# Development of Baseline Data and Analysis of Life Cycle Greenhouse Gas Emissions of Petroleum-Based Fuels

November 26, 2008

DOE/NETL-2009/1346

# Disclaimer

This report was prepared as an account of work sponsored by an agency of the United States Government. Neither th e United States Government nor any agency thereof, nor any of their employees, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any info rmation, apparatus, product, or process disclosed, or represents that its use w ould not infringe privately owned rights. Reference therein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwis e does not necessarily constitute or imply its endorsement, recommendation, or favoring by the United States Government or any agency thereof. Th e views and opinions of authors expressed therein do not necessarily state or reflect those of the United States Government or any agency thereof.

# Development of Baseline Data and Analysis of Life Cycle Greenhouse Gas Emissions of Petroleum-Based Fuels

DOE/NETL-2009/1346

November 26, 2008

NETL Contacts:

Timothy J. Skone, P.E.
Kristin Gerdes Office of Systems, Analyses and Planning

National Energy Technology Laboratory www.netl.doe.gov

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# Acknowledgements

This work was funded by the U.S. Department of Energy’s National Energy Technology Laboratory (U.S. DOE-NETL). Th e NETL sponsor for this proj ect was Dan Cicero, Office of Coal and Power R&D, Technology Manager for Hydrogen and Syngas Program. The NETL management team provided guidance and technical oversight for this study. Contract support was provided by Massood Ra mezan and Barbara Bennett, Research and Development Solutions, LLC (RDS) under contract number DE-AC26-04NT 41817.403.01.12A. NETL would like to acknowledge and thank the c ontributions of Bill Harrison, U.S. Air Force Research Laboratory; Dr. James Hileman, Massac husetts Institute of Technology; and Dr. Joyce Cooper, University of Washington for their review comments that helped improve the quality of this report. NETL would also like to thank Aaron Levy and Ari Kahan from the U.S. Environmental Protection Agenc y, Office of Transportation and Air Quality for developing the national average vehicle emissi ons profile for the year 2005.

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### i 

## Table of Contents

List of Tables ................................................................................................................. ............... vi List of Figures................................................................................................................ ............... xi Acronyms and Abbreviations ................................................................................................... xi v Executive Summary.............................................................................................................. ES - 1
1.0 Introduction................................................................................................................... .... 1 1.1 Background................................................................................................................. .... 1 1.2 Purpose & Goal of the Study .......................................................................................... 2 1.3 Study Boundary and Modeling Approach ...................................................................... 2 1.3.1 Scope of the Environmental Life Cycle Analysis................................................... 2
1.3.2 Cut-off Criteria for th e System Boundary .............................................................. 4 1.3.3 Exclusion of Data from the System Boundary ....................................................... 4
1.3.4 Data Reduction and Allocation Procedures ............................................................ 5 1.3.5 Geography, Technology and Time-frame Represented.......................................... 5 1.4 Life Cycle Stages .......................................................................................................... .. 5
2.0 LC Stage #1: Raw Ma terial Acquisition ........................................................................ 8 2.1 Raw Material Acquisition for Do mestic Petroleum Refineries ...................................... 8 2.1.1 Crude Oil Acquisition............................................................................................. 9

2.1.1.1 Crude Oil Extraction GHG Profiles.................................................................... 9
2.1.1.2 Canadian Crude Oil Mix Extraction GHG Profile............................................ 11 2.1.1.3 Crude Oil Mix Composite Extraction GHG Profiles........................................ 12 2.1.2 Natural Gas Liquids Extr action and Processing ................................................... 13 2.1.3 Unfinished Oils Extraction and Processing .......................................................... 14 2.1.4 LC Stage #1 Summary for Domestic Refineries................................................... 15 2.2 Raw Material Acquisition for Fo reign Petroleum Refineries....................................... 15 2.2.2 Raw Material Extraction for Gasoline Imports..................................................... 22 2.2.3 Raw Material Extraction for Diesel Imports......................................................... 22 2.2.4 Raw Material Extraction for Jet Fuel Imports ...................................................... 22 2.3 Summary of Life Cycle Stage #1 GHG Emissions Profiles ......................................... 23
3.0 Life Cycle Stage #2: Ra w Material Transport ............................................................ 24 3.1 Crude Oil Mix Transport .............................................................................................. 25 3.1.1 Crude Oil Mix Transport to Domestic Refineries................................................. 25

### ii 3.1.1.1 Crude Oil Transport within Exporting Country................................................ 25 3.1.1.2 Crude Oil Mix Ocean Transport to Domestic Ports.......................................... 25 3.1.1.3 Crude Oil Mix Domestic Transport .................................................................. 27 3.1.2 Crude Oil Mix Transport to Foreign Refineries ................................................... 30 3.2 Natural Gas Liquids Transport...................................................................................... 31 3.3 Unfinished Oils Transport............................................................................................. 31 3.4 Summary of Life Cycle Stage #2 GHG Emissions Profiles ......................................... 32
4.0 Life Cycle Stage #3: Li quid Fuels Production.............................................................. 33 4.1 General Description of a Petroleum Refinery............................................................... 34 4.2 Liquid Fuels Production at Dome stic Petroleum Refineries......................................... 37 4.2.1 Reported Refinery Data ........................................................................................ 39 4.2.2 Refinery Energy Usage......................................................................................... 39 4.2.3 Fuels Acquisition .................................................................................................. 41

4.2.3.1 Purchased Electricity and Steam....................................................................... 41
4.2.3.2 Coal................................................................................................................... 42
4.2.3.3 Natural Gas ....................................................................................................... 47 4.2.3.4 Refinery-Produced Fuels .................................................................................. 47 4.2.3.5 Refinery Fuels Acquisition Emissions Profile.................................................. 48
4.2.4 Refiner Fuels Combustion .................................................................................... 48

4.2.4.1 CO 2 

### Emissions from Refinery Fuels Combustion ............................................ 48 4.2.4.2 Methane Emissions from Refinery Fuels Combustion ..................................... 48
4.2.4.3 N 2 

### O Emissions from Refinery Fuels Combustion............................................ 49 4.2.4.4 Refinery Fuels Combustion Emissions Profile................................................. 50 4.2.5 Hydrogen Production............................................................................................ 51

4.2.5.1 Hydrogen Production Via Steam Methane Reforming (SMR)......................... 52 4.2.5.2 Hydrogen Produced from Catalytic Reformer.................................................. 55 4.2.5.3 Summary of Hydrogen Pool ............................................................................. 56 4.2.6 Flaring Operations ................................................................................................ 58

4.2.6.1 CO 2 

### Emissions .................................................................................................. 58
4.2.6.2 Methane Emissions ........................................................................................... 58
4.2.6.3 N 2 

### O Emissions.................................................................................................. 60 4.2.7 Vented/Fugitive Emissions ................................................................................... 60 4.2.8 Refinery Emissions Profile ................................................................................... 60

### iii 4.2.9 Refinery Process Unit Data Modeli ng and GHG Allocation to Products............. 62

4.2.9.1 Process Unit Capacity and Throughput ............................................................ 64 4.2.9.2 Refinery Unit Operations’ Energy Consumption ............................................. 68 4.2.9.3 Refinery Unit Hydrogen Consumption............................................................. 68 4.2.9.4 Contribution of Unit Operati on to Product Categories..................................... 72
4.2.9.5 Resources and Emissions Allo cation to Product Fractions............................... 79 4.2.10 Summary of LC Stage #3 fo r Domestic Refineries .............................................. 81 4.3 Liquid Fuels Production at Foreign Refineries............................................................. 86 4.4 Summary of Life Cycle Stage #3 GHG Emissions Profiles ......................................... 87
5.0 Life Cycle Stage #4: Tran sport of Liquid Fuels to Ve hicle Refueling Station or Airport and Refueling of Vehicle/Aircraft ................................................................... 88 5.1 Product Transport.......................................................................................................... 88 5.1.1 Foreign Transport.................................................................................................. 88

5.1.1.1 Gasoline Transport to the U.S........................................................................... 90 5.1.1.2 Diesel Transport to the U.S............................................................................... 90 5.1.1.3 Kerosene-Based Jet Fuel Transport to the U.S. ................................................ 91 5.1.2 Domestic Transport............................................................................................... 92
5.2 Vehicle/Aircraft Refueling............................................................................................ 94 5.2.1 Vehicle Refueling ................................................................................................. 94

5.2.1.1 Gasoline Refueling Operations......................................................................... 95 5.2.1.2 Diesel Refueling Operations............................................................................. 95 5.2.2 Aircraft Refueling ................................................................................................. 95 5.3 Summary of Life Cycle Stage #4 GHG Emissions Profiles ......................................... 96
6.0 Life Cycle Stage #5: Vehi cle/Aircraft Operation ......................................................... 97 6.1 Vehicle Operation ......................................................................................................... 9 7 6.2 Aircraft Operation......................................................................................................... 98 6.3 Life Cycle Stage #5 Summary ...................................................................................... 98
7.0 Results and Discussion.................................................................................................... 99 7.1 Construction of Life Cy cle Emissions Profiles............................................................. 99 7.2 Life Cycle GHG Emissions Associated with Finished Transportation Fuels Consumed in the U.S. in 2005 ............................................................................................................ ...... 105 7.2.1 Life Cycle Stage #1............................................................................................. 114 7.2.2 Life Cycle Stage #2............................................................................................. 114

### iv 7.2.3 Life Cycle Stage #3............................................................................................. 114 7.2.4 Life Cycle Stage #4............................................................................................. 115 7.2.5 Life Cycle Stage #5............................................................................................. 116 7.3 GHG Emissions Associated with Liquid Fuel s Produced at U.S. Refineries in 2005: Comparison to Foreign Imported Fuels .................................................................................. 117
8.0 Data Quality and Sensitivity Analysis......................................................................... 123 8.1 Life Cycle Stage #1..................................................................................................... 123
8.1.1 Crude Oil Extraction Profiles.............................................................................. 123 8.1.2 Oil Sands/Heavy Oils GHG Emissions Profiles ................................................. 124 8.2 Life Cycle Stage #2..................................................................................................... 126 8.2.1 Waterborne Transport ......................................................................................... 127 8.2.2 Pipeline Transport............................................................................................... 127
8.2.3 Crude Oil Loss Factor......................................................................................... 127 8.3 Life Cycle Stage #3..................................................................................................... 129 8.3.1 Total Petroleum Refining Emissions .................................................................. 129
8.3.2 Allocation of Emissions to Petroleum Refining Products .................................. 131

8.3.2.1 Hydrogen Production and Consumption......................................................... 131 8.3.2.2 Capacity Utilization ........................................................................................ 132 8.3.2.3 Energy Consumption ...................................................................................... 132 8.3.2.4 Contribution of Unit Operations to Product Categories ................................. 134 8.3.3 Refining Profile for Imported Products .............................................................. 134 8.4 Life Cycle Stage #4..................................................................................................... 138 8.5 Life Cycle Stage #5..................................................................................................... 140 8.6 Data Quality and Sensitivity Analysis Summary........................................................ 140
References..................................................................................................................... ............. 141

Appendix A: Overview of Domestically-Produ ced and Imported Finished Transportation Fuels Appendix B: Cradle-to-Gate G HG Emissions Inventory for El ectric Power from the U.S. (Average) Grid Mix Appendix C: Cradle-to-Gate GHG Emissions Profile for Fuels Produced in Domestic Refineries Appendix D: Petroleum Industry Guidelines for Reporting Greenhouse Gas Emissions Appendix E: Nitrous Oxide Emission Factors

### v Appendix F: Overview of Allocation Pro cedures for Petroleum Refining Operations Appendix G: Cradle-to-Gate GHG Emissions Inventory fo r Hydrogen Production Via SMR with PSA Purification Appendix H: Crude Oil and Finished Product Loss Factors Appendix I: Conversion Factors Appendix J: Emissions Factor s for Various Vehicle Types Appendix K: LTO Emission Factor s and Emissions for Various Aircraft Appendix L: Study GHG Results Presented in Alternate Units
Attachment 1: Documentation Associated with Profiles Extracted from GaBi 4

### vi 

## List of Tables

Table ES-1. Life Cycle Gree nhouse Gas Study Design ......................................................... ES - 5 Table ES-2. Product Specifications and Ve hicle/Aircraft Use Profiles.................................. ES - 6 Table ES-3. Data Quality Assessment of Study Methodology and Results ........................... ES - 8
Table 1-1. GHG Emissions Included in St udy Boundary and their 100-year GWP...................... 3 Table 2-1. Daily Refinery Feed stock Input in 2005 (EIA 2008) ................................................... 9
Table 2-2. Sources of Crude Oil Utilized at U.S. Petroleum Refineries in 2005 .......................... 9
Table 2-3. GHG Emissions Consiste nt with Extraction of Crude O il in Countries Exporting to U.S. Petroleum Refineries in 2005 ....................................................................................... 10
Table 2-4. GHG Emissions Consistent with Ex traction of Canadian Conventional Crude Oil Based on Adjusted U.S. Crude Oil Extraction Emissions Profile ........................................ 12
Table 2-5. GHG Emissions Consistent with Extr action and Processing of Canadian Oil Sands 12
Table 2-6. GHG Emissions Consistent with Extr action of Composite U.S. Crude Oil Mix for 2005........................................................................................................................... ............ 13
Table 2-7. Emissions from Natural Ga s Production and Processing (CAPP 2004) .................... 14
Table 2-8. Emissions from Natural Ga s Liquids Production and Processing.............................. 14 Table 2-9. Unfinished Oils Net Input to U.S. Refineries in 2005 (EIA 2008) ............................ 14
Table 2-10. Emissions for Unfinished Oils Extraction and Processing....................................... 15
Table 2-11. GHG Emissions from Feedstock Extraction for Input to Domestic Refineries in 2005........................................................................................................................... ............ 15 Table 2-12. Import Quantities of Petroleu m Fuels in 2005 and Percent of 2005 U.S. Consumption.................................................................................................................... ..... 16 Table 2-13. Petroleum Products Import Source s and Data Availability for Raw Material Extraction GHG Emissions................................................................................................... 16 Table 2-14. Canadian Refinery F eedstocks for 2005 (StatCan 2008) ......................................... 18
Table 2-15. GHG Emissions Consistent with Extraction of Crude Oil Mix to Canadian Refineries in 2005............................................................................................................. .... 19 Table 2-16. Virgin Islands Refine ry Feedstocks for 2005 (EIA 2008)........................................ 20
Table 2-17. GHG Emissions Consiste nt with Extraction of Crude Oil Mix to the Virgin Islands Refinery in 2005 ............................................................................................................... .... 20
Table 2-18. GHG Emissions Consistent with Extraction of Composite Crude Oil Mix for Foreign Gasoline Refining in 2005....................................................................................... 22
Table 2-19. GHG Emissions Consistent with Extraction of Composite Crude Oil Mix for Foreign Diesel Refining in 2005........................................................................................... 22

### vii Table 2-20. GHG Emissions Consistent with Extraction of Composite Crude Oil Mix for Foreign Jet Fuel Refining in 2005 ........................................................................................ 22 Table 2-21. Summary of GHG Emi ssions Consistent with Extrac tion of Crude Oil and Other Feedstocks for U.S. and Foreign Refineries in 2005 ............................................................ 23
Table 3-1. GHG Emissions Associ ated with Transport of Impor ted Crude Oil from Point of Extraction to Foreign Ports ................................................................................................... 2 5 Table 3-2. Performance Specificatio ns for Various Crude Tankers............................................ 26
Table 3-3. GHG Emissions from Combustion of HFO (Residual Fuel Oil) in Ships (EIA 2007)

............................................................................................................................... ................ 26 Table 3-4. Sources of U.S. Crude Input to Re fineries, Exporting Port, and Country-Specific Average Ocean Travel Distance ........................................................................................... 26
Table 3-5. GHG Emissions Associated with Oc ean Tanker Transport of Waterborne Imported Crude Oil to Domestic Ports................................................................................................. 27
Table 3-6. Total Crude Petroleum Carried In Domestic Transportation (Billions of Ton-Miles) and Percent of Total Carried by Mo de of Transportation (AOP 2006) ................................ 27 Table 3-7. Energy Intensity of Transport Activities .................................................................... 28 Table 3-8. Energy Usage for Crude Petroleum Transport Activities........................................... 28 Table 3-9. Crude Oil Transportation M odes and Associated Emission Factors.......................... 29
Table 3-10. GHG Emissions Associated with Crude Oil Transport within U.S.......................... 29
Table 3-11. GHG Emissions Associated with Transport of Foreign Crude to Foreign Refineries/Ports............................................................................................................... ...... 30 Table 3-12. GHG Emissions and One-Way Travel Distance Assumptions Associated with Ocean Tanker Transport of Foreign Cr ude to Foreign Refineries/Ports............................... 31
Table 3-13. GHG Emissions Associated with Al l Modes of Transport of Foreign Crude to Foreign Refineries............................................................................................................. .... 31
Table 3-14. GHG Emissions Associ ated with NGL Transport.................................................... 31
Table 3-15. GHG Emissions Associated w ith Unfinished Oils Transport .................................. 31 Table 3-16. Summary of GHG Emi ssions Consistent with Transport of Crude Oil and Other Feedstocks for U.S. and Foreign Refineries in 2005 ............................................................ 32 Table 4-1. Crude Oil Boiling Point Range for Product Slate (Energetics 2007)......................... 35 Table 4-2. Refinery Fuels Consumed for 2005............................................................................ 39 Table 4-3. Refinery Fuel s Energy Content (HHV)...................................................................... 40 Table 4-4. Refinery Fuels Ener gy Usage Profile for 2005 (HHV).............................................. 40 Table 4-5. Refinery Fuels and Associated Indirect CO 2 

### Emissions ............................................ 41 Table 4-6. Refinery Fuels and Associ ated Indirect Methane Emissions ..................................... 41 Table 4-7. Refinery Fuels and Associated Indirect N 2 

### O Emissions ............................................ 41

### viii Table 4-8. Underground Mining Energy Inputs Required for Extr action and Preparation of 371.4 Million Tons of Bituminous Coal (USDOC 2004)............................................................... 43 Table 4-9. Underground Bituminous Coal Mi ning/Preparation Fuels and Associated CO 2 

### Emission Factors............................................................................................................... .... 43 Table 4-10. Underground Bituminous Coal Mi ning/Preparation Fuels and Associated CH 4 

### Emission Factors............................................................................................................... .... 43 Table 4-11. Underground Bituminous Coal Mi ning/Preparation Fuels and Associated N 2 

### O Emission Factors............................................................................................................... .... 44 Table 4-12. Summary of Coal Be d Methane Productivity Estimates.......................................... 45 Table 4-13. Coal Mining Methan e Emissions Factors (API 2004) ............................................. 45 Table 4-14. Summary of Assumptions for Coal Rail Transportation.......................................... 46
Table 4-15. GHG Emissions Consistent w ith Coal Transport by Rail (EIA 2007)..................... 46 Table 4-16. Summary of GHG Emissions C onsistent With Coal Acquisition............................ 46
Table 4-17. GHG Emissions Consistent with Delivered Natural Gas in the U.S........................ 47 Table 4-18. Summary of GHG Emi ssions Consistent with Acquisition of Refinery-Produced Fuels.......................................................................................................................... ............ 47 Table 4-19. Summary of GHG Emi ssions Consistent with Acquisition of Petroleum Refinery Fuels.......................................................................................................................... ............ 48 Table 4-20. Refinery Fuels and Associated CO 2 

### Emissions from Fuel Combustion .................. 49 Table 4-21. Refinery Fuels and Associated Methane Emissions from Fuel Combustion ........... 49 Table 4-22. Refinery Fuels and Associated N 2 

### O Emissions from Fuel Combustion .................. 50
Table 4-23. GHG Emissions Associated with Daily Fuels Input to Refineries........................... 50 Table 4-24. Refinery Hydrogen Sources and Emissions Accounting Summary ......................... 51 Table 4-25. Specific Natural Gas Input as Feedstock to SMR Hydrogen Plants ........................ 53 Table 4-26. Composition of U.S. Pipelin e Quality Natural Gas (API 2004)............................... 53 Table 4-27. Estimated Energy Cons umption for Hydrogen Production...................................... 54
Table 4-28. Cradle-to-Gate GHG Emissions Inventory for Hydr ogen Production via SMR with PSA Purification ............................................................................................................... .... 54 Table 4-29. Specific Hydrogen Produc tion from Catalytic Reformer......................................... 55 Table 4-30. Catalytic Reform er Net Hydrogen Output ............................................................... 55 Table 4-31. Hydrogen Production for U.S. Refineries in 2005 ................................................... 57 Table 4-32. Refinery Energy Used for Hydroge n Production for U.S. Refineries in 2005......... 57
Table 4-33. GHG Emissions Not Included in Re finery Energy Usage for Hydrogen Production for U.S. Refineries in 2005 ................................................................................................... 5 7 Table 4-34. Flaring Summary for Se lected California Refineries ............................................... 59

### ix Table 4-35. Flaring Summary for Selected California Refineries 2005 (BA AQMD 2008)....... 59
Table 4-36. Estimate of GHG Emissions Cons istent with Flaring Activities 2006..................... 59
Table 4-37. 2005 Methane Emissions from Petroleum Refining (EPA 2007c) .......................... 61 Table 4-38. Refining GHG Emissions Sources .......................................................................... 62 Table 4-39. U.S. Total Refinery Unit Op erations Capacities in 2005* (EIA 2008).................... 64 Table 4-40. Boiling Range for Various Petroleum Intermediates (EIA 2008)............................ 65 Table 4-41. Unit Operation Capacity, Actual Input, and Utilization Rate for Key U.S. Refinery Operations in 2005 (EIA 2008)............................................................................................. 66 Table 4-42. U.S. Total Refinery Un it Operations Capacities in 2005* ....................................... 67 Table 4-43. Estimated Energy Use by Refining Process (Energetics 2007) and Study Value with Electricity Loss Adjustment.................................................................................................. 69 Table 4-44. Chemical Hydrogen Consump tion for Various Petroleum Fractions....................... 70 Table 4-45. Estimated Hydrogen Consump tion for Hydrocracking Operations ......................... 71 Table 4-46. Hydrogen Consumption Mass Balance .................................................................... 71 Table 4-47. Estimated Hydrogen Requirements fo r Hydrotreating (Relative to Naphtha) ......... 72 Table 4-48. Estimated Hydrogen Re quirements for Hydrotreating............................................. 72 Table 4-49. Product Categories a nd Amount Produced in 2005 ................................................. 73
Table 4-50. Diesel Production and Sulf ur Content in 1996 and 2005 (EIA 2008)...................... 74 Table 4-51. 1996 Reported and 2005 Estimated Un it Operation Contributions to Diesel, Gasoline, and Kerosene Fractions......................................................................................... 74 Table 4-52. Summary of Unit Operat ion Contribution to End Products ..................................... 75 Table 4-53. LC Stage #3 GHG Emissions for Tr ansportation Fuels Produced in Domestic Refineries ..................................................................................................................... ......... 81 Table 4-54. Refinery Performance Summary for Product Fractions ........................................... 83 Table 4-55. Life Cycle Stage #3 GHG Emissions for Domestic Refineries by Activity SubCategory....................................................................................................................... ......... 84 Table 4-56. Life Cycle Stage #3 GHG Emissions for Domestic Re fineries by Sub-Category ... 85 Table 4-57. Summary of GHG Emissi ons Consistent with Refining of Gasoline, Diesel and Jet Fuel at U.S. and Forei gn Refineries in 2005......................................................................... 87 Table 5-1. Performance Specifications for Various Petroleum Product Tankers (Brodosplit 2008) .......................................................................................................................... ........... 89
Table 5-2. GHG Emissions from Combustion of HFO (Residual Fuel Oil) in Ships (EIA 2007)

............................................................................................................................... ................ 89
Table 5-3. GHG Emissions Associat ed with Transport of Importe d Gasoline to Domestic Ports

............................................................................................................................... ................ 90

### x Table 5-4. GHG Emissions Associated with Trans port of Imported Diesel to Domestic Ports.. 91
Table 5-5. GHG Emissions Associated with Trans port of Imported Kerosene -Based Jet Fuel to Domestic Ports................................................................................................................. ..... 91
Table 5-6. Total Petroleum Products Carried In Domestic Transportation (Billions of TonMiles) and Percent of Total Carried by Mode of Transportation (AOP 2006)..................... 92 Table 5-7. Energy Intensity of Transport Activities .................................................................... 93 Table 5-8. Energy Usage for Petrol eum Product Transport Activities........................................ 93 Table 5-9. Petroleum Product Transportation Modes and Associated Emission Factors............ 94
Table 5-10. Emissions Associated wi th Petroleum Products Transport...................................... 94
Table 5-11. Greenhouse Gas Emissions Associat ed with Vehicle Refueling Operations........... 95 Table 5-12. Summary of GHG Emissi ons Consistent with Transport of Gasoline, Diesel and Jet Fuel in 2005 ................................................................................................................... ....... 96
Table 6-1. Conventional Dies el and Conventional Gasoline Operational Parameters and Emissions for 2000 Model Passenger Cars (EPA 2008) ...................................................... 97
Table 6-2. GHG Emissions Consistent with Average Flight Operations .................................... 98 Table 6-3. Summary of GHG Emissi ons Consistent with Consumption of Gasoline, Diesel and Jet Fuel in 2005............................................................................................................... ...... 98
Table 7-1. Heat Content of Petroleum Products ........................................................................ 100
Table 7-2. GHG Emissions for Liquid Fuels Production .......................................................... 105
Table 7-3. Methane Emissions for Liquid Fuels Production ..................................................... 106
Table 7-4. Nitrous Oxide Emissions for Liquid Fuels Production ............................................ 106
Table 7-5. Well-to-Wheels GHG Emi ssions in a Passenger Vehicle ........................................ 106 Table 8-1. Adjustments to Hydrotreating S ubcategory Energy Consumption Utilized in Sensitivity Analysis ........................................................................................................... . 133

### xi 

## List of Figures

Figure ES-1. Life Cycle of Petroleu m-Based Transportation Fuels...................................... ES - 1 Figure ES-2. Baseline Life Cycle Greenhouse Gas Emissions for Petroleum Transportation Fuels Sold or Distributed in the U.S. in Year 2005 (kg CO 2 

### E/MMBtu LHV of Fuel Consumed) ...................................................................................................................... ES - 1 Figure ES-3. Life Cycle GHG Emissions for Conventional Transportation Fuels in kg CO 2 

### E per MMBtu LHV Fuel Consumed ........................................................................................ ES - 3 Figure ES-4. Comparison of Diesel Fuel Greenhouse Gas Profiles from Various Studies.... ES - 4 Figure ES-5. Year 2005 Petroleum Refinery Feedstock and Product Flows.......................... ES - 6 Figure 1-1. Comparison of Diesel Fuel GHG Profiles from Various U.S. Studies ....................... 1 Figure 1-2. Conceptual Study Boundary ....................................................................................... 3 Figure 1-3. Flow of Petroleum Refining Feedstock and Products through the Life Cycle Stages 6 Figure 2-1. Flow Diagram of Raw Ma terial Acquisition Activities .............................................. 8 Figure 2-2. Country-Specific CO 2 

### Emissions Associated with Cr ude Oil Extraction Relative to Reported Flaring ............................................................................................................... .... 10 Figure 2-3. Country-Specific Meth ane Emissions Associated with Crude Oil Extraction Relative to Reported Venting............................................................................................................ .. 11 Figure 2-4. GHG Emissions Consistent with Extraction of Crude Oil Input to U.S. Refineries in 2005........................................................................................................................... ............ 13 Figure 2-5. GHG Emissions Consistent with Crude Oil Extraction ............................................ 21 Figure 3-1. Flow Diagram of Raw Material Transport Activities ............................................... 24 Figure 4-1. Flow Diagram of Liqui d Fuels Production Activities............................................... 33 Figure 4-2. Modern Oil Re finery (Chevron 2007)....................................................................... 34 Figure 4-3. Atmospheric Dist illation Column (EIA 1999).......................................................... 35 Figure 4-4. Depiction of Refinery and Hydrogen Emissions Pools............................................. 38 Figure 4-5. Map of the United States Showing Petroleum Administration for Defense Districts and Refinery Locations (Energy Velocity 2007).................................................................. 42 Figure 4-6. Representation of Allocation of Life Cycle Stage #3 Emissions to Product Categories ..................................................................................................................... ........ 63 Figure 4-7. Hydrogen Consumption for H ydrotreating Operations (Jechura 2008).................... 70 Figure 4-8. Percent of Volumetric Throughput Allocated to End Products ................................ 80 Figure 4-9. Life Cycle Stage #3 GHG Emissions for Domestic Refineries - Key Products ....... 82 Figure 4-10. Comparison of Refini ng GHG Emissions Between Studies................................... 87 Figure 5-1. Flow Diagram of Product Tr ansport and Refueling Activities ................................. 88

### xii Figure 7-1. Feedstock and Pr oduct Volumetric Flows for C onsumption of Conventional Gasoline, Conventional Diesel and Kerosene -Based Jet Fuel in the U.S. in 2005............. 101 Figure 7-2. Feedstock and Produc t Requirements Consistent with One Thousand Barrels of Conventional Gasoline Consumed in the U.S. in 2005 ...................................................... 102 Figure 7-3. Feedstock and Produc t Requirements Consistent with One Thousand Barrels of Conventional Diesel Consumed in the U.S. in 2005 .......................................................... 103 Figure 7-4. Feedstock and Produc t Requirements Consistent with One Thousand Barrels of Kerosene-Based Jet Fuel Consumed in the U.S. in 2005 ................................................... 104 Figure 7-5. GHG Emissions for Liqu id Fuels’ Individual Life Cy cle Stages and Complete Wellto-Wheels Life Cycle .......................................................................................................... 1 08 Figure 7-6. Carbon Dioxide Emi ssions for Liquid Fuels’ Indivi dual Life Cycle Stages and Complete Well-to-Wheels Life Cycle ................................................................................ 109 Figure 7-7. Methane Emissions for Liquid Fuels’ Individual Life Cycle Stages and Complete Well-to-Wheels Life Cycle................................................................................................. 110 Figure 7-8. Nitrous Oxide Emissions for Liqui d Fuels’ Individual Life Cycle Stages and Complete Well-to-Wheels Life Cycle ................................................................................ 111 Figure 7-9. Well-to-Tank GHG Em issions for Liquid Fuels..................................................... 112 Figure 7-10. Life Cycle Stage Percent Contri butions to Total Life Cycle GHG Emissions ..... 113 Figure 7-11. GHG Emissions for Liquid Fuels Produced Domestically ................................... 118 Figure 7-12. Well-to-Tank GHG Emissions fo r Liquid Fuels Produced Domestically ............ 119 Figure 7-13. Comparison of GHG Emissions fo r Conventional Gasoline Produced at U.S. Refineries and Imported from Foreign Refineries.............................................................. 120 Figure 7-14. Comparison of GHG Emissions for Conventional Diesel Fuel Produced at U.S. Refineries and Imported from Foreign Refineries.............................................................. 121 Figure 7-15. Comparison of GHG Emissions for Kerosene-Based Jet Fuel Produced at U.S. Refineries and Imported from Foreign Refineries.............................................................. 122 Figure 8-1. Sensitivity Analysis of Life Cycle Stage #1 Activities on the Well-to-Tank GHG Emissions Profile for Conventional Gaso line Consumed in the U.S. in 2005 ................... 125 Figure 8-2. Sensitivity Analysis of Life Cycle Stage #1 Activities on the Well-to-Tank GHG Emissions Profile for Conventional Dies el Consumed in the U.S. in 2005 ....................... 126 Figure 8-3. Sensitivity Analysis of Life Cycle Stage #1 Activities on the Well-to-Tank GHG Emissions Profile for Kerosene-Based Jet Fuel Consumed in the U.S. in 2005 ................ 126 Figure 8-4. Sensitivity Analysis of Life Cycle Stage #2 Activities on the Well-to-Tank GHG Emissions Profile for Conventional Gaso line Consumed in the U.S. in 2005 ................... 128 Figure 8-5. Sensitivity Analysis of Life Cycle Stage #2 Activities on the Well-to-Tank GHG Emissions Profile for Conventional Dies el Consumed in the U.S. in 2005 ....................... 128 Figure 8-6. Sensitivity Analysis of Life Cycle Stage #2 Activities on the Well-to-Tank GHG Emissions Profile for Kerosene-Based Jet Fuel Consumed in the U.S. in 2005 ................ 129

### xiii Figure 8-7. Sensitivity Analysis of Life Cycle Stage #3 Activities on the Well-to-Tank GHG Emissions Profile for Conventional Gaso line Consumed in the U.S. in 2005 ................... 135 Figure 8-8. Sensitivity Analysis of Life Cycle Stage #3 Activities on the Well-to-Tank GHG Emissions Profile for Conventional Dies el Consumed in the U.S. in 2005 ....................... 136 Figure 8-9. Sensitivity Analysis of Life Cycle Stage #3 Activities on the Well-to-Tank GHG Emissions Profile for Kerosene-Based Jet Fuel Consumed in the U.S. in 2005 ................ 137 Figure 8-10. Sensitivity Analysis of Life Cycle Stage #4 Activities on the Well-to-Tank GHG Emissions Profile for Conventional Gaso line Consumed in the U.S. in 2005 ................... 139 Figure 8-11. Sensitivity Analysis of Life Cycle Stage #4 Activities on the Well-to-Tank GHG Emissions Profile for Conventional Dies el Consumed in the U.S. in 2005 ....................... 139 Figure 8-12. Sensitivity Analysis of Life Cycle Stage #4 Activities on the Well-to-Tank GHG Emissions Profile for Kerosene-Based Jet Fuel Consumed in the U.S. in 2005 ................ 140

### xiv 

## Acronyms and Abbreviations
AEO Annual Energy Outlook (Energy Information Agency)
AGR Acid Gas Removal ANL Argonne National Laboratory
API American Petroleum Institute ASU Air Separation Unit BA AQMD Bay Area Air Qual ity Management District
bbl Barrel BEA Bureau of Economic Analysis
BP British Petroleum
Btu British Thermal Unit bpcd Barrels per Calendar Day bpd Barrels per Day bpsd Barrels per Stream Day
CARB California Air Resources Board
CBM Coal Bed Methane CCS Carbon Capture and Storage cd Calendar Day
cf Cubic feet
CH 4 

### Methane CIDI Compression-Ignition, Direct-Injection
CO Carbon Monoxide
CO 2 

### Carbon Dioxide
CO 2 

### E Carbon Dioxide Equivalent COE Cost of Electricity
DF Diesel Fuel DOE Department of Energy DOT Department of Transportation DWT Dead Weight Ton EE Energy Efficiency EERE Energy Efficiency and Renewable Energy EIA Energy Information Administration

### xv ELCD European Reference Life Cycle Data EOR Enhanced Oil Recovery EOS Equation of State EPA Environmental Protection Agency ETE Effective Thermal Efficiency EU European Union EUCAR European Council for Automotive R&D EX Existing Refinery
FAA Federal Aviation Administration FE Fossil Energy FEHQ Fossil Energy Headquarters FERC Federal Energy Regulatory Commission FTE Full Time Equivalent
G&A General and Administrative
GHG Greenhouse Gas GPM Gallons per Minute GREET Greenhouse Gases, Regulated Emissi ons, and Energy Use in Transportation Model GWP Global Warming Potential

H 2 

### Hydrogen HDSAM Hydrogen Delivery Scenario Analysis Model HFO Heavy Fuel Oil HHV Higher Heating Value hphr Heat Pump Heat Recovery HRSG Heat Recovery Steam Generator
IC Internal Combustion IGCC Integrated Gasification Combined Cycle
IISI International Iron and Steel Institute IPCC Intergovernmental Panel on Climate Change IPIECA International Petroleum Industry Environmental Conservation Association ISO International Organiza tion for Standardization kg Kilogram
kt Knot

### xvi kW Kilowatt
kWh Kilowatt-hour
lb Pound LC Life Cycle LCA Life Cycle Analysis LCC Life Cycle Cost LCI Life Cycle Inventory LCIA Life Cycle Impact Assessment LHV Lower Heating Value LPG Liquefied Petroleum Gas
LS Low Sulfur LTO Landing and Takeoff
Mbbl Thousand Barrels MJ Megajoule
MMBtu Million Btu
MMscf Million Standard Cubic Feet
Mcf Thousand cubic feet MPa Megapascal mpg Miles Per Gallon MTBE Methyl Tertiary-Butyl Ether
MTPA Million Tonnes Per Annum MWh Megawatt-hour

N 2 

### O Nitrous Oxide
NAICS North American Indus try Classification System NEB National Energy Board NEI National Emissions Inventory NETL National Energy Technology Laboratory
NG Natural Gas NGL Natural Gas Liquids NIST National Institute of Standards and Technology NOx Nitrogen Oxides
NPRA National Petroleum Refiners Association

### xvii NRC National Research Council NREL National Renewable Energy Laboratory
O&GJ Oil and Gas Journal O&M Operating and Maintenance ORNL Oak Ridge National Laboratory OSAP Office of Systems and Planning
PADD Petroleum Administra tion for Defense District
PM Particulate Matter ppm Parts Per Million PSA Pressure Swing Adsorption psi Pounds per Square Inch
PV Present Value
RCRA Resource Conservati on and Recovery Act ROG Reactive Organic Gas SCAQMD South Coast Air Qual ity Management District
scf Standard Cubic Feet scfb Standard Cubic Feet per Barrel scfd Standard Cubic Feet per Day SCR Selective Catalytic Reduction SMR Steam Methane Reforming
SOA State of the Art
SOx Sulfur Oxides TOG Total Organic Gas TPD Tons Per Day TRI Toxic Release Inventory
ULSD Ultra Low Sulfur Diesel
U.S. United States VOC Volatile Organic Compound
WTT Well-to-Tank
WTW Well-toWheels/Wake

### xviii This page intentionally left blank.

### ES - 1 

## Executive Summary

Alternative transportation fuel options are curre ntly being explored or implemented across the nation to (1) reduce climate change impacts from the release of gree nhouse gases (GHGs), (2) reduce our reliance on foreign sources of ener gy, and (3) provide an economically-stable transportation fuel source to reduce price shoc ks to our economy. The U.S. Department of Energy (DOE), National Energy Technology Laborato ry (NETL) is currently evaluating options to produce transportation fuels from coal, coal and biomass, and unconventional fossil energy resources. This study develops a comprehensive and transparen t baseline for the life cycle GHG emissions from conventional petroleum-based tran sportation fuels sold or distributed in the United States in the year 2005. The scope of this study is depicted in Figure ES-1. The results of this study are necessary to benchmark the perf ormance of alternative transportation fuels with respect to climate change impacts. The st udy goals and scope were aligned to meet the definition of “baseline lifecycle greenhouse gas emissions” as defined in the Energy Independence and Security Act of 2007 (EISA 2007), Title II, Subtitle A, Sec. 201.

Figure ES-1. Life Cycle of Petroleum-Based Transportation Fuels 

### Figure ES-2 summarizes the study results for the U.S. average “baseline” life cycle GHG emissions of conventional gasoline, conventional diesel fuel ( ≤ 500 parts per million (ppm) sulfur), and kerosene-based jet fuel. The results are reported in terms of carbon dioxide equivalents (CO 2 

### E) per million British Thermal

Figure ES-2. Baseline Life Cycle Greenhouse Gas Emissions for Petroleum Transportation Fuels Sold or Distributed in the U.S. in Year 2005 (kg CO 2 E/MMBtu LHV of Fuel Consumed)Key Life Cycle Stage Conventional Gasoline Conventional Diesel Kerosene-Based Jet Fuel

#1: RMA 7.3 8% 6.6 7% 6.8 7% #2: RMT 1.4 1% 1.3 1% 1.3 1% #3: LFP 9.8 10% 9.5 10% 6.0 6% #4: PTR 1.1 1% 0.9 1% 1.0 1% #5: Use 76.6 80% 76.7 81% 77.7 84%
Total:WTT 19.6 20% 18.4 19% 15.1 16% Total:WTW 96.3 100% 95.0 100% 92.9 100% Non-U.S. Operations U.S. Operations

Gasoline Jet Fuel Diesel Fuel Crude OilKey LC Stage #1 Raw Material Acquisition

(RMA)

LC Stage #2 Raw Material Transport

(RMT)

LC Stage #3

Liquid Fuels Production

(LFP)

LC Stage #4

Product Transport & Refueling

(PTR)

LC Stage #5

Vehicle/ Aircraft Operation

(USE)

System BoundaryWell-to-Tank (WTT)Well-to-Wheels/Wake (WTW)

Conventional

Gasoline Conventional Diesel Fuel Kerosene-Type Jet Fuel Domestic + Imports - Exports Foreign Crude Oil

For Foreign Production

of Gasoline For Foreign Production

of Diesel Fuel For Foreign Production

of Jet Fuel For Domestic Production of Transportation

Fuels

T-3 T-2 T-1 Foreign Crude Oil Foreign Crude Oil Foreign Crude Oil Domestic Crude Oil 

## Summary Results

0 10 20 30 40 50 60 70 80 90 100Greenhouse Gas (GHG) Emissions(kg CO2E/MMBtu LHV of Fuel Consumed)

### ES - 2 Units (MMBtu), lower heating value (LHV), of fuel consumed. The total contribution in CO 2 

### E of carbon dioxide (CO 2 

### ), methane (CH 4 

### ), and nitrous oxide (N 2 

### O) are reported based on the 2007 IPCC 100-year global warming potentials. Combusti on of the fuel (denoted as “Life Cycle Stage #5: Use” in this study) accounts for 80% of the ga soline and diesel vehicle emissions and almost 84% of the total GHG emissions from the use of je t fuel. The life cycle GHG analysis results, as reported, are modeled based on the 2005 averag e passenger vehicle as modeled by the U.S. Environmental Protection Agency’s MOVES model. Changes to the vehicle or engi ne type will not change the baseline life cycle GHG emi ssions profile for conve ntional gasoline and conventional diesel fuel as re ported on a “per MMBtu LHV of Fuel Consumed” basis. Results reported on a “per mile traveled” basis are depe ndant on the vehicle and engine type modeled. GHG emissions associated with the combustion of kerosene-type jet fuel (Life Cycle Stage #5: Use) are modeled based on the U.S. Fe deral Aviation Administration (FAA) and Intergovernmental Panel on Climate Change (IPCC) methodology for estimating GHG emissions from aircraft. The composite GHG value used in this study is the same value used by the FAA and U.S. Environmental Protection Agency (E PA) to calculate annual GHG emissions from aircraft operations in the United States. Well-to-tank (WTT) releases of GHGs contribu te 20% or less to the total life cycle GHG emissions for each fuel type. Refinery operations (Life Cycle Stage #3: LFP) contribute 10% of the life cycle GHG emissions for conventional ga soline and diesel fuel while the crude oil extraction process (Life Cycle Stage #1: RMA) c ontributes another 7-8%. Crude oil extraction contributes slighter more GHGs then refining operations for kerosene-type jet fuel (7.3% compared to 6.5%) due to the lower refining energy requirements for producing jet fuel. The remainder for each fuel type, less than 3%, is from crude oil (Life Cycle Stage #2: RMT) and finished product (Life Cycle Stage #4: PTR) transportation and distribution operations. Comparative life cycle stage results for each fuel type are presented in Figure ES-3 by a stacked bar chart showing the relative contribution of GH G emissions on a CO 2 

### E basis. Opportunities for lowering the life cycle GHG em issions from transportation-related fuels will best be achieved through improved vehicle effici ency (e.g., gallons of fuel consumed per mile traveled) or alternative sources of transportation fuels. Fo r example, improving the average gasoline-powered light-duty passenger vehicle e fficiency from 21.6 miles per gallon (MPG) to 28.6 MPG, a 7 MPG increase, reduces the life cycle GHG emissions by 20%–equal to the total upstream GHG emissions from well-to-tank. Opportunities for reducing emissions from refining operations are very limited. Petroleum refining operations are one of the most energy efficient chemical conversion processes in the country– averaging around 90% energy efficiency. The U.S. petroleum refining industry, through it s trade association th e American Petroleum Institute (API), has implemented an aggressi ve greenhouse gas reduction program entitled “API Voluntary Climate Change Program.” This pr ogram, and others, should continue to be encouraged to reduce life cycle GHG emissions ; however, large-scale reductions can only be achieved through improved vehicle efficiency and alternative sources of transportation fuels. Opportunities for lowering the life cycle GHG emissions will best be achieved through improved vehicle efficiency or alternative sources of transportation fuels

. A 7 MPG increase in vehicle efficiency reduces the life cycle GHG emissions by 20% - equal to the total upstream GHG emissions from well-to-tank.ES - 3Figure ES-3. Life Cycle GHG Emissions for Conventional Transportation Fuels in kg CO2E per MMBtu LHV Fuel Consumed7.36.6 6.81.4 1.3 1.39.89.56.01.1 0.9 1.096.395.092.977.776.776.6020406080100 Gasoline Diesel Jet Fuel Gasoline Diesel Jet Fuel Gasoline Diesel Jet Fuel Gasoline Diesel Jet Fuel Gasoline Diesel Jet Fuel Gasoline Diesel Jet FuelLC Stage #1:Raw MaterialAcquisitionLC Stage #2:Raw MaterialTransportLC Stage #3:Liquid FuelsProductionLC Stage #4:Product Transportand RefuelingLC Stage #5:Vehicle /AircraftOperationTotalWell-to-Wheels

GHG Emissions (kg CO 2 E/MMBtu LHV of fuel consumed)Carbon DioxideMethaneNitrous Oxide

### ES - 4 

## Study Drivers
The production and delivery of transportation fuels ha s been widely studied in the United States. Over the past 10 years, the increasing empha sis on GHG emissions in the United States and abroad has resulted in a number of well-documented and cited re ports on the life cycle emissions of petroleum-based diesel fuel and gasoline. Figure ES-4 illustrates the results from various studies for the production and delivery of diesel fuel on a “well-to-tank” (WTT) basis. The results vary from 11.8 to 37.5 kg CO 2 

### E/MMBtu LHV–a three-fold differential between the minimum and maximum values.

Figure ES-4. Comparison of Diesel Fuel Greenhouse Gas Profiles from Various Studies

0.0 5.0 10.0 15.0 20.0 25.0 30.0 35.0 40.0
Life Cycle GHG Contribution (kg CO 2 E/MMBtu LHV of Fuel Delivered) EPA, OTAQ (2006) Minimum Value NREL Biodiesel Study (1998) GREET Ver. 1.8b (2008), Year 2005

EPA, OTAQ (2006) Average Value GREET Ver. 1.8b (2008), Year 2010 U.C. Davis, LEM (2003), Year 2015 EPA, OTAQ (2006) Maximum Value GM Study WTT (2001) McCann, O&G Journal (1999), Canadian Light Crude California LCFS (2007) - modified GREET Model McCann, O&G Journal (1999), Saudia Light Crude McCann, O&G Journal (1999), Venezuela Heavy Crude McCann, O&G Journal (1999), Venezuela Very Heavy Crude

From Extraction (oil well)... ...to Fuel Dispensing (vehicle tank).



### This raised the questions “ What is the greenhouse gas (GHG) contribution from the production and delivery of diesel fuel, gas oline and kerosene-based jet fu el in the United States? ” and “H ow does one compare alternative fuel options? ” Each of the results pr esented in Figure ES-4 is appropriate based on the indi vidual study purpose and modeling assumptions employed by the authors. Significant differences in results ar ise primarily from diffe rences in study boundary conditions, type of data used in the analysis , technology represented, ge ographical representation of key processes (national average, regional, or site-specific), time-relate d coverage (age of the data used in the analysis), and/ or the allocation procedures used to assign emissions to operations with more than one valuable product (such as in a petroleum refinery). On January 4, 2007, the EISA 2007 was passed into law. Under Title II, Subtit le A, Sec. 201 of the Act, it calls for the development of baseline lifecycle greenhouse gas emissions for gasoline and diesel sold or distributed as a tran sportation fuel in the U.S. in 2005. The baseline is to be determined by the U.S. EPA Administrator, after notice and opportunity for comment. The goals and scope of th is study were aligned to meet the above drivers. EISA 2007, Title II, Subtitle A, Sec. 201 “(C) BASELINE LIFECYCLE GREENHOUSE GAS EMISSIONS- The term ‘baseline lifecycle greenhouse gas emissions’ means the average lifecycle greenhouse gas emissions, as determined by the Administrator, after notice and opportunity for comment, for gasoline or diesel (whichever is being replaced by the renewable fuel) sold or distributed as transportation fuel in 2005.”

### ES - 5 

## Life Cycle Modeling Approach and Data Limitations
This study conforms to the International Standa rds Organization (IS O) 14040 and 14044 life cycle assessment standards. This study includes all four phases of a life cycle assessment: Goal and Scope Definition, Inventory An alysis, Impact Assessment, and Interpretation. The scope of the life cycle inventory (LCI) is limited to gr eenhouse gas emissions; as a result, the life cycle impact assessment (LCIA) only determines the global warming potential (GWP) of the GHG emissions based on their relative contribution. The life cycle GHG emissions are calculated fo r the following transportation fuel types:

• Conventional Gasoline

• Conventional Diesel Fuel ( ≤ 500 ppm sulfur)

• Kerosene-Based Jet Fuel The physical boundaries of the life cycle include operations that have a significant contribution to the total life cycle GHG emissions. Specifi cally, the average life cycle GHG profile for transportation fuels sold or dist ributed in the United States in 2005 is determined based on the weighted average of fuels produced in the U.S. plus fuels imported into the U.S. minus fuels produced in the U.S. but exporte d to other countries for use. GHG life cycle results are re ported in terms of kg CO 2 

### E/MMBtu LHV of fuel consumed. This metric is dependant on the energy content of the fu el and could alternatively be reported in terms of kg CO 2 

### E/mile traveled. The first expression is more commonly accepted for use in comparing well-to-tank and well-to-wheel/wake (WTW) results. Table ES-1 summarizes the life cycle GHG an alysis study design parameters. Figure ES-5 depicts the magnitude of transportation fuels so ld or distributed in the U.S. in year 2005.

Table ES-1. Life Cycle Greenhouse Gas Study Design

Well-to-Wheels/Wake Life Cycle Boundary (Raw Material Extraction thru Fuel Use) Temporal Representation Year 2005 Technological Representation Industry Average Geographical Representation Transportation Fuel Sold or Distributed in the United States Conventional Gasoline Conventional Diesel Fuel ( ≤ 500 ppm Sulfur) Transportation Fuel Life Cycles Modeled Kerosene-Based Jet Fuel Impact Assessment Methodology Global Warming Potential, IPCC 2007, 100-year time-frame Reporting Metric kg CO 2 E/MMBtu LHV of Fuel Consumed 100% Publically Available Data Full Transparency of Modeling Approach and Data Sources Accounting for 99% of Mass and Energy Accounting for 99% of Environmental Relevance Data Quality Objectives

Process-based (“Bottoms-up”) Modeling Approach

### ES - 6 Figure ES-5. Year 2005 Petroleum Refinery Feedstock and Product Flows



### The physical properties of the final products modeled and the fuel combustion profiles (vehicle/aircraft use) applied to each life cycle have a significant impact on the final results. Table ES-2 summarizes the fuel properties and provides the use profiles used in this study. Application of different physical properties and/or vehicle/ai rcraft use profiles have been identified as common differences between existi ng studies that charact erize the life cycle GHG emissions from conventional transp ortation fuels for comparison to alternative transportation fuel options.

Table ES-2. Product Specifications and Vehicle/Aircraft Use Profiles

Property Conventional Gasoline Conventional Diesel Fuel KeroseneBased Jet Fuel Lower Heating Value (LHV), MMBtu/bbl 4.892 5.512 5.230 Density, lb/gal 6.16 7.07 6.70 Vehicle Fuel Efficiency, MPG 23.7 31.2 Not Applicable Vehicle Total Fuel Use, Btu LHV/mile 4,866 3,737 Not Applicable Use Phase GHG Emissions, kg CO 2 E/MMBtu LHV 76.6 76.7 77.7 Use Phase GHG Emissions, kg CO 2 E/mile 0.373 0.286 Not Applicable * Crude oil input to FOREIGN refineries include only the portion of crude oil considered to be contributing to gasoline, diesel and jet fuel production

### ES - 7 

### Data Limitations The following limitations exist in the body of publicly-available data to characterize the life cycle of conventional transportation fuels sold or distributed in the United States in 2005.

• Crude oil extraction profiles for each country were available for year 2002, not 2005. No significant changes in crude oil extracti on practices were identified for the U.S. or foreign countries with the ex ception of Canada. The magnitude of this limitation was minimized through the development of Canadian crude oil extraction, oil sands production, and bitumen upgrading profiles. The 2005 mix of conventional crude oil, syncrude from oil sands, and blended bitumen imported from Canada was used in this study.

• Level of refinery data collected and repor ted by the Energy Information Administration (EIA) and other industry sources does not pr ovide detail for all pertinent data to differentiate between different gr ades of gasoline, distillate fuel oil or kerosene produced when developing a detailed refinery model. The data represents the “average” for the various grades produced. For example, dist illate fuel was produced and sold as conventional (also referred to as “low-sulfur”) diesel fuel ( ≤ 500 ppm sulfur) and off-road diesel fuel (>500 ppm sulfur) in 2005.

• Oxygenates and other additives used in re formulated gasoline blends were excluded from the study. In 2005, oxygenate input accounted for 4% of the total finished motor gasoline volume from U.S. refinery and ble nder operations (EIA 2008). Development of individual life cycles was determined to add negligible value to the study results when modeled as 100% of the volume from conventional gasoline.

• Foreign refining of conventional gasoline, c onventional diesel fuel, and kerosene-based jet fuel is based on the U.S. refining mode l developed within this study. Significant differences in modeling assumptions a nd boundary conditions for foreign refining operations characterized in the public data vo ided the potential use in this study. The impact of this limitation was evaluated in the sensitivity analysis and determined to contribute less than ± 0.4 % to the total life cy cle GHG results (WTW).

• Vehicle emissions profiles were develope d by the U.S. Environmental Protection Agency, Office of Transportation and Ai r Quality, MOVES model. The profiles represent the average vehicle in operation duri ng the year 2005. The results are reported by vehicle class. Emissions from operation of the vehicle and combustion of the fuel account for 80% of the total life cycle GHG emis sion. Inherent uncerta inties in the use emissions modeling are managed by ensuring consistent and comparable vehicle use profiles are applied when evaluating alte rnative transportation fuel options.

• A statistical average of the aircraft in ope ration in 2005 is not available and emissions associated with cruise methane and nitr ous oxide emissions ar e highly uncertain. Furthermore, gross estimates are used to estima te the relative fuel consumption of cruise and landing and take-off. This limitation is also managed by ensu ring consistent and comparable aircraft use profiles are applied when evaluating alternative transportation fuel options.

### ES - 8 

### Data Quality Assessment Table ES-3 assesses the data quality requirement s identified by the International Standards Organization (ISO) 14044 “Environmental Ma nagement – Life Cycle Assessment – Requirements and Guidelines” as appropriate metr ics for evaluating the qu ality of study results with respect to the study goal and scope.

Table ES-3. Data Quality Assessment of Study Methodology and Results
Quality Metric Qualitative Assessment

Time-related Coverage Crude oil extraction profiles for all countries are technologically representative of year 2005 operations.

Year 2005 industry data, reported to the EIA, was used to characterize sources of refinery feedstock material, refinery energy usage, refinery production data, and imported product data.
Energy intensity and modes of transport were derived from Oak Ridge National Laboratory, Transportation Energy Data Book for year 2005 which are compiled from Department of Transportation statistics.

Vehicle emission profiles (from fuel combustion) are based on the average 2005 U.S. passenger vehicle fleet.

Aircraft emission profile are not specific to 2005 operations, but are consistent with the aviation standard for reporting GHG emissions for the year 2005.

Geographical Coverage U.S. specific models were construct ed to represent all U.S. operations. Country specific crude oil extraction prof iles were used to represent 90% of the total crude oil consumed at U.S. refineries.
Foreign refining operations are based on the NETL U.S. Petroleum Refining Model. Results were compared to non-U.S. studies of foreign refining operations. Due to high variability in re sults of non-U.S. studies, sensitivity analysis was conducted to determine the impact of utilizing the U.S. model.

Technology Coverage Petroleum refining technology has not changed significantly in the past 15- years. All data was evaluated to accu rately represent energy consumption and emission rates relative to year 2005.
Petroleum refining unit process capa city utilization data was based on a 1996 survey of the U.S. petroleum in dustry. Unit process throughput allocation to the product categories was based on a survey of recent literature. Sensitivity analysis wa s conducted on these parameters and determined to have minimal impact on the final results.

Precision Precision was managed by subject matter expert review and quality assessment of data sources and subse quent selection of the best available data representing actual operations in year 2005. Key parameters were evaluated through sensitivity analysis to assess the impact to the final results.

### ES - 9 Quality Metric Qualitative Assessment

Completeness Completeness is achieved within the st udy’s defined cut-off criteria of mass, cost, and environmental relevance cons istent with ISO 14044 life cycle assessment standards. This includes analysis and selection of carbon dioxide, methane, and nitrous oxide as the three types of GHG emissions that have environmental relevance to the total life cycle of petroleumderived transportation fuels.
The refinery model was balanced to 100% based on an iterative calculation procedure to balance both the energy and hydrogen values.

Representativeness The results of this study accurately reflect the 2005 U.S. national average GHG profile for conventional transportat ion fuels sold or distributed using the highest quality data publically-available.

Consistency The study methodology and level of modeling detail were applied consistently throughout all aspects of the study. Any deviations were evaluated through sensitivity analysis and determined to have minor impact to the final results.

Reproducibility The results of this study are 100% re producible. Proprietary purchaseddata from PE International were not reported but these data are publicallyavailable and calculated results in terms of CO 2 E using the PE International data are fully reported. All documentat ion for PE International data sets used in this study is included as an attachment for full transparency.

Sources of Data Industry average data was used as the primary data source. Industry specific data and engineering estimate s were used when industry average data was not available. The source of all data is clearly documented in the report for each unit process modeled.

Uncertainty of the Information Uncertainty is an inherent aspect of performing life cycle based studies. Probability estimates were not determine d for each data point used in this study. Key parameters were assessed th rough sensitivity analysis in place of uncertainty analysis.
This analysis has a variance of less than +/- 4% for the well-to-tank results on any single sensitivity parameter. Use phase results are static (+/- 0%) based on a fixed modeling assumption to manage the variance in the study results. The variance in the life cycle total (well-to-wheels/wake) then equates to less than +/- 1% on any single sensitivity parameter.

Study Quality/Applicable Uses This study reflects the highest qualit y of life cycle (GHG) analysis based on the study goal and scope. Use of t he study results is applicable for all decision types (internal, public, policy, etc.) when used in the appropriate context.

### ES - 10 This page intentionally left blank.

### 1 

## 1.0 Introduction

1.1 Background
The Energy Independence and Security Act of 2007 (EISA 2007), Title II, Subtitle A, Sec. 201 calls for the development of baseline life cy cle greenhouse gas (GHG) emissions for gasoline and diesel sold or distributed as a transpor tation fuel in 2005 to be determined by the Administrator of the U.S. Environmental Protec tion Agency (EPA), after notice and opportunity for comment. That baseline will become the metr ic against which alternative transportation fuels will be evaluated. Under Title V, Subtitle C, Section 526 of the same act, Federal agencies buying either an alternative or a synthetic fuel can do so only if the life cycle GHG emissions from both the “the production and combustion of the fuel” are less than that from a conventional petroleum pathway. The key to determining both the eligibility of a lternative fuel projects for award and justifying the purchase of biofuels and/or synthetic fuels byFederal agencies is the ability to accurately account for life cycle GHG emissions. A life cycle methodology for quantitatively determining GHG gas emissions for the 2005 petroleum baseline is developed in this study. The production and delivery of transportation fuels ha s been widely studied in the United States. Over the past 10 years, the increasing empha sis on GHG emissions in the United States and abroad has resulted in a number of well-documented and cited re ports on the life cycle emissions of diesel fuel and gasoline. Figure 1-1 illustrates the results from various studies for the production and delivery of diesel fuel (commonly referred to as a “well-to-tank” (WTT) analysis). The results vary from 11.8 to 37.5 kg CO 2 

### E/MMBtu LHV 1 

### –a three-fold differential between the minimum and maximum values.
Figure 1-1. Comparison of Diesel Fuel GHG Profiles from Various U.S. Studies

0.0 5.0 10.0 15.0 20.0 25.0 30.0 35.0 40.0
Life Cycle GHG Contribution (kg CO 2 E/MMBtu LHV of Fuel Delivered) EPA, OTAQ (2006) Minimum Value NREL Biodiesel Study (1998) GREET Ver. 1.8b (2008), Year 2005

EPA, OTAQ (2006) Average Value GREET Ver. 1.8b (2008), Year 2010 U.C. Davis, LEM (2003), Year 2015 EPA, OTAQ (2006) Maximum Value GM Study WTT (2001) McCann, O&G Journal (1999), Canadian Light Crude California LCFS (2007) - modified GREET Model McCann, O&G Journal (1999), Saudia Light Crude McCann, O&G Journal (1999), Venezuela Heavy Crude McCann, O&G Journal (1999), Venezuela Very Heavy Crude

From Extraction (oil well)... ...to Fuel Dispensing (vehicle tank).

1 “kg CO 2 E/MMBtu” = kilograms of carbon dioxide (CO 2 ) equivalents (E) per million British thermal units (MMBtu) Lower Heating Value (LHV) of di esel fuel dispensed into a vehicle.

### 2 The large variability in diesel WTT GHG emission profiles raises the questions “ What is the GHG contribution from the production and delivery of diesel fuel, gasoline, and kerosene-based jet fuel in the United States? ” and “ How does one compare alternative fuel options? ” Each of the results presented in Figure 1-1 may be appr opriate based on the individual study purpose and modeling assumptions employed by the authors. Si gnificant differences in results arise primarily from differences in study boundary conditions, t ype of data used in the analysis, technology represented, geographical represen tation of key processes (nationa l average, regional, or sitespecific), time-related coverage (age of the data used in the analysis), and/or the allocation procedures used to assign emissions to operations with more than one valuable product (such as in a petroleum refinery).


## 1.2 Purpose & Goal of the Study
The purpose of this study is to develop baseline data, methodologies, and re sults to determine the life cycle greenhouse gas emissions for liquid fuel s (conventional gasoline, conventional diesel, and kerosene-based jet fuel) production from petroleum as consumed in the U.S. in 2005 to allow comparisons with alternative transportation fuel options on the same basis (i.e., life cycle modeling assumptions, boundaries, and allocation procedures).


## 1.3 Study Boundary and Modeling Approach
The boundary of this study includes both domestic a nd foreign extraction of refinery feedstocks and fuels, transport to U.S. and foreign refineri es (exporting transportation fuels to the U.S.), processing of petroleum to produce transportation fuels, transport to refueling stations, and consumption in either a light-duty passenger vehicl e or a jet aircraft. The life cycle boundary for this study is referred to as “crad le-to-grave.” The “cradle” refers to extraction of raw materials from the earth and the “grave” is represented as the combustion of the fuel in a vehicle. Figure 1-2 graphically represents the boundary for petr oleum-based fuel production operations included within this study. This conceptual boundary ap plies to both liquid fuels produced domestically as well as imported liquid fuels. 

### 1.3.1 Scope of the Environmental Life Cycle Analysis The environmental life cycle analysis (LCA) a pproach utilizes the International Standards Organization (ISO) 14040 “Environmental Manageme nt – Life Cycle Assessment – Principles and Framework.” (ISO 2006) This study includes all four phases of a lif e cycle assessment: Goal and Scope Definition, Inventory Analysis, Impact Assessment, and Interpretation. The scope of the life cycle inventory (LCI) is limited to quantifying greenhouse gas emissions. As a result, the life cycle impact assessment (LCI A) considers only the global warming potential (GWP) of the GHG emissions based on their rela tive contribution. Emissions from various greenhouse gases were assessed during a pre-scr eening assessment to determine the primary emissions of relevance to be tracked and in cluded within the study. Based on analysis of available data, carbon dioxide (CO 2 

### ), methane (CH 4 

### ), and nitrous oxide (N 2 

### O) were identified as the three forms of GHG emissions that have environmental relevance to the total life cycle of petroleum-derived transportation fuels.

### 3 Figure 1-2. Conceptual Study Boundary



### The Intergovernmental Panel on Climate Change (IPCC) publishes the international standard for calculating GWP based on the weighted contri bution of various emissions (IPCC 2001; IPCC 2007). The IPCC publishes values for three time-frames: 20, 100, and 500 years. The U.S. standard is based on the 100-year time-frame . GWP were standardized in 1990, 1996, 2001, and in 2007 by the IPCC. Within this study the mo st current 2007 IPCC values are used. When interpreting older data so urces that report GWP, it is necessary to determine which set of IPCC GWP values were used in the calculation. Table 1-1 lists the primary GHGs and their corresponding 100-year global warming potentials reporte d in mass of CO 2 

### equivalents for the three most recent set of IPCC values.

Table 1-1. GHG Emissions Included in Study Boundary and their 100-year GWP

Emissions to Air Abbreviation 1996 IPCC (GWP CO 2 E) 2001 IPCC (GWP CO 2 E) 2007 IPCC (GWP CO 2 E) This Study (GWP CO 2 E) Carbon Dioxide CO 2 1 1 1 1 Methane CH 4 21 23 25 25 Nitrous Oxide N 2 O 310 296 298 298

### 4 Nitrogen oxides (NO x 

### ) and their impact to global warming are currently being reviewed by climatologists around the world and there is a lack of agreement a bout the impact of NO x 

### in relation to global warming. The 2007 Intergov ernmental Panel on Climate Change (IPCC) report entitled “Climate Change 2007: The Physi cal Science Basis” notes that nitrogen oxides have short lifetimes and complex nonlinear ch emistry with opposing indirect effects through ozone enhancements and methane reduction (IPCC 2007). Most current re search suggests that the GWP for surface/industrial NO x 

### emission may be negative. W ild et al. (2001) report a GWP for industrial NO x 

### emissions of -12. Since there is a lack of agreement on NO x 

### effects, the IPCC has opted to omit them from consideration. 

### 1.3.2 Cut-off Criteria for the System Boundary
Cut-off criteria define the selection of material s and processes to be in cluded in the system boundary. Following the requirements of Internat ional Organization of Standardization (ISO) LCA standard 14044 (ISO 2006), the criteria of ma ss, cost, and environmental relevance were used for material and energy inputs. A significant material input is defined as a materi al input that has a mass greater than 1% of the principal product that is produced by a process. A significant material i nput is also defined as one that has a relatively high cost (for instance, compared to th e cost of the largest, by mass, material input), or has an important envir onmental relevance (for instance, a high GWP). A significant energy input is define d as one that contri butes more than 1% of the total energy used by the process. As with materials, a signif icant energy input is also one that has a relatively high cost or has an important environmental relevance. 

### 1.3.3 Exclusion of Data from the System Boundary All operations are considered pre-existing; th erefore, no construction related emissions are included within the scope of this study. Humans involved in the system boundary have a burden on the envi ronment, such as driving to and from work and production of food they eat, that is part of the overall life cycle. However, this complicates the life cycle tremendously due to the data collection re quired to quantify the human-related inflows-from and out flows-to the environment and how to allocate them to fuel production. Furthermore, it is assumed that th e workforce will be unaffected by the choice of fuel at large-scale production volumes . Issues related to humans, su ch as the societal impacts of humans in the workforce that need to be addr essed through policy and value-based decisions, are outside the scope of this life cycle study. Low frequency, high magnitude environmental events (e.g., accidental releases) were not included in the system boundary since such circum stances are difficult to predict, quantify, or associate with a particular product. However, where the impact of operational abnormalities is embedded in 2005 data, no attempt was made to account for or quantify the effects. For example, no adjustment was made for the at ypical energy usage, feedstock quality and production volumes embedded in reported data in 2005 associated with shut -down of Gulf Coast refineries impacted by hurricanes Katrina and Rita . More frequent, but perhaps lower magnitude events, such as material loss during trans port, are included in the system boundary.

