kg CO 2 

### equivalents ( CO 2 

### E ) per barrel of oil extracted

- a value nearly three times higher than the average GHG emissi ons for domestic oil extracted in 2005 of 24 kg CO 2 

### e per barrel (NETL, 2009). In this “best practices” case, 53 percent of the total GHG emissions associated with CO 2 

### - EOR activity result from processing of produced gas to separate CO 2 

### from the flashed lig ht hydrocarbon fraction (glycol dehydration with Ryan

- Holmes type distillative separation), while

41 percent of GHG emissions result from CO 2 

### compression. The process es to separate brine from produced crude and to pump the brine for re

- injection each acco unt 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 CO 2 

### EOR operational scenarios. Under current “best practices” 2.5 times more CO 2 

### is injected than in the

historical case, and a high CO 2 

### injection scenario considers performance with 50 percent more CO 2 

### injected than in “best practices.” These results show that the amount of CO 2 

### stored per barrel of crude oil produced is highest in the “best practice s ” case and lower i n the high CO 2 

### injection scenario.

### ES

- 2 Table ES

- 1 Summary Results for CO 2 Enhanced Oil Recovery Life Cycle Assessment

CO 2 - EOR Operational Scenario Historical Current Best

Practices High CO 2 Scenario **a**

CO 2 injection duration (single pattern, years) 7 25 36

Volume of CO 2 injected as a percent of the hydrocarbon pore volume in the target
formation b 0.4 1.0 1.5

Oil recovery as a percent of original oil in place (OOIP) 12% 17% 21%

Percent of injected CO 2 recycled c 60% 71% 78%
CO 2 stored per barrel of oil produced (kg
CO 2 /bbl oil) c 200 230 210

GHG emissions per barrel of oil produced (kg CO 2 e/bbl oil) c 51 71 95

a Assumes (1) improved technologies that enable more efficient contact between CO 2 and residual oil and (2) policy in centives for sequestering CO 2

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 Σ A * 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 mod eling of a 40 acre 5

- spot tapered WAG injection in a typical formation in the Permian basin, using the CO 2 P rophet model.



### Figure ES

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

for the three CO 2 

### - EOR scenarios. GHG emissions increase as oil recovery increases from 12

percent in the historic al case, to 17 percent in current “best practices,” and to 21 percent in the high CO 2 

### case. This increase is greater between “best practices” and high CO 2 

### 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 CO 2 

### are applied, processed, and re

- injected.

### ES

- 3 -

Figure ES

- 1 Recovery versus GHG Emissions for CO 2 - EOR Operational Scenarios



### Figure ES

- 2 reports cumulative CO 2 

### sequestration and incremental oil production over the life of

a CO 2 

### flood, for the three cases considered; these are pattern

- level stream tube model result s. The figure shows that most of the CO 2 

### 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, CO 2 

### is displaced from the formation and cumulative CO 2 

### storage decreases below peak storage in year eight by 23 percent. In contrast, best practices and high CO 2 

### cases continue the WAG injection until the end of the f lood 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 CO 2 

### purchase price. historical best practices high CO 2



### 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 CO 2 Retained (Metric Tonne CO 2 ) 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” a ssessment 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 CO 2 

### - EOR is used as a geologic sink for CO 2 

### emissions (e.g., pulverize d coal combustion with CO 2 

### capture and sequestration through CO 2 

### - EOR). Also, the methodology used for estimation of Permian Basin WAG injection will be applied to estimate “gate

- to

- gate” CO 2 

### - EOR performance of next

- generation WAG CO 2 

### - EOR technologies that improve contact between CO 2 

### and remaining oil, straight CO 2 

### flooding EOR as is practiced in the Gulf Coast Basin, and other variations on the CO 2 

### - EOR technology paradigm.

### 1 

## 1.0 Introduction

1.1 Overview of CO 2 

### - Enhanced Oil Recovery Technology

This study is foc used on assessing environmental life cycle performance of domestic , on

- shore

, CO 2 

### - miscible 1

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 . CO 2 

### - miscible operations account for the vast majority of currently producing and planned CO 2 

### - EOR operations in the Unite d

States ; the Oil & Gas Journal 2010 Worldwide EOR Survey lists 10 6 producing CO 2 

### - miscible EOR projects (with total enhanced production of approximately 2 53 ,000 barrels per day) and only 5 CO 2 

### - immiscible projects (with total enhanced production of approxim ately 9,300 barrels per day)

, accounting for less than four percent of all domestic CO 2 

### - EOR (Koottungal, 2009). Figure 1 illustrates that a pproximately 67 percent of all crude produced in the United States by

CO 2 

### - miscible EOR is generated in Texas, and ap proximately 74 percent of that is produced from the San Andres pay zone , Permian Basin (Koottungal, 2009).

Figure 1

- 1 Summary of the D istribution of CO 2 - EOR O perations in the United States,

R eported in B arrels of C rude O il P roduced per D ay



### Recent publications by the U.S DOE NETL indicate that significant potential remains for domestic incremental oil production from tertiary CO 2 

### - flood EOR, with an estimated 45.0 billion

barrels of additional stranded o il accessible using current CO 2 

### - EOR “be st practices,” and a potential 64.4 billion barrels accessible using “next generation” EOR technology and practices.

In addition to th is estimated total incremental production, the NETL studies report that implementa tion of these technologies has the potential to sequester significant quantities of CO 2 

### 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 Stud y

This study is intended to provide a detailed, bottom

- up life cycle inventory of CO 2 

### - flood enhanced oil recovery ( CO 2 

### - EOR) operations, considering all associated significant infrastructure elements, process flows, and activities. The assessment is based on a n inventory of all phases of activity for model CO 2 

### - EOR operations

, and a ll of the environmental burdens

attributed to each phase of CO 2 

### - EOR activity are summed to estimate a total environmental burden of producing crude oil through CO 2 

### - EOR . Natural g as 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 deve lop an improve d understanding of CO 2 

### - EOR performance with respect to oil production , geologic CO 2 

### storage potential, and environmental performance under different operational scenarios. Results of this “ gate

- to

- gate” analysis can be integrated with charac terizations of other unit processes (e.g., petroleum refinery or integrated gasification combined cycle inventories) to generate full “ cradle

- to

- grave ” assessment s of various energy conversion pathways.

Whether used as a stand

- alone tool for assessment of CO 2 

### - EOR performance or integrated into a larger, cradle

- to

- grave life cycle assessment (LCA) of fossil energy conversion pathways, t he 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 o r 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 CO 2 

### - 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 CO 2 

### storage permanence

. To the extent practicable, all significant material and energy flow s have been considered for primary activities associated with implementation of tertiary CO 2 

### - 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 wou ld 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 C ycle A ssessment Methodology

Factors considered in establishing appropri ate 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) definin g an appropriate system boundary ; (5) summar izing 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 C ycle G oal and S cope D efinition for CO 2 - EOR G ate

- to

- G ate E nvironmental

L ife C ycle A ssessment

General Question Specific Goal

Study purpose T o develop life cycle inventory of CO 2 - flood enhanced oil recovery ( CO 2 - EOR) operations and use that inventory to develop analysis of environmental performance of this CO 2 management alternative

Intended audience Life cycle practitioners interested in eval uating environmental performance of CO 2 - EOR potential as applied to storage of anthropogenic
CO 2 and stimulation of incremental oil production

Intended l evel of

assessment d etail 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 CO 2 - EOR operational scenarios, and for integration into f ull cradle

- to

- grave life

- cycle analyses associated

with CO 2 - producing energy conversion processes

### 4 Table 2

- 2 Summary of L ife C ycle B oundary and R epresentativeness of CO 2 - EOR L ife
C ycle A ssessment

Life Cycle Boundary G ate

- to

- gate ( receipt of purchased CO 2 thru crude oil delivery to sales pipeline )

Temporal Representation 30 years of CO 2 - EOR active operations to sequester CO 2 from one industrial

- scale anthropogenic CO 2 source

Technological Representation Ter tiary, m iscible

, CO 2 water alternating gas

- type EOR

fl ood

Geographical Representation Typical Permian Basin (West Texas) reservoir properties

assumed

Impact Assessment Methodology Global Warming Potential, IPCC 2007, 100

- year time

fram e Reporting Metri c M ass of CO 2 E emitted per barrel of oil produced

Data Quality Objectives Process

- based (“ b ottom

- up”) m odeling a pproach

Full t ransparency of m odeling a pproach and d ata

s ources

Accounting for 99% of m ass and e nergy, and a ccounting
for 99% of e nvironm ental r elevance (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 delive red pipeline

- quality CO 2 

### at the EOR project location through

deliver y 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 characteri zation of process energy and material flows and infrastructure requirements associated with CO 2 

### - based enhanced oil recovery. Performance of these operations

is independent of the source from which the CO 2 

### was taken and the distance from which CO 2 

### is

deliv ered, and these upstream activities are, therefore, excluded from this gate

- to

- gate analysis

. As is detailed in subsequent sections, CO 2 

### injection is alternated with water injection in water alternating gas (WAG)

– type CO 2 

### - EOR flood. For purposes of this study it is assumed that brine produced from this or adjacent EOR floods serves as the sou r ce 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. D isposal of produced

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

more detail in subsequent sections

. Figure 2

- 1 provides a simplif ied schematic of the major process elements associated with the CO 2 

### - EOR operation phase and establishe s the LCA boundary for this system

.

### 5 Figure 2

- 1 Simplified S ystem B oundary for O peration P hase of “ G at e
- to

- G ate” L ife C ycle A ssessment of CO 2 - B ased

E nhanced O il R ecovery . 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 for e go 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 incr emental 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 acti vities 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 w ho 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 reas ons 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 b oundary analysis. However, for the purposes of this study and the relative comparison of different CO 2 

### - EOR operational scenarios, such a boundary analysis is considered to be unnecessary and attributional; a process

- based LCA guided by engineering judgmen t

- 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 m ass, 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 proc ess. 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

. The re are a number of human activities performed t hat 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. T hese activities have not been taken into account in the life cycle inventory described

herein

. Catastrophic Releases. In c ontrast 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 inventor y of CO 2 

### - EOR include s 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 ter minology). Therefore, secondary material and energy inputs such as concrete and steel for facility construction or grid electricity for pump operation have been take n 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 fun ctional 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 a n 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 performan ce 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 follo wing 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 I dentification of Function


### The primary function of CO 2 

### - EOR operations is the enhanced recovery of oil from under

producing or non

- producing target oil

- bearing formation(s), with geologic sequestration of CO 2 

### considered to be a secondary function. That is t o say, construction and operation of CO 2 

### - 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 CO 2 

### storage capacity. In co ntrast, sequestration of CO 2 

### in brine aquifers would be carried out with the sole function of preventing release of anthropogenic CO 2 

### to the atmosphere, with no salable product generated from such operations.

The f unctional unit that has been adopted is sequestration of CO 2 

### captured from 30 years of operations from one thermoelectric generation facility, and sequestration for a period of 100 years (that CO 2 

### which has been delivered to the injection site, injected over a period of 30 years, and remains geo logically sequestered 100 years after initial injection).

For purposes of this study, CO 2 

### - EOR operations have been scaled to be of sufficient size to accept CO 2 

### from an existing pulverized coal plant that has been retrofitted with amine

- based

capture. Th e p lant 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 retrofit ting 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 CO 2 

### 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, f orthcoming) . Performance of this existing PC plant with retrofit capture system is not included within the gate

- to

- gate life cycle inventory of CO 2 

### - EOR operations. The flowrate of s eparated CO 2 

### stream estimated from this study has been used to estimate t he amount of CO 2 

### that would be supplied to CO 2 

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

estimate the scale of CO 2 

### - EOR activity that would be required to accept this volume of CO 2 

### . In all cases, result s 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), “CO 2 

### , whether being sold for chemical processin g or being sequestered, is to be supplied as a liquid and must meet the pipeline specification ” as shown in Table 2

- 3

. B oosting or reduction of pressure may be required prior to injection into the receiving formation.

Table 2

- 3 : Specifications for CO 2 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

N 2 <300 p pmv O 2 <40 ppmv

Ar <10 ppmv Referenced from McGurl, et al. (2004)



## 2.2 Geographic, Temporal, and Technological Representation

This LCA considers CO 2 

### - EOR activity that is limited to oil fields that have been depleted through prima ry production and repressured through s ubsequent secondary water flood enhanced oil recovery prior to initiation of tertiary recovery through CO 2 

### 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 CO 2 

### flood scenario, although the values do not correspond to a specific real

world EOR reservoir. Evaluation of CO 2 

### - flood EOR performance in target reservoirs with different parameter values wou ld require re

- evaluation based on a revised prediction of flood performance. A lternatively, real, detailed, and site

- specific flood performance from an existing

CO 2 

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

Six life cycle st ages are considered by NETL in full , “ cradle

- to

- grave” LCAs of energy products :

r aw material acquisition

, r aw m aterial t ransport

, energy co nversion, p roduct transpor t

, p roduct

use , and e nd

- of life management

. For the purposes of this assessment of CO 2 

### - EO R, a limited “gate

- to

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

- up characterization of activity associated with management of CO 2 

### 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 CO 2 

### is generated is not significant and can be omitted from the comparative assessment of different CO 2 

### - EOR operational scenarios

. CO 2 

### - EOR is considered to

### 9 be a well established and relatively mature technology. CO 2 

### - EOR technology represented includes tapered WAG injection using a 40

- acre five

- spot pattern configuration with an injection:production wel l 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 characteriz ation is based on gas stream dehydration and subsequent distillation to separate hydrocarbon from CO 2 

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

all unit operations, a n assumption has be en mad e that current technology is representative of future operations . However, scenarios have been considered with different application s of those unit operations to represent historical, current best

- pra c tices, and high

- CO 2 

### injection CO 2 

### - EOR

scenarios , as de scribed in detail in subsequent sections. The assessment assumes relatively large

- scale implementation of CO 2 

### - EOR to facilitate the sequestration of large flows of CO 2 

### that would be generated from capture and sequestration of CO 2 

### 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, crite ria 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 CO 2


### equ ivalents 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 Ga ses Included in Study Boundary

Emissions to Air Abbreviation GWP, CO 2 Equivalents

, 100

- year time horizon

Carbon Dioxide CO 2 1

Methane CH 4 2 5
Nitrous Oxide N 2 O 298
Sulfur Hexafluoride SF 6 22, 8 00

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 limit ed to, these criteria pollutants.

### 10 Table 2

- 5 Criteria A ir P ollutants I ncluded in S tudy B oundary

Emissions to Air Abbreviation Comment

Carbon Monoxide CO

-- Nitrogen Dioxide/Nitrogen
Oxides NO 2 /NO X Includes all forms of nitrogen oxides.

Sulfur Dioxide SO 2 Includes SO 2 and other forms of sulfur oxides.

Ozone, also reported as Volatile Organic Compounds O 3 , VOCs VOCs combined with NO

x 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: PM 10 , PM 2.5 , and unspecified mean aerodynamic diameter.

Lead Pb

--

2.3.3 Water Consumption


### In addition to atmospheric emissions, water consumption associated with CO 2 

### - EOR activity is

also considered

. This life cycle performance metric is reported in units of volume per volume of oil produced and i nclude s 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 inventor y 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 operat ions. 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 associa ted with its production. When considering gate

- to

- gate
CO 2 

### - 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 con tribute to generation of those products.



## 2.4 Allocation Methodology

Allocation procedures f ollow those set forth in ISO Document 14044 (ISO, 2006 ) , which details a favored hierarchy of allocation methodology giving preference to the most detailed and

technic ally 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 limitation s do n ot 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 CO 2 

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

These co

- products are generat ed 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

gener ated through CO 2 

### - 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 ) ar e reported to be below the

d etection 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/MM B tu of fuel consumed, the value used for

emissions estimation will be 0.0005 lb/M B tu fuel consumed. Higher heating values used in characterization of mixed hydrocarbon gas are reported in Table 2

- 6



### .

Table 2

- 6 Higher H eating V alues for C onstituents of G as P roduced from CO 2 - EOR

A ctivities

Fuel HHV a B tu /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

So urce: 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 Integrat ed 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 CO 2 

## - EOR Technology

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

associated with CO 2 

### - EOR and brine aquifer sequestration of CO 2 

### to facilitate c omparative

assessment of l ife cycle inventories of these processes

. The f ollowing is a brief description of major activities and infrastructure elements associated with all phases of these CO 2 

### sequestration options.

CO 2 

### flood enhanced oil recovery ( CO 2 

### - EOR) is the injection of C O 2 

### (often injected in alternat ion with water/brine) into a n 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 employe d 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 CO 2 

### - EOR can be expected to stimulate recovery of an

additi onal 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 CO 2 

### projects producing an average of 250 ,000 barrels of incremental oil per day, or approxima tely 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 report ed 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 CO 2 

### - EOR in the Permian Basin is limited by the availability of CO 2 

### , with 85 percent of CO 2 

### used in EOR operations com ing from natural

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

- product sources (Melzer, 2010). Capture incentives or p roposed climate change legislation calling for large

- scale capture and sequestration of anthropogenic CO 2 

### would resolve that limitation and create an opportunity to realize large increases in incremental oil production , and achieve significant geologic sequestration of CO 2 

### (as much as 13 gigatons of CO 2 

### storage capability) (NETL, 2008).



## 3.1 CO 2 

## - EOR Mechanisms and Methodologies

In general, r eservoir 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 ( CO 2 

### - flood) recovery can be assumed.

The p rimary mechanisms by which oil is recovered through tertiary CO 2 

### flooding are:

**•** Generation o f miscibility conditions with the oil and CO 2



### • Swelling crude oil

**•** Lowering oil viscosity

**•** Lowering interfacial tension between oil and CO 2 

### - 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 CO 2 

### and crude oil is a function of fluid and formation properties such as formation depth, temperature/pressure, and crude oil composition. When CO 2 

### /oil miscibility is achieved in tertiary EOR operations, d isplacement efficiency of the miscible fluid improves, and the overall flood productivity increases.

In immiscible CO 2 

### floods, oil swelling and viscosity reduction are the primary mechanisms of enhanced recovery, with oil volume increases of as much a s 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 me thods, the increased incremental oil production will be lower as compared to CO 2 

### - 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 CO 2 

### - 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 CO 2 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 intermedi ates (C5 to C12)

Reservoir

Oil Saturation in W ater

flooded S wept Z one > 25* a 15 to 70

Type of Formation Thick but r elatively thin ly bedded sandstone or carbonate unless dipping * Permeability > 1 millidarcy

Bottom Hole Depth/Temperature For miscible di splacement, depth must be great enough to allow injection pressures greater than the MMP b , which increase with temperature and for heavier oils. Recommend depths of CO 2 floods of typical Permian Basin
oils is as follows:

Gravity, oAPI Depth Greater Than (ft)

CO 2 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 CO 2 Screening test

CO 2 immiscible 13 to 21.9 1,800

<13 Fails CO 2 Screening

a Where noted by an asterisk (*), a dapted from Lyons (1996) per c omments 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 CO 2 

### becomes miscible with the oil in place in the reservoir ; it is important t o determine this threshold to effectively identify reservoirs that are candidates for miscible CO 2 

### flooding. A number of

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

Sarma 2005 ) ; Equation ( 1 ) illustrates a sim plified Cronquist correlation

, which provid es a simple

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

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

also takes in to account methane and nitrogen gas molar fraction. It is not applied in this study, but may be appropriate for use in future work considering CO 2 

### - EOR operations employing direct

CO 2 

### recycle (without gas processing for CO 2 

### /hydrocarbon separation)

. This c orrelation 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 f ractions 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 fraction s from 180 to 340 g/mole) is shown in Figure 3

- 1



### .

Figure 3

- 1 Plot of Cro nquist C orrelation for a S eries of C5+ M olecular W eight V alues over the R ange of

T emperatures from 75 to 275 °F

### 15 Increased tertiary incremental oil production observed with increasing CO 2 

### injection and market incentives created by high crude prices have, i n recent years, driven operators to inject higher

CO 2 

### hydrocarbon pore volume (HCPV 3 

### ) fractions. In one case, at the Means CO 2 

### - EOR WAG injection in the San Andres Unit, original CO 2 

### injection targets of 0.55 hydrocarbon pore

volume 2

Figure 3

- 2 

### ( HCPV ) (0.4 HCPV purch ased CO 2 

### , and 0.15 HCPV recycled CO 2 

### ) were increased to approximately one HCPV. Results of reservoir engineering models that demonstrate increased

volumes of CO 2 

### injection show improved reservoir sweep efficiency ( ), which corresponds to higher incremental oil recovery from tertiary EOR ( Figure 3

- 3 

### ).

Figure 3

- 2 Example of O il Recovery E fficiency vs. CO 2 Injectio n ( assumes homogeneous

reservoir ) . Sweep E fficiency in R eservoir P ore V olumes (RVPs) of M iscible CO 2 - EOR F lood

I ncreases with I ncreasing H ydrocarbon P ore V olume (HCPV) I njection.

