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 the United States Government nor any 

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

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

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

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

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

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

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

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

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

or any agency thereof. 
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). The NETL sponsor for this project 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 Ramezan 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 contributions of Bill Harrison, U.S. Air Force 

Research Laboratory; Dr. James Hileman, Massachusetts 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 Agency, Office of Transportation and Air Quality for developing the 

national average vehicle emissions profile for the year 2005. 
 

This page intentionally left blank. 
i

Table of Contents 

List of Tables ................................................................................................................................ vi

List of Figures............................................................................................................................... xi

Acronyms and Abbreviations ................................................................................................... xiv

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 the 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 Material Acquisition ........................................................................ 8

2.1 Raw Material Acquisition for Domestic 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 Extraction 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 Foreign 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: Raw 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: Liquid Fuels Production.............................................................. 33

4.1 General Description of a Petroleum Refinery............................................................... 34 

4.2 Liquid Fuels Production at Domestic 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 CO2 Emissions from Refinery Fuels Combustion ............................................ 48 

4.2.4.2 Methane Emissions from Refinery Fuels Combustion ..................................... 48 

4.2.4.3 N2O 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 CO2 Emissions .................................................................................................. 58 

4.2.6.2 Methane Emissions ........................................................................................... 58 

4.2.6.3 N2O Emissions.................................................................................................. 60 

4.2.7 Vented/Fugitive Emissions ................................................................................... 60 

4.2.8 Refinery Emissions Profile ................................................................................... 60 
iii

4.2.9 Refinery Process Unit Data Modeling 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 Operation to Product Categories..................................... 72 

4.2.9.5 Resources and Emissions Allocation to Product Fractions............................... 79 

4.2.10 Summary of LC Stage #3 for 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: Transport of Liquid Fuels to Vehicle 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: Vehicle/Aircraft Operation ......................................................... 97

6.1 Vehicle Operation ......................................................................................................... 97 

6.2 Aircraft Operation......................................................................................................... 98 

6.3 Life Cycle Stage #5 Summary ...................................................................................... 98 

7.0 Results and Discussion.................................................................................................... 99

7.1 Construction of Life Cycle 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 Fuels 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-Produced and Imported Finished Transportation 

Fuels 

Appendix B: Cradle-to-Gate GHG Emissions Inventory for Electric 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 Procedures for Petroleum Refining Operations 

Appendix G: Cradle-to-Gate GHG Emissions Inventory for Hydrogen Production Via 

SMR with PSA Purification 

Appendix H: Crude Oil and Finished Product Loss Factors 

Appendix I: Conversion Factors 

Appendix J: Emissions Factors for Various Vehicle Types 

Appendix K: LTO Emission Factors 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 Greenhouse Gas Study Design ......................................................... ES - 5 

Table ES-2. Product Specifications and Vehicle/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 Study Boundary and their 100-year GWP...................... 3 

Table 2-1. Daily Refinery Feedstock 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 Consistent with Extraction of Crude Oil in Countries Exporting to 

U.S. Petroleum Refineries in 2005 ....................................................................................... 10 

Table 2-4. GHG Emissions Consistent with Extraction of Canadian Conventional Crude Oil 

Based on Adjusted U.S. Crude Oil Extraction Emissions Profile ........................................ 12 

Table 2-5. GHG Emissions Consistent with Extraction and Processing of Canadian Oil Sands 12 

Table 2-6. GHG Emissions Consistent with Extraction of Composite U.S. Crude Oil Mix for 

2005....................................................................................................................................... 13 

Table 2-7. Emissions from Natural Gas Production and Processing (CAPP 2004) .................... 14 

Table 2-8. Emissions from Natural Gas 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 Petroleum Fuels in 2005 and Percent of 2005 U.S. 

Consumption......................................................................................................................... 16 

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

Extraction GHG Emissions................................................................................................... 16 

Table 2-14. Canadian Refinery Feedstocks 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 Refinery Feedstocks for 2005 (EIA 2008)........................................ 20 

Table 2-17. GHG Emissions Consistent 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 Emissions Consistent with Extraction of Crude Oil and Other 

Feedstocks for U.S. and Foreign Refineries in 2005 ............................................................ 23 

Table 3-1. GHG Emissions Associated with Transport of Imported Crude Oil from Point of 

Extraction to Foreign Ports ................................................................................................... 25 

Table 3-2. Performance Specifications 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 Refineries, Exporting Port, and Country-Specific 

Average Ocean Travel Distance ........................................................................................... 26 

Table 3-5. GHG Emissions Associated with Ocean 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 Mode 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 Modes 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 Crude to Foreign Refineries/Ports............................... 31 

Table 3-13. GHG Emissions Associated with All Modes of Transport of Foreign Crude to 

Foreign Refineries................................................................................................................. 31 

Table 3-14. GHG Emissions Associated with NGL Transport.................................................... 31 

Table 3-15. GHG Emissions Associated with Unfinished Oils Transport .................................. 31 

Table 3-16. Summary of GHG Emissions 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 Fuels Energy Content (HHV)...................................................................... 40 

Table 4-4. Refinery Fuels Energy Usage Profile for 2005 (HHV).............................................. 40 

Table 4-5. Refinery Fuels and Associated Indirect CO2 Emissions ............................................ 41 

Table 4-6. Refinery Fuels and Associated Indirect Methane Emissions ..................................... 41 

Table 4-7. Refinery Fuels and Associated Indirect N2O Emissions ............................................ 41 
viii

Table 4-8. Underground Mining Energy Inputs Required for Extraction and Preparation of 371.4 

Million Tons of Bituminous Coal (USDOC 2004)............................................................... 43 

Table 4-9. Underground Bituminous Coal Mining/Preparation Fuels and Associated CO2

Emission Factors................................................................................................................... 43 

Table 4-10. Underground Bituminous Coal Mining/Preparation Fuels and Associated CH4

Emission Factors................................................................................................................... 43 

Table 4-11. Underground Bituminous Coal Mining/Preparation Fuels and Associated N2O 

Emission Factors................................................................................................................... 44 

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

Table 4-13. Coal Mining Methane Emissions Factors (API 2004) ............................................. 45 

Table 4-14. Summary of Assumptions for Coal Rail Transportation.......................................... 46 

Table 4-15. GHG Emissions Consistent with Coal Transport by Rail (EIA 2007)..................... 46 

Table 4-16. Summary of GHG Emissions Consistent 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 Emissions Consistent with Acquisition of Refinery-Produced 

Fuels...................................................................................................................................... 47 

Table 4-19. Summary of GHG Emissions Consistent with Acquisition of Petroleum Refinery 

Fuels...................................................................................................................................... 48 

Table 4-20. Refinery Fuels and Associated CO2 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 N2O 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. Pipeline Quality Natural Gas (API 2004)............................... 53 

Table 4-27. Estimated Energy Consumption for Hydrogen Production...................................... 54 

Table 4-28. Cradle-to-Gate GHG Emissions Inventory for Hydrogen Production via SMR with 