### 5 

### 1.3.4 Data Reduction and Allocation Procedures In order to generate a life cycl e inventory for each pathway, the va st array of collected secondary data (data not directly usable but which in concert with other data meets the necessary requirements) must be reduced using numerous calculations and equations. These reductions constitute manipulation of the secondary data to conform it to the requirements of the goal and scope of this study (e.g., relating data to a functional unit, da ta aggregation, allocation of flows/releases, etc.). ISO standards, where appr opriate, are used as guidelines in performing data reductions and allocation procedures (ISO 2006). System expansion and unit process division ar e the two methods recommended within ISO 14044 for avoiding allocation wherever possible (i.e ., avoiding allocation is preferred) and are used within this study. The disp lacement method, a type of sy stem expansion, is recommended by the U.S. Environmental Protection Agency (EPA) for allocating co-products from energy conversion facilities producing transportati on fuels (EPA 2007). The displacement method expands the system boundary to include the produ ction of co-products by other means that would theoretically be avoided as a result of secondary production by the primary process being modeled. When system expansion is determined not to be feasible, then the following shall apply. In general, flows associated with ener gy carriers or any material s produced for its energy value are allocated based on energy content. A ll other materials and co -products are allocated based on mass or volume. Allocation by economic value was not performed in this study.


### 1.3.5 Geography, Technology and Time-frame Represented The scope of this study is the production and deli very of petroleum-base d liquid transportation fuels sold or distributed in the United States in 2005. Consumption of transportation fuels in Puerto Rico and the Virgin Islands is excluded. The technology represen ts existing operations for 2005. The primary source of U.S. petroleum refining opera tions data used in the analysis is the U.S. Department of Energy (DOE), Energy Informa tion Administration (EIA) petroleum industry statistics. Refinery equipment is surveyed annually on January 1 st 

### providing a snapshot of refinery operations. Refinery equipment and capacities reported on January 1, 2006, are assumed to be representative of that which was in operation in 2005. Using this data set allows comparison with the Oil & Gas Journal 2005 Worl dwide Refining Survey which also presents data as of January 1, 2006. The vehicle emissions for conventional gasoline a nd conventional diesel are representative of the average fleet of light-duty passenger vehicles for 2005. This data was obtained from EPA and was extracted from the MOVES model (EPA 2008).
Aircraft emissions estimates were derived from emission factors for typical jet aircraft operation, as reported by the IPCC in 2006 (IPCC 2006).


## 1.4 Life Cycle Stages
The boundary for this study is from cradle-to- grave or raw material acquisition through the consumption of the fuel by the vehicle/aircraft. The following five life cycle (LC) stages are used to organize data and report results:

### 6 • Life Cycle Stage #1: Raw Material Acquisition

• Life Cycle Stage #2: Raw Material Transport

• Life Cycle Stage #3: Liquid Fuels Production

• Life Cycle Stage #4: Product Transport and Refueling

• Life Cycle Stage #5: Ve hicle/Aircraft Operation Figure 1-3 depicts the flow of petroleum refining feedstocks and products of interest through the life cycle stages and highlights the key activities occurring within the U.S. and in foreign countries.
Figure 1-3. Flow of Petroleum Refining Feedstock and Products through the Life Cycle Stages



### The following briefly describes the boundary of each LC stage. Environmental modeling assumptions applied to each of the LC stages are documented in Sections 2.0 to 6.0 of this document.

• Life Cycle Stage #1: Raw Material Acquisition

o Boundary includes extraction of raw feedstocks from the earth and any partial processing of the raw materials that may occur.

o Feedstocks include foreign and domestic cr ude oil, natural gas liquids, unfinished oils, and unconventional hydr ocarbons (e.g. oil sands).

### 7 • Life Cycle Stage #2: Raw Material Transport

o Boundary begins at the end of extraction/ processing of the raw materials and ends at the entrance to the petroleum refineries.

o Feedstocks are transported from both dome stic and foreign sources to U.S. and foreign refineries.

• Life Cycle Stage #3: Liquid Fuels Production

o Boundary starts at the entrance of the petr oleum refinery with the receipt of crude oil (and other feedstock inputs) and ends at the entrance to the petroleum pipeline used to transport the liquid fuel s to the bulk fuel storage depot.

o Petroleum refinery operations ar e both foreign and domestic.

o Emissions associated with acquisition and production of indirect fuel inputs such as purchased power and steam, purchased fu els such as natural gas and coal, and fuels produced in the refinery and subseque ntly consumed therein are included in this stage.

o Emissions associated with on-site and off-site hydrogen production are included in this stage, including emissions associ ated with raw material acquisition for hydrogen plant feedstock and fuel.

o Production of oxygenates is excluded from the scope of this study.

• Life Cycle Stage #4: Product Transport and Refueling

o Boundary starts at the exit of the petroleum refinery and ends with dispensing the fuel into the vehicle/aircraft.

o Boundary includes the operation of the bul k fuel storage depot for gasoline and diesel and the airport fuel storage tanks.

o Boundary includes the operation of liquid fu el tanker trucks used to transfer the gasoline/diesel from the depot to the vehi cle fueling stations and the transport of jet fuel from the airport fuel storage ta nks to the aircraft by a refueling truck.

• Life Cycle Stage #5: Ve hicle/Aircraft Operation

o Boundary starts at the vehicle/aircraft fu el tank and ends with the combustion of the liquid fuel.

### 8 

## 2.0 LC Stage #1: Raw Material Acquisition

LC Stage #1 consists of extraction of raw refinery feedstocks (crude oil and equivalent, natural gas liquids, and unfinished oils) from the ear th and associated pos t-extraction-processing required to derive a feedstock-qua lity input. This section desc ribes the environmental modeling assumptions associated with this LC stage for fe edstocks for U.S. petrol eum refineries and for foreign petroleum refineries producing gasoline, diesel and kerosene-based jet fuel imported by the U.S. in 2005. Figure 2-1 depicts the activitie s and flow of feedstoc ks for LC Stage #1.
Figure 2-1. Flow Diagram of Raw Material Acquisition Activities

Domestic Crude

Oil Extraction

Foreign Crude Oil Extraction Transport to U.S. Refineries

Canadian Oil Sands

Extraction and

Processing Natural Gas Liquids

Production and

Processing

Unfinished Oils Production and

Processing Transport to Foreign Refineries Exporting Conventional Gasoline,

Conventional Diesel and Kerosene-Based Jet Fuel to the U.S. LC Stage #1: Raw Material Acquisition LC Stage #2: Raw Material Transport

U.S. Operations Non-U.S. Operations



## 2.1 Raw Material Acquisition for Domestic Petroleum Refineries
Table 2-1 shows the daily refinery input of feedstocks in barrels (bbl) to U.S. refineries in 2005 (excludes refining operations in the Virgin Islands and Puerto Rico). Emissions profiles associated with extraction and processing for th e following petroleum refinery feedstocks are included in this stage:

• Crude oil and other hydrocarbons fed to refineri es as synthetic crude (i.e. from Canadian oil sands)

• Natural Gas Liquids

• Unfinished Oils

### 9 Table 2-1. Daily Refinery Feedstock Input in 2005 (EIA 2008)

Feedstock Input (thousand bbl/day) Crude Oil 15,220 Natural Gas Liquids 432 Unfinished Oils (net) 569



### Each raw material acquisition process is described below.


### 2.1.1 Crude Oil Acquisition
The crude oil mix fed to U.S. refineries include s domestic and foreign crude oil. Extraction profiles are modeled for the foreign sources show n in Table 2-2 which (when added to the U.S. resources) account for over 90% of the tota l crude input to U.S. refineries in 2005.

Table 2-2. Sources of Crude Oil Utilized at U.S. Petroleum Refineries in 2005

U.S. Crude Oil Sources Production/Import as % of Refinery Crude Input (Year 2005, EIA) U.S. Crude Oil 33.8% Canada Crude Oil Canada Oil Sands 10.7%

Mexico Crude Oil 10.2% Saudi Arabia Crude Oil 9.4% Venezuela Crude Oil 8.1% Nigeria Crude Oil 7.1% Iraq Crude Oil 3.4% Angola Crude Oil 3.0% Ecuador Crude Oil 1.8% Algeria Crude Oil 1.5% Kuwait Crude Oil 1.5% Total 90.5%



### 2.1.1.1 Crude Oil Extraction GHG Profiles Country-specific crude o il extraction profiles were purchased from PE In ternational (2008) for the U.S. crude oil sources listed in Table 2-2, with the exception of Canada. The Canadian profile was derived independently by N ETL. The global warming potential in CO 2 

### equivalents (utilizing the factors in Table 1- 1) associated with the purchase d extraction profiles is shown in Table 2-3. The data are representative of 2002 ra ther than 2005 but this temporal difference is expected to result in minor differences in the upstream profile for conventional crude oil extraction.

### 10 Table 2-3. GHG Emissions Consistent with Extraction of Crude Oil in Countries Exporting to U.S. Petroleum Refineries in 2005

Crude Oil Source GHG Emissions (kg CO 2 E/bbl of crude oil)
U.S. Crude Oil 24.5 Saudi Arabia Crude Oil 13.6 Mexico Crude Oil 38.4 Venezuela Crude Oil 24.2 

### § Nigeria Crude Oil 128.6 Iraq Crude Oil 19.6 Angola Crude Oil 81.8 Ecuador Crude Oil 31.3 Algeria Crude Oil 35.1 Kuwait Crude Oil 16.5



### Differences in the extraction profiles from count ry-to-country are significant. Much of the variability can be explained by the reported flari ng and venting rates consistent with crude oil extraction in each of the countries. Figure 2-2 shows the relationship between flaring rate and CO 2 

### emissions. A dotted line is adde d to show what the expected CO 2 

### emissions would be if the gas flared is assumed to be na tural gas. Figure 2-3 shows the relationship between venting rate and CH 4 

### emissions. A dotted line is added to show what the expected methane emissions would be assuming the vented gas if 75% by weight methane is assumed. Fl aring and venting data presented in these figures are consistent with th e values reported in the documentation associated with the crude oil extracti on profiles (Attachment 1). §
Figure 2-2. Country-Specific CO 2 Emissions Associated with Crude Oil Extraction Relative to Reported Flaring

Angola

Equador

Iraq Mexico Nigeria

Venezuela U.S. Algeria

Kuwait Saudi Arabia

0.000 0.00 Flared Hydrocarbons (per kg of crude oil)CO2Emissions(per kg of crude oil)

Predicted CO 2 emissions assuming flaring emissions are equivalent to natural gas combustion emissions PLUS an estimated baseline value

§ A sensitivity analysis was performed on these parameters.

### 11 Figure 2-3. Country-Specific Methane Emissions Associated with Crude Oil Extraction Relative to Reported Venting

Angola

Iraq Mexico Nigeria

Algeria Equador

Kuwait Saudi Arabia Venezuela U.S. 0.00000 0.0000 Vented Hydrocarbons (per kg of crude oil)Methane Emissions(per kg of crude oil)

Predicted methane emissions assuming vented gas is 75% methane (by weight)



### 2.1.1.2 Canadian Crude Oil Mix Extraction GHG Profile For Canada, the crude oil mix extraction profile will vary significantly based on the assumed mix of oil sands and conventional crude oil. As Canada was the larg est foreign contributor of crude oil to U.S. refineries in 2005, this variability can have a significant impact on the final U.S. composite extraction profile. For this reason, separate profiles for Canadian conventional crude oil extraction and Canadian oil sands extraction and processing were developed to allow for increased quality and transparency.



### Conventional Canadian Crude Oil Determining an emissions profile for Canadian conventional crude oil ex traction is challenged due to the inclusion of oil sands activities in many reported data. The Canadian Association of Petroleum Producers (CAPP) sponsored the development of a report determining a GHG emissions inventory for upstream oil and gas ope rations. However, in this report indirect emissions from purchased power and steam were not fully quantified. CAPP noted that convenient and reliable sour ces of these data genera lly do not exist (CAPP 2004). The U.S. crude oil extraction GHG emissions profile has been adjusted for use as an estimate for the Canada crude oil extraction profile. Because of the strong relationship between flaring and venting rates associated with crude oil extraction and the CO 2 

### and methane emissions profiles, the U.S. profile was modified to account for th e differences in reported flaring and venting for U.S. and Canada extraction activities. Assuming that the gas flared is natural gas, and the gas vented is 75% by weight methane, the resulting Canada profile is as shown in Table 2-4. The U.S. profile is provided for reference.

### 12 Table 2-4. GHG Emissions Consistent with Extraction of Canadian Conventional Crude Oil Based on Adjusted U.S. Crude Oil Extraction Emissions Profile

Crude Oil Source GHG Emissions (kg CO 2 E/bbl of crude oil)
Canadian Crude Oil 35.2 U.S. Crude Oil 24.5



### Canadian Oil Sands The Canadian crude oil mix exported to the U.S. in 2005 included conventi onal crude oil as well as oil sands products (either dilu ted crude bitumen or synthetic crude produced from extracted bitumen). In 2005, the U.S. refinery crude feed stock mix contained 3.5% oil sands (NEB 2006). Of this amount, 43% was input as blended bitu men, 35% as light synthe tic crude, and 21% as heavy synthetic crude (NEB 2006). The environmental emissions and GHG profile is significantly higher for oil sands than for conventiona l crude oil and there is variation in the oil sands profile depending upon the method of extr action and final quality of the material. Table 2-5 shows the GHG emissions profiles used for crude bitumen and synthetic crude from oil sands as well as the composite profile for input to U.S. refineries in 2005. These values were derived using actual emissions reported by two pr imary producers, Imperial Oil and Syncrude, and their estimated 2005 production ra tes, as reported by the resp ective operators. Together, these two operations accounted for approximate ly 33% of the Canadian oil sands bitumen production in 2005 (AEUB 2006).
Table 2-5. GHG Emissions Consistent with Extraction and Processing of Canadian Oil Sands 

### §

Emissions (kg/bbl synthetic crude oil) Source CO 2 CH 4 N 2 O References/Comments

Crude Bitumen 80.8 0.00943 0.00114 (EnvCan 2008); estimated using Imperial Oil Cold Lake data; (Imperial Oil 2006) Synthetic Crude from Oil Sands 122 0.426 0.00410 (EnvCan 2008); (Syncrude 2006)
Study Value for Input to U.S. Refineries 104 0.247 0.00283 43% Crude Bitumen & 57% Synthetic Crude


### 2.1.1.3 Crude Oil Mix Composit e Extraction GHG Profiles Figure 2-4 compares the global warming poten tial for crude oil extraction based on the purchased profiles, the developed Canadian conven tional and oil sands profiles, the profile used for the remaining foreign import sources, and the U.S. composite profile. The extraction profile for the remaining foreign import sources (9.5%) has been approximated by assuming that the GHG profile is equivalent to the average profile for the foreign sources listed in Table 2-2 (excluding Canadian oil sands). §

§ A sensitivity analysis was performed on these parameters.

### 13 The GHG emissions associated with extraction op erations for the 2005 composite crude oil input to U.S. refineries are reported in Table 2-6.

Figure 2-4. GHG Emissions Consistent with Extraction of Crude Oil Input to U.S. Refineries in 2005

0 20 40 60 80 100 120 140

United States
Canada Crude Oil Canada Oil Sands
Saudi Arabia
Mexico
Venezuela Nigeria Iraq Angola
Ecuador

Algeria
Kuwait Other (Foreign Average) GWP (kg CO 2 E/bbl crude oil extracted)

Composite Mix to U.S. Refineries in 2005

Table 2-6. GHG Emissions Consistent with Extraction of Composite U.S. Crude Oil Mix for 2005
Emissions (kg/bbl crude oil) Source CO 2 CH 4 N 2 O Conventional Crude Oil Only 23.5 0.525 0.000641 Crude Oil and Canadian Oil Sands 26.3 0.515 0.000717



### 2.1.2 Natural Gas Liquids Extraction and Processing Natural gas liquids (NGL) are hydrocarbons ex tracted from a reservoir during natural gas recovery. Natural gas liquids in clude primarily ethane, propane, butanes, and pentanes and are separated from the natural gas (methane) during processing. The emissions profile for natural gas liquids has been estimated using Canadian data for upstream oil and gas operations. The emissions profile generated is fo r natural gas liquids produced from a natural gas well (NGL processing from an associated oil and gas production operation may differ due to the different proc essing options available). Table 2-7 shows emission factors for natural gas production and processing in Canada in 2000 (CAPP 2004). No significant technology differences/advances occurred in the field of oil and gas extraction in the years between 2000 and 2005 and therefore the data meets the quality objectives for this study.

### 14 Table 2-7. Emissions from Natural Gas Production and Processing (CAPP 2004)
Emissions (tonnes/million m 3 raw natural gas produced) Source CO 2 CH 4 N 2 O Natural Gas Production 42.7 2.34 0.0040 Natural Gas Processing 90.4 0.29 0.0032
Total 133 2.63 0.0072



### Since NGL are produced via the sa me general mechanisms as natural gas (NG), the volume of NG that is extracted and processed to produce a quantity of NGL is allocated to the NGL component. Based upon EIA’s Natural Gas Annual 2005 Table 7, NGL production totaled 619,884 thousand barrels (Mbbl) in the U.S. and th is resulted in an apparent NG extraction volumetric loss of 876,497 million cubic feet (cf) . Thus, for every barrel of NGL produced, 1,414 cf of NG is extracted and processed. Applying the Canadian emission factors to the above quantity of NG extracted/processed, an emissions profile for NGL is generated, as shown in Table 2-8.
Table 2-8. Emissions from Natural Gas Liquids Production and Processing
Emissions (kg/bbl natural gas liquids produced) Source CO 2 CH 4 N 2 O Natural Gas Liquids 5.33 0.105 0.000288



### 2.1.3 Unfinished Oils Ex traction and Processing
Unfinished oils are modeled in a similar manner to crude oil but have an additional emission component associated with atmospheric/vacuum distillation column opera tion. EIA reports the unfinished oils input to refineri es in barrels per day (bpd) by fraction, as shown in Table 2-9.
Table 2-9. Unfinished Oils Net Input to U.S. Refineries in 2005 (EIA 2008)

Composition Input (bpd) Percent of Total
Naphthas and Lighter 74,759 13% Kerosene and Light Gas Oils* -10,575 -2% Heavy Gas Oils 382,592 67% Residuum 122,351 21% Unfinished Oils (net) 569,126 100% * Negative value due to inventory accounting 

### The extraction profile is modeled to be the sa me as the U.S. composite crude oil profile (excluding Canadian oil sands) generated in Section 2.1.1. The minimum additional processing for the unfin ished oils is assumed to be atmospheric distillation separation for all co mponents. Residuum is anticip ated to also pass through the vacuum distillation column. Energy usage, and a ssociated emissions, consistent with performing these operations (see Life Cycle Stage #3) are ad ded to the crude oil composite to generate a total for the unfinished oils fr action as shown in Table 2-10.

### 15 Table 2-10. Emissions for Unfinished Oils Extraction and Processing
Emissions (kg/bbl unfinished oils) Source CO 2 CH 4 N 2 O Extraction 23.6 0.526 0.000643 Processing 14.7 0.0177 0.000258 Total 38.3 0.544 0.000901



### 2.1.4 LC Stage #1 Summary for Domestic Refineries The following table summarizes the upstream G HG emissions profiles for the U.S. refinery feedstocks for 2005. The results are based on the f eedstock volumes delivered to U.S. refineries and thus the additional crude o il extraction required to account for losses and the associated emissions are incorporated here. Additional information on the loss factors applied are detailed in Appendix H.

Table 2-11. GHG Emissions from Feedstock Extraction for Input to Domestic Refineries in 2005 Emissions (kg/day) Feedstock Input (bpd) CO 2 CH 4 N 2 O Crude Oil 14,692,542 346,326,430 7,734,105 9,448 Canadian Oil Sands 527,545 55,276,887 130,421 1,495 Natural Gas Liquids 432,044 2,302,453 45,496 125 Unfinished Oils (net) 569,126 21,804,399 309,632 513 Total 16,221,258 425,710,170 8,219,654 11,581



## 2.2 Raw Material Acquisition for Foreign Petroleum Refineries
Refined petroleum products were imported in 200 5 and contributed to th e overall U.S. liquid fuels GHG footprint. Upstream emissions for those materials imported to the U. S. were estimated and added to the U.S. refining upstream profile to gain a comp rehensive view of the GHG emissions consistent with use of liquid fuels in the U.S. in 2005. Crude oil was refined in and finished products e xported from a distinct se t of foreign countries for each fuel–gasoline, diesel and jet fuel. Feedstock extraction modeling was conducted and results compiled for each of these sets of fo reign countries. Appendix A outlines the specific sources for imported gasoline (and as sociated blendstocks), diesel ( ≤ 500 ppm sulfur), and kerosene-based jet fuel as reported by EIA. Table 2-12 shows the im port quantities and the percent of U.S. consumption for 2005 that the import quantity represents. Significant proportions of gasoline and jet fuel are imported but only a small fraction of diesel fuel.

### 16 Table 2-12. Import Quantities of Petroleum Fuels in 2005 and Percent of 2005 U.S. Consumption

Import Quantity (bpd) Imports as a % of 2005 U.S. Consumption
Conventional Gasoline 1,106,712 12.7% Conventional Diesel 157,164 5.2% Kerosene-Based Jet fuel 190,049 11.3%



### All countries which exported finished products of interest to the U.S. in 2005 are shown in Table 2-13. Data for the raw material extraction process is divided into three categories depending upon data availability for crude oil extraction profiles.

Table 2-13. Petroleum Products Import Sources and Data Availability for Raw Material Extraction GHG Emissions

Exporting Country Country-Specific Crude Oil Extraction Profile Used Country-Specific Delivered Crude Oil Profile Used Surrogate Profile

Algeria Yes Angola Yes Argentina FA Aruba FA Australia Yes Bahamas FA Belgium Yes Brazil Yes Bulgaria FA Canada Individually Developed Chile FA China, Peoples Rep Yes Colombia FA Congo (Brazzaville) FA Denmark EU-15 Ecuador Yes Egypt FA Estonia EU-25 Finland Yes France Yes Gabon FA Georgia FA Germany Yes Ghana FA India FA Indonesia FA

### 17 Exporting Country Country-Specific Crude Oil Extraction Profile Used Country-Specific Delivered Crude Oil Profile Used Surrogate Profile

Iraq Yes Ireland EU-15 Italy Yes Japan Yes Kazakhstan FA Korea, South Saudi Arabia Kuwait Yes Latvia EU-25 Lithuania EU-25 Malaysia FA Martinique FA Mexico Yes Netherlands Yes Netherlands Antilles FA Nigeria Yes Norway Yes Peru FA Philippines FA Poland EU-25 Portugal Yes Qatar FA Romania FA Russia Yes Saudi Arabia Yes Singapore FA Spain Yes Sweden Yes Taiwan FA Thailand FA Trinidad & Tobago FA Turkey FA Turkmenistan FA United Kingdom Yes Uruguay FA Venezuela Yes Virgin Islands, U.S. Individually Developed FA = Foreign Average (Average of Australia, Belgium, Brazil, China, EU-15, EU-25, Finland, France, Germany, Italy, Japan, Netherlands, Norway, Port ugal, Russia, Spain, Sweden, and United Kingdom) EU-15 includes Austria, Belgium, Denmark, Finland, France, Germany, Greece, Ireland, Italy, Luxembourg, the Netherlands, Portug al, Spain, Sweden and the United Kingdom EU-25 includes EU-15 plus Cyprus, Czech Republic , Estonia, Hungary, Latvia, Lithuania, Malta, Poland, Slovakia, and Slovenia

### 18 

### Country-Specific Crude Oil Extraction Profiles Emissions data for crude oil extr action for the top countries supplyi ng crude oil to the U.S. were purchased from PE International (2008). Of the foreign countries for which extraction information was obtained, Angola, Ecuador, Iraq, Kuwait, Mexico, Nigeria, Saudi Arabia, and Venezuela report no crude oil imports for 2005 (IEA 2008). Algeria imports a small quantity of crude oil (less than 0.5% of the produced quantit y) (IEA 2008). For all of the aforementioned countries it is assumed that the country-specific extraction profile is repr esentative of the crude oil being fed to refineries in these countries.


### Country-Specific Delivered Crude Oil Profile Country-specific “free-to-customer” or in-country delivered crude oil mix profiles were extracted from GaBi 4 Life Cycle Assessment Software, Pr ofessional Database (2007), when available. Delivered “free-to-customer” country-specifi c profiles include an embedded transport component in the GHG profile. The extraction c ontribution to the total GHG profile has been estimated by determining the GHG contribution of th e extraction step to th e total U.S. delivered GHG profile and assuming that the same relative contribution of the extraction component is applicable to foreign crude oil mixes. For crude oil delivered to domestic refineries, 75% of the CO 2 

### , 99% of methane, and 80% of nitrous oxide is attributable to raw material acquisition. The embedded transport component which is excluded he re is incorporated in LC Stage #2 modeling.


### Canada Profile The Canada composite profile was individually de veloped, as it is a primary liquid fuel exporter to the U.S. and its refineries import a significant po rtion of their feedstocks. Table 2-14 lists the refinery feedstocks—both foreign and domestic—i nput to Canadian refineries in 2005. Over 50% of the Canadian refinery feedstocks for 2005 were attributable to foreign crudes.
Table 2-14. Canadian Refinery Feedstocks for 2005 (StatCan 2008)

Country/Crude Source Quantity (thousands
m 3 ) % of Total Crude Oil and

Equivalent Quantity (bpd)
Imports Algeria 9,469 8.8% 163,170 Angola 908 0.8% 15,652 Iraq 3,803 3.6% 65,531 Nigeria 1,426 1.3% 24,570 Saudi Arabia 4,386 4.1% 75,574 Venezuela 2,805 2.6% 48,342 Russia 1,263 1.2% 21,759 Norway 13,961 13.0% 240,579 United Kingdom 8,461 7.9% 145,808 United States 1,226 1.1% 21,130 Mexico 2,153 2.0% 37,103 Ecuador 351 0.3% 6,054 Other Countries 3,574 3.3% 61,587 Total Imports 53,786 50.2% 926,860

### 19 Country/Crude Source Quantity (thousands
m 3 ) % of Total Crude Oil and

Equivalent Quantity (bpd)

Domestic Production Canada Crude (light + heavy) 32,402 30.3% 558,370 Synthetic Crude Oil (li ght) 14,836 13.9% 255,663 Crude Bitumen 4,065 3.8% 70,056 Condensates and pentanes + 2,024 1.9% 34,885 Total Domestic 53,328 49.8% 918,974 Total Imports + Domestic 107,114 100.0% 1,845,833



### Country-specific extraction profiles obtained for PE International (2008) were utilized for all foreign crude oil sources with the exception of Russia, Norway and the United Kingdom. For the three latter countries, the delivered crude oi l profile is used after removing the estimated transport component. The underlying assumption in using these profiles is that the GHG extraction profile for the crude oil mix utilized in these countries is equivalent to the profile for the crude oil exported from those countries. For Canadian conventional crude oil, the extr action profile was developed as described in Section 2.1.1.1. For Canadian oil sands, Table 2- 6 lists the upstream em issions on a per-barreloil-equivalent basis. For this profile, synthetic crude oil (lig ht) upstream emissions were taken from Syncrude emissions reports for 2005 (EnvC an 2008), (Syncrude 2006) and crude bitumen upstream emissions were approximated by assumi ng Imperial Oil Cold Lake bitumen production emissions are representative of all 2005 crude bitumen production operations. Condensates and pentanes plus were modeled the sa me as U.S. NGL (see Section 2.1.2). The resulting extraction profile fo r feedstocks to Canadian refine ries in 2005 is shown in Table 2-15.

Table 2-15. GHG Emissions Consistent with Extraction of Crude Oil Mix to Canadian Refineries in 2005
Emissions (kg/bbl crude oil) Source CO 2 CH 4 N 2 O Crude Oil Mix Average 35.0 0.366 0.00102



### Virgin Islands Profile The Virgin Islands profile was also developed in dividually as it is a primary liquid fuel exporter to the U.S. and its refineries import all of their feedstocks, as shown in Table 2-16.

### 20 Table 2-16. Virgin Islands Refinery Feedstocks for 2005 (EIA 2008)

Country/Crude Source Import Quantity (bpd) % of Total Crude Oil and Equivalent Angola 7,984 1.7% Colombia 8,858 1.9% Ivory Coast 2,584 0.6% Gabon 65,479 14.2% Iraq 1,233 0.3% Nigeria 29,945 6.5% Norway 28,162 6.1% Peru 989 0.2% United Kingdom 8,395 1.8% Venezuela 307,767 66.7% Total 461,395 100.0%



### As available, country-specific extraction profiles obtained for PE International (2008) were utilized for all foreign crude o il sources. Colombia was modeled using Venezuela as a surrogate profile, Peru was modeled using Ecuador as a su rrogate profile, and th e Ivory Coast and Gabon were modeled using Angola as a surrogate prof ile. The resulting extraction profile for feedstocks to Virgin Island refine ries in 2005 is shown in Table 2-17.
Table 2-17. GHG Emissions Consistent with Extraction of Crude Oil Mix to the Virgin Islands Refinery in 2005
Emissions (kg/bbl crude oil) Source CO 2 CH 4 N 2 O Crude Oil Mix Average 23.0 0.634 0.000590



### Surrogate Profiles For other countries, a surrogate profile was c hosen based upon either geographic location or primary crude source. For any European country for which a country-sp ecific delivered profile was not available, the EU-15 or EU-25 delivered profile was utilized. For South Korea, the crude source is primarily Saudi Arabia (EIA 2008) . For all other countries , the crude oil profile is estimated as simply a foreign av erage (FA) of the delivered profiles. § The foreign average is used for 9% of the gasoline cr ude oil mix, 12% of the diesel cr ude oil mix, and 22% of the jet fuel crude oil mix. With th e exception of Saudi Arabia, th ese profiles represent the GHG emissions for delivered crude oil and the em bedded transport component was removed as previously described. Table 2-13 lists the export coun tries and the upstream profile us ed to determine the crude oil extraction emissions. Figure 2-5 shows the gl obal warming potential (calculated using the factors in Table 1-1) for each of the profiles utilized and devel oped. For the delivered crude oil profiles, the transport co mponent was excluded.

§ A sensitivity analysis was performed on these parameters.

### 21 Figure 2-5. GHG Emissions Consistent with Crude Oil Extraction

0 20 40 60 80 100 120 140

Algeria Angola
Ecuador Iraq
Kuwait
Mexico Nigeria
Saudi Arabia

Venezuela
United States Foreign Average Extraction
Canada Conventional
Canada Blended Bitumen

Canada Synthetic Crude
Australia Belgium
Brazil
China
EU-15
EU-25
Finland
France Germany Italy Japan
Netherlands Norway Portugal

Russia

Spain
Sweden United Kingdom Foreign Average Del'd
United States
Canada Virgin Islands GWP (kg CO 2 E/bbl crude oil extracted)

2002 Crude Oil Extraction Profiles (derived from PE 2008)

2005 Canadian Oil Sands Extraction and Processing Profiles (derived from available data) 2002 Crude Oil Delivered Profile ex Transport (derived from GaBi 4 2007)

2005 Extraction Profile for Crude Oil Mix to Refineries (individually derived using above profiles)

### 22 

### 2.2.2 Raw Material Extraction for Gasoline Imports Imported motor gasoline and asso ciated blendstocks amounted to 14.2% of domestic gasoline production in 2005. Imports come from many diff erent countries, as shown in Appendix A. Canada (15.8%), the Netherlands (10.5%), Virg in Islands (10.5%), th e United Kingdom (10.3%), and Venezuela (7.6%) were the top exporters of gasoline (and associ ated blendstocks) to the U.S. in 2005. The composite GHG emissions profile cons istent with extraction of the crude oil mix used in refining of gasoline imported to the U.S. in 2005 is shown in Table 2-18.

Table 2-18. GHG Emissions Consistent with Extraction of Composite Crude Oil Mix for Foreign Gasoline Refining in 2005
Emissions (kg/bbl crude oil extracted) Source CO 2 CH 4 N 2 O Crude Oil Mix Average 19.3 0.429 0.000497



### 2.2.3 Raw Material Extraction for Diesel Imports Diesel is imported primarily from Canada and th e Virgin Islands and these two sources make up 68.5% of the total U.S. diesel imports ( ≤ 500 ppm sulfur). European countries (Belgium, Denmark, Estonia, France, Germany, Latvia, L ithuania, Netherlands, Sweden, and the United Kingdom) make up an additional 11.5%. The origin of U.S. distillate imports for 2005 is shown in Appendix A along with the quantity impor ted. The composite GHG emissions profile consistent with extraction of the cr ude oil mix used in refining of diesel fuel imported to the U.S. in 2005 is shown in Table 2-19.

Table 2-19. GHG Emissions Consistent with Extraction of Composite Crude Oil Mix for Foreign Diesel Refining in 2005
Emissions (kg/bbl crude oil extracted) Source CO 2 CH 4 N 2 O Crude Oil Mix Average 25.0 0.437 0.000676



### 2.2.4 Raw Material Extraction for Jet Fuel Imports The primary import sources for jet fuel in 2005 were South Korea (21.9%), followed by the Virgin Islands (16.7%) and Venezu ela (15.7%). The origin of U.S. jet fuel imports for 2005 is shown in Appendix A along with the quantity im ported. The composite GHG emissions profile consistent with extraction of th e crude oil mix used in refining of kerosene-based jet fuel imported to the U.S. in 2005 is shown in Table 2-20.

Table 2-20. GHG Emissions Consistent with Extraction of Composite Crude Oil Mix for Foreign Jet Fuel Refining in 2005
Emissions (kg/bbl crude oil extracted) Source CO 2 CH 4 N 2 O Crude Oil Mix Average 18.0 0.315 0.000448

### 23 

## 2.3 Summary of Life Cycle Stage #1 GHG Emissions Profiles
Table 2-21 summarizes the emissions profiles asso ciated with acquisition of petroleum refining feedstocks for U.S. refineries and foreign refineries producing gasoline, diesel and jet fuel imported by the U.S. in 2005. Emissions are pr esented per barrel of feedstock extracted. Emissions associated with Canadian oil sands ex traction and processing are included in the crude oil extraction profile.
Table 2-21. Summary of GHG Emissions Consistent with Extraction of Crude Oil and Other Feedstocks for U.S. and Foreign Refineries in 2005
Emissions (kg/bbl extracted) Source CO 2 CH 4 N 2 O Feedstock Extraction for U.S. Refineries Crude Oil 26.3 0.515 0.000717 NGL 5.33 0.105 0.000288 Unfinished Oils 38.3 0.544 0.000901 Crude Oil Extraction for Foreign Refineries Gasoline Imports 19.3 0.429 0.000497 Diesel Imports 25.0 0.437 0.000676 Jet Fuel Imports 18.0 0.315 0.000448

### 24 

## 3.0 Life Cycle Stage #2: Raw Material Transport

Emissions profiles associated with transportation for the following petroleu m refinery feedstocks are included in this stage:

• Crude oil and other hydrocarbons (i.e. from Ca nadian oil sands) fed to refineries as synthetic crude

• Natural Gas Liquids

• Unfinished Oils Figure 3-1 depicts the activities and flow of feedstocks for LC Stage #2.
Figure 3-1. Flow Diagram of Raw Material Transport Activities

U.S. Crude Oil

Extraction

Other Foreign

Crude Oil Extraction U.S. Refinery Operations Other Feedstock Acquisition

Canadian Crude Oil Extraction Transport within U.S.

Pipeline, waterborne,

rail, truck LC Stage #2: Raw Material Transport

Pipeline Transport to Border

Tanker Transport to U.S. Port Pipeline Transport to Foreign Port LC Stage #3: Liquid Fuels Production LC Stage #1: Raw Material Acquisition

Foreign Refinery Operations for Production of

Gasoline, Diesel and Jet Fuel Imported

by the U.S. U.S. Crude Oil

Extraction

Foreign Crude Oil Extraction Pipeline Transport

to Port Tanker Transport

Pipeline Transport to Refinery

Pipeline Transport to Border

U.S. Operations Non-U.S. Operations

### 25 

## 3.1 Crude Oil Mix Transport
Crude oil transport includes tr ansport of foreign and domestic crude oil from the point of extraction to the refinery. Crude oil transport is modeled for deliv ery to domestic refineries and foreign refineries for processi ng into finished imports. Tran sport emissions are based on the amount input to a transport operation (amount extr acted). Losses are then assessed at the end of the transport operation (Appendix H).


### 3.1.1 Crude Oil Mix Transport to Domestic Refineries Crude oil transport to U.S. refineries include s pipeline transport with in the exporting country, ocean tanker transport to the U.S., and domes tic crude oil transport to refineries via a combination of pipeline, water carrier, rail, and truck.
3.1.1.1 Crude Oil Transport within Exporting Country For all foreign crude sources for U.S. refineries, the crude is assumed to be transported 100 miles via pipeline to an ocean port or U.S. border. § The energy intensity for pipeline transport is assumed to be 260 Btu/ton-mile (Wang 2008) and electricity is assumed to be the power source. The emissions associated with pipeline transport are estimated using emissions from the U.S. power grid as a surrogate prof ile for that of foreign countries (Appendix B). § This is noted as a data limitation but the overall impact to the life cycle emissions is minimal. The resulting emissi ons profile per barrel of crude oil imported is shown in Table 3-1.
Table 3-1. GHG Emissions Associated with Transport of Imported Crude Oil from Point of Extraction to Foreign Ports Emissions (kg/bbl extracted) Emissions Source CO 2 CH 4 N 2 O Pipeline Transport 0.863 1.00E-03 1.12E-05



### 3.1.1.2 Crude Oil Mix Ocean Tr ansport to Domestic Ports The energy requirement for transporting crude oil via tanker is calculated by multiplying the quantity shipped by the distance travel ed in nautical miles and the energy intensity for transport. The return trip is assumed to require the same amount of energy. The values are summed for each of the different import sources and the emi ssions associated with consumption of that quantity of energy (as heavy fuel oil) is determined. Table 3-2 outlines the performance specifications fo r various sizes and types of crude carriers. The energy intensity ranges from 4.2 to 7.5 Btu pe r barrel-nautical mile of crude transported. The assumed study value for crude tanker transp ort operations is 5.5 Btu per barrel-nautical mile. § The heavy fuel oil (HFO) used to power tanker op erations is essentiall y residual fuel oil and therefore the GHG emissions profile consistent with combustion of residual fuel oil in marine

§ A sensitivity analysis was performed on these parameters.

### 26 engines is used to determine the ship emissions during international transport. GHG emissions from heavy fuel oil are presented in Table 3-3. Emissions are per million Btu higher heating value (HHV) of fuel combusted.
Table 3-2. Performance Specifications for Various Crude Tankers

Designation Formosapetro Discovery

VLCC (IHI 2008a) Sky Wing (IHI 2008b) VLCC (IHI 2008c) Suezmax Oil Tanker (Brodosplit 2008) Oil Tanker (Brodosplit 2008) Oil Tanker (Brodosplit 2008) Service Speed (kt) 15 15.8 16.3 15.5 15.3 15.52 Fuel Oil Consumption (tonnes/day) 75.4 97.3 89.7 56.7 52.3 51.2 Cargo Volume (m 3 ) 328,458 340,218 350,000 185,447 126,210 126,211 Deadweight (MT) 281,434 299,997 300,500 166,300 114,000 108,000 Product Volume (bbl) 2,065,938 2,139, 907 2,201,434 1,166,426 793,837 793,843 Energy Intensity: Btu/bbl-nautical mile 4.24 5.02 4.36 5.47 7.51 7.25

Table 3-3. GHG Emissions from Combustion of HFO (Residual Fuel Oil) in Ships (EIA 2007) Emissions (kg/MMBtu HHV) Emissions Source CO 2 CH 4 N 2 O HFO Combustion in Ships 78.8 5.75E-03 2.00E-03



### Table 3-4 lists the foreign crude sources for 2005 and the expor ting port(s) with associated average ocean travel distance in nautical miles. EIA reports crude oil volumes, receiving ports, and country of origin for each shipment impor ted in 2005. Portworld distance calculator (2008) was used along with the EIA data to determine port-to-port travel distances for all crude oil shipments for the top ten crude oil importing countries. Transpor t through the Panama Canal, Suez Canal, and Bosporus Strait was disallowed. Canadian ex ports entering the U.S. through ocean or lake ports are assumed to travel via wate r while all others are assumed to be transported via pipeline. Based on this assumption, approxi mately 28% of the imports from Canada are waterborne. For shipments received from countries other than those listedin Table 3-4, the oneway travel distance is assumed to be 10,000 nautical miles. §
Table 3-4. Sources of U.S. Crude Input to Refineries, Exporting Port, and CountrySpecific Average Ocean Travel Distance

U.S. Crude Oil Sources Import as % of Refinery Crude Input (Year 2005, EIA) Exporting Port Country-SpecificAverage OneWayTravel Distance (nautical miles)
Canada Waterborne 2.99% Vancouver/Hibernia 675* Canada Pipeline 7.70% NA NA

§ A sensitivity analysis was performed on these parameters.

### 27 U.S. Crude Oil Sources Import as % of Refinery Crude Input (Year 2005, EIA) Exporting Port Country-SpecificAverage OneWayTravel Distance (nautical miles) Mexico Crude Oil 10.2% Cayo Arcas 1,061 Saudi Arabia Crude Oil 9.4% Ras Tanura 12,018 Venezuela Crude Oil 8. 1% Amuay/Cardon 1,789 Nigeria Crude Oil 7.1% Bonny Island 5,672 Iraq Crude Oil 3.4% Umm Qasr 12,370 Angola Crude Oil 3.0% Luanda 6,736 Ecuador Crude Oil 1.8% Balao 5,653 Algeria Crude Oil 1.5% Arzew 4,452 Kuwait Crude Oil 1.5% Mina al-Ahmadi 12,526 Other 9.5% 10,000 * Weighted average based on assumed waterborne import volumes only.



### Table 3-5 lists the GHG emissions associated with tanker transport of wate rborne crude oil from foreign ports to the U.S. in 2005.

Table 3-5. GHG Emissions Associated with Ocean Tanker Transport of Waterborne Imported Crude Oil to Domestic Ports Emissions (kg/bbl exported) Emissions Source CO 2 CH 4 N 2 O Tanker Transport to U.S. Port 5.54 4.04E-04 1.41E-04



### 3.1.1.3 Crude Oil Mix Domestic Transport Crude oil mix within the U.S. is transported via pipeline, water carrier, ra il, and truck. Table 3-6 summarizes U.S. crude petroleum domestic tr ansportation modes for years 2000 through 2004.

Table 3-6. Total Crude PetroleumCarried In Domestic Transportation (Billions of TonMiles) and Percent of Total Carried by Mode of Transportation (AOP 2006)

Total Products Pipelines* Water Carriers Motor Carriers** Railroads Year Ton-miles Tonmiles % of Total Tonmiles % of Total Tonmiles % of Total Tonmiles % of Total 2000 376.0 283.4 75.4 91.0 24. 2 1.2 0.3 0.4 0.1 2001 376.6 277.0 73.6 98.1 26. 0 1.1 0.3 0.4 0.1 2002 384.0 286.6 74.7 95.7 24. 9 1.2 0.3 0.5 0.1 2003 380.4 284.5 74.8 94.1 24. 8 1.3 0.3 0.5 0.1 2004 374.1 283.7 75.9 88.7 23. 7 1.2 0.3 0.5 0.1

* The amounts carried by pipeline are based on ton-mi les of crude and petroleum products for federallyregulated pipelines (84 percent) plus an estimated br eakdown of crude and petroleum products in units of ton-miles for pipelines that are not federally regulated (16 percent).

** The amounts carried by motor carriers are estimated.

### 28 The Oak Ridge National Laboratory (ORNL) Tr ansportation Energy Data Book (2007), Table 2.4, outlines the domestic consumption of transportation energy by mode and fuel type. These data were used to determine the fuel poweri ng the aforementioned tran sportation operations. Based upon the ORNL Transportation Energy Da ta Book, Table 2.4, in 2004, natural gas and electricity were the primary fuels for effecting pipeline transport. Sinc e natural gas is used primarily for fueling natural gas pipeline transpor t, all crude oil and petroleum product transport via pipeline is assumed to be fueled by electricit y. Similarly, diesel fu el is shown to be the exclusive fuel source for Class I freight railroa d operations. Water carri ers transporting freight are powered by diesel fuel and residual fuel oi l (30.5 % diesel fuel and 69.5% residual fuel oil on an energetic basis). Medium/hea vy trucks were powered primaril y (90%) by diesel fuel and all petroleum tanker trucks in this study are assumed to be powered exclusively by diesel fuel.
Table 3-7. Energy Intensity of Transport Activities

Transport Mode Energy Intensity (One-way) Unit Reference Year Reference
Petroleum Pipeline 260 Btu/ton-mile 2008 Wang 2008 Water Carriers 514 Btu/ton-mile 2005 ORNL 2007, Table 2.16 Railroad 337 Btu/ton-mile 2005 ORNL 2007, Table 2.16 Heavy single-unit and combination trucks 20,539 Btu/VehicleMile 2005 ORNL 2007, Table 2.16
Heavy single-unit and combination trucks 822* Btu/ton-Mile 2005 ORNL 2007, Table 2.16 * Assuming a 25-ton tanker truck capacity



### The data from Table 3-6 and Tabl e 3-7 are then combined to de termine a quantity of energy (by transport type) expended for crude petroleum tran sport in 2004. This energy/resource usage is then allocated to the 5,675,365,000 ba rrels of crude oil (sum of 2004 imported crude oil and 2004 U.S. crude oil production). The transportati on energy usage relative to barrels transported is assumed to be the same for 2005. Results of the energy usage allocation are summarized in Table 3-8.
Table 3-8. Energy Usage for Crude Petroleum Transport Activities

Transport Mode Total Energy Usage (Billion Btu HHV) Energy Usage (Btu HHV/bbl of Crude Petroleum Transported) Fuel Source

Petroleum Pipeline 73,762 12,997 Electricity

Water Carriers 91,184 16,067 30.5% Diesel Fuel 69.5% Residual Fuel Oil
Railroad 337 59 Diesel Fuel Heavy single-unit and combination trucks 1,972 347 Diesel Fuel



### In order to determine emissions associated with the estimated fuel consumption for crude oil transport, appropriate emissions factors are applied to the quantit ies of fuels consumed (as shown in Table 3-8) for transport. Table 3-9 provides a summary of the emissions factors applied for

### 29 each mode of fuel product transportation. The emi ssions factors for diesel fuel and residual fuel oil are for combustion of the fuel only. The ups tream emissions associated with production of secondary fuels contribute only minimally to the final results for the scen arios of interest.
Table 3-9. Crude Oil Transportation Modes and Associated Emission Factors

Transport Mode Energy Usage (Btu HHV

/bbl of Petroleum Transport) Fuel Source Fuel Energy Content (MMBtu

HHV/ bbl) CO 2 Emissions

(g CO 2 /gallon) CH 4 Emissions

(g CH4 /gallon) N 2 O Emissions

(g N 2 O /gallon) Emission Factor References

Pipeline 12,997 Electricity N/A 217* 0.251* 0.00281* EPA, 2007 (eGRID); GaBi 4,

2007 Water Carriers 4,900 Diesel Fuel 5.825 10,147 0.74 0.26 EIA 2007

Water Carriers 11,166 Residual Fuel Oil 6.287 11,793 0.86 0.3 EIA 2007

Railroad 59 Diesel Fuel 5.825 10,147 0.8 0.26 EIA 2007 Heavy single-unit and combination trucks 347 Diesel Fuel 5.825 10,147 0.57 0.3 API 2004 Table 4-9

* Emission factor units are kg/MMBtu for electricity



### Calculated specific transit GHG emissions associat ed with each of the aforementioned modes of crude oil transportation are repor ted in Table 3-10. The total GHG emissions per barrel factors are applied to all crude oil fed to U.S. refineries.
Table 3-10. GHG Emissions Associated with Crude Oil Transport within U.S.
Emissions (kg/bbl extracted) Transport Mode CO 2 CH 4 N 2 O Pipeline 2.81 3.27E-03 3.65E-05 Water Carriers (Diesel) 0.359 2.61E-05 9.19E-06 Water Carriers (Residual Fuel Oil) 0.880 6.42E-05 2.24E-05 Railroad 0.00434 3.43E-07 1.11E-07 Heavy single-unit and combination trucks 0.0254 1.43E-06 7.52E-07

Total 4.08 3.36E-03 6.90E-05

### 30 

### 3.1.2 Crude Oil Mix Transport to Foreign Refineries Crude oil transport is estimated from the point of extraction to the fore ign refineries producing imported liquid fuels. The methods utilized for e ach country exporting finished fuels to the U.S. vary by country.


### Delivered Country-Specific Profiles Countries for which the crude oil delivered “f ree-to-customer” country -specific profiles are available are detailed in Table 2-13. These profiles include an embedded transport component in the GHG profile. The transport contribution to the total GHG profile for these countries has been estimated by determining the GHG contributi on of the transport step to the total U.S. delivered GHG profile and assuming that the same relative contribution of the transport component is applicable to foreign crude oil mixes. For crude oil delivered to domestic refineries, 25% of the CO 2 

### , 1% of methane, and 20% of nitrous oxide is attributable to transport operations.


### Pipeline Transport An average pipeline transport di stance of 100 miles from the point of extraction to an in-country refinery is assumed for all countries where a country-specific extraction profile was used. § The energy intensity for pipeline transport is assumed to be 260 Btu/ton-mile (Wang 2008) and electricity is assumed to be the power source. The emissions associated with pipeline transport are estimated using emissions from the U.S. power grid as a surrogate prof ile for that of foreign countries (Appendix B). This is noted as a data limitation but the overall impact to the life cycle emissions is expected to be minimal. The re sulting emissions profile per barrel of crude oil transported by pipeline is shown in Table 3-11.
Table 3-11. GHG Emissions Associated with Transport of Foreign Crude to Foreign Refineries/Ports Emissions (kg/bbl exported) Source CO 2 CH 4 N 2 O Pipeline Transport 0.863 1.00E-03 1.12E-05


### Tanker Transport Canada and the Virgin Islands import significan t quantities of foreign crudes for refinery processing. Transport of crude oil to South Korea is also a ssumed to be 100% by tanker transport. Portworld distance calculator (2008) was used along with the EIA data to determine port-to-port travel distances for crude oil shipments. Transpor t through the Panama Canal, Suez Canal, and Bosporus Strait was disallowed. The emissions associated with ocean transport of crude was determined as outlined in Section 3.1.1.2 and are shown in Table 3-12 along with the weighted average travel distance determined fo r each country. It was assumed that all crude imports to Canada from the U.S. were by pipeli ne. Crude oil mix transport within Canada, the Virgin Islands and South Korea is assumed to be negligible because refineries receiving crude are located at a port.

§ A sensitivity analysis was performed on these parameters.

### 31 Table 3-12. GHG Emissions and One-Way Travel Distance Assumptions Associated with Ocean Tanker Transport of Foreign Crude to Foreign Refineries/Ports Emissions (kg/bbl exported) Receiving

Country Weighted Average Travel Distance One Way (nautical miles)* CO 2 CH 4 N 2 O
Canada 4,967 4.31 3.14E-04 1.09E-04 Virgin Islands 1,729 1.50 1.09E-04 3.81E-05 South Korea 6,190 5. 37 3.91E-04 1.36E-04 * Weighted average based on assumed waterborne import volumes only.


### Composite Transport GHG Emissions to Foreign Refineries Combining the ocean transport, pipeline trans port and the transport portion of the delivered country-specific profiles for the countries exporting gasoline, dies el and jet fuel to the U.S. results in GHG emissions per barrel of crude oil as shown in Table 3-13.

Table 3-13. GHG Emissions Associated with All Modes of Transport of Foreign Crude to Foreign Refineries Emissions (kg/bbl crude oil exported) Source CO 2 CH 4 N 2 O Conventional Gasoline 3.87 2.38E-03 7.01E-05 Conventional Diesel 3.45 1.59E-03 6.80E-05 Kerosene-Based Jet Fuel 3.69 1.80E-03 7.33E-05



## 3.2 Natural Gas Liquids Transport
NGL transport has been modeled the same as pe troleum products transport in Life Cycle Stage #4 (see Section 5.1.2 for detailed modeling assump tions). Table 3-14 lists the estimated GHG emissions consistent with NGL transport.

Table 3-14. GHG Emissions Associated with NGL Transport Emissions (kg/bbl exported) Source CO 2 CH 4 N 2 O NGL Transport 4.54 2.81E-03 8.93E-05



## 3.3 Unfinished Oils Transport
The unfinished oils transport component is mode led the same as an equivalent volume of imported crude oil. Refer to Section 3.1.1 for furt her detail. Table 3-15 lists the estimated GHG emissions consistent with unfinished oils transport.

Table 3-15. GHG Emissions Associated with Unfinished Oils Transport Emissions (kg/bbl exported) Source CO 2 CH 4 N 2 O Unfinished Oils Transport 7.92 4.27E-03 1.59E-04

### 32 

## 3.4 Summary of Life Cycle Stage #2 GHG Emissions Profiles
Table 3-16 summarizes the emissions profiles asso ciated with transport of petroleum refining feedstocks for U.S. refineries and foreign refineries producing th e gasoline, diesel and jet fuel imported by the U.S. in 2005. The increase in trans port activity required to deliver each barrel of crude oil (due to transport losses detailed in Appendix H are applied and emissions are presented per barrel delivered to refineries.
Table 3-16. Summary of GHG Emissions Consistent with Transport of Crude Oil and Other Feedstocks for U.S. and Foreign Refineries in 2005
Emissions (kg/bbl delivered) Source CO 2 CH 4 N 2 O Feedstock Transport to U.S. Refineries Crude Oil 7.92 4.27E-03 1.59E-04 NGL 4.54 2.81E-03 8.93E-05 Unfinished Oils 7.92 4.27E-03 1.59E-04 Crude Oil Transport to Foreign Refineries Gasoline Imports 3.88 2.39E-03 7.03E-05 Diesel Imports 3.46 1.60E-03 6.82E-05 Jet Fuel Imports 3.70 1.80E-03 7.36E-05

### 33 

## 4.0 Life Cycle Stage #3: Liquid Fuels Production

The boundary of LC Stage #3 starts at the entrance of the petroleum refinery with the receipt of feedstocks and ends at the entrance of the petr oleum pipeline or tanker used to transport the liquid fuels to a bulk fuel storage depot. M odeling assumptions and methodology are described for both domestic refineries and foreign refineri es providing imported gasoline, diesel and jet fuel. Production of oxygenates is ex cluded from the scope of this study. Figure 4-1 depicts the activities and flow of feedstocks for LC Stage #3.
Figure 4-1. Flow Diagram of Liquid Fuels Production Activities

### 34 

## 4.1 General Description of a Petroleum Refinery
Petroleum refining is an extremely complicated, highly integrated process where the equipment and unit operations are tailored to sp ecific feed properties. The comp lexity level of refineries is increasing with time due to decreasing crude oi l input quality (heavier crude oils with higher sulfur contents) resulting in increased upgrad ing and processing requi rements. Figure 4-2 depicts a typical U.S. refinery operation.
Figure 4-2. Modern Oil Refinery (Chevron 2007)



### The following sections outline the basic operations th at constitute a modern refinery and provide brief descriptions of those operations. Special ized operations that contribute solely (or primarily) to upgrading of hydrocar bon materials not intended for li quid transportation fuels (i.e. lubricants, etc) are not discussed. Atmospheric and Vacuum Distillation: The first and most basic operation associated with a refinery is distillation. The at mospheric distillation column frac tionates the crude oil input into various fractions with differentboiling point ranges. Figure 4- 3 shows the generalized operation of a distillation column and the various product cuts obtained. Table 4-1 shows a simplified breakdown of the boiling point cuts.

### 35 Figure 4-3. Atmospheric Distillation Column (EIA 1999)



### The vacuum distillation process takes the hea vy (high-molecular weight) fraction from the atmospheric distillation column and further separates the components by distillation under vacuum conditions.
Table 4-1. Crude Oil Boiling Point Range for Product Slate (Energetics 2007)

Fraction ASTM Boiling Range, oF Light Straight-Run Gasoline 90-220 Naphtha 108-400 Kerosene 330-540 Light Gas Oil 420-640 Atmospheric Gas Oil 520-830 Heavy Residue 650+ Vacuum Gas Oil 750+

### 36 Catalytic Cracking: Catalytic cracking pro cesses involve heating high-molecular weight hydrocarbons in the presence of a catalyst to break the molecules down into lighter components. This operation helps increase the ga soline and diesel fractions at the expense of the less-desirable residual fraction. Catalytic crack ing is the most widely used crude oil upgrading process. Catalytic Hydrocracking: Catalytic hydrocracking is similar to catalytic cracking except that hydrogen is added to facilitate molecular decompositions while simultaneously removing undesirable heteroatomic species (sulfur, nitrogen, etc.). Coking: Coking processes are refining operations in which solid carbonaceous material (known as coke) is produced when the heavy hydrocarbo n fraction from the vacuum distillation columns is thermally devolatilized. The low-molecular weight species produced during coking can be used as fuel gas, gasoline blendstocks, distil late blendstocks, or feedstocks for secondary upgrading/reforming processes. The solid coke can be either marketed or used as a refinery fuel. Coking operations in the U.S. are primarily dela yed coking with a small number of fluid coking processes. Delayed coking produces large coke grains suitable for electrode manufacture while fluid coking produces coke particulates. Delaye d coking is a semi-batch process while fluid coking is a continuous process. Desulfurization/Hydrotreating: The desulfurization/hydrotreating process is very similar to hydrocracking in that a hydrocarbon stream is re acted with hydrogen to remove sulfur species from the stream. This process is often distingu ished from hydrocracking by the severity of the processing conditions. Since the purpose of the pro cess is to remove sulfur and not significantly alter the molecular composition and species pr ofile, it is often pe rformed under milder conditions. Catalytic Reforming: The catalytic reforming operation ta kes less desirable naphtha streams and chemically reconfigures the compounds. The primary ope rations are dehydrogenation of napthenes to produce aromatic species, isom erization, dehydrocyclization (transforming a straight-chain compound into a ring struct ure while dehydrogenating the same), and hydrocracking (Energetics 2007). While catalytica lly-reformed liquid fuels contribute primarily to the gasoline fraction, hydrogen is produced as a by-product of the reforming operations. This hydrogen may be used for desulfurization of pro ducts not contributing di rectly to the gasoline slate.
Isomerization: Isomerization is a process where stra ight-chain hydrocarbons (paraffins) are converted into branched isomers. The isopara ffins are produced through a series of molecular rearrangements in the presence of a catalyst. The branched paraffins are s uperior to the straight chain species because they have a higher octane number and thus contribute primarily to the gasoline product slate. Alkylation: Alkylation is a process where isobutane, is opentane, and/or isohexane are alkylated with low-molecular-weight alkenes (primarily a mixture of propylene and butylene) in the presence of a strong acid catalyst, either sulfur ic acid or hydrofluoric ac id. The product of the reaction is a mixture of branched chain para ffins which are used as gasoline additives.

### 37 

## 4.2 Liquid Fuels Production at Do mestic Petroleum Refineries
The emissions profile associated with U.S. pe troleum refining operations in 2005 consists of emissions from fuels acquisition, fuels com bustion, hydrogen production, flaring, and venting and fugitive emissions. These refinery operations re sult in the production of a variety of finished products including gasoline, diesel fuel, kerosene-based jet fu el, and other petroleum-based products. The methodology for developing the GHG emissions profile and for allocating GHG emissions to the various co-products is discussed in deta il in this section. The GHG emissions profile associated with U.S. petroleum refining operati ons in 2005 consists of emissions from the following activities/sources:

• Acquisition of fuels

o Indirect emissions associated with purchased power and steam

o Emissions associated with the acquisition of coal and natural gas purchased and consumed at the refinery as fuels

o Emissions associated with production of fuels at the refinery which are subsequently consumed as fuels (i.e. still gas, petroleum coke)

• Combustion of fuels at the refinery

• Hydrogen production (on-site and off-site)

o Upstream emissions associat ed with natural gas feed

o CO 2 

### process emissions from steam methane reforming (SMR)

o Fuel combustion and upstream emissions associated with natural gas fuel and indirect (electricity) emissions for off-site hydrogen production

• Flaring

• Venting and fugitive emissions The emissions above will be organized into a refinery emissions pool and a hydrogen emissions pool and subsequently allocated between the vari ous refinery products. There are no individual assignments of energy sources to unit operations or refinery products. For example, emissions associated with acquisition and combustion of na tural gas will not be al located based on the unit operations where the natural gas is consumed. Figure 4-4 depicts the two emissions pools, refine ry and hydrogen, developed in this section. Fuels for use at the refinery enter from the left of the diagram while hydrogen produced off-site enters the refinery from the right of the diagram. As shown, a portion of the emissions associated with on-site hydrogen production ar e embedded in the refinery emissions profile while the remaining is included in the hydrogen emi ssions pool. This is di scussed in detail in subsequent sections.38Figure 4-4. Depiction of Refinery and Hydrogen Emissions Pools

### 39 

### 4.2.1 Reported Refinery Data The primary source of information used to de termine greenhouse gas emissions for petroleum refineries is the EIA dataset compiled for U.S. refineries from individual government-mandated refinery surveys. EIA collects and compiles pe troleum production and processing data from U.S. refineries and publishes most of the informati on on their website for public use. While some refinery-specific information is available, refinery operational da ta are generally aggregated to avoid disclosing proprietary information.


### 4.2.2 Refinery Energy Usage Fuels consumed data are presented by EIA on an a nnual basis and aggregated data at the regional Petroleum Administration for Defense Districts (PADD) level represent the highest level of detail available for this information. Refinery fuels consumed for 2005 are shown in Table 4-2 for the U.S. This information is used to estima te the refinery energy consumption and associated emissions. Puerto Rico and the Virgin Islands refineries are not in cluded in these data.
Table 4-2. Refinery Fuels Consumed for 2005

Fuel Annual Consumption (thousand bbl) Crude Oil 0 Liquefied Petroleum Gases 4,175 Distillate Fuel Oil 755 Residual Fuel Oil 2,207 Still Gas 238,236 Petroleum Coke 89,652 Marketable Petroleum Coke 2,242 Catalyst Petroleum Coke 87,410 Other Petroleum Products 5,329 Natural Gas (Million Cubic Feet) 682,919 Coal (Thousand Short Tons) 41 Purchased Electricity (Million Kilowatt-hours) 36,592 Purchased Steam (Million Pounds) 63,591



### Refinery energy consumption is calculated by multiplying the energy content of the various fuels, as reported in Table 4-3, by the quantity used and summ ing to obtain a total refinery energy usage. The energy usage profile is shown in Table 4-4.

### 40 Table 4-3. Refinery Fuels Energy Content (HHV)

Refinery Fuel Energy Content

(HHV) Units References

Liquefied Petroleum Gases (LPG) 3.616 MMBtu/bbl EIA 2008 Distillate Fuel Oil 5.825 MMBtu/bbl EIA 2008 Residual Fuel Oil 6.287 MMBtu/bbl EIA 2008 Still Gas 6.000 MMBtu/bbl EIA 2008 Petroleum Coke 6.024 MMBtu/bbl EIA 2008 Other Petroleum Products* 5.796 MMBtu/bbl EIA 2008 Natural Gas 1,027 MMBtu/Mcf EIA 2008 Coal** 27 MMBtu/ton API 2004 Table 3-5 Purchased Electricity 3,412 Btu/kWh
Purchased Steam 1,200 Btu/lb ConEdison, 2007; GaBi 4, 2007 * Includes pentanes plus, other hydrocarbons, oxygenates, hydrogen, unfinished oils, gasoline,

special naphthas, jet fuel, lubricants, asphalt and road oil, and miscellaneous products. ** Assume bituminous coal; API average energy c ontent for bituminous coal of 13,500 Btu

HHV/lb

Table 4-4. Refinery Fuels Energy Usage Profile for 2005 (HHV)

Fuel Consumed Energy Usage (MMBtu HHV/day)
Liquefied Petroleum Gases (LPG) 41,361 Distillate Fuel Oil 12,049 Residual Fuel Oil 38,015 Still Gas 3,916,208 Petroleum Coke 1,479,626 Other Petroleum Products* 84,622 Natural Gas 1,921,528 Coal** 3,033 Purchased Electricity 342,060 Purchased Steam 209,066 Total 8,047,569 * Includes pentanes plus, other hydroc arbons, oxygenates, hydrogen, unfinished

oils, gasoline, special naphthas, jet fuel, lubricants, asphalt and road oil, and miscellaneous products. ** Assume bituminous coal; API average ener gy content for bituminous coal of

13,500 Btu HHV/lb

### 41 

### 4.2.3 Fuels Acquisition
Each of the fuels consumed and indirect fuel in puts for refineries have an emissions profile associated with extraction/produc tion of those fuels/energy sources . These fuel inputs include:

• Indirect fuel inputs including purchased electricity and steam

• Purchased fuels including coal and natural gas

• Produced fuels from the refinery operations which includes all other fuels reported by refineries to EIA

4.2.3.1 Purchased El ectricity and Steam
The tables below list CO 2 

### , CH 4 

### , and N 2 

### O emissions factors consistent with refinery usage of purchased power and steam. Emissions consiste nt with purchased electricity were estimated using eGRID data with U.S. average emissions, as applicable (refer to Appendix B) for further discussion). The emissions from the U.S. power grid mix are representative of 2004 emissions due to unavailability of 2005 data at the time the study was performed.
Table 4-5. Refinery Fuels and Associated Indirect CO 2 Emissions

Refinery Fuel CO 2 Emissions (kg CO 2 /MMBtu HHV) References

Purchased Electricity 217 

### § EPA 2007 (eGRID); GaBi 4 2007 Purchased Steam 92.7 ConEdison 2007; GaBi 4 2007

Table 4-6. Refinery Fuels and Associated Indirect Methane Emissions

Refinery Fuel CH 4 Emissions (kg CH 4 /MMBtu HHV) References

Purchased Electricity 0.251 

### § EPA, 2007 (eGRID); GaBi 4, 2007 Purchased Steam 0.132 ConEdison, 2007; GaBi 4, 2007

Table 4-7. Refinery Fuels and Associated Indirect N 2 O Emissions

Refinery Fuel N 2 O Emissions (kg N 2 O/MMBtu HHV) References

Purchased Electricity 0.00281 

### § EPA 2007 (eGRID); GaBi 4 2007 Purchased Steam 0.00104 ConEdison 2007; GaBi 4 2007

§ A sensitivity analysis was performed on these parameters.

### 42 4.2.3.2 Coal Coal was used as a refinery fuel in PADD 1 a nd 2 in 2005. A total of 41 ,000 short tons of coal was consumed in 2005—33,000 short tons in P ADD 1 and 8,000 in PADD 2 (EIA 2008). Figure 4-5 shows the location of the regional PADDs in th e United States and the location of refineries. Given that PADD 1 refineries are located primarily in the northeast, it is assumed that the coal used as a refinery fuel is a bitumi nous coal extracted by underground mining.
Figure 4-5. Map of the United States Showing Petroleum Administration for Defense Districts and Refinery Locations (Energy Velocity 2007)



### There are three primary emissions components th at contribute to the greenhouse gas emissions profile for coal acquisition: (1) energy usage (fuels consumed) for mining and preparation, (2) mine methane emissions, and (3) tran sport of coal to the refineries.


### Coal Mining and Preparation Data for fuels consumed and resulting emissions were derived from 2002 Census Data (USDOC 2004) for Bituminous Coal Underground Mining (i ncluded preparation). No major technology advances occurred in the field of coal mini ng in the years between 2002 and 2005 and therefore it is assumed that these data meets the quality ob jectives for this study. Table 4-8 lists the fuels used for extraction and preparation of bitu minous coal recovered by underground mining in 2002. Emission factors for fuel consumption are shown in Table 4-9 thru Table 4-11.