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

Σ

A * h *φ*( 1

− Swi )

, where A is surface a rea, h is g ross pay thickness, φ is p orosity as fraction, and Swi is initial

w ater saturation as fraction

.

### 16 Figure 3

- 3 Tertiary O il R ecovery I ncreases with I ncreasing CO 2 , B ut A lso I ncreases the R equired

D uration of the CO 2 I njection B efore R ecovery D rops O ff.

3.1.2 Water Alternating Gas (WAG) Tertiary Injection Scheme



### V iscosity of CO 2 

### at formation conditions is significantly lower than tha t of crude oil (CO 2 

### 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

l ess viscous pressure

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

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

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

without stimul ating its production. Any subsequently injected CO 2 

### 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 CO 2 

### 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 CO 2 

### aids in inhibiting the channeling of

less viscous CO 2 

### through the reservoir from injection to production well

, thereby increasing CO 2 

### residence time and improving contact between CO 2 

### and the oil remaining in the reservoir. Tab le

3

- 2 

### provides a simplified representation of selected injection options : continuous CO 2 

### injection,

continuous CO 2 

### followed by water sweep, WAG injection followed by water sweep, tapered

### 17 WAG followed by water sweep, and WAG followed by hydrocarbon gas in j ection and water

sweep.

Table 3

- 2 Simplified Representation of CO 2 - 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

Conti nuous CO 2 i njection

Continuous CO 2 followed by water

sweep
WAG injection followed by water

sweep

T apered WAG followed by water

sweep

WAG followed by HC gas inj ection and water sweep Color key :

CO 2 I njection 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 F ields 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 a nd 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

- place 3



### • 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 re al 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 define d by the equation:

where N is OIIP in stock tank ba rrels

, V b is bulk reservoir volume in acre

- feet, φ is

fraction of bulk reservoir volume that is fluid

- filled porosity, S

w is the fraction of fluid

- filled porosity that is saturated with water, B oi 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 cos ts of implementing CO 2 

### - 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 CO 2 

### - EOR reserves

The database also cont ains sub

- routines containing logic to screen reservoirs based on parameter

data to:

**•** Determine reservoir suitability for CO 2 

### - miscible flooding

**•** Ensure volumetric consistency of reported data

**•** Summarize reservoir miscible and immiscible CO 2 

### - EOR activity and flood volumes

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

domestic CO 2 

### - EOR technology development, including a series of reports entitled Basin Oriented Strategies for CO 2 

### Enhanced Oil Recovery for dome stic resource basins/areas and two technology analysis reports entitled Storing CO 2 

### with Enhanced Oil Recovery , and Storing CO 2 

### and Producing Domestic Crude Oil with Next Generation CO 2 

### - EOR Technology

.



## 3.2 CO 2 

## - EOR as CO 2 

## Geologic Sequestration Mechanism

In add ition to the primary function of CO 2 

### - EOR to stimulate incremental oil production with the benefit of increasing the security of the domestic oil supply, CO 2 

### - EOR may also serve to store anthropogenic CO 2 

### through geologic sequestration. A set of “next genera tion” CO 2 

### - EOR techniques and practices have been proposed to accomplish significant geologic storage of CO 2 

### 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 CO 2 

### - EOR operational scenarios are described in detail in the following sections

. As discussed above,

CO 2 

### - EOR operations are, at present, supplied primarily from naturally

- occurring reservoirs of

CO 2 

### ; p roposed legislati on on emission of greenhouse gasses could dramatically increase the supply of CO 2 

### from anthropogenic sources available for CO 2 

### - EOR with concomitant sequestration

.

3.2.1 Retention vs. Sequestration in CO 2 - Flood EOR


### Terminology used to discuss the fate of CO 2 

### us ed in EOR operations can be somewhat confusing, and warrants discussion. This confusion stems from differences in understanding and

use of the word CO 2 

### “retention.” The EPA’s Proposed Mandatory Reporting Rule (75 FR 16584 [2009

- 4

- 10]) states:

The object ive of EOR operations is not to maximize reservoir CO 2 

### retention rates, but to maximize oil production and the amount of CO 2 

### trapped underground would be a function of site specific and operational factors. There are several EOR operations in the Permian B asin 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 CO 2 

### TSD [ EPA

– HQ

– OAR

– 2008

– 05 08

– 044 ] ).

### 19 While it is true that CO 2 

### - EOR has, traditionally, been concerned with resource production and not maximizing CO 2 

### retention, and retention rates are often well below 100 percent , the statement implies that the fraction of CO 2 

### not retained undergro und 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

dis cussion of retention rates recognizes this fact and states that, regarding a reservoir with 38% retention, “Essentially 100% of the purchased CO 2 

### is still in the system. At the end essentially 100% of the fluid will be stored in a reservoir.” Additionally, evidence suggests that CO 2 

### 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 firs t portion of this quotation states that essentially all of the acquired (purchased) CO 2 

### is stored geologically, and the second portion refers to studies suggesting that this storage might reasonably be expected to exhibit favorable permanence of storage th at 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

- base d examples. To contribute to this clarification,

definitions of CO 2 

### “retention” and “sequestration” in CO 2 

### - EOR are provided, and, in lieu of presentation of case study

- based evidence, a simplified example is provided.

**3.2.1.1** 

### CO 2 

### Retention in CO 2 

### - EOR Operations

The distinction between CO 2 

### “retention” and CO 2 

### “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) define d “retention” to be

the amount of CO 2 

### remaining in the reservoir at any given time, which equals the

amount of CO 2 

### injected less the amount of CO 2 

### produced.

Expressed as a fraction (as in the previously referenced Proposed EPA Rule), this definition

could be written as :

w here injection includes both the newly purchased plus recycled CO 2



### . To calculate this fraction,

units of standard volume or units of mass can be used. CO 2 

### retention is used in evaluating the efficiency of CO 2 

### 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 CO 2 

### to injected CO 2 

### . In both cases, the injected CO 2 

### is the sum of purchased and recycled CO 2 

### . For purposes of this

report , cumulative quantities will be used.

### 20 From the operator’s perspective, CO 2 

### retention during CO 2 

### - EOR operations is considered to be a detrimental factor , as it requires purchase of additional CO 2 

### to accomplish the same total CO 2 

### cumulative injection per well pattern (and the same oil production per well pattern): more CO 2 

### retention can correspond to less efficient utilization of purchased CO 2 

### resource. As defined by industry, “ r etention” does not co nsider the disposition of the CO 2 

### that is not retained in the

reservoir

. However, it is important to note that CO 2 

### that is not retained in the flooded area is not emitted to the atmosphere, but only produced from the reservoir (pattern or field) and avail able for reuse in the same or adjacent CO 2 

### - EOR operations. While the amount of CO 2 

### “retained” per well pattern may be as low as 38 percent (U.S. EPA, 2009), the amount of purchased CO 2 

### that is geologically stored through the period of active injection wil l approach 100 percent (assumes negligible loss in recycling 4

**3.2.1.2** 

### CO 2 

### Sequestration in CO 2 

### - EOR Operations ). Furthermore , the term “retention” refers to the storage of CO 2 

### in

the subsurface over the cumulative period of active injection (per pattern or field) at some point during the period of activ e injection; it does not consider the amount of CO 2 

### that is permanently sequestered

— which considers the amount of retained CO 2 

### that remains stored in the subsurface at some period after completion of active injection. However, the experience in many reser voirs suggests that the two may be very close (Melzer, 2010).

The definition of geologic CO 2 

### sequestration given by the U.S. Department of Energy, National Energy Technology Laboratory (NETL) is as follows:

the pla cement of CO 2 

### 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 (post

injection), and has set a goal of 99 percent storage permanence. S equestration is the geologic storage of CO 2 

### 100 years after the completion of active injection. Storage impermanence takes

into account the amount of CO 2 

### lost to the atmosphere both during the period of active injection and through 100 years of post

- injec tion monitoring, verification, and accounting (MVA) of CO 2 

### storage. For CO 2 

### - EOR, CO 2 

### sequestration is the amount of gross CO 2 

### retained through the period of active injection minus losses. Described as a fraction, this is:

To calculate this fraction, un its of standard volume or units of mass can be used. The term

“ l osses” 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

C O 2 

### leakage to the atmosphere through cap rock and compromised wellbores or plugs 5

4 CO 2 separation and recycle operations are considered as a “tight” chemical process with significant effort made to

m inimize 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 CO 2 be purchased

. 

### .

5 Fugitive losses from gas recycling operations, as well as di rect 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 seq uestration” performance.

### 21 In summary, CO 2 

### 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. CO 2 

### that is n ot “retained” in one pattern is, therefore, available for reinjection into the same or adjacent patterns. CO 2 

### 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 CO 2 

### - EOR operations, nearly 100 percent of the purchased CO 2 

### will be geologically stored at the end of the period of active injection and, with sufficient permanence of

CO 2 

### stor age, at least 99 percent of the stored CO 2 

### 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 CO 2 - EOR Economic and Technical Potential



### R ecent studies published by U.S. DOE NETL and prepared by Advanced Resources International, Inc. ( NETL, 2008; NETL, 2009 ) have defined three CO 2 

### - EOR technology implementation scenarios descriptive of past, present, and likely future CO 2 

### - EOR technology

ap plication. In those reports these scenarios are referred to as:

**•** “ Historical ” CO 2 

### - EOR Flood Practices

**•** “Best Practices” CO 2 

### - EOR

**•** “Next Generation” CO 2 

### - EOR

Progression of CO 2 

### - EOR practice s ha ve generally trended toward increased total CO 2 

### injection

volu mes to achieve increased oil recovery. While , in the past, CO 2 

### - EOR operations took

measures to minimize the purchase of CO 2 

### by applying modest amounts of CO 2 

### and water sweeping the flood after CO 2 

### application to maximize CO 2 

### recovery for re use, best

- pract ices reservoir management calls for additional CO 2 

### injection and allowing retained CO 2 

### to remain in

situ without water slug recovery, and the “ next

- generation ” CO 2 

### - EOR operational scenario further increases formation oil production by increasing CO 2 

### inject ion, modification of reservoir fluid properties, and modification of injection well pattern

. Each of these three CO 2 

### - 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 ” CO 2 

### - EOR

. Historically, t he amount of CO 2 

### injected for tertiary oil recovery has

been limited by the cost of CO 2 

### that is purchased for injection

. As such, relativel y small total injection volumes (as compared with current “best practices” and “ n ext g eneration” scenarios as

defined herein ) were used in early CO 2 

### - EOR. In addition, CO 2 

### contained in the produced fluid was (and still is ) separated, recompressed, and reus ed. Finally, a slug of water is injected into

the formation at the end of the CO 2 

### flood to recover residual CO 2 

### remaining in the formation,

and the recovered CO 2 

### is transported to an adjacent field for use as tertiary EOR solvent. Following water slug in jection for CO 2 

### recovery, an estimated 2,000

- 4,000 standard cubic feet ( scf ) of CO 2 

### would remain trapped in the target formation for each barrel of incremental oil produced. While some CO 2 

### remains trapped following historical CO 2 

### - EOR flood, geologic

seque stration of CO 2 

### is not a goal of CO 2 

### - EOR. Rather, the primary function of CO 2 

### in

historical CO 2 

### - EOR was to maximize tertiary production of oil at a minimum purchased CO 2


### cost.

For purposes of this study, and in keeping with the definition of historical CO 2 

### - EOR as defined in previous CO 2 

### - EOR studies , total cumulative CO 2 

### inject ed over the flood lifetime is assumed

to be 40 percent of total hydrocarbon pore volume (HCPV) in the target formation . Following completion of CO 2 

### - EOR WAG injection, it is assumed that one HCPV of brine is injected to recover as much of the injected CO 2 

### as possible for use at adjacent operations.

“Best Practices” CO 2 

### - EOR Operational Scenario

. High prices of crude oil observed in recent

years

— on July 11, 2008

, light crude prices te mporarily reached $147.27/bbl on the New York

Mercantile Exchange

- symbol CL

— have led to the injection of higher total volumes of CO 2 

### to increase incremental oil production. A series of studies sponsored by the U.S. DOE have

### 23 evaluated the magnitude of C O 2 

### - EOR potential in 10 domestic basins (in 22 states) using best practices CO 2 

### - EOR technology and “best practices. ”

A follow

- on study sponsored by NETL entitled Storing CO 2 

### with Enhanced Oil Recovery (NETL, 2008) built on the series of basin studies, addi ng an additional 500 reservoirs to the

database of domestic CO 2 

### - EOR potential resources, considering a greater variety of oil and CO 2 

### price scenarios, and addressing, for the first time, the domestic CO 2 

### storage capacity using a CO 2 

### - EOR “ best practices” in jection scenario. In these studies, “ b est p ractices” CO 2 

### flood is defined based on a dramatically increased volumetric injection of 1.0 hydrocarbon pore volumes (as compared to 0.4 HCPV total CO 2 

### injection representative of “ historical ” CO 2 

### - EOR operations ). In addition to the increase in volume of CO 2 

### 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” CO 2 

### - EOR includes separation of CO 2 

### from the produced fluid and recycling if for further injection. In

contrast to “historical ” CO 2 

### - EOR operations, “ b est practice s ” assumes that a water slug is not injected at the end of the CO 2 

### flood , and the i njected CO 2 

### is not recovered

.

“

Next Generation ” CO 2 

### - EOR Operational Scenario

. “ N ext generation” CO 2 

### - 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 whi ch would be realized with “best practices” CO 2 

### - EOR

and/or to increase the total number of reservoirs that meet criteria to be considered as a viable

candidate for miscible CO 2 

### - EOR. Technology/operational alternatives considered to represent “next generatio n” CO 2 

### - EOR include:

1. Increase volu m e of CO 2 

### i njection 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 infi ll 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 mobilit y ratio and fluid flow patterns of the

flood ) (Fanchi, 2006)

4. Extending miscibility (decreasing minimum miscibility pressure)

– Liquefied petroleum gas , H 2 

### S, or other interfacial tension reduction elements

– Reduce miscibility requirements by 500 psi (21 reserv oirs)

In the report entitled Storing CO 2 

### with Next Generation Technology (NETL, 2008), this definition of “next generation” CO 2 

### - EOR is used to evaluate magnitude of potential to produce

incremental oil.

Evaluation of Domestic Technically

- and Economica lly

- 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 rec overy potential through application of CO 2 

### - 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 s ubset of 1,600 w as identified as meeting these size, depth, and density

criteria. These candidate reservoirs were then evaluated using a stream

- tube CO 2 

### - EOR model to
estimate technical incremental oil under each of the three CO 2 

### - EOR flood operational scen arios.

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 cru de oil price of $70 per barrel and a

value for CO 2 

### storage of $45 per metric ton ne of CO 2 

### , 60 billion barrels of economically

recoverable oil was estimated

. This amount of CO 2 

### - EOR corresponds to an estimated nine

billion metric ton ne s of CO 2 

### sequestration

. This volume of CO 2 

### is roughly equal to captured

CO 2 

### 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 CO 2 - EOR T echnology S cenarios and D ata S ources U sed in E valuation of CO 2 - EOR S cenarios in S tudies

P reviously P ublished by NETL

Parameter Description Historic al
CO 2 - EOR Best

Practices
CO 2 - EOR Next

- Gen
CO 2 - EOR

Tech 1

Increase
CO 2 HCPV Tech 2

Innovative flood design Tech 3

Increase

Water Viscosity Tech 4 Miscibility

extenders Tech 1

- 4

All Next

gen options Incremental hydrocarbon pore volumes injected 0.4 1 1.5 1 a 1 1 1.5

Number of i njectors 1 1 1 1 1 1 1

Number of producers 1 1 1 2 1 1 2

Viscosity of water (cp) ARI DB b ARI DB ARI DB ARI DB 3 cp ARI DB 3 cp

Minimum m iscibility p ressure (psia) ARI DB ARI DB ARI DB ARI DB ARI DB ARI DB

- 500 ARI DB

– 500

WAG t ype Normal Tapered Tapered Tapered Tapered Tapered Tapered

Water c hase? Yes No No No No No No
( Adapted from U.S. DOE, 2006; NETL 2008a; NETL 2008b; NETL 2009 ).

a Grey cells i dentify next

- generation CO 2 - EOR technologies that are not considered in this study.

b ARI DB=Advanced R esources International Big Oil Fields Database

### 26 Table 3

- 4 Summary of CO 2 - EOR Injection Scenarios as D e fined in P reviously P ublished R eports

Pore volume

injection CO 2 storage rate (mtCO 2 /bbl) a Aggregate impacts of CO 2 - EOR in the U.S.

Crude Oil recovery, (B illion

barrels ) b CO 2 stored (Bmt CO 2 )

Historic CO 2 - EOR **c** 0.4 0.11

- 0.22 10

- 20 1.0

– 5.0

Best Pra ctices **d** 1.0 0.28 45 12.5 e

Next G eneration f 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 CO 2 cost of $45 per metric ton, delivered to the field, and a project IRR of 15% before tax

. b Con version 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 i ndustry heuristics

d “Best Practices” entails 1.0 pore volume CO 2 injection, tapered WAG process, reinjection of CO 2 produced with oil, and a water slug at the
end of the flood recovers residual CO 2

. e ARI estimates that 3.5 billion metric tons of total wi ll be supplied by natural sources and industrial vents. A net of 9 billion mt is the capacity
that will motivate advanced coal with CO 2 capture.

f “Next Generation” entails 1.5 pore volume CO 2 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 sl ug at the end of the
flood to recover CO 2

.

Adapted from U.S. DOE, 2006; NETL 2008a; NETL 2008b; NETL 2009

.