PSA Purification ................................................................................................................... 54 

Table 4-29. Specific Hydrogen Production from Catalytic Reformer......................................... 55 

Table 4-30. Catalytic Reformer Net Hydrogen Output ............................................................... 55 

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

Table 4-32. Refinery Energy Used for Hydrogen Production for U.S. Refineries in 2005......... 57 

Table 4-33. GHG Emissions Not Included in Refinery Energy Usage for Hydrogen Production 

for U.S. Refineries in 2005 ................................................................................................... 57 

Table 4-34. Flaring Summary for Selected 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 Consistent 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 Operations 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 Unit 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 Consumption for Various Petroleum Fractions....................... 70 

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

Table 4-46. Hydrogen Consumption Mass Balance .................................................................... 71 

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

Table 4-48. Estimated Hydrogen Requirements for Hydrotreating............................................. 72 

Table 4-49. Product Categories and Amount Produced in 2005 ................................................. 73 

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

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

Gasoline, and Kerosene Fractions......................................................................................... 74 

Table 4-52. Summary of Unit Operation Contribution to End Products ..................................... 75 

Table 4-53. LC Stage #3 GHG Emissions for Transportation 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 Refineries by Sub-Category ... 85 

Table 4-57. Summary of GHG Emissions Consistent with Refining of Gasoline, Diesel and Jet 

Fuel at U.S. and Foreign 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 Associated with Transport of Imported Gasoline to Domestic Ports

............................................................................................................................................... 90 
x

Table 5-4. GHG Emissions Associated with Transport of Imported Diesel to Domestic Ports.. 91 

Table 5-5. GHG Emissions Associated with Transport 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 Petroleum Product Transport Activities........................................ 93 

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

Table 5-10. Emissions Associated with Petroleum Products Transport...................................... 94 

Table 5-11. Greenhouse Gas Emissions Associated with Vehicle Refueling Operations........... 95 

Table 5-12. Summary of GHG Emissions Consistent with Transport of Gasoline, Diesel and Jet 

Fuel in 2005 .......................................................................................................................... 96 

Table 6-1. Conventional Diesel 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 Emissions 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 Emissions in a Passenger Vehicle ........................................ 106 

Table 8-1. Adjustments to Hydrotreating Subcategory Energy Consumption Utilized in 

Sensitivity Analysis ............................................................................................................ 133 
xi

List of Figures 

Figure ES-1. Life Cycle of Petroleum-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 CO2E/MMBtu LHV of Fuel 

Consumed) ...................................................................................................................... ES - 1 

Figure ES-3. Life Cycle GHG Emissions for Conventional Transportation Fuels in kg CO2E 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 Material Acquisition Activities .............................................. 8 

Figure 2-2. Country-Specific CO2 Emissions Associated with Crude Oil Extraction Relative to 

Reported Flaring ................................................................................................................... 10 

Figure 2-3. Country-Specific Methane 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 Liquid Fuels Production Activities............................................... 33 

Figure 4-2. Modern Oil Refinery (Chevron 2007)....................................................................... 34 

Figure 4-3. Atmospheric Distillation 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 Hydrotreating 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 Refining GHG Emissions Between Studies................................... 87 

Figure 5-1. Flow Diagram of Product Transport and Refueling Activities ................................. 88 
xii

Figure 7-1. Feedstock and Product Volumetric Flows for Consumption of Conventional 

Gasoline, Conventional Diesel and Kerosene-Based Jet Fuel in the U.S. in 2005............. 101 

Figure 7-2. Feedstock and Product Requirements Consistent with One Thousand Barrels of 

Conventional Gasoline Consumed in the U.S. in 2005 ...................................................... 102 

Figure 7-3. Feedstock and Product Requirements Consistent with One Thousand Barrels of 

Conventional Diesel Consumed in the U.S. in 2005 .......................................................... 103 

Figure 7-4. Feedstock and Product 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 Liquid Fuels’ Individual Life Cycle Stages and Complete Wellto-Wheels Life Cycle .......................................................................................................... 108 

Figure 7-6. Carbon Dioxide Emissions for Liquid Fuels’ Individual 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 Liquid Fuels’ Individual Life Cycle Stages and 

Complete Well-to-Wheels Life Cycle ................................................................................ 111 

Figure 7-9. Well-to-Tank GHG Emissions for Liquid Fuels..................................................... 112 

Figure 7-10. Life Cycle Stage Percent Contributions 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 for Liquid Fuels Produced Domestically ............ 119 

Figure 7-13. Comparison of GHG Emissions for 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 Gasoline 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 Diesel 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 Gasoline 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 Diesel 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 Gasoline 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 Diesel 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 Gasoline 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 Diesel 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 Quality 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 

CH4 Methane 

CIDI Compression-Ignition, Direct-Injection 

CO Carbon Monoxide 

CO2 Carbon Dioxide 

CO2E 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 Emissions, and Energy Use in Transportation 

Model 

GWP Global Warming Potential 

H2 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 Organization 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 

N2O Nitrous Oxide 

NAICS North American Industry 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 Administration for Defense District 

PM Particulate Matter 

ppm Parts Per Million 

PSA Pressure Swing Adsorption 

psi Pounds per Square Inch 

PV Present Value 

RCRA Resource Conservation and Recovery Act 

ROG Reactive Organic Gas 

SCAQMD South Coast Air Quality 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

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ES - 1

Executive Summary 

Alternative transportation fuel options are currently being explored or implemented across the 

nation to (1) reduce climate change impacts from the release of greenhouse gases (GHGs), (2) 

reduce our reliance on foreign sources of energy, and (3) provide an economically-stable 

transportation fuel source to reduce price shocks to our economy. The U.S. Department of 

Energy (DOE), National Energy Technology Laboratory (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 transparent baseline for the life cycle GHG 

emissions from conventional petroleum-based transportation 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 performance of alternative transportation fuels with 

respect to climate change impacts. The study 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 (CO2E) 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 CO2E/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% 

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

Crude Oil Gasoline Diesel Fuel Jet Fuel

Key

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 Boundary

Well-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

100

Greenhouse 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 CO2E 

of carbon dioxide (CO2), methane (CH4), and nitrous oxide (N2O) are reported based on the 2007 

IPCC 100-year global warming potentials. Combustion of the fuel (denoted as “Life Cycle Stage 

#5: Use” in this study) accounts for 80% of the gasoline and diesel vehicle emissions and almost 

84% of the total GHG emissions from the use of jet fuel. The life cycle GHG analysis results, as 

reported, are modeled based on the 2005 average passenger vehicle as modeled by the U.S. 

Environmental Protection Agency’s MOVES model. Changes to the vehicle or engine type will 

not change the baseline life cycle GHG emissions profile for conventional gasoline and 

conventional diesel fuel as reported on a “per MMBtu LHV of Fuel Consumed” basis. Results 

reported on a “per mile traveled” basis are dependant 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. Federal 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 (EPA) to calculate annual GHG emissions from 

aircraft operations in the United States. 