### 43 Table 4-8. Underground Mining Energy Inputs Required for Extraction and Preparation of 371.4 Million Tons of Bituminous Coal (USDOC 2004)

Fuel Value Units Comments Coal (produced & used in same plant as fuel) 179.8 [1,000 tons]
Distillate (light) grad e numbers 1, 2, 4, and light diesel fuel 655.9 [1,000 bbls] (data from 1997 survey— 2002 data unavailable) Residual (heavy) grade numbers 5 and 6 and heavy diesel fuel 178.3 [1,000 bbls]

Gas (natural, manufactured, and mixed) 0.5 [billion cubic feet] (data from 1997 survey— 2002 data withheld)
Gasoline 1.5 [million gallons]
Purchased Electricity 6,287,072 [1,000 kWh]

Table 4-9. Underground Bituminous Coal Mining/Preparation Fuels and Associated CO 2 Emission Factors

Fuel CO 2 Emissions (kg CO 2 /MMBtu HHV) References

Coal* 93.1 API 2004 Table A-3 Distillate Fuel Oil 73.2 API 2004 Table 4-1 Residual Fuel Oil 78.8 API 2004 Table 4-1 Natural Gas 53.1 API 2004 Table 4-1 Gasoline 70.9 API 2004 Table 4-1 Purchased Electricity 217 EPA, 2007 (eGRID); GaBi 4, 2007 * Assume bituminous coal; API average energy content for bituminous coal of 13,500 Btu HHV/lb
Table 4-10. Underground Bituminous Coal Mining/Preparation Fuels and Associated CH 4 Emission Factors

Fuel CH 4 Emissions (kg CH 4 /MMBtu HHV) References

Coal* 7.65E-04 NEB 1999, Table A10.1 Distillate Fuel Oil 5.45E-03 NEB 1999, Table A10.1 Residual Fuel Oil 4.32E-03 NEB 1999, Table A10.1 Natural Gas 1.34E-03 NEB 1999, Table A10.1 Gasoline 0.137 API 2004 Table 4-5 Purchased Electricity 0.251 EPA, 2007 (eGRID); GaBi 4, 2007 * Assume bituminous coal; API average energy content for bituminous coal of 13,500 Btu HHV/lb

### 44 Table 4-11. Underground Bituminous Coal Mining/Preparation Fuels and Associated N 2 O Emission Factors

Fuel N 2 O Emissions (kg N 2 O/MMBtu HHV) References

Coal* 2.37E-03 NEB 1999, Table A10.1 Distillate Fuel Oil 3.51E-03 NEB 1999, Table A10.1 Residual Fuel Oil 3.26E-03 NEB 1999, Table A10.1 Natural Gas 5.70E-04 NEB 1999, Table A10.1 Gasoline 1.17E-04 API 2004 Table 4-5 Purchased Electricity 2.81E-03 EPA, 2007 (eGRID); GaBi 4, 2007 * Assume bituminous coal; API average energy content for bituminous coal of 13,500 Btu HHV/lb



### Mine Methane Emissions An approximation was developed for mine methan e emissions by considering available estimates of coal bed methane (CBM) in-situ productivity for basins containing large bituminous coal reserves, and adding estima ted methane emissions that would be released if that mined coal were removed and processed, such as would be th e case in mining and post-mining processing. Table 4-12 reports values or ranges of estimated extractable CBM for se veral large bituminous coal basins in the conterminous United States. These data, reported from various sources, all describe the estimated extractable methane usi ng best available CBM extraction technologies and do not represent the total volum e of methane that would be expected to be released if coal were extracted and processed at the surface. It is assumed herein that these CBM estimates are comparable to coal methane released during onl y the preliminary coal extraction phase (initial mining being considered roughly equi valent to fracturing and depre ssurizing the coal seam, as is the case in in-situ CBM extraction). In the absence of more geospatially detailed data that would allow development of a more rigorous methodology, a simplistic approach of estimating a mean bituminous CBM productivity has been adopted. The reported estimated CBM values (or averages of reported productivity ranges) have simply been averaged with equa l weighting for all formations. Using this simplified estimation method, an estimated mean bituminous CBM specific productivity value of approximately 260 standard cubic feet (scf) per ton was determined. A publication by the American Petroleum Institute in 2004 reports mining and post-mining methane emissions factors for underground and su rface mining operations. While these data (summarized in Table 4-13) are average values and do not break down emissions as a function of coal type, the reported underground mining methane emissions value of 250 scf CH 4 

### per short ton of coal (vented and degasse d) compares favorably with the aforementioned estimated mean bituminous CBM productivity value of 260 scf/short ton bituminous coal.

### 45 Table 4-12. Summary of Coal Bed Methane Productivity Estimates

Coal Basin CBM Estimate (scf/ton coal) mean of ranges noted parenthetically References

Northern Appalachian 150 GTI 2002 Central Appalachian 300 GTI 2002 Warrior Basin 350 Lee 2007 San Juan Basin 400 Lee 2007

Illinois Basin 100-150 (mean 125) 83.3-188.7 (mean 138.5) mean of two means: 131.75) U.S. DOE 2007; Eble, et al. 2005

Cherokee Basin (SE Kansas) 185-325 (225) Tedesco 2004 Forest City Basin 50-450 (250) Tedesco 2004 Study Value 260* * Excludes post-mining emissions

Table 4-13. Coal Mining Methane Emissions Factors (API 2004)

Methane Emission Factor Activity scf CH 4 /short ton coal lb CH 4 /short ton coal Tonnes CH 4 / tonne coal Percent of total methane released Underground Mining (Ventilation and Degasification) 250 10.6 0.00528 76.6%

Underground Postmining (Coal Handling) 76.2 3.22 0.00161 23.4% Surface Mining 32.1 1.36 0.000679 85.7% Surface Post-Mining (Coal Handling) 5.35 0.23 0.000113 14.3%



### In addition to methane emitted at the point of underground mining, the API report also gives an average value for methane released during pos t-mining processing of coal mined from an underground mine of 76.2 scf CH 4 

### /short ton. Based on these data, approximately 77% of coal methane is released during coal mining (in the case of longwall mining, at the shearing point), while the remaining 23% of the coal methane is released during post-mining processing. Postmining methane emissions are not, as previously discussed, consider ed to be represented in the CBM specific productivity values. To acc ount for the post-mining methane emissions (analogous to methane that remains in the fo rmation following in-situ CBM extraction), it is assumed that an additional 23% of the reporte d bituminous CBM value (2 60 scf/ton) would be released following mining of the same coal; an additional 60 scf/ton would be released during post-mining processing resulting in total methane em issions from bituminous coal of 320 scf/ton. A value of 320 scf/ton is therefore used for methane emissions from bituminous coal mining, assuming that voluntary best-management practic es are not employed at underground bituminous coal mines.

### 46 

### Coal Transportation Transport of the coal from the mine or preparati on plant to the refinery is assumed to be 100% by rail. The assumed transport distance is 400 mile s (round trip) and energy intensity values for rail transport for 2005, extracted from the Transpor tation Energy Data Book (ORNL 2007), is used for determining transport emissions from locomo tive transport operations. According to the Transportation Energy Data Book, locomotives for freight transport are fu eled 100% by diesel fuel. Assumptions made to construct the coal transportation portion of the coal extraction/transport upstream profile for use in pe troleum refineries are reported in Table 4-14. Table 4-15 outlines the GHG emissions asso ciated with coal transport via rail.
Table 4-14. Summary of Assumptions for Coal Rail Transportation

Parameter Value Units Reference Trip from Product Origin to Destination 337 Btu HHV/ton-mile ORNL 2007, Table 2.16
Trip from Product Destination Back to Origin 337 Btu HHV/ton-mile ORNL 2007, Table 2.16
Round-trip Distance for Coal Transport 400 Miles Study Assumption
Locomotive Fuel Diesel - ORNL 2007, Table 2.4

Table 4-15. GHG Emissions Consistent with Coal Transport by Rail (EIA 2007)
Diesel Emissions (kg/MMBtu HHV diesel fuel) Transport Emissions (kg/ton bituminous coal) Source Energy Usage (Diesel)

in Btu HHV/ton CO 2 CH 4 N 2 O CO 2 CH 4 N 2 O

Coal Transport 134,800 73.2 0.00577 0.00187 9.86 7.78E-04 2.53E-04



### Table 4-16 shows the GHG emissions for bitumi nous coal mining from an underground mine, associated mine methane emissions, and estimated em issions consistent with railroad transport of the coal to petroleum refineries.
Table 4-16. Summary of GHG Emissions Consistent With Coal Acquisition
Emissions (kg/ton Coal) Source CO 2 CH 4 N 2 O Coal Mining & Preparation 14.8 0.0147 2.41E-04 Mine Methane Emissions N/A 6.12 N/A Coal Transport 9.86 7.78E-04 2.53E-04 Total 24.7 6.14 4.93E-04

### 47 4.2.3.3 Natural Gas The emissions profile for natural gas used as a re finery fuel/feedstock was extracted from GaBi 4 (2008). The profile includes emissions associated with extraction, processing, and transport of natural gas to the final consumer. The data ar e representative of the U.S. natural gas mix delivered to customers in 2002 (GaBi data se t dated September 15, 2006). The GHG emissions consistent with natural gas consumed by refine ries are shown in Table 4-17. No significant technology differences/advances occurred in the fiel d of natural gas extraction and processing in the years between 2002 and 2005 and therefore the da ta meet the quality objectives for this study.

Table 4-17. GHG Emissions Consistent with Delivered Natural Gas in the U.S.

Basis/Quantity GHG Emissions (kg CO 2 E) kg Natural Gas 0.516 scf Natural Gas 0.00984


### 4.2.3.4 Refinery-Produced Fuels The upstream emissions profile for fuels that ar e produced in the refinery and subsequently combusted therein are equivalent to the cradle-to-gate emissions associated with production of that fuel as if it were a refinery product. Fo r example, the emissions associated with production of still gas include the emissions associated with refinery feedstock acquisition and transport and all refinery operations as allocated to still gas. For that reason, a preliminary calculation of the entire LC Stage #3 profile (excl uding acquisition of refi nery-produced fuels) must be determined prior to incorporating the upstrea m emissions of these fuels. Appendix C details the development of this pr ofile. A summary of the upstream emissions profile is shown in Table 4-18.
Table 4-18. Summary of GHG Emissions Consistent with Acquisition of RefineryProduced Fuels
Emissions (kg/day) Fuel Quantity Input (bpd) CO 2 CH 4 N 2 O LPG 11,438 696,439 5,886 15 Distillate 2,068 171,312 1,122 3 Residual Fuel Oil 6,047 409,065 3,165 8 Still Gas 652,701 39,740,582 335,879 850 Petroleum Coke 245,622 18,267,585 130,326 380 Other Products 14,600 1,095,456 7,768 22 Total 60,380,439 484,146 1,278

### 48 4.2.3.5 Refinery Fuels Ac quisition Emissions Profile Table 4-19 provides a summary of the GHG Emissi ons profiles for each of the fuel acquisition categories.
Table 4-19. Summary of GHG Emissions Consistent with Acquisition of Petroleum Refinery Fuels Emissions (kg/day) Source CO 2 CH 4 N 2 O Indirect Inputs 93,451,488 113,716 1,178 Purchased Fuels 14,134,109 168,565 277 Produced Fuels 60,380,439 484,146 1,278



### 4.2.4 Refinery Fuels Combustion The primary source of GHG emissions at a refine ry is from fuels combustion. Emissions are determined for all of the fuels consumed duri ng the refining operations. All hydrocarbon species are assumed to be combusted in industrial-scale equipment. The following sections outline the emission factors associated with consumption of the various refini ng fuels. Total emissions are determined by multiplying the emission factor by the quantity of fuel consumed. Since it is not possible to accurately ascribe fu el types, combustion equipment and the resulting emissions to the various refinery operations, a composite energy usage/emissions profile was determined for all refining operations. The GHG emissions associated with the fuels consumed are allocated equivalently for each unit of energy consumed.

4.2.4.1 CO 2 

### Emissions from Refinery Fuels Combustion Refinery CO 2 

### emissions are determined by multiplying the quantity of fuel consumed by the appropriate CO 2 

### emissions factor for fuel consum ption. Table 4-20 shows the various hydrocarbon fuels consumed at refineries and lists the CO 2 

### emissions consistent with combustion of the individual species.

4.2.4.2 Methane Emissions from Refinery Fuels Combustion Methane emissions have been quantified for standa rd combustion processes using finished fuels, but off-spec refinery still gas and coke com bustion emission factors are not as precise and estimates vary. In the absence of detailed pr ocess and equipment information for the refining facilities, the uncertainty of the methane estimate s from combustion emissions is high. Due, in part, to this high level of uncertainty, the Petroleum Industry Guid elines for Reporting Greenhouse Gas Emissions (IPIECA et al. 2003) do not consider methane produced by fuel combustion in any of its GHG estimation tier s for refining operations (see Appendix D). The Canadian National Energy Board has estimate d methane emission factors for combustion of various standard and non-standard hydrocarbon fuels (NEB 1999) and those values have been used to determine methane emissions consiste nt with refinery combustion operations. The methane emission factors utilized in this study for fuel combustion are presented in Table 4-21.

### 49 Table 4-20. Refinery Fuels and Associated CO 2 Emissions from Fuel Combustion

Refinery Fuel CO 2 Emissions (kg CO 2 /MMBtu HHV) References Liquefied Petroleum Gases (LPG) 62.3 API 2004 Table 4-1 Distillate Fuel Oil 73.2 API 2004 Table 4-1 Residual Fuel Oil 78.8 API 2004 Table 4-1 Still Gas 64.2 

### § API 2004 Table 4-1 Petroleum Coke 102.1 API 2004 Table 4-1 Other Petroleum Products* 72.1 API 2004 Table A-3 Natural Gas 53.1 API 2004 Table 4-1 Coal** 93.1 API 2004 Table A-3 * Includes pentanes plus, other hydrocarbons, oxygenates, hydrogen, unfinished oils, gasoline,

special naphthas, jet fuel, lubricants, asphalt and road oil, and miscellaneous products. CO 2 emissions estimate consistent with API Co mpendium emission factor or “miscellaneous petroleum products and crude” (see API 2004 Appendix A). ** Assume bituminous coal; API average energy cont ent for bituminous coal of 13,500 Btu HHV/lb

and 93.1 kg CO 2 emitted per MMBtu HHV

Table 4-21. Refinery Fuels and Associated Methane Emissions from Fuel Combustion

Refinery Fuel CH 4 Emissions (kg CH 4 /MMBtu HHV) References Liquefied Petroleum Gases (LPG) 0.00118 NEB 1999, Table A10.1 Distillate Fuel Oil 0.00545 NEB 1999, Table A10.1 Residual Fuel Oil 0.00432 NEB 1999, Table A10.1 Still Gas* 0.00134 NEB 1999, Table A10.1 Petroleum Coke 0.00299 NEB 1999, Table A10.1 Other Petroleum Products** 0.00545 NEB 1999, Table A10.1 Natural Gas 0.00134 NEB 1999, Table A10.1 Coal*** 0.00076 NEB 1999, Table A10.1 * Methane emissions from still gas combustion are assumed to be the same as for combustion of natural gas. ** Includes pentanes plus, other hydrocarbon s, oxygenates, hydrogen, unfinished oils, gasoline, special naphthas, jet fuel, lubricants, asphalt and road oil, and miscellaneous products; methane emissions are assumed to be similar to that of diesel fuel. *** Assume U.S. bituminous coal



### 4.2.4.3 N 2 

### O Emissions from Refinery Fuels Combustion
Current estimates for N 2 

### O emissions from combustion operations, as determined by the U.S. Environmental Protection Agency (EPA) AP-42 emi ssion factors, are only determined for typical operations using petroleum refine ry products—not petroleum intermediates such as still gas. Similarly, EPA emission factors have not been developed for petroleum coke combustion. Ignoring the effects of still gas and coke co mbustion would dramatically underestimate N 2 

### O

§ A sensitivity analysis was performed on these parameters.

### 50 production. Emission factors for re finery operations using standard fuels are shown in Appendix E. The Canadian National Energy Board has estimated N 2 

### O emission factors for combustion of various non-standard hydrocarbon fuels (NEB 1999) and those values have been used to determine N 2 

### O emissions consistent with refi nery combustion operations. The N 2 

### O emission factors utilized in this stu dy are presented in Table 4-22.

Table 4-22. Refinery Fuels and Associated N 2 O Emissions from Fuel Combustion

Refinery Fuel N 2 O Emissions (kg N 2 O/MMBtu HHV) References

Liquefied Petroleum Gases (LPG) 0.00950 NEB 1999, Table A10.1 Distillate Fuel Oil 0.00351 NEB 1999, Table A10.1 Residual Fuel Oil 0.00326 NEB 1999, Table A10.1 Still Gas 0.00065 NEB 1999, Table A10.1 Petroleum Coke 0.00322 NEB 1999, Table A10.1 Other Petroleum Products* 0.00351 NEB 1999, Table A10.1 Natural Gas 0.00057 NEB 1999, Table A10.1 Coal** 0.00237 NEB 1999, Table A10.1 * Includes pentanes plus, other hydrocarbon s, oxygenates, hydrogen, unfinished oils,

gasoline, special naphthas, jet fuel, lubricants, asphalt and road oil, and miscellaneous products; emissions are assumed to be similar to diesel fuel. ** Assume bituminous coal



### 4.2.4.4 Refinery Fuels Combustion Emissions Profile Refinery GHG emissions attributab le to fuels combusted on a daily basis are presented in Table 4-23.
Table 4-23. GHG Emissions Associated with Daily Fuels Input to Refineries
Emissions (kg/day) Refinery Fuel Quantity Input Units CO 2 CH 4 N 2 O LPG 11,438 bpd 2,576,796 49 393 Distillate Fuel Oil 2,068 bpd 881,985 66 42 Residual Fuel Oil 6,047 bpd 2,995,568 164 124 Still Gas 652,701 bpd 251,420,568 5,247 2,562 Petroleum Coke 245,622 bpd 151,069,859 4,418 4,761 Other Petroleum Products 14,600 bpd 6,101,217 462 297
Natural Gas 1,871 MMcfd 102,033,150 2,575 1,095 Coal 112 tons/day 282,361 2 7 Total 517,361,504 12,983 9,281

### 51 

### 4.2.5 Hydrogen Production Refineries are the largest consumers of hydrogen in the United States (CEH 2004). Hydrogen at refineries comes primarily from three diffe rent sources—hydrogen by-product from catalytic reforming, on-site hydrogen plants, and purchased hydrogen produced off-site. For this study all hydrogen produced on-site and off-site is assume d to be generated by steam methane reforming using natural gas as both a feedstock and fuel.
While all three of the aforementioned sources cont ribute to the emissions profile for the refining industry, their GHG accounting differs. The en ergy used to produce hydrogen via catalytic reforming—and hence the emissions associated with this activity—are embedded in the total refinery energy usage estimation calculated in th e previous section. The fuel and associated utilities for on-site hydrogen production at a dedicat ed hydrogen plant are also included in the refinery fuels-consumed tally, but the natural gas used as a feedstock is explicitly excluded. The energy/resource usage and envir onmental effects of hydrogen produ ced and purchased from an off-site or third party supplier are not accounted for in the refine ry fuels consumed estimate. Table 4-24 outlines these hydrogen accounting issues.
Table 4-24. Refinery Hydrogen Sources and Emissions Accounting Summary

Hydrogen Source Included in Refinery Fuels Consumed Emissions Profile Not Included in Refinery Fuels Consumed Emissions Profile

Catalytic Reformer Complete accounting in refinery fuels used tally; Resource, energy used, and

associated emissions embedded in refinery total None

On-Site H 2 Production Partial accounting in refinery fuels used tally; Fuel/utilities and associated emissions embedded in refinery total Feedstock (natural gas) input and GHG emissions (primarily CO 2 ) consistent with H 2 production not included

Off-Site (3 rd party) H 2 Production None Complete cradle-to-gate LCA inventory/profile must be generated for H 2 production and delivery



### To ensure complete accounting of emissions for hydrogen production, the following must be determined:

• Refinery energy/fuels consumed for catalytic reforming and allocation to liquid fuels and hydrogen, as appropriate

• Refinery energy/fuels consumed for the on-site hydrogen plant

• Feedstock quantity of natural gas fed to th e on-site hydrogen plant and associated cradleto-gate emissions consistent with production and delivery of that qua ntity of natural gas

• Process emissions from the on-site hydrogen plant

• A full cradle-to-gate LCA inve ntory/profile for off-site H 2 

### production and delivery

• Allocation of emissions associated with hydrogen production (detailed in subsequent sections)

### 52 To simplify the issue of hydr ogen accounting, the concept of a hydrogen “pool” has been developed. This pool consists of excess hydr ogen from the catalytic reformer and hydrogen produced on- and off-site via steam methane re forming. All hydrogen gets input into the pool and hydrogen needed for refinery unit operations is pulled indiscriminately from the pool. Each hydrogen-contributing source is allotted an emburdened usage for that fraction.
4.2.5.1 Hydrogen Production Via St eam Methane Reforming (SMR) Hydrogen for refinery usage in the United Stat es is produced predominantly by steam methane reforming (SMR) of natural gas and this st udy assumes both on-site and off-site hydrogen production utilize this method. Th e amount of hydrogen produced at on-site hydrogen plants is assumed to be 85% of the installed hydrogen pr oduction capacity reported by EIA (as of January 1, 2006). § The amount of hydrogen input to the refinery from an external source is estimated to be 1,220 million standard cubic feet per day (scfd) based on the 2004 Chemical Economics Handbook Marketing Report for Hydrogen (CEH 2004). § This source reports a value for 2003 which was extrapolated using the percentage growth in off-site hydrogen production for refineries from 1999 to 2003.


### Hydrogen Plant Feedstock Requirements Hydrogen plants are being built/ret rofitted to handle increasingl y heavier hydrocarbon feedstocks and fuels but this study assumes that hydrogen production in the U.S. operates solely using natural gas as both a fuel and feedstock. Th e SMR stoichiometry for converting hydrocarbons (primarily methane) to hydrogen is shown in E quation 1. From the stoichiometry, it can be seen that for pure methane and 100% conversion, th e theoretical minimum necessary feedstock requirements would be 0.0048 kg (231 Btu LHV, 256 Btu HHV) methane per scf of hydrogen.

C x 

### H (2x+2) 

### + 2xH 2 

### O Æ (3x+1)H 2 

### + xCO 2 

### (1)
The actual amount of natural gas used as a f eedstock must be determined to estimate the upstream and process emissions for the on-site hydrogen plant. The following table shows a survey of total feedstock input to SMR proce sses for every standard cubic foot of hydrogen produced and their associated references. Natura l gas lower heating value is assumed to be 918 Btu/ft 3 

### and higher heating value is assumed to be 1020 Btu/ft 3 

### (API 2004). The average density is assumed to be 23.8 ft 3 

### per pound (API 2004). In this study, the hydrogen plant feedstock requirement for natural gas is assumed to be 352 Btu HHV/scf H 2 

### (0.006581 kg natural gas per scf H 2 

### ).


### Hydrogen Plant CO 2 

### Process Emissions The CO 2 

### process emissions consistent with on-site SMR operation must be determined from the above feedstock specific input. Table 4-26 shows the average U.S. natural gas composition that is assumed to be representative of the na tural gas input for all cases in this study.

§ A sensitivity analysis was performed on these parameters.

### 53 Table 4-25. Specific Natural Gas Input as Feedstock to SMR Hydrogen Plants
Feedstock Input (Btu LHV/scf H 2 ) Feedstock Input (Btu HHV/scf H 2 ) Reference Comments

275 306 Boyce 2004 Old style--methanation process with amine purification 317 352 Boyce 2004 Modern—PSA purification 331 368 NREL 2001 338 376 FW 2001
352 

### § Study Value

Table 4-26. Composition of U.S. Pipeline Quality Natural Gas (API 2004)
Compound Average Volume % Methane 93.07 Ethane 3.21 Propane 0.59 Higher hydrocarbons * 0.32 Non-hydrocarbons ** 2.81 * Higher molecular weight hydrocarbons were represented by C5 in

calculating the CO 2 and hydrogen production rates. ** The non-hydrocarbons are assumed to contain 0.565 volume % CO 2

based on an average natural gas comp osition from Perry’s Chemical Engineers Handbook.


### Based upon the natural gas composition show n in Table 4-26, hydrogen plant process CO 2 

### emissions have been calculated, consistent with the rigorous API methodology that uses the average U.S. pipeline natural gas specifications (API 2004). Natural gas is estimated to be 76 weight percent carbon (API 2004) and CO 2 

### process emissions are estimated to be 0.01879 kg CO 2 

### per scf H 2 

### produced (2.855 kg CO 2 

### per kg of natural gas feed input). Complete combustion of natural gas is assumed and thus there are ne gligible methane process emissions. The use of hydrogen process waste gas streams recycled to the hydrogen plant re former furnaces as a fuel gas are assumed to be unaccounted for in th e EIA refinery fuels-consumed estimate. To bound the above determined process CO 2 

### emissions estimate and determine the absolute minimum CO 2 

### emissions, the simplified approach for determining CO 2 

### process emissions was also evaluated. This method considers the stoi chiometry shown in Equation 1 and determines the CO 2 

### production consistent with a given rate of H 2 

### production. Using this method, the minimum CO 2 

### process emissions for a hydrogen plant us ing the above pipeline quality natural gas would be 0.0134 kg CO 2 

### per scf H 2


### . 

### Hydrogen Plant Energy Usage Table 4-27 shows a survey of reported total energy usage (i ncluding feedstock energy) for hydrogen production from various vendors and the literatu re. It is important to note that all but one of the estimates considers modern pressu re swing adsorption (PSA) as the purification

§ A sensitivity analysis was performed on these parameters.

### 54 technology. This technology is le ss energy intensive than the olde r style plant which uses aminebased purification and methanation technology (Boyce 2004). Thus, these estimates may be more conservative and underestimate the energy requirements for older plants. The average energy usage (including natural ga s for feedstock and fuel use) for production of hydrogen in this study is estimated to be 388 Btu HHV/scf H 2


### . Table 4-27. Estimated Energy Consumption for Hydrogen Production

Estimated Energy Usage (Fuel + Feed + Power – Steam) in Btu HHV/scf H 2 Technology Supplier Reference Comments

370 Uhde GmbH HP 2006 This estimate does not include power consumption; Energy usage reported as 333 MMBtu/MMscf and assumed to be LHV and adjusted to HHV basis 389 Technip HP 2006

430 Haldor Topsøe A/S HT 2008 HTCR Technology

506 Chicago Bridge & Ironworks (CBI) Boyce 2004 Old style--methanation process with amine purification; steam valued at 1,200 Btu/lb

388 Chicago Bridge & Ironworks (CBI) Boyce 2004 Modern—PSA purification; steam valued at 1,180 Btu/lb

354 Foster Wheeler Meyers 2004 Feed and fuel energy usage assumed to be HHV basis; Energy usage = 400 Btu/scf if

feed/fuel usage reported on LHV basis 385 NREL 2001 Steam valued at 1,200 Btu/lb 388 Study Value



### For hydrogen purchased from an external supplier, the entire life-cycle inventory from the cradle-to-gate must be determined. This inventory includes emissions from natural gas acquisition, transport, conversion to hydrogen, and subsequent hydrogen transport to the refinery. The cradle-to-gate GHG emissions profile for natu ral gas is necessary to estimate the upstream emissions associated with the natural gas feedst ock input to the refine ry hydrogen plant (the natural gas input to the refinery fuels consum ed tally is discussed in Section 4.2.3.3). The GHG life cycle inventory fo r natural gas is shown in Table 4-17. The cradle-to-gate life cycle inventory for hydrogen production using SMR with PSA purification technology has been derived and is presented in Appendix G. Table 4-28 summarizes the results for this process.
Table 4-28. Cradle-to-Gate GHG Emissions Inventory for Hydrogen Production via SMR with PSA Purification Emissions (kg) Basis/Quantity CO 2 CH 4 N 2 O scf H 2 Produced 0.0204 2.98E-05 1.03E-07

### 55 4.2.5.2 Hydrogen Produced from Catalytic Reformer It has been estimated that hydrogen produced dur ing catalytic reforming accounts for more than 60% of refinery hydrogen needs (Aitani 1996). In addition to producing high-octane reformate for gasoline blending, catalytic re forming also produces an off-ga s that is typically 80-85% hydrogen by volume (CEH 2004). Table 4-29 sh ows the quoted hydrogen production quantities from reforming operations cited from various sources. This study assumes that catalytic reforming operations produce 1,000 standard cubic feet of hydrogen per barre l (scfb) of feed, on average. §
Table 4-29. Specific Hydrogen Production from Catalytic Reformer
Specific Hydrogen Production (scf H 2 per bbl of Reformer Feed) Reference Comments

600 – 1,600 CEH 2004 1,481 Energetics 2007 1,085 HPP 2006 Semiregenerative 1,709 HPP 2006 Continuous Catalyst Regeneration 1,150 HP 2006 CB&I Licensor 950 – 1,500 UOP 2003 1,000 Study Value



### For the estimated catalytic reformer throughput of 3,419,000 bpd (detailed in Section 4.2.9.1), this results in a net hydrogen production from th e catalytic reformer of 3,419 million standard cubic feet per day (MMscfd) of hydrogen producti on. This corresponds to approximately 49% of the total refinery hydrogen requirements be ing met by the reformer hydrogen output. The feed to the catalytic reformer requires hydrotreating to remove sulfur prior to entering the catalytic reformer. The hydrogen used in this operation is a recycle stream from the hydrogen produced in the catalytic reformer and is consider ed to be integral to the catalytic reformer operation (Maples 1993). Thus, the hydrogen recycl e stream is subtracted from the catalytic reformer hydrogen output and the remaining hydrogen fr om the reformer is then allocated to the hydrogen pool. Table 4-30 demonstrates catalytic reformer contributions to the hydrogen pool. Hydrotreating the catalytic reformer/naphtha st ream utilizes approximately 19% of the hydrogen produced by the reformer.
Table 4-30. Catalytic Reformer Net Hydrogen Output

Source Estimated Unit Operation Input (thousand bpd) Specific H 2 Production (Consumption) (scfb feed) Daily H 2 Production (Consumption) (MMscfd) Catalytic Reformer 3,419 1,000 3,419 Reformer Feed Hydrotreating* 3,419 (186) (637) Catalytic Reformer—Net Contribution to H 2 Pool 814 2,782 * Hydrogen use for hydrotreating will be discuss ed in greater detail in subsequent sections

§ A sensitivity analysis was performed on these parameters.

### 56 Hydrogen produced from the cataly tic reformer must be allocate d a portion of the unit operation energy burden. This burden is expressed as “energy used” to operate the catalytic reformer. The total energetic burden (the energy used to opera te the catalytic reformer and reformer feed hydrotreater) must be allocated to the co-pr oducts of the operation, gasoline and hydrogen. Typical methods for allocation considered are examined below:

• Historically the catalytic reformer bur den has been assigned principally—if not entirely—to the gasoline fracti on. However, hydrogen usage is now a critical component for meeting regulatory requirements regarding sulfur content.

• If the energetic burden is divided betw een the reformate and hydrogen based on the energetic content of the species, then the refo rmate (gasoline) bears the lion’s share of the energy burden. The value of the hydrogen is no t as an energy carrier, but rather as a reactant. This distin ction in the intrinsic value of hydrogen preven ts straight-forward comparison to the reformate. Alternatively, this study uses “sys tem expansion” to determine the “value” of hydrogen. If the catalytic reformer was not sufficient/operationa l/present to meet the hydrogen needs, hydrogen would need to be produced by the next best me thod—steam methane reforming. Therefore, the energetic burden associated with producing hydr ogen via steam methane reforming is allocated to hydrogen from the catalytic reformer as though it were produced by SMR. One salient difference is that the hydroge n stream from a dedicated hydr ogen plant is of higher purity— generally 97+% hydrogen while hydrogen from a catal ytic reformer is estimated to be 80-85% hydrogen (CEH 2004). The estimated specific energy consumption for the catalytic reformer and reformer hydrotreater used in this study is 312 MBtu/barrel (Energe tics 2007). This corres ponds to a daily energy consumption for the reformer of 384 Btu/scf H 2 

### net output from the reformer. This is lower than the 388 Btu/scf H 2 

### required to produce hydrogen via SMR (from Table 4-27). Therefore, reformate—a high-quality gasoline blendsto ck—and hydrogen are both produced during the operation with less energy consumption than w ould be needed to simply produce the same quantity of hydrogen by SMR. In the absence of a more equitable method for allocating the catalytic reformer burden to the reformate and hydrogen co-products, the system expansion methodology calls for the hydrogen contributed to the pool to be bur dened with 100% of the energetic requirement for the catalytic reformer, 384 Btu/scf. All operations/products that draw hydrogen from that pool are then equally burdened. Appendix F provides additional discussion on the allocation rationale and methodology employed in this study.
4.2.5.3 Summary of Hydrogen Pool Table 4-31 provides the estimated hydrogen produc tion rate and relative contribution to total refinery production from the various sources for 2005.

### 57 Table 4-31. Hydrogen Production for U.S. Refineries in 2005

Source Contribution Amount (MMscfd H 2 ) Percent Contribution
Catalytic Reformer 2,782 43.4% On-Site H 2 Plant 2,400 37.5%
Off-Site H 2 Plant 1,222 19.1%
Total 6,404 100%



### Table 4-32 summarizes the refinery energy burden for hydrogen produced from the three aforementioned sources. The energy usage fo r on-site hydrogen production reported by U.S. refineries to the EIA specifically excludes the energy contained in the natural gas feedstock and is calculated as shown in Appendix G. The to tal refinery energy used for hydrogen production is used as part of the allocation process for the refinery fuels combustion profile.
Table 4-32. Refinery Energy Used for Hydrogen Production for U.S. Refineries in 2005

Source Refinery Energy Used for Hydrogen Production (MMBtu HHV per day) Catalytic Reformer 1,068,397 On-Site H 2 Plant 87,472
Off-Site H 2 Plant 0
Total 1,155,866



### Table 4-33 summarizes the emissions burden for the hydrogen produced from the three sources. Note that the GHG profile here doe s not include emissions associated with fuels consumed at the refinery. Those emissions are captured in the re finery fuels combustion em issions presented in a previous section.
Table 4-33. GHG Emissions Not Included in Refinery Energy Usage for Hydrogen Production for U.S. Refineries in 2005
Emissions (kg/day) Source Emburdened Usage CO 2 CH 4 N 2 O Catalytic Reformer 0 0 0

On-Site H 2 Plant NG feedstock cradle-to-gate GHG emissions + CO 2 process emissions from H 2 production 51,350,819 74,346 123

Off-Site H 2 Plant Complete cradle-to-gate LCA inventory/profile for H 2 production and delivery 24,936,718 36,440 126

Total 76,287,537 110,786 249

### 58 

### 4.2.6 Flaring Operations Flare operations and associated emissions are no t generally tracked for petroleum refineries across the United States. For this study, U.S. refi nery flare operations and emissions have been estimated by taking data from tw o air quality districts in Califor nia—which require refineries to report flaring operations—and ex trapolating that data to the U.S. as a whole. A flaring summary was compiled for selected petroleum refineries in two air quality basins in California for a one-year period. The two basins selected were the Bay Area Air Quality Management District 2 

### (BA AQMD) and the South Coast Air Quality Management District 3 

### SCAQMD). The BA AQMD data included methane, whereas the SCAQMD data did not. Flare gas flow for selected California refineries during 2005 in the BA AQMD and during 2006 in SCAQMD are illustrated in Table 4-34. Thes e data were extracted from the BA AQMD and SCAQMD websites and totaled. The total flare ga s flow was divided by the total refinery atmospheric distillation column capacity for those refineries in order to apply a metric by which to scale the refineries’ flaring activities. Table 4-34 shows the flare gas flow in standard cubic feet and the flare gas output in terms of standard cubic feet per barrel of atmospheric distillation capacity. For this study, the average U.S. refinery flare gas flow is assumed to be 5.65 standard cubic feet per barrel (scfb). § Using California data for flare opera tions and extrapolating those valu es to all U.S. refineries is expected to underestimate the emissions for total U.S. refinery flaring operations. California— and the BA AQMD and SCAQMD in particular—have more stringent environmental regulations than most other locations. The SCAQMD require s refineries to have flare minimization plans and report their performance. Refineries located in other regions will not likely have such strict anti-flaring operational mandates.

4.2.6.1 CO 2 

### Emissions Given that the composition of flared gas is unknown, it is nece ssary to estimate CO 2 

### combustion emissions without an understanding of th e composition of the gas. The minimum CO 2 

### emissions consistent with flaring would result from the combustion of flare gas composed entirely of natural gas (since it has the lowe st carbon-to-hydrogen ratio). For a flare gas flow rate of 5.65 scfb, using the natural gas energy content and emission factor for combustion shown in Table 4-20, refinery CO 2 

### emissions from flaring would be 0.308 kg CO 2 

### per barrel of atmospheric distillation capacity. This represents the minimum CO 2 

### emissions produced by flare activities.

4.2.6.2 Methane Emissions In addition to presenting the flare gas flow , the BAAQMD data include methane emissions, whereas the SCAQMD data do not. BAAQMD flare data are shown in Table 4-35.

2 http://www.baaqmd.gov/enf/flares/index_2005.htm

3 http://www.aqmd.gov/comply/1118/emissiondata.htm
§ A sensitivity analysis was performed on these parameters.

### 59 Table 4-34. Flaring Summary for Selected California Refineries

Refinery (Location) Flare Gas Flow (scf) Flare Flow per Unit of Atmospheric Distillation Capacity (scfb) Year Reference

Chevron (Richmond) 73,168,477 0.83 2005 BA AQMD 2008 ConocoPhillips (Rodeo) 58,545,909 2.11 2005 BA AQMD 2008 Shell (Martinez) 144,843,539 2.55 2005 BA AQMD 2008 Tesoro (Martinez) 298,309,759 4.92 2005 BA AQMD 2008 Valero (Benicia) 67,533,365 1.28 2005 BA AQMD 2008 Chevron (El Segundo) 402,340,700 4.24 2006 SCAQMD 2008 Ultramar (Wilmington) 122,149,430 4.14 2006 SCAQMD 2008 BP (Carson/LA) 714,386,630 7.53 2006 SCAQMD 2008 ExxonMobil (Torrance) 270,100,637 4.95 2006 SCAQMD 2008 Paramount (Paramount) 222,424,303 12.19 2006 SCAQMD 2008 ConocoPhillips (Wilmington) 1,178,351,730 23.23 2006 SCAQMD 2008

Table 4-35. Flaring Summary for Selected California Refineries 2005 (BA AQMD 2008)

Refinery (Location) Flare Gas Flow (scf) CH 4 Emissions per Unit of Atmospheric Distillation Capacity (scfb) Flare Flow per Unit of Atmospheric Distillation Capacity (scfb) Chevron (Richmond) 73,168,477 0.0027 0.83 ConocoPhillips (Rodeo) 58,545,909 0.0120 2.11 Shell (Martinez) 144,843,539 0.0090 2.55 Tesoro (Martinez) 298,309,759 0.0144 4.92 Valero (Benicia) 67,533,365 0.0042 1.28



### If methane combustion emissions are estimated as if the flare gas was natural gas, as above, then the refinery methane emissions are significantly lower than if we use the refinery-reported methane flare emissions. Table 4-36 shows the es timate for refinery flare emissions if natural gas is considered to be the flare gas, as well as the actual (reported) refi nery methane emissions. As can be seen, the reported value is much larger than the estimated value. The reported refinery methane emissions are used to estimate U.S. to tal refinery methane emissions from flaring activities.
Table 4-36. Estimate of GHG Emissions Consistent with Flaring Activities 2006

Source/Method CH 4 Emitted from Flares (kg CH 4 per bbl of Distillation Capacity) Estimated from Flare Rate 7.77E-06 Reported 1.46E-04 Study Value 1.46E-04

### 60 4.2.6.3 N 2 

### O Emissions For a flare gas flow rate of 5.65 scfb, using the natural gas energy content and emission factor for combustion shown in Table 4-22, refinery N 2 

### O emissions from flaring would be 3.306E-06 kg N 2 

### O per barrel of atmospheri c distillation capacity. 

### 4.2.7 Vented/Fugitive Emissions The primary source of methane emissions from re fineries is vented emissions, with smaller amounts of unburned CH 4 

### in process heater stack emissions and unburned CH 4 

### in engine exhausts and flares (EPA 2007b). Methane emissions from refinery operations have not generally been tracked or estimated and very litt le information is available regarding estimation procedures and data for estimates. The Petrol eum Industry Guidelines for Reporting Greenhouse Gas Emissions (IPIECA et al. 2003) does not co nsider methane in any of its GHG estimation tiers for refining operations (see Ap pendix D). Due to the small contribution of methane to total GHG emissions from refineries and the uncertainty associated with the methane estimate, direct methane emissions are often ignored when compiling GHG totals for refineries. Methane emissions from refinery operations for the 2005 U.S. GHG Inventory have been estimated and extrapolated from 1996 and 1999 EPA studies (EPA 1996; EPA 1999) of refinery process unit methane emissions. Table 4-37 sh ows the EPA estimates of methane emissions from petroleum refinery operations for 2005. For the purpose of this study, methane emissions a ssociated with asphalt blowing have not been included in the refinery methane emissions wh ich are allocated to liquid fuel production. Asphalt blowing emissions are one of the primar y sources of refinery methane emissions but these operations are not attribut able to liquid fuels production and thus should be allocated exclusively to asphalt production. It is important to note that e nvironmental regulations and indust ry responsible care has increased in the interim since 1996 and 1999 when the esti mates for process emissions were developed. Thus, these values may be inflated for refineri es currently in operation today. Methane venting and fugitive emissions for liquid fuels production in 2005, as derived from the data in Table 4-37, were assumed to be 0.861 Bcf/year (ven ted emissions, excluding asphalt blowing, plus fugitive emissions). §


### 4.2.8 Refinery Emissions Profile
Table 4-38 summarizes the refine ry emissions from fuels consum ption (direct fuel combustion emissions as well as indirect emissions ), hydrogen production, flaring, and methane venting/fugitives. The indirect refinery emissions li sted in Table 4-38 include upst ream emissions associated with purchased power and steam. The emissions associ ated with extraction of the raw materials from the earth, transport of those material to an energy conversion facility, energy conversion, and transport to the consumer are embedded in the GHG estimates shown in that table. The direct emissions shown in Table 4-38 account for the upst ream emissions associated with acquisition of the purchased coal and natural gas.

§ A sensitivity analysis was performed on these parameters.

### 61 Table 4-37. 2005 Methane Emissions fr om Petroleum Refining (EPA 2007c)

Activity/Equipment Emission Factor Units Activity Factor Units Emissions (Bcf/yr)

Vented Emissions 1.252

Tanks 20.6 scf CH 4 /Mbbl 1,951 Mbbl/cd heavy crude feed 0.015

System Blowdowns 137 scf CH 4 /Mbbl 15,204 Mbbl/cd refinery feed 0.760

Asphalt Blowing 2,555 scf CH 4 /Mbbl 510 Mbbl/cd production 0.477
Fugitive Emissions 0.086
Fuel Gas System 439 Mcf CH 4 /refinery/yr 142 Refineries 0.062

Floating Roof Tanks 587 scf CH 4 /floating roof tank/yr 767 No. of floating roof tanks 0.000

Wastewater Treating 1.88 scf CH 4 /Mbbl 15,204 Mbbl/cd refinery feed 0.010

Cooling Towers 2.36 scf CH 4 /Mbbl 15,204 Mbbl/cd refinery feed 0.013

Combustion Emissions 0.094
Atmospheric Distillation 3.61 scf CH 4 /Mbbl 15,479 Mbbl/cd refinery feed 0.021

Vacuum Distillation 3.61 scf CH 4 /Mbbl 6,966 Mbbl/cd feed 0.009 Thermal Operations 6.02 scf CH 4 /Mbbl 2,181 Mbbl/cd feed 0.005 Catalytic Cracking 5.17 scf CH 4 /Mbbl 5,239 Mbbl/cd feed 0.010 Catalytic Reforming 7.22 scf CH 4 /Mbbl 3,222 Mbbl/cd feed 0.008 Catalytic Hydrocracking 7.22 scf CH 4 /Mbbl 1,340 Mbbl/cd feed 0.003 Hydrorefining 2.17 scf CH 4 /Mbbl 2,167 Mbbl/cd feed 0.002 Hydrotreating 6.50 scf CH 4 /Mbbl 9,941 Mbbl/cd feed 0.023 Alkylation/Polymerization 12.6 scf CH 4 /Mbbl 1,111 Mbbl/cd feed 0.005 Aromatics/Isomeration 1.80 scf CH 4 /Mbbl 992 Mbbl/cd feed 0.001 Lube Oil Processing 0.00 scf CH 4 /Mbbl 185 Mbbl/cd feed 0.000 Engines 0.006 scf CH 4 /hp-hr 1,187 MMhp-hr/yr 0.007

Flares 0.189 scf CH 4 /Mbbl 15,204 Mbbl/cd refinery feed 0.001

Total 1.432 Total Vented + Fugitive (excluding asphalt blowing) 0.861

### 62 Table 4-38. Refining GHG Emissions Sources Emissions (kg/day) Source CO 2 CH 4 N 2 O Fuels Combustion 517,361,504 12,983 9,281 Fuels Acquisition* Indirect Energy Inputs 93,451,488 113,716 1,178 Purchased Fuels 14,134,109 168,565 277 Flare Emissions 76,287,537 110,786 249
H 2 Production Emissions** 5,337,947 2,524 57
CH 4 Vented/Fugitive Emissions*** 0 45,159 0
Total 706,572,586 453,732 11,042 * Excludes emissions associated with refinery-produced fuels ** Does not include emissions associated with H 2 production embedded in the refining profile *** Does not include methane emissions from asphalt blowing



### Emissions from all fuels consumed (combustion and acquisition) and flaring and vented/fugitive emissions are combined to determine a total re finery emissions pool. There are no individual assignments of energy sources to unit operations. This particular modeling aspect is well-suited to allocation of refinery emissions to energy cons umers. However, it should be noted that energy sources have very different upstream emissions profiles. For example, coal extraction, processing, and transport emits 6.60 kg CO 2 

### E per MMBtu of coal delivered while natural gas extraction, processing, and transport emits 9.58 kg CO 2 

### E per MMBtu delivered. The emissions associated with hydrogen produc tion create a second pool. These pools will be allocated to various petroleum refinery pr oducts as discussed in the next section.


### 4.2.9 Refinery Process Unit Data Modeling and GHG Allocation to Products Refinery emissions and emissions associated with hydrogen produc tion are allocated to products based upon each product’s consumption of resources (hydrocarbon feedstocks, fuels/energy, and hydrogen). To do this, the individua l unit operations within the re fineries are modeled using the following steps:
1. Capacity/throughput is determined for each of the unit processes
2. Energy requirements are determined for each of the unit processes
3. Hydrogen consumption is determined for each of the unit processes
4. Contribution of each of the unit processes to the final product slate is determined

5. Resource usage (energy and hydrogen) is allocated to the product slate Figure 4-6 depicts the allocation of the refi nery emissions and hydr ogen production emissions pools developed in this section. Additional information on the selection of the allocation technique is provi ded in Appendix F.63Figure 4-6. Representation of Allocation of Life Cycle Stage #3 Emissions to Product Categories

Gasoline Diesel Jet Fuel Fuel Oil Coke "Light Ends" "Heavy Ends"Fraction of RefineryEnergy Attributable toEach Product Gasoline Diesel Jet Fuel Fuel Oil Coke "Light Ends" "Heavy Ends"ABCDEFG% of Volumetric ThroughputProcessUnitsEnergyUsageHydrogenConsumption Gasoline Diesel Jet Fuel Fuel Oil Coke "Light Ends" "Heavy Ends"Fraction of H2Consumption Attributableto Each Product

Gasoline Diesel Jet Fuel Fuel Oil Coke "Light Ends" "Heavy Ends"Emissions Attributable toEach Product

### 64 4.2.9.1 Process Unit Capacity and Throughput EIA compiles data annually for U.S. refineries which include unit operation capacities in barrels per stream day and/or barrels pe r calendar day. Barrels per stream day (bpsd) is defined as the maximum number of barrels input to a unit opera tion which can be processed within a 24-hour period when running at full capaci ty under optimal crude and pr oduct slate conditions with no allowance for downtime. Barrels per calendar day ( bpcd) is defined as the amount of input that a unit operation can process in one day under us ual operating conditions. Thus, barrels per calendar day is representative of actual operating conditions a nd barrels per stream day is representative of a theoretical maximum capacit y. Table 4-39 shows U.S. refineries total unit operation capacities in barrels pe r stream day and barrels per calendar day (where reported) for 2005 (plant capacities reported as of January 1, 2006). It is assume d that plant capacity reported on January 1, 2006, is representative of the cap acity available for the entire year of 2005.
Table 4-39. U.S. Total Refinery Unit Operations Capacities in 2005* (EIA 2008)

Process Unit Operation Capacity in 2005 (bpsd) Unit Operation Capacity in 2005 (bpcd) Atmospheric Distillation 18,307,502 17,338,814 Vacuum Distillation 8,398,470 Not Reported Catalytic Cracking (Fresh Feed) 6,187,883 5,799,582 Catalytic Hydrocracking 1,637,200 1,474,986 Distillate 516,600 473,515 Gas Oil 920,200 824,171 Residual 200,400 177,300 Coking 2,510,910 2,330,100 Delayed 2,305,510 2,141,600 Fluid 205,400 188,500 Hydrotreating 14,807,986 Not Reported Naphtha/Reformer Feed 4,400,484 Not Reported Gasoline 2,056,470 Not Reported Heavy Gas Oil 2,557,040 Not Reported Distillate Fuel Oil 4,784,852 Not Reported Kerosene/Jet Fuel 960,700 Not Reported Diesel Fuel 2,950,792 Not Reported Other Distillate 873,360 Not Reported Residual Fuel Oil/Other 1,009,140 Not Reported Residual Fuel Oil 327,100 Not Reported Other 682,040 Not Reported Catalytic Reforming 3,859,070 Not Reported Alkylation** 1,238,479 Not Reported Isomerization** 708,357 Not Reported Isobutane 230,714 Not Reported Isopentane/Isohexane 477,643 Not Reported

### 65 Process Unit Operation Capacity in 2005 (bpsd) Unit Operation Capacity in 2005 (bpcd)
Aromatics** 319,250 Not Reported Asphalt & Road Oil** 893,249 Not Reported Fuels Solvent Deasphalting 386,290 Not Reported Lubricants** 219,840 Not Reported Hydrogen** (MMcf) 2,823 Not Reported Sulfur** (short tons) 32,421 Not Reported * Refinery capacities were based on operational capacity as of January 1, 2006 ** Production Capacity rather than downstream charge capacity


### In order to better quantify the gas oil fractions, EIA has define d fractional cuts by boiling point range. Table 4-40 shows the boiling point ranges for the gas oil fractions noted in Table 4-39.
Table 4-40. Boiling Range for Various Petroleum Intermediates (EIA 2008)

Fraction Boiling Range ( o F) Naphtha 122 - 400 Kerosene and Light Gas Oils 401 – 650 Heavy Gas Oils 651 – 1,000 Residuum > 1,000



### Visbreaking and other thermal cracking cap acity were excluded from the thermal cracking/coking category because th e total visbreaking plus other capacity amounts to less than 1% of the coking capacity. In addition, visbreaking un it operation capacity is decreasing in the U.S. and there was an 11% reduction between January 1, 2006, and January 1, 2007. Actual capacity utilization is therefor e questionable and has been excluded from this life cycle study. Aromatics, asphalts, and fuels solv ent deasphalting are also excluded and thus are not captured in the refinery modeling for liquid fuels production. It is not prac tical to attempt to estimate throughput and energy consumption associated with these downstream op erations due to the variability in refinery designs, unspecified fina l product qualities, and a general lack of publicly available information to characterize the operation of these processes. It is acknowledged that liquid fuels will, therefore, bear some burden for these operations. Unit operation capacities are not reported for all unit operation s in barrels per calendar day, as indicated in Table 4-39. The act ual daily operating capacity for unit operations—a s a percent of the stream day capacity—varies by operation. The atmospheric di stillation column capacity in barrels per calendar day is 94.7% of stream day capacity, catalytic cracking is 93.7%, catalytic hydrocracking is 90.1%, and coking is 92.8%. Data on the actual downstream (subsequent proce ss units) input into certain key refinery unit operations are collected by EIA. The actual i nputs (in barrels per ca lendar day) into the atmospheric distillation colum n, catalytic cracking units, ca talytic hydrocracking units, and delayed and fluid coking units ar e reported by EIA. Table 4-41 shows the actual input to these unit operations for refineries in the U.S. in 2005.

### 66 Table 4-41. Unit Operation Capacity, Actual Input, and Utilization Rate for Key U.S. Refinery Operations in 2005 (EIA 2008)

Unit Operation Unit Capacity (bpcd) Unit Actual Input (bpd) Operable Utilization Rate (%) Atmospheric Distillation 17,338,814 15,578,000 89.8 Catalytic Cracking (Fresh Feed) 5,799,582 5,269,000 90.9 Catalytic Hydrocracki ng 1,474,986 1,172,000 79.5 Delayed and Fluid Coking 2,330,100 2,054,000 88.2



### In order to estimate the energy consumption a ssociated with individua l unit operations, it is necessary to determine the input to those ope rations. The actual thr oughputs/inputs for the atmospheric distillation colum n, catalytic cracking units, ca talytic hydrocracking units and delayed and fluid coking units are known but the inputs to the vacuum distillation, hydrotreating, catalytic reforming, alkylation, and isomerization units must be approximated. Table 4-42 shows the actual or estimated input for each of the refi nery unit operations listed in Table 4-39. The actual hydrocracking input has been sub-divided into distillate , gas oil, and residual inputs according to the relative installed unit operation capacities. Similarly, the total coking input has been ratioed to delayed and fluid coking units based upon the installed capacities. A 1996 American Petroleum Institute (API)/Nati onal Petroleum Refiners Association (NPRA) survey of refinery operations and product qual ity (API 1997) was used to estimate the actual inputs to the vacuum distillation, hydrotr eating, catalytic reforming, alkylation, and isomerization units. The survey details the “percent capacity utilization” for the aforementioned units but the API/NPRA survey (A PI 1997) definition of “percent cap acity utilization” is slightly different than that of EIA. The API/NPRA survey definition of percent capacity utilization is ({Actual Unit Daily Charge or Production/Stre am Day Capacity} x 100). Hence the capacity reduction associated with the stream day to cale ndar day conversion (op timum to usual), as well as the decrease in utilization from the capacity at usual operati ng conditions to actual throughput, is included in this factor. The 1996 API/NPRA survey shows the percent utilization for hydrotreating operations at U.S. refineries (excluding California) averaged 79%. Most hydrotreating operations are therefore estimated, for the purpose of this model, to have operated at an 80% utilization rate in 2005 (slightly higher utiliz ation rate since crud e oil sulfur content has increased significantly since 1996 and sulfur requirements in finished products has become more stringent). Table 4-42 shows the 1996 API/ NPRA reported operation utilization rate and the estimated 2005 unit operati on utilization rate. In 2005, there was 168,000 bpd of lubricant produc tion (EIA 2008) resulti ng in a unit operation utilization rate of 76.3% (unknown quantity of process input since EIA only tracks production for this operation).

### 67 Table 4-42. U.S. Total Refinery Unit Operations Capacities in 2005*

Process Actual or Estimated Unit Operation Input

in 2005 (bpd) API/NPRA 1996 Unit Operation Utilization Rate (%) 2005 Unit Operation Utilization Rate (%) Atmospheric Distillation** 15,578,000 92.4 89.8 Vacuum Distillation 7,138,700 84.7 85.0 

### § Catalytic Cracking (Fresh Feed)** 5,269,000 91.2 90.9 Catalytic Hydrocracking** 1,172,000 89.9 79.5 Distillate 376,247 79.5 Gas Oil 654,873 79.5 Residual 140,880 79.5 Coking** 2,054,000 89.1 88.2 Delayed 1,887,836 88.2 Fluid 166,164 88.2 Hydrotreating 11,846,389 Naphtha/Reformer Feed*** 3,520,387 82.4 80.0 

### § Naphtha*** 101,251 Reformer Feed*** 3,419,136 Gasoline 1,645,176 80.0 

### § Heavy Gas Oil 2,045,632 83.6 80.0 

### § Distillate Fuel Oil 3,827,882 80.0 

### § Kerosene/Jet Fuel 768,560 75.5 80.0 

### § Diesel Fuel 2,360,634 78.8 80.0 

### § Other Distillate 698,688 80.0 

### § Residual Fuel Oil/Other 807,312 80.0 

### § Residual Fuel Oil 261,680 74.3 80.0 

### § Other 545,632 79.1 80.0 

### § Catalytic Reforming 3,419,136 86.1 88.6 Alkylation 1,052,707 84.4 85.0 Isomerization 521,553 Isobutane 177,650 76.6 77.0 Isopentane/Isohexane 343,903 71.3 72.0 Lubricants 168,000 Not Reported 76.4 Sulfur (short tons) 22,695 Not Reported 70.0 * Refinery capacities were based on operational capacity as of January 1, 2006 ** Actual throughput as reported by EIA, all ot hers are estimated; utilization rate based on bpcd capacity rather than bpsd (as for all other operations) *** Reformer feed hydrotreating assumed equal to reformer throughput with balance to naphtha hydrotreating

§ A sensitivity analysis was performed on these parameters.

### 68 4.2.9.2 Refinery Unit Oper ations’ Energy Consumption In order to allocate refinery energy usage and associated emissions, it is first necessary to determine the energy requirements for the individu al unit operations found in refineries. Energy utilization for each of the opera tions outlined in Table 4-43 has been estimated in the DOE study Energy and Environmental Profile of the U.S. Petroleum Refining Industry (Energetics 2007). All energy consumption data is on the basis of thousands Btu (MBtu) per barrel of feed input to the operation. The specific energy use is based on the estimated utility requirements for a range of technologies. The report breaks the unit processes energy requirements down into estimates from various energy sources, such as electricit y and hydrocarbon fuels, and reports total energy requirements after incorporating ex ported energy and electricity losses. The unit process energy requirements used from the re port specifically exclude ener gy associated with hydrogen production and consumption. The estimated net electricity requirements (b ased on Energetics unit operation electrical requirements combined with the 2005 actual and estimated throughputs from the previous section) yields an electricity requirement of approximately 33.5% more power than the EIA reported quantity of purchased power for refineries in 2005 (see Section 4.2.2). It is therefore assumed that 33% of the refineri es’ electricity is produced on s ite in combined heat and power (CHP) units or other power genera tion activities. To account fo r the thermodynamic inefficiency associated with producing electricity from hydrocarbon species, the 33% power component is multiplied by a factor of 2.5. At a practical level, this means that for every MMBtu of electricity produced on site that is used by a unit operation, 2.5 MMBtu of th ermal energy is necessary as a refinery input. Table 4-43 shows the original ranges and aver ages reported by Energetics including all electricity losses and the adjusted values incorp orating only those electricity losses associated with power generation o ccurring at the refinery. The study values align with the manner in which EIA reports fuels consumption.
4.2.9.3 Refinery Unit Hydrogen Consumption The primary use for hydrogen in refineries is for removal of sulfur (des ulfurization) to meet product quality requirements. Hydrotreating al so removes nitrogen, oxyge n, halides, and metals from petroleum fractions. U.S. refineries have the capacity to hydrotreat a combined volume equivalent to approximately 81% of the atmo spheric distillation capaci ty. Hydrocracking—a more severe hydrotreating process which simulta neously hydrotreats a nd breaks down larger hydrocarbons— can treat a volume equivalent to approximately 9% of the atmospheric distillation capacity. Together, th ese processes can treat a volume equivalent to 90% of the total refinery atmospheric distillation capacity.

### 69 Table 4-43. Estimated Energy Use by Refining Process (Energetics 2007) and Study Value with Electricity Loss Adjustment

Process Range of Unit Operation Specific Energy Usage (MBtu/bbl)* Average Unit Operation Specific Energy Usage (MBtu/bbl)* Study Unit Operation Specific Energy Usage (MBtu/bbl) Atmospheric Distillation 82 - 186 114 110 Vacuum Distillation 51 - 113 92 89.7 

### § Fluid Catalytic Cracking 209 209 189 Catalytic Hydrocracking 159 - 321 168 107 Coking Delayed 114 - 230 166 147 

### § Fluid*** 258 260 98.9 Catalytic Hydrotreating 61 - 164 88 59 

### § Catalytic Reforming 213 - 342 269 253 

### § Alkylation **** 330 - 340 335 270 Isomerization Isobutane 359 359 343 Isopentane/Isohexane 102-236 175 166 Lubricants 1,506 1,506 1,410 Sulfur (per short ton) 389 389 190 * Specific energy usage is inflated to incl ude electricity generation and transmission losses ** Specific energy usage is inflated to inclu de electricity generation losses associated with power generation occurring at the refinery *** Energetics fluid coking category encompasse s traditional fluid coking and flexicoking. The traditional fluid coking specific energy requirement is used here. **** Alkylation assumes the sulfuric acid process which has a higher specific energy requirement than hydrofluoric acid process 

### The amount of hydrogen consumed during hydrotr eating is a function of the species being treated and the sulfur content of the fraction. Generally, for stra ight-run fractions, the heavier the hydrocarbons, the more hydrogen is required to remove heteroatoms. Lower boiling point compounds are desulfurized more readily than higher-boiling point fractions and the difficulty of sulfur removal increases in the following order: paraffins, naphthenes, aromatics (Gary 2007). Straight-run species require less hydrogen than cracked species because much of the hydrogen used for desulfurizing cracked species is uptaken for hydrogenati on of these compounds. Figure 4-7 shows the increasing hydrogen requirement as the hydrotreated fraction becomes heavier and demonstrates the variability in hydrogen requi rements for a particular fraction. Table 4-44 shows the average hydrotreating hydrogen requirements for various fractions, as quoted from different sources. A broad range of hydrogen cons umption values is quoted for each fraction and there is often large variability between quoted estimates for the same fraction from different sources. The estimation of hydrogen utilization is further complicat ed by the fact that the total required hydrogen is generally highe r than the chemical consumption.

§ A sensitivity analysis was performed on these parameters.

### 70 Figure 4-7. Hydrogen Consumption for Hydrotreating Operations (Jechura 2008)

Table 4-44. Chemical Hydrogen Consumption for Various Petroleum Fractions

Fraction Hydrogen Consumption (scfb) References
10-50 Maples 1993 Naphtha 20-200 O&GJ 2007 FCC Gasoline 20-200 O&GJ 2007 Kerosene 25-140 Maples 1993 Distillate 200-600 O&GJ 2007 Diesel 50-200 Maples 1993 Light Gas Oil 100-200 Maples 1993 Heavy Gas Oil 200-300 Maples 1993 FCC Feed 200-1,000 O&GJ 2007



### Hydrogen requirements for hydrocracking are usually more severe than for hydrotreating. The requirements increase as the feedstock beco mes heavier and the degree of hydrocracking increases. Hydrogen consumption for hydroc racking generally ranges between 1,000 and 2,500 scfb depending upon the feed and desired degree of conversion to lighter species (Maples 1993). Hydrocracking hydrogen consumption has been recently estimated to be 1,120 scfb (Energetics 2007). The estimated hydrogen consumption for hydr ocracking operations used in this study is shown in Table 4-45.

### 71 Table 4-45. Estimated Hydrogen Consumption for Hydrocracking Operations

Hydrocracking Operation Estimated Hydrogen Consumption (scfb) § Distillate 1,000 Gas Oil 1,200 Residual 1,400



### Hydrogen input to unit operations for hydrot reating/hydrocracking includes the hydrogen chemically consumed as well as excess hydrogen fo r operation and hydrogen lost as a dissolved species in the liquid product. Not all produced hy drogen is used as a reactant. When a hydrogen stream is sufficiently depleted of hydrogen so as to be unacceptable for use in hydrotreating operations or too difficult/costly to purify, the stream is used as a fuel gas. This quantity is considered part of the “refinery ga s” or “still gas” fuels. The emission factor for still gas should include the presence of hydrogen. Additionally, combustion of hydrogen results in production of water and there should be no extraneous emissions consistent with util ization of the hydrogen stream as a fuel gas. For this study, a mass balance determines th e hydrogen requirements for hydrotreating. The quantity of hydrogen produced was detailed in Se ction 4.2.5 and this hydrogen is then distributed to the hydrotreating and hydrocracking operati ons. The quantities of hydrogen used for hydrocracking were chosen as shown in Table 4-45. The remaining hydrogen, as shown in Table 4-46, has been assigned to the hydrotreating operations.
Table 4-46. Hydrogen Consumption Mass Balance

Source Hydrogen Consumption (MMscfd H 2 ) Reference Hydrocrackers 1,359 Table 4-45 & Table 4-42 Hydrotreaters 5,681 Balance Total (including reformer feed hydrotreating) 7,041 Table 4-31 & 

### Table 4-30

The allocation of this hydrogen to the hydrotreater subcategories is based on a ratio (relative to naphtha) of hydrogen consumption estimated from Table 4-44 and other hydrotreating data/trends. The ratios are reported in Table 4-47. Given these relative hydrogen re quirements, the quantity of hydrogen required for refinery operation is estimated for each of the hydrotreati ng operations. This method balances refinery consumption with hydrogen production. Tabl e 4-48 shows the calculated (estimated) hydrotreating hydrogen requirements for the various fractions. Note that the mass balance results in hydrogen requirements that are within the bounds presented in Figure 4-7.

§ A sensitivity analysis was performed on these parameters.

### 72 Table 4-47. Estimated Hydrogen Requirements for Hydrotreating (Relative to Naphtha)

Hydrotreater Relative Hydrogen Consumption Naphtha/Reformer Feed 1.0 Gasoline 2.25 Heavy Gas Oil 4.0 Distillate Fuel Oil Kerosene/Jet Fuel 2.5 Diesel Fuel 3.0 Other Distillate 3.5 Residual Fuel Oil/Other Residual Fuel Oil 4.5 Other 4.5

Table 4-48. Estimated Hydrogen Requirements for Hydrotreating

Hydrotreater Hydrogen Consumption (scfb) Naphtha/Reformer Feed 186 Gasoline 419 Heavy Gas Oil 745 Distillate Fuel Oil Kerosene/Jet Fuel 466 Diesel Fuel 559 Other Distillate 652 Residual Fuel Oil/Other Residual Fuel Oil 839 Other 839



### 4.2.9.4 Contribution of Unit Operation to Product Categories Allocation of refinery emissions are made to seven diffe rent product categories: gasoline, diesel, kerosene and kerosene-based jet fu el, residual fuel oil, coke, “lig ht ends,” and “heavy ends.” The light ends category is composed of still gas, liquefied refinery gases (LRG), special naphtha, and petrochemical feedstocks. The heavy ends cat egory is composed of asphalt and road oil, lubricants, waxes, and a miscellaneous fraction.