### 27 Table 3

- 5 : Economically Recoverable Oil and CO 2 S equestration C apacity in the C onterminous 48 S tates and Alaska, E stimated B ased on
S tream

- T ube M odeling of B est P ractices and “ N ext G eneration” CO 2 - EO R S cenarios

B asin/Area Best Practices a Next Generation b

Oil produced,

Bbbls c CO 2 stored,
MMmtCO 2 Oil produced,

Bbbls CO 2 stored, MMmtCO 2

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 CO 2 injection, tapered WAG process, reinject ion of CO 2 produced with oil, and no water slug at the end of the flood to recover
CO 2 b “Next Generation” entails 1.5 pore volume CO 2 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 CO 2 . c Economically recoverable resource based on a market price for crude oil of $70 per barrel and a CO 2 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 CO 2 

### - EOR Electricity Requirements

A report published by NETL and prepared by Advanced Resources International, Inc. entitled Electricity Use of Enhan ced Oil Recovery with Carbon Dioxide (CO 2 

### - EOR) provides ranges of unit process electricity demand based largely on input from field operators of existing CO 2 

### - EOR operations ( Van Leeuwen and Ferguson

, 2009 )

. Table 3

- 6 summarizes ranges of electricity demands for three major operations: CO 2 

### re

- compression, artificial lifting of produced fluids

from CO 2 

### - EOR producing wells, and separation of natural gas liquid (NGL) from CO 2 

### 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 CO 2 

### - EOR facility operation.

Table 3

- 6 Range of E lectricity U se at CO 2 - EOR F ields by S ource

Project Component Low Bound Electricity Consumption a Mid Range Electricity Consumption b High Bound Electricity Consumption c

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 separat ion equipment and that injects straight CO 2

.

b A m id

- range field injects greater volumes of CO 2 into the reservoir , or has somewhat i nefficient compression equipment. It requires artificial lift equipment to produce its oil and injects some of its produce d
water in a WAG flood.

c A h igh

- electricity use field injects large amounts of CO 2 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 CO 2 

### - EOR operations. The report also highlights the scarcity of this type of performance data. T he way in which these data a re 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 (CO 2 

### 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 oi l produced )

.

### 29 3.3.2 Literature Review of CO 2 - EOR Environmental Performance



### Several assessments of CO 2 

### - EOR have been reported at technical conferences or in peer

reviewed literature. Table 3

- 7 provides a summary of characterizations that endeavor to describe

CO 2 

### - EOR operatio ns in basins or a specific field the Permian Basin, West Texas. The broad range of estimated CO 2 

### 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 CO 2 

### - EOR practice

. CO 2 

### - 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 scope s or differences in complexity

of model structure.

The m ost reliable estimates of emissions associated with CO 2 

### - 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 Ope rators (SACROC) facility near Snyder, Texas (unpublished presentation Kinder

- Morgan CO 2 

### 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 characterizat ion 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 facto r that will impact operational emissions for CO 2 

### - EOR scenarios with gas processing and recycle is the cumulative injection volume of CO 2



### — commonly reported as

HCPVs of CO 2 

### injected. In current best practice, cumulative CO 2 

### 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 CO 2 

### injection often varies on a pattern

- by

- pattern basis and, as s uch, field

- level CO 2 

### 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 CO 2 

### - 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 C haracterizations of CO 2 - EOR GHG P erformance R eported from

O ther S tudies

Source Scope Location Gross Storage Capacity (kg CO

2 /bbl) GHG

Emissions (kg
CO

2 E /bbl) Net GHG Storage (kg

CO 2 E /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 Perm i a n Basin

type reservoir 409 56 353

Kovscek (2002) Operation Non

- specific 360 n/r b 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 CO 2 

## Prophet CO 2 

## - 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, CO 2 

### Flood in a Light Oil, Fluvial Dominated Del taic Reservoir

, under U.S. DOE

ContractDE

- FC22

- 93BC14960. The CO 2 

### 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 CO 2 

### Prophet model has also been

used in a series of basin

- specific evaluations of CO 2 

### - EOR potential, and for evaluation of “best practices” and “next

- generation” practices technology scenario evaluation studies published by

NETL and summarized in t he body of this report. Finally, the electricity demand for three general geographic CO 2 

### - EOR scenarios (W. Texas, Gulf Coast/Mississippi, and California) were estimated based on production estimates developed using CO 2 

### 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 CO 2 Prophet Screening Model



### The CO 2 

### Prophet model performs two main operations . The model generates streamlines to
describe fluid flow between injection and productio n wells, and then performs oil displacement and recovery calculations along the streamlines using a finite difference routine to calculate oil displacement

. CO 2 

### Prophet handle s areal sweep efficiency by incorporating streamlines that are

a function of we ll spacing, mobility ratio

, and reservoir heterogeneity

. Required input parameters for the CO 2 

### Prophet model fall into the following broad categories:

**•** Fluid property parameters

**•** Reservoir property parameters

**•** Relative permeability parameters

**•** Flood patt ern 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 g ravity of oil, water salinity, and gas

- specific

gra vity. 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 operatio ns 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 CO 2 

### Prophet for simulation of the miscible CO 2 

### process , particularly

CO 2 

### /oil mixing and the viscous fingering of CO 2



### .

The CO 2 

### 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 de fined by the user in the Prophet model

. CO 2 

### Prophet injection parameters can be modified to simulate a variety of recovery processes, including

continuous miscible CO 2 

### , WAG miscible CO 2 

### and immiscible CO 2 

### , as well as waterflooding.

Performance of the CO 2 

### 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 stand ard 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 W ell G eometries Commonly U sed for E nhanced

O il R ecovery

### 33 Table 3

- 8 P roduction W ell to I njection W ell Ratio for a S eries of C ommon EOR W ell

P atterns

Pattern type Drilling Pattern Well Ratio

P roducers : 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 f rom Manning and Thompson (1995)



### Finally, inje ction schedule is a function of operator preference and reservoir injectivity

limitations. As detailed above, t he rate and order in which CO 2 

### and brine are injected in a WAG injection scenario will affect the rate of oil and gas production, time to CO 2 

### br eakthrough, and ultimate resource recovery efficiency of the flood.

### 34 (a) area of 5

- spot well pattern (b) portion of 5

- spot pattern simulated in CO 2 Prophet model

Figure 3

- 5 : Surface Area of a 5

- Spot Well Pattern and Portion Simulated in Prophet Model

Source: CO 2 Prophet Model Documentation (1986)

### 35 3.4.1.1 Estimation of CO 2 

### - Flood Performance Using CO 2 

### Prophet Screening Model

Reservoir parameter values used to define the CO 2 

### - 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 datab a se reports r eservoir 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, Willis ton 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 CO 2 

### - EOR act ivity, and because it holds significant potential f or future domestic tertiary incremental oil production.

I dentifying Representative R eservoir and F luid P roperties for Use in Analysis Scenarios

. Data reported in the AR I “ Big Oil Fields Database” were not used directly to define the reservoir

scenario use d in base case and subsequent scenario analyses of CO 2 

### - 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 CO 2 

### - EOR relative performance under different operational

scenarios . The database was, however, used to identify acceptable ranges of parameter values for a single b asin. Distribution metrics (mean, stand ard 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 F ields” database (based on a nominal sample size of 228 reservoirs).

Table 3

- 9 Fluid P arameter V alues U sed in M odeling of CO 2 - EOR S cenarios and M ean and
S tandard D eviation V alues from ARI D atabase Permian Basi n R eservoirs (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 P arameter V alues U sed in M odeling of CO 2 - EOR S cenarios and

M ean and S tandard D eviation V alues from ARI D atabase for Permian Basin R eservoirs

Parameter Descript ion Parameter

Value Used

in This Study ARI Database

Units No. of samples Mean Std.

Dev. Median

R eservoir temperature 123 228 123.5 35.6 112 oF

R eservoir 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 z one 0.73 224 0.73 0.151 0.75 d imension

- 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 p a y (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. 3 2 228 0.306 0.054 0.30 fraction (0

- 1)

I nitial gas saturation value in all segments 0

- a a a fraction (0

- 1)

a Not reported in ARI database, default value from CO 2 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 va lues

from the CO 2 

### Prophet model are used except where noted. A complete list of relative permeability parameter assumptions are listed in Appendix A

. Defining Flood Schedule in “Hi storical,” “State

- of

- Art,” and High CO 2 

### WAG CO 2 

### - EOR

Scenarios

. In additi on to fluid, reservoir, and relative permeability parameters, it was also

necessary to specify the volumes and timing of injection of water and CO 2 

### for each CO 2 

### - EOR operational scenario. The specific injection schedules used in previous studies to evaluat e each

CO 2 

### - 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” CO 2 

### - EOR, as defined in DOE Basin

- S pecific CO 2 

### - 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” CO 2 

### - EOR flood

. This scenario calls f or injection of a water slug following completion of CO 2 

### WAG injection in order to recover remaining mobile oil and a small amount of CO 2 

### that will be used in less mature and nearby

patterns

.

### 37 Table 3

- 11 : Injectio n S chedule P arameters U sed in D efining “ H istorical ” M iscible CO 2 - flood EOR in the CO 2 Prophet S creening M odel

Parameter Description Cycle a Units 1 2 3 4

Water/CO 2 Injection Ratio

- 1.0 2 .0 inf. HCPV:HCPV
Incremental hydrocarbon pore
volumes CO 2 injected. 0. 2 0. 1 0. 1 0 HCPVs of CO 2
Injection rate of water, in surface units (SURF BBL/D) - 5 62 5 62 5 62 surface bbl/day

Injection rate of CO 2 , in surface units (MM scf /D) 1.24 1.24 1.24

- MM scf CO 2 /day

a All injection cycle s reported in terms of volu me, as opposed to time.



### As defined in previous studies (NETL, 2008) and summarized earlier, “ best practices ” CO 2 

### - EOR operational scenario involves injection of significantly higher volumes of CO 2 

### to increase sweep efficiency and improve incremental oil rec overy over that which could be accomplished using “historical” injection design. To model this scenario, a total CO 2 

### injection of 1.0 HCPV was specified , with injection performed using WAG process. In contrast to the historical CO 2 

### - EOR scenario, no water slug is applied at the end of WAG injection. Model pa rameter s selected to describe “best practices” WAG injection scenario are summarized in Table 3

- 12

.

Table 3

- 12 : Injection sched ule parameters used in defining “ best practices ” miscible
CO 2 - flood EOR in the CO 2 Prophet screening model

Parameter Description Cycle a Units 1 2 3 4

Water/CO 2 i njection r atio

- 1.0 2 .0 3.0 HCPV:HCPV
Incremental hydrocarbon pore
volumes CO 2 injected 0.2 5 0. 25 0. 25 0 .25 HCPVs of CO 2
Injection rate of water, in surface units (SURF BBL/D) - 5 62 500 5 62 surface bbl/day

Injection rate of CO 2 , in surface units (MM scf /D) 1.24 1.24 1.24 1.24 MM scf CO 2 /day

a All injection cycles reported in terms of volume, as opposed to time.



### Modeling High

- CO 2 

### Injection Scenario

As described above and detailed in a previously published NETL report entitled Storing CO 2 

### with Next Generation Technology

, the “next generation” CO 2 

### - EOR technology scenario calls for increased inj ection 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 CO 2 

### recycling. “Next generation” CO 2 

### - EOR scenarios requiring infill well placement , or polymer addition to in crease water viscosity to 3 centipoise, or miscibility extenders are not considered in this study. As with “best practices” CO 2 

### - EOR (and in contrast to “historic” CO 2 

### - EOR), the “next generation”

scenario does not call for a water slug to be injected follo wing completion of the CO 2 

### slug

, allowing more CO 2 

### retention in the formation than would be observed with “chase” water sweep

. I njection schedule defining the high CO 2 

### injection scenario considered in this study is detailed in

Table 3

- 13

.

### 38 Table 3

- 13 Injection S chedu le P arameters U sed in D efining 1.5 HCPV CO 2 M iscible WAG
EOR in the CO 2 Prophet S creening M odel

Parameter Description Cycle a Units 1 2 3 4

Water/CO 2 i njection r atio

- 1. 0 2. 0 3 .0 HCPV:HCPV
Incremental hydrocarbon pore
volumes CO 2 injected. 1 0. 4 0.4 0. 4 0. 3 HCPVs of CO 2
Injection rate of water, in surface units (SURF BBL/D) 1 - 562 562 562 surface bbl/day

Injection rate of CO 2 , in surface units (MM scf /D) 1 1.24 1.24 1.24 1.24 MM scf CO 2 /day

a All injection cycle s 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 CO 2 

### - EOR scenarios. T he 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 CO 2 

### - 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 CO 2 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: historica l, best practices, and 1.5 HCOV CO 2 

### WAG injection . Plots of incremental and cumulative injection of water (thousands of standard barrels [ MSTB ] per year) and CO 2 

### (millions of standard cubic feet
[ MM scf ] per year) define the injection schedule appropriate for each scenario. Incremental production estimates for all fluids (oil, brine, CO 2 

### , and hydrocarbon gas) are also plotted. These model inputs and outputs serve as the basis on which estimates of incremental oil and gas production, CO 2 

### storage potential

, fluid processing infrastructure requirements, processing resource demands, and environmental emissions have been developed.

### 40 Figure 3

- 6 Incremental W ater I njection S chedule for WAG I njection S cenarios (MST B water/year)

### 41 Figure 3

- 7 : Incremental CO 2 Injection Schedule for WAG Injection Scenarios (MMscf CO 2 /year)

### 42 Figure 3

- 8 Cumulative CO 2 Injection Profile for WAG Injection Scenarios (MMscf)

### 43 Figure 3

- 9 Cumulative W ater I njection P rofile for WAG I njection S cenarios (MSTB)

### 44 Figure 3

- 10 Cumulative O il P roduction P r ofile for WAG I njection S cenarios (MSTB)

### 45 Figure 3

- 11 Cumulative W ater P roduction P rofi le for WAG I njection S cenarios (MSTB)

### 46 Figure 3

- 12 Cumulative CO 2 P ro duction P rofile for WAG I njection S cenarios (MM scf )

### 47 Figure 3

- 13 Incremental O il P roduction for WAG I njection S cenarios ( MSTB/yr )

### 48 Figure 3

- 14 Incremental W ater P roduction for WAG I njection S cenarios ( MSTB/year ). Dotted line in historical CO 2 - EOR scenario represents brine production response after initiation of water slug.

### 49 Figure 3

- 1 5 Incremental CO 2 P roduct ion for WAG I njection S cenarios ( MM scf /year )

### 50 Figure 3

- 16 Incremental H ydrocarbon G as P roduction for WAG I njection S cenarios (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 CO 2 

### injection ( Table 3

- 14 ), in agreement with the previously discussed field observations and the adopted definition of CO 2 

### - EOR scen arios.

Table 3

- 14 Oil R ecovery E fficiency ( P ercent of O riginal O il in P lace R ecovered) as

E stimated B ased on CO 2 Prophet S creening M odel C haracterization of T hree WAG
S cenarios

CO 2 - EOR Scenario HCPV CO 2 In jected Oil Recovery, %

OOIP Single Pattern Flood Duration (years)

Historical 0.4 11.6 17

Best Practices 1 17.4 25
1.5 HCPV CO 2 WAG Injection 1.5 20.9 36



### Average f luid 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 M odel R esults for I njection and P roduction S tream F luid F low

R eported on a per P attern Y ear B asis (40

- A cre, 5

- S pot P attern C onfiguration)

Parameter CO 2 - EOR Operational Scenario

Units Historical Best

Practices 1.5 HCPV CO 2 WAG
Water Injected 157.0 123.3 119.8 MSTB/(pattern

- yr)

CO 2 Injected 106.4 180.9 185.5 MM scf /(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)

CO 2 Produced 63.9 127.7 147.6 MM scf /(pattern

- yr)

HC Gas Produced 9.1 9.7 8.1 MM scf /(pattern

- yr)

Total Gas Produced 73.0 137.4 155.7 MM scf /(pattern

- yr)



### Produced flu ids 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 , CO 2 

### , 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

process es flow from a number of producing we lls.

### 52 Calculated Produced Fluid Loading to Tank Battery from 10 CO 2 

### - EOR Patterns

It is assumed that produced fluid from ten CO 2 

### - 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 t ank 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 initiate s fluid injection at six

- month intervals, thereby dis tributing 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 CO 2 

### - EOR patterns of approximately 10

- 20 percent of the tot al flood duration (approximately 3

- 6 years for the next

generation EOR scenario considered herein )

. Figure 3

- 17

, 3

- 21

, 3

- 22 , and 3

- 23 illustrate the incremental production rates of total fluid, oil, water, CO 2 

### 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” CO 2 

### - EOR practices.

### 53 Figure 3

- 17 Incremental O il P roduction D ata from 10 W ell P atterns O perated U nder T hree WAG S cenarios

, with I njection I nitiated at S ix

- M onth I ntervals for E ach P attern (MSTB/year)

### 54 Figure 3

- 18 Inc remental W ater P roduction D ata from 10 W ell P atterns O perated U nder T hree WAG S cenarios

, with I njection I nitiated at S ix

- M onth I ntervals for E ach P attern (MSTB/year)

### 55 

## 3.5 Phases of CO 2 

## - EOR Facility Operation

Five phases of CO 2 

### - EOR facility life have been consi dered :

**•** 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



### E nhanced oil recovery operations have take n place at sites where ex tensive 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

c ould serve as a conduit for leakage of CO 2 

### from target formations, thereby decreasing CO 2 

### - EOR effectivene ss, decreasing overall CO 2 

### storage , and creating a hazard to human health. Therefore, it will be appropriate to review well files, regulatory m aps 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 whe ther or not an existing well

can be used as a CO 2 

### /water injection well or production well in proposed CO 2 

### - EOR operations. In addition, to visual inspection, mechanical integrity testing of old wells may be performed to establish utility of existing well s 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 sur face 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 CO 2 

### - 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. I t 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 i n CO 2 

### - EOR operations ( U.S. EPA,

2008 ). Emissions associated with airborne and survey ha ve been considered. It is assumed that

abandoned wells located within the area of review are plugged to prevent CO 2 

### leakage from the

### 56 target formation and prevent deter ioration 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 h erein. The assumed n umber 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 CO 2 

### - EOR scenario. Values are 0.00368

, 0.00250 , and

0.00184 abandoned wells per pattern year for historical, best practices, and 1.5 HCPV CO 2 

### WAG injection scenarios, respectively. Well

- plugging diesel

- fuel demand and emissions per pattern

year are reported in Table 3

- 16 for each operational scenario.

Table 3

- 16 Emissions P rofile from A bandoned W ell P lugging O perations R eported per

40

- A cre P atter n Y ear B ased on O perational S cenarios D escribed H erein

Historical Best

Practices 1.5 HCPV CO 2 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

NO X 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

SO 2 2.25E

- 06 1.53E

- 06 1.12E

- 06 kg per pattern year

CO 2 33.35 22.7 16.7 kg pe r 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 CO 2 

### - EOR Facility Overview

The CO 2 

### - EOR facility is considered to include all surface infrastructure eleme nts 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 fro m CO 2 

### recycle stream ) . Infrastructure elements associated with delivery of CO 2 

### 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 patte rn 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 CO 2 

### - Flood EOR

It has been assumed that the reservoirs for which CO 2 

### flood tertiary EOR would be considered

are sites that have already unde r gone 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 prepara tion . 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 :

**•** CO 2 

### distribution lines

**•** Gas processing facility

**•** Recycle CO 2 

### compressor s

**•** 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 Cl asses

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 t ypes of fluid injected, constr uction 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 II I wells are used for solution mining. Class IV wells are specified in rare cases where hazardous or radioactive wastes a re 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 CO 2 

### into reservoirs that do not contain significant quantities of hydrocarbons to demonstrate geologic sequestration of anthropogenic CO 2 

### (for example, in brine aquifers). A Class VI well type has been proposed by the EPA to formalize regulatory requirements of dedicated anthropogenic CO 2 

### disposal through geologic sequestration (GS) not associated with oil and gas production. In July 2008, the EPA published the f ederal

### 58 r equirements for CO 2 

### GS wells u nder 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 Cl ass 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 CO 2 

### - EOR activity, and it is assumed that new wells must be constructed for disposal of this byproduct stream. Salt water 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 CO 2 

### - EOR operations as to not impact fluid pro duction 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 CO 2 

### - 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 CO 2 

### - EOR operations, injection wells are drilled into oil bearing reservoirs capable of accepting injection fluids (i.e., CO 2 

### , water) to stimulate oil production. Brine and acid gas disposal wells are also sometimes required to

m anage 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 con fining 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 al so 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 s ections 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 b e 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 CO 2 

### - EOR operations.

**3.5.2.5** 

### Estimation of Brine Disp osal 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 estim ated 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

. On e 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 10 6 

### cubic meters (1.3 billion liters, or 8.2 million barrels , and assuming a

br ine 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 cu mulative storage capacity of 1.3 billion liters is assumed, but t his 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 brine

injection wells that will be required to accept excess brine produced as a result of CO 2 

### - 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 fr ictional 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 . Ap plying 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 hydrosta tic 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 CO 2 

### - EOR in the Pe rmian Basin , fields have safely accommodated higher surface injection pressure than that specified by the default fracture gradient, where as operations in other basins have not (Melzer, 2010).