Well-to-tank (WTT) releases of GHGs contribute 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 gasoline and diesel fuel while the crude oil 

extraction process (Life Cycle Stage #1: RMA) contributes 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 GHG emissions on a CO2E 

basis. 

Opportunities for lowering the life cycle GHG emissions from transportation-related fuels will 

best be achieved through improved vehicle efficiency (e.g., gallons of fuel consumed per mile 

traveled) or alternative sources of transportation fuels. For example, improving the average 

gasoline-powered light-duty passenger vehicle efficiency 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 its trade association the American Petroleum 

Institute (API), has implemented an aggressive greenhouse gas reduction program entitled “API 

Voluntary Climate Change Program.” This program, 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 - 3

Figure ES-3. Life Cycle GHG Emissions for Conventional Transportation Fuels in kg CO2E per MMBtu L

7.3 6.6 6.8

1.4 1.3 1.3

9.8 9.5

6.0

1.1 0.9 1.0

76.6 76.7 77.7

0

20406080

100

Gasoline

Diesel

Jet Fuel

Gasoline

Diesel

Jet Fuel

Gasoline

Diesel

Jet Fuel

Gasoline

Diesel

Jet Fuel

Gasoline

Diesel

Jet Fuel

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

GHG Emissions 

(kg CO

2E/MMBtu LHV of fuel consumed)

Carbon Dioxide Methane Nitrous Oxide
ES - 4

Study Drivers 

The production and delivery of transportation fuels has been widely studied in the United States. 

Over the past 10 years, the increasing emphasis on GHG emissions in the United States and 

abroad has resulted in a number of well-documented and cited reports 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 CO2E/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 CO2E/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, 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 ES-4 is 

appropriate based on the individual study purpose and modeling assumptions employed by the 

authors. Significant differences in results arise primarily from differences in study boundary 

conditions, type of data used in the analysis, technology represented, geographical representation 

of key processes (national average, regional, or site-specific), 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). 

On January 4, 2007, the EISA 2007 was passed into 

law. Under Title II, Subtitle 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 transportation 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 this 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 Standards Organization (ISO) 14040 and 14044 life 

cycle assessment standards. This study includes all four phases of a life cycle assessment: Goal 

and Scope Definition, Inventory Analysis, Impact Assessment, and Interpretation. The scope of 

the life cycle inventory (LCI) is limited to greenhouse 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 for 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. Specifically, the average life cycle GHG profile for 

transportation fuels sold or distributed 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 exported to other countries for use. 

GHG life cycle results are reported in terms of kg CO2E/MMBtu LHV of fuel consumed. This 

metric is dependant on the energy content of the fuel and could alternatively be reported in terms 

of kg CO2E/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 analysis study design parameters. Figure ES-5 

depicts the magnitude of transportation fuels sold 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 CO2E/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/aircraft use profiles have been 

identified as common differences between existing studies that characterize the life cycle GHG 

emissions from conventional transportation 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 CO2E/MMBtu LHV 76.6 76.7 77.7 

Use Phase GHG Emissions, kg CO2E/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 extraction practices were identified for the U.S. or 

foreign countries with the exception 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 reported by the Energy Information Administration 

(EIA) and other industry sources does not provide detail for all pertinent data to 

differentiate between different grades 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, distillate 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 reformulated 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 blender 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, conventional diesel fuel, and kerosene-based 

jet fuel is based on the U.S. refining model developed within this study. Significant 

differences in modeling assumptions and boundary conditions for foreign refining 

operations characterized in the public data voided 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 cycle GHG results (WTW). 

• Vehicle emissions profiles were developed by the U.S. Environmental Protection 

Agency, Office of Transportation and Air Quality, MOVES model. The profiles 

represent the average vehicle in operation during 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 emission. Inherent uncertainties in the use 

emissions modeling are managed by ensuring consistent and comparable vehicle use 

profiles are applied when evaluating alternative transportation fuel options. 

• A statistical average of the aircraft in operation in 2005 is not available and emissions 

associated with cruise methane and nitrous oxide emissions are highly uncertain. 

Furthermore, gross estimates are used to estimate the relative fuel consumption of cruise 

and landing and take-off. This limitation is also managed by ensuring 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 requirements identified by the International Standards 

Organization (ISO) 14044 “Environmental Management – Life Cycle Assessment – 

Requirements and Guidelines” as appropriate metrics for evaluating the quality 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 constructed to represent all U.S. operations. 

Country specific crude oil extraction profiles 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 results 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 accurately represent energy consumption 

and emission rates relative to year 2005. 

 

Petroleum refining unit process capacity utilization data was based on a 

1996 survey of the U.S. petroleum industry. Unit process throughput 

allocation to the product categories was based on a survey of recent 

literature. Sensitivity analysis was 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 subsequent 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 study’s defined cut-off criteria of mass, 

cost, and environmental relevance consistent 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 transportation 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% reproducible. Proprietary purchased 

data from PE International were not reported but these data are publicallyavailable and calculated results in terms of CO2E using the PE International 

data are fully reported. All documentation 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 estimates 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 determined for each data point used in this 

study. Key parameters were assessed through 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 quality of life cycle (GHG) analysis based on 

the study goal and scope. Use of the study results is applicable for all 

decision types (internal, public, policy, etc.) when used in the appropriate 

context. 
ES - 10

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 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 cycle greenhouse gas (GHG) emissions for gasoline 

and diesel sold or distributed as a transportation fuel in 2005 to be determined by the 

Administrator of the U.S. Environmental Protection Agency (EPA), after notice and opportunity 

for comment. That baseline will become the metric 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 alternative fuel projects for award and justifying 

the purchase of biofuels and/or synthetic fuels by Federal 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 has been widely studied in the United States. 

Over the past 10 years, the increasing emphasis on GHG emissions in the United States and 

abroad has resulted in a number of well-documented and cited reports 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 CO2E/MMBtu LHV1

–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 CO2E/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 CO2E/MMBtu” = kilograms of carbon dioxide (CO2) equivalents (E) per million British thermal units 

(MMBtu) Lower Heating Value (LHV) of diesel 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 appropriate based on the individual study purpose and 

modeling assumptions employed by the authors. Significant differences in results arise primarily 

from differences in study boundary conditions, type of data used in the analysis, technology 

represented, geographical representation of key processes (national 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 results to determine the 

life cycle greenhouse gas emissions for liquid fuels (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 and foreign extraction of refinery feedstocks 

and fuels, transport to U.S. and foreign refineries (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 vehicle or a jet aircraft. The life cycle boundary for 

this study is referred to as “cradle-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 petroleum-based fuel production operations included 

within this study. This conceptual boundary applies 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) approach utilizes the International Standards 

Organization (ISO) 14040 “Environmental Management – Life Cycle Assessment – Principles 

and Framework.” (ISO 2006) This study includes all four phases of a life 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 (LCIA) considers only the global warming potential 