### Production Volumes by Product Category Table 4-49 shows the quantity of domestically refined petroleum products for 2005 for each of the categories. This information is reported by EIA (2008). The gasoline category includes all formulations of motor gasoline and aviation gaso line, as well as gasoline blendstocks produced at the refineries (but which wa s not yet blended to produce finish ed gasoline). Diesel includes all types of distillate fuel oil (with varying sulfur content). Re sidual fuel oil includes all types (with varying sulfur content). C oke includes both catalyst and mark etable coke. This table also

### 73 shows the portion of each product cat egory that is associated with the liquid fuels of interest: conventional gasoline, conventiona l diesel and kerosene-based je t fuel. When determining the contribution of each of the unit operations to th e product categories, no differentiation is made between these subcategories. For gasoline and kero sene, the subcategory for the fuel of interest makes up more than 95% of the category. For diesel, however, convent ional diesel makes up only 75% of the of the di stillate production.
Table 4-49. Product Categories and Amount Produced in 2005

Product Category Amount Produced (thousand bpd)

Gasoline 7,816 Conventional Gasoline 7,794 Aviation Gasoline 22 Diesel 3,954

Conventional Diesel ( ≤ 500 ppm sulfur) 2,933 All Other Diesel 1,022 Kerosene and Kerosene-Based Jet Fuel 1,611

Kerosene-Based Jet Fuel 1,546 Kerosene 66 Residual fuel oil 628 Coke 835 Light ends 1,684 Heavy ends 754



### Primary Basis for Unit Operation Allo cation to Product Categories Historical information from 1996 serves as the pr imary basis for allocation of the contribution of various unit operations to the finished liquid fu els product slate. The 1996 API/NPRA refining survey took a detailed look at refining operati ons and product quality for a 4-month time frame (API 1997). These data have been adjusted to ac count for the changes in feedstock quality since that time, changes in environmental emissions requirements, changes in product quality/slate, and modified refinery operations. Refinery feedstocks are, on average, becomi ng lower quality. In 1996, the weighted U.S. average sulfur content of crude oil input to refineries was 1.15% (EIA 2008). In 2005, the average sulfur content was 1.42%—a 23% increase in sulfur. Th e average API gravity for crude oil inputs was 31.14 degrees in 1996 and wa s 30.20 in 2005—a 0.94 degree drop in API gravity (indicating heavie r crude oil). Diesel production has increased since 1996 and the product slate is moving towards lower sulfur products. Ultra low sulfur diesel (ULSD) wa s not produced in 1996 and accounted for less than 1% of distillate production in 2005. Table 4-50 shows diesel produc tion and product sulfur contents in 1996 and 2005.

### 74 Table 4-50. Diesel Production and Sulfur Content in 1996 and 2005 (EIA 2008)

Diesel Production 1996 2005 Total Production (1,000 bbls) 1,213,563 1,443,348 Ultra Low Sulfur Diesel, <15 ppm S (%) 0.00% 0.60% Low Sulfur Diesel, 15-500 ppm S (%) 63% 74% High Sulfur Diesel, >500 ppm S (%) 37% 26%



### Table 4-51 summarizes the data presented in the 1996 API/NPRA su rvey report and presents the estimates used in this study for 2005. Data are presented for catalytic cr acking, coking, catalytic hydrocracking, and hydrotreating oper ations detailing the percentage of the final product that goes through the selected refinery operations.

Table 4-51. 1996 Reported and 2005 Estimated Unit Operation Contributions to Diesel, Gasoline, and Kerosene Fractions

Unit Operation 1996Contribution (%)

to LowSulfur Diesel* 1996Contribution (%) to All Diesel* Estimate of 2005

(%)Contribution to

Diesel 1996Contribution (%)

to US Gasoline* Estimate of 2005

(%)Contribution to Gasoline 1996Contribution (%) to Kerosene /Jet Fuel Estimate of 2005

(%)Contribution to Kerosene/

Jet Fuel Catalytic Cracking 22.5 22.4 25 31.0** 40.4** 4.3 5.0 Coking 9.2*** 7.9 23.4 0.25 2.6 1.4 6.4 Catalytic Hydrocracking 4.0 5.9 9.0 -- 8.0 5.4 8.4 Hydrotreating 79.4 64. 1 82.6 -- 89.4 44.8 52.7 Source: Final Report: 1996 American Petroleum In stitute/National Petroleum Refiners Association Survey of Refining Operation and Product Quality * Total U.S. data, excludes California ** Catalytic cracked gasoline amounts to approximat ely 60% of the catalytic cracking unit feed *** In California, coking contributes 40.5% to the low-sulfur diesel fraction 

### Individual Unit Operation Alloca tions to Product Categories The volumetric capacities of the individual unit operations have been assigned to the seven product categories based upon the relative contributi on of the throughput of that operation to the final product category. Table 4-52 summarizes the volumetric thr oughput allocations to the final product fractions. The rationale for the indivi dual unit operations’ capacity assignments to product categories is describe d in greater detail below.75Table 4-52. Summary of Unit Operation Contribution to End ProductsGasolineDieselKerosene/KeroseneBased JetFuelResidualFuel OilCokeLight EndsHeavy EndsAtmospheric DistillationRelative to final product slateVacuum DistillationEqual to catalytic cracking throughput contribution forGasoline, Diesel or Kerosene plus the remainder (after fueloil, coke, heavy ends is assigned) ratioed to Gasoline,Diesel and Kerosene relativeto respective throughputcontribution of coking unitsEqual to final product slateEqual to finalproduct slateCatalytic Cracking60% ofthroughput25% of dieselproduced5% of keroseneproducedAll catalystcokeBalanceDistillate Hydrocracking75%10%15%Gas Oil Hydrocracking50%40%10%Residual HydrocrackingBalance40%10%51.3 MbpdDelayed CokingFluid Coking10% ofthroughput45% ofthroughput5% ofthroughputAll marketablecoke distributedbased onthroughputBalanceNaphtha Hydrotreating95% ofthroughput5% ofthroughputReformer Feed Hydrotreating*95% ofthroughput*5% ofthroughput*Gasoline HydrotreatingAllHeavy Gas Oil HydrotreatingKerosene/Jet Fuel HydrotreatingAllDiesel Fuel HydrotreatingAllOther Distillate HydrotreatingRelative to final product slateResidual Fuel Oil HydrotreatingAllOther HydrotreatingBalance relative to final product slate115 MbpdCatalytic Reforming*95% ofthroughput*5% ofthroughput*AlkylationAllIsomerizationAllLubricantsAllSulfurAll* Allocations for reformer feed hydrotreating and catalytic reforming include only energy requirements remaining after assigning energy to the hydrogen pool1,850 kbbl/day is catalytic cracker feed hydrotreating and is distributed as in catalytic cracking; remainder to diesel fraction

### 76 Atmospheric Distillation 

### Since all refinery products pass th rough the atmospheric distillation column in the form of the initial feedstock, the atmospheric distillati on capacity is divided among all seven product categories according to that pr oduct category’s fraction of the to tal refinery output (includes fuels produced and consumed in the refinery).

Vacuum Distillation 

### The vacuum distillation column separates the bo ttoms from the atmospheric distillation column into additional boiling-point cuts for appropria te downstream treating. The primary downstream operations used to upgrade the heavy vacuum di stillation cuts are the coking and catalytic cracking units. All coke, residual fuel oil, and heavy ends production is assumed to pass through the vacuum distillation column. A large volume of the vacuum distillation colu mn throughput is heavy oils destined for the catalytic cracking unit. The vac uum distillation column capacity is ratioed to the products from the catalytic cracki ng unit relative to that unit’s contribu tion to the final product slate. For example, based on the 1996 API/NPRA refining su rvey (API 1997), 60% of the catalytic cracker input is slated to go to the gasoline fraction; th erefore, 60% of the cata lytic cracker throughput is slated to go through the vacuum distillation co lumn to the gasoline fraction. The vacuum distillation contribution to the diesel and kerosene/jet-fuel fracti ons is calculated relative to the catalytic cracking contribution in the same mann er (as described above for gasoline) for those species. The remaining vacuum distillation column capacity, after subtracting out the above contributions, is then ratioed to gasoline, diesel , and kerosene/jet-fuel in the same ratio as the liquid product allocation from the coking unit—1 6.7% to gasoline, 75% to diesel, and 8.3% to kerosene/jet fuel (see subsequent di scussion of the coking operations).

Catalytic Cracking 

### The catalytic cracking unit breaks large hydrocarbon molecules down into smaller, more useful, species. The primary recipient of the products from this operati on is the gasoline fraction. Based on the 1996 API/NPRA refining survey (API 1997), 60% of the catalytic cracker input went to the gasoline fraction; therefore, 60% of the catalytic cracker input in 2005 has been slated to go to the gasoline fraction. § The 1996 API/NPRA refining survey (API 1997), reported that 22.4% of 15-500 ppm diesel was cracked in 1995. Considering that crude stocks have gotten heavier in the interim, it was estimated that 25% of diesel fuel to tal production would be cracked in 2005. § The 1996 API/NPRA refining survey (API 1997), reported that 4.3% of kerosene/jet fuel production is cracked. In 2005, 5% of kerosene/j et fuel total production is estimated to be cracked. § EIA reports that 239,000 bpd of catalyst coke wa s produced in 2005. The catalytic cracker is assumed to be the sole producer of this cataly st coke and thus 239,000 bpd has been allocated to the coke fraction.

§ A sensitivity analysis was performed on these parameters.

### 77 The remaining unaccounted for cat alytic cracking capacity (after coke, gasoline, diesel, and kerosene/jet fuel fractions have been accounted for) has been assigned to the light ends.

Catalytic Hydrocracking 

### The catalytic hydrocracking operation is divided into three sub-categories based on the feed input: distillate, gas oil, and re sidual. The severity of the hydroc racking operation, as well as the feed quality, determines the pr oduct quality/category. The hydroc racking throughput allocations to the final products have a high degree of uncertainty. Distillate hydrocracki ng is assumed to produce predominan tly gasoline; 75% of distillate hydrocracking capacity has been assigned to gaso line, 15% to kerosene/jet fuel, and 10% to diesel fuel. Gas oil hydrocracking is a more severe (highe r pressure and higher hydrogen consumption) process than distillate hydroc racking. The throughput capacit y for this operation has been allocated 50% to gasoline, 40% to di esel, and 10% to kerosene/jet fuel. § Residual hydrocracking is the most severe of the three types listed. Acco rding to the Oil and Gas Journal Worldwide Refining Survey (O&G J 2005) there was 57,000 bpcd of installed hydrocracking capacity for lube o il manufacturing. Assuming a 90% utilization rate, this results in 51,300 bpcd of capacity allocated to the heavy ends product fraction. Forty percent of the residual hydrocracking capacity ha s been allocated to the dies el fraction and 10% has been allocated to the kerosene/jet fu el fraction. The remainder (14 %) has been allocated to the gasoline fraction.

Coking 

### The coking operation is divided in to two types, delayed and flui d. The total coking annual input is reported and the capacity is allocated to the delayed and fluid coking operations according to the ratio of the installed cap acities. In 2005, a total of 596,000 bpd of marketable petroleum coke was produced and the production was allocated to the coke fraction (d elayed and fluid) in the same ratio as their respective installed capacity. The allocation of the remaining capacity was performed using information derived fr om Petroleum Refining Technology and Economics Table 5.11 (Gary 2007). The yield on fresh feed is reported to be approximately 10% naphtha, 50% gas oil, and 10% gases. Therefore, the gasoline fraction was assi gned 10% of the coking throughput, diesel was assigned 45% (reported yiel d is designated as gas oil and so it was assumed that 45% would be allocated to diesel and 5% to kerosene), kerosene/jet fuel was assigned 5%, coke was assigned 596,000 bpd (29%), and light ends made up the remainder (11%).

Catalytic Reforming 

### Using system expansion, it was determined in Section 4.2.5 that the energy associated with the catalytic reformer would be assigned entirely to the hydrogen pool. However, for various sensitivity analysis cases, this same methodology calls for a portion for th e catalytic reformer energy to be assigned to the liqui d products. Note that the alloca tion detailed here applies only

§ A sensitivity analysis was performed on these parameters.

### 78 to any portion of the catalytic reformer energy requi rement that is assigned to the reformate after energy requirements are distribut ed to the hydrogen pool. In addition to hydrogen, the cataly tic reformer produces reformate, which goes exclusively to the gasoline fraction, and light hydrocarbons which are assigned to the light ends. It is assumed that 95% of the catalytic reforming unit capacity is at tributable to the gasoli ne fraction and 5% is attributable to the light ends (due to decomposition and remo val of miscellaneous hydrocarbon gases during the reforming operation).

Hydrotreating 

### The hydrotreating operations are subdivided into several categories base d upon the species being hydrotreated. The hydrotreating categories are br oken down as follows: naphtha/reformer feed, heavy gas oil, kerosene/jet fuel, diesel fuel, ot her distillate, residual fuel oil, and other. Reformer feed hydrotreating capacity has been a ssigned to the final produ ct slate based on the catalytic reformer output assignments. Hence, af ter allocation to the hydrogen pool, 95% of the reformer feed hydrotreating capacity is attributable to the gasoline fraction and 5% is attributable to the light ends. Naphtha hydr otreating capacity has been as signed as 95% to the gasoline fraction and 5% to the light ends fraction. Heavy gas oil hydrotreating is assumed to be attr ibuted primarily to cata lytic cracking unit feed hydrotreating. This is consistent with the Oil and Gas Journal Worldwide Refining Survey (O&GJ 2005) citing that in 2005, 2,056,437 bpcd of capacity existed for pretreatment of catalytic cracker feeds. Assuming a 90% utilization rate this results in 1,850,793 bpcd of catalytic cracker hydrotreating. Hence, 1,850,793 bpcd is allocated to the products from the catalytic cracking unit and the remaining 194,839 bpcd is al located to the diesel fraction. Kerosene/jet fuel hydrotreating cap acity has been assigned exclusiv ely to the kerosene/jet fuel final product fraction. Diesel fuel hydrotreating capacity has been al located exclusively to the diesel fuel product fraction. Other distillate hydrotreating capac ity has been allocated to the gaso line and diesel fuel fractions based upon the relative production volume of gasolin e and diesel, due to a lack of information allowing a more defini tive classification. Residual fuel oil hydrotreating cap acity has been allocated exclusively to the residual fuel oil product fraction. Other hydrotreating capacity is somewhat ill-defined and thus assumptions must be made to distribute throughput among the produc t fractions. Hydrogen is used for lube oil “polishing” and according to the Oil and Gas Journal Worldw ide Refining Survey (O&GJ 2005) there was 128,450 bpcd of installed capacity for lube oil po lishing. Therefore, 115,605 bpcd (based on an assumed 90% utilization rate) ha s been assigned to the heav y ends product fraction. The remainder of "other" hydrotreat ing capacity has been assign ed to gasoline, diesel, and kerosene/jet fuel based on thei r relative production quantities.

Alkylation 

### The alkylation operations and the throughput for t hose operations are assigned exclusively to the gasoline fraction.

### 79 Isomerization 

### Isomerization is further categorized into isobut ane or isopentane/isohexane isomerization. The products of this operation are assumed to cont ribute exclusively to the gasoline fraction.

Summary 

### Table 4-52 shows a summary of the allocation data described above. Figure 4-8 shows the resulting percentages of volumetric throughput for each unit operation that is being allocated to each end product. Catalytic reforming operati ons are excluded from this figure due to the separate allocation process with hydrogen.

4.2.9.5 Resources and Emissions Allocation to Product Fractions A refinery performance summary with al location of refining energy use and hydrogen production/consumption has been developed fo r the seven product fractions discussed previously. This performance summary is then used to allocate the emissions associated with refinery fuels, hydrogen production, flaring and venting/fugitive methane emissions to the final product categories.


### Product Fractions Performance Summary The refinery energy consumption has been esti mated for the seven categories by multiplying the throughput for contributing unit operations by the specific energy usage, in thousands Btu per barrel (see Table 4-43), and summing for each pr oduct category. For catalytic reforming and reformer feed hydrotreating, the entire specific energy usage is allocated to hydrogen output (see Section 4.2.5.2 for further discussion). Hydrogen requirements are determined for th e seven product categories by multiplying the process input/throughput for each operation by th e specific hydrogen consumption and summing. Hydrogen requirements for the reformer feed hydrot reating operation are excl uded from this total because hydrogen used for pretreatment of the refo rmer feed (recycle stream) is subtracted from the reformer output prior to contribution to the hydrogen pool. The concept of a refinery hydrogen pool was devel oped earlier and is desc ribed in Section 4.2.5. Hydrogen extracted from that “pool” has a refinery energy requirement associated with it, as well as a GHG emissions profile. Energy consum ption consistent with hydrogen consumption is calculated by multiplying the total refinery ener gy associated with hydrogen from Table 4-32 by the fraction of the total hydrogen requir ement for each of the categories. The total refining energy requirement is a sum of the process unit energy requirements and the energy requirements for producing hydrogen consum ed by refinery operations across all seven product categories. The fraction of the total refi nery energy that is attr ibutable to the product slate is determined by summing the refining pr ocess unit energy requirements and the hydrogen production energy requirements for each category a nd dividing by the total energy requirements for the entire refinery. Note that the refinery energy requirement calcu lated here is based on estimated unit operation throughput and energy usage and only includes th ose operations modeled. This total is approximately 75% of the total energy input calc ulated from the fuels consumed as reported by refiners to EIA.80Figure 4-8. Percent of Volumetric Throughput Allocated to End Products0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%SulfurLubricantsIsomerizationAlkylationOther HydrotreatingResidual Fuel Oil HydrotreatingOther Distillate HydrotreatingDiesel Fuel HydrotreatingKerosene/Jet Fuel HydrotreatingHeavy Gas Oil HydrotreatingGasoline HydrotreatingNaphtha HydrotreatingFluid CokingDelayed CokingResidual HydrocrackingGas Oil HydrocrackingDistillate HydrocrackingCatalytic CrackingVacuum DistillationAtmospheric DistillationLight EndsGasolineKeroseneDieselResidual Fuel OilHeavy EndsCoke

### 81 A refinery performance summary with al location of refining energy use and hydrogen production/consumption has been calculated fo r the product fractions outlined above. Table 4-54 summarizes the refinery performance.


### Fuels Combustion and Acquis ition Emissions Allocation to Product Fractions Fuels-consumed emissions are assigned to the pr oduct fractions based upon the fractional energy usage required to produce these pr oducts. Table 4-54 reports the fr action of total refinery energy consumption attributable to the seven product cat egories. The GHG emissions consistent with fuels consumption is then multiplied by the appropriate energy consumption fraction for each category.


### Hydrogen Production Emissions A llocation to Product Fractions Hydrogen production emissions asso ciated with operations not included in the refinery energy and emissions profile have been assigned to th e product fractions accord ing to each category’s hydrogen consumption fraction.


### Flaring and Methane Venting/Fugitive Emi ssions Allocation to Product Fractions Refinery flaring and methane venting/fugitive emi ssions have been allocated to product fractions based upon the fraction of the total refinery energy usage required for production of each product category.



### 4.2.10 Summary of LC Stage #3 for Domestic Refineries The resulting emissions profile for each produc t category per barrel and per million Btu LHV of product refined are shown in Table 4-55 and Table 4-56 including a breakdown for various subcategories. Heating values in Appendix I were utilized to convert from a volumetric to an energetic basis. Figure 4-9 show s the information for the refine ry products of interest on a CO 2 

### equivalent basis. Table 4-53 provides the CO 2 

### , methane and nitrous oxide emissi ons on a per barrel refined basis for the transportation fuels of interest.
Table 4-53. LC Stage #3 GHG Emissions for Transportation Fuels Produced in Domestic Refineries
Emissions (kg/bbl refined) Source CO 2 CH 4 N 2 O Conventional Gasoline 46.0 0.0562 7.45E-04 Conventional Diesel 50.8 0.0627 7.85E-04 Kerosene-Based Jet Fuel 30.5 0.0376 4.72E-0482Figure 4-9. Life Cycle Stage #3 GHG Emissions for Domestic Refineries - Key Products6.455.963.781.201.110.700.230.210.130.900.830.530.08 0.070.059.749.556.040.891.370.850246810 Gasoline Diesel Jet Fuel Gasoline Diesel Jet Fuel Gasoline Diesel Jet Fuel Gasoline Diesel Jet Fuel Gasoline Diesel Jet Fuel Gasoline Diesel Jet Fuel Gasoline Diesel Jet FuelRefineryFuelsCombustionSteam &ElectricityAcquisitionNaturalGas & CoalAcquisitionRefineryProducedFuelsAcquisitionHydrogenProduction*Flaring,Venting,& FugitiveTotalLC Stage #3Domestic

GHG Emissions (kg CO 2 E/MMBtu LHV of fuel refined)Carbon DioxideMethaneNitrous Oxide* Does not include fuel usage at the refineries (and associated emissions) that is attributable to hydrogen production83Table 4-54. Refinery Performance Summary for Product FractionsPropertiesGasolineDieselKerosene&KeroseneBased JetFuelResidualFuel OilCokeLightEndsHeavyEndsH2Requirement (MMscfd)[Excluding reformer feed hydrotreating]2,751 2,414 577 219 63 210 169Fraction of H2Consumption Requirement0.430 0.377 0.090 0.034 0.010 0.033 0.026Refinery Energy Requirement for H2Production(MMBtu HHV/day)496,515 435,814 104,213 39,612 11,295 37,956 30,463Estimated Energy Requirement for RefiningUnit Operations Modeled (MMBtu HHV/day)[excludes H2production energy consumption]2,378,144 1,077,947 267,077 134,126 293,143 367,615 396,018Estimated Energy Requirement for RefiningUnit Operations Modeled (MMBtu HHV/day)[includes H2production energy consumption]2,874,660 1,513,760 371,290 173,738 304,438 405,571 426,482Fraction of Refinery Energy ConsumedAttributable to Refinery Unit OperationsModeled0.47 0.25 0.06 0.03 0.05 0.07 0.07TotalRefinery Energy Usage Attributable toProduct Category (MMBtu HHV/day)[Based on total fuels consumed for 2005]3,811,449 2,006,952 492,258 230,343 403,625 537,708 565,432Fraction of Total Refinery ProductionAttributable to Products (volumetric)0.45 0.23 0.09 0.04 0.05 0.10 0.0484Table 4-55. Life Cycle Stage #3 GHG Emissions for Domestic Refineries by Activity Sub-CategorySourceGasolineDieselKerosene&Kerosenetype JetFuelResidualFuel OilCokeLightEndsHeavyEndsCO2Emissions (kg/bbl Refined Product) 46.0 50.8 30.5 35.7 42.4 28.9 67.0Refinery Fuels Combustion31.4 32.6 19.6 23.6 31.1 20.5 48.2Purchased Steam and Electricity5.66 5.89 3.55 4.26 5.61 3.71 8.70Acquisition of Natural Gas & Coal0.86 0.89 0.54 0.64 0.85 0.56 1.32Acquisition of Refinery-Produced Fuels 3.66 3.81 2.29 2.75 3.63 2.40 5.62Hydrogen Production* 4.197.27 4.27 4.17 0.89 1.49 2.67Flaring, Vented & Fugitive0.32 0.34 0.20 0.24 0.32 0.21 0.50CH4Emissions (kg/bbl Refined Product) 5.62E-02 6.27E-02 3.76E-02 4.38E-02 5.10E-02 3.50E-02 8.09E-02Refinery Fuels Combustion 7.87E-04 8.19E-04 4.93E-04 5.92E-04 7.80E-04 5.15E-04 1.21E-03Purchased Steam and Electricity 6.89E-03 7.17E-03 4.32E-03 5.19E-03 6.83E-03 4.51E-03 1.06E-02Acquisition of Natural Gas & Coal 1.02E-02 1.06E-02 6.40E-03 7.69E-03 1.01E-02 6.69E-03 1.57E-02Acquisition of Refinery-Produced Fuels 2.93E-02 3.05E-02 1.84E-02 2.21E-02 2.91E-02 1.92E-02 4.51E-02Hydrogen Production* 6.09E-03 1.06E-02 6.20E-03 6.05E-031.30E-03 2.16E-03 3.87E-03Flaring, Vented & Fugitive 2.89E-03 3.01E-03 1.81E-03 2.17E-03 2.86E-03 1.89E-03 4.44E-03N2O Emissions (kg/bbl Refined Product) 7.45E-04 7.85E-04 4.72E-04 5.64E-04 7.28E-04 4.84E-04 1.13E-03Refinery Fuels Combustion 5.62E-04 5.85E-04 3.52E-04 4.23E-04 5.58E-04 3.68E-04 8.64E-04Indirect Energy Inputs 7.14E-05 7.43E-05 4.47E-05 5.37E-05 7.08E-05 4.68E-05 1.10E-04Acquisition of Purchased Fuels 1.68E-05 1.75E-05 1.05E-05 1.26E-05 1.66E-05 1.10E-05 2.58E-05Acquisition of Refinery-Produced Fuels 7.75E-05 8.06E-05 4.85E-05 5.83E-05 7.68E-05 5.07E-05 1.19E-04Hydrogen Production* 1.37E-05 2.37E-05 1.39E-05 1.36E-052.91E-06 4.86E-06 8.71E-06Flaring, Vented & Fugitive 3.47E-06 3.61E-06 2.17E-06 2.61E-06 3.44E-06 2.27E-06 5.33E-0685SourceGasolineDieselKerosene&Kerosenetype JetFuelResidualFuel OilCokeLightEndsHeavyEndsGWP in CO2E (kg/bbl Refined Product) 47.7 52.6 31.6 36.9 43.9 29.9 69.4Refinery Fuels Combustion31.5 32.8 19.8 23.7 31.3 20.7 48.5Purchased Steam and Electricity5.86 6.10 3.67 4.41 5.81 3.84 9.00Acquisition of Natural Gas & Coal1.12 1.16 0.70 0.84 1.11 0.73 1.72Acquisition of Refinery-Produced Fuels 4.42 4.60 2.77 3.32 4.38 2.89 6.79Hydrogen Production* 4.357.55 4.43 4.32 0.93 1.54 2.77Flaring, Vented & Fugitive0.40 0.41 0.25 0.30 0.39 0.26 0.61* Does not include fuel usage at the refineries (andassociated emissions) that is attributable to hydrogen productionTable 4-56. Life Cycle Stage #3 GHG Emissions for Domestic Refineries by Sub-CategorySourceGasolineDieselKerosene &Kerosenetype JetFuelGWP in CO2E (kg CO2E/MMBtu LHV ofRefined Product)9.74 9.55 6.04Refinery Fuels Combustion 6.45 5.96 3.78Purchased Steam and Electricity 1.20 1.11 0.70Acquisition of Natural Gas & Coal 0.228 0.211 0.134Acquisition of Refinery-Produced Fuels 0.903 0.834 0.529Hydrogen Production* 0.889 1.369 0.847Flaring, Vented & Fugitive 0.081 0.075 0.048* Does not include fuel usage at the refineries (and associated emissions) that is attributable tohydrogen production

### 86 

## 4.3 Liquid Fuels Production at Foreign Refineries
Determining emissions consistent with refining op erations for foreign en tities is not a trivial matter due to the inherent variability in feed stocks and technologies employed, as well as different product emphasis and environmental regul ations. Information extracted from foreign studies of gasoline and diesel production vary widely due to differences in study assumptions, system boundaries, and information sources. Thr ee publicly available sources of information for gasoline and diesel production emissions are disc ussed briefly below, two for European refining operations and one for Brazilian refinery operations. The Brazilian source also details emissions consistent with kerosene production. EUCAR/CONCAWE/JRC Study: An analysis of European well-to-tank emissions for petroleum products was performed join tly by representati ves of EUCAR (the European Council for Automotive R&D), CONCAWE (the oil companies’ European association for environment, health and safe ty in refining and dist ribution) and JRC/IES (the Institute for Environment and Sustai nability of the EU Commission’s Joint Research Centre), assisted by personnel from L-B-Systemtechnik GmbH (LBST) and the Institut Français de Pétrole (IFP). Th e study is entitled “Well-to -Wheels analysis of future automotive fuels and powertrains in the European context: WELL-TO-TANK Report” (EUCAR 2007). European Commission Life Cycle Inventory Data: The European Commission maintains the "European Reference Life Cy cle Data System" (ELCD) of Life Cycle Inventory (LCI) data sets ( ELCD 2008). Life cycle invent ory information is publicly available for gasoline and diesel production (cradle-to-gate). These data were used to determine the refining emissions consistent with gasoline and diesel production by subtracting the crude oil fr ee-to-customer emissions for EU-15 crude oil mix (GaBi 4 2007) from the profile assuming a ratio of 0.94 bbl inputs/bbl of product (the same ratio determined for U.S. refineries).
Brazilian National LCI Database: The cradle-to-gate life cy cle inventory is publicly available for the largest petroleum refinery in Brazil—REPLAN Refinery (Refinaria de Paulínia) located in Sao Paulo Brazil (BNL D 2008). Refinery experts deemed that refinery to be a “representat ive Brazilian refinery” (BNLD 2008). Life cycle inventory data is available for gasoline (200 ppm sulfu r), diesel (500 ppm sulfur), and kerosene (2,000 ppm sulfur) production in 2005, as well as other refi nery products. These data were used to determine the refining emissi ons consistent with gasoline, diesel, and kerosene production by subtracting the crude oil free-to-custome r emissions for the 2002 Brazilian crude oil mix (GaBi 4 2007) fr om the profile assuming a ratio of 0.94 bbl inputs/bbl of product (the same ratio determined for U.S. refineries). Figure 4-10 shows a comparison of this study’s resu lts for gasoline and diesel refining with that of the three aforementioned foreign studies m odeling gasoline and dies el production. Figure 4-10 also shows a comparison of th is study’s results for kerosene-b ased jet fuel with Brazilian results for kerosene production. The results are presented in CO 2 

### E. Due to the wide variability between studies modeling refining operations, the U.S. domestic refining emissions profile (shown in Table 4-53) developed herein has been used as a surrogate for foreign refinery operations.

### 87 Figure 4-10. Comparison of Refining GHG Emissions Between Studies

0 5 10 15 20

U.S. - This Study EU - EUCAR/ CONCAWE/JRC EU - European Commission Brazil - REPLAN RefineryGHG Emissions(kg CO2E/MMBtu LHV fuel consumed) 

### Gasoline Diesel Kerosene



## 4.4 Summary of Life Cycle Stage #3 GHG Emissions Profiles
Table 4-57 summarizes the emissions profiles asso ciated with petroleum refining operations for production of gasoline, diesel and jet fuel. The profile here is used for both U.S. and non-U.S. operations. Emissions are pres ented as per barrel refined. §

Table 4-57. Summary of GHG Emissions Consistent with Refining of Gasoline, Diesel and Jet Fuel at U.S. and Foreign Refineries in 2005
Emissions (kg/bbl refined) Fuel Type CO 2 CH 4 N 2 O Conventional Gasoline 46.0 0.0562 7.45E-04 Conventional Diesel 50.8 0.0627 7.85E-04 Kerosene-Based Jet Fuel 30.5 0.0376 4.72E-04

§ A sensitivity analysis was performed on these parameters.

### 88 

## 5.0 Life Cycle Stage #4: Transport of Liquid Fuels to Vehicle Refueling Station or Airport and Refueling of Vehicle/Aircraft

Life Cycle Stage #4 begins where liquid fuels exit foreign and domestic re fineries and end with fueling of the vehicle/aircraft. This stage includes product transport to bulk storage, bulk storage at terminals or the airport, transport of je t fuel to aircraft, and refueling operations. Figure 5-1 depicts the activities and flow of feedstocks for LC Stage #3.
Figure 5-1. Flow Diagram of Product Transport and Refueling Activities

U.S. Refinery Operations Transport within

U.S. Pipeline, waterborne,

rail, truck LC Stage #4: Product Transport and Refueling LC Stage #3: Liquid Fuels

Transport

Foreign Refinery Operations

for the Production of Gasoline, Diesel andKeroseneBased Jet

Fuel Imported by

the U.S. Pipeline Transport

to Port Tanker Transport Pipeline Transport to Border Conventional Gasoline Consumption in Passenger Vehicle Bulk Storage

Vehicle Refueling

Airport Bulk

Storage

Aircraft Refueling LC Stage #5: Vehicle/Aircraft Use

Conventional Diesel Consumption in Passenger Vehicle

KeroseneBased Jet

Fuel Consumption in Jet Aircraft

U.S. Operations Non-U.S. Operations



## 5.1 Product Transport
Product transport includes transport of imported liquid fuels from the exporting nations to the U.S. as well as domestic transport of both importe d fuels and domestically produced liquid fuels.


### 5.1.1 Foreign Transport Product transport includes tanker and/or pipeline transport of imported products to the U.S. receiving port. Emissions associated with tanker/pipeline opera tion are the primary GHG emission sources. Losses during product tran sport indirectly add to GHG emissions by necessitating more product be produced to meet end use requirements.

### 89 Petroleum products are assumed to be shipped an average of 10 miles by pipe line to either a port for ocean transport or to the U.S. border. The energy intensity for pipeline transport is assumed to be 260 Btu/ton-mile (Wang 2008) and electricity is assumed to be the power source. The emissions associated with pipeline transport ar e estimated using emissions from the U.S. power grid as a surrogate profile for that of foreign countries (Appendix B). § This is noted as a data limitation but the resulting impact to th e overall life cycle emissions is minor. The energy requirement for transporting liquid fu els via tanker is calculated by multiplying the number of barrels of fuel shipped by the dist ance traveled in nautical miles and the energy intensity for transport. The return trip is a ssumed to require the same amount of energy. The values are summed for each of the different im port sources and the emi ssions associated with consumption of that quantity of energy (as heavy fuel oil) are determined. Table 5-1 outlines the performance specifications for various sizes and types of petroleum product tankers. The energy intens ity ranges from 7.4 to 10.9 Btu per barrel-nautical mile of fuel transported. The assumed study value for produc t tanker transport operations is 10 Btu per barrel-nautical mile. §
Table 5-1. Performance Specifications for Various Petroleum Product Tankers (Brodosplit 2008)

Designation Product Tanker Product Tanker Ice-1A Class Product Tanker Oil Product/ Chemical

Tanker Handy Size Oil Product Tanker Service Speed (kt) 15.8 16.3 14.9 15.7 15.3 Fuel Oil Consumption (tonnes/day) 49.0 49.2 41.0 33.6 31.8 Cargo Volume (m 3 ) 116,032 85,950 70,255 55,423 53,000 Deadweight (MT) 95,000 74,999 65,200 45,000 45,000 Product Volume (bbl) 729,819 540,610 441,891 348,600 333,360 Energy Intensity: Btu/bbl-nautical mile 7.4 9.8 10.8 10.7 10.9



### The heavy fuel oil (HFO) used to power tanker op erations is essentiall y residual fuel oil and therefore the GHG emissions profile consistent with combustion of residual fuel oil in marine engines is used to determine the ship emissions during international transport. GHG emissions from heavy fuel oil are presented in Table 5-2.
Table 5-2. GHG Emissions from Combustion of HFO (Residual Fuel Oil) in Ships (EIA 2007) Emissions (kg/MMBtu HHV) Source CO 2 CH 4 N 2 O HFO Combustion in Ships 78.8 5.75E-03 2.00E-03

§ A sensitivity analysis was performed on these parameters.

### 90 Product losses from marine transport operations were estimated using EPA AP-42 emission factors and a detailed discussion of loss factors is presented in Appendix H.
5.1.1.1 Gasoline Transport to the U.S. EIA (2008) reports more than 3,000 import shipment s of gasoline and gasoline blendstocks in 2005 totaling 403,950,000 barrels. Gaso line is imported to 89 diffe rent U.S. ports from 59 different sources. 80.7% of these imports were received by PADD 1. Import source and quantity of imports are shown in Appendix A. The average density of all gasoline types and gaso line blendstocks is assumed to be the same at 2.79 kg per gallon (EPA 2008). This yields 372 million Btu HHV per day of energy consumed for the assumed 10 miles of foreign pipeline transport of gasoline. The GHG emissions associated with this energy consum ption are shown in Table 5-3. Specific port-to-port travel distances were estima ted for imports from Canada (98% of gasoline imports received via waterborne transit) and th e Virgin Islands because of their high volume of exports to the U.S. Given the complexity involve d in determining transit distances for all other import shipments, all other imports were estimate d to travel 5,000 nautical miles to their U.S. destination. The transit time for imports from Canada and the Virgin Islands was calculated assuming an average ship speed of 15 knots (kt). All other imports are assumed to have a two week transit time (effectively assuming an average speed of approximately 15 kt). § Tanker transport emissions for gasoline imported to the U.S. is shown in Table 5-3, along with the foreign pipeline transport emissions a nd the total foreign tr ansport emissions.

Table 5-3. GHG Emissions Associated with Transport of Imported Gasoline to Domestic Ports Emissions (kg/bbl refined) Source CO 2 CH 4 N 2 O Pipeline Transport 0.073 8.46E-05 9.45E-07 Tanker Transport to U.S. Port 4.90 3.57E-04 1.24E-04 Total Foreign Transport 4.97 4.41E-04 1.25E-04



### 5.1.1.2 Diesel Transport to the U.S. Diesel is imported primarily fr om Canada (82% of diesel im ports received via waterborne transit) and the Virgin Islands and these two s ources make up 69% of the total U.S. conventional diesel imports ( ≤ 500 ppm S). European countries (Belgium, Denmark, Estonia, France, Germany, Latvia, Lithuania, Netherlands, Sweden, and the United Kingdom) make up an additional 11%. The origin of U.S. distilla te imports for 2005 is shown in Appendix A along with the quantity imported. The average density of diesel (EPA 2008) is 3.21 kg per gallon. This yields 60.6 million Btu HHV per day of energy consumed for the assume d 10 miles of foreign pipeline transport of

§ A sensitivity analysis was performed on these parameters.

### 91 diesel fuel. The GHG emissions associated with this energy consumption are shown in Table 5-4. Specific port-to-port travel distances were esti mated for imports from Canada and the Virgin Islands because they represent the primary sources for diesel imports to the U.S. in 2005. Given the complexity involved in determining transit di stances for all other import shipments, all other imports were estimated to travel 5,000 nautical m iles to their U.S. destin ation. The transit time for imports from Canada and the Virgin Islands was calculated assuming an average ship speed of 15 kt. All other imports are assumed to have a two week transit time (effectively assuming an average speed of approximately 15 kt). §

Table 5-4. GHG Emissions Associated with Transport of Imported Diesel to Domestic Ports Emissions (kg/bbl refined) Source CO 2 CH 4 N 2 O Pipeline Transport 0.084 9.70E-05 1.08E-06 Tanker Transport to U.S. Port 2.97 2.16E-04 7.54E-05 Total Foreign Transport 3.05 3.13E-04 7.65E-05



### 5.1.1.3 Kerosene-Based Jet Fue l Transport to the U.S. Kerosene-based jet fuel is imported primarily from South Korea, the Virgin Islands, and Venezuela. The origin of U.S. jet fuel impor ts for 2005 is shown in Appendix A along with the quantity imported. The average density of jet fuel is 3.04 kg per gallon (DESC 2005). This yields 69.5 million Btu HHV per day of energy consumed for the assumed 10 miles of foreign pipe line transport of jet fuel. The GHG emissions associated with this energy consumption are shown in Table 5-5. Given the complexity involved in determining transit distances for import shipments, imports from Canada and the Virgin Islands were assu med the have the same effective waterborne transport distance as diesel imports; all remaining imports were estimated to travel 5,000 nautical miles to their U.S. destination. All imports (with the exception of Ca nada and the Virgin Islands) are assumed to have a two week transit time (effectivel y assuming an average speed of approximately 15 kt). §

Table 5-5. GHG Emissions Associated with Transport of Imported KeroseneBased Jet Fuel to Domestic Ports Emissions (kg/bbl refined) Source CO 2 CH 4 N 2 O Pipeline Transport 0.079 9.20E-05 1.03E-06 Tanker Transport to U.S. Port 4.99 3.64E-04 1.27E-04 Total Foreign Transport 5.07 4.56E-04 1.28E-04

§ A sensitivity analysis was performed on these parameters.

### 92 

### 5.1.2 Domestic Transport Liquid fuels are transported within the U.S. vi a five primary mechanisms: pipeline, ocean tanker, barge, railroad, and truck. Table 5-6 summarizes the U.S. petroleum products’ domestic transportation modes. The Oak Ridge National Laboratory (ORNL) Transportation Energy Data Book, Table 2.4, outlines the domestic consumption of transportati on energy by mode and fuel type. These data were used to determine the fuel powering the aforementioned transportation operations. Based upon the ORNL Transportation Energy Data Book, Ta ble 2.4, in 2004 natural gas and electricity were the primary fuels for effecti ng pipeline transport. Since na tural gas is used primarily for fueling natural gas pipeline transport, all crude oil and petroleum product tr ansport via pipeline is assumed to be fueled by electricity. Similarly, diesel fuel is shown to be the exclusive fuel source for Class I freight railroad operations. Wa ter carriers transporti ng freight are powered by diesel fuel and residual fuel oi l (30.5 % diesel fuel and 69.5% re sidual fuel oil on an energetic basis). Medium/heavy trucks were powered prim arily (90%) by diesel fuel and all petroleum tanker trucks in this study are assumed to be powered exclusively wi th diesel fuel.

Table 5-6. Total Petroleum ProductsCarried In Domestic Transportation (Billions of TonMiles) and Percent of Total Carried by Mode of Transportation (AOP 2006)

Total Products Pipelines* Water Carriers Motor Carriers** Railroads Year Tonmiles Tonmiles % of Total Tonmiles % of Total Tonmiles % of Total Tonmiles % of Total
2000 497.3 293.9 59.1 153.4 30. 8 30.1 6.1 19.9 4.0
2001 493.2 299.1 60.6 145.9 29. 6 29.7 6.0 18.5 3.8
2002 480.6 299.6 62.3 131.9 27. 5 29.4 6.1 19.7 4.1
2003 502.9 305.7 60.8 146.0 29. 1 31.9 6.3 19.3 3.8
2004 528.4 315.9 59.8 158.2 29. 9 33.2 6.3 21.1 4.0 * The amounts carried by pipeline are based on ton-miles of crude and petroleum products for federallyregulated pipelines (84 percent) plus an estimated br eakdown of crude and petroleum products in units of ton-miles for pipelines that are not federally regulated (16 percent). ** The amounts carried by motor carriers are estimated.



### The above data were then combined to determ ine a quantity of energy expended for petroleum products transport and the fuel type powering the operation for th e whole U.S. for 2004. In the absence of a better method for allocating tr ansportation energy to petroleum products 4 

### , the total energy consumption for transport of petroleum pr oducts in 2004 and their associated emissions are allocated to the volume of petroleum products produced or imported in 2004. This total volume is 7,781,225 Mbbl and was computed as follows : total refinery products minus refinery products used on-site as a fuel minus petrochemical feedstocks plus total imported petroleum

4 The U.S. Department of Transportation Federal Highway Administration notes that shipments of petroleum

products “are significantly underestimated” in the U.S. Commodity Flow Survey (CFS) which tracks gasoline and aviation turbine fuels, fuel oils, and other petroleum products. The CFS is conducted as part of the Economic Census by the U.S. Census Bureau in partnership with the Bureau of Transportation Statistics of the U.S. Department of Transportation. http://ops.fhwa.dot.gov/ freight/freight_analysis/faf/ faf2_reports/r eports6.htm

### 93 products plus natural gas liquids production. § This transportation energy is assumed to be the same for 2005. Results of this energy usag e allocation are summari zed in Table 5-6.

Table 5-7. Energy Intensity of Transport Activities

Transport Mode Energy Intensity (One-way) Unit Reference Year Reference

Petroleum Product Pipeline 260 Btu/ton-mile 2008 Wang 2008
Water Carriers 514 Btu/ton-mile 2005 ORNL 2007, Table 2.16 Railroad 337 Btu/ton-mile 2005 ORNL 2007, Table 2.16 Heavy single-unit and combination trucks 20,539 Btu/VehicleMile 2005 ORNL 2007, Table 2.16
Heavy single-unit and combination trucks 822* Btu/ton-Mile 2005 ORNL 2007, Table 2.16 * Assuming a 25-ton truck tanker capacity

Table 5-8. Energy Usage for Petroleum Product Transport Activities

Transport Mode Energy Usage (Billion Btu HHV) Energy Usage (Btu HHV/bbl of Petroleum Products Transported) Fuel Source

Petroleum Product Pipeline 82,134 10,555 Electricity

Water Carriers 162,630 20,900 30.5% Diesel Fuel/69.5% Residual Fuel Oil Railroad 14,221 1,828 Diesel Fuel Heavy single-unit and combination trucks 54,552 7,011 Diesel Fuel



### In order to determine emissions associated with the estimated fuels consumption for petroleum products transport, appropriate em issions factors are applied to th e quantities of fuels consumed (as shown in Table 5-8) for transport. Table 5-9 provides a summary of the emissions factors applied for each mode of fuel product transportati on. The emissions factor s for diesel fuel and residual fuel oil take into account combustion of the fuel only. The upstream emissions associated with production of th ese secondary fuels contribute onl y minimally to the final results for the scenarios of interest.

§ A sensitivity analysis was performed on these parameters.

### 94 Table 5-9. Petroleum Product Transportation Modes and Associated Emission Factors

Transport Mode Energy Usage (Btu HHV/bbl of Petroleum

Products Transported) Fuel Source Fuel Energy Content (MMBtu

HHV/ bbl) CO 2 (g CO 2 / gallon) CH 4 (g CH 4 /gallon) N 2 O (g N 2 O/ gallon) Emission Factor Reference

Pipeline 10,555 Electricity N/A 217* 0.251* 0.00281* EPA, 2007 (eGRID); GaBi 4,

2007
Water Carriers 6,375 Diesel Fuel 5.825 10,147 0.74 0.26 EIA 2007

Water Carriers 14,526 Residu al Fuel

Oil 6.287 11,793 0.86 0.30 EIA 2007

Railroad 1,828 Diesel Fuel 5.825 10,147 0.80 0.26 EIA 2007 Heavy single-unit and combination trucks 7,011 Diesel Fuel 5.825 10,147 0.57 0.30 API 2004 Table 4-9

* Emission factor units are kg/MMBtu for electricity 

### Calculated specific transit emissions associated with each of the aforementioned modes of petroleum product transportation are reported with the associat ed emissions in Table 5-10. Losses from transport are not incorporated here.

Table 5-10. Emissions Associated with Petroleum Products Transport Emissions (kg/bbl) Transport Mode CO 2 CH 4 N 2 O Pipeline 2.29 2.65E-03 2.97E-05 Water Carriers (Diesel) 0.47 3.40E-05 1.20E-05 Water Carriers (Residual Fuel Oil) 1.14 8.35E-05 2.91E-05 Railroad 0.13 1.05E-05 3.43E-06 Heavy single-unit and combination trucks 0.51 2.88E-05 1.52E-05 Total 4.54 2.81E-03 8.93E-05



## 5.2 Vehicle/Aircraft Refueling
5.2.1 Vehicle Refueling The vehicle fueling station is defined as the fuel storage tank, fuel pumps, and dispensing stations. Emissions consistent with energy consumption to transfer fuel from the underground storage tank and meter the fuel into the vehicles were es timated. Electricity is the primary power source

### 95 for this motive action and emissions consistent with the power consumption were modeled using the U.S. power grid mix developed using th e U.S. EPA eGRID database (EPA 2007a). A discussion of the power-related GHG emi ssions is presented in Appendix B. Evaporative losses (see Appendix H) consistent with unloading the fuel from the tanker truck and refueling the vehicle at the st ation occur in this stage.
5.2.1.1 Gasoline Refueling Operations Electricity usage at service st ation to pump liquid fuels from the underground storage tank and meter them into vehicles is relatively minor . The electrical cons umption for a gasoline dispensing unit was calculated based on assump tions made about the dispensing unit and the amount of fuel it dispensed. The power output for the motor in the dispensing unit is rated at 750 W (CHG 2008). The EPA regulated flow rate of gasoline dispensing units is 10 gal/min or 600 gal/hr. By taking the power and dividing it by th e flow rate, the amount of energy consumed by the motor for an hour per gallon is found. Di spensing gasoline into vehicles required 0.00125 kWh per gallon of gasoline dispensed.
GHG emissions associated with vehicle refue ling operations are summarized in Table 5-11.

Table 5-11. Greenhouse Gas Emissions Associated with Vehicle Refueling Operations
Emissions (kg/bbl delivered to refueling station) Source CO 2 CH 4 N 2 O Gasoline Dispenser Operat ion 0.0388 4.50E-05 5.03E-07



### 5.2.1.2 Diesel Refueling Operations The electricity needed to effect fuel transfer ope rations for diesel is calculated the same as for gasoline transfer. Hence the el ectricity requirement for dispen sing diesel fuel is 0.00125 kWh per gallon of diesel dispensed. Table 5-11 shows the emissions associated with the fuel pump and dispenser operation.


### 5.2.2 Aircraft Refueling Aircraft fueling operation includes tr ansfer of jet fuel from the airp ort tank farm to a tanker truck followed by aircraft refueling from the tanker. Aircraft refueling emissions consistent with transport of the jet fuel from airport storage to the aircraft via tanker truck are assumed to be included in the product tran sport emissions profile.

### 96 

## 5.3 Summary of Life Cycle Stage #4 GHG Emissions Profiles

Table 5-12 summarizes the emissions profiles associated with transp ort of gasoline, diesel and jet fuel. The foreign transport profil e is applicable only to imported fuels. The domestic transport and refueling profiles are applicable to both domestically-produced and imported transportation fuels. The increase in transport activity requi red to deliver each barrel of product (due to transport losses detailed in Appendix H) are ap plied. Emissions for the transport profiles are presented as per barrel delivered to U.S. por ts/borders for foreign transport and per barrel delivered to the airport or refueling station fo r domestic transport. Refueling emissions are presented as per barrel deliver ed to the vehicle tank.
Table 5-12. Summary of GHG Emissions Consistent with Transport of Gasoline, Diesel and Jet Fuel in 2005

CO 2 CH 4 N 2 O Foreign Transport Emissions (kg/bbl delivered to U.S.) Conventional Gasoline 4.97 4.40E-04 1.25E-04 Conventional Diesel 3.05 3.13E-04 7.65E-05 Kerosene-Based Jet Fuel 5.07 4.56E-04 1.28E-04 Domestic Transport Emissions (kg/bbl delivered to refueling station) Conventional Gasoline 4.55 2.82E-03 8.95E-05 Conventional Diesel 4.54 2.81E-03 8.93E-05 Kerosene-Based Jet Fuel 4.54 2.81E-03 8.93E-05 Refueling Emissions (kg/bbl delivered to tank) Conventional Gasoline 0.0388 4.51E-05 5.04E-07 Conventional Diesel 0.0388 4.50E-05 5.03E-07 Kerosene-Based Jet Fuel Included in transport profile

### 97 

## 6.0 Life Cycle Stage #5: Vehicle/Aircraft Operation

This LC stage comprises of combustion of the fuel in the vehicle or aircraft. This is the last LC stage in the study. Routine mainte nance of the vehicle over the us eful lifespan is excluded from the study boundary.



## 6.1 Vehicle Operation
This LC stage starts when refueli ng of the vehicle is complete and continues as the fuel is burned for the energy it provides. The primary focus of an alysis in this stage is the emissions which are created during the combustion process. Vehicle use profiles for gasoline and diesel fuel consumption for the 2005 average fleet were calculated by the U.S. EPA, Office of Trans portation and Air Quality, Motor Vehicle Emission Simulator (MOVES) model (EPA 2008). A conven tional internal combustion engine for HPMS passenger car vehicle class is utilized in this study for reporting of use emissions for conventional gasoline and conventional diesel. Ta ble 6-1 shows the fuel efficiency and vehicle use emissions on a per-mile and per-MMBtu L HV-fuel-burned basis for gasoline and dieselpowered passenger cars. The vehicle use profile on a kg/MMBtu LHV basis is equivalent for all vehicle types as reported. 5 

### Results calculated and reported on a “per-mile” basis are dependant on each vehicle class’s fuel efficiency (i.e., fuel consumed per mile traveled) and are therefore only applicable to the applied vehicle class. Appendix J provides the emissions factors for the 2005 average fleet for other vehicle classifications.

Table 6-1. Conventional Diesel and Conventional Gasoline Operational Parameters and Emissions for 2000 Model Passenger Cars (EPA 2008)

Property Units Conventional Gasoline Conventional Diesel Fuel Efficiency MPG 23.9 35.1 Total fuel use Btu LHV/mile 4,866 3,737 Emissions: CO 2 kg/mile 0.365 0.286 CH 4 kg/mile 2.37E-05 2.99E-07 N 2 O kg/mile 2.43E-05 6.53E-07 CO 2 kg/MMBtu LHV 75.0 76.6 CH 4 kg/MMBtu LHV 4.9E-03 8.0E-05 N 2 O kg/MMBtu LHV 5.0E-03 1.7E-04

5 Differences in vehicle engine effici ency result in different methane and nitrous oxide emissions, however, the contribution to the total GWP, on a CO 2 equivalent basis, is orders of magnitude smaller than the CO 2 emissions.

### 98 

## 6.2 Aircraft Operation
The LC stage starts when refueling of the aircraft is complete. The stage continues as the fuel is burned for the energy it provides. The primary focu s of analysis in this stage is the emissions which are created during the combustion proces s. The U.S. Federal Aviation Administration (FAA 1997) Air Quality Handbook, Appendix D: Aircraft Emission Methodology, outlines emissions estimation techniques for aircraft. Aircraft-specific emissions are available for la nding and take-off (LTO) operations but not for the cruise component of flights. Appendix K shows the LTO emissions for various aircraft. The IPCC methodology for estimating ai rcraft emissions for both LTO and cruise are utilized in this study. The CO 2 

### cruise emissions—like LTO emissions—assume all carbon in the fuel is converted to CO 2 

### and CO 2 

### emissions are estimated to be 3.16 kg CO 2 

### per kg of fuel (IPCC 2006). The cruise emission estimates are consider ed highly uncertain for methane and nitrous oxide (IPCC 2006). IPCC (2006) reports that in -flight methane emissions are considered negligible and assumed to be zero. A composite CH 4 

### emission factor has been generated by the IPCC (2006) for flights assuming that the LTO emission factor is 5 kg/TJ (0.005 kg CH 4 

### /MMBtu LHV) (10% of total VOC factor) and that globa lly about 10% of the total fuel is consumed during LTO cycles, resulti ng in a fleet averaged CH 4 

### emission factor of 0.5 kg/TJ (0.0005 kg CH 4 

### /MMBtu LHV). N 2 

### O emissions are computed indirectly and the default value is 2 kg/TJ LHV (0.002 kg/MMBtu LHV) for fli ght operations (LTO plus cruise ). Table 6-2 lists the total average flight emissions in kg per MMBtu LHV of jet fuel consumed. Appendix I provides the heat content and densities for jet fuel.
Table 6-2. GHG Emissions Consistent with Average Flight Operations
Emissions (kg/MMBtu LHV) Source CO 2 CH 4 N 2 O Average Flight Operations (LTO + Cruise) 77.1 0.0005 0.002



## 6.3 Life Cycle Stage #5 Summary

Table 6-3 summarizes the emissions profiles associated w ith consumption of gasoline, diesel and jet fuel.
Table 6-3. Summary of GHG Emissions Consistent with Consumption of Gasoline, Diesel and Jet Fuel in 2005
Emissions (kg/MMBtu LHV consumed) Petroleum Product CO 2 CH 4 N 2 O Conventional Gasoline 75.0 4.88E-03 4.99E-03 Conventional Diesel 76.6 8.00E-05 1.75E-04 Kerosene-Based Jet Fuel 77.1 5E-04 2E-03

### 99 

## 7.0 Results and Discussion

The U.S. liquid fuels GHG profile for 2005 incl udes domestically-produced petroleum products as well as imported petroleum products (either as a finished product or blendstock). The following sections detail the GHG profile for the product mix (foreign and domestically produced) consumed in the U.S. in 2005 for each of the following fuels:

• Conventional motor gasoline

• Conventional diesel ( ≤ 500 ppm sulfur)

• Kerosene-based jet fuel


## 7.1 Construction of Life Cycle Emissions Profiles

CO 2 

### , CH 4 

### , and N 2 

### O emission profiles were developed for each life cycle stage associated with both U.S. and foreign petroleum feedstock acquisition and transpor t, refining, and transport of gasoline, diesel and jet fuel to and within the U.S. in 2005. The final results are presented as GHG emissions per million Btu of fuel consumed in a vehicle or aircraft. This requires relating the emissions profiles in each life cycle stage to this functional unit. The individual life cycle stages report emissions as a function of the out put for the individual operations. For example, emissions associated with crude oil extraction are reported on a per-barre l-of-crude-oil-extracted basis. The following factors must be taken into account when relating th e profiles from each life cycle stage to the functional unit (one million Btu of fuel consumed): (1) allocation of crude oil acquisition and transport emissions to petroleum refinery produc ts; (2) the relationship between imported and domestically produced fuels; (3) losses occurring dur ing transport of the crude oil and the finished product and the necessary incr ease in feedstock acquisi tion and liquid fuel production to meet the specified consumption (1 MMBtu); and (4) the heating values for the transportation fuels.


### Allocation of Feedstock Acquisition and Tr ansport Emissions to Refinery Products The acquisition and transport emissions for the crude oil mix, NGL, and unfinished oils have been allocated to the refinery products based on each product categories ’ volumetric contribution to total production (rather than energy contribut ion). This allocation method was selected based on the fact that the volumetric output of the species is more closely correlated with the volumetric input of crude oil than with the en ergy content (and not al l refinery products are valued for their energy content). EIA reports refinery yield in volume percent and most unit operation product data are expressed in volume percent of feed. The product categories’ volumetric contribution to tota l production is shown in Tabl e 4-54 of Section 4.2.9.5. This allocation method results in emissions for each of the products being equi valent on a per-barrelrefined basis (but varying on an energetic basi s). As reported by EIA, total refinery product volume in 2005 was 17,281 Mbbl per day while input to the refineries (crude oil mix, unfinished oils and natural gas liquids) was 16,221 Mbbl per day. This yields a ratio of 0.939 barrels of input per barrel of product which has been used to relate the feedstock acquisition emissions to refinery products. This ratio cal culated using U.S. refining data is assumed to also be applicable to foreign refinery operations.

### 100 

### Volumetric Representation of Importe d and Domestically-Produced Fuels Figure 7-1 shows an overview of the volumetri c flows of feedstock and products for U.S. refineries and imported and exported conventiona l gasoline, conventional diesel and kerosenebased jet fuel. Figure 7-2 thru Figure 7-4 show the feedstock and product requirements necessary for each activity to result in one thousand barrels of fuel consumed in the U.S. in 2005 for conventional motor gasoline, conventional dies el fuel and kerosene-based jet fuel. The relationship between imported and domestically -produced transportation fuels discussed in Appendix A and loss factors developed and di scussed in Appendix H were utilized in development of these figures.


### Conversion to Energetic Basis After the emissions factors for each activity in ea ch LC Stage are combined with the volumetric flows associated with each activit y, the final profile is converted to a LHV basis using the energy contents in Table 7-1.

Table 7-1. Heat Content of Petroleum Products

Petroleum Product Heat Content (MMBtu LHV per bbl) Reference

Conventional Gasoline 4.89 EPA 2008 Conventional Diesel 5.51 EPA 2008 Kerosene-Based Jet Fuel 5.23 DESC 2008101Figure 7-1. Feedstock and Product Volumetric Flows for Consumption of Conventional Gasoline, Conventional Diesel andKerosene-Based Jet Fuel in the U.S. in 2005Feedstock Acquisitionfor U.S. Refineries- Domestic Crude Oil- Foreign Crude Oil- Other InputsConventionalGasoline Consumedin the U.S. in 2005ConventionalDiesel Consumedin the U.S. in 2005OtherRefineryProductsExportedConventionalDieselExportedConventionalGasolineRefinery Fuels340 MMbbl/yrCrude Oil Extractionfor Foreign Productionof GasolineKersosene-BasedJet Fuel Consumedin the U.S. in 2005379 MMbbl/yr*54 MMbbl/yr*57 MMbbl/yr404 MMbbl/yr65 MMbbl/yr*69 MMbbl/yr1,056 MMbbl/yr545 MMbbl/yr2,772 MMbbl/yrExportedJet Fuel1,488 MMbbl/yr19 MMbbl/yr14 MMbbl/yr73 MMbbl/yr3,176 MMbbl/yr1,113 MMbbl/yr614 MMbbl/yrLC Stage #1:Raw MaterialAcquisitionLC Stage #2:Raw MaterialTransportLC Stage #3:Liquid FuelsProductionLC Stage #4:Product Transportand RefuelingLC Stage #5:Vehicle/AircraftUseVolume Gain387 MMbbl/yrVolume Gain32 MMbbl/yrOther Inputs: 365 MMbbl/yrDomestic: 1,876 MMbbl/yrForeign: 3,679 MMbbl/yrCrude Oil Extractionfor Foreign Productionof DieselCrude Oil Extractionfor Foreign Productionof Jet FuelForeign Refineries ExportingGasoline to the U.S.(59 Countries)Foreign Refineries ExportingDiesel to the U.S.(26 Countries)Foreign Refineries ExportingKerosene Jet Fuel to the U.S.(26 Countries)149U.S.RefineriesCrude OilConventional GasolineConventional DieselKerosene-Based Jet Fuel* Crude oil input to FOREIGN refineries include only the portionof crude oil considered to be contributing to gasoline, dieseland jet fuel production102Figure 7-2. Feedstock and Product Requirements Consistent with One Thousand Barrels of Conventional GasolineConsumed in the U.S. in 2005103Figure 7-3. Feedstock and Product Requirements Consistent with One Thousand Barrels of Conventional Diesel Consumedin the U.S. in 2005LC Stage #1:Raw MaterialAcquisitionLC Stage #2:Raw Material TransportLC Stage #3:Liquid FuelsProductionLC Stage #4:Final ProductTransport and VehicleRefuelingLC Stage #5:Vehicle UseDomestic Crude OilExtractionAcquisition of OtherInputsForeign Crude OilExtractionCrude Oil Extractionfor Virgin IslandRefineryCrude Oil Extractionfor CanadianRefineriesCrude Oil Extractionfor all other ForeignRefineriesU.S. Refinery OperationsCanada RefineryOperationsVirgin IslandRefineryOperationsForeign RefineryOperations(24 countries exportingdiesel to U.S. in 2005)TransportWithin U.S.,Bulk Storageand VehicleRefuelingTransportfromForeignRefinery toU.S. PortConsumptionofConventionalDiesel in theU.S.282.9 bblcrude oil554.8 bblfeedstock55.0 bblcrude oil890.3 bblcrude oil18.1 bblcrude oil15.1 bblcrude oil15.3 bblcrude oil18.1 bblcrude oil15.1 bblcrude oil15.2 bblcrude oil19.2 bbldiesel16.1 bbldiesel16.2 bbldiesel948.5 bbldiesel51.5 bbldiesel1,000 bbldieselLossesFromDomesticTransport,BulkStorage,Refueling<0.1 bbldieselLossesFromForeignTransport<0.1 bbldieselLosses fromCrude Oil Transport2.5 bblcrude oilAll crude oil and other refinery feedstockvolumes shown (LC Stages #1 & #2) includeonly the portion of feedstock considered tobe contributing to DIESEL productionVolume Gain58.2 bblVolume Gain3.1 bblTransportWithinU.S.PipelineTransportto ForeignPortMix of Domestic/Foreign TransportTransport byTankerPipeline Transportto Foreign PortPipeline Transportto Foreign Port/RefineryTransport byTanker(excludingU.S. and Canadian)Transport (Pipeline, Tanker, etc)from Point of Extraction to ForeignRefineryTransportby Tanker(excludingportion ofCanadacrude oil)104Figure 7-4. Feedstock and Product Requirements Consistent with One Thousand Barrels of Kerosene-Based Jet FuelConsumed in the U.S. in 2005

### 105 

## 7.2 Life Cycle GHG Emissions Associated with Finished Transportation Fuels Consumed in the U.S. in 2005

CO 2 

### , CH 4 

### , and N 2 

### O emission profiles were developed for the mix of the domestically-produced and imported fuels of interest for 2005. The resu lts from the first four life cycle stages are applicable to any source consuming these petrol eum-based fuels. Vehicl e/aircraft operation (LC Stage #5) represents the carbon content of the fuel , on a MMBtu basis, being converted to carbon dioxide during combustion. 6 

### These results are only applicable on a “per-MMBtu” basis as reported. Also, these results are not applicable to any fuel mix contai ning non-petroleum based fuels, off-road diesel fuel (>500 ppm sulfur), avia tion gasoline or kerosene for other than aircraft

use. Table 7-2 shows the GWP for production and cons umption of the three liquid fuels on a perMMBtu-LHV-consumed basis using th e global warming potentials for CO 2 

### , CH 4 

### , and N 2 

### O listed in Table 1-1. To help demonstrate the contri butions each GHG species makes to the total GWP, the contribution of CO 2 

### , CH 4 

### , and N 2 

### O (in CO 2 

### E) is also presented for each liquid fuel under the total. Appendix L presents the data from Table 7-2 in alternate units (GHG emissions on a kgper-barrel-consumed basis and kg-per-GJ-fuel-consumed basis) and in alternate IPCC global warming potential values based on the 1996 and 2001 technical reports.
Table 7-2 thru Table 7-4 show the individual GHG species and thei r emissions for the five life cycle stages for conventional motor gasoline, conv entional diesel, and kerosene-based jet fuel on a per-MMBtu-LHV-consumed basis.

Table 7-2. GHG Emissions for Liquid Fuels Production

LC Stage #1: Raw Material Acquisition LC Stage #2: Raw Material Transport LC Stage #3: Liquid Fuels Production LC Stage #4: Product Transport and Refueling LC Stage #5: Vehicle / Aircraft Operation TotalWell-toWheels

Conventional Gasoline (kg CO 2 E/ MMBtu LHV fuel consumed) Total 7.32 1.44 9.78 1.09 76.6 96.3

CO 2 4.89 1.41 9.45 1.07 75.0 91.9 CH 4 (CO 2 E) 2.39 0.0193 0.288 0.0149 0.12 2.84 N 2 O (CO 2 E) 0.0394 0.0084 0.0456 0.0065 1.49 1.59 Conventional Diesel (kg CO 2 E/ MMBtu LHV fuel consumed) Total 6.64 1.32 9.55 0.88 76.7 95.0

CO 2 4.46 1.30 9.22 0.86 76.6 92.4 CH 4 (CO 2 E) 2.14 0.0175 0.285 0.0130 0.0020 2.46 N 2 O (CO 2 E) 0.0361 0.0078 0.0424 0.0051 0.0521 0.143 Kerosene-Based Jet Fuel (kg CO 2 E/ MMBtu LHV fuel consumed) Total 6.76 1.35 6.04 1.00 77.7 92.9

CO 2 4.54 1.32 5.83 0.978 77.1 89.8 CH 4 (CO 2 E) 2.18 0.0178 0.180 0.0137 0.013 2.40 N 2 O (CO 2 E) 0.0366 0.0079 0.0269 0.0059 0.629 0.706

6 See Section 6.0 for detailed explanation of vehicle and aircraft emission factors from fuel combustion.

### 106 Table 7-3. Methane Emissions for Liquid Fuels Production

LC Stage #1: Raw Material Acquisition LC Stage #2: Raw Material Transport LC Stage #3: Liquid Fuels Production LC Stage #4: Product Transport and Refueling LC Stage #5: Vehicle / Aircraft Operation TotalWell-toWheels Petroleum

Product

kg CH 4 /MMBtu LHV fuel consumed Conventional Gasoline 0.0977 0.000774 0.0117 0.000608 0.00411 0.115

Conventional Diesel 0.0891 0.000713 0.0117 0.000542 0.000581 0.103

KeroseneBased Jet Fuel 0.0886 0.000711 0.00725 0.000548 0.0131 0.110

Table 7-4. Nitrous Oxide Emissions for Liquid Fuels Production

LC Stage #1: Raw Material Acquisition LC Stage #2: Raw Material Transport LC Stage #3: Liquid Fuels Production LC Stage #4: Product Transport and Refueling LC Stage #5: Vehicle / Aircraft Operation TotalWell-toWheels Petroleum

Product

kg N 2 O/MMBtu LHV fuel consumed Conventional Gasoline 1.32E-04 2.82E-05 1.53E-04 2.17E-05 4.99E-03 5.33E-03

Conventional Diesel 1.21E-04 2.60E-05 1.42E-04 1.70E-05 1.75E-04 4.81E-04

KeroseneBased Jet Fuel 1.23E-04 2.66E-05 9.03E-05 1.98E-05 2.11E-03 2.37E-03



### Passenger vehicle emissions are presented on the basi s of one mile traveled in Table 7-5. This metric is important since gasoline and diesel-power ed vehicles have different fuel efficiencies.