3.5.3 Well Drilling and Completion



### Oil production, injection, and f luid 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 flu id transfer

**•** Rotat e 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 oper ations. 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 tu rn 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.

Consi deration 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 drilli ng 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 f oot 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 dri lling rig is estimated using rig number 472 ( http://patdrilling.com/pdf/rigs/472.pdf), which operates with

two Caterpillar 3 408 engines (475 HP each) . Specifications for major rig element s are summarized in Table 3

- 17 ; additional detail is provided in Appendix F

.

Table 3

- 17 Specifications U sed to C haracterize D rill R ig

Rig Element Equipment Description

Power p lant (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 t able 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 well head 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

- stri ng, 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 CO 2 

### injection.

Injection well design is assumed to be the same as that used for CO 2 

### 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 settin g 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 9 5 

### / 8 

### - inch surface casing is cemented along the full length. The injection well is completed with a 51⁄2

- inch production casing string (a lso cemented between outside of casing pipe and 7 1 

### / 8 

### inch drill hole wall along the deep

- section length of 5,826 feet), and 2 7⁄8

- inch tubing installed inside the protection casing through which injected fluid is conveyed to the target reservoir.

Table 3

- 18 Specifications U sed to C haracterize I njection W el l: C asing, I njection T ubing,

and D rill P ipe

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

Surf ace casing 0

– 2,600 9 5⁄8 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 2 7⁄8 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 usi ng 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 flui ds from the injection target formation to overlying drinking water aquifers and the surface, a s well as providing isolation of the pressured formations from anything but the wellbore. The v olume 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 sac k 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 ft 3 

### /sack of cement. Volume of the cement is

estimate d to be approximately 1

, 722 ft 3 

### (49 m 3 

### )

— the space between eac h 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

sack s 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 char acterized by estimating the number of heavy

- rig truck round trips to deliver all drill rig elements, assuming a round trip distance of 5 0 miles. The rig is assumed to be of modular design, with each module

delivered to the well site in a single tractor tr ailer load . Based on drill rig layout blueprints available online ( Integrated Drilling Equipment, 2004 ) , an estimated 25 skid

- mounted rig

elements are d elivered by a single tractor trailer

. This count is assumed to include drill pipe required for drillin g, 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 , Por tland 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

remov al 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 af ter 2001 as specified in

EPA AP

- 42 , Appendix H , and reported in Table 3

- 19

.

Table 3

- 19 Emissions E stimate for D elivery of R ig E lements to D rilling S ite

Pollutant Emis sions

F actor 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
NO X 6.490 g/mile 15.6 U.S. EPA AP

- 42

CO 2 10,084 g/gallon

diesel 3,899 U.S. EPA

“Emissions Facts” (200 9)

### 63 **3.5.3.5** 

### Operation of Drill Rig

Operational p arameters for the drill rig specified above with two 475

- horsepower diesel engines

are summarized in Table 3

- 20

.

Table 3

- 20 New W ell D rilling R ig P erformance S pecifications

Parameter Value Units

Drilling time 10 days of continuous operation (504) D ays (hours)

Rig p ower p lant 2 x 475 No. engines x horsepower Engine load factor 0.75 unitless

Break

- specific fuel consumption 0 .367 lb/hp

- hr

Emissions performance M eets 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 estimate s 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 d uring 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

- take

down 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 E stimate for D rill R ig O perated in N ew W ell C onstruction for B rine

D isposal

Constituent Metric T onnes ( S hort

T on) per W ell E rilled

Total Hydrocarbon 0.0285 (0.031 5 )

CO 0.131 (0.144)

NO X 1.05 (1.1 6 )

PM Total 0.022 1 (0.0243)

PM 10 0.0214 (0.023 6 )

PM 2.5 0.000662 (0.000730)

CO 2 90.7 ( 100 )

SO 2 0.13 9 (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

- b ased m ud is used in all drilling operations. The c omposition of the assumed drill mud is reported in Table 3

- 22

.

Table 3

- 22 Range of W ater

- B ased D rilling M ud C omposition as R eported by Eaton and Colleagues (1981), and A verage C omposition A ssumed for D rilling M ud U sage C alculations

Component Concentration Range, kg/m 3
(lb/bbl) per Eaton et al. (198 1) Average Mud Concentration (value assumed for this

study) , kg/m 3 (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 ft 3 

### (88 m 3 

### ) per well , the following total mass of mud components is estimated

. The m ass 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 M ass of D rilling M ud and M ud C omponents, and E stimated M ass and C omposition of U sed M ud for D isposal

Component Estimated M ass of W ater

- B ased

M ud R equired to D rill a S ingle

W ell, M etric T onne ( S hort T on) Estimated M ass of

D ewatered U sed M ud

M anaged as W aste
F ollowin g D rilling of a

S ingle W ell, 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

recirculat ion 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 dispos al 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 ft 3



### . At the end of drilling operations, it is assumed that drilling mud is dewatered, cha racterized, 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 CO 2 

### - EOR WAG injection or disposed of in adjacent brine disposal well.

Drilling Mud Deg assing CH 4 

### 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

press ure. 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 method ology reports default factors for total hydrocarbons (THC) and methane emission s 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 CH 4 

### per drilling day (0.2605 metric tonnes

CH 4 

### per drilling day) (API, 2009). Non

- methane hydrocarbon emissions are, therefore, 307.53

lb non

- methane hydrocarbon s per drilling day (0.1395 metric tonnes non

- methane hydrocarbon s per drilling day). Using the aforementioned 10

- day drill ing time , emissions per well drilled are

estimated at 2.605 metric tonnes of CH 4 

### and 1.395 metric t onnes of non

- methane VOC

. Existing Well Recompletion Prior to CO 2 

### - 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 CO 2 

### - EOR, it is not possible to develop a single characterization th at appropriately represents all cases. For purposes of this study it has been assumed that reworking of existing waterflood production and injection wells for CO 2 

### - EOR (the first rework following

### 66 waterflood operations and prior to initiation of CO 2 

### - EOR ope rations) 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 befor e initiation of CO 2 

### - EOR operations, it

is assumed that all wells ( one injection and one producing well per pattern) will require

workover during CO 2 

### - 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 N umber of W ell W orkovers R equired over the L ife of CO 2 - EOR

P attern O perations for E ach O perational S cenario

CO 2 - EORScenario Years of

O peration

of S ingle

W ell

P attern Number of

I nitial

W orkovers

per P attern Number of M aintenance

W orkovers R equired

over O perational L ifetime (excludes initial workover) Total Number of Workovers Required
Over Life of CO 2 - 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
CO 2 Injection 36 1 (x 2) 8 (x 2 ) 18



### Assumptions that have been made in characterizing workover activities are summarized in T able

3

- 25

.

Table 3

- 25 Summary of A ssumptions M ade to C haracterize W ell W orkover P rior to

I nitiation of CO 2 - EOR F looding

Workover Parameter Value Units Workover rig horsepower 475 hp Workover rig load fa ctor 0.75 unitless Assumed average

workover duration 36 (3 days @

12 hours/day) hours

Environmental

p erformance Meets Tier 3

emissions

standards -

Brake

- s pecific f uel

c onsumption 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 D iesel U sage from W orkover R ig O peration

Constituent Emission from
S ingle W ell

W orkover prior

to I nitiation of
CO 2 - EOR U nits

HC 2.14E

- 0 3 (2.36E

- 0 3) Metric tonnes (sho rt tons)

CO 1.70E

- 0 2 (1.88E

- 0 2) Metric tonnes (short tons)

NO X 3.21E

- 0 2 (3.53E

- 0 2 ) Metric tonnes (short tons)

PM Total 1.66E

- 0 3 (1.82E

- 0 3) Metric tonnes (short tons)

PM 10 1.61E

- 0 3 (1

. 7 7E

- 03 ) Metric tonnes (short tons)

PM 2.5 4.97E

- 0 5 (5.47E

- 05) Metric tonnes (short tons)

CO 2 6.80 ( 7

. 50 ) Metric tonnes (short tons)

SO 2 1

. 04 E

- 2 (1

. 1 5E

- 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, in direct

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 dur ing workover operations. Fugiti ve emissions associated with workover operations were estimated using the US. EPA AP

- 42 emissions factor of 96 scf of

CH 4 

### /workover (U.S. EPA, 1995).

Table 3

- 27 Estimate of M ethane F ugitive E missions from W e ll W orkover over the L ife of

a S ingle W ell P attern for E ach O perational S cenario U nder C onsideration

CO 2 - EOR
Scenario Number of

W orkovers per

W ell pattern over

L ifetime of S ingle

EOR F lood Fugitive M ethane

E missions from

W orkovers over

L ifetime of S i ngle

E OR F lood P attern (scf M ethane / P attern ) Mass of M ethane

, kg (lbs) per EOR P attern **a**

Historical 6 576 10.9 ( 24.02 )

Best Practices 10 960 18.17 ( 40.03 )

1.5 HCPV CO 2 WAG 14 1

, 344 25.44 ( 56.05 )

a Based on 0.0417 lb/ft 3 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 CO 2 

### - EOR flood site are controlled using “wet suppression” practice s

— applying water to the road surface to keep it wet. In contrast,

### 68 methods of “chemical sta b ilization” require chemical application to modify the physical properties of the unpa v ed road surface to decrease particulate emissions. Water application conglome rates 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 fac tors 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 Particul ate 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:

(2 a )

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 emissio n 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 P articulate E missions ( C ontrolled) from C onstructi on T raffic on

U npaved R oads, and D ust S uppression W ater C onsumption R ate per P attern Y ear

Parameter Historical Best

Practices 1.5 HCPV CO 2 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 Particulate s 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 m 2 

### , 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 dus t 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 p er well

- pattern year was calculated and is reported in Table 3

- 29

.

**3.5.3.6** 

### Fluid Distribution and Gathering Lines

CO 2 

### Distribution System. The CO 2 

### distribution system is analogous in scale and infrastructure makeup to the gathering systems used for natural gas, with CO 2 

### distributed from a central “hub”

to the CO 2 

### injection site through a system of smaller pipelines (ARI, 2006). Typical p ipeline size ( diameter and wall thickness ) is a function of the maximum injection requirements for a site ( Melzer, 2010 )

.

**•** 4” pipe (CO 2 

### rate less than 40MMcf /d)

**•** 6” pipe (CO 2 

### rate of 40 to 60 MMcf/d)

**•** 8” pipe (CO 2 

### rate of 60 to 8 0 MMcf/d)

**•** P ipe greater than 8” diameter (CO 2 

### rate greater than 80 MMcf/d)

**•** D istance from the CO 2 

### “hub” (trans fer 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 CO 2 

### , required CO 2 

### 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 in ternal d esign pressure, thousand psi (kpsi), ( 2 .2 kpsi)

D = pipe outside diameter, inches (assuming 4 inch nominal pipe, with 4 .5 inch OD)

S = s tress v alue for material (in tension) as a function of operating temperature, kpsi (f or 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 T P 316L s eamless 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 CO 2 

### 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 CO 2 

### - 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 CO 2 

### distribution pipeline can be approximated to be the square root of the developed CO 2 

### study area

.

Table 3

- 30 Estimation of M ass of ANSI S chedule 80 S tainless S teel P ipe R equired per 10

W ell P atterns for CO 2 D istribution

CO 2 Distribution

Element Pipe

T hickness,

I nches (ANSI

Schedule) Unit W eight of

P ip ing Estimated M ass of P ipe, M etric T onnes ( S hort T ons)

lb/ft lb/mile per 20 square miles ( based on 4.5 miles of each size pipe) p er square mile

4” stainless steel pipe 0.337 14.9 78,672 161 (177) 8.0 ( 8.8 5)

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 estima te emissions associated with production of these steel

CO 2 

### - EOR infrastructure elements

. E missions associated with installation of CO 2 

### 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 CO 2 

### - EOR activity because these infrastructure elements are required for secondary water flood EOR that would have already taken place at sites where tertiary CO 2 

### - EOR activity is being initiated. As such, inventory of resource demands

and emissions for br ine 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 facilit y 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 pl ant 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 MM cf/day. This corresponds

to estimated st eel 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

co nstruction 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 t o characterize natural gas processing plant construction is considered to be adequate. This is noted as data limitation.

Table 3

- 31 : Estimate of E missions A ssociated with G as P rocessing F acility
C onstructio n M aterials U pstream P rofile

Pollutant Mass of P ollutant,

M etric T onnes ( S hort T ons)

CO 2 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 CO 2 

### - EOR facility operations phase is based on modeled flood performance under historical, be st practices, and next

- generation scenarios designed previously. Fluid production rates and compositions estimated as a result of specified CO 2 

### and brine injection schedules serve as the basis from which infrastructure size, throughput, process energy inp ut 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 th is LCA as described above does not include bulk CO 2 

### transport to the EOR reservoir site from the CO 2 

### source. Each of these four areas of operation is

considered in more detail below

.

**3.5.5.1** 

### Pat tern

- Year Concept

Total gate

- to

- gate emissions associated with CO 2 

### - EOR activity can be estimated through a relatively straightforward summation of emissions from individual activities contributing to t he

### 73 overall life cycle profile. However, relating the a ctivity 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 conce pt of the pattern

- year is introduced. Pattern

- year describes the number of years of operation of each CO 2 

### - EOR well pattern. As described earlier, the length of CO 2 

### WAG injection for each scenario varies as a function of the total volume of fluid ( CO 2 

### and water) injected and injection rate. For the historical, best practices, and 1.5 HCPV CO 2 

### WAG injection scenarios as defined in this report, each pattern flood operates for 17

, 2 5, and 36 years, respectively. Operation of one well pattern as a historical CO 2 

### - 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 CO 2 

### - EOR scenario accepts 170 pattern

- years of produced l iquids. When operated under a 1.5 HCPV CO 2 

### WAG scenario, the tank battery

accepts 360 pattern

- years of produced fluid. Finally, a well pattern operated under the historical

CO 2 

### - EOR scenario produces an average of 73.0 MM scf of total gas per pattern year ( 0. 2 MM scf per pattern day) over the pattern flood lifetime. At this production rate a gas processing facility accepting 45 MM scf of total gas per day is capable of accepting gas from approximately 225 well patterns operated under the historical CO 2 

### - EOR sc enario. 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 CO 2 

### - EOR injection

is provided by water produced from EOR activity within the oil field (stored produced brine

fro m adjacent EOR t ank batteries) . Validity of this assumption has been evaluated by comparing

the total volume of brine produced fr om each injection scenario with the total volu me 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 CO 2 

### - EOR operations except for the end (chase water) period . This justifies that, in the case of the average

bas in considered in this report and under the assumed operational scenarios, CO 2 

### - 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 CO 2 

### - EOR opera tions will require management. It is assumed that brine that is produced in excess of that which is used in

the CO 2 

### - 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 B etween C umulative P roduced I njected W ater ( CO 2 Prophet model results)

CO 2 - EOR
Scenario Volume of E xcess P roduced

B rine ( C umulative O ver L ifetime

of S ingle P attern F loo d ) (MSTB)

Historical 100.8

State

- of

- art 246.0

1.5 HCPV CO 2 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 Unive rsity 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 wel ls having a hole size of 7 7 

### / 8 

### inches in diameter and tubing

between 2 3 

### / 8 

### and 2 7 

### / 8 

### inches . Their a nalysis of reported maximum injection pressure gradient (injection pressure/tubing depth) demonstrated that essentially all wells operate below or near hydros tatic gradient

. ( The maximum surface injection pressure is a function of desired bottomhole pressure and tubing diameter and length, with s maller diameter tubing having greater frictional loss because a greater proportion of the fluid is in contact with t ube

. )

Water Injection Pump Electricity Requirements
The simple equation to estimate pump brake horsepower requirement shown below (Perez et al., 2009) wa s applied based on an assumed suction pressure of 14.7 psi a , an assumed wellhead discharge pressure o f 3 14 .7 psi a ( 300 psig) , and a mechanical efficiency of 70 percent . Volume of fluid flowing to the injection well is estimated by results of CO 2 

### Prophet model runs of historical, best practices, and high CO 2 

### WAG scenarios

.

(5)

w here

BHP = pump brake horsepower Q = volume of fluid pumped

P d 

### = discharge pressure

P

s 

### = suction pressure

ME = mechanical efficiency (typically between 65

- 75 percent )

### 75 Table 3

- 33 Estimated T otal E lectricity D emand O ver the L ife of CO 2 - EOR F lood
O perations to P ressurize B rine for WAG I njection, R eported for a S ingle W ell P attern

CO 2 - EOR
Scenario Estimated Electricity Demand for Water Injection O ver Lifetime of
CO 2 - EOR O perations for S ingle

P attern (40

- acre, 5

- spot)

Historical 3,832

Best Practices 4,756

1.5 HCPV CO 2 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 CO 2 

### for Injection

Initially, CO 2 

### is assumed to be supplied to the site by a pipeline that transport s CO 2 

### from naturally

- occurring CO 2 

### reservo irs, large anthropogenic CO 2 

### point sources, or a combination

thereof. As CO 2 

### - EOR floods pro gress and CO 2 

### breakthrough is observed, CO 2 

### 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 pro cessing facility and that pressure used to drive distribution and injection operations.