(GWP) of the GHG emissions based on their relative contribution. Emissions from various 

greenhouse gases were assessed during a pre-screening assessment to determine the primary 

emissions of relevance to be tracked and included within the study. Based on analysis of 

available data, carbon dioxide (CO2), methane (CH4), and nitrous oxide (N2O) 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 contribution 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 most current 2007 IPCC values are used. When 

interpreting older data sources 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 reported in mass of CO2 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 CO2E) 

2001 IPCC 

(GWP CO2E) 

2007 IPCC 

(GWP CO2E) 

This Study 

(GWP CO2E) 

Carbon Dioxide CO2 1 1 1 1 

Methane CH4 21 23 25 25 

Nitrous Oxide N2O 310 296 298 298 
 

 4

Nitrogen oxides (NOx) and their impact to global warming are currently being reviewed by 

climatologists around the world and there is a lack of agreement about the impact of NOx in 

relation to global warming. The 2007 Intergovernmental Panel on Climate Change (IPCC) 

report entitled “Climate Change 2007: The Physical Science Basis” notes that nitrogen oxides 

have short lifetimes and complex nonlinear chemistry with opposing indirect effects through 

ozone enhancements and methane reduction (IPCC 2007). Most current research suggests that 

the GWP for surface/industrial NOx emission may be negative. Wild et al. (2001) report a GWP 

for industrial NOx emissions of -12. Since there is a lack of agreement on NOx 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 materials and processes to be included in the system 

boundary. Following the requirements of International Organization of Standardization (ISO) 

LCA standard 14044 (ISO 2006), the criteria of mass, cost, and environmental relevance were 

used for material and energy inputs. 

A significant material input is defined as a material input that has a mass greater than 1% of the 

principal product that is produced by a process. A significant material input is also defined as 

one that has a relatively high cost (for instance, compared to the cost of the largest, by mass, 

material input), or has an important environmental relevance (for instance, a high GWP). 

A significant energy input is defined as one that contributes more than 1% of the total energy 

used by the process. As with materials, a significant 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; therefore, no construction related emissions are 

included within the scope of this study. 

Humans involved in the system boundary have a burden on the environment, 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 required to quantify the 

human-related inflows-from and outflows-to the environment and how to allocate them to fuel 

production. Furthermore, it is assumed that the workforce will be unaffected by the choice of 

fuel at large-scale production volumes. Issues related to humans, such as the societal impacts of 

humans in the workforce that need to be addressed 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 circumstances 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 atypical 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 transport, are included in the system boundary. 
 

 5

1.3.4 Data Reduction and Allocation Procedures 

In order to generate a life cycle inventory for each pathway, the vast 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, data aggregation, allocation of 

flows/releases, etc.). ISO standards, where appropriate, are used as guidelines in performing data 

reductions and allocation procedures (ISO 2006). 

System expansion and unit process division are 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 displacement method, a type of system expansion, is recommended 

by the U.S. Environmental Protection Agency (EPA) for allocating co-products from energy 

conversion facilities producing transportation fuels (EPA 2007). The displacement method 

expands the system boundary to include the production 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 energy carriers or any materials produced for its energy 

value are allocated based on energy content. All 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 delivery of petroleum-based 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 represents existing operations 

for 2005. 

The primary source of U.S. petroleum refining operations data used in the analysis is the U.S. 

Department of Energy (DOE), Energy Information Administration (EIA) petroleum industry 

statistics. Refinery equipment is surveyed annually on January 1st 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 Worldwide Refining Survey which also presents 

data as of January 1, 2006. 

The vehicle emissions for conventional gasoline and 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: Vehicle/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 crude oil, natural gas liquids, unfinished 

oils, and unconventional hydrocarbons (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 domestic and foreign sources to U.S. and 

foreign refineries. 

• Life Cycle Stage #3: Liquid Fuels Production 

o Boundary starts at the entrance of the petroleum 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 fuels to the bulk fuel storage depot. 

o Petroleum refinery operations are both foreign and domestic. 

o Emissions associated with acquisition and production of indirect fuel inputs such 

as purchased power and steam, purchased fuels such as natural gas and coal, and 

fuels produced in the refinery and subsequently 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 associated 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 bulk fuel storage depot for gasoline and 

diesel and the airport fuel storage tanks. 

o Boundary includes the operation of liquid fuel tanker trucks used to transfer the 

gasoline/diesel from the depot to the vehicle fueling stations and the transport of 

jet fuel from the airport fuel storage tanks to the aircraft by a refueling truck. 

• Life Cycle Stage #5: Vehicle/Aircraft Operation 

o Boundary starts at the vehicle/aircraft fuel 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 earth and associated post-extraction-processing 

required to derive a feedstock-quality input. This section describes the environmental modeling 

assumptions associated with this LC stage for feedstocks for U.S. petroleum 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 activities and flow of feedstocks 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 the following petroleum refinery feedstocks are 

included in this stage: 

• Crude oil and other hydrocarbons fed to refineries 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 includes domestic and foreign crude oil. Extraction 

profiles are modeled for the foreign sources shown in Table 2-2 which (when added to the U.S. 

resources) account for over 90% of the total 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 oil extraction profiles were purchased from PE International (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 NETL. The global warming potential in CO2 equivalents 

(utilizing the factors in Table 1-1) associated with the purchased extraction profiles is shown in 

Table 2-3. The data are representative of 2002 rather 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 CO2E/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 country-to-country are significant. Much of the 

variability can be explained by the reported flaring and venting rates consistent with crude oil 

extraction in each of the countries. Figure 2-2 shows the relationship between flaring rate and 

CO2 emissions. A dotted line is added to show what the expected CO2 emissions would be if the 

gas flared is assumed to be natural gas. Figure 2-3 shows the relationship between venting rate 

and CH4 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. Flaring and venting data 

presented in these figures are consistent with the values reported in the documentation associated 

with the crude oil extraction profiles (Attachment 1).§

Figure 2-2. Country-Specific CO2 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)

CO2 Emissions 

(per kg of crude oil)

Predicted CO2 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

U.S. Venezuela

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 largest 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 extraction 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 operations. However, in this report indirect 

emissions from purchased power and steam were not fully quantified. CAPP noted that 

convenient and reliable sources of these data generally 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 CO2 and methane emissions profiles, 

the U.S. profile was modified to account for the 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 CO2E/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 conventional crude oil as well 

as oil sands products (either diluted crude bitumen or synthetic crude produced from extracted 

bitumen). In 2005, the U.S. refinery crude feedstock mix contained 3.5% oil sands (NEB 2006). 