Table 7-5. Well-to-Wheels GHG Emissions in a Passenger Vehicle

Conventional Gasoline Conventional Diesel GHG kg/mile traveled
CO 2 0.447 0.345
CH 4 5.52E-04 3.68E-04
N 2 O 2.59E-05 1.80E-06 GHG, CO 2 E 0.468 0.355



### Figure 7-5 thru Figure 7-8 graphi cally portray the individual GHG species and their emissions for the five life cycle stages for conventional motor gasoline, conventiona l diesel, and kerosenebased jet fuel on a per-MMBtu-LHV-consumed basi s. Appendix L presents the data from Figure

### 107 7-5 in alternate units (GHG emissions on a kg- per-barrel-consumed basis and kg-per-GJ-fuelconsumed basis) and in alternate IPCC globa l warming potential values based on the 1996 and 2001 technical reports. To allow a more detailed examination of upstrea m fuels processing and th eir resulting emissions, well-to-tank emissions for gasoline, diesel , and jet fuel are shown in Figure 7-9. The percent contributions of each life cycle stage are displayed graphically in Figure 7-10. This allows a quick assessment of the relative impact of the various life cy cle stages on the total emissions.108Figure 7-5. GHG Emissions for Liquid Fuels’ Individual Life Cycle Stages and Complete Well-to-Wheels Life Cycle7.36.6 6.81.4 1.3 1.39.89.56.01.1 0.9 1.096.395.092.977.776.776.6020406080100 Gasoline Diesel Jet Fuel Gasoline Diesel Jet Fuel Gasoline Diesel Jet Fuel Gasoline Diesel Jet Fuel Gasoline Diesel Jet Fuel Gasoline Diesel Jet FuelLC Stage #1:Raw MaterialAcquisitionLC Stage #2:Raw MaterialTransportLC Stage #3:Liquid FuelsProductionLC Stage #4:Product Transportand RefuelingLC Stage #5:Vehicle /AircraftOperationTotalWell-to-Wheels

GHG Emissions (kg CO 2 E/MMBtu LHV of fuel consumed)Carbon DioxideMethaneNitrous Oxide109Figure 7-6. Carbon Dioxide Emissions for Liquid Fuels’ Individual Life Cycle Stages and Complete Well-to-Wheels LifeCycle4.9 1.49.41.191.94.5 1.39.20.992.44.5 1.3 5.8 1.089.875.076.677.1020406080100LC Stage #1:Raw MaterialAcquisitionLC Stage #2:Raw MaterialTransportLC Stage #3:Liquid FuelsProductionLC Stage #4:Product Transportand RefuelingLC Stage #5:Vehicle /AircraftOperationTotalWell-to-Wheels

CO 2 Emissions (kg CO 2 /MMBtu LHV fuel consumed)Conventional GasolineConventional DieselKerosene-Based Jet Fuel110Figure 7-7. Methane Emissions for Liquid Fuels’ Individual Life Cycle Stages and Complete Well-to-Wheels Life Cycle0.000.050.100.15LC Stage #1:Raw MaterialAcquisitionLC Stage #2:Raw MaterialTransportLC Stage #3:Liquid FuelsProductionLC Stage #4:Product Transportand RefuelingLC Stage #5:Vehicle /AircraftOperationTotalWell-to-Wheels

Methane Emissions (kg CH 4 /MMBtu LHV fuel consumed)Conventional GasolineConventional DieselKerosene-Based Jet Fuel111Figure 7-8. Nitrous Oxide Emissions for Liquid Fuels’ Individual Life Cycle Stages and Complete Well-to-Wheels Life Cycle0.0000.0010.0020.0030.0040.0050.006LC Stage #1:Raw MaterialAcquisitionLC Stage #2:Raw MaterialTransportLC Stage #3:Liquid FuelsProductionLC Stage #4:Product Transportand RefuelingLC Stage #5:Vehicle /AircraftOperationTotalWell-to-Wheels

N 2 O Emissions (kg N 2 O/MMBtu LHV fuel consumed)Conventional GasolineConventional DieselKerosene-Based Jet Fuel112Figure 7-9. Well-to-Tank GHG Emissions for Liquid Fuels7.36.66.81.41.3 1.39.89.56.01.10.91.015.118.419.605101520 Gasoline Diesel Jet Fuel Gasoline Diesel Jet Fuel Gasoline Diesel Jet Fuel Gasoline Diesel Jet Fuel Gasoline Diesel Jet FuelLC Stage #1:Raw MaterialAcquisitionLC Stage #2:Raw MaterialTransportLC Stage #3:Liquid FuelsProductionLC Stage #4:Product Transportand RefuelingTotalWell-to-Tank

GHG Emissions (kg CO 2 E/MMBtu LHV of fuel delivered)Carbon DioxideMethaneNitrous Oxide113Figure 7-10. Life Cycle Stage Percent Contributions to Total Life Cycle GHG EmissionsConventionalGasolineConventionalDieselKerosene-BasedJet Fuel0%20%40%60%80%100%

Percent of WTW GWPLC Stage #1:Raw MaterialAcquisitionLC Stage #2:Raw MaterialTransportLC Stage #3:Liquid FuelsProductionLC Stage #4:Product Transportand RefuelingLC Stage #5:Vehicle /AircraftOperation

### 114 

### 7.2.1 Life Cycle Stage #1 Life Cycle Stage #1 includes emissions associ ated with the extraction and post-extraction processing of refinery feedstocks for U.S. refineries and for fore ign refineries providing imported gasoline, conventional diesel and kerosene-bas ed jet fuel. Crude oil mix (conventional and synthetic crude oil/blended bitume n) is the primary feed stock of interest. For U.S. refineries, inputs of NGL and unfinished oils are also in cluded. The primary sources for feedstock acquisition emissions are country -specific crude oil extraction emission pr ofiles (PE 2008) and country-specific delivered crude oil mix emission profiles for fore ign refineries (as available) extracted from GaBi 4 (2007). The PE Internatio nal and GaBi profiles ar e representative of 2002 rather than 2005 but this temporal difference is expected to only result in minor differences in the upstream profile for conventional crude oil extraction. The extraction and processing emissions are distribut ed to all refinery products on a volumetric basis. The relationship between volumetric inpu t and volumetric output at U.S. refineries was also applied to foreign refineries. Life Cycle Stage #1 contributes a significant amount to the total life cycle emissions for all liquid fuels (7%). This life cycle stage is the primary contributor of methane emissions. Methane from oil and gas extraction operations (primarily associated with venting of light hydrocarbons) accounts for 84-91% of the total life cycle me thane emissions. Flare operations contribute significantly to the extraction CO 2 

### emissions profile. 

### 7.2.2 Life Cycle Stage #2 Life Cycle Stage #2 includes transport of feedstoc ks from the extraction/processing location to a refinery—either domestic or forei gn. Modeling of this transpor t component includes (1) foreign transport of crude in-country via pipeline to either a por t of loading or a refinery (located at a port); (2) ocean transport of foreign crude to a U.S. port or foreign refinery; and (3) U.S. domestic transport of domestically produced feedst ocks and foreign imports via a combination of pipeline, waterborne vessel , rail, and truck transpor t to domestic refineries. This life cycle stage accounts for 1-2% of the to tal life cycle GHG emissi ons. These emissions are primarily CO 2 

### from fuel combustion. 

### 7.2.3 Life Cycle Stage #3 Life Cycle Stage #3 includes emissions associ ated with petroleum refinery operations:

• Extraction, transport, and production (collect ively acquisition) of refinery fuels and energy inputs including purchased power and st eam, purchased coal and natural gas, and fuels produced and subsequently consumed at petroleum refineries

• Combustion of fuels at petroleum refineries

• Cradle-to-gate emissions associ ated with hydrogen production

• Flaring, venting, and fugitive emissions Not all GHG emissions for this life cycle stage are actually occurring at th e refinery and thus are not being emitted from the refineries. The actual GHG emissions being emitted locally at refineries is 63-67% of the total emissions for LC Stage #3. The remaining 33-37% is attributable to upstream fuel acquisition emi ssions, merchant hydrogen production, and indirect

### 115 emissions associated with purchased steam and electricity. Quantities of fuels consumed are reported by U.S. refineries in 2005 (EIA 2008), but a wide range of sources are utilized for combustion emissions factors, development of fuels and hydrogen acquisition GHG emissions profiles, and estimation of emissions from flaring and venting and fugitive methane emissions. Because petroleum refineries convert crude oil to a range of co-products, an allocation process is necessary to distribute the emissions associated with petroleum refinery operations between the various refinery products. The a llocation used here is based on the relative energy and hydrogen usage attributable to the produc tion of each of the products, as determined through process unitlevel analysis. Capacities, volumetric throughpu t, energy usage, and hydrogen consumption and production are estimated for 11 process unit categori es. The contribution of each process unit to each of the product categories is determined, comb ined with the above, and the result is the fraction of energy and hydrogen usage attributab le to each product. Throughput capacities of process units are as reported by U.S. refineri es for January 1, 2006 (EIA 2008), but a wide range of sources are utilized to de termine capacity utilization, en ergy usage, hydrogen usage and contribution of process unit operations to end pro ducts. Refinery data are aggregate U.S. data and the refineries were modeled for steady-st ate operation. Start-up, shut-down, systemic anomalies and perturbations are di fficult to quantify and thus exclude d from this modeling effort. Refinery energy estimations using unit operation energy requirement for the processes modeled accounted for approximately 75% of the actual fuels/energy consumption reported by EIA. There are two primary reasons that the total modeled energy consumption does not agree with the actual energy consumption. First, the energy estimates used to model the aggregate refinery operations are average values. There will be variability due to differences in processing schemes, efficiency/age of process units, differi ng feedstock qualities, et c. Secondly, there are miscellaneous other downstream operations that are not tracked by EIA th at contribute to the total refinery energy consumption (e.g. Merox pro cess unit, etc.) It is acknowledged that liquid fuels will, therefore, bear some burden for these operations. Foreign refineries producing petr oleum products for export to the U.S. have been assumed to have the same refining GHG profile as U.S. refine ries. There is a lack of publicly available, accurate information for foreign refinery operati ons that covers the appropriate system boundary (i.e. indirect emissions associat ed with electricity usage and hydrogen inputs). The refining GHG profile developed for this study was compared to three foreign studies (refer to Section 4.3), however, U.S. refining results were used as a surrogate for foreign refinery operations to maintain transparency. This assumption is noted as a data limitation. This life cycle stage represents 6.5% of the total GHG emissions profile for kerosene-type jet fuel and 10% for both gasoline and diesel fuel. 

### 7.2.4 Life Cycle Stage #4 Life Cycle Stage #4 consists of emissions and pro duct losses associated wi th transport of liquid fuels from the refinery to either the vehicl e refueling station or the airport followed by aircraft/vehicle refueling. This includes ocean tanker and/or pipeline transport of petroleum products from a foreign refinery to the U.S. and domestic transport of foreign imports and domestically produced liquid fuels via a combina tion of pipeline, waterborne vessel, rail, and truck transport to refueling facilities.

### 116 Life Cycle Stage #4 does not incl ude any emissions consistent w ith blender operations (other than bulk storage). Since only conventional gaso line is modeled, blender operations necessary to add oxygenates or other fuel additives, or create boutique fuel blends w ould not be required. Life Cycle Stage #4 also includes emissions asso ciated with refueling operations for passenger vehicles and aircraft. For gasoline and diesel , the only direct GHG emi ssions are the result of power requirements to operate the dispenser (pump and meter). Transport losses occurring during transport and refueling are a function of the liquid fuel’s volatility. Hence, gasoline—which is the most volatile of the three primary transportation fuels—will experience the largest evaporative losse s. These evaporative losses do not have an associated GHG emissions prof ile. However, they do indire ctly increase GHG emissions minimally because more upstream product refining (and refinery feedstock acquisition) is required to meet a specified final need. For this study, the delivery re quirements are 1 MMBtu (LHV) consumed by a vehicle or aircraft. Transportation and refueling opera tions are not a significant contributor to the total life cycle GHG emissions (approximately 1%). 

### 7.2.5 Life Cycle Stage #5 Life Cycle Stage #5 is the use stage for the thr ee liquid fuels modeled. As expected, combustion emissions generated during the use phase are the primary contributo rs to the total life cycle GHG emissions. The use phase ranges from 79.6% to 83.7% of the total life cycle GHG emissions for the three fuels modeled. Vehicle use profiles for gasoline and diesel fuel consumption for the 2005 average fleet were calculated by the U.S. EPA, Office of Trans portation and Air Quality, Motor Vehicle Emission Simulator (MOVES) model (EPA 2008). A conven tional internal combustion engine for HPMS passenger car vehicle class is utilized in this study for reporting of use emissions for conventional gasoline and conventional diesel. The vehicle use profile on a kg/MMBtu LHV basis is equivalent for all vehicle types as reported. 7 

### Results calculated and reported on a “permile” basis are dependant on each vehicle class’s fu el efficiency (i.e., fuel consumed per mile traveled) and are therefore only appli cable to the applied vehicle class. The IPCC methodology for estimating ai rcraft emissions for both LTO and cruise are utilized in this study. The CO 2 

### cruise emissions—like LTO emissions—assume all carbon in the fuel is converted to CO 2 

### and CO 2 

### emissions are estimated to be 3.16 kg CO 2 

### per kg of fuel (IPCC 2006). The cruise emission estimates are consider ed highly uncertain for methane and nitrous oxide (IPCC 2006). IPCC (2006) reports that in -flight methane emissions are considered negligible and assumed to be zero. A composite CH 4 

### emission factor has been generated by the IPCC (2006) for flights assuming that the LTO emission factor is 5 kg/TJ (0.005 kg CH 4 

### /MMBtu LHV) (10% of total VOC factor) and that globa lly about 10% of the total fuel is consumed during LTO cycles, resulti ng in a fleet averaged CH 4 

### emission factor of 0.5 kg/TJ (0.0005 kg CH 4 

### /MMBtu LHV). N 2 

### O emissions are computed indirectly and the default value is 2 kg/TJ LHV (0.002 kg/MMBtu LHV) for flight operations (LTO plus cruise).

7 Differences in vehicle engine effici ency result in different methane and nitrous oxide emissions, however, the contribution to the total GWP, on a CO 2 equivalent basis, is orders of magnitude smaller than the CO 2 emissions.

### 117 

## 7.3 GHG Emissions Associated with Liquid Fuels Produced at U.S. Refineries in 2005: Comparison to Foreign Imported Fuels
Figure 7-11 and Figure 7-12 show the life cycl e GHG emissions for domestically-produced liquid fuels. Figure 7-13 thru Figure 7-15 compare the life cycle stage GHG emissions for U.S. fuel production and consumption with that of imported fuels. Life Cycle Stage #1 emissions for U.S. fuel production is higher than that for imports, due in part to the U.S. import of Canadian oil sands which has a significantly higher GHG extr action profile. LC Stage #2 emissions for refinery feedstock transport for U.S. fuel pr oduction are approximately twice as high as for imported fuel production. This is due to the fact that the U.S. imports a significant amount of the refinery feedstocks from foreign destinations while foreign production of imported liquid fuels utilizes a greater proportion of local crude oil f eedstocks. LC Stage #3 emissions for refinery operation are the same for both U.S. and fore ign refining (study assumption). LC Stage #4 emissions for foreign imports are higher than for U.S. production because of the additional foreign transport operations (primarily ocean tank er transport). LC Stage #5 emissions will be the same for both fuel sources since it is assumed that there is no differen ce in final fuel quality between U.S. and foreign fuel sources.118Figure 7-11. GHG Emissions for Liquid Fuels Produced Domestically7.56.77.01.5 1.4 1.49.8 9.56.01.00.80.996.595.193.176.6 76.777.7020406080100 Gasoline Diesel Jet Fuel Gasoline Diesel Jet Fuel Gasoline Diesel Jet Fuel Gasoline Diesel Jet Fuel Gasoline Diesel Jet Fuel Gasoline Diesel Jet FuelLC Stage #1:Raw MaterialAcquisitionLC Stage #2:Raw MaterialTransportLC Stage #3:Liquid FuelsProductionLC Stage #4:Product Transportand RefuelingLC Stage #5:Vehicle /AircraftOperationTotalWell-to-Wheels

GHG Emissions (kg CO 2 E/MMBtu LHV of fuel consumed)Carbon DioxideMethaneNitrous Oxide119Figure 7-12. Well-to-Tank GHG Emissions for Liquid Fuels Produced Domestically7.56.77.01.51.41.49.89.56.01.00.80.915.418.419.805101520 Gasoline Diesel Jet Fuel Gasoline Diesel Jet Fuel Gasoline Diesel Jet Fuel Gasoline Diesel Jet Fuel Gasoline Diesel Jet FuelLC Stage #1:Raw MaterialAcquisitionLC Stage #2:Raw MaterialTransportLC Stage #3:Liquid FuelsProductionLC Stage #4:Product Transportand RefuelingTotalWell-to-Tank

GHG Emissions (kg CO 2 E/MMBtu LHV of fuel delivered)Carbon DioxideMethaneNitrous Oxide120Figure 7-13. Comparison of GHG Emissions for Conventional Gasoline Produced at U.S. Refineries and Imported fromForeign Refineries7.55.81.50.89.8 9.81.02.019.818.405101520U.S. Imports U.S. Imports U.S. Imports U.S. Imports U.S. ImportsLC Stage #1:Raw MaterialAcquisitionLC Stage #2:Raw MaterialTransportLC Stage #3:Liquid FuelsProductionLC Stage #4:Product Transportand RefuelingTotalWell-to-Tank

GHG Emissions (kg CO 2 E/MMBtu LHV of fuel delivered)Carbon DioxideMethaneNitrous Oxide121Figure 7-14. Comparison of GHG Emissions for Conventional Diesel Fuel Produced at U.S. Refineries and Imported fromForeign Refineries6.76.21.40.69.5 9.50.81.418.417.705101520U.S. Imports U.S. Imports U.S. Imports U.S. Imports U.S. ImportsLC Stage #1:Raw MaterialAcquisitionLC Stage #2:Raw MaterialTransportLC Stage #3:Liquid FuelsProductionLC Stage #4:Product Transportand RefuelingTotalWell-to-Tank

GHG Emissions (kg CO 2 E/MMBtu LHV of fuel delivered)Carbon DioxideMethaneNitrous Oxide122Figure 7-15. Comparison of GHG Emissions for Kerosene-Based Jet Fuel Produced at U.S. Refineries and Imported fromForeign Refineries7.04.71.40.76.0 6.00.91.915.413.305101520U.S. Imports U.S. Imports U.S. Imports U.S. Imports U.S. ImportsLC Stage #1:Raw MaterialAcquisitionLC Stage #2:Raw MaterialTransportLC Stage #3:Liquid FuelsProductionLC Stage #4:Product Transportand RefuelingTotalWell-to-Tank

GHG Emissions (kg CO 2 E/MMBtu LHV of fuel delivered)Carbon DioxideMethaneNitrous Oxide

### 123 

## 8.0 Data Quality and Sensitivity Analysis

Applicability of data for the study year 2005, level of detail available (i.e. due to the country where the activity occurs), absence of data, and fitn ess of data sources are all factors that effect the overall quality of the results of this study. The impact of lower quality data or necessary assumptions and estimations on the final results will vary based on the relative contribution of the associated activity to the final emissions pr ofile. To understand and quantify the effects of such uncertainty, a data quality assessment is di scussed and associated sensitivity analysis results are presented for each life cycle stage. Sensitivity analyses are shown in terms of well-to-tank GHG emissions and have not been conducted for the vehicle/aircraft use phase of th e fuel cycle. While this stage contributes a significant portion of the total life cycle GHG profile, the variabi lity can simply be represented by modifying the LC Stage #5 results. In general for well-to-tank GHG emissions, greater variability occurs for raw material acquisition and liquid fuels production stages, since these stages account for a much higher fr action of the well-to-tank profile.


## 8.1 Life Cycle Stage #1
LC Stage #1 includes emissions a ssociated with the extraction a nd post-extraction processing of refinery feedstocks for U.S. refineries and fo r foreign refineries providing imported gasoline, conventional diesel and kerosene-b ased jet fuel. Figure 8-1 thru Figure 8-3 show the results of the sensitivity analysis for LC Stage #1 ac tivities for each liquid product of interest: conventional motor gasoline, conven tional diesel fuel and kerosene -based jet fuel. The figures show the variability in the well- to-tank GHG emissions profiles for several factors. The baseline value is represented by the dotted line.



### 8.1.1 Crude Oil Extraction Profiles Crude oil extraction accounts for approximately 87% of the GHG emissions in LC Stage #1 and between 31 and 39% of the entire well-to-tank pr ofiles. The country of origin for crude oil imported by the U.S. and by the Virgin Islands is as reported by EIA and is specific to the year 2005. A similar level of detail is available for cr ude oil inputs to Canadian refineries in 2005. Country-specific crude oil GHG emissi ons profiles, either for extrac tion by country of origin (PE 2008) or delivered profiles (Gabi 4 2007), were used as available. These profiles are representative of 2002 operations and, where delive red crude oil profiles were used for foreign refineries, representative of crude oil mixes in 2002.


### Use of Crude Oil Profiles As discussed in Section 2.1.1.1, the country-speci fic crude oil extracti on profiles are highly dependent on flaring and venting and, while a linear relationship between CO 2 

### emissions and flaring is apparent, the U. S. profile is above the CO 2 

### emissions predicted from this relationship. Because U.S. data is often more readily availabl e and transparent, the higher U.S. value relative to the trend for GHG emissions a ssociated with crude oil extrac tion in the foreign countries could lead to the conclusion that the foreign data are underestimated. Assuming that half of the difference is due to this (and the other half is due to different extracti on technologies, mix of on-

### 124 shore/off-shore, maturity of fields, etc), all of the foreign extraction prof iles would be increased by 3.4 kg CO 2 

### E/bbl. The extraction profiles for all countries are repr esentative of 2002 rather than 2005. Significant changes in the flaring and ven ting rates relative to crude oi l production in the countries of interest would change the profile s. Assuming Mexico, Algeria, Angola, and Nigeria all reduced their flaring and venting by one fourth would result in an overall reduction of emissions associated with this life cycle stage. The impact of these two scenarios is shown in Fi gure 8-1 as “Baseline adju stment in line with U.S. profile” and “Reduced flaring/venting.” Th e impact of reduction in flaring and venting has the greatest impact on the GHG profile for this lif e cycle stage, but results in less than 5% percent reduction in the well-to-tank profiles an d less than 1% percent reduction in the well-towheels profiles. While not quantified here, it is im portant to note that the impact of flaring and venting highlights the substantial reliance on country-reported flarin g and venting rates, al though to a lesser degree in countries where multi-national companies opera te the crude oil and natural gas production.


### Foreign Average Crude Oil Extraction Profile Country-specific crude o il extraction profiles for the countri es contributing over 90% of the crude oil input to U.S. refineries in 2005 are mo deled with the remaining assumed to be a foreign average. This foreign average is also used for 3.3% of the crude oil fed to Canadian refineries. Figure 8-1 thru 8-3 show the impact of varying the foreign average extraction profile study value from 58% (equal to the U.S. profile) to 125% (65% of the Angola profile) on WTT GHG emissions. The GHG profile varies le ss than ±2% with these changes.


### Foreign Average Delivered Crude Oil Profile Country-specific delivered profiles or extracti on profiles were used for foreign refineries producing conventional gasoline, co nventional diesel, or kerosene-b ased jet fuel imported by the U.S. in 2005. A foreign average delivered profile was used as a surrogate for the crude input to foreign refineries in countries where crude oil extraction profil es were not available. For imported fuels, the foreign average is used fo r 9% of the gasoline crude oil mix, 12% of the diesel crude oil mix, and 22% of the jet fuel cr ude oil mix. The sensitiv ity of the well-to-tank profiles assuming the delivered foreign profile study value is varied from 67% (equal to Sweden’s delivered profile) to 151% (equal to China’s delivered pr ofile) was found to be insignificant. 

### 8.1.2 Oil Sands/Heavy Oils GHG Emissions Profiles Oil sands and other heavy oils a nd synthetic crude oil are emergi ng as unconventional feedstocks to refineries and the extraction process and subsequent upgrading a ssociated with these oils are more energy intensive th an traditional crude oil extraction. The specific quantity of Canadian oil sands utilized by U.S. refineri es in 2005 is available, howev er, data are limited for other countries that may have supplied similar unc onventional feedstocks to U.S. refineries.

### 125 

### Canadian Oil Sands When determining the GHG emissions profile for Canadian oil sands, the 2005 reported GHG emissions from a company producing blended bitu men and another producing synthetic crude oil were used and assumed to be representative of the industry. While these companies are well established and represented appr oximately 33% of the Canadian oil sands bitumen production in 2005 (AEUB 2006), it is expected that there is uncerta inty in this profile of Canadian oil sands. The GHG well-to-tank emissions profile for each of th e fuels is shown in the sensitivity analysis for a scenario where the Canadian oils sands GHG profile is varied between 75% and 125% of the study value. This change in the Canadian oil sands GHG profile results in a 1% or less change in the GHG profile for each of the petroleum products.


### Venezuelan Crude Oil Extraction Profile Heavy oil extraction and upgradi ng is a growing piece of Venezu elan oil production. However, due to limited availability of information, the extraction emissions profile used does not incorporate such activities. The sensitivity an alysis shows what the well-to-tank emissions profile would be if 25% of the Venezuelan crude o il input to U.S. and fore ign refineries were set equal to the Canadian oil sands extraction profile (50/50 mix of synthetic crude oil and blended bitumen). Increasing Venezuelan crude o il extraction emissions increases the WTT GHG emissions by less than 3%.

Figure 8-1. Sensitivity Analysis of Life Cycle Stage #1 Activities on the Well-to-Tank GHG Emissions Profile for Conventional Gasoline Consumed in the U.S. in 2005

18 19 20 21 22 Venezuelan Profile Canadian Oil Sands Profile Foreign Average Crude Oil Delivered Profiles Foreign Average Crude Oil Extraction Profiles

Crude Oil Extraction Profile Adjustment

Well-to-Tank GHG Emissions in kg CO 2 E per MMBtu LHV of Conventional Gasoline Consumed in the U.S. in 2005 58% of study value (equal to U.S.) 125% of study value (65% of Angola)

151% of study value (equal to China) 67% of study value (equal to Sweden) Baseline adjustment in line with U.S. profile Reduced flaring/ venting

25% synthetic/ blended bitumen 75% of study value 125% of study value Baseline Value

### 126 Figure 8-2. Sensitivity Analysis of Life Cycle Stage #1 Activities on the Well-to-Tank GHG Emissions Profile for Conventional Diesel Consumed in the U.S. in 2005

16.5 17.5 18.5 19.5 20.5 Venezuelan Profile Canadian Oil Sands Profile Foreign Average Crude Oil Delivered Profiles Foreign Average Crude Oil Extraction Profiles

Crude Oil Extraction Profile Adjustment

Well-to-Tank GHG Emissions in kg CO 2 E per MMBtu LHV of Conventional Diesel Fuel Consumed in the U.S. in 2005 Baseline Value 58% of study value (equal to U.S.) 125% of study value (65% of Angola)

151% of study value (equal to China) 67% of study value (equal to Sweden) Baseline adjustment in line with U.S. profile Reduced flaring/ venting

25% synthetic/ blended bitumen 75% of study value 125% of study value

Figure 8-3. Sensitivity Analysis of Life Cycle Stage #1 Activities on the Well-to-Tank GHG Emissions Profile for Kerosene-Based Jet Fuel Consumed in the U.S. in 2005

13.5 14.5 15.5 16.5 17.5 Venezuelan Profile Canadian Oil Sands Profile Foreign Average Crude Oil Delivered Profiles Foreign Average Crude Oil Extraction Profiles

Crude Oil Extraction Profile Adjustment

Well-to-Tank GHG Emissions in kg CO 2 E per MMBtu LHV of Kerosene-Based Jet Fuel Consumed in the U.S. in 2005 Baseline Value 58% of study value (equal to U.S.) 125% of study value (65% of Angola)

151% of study value (equal to China) 67% of study value (equal to Sweden) Baseline adjustment in line with U.S. profile Reduced flaring/ venting

25% synthetic/ blended bitumen 75% of study value 125% of study value



## 8.2 Life Cycle Stage #2
LC Stage #2 includes emissions asso ciated with the transport of crude oil and other feedstocks from the point of extraction to the refinery that processes the crude oi l. This is applicable to both crude oil for use in U.S. refineries and for foreign refineries providing imported gasoline, conventional diesel, and kerosene-b ased jet fuel. Figure 8-4 thru Figure 8-6 show the results of the sensitivity analysis for LC Stage #2 ac tivities for each liquid product of interest: conventional motor gasoline, conven tional diesel fuel and kerosene -based jet fuel. The figures show the variability in the well- to-tank GHG emissions profile for se veral factors. The baseline value is represented by the dotted line.

### 127 

### 8.2.1 Waterborne Transport Transport of crude oil by tanker from foreign por ts to refineries in the U.S., Canada, Virgin Islands and South Korea was m odeled. EIA volume and receiving port data are available for each shipment received by the U.S. and Virgin Is lands in 2005. While specific ports of receipt were not available for Canada, a similar approach wa s used for distance traveled calculations. For foreign countries where a delivered crude oi l profile was not available, any waterborne transport associated with shipment of crude oi l is embedded in that profile and thus is not impacted by the sensitivity analysis.


### Crude Oil Carrier Energy Intensity A crude oil carrier energy intens ity factor was determined after conducting a survey of crude oil vessels. The energy intensity factor will be spec ific to the tanker characteristics and capacity. For this sensitivity analysis, the crude oil water carrier energy intensity was varied from 4.25 to 7.25 Btu/bbl-nautical mile (study value of 5.5 Bt u/bbl-nautical mile) in line with the range occurring in the survey of tankers conducted as pa rt of this study. The re sulting variability in the well-to-tank GHG emissions profile is minor (±1%).


### Crude Oil Waterborne Transport Distances Modeling of the transport of crude oil by tanker fr om foreign ports to re fineries in the U.S., Canada, Virgin Islands and South Korea used es timated port-to-port trav el distances assuming no crude oil tanker transport through various canals. For 9.5% of the crude oil to U.S. refineries and 3.3% of the crude oil to Canadian refineries, assumed average transport distances are 10,000 and 5,000 nautical miles, respectively. To simulate uncertainty in the use of these averages and restriction of canal usage, a sensitivity analysis varied all waterborne distances from 90% to 115%. This results in a range in the well-to-t ank GHG emissions profile of minor consequence.


### 8.2.2 Pipeline Transport All transport from the point of ex traction to port/border of export or refinery was assumed to be 100 miles by pipeline and a GHG emissions profile for the U.S. power grid was applied to the power consumed for pipeline operation. The impact of these two assumptions is negligible, as shown by the sensitivity analysis where the pipeline mileage is varied from 50 to 200 miles and the electricity profile for fo reign transport is simultaneous ly varied from 80% to 120%. For foreign countries where a delivered crude oil profile was not avai lable, any pipeline movements associated with crude oil transport is embedded in that pr ofile and thus is not impacted by the sensitivity analysis.



### 8.2.3 Crude Oil Loss Factor
Losses associated with crude oi l transport will vary based on crude oil type, duration of transport, and modes of transport. For this reason , data on average loss factors is not available. The loss factor used is based on that reporte d by a European company for 2005 that imports a majority of its crude oil (Eni 2006). This loss fa ctor was applied to all crude oil transported. The sensitivity analysis shows that varying the crude oil loss factor fr om 50% to 200% of the base value has an insignificant impact on the fi nal well-to-tank emissions profile. Note that crude oil losses occur during LC Stage 2 activitie s, but impact the profile of both LC Stage #1 and #2.

### 128 Figure 8-4. Sensitivity Analysis of Life Cycle Stage #2 Activities on the Well-to-Tank GHG Emissions Profile for Conventional Gasoline Consumed in the U.S. in 2005

18 19 20 21 22 Crude Oil Loss Factor Crude Oil Foreign Pipeline Transport Crude Oil Waterborne Transport Distances Crude Oil Carrier Energy Intensity

Well-to-Tank GHG Emissions in kg CO 2 E per MMBtu LHV of Conventional Gasoline Consumed in the U.S. in 2005 90% of study value 115% of study value

200 miles; 120% of U.S. electricity profile 50 miles; 80% of U.S. electricity profile 7.25 Btu / bbl-mile 4.25 Btu / bbl-mile

50% of study value 200% of study value Baseline Value

Figure 8-5. Sensitivity Analysis of Life Cycle Stage #2 Activities on the Well-to-Tank GHG Emissions Profile for Conventional Diesel Consumed in the U.S. in 2005

16.5 17.5 18.5 19.5 20.5 Crude Oil Loss Factor Crude Oil Foreign Pipeline Transport Crude Oil Waterborne Transport Distances Crude Oil Carrier Energy Intensity

Well-to-Tank GHG Emissions in kg CO 2 E per MMBtu LHV of Conventional Diesel Fuel Consumed in the U.S. in 2005 Baseline Value 90% of study value 115% of study value

200 miles; 120% of U.S. electricity profile 50 miles; 80% of U.S. electricity profile 7.25 Btu / bbl-mile 4.25 Btu / bbl-mile

50% of study value 200% of study value

### 129 Figure 8-6. Sensitivity Analysis of Life Cycle Stage #2 Activities on the Well-to-Tank GHG Emissions Profile for Kerosene-Based Jet Fuel Consumed in the U.S. in 2005

13.5 14.5 15.5 16.5 17.5 Crude Oil Loss Factor Crude Oil Foreign Pipeline Transport Crude Oil Waterborne Transport Distances Crude Oil Carrier Energy Intensity

Well-to-Tank GHG Emissions in kg CO 2 E per MMBtu LHV of Kerosene-Based Jet Fuel Consumed in the U.S. in 2005 Baseline Value 90% of study value 115% of study value

200 miles; 120% of U.S. electricity profile 50 miles; 80% of U.S. electricity profile 7.25 Btu / bbl-mile 4.25 Btu / bbl-mile

50% of study value 200% of study value



## 8.3 Life Cycle Stage #3
Life Cycle Stage #3 includes emissions associ ated with the following petroleum refinery operations:

• Extraction, transport, and production of refinery fuels and energy inputs

• Combustion of fuels for use as an en ergy source at petr oleum refineries

• Cradle-to-gate emissions associ ated with hydrogen production

• Flaring, venting and fugitive methane emissions Figure 8-7 thru Figure 8-9 at the en d of the discussion show the resu lts of the sensitivity analysis for LC Stage #3 activities for each liquid product of interest: conventional motor gasoline, conventional diesel fuel and kerosene-based jet fuel. The figures show the variability in the well-to-tank GHG emissions profiles for several f actors. The baseline value is represented by the dotted line.


### 8.3.1 Total Petroleum Refining Emissions Quantities of fuels consumed in refineries are as reported by U.S. petroleu m refineries to EIA in 2005, but a variety of sources not specific to 2005 were used to determine the energy content, emissions profiles for these fuels, flaring a nd venting at refineries , and energy usage and resulting GHG emissions associated with merchant hydrogen production. Sensitivity analysis on these factors will generally rais e or lower the GHG emissions prof ile for all refinery products.



### Still Gas Emissions Factors Still gas is a mix of light gases from various parts of the refinery and provides nearly half of the energy input to refineries. The quantity of still ga s consumed at refineries is reported by EIA and these data are of high quality. One area of un certainty however, is still gas composition. The

### 130 carbon content and resulting GHG emissions are not specifically known. However, the impact of varying the CO 2 

### emissions equal to that from combustion of liquid propane gas to pentanes plus is minor. The emissions factors for liquid propa ne gas and pentanes plus utilized for this analysis are 62.3 and 66.9 kg CO 2 

### /MMBtu HHV, respectively (API 2004). The still gas study value used is 64.2 kg CO 2 

### /MMBtu HHV.


### Electricity Profile for Refineries The U.S. average mix of electricity sources (coa l, nuclear, renewables, etc.) in 2004 was used to represent to GHG emissions profile for electricity purchased and us ed by U.S. refineries. U.S. refineries are generally located in specific regions of the country and thus the actual electricity source mix may vary from the U.S. average. A se nsitivity analysis varying the electricity profile from 90% to 115% of the study value show s minimal impact on the overall profiles.


### Hydrogen Plant Feed Input Hydrogen plant feed input is estimated to be 352 Btu HHV per scf of hydrogen. Based on the survey conducted as part of this study, other reported values vary from 306 to 376 Btu HHV per scf depending on the technology applied. The ra nge evaluated here is 325 to 375 Btu HHV per scf to more accurately represent the range of average values for 2005. For diesel fuel and jet fuel, reducing the feed requirements (essentially incr easing the efficiency) results in a decrease in the well-to-tank GHG profile. However, gasoline actually shows a slight increase from the baseline profile for both cases. Th is is due to the system expansi on process used for allocation of the catalytic reformer energy. When the model hydrogen plant efficiency is increased, it results in the energy to produce hydrogen from the cataly tic reformer being greater than for the model hydrogen plant (SMR). This resu lts in 6% of the catalytic re former energy requirement being allocated to the reformate and thus to gasoline.


### Off-Site Hydrogen Production Merchant hydrogen consumption by U.S. refi neries was estimated using 2003 data and extrapolated based on historical growth rates. Varying the study value between 80% and 125% of the base consumption quantity directly aff ects the GHG WTT emissions profiles with greater variability for diesel (due to the greater hydrog en consumption associated with its production), but to a small extent (~0.6% difference).


### On-Site Hydrogen Plan t Capacity Utilization Hydrogen plant capacity at U.S. refineries is pr ovided by EIA, however th e percentage of that capacity that is utilized had to be estimated. The assumed value was 85%. Increasing this value primarily results in an increase in the overall natural gas feed requirements and associated emissions and the CO 2 

### process emissions associated with production of the hydrogen. Sensitivity analysis for this parameter shows only slight variability in the GHG emissions profiles for each of the fuels through a range of 80% to 90% capaci ty utilization.


### Flaring and Ven ting/Fugitive Methane Emissions Emissions associated with flari ng at U.S. refineries, as determined in this study, makes up less than 1% of the LC Stage #3 GHG emissions profile . The study value was estimated using flare rates from a group of California refineries for whic h reporting of such data is required. It was assumed that the flared gas is natural gas. Because California genera lly has more stringent

### 131 restrictions on such activities and because combus tion emissions from natural gas are expected to underpredict GHG emissions related to refinery fl aring, a sensitivity analys is has been conducted to show the impact of a valu e 300% of the study value. The impact on the overall profile is minor (0.7% or less increase in WTT GHG emissions). Methane vented and fugitive emissions from refinery operations for the 2005 U.S. GHG Inventory have been estimated and extrapol ated from 1996 and 1999 EPA studies (EPA 1996; EPA 1999) of refinery process unit methane em issions. It is impor tant to note that environmental regulations and industry responsib le care has increased in the interim since 1996 and 1999. Thus, these values may be inflated fo r refineries currently in operation today. However, the sensitivity analysis shows an insignificant change to the GHG emissions profiles when the study value is reduced to 25%.



### 8.3.2 Allocation of Emissions to Petroleum Refining Products While U.S. petroleum refineries repo rt process unit capaci ties for January 1 st 

### of each year, capacity utilization, unit-specifi c energy and hydrogen requirement s, and the contribution of each process unit to the product categories are all factors that will vary from year to year. Furthermore, if reported values are available, they are typically linked to a technology type rather than a U.S. weighted average. Sensitivity an alysis on these factors wi ll generally change the GHG distribution between products.
8.3.2.1 Hydrogen Production and Consumption Changing factors related to hydrogen production or consumption will impact the energy consumption at the refinery attributable to hydrogen production and thus shift the emissions towards or away from those processes and asso ciated products that consume more hydrogen.


### Catalytic Reformer Hydrogen Production Hydrogen production by the cataly tic reformer was assumed to be 1,000 scf/bbl based on a literature survey. While sources showed ranges from 600 to 1,700 scf/bbl, the range of uncertainty is likely smaller based on the aver age technology and mode of operation for U.S. refineries in 2005. The sensitivity analysis shows the impact on the GHG emissions as the catalytic reformer hydrogen production is vari ed from 800 to 1,200 scf/bbl. Increasing the hydrogen production by the catalytic reformer slightly skews the distribution of emissions towards those products that consume hydrogen (i.e . diesel). However, decreasing the hydrogen production by the catalytic reformer has a more co mplex effect and thus a greater impact. This change increases the energy requirements for th e catalytic reformer to produce hydrogen to a value greater than that for hydr ogen production by SMR. Applica tion of the system expansion methodology described in Section 4.2.5.2 for this scenario results in 21% of the catalytic reformer energy being assigned to reformate production and away from the hydrogen pool. Because reformate is primarily a gasoline blending co mponent, this results in a direct shift of the emissions profile from diesel and kerosene to gasoline. Reducing the catalytic hydrogen consumption results in one of the larger pr ofile shifts, but it is less than a 3% change from baselin e in the well-to-tank profiles.

### 132 

### Hydrocracker Hydrogen Consumption The hydrocracker hydrogen consumption is fixed and the hydrotreating hydrogen consumption is calculated to balance the sy stem. This means that varying the hydrocracker hydrogen consumption also varies the hydrotreater hydr ogen consumption. The results of varying the hydrocracker hydrogen consumption from 80% to 150% of the baseline value for all hydrocracking operations are shown. Varying hy drocracker hydrogen consumption results in only a small deviation of the GHG profile from the study baseline.
8.3.2.2 Capacity Utilization EIA provides U.S. refinery 2005 actual volumetri c throughput for the atmospheric distillation column, catalytic cracking units, hydrocracki ng units, and coking units. However, for the remaining processing units, capacity utilization must be estimated. A 1996 API/NPRA refinery survey (API 2004) provided capacity utilization factors for various process units and was used as a starting point, but changes in economics, technology, and regulatory requirements, and their resulting impact on capacity utiliz ation is difficult to predict.


### Hydrotreating Capacity Utilization A large volume of intermediate and final products ar e hydrotreated in refineri es to remove sulfur. Furthermore, changes since 1996 have been more than minor due to the processing of heavier, higher sulfur crude oils and lower limits for sulfur content in final products. However, increasing the capacity utilizati on to 85% (from the study value of 80%) results in only a minor increase in the profile for diesel and an insignificant decrease in the profiles for gasoline and jet fuel.



### Vacuum Distillation C apacity Utilization Increasing the vacuum distillation column capac ity utilization results in a shift of GHG emissions from lighter products to heavier products. Varying the vacuum distillation between 80 and 90% (study value is 85%) has a minor impact on the diesel profile, w ith even less of an impact on the gasoline and jet fuel profiles.
8.3.2.3 Energy Consumption Process unit-specific energy consumption was us ed for purposes of allocating between product categories. The average energy consumption for each process unit and ranges for various technologies were shown in Table 4-43 (Energet ics 2007). This source draws on the reported energy requirements of multiple li censed technologies employed by U.S. refineries in 2005. The ranges represent different technol ogies and are not intended to provi de a range for the aggregated average value for the year 2005. They are, however, us ed as a guide for this sensitivity analysis.


### Vacuum Distillation Energy Consumption The vacuum distillation column energy intensity is varied here in the ra nge relative to the study value of 90 MBtu HHV per barrel of throughput. When the energy requirement is increased from the baseline, more energy and associat ed emissions are allocated to heavier nontransportation fuel products such as lubricants an d coke, and less are allocated to gasoline, diesel, and jet fuel.

### 133 

### Delayed Coker Energy Consumption The delayed coker energy intensity range repo rted by Energetics is wide (115 MBtu/bbl), representing various technologies and severity of operations. In the sensitivity analysis presented here, for the range ev aluated (115 to 175 MBtu HHV per barrel of throughput versus the study value of 147) a minor shift in the emissi ons profile from lighter to heavier products is observed.


### Catalytic Reformer Energy Consumption The catalytic reformer energy intensity reporte d range is wide (130 MB tu/bbl), representing various technologies and severity of operations. For the sensitivit y analysis presented here, the range evaluated (223 to 283 MBtu HHV per barrel of throughput versus the study value of 253) results in only a minor shift in the emissions profiles. As with the hydrogen production associated with the catalytic reformer, the relationship is no t linear due to a shifting of GHG emissions between the hydrogen and reformate.


### Hydrotreater Energy Consumption EIA provides volumetric throughput ca pacity data on a variety of hydrotreating and hydrocracker subcategories. Energetics (2007) reports averag e energy intensities for the broad categories of hydrotreating and hydrocracking an d the average values are app lied across the board to all subcategories. However, energy requirements will vary between these subcategories based on the quantity and type of sulfur in the feed, density of the feed, and product specifications. This sensitivity analysis varies the energy intensities for the subcategories as shown in Table 8-1 to attempt to simulate such variability. The result is a small decrease in GHG emissions for jet fuel, a small increase for diesel, and an insignificant de crease for gasoline. This shift is expected as jet fuel is generally made from a lighter, lower su lfur cut of the crude oil and generally has a less stringent sulfur specifi cation, as compared to gasoline and diesel.
Table 8-1. Adjustments to Hydrotreating Subcategory Energy Consumption Utilized in Sensitivity Analysis

Study Value Sensitivity Analysis

Value Hydrotreating Subcategory
Thousand Btu per barrel Distillate Hydrocracking 107 85 Gas Oil Hydrocracking 107 115 Residual Hydrocracking 107 130 Naphtha/Reformer Feed Hydrotreating 59.0 45 Gasoline Hydrotreating 59.0 56.5 Heavy Gas Oil Hydrotreating 59.0 75 Kerosene Hydrotreating 59.0 45 Diesel Fuel Hydrotreating 59.0 70 Other Distillate Hydrotreating 59.0 60 Residual Fuel Oil Hydrotreating 59.0 75 Other Hydrotreating 59.0 60

### 134 8.3.2.4 Contribution of Unit Op erations to Product Categories An API/NPRA 1996 refinery survey was the prim ary source used to determine the contribution of each of the process units to the product categor ies (API 1997). Adjustments were made to the reported values to account for changes in feedstock quality, environmental emissions requirements, product quality/slate, and refinery operations. That report did not c onsider all unit operations and thus estimates were required in some cases.


### Catalytic Cracking Contribution to Product Categories The API/NPRA refinery study provided the basis for assigning catalytic cracking operational throughput to the final product slate. This assi gnment also impacts the distribution of energy usage associated with the vac uum distillation column. These two unit operations combined contribute to 27% of the modeled energy consum ption. The sensitivity analysis shows that simply shifting the contribution to gasoline be tween 56% and 64% (study value of 60%) results in one of the more significant changes to the ga soline and diesel emissions profiles. The overall impact on the well-to-tank GHG emissions profiles is around 2%.


### Gas Oil Hydrocracking Contribu tion to Product Categories Allocation of hydrocracking operatio ns between final products is not ed as a data gap in this analysis. For this sensitivity analysis, the allocation of gas oil hydr ocracking, which is the greatest subcategory of hydrocrack ing, was varied between gasolin e and diesel. The baseline values of 50% gasoline/40% di esel were varied to 70%/20% and 30%/60%. The resulting change in GHG emissions for gasoline and diesel is less than 2% from the base value. There is no effect on jet fuel.


### 8.3.3 Refining Profile for Imported Products The U.S. refining profile for each transportation fuel was used as a surrogate for the foreign refining profiles because of the lack of publically available data that meets the transparency and detail required for this study. Other studies examined showed re sults that ranged from 60% of this study value for diesel fuel to 95% of this study value for gasoline and from 48% to 125% for diesel. While some of this variability is due to system boundaries and differences in allocation of hydrogen, a portion may also be due to the fu els used and technologies employed at foreign refineries. All profiles (gasoline, di esel and jet fuel) for foreign refineri es are varied from 65% to 130% to characterize the influence of this paramete r on the well-to-tank GHG emissions profile. Variation of this parameter ha s a greater influence on the overall GHG profile for gasoline than for jet fuel or diesel. This is due to the fact that gasoline has the highest import fraction of the three fuels. However, the impact to the gasoli ne well-to-tank GHG emissions profile is less than 3% and the impact on the well-to-wheels GHG emissions profile is less than 1%.

### 135 Figure 8-7. Sensitivity Analysis of Life Cycle Stage #3 Activities on the Well-to-Tank GHG Emissions Profile for Conventional Gasoline Consumed in the U.S. in 2005

18 19 20 21 22 Refining Profile for Imported Products Gas Oil Hydrocracking Contribution to Products Catalytic Cracking Contribution to Products Hydrotreating Energy Consumption Catalytic Reformer Energy Consumption Delayed Coker Energy Consumption Vacuum Distillation Energy Consumption

Vacuum Distillation Capacity Utilization Hydrotreating Capacity Utilization Hydrocracker Hydrogen Consumption Catalytic Reformer Hydrogen Production Flaring/Venting/Fugitive at Refinery Hydrogen Plant Capacity Utilization Off-Site Hydrogen Production Hydrogen Plant Feed Input Electricity Profile for Refineries Still Gas Emissions Factors

Well-to-Tank GHG Emissions in kg CO 2 E per MMBtu LHV of Conventional Gasoline Consumed in the U.S. in 2005 Equal to pentanes plus Equal to LP G

Baseline Value 375 Btu HHV/ scf hydrogen 325 Btu HHV / scf hydrogen

125% of study value 80% of study value

90% capacity utilization 80% capacit y utilization
300% of study flaring value 25% of study venting / fugitive value

800 scf hydrogen/ bbl throughput 1,200 scf hydrogen / bbl throughput

150% of study value 80% of study value

85% capacit y utilization

50 MBtu HHV/ bbl throughput 115 MBtu HHV / bbl throughput

115 MBtu HHV/ bbl throughput 175 MBtu HHV / bbl throughput

283 MBtu HHV/ bbl throughput 223 MBtu HHV / bbl throughput 90% capacity utilization 80% capacit y utilization

A djusted b y subcategories

64%/15%/1% gasoline/diesel/jet fuel 56%/22%/2 % gasoline/diesel/jet fuel

70%/20% gasoline/diesel 30%/60 % gasoline/diesel Same for subcategories (study assumption) 80% capacity utilization (study value)

130% of study value 65% of study value 115% of study value 90% of study value

### 136 Figure 8-8. Sensitivity Analysis of Life Cycle Stage #3 Activities on the Well-to-Tank GHG Emissions Profile for Conventional Diesel Consumed in the U.S. in 2005

16.5 17.5 18.5 19.5 20.5 Refining Profile for Imported Products Gas Oil Hydrocracking Contribution to Products Catalytic Cracking Contribution to Products Hydrotreating Energy Consumption Catalytic Reformer Energy Consumption Delayed Coker Energy Consumption Vacuum Distillation Energy Consumption

Vacuum Distillation Capacity Utilization Hydrotreating Capacity Utilization Hydrocracker Hydrogen Consumption Catalytic Reformer Hydrogen Production Flaring/Venting/Fugitive at Refinery Hydrogen Plant Capacity Utilization Off-Site Hydrogen Production Hydrogen Plant Feed Input Electricity Profile for Refineries Still Gas Emissions Factors

Well-to-Tank GHG Emissions in kg CO 2 E per MMBtu LHV of Conventional Diesel Fuel Consumed in the U.S. in 2005 Baseline Value Equal to pentanes plus Equal to LP G

375 Btu HHV/ scf hydrogen 325 Btu HHV / scf hydrogen

125% of study value 80% of study value

90% capacity utilization 80% capacit y utilization 300% of study flaring value 25% of study venting / fugitive value
800 scf hydrogen / bbl throughput 1,200 scf hydrogen/ bbl throughput

150% of study value 80% of study value

85% capacity utilization

50 MBtu HHV/ bbl throughput 115 MBtu HHV / bbl throughput

175 MBtu HHV/ bbl throughput 115 MBtu HHV / bbl throughput
223 MBtu HHV/ bbl throughput 283 MBtu HHV / bbl throughput 90% capacity utilization 80% capacit y utilization

Adjusted by subcategories

64%/15%/1 % gasoline/diesel/jet fuel 56%/22%/2% gasoline/diesel/jet fuel

70%/20 % gasoline/diesel 30%/60% gasoline/diesel Same for subcategories (study assumption) 80% capacity utilization (study value)

130% of study value 65% of study value 115% of study value

90% of study value

### 137 Figure 8-9. Sensitivity Analysis of Life Cycle Stage #3 Activities on the Well-to-Tank GHG Emissions Profile for Kerosene-Based Jet Fuel Consumed in the U.S. in 2005

13.5 14.5 15.5 16.5 17.5 Refining Profile for Imported Products Gas Oil Hydrocracking Contribution to Products Catalytic Cracking Contribution to Products Hydrotreating Energy Consumption Catalytic Reformer Energy Consumption Delayed Coker Energy Consumption Vacuum Distillation Energy Consumption

Vacuum Distillation Capacity Utilization Hydrotreating Capacity Utilization Hydrocracker Hydrogen Consumption Catalytic Reformer Hydrogen Production Flaring/Venting/Fugitive at Refinery Hydrogen Plant Capacity Utilization Off-Site Hydrogen Production Hydrogen Plant Feed Input Electricity Profile for Refineries Still Gas Emissions Factors

Well-to-Tank GHG Emissions in kg CO 2 E per MMBtu LHV of Kerosene-Based Jet Fuel Consumed in the U.S. in 2005 Baseline Value Equal to pentanes plus Equal to LP G

375 Btu HHV/ scf hydrogen 325 Btu HHV / scf hydrogen

125% of study value 80% of study value

90% capacity utilization 80% capacit y utilization 300% of study flaring value 25% of study venting / fugitive value
800 scf hydrogen / bbl throughput 1,200 scf hydrogen/ bbl throughput

150% of study value 80% of study value

85% capacit y utilization

50 MBtu HHV/ bbl throughput 115 MBtu HHV / bbl throughput

175 MBtu HHV / bbl throughput 115 MBtu HHV/ bbl throughput

223 MBtu HHV/ bbl throughput 283 MBtu HHV / bbl throughput 90% capacity utilization 80% capacit y utilization

A

djusted b y subcategories

64%/15%/1 % gasoline/diesel/jet fuel 56%/22%/2% gasoline/diesel/jet fuel

No change to jet fuel Same for subcategories (study assumption) 80% capacity utilization (study value)

130% of study value 65% of study value 115% of study value 90% of study value

### 138 

## 8.4 Life Cycle Stage #4
LC Stage #4 consists of activities to transpor t domestically-produced and imported conventional gasoline, conventional diesel, and kerosene-based jet fuel to and within the U.S. and subsequent refueling operations. Modeling of this particular life cycle stage required that multiple simplifying assumptions be made. These assumpti ons are not expected to have a significant impact on the overall GHG emissions profiles becau se this profile only contributes 4.8-6.6% to the total well-to-tank profiles. Figure 8-10 thru Figure 8-12 show the results of the sensitivity analysis for LC Stage #4 activities for each liquid product of interest: conventional motor gasoline, conventional diesel fuel, and kerosene-based jet fuel. The figures show the variability in the well-to-tank GHG emissions profiles for several factors. The base line value is represented by the dotted line.


### Product Water Carrier Energy Intensity The product water carrier energy in tensity was varied based on a survey of tankers conducted as part of this study for transport of imported gaso line, diesel, and jet fuel. For this sensitivity analysis, the petroleum product tanker energy in tensity was varied from 7.4 to 10.9 Btu/bblnautical mile (study value of 10 Btu/bbl-nautical mile). The resu lting variability in the well-totank GHG emissions profile is minimal for all prof iles, with less of an impact on the profiles which have a smaller fraction of imported products (diesel).



### Product Water Carrier Travel Distance Precise estimates of port-to- port travel distance were dete rmined for petroleum products imported from Canada and the Virgin Islands while a study assumption of 5,000 nautical miles was used for all other imports. Varying all wa terborne travel distan ces between 75% and 140% of the study values results in a minor shift in the GHG emissions profile for gasoline, and an insignificant change to the di esel and jet fuel profiles.


### Total Products Transported Domestically Based on availability of data on transport mode s and volumes of petroleum products transported domestically, it was assumed th at all petroleum products moved the same distance and by the same mix of modes of transporta tion. Obviously, this is not going to be the case since solids— like coke—will not be transported via pipeline. Petroleum product additives—such as oxygenates—will also be included in this transpor t estimate, but it is unknown to what extent. Volumes of gasoline, diesel, and kerosene-based jet fuel produced at U.S. refineries and the imported products of interest account for 70% of the study value used for total products transported domestically. The sensitivity anal ysis shows the impact of using 80% of the study value to simulate a shift toward s the transportation fuels covered in this study. The impact on all profiles is minor.



### Product Loss Factors Varying all product loss factors from 50% to 200% of the base valu e results in a minor shift in the gasoline profile, and essentiall y no change in the diesel an d jet fuel profiles due to the relative volatility of the products. While these loss factors are associated with activities in LC Stage #4, they impact the results in stages #1, #2, and #3 as well.

### 139 Figure 8-10. Sensitivity Analysis of Life Cycle Stage #4 Activities on the Well-to-Tank GHG Emissions Profile for Conventional Gasoline Consumed in the U.S. in 2005

18 19 20 21 22 Product Transport Loss Factors Total Products Transported Domestically Product Vessel Transport Distance Product Vessel Energy Intensity

Well-to-Tank GHG Emissions in kg CO 2 E per MMBtu LHV of Conventional Gasoline Consumed in the U.S. in 2005 75% of study value 140% of study value

80% of study value 10.9 Btu / bbl-mile 7.4 Btu / bbl-mile

50% of study value 200% of study value Baseline Value

Figure 8-11. Sensitivity Analysis of Life Cycle Stage #4 Activities on the Well-to-Tank GHG Emissions Profile for Conventional Diesel Consumed in the U.S. in 2005

16.5 17.5 18.5 19.5 20.5 Product Transport Loss Factors Total Products Transported Domestically Product Vessel Transport Distance Product Vessel Energy Intensity

Well-to-Tank GHG Emissions in kg CO 2 E per MMBtu LHV of Conventional Diesel Fuel Consumed in the U.S. in 2005 Baseline Value 75% of study value 140% of study value

80% of study value 10.9 Btu / bbl-mile 7.4 Btu / bbl-mile

50% of study value 200% of study value

### 140 Figure 8-12. Sensitivity Analysis of Life Cycle Stage #4 Activities on the Well-to-Tank

GHG Emissions Profile for Kerosene-Based Jet Fuel Consumed in the U.S. in 2005

13.5 14.5 15.5 16.5 17.5 Product Transport Loss Factors Total Products Transported Domestically Product Vessel Transport Distance Product Vessel Energy Intensity

Well-to-Tank GHG Emissions in kg CO 2 E per MMBtu LHV of Kerosene-Based Jet Fuel Consumed in the U.S. in 2005 Baseline Value 75% of study value 140% of study value

80% of study value 10.9 Btu / bbl-mile 7.4 Btu / bbl-mile

50% of study value 200% of study value



## 8.5 Life Cycle Stage #5
The vehicle emissions for conventional gasoline a nd conventional diesel are representative of the average fleet of passenger car vehicles for 2005. This data was obtained from EPA and was extracted from the MOVES model (EPA 2008).
GHG emissions associated with the combustion of kerosene-type jet fuel are modeled based on average jet aircraft operation. The profile is based on the FAA and IPCC methodology for estimating GHG emissions from aircraft. The CO 2 

### emissions value used in this study is the same value used by the FAA and EPA to calculate an nual GHG emissions from aircraft operations in the United States. Although it is recognized that improvements and/or adjustments to the vehicle and aircraft use profile will significantly impact the total life cycle GHG results (emissions from the operation of the vehicle and combustion of the fuel account fo r approximately 80% of the total life cycle GHG emissions), sensitivity analysis was not con ducted on these factors. This limitation should instead be managed by ensuring consistent and co mparable vehicle use profiles are applied when evaluating alternative tran sportation fuel options.


## 8.6 Data Quality and Sensit ivity Analysis Summary
Analysis of the data quality and sensitivity studi es on parameters in each life cycle stage show that while there are many factors of uncertain ty, no single variable sh ifts the well-to-tank GHG emissions profile by more than ±4% for each of the three transportation fuels modeled. Holding the use profile static, this translates to less than ±1% variance in the well-to-wheels GHG emissions profiles.

### 141 

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### Emissions . Office of Transportation and Air Qu ality (OTAQ) web-page. www.epa.gov/otaq/climate/420f05001.htm (accessed August 14, 2007) EPA 2007c U.S. Environmental Protection Agency. Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990 – 2005 . Washington, D.C. April 2007. EPA 2008 U.S. Environmental Protection Agency; 2005 National Average Vehicle Emissions Profile for Gasoline and Diesel Powered On-road Vehicle Emissions ; Developed by U.S. EPA, Office of Transportation and Air Quality for NETL Request for Data from MOVES model; Email transmittal dated November 6, 2008 from Ari Kahan, EPA/OTAQ to Timothy J. Skone, DOE/NETL. EUCAR 2007 EUCAR (the Eur opean Council for Automotive R&D), CONCAWE (the oil companies’ European association for environment, health and safety in refining and distribution) a nd JRC/IES. “Well-to-Wheels analysis of future

### 144 automotive fuels and powertrains in the European context: WELL-TOTANK Report” 2007. http://ies.jrc.ec.europa.eu/ our-activities/support-to-eupolicies/well-to-wheels-analysis/WTW.html (accessed September 2008)
FAA 1997 U.S. Federal Aviation Administratio n. Air Quality Procedures For Civilian Airports & Air Force Bases. April 1997. http://www.faa.gov/regulations%5Fpo licies/policy%5Fgui dance/envir%5Fpol icy/airquality%5Fhandbook/ Farrell 2007 Farrell, Alexander E, and Sperling, Daniel. A Low-Carbon Fuel Standard for California, Part 1: Technical Analysis . Institute of Transportation Studies, University of California, Davis. Re search Report UCD-ITS-RR-07-07. Davis, CA. May 2007. http://pubs.its.ucdavis.edu/ publication_detail.php?id=1082 FW 2001 Foster Wheeler, Hydrogen Plants for the New Millenium, Middle East PETROTECH 2001 Conference and Exhibition, 29-31 October 2001. http://www.fwc.com/publicati ons/tech_papers/files/WARD1109.pdf (accessed March 7, 2008)
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. Springer, 2006, pp. 217-238. HT 2008 Haldor Topsøe brochure. Accessed on 3/5/2008 at:http://www.topsoe.com/site.nsf/vALLWEBDOCID/KVOO5PGFBN/$file/Hydrogen-UK_HTCR.pdf IEA 2008 International Energy Agency (IEA) Statistics: Oil. 2008. http://www.iea.org/Textbase/sta ts/prodresult.asp?PRODUCT=Oil IHI 2008a IHI Marine United. 280,000 MT DW Double Hull VLCC Formosapetro Discovery. 2008. http://www.ihi.co.jp/ihimu/images/seihin/pl03-1.pdf

### 145 IHI 2008b IHI Marine United. 300,000 MT DW Double Hull VLCC Sky Wing. 2008. http://www.ihi.co.jp/ihimu /images/seihin/pl04_1.pdf IHI 2008c IHI Marine United. 300, 500 MTDW Double Hull VLCC. 2008. http://www.ihi.co.jp/ihimu /images/seihin/pl05_1.pdf Imperial Oil 2006 Imperial Oil Ltd. Securities and Exchange Commission (SEC) Filing 8-K, 2006. IPCC 1996 Intergovernmental Panel on Climate Change. Climate Change 1995: The Science of Climate Change. Contributi on of Working Group I to the Second Assessment Report of the Intergo vernmental Panel on Climate Change [Houghton, J.T.,Meira Filho, Callander, B.A., Harris, H., Kattenberg, A., and Maskell, K. (eds)]. Cambridge Univer sity Press, Cambridge, United Kingdom and New York, NY, USA IPCC 2001 Intergovernmental Panel on Climate Change. Climate Change 2001: The Scientific Basis. Contribution of Wo rking Group I to the Third Assessment Report of the Inte rgovernmental Pane l on Climate Change [Houghton, J.T.,Y. Ding, D.J. Griggs, M. Noguer, P.J. van der Linden, X. Dai, K. Maskell, and C.A. Johnson (eds.)]. Cambridge University Press, Cambridge, United Kingdom and New York, NY, USA, 881pp. IPCC 2007 Forster, P., V. Ramaswamy, P. Arta xo, T. Berntsen, R. Betts, D.W. Fahey, J. Haywood, J. Lean, D.C. Lowe, G. Myhre, J. Nganga, R. Prinn, G. Raga, M. Schulz and R. Van Dorland, 2007: Change s in Atmospheric Constituents and in Radiative Forcing. In: Climate Change 2007: The Physical Science Basis. Contribution of Working Group I to the Fourth A ssessment Report of the Intergovernmental Panel on Climate Change [Solomon, S., D. Qin, M. Manning, Z. Chen, M. Marquis, K.B. Averyt, M.Tignor and H.L. Miller (eds.)]. Cambridge University Pre ss, Cambridge, United Kingdom and New York, NY, USA, Table 2.14. IPIECA 2003 International Petroleum Industry Environmental Conservation Association (IPIECA), American Petroleum Institute (API), International Association of Oil and Gas Producers (OGP), and Battelle. Petroleum Industry Guidelines for Reporting Greenhouse Gas Emissions. December 2003. http://www.ipieca.org/activ ities/climate_change/dow nloads/publications/ghg_ guidelines.pdf
ISO 2006 International St andards Organization. ISO 14040:2006 Environmental Management – Life Cycle Assessment – Principals and Framework . Revises ISO 14040:1997. Developed by TC 207 Environmental Management. Geneva, Switzerland. June 30, 2006. Jechura 2008 Jechura, John. Hydrocracking & Hydrotreating, 2008. http://home.comcast.net/~jjechura/CHEN409/ Lee 2007 Lee, John. Course Notes: Petroleum Engineering 689. Special Topics in Unconventional Resource Reserves Lect ure 1A. Texas A&M University - Spring 2007. Accessed 6/4/2008 at:

### 146 http://www.pe.tamu.edu/DL_Program/Sample_Courses/689- Lee/PowerPoint/689_Lecture_1A.pdf Lewis 1997 Lewis, C. A. Fuel and Energy Production Emission Factors. MEET Project: Methodologies for Estimating Air Pollutant Emissions from Transport, 1997. Maples 1993 Maples, Robert. Petroleum Refinery Process Economics. PennWell Books, 1993. McCann 1999 McCann, T., and Magee, P. 1999. Crude Oil Greenhouse Gas Life Cycle Analysis Helps Assign Values for CO 2 

### Emissions Trading . Oil & Gas Journal. February 1999. Vol. 97. Iss. 8. pp. 38-43. Meyers 2004 Meyers, Robert A. Ha ndbook of Petroleum Refining Pr ocesses; Third Edition Copyright © 2004, The McGraw-Hill Companies, Inc. ISBN 0-07-139109-6 NEB 1999 Canadian National Energy Board (NEB), Canadian Energy - Supply and Demand to 2025 , Appendix 10, 1999. http://www.neb-one.gc.ca/clfnsi/rnrgynfmtn/nrgyrprt/spplydm nd/spplynddmndt20251999/spplydmndppndc 1999-eng.pdf NEB 2006 Canadian National Energy Board (N EB), Canada’s Oil Sands Opportunities and Challenges to 2015: An Update, An Energy Market Assessment, June2006. http://www.neb.gc.ca/clfnsi/rnrgynfmtn/nrgyrprt/lsnd/pprtnt sndchllngs20152006/pprtntsndchllngs2015 2006-eng.pdf Nguyen 1999 Nguyen, M. Source Inventory Category #67-74 Filling Stations – Storage Tanks . California Air Resources Board. Sacramento, California. 1999. www.arb.ca.gov/ei/areasrc/dis trictmeth/BayArea/C67.pdf (accessed August 1, 2007) NREL 2001 Spath, Pamela and Mann, Margaret. Life Cycle Assessment of Hydrogen Production via Natural Gas Steam Reforming. NREL/TP-570-27637, 2001. O&GJ 2005 Stell, Jeannie (ed.) Oil & Gas J ournal. 2005 Worldwide Refining Survey, Vol. 103, No. 47. December 19, 2005. Oregon DEQ 2004 Oregon DEQ. U.S. EPA. "Life Cycle Inventory of Packaging Options for Shipment of Retail Mail-Order Soft Goods: Appendix A - Energy Requirements and Environmental Em issions for Fuel Consumption" report prepared by Franklin Associates, Inc. 2004. ORNL 2007 Oak Ridge National Laboratory (ORNL). Transpor tation Energy Data Book: Edition 26. ORNL-6978, 2007. http://cta.ornl.gov/data/download26.shtml (accessed June 10, 2008). Parkash 2003 Parkash, Surinder. Refining Processes Handbook . Elsevier, 2003. SCAQMD 2008 South Coast Air Qu ality Management District. “Flares: Emission Data and Minimization Plans.” South Coast Ai r Quality Management District. http://www.aqmd.gov/comply/1118/emissiondata.htm (accessed June 1, 2008)

### 147 Sheehan 1998 Sheehan, J., et. al. Life Cycle Inventory of Biod iesel and Petroleum Diesel for Use in an Urban Bus: Final Report . NREL/SR-580-24089 UC Category 1503. U.S. Department of Energy, National Renewable Energy Laboratory. Golden, CO. May 1998. www.nrel.gov/docs/legosti/fy98/24089.pdf StatCan 2008 Statistics Canada. The Supply a nd Disposition of Refined Petroleum Products in Canada. Catalogue no. 45-004-X. 2008. http://www.statcan.ca/bsolc/ english/bsolc?catno=45-004-X Syncrude 2006 Syncrude Canada Ltd. 2005 Sustainability Report. http://sustainability.syncrude.ca/sustai nability2005/environm ent_health_safety /air_quality.shtml Tedesco 2004 Tedesco, Steven. Coalbed Meth ane Potential and Activity of the Western Interior Basin. API Search and Di scovery Article #10059 (2004). Published by: AAPG/Datapages, Inc. , 1444 South Boulder, Tulsa, OK, 74119, USA. Accessed 6/4/2008 at: http://www.searchanddiscovery.net/doc uments/2004/tedesco02/images/tedesc o2.pdf UOP 2003 UOP, Platforming Technology Advances: CycleX System for Increased Hydrogen Production from a Fixed-Bed Reforming Unit
, http://www.uop.com/objects/ UOP%20CycleX%20AM-03-93.pdf (accessed March 7, 2008) USDOC 2004 U.S. Departme nt of Commerce (DOC). Bituminous Coal Underground Mining: 2002 . EC02-211-212112(RV), December 2004.
VesselTrax 2007 VesselTrax web-site. http://vesseltrax.com/crude_oil_imports.html (accessed January 28, 2008) Wang 2004 Wang, Michael, Lee, Hanjie, and Mo lburg, John. Allocation of Energy Use in Petroleum Refineries to Petroleum Pr oducts: Implication for Life-Cycle Energy Use and Emission Inventory of Petroleum Transportation Fuels

. International Journal of LCA, 9 (1) 34-44. 2004. Wang 2008 Wang, M. Greenhouse Gases, Regulated Emissions, and Energy Use in Transportation (GREET) Model, Version 1.8b . DOE, Argonne National Laboratory. Ann Arbor, Michigan. 2008. www.transportation.anl.gov/software/GREET Wild, et.al. 2001 Wild, O., M.J. Prather, and H. Akimoto. Indirect long-term global radiative cooling from NOx emissions

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### A - 1 

## Appendix A

Overview of Domestically-Produced and Imported Finished Transportation Fuels
Table A-1 shows the U.S. production, exports and imports of finished motor gasoline and motor gasoline blending components, finished conventi onal diesel (<500 ppm sulfur), and finished kerosene-type jet fuel for the year 2005. The resu lting weighting factors in Table A-2 are used in combination with the modeling of domestically-p roduced and imported finished fuels described in Sections 2.0 to 5.0 to develop a composite profile for the tran sportation fuels being consumed in the U.S. in 2005.
Table A-1. U.S. Production, Exports and Imports of Transportation Fuels for 2005 (EIA 2008)

Production in U.S. Refineries Imported to U.S. Exported from U.S. Estimated Consumption Petroleum Product

Barrels per Day Conventional Gasoline* 7,794, 233 1,106,712 199,449 8,701,496 Conventional Diesel** 2,932, 578 157,164 39,299 3,050,444 Kerosene-Type Jet Fuel 1,545,825 190,049 52,611 1,683,263 * Gasoline includes: motor gas, conventional , other; motor gas, conventional—blended with

alcohol; motor gas, reformulated—blended with ether; and motor gas blending components (RBOB, CBOB, GTAB, and all other) ** Includes distillate with 500 ppm or less sulfur

Table A-2. Weighting Factors for U.S. Refined and Imported Transportation Fuels

Petroleum Product U.S. Refined Weighting

Factor Imports Weighting

Factor Conventional Gasoline 87.3% 12.7% Conventional Diesel 94.8% 5.2% Kerosene-Type Jet Fuel 88.7% 11.3%



### The exporting countries and volumes of transpor tation fuels imported by the U.S. as reported by EIA for the year 2005 are shown in Table A-3 thru Table A-5. Imports reported by EIA destined for Puerto Rico and the Virgin Islands are excluded.