Boost compression is required to raise the CO 2 

### feed stream to target injection pressure of 2200 psig ( Meyer, no year referenced). CO 2 

### is supplied to the flood from a combination of two

sources: CO 2 

### that is purchased from a large pipeline, and CO 2 

### that is recycled from produced fluid stream. The purchased CO 2 

### is assumed to arrive at the site at a pressure of 1,500 psig (Meyer, no year referenced ), and the CO 2 

### recycle d from CO 2 

### - EOR operations leaves the gas processing plant at a pressure of 2,000 psig. The pressure of the CO 2 

### feed stream is, therefore, calculated as the weighted average pressure as a function of the fraction of CO 2 

### supplied from

each source. These fr actions are given in the equations below :

(6)

(7)

Based on this calculation method, mean supplied CO 2 

### pressures for historical, best practices, and high

- CO 2 

### volume injection scenarios were 169 0, 1 800, and 18 50 psi, respectively. Boost compression electricity requirements were, therefore, highest on a per

- tonne of CO 2 

### injected basis in historic cases, but the smaller amount of CO 2 

### injected in historical cases as compared to other scenarios means that the total compression energy requirements will b e lower on a per

flood pattern basis. Boost compression energy requirements were estimated simply as the change in pressure divided by the product of CO 2 

### 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 P arameters U sed in C alculating CO 2 B oost C ompression

R equirements, and R esults of C alculation R eported on a per P attern

- Y ear B asis

CO 2 - EOR Scenario Historical Best Practices 1.5 HCPV CO 2 WAG Injection

Fraction of stored to injected CO 2 (%) 51.4 33.7 25.2

CO 2 f eed p ressure (psig) 1,800 1,853 1,8 91

Pressure at i njection

w ellhead (psig) 2,200 2,200 2,200

Ave rage flood CO 2 feed rate (tonnes/pattern year) 5,629 9,573 9,972

Estimated average electricity demand to boost compression (M J /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 free

flowing well production. A rtificial 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/liqu id separation (gas expansion chamber), water/oil separation (water knock out), and

oil/water emulsion separation (heater treater)

. In CO 2 

### - EOR fields that produce relatively large volumes of hydrocarbon gases in their produced gas streams, operators may ch oose to install equipment to separate hydrocarbon gas from CO 2 

### so that the separated hydrocarbon stream can

be sold

. In this study it has been assumed that CO 2 

### /hydrocarbon separation will be carried out using the Ryan

- Holmes process for distillative separ ation to remove acid gasses ( CO 2 

### and H 2 

### S) with a propane or butane additive.



### Artificial Lift

Under favorable conditions, it may be possible for fluid to be produced, in CO 2 

### - EOR operations,

from free

- flowing wells. While free

- flowing production wells off er obvious cost, energy demand, and maintenance advantages, artificial fluid lifting is, more often, required

, with approximately 80 percent of all CO 2 

### - 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 CO 2 

### - EOR activity. While in practical application the selec tion 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 o perations (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 regu lar repair and maintenance, it can, with proper care, r emain 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, reservo ir 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 CO 2 

### - EOR flood operators reveals that electricity

- driven lifting

power accounts for between 10 and 30 percent of the electrici ty use by a CO 2 

### - 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 elec tricity requirements for CO 2 

### - 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 W ell P attern A rtificial L ift E stimate for CO 2 - EOR S cenarios E stimated

U sing ARI m M id

- range E lectricity E stimate of 5 kWh/bbl for H istorical CO 2 - EOR and 10
kWh for B est practice s and N ext

- G eneration CO 2 - EOR S cenarios

CO 2 - EOR Scenario Single Pattern

Total Oil

Production

(MSTB) Assumed ARI

R eported 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 CO 2 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 requiremen ts to drive artificial lifting based on estimation of horsepower demand.

Artificial Lift Electricity Demand Characterizat ion 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 HP PM 

### = horsepower of prime mover
D = net lift of liquid in feet

PMF = prime mover factor , with

PMF = 135,735 when SG is 1 a nd lifting with 100 percent efficiency

G enerally PMFs are 1.8 to 3 times smaller than 135,735 . F or high slip NEMA D motors or

slow

- speed internal combustion engines, recommended prime mover HP can be calculated from:

HP PM 

### = q*D/56000 . For high

- speed internal combustion engines or normal slip NEMA C motors, prime mover HP suggested is: HP PM 

### = 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

, 8 26 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 CO 2 

### - EOR flood progresses, the required horsepower to lift flu id will also vary. To address this, the vol ume of total fluid was estimated for each year in which

the CO 2 

### - EOR flood is produc ed, t he 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 E lectricity R equirement for A rtificial L ift for S ingle W ell P attern as
C alculated B ased on E stimated A rtificial L ift P rime M over H orsepower R equirement

CO 2 - 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

L iquid P roduced (kWh / bbl liquid)

Historical 3.83 20.0 1.3
Best practices 4.76 15.8 1.3

1.5 HCPV CO 2 WAG 6.46 17.8 1.3



### These results are significantly higher

, on a kWh/bbl o il 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 artific ial 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 f rom 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 mad e 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 CO 2 

### - flood tertiary EOR fluid flow. In all scenarios conside red in this report , it is

assumed that the liquid

- gathering lines that are used for CO 2 

### - 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 B**  **attery 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 sa le. 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 perfor mance 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 fro m 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 CO 2 Prophet CO 2 - 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

pe rform these functions include :

**•** H eater/treater

- Heat s water/oil emulsion to separate oil, water, and gas. (atmospheric

or pressurized three

- phase vessel.)

**•** G un barrel or wash tank

- Separates oil, water, and small amounts of gas. (atmospheric, thr ee

- phase vessel)

**•** S tock tank

- Store s crude oil that is to be sold (atmospheric pressure)

**•** W ater storage tank

- S tores produced water prior to disposed or re

- injection (atmospheric pressure)

P arameters listed in Table 3

- 37 h ave 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

facil ity configuration. These values will impact facility performance and environmental emissions, and are used in th is LCA to estimate performance of each unit process.

### 80 Table 3

- 37 Process E lement A ssumptions M ad e in C haracterization of CO 2 - EOR

P roduced L iquids P rocessing

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 Performan ce 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 desi gned to d irect all produ ced fluid to a central facility or to separate bulk gas before sending liquid water and oil stream on to central battery and bulk gas ( CO 2 

### and hydrocarbon gas) to a gas processing facility . F oregoing satellite separation of bulk

ga s 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 sat ellite 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 compos ition, crude oil sales specifications, water quality specifications, and site layout.

For purposes of this study, i t is assumed that fluid produced from five CO 2 

### - EOR well patterns passes through a primary satellite separator where bulk gas is separated fr om 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 s atellite separators servicing ten tank batteries is collected to a secondary water/oil/gas separator. At this stage nearly all of the free water 6

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

behavi or described by Stokes' Law. in the fluid is separated and transported to water storage tank. Oil, water/oil emulsion, and a small

fracti on 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
diamet er , 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 f or oil gravity above 35 ° API one minute liquid

retention time is recommended , average flow from five patterns can be proc essed through a gas/liquid separator (also assum ing e ffective 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, a nd a small fraction of free water) is moved to a heater/treater vessel i n 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

, emuls ion heating for mechanical separation is typically in the range of 100 to 120 °F. The water

oil 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 addit ion 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 9 8 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 E stimate Heater/T reater Fugitive E missions



### AP

- 42 specifies methane emissions from heater

- treater to be 19 scf of CH 4 

### per day per heater,

and 0.319 scf CO 2 

### per day per heater. This corresponds to production rate s of 6935 scf of CH 4 

### per year for a single heater treater, and 116 scf of CO 2 

### 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 CO 2 

### and reinjected (this option is not
considered in this report )

. These emissions estimates offer only a coarse estimate of CO 2 

### 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 c rude treating te mperatures and r ates based on tables provide d by Manning and Thompson (1995) suggest a required emulsion heating temperature and treating rate (assuming mechanical emulsion separation) of 140 °F and 57 bpd/ft 2 

### . Based on this treatment rate,

c alculated heat duty for a heater treater firetube burner is on the order of 1 MMB tu /hour. In all

CO 2 

### - 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 h ave 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 meta ls,

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 Thompso n (1995) presen t ed below :

Heat Duty (btu/day) = (Q oil 

### * Cp oil 

### + Q water 

### * Cp water 

### )* ΔT * (1 + heat loss) (9)

w here Heat duty = heat duty of heater/treater in btu of natural gas per day Q oil 

### = daily flow of oil to heater/treater, barrel of o il per day Q water 

### = daily flow of water to heater/treater, barrel of oil per day

ΔT = change in temperature between influent stream and vessel , °F Cp oil 

### = Saybolt viscosity of oil

, S a ybolt second units ( SSU ) Cp water 

### = Saybolt viscosity of water

, SSU

Heat loss = percent v essel heat loss ( for a well

- insulated vessel, assumed to be 2 percent )

To estimate total emissions over the life of CO 2 

### - EOR operations from natural gas combustion to heat water/oil emulsion at a single tank battery (for each operational sc enario), an average annual heat duty was calculated for each year of operation for each CO 2 

### - EOR operational scenario using assumptions listed in Table 3

- 38

.

Table 3

- 38 Assumptions U sed in E stimation of H eater/ T reater F iretube H eat D uty. In addition to these parameters, the flow of oil to the heater/treater was estimated for each year of CO 2 - 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 o f

CO 2 

### - EOR flood operation) to determine the total heat duty (calculated for each CO 2 

### - 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 CO 2 

### - E OR operation from 10 CO 2 

### - 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 E nergy R equirement of F iretube U sed T o H eat H eater/ T reater
S ervicing 10 CO 2 - EOR W ell P atterns

Parameter Historical Best Practices 1.5 HCPV CO 2 WAG Injection Units

MMBtu required

ove r life of CO 2 - EOR operations
for heater/treater firetube (tank battery supplies
10 CO 2 - 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 C ombustion E missions from H eater/ T reater F iretube O peration for

a U nit S ervicing 10 W ell P attern s O ver the L ife of the CO 2 - EOR F lood

Constituent Historical Best Practices 1.5 HCPV CO 2 WAG Injection Unit s

GHGs

CO 2 14,500 13,500 12,100 kg/(pattern*year)

Methane 0.28 0.26 0.23 kg/(pattern*year)

N 2 O 0.27 0.25 0.22 kg/(pattern*year)

Criteria Air Pollutants

NO X 1 2 .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)

SO 2 0.07 0.07 0.06 kg/(pattern*year)

VOC 0.6 7 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 discu ssed elsewhere, these emissions are assumed to be controlled largely through installation and operation of a vapor recovery unit at the stock tank battery. Uncontrolled t ank 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, an d flashing losses from the

heater/treater are summarized in Table 3

- 41

.

### 84 Table 3

- 41 Design A ssumptions U sed in E stimating H eater/ T reater V essel W orking,

B reathing, and F lashing E missions

Parameter Value Units

Vessel d iameter 6 ft

Vessel h eight 12 ft

Max imum h eat d uty 500 Mbtu/hr
Target liquid r esidence time range 1

- 4 hours

Total v olume of heater/treater v essel 60 ft 3

Fraction of total volume as working volume 0.66 ft

Effec tive working volume of heater/ treater 40 ft 3

### 85 Table 3

- 42 Estimate of W orking, B reathing, and F lashing E missions from H eater/ T reater V essel T hat A re C ollected to the

V apor R ecovery U nit

CO 2 - EOR
S cenario Tank
Contents Flash Losses ( kg /tank

- year) Working

Losses ( kg /tank

year) Breathing

Losses ( kg /tank

year) Total L osses
per T ank per

Y ear ( kg /tank

year)

Historical Water Oil

Emulsion 125,900 3062 58. 4 129,000

Best Practices Water Oil

Emulsion 132,3 00 3059 58. 4 135,400

1.5 HCPV CO 2 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, CO 2 

### , and hydrocarbon gas wi thin the tank battery prior to transfer from lease operations to the pip e line 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, i t
has been assum ed 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 e stimated 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 volu me)

. 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 CO 2 

### - EOR scenarios, a ran ge 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 decrease s in gas solubility wh en 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 re sult 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

w orking losses were estimated using E PA 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 (determin ed as a function of site location). Crude oil storage tank s pecifications used in development of standing and working

loss estimates are summarized in Table 3

- 43

. It has been assumed that the vessel contains crud e 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 AS TM

- D

- 323

— a value differing slightly from a liquid’s true vapor pressure.

### 87 Table 3

- 43 Specifications U sed in C alculation of W ell T ank E missions

Parameter Value Units

City , State Midland

- Odessa

, Texas -

Type of Tank: Vertical Fixed
Roof Tank -
Shell Height (ft): 15 Feet Diameter (ft): 1 2 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

- Sh ell Condition : Good

- Roof Color/Shade: Grey/Light

- Roof Condition: Good

- Roof Characteristics Type: Dome

- Height (ft) 2 .00 F eet 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 CO 2 

### - EOR scenario, and that flow rate was applied t o 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 operatio nal tank

- years (number of tanks in operation per year times the number of years each

tank is in o peration) over the life of the CO 2 

### - EOR flood (a value that varies for each CO 2 

### - 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 B tu /scf vapor gas s ample 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 H ydrocarbon G as R eleased from C rude S torage T ank O ver L ifetime
of 10 P attern T ank B attery O peration s (an estimated 95% of this vapor is collected by a VRU)

CO 2 - EOR
Scenario Total Tank Releases Throughout CO 2 - EOR Operation, lb
VOC

His torical 1,404,000

Best Practices 2,187,000

1.5 HCPV
CO 2 WAG Injection 2,689,000

### 88 Table 3

- 45 Summary of C rude O il T ank E missions E stimate ( working and breathing losses estimated using EPA Tanks model, flas hing losses estimated using the Vasquez

- Beggs equation)

CO 2 - EOR
Scenario Tank
Contents Tank

- Years
in 10

- well

T ank B attery

F ull EOR

P erformance Average
Number of

Turnovers

per Y ear per T ank Average

T hroughput

per T ank per

Y ear (stb/tank

year) Estimate d Tank Emissions ( kg /tank

- year)

Flash

Losses Working

Losses Breathing

Losses Total

L osses
per T ank

per Y ear

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
CO 2 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 st orage 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 associat ed with fluid storage in those vessels have not been considered.



## 3.7 Produced Water Tank CH 4 

## Emissions Estimate

After water produced to the surface from CO 2 

### - 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. M ethan e contain ed in produced water is of a significantly small er concentration than that entrained in an equivalent volume of produced oil,

since CH 4 

### 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 th e 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 CH 4 

### per 1000 bbl produced wate r) and the value reported for upstream separator pressure of 50 psig and produced water salt content of 20 percent (0.0015 tonnes

CH 4 

### /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 CH 4 

### 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 P roduced from B rine S torage T anks and C ollected by VRU or

R eleased to A tmosphere

— R eported on per P attern

- Y ear B asis (40

- acre, 5

- spot well pattern )

Parameter Historical Best

Practices 1.5 HC PV CO 2 WAG Injection Units

Volume methane
from brine tanks 12,900 10,600 10,000 scf CH 4 /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 pressure s and temperature s 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 atmo sphere 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

evolve d 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 fa rthest 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 return ed 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 ad justed 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 ca tastrophic 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 a re already equipped with VRUs ( Melzer, 2010).

In general, the volume of v apor 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 configur ation, 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 ta nks and

heater/treater vessel s using the U.S EPA TANKS version 4.0.9d, as described above. Flashing

### 91 losses resulting from sudden decrease s in gas solubility when fluid is transferred from higher to lower pressure and/or lower to higher temperature conditi ons are estimated using the Vazquez

Beggs 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 collect ed by the VRU is estimated to be 524, 328, and 346 M scf per pattern year of 2000 btu/scf vapor for historical, best practices, and high CO 2 

### - EOR operational scenarios, respectively. Table 3

- 47 summarizes vapor recov ery and methane/non

methane 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 rec overy, vapor is transported to a solid desiccant dehydrat ion unit prior to sale

, or for

on

- site use

, ( Sidebottom and Richards, 2009) or recycling ( Melzer, 2010 )

.

Table 3

- 47 Summary of V apor R ecovery U nit P erf ormance for E ach O perational S cenario

C onsidered, R eported on a per P attern

- Y ear B asis (40

- acre, 5

- spot patterns in all cases)

Parameter Historical Best Practices 1.5 HCPV
CO 2 WAG Injection Units

Volume vapor

recovered 486 538 492 M scf 2000 btu/cft gas pe r (pattern

- yr)

VRU e lectricity u se 15,200 14,100 13,400 MJ electricity used per pattern

- yr HHV of r ecovered

v apor 1, 025,000 1,134,000 1,038,000 MJ recovered vapor per pattern

- yr Mass v apor

r eleased 3, 483 3,854 3,528 lb vapor released per pattern

- yr Mas s CH 4 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 T ank B attery V apor C omposition for 2000 B tu/scf HHV G as C ol lected by V apor R ecovery U nit

Constituent Mol % Volume % Weight % MW (g/mole) HHV (MJ/kg) Density (lb/ft 3 )

N 2 4.7 4.7 3.7 28.01 0 0.0727

O 2 0.7 0.7 0.6 3 2

. 00 0 0.0 831

CO 2 0.2 0.2 0.2 44.01 0 0.1142

CH 4 46.3 46.5 21.0 16.04 55.5 0.0416

Ethane 10.1 1 0.1 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 0.150 9

n

- butane 6.2 6.2 10.2 58.12 49.5 0.150 9

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 48.7 7 0.223 6

Tank Battery Vapor 99.7 100.0 100.0 35.47 49.6 4 0.093 7
Tank Battery NM

- VOC

fraction 47.8 48 74 53.36 49.6 8 0.138 9

Calculated from reported as

- received vent gas sampl e (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

characteri zation of tank battery operations (accepting liquids from 10 specified CO 2 

### - EOR patterns), the calculated required triethylene glycol circulation rate was sufficiently low to justify replacement of a liquid desiccant system with a solid desiccant dehydratio n 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 soli d desiccant systems are fully enclosed, they have significantly lower overall emissions, only releasing CO 2 

### and CH 4 

### when the system is opened to replace spent desiccant. API greenhouse gas emissions methodology document cites a 2003

EPA Gas STAR Lessons L earned 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

P 2 

### = gas pressure, psia

P 1 

### = 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 V alues U sed in e E stimation of V enting E missions from S olid

D esiccant D ehydration S ystem

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/y ear) Volumetric packing efficiency , % 45 Vessel gas CH 4 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 M scf/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

CH 4 

### /p attern

- 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 CO 2 

### - EOR operations contains both CO 2 

### and hydrocarbon (HC) gas

. The fraction of HC gas contained in th e 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 CO 2 

### - EOR production and tapers off as CO 2 

### breakthrough increases and total hydrocarbo n production decreases

. The handbook of the CO 2 

### Predictive Model ( Ray and Muñoz, 1986) specifies a threshold gas production rate of 5.0 MMCF/day, below which CO 2 

### - EOR operations gas processing is assumed to include only dehydration and recompression of

wh ole gas. However, modern floods have examples in which the volumes of recycle gas are dramatically higher and no NGLs are removed. Nonetheless, CO 2 

### - EOR operations with daily flows greater than this threshold were assumed to process produced gas by full h ydrocarbon gas separation and recycle of concentrated CO 2 

### for reinjection. An early summary report on CO 2 

### - EOR prepared by the National Petroleum Council ( Bailey and Curtis, 1984) identifies a peak total gas production rate threshold of approximately 20 MM s cf /day above which CO 2 

### - 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 CO 2 

### stream separation and recycle, and that CO 2 

### - EOR operations will require construction of a dedicated gas

- processing facility with separation of CO 2 

### , recycle of

concentrated CO 2 

### , dehydration and sale or combustion of gas, and recovery of NGL.

Figure 3

- 19 CO 2 - PM M odel E stablished a P eak T otal G as P roduction T hreshold of 2 0

MM scf / day A bove W hich a CO 2 - EOR O peration W as A ssumed to R equire C onstruction of

a D edicated G as P rocessing F acil ity

Figure source: Bailey and Curtis (1984)

### 95 3.9.1 Characterization of Ryan

- Holmes CO 2 Separation and NGL Recovery



### The Ryan

- Holmes process is a distillation separation process that separates natural gas liquids (NGLs) from a CO 2 

### stream by taking advantage of the difference in dew point between CO 2 

### 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 resul ts from the compression of refrigerant that is used to cool the separation column. In CO 2 

### - EOR operations, t he primary function served by the Ryan

- Holmes

p rocess is considered to be the separat ion of CO 2 

### from mixed gas stream, while generation of NGL produ ct represent s a secondary function; the primary product is CO 2 

### that is recycled to

CO 2 

### - 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 CO 2 

### - EOR carbon dioxide separation a nd 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 CO 2 

### - 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 CO 2 

### is recycled to CO 2 

### - 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 liqui ds (NGLs) are collected to a storage tank and transported periodically offsite by truck for sales.