Of this amount, 43% was input as blended bitumen, 35% as light synthetic crude, and 21% as 

heavy synthetic crude (NEB 2006). The environmental emissions and GHG profile is 

significantly higher for oil sands than for conventional crude oil and there is variation in the oil 

sands profile depending upon the method of extraction 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 primary producers, Imperial Oil and Syncrude, 

and their estimated 2005 production rates, as reported by the respective operators. Together, 

these two operations accounted for approximately 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 

Source (kg/bbl synthetic crude oil) 

CO2 CH4 N2O 

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 Composite Extraction GHG Profiles 

Figure 2-4 compares the global warming potential for crude oil extraction based on the 

purchased profiles, the developed Canadian conventional 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 operations 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 CO2E/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 

CO2 CH4 N2O 

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 extracted from a reservoir during natural gas 

recovery. Natural gas liquids include 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 for 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 processing 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 m3 raw natural gas produced) Source 

CO2 CH4 N2O 

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 same 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 this 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 

CO2 CH4 N2O 

Natural Gas Liquids 5.33 0.105 0.000288 

2.1.3 Unfinished Oils Extraction 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 operation. EIA reports the 

unfinished oils input to refineries 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 same as the U.S. composite crude oil profile 

(excluding Canadian oil sands) generated in Section 2.1.1. 

The minimum additional processing for the unfinished oils is assumed to be atmospheric 

distillation separation for all components. Residuum is anticipated to also pass through the 

vacuum distillation column. Energy usage, and associated emissions, consistent with performing 

these operations (see Life Cycle Stage #3) are added to the crude oil composite to generate a 

total for the unfinished oils fraction as shown in Table 2-10. 
 

 15

Table 2-10. Emissions for Unfinished Oils Extraction and Processing 

Emissions (kg/bbl unfinished oils) Source 

CO2 CH4 N2O 

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 GHG emissions profiles for the U.S. refinery 

feedstocks for 2005. The results are based on the feedstock volumes delivered to U.S. refineries 

and thus the additional crude oil 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) CO2 CH4 N2O 

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 2005 and contributed to the 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 comprehensive 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 exported from a distinct set 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 foreign countries. Appendix A outlines the specific 

sources for imported gasoline (and associated blendstocks), diesel (≤ 500 ppm sulfur), and 

kerosene-based jet fuel as reported by EIA. Table 2-12 shows the import 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, Portugal, Russia, Spain, Sweden, and United Kingdom) 

EU-15 includes Austria, Belgium, Denmark, Finland, France, Germany, Greece, Ireland, Italy, 

Luxembourg, the Netherlands, Portugal, 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 extraction for the top countries supplying 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 quantity) (IEA 2008). For all of the aforementioned 

countries it is assumed that the country-specific extraction profile is representative 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, Professional Database (2007), when available. 

Delivered “free-to-customer” country-specific profiles include an embedded transport 

component in the GHG profile. The extraction contribution to the total GHG profile has been 

estimated by determining the GHG contribution of the extraction step to the 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 

CO2, 99% of methane, and 80% of nitrous oxide is attributable to raw material acquisition. The 

embedded transport component which is excluded here is incorporated in LC Stage #2 modeling. 

Canada Profile 

The Canada composite profile was individually developed, as it is a primary liquid fuel exporter 

to the U.S. and its refineries import a significant portion of their feedstocks. Table 2-14 lists the 

refinery feedstocks—both foreign and domestic—input 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 

m3) 

% 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 

m3) 

% of Total 

Crude Oil and 

Equivalent 

Quantity 

(bpd) 

Domestic Production 

Canada Crude (light + heavy) 32,402 30.3% 558,370 

Synthetic Crude Oil (light) 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 oil 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 extraction profile was developed as described in 

Section 2.1.1.1. For Canadian oil sands, Table 2-6 lists the upstream emissions on a per-barreloil-equivalent basis. For this profile, synthetic crude oil (light) upstream emissions were taken 

from Syncrude emissions reports for 2005 (EnvCan 2008), (Syncrude 2006) and crude bitumen 

upstream emissions were approximated by assuming Imperial Oil Cold Lake bitumen production 

emissions are representative of all 2005 crude bitumen production operations. Condensates and 

pentanes plus were modeled the same as U.S. NGL (see Section 2.1.2). 

The resulting extraction profile for feedstocks to Canadian refineries 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 

CO2 CH4 N2O 

Crude Oil Mix Average 35.0 0.366 0.00102 

Virgin Islands Profile 

The Virgin Islands profile was also developed individually 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 oil sources. Colombia was modeled using Venezuela as a surrogate 

profile, Peru was modeled using Ecuador as a surrogate profile, and the Ivory Coast and Gabon 

were modeled using Angola as a surrogate profile. The resulting extraction profile for 

feedstocks to Virgin Island refineries 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 

CO2 CH4 N2O 

Crude Oil Mix Average 23.0 0.634 0.000590 

Surrogate Profiles 

For other countries, a surrogate profile was chosen based upon either geographic location or 

primary crude source. For any European country for which a country-specific 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 average (FA) of the delivered profiles. § The foreign average is 

used for 9% of the gasoline crude oil mix, 12% of the diesel crude oil mix, and 22% of the jet 

fuel crude oil mix. With the exception of Saudi Arabia, these profiles represent the GHG 

emissions for delivered crude oil and the embedded transport component was removed as 

previously described. 

Table 2-13 lists the export countries and the upstream profile used to determine the crude oil 

extraction emissions. Figure 2-5 shows the global warming potential (calculated using the 

factors in Table 1-1) for each of the profiles utilized and developed. For the delivered crude oil 

profiles, the transport component 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 CO2E/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 associated blendstocks amounted to 14.2% of domestic gasoline 

production in 2005. Imports come from many different countries, as shown in Appendix A. 

Canada (15.8%), the Netherlands (10.5%), Virgin Islands (10.5%), the United Kingdom (10.3%), 

and Venezuela (7.6%) were the top exporters of gasoline (and associated blendstocks) to the U.S. 

in 2005. The composite GHG emissions profile consistent 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 

CO2 CH4 N2O 

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 the 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, Lithuania, 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 imported. The composite GHG emissions profile 

consistent with extraction of the crude 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 

CO2 CH4 N2O 

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 Venezuela (15.7%). The origin of U.S. jet fuel imports for 2005 is 

shown in Appendix A along with the quantity imported. The composite GHG emissions profile 

consistent with extraction of the 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 

CO2 CH4 N2O 

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 associated 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 presented per barrel of feedstock extracted. 

Emissions associated with Canadian oil sands extraction 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 

CO2 CH4 N2O 

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 petroleum refinery feedstocks 

are included in this stage: 

• Crude oil and other hydrocarbons (i.e. from Canadian 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 Other Operations

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 transport of foreign and domestic crude oil from the point of 

extraction to the refinery. Crude oil transport is modeled for delivery to domestic refineries and 

foreign refineries for processing into finished imports. Transport emissions are based on the 

amount input to a transport operation (amount extracted). 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 includes pipeline transport within the exporting country, 

ocean tanker transport to the U.S., and domestic 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 profile 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 emissions 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 CO2 CH4 N2O 

Pipeline Transport 0.863 1.00E-03 1.12E-05 

3.1.1.2 Crude Oil Mix Ocean Transport to Domestic Ports 

The energy requirement for transporting crude oil via tanker is calculated by multiplying the 

quantity shipped by the distance traveled 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 emissions associated with consumption of that 

quantity of energy (as heavy fuel oil) is determined. 