### A - 2 Table A-3. Imports of Finished Motor Gasoline and Motor Gasoline Blending Components to the U.S. in 2005 (EIA 2008)

Exporting Country Volume Imported

(Mbbl)
Algeria 899 Angola 147 Argentina 8,796 Aruba 326 Australia 40 Bahamas, The 529 Belgium 10,790 Brazil 1,668 Bulgaria 541 Canada 63,669 Chile 2,877 China, Peoples Rep 831 Colombia 538 Congo (Brazzaville) 127 Denmark 854 Ecuador 985 Egypt 2,410 Estonia 9,363 Finland 5,242 France 14,316 Gabon 24 Georgia 100 Germany 10,279 Ghana 540 India 3,875 Indonesia 108 Ireland 1,031 Italy 12,514 Japan 906 Korea, South 1,788 Kuwait 50 Latvia 6,863 Lithuania 6,952 Malaysia 618 Martinique 255 Mexico 588 Netherlands 42,316 Netherlands Antilles 2,060

### A - 3 Exporting Country Volume Imported

(Mbbl)
Nigeria 5,609 Norway 5,372 Peru 1,171 Poland 32 Portugal 3,392 Qatar 40 Romania 1,057 Russia 24,913 Saudi Arabia 6,738 Singapore 863 Spain 8,893 Sweden 5,162 Taiwan 1,402 Thailand 69 Trinidad & Tobago 3,283 Turkey 4,228 Turkmenistan 198 United Kingdom 41,653 Uruguay 1,165 Venezuela 30,567 Virgin Islands, U.S. 42,328 Total Imports 403,950

### A - 4 Table A-4. Imports of Finished Conventional Diesel Fuel (<500 ppm Sulfur) to the U.S. in 2005 (EIA 2008)

Exporting Country Volume Imported

(Mbbl)
Algeria 299 Aruba 4,646 Belgium 473 Canada 21,429 Denmark 757 Estonia 433 France 142 Germany 279 Indonesia 682 Japan 631 Kazakhstan 206 Korea, South 1,658 Kuwait 231 Latvia 639 Lithuania 135 Netherlands 3,022 Netherlands Antilles 116 Norway 260 Philippines 40 Russia 36 Singapore 746 Sweden 437 Taiwan 529 United Kingdom 297 Venezuela 1,363 Virgin Islands, U.S. 17,879 Total Imports 56,581

### A - 5 Table A-5. Imports of Kerosene-Type Jet Fuel to the U.S. in 2005 (EIA 2008)

Exporting Country Volume Imported

(Mbbl)
Algeria 532 Argentina 179 Aruba 2,971 Belgium 287 Canada 4,164 China, Peoples Rep 103 Colombia 431 France 850 India 1,546 Iraq 716 Japan 1,221 Korea, South 15,199 Kuwait 2,618 Malaysia 200 Mexico 1,890 Netherlands 573 Netherlands Antilles 164 Qatar 25 Russia 325 Saudi Arabia 2,947 Singapore 4,652 Taiwan 4,271 Trinidad & Tobago 920 United Kingdom 105 Venezuela 10,894 Virgin Islands, U.S. 11,585 Total Imports 69,368

### A - 6 This page intentionally left blank.

### B - 1 

## Appendix B

Cradle-to-Gate GHG Emissions Invento ry for Electric Power from the U.S. (Average) Grid Mix

Certain emissions from electric ity generating facilities are trac ked by EPA (EPA 2007a) and are publically available in the Emissions & Generati on 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. Th erefore, GaBi 4 modeli ng data were modified to generate a profile more inclusive of upstr eam and construction emissions not represented within eGRID. A U.S. electric grid mix was generated where the individual electricity source profiles (solar, wind, hydro, etc.) were aggregated into a mix cons istent with the 2004 U.S. electricity source mix. Figure B-1 shows the source mix as a perc entage of total U.S. electricity generation.
Figure B-1. Year 2004 Electricity Sources for the Average U.S. Grid Mix

Coal 50.4% Oil 3.0%

Gas 17.5%

Other Fossil

0.5%

Biomass

1.4%

Hydro 6.6% Nuclear 20.1% Wind 0.3% Solar 0.0% Geothermal 0.3%



### A representation of the GaBi 4 process plan for th e U.S. electricity mix is shown in Figure B-2. The process plan incorporates pow er inputs derived from the elec tricity generation mix discussed previously and includes 98.2 percen t of the total U.S. energy mix. Inputs are expressed in MegaJoules (MJ) and are net calorific values. The process plan assumes: 1) U.S. “coal generation” is

8 U.S. EPA released eGRID2007 Version 1.0 in Septem ber 2008 following the completion of this analysis. eGRID2007 Version 1.0 contains CO 2 , CH 4 , and N 2 O emissions for 2005. The impact was analyzed and determined to have negligible effect on the total life cycle GWP results of this study.

### B - 2 allocated 100 percent to hard coal. 2) U.S. “oth er fossil generation” (tires, chemicals, batteries, etc.) and “unknown/purchased generati on” are allocated 100 percent to lignite (s urrogate profile) and 3) No cradle to gate profile is current ly available for “biomass/ wood generation”, “solar generation”, and “geothermal generation.” The resu lting GHG profile generated for the U.S. grid mix is shown in Table B-1.
Figure B-2. 2004 U.S. Electric Grid Power Mix

Table B-1. Greenhouse Gas Emissions from 2004 U.S. Electricity Grid Mix

Source CO 2 Emissions (kg/kWh) CH 4 Emissions (kg/kWh) N 2 O Emissions (kg/kWh)
2004 U.S. Average Electricity Grid Mix 0.739 8.58E-04 9.59E-06C - 1Appendix CCradle-to-Gate GHG Emissions Profile forFuels Produced in Domestic RefineriesThe cradle-to-gate environmental profile (LC Stages #1-3) for production of refineryproducts is also the upstream emissions profilefor the petroleum products that are input to the refinery as afuel. However, the upstream emissions profile for fuels produced andconsumed in the refinery are also part of the LC Stage #3 profilerequiring an iterative solutionto determine this profile.Table C-1 shows the volume consumed and the product category for each refinery-produced fuel.Table C-1. Product Categories Corresponding to Refinery Produced FuelsRefinery Fuel2005 FuelConsumptionby U.S.Refineries(bpd)Product Categoryfor Refinery FuelLPG 11,438 Light EndsDistillate 2,068 DieselResidual Fuel Oil 6,047 Residual Fuel OilStill Gas 652,701 Light EndsPetroleum Coke 245,622 CokeOther Products 14,600 Average of AllTable C-2 shows the preliminary cradle-to-gate profile (LC Stage #1-3)excluding the upstream profilefor refinery-produced fuels.This profile is on a per-barrel-refined basis does not include loss factors associatedwith product transport, but does includelossesassociated with feedstock transport.C - 2Table C-2. “Cradle-to-Gate” GHG Emissions Profile for Domestic Refineries Excluding Upstream Profile forRefinery-Produced FuelsEmissionsUnitsGasolineDieselKerosene&Kerosenetype JetFuelResidualFuel OilCokeLightEndsHeavyEndskg CO2/day581,279,653312,441,60096,975,96440,730,26159,063,56498,471,25870,376,749CO2kg CO2/bbl refined74.479.060.264.970.758.593.4kg CH4/day3,958,5512,023,864803,809314,617418,700834,008388,544CH4kg CH4/bbl refined0.510.510.500.500.500.500.52kg N2O/day11,6126,0202,0018311,2272,1071,381N2Okg N2O/bbl refined0.001490.001520.001240.001320.001470.001250.00183For example, as a starting point, theupstream profile for still gas is 58.5 kg CO2per barrel (corresponding to light ends). The result ofmultiplying this factor by the consumption ofstill gas at the refinery is 38 million kg CO2per day and the cradle-to-gate emissionsprofile should be increased bythis amount. An iterative solution to calculate the total cradle-to-gate refinery profile follows. Theresulting profile for each of the fuels is shown in Table C-3.The emissions associated with production of these species are divvied upto the product slate according to each product category’s energy consumption.Table C-3. GHG Emissions Profile Consistent with Acquisition of Refinery-Produced FuelsFuelCO2(kg/day)CH4(kg/day)N2O (kg/day)LPG 696,439 5,886 15Distillate 171,312 1,122 3Residual Fuel Oil 409,065 3,165 8Still Gas 39,740,582 335,879 850Petroleum Coke 18,267,585 130,326 380Other Products 1,095,456 7,768 22Total60,380,439484,1461,278

### D - 1 

## Appendix D

Petroleum Industry Guidelines for Reporting Greenhouse Gas Emissions
The Petroleum Industry Guidelin es for Reporting Greenhouse Gas Emissions (IPIECA et al. 2003) outlines various tiers for GHG emissions estim ation using data with different levels of detailed information—and hence di fferent levels of precision in the final GHG estimate. Table D-1 shows the different estimation tiers and summarizes the associated emission estimation methodologies. Methodologies outlined in the ta ble refer to detailed calculation procedures presented in the American Petroleum Instit ute’s (API) 2004 Compendium of Greenhouse Gas Emissions Methodologies for the Oil and Gas Industry (API 2004).

### D - 2 Table D-1. GHG Estimation Tiers and Associated Estimate of Uncertainty (IPIECA et al. 2003)

Estimation Tiers Tier C Tier B Tier A +/- 15-30% Uncertainty < 15% Uncertainty +/- 5-10% Uncertainty Source GHG Estimation Approach

CO 2 Thermal input (fuel burnt) estimated based on design rating of plant and hours operated, default fuel factors Thermal input (fuel input) based on metering or energy balances on heaters/boilers, fuel composition obtained from occasional spot sampling Thermal input (fuel input) based on metering or energy balances on heaters/boilers,

fuel composition obtained from frequent spot sampling Combustion

Sources

CH 4 Not considered Not considered Not considered

CO 2 Thermal input (fuel burnt) estimated based on design rating of plant and

hours operated, default coke factor Coke burn rate calculated based on process mass/energy balance and average coke compositionbased on spot samples -ORestimated directly from measured CO and CO 2 concentrations in exhaust (spot samples) and air/oxygen flow rate to regenerator Coke burn rate calculated based on process mass/energy balance and average coke compositionbased on spot samples -ORestimated directly from measured CO and CO 2 concentrations in exhaust (spot samples) and air/oxygen flow rate to regenerator FCC Coke Burn

CH 4 Not considered Not considered Not considered

CO 2 Engineering estimates of gas flared i.e., using API flame length correlation

and default factor for refinery gas Process engineering estimates of flared volume based on known purge rates,

process unit flows to flare and estimates of non-routine flaring based on plant logs. Weighted average flare gas composition based on estimated composition. Flared volume estimated from flare gas meters where available, known purge rates and best process engineering estimates,

average flare gas composition based on spot samples throughout the year

adjusted if significant nonroutine flaring. Flaring

CH 4 Not considered Not considered Not considered

CO 2 Process mass balance based on estimated hydrogen production API Compendium “simple” method based on estimated hydrogen make API Compendium “complex” method i.e. process mass balance based on known

reformer feed rate and composition Hydrogen Plant (process)

CH 4 Not considered Not considered Not considered (spot check on methane content of CO 2 vent stream)

CO 2 Not considered Process mass balance as in API Compendium using activity data based on best

engineering estimates Process mass balance as in API Compendium using activity data based on best

engineering estimates Other Process Sources

CH 4 Not considered Not considered Not considered CO 2 Not considered Not considered Not considered Process Fugitives CH 4 Not considered Not considered Not considered

### E - 1 

## Appendix E

Nitrous Oxide Emission Factors

Table E-1 lists N 2 

### O emission factors for the various combustion operations encountered in refinery operations. The emission factors were compiled from various so urces and reported in the American Petroleum Institute (API) Compendium of Greenhouse Gas Emissions Methodologies for th e Oil and Gas Industry (API 2004). These factors are both a function of the petroleum species being combusted and the equipment utilized for combustion.

Table E-1. N 2 O Emission Factors for Various Combustion Operations Encountered in Refinery Operations (API 2004)

N 2 O Emission Factor Emission Source Original Units Converted Units Residual Oil-fired Boilers and Heaters 0.53 lb/1000 gal 2.4×10 -7 tonne/gal Distillate Oil-fired Boilers and Heaters 0.26 lb/ 1000 gal 1.2×10 -7 tonne/gal Natural Gas-fired Boilers and Heaters

Controlled 0.64 lb/10 6 scf 2.8×10 -7 tonne/10 6 Btu (HHV)

Uncontrolled 2.2 lb/10 6 scf 9.8×10 -7 tonne/10 6 Btu (HHV) Natural Gas Combustion Turbines
Controlled (SCR) 0.03 lb/10 6 Btu 1.4×10 -5 tonne/10 6 Btu (HHV)

Uncontrolled 0.003 lb/10 6 Btu 1.4×10 -6 tonne/10 6 Btu (HHV) Stationary Gas-fired IC Engines (without catalyst controls)

4-stroke rich burn 0.001 lb/10 6 Btu (HHV) 4.5×10 -7 tonne/10 6 Btu (HHV)

4-stroke lean burn 0.003 lb/10 6 Btu (HHV) 1.4×10 -6 tonne/10 6 Btu (HHV)

2-stroke 0.005 lb/10 6 Btu (HHV) 2.3×10 -6 tonne/10 6 Btu (HHV) Gasoline IC Engines 0.031 g/L (distillate) 1.17×10 -7 tonne/gal

Diesel IC Engines 0.4 g/L 1.51×10 -6 tonne/gal 1.1×10 -5 tonne/10 6 Btu (HHV)

Large Bore Diesel Engine (> 600 hp) 0.08 g/L 3.03×10 -7 tonne/gal 2.2×10 -6 tonne/10 6 Btu (HHV)

### E - 2 This page intentionally left blank.

### F - 1 

## Appendix F

Overview of Allocation Procedures for Petroleum Refining Operations
Allocation of refinery emissions to the various species in the refinery product slate is a controversial part of the petrol eum refining LCA process. It is commonly accepted that gasoline production is a more energy-inte nsive process than diesel pr oduction due to the additional processing steps required to develop optimal gaso line and boutique blends. For example, while all refinery products pass through the atmospheri c distillation column, the catalytic reformer, alkylation unit and isomeriza tion unit predominantly pro cess gasoline precursors. Several allocation methodologies have evolved over time with different allocation mechanisms of varying complexity. These allocation methodol ogies are most broadl y broken into economicbased and process-based allocations.



### Economic-based Allocations Economic-based allocation techniqu es assert that emissions fr om production are allocated to individual products based on product cost (market value). This mechanism assumes capital cost of related process equipment and operating cost (including utilities) are represented in the product selling price for the various cuts of the product slate and thus emissions should be ratioed accordingly. Complex linear programming tec hniques have been developed to allocate CO 2 

### emissions to the various products at an o il refinery using economic factors (Babusiaux 2007). There are many inherent problems that arise when considering produc t pricing to allocate process emissions. First, product pricing is often more a factor of market conditions than actual production cost. The most obvious example of this phenomenon is demonstrated quite remarkably in the petroleum refining business. While gasoline production is more capital and energy intensive than diesel production (excludi ng hydrogen considerations), domestic diesel selling price has been steadily climbing in the pa st 10 years and is often higher than gasoline, as shown in Figure F-1a. When detailed gasoline and diesel pricing data presented by the EIA are analyzed (EIA 2008), it can be concluded that re fining “costs” for diesel have increased to surpass that of gasoline. Figure F-1b shows EIA’s determination of the “refining” contribution to gasoline and diesel prices. Each of these analys es show that while it is generally acknowledged that refining diesel requires less process equipment and utilities , the impact of market-driven aspects on the “cost” of producing diesel and gasoline result in it is being so ld at a higher price than gasoline (thus a higher profit margin). As a result, emissions allocations based on refinery selling prices (without adequate adjustment to account for varying profit margins) will result in higher emissions being allocated to diesel fuels than to gasoline duri ng certain economic cycles.

### F - 2 Figure F-1. Gasoline and Diesel Price (a) and Associated Refining Costs (b) (EIA 2008)

50 100 150 200 250 300 350

Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02 Jan-03 Jan-04 Jan-05 Jan-06 Jan-07Cents Diesel Price
Gasoline Price

0 10 20 30 40 50 60 70 80 90 100

Apr-02 Aug-03 Dec-04 May-06 Sep-07 Gasoline Refining Cost Diesel Refining Cost



### Process-based Allocations: There are many different methodologies for perfor ming process-based allocations. The simplest method is to ratio emissions with product output on a mass, energy, or volumetric basis. This technique, however, does not take into account the fact that many product streams do not pass through certain process units. T hus products that require extens ive processing are allocated the same level of emissions as streams which requir e very little processing. Attempts to divide refinery level emissions into process unit and as sociated emissions are extremely difficult to do and detailed process information is not readily available. It has been suggested by Argonne National Labor atory (ANL) researcher s that a simplified approach be used where each individual unit pr ocess energy use (energy from incoming streams and energy provided directly to the process) be divided among th e products of the unit operation on the basis of mass, energy content, or market value (Wang 2004). However, such approaches consider only unit operation energy consump tion and there is no accounting for hydrogen utilization. The GREET model developed by ANL divides th e total refinery energy consumption among constituents of the product slate according to industry “rule-of -thumb” suggesting that 60% of total refining fuel use is allocated to gasoline, 25% to diesel, and the remaining 15% to other petroleum products (Wang 2008). Many researchers allocate emissions to produc ts based on unit proces s operations and the associated utilities and emissions of that pa rticular unit, without proper accounting of coproducts. One example is the catalytic reforming of naphtha. All utility use has traditionally been allocated to gasoline and adequate accounting of hydrogen by-product disposition is not undertaken. Approximately one half of the total quantity of hydr ogen utilized at a refinery is produced as a by-product of reformer operation (A itani 1996). Discounting this contribution to diesel production (for hydrotreat ing) biases the results and bu rdens gasoline with a larger emissions profile and artificially lowers the dies el emissions profile. This phenomenon is more easily seen in Europe where increased demand for diesel (at the expense of gasoline) has resulted in catalytic reforming units operating at capacit y, not to produce gasoline, but to produce needed hydrogen. Therefore, the additional energy use and associated emissions should no longer be

### F - 3 assigned to gasoline (as would usually be the cas e) and must be allocated to the benefitting distillate fractions (Alireza 2007). Hydrogen is used in refineries primarily for de sulfurization and hydrocra cking processes, with waste (impure) hydrogen being burne d as a fuel. To meet curren t sulfur-level requirements for fuels, practically all finished diesel and gasoline products must be desulfurized during processing. Thus, the utilization of hydrogen mu st be appropriately a llocated to the various product species and their precursors. For exampl e, ten times more hydrogen may be needed to desulfurize diesel than is necessa ry to desulfurize naphtha fed to a catalytic reformer to produce gasoline (Parkash 2003). The integrated and complex nature of modern re fineries precludes simplis tic determinations of energy/utility requirements for any particular uni t operation. All allocatio n mechanisms will be controversial and no mechanism is correct . Thermal inefficiencies are not the same for all unit operations and thus some units will ha ve lower efficiencies than others.


### Study Allocation Technique Allocation of energy (utilities) and hydrogen us age are estimated for the major unit operations undertaken for liquid fuels production at U.S. refi neries using system expansion to the extent possible before allocating unit operation thr oughput to final liquid fuel fractions. Petroleum products output from refineries have been broadly divided into seven different product categories: gasoline, diesel, kero sene and kerosene-type jet fuel, residual fuel oil, coke, “light ends,” and “heavy ends.” The light ends categor y is composed of still gas, liquefied refinery gases (LRG), special naphtha, and petrochemical feedstocks. The hea vy ends category is composed of asphalt and road oil, lubricants, waxes, and miscellaneous. The volumetric capacity of the i ndividual unit operations has been assigned to the seven product fractions described above. The capacity is assigned to the final product fractions based upon the relative contribution of the throughp ut of that operation to the fi nal product category. Rationale for each individual unit operation’s capacity assignments to product categories has been discussed. Fuels-consumed emissions are assigned to the pr oduct fractions based upon the fractional energy usage required to produce these products. The GHG emissions consistent with fuels consumption (minus the quantity attributed to se condary, unrelated producti on activities) is then multiplied by the appropriate energy consumption fraction for each product category. Since it is not possible to accurately ascribe fuel types, combustion equipment and the resulting emissions to the various refinery operations, a composite energy usage/emissions profile was determined for all refining operations. The GHG emissions a ssociated with the fuels consumed are allocated equivalently for each unit of energy consumed. Refinery flaring and methane venting/fugitive emi ssions have been allocated to product fractions based upon the fraction of the total refinery energy usage required for production of each product category. Hydrogen production emissions have been assigned to the product fractions according to each categories’ hydrogen consumption/ production quantities. There is no differentiation between the sources of hydrogen with rega rd to pressure or purity.

### F - 4 Catalytic Reformer Allocation 

### Distribution of the energy associated with the catalytic reformer was discussed in detail in Section 4.2.5.2. System expansion was used to allocate the energy/ resource usage to the hydrogen produced in the catalytic reformer usi ng hydrogen production via SM R as the next best alternative. This results in al l energy for operation of the catal ytic reformer being allocated to the produced hydrogen (as opposed to the reformate) . Figure F-2 shows the change in the LC Stage #3 profile for each fuel and emphasizes that this decision has a significant impact on the allocation of energy and the associated emissions between gasoline, diesel, and jet fuel. If all energy for reformer operation is allocated to th e reformate (gasoline fr action), then the hydrogen is “free.” As a result, the gasoline GHG emissi ons are significantly higher while diesel and jet fuel GHG emissions are lower.

Figure F-2. Impact of Modeling Approach for Catalytic Reformer Allocation on LC Stage #3 GHG Emissions Profile

0 2 4 6 8 10 12 14

100% Catalytic Reformer to Hydrogen (Study Value) 100% Catalytic Reformer Energy to ReformateGHG Emissions(kg CO2E/MMBtu LHV fuel consumed) Conventional Gasoline Conventional Diesel Kerosene-Based Jet Fuel

### G - 1 

## Appendix G

Cradle-to-Gate GHG Emissions Inven tory for Hydrogen Production Via SMR with PSA Purification
Hydrogen plant energy requirements and natural gas consumption were derived from Boyce (2004) on the basis of 1 scf of H 2 

### . It is assumed that hydrogen compression to elevated pressures is performed at the refinery a nd thus associated energy/emissions are included in the refinery energy/fuels consumed total. The hydrogen plant is modeled as a “modern” facility operating by steam methane reforming of natural gas with subsequent hydrogen purification by pressure swing absorption. Natural gas is assumed to have a higher heating value of 1020 Btu/ft 3 

### (API 2004). Average natural gas density is assumed to be 23.8 ft 3 

### per pound (API 2004). Hydrogen plant input and utilities are summarized below in Table G-1 (Boyce 2004) for 1 scf of produced hydrogen.
Table G-1. Hydrogen Plant Input/Utilities on the Basis of 1 scf H 2 Produced

NG Feed (kg) NG Feed (Btu HHV) NG Fuel (kg) NG Fuel (Btu HHV) Electricity (kWh) HP Steam (lb) [Credit] HP Steam (Btu) [Credit] 0.00658 352 0.00262 140 0.00052 0.09 106



### For hydrogen plant operations occurring on site with U.S. petroleum refineries, it is necessary to calculate the refinery energy usag e that is attributable to hydr ogen production. When the natural gas feed requirements are excluded from the above data, the result is a ne t energy requirement of 35.6 Btu HHV per scf of hydrogen. For U.S. petroleu m refineries it was estimated, as discussed in Section 4.2.9.2, that for the portion of electric ity assumed to be produced at the petroleum refinery, electricity losses must be incorporated. This raises th e refinery energy associated with on-site hydrogen plants to 36.5 Btu HHV per scf of hydrogen. For both merchant and captive hydroge n production, process emissions of CO 2 

### from the separation/purification proce ss must be determined. CO 2 

### is produced during the hydrogen production process, as shown in the following equation, and subsequent ly vented to the atmosphere during hydrogen purification. Thus, for every four moles of hydrogen produced, one mole of CO 2 

### is emitted.
C

x 

### H (2x+2) 

### + 2 x 

### H 2 

### O Æ (3x+1)H 2 

### + xCO 2



### Combustion emissions associated with reform er furnace operation were estimated using API emission factors for a natural gas boiler/furnace /heater (API 2004). API emission factors are summarized in Table G-2 for natural gas com bustion in a boiler/furn ace/heater. The N 2 

### O emissions from the boiler are modeled as uncont rolled since the energy requirements listed in Table G-1 do not include selec tive catalytic reduction (SCR).

### G - 2 Table G-2. API Emission Factors for Natural Gas Boiler/Furnace/Heater Operation (API 2004)

GHG Gas API Emission Factor (tonne/MMBtu HHV)

CO 2 0.0531 CH 4 1.0E-06

N 2 O 9.8E-07 (uncontrolled) 2.8E-07 (controlled)



### Using the above information and upstream life cy cle emissions presented in Section 3.0, the following emissions profile was ge nerated for hydrogen production:
Table G-3. Hydrogen Production Emissions and Sources on the Basis of 1 scf H 2 Produced

(kg) NG Upstream

Profile H 2 Process Emissions (CO 2 ) H 2 Plant Fuel Combustion

Emissions Electricity Emissions Steam Credit Total

CO 2 3.64E-03 1.88E-02 7.43E -03 3.84E-04 -9.85E-03 2.04E-02
CH 4 4.33E-05 0 1.40E-07 4.46E-07 -1.41E-05 2.98E-05
N 2 O 7.14E-08 0 1.37E-07 4.99E-09 -1.10E-07 1.03E-07

### H - 1 

## Appendix H

Crude Oil and Finished Product Loss Factors
While the volatilization of the liquid fuels doe s not contribute directly to life cycle GHG emissions, it contributes indirect ly by necessitating that a larger overall quantity of fuel be produced to meet a specified need. Loss factors utilized throughout the LC stages are shown in Table H-1 and Table H-2. Loss factors are app lied at the end of each activity and for all activities occurring prior to the loss. For exam ple, losses for all produ ct activities shown in Table H-2 are applied to determine the emissions associated with waterborne transport of imports per barrel of fuel consumed in a vehicle.

Table H-1. Feedstock Loss Factors

Feedstock Transport Crude Oil 0.285%

Table H-2. Finished Product Loss Factors

Petroleum

Product Waterborne Transport of Imports Marine Vessel Loading of

Imports Domestic Transport Bulk Storage Filling Station Refueling

Gasoline 0.0293% 0.0726% 0. 0851% 0.116% 0.135% 0.0293% Diesel 0.000071% 0.000071% 0.0001 9% 0.00025% 0.00025% 0.00041% Kerosene-Type Jet Fuel 0.000076% 0.000128% 0.00094% 0.00129% 0.00129% 0.00210%



## Loss Factor Development
Crude Oil Transport Losses associated with crude oi l transport include more than volatilization losses and, in the absence of better data, a total transport loss wa s assumed for crude oil transport. Crude oil transport is assumed to incur a 0.285% total loss consistent with a report value by an Eni (2006) for 2005. This loss factor is greater than the loss es incurred from crude oil tanker transport, as discussed below.
Losses associated with crude oil transport via tanker to the U.S. can be estimated using EPA AP42 emissions factors (Section 5.2 Transportation a nd Marketing of Petroleum Liquids) for tanker operations (EPA 1995). Table H-3 lists the emissi ons factors for crude oi l tanker transport using this alternate method.

### H - 2 Table H-3. Total Organic Emission Factors for Petroleum Marine Vessel Sources*

Source Units Crude Oil Reference Loading Operations lb/1000 gallon trans ferred 0.61 EPA AP-42, Table 5.2-6

Transit lb/week-1000 gallon transported 1.3 EPA AP-42, Table 5.2-6 * Factors are for dispensed product



### These loss factors translate into the percent loss factors shown in Table H-4. Since they are significantly less than the loss factor repor ted above, the larger value was used.
Table H-4. Crude Oil Tanker Transport Losses

Source Units Crude Oil Loading Operations % Loss 0.0084% Transit % Loss/week 0.0178%


### Imported Products Waterborne Transport Losses associated with imported product transpor t to the U.S. are estimated using EPA AP-42 emissions factors (Section 5.2 Tr ansportation and Marketing of Petroleum Liquids) for tanker operations (EPA 1995). Table H-5 lists the em issions factors applied to petroleum product tanker transport.
Table H-5. Total Organic Emission Factors for Petroleum Marine Vessel Sources*

Source Units Gasoline Diesel Kerosenebased Jet Fuel Reference

Loading Operations (Typical Overall Situation) lb/1000 gallon transferred 1.8 0.005 0.005 EPA AP-42, Tables 5.2-2

and 5.2-6

Transit lb/week-1000 gallon transported 2.7 0.005 0.005 EPA AP-42, Table 5.2-6 * Factors are for dispensed product


### Domestic Transport and Bulk Storage Development of evaporative emissions losses asso ciated with domestic transport and during bulk storage is detailed in Table H-6.
Table H-6. Evaporative Emissions During Fuel Distribution (Lewis 1997)

Petroleum

Product Energy Content (MMBtu/

bbl)* Mean Density (g/bbl)* Transport Loss (g/GJ) Transport Loss (bbl/bbl) Transport (% Loss) Bulk Terminal

(g/GJ) Bulk Terminal (bbl/bbl) Bulk Terminal (% Loss)
Gasoline 5.253 117,233 18.0 8.51E -04 0.0851% 24.6 1.16E-03 0.116% Diesel 5.825 134,048 0.0405 1.86E -06 0.0002% 0.0551 2.53E-06 0.0003% Kerosene 5.670 126,103 0.199 9.44E -06 0.0009% 0.271 1.29E-05 0.0013% * EPA 2007c

### H - 3 

### Vehicle/Aircraft Refueling

Gasoline Fuel losses during transfer operations at serv ice stations were esti mated using EPA AP-42 emissions factors (Section 5.2 Tran sportation and Marketing of Pe troleum Liquids). Table 5.2-7 of the EPA document outlines evaporative emissi ons from gasoline service station operations (see Table H-7). It is assumed that the undergro und tank is filled using submerged filling and that vehicle refueling displacement losses are controlled.
Table H-7. Evaporative Emissions from Gasoline Service Station Operations (EPA 1995)

Source Emission Factor (lb/1000 gallons throughput) Filling underground tank (Stage I) Submerged filling 7.3 Splash filling 11.5 Balanced submerged filling 0.3 Underground tank breathing and emptying 1.0 Vehicle refueling operation (Stage II) Displacement losses (uncontrolled) 11.0 Displacement losses (controlled) 1.1 Spillage 0.7



### From the above data, there are 10.1 lbs of ga soline lost for every 1,000 gallons of gasoline dispensed to consumers (0.00164 bbl/bbl, or 0.164%).

Conventional Diesel Fuel EPA AP-42 emission factors are not specified for diesel service station operations. Estimates for diesel losses during refueling operations were de rived from a report ent itled Methodologies for Estimating Air Pollutant Emissions from Transport (Lewis 1997). For dies el, the filling station emissions are 0.0551 g/GJ (2.53 x 10 -6 

### bbl/bbl, or 0.0003%) and the ve hicle refueling emissions are 0.0903 g/GJ (4.14 x 10 -6 

### bbl/bbl, or 0.0004%). The total eva porative losses for this stage are 0.1454 g/GJ (0.0007%).

Kerosene-Based Jet Fuel According to the U.S. Federal Aviation Ad ministration (FAA) Air Quality Handbook, Appendix D: Aircraft Emission Methodol ogy, there is currently no inform ation available on calculating evaporative-related emissions (e.g., refueling em issions) from commercial aircraft (FAA 1997). The FAA Air Quality Handbook notes that these eva porative related emissi ons are small due to the low vapor pressure of the fuel a nd the quick-connect refueling nozzles. In the absence of use-specific em issions factors for aircraft refu eling, product losses associated with kerosene refueling operations (filling sta tion operation and vehicle refueling operations) are used to approximate aircraft refueling losses. According to Lewis (1997), losses associated with refueling with kerosene results in 0. 714 g/GJ in evaporative losses (3.39 x 10 -5 

### bbl/bbl, or 0.0034%).

### H - 4 This page intentionally left blank.

### I - 1 

## Appendix I

Conversion Factors
Life Cycle Stage #5 and final WT W and WTT results are presented on the basis of lower heating values for conventional gasoline, conventional diesel and kerose ne-based jet fuel. The energy content and densities used for thes e final results conversions for th e three fuels is shown in Table I-1. Intermediate calculations in Life Cycle Stages #1 through #4 calculate emissions associated with combustion of various transportation fuels and refi nery fuel on a higher heating value basis (see Table I-2). Densities of various petroleum refi ning products are shown in Table I-3.

Table I-1. Approximate Heat Content (LHV) and Density of Petroleum Products

Petroleum Product Heat Content (MMBtu LHV/bbl) Density (kg/bbl) Reference

Conventional Gasoline 4.89 117 EPA 2008 Conventional Diesel 5.51 135 EPA 2008 Kerosene-based Jet Fuel 5.23 128 DESC 2008

Table I-2. Approximate Heat Content (HHV) of Petroleum Products (EIA 2008)

Petroleum Product Heat Content Asphalt 6.636 Aviation Gasoline 5.048 Butane 4.326 Butane-Propane Mixture (60 percent-40 percent) 4.130 Distillate Fuel Oil 5.825 Ethane 3.082 Ethane-Propane Mixture (70 per cent-30 percent) 3.308 Isobutane 3.974 Jet Fuel, Kerosene-Type 5.670 Jet Fuel, Naphtha-Type 5.355 Kerosene 5.670 Lubricants 6.065 Motor Gasoline Conventional 5.253 Oxygenated 5.150 Reformulated 5.150 Fuel Ethanol 3.539 Natural Gasoline 4.620 Pentanes Plus 4.620 Petrochemical Feedstocks Naphtha less than 401° F 5.248 Other Oils equal to or greater than 401° F 5.825

### I - 2 Petroleum Product Heat Content Still Gas 6.000 Petroleum Coke 6.024 Plant Condensate 5.418 Propane 3.836 Residual Fuel Oil 6.287 Road Oil 6.636 Special Naphthas 5.248 Still Gas 6.000 Unfinished Oils 5.825 Unfractionated Stream 5.418 Waxes 5.537 Miscellaneous 5.796

Table I-3. Density Conversions (EPA 2007c)
Hydrocarbon Density (bbl/tonne) Density (liters/tonne) Natural gas liquids 11.6 1,844.2 Unfinished oils 7.46 1,186.04 Liquefied petroleum gas 11.6 1,844.2 Aviation gasoline 8.9 1,415.0 Naphtha jet fuel 8.27 1,314.82 Kerosene jet fuel 7.93 1,260.72 Motor gasoline 8.53 1,356.16 Kerosene 7.73 1,228.97 Naphtha 8.22 1,306.87 Distillate 7.46 1,186.04 Residual oil 6.66 1,058.85 Lubricants 7.06 1,122.45 Bitumen 6.06 963.46 Waxes 7.87 1,251.23 Petroleum coke 5.51 876.02 Petrochemical feedstocks 7.46 1,186.04 Special naphtha 8.53 1,356.16 Miscellaneous products 8.00 1,271.90 Crude oil (2005)* 7.188* 1,142.8* *API Gravity for 2005 was 30.20 degrees (EIA 2008)



### Methane Density = 0.67606 kg/m 3 

### (EPA 2007c)

### J - 1 

## Appendix J

Emissions Factors for Various Vehicle Types
The following emissions are for different vehi cle types and are repr esentative of the 2005 average fleet. The total fuel use and emissions per mile were provided by the EPA and were extracted from the MOVES model (EPA 2008).J - 2Table J-1. 2005 Fleet Vehicle Emissions for Conventional GasolineTotalFuelUseVehicleEfficiencyCO2Emissions(per mile)CH4Emissions(per mile)N2OEmissions(per mile)GHGEmissions(per mile)CO2EmissionsCH4EmissionsN2OEmissionsGHGEmissionsMOVES Vehicle ClassBtuLHV/milempgkg CO2/milekg CH4/milekg N2O/milekg CO2E/milekg CO2/MMBtuLHVkg CH4/MMBtuLHVkg N2O/MMBtuLHVkg CO2E/MMBtuLHV11. Motorcycle4,90523.70.3684.88E-055.44E-060.37175.09.95E-031.11E-0375.621. Passenger Car4,86623.90.3652.37E-052.43E-050.37375.04.88E-034.99E-0376.631. Passenger Truck6,78517.20.5093.95E-055.50E-050.52675.05.83E-038.11E-0377.632. Light Commercial Truck7,43615.70.5584.56E-055.82E-050.57675.06.13E-037.82E-0377.542. Transit Bus15,5437.51.1662.31E-053.03E-051.17675.01.49E-031.95E-0375.743. School Bus12,6639.20.9501.94E-049.05E-050.98275.01.53E-027.15E-0377.651. Refuse Truck13,5098.61.0141.80E-051.89E-051.02075.01.33E-031.40E-0375.552. Single-Unit Short-Haul Truck58,3212.04.3766.04E-054.18E-054.39075.01.03E-037.16E-0475.353. Single-Unit Long-Haul Truck38,9583.02.9232.53E-053.08E-052.93375.06.50E-047.91E-0475.354. Motor Home16,0147.31.2021.02E-043.75E-051.21575.06.34E-032.34E-0375.961. Combination Short-Haul Truck15,5017.51.1631.21E-051.44E-051.16875.07.79E-049.32E-0475.362. Combination Long-Haul Truck15,3747.61.1549.76E-061.38E-051.15875.06.35E-048.95E-0475.3Table J-2. 2005 Fleet Vehicle Emissions for Conventional DieselTotalFuelUseVehicleEfficiencyCO2Emissions(per mile)CH4Emissions(per mile)N2OEmissions(per mile)GHGEmissions(per mile)CO2EmissionsCH4EmissionsN2OEmissionsGHGEmissionsMOVES Vehicle ClassBtuLHV/milempgkg CO2/milekg CH4/milekg N2O/milekg CO2E/milekg CO2/MMBtuLHVkg CH4/MMBtuLHVkg N2O/MMBtuLHVkg CO2E/MMBtuLHV21. Passenger Car3,73735.10.2862.99E-076.53E-070.28676.68.00E-051.75E-0476.731. Passenger Truck5,88422.30.4517.61E-071.27E-060.45176.61.29E-042.16E-0476.732. Light Commercial Truck6,38520.60.4899.67E-071.57E-060.49076.61.51E-042.46E-0476.741. IntercityBus15,3838.51.1782.37E-062.40E-061.17976.61.54E-041.56E-0476.642. Transit Bus13,10810.01.0042.34E-062.81E-061.00576.61.78E-042.14E-0476.743. School Bus10,06213.00.7712.33E-064.13E-060.77276.62.31E-044.10E-0476.751. Refuse Truck10,89012.10.8342.32E-062.54E-060.83576.62.13E-042.34E-0476.752. Single-Unit Short-Haul Truck42,5413.13.2591.97E-062.51E-063.25976.64.63E-055.91E-0576.653. Single-Unit Long-Haul Truck28,9334.52.2162.04E-062.48E-062.21776.67.07E-058.57E-0576.654. Motor Home13,8519.51.0612.27E-062.60E-061.06276.61.64E-041.88E-0476.761. Combination Short-Haul Truck23,2115.71.7781.90E-062.08E-061.77976.68.19E-058.96E-0576.662. Combination Long-Haul Truck23,9475.51.8341.86E-062.02E-061.83576.67.77E-058.45E-0576.6

### K - 1 

## Appendix K

LTO Emission Factors and Emi ssions for Various Aircraft
Emissions for aircraft operation are examined fo r various aircraft for landing and take-off (LTO) operations and emissions are presented in Table K-1 for LTO in kg per MMBtu LHV of jet fuel consumed. IPCC reports the fuel consumption in terms of kg of jet fuel. These values were converted to MMBtu LHV using 0.04099 MMBtu LHV/kg jet fuel (DESC 2005).

Table K-1. LTO Emission Factors for Typical Aircraft (IPCC 2006)

LTO emissions factors (kg/LTO/) (12) LTO emissions (kg/MMBtu LHV)

AIRCRAFT CO 2 (11) CH 4 (7) N 2 O (9) LTO Fuel Consumption (kg/LTO) CO 2 (11) CH 4 (7) N 2 O (9)

A300 5,450 0.12 0.2 1,720 77.3 0.0017 0.00284 A310 4,760 0.63 0.2 1,510 76.9 0.0102 0.00323 A319 2,310 0.06 0.1 730 77.2 0.0020 0.00334 A320 2,440 0.06 0.1 770 77.3 0.0019 0.00317 A321 3,020 0.14 0.1 960 76.7 0.0036 0.00254 A330-200/300 7,050 0.13 0.2 2,230 77.1 0.0014 0.00219

A340-200 5,890 0.42 0.2 1,860 77.3 0.0055 0.00262 A340-300 6,380 0.39 0.2 2,020 77.1 0.0047 0.00242 A340-500/600 10,660 0.01 0.3 3,370 77.2 0.0001 0.00217 707 5,890 9.75 0.2 1,860 77.3 0.1279 0.00262 717 2,140 0.01 0.1 680 76.8 0.0004 0.00359 727-100 3,970 0.69 0.1 1,260 76.9 0.0134 0.00194 727-200 4,610 0.81 0.1 1,460 77.0 0.0135 0.00167 737-100/200 2,740 0.45 0.1 870 76.8 0.0126 0.00280 737- 300/400/500 2,480 0.08 0.1 780 77.6 0.0025 0.00313

737-600 2,280 0.1 0.1 720 77.3 0.0034 0.00339 737-700 2,460 0.09 0.1 780 76.9 0.0028 0.00313 737-800/900 2,780 0.07 0.1 880 77.1 0.0019 0.00277

747-100 10,140 4.84 0.3 3,210 77.1 0.0368 0.00228 747-200 11,370 1.82 0.4 3,600 77.1 0.0123 0.00271 747-300 11,080 0.27 0.4 3,510 77.0 0.0019 0.00278 747-400 10,240 0.22 0.3 3,240 77.1 0.0017 0.00226 757-200 4,320 0.02 0.1 1,370 76.9 0.0004 0.00178 757-300 4,630 0.01 0.1 1,460 77.4 0.0002 0.00167 767-200 4,620 0.33 0.1 1,460 77.2 0.0055 0.00167 767-300 5,610 0.12 0.2 1,780 76.9 0.0016 0.00274Large Commercial Aircraft(1) (2)

767-400 5,520 0.1 0.2 1,750 77.0 0.0014 0.00279

### K - 2 LTO emissions factors (kg/LTO/) (12) LTO emissions (kg/MMBtu LHV)

AIRCRAFT CO 2 (11) CH 4 (7) N 2 O (9) LTO Fuel Consumption (kg/LTO) CO 2 (11) CH 4 (7) N 2 O (9)

777-200/300 8,100 0.07 0.3 2,560 77.2 0.0007 0.00286 DC-10 7,290 0.24 0.2 2,310 77.0 0.0025 0.00211 DC-8-50/60/70 5,360 0.15 0.2 1,700 76.9 0.0022 0.00287 DC-9 2,650 0.46 0.1 840 77.0 0.0134 0.00290 L-1011 7,300 7.4 0.2 2,310 77.1 0.0782 0.00211 MD-11 7,290 0.24 0.2 2,310 77.0 0.0025 0.00211 MD-80 3,180 0.19 0.1 1,010 76.8 0.0046 0.00242 MD-90 2,760 0.01 0.1 870 77.4 0.0003 0.00280 TU-134 2,930 1.8 0.1 930 76.9 0.0472 0.00262 TU-154-M 5,960 1.32 0.2 1,890 76.9 0.0170 0.00258 TU-154-B 7,030 11.9 0.2 2,230 76.9 0.1302 0.00219 RJ-RJ85 1,910 0.13 0.1 600 77.7 0.0053 0.00407 BAE 146 1,800 0.14 0.1 570 77.0 0.0060 0.00428 CRJ-100ER 1,060 0.06 0.03 330 78.4 0.0044 0.00222

ERJ-145 990 0.06 0.03 310 77.9 0.0047 0.00236

Fokker 100/70/28 2,390 0.14 0.1 760 76.7 0.0045 0.00321

BAC111 2,520 0.15 0.1 800 76.9 0.0046 0.00305 Dornier 328 Jet 870 0.06 0.03 280 75.8 0.0052 0.00261

Gulfstream IV 2,160 0.14 0.1 680 77.5 0.0050 0.00359 Gulfstream V 1,890 0.03 0.1 600 76.9 0.0012 0.00407Regional Jets

Yak-42M 2,880 0.25 0.1 910 77.2 0.0067 0.00268Jets(3) Cessna 525/560 1,070 0.33 0.03 340 76.8 0.0237 0.00215

Notes: (1) ICAO Engine Exhaust Emissions Data Bank (ICAO, 2004) based on aver age measured data. Emissions factors apply to LTO (Landing and Take off) only. (2) Engine types for each aircraft were selected on a co nsistent basis of the engine with the most LTOs. This approach, for some engine types, may underest imate (or overestimate) fleet emissions which are not directly related to fuel consumption (eg NOx, CO, HC). (2) Emissions and Dispersion Modeling System (EDMS) (FAA 2004b) (8) Assuming 10% of total VOC emissions in LTO c ycles are methane emissions (Olivier, 1991) (as in the 1996 IPCC Guidelines). (9) Estimates based on Tier I default values (EF ID 11053) (as in the 1996 IPCC Guidelines). (10) The sulfur content of the fuel is assum ed to be 0.05% (as in the 1996 IPCC Guidelines). (11) CO 2 for each aircraft based on 3.16 kg CO 2 produced for each kg fuel used, then rounded to the nearest 10 kg. (12) Information regarding the uncertainties associat ed with this data can be found in: Lister and Norman, 2003; ICAO, 1993.

### L - 1 

## Appendix L

Study GHG Results Presen ted in Alternate Units
The following tables and figures present GHG em issions on a kg-per-barrel-consumed basis and kg-per-GJ-fuel-consumed basis and in alternat e IPCC global warming potential values based on the 1996 and 2001 technical reports (Table 1.1).
Table L-1. GHG Emissions for Liquid Fuels Production (kg CO 2 E/barrel consumed)

LC Stage #1: Raw Material Acquisition LC Stage #2: Raw Material Transport LC Stage #3: Liquid Fuels Production LC Stage #4: Product Transport and Refueling LC Stage #5: Vehicle / Aircraft Operation TotalWell-toWheels

Conventional Gasoline (kg CO 2 E/barrel consumed) Total 35.8 7.0 47.9 5.3 375 471

CO 2 23.9 6.9 46.2 5.2 367 449 CH 4 (CO 2 E) 11.7 0.1 1.4 0.1 0.6 13.9 N 2 O (CO 2 E) 0.2 0.0 0.2 0.0 7.3 7.8 Conventional Diesel (kg CO 2 E/barrel consumed) Total 36.6 7.3 52.6 4.8 422 524

CO 2 24.6 7.1 50.8 4.7 422 509 CH 4 (CO 2 E) 11.8 0.1 1.6 0.1 0.0 13.6 N 2 O (CO 2 E) 0.2 0.0 0.2 0.0 0.3 0.8 Kerosene-Based Jet Fuel (kg CO 2 E/barrel consumed) Total 35.3 7.0 31.6 5.2 407 486

CO 2 23.8 6.9 30.5 5.1 403 470 CH 4 (CO 2 E) 11.4 0.1 0.9 0.1 0.1 12.6 N 2 O (CO 2 E) 0.2 0.0 0.1 0.0 3.3 3.7

### L - 2 Table L-2. GHG Emissions for Liquid Fuels Production (kg CO 2 E/GJ LHV fuel consumed)

LC Stage #1: Raw Material Acquisition LC Stage #2: Raw Material Transport LC Stage #3: Liquid Fuels Production LC Stage #4: Product Transport and Refueling LC Stage #5: Vehicle / Aircraft Operation TotalWell-toWheels

Conventional Gasoline (kg CO 2 E/GJ LHV fuel consumed) Total 6.94 1.36 9.27 1.03 72.6 91.21

CO 2 4.63 1.34 8.96 1.01 71.1 87.0 CH 4 (CO 2 E) 2.27 0.02 0.27 0.01 0.11 2.68 N 2 O (CO 2 E) 0.04 0.008 0.04 0.006 1.41 1.51 Conventional Diesel (kg CO 2 E/GJ LHV fuel consumed) Total 6.29 1.25 9.05 0.83 72.7 90.13

CO 2 4.23 1.23 8.74 0.82 72.6 87.6 CH 4 (CO 2 E) 2.03 0.02 0.27 0.01 0.00 2.33 N 2 O (CO 2 E) 0.03 0.007 0.04 0.005 0.05 0.14 Kerosene-Based Jet Fuel (kg CO 2 E/GJ LHV fuel consumed) Total 6.41 1.28 5.72 0.95 73.6 88.00

CO 2 4.30 1.25 5.53 0.93 73.1 85.1 CH 4 (CO 2 E) 2.07 0.02 0.17 0.01 0.01 2.28 N 2 O (CO 2 E) 0.04 0.007 0.025 0.006 0.60 0.67

Table L-3. GHG Emissions for Liquid Fuels Production Based on 1996 IPCC GWP (kg CO 2 E/MMBtu LHV of Fuel Consumed)

LC Stage #1: Raw Material Acquisition LC Stage #2: Raw Material Transport LC Stage #3: Liquid Fuels Production LC Stage #4: Product Transport and Refueling LC Stage #5: Vehicle / Aircraft Operation TotalWell-toWheels

Conventional Gasoline (kg CO 2 E/MMBtu LHV fuel consumed) Total 6.94 1.44 9.74 1.09 76.7 95.9

CO 2 4.89 1.41 9.45 1.07 75.0 91.9 CH 4 (CO 2 E) 2.01 0.0162 0.242 0.0125 0.10 2.38 N 2 O (CO 2 E) 0.0410 0.0087 0.0474 0.0067 1.55 1.65 Conventional Diesel (kg CO 2 E/MMBtu LHV fuel consumed) Total 6.30 1.32 9.51 0.88 76.7 94.6

CO 2 4.46 1.30 9.22 0.86 76.6 92.4 CH 4 (CO 2 E) 1.80 0.0147 0.239 0.0109 0.0017 2.07 N 2 O (CO 2 E) 0.0376 0.0081 0.0442 0.0053 0.0541 0.149 Kerosene-Based Jet Fuel (kg CO 2 E/MMBtu LHV fuel consumed) Total 6.41 1.35 6.01 1.00 77.8 92.5

CO 2 4.54 1.32 5.83 0.978 77.1 89.8 CH 4 (CO 2 E) 1.83 0.0147 0.151 0.0115 0.011 2.02 N 2 O (CO 2 E) 0.0381 0.0082 0.0280 0.0062 0.654 0.735

### L - 3 Table L-4. GHG Emissions for Liquid Fuels Production Based on 2001 IPCC GWP (kg CO 2 E/MMBtu LHV of Fuel Consumed)

LC Stage #1: Raw Material Acquisition LC Stage #2: Raw Material Transport LC Stage #3: Liquid Fuels Production LC Stage #4: Product Transport and Refueling LC Stage #5: Vehicle / Aircraft Operation TotalWell-toWheels

Conventional Gasoline (kg CO 2 E/MMBtu LHV fuel consumed) Total 7.13 1.44 9.76 1.09 76.6 96.0

CO 2 4.89 1.41 9.45 1.07 75.0 91.9 CH 4 (CO 2 E) 2.20 0.0177 0.265 0.0137 0.11 2.61 N 2 O (CO 2 E) 0.0391 0.0083 0.0453 0.0064 1.47 1.58 Conventional Diesel (kg CO 2 E/MMBtu LHV fuel consumed) Total 6.47 1.32 9.53 0.88 76.7 94.8

CO 2 4.46 1.30 9.22 0.86 76.6 92.4 CH 4 (CO 2 E) 1.97 0.0161 0.262 0.0120 0.0018 2.26 N 2 O (CO 2 E) 0.0359 0.0077 0.0422 0.0050 0.0517 0.143 Kerosene-Based Jet Fuel (kg CO 2 E/MMBtu LHV fuel consumed) Total 6.58 1.35 6.02 1.00 77.7 92.7

CO 2 4.54 1.32 5.83 0.978 77.1 89.8 CH 4 (CO 2 E) 2.00 0.0163 0.165 0.0126 0.012 2.21 N 2 O (CO 2 E) 0.0363 0.0079 0.0267 0.0059 0.625 0.701L - 4Figure L-1. GHG Emissions for Liquid Fuels Production (kg CO2E/barrel consumed)35.836.635.37.07.37.047.952.631.65.34.85.2471.0523.8485.8375.0422.5406.6050100150200250300350400450500550 Gasoline Diesel Jet Fuel Gasoline Diesel Jet Fuel Gasoline Diesel Jet Fuel Gasoline Diesel Jet Fuel Gasoline Diesel Jet Fuel Gasoline Diesel Jet FuelLC Stage #1:Raw MaterialAcquisitionLC Stage #2:Raw MaterialTransportLC Stage #3:Liquid FuelsProductionLC Stage #4:Product Transportand RefuelingLC Stage #5:Vehicle /AircraftOperationTotalWell-to-Wheels

GHG Emissions (kg CO 2 E/Barrel of fuel consumed)Carbon DioxideMethaneNitrous OxideL - 5Figure L-2. GHG Emissions for Liquid Fuels Production (kg CO2E/GJ LHV fuel consumed)6.96.3 6.41.4 1.3 1.39.39.15.71.00.80.991.390.188.073.772.772.6020406080100 Gasoline Diesel Jet Fuel Gasoline Diesel Jet Fuel Gasoline Diesel Jet Fuel Gasoline Diesel Jet Fuel Gasoline Diesel Jet Fuel Gasoline Diesel Jet FuelLC Stage #1:Raw MaterialAcquisitionLC Stage #2:Raw MaterialTransportLC Stage #3:Liquid FuelsProductionLC Stage #4:Product Transportand RefuelingLC Stage #5:Vehicle /AircraftOperationTotalWell-to-Wheels

GHG Emissions (kg CO 2 E/GJ LHV of fuel consumed)Carbon DioxideMethaneNitrous OxideL - 6Figure L-3. GHG Emissions for Liquid Fuels Production Based on 1996 IPCC GWP (kg CO2E/MMBtu LHV of Fuel Consumed)6.96.3 6.41.4 1.3 1.39.79.56.01.1 0.9 1.095.994.692.577.876.776.7020406080100 Gasoline Diesel Jet Fuel Gasoline Diesel Jet Fuel Gasoline Diesel Jet Fuel Gasoline Diesel Jet Fuel Gasoline Diesel Jet Fuel Gasoline Diesel Jet FuelLC Stage #1:Raw MaterialAcquisitionLC Stage #2:Raw MaterialTransportLC Stage #3:Liquid FuelsProductionLC Stage #4:Product Transportand RefuelingLC Stage #5:Vehicle /AircraftOperationTotalWell-to-Wheels

GHG Emissions (kg CO 2 E/MMBtu LHV of fuel consumed)Carbon DioxideMethaneNitrous OxideL - 7Figure L-4. GHG Emissions for Liquid Fuels Production Based on 2001 IPCC GWP (kg CO2E/MMBtu LHV of Fuel Consumed)7.16.56.61.4 1.3 1.39.89.56.01.1 0.9 1.096.094.892.777.776.776.6020406080100 Gasoline Diesel Jet Fuel Gasoline Diesel Jet Fuel Gasoline Diesel Jet Fuel Gasoline Diesel Jet Fuel Gasoline Diesel Jet Fuel Gasoline Diesel Jet FuelLC Stage #1:Raw MaterialAcquisitionLC Stage #2:Raw MaterialTransportLC Stage #3:Liquid FuelsProductionLC Stage #4:Product Transportand RefuelingLC Stage #5:Vehicle /AircraftOperationTotalWell-to-Wheels

GHG Emissions (kg CO 2 E/MMBtu LHV of fuel consumed)Carbon DioxideMethaneNitrous Oxide

### L - 8 This page intentionally left blank.

## Attachment 1

Documentation Associated with Pr ofiles Extracted from GaBi 4Documentation Crude oil production 2002

Oil production in Algeria 1 / 8 05/08/2008 

## Production of crude oil in Algeria

1. Technology description of the Crude oil producti on

1.1 Introduction The production of crude oil was modelled as a combi ned natural gas and crude oil production. In most cases beside crude oil, different par ts of natural gas and NGL (natural gas liquids) are produced as by-products. For the diffe rent by-products allocation by lower calorific value was applied. The combined productio n comprises the exploration and production of crude oil and natural gas as well as all the desulphurization of natural gas. The data set includes all relevant parts of the upstrea m industry. Production may take place onshore and offshore. Both are taken into account p roportionate to their ratio of the total production of a country.



### 1.2 Exploration Exploration comprises the search of hydrocarbon (HC ) deposits and the drilling of wells. The search for new deposits is conducted at first b y seismic survey, which is not included in the data set. In a second step testing wells are drilled which can be characterized as wildcat wells for areas with low information about the subsurface, exploration wells for information gathering and appraisal wells to assess characteristics such as flow rate, amount of hydrocarbon, pressure and others. After a successful testing the production well is drilled to produce hydrocarbons. Vertical wells are drilled by the rotary mode. The base of a drilling facility is a rig. For offshore drilling jack-up rigs, based on a buoyant ste el hull with 3 or more legs, semisubmersible rigs, which float at all times on ponto ons, or drill ships are used. The oil rig contains machinery and fulfils the role of superstr ucture bearing the load of a drill string. Driven by a diesel unit the drill string transmits his rotation on a drill bit, which brakes up the stone and extends the hole (up to 0,8 m wide). The drill string is gradually lengthened as the well gets deeper. The drill cuttings are rem oved by a drilling fluid (drilling mud), which is pumped inside the drill string, leaves the drill string at the drill bit and is then floated together with the drill cuttings back to th e surface between drill string and the inner surface of the well due to the high pressure genera ted by piston pumps. At the rig the drilling fluid is separated from drill cuttings and circ ulated. The drilling fluid also serves to cool the drill bit, to seal the drill hole against seepa ge and to prevent wall cave-ins. Depending on geology and technology water-based, oil-based an d synthetic-based fluids are used. They are mixed with barium sulphate and bentonite t o increase the density of the fluid as well as further additives. After finishing the dril ling or at least after 1000m, the well is cased with concrete and smoothly steel pipes (0.08- 0.2 m diameter) and prepared for production. In general due to the lack of infrastructu re for preparing and transportation, produced oil and gas is flared. Small amounts of gas a re also vented into the atmosphere. During the drilling high amounts of drill cuttings and waste water arise. At offshore exploration the cuttings are discharged to water or brou ght ashore depending on drilling fluid and legislation.Documentation Crude oil production 2002

Oil production in Algeria 2 / 8 05/08/2008 

### 1.3 Production & Preparation Ideally the oil is transported as an oil-gas mixtur e to the surface without any effort by the high pressure of the hydrocarbon deposit. The flow of oil runs dry, when the pressure of the deposit will get lower as the flow resistance o r when the pressure was already lower at the beginning. For further exploitation it is neces sary to use pumps or to reinject a part of the separated natural gas to maintain a high pressu re in the deposit. Advanced measures raise the production are the reinjection of produce d water or sea water and the reinjection of steam to increase the viscosity or surface tensi on of the oil-gas mixture. The produced oil-gas mixture is a composite of crud e oil, natural gas, brine and other impurities. In a preparation process the natural gas and the NGL is separated from the oil. In a second preparation step most of the water is sepa rated from the oil due to the different densities. The remaining emulsified water and salt is removed in a dewatering and desalting plant. Small amounts of produced natural gas a re often still flared, sometimes also vented, due to missing preparation and transportati on opportunities. Hydrogen sulphide contained in the natural gas in different concentra tions, has to be removed before transportation via pipelines due to the high corrosive i mpact. The hydrogen sulphide is recovered from the natural gas by the Claus process prod ucing elementary sulphur and, depending on technology standards, a certain amount o f sulphur dioxide. The arising water with concentrations of approximately 15 or more mg hydrocarbons per litre is reinjected into the gas field, discharged into the sea (onshor e and in shore) or evaporated in pits. During preparation different kinds of waste and use d chemicals arise which have to be disposed. A certain amount of gas and oil is flared or vented into the atmosphere because of leakage or security reasons. The mechanical ener gy and electricity for pumping and all other machinery is provided by gas turbines and die sel units. At onshore facilities a certain amount is provided by the grid.Documentation Crude oil production 2002

Oil production in Algeria 3 / 8 05/08/2008 

## 2 General comments of the LCA assessment method
This chapter gives background information on the pr incipal modelling approach.



### 2.1 System boundaries and functional unit

Functional unit: The functional unit is 1 bbl of cr ude oil. This process includes all relevant Mass and energy flows for the exploration and extraction of crude oil. Figure 2-1 gives an overview on the considered processes along with their key in- and outputs

Cement, Steel pipe, chemicals

Energy

(electrical, mechanical) Drilling meter Onshore

Production

Offshore Production Flaring / venting
Wastes Flaring / venting
Wastes

Crude oil Energy (electrical, mechanical) Drilling meter Exploration Flaring / venting Energy (electrical) Bentonite, Bariumsulphate System boundary

Figure 2-1 System boundary for crude oil production

The exploration is modelled per drilling meters and is considered in the model via drilling meters per mass of produced hydrocarbon. Quantities of borehole volume, removed rock are based on multiple sources such as [6]-[8]. Amou nt of Bentonite and Bariumsulphate and water for drilling mud is taken from [6]. The m aterial used for reinforcing the well is calculated based on [9]-[12]. The power demand for drilling is taken from [13]. For venting of natural gas the averaged national natural gas co mposition is considered [14], [23]. The energy demand for production is given in section 3. 2. The associated emissions are calculated using emission factors sourced from [16] and industry data. Venting of solution gas from oil producing well is also considered. For fla ring region specific flare amounts and emissions are included, see section 3.3 and [15], [ 21], [22]. Solid wastes and waste water are considered. The referring data is sourced from [15], [17]-[20] and as stated in section 3.4.