Bulk gas produced from CO 2 

### - EOR operations enters the facility through a metering facility, undergoes primary gas filtration/separation to remove any entraine d 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 CO 2 

### - EOR product gas stream before being cycled to a second vessel where m oisture

- 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 ne gligible. Dehydrated CO 2 

### - 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 CO 2 

### 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. CO 2 

### - rich vapor is compressed and combined with liquid CO 2 

### product, while light hydrocarbon

- rich vapor is sent to the de

- methanizer. Liquid from the PRC reflux accumulator is

either sent to CO 2 

### recycle pipeline pumps, or returned to reflux the PRC. The PRC column bottoms are composed of heavier components (mostly C 5+ 

### ) that are transported to the gas/gas exchanger for use as an additive to facilitate hydrocarbon separation. Natural gas liquids d rawn from the middle of the PRC column are cooled to 120 °F, combined with excess C 5+ 

### additive,

### 96 and sent to the NGL storage tank. Natural gas used to power the plant is drawn from the de

methanizer overhead

The Ryan/Holmes Process uses a propane refrigera tion 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 ec onomizer 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, a nd 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 compr essors 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 turb ine 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 p rocess components and related fuel

use.

**3.9.1.2 R**  **yan**
**- Holmes Process**  **Stream Flow Calculations** 



### Estimation s 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/comp ression process is approximately the sum of produced CO 2 

### and produced hydrocarbon gas from CO 2 

### - 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/ft 3



### .
Based on CO 2 

### - EOR flood screening model results summarized in Section 3.4.2

, the volume s of

CO 2 

### and hydrocarbon gas generated (MM scf ) over the life of flood operation were predicted for a single well pattern . From these data, the average total gas product ion per year of pattern operation were calculated for each operational scenario. As mentioned previously, t he Whiting Dry Trail Gas Plant has a reported plant throughput capacity of 4 5 MM scf per day ( Milligan, 2007). The average rate of total gas product ion (CO 2 

### + 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 CO 2 - EOR B ulk P roduced G as ( CO 2 + hydrocarbon gas) S upplied

to G as P rocessing F acility

CO 2 - EOR
Scenario Average Daily

G as P roduction (CO 2 + HC gas) per Well Pattern Day,

MM scf / Pattern

Day Average Annual

G as P roduction (CO 2 + HC gas)

per Well Pattern per Year

, MM scf / Pattern

Year Number of Well Patterns Served by Single 4 5

MM scf /day G as P rocessing P lant

Historical 0.200 73 225

Best

Practices 0.376 137.4 120

1.5 HCPV
CO 2 WAG Injection 0.426 157.7 106

**3.9.1.3 Estimation of Produced Hydrocarbo**  **n Gas Composition**



### Results of CO 2 

### Prophet model runs provide estimates of the volume hydrocarbon gas generated

as a result of CO 2 

### - EOR operations, but do not provide details on properties of the mixed hydrocarbon gas. To estimate an appropriate gas composit ion, 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 a verage gas compositio n 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 l ess than 100 percent gas composition (98.5 percent ). To account for this, the mean value and standard d eviation for each

constituent were multiplied by (100 percent /98.5 percent ) to adjust to 100 percent total volume

. Calculated adjusted average gas com position 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

wi th API Gravity Between 32.5 ° and 37.5 °

Hydrocarbon
Gas Constituent Formula Mean Composition (wt %) **a** S tandard

D eviation

Methane CH 4 72.34 18.73

Ethane C 2 H 6 12.21 10.33
Propane C 3 H 8 4.02 4.05

Butanes C 4 H 10 1.27 1.48

Pentanes C 5 H 12 0.50 0.62

Hexanes Plus C 6 H 14 0.24 0.45

Carbon Dioxide CO 2 1.75 6.55
Hydrogen Sulfide H 2 S 0.62 3.14
Nitrogen N 2 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 m ean higher heating value from these 53 samples was 1141.6 btu/ft 3 

### , with a standard

deviat ion of 217.0 btu/ft 3 

### ( D atabase 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 o f 0.70 (air specific gravity is 1.0). The g as composition estimate arrived at in this manner is assumed to be representative of the hydrocarbon gas composition generated by CO 2 

### - EOR activity in the model

reservoir

. As is shown in reservoir production esti mates, the fraction of whole produced gas that is hydrocarbon gas of this composition will change over time as CO 2 

### breakthrough increases and hydrocarbon production trails off. The gas composition specified above and the degree of

dilution with CO 2 

### as spe cified by CO 2 

### 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 previ ously detailed combustion equipment specifications, manufacturer emissions data, EPA AP

42 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

MM B tu/hour hot oil heater were based on manufacturer’s data, wh ich report emissions factors of

0.08 lb NO X 

### /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 wer e 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 CO 2 

### emissions were based on an

EPA emission factor of 2778 grams of CO 2 

### 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 c ombustion

of 16.85 MM scfy 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)

. CO 2 

### emissions for flare gas combustion also assume 98 percent combustion e fficiency, and use an

emission factor of 134.46 lb CO 2 

### per MM B tu 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 H 2 

### O). Milliga n (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 throu ghput 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 M scf fugitive emissions per blowdown, a molecular weight of 41.81 lb/lb

mole, and an estimated VOC content of 3.8 percent ( Milligan, 2007).

### 100 Table 3

- 52 S ummary of C ombustion E quipment U sed to P ower B as P rocessing F acility or C ontrol H ydrocarbon E missions

Description Number
of Units Description Hours of Operation

Per Year Fuel Type Fuel Usage

Rate MM B tu/

Y ear/ U ni

t MM B tu/

Y ear F or A ll U nits Height, (feet) Di ameter (inches)

Flare 1 Intermittent
off

- spec gas and blowdown

combustion N/A Flare gas 1,209 MMscf/year N ot used
for work N ot 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 (92 4

B tu/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

Diesel a 57 gal/hr 7,497 7,497 30 12

Hot Oil Heater 1 13.48

MM B tu/hr 8

, 760 Natural Gas (924

B tu/scf) 13.48

MM B tu/hr

Superior 2416G Compressor Engine (operated at 728 °F w/OC) 2 3,200 hp 8

, 760 Natural Gas (924

B tu/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

B tu /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 Fa cility

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 Sea ls Light Liquid 9 Heavy Liquid 6

Other s a 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.

Ta ble 3

- 54 Gas

- P rocessing F acility S torage T ank V olumes

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 NO X (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/OC a 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 G as P rocessing F acility E missions

Emissions Source NO X CO VOC SO 2 a C O 2 b

lb/hr TPY lb/hr TPY lb/hr TPY lb/hr TPY TPY

Flare c

--- 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 Engi ne 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 SO 2 /MM scf ) except for the diesel engine which is based on fuel sulfur content of
0.5 %S.

b Based on CO 2 emissions factor of 13.446 lb CO 2 /BTU of natural gas and 2778 grams CO 2 per gallon of diesel consumed with 99%

diesel combustion efficiency

c Natural gas flare CO 2 emissions assumes combustion efficiency of 98% as estimated by Mill igan (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 auth ors 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 , CO 2 

### recovery to recycle

stream of over 90 p ercent , 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 CO 2 

### 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 conside red 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)

Constitue nt Feed G as F low R ate,

moles/hr Fuel G as P roduct F low rate, moles/hr CO 2 R ecycle
S tream F low rate, moles/hr NGL

P roduction

R ate,
moles/hr

CO 2 793.3 4.2 715.1 a 20

H 2 5

- 4 ppm 5

CH 4 214.2 199.2 15

-

C 2 H 6 110.9 8 102.9

C 3 H 8 94.8 0.1 0.3 94.4

C 4 116.8 0.7

- 116.1

N 2 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 g as

- 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 Separati on Efficiency of Ryan

- Holmes Process (percent mass)

Constituent Mass P ercent of

I nfluent S tream
R eporting to Fuel

G as (% mass) Mass %

I nfluent
S tream
R eporting to
CO 2 R ecycle

G as (% mass) Mass Percent of

I nfluent S tream

R eporting to

NGL S tream (% mass)

Ca rbon Dioxide (CO 2 ) 0.5 9 7.0 2.5

H 2 0.0 0.00 100.0

Methane (C 1 ) 93.0 7.00 0.00

Ethane ( C 2 H 6 ) 0.0 7. 2 92. 8

Propane ( C 3 H 8 ) 0.1 0.3 99. 6

Butanes(C 4 ) 0.6 0.0 99.4

Nitrogen (N 2 ) 100.0 0.0 0.0



### These calculated percent recovery estimates were modified to i nclude 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 fracti ons reporting to the NGL product stream, removal of H 2 

### (no H 2 

### 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 CO 2 

### - EOR

flood in the CO 2 

### stream.

Table 3

- 59 Estimate of Mass Allocation of Each Influent Gas Constituent Fraction Between Products of the Gas Processing Facility

Constituent Mass P ercent of

I nfluent R eporting

to F uel G as (% mass) Mass Percent

I nfluent

R eporting to
CO 2 R ecycle

S tream (% mass) Mass Percent of

I nfluent

R eporting to

NGL S tream (% mass)

Carbon dioxide ( CO 2 ) 0.5 97 2.5

Helium (He) 0.0 100 0.0

Methane (C 1 ) 93 7 0.0

Ethane ( C 2 H 6 ) 0.0 7 9 3

Propane ( C 3 H 8 ) 0.1 0.3 99. 6

Butanes(C 4 ) 0.6 0.0 99.4

Pentanes (C 5 ) 0 0 100

Hexanes Plus (C 6+ ) 0 0 100

Nitrogen (N 2 ) 100 0.0 0.0



### It is assumed that the H 2 

### S concentration in the CO 2 

### - EOR produced gas is negligible in all

scenarios considered in this report . In cases where si gnificant concentrations of H 2 

### S 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 Clau s plant to pro duce 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 + CO 2 

### ) collected from CO 2 

### - EOR operations, estimat e s of gas processing plant product mass flow rates and composition s were developed ( Table 3

- 60 

### )

.

Table 3

- 60 Average Mass Composition of Gas Recycled to CO 2 - EOR Operations

Constituen t Recycled CO 2 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 N atural G as and N at ural G as L iquids P roduction from Ryan

- Holmes

P rocess

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/ scf a 818 758 713 MMBtu of natural gas produced per pattern

year 7,690 8,260 6,860

MM scf natural gas equivalent produced per pattern

- year b 7.54 8.09 6.72

Natural Gas Liquids Btu/lb m, HHV 6,900 4,300 3,300
MMBtu/short ton 13.8 8.67 6.60

a Assumes density of 0.417 lb/ft 3 at 20 °C, 1 atmosphere

b Based on natural gas h igher 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 CO 2 - EOR Recycle Stream Through Ryan

- Holmes

Process

Const ituent Mass S eparated O ver L ife of CO 2 - EOR F lood per W ell

P attern

, S hort T ons Historical
CO 2 - EOR Best Practices
CO 2 - EOR 1.5 HCPV WAG
CO 2 - 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 Displacemen**  **t Credit for Energy Coproducts**



### In addition to production of the primary crude oil product of CO 2 

### - EOR activity, natural gas and natural gas liquids are also generated as coproducts. In determining the environmental life cycle profile associated with gate

- t o

- 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 pr ofile 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 CO 2 

### recycle/gas pro cessing 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 nat ural 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 CO 2 

### - 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 barrel s of oil equivalent), and no displacement credit for coproducts would be applied.

Accounting for Natural Gas Liquids Coproduct

### 108 Characterization of natural ga s liquids for dev elopment 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 estimate s that U.S. Production of propane/propylene is approximately hal f 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 CO 2 

### - E per bbl of LPG or 0.477 kg CO 2 

### - E per kg of LPG

.

Table 3

- 63 Displacement C redit for N atural G as L iquid C oproduct s of O il P roduction in
CO 2 - EOR E stimated as the A verage of D omestic R efinery L ight E nds and NGLs P roduced

at a G as
- P rocessing P lant

Pollutant Units Refinery L ight

E nds C radle

- to

G ate of refinery Natural G as L iquids
C radle

- to

- G ate of natural

gas processing plant

CO 2 kg / bbl liquefied gas 60.9 5.33

CH 4 kg / bbl liquefied gas 0.515 0.105

N 2 O kg / bbl liquefied gas 1.30E

- 3 2.88E

- 4

CO 2 E kg / bbl liquefied gas 74.2 8.04

CO 2 E kg / kg LPG 0.861 0.0933

Contribution to

o verall (national average) profile % 50 50



### Accounting for Natural Gas Coproduct

C omposition and volume of natural gas generated as a coproduct of CO 2 

### - EOR operations is the

sum of gas collected from tank battery vapor and gas processing facility minus th at which is used

in CO 2 

### - EOR operations. Any amount not consumed in CO 2 

### - 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 CO 2 

### - EOR operational scenario resul ts 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

- CO 2 

### injection scenarios consume more natural gas than they produce, requiring 0.66 MM scf an d 1.38 MM scf 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 pu rchased to supply CO 2 

### - EOR operations . The emissions profile for natural gas is based on a purchased, proprietary dataset and cannot , therefore, be reported.



## 3.10 Facility Closure and Decommissioning

Following CO 2 

### - EOR , it is assumed that no additional oil recov ery or CO 2 

### 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 sit e re

- vegetation. In this analysis, resource requirements and emissions associated with well plugging operatio ns; emissions and resource requirements associated with EOR infrastructure removal and site reclamation (regarding an y re

vegetation) have not bee n considered. Also, it has been assumed that no spills or subsurface

contamination occurred as a result CO 2 

### - EOR operations, and no site remediation is required.

3.11 P lugging and Abandonment of W ells

Potential conduits for leakage of CO 2 

### to the surface or subs urface 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 d epth

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 t ruck

- , 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 sy stems 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 i n operation 12 hours a day for an estimated 3 days of cementing per well ( Watson et al., 2002)

.
For well s 5,826 feet in depth, and reservoir s 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 c ementing p er w ell p lug 3 days

Hours of c ementing 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 U nitless

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

NO X 128.2 kg NO X per patter n

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

CO 2 27,215 kg CO 2 per pattern

SO 2 0. 00 18 kg SO 2 per pattern

Cement

Demand 56.7 Metric tonnes cement per pattern

Water
Consumed 26.1 Metric tonnes wa ter per pattern



## 3.12 Site Monitoring, Verification, and Assessment

NETL has established geologic storage permanence goal s of demonstrating 95 percent and 99

percent CO 2 retention by 2008 and 2012, respectively. This corresponds to maximum leakage of one and five percent of injected CO 2 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 monito r CO 2 

### plume migration, verify CO 2 

### reservoir storage integrity, and account for the amount of CO 2 

### 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 CO 2 

### can serve as a safe and effective GHG control strategy.

While CO 2 

### - EOR metho dology has employed some sophisticated reservoir surveillance to assure

that CO 2 

### was performing its intended function, it has not historically employed MVA techniques

to a degree that may be required for sequestration. T h us, i t is assumed that, going forw ard, increased monitoring of CO 2 

### - EOR facilities will become more robust so that the operator can claim a credit for storage of CO 2 

### . As such, a simplified characterization of CO 2 

### - 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 cl osure. 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 perfo rmance for three CO 2 

### - EOR operational scenarios are discussed with respect to environmental performance, resource demand, crude oil production, byproduct and coproduct production , and trends observed with increasing CO 2 

### injection.



## 4.1 Single CO 2 

## - EOR Well Patter n Performance

For each CO 2 

### - EOR operational scenario, performance was estimated based on stream

- tube modeling of tapered water alternating gas (WAG) CO 2 

### /brine injection in a post

- water flood,

Permian Basin

- type reservoir conditions. The model is based on a tapered WAG CO 2 

### /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 generat ed 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 CO 2 

### - EOR pattern is used to estimate the size of processing equipm ent 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 CO 2 

### - EOR 40

- acre
, 5

- spot well pattern performance for each operational

scenario. On an absolute basis, both crude oil production and CO 2 

### retention are shown to increase with increasing CO 2 

### injection. Considering only flood performance data suggests that

increased CO 2 

### injection will provide the best option for both CO 2 

### storage and oil production. Subsequent discussion of gate

- to

- gate life cycle environmental performance provides a more complete perspective on CO 2 

### - EOR flood performance, which leads to a different conclusion

about the relativ e merit of these CO 2 

### - EOR operational scenarios for crude oil production and environmental performance.

Table 4

- 1 Summary of CO 2 - EOR F lood P erformance for the O perational S cenarios

D efined Herein , and P redicted U sing the CO 2 Prophet S tream

- tube M odel

CO 2 - EOR
Scenario HCPV
CO 2 Injected Oil Recovery Cumulative Excess Brine Production,

MSTB per W ell

P attern CO 2 Stored Per Pattern,

M etric T onnes % OOIP MSTB

per W ell

P attern

Historical 0.4 11.6 191.4 100.8 38, 200

Best

Practices 1 17.4 301.7 246.0 70,300

High CO 2 Injection 1.5 20.9 360.9 240.0 77,800

### 112 

### 4.1.1 CO 2 

### Retention Performance of Single Well Pattern

Performance of the CO 2 

### - EOR flood as predicted by the CO 2 

### Prophet model shows that the stimulation of oil prod uction is greatest in early years of flooding. Similarly, storage of CO 2 

### in the formation is greatest early in the CO 2 

### - EOR flood, with very little additional storage achieved in later years (for the CO 2 

### - EOR operational scenarios considered). In Figure 4

- 1 , cumulative

mass of CO 2 

### sequestered (calculated as the difference between cumulative CO 2 

### injected and produced) is plotted as a function of time for each of the three CO 2 

### - EOR operational scenarios

considered.

Figure 4

- 1 CO 2 retained in a single 40

- acre , five

- spot CO 2 - 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 CO 2 , by mass

.


### In all CO 2 

### - EOR operational scenarios, the bulk of the geologic storage potential is realized early

in the W AG injection; data reported in Table 4

- 2 further detail this observation

.

### 113 Table 4

- 2 Summary of Single Pattern CO 2 Retention Performance. In all operational scenarios, 75 percent of maximum CO 2 storage potential is realized in the first t hird of flood operation.

Historical Best Practices 1.5 HCPV CO 2 WAG

Years to 50% of m ax.

r etention 1 2 2

Years to 75% of m ax.

r etention 2 6 8

Pattern Life (years) 17 25 36

Max retention (metric
tonnes CO 2 ) 49,500 70,300 77,800

Ultimate r etention a 38, 200 70.300 77,800

a Historical CO 2 - EOR scenario includes post WAG injection water slug to recover CO 2 , so the mass of CO 2 ultimately retained is less than the maximum that was stored prior to water slug injection.



### Figure 4

- 2 illustrates the CO 2 

### sequestered at the end of the flood as a function of the total amount

of CO 2 

### injected. This plot illustrates the trend of diminishing CO 2 

### storage benefit with higher

CO 2 

### throughput. Portions of the reservoir that have been swept with CO 2 

### earlier in the flood take up less additional CO 2 

### as the injection proceeds. Since high CO 2 

### throughput is also associated with increased gas processing activity, higher CO 2 

### injection scenarios also tend to have higher operational GHG emissi ons. Based on these preliminary observations, reconsideration of high

HCPV WAG CO 2 

### injection alone as a scheme to enhance CO 2 

### storage may be warranted.

Figure 4

- 2 Mass of CO 2 Sequestered per 40

- Acre, Fiv e
- Spot as a Function of the Mass of
CO 2 Injected. Additional storage benefit decreased with increasing CO 2 injection.