Table 3-2 outlines the performance specifications for various sizes and types of crude carriers. 

The energy intensity ranges from 4.2 to 7.5 Btu per barrel-nautical mile of crude transported. 

The assumed study value for crude tanker transport operations is 5.5 Btu per barrel-nautical 

mile.§ 

The heavy fuel oil (HFO) used to power tanker operations is essentially 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 (m3) 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 CO2 CH4 N2O 

HFO Combustion in Ships 78.8 5.75E-03 2.00E-03 

Table 3-4 lists the foreign crude sources for 2005 and the exporting 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 imported 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. Transport through the Panama Canal, 

Suez Canal, and Bosporus Strait was disallowed. Canadian exports entering the U.S. through 

ocean or lake ports are assumed to travel via water while all others are assumed to be transported 

via pipeline. Based on this assumption, approximately 28% of the imports from Canada are 

waterborne. For shipments received from countries other than those listed in 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-Specific 

Average 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-Specific 

Average 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 waterborne 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 CO2 CH4 N2O 

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, rail, and truck. Table 3-6 

summarizes U.S. crude petroleum domestic transportation modes for years 2000 through 2004. 

Table 3-6. Total Crude Petroleum Carried 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-miles of crude and petroleum products for federallyregulated pipelines (84 percent) plus an estimated breakdown 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) Transportation 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 powering the aforementioned transportation operations. 

Based upon the ORNL Transportation Energy Data Book, Table 2.4, in 2004, natural gas and 

electricity were the primary fuels for effecting pipeline transport. Since natural gas is used 

primarily for fueling natural gas pipeline transport, all crude oil and petroleum product transport 

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. Water carriers transporting freight 

are powered by diesel fuel and residual fuel oil (30.5 % diesel fuel and 69.5% residual fuel oil on 

an energetic basis). Medium/heavy trucks were powered primarily (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 Table 3-7 are then combined to determine a quantity of energy (by 

transport type) expended for crude petroleum transport in 2004. This energy/resource usage is 

then allocated to the 5,675,365,000 barrels of crude oil (sum of 2004 imported crude oil and 

2004 U.S. crude oil production). The transportation 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 quantities 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 emissions factors for diesel fuel and residual fuel 

oil are for combustion of the fuel only. The upstream emissions associated with production of 

secondary fuels contribute only minimally to the final results for the scenarios 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) 

CO2

Emissions 

(g CO2

/gallon) 

CH4

Emissions 

(g CH4 

/gallon) 

N2O 

Emissions 

(g N2O 

/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 associated with each of the aforementioned modes of 

crude oil transportation are reported 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 CO2 CH4 N2O 

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 foreign refineries producing 

imported liquid fuels. The methods utilized for each country exporting finished fuels to the U.S. 

vary by country. 

Delivered Country-Specific Profiles 

Countries for which the crude oil delivered “free-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 contribution 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 CO2, 1% of methane, and 20% of nitrous oxide is attributable to transport 

operations. 

Pipeline Transport 

An average pipeline transport distance 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 profile 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 resulting 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 CO2 CH4 N2O 

Pipeline Transport 0.863 1.00E-03 1.12E-05 

Tanker Transport 

Canada and the Virgin Islands import significant quantities of foreign crudes for refinery 

processing. Transport of crude oil to South Korea is also assumed 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. Transport 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 for each country. It was assumed that all crude 

imports to Canada from the U.S. were by pipeline. 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)* CO2 CH4 N2O 

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 transport and the transport portion of the delivered 

country-specific profiles for the countries exporting gasoline, diesel 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 CO2 CH4 N2O 

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 petroleum products transport in Life Cycle Stage 

#4 (see Section 5.1.2 for detailed modeling assumptions). 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 CO2 CH4 N2O 

NGL Transport 4.54 2.81E-03 8.93E-05 

3.3 Unfinished Oils Transport 

The unfinished oils transport component is modeled the same as an equivalent volume of 

imported crude oil. Refer to Section 3.1.1 for further 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 CO2 CH4 N2O 

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 associated with transport of petroleum refining 

feedstocks for U.S. refineries and foreign refineries producing the gasoline, diesel and jet fuel 

imported by the U.S. in 2005. The increase in transport 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 

CO2 CH4 N2O 

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 petroleum pipeline or tanker used to transport the 

liquid fuels to a bulk fuel storage depot. Modeling assumptions and methodology are described 

for both domestic refineries and foreign refineries providing imported gasoline, diesel and jet 

fuel. Production of oxygenates is excluded 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 specific feed properties. The complexity level of refineries is 

increasing with time due to decreasing crude oil input quality (heavier crude oils with higher 

sulfur contents) resulting in increased upgrading and processing requirements. 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 that constitute a modern refinery and provide 

brief descriptions of those operations. Specialized operations that contribute solely (or 

primarily) to upgrading of hydrocarbon materials not intended for liquid 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 atmospheric distillation column fractionates the crude oil input into 

various fractions with different boiling 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 heavy (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 processes 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 gasoline and diesel fractions at the expense of the less-desirable 

residual fraction. Catalytic cracking 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 hydrocarbon 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, distillate 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 delayed 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. Delayed 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 reacted with hydrogen to remove sulfur species 

from the stream. This process is often distinguished from hydrocracking by the severity of the 

processing conditions. Since the purpose of the process is to remove sulfur and not significantly 

alter the molecular composition and species profile, it is often performed under milder 

conditions. 

Catalytic Reforming: The catalytic reforming operation takes less desirable naphtha streams 

and chemically reconfigures the compounds. The primary operations are dehydrogenation of 

napthenes to produce aromatic species, isomerization, dehydrocyclization (transforming a 

straight-chain compound into a ring structure while dehydrogenating the same), and 

hydrocracking (Energetics 2007). While catalytically-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 products not contributing directly to the gasoline 

slate. 

Isomerization: Isomerization is a process where straight-chain hydrocarbons (paraffins) are 

converted into branched isomers. The isoparaffins are produced through a series of molecular 

rearrangements in the presence of a catalyst. The branched paraffins are superior 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, isopentane, 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 sulfuric acid or hydrofluoric acid. The product of the 

reaction is a mixture of branched chain paraffins which are used as gasoline additives. 
 

 37

4.2 Liquid Fuels Production at Domestic Petroleum Refineries 

The emissions profile associated with U.S. petroleum refining operations in 2005 consists of 

emissions from fuels acquisition, fuels combustion, hydrogen production, flaring, and venting 

and fugitive emissions. These refinery operations result in the production of a variety of finished 

products including gasoline, diesel fuel, kerosene-based jet fuel, 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 detail in this section. 

The GHG emissions profile associated with U.S. petroleum refining operations 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 associated with natural gas feed 

o CO2 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 various 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 natural gas will not be allocated based on the unit 

operations where the natural gas is consumed. 