### 2.2 Allocation or system expansion For the combined crude oil, natural gas and natural gas liquids production allocation by lower calorific value is applied. The lower heating values of the products are given in section 3.5.Documentation Crude oil production 2002

Oil production in Algeria 4 / 8 05/08/2008 

### 2.3 Data completeness The coverage for the exploration data (crude oil, n atural gas, natural gas liquids) is 90% of mass and energy and 95% of the environmental releva nce (expert judgement).



### 2.4 Data selection and combination principles The data sources for the complete product system ar e sufficiently consistent: The data on the energy carrier supply chain is based on statist ics with country/region specific transport distances and energy carrier composition as well as industry and literature data on the inventory of exploration, extraction and processing . LCI modelling is fully consistent.



### 2.5 Reference year Reference year for the data set is 2002. Although s ome of the emission data and product properties are sourced from different years represe ntativeness for the reference year is considered good.



### 2.6 Data treatment and extrapolations principles In terms of the country/region specific crude oil p roduction, missing data of certain parameters has been used from countries with a compar able technology 1 . Data measured at a group of representative production facilities hav e been used to represent the national production.

1 If this ist he case it is indicated in the tables in section 3.Documentation Crude oil production 2002

Oil production in Algeria 5 / 8 05/08/2008 

## 3 Country specific data

3.1 Production Table 1 shows the production ratio of natural gas, NGL and crude oil on a weight basis as well as the drilling feet per pound hydrocarbon pro duced.

Table 1 Production parameters

Parameter Value Source

Portion of natural gas production 49.83% [4]

Portion of NGL production 17.4% [4]

Portion of crude oil production 32.77% [1]

Drilling meters for onshore production 0.57x10 -06 ft/lb HC produced [2]



### 3.2 Energy use The specific energy use distinguished between elect ricity and mechanical energy is shown in Table 2.

Table 2 Energy consumption parameters

Parameter Value Source

Electricity demand 34.39 Btu/lb HC Region value for Africa [15] and own calculations

Mechanical energy demand 309.54 Btu/lb HC Region value for Africa [15] and own calculations

Total energy demand 343.93 Btu/lb HC Region value f or Africa [15]



### 3.3 Flaring and venting The flaring and venting of hydrocarbons during the production process is shown in Table 3. The flared Hydrocarbons are the sum of flared na tural gas and solution gas compounds.Documentation Crude oil production 2002

Oil production in Algeria 6 / 8 05/08/2008 Table 3 Flaring and venting parameters

Parameter Value Source

Flared Hydrocarbons 0.030 lb/lb HC [5], [24]

Vented Hydrocarbons 0.0041 lb/lb HC [5]



### 3.4 Waste and waste water
The amount of solid waste and waste water emitted d uring the production process is summarised in Table 4.

Table 4 Waste and waste water parameters

Parameter Value Source

Solid waste 0.0017 lb/lb HC Value for Nigeria [3]

Waste water onshore 0.044 lb/lb HC [15]



### 3.5 Product properties The lower heating value as a country specific produ ct property is given in Table 5.

Table 5 Product properties

Parameter Value Source

Net calorific value natural gas 19148.19 Btu/lb [23 ]

Net calorific value crude oil 18709.68 Btu/lb [1]Documentation Crude oil production 2002

Oil production in Algeria 7 / 8 05/08/2008 

## 4 References

[1] IEA: Oil information 2002, International Energy Age ncy, 2004


### [2] Pennwell: The international petroleum Encyclopaedia 1997


### [3] Shell Nigeria 2004 People and the environment Annua l Report, 2005


### [4] IEA: Natural Gas Information 2002, International En ergy Agency, 2004


### [5] EIA: International Energy Annual 2003; Energy Infor mation Administration, 2004


### [6] OGP: Environmental aspects of the use and disposal of non aqueous drilling fluids

associated with offshore oil& gas operations, 2003


### [7] Da Prat, G.: Well Testing management , SPE Foundati on, presentation 2002


### [8] Vickery et al.: Successful high rate gas completion through combination of extreme

overbalance perforating and one trip perforate and gravel pack techniques, Baker oil tools, 2001


### [9] N. Lapeyrouse: Formulas and calculations for Drilli ng, Production and work over,

2nd Edition, Golf Professional Publishing, 2002


### [10] Gordon, D. et al. Underbalanced Drilling with casin g SPE, SPE Drilling & completion

2005


### [11] Ohio Department of Health: Materials used in drilli ng and construction of wells, 1999


### [12] Culver, G.: Drilling and well construction, Chapter 6, OIST, Department of Energy

1998


### [13] Vektor AS – Environmental developments in Well test ing, 2000


### [14] BP: Das Buch zum Erdöl (The book on Crude oil), 198 9


### [15] OGP, International Association of Oil and Gas Produ cers: Environmental performance in the E&P industry 2003, 2004


### [16] US EPA: Compilation of Air pollutant emission facto rs, AP 42, Volume I: Stationary

point and area sources, Fifth edition, United State s Protection Agency, Office of air quality planning and standards, 1995-2000.


### [17] US EPA: Profile of the Oil and Gas Extraction Indus try, 2nd Section, 2000


### [18] PSI: Management of produced water on offshore oil i nstallations, Policy Studies Institute, 2005Documentation Crude oil production 2002

Oil production in Algeria 8 / 8 05/08/2008 

### [19] OGP: Aromatics in produced water occurrence, fate & effects and treatment, International Association of Oil and Gas Producers, 2002


### [20] OGP: Fate and effects of naturally occurring substa nces in produced water on the

marine environment, International Association of Oi l and Gas Producers, 2005


### [21] Leahey, G et at.: Theoretical and observational ass essments of flare efficiencies,

Journal of Air & Waste Management Association, Volu me 51, December 2001


### [22] Johnson, M.R. et al.: Efficiency measurements of fl ares in a cross flow, Dep. Of Mechanical Engineering, University of Alberta, Combus tion Canada conference,
1999


### [23] EIA: C.5 Gross Heat Content of Dry Natural Gas Pro duction, 1980-2004, Energy

Information Administration, 2005


### [24] World Bank: Global gas Flaring reduction initiative , 2004Documentation Crude oil production 2002

Oil production in AngolaAngola 1 / 8 05/08/2008 

## Production of crude oil in Angola

1. Technology description of the Crude oil producti on

1.1 Introduction The production of crude oil was modelled as a combi ned natural gas and crude oil production. In most cases beside crude oil, different par ts of natural gas and NGL (natural gas liquids) are produced as by-products. For the diffe rent by-products allocation by lower calorific value was applied. The combined productio n comprises the exploration and production of crude oil and natural gas as well as all the desulphurization of natural gas. The data set includes all relevant parts of the upstrea m industry. Production may take place onshore and offshore. Both are taken into account p roportionate to their ratio of the total production of a country.



### 1.2 Exploration Exploration comprises the search of hydrocarbon (HC ) deposits and the drilling of wells. The search for new deposits is conducted at first b y seismic survey, which is not included in the data set. In a second step testing wells are drilled which can be characterized as wildcat wells for areas with low information about the subsurface, exploration wells for information gathering and appraisal wells to assess characteristics such as flow rate, amount of hydrocarbon, pressure and others. After a successful testing the production well is drilled to produce hydrocarbons. Vertical wells are drilled by the rotary mode. The base of a drilling facility is a rig. For offshore drilling jack-up rigs, based on a buoyant ste el hull with 3 or more legs, semisubmersible rigs, which float at all times on ponto ons, or drill ships are used. The oil rig contains machinery and fulfils the role of superstr ucture bearing the load of a drill string. Driven by a diesel unit the drill string transmits his rotation on a drill bit, which brakes up the stone and extends the hole (up to 0,8 m wide). The drill string is gradually lengthened as the well gets deeper. The drill cuttings are rem oved by a drilling fluid (drilling mud), which is pumped inside the drill string, leaves the drill string at the drill bit and is then floated together with the drill cuttings back to th e surface between drill string and the inner surface of the well due to the high pressure genera ted by piston pumps. At the rig the drilling fluid is separated from drill cuttings and circ ulated. The drilling fluid also serves to cool the drill bit, to seal the drill hole against seepa ge and to prevent wall cave-ins. Depending on geology and technology water-based, oil-based an d synthetic-based fluids are used. They are mixed with barium sulphate and bentonite t o increase the density of the fluid as well as further additives. After finishing the dril ling or at least after 1000m, the well is cased with concrete and smoothly steel pipes (0.08- 0.2 m diameter) and prepared for production. In general due to the lack of infrastructu re for preparing and transportation, produced oil and gas is flared. Small amounts of gas a re also vented into the atmosphere. During the drilling high amounts of drill cuttings and waste water arise. At offshore exploration the cuttings are discharged to water or brou ght ashore depending on drilling fluid and legislation.Documentation Crude oil production 2002

Oil production in AngolaAngola 2 / 8 05/08/2008 

### 1.3 Production & Preparation Ideally the oil is transported as an oil-gas mixtur e to the surface without any effort by the high pressure of the hydrocarbon deposit. The flow of oil runs dry, when the pressure of the deposit will get lower as the flow resistance o r when the pressure was already lower at the beginning. For further exploitation it is neces sary to use pumps or to reinject a part of the separated natural gas to maintain a high pressu re in the deposit. Advanced measures raise the production are the reinjection of produce d water or sea water and the reinjection of steam to increase the viscosity or surface tensi on of the oil-gas mixture. The produced oil-gas mixture is a composite of crud e oil, natural gas, brine and other impurities. In a preparation process the natural gas and the NGL is separated from the oil. In a second preparation step most of the water is sepa rated from the oil due to the different densities. The remaining emulsified water and salt is removed in a dewatering and desalting plant. Small amounts of produced natural gas a re often still flared, sometimes also vented, due to missing preparation and transportati on opportunities. Hydrogen sulphide contained in the natural gas in different concentra tions, has to be removed before transportation via pipelines due to the high corrosive i mpact. The hydrogen sulphide is recovered from the natural gas by the Claus process prod ucing elementary sulphur and, depending on technology standards, a certain amount o f sulphur dioxide. The arising water with concentrations of approximately 15 or more mg hydrocarbons per litre is reinjected into the gas field, discharged into the sea (onshor e and in shore) or evaporated in pits. During preparation different kinds of waste and use d chemicals arise which have to be disposed. A certain amount of gas and oil is flared or vented into the atmosphere because of leakage or security reasons. The mechanical ener gy and electricity for pumping and all other machinery is provided by gas turbines and die sel units. At onshore facilities a certain amount is provided by the grid.Documentation Crude oil production 2002

Oil production in AngolaAngola 3 / 8 05/08/2008 

## 2 General comments of the LCA assessment method
This chapter gives background information on the pr incipal modelling approach.



### 2.1 System boundaries and functional unit

Functional unit: The functional unit is 1 bbl of cr ude oil. This process includes all relevant Mass and energy flows for the exploration and extraction of crude oil. Figure 2-1 gives an overview on the considered processes along with their key in- and outputs

Cement, Steel pipe, chemicals

Energy

(electrical, mechanical) Drilling meter Onshore

Production

Offshore Production Flaring / venting
Wastes Flaring / venting
Wastes

Crude oil Energy (electrical, mechanical) Drilling meter Exploration Flaring / venting Energy (electrical) Bentonite, Bariumsulphate System boundary

Figure 2-1 System boundary for crude oil production

The exploration is modelled per drilling meters and is considered in the model via drilling meters per mass of produced hydrocarbon. Quantities of borehole volume, removed rock are based on multiple sources such as [12]-[14]. Am ount of Bentonite and Bariumsulphate and water for drilling mud is taken from [12]. The material used for reinforcing the well is calculated based on [15]-[18]. The power demand for drilling is taken from [19]. For venting of natural gas the averaged national natural ga s composition is considered [5], [20] and [1]. The energy demand for production is given in section 3.2. The associated emissions are calculated using emission factors sourced from [22] and industry data. Venting of solution gas from oil producing well is also con sidered. For flaring region specific flare amounts and emissions are included, see section 3.3 and [21], [27], [28]. Solid wastes and waste water are considered. The referring data is sourced from [21], [23]-[26] and as stated in section 3.4.



### 2.2 Allocation or system expansion For the combined crude oil, natural gas and natural gas liquids production allocation by lower calorific value is applied. The lower heating values of the products are given in section 3.5.Documentation Crude oil production 2002

Oil production in AngolaAngola 4 / 8 05/08/2008 

### 2.3 Data completeness The coverage for the exploration data (crude oil, n atural gas, natural gas liquids) is 90% of mass and energy and 95% of the environmental releva nce (expert judgement).



### 2.4 Data selection and combination principles The data sources for the complete product system ar e sufficiently consistent: The data on the energy carrier supply chain is based on statist ics with country/region specific transport distances and energy carrier composition as well as industry and literature data on the inventory of exploration, extraction and processing . LCI modelling is fully consistent.



### 2.5 Reference year Reference year for the data set is 2002. Although s ome of the emission data and product properties are sourced from different years represe ntativeness for the reference year is considered good.



### 2.6 Data treatment and extrapolations principles In terms of the country/region specific crude oil p roduction, missing data of certain parameters has been used from countries with a compar able technology 1 . Data measured at a group of representative production facilities hav e been used to represent the national production.

1 If this ist he case it is indicated in the tables in section 3.Documentation Crude oil production 2002

Oil production in AngolaAngola 5 / 8 05/08/2008 

## 3 Country specific data

3.1 Production Table 1 shows the production ratio of natural gas, NGL and crude oil on a weight basis as well as the drilling feet per pound hydrocarbon pro duced.

Table 1 Production parameters

Parameter Value Source

Portion of natural gas production 1.11% [1]

Portion of NGL production 0% [1]

Portion of crude oil production 98.89% [2]

Drilling meters for offshore production 1.12x10 -07 ft/lb HC produced [3]



### 3.2 Energy use The specific energy use distinguished between elect ricity and mechanical energy is shown in Table 2.

Table 2 Energy consumption parameters

Parameter Value Source

Electricity demand 34.39 Btu/lb HC Value for region Africa [21] and own calculations

Mechanical energy demand 309.54 Btu/lb HC Value for region Africa [21] and own calculations

Total energy demand 343.93 Btu/lb HC Value for regi on Africa [21]



### 3.3 Flaring and venting The flaring and venting of hydrocarbons during the production process is shown in Table 3. The flared Hydrocarbons are the sum of flared na tural gas and solution gas compounds.Documentation Crude oil production 2002

Oil production in AngolaAngola 6 / 8 05/08/2008 Table 3 Flaring and venting parameters

Parameter Value Source

Flared Hydrocarbons 0.061 lb/lb HC [11]

Vented Hydrocarbons 0.017 lb/lb HC [11]



### 3.4 Waste and waste water
The amount of solid waste and waste water emitted d uring the production process is summarised in Table 4.

Table 4 Waste and waste water parameters

Parameter Value Source

Solid waste 0.0017 lb/lb HC Value for Nigeria [4]

Waste water offshore 0.49 lb/lb HC [21]



### 3.5 Product properties The lower heating value as a country specific produ ct property is given in Table 5.

Table 5 Product properties

Parameter Value Source

Net calorific value natural gas 18851.55 Btu/lb [5]

Net calorific value crude oil 18309.87 Btu/lb [6];[ 7];[8];[9];[10]Documentation Crude oil production 2002

Oil production in AngolaAngola 7 / 8 05/08/2008 

## 4 References

[1] IEA: Natural Gas Information 2002, International En ergy Agency, 2004


### [2] IEA: Oil information 2002, International Energy Age ncy, 2004


### [3] Pennwell: The international petroleum Encyclopaedia 1997


### [4] Shell Nigeria 2004 People and the environment Annua l Report, 2005


### [5] EIA: C.5 Gross Heat Content of Dry Natural Gas Prod uction, 1980-2004, 2005


### [6] EIA: C.3 Gross Heat Content of Crude Oil, 1980-2003 , 2004


### [7] Haverly: Crude assay libraries, 2005


### [8] Statoil: Statoil crudes, 2005


### [9] ChevronTexaco: http://www.chevrontexaco.com/crudemarketing/ , 2005


### [10] Energy Intelligence Group: The Crude Oils and Their Key Characteristics, 2003


### [11] EIA: International Energy Annual 2003; Energy Infor mation Administration, 2004


### [12] OGP: Environmental aspects of the use and disposal of non aqueous drilling fluids

associated with offshore oil& gas operations, 2003


### [13] Da Prat, G.: Well Testing management , SPE Foundati on, presentation 2002


### [14] Vickery et al.: Successful high rate gas completion through combination of extreme

overbalance perforating and one trip perforate and gravel pack techniques, Baker oil tools, 2001


### [15] N. Lapeyrouse: Formulas and calculations for Drilli ng, Production and work over,

2nd Edition, Golf Professional Publishing, 2002


### [16] Gordon, D. et al. Underbalanced Drilling with casin g SPE, SPE Drilling & completion

2005


### [17] Ohio Department of Health: Materials used in drilli ng and construction of wells, 1999


### [18] Culver, G.: Drilling and well construction, Chapter 6, OIST, Department of Energy

1998


### [19] Vektor AS – Environmental developments in Well test ing, 2000


### [20] BP: Das Buch zum Erdöl (The book on Crude oil), 198 9


### [21] OGP, International Association of Oil and Gas Produ cers: Environmental performance in the E&P industry 2003Documentation Crude oil production 2002

Oil production in AngolaAngola 8 / 8 05/08/2008 

### [22] US EPA: Compilation of Air pollutant emission facto rs, AP 42, Volume I: Stationary

point and area sources, Fifth edition, United State s Protection Agency, Office of air quality planning and standards, 1995-2000.


### [23] US EPA: Profile of the Oil and Gas Extraction Indus try, 2nd Section, 2000


### [24] PSI: Management of produced water on offshore oil i nstallations, Policy Studies Institute, 2005


### [25] OGP: Aromatics in produced water occurrence, fate & effects and treatment, International Association of Oil and Gas Producers, 2002


### [26] OGP: Fate and effects of naturally occurring substa nces in produced water on the

marine environment, International Association of Oi l and Gas Producers, 2005


### [27] Leahey, G et at.: Theoretical and observational ass essments of flare efficiencies,

Journal of Air & Waste Management Association, Volu me 51, December 2001


### [28] Johnson, M.R. et al.: Efficiency measurements of fl ares in a cross flow, Dep. Of Mechanical Engineering, University of Alberta, Combus tion Canada conference,
1999Documentation Crude oil production 2002

Oil production in Canada 1 / 8 05/08/2008 

## Production of crude oil in Canada

1. Technology description of the Crude oil producti on

1.1 Introduction The production of crude oil was modelled as a combi ned natural gas and crude oil production. In most cases beside crude oil, different par ts of natural gas and NGL (natural gas liquids) are produced as by-products. For the diffe rent by-products allocation by lower calorific value was applied. The combined productio n comprises the exploration and production of crude oil and natural gas as well as all the desulphurization of natural gas. The data set includes all relevant parts of the upstrea m industry. Production may take place onshore and offshore. Both are taken into account p roportionate to their ratio of the total production of a country.



### 1.2 Exploration Exploration comprises the search of hydrocarbon (HC ) deposits and the drilling of wells. The search for new deposits is conducted at first b y seismic survey, which is not included in the data set. In a second step testing wells are drilled which can be characterized as wildcat wells for areas with low information about the subsurface, exploration wells for information gathering and appraisal wells to assess characteristics such as flow rate, amount of hydrocarbon, pressure and others. After a successful testing the production well is drilled to produce hydrocarbons. Vertical wells are drilled by the rotary mode. The base of a drilling facility is a rig. For offshore drilling jack-up rigs, based on a buoyant ste el hull with 3 or more legs, semisubmersible rigs, which float at all times on ponto ons, or drill ships are used. The oil rig contains machinery and fulfils the role of superstr ucture bearing the load of a drill string. Driven by a diesel unit the drill string transmits his rotation on a drill bit, which brakes up the stone and extends the hole (up to 0,8 m wide). The drill string is gradually lengthened as the well gets deeper. The drill cuttings are rem oved by a drilling fluid (drilling mud), which is pumped inside the drill string, leaves the drill string at the drill bit and is then floated together with the drill cuttings back to th e surface between drill string and the inner surface of the well due to the high pressure genera ted by piston pumps. At the rig the drilling fluid is separated from drill cuttings and circ ulated. The drilling fluid also serves to cool the drill bit, to seal the drill hole against seepa ge and to prevent wall cave-ins. Depending on geology and technology water-based, oil-based an d synthetic-based fluids are used. They are mixed with barium sulphate and bentonite t o increase the density of the fluid as well as further additives. After finishing the dril ling or at least after 1000m, the well is cased with concrete and smoothly steel pipes (0.08- 0.2 m diameter) and prepared for production. In general due to the lack of infrastructu re for preparing and transportation, produced oil and gas is flared. Small amounts of gas a re also vented into the atmosphere. During the drilling high amounts of drill cuttings and waste water arise. At offshore exploration the cuttings are discharged to water or brou ght ashore depending on drilling fluid and legislation.Documentation Crude oil production 2002

Oil production in Canada 2 / 8 05/08/2008 

### 1.3 Production & Preparation Ideally the oil is transported as an oil-gas mixtur e to the surface without any effort by the high pressure of the hydrocarbon deposit. The flow of oil runs dry, when the pressure of the deposit will get lower as the flow resistance o r when the pressure was already lower at the beginning. For further exploitation it is neces sary to use pumps or to reinject a part of the separated natural gas to maintain a high pressu re in the deposit. Advanced measures raise the production are the reinjection of produce d water or sea water and the reinjection of steam to increase the viscosity or surface tensi on of the oil-gas mixture. The produced oil-gas mixture is a composite of crud e oil, natural gas, brine and other impurities. In a preparation process the natural gas and the NGL is separated from the oil. In a second preparation step most of the water is sepa rated from the oil due to the different densities. The remaining emulsified water and salt is removed in a dewatering and desalting plant. Small amounts of produced natural gas a re often still flared, sometimes also vented, due to missing preparation and transportati on opportunities. Hydrogen sulphide contained in the natural gas in different concentra tions, has to be removed before transportation via pipelines due to the high corrosive i mpact. The hydrogen sulphide is recovered from the natural gas by the Claus process prod ucing elementary sulphur and, depending on technology standards, a certain amount o f sulphur dioxide. The arising water with concentrations of approximately 15 or more mg hydrocarbons per litre is reinjected into the gas field, discharged into the sea (onshor e and in shore) or evaporated in pits. During preparation different kinds of waste and use d chemicals arise which have to be disposed. A certain amount of gas and oil is flared or vented into the atmosphere because of leakage or security reasons. The mechanical ener gy and electricity for pumping and all other machinery is provided by gas turbines and die sel units. At onshore facilities a certain amount is provided by the grid.Documentation Crude oil production 2002

Oil production in Canada 3 / 8 05/08/2008 

## 2 General comments of the LCA assessment method
This chapter gives background information on the pr incipal modelling approach.



### 2.1 System boundaries and functional unit

Functional unit: The functional unit is 1 bbl of cr ude oil. This process includes all relevant Mass and energy flows for the exploration and extraction of crude oil. Figure 2-1 gives an overview on the considered processes along with their key in- and outputs

Cement, Steel pipe, chemicals

Energy

(electrical, mechanical) Drilling meter Onshore

Production

Offshore Production Flaring / venting
Wastes Flaring / venting
Wastes

Crude oil Energy (electrical, mechanical) Drilling meter Exploration Flaring / venting Energy (electrical) Bentonite, Bariumsulphate System boundary

Figure 2-1 System boundary for crude oil production

The exploration is modelled per drilling meters and is considered in the model via drilling meters per mass of produced hydrocarbon. Quantities of borehole volume, removed rock are based on multiple sources such as [21]-[23]. Am ount of Bentonite and Bariumsulphate and water for drilling mud is taken from [21]. The material used for reinforcing the well is calculated based on [24]-[27]. The power demand for drilling is taken from [28]. For venting of natural gas the averaged national natural ga s composition is considered [29]. The energy demand for production is given in section 3. 2. The associated emissions are calculated using emission factors sourced from [31] and industry data. Venting of solution gas from oil producing well is also considered. For fla ring region specific flare emissions are included see section 3.3 and [30],[36],[37]. Solid wastes and waste water are considered. The referring data is sourced from [30], [32]-[35] and as stated in section 3.4. .



### 2.2 Allocation or system expansion For the combined crude oil, natural gas and natural gas liquids production allocation by lower calorific value is applied. The lower heating values of the products are given in section 3.5.Documentation Crude oil production 2002

Oil production in Canada 4 / 8 05/08/2008 

### 2.3 Data completeness The coverage for the exploration data (crude oil, n atural gas, natural gas liquids) is 90% of mass and energy and 95% of the environmental releva nce (expert judgement).



### 2.4 Data selection and combination principles The data sources for the complete product system ar e sufficiently consistent: The data on the energy carrier supply chain is based on statist ics with country/region specific transport distances and energy carrier composition as well as industry and literature data on the inventory of exploration, extraction and processing . LCI modelling is fully consistent.



### 2.5 Reference year Reference year for the data set is 2002. Although s ome of the emission data and product properties are sourced from different years represe ntativeness for the reference year is considered good.



### 2.6 Data treatment and extrapolations principles In terms of the country/region specific crude oil p roduction, missing data of certain parameters has been used from countries with a compar able technology 1 . Data measured at a group of representative production facilities hav e been used to represent the national production.

1 If this ist he case it is indicated in the tables in section 3.Documentation Crude oil production 2002

Oil production in Canada 5 / 8 05/08/2008 

## 3 Country specific data

3.1 Production Table 1 shows the production ratio of natural gas, NGL and crude oil on a weight basis as well as the drilling feet per pound hydrocarbon pro duced. Note that all values are given for unallocated joint production of Natural gas, NGL an d crude oil.

Table 1 Production parameters

Parameter Value Source

Portion of natural gas production 56.22% [1]

Portion of NGL production 7.73% [1]

Portion of crude oil production 36.05% [1]

Drilling meters for onshore production 0.42x10 -05 ft/lb HC produced [2]

Drilling meters for offshore production 0.67x10 -05 ft/lb HC produced [2]



### 3.2 Energy use The specific energy use distinguished between elect ricity and mechanical energy is shown in Table 2.

Table 2 Energy consumption parameters

Parameter Value Source

Electricity demand 85.98 Btu/lb HC [5] and own calc ulations

Mechanical energy demand 412.71 Btu/lb HC [5] and o wn calculations

Total energy demand 498.70 Btu/lb HC [5] and own calculations



### 3.3 Flaring and venting The flaring and venting of hydrocarbons during the production process is shown in Table 3. The flared Hydrocarbons are the sum of flared na tural gas and solution gas compounds.Documentation Crude oil production 2002

Oil production in Canada 6 / 8 05/08/2008 Table 3 Flaring and venting parameters

Parameter Value Source

Flared Hydrocarbons 0.0072 lb/lb HC [5];[6];[7]

Vented Hydrocarbons 0.0043 lb/lb HC [6];[7]



### 3.4 Waste and waste water
The amount of solid waste and waste water emitted d uring the production process is summarised in Table 4.

Table 4 Waste and waste water parameters

Parameter Value Source

Solid waste 0.0060 lb/lb HC Global value

Calculated from [8];[9];[10];[11];[12];[13];[14]

Waste water onshore 0.017 lb/lb HC [30]

Waste water offshore 0.91 lb/lb HC [30]



### 3.5 Product properties The lower heating value as a country specific produ ct property is given in Table 5.

Table 5 Product properties

Parameter Value Source

Net calorific value natural gas 19496.42 Btu/lb [15 ]

Net calorific value crude oil 18008.93 Btu/lb [16]; [17];[18];[19];[20]Documentation Crude oil production 2002

Oil production in Canada 7 / 8 05/08/2008 

## 4 References

[1] IEA: Natural Gas Information 2002, International En ergy Agency, 2004


### [2] IEA: Oil information 2002, International Energy Age ncy, 2004


### [3] Pennwell: The international petroleum Encyclopaedia 1997


### [4] British Columbia, CA: Ministry of Energy, Mines and Petroleum Resources: Drilling,

Production and Distribution Statistics 1994 – 2004, 2005


### [5] Canadian Association of Petroleum Producers (CAPP): A National Inventory of

Greenhouse Gas ; 2004


### [6] UKOOA: Accidental Oil Spills, 1999


### [7] CAPP - Canadian Association of Petroleum Producers: Estimation of Flaring and

Venting Volumes from Upstream Oil and Gas facilitie s, 2002


### [8] Yukos: Yukos and the environment, 2003


### [9] Shell: Sustainability report 2003, http://www.shell.com/home/Framework?siteId=myen&FC2=/myen/html/iwgen/society_environment/environment/susta inable2003/zzz_lhn.html&FC3=/myen/html/iwgen/society_environment/environment/susta inable2003/sd03_protectthee nvironment_1008.html , 2004


### [10] Shell Nigeria 2004 People and the environment Annua l Report,2005


### [11] Nederlandse Aardolie Maatschappij (NAM): Bron van e nergie, 2003


### [12] BP Pakistan 2003 Environmental Statement, 2004


### [13] BP Trinidad & Tobago: 2003 Environmental Statement Trinidad BU, 2004


### [14] Shell in the UK report 2001, 2002


### [15] Newfoundland Ocean Industries Association: Natural Gas Utilization Study, 1998


### [16] EIA: C.2 Barrels of Crude Oil Per Metric Ton, 1980 -2003, 2005


### [17] EIA: C.3 Gross Heat Content of Crude Oil, 1980-200 3, 2005


### [18] Haverly: Crude assay libraries, 2005


### [19] ChevronTexaco: http://www.chevrontexaco.com/crudemarketing , 2005


### [20] Energy Intelligence Group: The Crude Oils and Their Key Characteristics, 2003Documentation Crude oil production 2002

Oil production in Canada 8 / 8 05/08/2008 

### [21] OGP: Environmental aspects of the use and disposal of non aqueous drilling fluids

associated with offshore oil& gas operations, 2003


### [22] Da Prat, G.: Well Testing management , SPE Foundati on, presentation 2002


### [23] Vickery et al.: Successful high rate gas completion through combination of extreme

overbalance perforating and one trip perforate and gravel pack techniques, Baker oil tools, 2001


### [24] N. Lapeyrouse: Formulas and calculations for Drilli ng, Production and work over,

2nd Edition, Golf Professional Publishing, 2002


### [25] Gordon, D. et al. Underbalanced Drilling with casin g SPE, SPE Drilling & completion

2005


### [26] Ohio Department of Health: Materials used in drilli ng and construction of wells, 1999


### [27] Culver, G.: Drilling and well construction, Chapter 6, OIST, Department of Energy

1998


### [28] Vektor AS – Environmental developments in Well test ing, 2000


### [29] Uniongas, http://www.uniongas.com/aboutus/aboutng/c omposition.asp,2006


### [30] OGP, International Association of Oil and Gas Produ cers: Environmental performance in the E&P industry 2003


### [31] US EPA: Compilation of Air pollutant emission facto rs, AP 42, Volume I: Stationary

point and area sources, Fifth edition, United State s Protection Agency, Office of air quality planning and standards, 1995-2000.


### [32] US EPA: Profile of the Oil and Gas Extraction Indus try, 2nd Section, 2000


### [33] PSI: Management of produced water on offshore oil i nstallations, Policy Studies Institute, 2005


### [34] OGP: Aromatics in produced water occurrence, fate & effects and treatment, International Association of Oil and Gas Producers, 2002


### [35] OGP: Fate and effects of naturally occurring substa nces in produced water on the

marine environment, International Association of Oi l and Gas Producers, 2005


### [36] Leahey, G et at.: Theoretical and observational ass essments of flare efficiencies,

Journal of Air & Waste Management Association, Volu me 51, December 2001


### [37] Johnson, M.R. et al.: Efficiency measurements of fl ares in a cross flow, Dep. Of Mechanical Engineering, University of Alberta, Combus tion Canada conference,
1999Documentation Crude oil production 2002

Oil production in Ecuador 1 / 8 05/08/2008 

## Production of crude oil in Ecuador

1. Technology description of the Crude oil producti on

1.1 Introduction The production of crude oil was modelled as a combi ned natural gas and crude oil production. In most cases beside crude oil, different par ts of natural gas and NGL (natural gas liquids) are produced as by-products. For the diffe rent by-products allocation by lower calorific value was applied. The combined productio n comprises the exploration and production of crude oil and natural gas as well as all the desulphurization of natural gas. The data set includes all relevant parts of the upstrea m industry. Production may take place onshore and offshore. Both are taken into account p roportionate to their ratio of the total production of a country.



### 1.2 Exploration Exploration comprises the search of hydrocarbon (HC ) deposits and the drilling of wells. The search for new deposits is conducted at first b y seismic survey, which is not included in the data set. In a second step testing wells are drilled which can be characterized as wildcat wells for areas with low information about the subsurface, exploration wells for information gathering and appraisal wells to assess characteristics such as flow rate, amount of hydrocarbon, pressure and others. After a successful testing the production well is drilled to produce hydrocarbons. Vertical wells are drilled by the rotary mode. The base of a drilling facility is a rig. For offshore drilling jack-up rigs, based on a buoyant ste el hull with 3 or more legs, semisubmersible rigs, which float at all times on ponto ons, or drill ships are used. The oil rig contains machinery and fulfils the role of superstr ucture bearing the load of a drill string. Driven by a diesel unit the drill string transmits his rotation on a drill bit, which brakes up the stone and extends the hole (up to 0,8 m wide). The drill string is gradually lengthened as the well gets deeper. The drill cuttings are rem oved by a drilling fluid (drilling mud), which is pumped inside the drill string, leaves the drill string at the drill bit and is then floated together with the drill cuttings back to th e surface between drill string and the inner surface of the well due to the high pressure genera ted by piston pumps. At the rig the drilling fluid is separated from drill cuttings and circ ulated. The drilling fluid also serves to cool the drill bit, to seal the drill hole against seepa ge and to prevent wall cave-ins. Depending on geology and technology water-based, oil-based an d synthetic-based fluids are used. They are mixed with barium sulphate and bentonite t o increase the density of the fluid as well as further additives. After finishing the dril ling or at least after 1000m, the well is cased with concrete and smoothly steel pipes (0.08- 0.2 m diameter) and prepared for production. In general due to the lack of infrastructu re for preparing and transportation, produced oil and gas is flared. Small amounts of gas a re also vented into the atmosphere. During the drilling high amounts of drill cuttings and waste water arise. At offshore exploration the cuttings are discharged to water or brou ght ashore depending on drilling fluid and legislation.Documentation Crude oil production 2002

Oil production in Ecuador 2 / 8 05/08/2008 

### 1.3 Production & Preparation Ideally the oil is transported as an oil-gas mixtur e to the surface without any effort by the high pressure of the hydrocarbon deposit. The flow of oil runs dry, when the pressure of the deposit will get lower as the flow resistance o r when the pressure was already lower at the beginning. For further exploitation it is neces sary to use pumps or to reinject a part of the separated natural gas to maintain a high pressu re in the deposit. Advanced measures raise the production are the reinjection of produce d water or sea water and the reinjection of steam to increase the viscosity or surface tensi on of the oil-gas mixture. The produced oil-gas mixture is a composite of crud e oil, natural gas, brine and other impurities. In a preparation process the natural gas and the NGL is separated from the oil. In a second preparation step most of the water is sepa rated from the oil due to the different densities. The remaining emulsified water and salt is removed in a dewatering and desalting plant. Small amounts of produced natural gas a re often still flared, sometimes also vented, due to missing preparation and transportati on opportunities. Hydrogen sulphide contained in the natural gas in different concentra tions, has to be removed before transportation via pipelines due to the high corrosive i mpact. The hydrogen sulphide is recovered from the natural gas by the Claus process prod ucing elementary sulphur and, depending on technology standards, a certain amount o f sulphur dioxide. The arising water with concentrations of approximately 15 or more mg hydrocarbons per litre is reinjected into the gas field, discharged into the sea (onshor e and in shore) or evaporated in pits. During preparation different kinds of waste and use d chemicals arise which have to be disposed. A certain amount of gas and oil is flared or vented into the atmosphere because of leakage or security reasons. The mechanical ener gy and electricity for pumping and all other machinery is provided by gas turbines and die sel units. At onshore facilities a certain amount is provided by the grid.Documentation Crude oil production 2002

Oil production in Ecuador 3 / 8 05/08/2008 

## 2 General comments of the LCA assessment method
This chapter gives background information on the pr incipal modelling approach.



### 2.1 System boundaries and functional unit

Functional unit: The functional unit is 1 bbl of cr ude oil. This process includes all relevant Mass and energy flows for the exploration and extraction of crude oil. Figure 2-1 gives an overview on the considered processes along with their key in- and outputs

Cement, Steel pipe, chemicals

Energy

(electrical, mechanical) Drilling meter Onshore

Production

Offshore Production Flaring / venting
Wastes Flaring / venting
Wastes

Crude oil Energy (electrical, mechanical) Drilling meter Exploration Flaring / venting Energy (electrical) Bentonite, Bariumsulphate System boundary

Figure 2-1 System boundary for crude oil production

The exploration is modelled per drilling meters and is considered in the model via drilling meters per mass of produced hydrocarbon. Quantities of borehole volume, removed rock are based on multiple sources such as [11]-[13]. Am ount of bentonite and bariumsulphate and water for drilling mud is taken from [11]. The material used for reinforcing the well is calculated based on [14]-[17]. The power demand for drilling is taken from [18]. For venting of natural gas the averaged national natural ga s composition is [19]. The energy demand for production is given in section 3.2. The as sociated emissions are calculated using emission factors sourced from [20] and industry data. Venting of solution gas from oil producing well is also considered. For flaring regi on specific flare emissions are included see section 3.3 and [4],[25],[26]. Solid wastes and waste water are considered. The referring data is sourced from [4], [21]-[24] and as sta ted in section 3.4.



### 2.2 Allocation or system expansion For the combined crude oil, natural gas and natural gas liquids production allocation by lower calorific value is applied. The lower heating values of the products are given in section 3.5.Documentation Crude oil production 2002

Oil production in Ecuador 4 / 8 05/08/2008 

### 2.3 Data completeness The coverage for the exploration data (crude oil, n atural gas, natural gas liquids) is 90% of mass and energy and 95% of the environmental releva nce (expert judgement).



### 2.4 Data selection and combination principles The data sources for the complete product system ar e sufficiently consistent: The data on the energy carrier supply chain is based on statist ics with country/region specific transport distances and energy carrier composition as well as industry and literature data on the inventory of exploration, extraction and processing . LCI modelling is fully consistent.



### 2.5 Reference year Reference year for the data set is 2002. Although s ome of the emission data and product properties are sourced from different years represe ntativeness for the reference year is considered good.



### 2.6 Data treatment and extrapolations principles In terms of the country/region specific crude oil p roduction, missing data of certain parameters has been used from countries with a compar able technology 1 . Data measured at a group of representative production facilities hav e been used to represent the national production.

1 If this ist he case it is indicated in the tables in section 3.Documentation Crude oil production 2002

Oil production in Ecuador 5 / 8 05/08/2008 

## 3 Country specific data

3.1 Production Table 1 shows the production ratio of natural gas, NGL and crude oil on a weight basis as well as the drilling feet per pound hydrocarbon pro duced.

Table 1 Production parameters

Parameter Value Source

Portion of natural gas production 0% [1]

Portion of NGL production 0.41% [1]

Portion of crude oil production 99.59% [2]

Drilling meters for onshore production 0.46 x10 -06 ft/lb HC produced [3]



### 3.2 Energy use The specific energy use distinguished between elect ricity and mechanical energy is shown in Table 2.

Table 2 Energy consumption parameters

Parameter Value Source

Electricity demand 22.79 Btu/lb HC Value for Region LatinAmerica [4] and own calulations

Mechanical energy demand 206.36 Btu/lb HC Value for Region LatinAmerica [4] and own calulations

Total energy demand 227.85 Btu/lb HC Value for Region Latin America [4]



### 3.3 Flaring and venting The flaring and venting of hydrocarbons during the production process is shown in Table 3. The flared Hydrocarbons are the sum of flared na tural gas and solution gas compounds.Documentation Crude oil production 2002

Oil production in Ecuador 6 / 8 05/08/2008 Table 3 Flaring and venting parameters

Parameter Value Source

Flared Hydrocarbons 0.033 lb/lb HC [10]

Vented Hydrocarbons 0.0011 lb/lb HC [10]



### 3.4 Waste and waste water
The amount of solid waste and waste water emitted d uring the production process is summarised in Table 4.

Table 4 Waste and waste water parameters

Parameter Value Source

Solid waste 0.000073 lb/lb HC Value for Trinidad Tobago [5]

Waste water onshore 0.017 lb/lb HC Value for Region Latin America [4]



### 3.5 Product properties The lower heating value as a country specific produ ct property is given in Table 5.

Table 5 Product properties

Parameter Value Source

Net calorific value natural gas 20760.35 Btu/lb [1]

Net calorific value crude oil 18094.91 Btu/lb [6];[ 7];[8];[9]Documentation Crude oil production 2002

Oil production in Ecuador 7 / 8 05/08/2008 

## 4 References

[1] IEA: Natural Gas Information 2002, International En ergy Agency, 2004


### [2] IEA: Oil information 2002, International Energy Age ncy, 2004


### [3] Pennwell: The international petroleum Encyclopedia 1997


### [4] OGP, International Association of Oil and Gas Produ cers: Environmental performance in the E&P industry 2003


### [5] BP Trinidad & Tobago: 2003 Environmental Statement Trinidad BU, 2004


### [6] EIA: C.2 Barrels of Crude Oil Per Metric Ton, 1980 -2003, 2004


### [7] EIA: C.3 Gross Heat Content of Crude Oil, 1980-200 3, 2004


### [8] Haverly: Crude assay libraries, 2005


### [9] Energy Intelligence Group: The Crude Oils and Their Key Characteristics, 2003


### [10] EIA: International Energy Annual 2003; Energy Infor mation Administration, 2004


### [11] OGP: Environmental aspects of the use and disposal of non aqueous drilling fluids

associated with offshore oil& gas operations, 2003


### [12] Da Prat, G.: Well Testing management , SPE Foundati on, presentation 2002


### [13] Vickery et al.: Successful high rate gas completion through combination of extreme

overbalance perforating and one trip perforate and gravel pack techniques, Baker oil tools, 2001


### [14] N. Lapeyrouse: Formulas and calculations for Drilli ng, Production and work over,

2nd Edition, Golf Professional Publishing, 2002


### [15] Gordon, D. et al. Underbalanced Drilling with casin g SPE, SPE Drilling & completion

2005


### [16] Ohio Department of Health: Materials used in drilli ng and construction of wells, 1999


### [17] Culver, G.: Drilling and well construction, Chapter 6, OIST, Department of Energy

1998


### [18] Vektor AS – Environmental developments in Well test ing, 2000


### [19] EIA: C.5 Gross Heat Content of Dry Natural Gas Prod uction, 1980-2004, 2005


### [20] US EPA: Compilation of Air pollutant emission facto rs, AP 42, Volume I: Stationary

point and area sources, Fifth edition, United State s Protection Agency, Office of air quality planning and standards, 1995-2000.Documentation Crude oil production 2002

Oil production in Ecuador 8 / 8 05/08/2008 

### [21] US EPA: Profile of the Oil and Gas Extraction Indus try, 2nd Section, 2000


### [22] PSI: Management of produced water on offshore oil i nstallations, Policy Studies Institute, 2005


### [23] OGP: Aromatics in produced water occurrence, fate & effects and treatment, International Association of Oil and Gas Producers, 2002


### [24] OGP: Fate and effects of naturally occurring substa nces in produced water on the

marine environment, International Association of Oi l and Gas Producers, 2005


### [25] Leahey, G et at.: Theoretical and observational ass essments of flare efficiencies,

Journal of Air & Waste Management Association, Volu me 51, December 2001


### [26] Johnson, M.R. et al.: Efficiency measurements of fl ares in a cross flow, Dep. Of Mechanical Engineering, University of Alberta, Combus tion Canada conference,
1999Documentation Crude oil production 2002

Oil production in Iraq 1 / 8 05/08/2008 

## Production of crude oil in Iraq

1. Technology description of the Crude oil producti on

1.1 Introduction The production of crude oil was modelled as a combi ned natural gas and crude oil production. In most cases beside crude oil, different par ts of natural gas and NGL (natural gas liquids) are produced as by-products. For the diffe rent by-products allocation by lower calorific value was applied. The combined productio n comprises the exploration and production of crude oil and natural gas as well as all the desulphurization of natural gas. The data set includes all relevant parts of the upstrea m industry. Production may take place onshore and offshore. Both are taken into account p roportionate to their ratio of the total production of a country.



### 1.2 Exploration Exploration comprises the search of hydrocarbon (HC ) deposits and the drilling of wells. The search for new deposits is conducted at first b y seismic survey, which is not included in the data set. In a second step testing wells are drilled which can be characterized as wildcat wells for areas with low information about the subsurface, exploration wells for information gathering and appraisal wells to assess characteristics such as flow rate, amount of hydrocarbon, pressure and others. After a successful testing the production well is drilled to produce hydrocarbons. Vertical wells are drilled by the rotary mode. The base of a drilling facility is a rig. For offshore drilling jack-up rigs, based on a buoyant ste el hull with 3 or more legs, semisubmersible rigs, which float at all times on ponto ons, or drill ships are used. The oil rig contains machinery and fulfils the role of superstr ucture bearing the load of a drill string. Driven by a diesel unit the drill string transmits his rotation on a drill bit, which brakes up the stone and extends the hole (up to 0,8 m wide). The drill string is gradually lengthened as the well gets deeper. The drill cuttings are rem oved by a drilling fluid (drilling mud), which is pumped inside the drill string, leaves the drill string at the drill bit and is then floated together with the drill cuttings back to th e surface between drill string and the inner surface of the well due to the high pressure genera ted by piston pumps. At the rig the drilling fluid is separated from drill cuttings and circ ulated. The drilling fluid also serves to cool the drill bit, to seal the drill hole against seepa ge and to prevent wall cave-ins. Depending on geology and technology water-based, oil-based an d synthetic-based fluids are used. They are mixed with barium sulphate and bentonite t o increase the density of the fluid as well as further additives. After finishing the dril ling or at least after 1000m, the well is cased with concrete and smoothly steel pipes (0.08- 0.2 m diameter) and prepared for production. In general due to the lack of infrastructu re for preparing and transportation, produced oil and gas is flared. Small amounts of gas a re also vented into the atmosphere. During the drilling high amounts of drill cuttings and waste water arise. At offshore exploration the cuttings are discharged to water or brou ght ashore depending on drilling fluid and legislation.Documentation Crude oil production 2002

Oil production in Iraq 2 / 8 05/08/2008 

### 1.3 Production & Preparation Ideally the oil is transported as an oil-gas mixtur e to the surface without any effort by the high pressure of the hydrocarbon deposit. The flow of oil runs dry, when the pressure of the deposit will get lower as the flow resistance o r when the pressure was already lower at the beginning. For further exploitation it is neces sary to use pumps or to reinject a part of the separated natural gas to maintain a high pressu re in the deposit. Advanced measures raise the production are the reinjection of produce d water or sea water and the reinjection of steam to increase the viscosity or surface tensi on of the oil-gas mixture. The produced oil-gas mixture is a composite of crud e oil, natural gas, brine and other impurities. In a preparation process the natural gas and the NGL is separated from the oil. In a second preparation step most of the water is sepa rated from the oil due to the different densities. The remaining emulsified water and salt is removed in a dewatering and desalting plant. Small amounts of produced natural gas a re often still flared, sometimes also vented, due to missing preparation and transportati on opportunities. Hydrogen sulphide contained in the natural gas in different concentra tions, has to be removed before transportation via pipelines due to the high corrosive i mpact. The hydrogen sulphide is recovered from the natural gas by the Claus process prod ucing elementary sulphur and, depending on technology standards, a certain amount o f sulphur dioxide. The arising water with concentrations of approximately 15 or more mg hydrocarbons per litre is reinjected into the gas field, discharged into the sea (onshor e and in shore) or evaporated in pits. During preparation different kinds of waste and use d chemicals arise which have to be disposed. A certain amount of gas and oil is flared or vented into the atmosphere because of leakage or security reasons. The mechanical ener gy and electricity for pumping and all other machinery is provided by gas turbines and die sel units. At onshore facilities a certain amount is provided by the grid.Documentation Crude oil production 2002

Oil production in Iraq 3 / 8 05/08/2008 

## 2 General comments of the LCA assessment method
This chapter gives background information on the pr incipal modelling approach.



### 2.1 System boundaries and functional unit

Functional unit: The functional unit is 1 bbl of cr ude oil. This process includes all relevant Mass and energy flows for the exploration and extraction of crude oil. Figure 2-1 gives an overview on the considered processes along with their key in- and outputs

Cement, Steel pipe, chemicals

Energy

(electrical, mechanical) Drilling meter Onshore

Production

Offshore Production Flaring / venting
Wastes Flaring / venting
Wastes

Crude oil Energy (electrical, mechanical) Drilling meter Exploration Flaring / venting Energy (electrical) Bentonite, Bariumsulphate System boundary

Figure 2-1 System boundary for crude oil production

The exploration is modelled per drilling meters and is considered in the model via drilling meters per mass of produced hydrocarbon. Quantities of borehole volume, removed rock are based on multiple sources such as [15]-[17]. Am ount of Bentonite and Bariumsulphate and water for drilling mud is taken from [15]. The material used for reinforcing the well is calculated based on [18]-[21]. The power demand for drilling is taken from [22]. For venting of natural gas the averaged national natural ga s composition is considered [30]. The energy demand for production is given in section 3. 2. The associated emissions are calculated using emission factors sourced from [23] and industry data. Venting of solution gas from oil producing well is also considered. For fla ring region specific flare amounts and emissions are included, see section 3.3 and [4], [2 8], [29]. Solid wastes and waste water are considered. The referring data is sourced from [4], [24]-[27] and as stated in section 3.4.



### 2.2 Allocation or system expansion For the combined crude oil, natural gas and natural gas liquids production allocation by lower calorific value is applied. The lower heating values of the products are given in section 3.5.Documentation Crude oil production 2002

Oil production in Iraq 4 / 8 05/08/2008 

### 2.3 Data completeness The coverage for the exploration data (crude oil, n atural gas, natural gas liquids) is 90% of mass and energy and 95% of the environmental releva nce (expert judgement).



### 2.4 Data selection and combination principles The data sources for the complete product system ar e sufficiently consistent: The data on the energy carrier supply chain is based on statist ics with country/region specific transport distances and energy carrier composition as well as industry and literature data on the inventory of exploration, extraction and processing . LCI modelling is fully consistent.



### 2.5 Reference year Reference year for the data set is 2002. Although s ome of the emission data and product properties are sourced from different years represe ntativeness for the reference year is considered good.



### 2.6 Data treatment and extrapolations principles In terms of the country/region specific crude oil p roduction, missing data of certain parameters has been used from countries with a compar able technology 1 . Data measured at a group of representative production facilities hav e been used to represent the national production.

1 If this ist he case it is indicated in the tables in section 3.Documentation Crude oil production 2002

Oil production in Iraq 5 / 8 05/08/2008 

## 3 Country specific data

3.1 Production Table 1 shows the production ratio of natural gas, NGL and crude oil on a weight basis as well as the drilling feet per pound hydrocarbon pro duced.

Table 1 Production parameters

Parameter Value Source

Portion of natural gas production 3.18% [1]

Portion of NGL production 0.64% [1]

Portion of crude oil production 96.18% [2]

Drilling meters for onshore production 0.29x10-07 ft/lb HC produced [3]



### 3.2 Energy use The specific energy use distinguished between elect ricity and mechanical energy is shown in Table 2.

Table 2 Energy consumption parameters

Parameter Value Source

Electricity demand 24.50 Btu/lb HC Value for middle east region [4] and own calculations

Mechanical energy demand 219.25 Btu/lb HC Value for middle east region [4] and own calculations

Total energy demand 245.05 Btu/lb HC Value for midd le east region [4]



### 3.3 Flaring and venting The flaring and venting of hydrocarbons during the production process is shown in Table 3. The flared Hydrocarbons are the sum of flared na tural gas and solution gas compounds.Documentation Crude oil production 2002

Oil production in Iraq 6 / 8 05/08/2008 Table 3 Flaring and venting parameters

Parameter Value Source

Flared Hydrocarbons 0.0059 lb/lb HC [14]

Vented Hydrocarbons 0.0017 lb/lb HC [14]



### 3.4 Waste and waste water
The amount of solid waste and waste water emitted d uring the production process is summarised in Table 4.

Table 4 Waste and waste water parameters

Parameter Value Source

Solid waste 0.0060 lb/lb HC Global value [5];[6];[7];[8];[9];[10];[11]

Waste water onshore 0.030 lb/lb HC Value for middle east region [4]



### 3.5 Product properties The lower heating value as a country specific produ ct property is given in Table 5.

Table 5 Product properties

Parameter Value Source

Net calorific value natural gas 18413.05 Btu/lb [1]

Net calorific value crude oil 18288.37 Btu/lb [12]; [13]Documentation Crude oil production 2002

Oil production in Iraq 7 / 8 05/08/2008 

## 4 References

[1] IEA: Natural Gas Information 2002, International En ergy Agency, 2004


### [2] IEA: Oil information 2002, International Energy Age ncy, 2004


### [3] Pennwell: The international petroleum Encyclopaedia 1997


### [4] OGP, International Association of Oil and Gas Produ cers: Environmental performance in the E&P industry 2003, 2004


### [5] Yukos: Yukos and the environment, 2003


### [6] Shell: http://www.shell.com/home/Framework?siteId=my-en&FC 2=/myen/html/iwgen/society_environment/environment/susta inable2003/zzz_lhn.html&FC3=/myen/html/iwgen/society_environment/environment/susta inable2003/sd03_protectthee nvironment_1008.html , 2004


### [7] Shell Nigeria 2004 People and the environment Annua l Report, 2005


### [8] Nederlandse Aardolie Maatschappij (NAM): Bron van e nergie, 2003


### [9] BP Pakistan 2003 Environmental Statement, 2004


### [10] BP Trinidad & Tobago: 2003 Environmental Statement Trinidad BU, 2004


### [11] Shell in the UK report 2001, 2002


### [12] Haverly: Crude assay libraries, 2005


### [13] Energy Intelligence Group: The Crude Oils and Their Key Characteristics, 2003


### [14] EIA: International Energy Annual 2003; Energy Infor mation Administration, 2004


### [15] OGP: Environmental aspects of the use and disposal of non aqueous drilling fluids

associated with offshore oil& gas operations, 2003


### [16] Da Prat, G.: Well Testing management , SPE Foundati on, presentation 2002


### [17] Vickery et al.: Successful high rate gas completion through combination of extreme

overbalance perforating and one trip perforate and gravel pack techniques, Baker oil tools, 2001


### [18] N. Lapeyrouse: Formulas and calculations for Drilli ng, Production and work over,

2nd Edition, Golf Professional Publishing, 2002


### [19] Gordon, D. et al. Underbalanced Drilling with casin g SPE, SPE Drilling & completion

2005Documentation Crude oil production 2002

Oil production in Iraq 8 / 8 05/08/2008 

### [20] Ohio Department of Health: Materials used in drilli ng and construction of wells, 1999


### [21] Culver, G.: Drilling and well construction, Chapter 6, OIST, Department of Energy

1998


### [22] Vektor AS – Environmental developments in Well test ing, 2000


### [23] US EPA: Compilation of Air pollutant emission facto rs, AP 42, Volume I: Stationary

point and area sources, Fifth edition, United State s Protection Agency, Office of air quality planning and standards, 1995-2000.


### [24] US EPA: Profile of the Oil and Gas Extraction Indus try, 2nd Section, 2000


### [25] PSI: Management of produced water on offshore oil i nstallations, Policy Studies Institute, 2005


### [26] OGP: Aromatics in produced water occurrence, fate & effects and treatment, International Association of Oil and Gas Producers, 2002


### [27] OGP: Fate and effects of naturally occurring substa nces in produced water on the

marine environment, International Association of Oi l and Gas Producers, 2005


### [28] Leahey, G et at.: Theoretical and observational ass essments of flare efficiencies,

Journal of Air & Waste Management Association, Volu me 51, December 2001


### [29] Johnson, M.R. et al.: Efficiency measurements of fl ares in a cross flow, Dep. Of Mechanical Engineering, University of Alberta, Combus tion Canada conference,
1999


### [30] EIA: C.5 Gross Heat Content of Dry Natural Gas Prod uction, 1980-2004, 2005Documentation Crude oil production 2002

Oil production in Kuwait 1 / 8 05/08/2008 

## Production of crude oil in Kuwait

1. Technology description of the Crude oil producti on

1.1 Introduction The production of crude oil was modelled as a combi ned natural gas and crude oil production. In most cases beside crude oil, different par ts of natural gas and NGL (natural gas liquids) are produced as by-products. For the diffe rent by-products allocation by lower calorific value was applied. The combined productio n comprises the exploration and production of crude oil and natural gas as well as all the desulphurization of natural gas. The data set includes all relevant parts of the upstrea m industry. Production may take place onshore and offshore. Both are taken into account p roportionate to their ratio of the total production of a country.



### 1.2 Exploration Exploration comprises the search of hydrocarbon (HC ) deposits and the drilling of wells. The search for new deposits is conducted at first b y seismic survey, which is not included in the data set. In a second step testing wells are drilled which can be characterized as wildcat wells for areas with low information about the subsurface, exploration wells for information gathering and appraisal wells to assess characteristics such as flow rate, amount of hydrocarbon, pressure and others. After a successful testing the production well is drilled to produce hydrocarbons. Vertical wells are drilled by the rotary mode. The base of a drilling facility is a rig. For offshore drilling jack-up rigs, based on a buoyant ste el hull with 3 or more legs, semisubmersible rigs, which float at all times on ponto ons, or drill ships are used. The oil rig contains machinery and fulfils the role of superstr ucture bearing the load of a drill string. Driven by a diesel unit the drill string transmits his rotation on a drill bit, which brakes up the stone and extends the hole (up to 0,8 m wide). The drill string is gradually lengthened as the well gets deeper. The drill cuttings are rem oved by a drilling fluid (drilling mud), which is pumped inside the drill string, leaves the drill string at the drill bit and is then floated together with the drill cuttings back to th e surface between drill string and the inner surface of the well due to the high pressure genera ted by piston pumps. At the rig the drilling fluid is separated from drill cuttings and circ ulated. The drilling fluid also serves to cool the drill bit, to seal the drill hole against seepa ge and to prevent wall cave-ins. Depending on geology and technology water-based, oil-based an d synthetic-based fluids are used. They are mixed with barium sulphate and bentonite t o increase the density of the fluid as well as further additives. After finishing the dril ling or at least after 1000m, the well is cased with concrete and smoothly steel pipes (0.08- 0.2 m diameter) and prepared for production. In general due to the lack of infrastructu re for preparing and transportation, produced oil and gas is flared. Small amounts of gas a re also vented into the atmosphere. During the drilling high amounts of drill cuttings and waste water arise. At offshore exploration the cuttings are discharged to water or brou ght ashore depending on drilling fluid and legislation.Documentation Crude oil production 2002

Oil production in Kuwait 2 / 8 05/08/2008 

### 1.3 Production & Preparation Ideally the oil is transported as an oil-gas mixtur e to the surface without any effort by the high pressure of the hydrocarbon deposit. The flow of oil runs dry, when the pressure of the deposit will get lower as the flow resistance o r when the pressure was already lower at the beginning. For further exploitation it is neces sary to use pumps or to reinject a part of the separated natural gas to maintain a high pressu re in the deposit. Advanced measures raise the production are the reinjection of produce d water or sea water and the reinjection of steam to increase the viscosity or surface tensi on of the oil-gas mixture. The produced oil-gas mixture is a composite of crud e oil, natural gas, brine and other impurities. In a preparation process the natural gas and the NGL is separated from the oil. In a second preparation step most of the water is sepa rated from the oil due to the different densities. The remaining emulsified water and salt is removed in a dewatering and desalting plant. Small amounts of produced natural gas a re often still flared, sometimes also vented, due to missing preparation and transportati on opportunities. Hydrogen sulphide contained in the natural gas in different concentra tions, has to be removed before transportation via pipelines due to the high corrosive i mpact. The hydrogen sulphide is recovered from the natural gas by the Claus process prod ucing elementary sulphur and, depending on technology standards, a certain amount o f sulphur dioxide. The arising water with concentrations of approximately 15 or more mg hydrocarbons per litre is reinjected into the gas field, discharged into the sea (onshor e and in shore) or evaporated in pits. During preparation different kinds of waste and use d chemicals arise which have to be disposed. A certain amount of gas and oil is flared or vented into the atmosphere because of leakage or security reasons. The mechanical ener gy and electricity for pumping and all other machinery is provided by gas turbines and die sel units. At onshore facilities a certain amount is provided by the grid.Documentation Crude oil production 2002

Oil production in Kuwait 3 / 8 05/08/2008 

## 2 General comments of the LCA assessment method
This chapter gives background information on the pr incipal modelling approach.



### 2.1 System boundaries and functional unit

Functional unit: The functional unit is 1 bbl of cr ude oil. This process includes all relevant Mass and energy flows for the exploration and extraction of crude oil. Figure 2-1 gives an overview on the considered processes along with their key in- and outputs

Cement, Steel pipe, chemicals

Energy

(electrical, mechanical) Drilling meter Onshore

Production

Offshore Production Flaring / venting
Wastes Flaring / venting
Wastes

Crude oil Energy (electrical, mechanical) Drilling meter Exploration Flaring / venting Energy (electrical) Bentonite, Bariumsulphate System boundary

Figure 2-1 System boundary for crude oil production

The exploration is modelled per drilling meters and is considered in the model via drilling meters per mass of produced hydrocarbon. Quantities of borehole volume, removed rock are based on multiple sources such as [3],[16],[17] . Amount of Bentonite and Bariumsulphate and water for drilling mud is taken from [3]. The material used for reinforcing the well is calculated based on [18]-[21]. The power de mand for drilling is taken from [22]. For venting of natural gas the averaged national natura l gas composition is considered [33], [23] and [32]. The energy demand for production is given in section 3.2. The associated emissions are calculated using emission factors sou rced from [25] and industry data. Venting of solution gas from oil producing well is also considered. For flaring region specific flare amounts and emissions are included, see section 3.3 and [24], [30], [31]. Solid wastes and waste water are considered. The referrin g data is sourced from [24], [26]-[29] and as stated in section 3.4.



### 2.2 Allocation or system expansion For the combined crude oil, natural gas and natural gas liquids production allocation by lower calorific value is applied. The lower heating values of the products are given in section 3.5.Documentation Crude oil production 2002

Oil production in Kuwait 4 / 8 05/08/2008 

### 2.3 Data completeness The coverage for the exploration data (crude oil, n atural gas, natural gas liquids) is 90% of mass and energy and 95% of the environmental releva nce (expert judgement).



### 2.4 Data selection and combination principles The data sources for the complete product system ar e sufficiently consistent: The data on the energy carrier supply chain is based on statist ics with country/region specific transport distances and energy carrier composition as well as industry and literature data on the inventory of exploration, extraction and processing . LCI modelling is fully consistent.



### 2.5 Reference year Reference year for the data set is 2002. Although s ome of the emission data and product properties are sourced from different years represe ntativeness for the reference year is considered good.



### 2.6 Data treatment and extrapolations principles In terms of the country/region specific crude oil p roduction, missing data of certain parameters has been used from countries with a compar able technology 1 . Data measured at a group of representative production facilities hav e been used to represent the national production.

1 If this ist he case it is indicated in the tables in section 3.Documentation Crude oil production 2002

Oil production in Kuwait 5 / 8 05/08/2008 

## 3 Country specific data

3.1 Production Table 1 shows the production ratio of natural gas, NGL and crude oil on a weight basis as well as the drilling feet per pound hydrocarbon pro duced.

Table 1 Production parameters

Parameter Value Source

Portion of natural gas production 6.44% [33]

Portion of NGL production 3.70% [33]

Portion of crude oil production 89.86% [1]

Drilling meters for onshore production 1.23x10 -07 ft/lb HC produced [2]



### 3.2 Energy use The specific energy use distinguished between elect ricity and mechanical energy is shown in Table 2.

Table 2 Energy consumption parameters

Parameter Value Source

Electricity demand 24.5 Btu/lb Value for Region MiddleEast [24] and own calculations

Mechanical energy demand 219.25 Btu/lb Value for Region MiddleEast [24] and own calculations

Total energy demand 245.05 Btu/lb Value for Region Middle East [24]



### 3.3 Flaring and venting The flaring and venting of hydrocarbons during the production process is shown in Table 3. The flared Hydrocarbons are the sum of flared na tural gas and solution gas compounds.Documentation Crude oil production 2002

Oil production in Kuwait 6 / 8 05/08/2008 Table 3 Flaring and venting parameters

Parameter Value Source

Flared Hydrocarbons 0.0007 lb/lb HC [15]

Vented Hydrocarbons 0.0025 lb/lb HC [15]



### 3.4 Waste and waste water
The amount of solid waste and waste water emitted d uring the production process is summarised in Table 4.

Table 4 Waste and waste water parameters

Parameter Value Source

Solid waste 0.0060 lb/lb HC Global value [3];[5];[6];[7];[8];[9];[10]

Waste water onshore 0.030 lb/lb HC Value for Region Middle East [24]



### 3.5 Product properties The lower heating value as a country specific produ ct property is given in Table 5.

Table 5 Product properties

Parameter Value Source

Net calorific value natural gas 18413.05 Btu/lb [32 ]

Net calorific value crude oil 18219.59 Btu/lb [13]; [14];[13];[14]Documentation Crude oil production 2002

Oil production in Kuwait 7 / 8 05/08/2008 

## 4 References

[1] IEA: Oil information 2002, International Energy Age ncy, 2004


### [2] Pennwell: The international petroleum Encyclopaedia 1997


### [3] OGP: Environmental aspects of the use and disposal of non aqueous drilling fluids

associated with offshore oil& gas operations, 2003


### [4] Yukos: Yukos and the environment, 2003


### [5] Shell: http://www.shell.com/home/Framework?siteId=my-en&FC 2=/myen/html/iwgen/society_environment/environment/susta inable2003/zzz_lhn.html&FC3=/myen/html/iwgen/society_environment/environment/susta inable2003/sd03_protectthee nvironment_1008.html , 2004


### [6] Shell Nigeria 2004 People and the environment Annua l Report, 2005


### [7] Nederlandse Aardolie Maatschappij (NAM): Bron van e nergie, 2003


### [8] BP Pakistan 2003 Environmental Statement, 2004


### [9] BP Trinidad & Tobago: 2003 Environmental Statement Trinidad BU


### [10] Shell in the UK report 2001, 2002


### [11] EIA: C.2 Barrels of Crude Oil Per Metric Ton, 1980 -2003, 2004


### [12] EIA: C.3 Gross Heat Content of Crude Oil, 1980-200 3, 2004


### [13] Haverly: Crude assay libraries, 2005


### [14] Energy Intelligence Group: The Crude Oils and Their Key Characteristics, 2004


### [15] EIA: International Energy Annual 2003; Energy Infor mation Administration, 2004


### [16] Da Prat, G.: Well Testing management , SPE Foundati on, presentation 2002


### [17] Vickery et al.: Successful high rate gas completion through combination of extreme

overbalance perforating and one trip perforate and gravel pack techniques, Baker oil tools, 2001


### [18] N. Lapeyrouse: Formulas and calculations for Drilli ng, Production and work over,

2nd Edition, Golf Professional Publishing, 2002


### [19] Gordon, D. et al. Underbalanced Drilling with casin g SPE, SPE Drilling & completion

2005


### [20] Ohio Department of Health: Materials used in drilli ng and construction of wells, 1999Documentation Crude oil production 2002

Oil production in Kuwait 8 / 8 05/08/2008 

### [21] Culver, G.: Drilling and well construction, Chapter 6, OIST, Department of Energy

1998


### [22] Vektor AS – Environmental developments in Well test ing, 2000


### [23] BP: Das Buch zum Erdöl (The book on Crude oil), 198 9


### [24] OGP, International Association of Oil and Gas Produ cers: Environmental performance in the E&P industry 2003, 2004


### [25] US EPA: Compilation of Air pollutant emission facto rs, AP 42, Volume I: Stationary

point and area sources, Fifth edition, United State s Protection Agency, Office of air quality planning and standards, 1995-2000.