### This figure shows that a bout forty percent of the injected CO 2 

### is retained per pattern in the 0.4

HCPV CO 2 

### injection historical scenario, about 29 percent of injected CO 2 

### is retained per pattern in 1.0 HCPV “best practices” scenario, and about 22 percent of injected CO 2 

### is retained in the

### 114 1.5 HCPV CO 2 

### - EOR scenario. The volume not retained is not vented to the atmosphere, but rather recycle d for use in CO 2 

### - EOR operations. Ultimately, close to 100 percent of purchased

CO 2 

### will be stored geologically.

4.1.2 CO 2 Recovery in Historical Scenario



### In the historical CO 2 

### - EOR scenario, CO 2 

### use is kept low in order to minimize the expense of purchased CO 2 

### . In addition, at the end of the CO 2 

### WAG injection, an additional slug of water is injected ( assumed 1 HCPV of water) in order to recover as much of the oil and CO 2 

### as economically possible from the reservoir. The oil is sold and the CO 2 

### is reused in nea rby patterns still undergoing active injection. The cumulative storage profile of the historical CO 2 

### - EOR scenario illustrates the effect of this water slug injection to recover CO 2 

### . Approximately 27

percent of the sequestered CO 2 

### is recovered by post

- WAG injection of a 1.0 HCPV water slug.

From a CO 2 

### sequestration perspective, t his technique both decreases the storage of CO 2 

### per pattern and has associated emissions from production and delivery of electricity used to compress and inject water, and would n ot be applied in situations where maximizing sequestration of CO 2 

### is a goal.



## 4.2 Life Cycle Performance

Modeled single well performance results were used as the basis on which CO 2 

### and brine injection, fluid production, and processing activity estimates were based. The amount of CO 2 

### and brine injected were estimated based on the prescribed WAG injection schedule detailed in

Section 3, and the ratio of recycled to purchased CO 2 

### feeding CO 2 

### - 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 CO 2 

### feed stream, CO 2 

### 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 ass umed 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

CO 2 

### - EOR flood operations where the gas stream undergoes distillative separation to remove HC as natural gas and natural gas liquids from CO 2



### .

T he following sections summarize results of a gate

- to

- gate characterization of tapered wate r alternating gas CO 2 

### - 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 CO 2 

### - EOR flood GHG perf ormance were developed based on procedures outlined in

Sections 3 and 4. Figure 4

- 3 illustrates the life cycle GHG emissions performance of each CO 2 

### - EOR operational scenario broken out on a per

- phase basis

. ( P hase s of operation are here defined

as site evaluation and characterization, facility construction, CO 2 

### - 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 co products 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 L ife C ycle G reenhouse G as E missions A ssoc iated with E ach

P hase of CO 2 - EOR A ctivity, R eported in U nits of M etric T onnes of CO 2 - E quivalent

G enerated per B arrel of O il P roduced



### From this figure it can be seen that nearly all (99%) GHG emissions associated with CO 2 

### - EOR overall activity occur during t he operational phase, for all operational scenarios considered. In addition, this figure also shows a correlation between the amount of CO 2 

### injected and the operational phase GHG emissions. This correlation can be attributed, in large part, to the

increa se in emissions associated with increased gas processing required when larger volumes of

CO 2 

### are loaded to, and recycled from, the CO 2 

### - EOR flood. Figure 4

- 4 illustrates the total life cycle emissions for each oper ational scenario as compared to total CO 2 

### sequestered through

CO 2 

### - 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 CO 2 

### - EOR

o perations.

### 116 Figure 4

- 4 Total Gate

- to

- Gate Life Cycle Emissions for Each Operational Scenario and

Total CO 2 Sequestered Through CO 2 - EOR Activity (both reported per barrel of oil produced)



### From Figure 4

- 4 

### we see that net and gross CO 2 

### storage per barrel of oil produced is greatest in current “best practices” WAG scenario and the 1.5 HCPV CO 2 

### WAG exhibits the lowest net sequestration benefit per barrel of oil produced.

4.2.2 Criteria Air Po llutant Emissions


### Similar to GHG emissions, criteria air pollutants associated with the operational phase of CO 2 

### - EOR activity are significantly higher than those of other phases of activity. Results of the criteria air pollutant inventory for the Best Pra ctices operational scenario are plotted in Figure

4

- 5 . The other two operational scenarios show similar trends, with emissions being less in the historical (low

- CO 2 

### injection), and greater in the 1.5 HCPV CO 2 

### inje ction 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 fr om 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 s eparator, tank battery, and gas processing facility.

### 117 Figure 4

- 5 Summary of Criteria Air Pollutant Emissions Associated with Each Phase of
CO 2 - EOR Activity for the Best Practices Operational Scenario, Repo rted 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 im p act 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 CO 2 

### - EOR activity is included in this estimate, including all land occupied by CO 2 

### - EOR flood patter ns 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 CO 2 

### - EOR operations, is not included. It should be noted that a large fraction of the land

below which a CO 2 

### - 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 CO 2 - EOR Activity per Barrel of Oil

Produced

CO 2 - EOR Scenario Land U se, A cres/bbl C rude

Historical 2.09 x 10 - 4

Best Practices 1.33 x 10 - 4

1.5 HCPV CO 2 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 CO 2 

### - EOR activity could not be specified. United States Department of Agriculture land resource type designation for the Permian Bas in is either Central Great Plains or Western Range

.

4.2.4 Water Use



### Total w ater consumption in CO 2 

### - 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 CO 2 

### - 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 CO 2 

### - EOR facility is very low.

### 119 Figure 4

- 6 Water Consumption Associated with Each Phase of CO 2 - 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 CO 2 

### - EOR activity are crude oil, natural gas and natural gas liquids produced in the gas processing plant, and high er energy content hydrocarbon gas collected from tank battery vapors. A portion of the gross energy products generated through CO 2 

### EOR activity will

be consum ed 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 CO 2 - EOR Operational Scenario (barrel of o il equivalents per 40 acre pattern)

### 121 Figure 4

- 8 Net Hydrocarbon Products Generated per 40

- Acre Well Pattern in Each CO 2 - EOR Operational Scenario (barrel of oil equivalents per 40 acre pattern). Bars below z ero on the ordinate represent natural gas that is purchased to meet energy requirements of CO 2 - EOR operations

. 

### These figures show that the primary energy product is indeed crude oil. A significant fraction ( approximately 11 percent for all operational sce narios) of gross hydrocarbon product is natural

gas (by energy content) , but, in best practices and high CO 2 

### 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 CO 2 

### - EOR operations.

Complete accounting of all energy inputs into CO 2 

### - EOR operations (not only hydrocarbon fuel use as described above) is provided in Figure 4

- 9

. While natural gas (primarily used in gas

processing plant operations) is the primary energy source, a substantial amount of electricity is

used for artificial lift of produced fluid, CO 2 

### compression, and brine pressuri zation 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 CO 2 - EOR Operational
Scenarios



## 4.3 Sensitivity Analysis

Uncertainty in appropriateness and quality of data, model structure, and de fined scenario used in inventory development affect confidence in the final results. To improve understand ing of the potential impact of such uncertainty on the base case emissions estimate , sensitivity of CO 2 

### - EOR

gate

- to

- gate life cycle GHG emissions per formance was considered for a select subset of input

parameters. The “best practices” CO 2 

### - 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

paramet ers 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 CO 2 

### - 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 subsequ ent

text.

### 123 Table 4

- 4 Selected Parameters Used in Sensitivity Analysis of Gate

- to

- Gate Life Cycle GHG
Emissions Performance of CO 2 - 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 year

time horizon

CO 2 - EOR Operational
Scenario Historical Best Practices 1.5 HCPV
CO 2 WAG Electricity Profile (kg CO 2 E) 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 1 0 x base case

Displacement Credit for
Co

- products (NG, NGL) 1.5x base case 1x base case None

Fugitive Loss (% of CO 2 initially pu rchased) 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 CO 2 

### equivalency factors

, are most appropriate for estim ation of CO 2 

### - 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 

### . CO 2 

### E emissions per barrel of oil produced under the “best practices” CO 2 

### - EOR scenario was estimated using each set of global warming potential factors. Results show little variance in calculated

CO 2 

### equivalent emissions, wi th 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 (CO 2 - Equivalents)

IPCC Second

Assessment Report (1996) IPCC Third

Assessment Report (2001) IPCC Fourth

Assessment Report (2007 ) **a**

Carbon Dioxide CO 2 1 1 1

Methane CH 4 21 23 25

Nitrous Oxide N 2 O 310 296 298

Sulfur Hexafloride SF 6 23,900 22,200 22,800

a Base case for this study



### 4.3.1.2 CO 2 

### - EOR Scenario

As is detailed throughout th is document, three CO 2 

### - EOR scenarios wer e considered: “historical,” “best practices,” and “high CO 2 

### WAG” scenarios. Gate

- to

- gate life cycle performance (GHG emissions per barrel of oil produced basis) of each of these CO 2 

### - EOR operational scenarios is considered in this sensitivity analysis. Figure 4

- 10 

### illustrates that the

choice of flood scenario selected to characterize CO 2 

### - EOR flood performance substantially

### 124 affects the calculated emissions associated with this activity. This sensitivity is a function of a

scenari o choice as opposed to model or data uncertainty, and the reported variance is considered to be resolved through the identification of “best practices” CO 2 

### - flood EOR as the representative base scenario. It is reported in this context primarily to convey t he relative scale of calculated sensitivity to this scenario choice.



### 4.3.1.3 Electricity Source

In the base case, electricity used in CO 2 

### - EOR operations is characterized as a mix representative of the ERCOT Independent System Operator region using data collecte d 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

- to

gate GHG emissions above and below this basel ine 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, CO 2 

### equivalent emissions per barrel of crude oil produc ed 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 CO 2 

### 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 Re covery 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 t he 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 CH 4 

### is emitted to the atmosphere a nd 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 mo re 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 CO 2 

### 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 u nderestimation of the contribution of those (non

operational) phases of activity. To address this concern, the total GHG emissions (kg CO 2 

### E emissions per barrel of oil produced) were increased by an order of magnitude to determine the impact to total emis sions from CO 2 

### - EOR activity.



### 4.3.1.6 Fugitive Loss of Purchased CO 2


### In the base case, it is assumed that loss of CO 2 

### from the flooding activities approaches zero and can be neglected. The influence of this assumption on estimated CO 2 

### equivalent emissions per

### 125 b arrel 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 CO 2 

### used in CO 2 

### - EOR operations is relatively small a s 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 Co

Products

In the gate

- to

- gate analysis, it is assumed that natural gas and natur al gas liquids produced as a coproduct of gas processing operations (and CO 2 

### - EOR activity, more generally) displace natural gas and natural gas liquids, respectively, from the market. As such, a displacement credit is assigned for the CO 2 

### E emissions of an equivalent amount of those products, based on cradle

- to

gate 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 cred it 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 T ornado plot shows the r esults of the sensitivity analysis ( Figure 4

- 10 

### )

, indicat ing that choice in

CO 2 

### - 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 decision s by reservoir engineers and operators on how to run CO 2 

### - EOR operations, in contrast to a bounding analysis of data or model uncertainty. As such, variance resulting from scenario choice should be considered diffe rently 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. CO 2 

### equiv alent emissions per barrel of oil produced were also sensitive to the source of electricity used in CO 2 

### - 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 ele ctricity (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 CO 2 

### - EOR. Potential fugitive loss o f purchased CO 2 

### could also increase CO 2 

### equivalent emissions of CO 2 

### - EOR activity, but a one percent leakage of purchased CO 2 

### corresponding with U.S. DOE minimum geologic sequestration storage permanence of 99

percent results in only a 3 percent increase fr om base case emissions. D isplacement credit choice for natural gas and natural gas liquids co

- products and choice in 100

- year horizon IPCC global warming potential CO 2 

### equivalent values were found to contribute little to CO 2 

### - EOR activity GHG emissions (th ree 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

CO 2 

### - 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 CO 2 

### . Stream

- tube models were carried out to estimate flood performance for a

set of three CO 2 

### - flood operational scenarios. These model results served as the foundation on which an inventory of ” gate

- to

- gate ” CO 2 

### - EOR activity and analysis of environmental life cycle performance were developed. The assessment s considered GHG and c riteria air pollutant emissions, water and land use, and energy performance for five phases of CO 2 

### - EOR facility activity: site characterization ; site preparation ; CO 2 

### - EOR flood operation ; well abandonment ; and post

- closure monitoring, verification, and acc ounting.

Significant findings of this effort include:

**•** Stream

- tube modeling of low, moderate, and high CO 2 

### injection volume scenarios revealed

that both hydrocarbon production and CO 2 

### storage increase with increasing volume of

CO 2 

### injection.

**•** H igher vo lume s of CO 2 

### 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 CO 2 

### geologic retention is accomplished

early in the injection, and longer duration, higher CO 2 

### volume injection corresponds with lower volume of oil produced and CO 2 

### sequestered per volume of CO 2 

### injected.

**•** Between 22 and 40 percent of injected CO 2 

### is retained cumulatively over the life of each

well pattern

. CO 2 

### that is not retained in one pattern is produced and re

- injected in the same or adjacent patterns such that essentially all CO 2 

### will eventually be geologically stored.

**•** For every barrel of crude oil extracted through WAG CO 2 

### - EOR, energy feedstocks

equivalent to between 1 3 and 2 7 percent of the energy content of th at oil are consumed.

**•** Greater than 99 percent of CO 2 

### - EOR energy demand is associated with the operational

phase , and g as proc essing is responsible for between 6 6 and 73 percent of operational phase energy consumption.

**•** G reenhouse gas emissions from “gate

- to

- gate” CO 2 

### - EOR activity are between 51 and 95 k g

CO 2 

### e/ bbl crude produced for CO 2 

### injection scenarios considered

.

**•** Gross storage valu es range between 195 and 228 kg/bbl oil produced

.

**•** N et GHG storage performance (geologic storage minus GHG emissions ) range from 116

kg CO 2 

### E /bbl crude oil produced for the highest CO 2 

### injection scenario, to 157 kg CO 2 

### E /bbl

crude oil for the best practices CO 2 

### - 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 CO 2 

### storage potential may increase on an absolute basis with increasing CO 2 

### injection, these benefits are weighted heavily to early years of flooding and

earlier volumes of CO 2 

### injection. Longer, higher cumulative volume CO 2 

### injections effec tively dilute benefits over longer periods of injection and erode energy production and CO 2 

### storage through higher parasitic energy load and increased emissions associated with processing of high volumes of produced gas. Considered together, stream tube m odel results and related life cycle performance data sugg e st that , of the three scenarios considered, current “best practices” WAG

CO 2 

### - EOR scenario performs best. H igh

- volume CO 2 

### injection is not favorable from an environmental and energy performance stan dpoint

, 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 CO 2 

### - EOR . The three oper ational scenarios considered are intended to represent performance of technology as it was performed in its infancy, as it i s performed in present application, and as it might be performed in one possible future scenario. This set of

scenario choices is b y no means exhaustive of alternatives that might reasonably be employed. Furthermore, consideration of gate

- to

- gate activities associated with CO 2 

### - 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 CO 2 

### - EOR activity and its performance within a larger cradle

- to

- grave life cycle

of CO 2 

### - generating energy systems.



### 5.1.1 Gate

- to

- Gate Analysis of Alter native CO 2 

### - EOR Scenarios

There are a number of alternative CO 2 

### - flood EOR scenarios that would be of value to consider to
facilitate comparison between current best practices as described herein, and other viable CO 2 

### - EOR schemes. Several conceivable scenari os fall within the general framework of the current

CO 2 

### - flood EOR paradigm and would be relatively straightforward to characterize, including considering the following: applying CO 2 

### - EOR technology in reservoirs other than the Permian Basin, using alternati ve gas

- processing technologies, assessing cases with no hydrocarbon gas separation (straight recycle), using large

- scale electricity to power CO 2 

### - EOR operations, applying CO 2 

### re

- pressuring (“soak”) or CO 2 

### EOR WAG injection before water flood is applied, imp lementing large

- scale infill well placement to enhance tertiary flood oil production, and considering short CO 2 

### injection periods to maximize CO 2 

### storage per unit energy input as opposed to maximizing oil production.

There are also scenarios that would req uire more

- aggressive modification or reworking of the

model de scribed in this report. . These scenarios would characterize schemes that serve as

transition s between straight “business

- as

- usual” CO 2 

### - flood EOR activity and dedicated brine sequestration, such as is being considered in flooding residual oil zones and/or deep brine aquifers. These alternative CO 2 

### - EOR technologies include:

**•** CO 2 

### - flood stimulation of residual oil zones

- naturally water

- flooded residual resources that

are believed to underlie prim ary oil production zones in extensive “freeway” aquifers.