Figure 4-4 depicts the two emissions pools, refinery 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 are embedded in the refinery emissions profile 

while the remaining is included in the hydrogen emissions pool. This is discussed in detail in 

subsequent sections.
38

Figure 4-4. Depiction of Refinery and Hydrogen Emissions Pools 
 

 39

4.2.1 Reported Refinery Data 

The primary source of information used to determine 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 petroleum production and processing data from U.S. 

refineries and publishes most of the information on their website for public use. While some 

refinery-specific information is available, refinery operational data are generally aggregated to 

avoid disclosing proprietary information. 

4.2.2 Refinery Energy Usage 

Fuels consumed data are presented by EIA on an annual 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 estimate the refinery energy consumption and associated 

emissions. Puerto Rico and the Virgin Islands refineries are not included 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 summing 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 content 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 hydrocarbons, oxygenates, hydrogen, unfinished 

oils, gasoline, special naphthas, jet fuel, lubricants, asphalt and road oil, and 

miscellaneous products. 

** Assume bituminous coal; API average energy content for bituminous coal of 

13,500 Btu HHV/lb
 

 41

4.2.3 Fuels Acquisition 

Each of the fuels consumed and indirect fuel inputs for refineries have an emissions profile 

associated with extraction/production 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 Electricity and Steam 

The tables below list CO2, CH4, and N2O emissions factors consistent with refinery usage of 

purchased power and steam. Emissions consistent 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 CO2 Emissions 

Refinery Fuel 

CO2 Emissions 

(kg CO2/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 

CH4 Emissions 

(kg CH4/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 N2O Emissions 

Refinery Fuel 

N2O Emissions 

(kg N2O/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 and 2 in 2005. A total of 41,000 short tons of coal 

was consumed in 2005—33,000 short tons in PADD 1 and 8,000 in PADD 2 (EIA 2008). Figure 

4-5 shows the location of the regional PADDs in the 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 bituminous 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 that 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) transport 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 (included preparation). No major technology 

advances occurred in the field of coal mining in the years between 2002 and 2005 and therefore 

it is assumed that these data meets the quality objectives for this study. Table 4-8 lists the fuels 

used for extraction and preparation of bituminous 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) grade 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 CO2

Emission Factors 

Fuel CO2 Emissions 

(kg CO2/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 CH4

Emission Factors 

Fuel CH4 Emissions 

(kg CH4/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 N2O 

Emission Factors 

Fuel N2O Emissions 

(kg N2O/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 methane emissions by considering available estimates 

of coal bed methane (CBM) in-situ productivity for basins containing large bituminous coal 

reserves, and adding estimated methane emissions that would be released if that mined coal were 

removed and processed, such as would be the case in mining and post-mining processing. 

Table 4-12 reports values or ranges of estimated extractable CBM for several large bituminous 

coal basins in the conterminous United States. These data, reported from various sources, all 

describe the estimated extractable methane using best available CBM extraction technologies 

and do not represent the total volume 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 only the preliminary coal extraction phase (initial 

mining being considered roughly equivalent to fracturing and depressurizing 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 equal 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 surface 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 CH4 per short 

ton of coal (vented and degassed) 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 CH4/short 

ton coal 

lb CH4/short 

ton coal 

Tonnes CH4/ 

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 post-mining processing of coal mined from an 

underground mine of 76.2 scf CH4/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, considered to be represented in the 

CBM specific productivity values. To account for the post-mining methane emissions 

(analogous to methane that remains in the formation following in-situ CBM extraction), it is 

assumed that an additional 23% of the reported bituminous CBM value (260 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 emissions 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 practices are not employed at underground bituminous 

coal mines. 
 

 46

Coal Transportation 

Transport of the coal from the mine or preparation plant to the refinery is assumed to be 100% by 

rail. The assumed transport distance is 400 miles (round trip) and energy intensity values for rail 

transport for 2005, extracted from the Transportation Energy Data Book (ORNL 2007), is used 

for determining transport emissions from locomotive transport operations. According to the 

Transportation Energy Data Book, locomotives for freight transport are fueled 100% by diesel 

fuel. Assumptions made to construct the coal transportation portion of the coal 

extraction/transport upstream profile for use in petroleum refineries are reported in Table 4-14. 

Table 4-15 outlines the GHG emissions associated 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 

CO2 CH4 N2O CO2 CH4 N2O 

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 bituminous coal mining from an underground mine, 

associated mine methane emissions, and estimated emissions 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 

CO2 CH4 N2O 

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 refinery 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 are representative of the U.S. natural gas mix 

delivered to customers in 2002 (GaBi data set dated September 15, 2006). The GHG emissions 

consistent with natural gas consumed by refineries are shown in Table 4-17. No significant 

technology differences/advances occurred in the field of natural gas extraction and processing in 

the years between 2002 and 2005 and therefore the data 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 CO2E) 

kg Natural Gas 0.516 

scf Natural Gas 0.00984 

4.2.3.4 Refinery-Produced Fuels 

The upstream emissions profile for fuels that are 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. For 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 (excluding acquisition of refinery-produced fuels) must be determined 

prior to incorporating the upstream emissions of these fuels. 

Appendix C details the development of this profile. 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) CO2 CH4 N2O 

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 Acquisition Emissions Profile 

Table 4-19 provides a summary of the GHG Emissions 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 CO2 CH4 N2O 

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 refinery is from fuels combustion. Emissions are 

determined for all of the fuels consumed during 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 refining fuels. Total emissions are 

determined by multiplying the emission factor by the quantity of fuel consumed. 

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 associated with the fuels consumed 

are allocated equivalently for each unit of energy consumed. 

4.2.4.1 CO2 Emissions from Refinery Fuels Combustion 

Refinery CO2 emissions are determined by multiplying the quantity of fuel consumed by the 

appropriate CO2 emissions factor for fuel consumption. Table 4-20 shows the various 

hydrocarbon fuels consumed at refineries and lists the CO2 emissions consistent with combustion 

of the individual species. 

4.2.4.2 Methane Emissions from Refinery Fuels Combustion 

Methane emissions have been quantified for standard combustion processes using finished fuels, 

but off-spec refinery still gas and coke combustion emission factors are not as precise and 

estimates vary. In the absence of detailed process and equipment information for the refining 

facilities, the uncertainty of the methane estimates from combustion emissions is high. Due, in 

part, to this high level of uncertainty, the Petroleum Industry Guidelines for Reporting 

Greenhouse Gas Emissions (IPIECA et al. 2003) do not consider methane produced by fuel 

combustion in any of its GHG estimation tiers for refining operations (see Appendix D). 

The Canadian National Energy Board has estimated 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 consistent 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 CO2 Emissions from Fuel Combustion 

Refinery Fuel CO2 Emissions 

(kg CO2/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. CO2

emissions estimate consistent with API Compendium emission factor or “miscellaneous 

petroleum products and crude” (see API 2004 Appendix A). 