### [26] US EPA: Profile of the Oil and Gas Extraction Indus try, 2nd Section, 2000


### [27] PSI: Management of produced water on offshore oil i nstallations, Policy Studies Institute, 2005


### [28] OGP: Aromatics in produced water occurrence, fate & effects and treatment, International Association of Oil and Gas Producers, 2002


### [29] OGP: Fate and effects of naturally occurring substa nces in produced water on the

marine environment, International Association of Oi l and Gas Producers, 2005


### [30] Leahey, G et at.: Theoretical and observational ass essments of flare efficiencies,

Journal of Air & Waste Management Association, Volu me 51, December 2001


### [31] Johnson, M.R. et al.: Efficiency measurements of fl ares in a cross flow, Dep. Of Mechanical Engineering, University of Alberta, Combus tion Canada conference,
1999


### [32] EIA: C.2 of Dry Natural Gas Production, 1980-2004, 2005


### [33] IEA: Natural Gas Information 2002, International En ergy Agency, 2004Documentation Crude oil production 2002

Oil production in Mexico 1 / 8 05/08/2008 

## Production of crude oil in Mexico

1. Technology description of the Crude oil producti on

1.1 Introduction The production of crude oil was modelled as a combi ned natural gas and crude oil production. In most cases beside crude oil, different par ts of natural gas and NGL (natural gas liquids) are produced as by-products. For the diffe rent by-products allocation by lower calorific value was applied. The combined productio n comprises the exploration and production of crude oil and natural gas as well as all the desulphurization of natural gas. The data set includes all relevant parts of the upstrea m industry. Production may take place onshore and offshore. Both are taken into account p roportionate to their ratio of the total production of a country.



### 1.2 Exploration Exploration comprises the search of hydrocarbon (HC ) deposits and the drilling of wells. The search for new deposits is conducted at first b y seismic survey, which is not included in the data set. In a second step testing wells are drilled which can be characterized as wildcat wells for areas with low information about the subsurface, exploration wells for information gathering and appraisal wells to assess characteristics such as flow rate, amount of hydrocarbon, pressure and others. After a successful testing the production well is drilled to produce hydrocarbons. Vertical wells are drilled by the rotary mode. The base of a drilling facility is a rig. For offshore drilling jack-up rigs, based on a buoyant ste el hull with 3 or more legs, semisubmersible rigs, which float at all times on ponto ons, or drill ships are used. The oil rig contains machinery and fulfils the role of superstr ucture bearing the load of a drill string. Driven by a diesel unit the drill string transmits his rotation on a drill bit, which brakes up the stone and extends the hole (up to 0,8 m wide). The drill string is gradually lengthened as the well gets deeper. The drill cuttings are rem oved by a drilling fluid (drilling mud), which is pumped inside the drill string, leaves the drill string at the drill bit and is then floated together with the drill cuttings back to th e surface between drill string and the inner surface of the well due to the high pressure genera ted by piston pumps. At the rig the drilling fluid is separated from drill cuttings and circ ulated. The drilling fluid also serves to cool the drill bit, to seal the drill hole against seepa ge and to prevent wall cave-ins. Depending on geology and technology water-based, oil-based an d synthetic-based fluids are used. They are mixed with barium sulphate and bentonite t o increase the density of the fluid as well as further additives. After finishing the dril ling or at least after 1000m, the well is cased with concrete and smoothly steel pipes (0.08- 0.2 m diameter) and prepared for production. In general due to the lack of infrastructu re for preparing and transportation, produced oil and gas is flared. Small amounts of gas a re also vented into the atmosphere. During the drilling high amounts of drill cuttings and waste water arise. At offshore exploration the cuttings are discharged to water or brou ght ashore depending on drilling fluid and legislation.Documentation Crude oil production 2002

Oil production in Mexico 2 / 8 05/08/2008 

### 1.3 Production & Preparation Ideally the oil is transported as an oil-gas mixtur e to the surface without any effort by the high pressure of the hydrocarbon deposit. The flow of oil runs dry, when the pressure of the deposit will get lower as the flow resistance o r when the pressure was already lower at the beginning. For further exploitation it is neces sary to use pumps or to reinject a part of the separated natural gas to maintain a high pressu re in the deposit. Advanced measures raise the production are the reinjection of produce d water or sea water and the reinjection of steam to increase the viscosity or surface tensi on of the oil-gas mixture. The produced oil-gas mixture is a composite of crud e oil, natural gas, brine and other impurities. In a preparation process the natural gas and the NGL is separated from the oil. In a second preparation step most of the water is sepa rated from the oil due to the different densities. The remaining emulsified water and salt is removed in a dewatering and desalting plant. Small amounts of produced natural gas a re often still flared, sometimes also vented, due to missing preparation and transportati on opportunities. Hydrogen sulphide contained in the natural gas in different concentra tions, has to be removed before transportation via pipelines due to the high corrosive i mpact. The hydrogen sulphide is recovered from the natural gas by the Claus process prod ucing elementary sulphur and, depending on technology standards, a certain amount o f sulphur dioxide. The arising water with concentrations of approximately 15 or more mg hydrocarbons per litre is reinjected into the gas field, discharged into the sea (onshor e and in shore) or evaporated in pits. During preparation different kinds of waste and use d chemicals arise which have to be disposed. A certain amount of gas and oil is flared or vented into the atmosphere because of leakage or security reasons. The mechanical ener gy and electricity for pumping and all other machinery is provided by gas turbines and die sel units. At onshore facilities a certain amount is provided by the grid.Documentation Crude oil production 2002

Oil production in Mexico 3 / 8 05/08/2008 

## 2 General comments of the LCA assessment method
This chapter gives background information on the pr incipal modelling approach.



### 2.1 System boundaries and functional unit

Functional unit: The functional unit is 1 bbl of cr ude oil. This process includes all relevant Mass and energy flows for the exploration and extraction of crude oil. Figure 2-1 gives an overview on the considered processes along with their key in- and outputs

Cement, Steel pipe, chemicals

Energy

(electrical, mechanical) Drilling meter Onshore

Production

Offshore Production Flaring / venting
Wastes Flaring / venting
Wastes

Crude oil Energy (electrical, mechanical) Drilling meter Exploration Flaring / venting Energy (electrical) Bentonite, Bariumsulphate System boundary

Figure 2-1 System boundary for crude oil production

The exploration is modelled per drilling meters and is considered in the model via drilling meters per mass of produced hydrocarbon. Quantities of borehole volume, removed rock are based on multiple sources such as [16]-[18]. Am ount of bentonite and bariumsulphate and water for drilling mud is taken from [16]. The material used for reinforcing the well is calculated based on [19]-[22]. The power demand for drilling is taken from [23]. For venting of natural gas the averaged national natural ga s composition is considered [24], [32]. The energy demand for production is given in sectio n 3.2. The associated emissions are calculated using emission factors sourced from [25] and industry data. Venting of solution gas from oil producing well is also considered. For flaring region specific flare emissions are included see section 3.3 and [4],[30],[31]. Sol id wastes and waste water are considered. The referring data is sourced from [4], [26]- [29] and as stated in section 3.4.



### 2.2 Allocation or system expansion For the combined crude oil, natural gas and natural gas liquids production allocation by lower calorific value is applied. The lower heating values of the products are given in section 3.5.Documentation Crude oil production 2002

Oil production in Mexico 4 / 8 05/08/2008 

### 2.3 Data completeness The coverage for the exploration data (crude oil, n atural gas, natural gas liquids) is 90% of mass and energy and 95% of the environmental releva nce (expert judgement).



### 2.4 Data selection and combination principles The data sources for the complete product system ar e sufficiently consistent: The data on the energy carrier supply chain is based on statist ics with country/region specific transport distances and energy carrier composition as well as industry and literature data on the inventory of exploration, extraction and processing . LCI modelling is fully consistent.



### 2.5 Reference year Reference year for the data set is 2002. Although s ome of the emission data and product properties are sourced from different years represe ntativeness for the reference year is considered good.



### 2.6 Data treatment and extrapolations principles In terms of the country/region specific crude oil p roduction, missing data of certain parameters has been used from countries with a compar able technology 1 . Data measured at a group of representative production facilities hav e been used to represent the national production.

1 If this ist he case it is indicated in the tables in section 3.Documentation Crude oil production 2002

Oil production in Mexico 5 / 8 05/08/2008 

## 3 Country specific data

3.1 Production Table 1 shows the production ratio of natural gas, NGL and crude oil on a weight basis as well as the drilling feet per pound hydrocarbon pro duced. Note that all values are given for unallocated joint production of Natural gas, NGL an d crude oil.

Table 1 Production parameters

Parameter Value Source

Portion of natural gas production 14.02% [2]

Portion of NGL production 5.85% [2]

Portion of crude oil production 80.12% [33]

Drilling meters for onshore production 1.05 x10 -06 ft/lb HC produced [3]

Drilling meters for offshore production 1.05 x10 -06 ft/lb HC produced [3]



### 3.2 Energy use The specific energy use distinguished between elect ricity and mechanical energy is shown in Table 2.

Table 2 Energy consumption parameters

Parameter Value Source

Electricity demand 22.78 Btu/lb HC Value for region Latin America [4] and own calculations

Mechanical energy demand 202.06 Btu/lb HC Value for region Latin America [4] and own calculations

Total energy demand 227.85 Btu/lb HC Value for region Latin America [4]



### 3.3 Flaring and venting The flaring and venting of hydrocarbons during the production process is shown in Table 3. The flared Hydrocarbons are the sum of flared na tural gas and solution gas compounds.Documentation Crude oil production 2002

Oil production in Mexico 6 / 8 05/08/2008 Table 3 Flaring and venting parameters

Parameter Value Source

Flared Hydrocarbons 0.022 lb/lb HC [33], [34] and own calculations

Vented Hydrocarbons 0.0055 lb/lb HC [33], [34] and own calulations



### 3.4 Waste and waste water
The amount of solid waste and waste water emitted d uring the production process is summarised in Table 4.

Table 4 Waste and waste water parameters

Parameter Value Source

Solid waste 0.0060 lb/lb HC Global value [5];[6];[7];[8];[9];[10];[11]

Waste water onshore 0.017 lb/lb HC Value for region Latin America [4]

Waste water offshore 0.091 lb/lb HC Value for region Latin America [4]



### 3.5 Product properties The lower heating value as a country specific produ ct property is given in Table 5.

Table 5 Product properties

Parameter Value Source

Net calorific value natural gas 17755.28 Btu/lb [24]

Net calorific value crude oil 18946.13 Btu/lb [12];[13];[14];[15]Documentation Crude oil production 2002

Oil production in Mexico 7 / 8 05/08/2008 

## 4 References

[1] World Bank: Global gas flaring reduction initiative 

### , 2004
[2] IEA: Natural Gas Information 2002, International En ergy Agency, 2004


### [3] Pennwell: The international petroleum Encyclopedia 1997


### [4] OGP, International Association of Oil and Gas Produ cers: Environmental performance in the E&P industry 2003, 2004


### [5] Yukos: Yukos and the environment, 2003


### [6] Shell: http://www.shell.com/home/Framework?siteId=my-en&FC 2=/myen/html/iwgen/society_environment/environment/susta inable2003/zzz_lhn.html&FC3=/myen/html/iwgen/society_environment/environment/susta inable2003/sd03_protectthee nvironment_1008.html , 2004


### [7] Shell Nigeria 2004 People and the environment Annua l Report, 2005


### [8] Nederlandse Aardolie Maatschappij (NAM): Bron van e nergie, 2003


### [9] BP Pakistan 2003 Environmental Statement, 2004


### [10] BP Trinidad & Tobago: 2003 Environmental Statement Trinidad BU, 2004


### [11] Shell in the UK report 2001, 2002


### [12] EIA: C.2 Barrels of Crude Oil Per Metric Ton, 1980 -2003, 2004


### [13] EIA: C.3 Gross Heat Content of Crude Oil, 1980-200 3, 2004


### [14] Haverly: Crude assay libraries, 2005


### [15] Energy Intelligence Group: The Crude Oils and Their Key Characteristics, 2004


### [16] OGP: Environmental aspects of the use and disposal of non aqueous drilling fluids

associated with offshore oil& gas operations, 2003


### [17] Da Prat, G.: Well Testing management , SPE Foundati on, presentation 2002


### [18] Vickery et al.: Successful high rate gas completion through combination of extreme

overbalance perforating and one trip perforate and gravel pack techniques, Baker oil tools, 2001


### [19] N. Lapeyrouse: Formulas and calculations for Drilli ng, Production and work over,

2nd Edition, Golf Professional Publishing, 2002Documentation Crude oil production 2002

Oil production in Mexico 8 / 8 05/08/2008 

### [20] Gordon, D. et al. Underbalanced Drilling with casin g SPE, SPE Drilling & completion

2005


### [21] Ohio Department of Health: Materials used in drilli ng and construction of wells, 1999


### [22] Culver, G.: Drilling and well construction, Chapter 6, OIST, Department of Energy

1998


### [23] Vektor AS – Environmental developments in Well test ing, 2000


### [24] EIA: C.5 Gross Heat Content of Dry Natural Gas Prod uction, 1980-2004, 2005


### [25] US EPA: Compilation of Air pollutant emission facto rs, AP 42, Volume I: Stationary

point and area sources, Fifth edition, United State s Protection Agency, Office of air quality planning and standards, 1995-2000.


### [26] US EPA: Profile of the Oil and Gas Extraction Indus try, 2nd Section, 2000


### [27] PSI: Management of produced water on offshore oil i nstallations, Policy Studies Institute, 2005


### [28] OGP: Aromatics in produced water occurrence, fate & effects and treatment, International Association of Oil and Gas Producers, 2002


### [29] OGP: Fate and effects of naturally occurring substa nces in produced water on th

marine environment, International Association of Oi l and Gas Producers, 2005


### [30] Leahey, G et at.: Theoretical and observational ass essments of flare efficiencies,

Journal of Air & Waste Management Association, Volu me 51, December 2001


### [31] Johnson, M.R. et al.: Efficiency measurements of fl ares in a cross flow, Dep. Of Mechanical Engineering, University of Alberta, Combus tion Canada conference,
1999


### [32] California Energy Commission: Natural gas compositi on and Quality, 2005


### [33] IEA: Oil Information 2002, International Energy Age ncy, 2004


### [34] EIA: International Energy Annual 2003; Energy Infor mation Administration, 2004Documentation Crude oil production 2002

Oil production in Nigeria 1 / 8 05/08/2008 

## Production of crude oil in Nigeria

1. Technology description of the Crude oil producti on

1.1 Introduction The production of crude oil was modelled as a combi ned natural gas and crude oil production. In most cases beside crude oil, different par ts of natural gas and NGL (natural gas liquids) are produced as by-products. For the diffe rent by-products allocation by lower calorific value was applied. The combined productio n comprises the exploration and production of crude oil and natural gas as well as all the desulphurization of natural gas. The data set includes all relevant parts of the upstrea m industry. Production may take place onshore and offshore. Both are taken into account p roportionate to their ratio of the total production of a country.



### 1.2 Exploration Exploration comprises the search of hydrocarbon (HC ) deposits and the drilling of wells. The search for new deposits is conducted at first b y seismic survey, which is not included in the data set. In a second step testing wells are drilled which can be characterized as wildcat wells for areas with low information about the subsurface, exploration wells for information gathering and appraisal wells to assess characteristics such as flow rate, amount of hydrocarbon, pressure and others. After a successful testing the production well is drilled to produce hydrocarbons. Vertical wells are drilled by the rotary mode. The base of a drilling facility is a rig. For offshore drilling jack-up rigs, based on a buoyant ste el hull with 3 or more legs, semisubmersible rigs, which float at all times on ponto ons, or drill ships are used. The oil rig contains machinery and fulfils the role of superstr ucture bearing the load of a drill string. Driven by a diesel unit the drill string transmits his rotation on a drill bit, which brakes up the stone and extends the hole (up to 0,8 m wide). The drill string is gradually lengthened as the well gets deeper. The drill cuttings are rem oved by a drilling fluid (drilling mud), which is pumped inside the drill string, leaves the drill string at the drill bit and is then floated together with the drill cuttings back to th e surface between drill string and the inner surface of the well due to the high pressure genera ted by piston pumps. At the rig the drilling fluid is separated from drill cuttings and circ ulated. The drilling fluid also serves to cool the drill bit, to seal the drill hole against seepa ge and to prevent wall cave-ins. Depending on geology and technology water-based, oil-based an d synthetic-based fluids are used. They are mixed with barium sulphate and bentonite t o increase the density of the fluid as well as further additives. After finishing the dril ling or at least after 1000m, the well is cased with concrete and smoothly steel pipes (0.08- 0.2 m diameter) and prepared for production. In general due to the lack of infrastructu re for preparing and transportation, produced oil and gas is flared. Small amounts of gas a re also vented into the atmosphere. During the drilling high amounts of drill cuttings and waste water arise. At offshore exploration the cuttings are discharged to water or brou ght ashore depending on drilling fluid and legislation.Documentation Crude oil production 2002

Oil production in Nigeria 2 / 8 05/08/2008 

### 1.3 Production & Preparation Ideally the oil is transported as an oil-gas mixtur e to the surface without any effort by the high pressure of the hydrocarbon deposit. The flow of oil runs dry, when the pressure of the deposit will get lower as the flow resistance o r when the pressure was already lower at the beginning. For further exploitation it is neces sary to use pumps or to reinject a part of the separated natural gas to maintain a high pressu re in the deposit. Advanced measures raise the production are the reinjection of produce d water or sea water and the reinjection of steam to increase the viscosity or surface tensi on of the oil-gas mixture. The produced oil-gas mixture is a composite of crud e oil, natural gas, brine and other impurities. In a preparation process the natural gas and the NGL is separated from the oil. In a second preparation step most of the water is sepa rated from the oil due to the different densities. The remaining emulsified water and salt is removed in a dewatering and desalting plant. Small amounts of produced natural gas a re often still flared, sometimes also vented, due to missing preparation and transportati on opportunities. Hydrogen sulphide contained in the natural gas in different concentra tions, has to be removed before transportation via pipelines due to the high corrosive i mpact. The hydrogen sulphide is recovered from the natural gas by the Claus process prod ucing elementary sulphur and, depending on technology standards, a certain amount o f sulphur dioxide. The arising water with concentrations of approximately 15 or more mg hydrocarbons per litre is reinjected into the gas field, discharged into the sea (onshor e and in shore) or evaporated in pits. During preparation different kinds of waste and use d chemicals arise which have to be disposed. A certain amount of gas and oil is flared or vented into the atmosphere because of leakage or security reasons. The mechanical ener gy and electricity for pumping and all other machinery is provided by gas turbines and die sel units. At onshore facilities a certain amount is provided by the grid.Documentation Crude oil production 2002

Oil production in Nigeria 3 / 8 05/08/2008 

## 2 General comments of the LCA assessment method
This chapter gives background information on the pr incipal modelling approach.



### 2.1 System boundaries and functional unit

Functional unit: The functional unit is 1 bbl of cr ude oil. This process includes all relevant Mass and energy flows for the exploration and extraction of crude oil. Figure 2-1 gives an overview on the considered processes along with their key in- and outputs

Cement, Steel pipe, chemicals

Energy

(electrical, mechanical) Drilling meter Onshore

Production

Offshore Production Flaring / venting
Wastes Flaring / venting
Wastes

Crude oil Energy (electrical, mechanical) Drilling meter Exploration Flaring / venting Energy (electrical) Bentonite, Bariumsulphate System boundary

Figure 2-1 System boundary for crude oil production

The exploration is modelled per drilling meters and is considered in the model via drilling meters per mass of produced hydrocarbon. Quantities of borehole volume, removed rock are based on multiple sources such as [11]-[13]. Am ount of Bentonite and Bariumsulphate and water for drilling mud is taken from [11]. The material used for reinforcing the well is calculated based on [14]-[17]. The power demand for drilling is taken from [18]. For venting of natural gas the averaged national natural ga s composition is considered [27], [19]. The energy demand for production is given in sectio n 3.2. The associated emissions are calculated using emission factors sourced from [20] and industry data. Venting of solution gas from oil producing well is also considered. For flaring region specific flare amounts and emissions are included, see section 3.3, [25], [26]. Solid wastes and waste water are considered. The referring data is sourced from [3], [21]-[24] and as stated in section 3.4.



### 2.2 Allocation or system expansion For the combined crude oil, natural gas and natural gas liquids production allocation by lower calorific value is applied. The lower heating values of the products are given in section 3.5.Documentation Crude oil production 2002

Oil production in Nigeria 4 / 8 05/08/2008 

### 2.3 Data completeness The coverage for the exploration data (crude oil, n atural gas, natural gas liquids) is 90% of mass and energy and 95% of the environmental releva nce (expert judgement).



### 2.4 Data selection and combination principles The data sources for the complete product system ar e sufficiently consistent: The data on the energy carrier supply chain is based on statist ics with country/region specific transport distances and energy carrier composition as well as industry and literature data on the inventory of exploration, extraction and processing . LCI modelling is fully consistent.



### 2.5 Reference year Reference year for the data set is 2002. Although s ome of the emission data and product properties are sourced from different years represe ntativeness for the reference year is considered good.



### 2.6 Data treatment and extrapolations principles In terms of the country/region specific crude oil p roduction, missing data of certain parameters has been used from countries with a compar able technology 1 . Data measured at a group of representative production facilities hav e been used to represent the national production.

1 If this ist he case it is indicated in the tables in section 3.Documentation Crude oil production 2002

Oil production in Nigeria 5 / 8 05/08/2008 

## 3 Country specific data

3.1 Production Table 1 shows the production ratio of natural gas, NGL and crude oil on a weight basis as well as the drilling feet per pound hydrocarbon pro duced.

Table 1 Production parameters

Parameter Value Source

Portion of natural gas production 10.34% [1]

Portion of NGL production 3.71% [1]

Portion of crude oil production 85.95% [28]

Drilling meters for onshore production 0.43 x10 -06 ft/lb HC produced [2]

Drilling meters for offshore production 0.34x10 -06 ft/lb HC produced [2]



### 3.2 Energy use The specific energy use distinguished between elect ricity and mechanical energy is shown in Table 2.

Table 2 Energy consumption parameters

Parameter Value Source

Electricity demand 34.39 Btu /lb HC Value for region Africa [3] and own calculations

Mechanical energy demand 309.54 Btu/lb HC Value for region Africa [3] and own calculations

Total energy demand 343.93 Btu/lb HC Value for region Africa [3]



### 3.3 Flaring and venting The flaring and venting of hydrocarbons during the production process is shown in Table 3. The flared Hydrocarbons are the sum of flared na tural gas and solution gas compounds.Documentation Crude oil production 2002

Oil production in Nigeria 6 / 8 05/08/2008 Table 3 Flaring and venting parameters

Parameter Value Source

Flared Hydrocarbons 0.10 lb/lb HC [10]

Vented Hydrocarbons 0.029 lb/lb HC [10]



### 3.4 Waste and waste water
The amount of solid waste and waste water emitted d uring the production process is summarised in Table 4.

Table 4 Waste and waste water parameters

Parameter Value Source

Solid waste 0.0017 lb/lb HC [4]

Waste water onshore 0.44 lb/lb HC Value for region Africa [3]

Waste water offshore 0.53 lb/lb HC [4]



### 3.5 Product properties The lower heating value as a country specific produ ct property is given in Table 5.

Table 5 Product properties

Parameter Value Source

Net calorific value natural gas 18851.55 Btu/lb [27 ]

Net calorific value crude oil 18391.55 Btu/lb [5];[ 6];[7];[8];[9]Documentation Crude oil production 2002

Oil production in Nigeria 7 / 8 05/08/2008 

## 4 References

[1] IEA: Natural Gas Information 2002, International En ergy Agency, 2004


### [2] Pennwell: The international petroleum Encyclopaedia 1997


### [3] OGP, International Associations of Oil and Gas Prod ucers: Environmental performance in the E&P industry 2003, 2004


### [4] Shell Nigeria 2004 People and the environment Annua l Report, 2005


### [5] EIA: C.2 Barrels of Crude Oil Per Metric Ton, 1980 -2003, 2004


### [6] EIA: C.3 Gross Heat Content of Crude Oil, 1980-200 3, 2004


### [7] Haverly: Crude assay libraries, 2005


### [8] ChevronTexaco: http://www.chevrontexaco.com/crudemarketing/ , 2005


### [9] Energy Intelligence Group: The Crude Oils and Their Key Characteristics, 2004


### [10] International Energy Annual 2003; Energy Informatio n Administration, 2004


### [11] OGP: Environmental aspects of the use and disposal of non aqueous drilling fluids

associated with offshore oil& gas operations, 2003


### [12] Da Prat, G.: Well Testing management , SPE Foundati on, presentation 2002


### [13] Vickery et al.: Successful high rate gas completion through combination of extreme

overbalance perforating and one trip perforate and gravel pack techniques, Baker oil tools, 2001


### [14] N. Lapeyrouse: Formulas and calculations for Drilli ng, Production and work over,

2nd Edition, Golf Professional Publishing, 2002


### [15] Gordon, D. et al. Underbalanced Drilling with casin g SPE, SPE Drilling & completion

2005


### [16] Ohio Department of Health: Materials used in drilli ng and construction of wells, 1999


### [17] Culver, G.: Drilling and well construction, Chapter 6, OIST, Department of Energy

1998


### [18] Vektor AS – Environmental developments in Well test ing, 2000


### [19] BP: Das Buch zum Erdöl (The book on Crude oil), 198 9


### [20] US EPA: Compilation of Air pollutant emission facto rs, AP 42, Volume I: Stationary

point and area sources, Fifth edition, United State s Protection Agency, Office of air quality planning and standards, 1995-2000.Documentation Crude oil production 2002

Oil production in Nigeria 8 / 8 05/08/2008 

### [21] US EPA: Profile of the Oil and Gas Extraction Indus try, 2nd Section, 2000


### [22] PSI: Management of produced water on offshore oil i nstallations, Policy Studies Institute, 2005


### [23] OGP: Aromatics in produced water occurrence, fate & effects and treatment, International Association of Oil and Gas Producers, 2002


### [24] OGP: Fate and effects of naturally occurring substa nces in produced water on the

marine environment, International Association of Oi l and Gas Producers, 2005


### [25] Leahey, G et at.: Theoretical and observational ass essments of flare efficiencies,

Journal of Air & Waste Management Association, Volu me 51, December 2001


### [26] Johnson, M.R. et al.: Efficiency measurements of fl ares in a cross flow, Dep. Of Mechanical Engineering, University of Alberta, Combus tion Canada conference,
1999


### [27] EIA: C.5 Gross Heat Content of Dry Natural Gas Prod uction, 1980-2004, 2005


### [28] IEA: Oil Information 2002, International Energy Age ncy, 2004Documentation Crude oil production 2002

Oil production in Saudi Arabia 1 / 8 05/08/2008 

## Production of crude oil in Saudi Arabia

1. Technology description of the Crude oil producti on

1.1 Introduction The production of crude oil was modelled as a combi ned natural gas and crude oil production. In most cases beside crude oil, different par ts of natural gas and NGL (natural gas liquids) are produced as by-products. For the diffe rent by-products allocation by lower calorific value was applied. The combined productio n comprises the exploration and production of crude oil and natural gas as well as all the desulphurization of natural gas. The data set includes all relevant parts of the upstrea m industry. Production may take place onshore and offshore. Both are taken into account p roportionate to their ratio of the total production of a country.



### 1.2 Exploration Exploration comprises the search of hydrocarbon (HC ) deposits and the drilling of wells. The search for new deposits is conducted at first b y seismic survey, which is not included in the data set. In a second step testing wells are drilled which can be characterized as wildcat wells for areas with low information about the subsurface, exploration wells for information gathering and appraisal wells to assess characteristics such as flow rate, amount of hydrocarbon, pressure and others. After a successful testing the production well is drilled to produce hydrocarbons. Vertical wells are drilled by the rotary mode. The base of a drilling facility is a rig. For offshore drilling jack-up rigs, based on a buoyant ste el hull with 3 or more legs, semisubmersible rigs, which float at all times on ponto ons, or drill ships are used. The oil rig contains machinery and fulfils the role of superstr ucture bearing the load of a drill string. Driven by a diesel unit the drill string transmits his rotation on a drill bit, which brakes up the stone and extends the hole (up to 0,8 m wide). The drill string is gradually lengthened as the well gets deeper. The drill cuttings are rem oved by a drilling fluid (drilling mud), which is pumped inside the drill string, leaves the drill string at the drill bit and is then floated together with the drill cuttings back to th e surface between drill string and the inner surface of the well due to the high pressure genera ted by piston pumps. At the rig the drilling fluid is separated from drill cuttings and circ ulated. The drilling fluid also serves to cool the drill bit, to seal the drill hole against seepa ge and to prevent wall cave-ins. Depending on geology and technology water-based, oil-based an d synthetic-based fluids are used. They are mixed with barium sulphate and bentonite t o increase the density of the fluid as well as further additives. After finishing the dril ling or at least after 1000m, the well is cased with concrete and smoothly steel pipes (0.08- 0.2 m diameter) and prepared for production. In general due to the lack of infrastructu re for preparing and transportation, produced oil and gas is flared. Small amounts of gas a re also vented into the atmosphere. During the drilling high amounts of drill cuttings and waste water arise. At offshore exploration the cuttings are discharged to water or brou ght ashore depending on drilling fluid and legislation.Documentation Crude oil production 2002

Oil production in Saudi Arabia 2 / 8 05/08/2008 

### 1.3 Production & Preparation Ideally the oil is transported as an oil-gas mixtur e to the surface without any effort by the high pressure of the hydrocarbon deposit. The flow of oil runs dry, when the pressure of the deposit will get lower as the flow resistance o r when the pressure was already lower at the beginning. For further exploitation it is neces sary to use pumps or to reinject a part of the separated natural gas to maintain a high pressu re in the deposit. Advanced measures raise the production are the reinjection of produce d water or sea water and the reinjection of steam to increase the viscosity or surface tensi on of the oil-gas mixture. The produced oil-gas mixture is a composite of crud e oil, natural gas, brine and other impurities. In a preparation process the natural gas and the NGL is separated from the oil. In a second preparation step most of the water is sepa rated from the oil due to the different densities. The remaining emulsified water and salt is removed in a dewatering and desalting plant. Small amounts of produced natural gas a re often still flared, sometimes also vented, due to missing preparation and transportati on opportunities. Hydrogen sulphide contained in the natural gas in different concentra tions, has to be removed before transportation via pipelines due to the high corrosive i mpact. The hydrogen sulphide is recovered from the natural gas by the Claus process prod ucing elementary sulphur and, depending on technology standards, a certain amount o f sulphur dioxide. The arising water with concentrations of approximately 15 or more mg hydrocarbons per litre is reinjected into the gas field, discharged into the sea (onshor e and in shore) or evaporated in pits. During preparation different kinds of waste and use d chemicals arise which have to be disposed. A certain amount of gas and oil is flared or vented into the atmosphere because of leakage or security reasons. The mechanical ener gy and electricity for pumping and all other machinery is provided by gas turbines and die sel units. At onshore facilities a certain amount is provided by the grid.Documentation Crude oil production 2002

Oil production in Saudi Arabia 3 / 8 05/08/2008 

## 2 General comments of the LCA assessment method
This chapter gives background information on the pr incipal modelling approach.



### 2.1 System boundaries and functional unit

Functional unit: The functional unit is 1 bbl of cr ude oil. This process includes all relevant Mass and energy flows for the exploration and extraction of crude oil. Figure 2-1 gives an overview on the considered processes along with their key in- and outputs

Cement, Steel pipe, chemicals

Energy

(electrical, mechanical) Drilling meter Onshore

Production

Offshore Production Flaring / venting
Wastes Flaring / venting
Wastes

Crude oil Energy (electrical, mechanical) Drilling meter Exploration Flaring / venting Energy (electrical) Bentonite, Bariumsulphate System boundary

Figure 2-1 System boundary for crude oil production

The exploration is modelled per drilling meters and is considered in the model via drilling meters per mass of produced hydrocarbon. Quantities of borehole volume, removed rock are based on multiple sources such as [16]-[18]. Am ount of Bentonite and Bariumsulphate and water for drilling mud is taken from [16]. The material used for reinforcing the well is calculated based on [19]-[22]. The power demand for drilling is taken from [23]. For venting of natural gas the averaged national natural ga s composition is considered [32]. The energy demand for production is given in section 3. 2. The associated emissions are calculated using emission factors sourced from [25] and industry data. Venting of solution gas from oil producing well is also considered. For fla ring region specific flare amounts and emissions are included, see section 3.3 and [24], [ 30], [31]. Solid wastes and waste water are considered. The referring data is sourced from [24], [26]-[29] and as stated in section 3.4.



### 2.2 Allocation or system expansion For the combined crude oil, natural gas and natural gas liquids production allocation by lower calorific value is applied. The lower heating values of the products are given in section 3.5.Documentation Crude oil production 2002

Oil production in Saudi Arabia 4 / 8 05/08/2008 

### 2.3 Data completeness The coverage for the exploration data (crude oil, n atural gas, natural gas liquids) is 90% of mass and energy and 95% of the environmental releva nce (expert judgement).



### 2.4 Data selection and combination principles The data sources for the complete product system ar e sufficiently consistent: The data on the energy carrier supply chain is based on statist ics with country/region specific transport distances and energy carrier composition as well as industry and literature data on the inventory of exploration, extraction and processing . LCI modelling is fully consistent.



### 2.5 Reference year Reference year for the data set is 2002. Although s ome of the emission data and product properties are sourced from different years represe ntativeness for the reference year is considered good.



### 2.6 Data treatment and extrapolations principles In terms of the country/region specific crude oil p roduction, missing data of certain parameters has been used from countries with a compar able technology 1 . Data measured at a group of representative production facilities hav e been used to represent the national production.

1 If this ist he case it is indicated in the tables in section 3.Documentation Crude oil production 2002

Oil production in Saudi Arabia 5 / 8 05/08/2008 

## 3 Country specific data

3.1 Production Table 1 shows the production ratio of natural gas, NGL and crude oil on a weight basis as well as the drilling feet per pound hydrocarbon pro duced.

Table 1 Production parameters

Parameter Value Source

Portion of natural gas production 10.22% [1]

Portion of NGL production 7.79% [1]

Portion of crude oil production 81.99% [33]

Drilling meters for onshore production 0.51x -07 ft/lb HC produced [2]

Drilling meters for offshore production 0.51x -07 ft/lb HC produced [2]



### 3.2 Energy use The specific energy use distinguished between elect ricity and mechanical energy is shown in Table 2.

Table 2 Energy consumption parameters

Parameter Value Source

Electricity demand 24.51 Btu/lb Value for region Middle East [24] and own calculations

Mechanical energy demand 219.25 Btu/lb Value for region Middle East [24] and own calculations

Total energy demand 245.05 Btu/lb [24]



### 3.3 Flaring and venting The flaring and venting of hydrocarbons during the production process is shown in Table 3. The flared Hydrocarbons are the sum of flared na tural gas and solution gas compounds.Documentation Crude oil production 2002

Oil production in Saudi Arabia 6 / 8 05/08/2008 Table 3 Flaring and venting parameters

Parameter Value Source

Flared Hydrocarbons 0.00032 lb/lb HC [15] and own calculations

Vented Hydrocarbons 0.000092 lb/lb HC [15] and own calculations



### 3.4 Waste and waste water
The amount of solid waste and waste water emitted d uring the production process is summarised in Table 4.

Table 4 Waste and waste water parameters

Parameter Value Source

Solid waste 0.0060 lb/lb HC Global value [4];[5];[6];[7];[8];[9];[10]

Waste water onshore 0.030 lb/lb HC [24]

Waste water offshore 3.11 lb/lb HC Value for the Middle East Region [24]



### 3.5 Product properties The lower heating value as a country specific produ ct property is given in Table 5.

Table 5 Product properties

Parameter Value Source

Net calorific value natural gas 18413,05 Btu/lb [32 ]

Net calorific value crude oil 18249,68 Btu/lb [11]; [12];[13];[14]Documentation Crude oil production 2002

Oil production in Saudi Arabia 7 / 8 05/08/2008 

## 4 References

[1] IEA: Natural Gas Information 2002, International En ergy Agency, 2004


### [2] Pennwell: The international petroleum Encyclopaedia 1997


### [3] OGP, International Association of Oil and Gas Produ cers: Environmental performance in the E&P industry 2003, 2004


### [4] Yukos: Yukos and the environment, 2003


### [5] Shell: http://www.shell.com/home/Framework?siteId=my-en&FC 2=/myen/html/iwgen/society_environment/environment/susta inable2003/zzz_lhn.html&FC3=/myen/html/iwgen/society_environment/environment/susta inable2003/sd03_protectthee nvironment_1008.html , 2004


### [6] Shell Nigeria 2004 People and the environment Annua l Report, 2005


### [7] Nederlandse Aardolie Maatschappij (NAM): Bron van e nergie, 2003


### [8] BP Pakistan 2003 Environmental Statement, 2004


### [9] BP Trinidad & Tobago: 2003 Environmental Statement Trinidad BU, 2004


### [10] Shell in the UK report 2001, 2002


### [11] EIA: C.2 Barrels of Crude Oil Per Metric Ton, 1980 -2003, 2004


### [12] EIA: C.3 Gross Heat Content of Crude Oil, 1980-200 3, 2004


### [13] Haverly: Crude assay libraries, 2005


### [14] Energy Intelligence Group: The Crude Oils and Their Key Characteristics, 2004


### [15] International Energy Annual 2003; Energy Informatio n Administration, 2004


### [16] OGP: Environmental aspects of the use and disposal of non aqueous drilling fluids

associated with offshore oil& gas operations, 2003


### [17] Da Prat, G.: Well Testing management , SPE Foundati on, presentation 2002


### [18] Vickery et al.: Successful high rate gas completion through combination of extreme

overbalance perforating and one trip perforate and gravel pack techniques, Baker oil tools, 2001


### [19] N. Lapeyrouse: Formulas and calculations for Drilli ng, Production and work over,

2nd Edition, Golf Professional Publishing, 2002Documentation Crude oil production 2002

Oil production in Saudi Arabia 8 / 8 05/08/2008 

### [20] Gordon, D. et al. Underbalanced Drilling with casin g SPE, SPE Drilling & completion

2005


### [21] Ohio Department of Health: Materials used in drilli ng and construction of wells, 1999


### [22] Culver, G.: Drilling and well construction, Chapter 6, OIST, Department of Energy

1998


### [23] Vektor AS – Environmental developments in Well test ing, 2000


### [24] OGP, International Association of Oil and Gas Produ cers: Environmental performance in the E&P industry 2003


### [25] US EPA: Compilation of Air pollutant emission facto rs, AP 42, Volume I: Stationary

point and area sources, Fifth edition, United State s Protection Agency, Office of air quality planning and standards, 1995-2000.


### [26] US EPA: Profile of the Oil and Gas Extraction Indus try, 2nd Section, 2000


### [27] PSI: Management of produced water on offshore oil i nstallations, Policy Studies Institute, 2005


### [28] OGP: Aromatics in produced water occurrence, fate & effects and treatment, International Association of Oil and Gas Producers, 2002


### [29] OGP: Fate and effects of naturally occurring substa nces in produced water on th

marine environment, International Association of Oi l and Gas Producers, 2005


### [30] Leahey, G et at.: Theoretical and observational ass essments of flare efficiencies,

Journal of Air & Waste Management Association, Volu me 51, December 2001


### [31] Johnson, M.R. et al.: Efficiency measurements of fl ares in a cross flow, Dep. Of Mechanical Engineering, University of Alberta, Combus tion Canada conference,
1999


### [32] EIA: C.5 Gross Heat Content of Dry Natural Gas Prod uction, 1980-2004, 2005


### [33] IEA: Oil Information 2002, International Energy Age ncy, 2004Documentation Crude oil production 2002

Oil production in Venezuela 1 / 8 05/08/2008 

## Production of crude oil in Venezuela

1. Technology description of the Crude oil producti on

1.1 Introduction The production of crude oil was modelled as a combi ned natural gas and crude oil production. In most cases beside crude oil, different par ts of natural gas and NGL (natural gas liquids) are produced as by-products. For the diffe rent by-products allocation by lower calorific value was applied. The combined productio n comprises the exploration and production of crude oil and natural gas as well as all the desulphurization of natural gas. The data set includes all relevant parts of the upstrea m industry. Production may take place onshore and offshore. Both are taken into account p roportionate to their ratio of the total production of a country.



### 1.2 Exploration Exploration comprises the search of hydrocarbon (HC ) deposits and the drilling of wells. The search for new deposits is conducted at first b y seismic survey, which is not included in the data set. In a second step testing wells are drilled which can be characterized as wildcat wells for areas with low information about the subsurface, exploration wells for information gathering and appraisal wells to assess characteristics such as flow rate, amount of hydrocarbon, pressure and others. After a successful testing the production well is drilled to produce hydrocarbons. Vertical wells are drilled by the rotary mode. The base of a drilling facility is a rig. For offshore drilling jack-up rigs, based on a buoyant ste el hull with 3 or more legs, semisubmersible rigs, which float at all times on ponto ons, or drill ships are used. The oil rig contains machinery and fulfils the role of superstr ucture bearing the load of a drill string. Driven by a diesel unit the drill string transmits his rotation on a drill bit, which brakes up the stone and extends the hole (up to 0,8 m wide). The drill string is gradually lengthened as the well gets deeper. The drill cuttings are rem oved by a drilling fluid (drilling mud), which is pumped inside the drill string, leaves the drill string at the drill bit and is then floated together with the drill cuttings back to th e surface between drill string and the inner surface of the well due to the high pressure genera ted by piston pumps. At the rig the drilling fluid is separated from drill cuttings and circ ulated. The drilling fluid also serves to cool the drill bit, to seal the drill hole against seepa ge and to prevent wall cave-ins. Depending on geology and technology water-based, oil-based an d synthetic-based fluids are used. They are mixed with barium sulphate and bentonite t o increase the density of the fluid as well as further additives. After finishing the dril ling or at least after 1000m, the well is cased with concrete and smoothly steel pipes (0.08- 0.2 m diameter) and prepared for production. In general due to the lack of infrastructu re for preparing and transportation, produced oil and gas is flared. Small amounts of gas a re also vented into the atmosphere. During the drilling high amounts of drill cuttings and waste water arise. At offshore exploration the cuttings are discharged to water or brou ght ashore depending on drilling fluid and legislation.Documentation Crude oil production 2002

Oil production in Venezuela 2 / 8 05/08/2008 

### 1.3 Production & Preparation Ideally the oil is transported as an oil-gas mixtur e to the surface without any effort by the high pressure of the hydrocarbon deposit. The flow of oil runs dry, when the pressure of the deposit will get lower as the flow resistance o r when the pressure was already lower at the beginning. For further exploitation it is neces sary to use pumps or to reinject a part of the separated natural gas to maintain a high pressu re in the deposit. Advanced measures raise the production are the reinjection of produce d water or sea water and the reinjection of steam to increase the viscosity or surface tensi on of the oil-gas mixture. The produced oil-gas mixture is a composite of crud e oil, natural gas, brine and other impurities. In a preparation process the natural gas and the NGL is separated from the oil. In a second preparation step most of the water is sepa rated from the oil due to the different densities. The remaining emulsified water and salt is removed in a dewatering and desalting plant. Small amounts of produced natural gas a re often still flared, sometimes also vented, due to missing preparation and transportati on opportunities. Hydrogen sulphide contained in the natural gas in different concentra tions, has to be removed before transportation via pipelines due to the high corrosive i mpact. The hydrogen sulphide is recovered from the natural gas by the Claus process prod ucing elementary sulphur and, depending on technology standards, a certain amount o f sulphur dioxide. The arising water with concentrations of approximately 15 or more mg hydrocarbons per litre is reinjected into the gas field, discharged into the sea (onshor e and in shore) or evaporated in pits. During preparation different kinds of waste and use d chemicals arise which have to be disposed. A certain amount of gas and oil is flared or vented into the atmosphere because of leakage or security reasons. The mechanical ener gy and electricity for pumping and all other machinery is provided by gas turbines and die sel units. At onshore facilities a certain amount is provided by the grid.Documentation Crude oil production 2002

Oil production in Venezuela 3 / 8 05/08/2008 

## 2 General comments of the LCA assessment method
This chapter gives background information on the pr incipal modelling approach.



### 2.1 System boundaries and functional unit

Functional unit: The functional unit is 1 bbl of cr ude oil. This process includes all relevant Mass and energy flows for the exploration and extraction of crude oil. Figure 2-1 gives an overview on the considered processes along with their key in- and outputs

Cement, Steel pipe, chemicals

Energy

(electrical, mechanical) Drilling meter Onshore

Production

Offshore Production Flaring / venting
Wastes Flaring / venting
Wastes

Crude oil Energy (electrical, mechanical) Drilling meter Exploration Flaring / venting Energy (electrical) Bentonite, Bariumsulphate System boundary

Figure 2-1 System boundary for crude oil production

The exploration is modelled per drilling meters and is considered in the model via drilling meters per mass of produced hydrocarbon. Quantities of borehole volume, removed rock are based on multiple sources such as [11]-[13]. Am ount of bentonite and bariumsulphate and water for drilling mud is taken from [11]. The material used for reinforcing the well is calculated based on [14]-[17]. The power demand for drilling is taken from [18]. For venting of natural gas the averaged national natural ga s composition is considered [19], [27]. The energy demand for production is given in sectio n 3.2. The associated emissions are calculated using emission factors sourced from [20] and industry data. Venting of solution gas from oil producing well is also considered. For flaring region specific flare emissions are included see section 3.3 and [3],[25],[26]. Sol id wastes and waste water are considered. The referring data is sourced from [3], [21]- [24] and as stated in section 3.4.



### 2.2 Allocation or system expansion For the combined crude oil, natural gas and natural gas liquids production allocation by lower calorific value is applied. The lower heating values of the products are given in section 3.5.Documentation Crude oil production 2002

Oil production in Venezuela 4 / 8 05/08/2008 

### 2.3 Data completeness The coverage for the exploration data (crude oil, n atural gas, natural gas liquids) is 90% of mass and energy and 95% of the environmental releva nce (expert judgement).



### 2.4 Data selection and combination principles The data sources for the complete product system ar e sufficiently consistent: The data on the energy carrier supply chain is based on statist ics with country/region specific transport distances and energy carrier composition as well as industry and literature data on the inventory of exploration, extraction and processing . LCI modelling is fully consistent.



### 2.5 Reference year Reference year for the data set is 2002. Although s ome of the emission data and product properties are sourced from different years represe ntativeness for the reference year is considered good.



### 2.6 Data treatment and extrapolations principles In terms of the country/region specific crude oil p roduction, missing data of certain parameters has been used from countries with a compar able technology 1 . Data measured at a group of representative production facilities hav e been used to represent the national production.

1 If this ist he case it is indicated in the tables in section 3.Documentation Crude oil production 2002

Oil production in Venezuela 5 / 8 05/08/2008 

## 3 Country specific data

3.1 Production Table 1 shows the production ratio of natural gas, NGL and crude oil on a weight basis as well as the drilling feet per pound hydrocarbon pro duced.

Table 1 Production parameters

Parameter Value Source

Portion of natural gas production 10.56% [1]

Portion of NGL production 2.89% [1]

Portion of crude oil production 86.55% [28]

Drilling meters for onshore production 0.14x10 -05 ft/lb HC produced [2]

Drilling meters for offshore production 0.14x10 -05 ft/lb HC produced Estimated to be the same as onshore



### 3.2 Energy use The specific energy use distinguished between elect ricity and mechanical energy is shown in Table 2.

Table 2 Energy consumption parameters

Parameter Value Source

Electricity demand 22.79 Btu/lb HC Value for Region LatinAmerica [3] and own calculations

Mechanical energy demand 206.36 Btu/lb HC Value for Region LatinAmerica [3] and own calculations

Total energy demand 227.85 Btu/lb HC Value for Region Latin America [3]



### 3.3 Flaring and venting The flaring and venting of hydrocarbons during the production process is shown in Table 3. The flared Hydrocarbons are the sum of flared na tural gas and solution gas compounds.Documentation Crude oil production 2002

Oil production in Venezuela 6 / 8 05/08/2008 Table 3 Flaring and venting parameters

Parameter Value Source

Flared Hydrocarbons 0.013 lb/lb HC [10], [30]

Vented Hydrocarbons 0.0016 lb/lb HC [10], [30]



### 3.4 Waste and waste water
The amount of solid waste and waste water emitted d uring the production process is summarised in Table 4.

Table 4 Waste and waste water parameters

Parameter Value Source

Solid waste 0.000073 lb/lb HC Value for Trinidad Tobago [4]

Waste water onshore 0.017 lb/lb HC [3]

Waste water offshore 0.091 lb/lb HC [3]



### 3.5 Product properties The lower heating value as a country specific produ ct property is given in Table 5.

Table 5 Product properties

Parameter Value Source

Net calorific value natural gas 19982.22 Btu/lb [19 ]

Net calorific value crude oil 18228.18 Btu/lb [5];[ 6];[7];[8];[9]Documentation Crude oil production 2002

Oil production in Venezuela 7 / 8 05/08/2008 

## 4 References

[1] IEA Natural Gas Information 2002, International Ene rgy Agency, 2004


### [2] Pennwell: The international petroleum Encyclopedia 1997


### [3] OGP, International Association of Oil and Gas Produ cers: Environmental performance in the E&P industry 2003, 2004


### [4] BP Trinidad & Tobago: 2003 Environmental Statement Trinidad BU, 2004


### [5] EIA: C.2 Barrels of Crude Oil Per Metric Ton, 1980 -2003, 2004


### [6] EIA: C.3 Gross Heat Content of Crude Oil, 1980-200 3, 2004


### [7] Haverly: Crude assay libraries, 2005


### [8] Energy Intelligence Group: The Crude Oils and Their Key Characteristics, 2004


### [9] ChevronTexaco: http://www.chevrontexaco.com/crudemarketing/ , 2005


### [10] EIA: International Energy Annual 2003; Energy Infor mation Administration, 2004


### [11] OGP: Environmental aspects of the use and disposal of non aqueous drilling fluids

associated with offshore oil& gas operations, 2003


### [12] Da Prat, G.: Well Testing management , SPE Foundati on, presentation 2002


### [13] Vickery et al.: Successful high rate gas completion through combination of extreme

overbalance perforating and one trip perforate and gravel pack techniques, Baker oil tools, 2001


### [14] N. Lapeyrouse: Formulas and calculations for Drilli ng, Production and work over,

2nd Edition, Golf Professional Publishing, 2002


### [15] Gordon, D. et al. Underbalanced Drilling with casin g SPE, SPE Drilling & completion

2005


### [16] Ohio Department of Health: Materials used in drilli ng and construction of wells, 1999


### [17] Culver, G.: Drilling and well construction, Chapter 6, OIST, Department of Energy

1998


### [18] Vektor AS – Environmental developments in Well test ing, 2000


### [19] EIA: C.5 Gross Heat Content of Dry Natural Gas Prod uction, 1980-2004, 2005


### [20] US EPA: Compilation of Air pollutant emission facto rs, AP 42, Volume I: Stationary

point and area sources, Fifth edition, United State s Protection Agency, Office of air quality planning and standards, 1995-2000.Documentation Crude oil production 2002

Oil production in Venezuela 8 / 8 05/08/2008 

### [21] US EPA: Profile of the Oil and Gas Extraction Indus try, 2nd Section, 2000


### [22] PSI: Management of produced water on offshore oil i nstallations, Policy Studies Institute, 2005


### [23] OGP: Aromatics in produced water occurrence, fate & effects and treatment, International Association of Oil and Gas Producers, 2002


### [24] OGP: Fate and effects of naturally occurring substa nces in produced water on the

marine environment, International Association of Oi l and Gas Producers, 2005


### [25] Leahey, G et at.: Theoretical and observational ass essments of flare efficiencies,

Journal of Air & Waste Management Association, Volu me 51, December 2001


### [26] Johnson, M.R. et al.: Efficiency measurements of fl ares in a cross flow, Dep. Of Mechanical Engineering, University of Alberta, Combus tion Canada conference,
1999


### [27] California Energy Commission: Natural gas compositi on and Quality, 2005


### [28] IEA: Oil Information 2002, International Energy Age ncy, 2004


### [29] EIA: International Energy Annual 2003; Energy Infor mation Administration, 2004


### [30] World Bank: Global gas flaring reduction initiative , 2004Documentation Crude oil & Natural gas production 20 02

Oil_Natural gas production in the USA 1 / 9 05/08/2 008 

## Production of crude oil and natural gas in the USA

1. Technology description of the Crude oil producti on

1.1 Introduction The production of crude oil and natural was modelle d as a combined natural gas and crude oil production. In the case of crude oil well s, different parts of natural gas and NGL (natural gas liquids) are produced as co-products a nd vice versa for natural gas wells. For the different co-products allocation by lower calor ific value was applied. The combined production comprises the exploration and production of crude oil and natural gas as well as all the desulphurization of natural gas. The dat a set includes all relevant parts of the upstream industry. Production may take place onshor e and offshore. Both are taken into account proportionate to their ratio of the total p roduction of a country.



### 1.2 Exploration Exploration comprises the search of hydrocarbon (HC ) deposits and the drilling of wells. The search for new deposits is conducted at first b y seismic survey, which is not included in the data set. In a second step testing wells are drilled which can be characterized as wildcat wells for areas with low information about the subsurface, exploration wells for information gathering and appraisal wells to assess characteristics such as flow rate, amount of hydrocarbon, pressure and others. After a successful testing the production well is drilled to produce hydrocarbons. Vertical wells are drilled by the rotary mode. The base of a drilling facility is a rig. For offshore drilling jack-up rigs, based on a buoyant ste el hull with 3 or more legs, semisubmersible rigs, which float at all times on ponto ons, or drill ships are used. The oil rig contains machinery and fulfils the role of superstr ucture bearing the load of a drill string. Driven by a diesel unit the drill string transmits his rotation on a drill bit, which brakes up the stone and extends the hole (up to 0,8 m wide). The drill string is gradually lengthened as the well gets deeper. The drill cuttings are rem oved by a drilling fluid (drilling mud), which is pumped inside the drill string, leaves the drill string at the drill bit and is then floated together with the drill cuttings back to th e surface between drill string and the inner surface of the well due to the high pressure genera ted by piston pumps. At the rig the drilling fluid is separated from drill cuttings and circ ulated. The drilling fluid also serves to cool the drill bit, to seal the drill hole against seepa ge and to prevent wall cave-ins. Depending on geology and technology water-based, oil-based an d synthetic-based fluids are used. They are mixed with barium sulphate and bentonite t o increase the density of the fluid as well as further additives. After finishing the dril ling or at least after 1000m, the well is cased with concrete and smoothly steel pipes (0.08- 0.2 m diameter) and prepared for production. In general due to the lack of infrastructu re for preparing and transportation, produced oil and gas is flared. Small amounts of gas a re also vented into the atmosphere. During the drilling high amounts of drill cuttings and waste water arise. At offshore exploration the cuttings are discharged to water or brou ght ashore depending on drilling fluid and legislation.Documentation Crude oil & Natural gas production 20 02

Oil_Natural gas production in the USA 2 / 9 05/08/2 008 

### 1.3 Production & Preparation
Crude oil Ideally the oil is transported as an oil-gas mixtur e to the surface without any effort by the high pressure of the hydrocarbon deposit. The flow of oil runs dry, when the pressure of the deposit will get lower as the flow resistance o r when the pressure was already lower at the beginning. For further exploitation it is neces sary to use pumps or to reinject a part of the separated natural gas to maintain a high pressu re in the deposit. Advanced measures raise the production are the reinjection of produce d water or sea water and the reinjection of steam to increase the viscosity or surface tensi on of the oil-gas mixture. The produced oil-gas mixture is a composite of crud e oil, natural gas, brine and other impurities. In a preparation process the natural gas and the NGL is separated from the oil. In a second preparation step most of the water is sepa rated from the oil due to the different densities. The remaining emulsified water and salt is removed in a dewatering and desalting plant. Small amounts of produced natural gas a re often still flared, sometimes also vented, due to missing preparation and transportati on opportunities.

Natural gas Due to the high pressure in the gas field the produ ction of natural gas is done without the need of pumps. In good gas fields up to 80% of the gas can be produced without any further measures. In deposits with stone of low porosi ty, the production rate is increased by pumping liquids under high pressure into the deposi t to crack open the stone. Hydrogen sulphide contained in the natural gas in different concentrations, has to be removed before transportation via pipelines due to the high c orrosive impact. The hydrogen sulphide is recovered from the natural gas by the Claus proc ess producing elementary sulphur and, depending on technology standards, a certain amount of sulphur dioxide. The arising water with concentrations of approximately 15 or more mg hydrocarbons per litre is reinjected into the gas field, discharged into the sea (onshore and in shore) or evaporated in pits. During preparation different kinds of waste a nd used chemicals arise which have to be disposed. A certain amount of gas and oil is fla red or vented into the atmosphere because of leakage or security reasons. The mechanica l energy and electricity for pumping and all other machinery is provided by gas turbines and diesel units. At onshore facilities a certain amount is provided by the grid.Documentation Crude oil & Natural gas production 20 02

Oil_Natural gas production in the USA 3 / 9 05/08/2 008 

## 2 General comments of the LCA assessment method
This chapter gives background information on the pr incipal modelling approach.



### 2.1 System boundaries and functional unit

Crude oil:

Functional unit: The functional unit is 1 bbl of cr ude oil. This process includes all relevant Mass and energy flows for the exploration and extraction of crude oil. Figure 2-1 gives an overview on the considered processes along with their key in- and outputs

Cement, Steel pipe, chemicals

Energy

(electrical, mechanical) Drilling meter Onshore

Production

Offshore Production Flaring / venting
Wastes Flaring / venting
Wastes

Crude oil Energy (electrical, mechanical) Drilling meter Exploration Flaring / venting Energy (electrical) Bentonite, Bariumsulphate System boundary

Figure 2-1 System boundary for crude oil production

Natural gas

Functional unit: The functional unit is 1 stand cub ic feet of natural gas. This process includes all relevant Mass and energy flows for the exploration and extraction of crude oil. Figure 2-2 gives an overview on the considered processes along with their key in- and outputsDocumentation Crude oil & Natural gas production 20 02

Oil_Natural gas production in the USA 4 / 9 05/08/2 008

Cement, Steel pipe, chemicals

Energy

(electrical, mechanical) Drilling meter Onshore

Production

Offshore Production Flaring / venting
Wastes Flaring / venting
Wastes

Natural gas Energy (electrical, mechanical) Drilling meter Exploration Flaring / venting Energy (electrical) Bentonite, Bariumsulphate System boundary

Figure 2-2 System boundary for natural gas producti on
The exploration is modelled per drilling meters and is considered in the model via drilling meters per mass of produced hydrocarbon. Quantities of borehole volume, removed rock are based on multiple sources such as [17]-[19]. Am ount of Bentonite and Bariumsulphate and water for drilling mud is taken from [17]. The material used for reinforcing the well is calculated based on [20]-[23]. The power demand for drilling is taken from [24]. For venting of natural gas the averaged national natural ga s composition is considered [33], [35]. The energy demand for production is given in sectio n 3.2. The associated emissions are calculated using emission factors sourced from [26] and industry data. Venting of solution gas from oil producing well is also considered. For flaring region specific flare emissions are included see section 3.3 and [25],[31],[32],[37 ]. Solid wastes and waste water are considered. The referring data is sourced from [25] , [27]-[30], [36] and as stated in section 3.4. .



### 2.2 Allocation or system expansion For the combined crude oil, natural gas and natural gas liquids production allocation by lower calorific value is applied. The lower heating values of the products are given in section 3.5.



### 2.3 Data completeness The coverage for the exploration data (crude oil, n atural gas, natural gas liquids) is 90% of mass and energy and 95% of the environmental releva nce (expert judgement).Documentation Crude oil & Natural gas production 20 02

Oil_Natural gas production in the USA 5 / 9 05/08/2 008 

### 2.4 Data selection and combination principles The data sources for the complete product system ar e sufficiently consistent: The data on the energy carrier supply chain is based on statist ics with country/region specific transport distances and energy carrier composition as well as industry and literature data on the inventory of exploration, extraction and processing . LCI modelling is fully consistent.



### 2.5 Reference year Reference year for the data set is 2002. Although s ome of the emission data and product properties are sourced from different years represe ntativeness for the reference year is considered good.



### 2.6 Data treatment and extrapolations principles In terms of the country/region specific crude oil p roduction, missing data of certain parameters has been used from countries with a compar able technology 1 . Data measured at a group of representative production facilities hav e been used to represent the national production.

1 If this ist he case it is indicated in the tables in section 3.Documentation Crude oil & Natural gas production 20 02

Oil_Natural gas production in the USA 6 / 9 05/08/2 008 

## 3 Country specific data

3.1 Production Table 1 shows the production ratio of natural gas, NGL and crude oil on a weight basis as well as the drilling feet per pound hydrocarbon pro duced. Note that all values are given for unallocated joint production of Natural gas, NGL an d crude oil.

Table 1 Production parameters

Parameter Value Source

Portion of natural gas production 58.56% [1]

Portion of NGL production 6.64% [1]

Portion of crude oil production 34.80% [34]

Share of offshore production 2 12,9% [39]

Drilling meters for onshore production 0.71x10 -05 ft/lb HC produced [2]

Drilling meters for offshore production 0.71x10 -05 ft/lb HC produced [2]



### 3.2 Energy use The specific energy use distinguished between elect ricity and mechanical energy is shown in Table 2.

Table 2 Energy consumption parameters

Parameter Value Source

Electricity demand 26.23 Btu/lb HC Value for region NorthAmerica [25] and own calculations

Mechanical energy demand 236.45 Btu/lb HC Value for region NorthAmerica [25] and own calculations

Total energy demand 262.25 Btu/lb HC Value for region North America [25]

2 Based on gross withdrawalDocumentation Crude oil & Natural gas production 20 02

Oil_Natural gas production in the USA 7 / 9 05/08/2 008 

### 3.3 Flaring and venting The flaring and venting of hydrocarbons during the production process is shown in Table 3. The flared Hydrocarbons are the sum of flared na tural gas and solution gas compounds.

Table 3 Flaring and venting parameters

Parameter Value Source

Flared Hydrocarbons 0.0037 lb/lb HC [16], [37]

Vented Hydrocarbons 0.00094 lb/lb HC [16] and own c alculations



### 3.4 Waste and waste water
The amount of solid waste and waste water emitted d uring the production process is summarised in Table 4.

Table 4 Waste and waste water parameters

Parameter Value Source

Solid waste 0.0060 lb/lb HC Global value [3];[4];[5];[6];[7];[8];[9]

Waste water onshore 0.017 lb/lb HC [25]

Waste water offshore 0.91 lb/lb HC [25]



### 3.5 Product properties The lower heating value as a country specific produ ct property is given in Table 5.

Table 5 Product properties

Parameter Value Source

Net calorific value natural gas 16762,1909 Btu/lb [ 35]

Net calorific value crude oil 18030,4254 Btu/lb [10 ];[11];[12];[13];[14];[15]Documentation Crude oil & Natural gas production 20 02

Oil_Natural gas production in the USA 8 / 9 05/08/2 008 

## 4 References

[1] IEA Natural Gas Information 2002, International Ene rgy Agency, 2004


### [2] Pennwell: The international petroleum Encyclopaedia 1997


### [3] Yukos: Yukos and the environment, 2003


### [4] Shell: http://www.shell.com/home/Framework?siteId=my-en&FC 2=/myen/html/iwgen/society_environment/environment/susta inable2003/zzz_lhn.html&FC3=/myen/html/iwgen/society_environment/environment/susta inable2003/sd03_protectthee nvironment_1008.html , 2004


### [5] Shell Nigeria 2004 People and the environment Annua l Report, 2005


### [6] Nederlandse Aardolie Maatschappij (NAM): Bron van e nergie, 2003


### [7] BP Pakistan 2003 Environmental Statement, 2004


### [8] BP Trinidad & Tobago: 2003 Environmental Statement Trinidad BU, 2004


### [9] Shell in the UK report 2001, 2002


### [10] EIA: C.2 Barrels of Crude Oil Per Metric Ton, 1980 -2003, 2004


### [11] EIA: C.3 Gross Heat Content of Crude Oil, 1980-200 3, 2004


### [12] Haverly: Crude assay libraries, 2005


### [13] Energy Intelligence Group: The Crude Oils and Their Key Characteristics, 2003


### [14] James W. Bunger and Associates, Inc.: Z-BaSICTM Crud e Oil Assay, West Texas sour, 2000


### [15] Aaron Dillard: Crude oil Quality Programs, Light Lo uisiana Sweet,2001


### [16] EIA: International Energy Annual 2003; Energy Infor mation Administration, 2004


### [17] OGP: Environmental aspects of the use and disposal of non aqueous drilling fluids

associated with offshore oil& gas operations, 2003


### [18] Da Prat, G.: Well Testing management , SPE Foundati on, presentation 2002


### [19] Vickery et al.: Successful high rate gas completion through combination of extreme

overbalance perforating and one trip perforate and gravel pack techniques, Baker oil tools, 2001


### [20] N. Lapeyrouse: Formulas and calculations for Drilli ng, Production and work over,

2nd Edition, Golf Professional Publishing, 2002Documentation Crude oil & Natural gas production 20 02

Oil_Natural gas production in the USA 9 / 9 05/08/2 008 

### [21] Gordon, D. et al. Underbalanced Drilling with casin g SPE, SPE Drilling & completion

2005


### [22] Ohio Department of Health: Materials used in drilli ng and construction of wells, 1999


### [23] Culver, G.: Drilling and well construction, Chapter 6, OIST, Department of Energy

1998


### [24] Vektor AS – Environmental developments in Well test ing, 2000


### [25] OGP, International Association of Oil and Gas Produ cers: Environmental performance in the E&P industry 2003


### [26] US EPA: Compilation of Air pollutant emission facto rs, AP 42, Volume I: Stationary

point and area sources, Fifth edition, United State s Protection Agency, Office of air quality planning and standards, 1995-2000.


### [27] US EPA: Profile of the Oil and Gas Extraction Indus try, 2nd Section, 2000


### [28] PSI: Management of produced water on offshore oil i nstallations, Policy Studies Institute, 2005


### [29] OGP: Aromatics in produced water occurrence, fate & effects and treatment, International Association of Oil and Gas Producers, 2002


### [30] OGP: Fate and effects of naturally occurring substa nces in produced water on the

marine environment, International Association of Oi l and Gas Producers, 2005


### [31] Leahey, G et at.: Theoretical and observational ass essments of flare efficiencies,

Journal of Air & Waste Management Association, Volu me 51, December 2001


### [32] Johnson, M.R. et al.: Efficiency measurements of fl ares in a cross flow, Dep. Of Mechanical Engineering, University of Alberta, Combus tion Canada conference,
1999


### [33] California Energy Commission: Natural gas compositi on and Quality, 2005+


### [34] IEA: Oil Information 2002, International Energy Age ncy, 2004


### [35] EIA: C.5 Gross Heat Content of Dry Natural Gas Prod uction, 1980-2004, 2005


### [36] BP: Environmental Statement Lower 48 U.S. Oil and G as Operations, 2001


### [37] World Bank: Global gas flaring reduction initiative , 2004


### [38] EIA: Natural gas navigator, Exploration & reserves, Footage drilled for Crude Oil and

Natural gas wells, Department of Energy, 2005


### [39] Pennwell: The international petroleum Encyclopedia 2004