These

### 129 **•** Stacked storage of CO 2



### – a scenario that allows for CO 2 

### - flood EOR with storage in

dedicated storage in adjacent or underlying brine aquifers. T his technology alternative has the potential to address issues of intermittency in CO 2 

### demand associated with traditional

CO 2 

### - 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 c haracterization of CO 2 

### - 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 anal yses of electricity production and liquid fu e l production recently published by NETL include scenari os with carbon capture and sequestration. These studies employ simplified characterizations of dedicated brine sequestration as the CO 2 

### sequestration techn ology. Additional scenarios could be considered in which these energy product pathways incorporate CO 2 

### - flood EOR in place of brine sequestration as a sink for captured CO 2 

### . In addition, there may be interest in coupling CO 2 

### - EOR not with anthropogenic CO 2 

### , but rather with CO 2 

### from natural sources

— the primary source of CO 2 

### used today for CO 2 

### - flood EOR. These natural geologic CO 2 

### sources could also be considered as intermediate storage locations for anthropogenic CO 2 

### to buffer intermittency of supply and

de mand in anthropogenic CO 2 

### capture/geologic sequestration scenarios. It should be noted that incorporating CO 2 

### - EOR gate

- to

- gate activity into larger cradle

- to

- grave pathways will create a source of uncertainty associated with methods of allocation. Fortun ately , 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 consider ing only the environmental performance of CO 2 

### - EOR activity, including GHG emissio ns, 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 CO 2 

### - EOR. Also, the life cycle performance of CO 2 

### - E OR 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 ana lysis 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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2009 from: http://www.gastool.methanetomarkets.org/m2mtool/files/docs/convertwatertank.pdf

Directed Inspection and Maintenance a nd IR Leak Detection: Lessons Learned from Natural Gas STAR. Producers Technology Transfer Workshop. Occidental Oil and Gas and EPA’s Natural Gas STAR Program. Midland, TX. June 8, 2006. Accessed online 03 February, 2009 from: http://www.gastool.methanetomarkets.org/m2mtool/files/docs/dim_pres1.pdf

United States Environmental Protection Agency, Natural Gas STAR Program . “Eliminate Unnecessary Equipment and/or System s.” Accessed online 03 February, 2009 from: http://www.gastool.methanetomarkets.org/m2mtool/files/docs/eliminateunnecessaryequip mentandorsystems.pdf

United States Environmental Protection Agency, Natural Gas STAR Program . “Options for Reducing Methane E missions f rom Pneumatic Devices in the Natural Gas Industry.” Accessed online 03 February, 2009 from: http://www.gastool.methanetomarkets.org/m2mtool/files/docs/gremi llion2.pdf

United States Environmental Protection Agency, Natural Gas STAR Program . “Install Electronic Flare Ignition Devices.” Accessed online 03 February, 2009 from: http://www.gastool.methanetomarkets.org/m2mtool/files/docs/installelectronicflareig nitio ndevices.pdf

United States Environmental Protection Agency, Natural Gas STAR Program . “Installing Vapor Recovery Units on Crude Oil Storage Tanks.” (2006) Accessed online 03 February, 2009

from: http://www.gastool.methanetomarkets.org/m2mtool/fil es/docs/ll_final_vap.pdf

United States Environmental Protection Agency, Natural Gas STAR Program . “Convert Gas Pneumatic Controls to Instrument Air.” Accessed online 03 February, 2009 from: http://www.gastool.methanetomarkets.org/m2mtool/files/docs/ll_instrument_air.pdf

United States Environmental Protection Agency, Natural Gas STAR Program . “Directed Inspection and Maintenance with Optical Imaging.” Accesse d online 03 February, 2009

from: http://www.gastool.methanetomarkets.org/m2mtool/files/docs/ngstar_fall2005.pdf

United States Environmental Protection Agency, Natural Gas STAR Program . “Recover Gas from Pipeline Pigging Operations.” Accessed online 03 February, 2009 from: http://www.gastool.methanetomarkets.org/m2mtool/files/docs/pigging_lines.ppt

### 141 United States Environmental Protection Agency, Natural Gas STAR Pr ogram . “Optimizing Operating Pressures.” Accessed online 03 February, 2009 from: http://www.gastool.methanetomarkets.org/m2mtool/files/docs/seperator_pressures.ppt

United States Environmental Protection Agency, Natural Gas STAR Program . “Process Optim ization.” Accessed online 03 February, 2009 from: http://www.gastool.methanetomarkets.org/m2mtool/files/docs/spring2005update.pdf

United States Environmental Protection Agency, Natural Gas STAR Program . “Install Flow

Valves.” Accessed online 03 Februa ry, 2009 from: http://www.gastool.methanetomarkets.org/m2mtool/files/docs/summer2005update.pdf

United States Environmental Protection Agency, Office of Water. “ Geologic CO 2 

### Sequestration Technology and Cost Analysis. Technical Support Document. ” EPA 81 6

- B

- 08

- 009. (June 2008) Accessed online 22 December, 2008 from: http://www.epa.gov/OGWDW/uic/pdfs/support_uic_co2_technologyandcostanalysis.pdf

United States Environmental Protection Agency, Technology Transfer Network Clearinghouse

for Inventories & Emiss ions Factors. Factor Information Retrieval (FIRE) Data System

. Accessed online 17 April, 2009 from: http://cfpub.epa.gov/oarweb/index.cfm?action=fire.main

Van Leeuwen, Tyler and Ferguson, Robert. “Electricity Use of Enhanced Oil Recovery with

Carbon Di oxide (CO 2 

### - EOR).” White Paper prepared for National Energy Technology Laboratory by Advanced Resources International, Inc.

Veil, J.A, et al., 2004, A White Paper Describing Produced Water from Production of Crude Oil, Natural Gas, and Coal Bed Methane, pr epared by Argonne National Laboratory, Argonne, Illinois for the U.S. Department of Energy, National Energy Technology Labo

Watson, Theresa; Getzlaf, Don; and Griffith, James E. “Specialized cement desing and placement procedures prove successful for miti gating casing vent flows

– case histories.” SPE 76333. Originally Presented at the SPE Gas Technology Symposium held in Calgary, Alberta, Canada, 30 April

– 2 May 2002.

White. C. M., B.R. Strazisar, E.J. Granite, J.S. Hoffman, and H.W. Pennline, ( June 20 03) Separation and Capture of CO 2 

### from large stationary sources and sequestration in geological formations

- coalbeds and deep saline aquifers, Journ. Air & Waste Manage.
Assoc., 53 , 645

- 715.

Williams, Gustavious Paul; Tomasko, David; Smith, Karen; and Blunt , Deborah. “Analytical Model for Radial injection of NORM with a Step

- Function Source.” International Petroleum Environmental Conference. September 9

- 12, 1997. San Antonio, TX

Zhenhao Duan, Jiawen Hu, Dedong Li and Shide Mao (2008) Density of the CO 2 

### - H 2 

### O and CO 2 

### - H 2 

### O

- NaCl systems up to 647 K and 100 MPa. Energy & Fuels. Model Accessed

7/28/2008 at: http://www.geochem

- model.org/programs.htm

### 142 This page intentionally left blank

### DRAFT A

- 1 

## Appen dix A : CO 2 

## Prophet CO 2 

## - EOR Screening Model Definition of Relative Permeability Parameters

Relative Permeability of Water

Expw



### Sorw Swir Swir Sw Kwro Krw ** **  ** **  ** ** 

**− −**  **−**

**=** 1



### where: Krw is the relative permeability of water

Sw is the water saturation Expw is the water equation expo nent 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



### Sorw Swc Sorw Sw Krocw Krow ** **  ** **  ** ** 

**− −**  **− −** 

**=** 1 1



### 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



### Sgr Swc Sgr Sg Krgcw Krg ** **  ** **  ** **  ** ** 

**− −**  **−**

**=** 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 0.3 7 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



### Sorg Swc Sg Sorg Swc Krocw Krog ** **  ** **  ** **  ** ** 

**− −**  **− −**  **−**

**=** 1 1



### w here: Krog is the relative permeability of oil Sg is th e 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 (maximu m) relative permeability of oil at irreducible water

saturation. The default is 0.4.

Relative Permeability of Solvent (CO 2 

### )

Exps



### Sorm Ssr Swir Ssr Sg ** **  ** **  ** ** 

**− −**  **− −** 
1 Krsmax = Krs



### w here: Krs is the relative permeability of solvent Sg is the gas (i.e., solvent) saturation Exps is the solv ent 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 oi l 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: CO 2 Prophet model parameters and default val ues used in CO 2 Prophet model

to characterize relative permeability of fluids that interact in a CO 2 - EOR miscible flood

. These values are used in all CO 2 - EOR scenarios developed herein.

Parameter Description CO 2 Prophet

Variable CO 2 Prophet
Default Units

Residual oil saturation to water SORW 0.3 2 fraction (0

- 1)

Residual oil saturation to gas SORG 0.3 2 fraction (0

- 1)
Residual oil saturation to miscible gas
solvent flood SORM 0.0 5 fraction (0

- 1)

Residual gas saturation SGR 0. 32 fraction (0

- 1)

Residual s olvent ( CO 2 ) 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 fra ction (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 connat e 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 c urve 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 parame ter

- 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 CO 2 

### emissions from these generating facilities, it does not address other GHG constituents such as N 2 

### O and CH 4 

### 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 200 5 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 e missions from 2005 Electric Reliability Council of Texas Independent System Operato r

.

Pollutant Output

Emission

Rates Units

CO 2 0.736 kg/MWh

SO 2 2.84 x 10 - 3 kg/MWh

NO

x 1. 26 x 10 - 3 kg/MWh Dust (unspecified) 5.34 x 10 - 5 kg/MWh

Non

- Methane VOC s 1.02 x 10 - 4 kg/MWh Lead (II) 2.54 x 10 - 8 kg/MWh

CH 4 9.76 x 10 - 4 kg/MWh

N 2 O 9.46 x 10 - 6 kg/MWh

SF6 8.95 x 10 - 13 kg/MWh

### DR AFT C

- 1 

## Appendix C : Raw Output from CO 2 

## Prophet Model for Historical, Best Practices, and 1.5 HCPV CO 2 

## WAG CO 2 

## - EOR
Scenarios.

Histor ical CO 2 

### - 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 SO LUTION 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

SG R SSR SWC SWIR

0.3200 0.3200 0.2000 0.2000

KROCW KWRO KRSMAX KRGCW

0.4000 0.3000 0.4000 0.4000

### DR AFT 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

I NJECTION 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

TO TAL 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

- 0 3 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 0.000 0 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

### DR AFT C

- 3 3.000 0.3007 0.0504 0.2504 103.3 1130.8

3.9 91 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 0.213 8 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

### DR AFT C

- 4 ER OIL OI L 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 2 571.0 152.2 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 0.000 0 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 0.10 01 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

### DR AFT C

- 5 16.979 0.0979 0.0013 0.0957 0.0 009 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 19 3.9 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

### DR AFT C

- 6 Best

- Practices CO 2 

### - 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 VISCOSI TIES 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 0.20 00

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 PERMEABI LITY 0.6660 EQUAL TO Krow

### DR AFT 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 T IME ****** 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 INJEC TION

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

### DR AFT 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 0.1 725 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 1.803 1 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

### DR AFT 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 0.17 44 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+0 1

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 0.057 9 0.0277 1.47

2.493 0.0494 0.0083 0.0145 0.0267 0.83

### DR AFT 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

10.0 00 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 0.0 732 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 SOL VENT 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

5.0 00 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 0.178 E+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

### DR AFT 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 10 0.3 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

### DR AFT C

- 12 1.5 HCPV CO 2 

### WAG CO 2 

### - EOR Scenario

************** RESERVOIR DATA **************

PRESSURE PATTERN

TEMP OPERATING MMP POROSITY THIC KNESS 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 0.0 500

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

### DR AFT 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

  IN JECTION ** ** 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 1 806.6

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 4 12.1 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

### DR AFT C

- 14 12.000 1.2026 0.4017 0.8 009 824.0 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 4 162.4 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 OUTPU T ********** 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 1.302 7 0.1241 0.6201 0.5585 12.41 132.36 66.95

### DR AFT 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 0.16 24 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 1.20 50 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 1.4 788 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 0.1 30E+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

### DR AFT 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 0.14 1E+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 3 33.0 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 0.149 E+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 36 0.9 4547.4 290.5 5303.8 0.155E+02 0.126E+02

***********************************************

SUMMARY OF FLUID PRODUCTION

INCREMENTAL DATA

********** HCPV OUTPUT ********** OIL

TIME HYDR OCARBON 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 0.0 534 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

### DR AFT 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 0.002 9 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 0.0 1 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 0.56 6E+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 1 86.1 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

1 8.000 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 0.20 4E+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

### DR AFT 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 CH 4 Emission s Factors for the Oil and Gas Industry

Activity/Equipment Emission Factor EF Units

Vented Emissions

Oil Tanks 5.28 scf of CH 4 /bbl crude

Pneumatic Devices, High Bleed 330 scfd CH 4 /device

Pneumatic Devices, Low Bleed 52 scfd CH 4 /de vice

Chemical Injection Pumps 248 scfd CH 4 /pump

Vessel Blowdowns 78 scfy CH 4 /vessel

Compressor Blowdowns 3,775 scf/yr of CH 4 /compressor

Compressor Starts 8,443 scf/yr. of CH 4 /compressor

Stripper wells 2,345 scf/yr of CH 4 /stripper well

Well Completion Venting 733 scf/completion

Well Workovers 96 scf CH 4 /workover

Pipeline Pigging 2.4 scfd of CH 4 /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

Heade rs (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 sc fd 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/wel l 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 CO 2 Emissions Factors for the Oil and Gas Industry

CO 2 Emission s Activity/Equipment Emission Factor EF Units

Vented Emissions

Oil Tanks 3.53 scf of CO 2 /bbl crude

Pneumatic Devices, High Bleed 6.704 scfd CO 2 /device

Pneumatic Devices, Low Bleed 1.055 scfd CO 2 /device

Chemical Injection Pumps 5.033 scfd CO 2 /pump

Vessel Blowdowns1 1.583 scfy CO 2 /vessel

Compressor Blowdowns1 77 scf/yr of CO 2 /compressor

Compressor Starts1 171 scf/yr of CO 2 /compressor

Stripper wells 48 scf/yr of CO 2 /stripper well

Well Complet ion Venting1 14.87 Scf CO 2 /completion

Well Workovers 1.95 scf CO 2 /workover

Pipeline Pigging NE scfd of CO 2 /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 CO 2 /separator

Separators (light crude) 0.281 scfd CO 2 /separator

Heater/Treaters (light crude) 0.319 scfd CO 2 /heater

Headers (heavy crude)1 0.002 scfd CO 2 /header

Headers (light crude ) 0.22 scfd CO 2 /header

Floating Roof Tanks1 17,490 scf CO 2 /floating roof tank/yr.
Compressors 2.029 scfd CO 2 /compressor

Large Compressors 332 scfd CO 2 /compressor

Sales Areas 2.096 scf CO 2 /loading

Pipelines NE scfd of CO 2 / mile of pipeline

Well Drilling NE scfd of CO 2 /oil well drilled

Battery Pumps 0.012 scfd of CO 2 /pump

Process Upset Emissions

Pressure Relief Valves1 1.794 scf/yr/PR valve

Well Blowouts Onshore 0.051 MMscf/blowout

### DRAFT E

- 1 

## Append ix E : Summary Output form U.S. EPA TANKS Model of Oil Storage Tanks for Historical, Best Practices, and 1.5 HCPV CO 2 

## WAG CO 2 

## - EOR Scenarios.

Historical CO 2 

### - EOR

a) Estimated Annual Working and Breathing Losses of Single Oil Tank Under Historical CO 2 

### - EOR Scena rio 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 CO 2 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

T urnovers: 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 Typ e: 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 50.000 0 207.00 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 Br eathing 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 CO 2 

### - 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 CO 2 _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 H eated (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
Breathe r 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

Mixt ure/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 Rep ort

- 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) 6,749.82 128.7 8 6,878.59



### a) Estimated Annual Working and Breathing Losses of Single Oil Tank Under Best Practices CO 2 

### - EOR Scenario

Conditions Best Practices CO 2 

### - EOR

TANKS 4.0.9d
Emissions Report

- Summary Format
Tank Indentification and Physical Characteristics

Id entification

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 CO 2 WAG Scenario
Tank Dimensions Shell Heigh t (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):

- 0.0 3 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

- Vertic al 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. Mi n. 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 Total s

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 Losse s of Heater/Treater Under Best Practices CO 2 

### - 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 CO 2 _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/Shad e: 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 Emiss ions 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

Cru de 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 Fix ed 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 CO 2 

### WAG CO 2 

### - EOR

a) Estimate Annual Working and Breathing Losses of Oil Tank Under 1.5 HCPV CO 2 

### WA G CO 2 

### - 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 Fi xed 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 Pressu re = 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 CO 2 

### WAG CO 2 

### - EOR Scenario

Conditions

TANKS 4.0.9d
Emissions Report

- Summary Format

Tank Indentification an d 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 Heat ed (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 V ent 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 Co ntents 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

- MW electric 

## (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 CO 2 

### Capture.

Emissions (kg
CO 2 e /MWh) Stage #1: Raw

Material Acquisition Stage #2: Raw

Material Transport Stage #3:

P ower Plant Stage #4:

Transmission &

Distribution Total

Case 1

- EXPC Without CCS

CO 2 3.2 5.2 1.0E+03 0 1020

N 2 O 1.4E

- 02 3.7E

- 02 5.1 0 5.1

CH 4 80 1.9E

- 01 2.8E

- 01 0 80

SF 6 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 C CS

CO 2 3.2 5.2 340 0 348

N 2 O 1.4E

- 02 3.7E

- 02 6.0 0 6.0

CH 4 8.0E+01 1.9E

- 01 6.6 0 87

SF 6 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 CO 2 - EOR scenario.

Parameter Units Site Eval. & Char. Construction Operation Closure MVA Total

Greenhouse Gas Emissions

CO 2 kg/bbl crude 3.49E

- 03 3. 24E

- 01 4.88E+01 1. 83E

- 01 6.99E

- 03 4.93E+01

CH 4 kg/bbl crude 0.00E+00 5.79E

- 05 8.84E

- 02 1.87E

- 06 0.00E+00 8.85E

- 02

N 2 O kg/bbl crude 0.00E+00 0.00E+00 2.13E

- 04 0.00E+00 0.00E+00 2.13E

- 04

SF 6 kg/bbl crude 0.00E+00 0.00E+00 2.18E

- 11 0.00E+00 0.00E+00 2.18E

- 11

CO 2 E* kg/bbl crude 3.67E

- 03 3. 36E

- 01 5.01E+01 1. 90E

- 01 7 .35E

- 03 5.06E+01

Criteria Air Pollutants

NO X 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 8.18 E

- 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

SO 2 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

CO 2 Sequestered (gross)

CO 2 stored kg/bbl crude

- - 195

- - 195

Land Use

Pattern Area Acres/bbl crude

- - 2.09E

- 04

- - 2.09E

- 04

* CO 2 equivalent values are aggregate values including credits and upstream emissions for which only CO 2 E values are available. Individual GHG constituent values will not correspond directly wit h the reported total global warming potential.

### DRAFT H

- 2 Table H

- 2 : Summary of emissions and resource demands for best practices CO 2 - EOR scenario.

Parameter Units Site Eval. & Char. Construction Operation Closure MVA Total

Greenhouse Gas Emissions

CO 2 kg/bbl c rude 2.22E

- 03 2.99E

- 01 6.88E+01 1.16E

- 01 4.44E

- 03 6.92E+01

CH 4 kg/bbl crude 0.00E+00 6.08E

- 05 7.95E

- 02 1.19E

- 06 0.00E+00 7.96E

- 02

N 2 O kg/bbl crude 0.00E+00 0.00E+00 2.01E

- 04 0.00E+00 0.00E+00 2.01E

- 04

SF 6 kg/bbl crude 0.00E+00 0.00E+00 1.84E

- 11 0.00E+00 0.00E+00 1.84E

- 11

CO 2 E* kg/bbl crude 2.33E

- 03 3.12E

- 01 7.03E+01 1.21E

- 01 4.67E

- 03 7.07E+01

Criteria Air Pollutants

NO X 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

SO 2 kg/bbl crude 1.95E

- 10 6.41E

- 04 8.35E

- 02 6.06E

- 05 3.90E

- 10 8.42E

- 02

VOC kg/bbl c rude 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

CO 2 Sequestered (gross)

CO 2 stored kg CO 2 /bbl crude

- - 228

- - 228

Land Use

Land use Acres/bbl crude

- - 1

. 33 E

- 04

- - 1

. 33 E

- 04

* CO 2 equivalent values are aggregate values including credits and upstream emissions for which only CO 2 E values are ava ilable. 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 CO 2 WAG EOR scenario.

Parameter Units Site Eval. & Char. Construct ion Operation Closure MVA Total

Greenhouse Gas Emissions

CO 2 kg/bbl crude 1.97E

- 03 3.45E

- 01 9.09E+01 9.72E

- 02 3.93E

- 03 9.13E+01

CH 4 kg/bbl crude 0.00E+00 7.50E

- 05 1.41E

- 01 9.93E

- 07 0.00E+00 1.41E

- 01

N 2 O kg/bbl crude 0.00E+00 0.00E+00 2.54E

- 04 0.00E+00 0.00E+00 2.54E

- 04

SF 6 kg/bbl crude 0.00E+00 0.00E+00 2.15E

- 11 0.00E+00 0.00E+00 2.15E

- 11

CO 2 E* kg/bbl crude 2.07E

- 03 3.61E

- 01 9.42E+01 1.01E

- 01 4.13E

- 03 9.46E+01

Criteria Air Pollutants

NO X 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

SO 2 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 Inje ction Disposal barrel excess brine per bbl

crude - - 6.65E

- 01

- - 6.65E

- 01

CO 2 Sequestered (gross)
Injected

- produced kg/bbl crude

- - 211

- - 211

Land Use

Total Pattern Coverage Acres/bbl crude

- - 1

. 17 E

- 04

- - 1

. 17 E

- 04



### * CO 2 

### equivalent values are a ggregate values including credits and upstream emissions for which only CO 2 

### E values are available. Individual GHG constituent values will not correspond directly with the reported total global warming potential.