** Assume bituminous coal; API average energy content for bituminous coal of 13,500 Btu HHV/lb 

and 93.1 kg CO2 emitted per MMBtu HHV 

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

Refinery Fuel CH4 Emissions 

(kg CH4/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 hydrocarbons, 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 N2O Emissions from Refinery Fuels Combustion 

Current estimates for N2O emissions from combustion operations, as determined by the U.S. 

Environmental Protection Agency (EPA) AP-42 emission factors, are only determined for typical 

operations using petroleum refinery 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 combustion would dramatically underestimate N2O 

 

§ A sensitivity analysis was performed on these parameters. 
 

 50

production. Emission factors for refinery operations using standard fuels are shown in Appendix 

E. 

The Canadian National Energy Board has estimated N2O emission factors for combustion of 

various non-standard hydrocarbon fuels (NEB 1999) and those values have been used to 

determine N2O emissions consistent with refinery combustion operations. The N2O emission 

factors utilized in this study are presented in Table 4-22. 

Table 4-22. Refinery Fuels and Associated N2O Emissions from Fuel Combustion 

Refinery Fuel N2O Emissions 

(kg N2O/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 hydrocarbons, 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 attributable 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 

CO2 CH4 N2O 

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 different 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 assumed to be generated by steam methane reforming 

using natural gas as both a feedstock and fuel. 

While all three of the aforementioned sources contribute to the emissions profile for the refining 

industry, their GHG accounting differs. The energy 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 the previous section. The fuel and associated 

utilities for on-site hydrogen production at a dedicated 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 environmental effects of hydrogen produced and purchased from an 

off-site or third party supplier are not accounted for in the refinery 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 H2 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 

CO2) consistent with H2

production not included 

Off-Site (3rd party) H2

Production None 

Complete cradle-to-gate LCA 

inventory/profile must be 

generated for H2 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 the on-site hydrogen plant and associated cradleto-gate emissions consistent with production and delivery of that quantity of natural gas 

• Process emissions from the on-site hydrogen plant 

• A full cradle-to-gate LCA inventory/profile for off-site H2 production and delivery 

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

sections) 
 

 52

To simplify the issue of hydrogen accounting, the concept of a hydrogen “pool” has been 

developed. This pool consists of excess hydrogen from the catalytic reformer and hydrogen 

produced on- and off-site via steam methane reforming. 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 Steam Methane Reforming (SMR) 

Hydrogen for refinery usage in the United States is produced predominantly by steam methane 

reforming (SMR) of natural gas and this study assumes both on-site and off-site hydrogen 

production utilize this method. The amount of hydrogen produced at on-site hydrogen plants is 

assumed to be 85% of the installed hydrogen production 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/retrofitted to handle increasingly 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. The SMR stoichiometry for converting hydrocarbons 

(primarily methane) to hydrogen is shown in Equation 1. From the stoichiometry, it can be seen 

that for pure methane and 100% conversion, the theoretical minimum necessary feedstock 

requirements would be 0.0048 kg (231 Btu LHV, 256 Btu HHV) methane per scf of hydrogen. 

 CxH(2x+2) + 2xH2O Æ (3x+1)H2 + xCO2 (1) 

The actual amount of natural gas used as a feedstock 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 processes for every standard cubic foot of hydrogen 

produced and their associated references. Natural gas lower heating value is assumed to be 918 

Btu/ft3

 and higher heating value is assumed to be 1020 Btu/ft3 (API 2004). The average density 

is assumed to be 23.8 ft3 per pound (API 2004). In this study, the hydrogen plant feedstock 

requirement for natural gas is assumed to be 352 Btu HHV/scf H2 (0.006581 kg natural gas per 

scf H2). 

Hydrogen Plant CO2 Process Emissions 

The CO2 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 natural 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 H2) 

Feedstock Input 

(Btu HHV/scf H2) 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 CO2 and hydrogen production rates. 

** The non-hydrocarbons are assumed to contain 0.565 volume % CO2

based on an average natural gas composition from Perry’s Chemical 

Engineers Handbook. 

Based upon the natural gas composition shown in Table 4-26, hydrogen plant process CO2

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 CO2 process emissions are estimated to be 0.01879 kg 

CO2 per scf H2 produced (2.855 kg CO2 per kg of natural gas feed input). Complete combustion 

of natural gas is assumed and thus there are negligible methane process emissions. The use of 

hydrogen process waste gas streams recycled to the hydrogen plant reformer furnaces as a fuel 

gas are assumed to be unaccounted for in the EIA refinery fuels-consumed estimate. 

To bound the above determined process CO2 emissions estimate and determine the absolute 

minimum CO2 emissions, the simplified approach for determining CO2 process emissions was 

also evaluated. This method considers the stoichiometry shown in Equation 1 and determines 

the CO2 production consistent with a given rate of H2 production. Using this method, the 

minimum CO2 process emissions for a hydrogen plant using the above pipeline quality natural 

gas would be 0.0134 kg CO2 per scf H2. 

Hydrogen Plant Energy Usage 

Table 4-27 shows a survey of reported total energy usage (including feedstock energy) for 

hydrogen production from various vendors and the literature. It is important to note that all but 

one of the estimates considers modern pressure swing adsorption (PSA) as the purification 

 

§ A sensitivity analysis was performed on these parameters. 
 

 54

technology. This technology is less energy intensive than the older 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 gas for feedstock and fuel use) for production of hydrogen in this 

study is estimated to be 388 Btu HHV/scf H2. 

Table 4-27. Estimated Energy Consumption for Hydrogen Production 

Estimated Energy 

Usage (Fuel + Feed 

+ Power – Steam) 

in Btu HHV/scf H2

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 natural gas is necessary to estimate the upstream 

emissions associated with the natural gas feedstock input to the refinery hydrogen plant (the 

natural gas input to the refinery fuels consumed tally is discussed in Section 4.2.3.3). The GHG 

life cycle inventory for 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 

Basis/Quantity Emissions (kg) 

CO2 CH4 N2O 

scf H2 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 during catalytic reforming accounts for more than 

60% of refinery hydrogen needs (Aitani 1996). In addition to producing high-octane reformate 

for gasoline blending, catalytic reforming also produces an off-gas that is typically 80-85% 

hydrogen by volume (CEH 2004). Table 4-29 shows 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 barrel (scfb) of feed, on 

average.§ 

Table 4-29. Specific Hydrogen Production from Catalytic Reformer 

Specific Hydrogen 

Production (scf H2 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 the catalytic reformer of 3,419 million standard 

cubic feet per day (MMscfd) of hydrogen production. This corresponds to approximately 49% 

of the total refinery hydrogen requirements being 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 considered to be integral to the catalytic reformer 

operation (Maples 1993). Thus, the hydrogen recycle stream is subtracted from the catalytic 

reformer hydrogen output and the remaining hydrogen from 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 stream 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 H2

Production 

(Consumption) 

(scfb feed) 

Daily H2

Production 

(Consumption) 

(MMscfd) 

Catalytic Reformer 3,419 1,000 3,419 

Reformer Feed Hydrotreating* 3,419 (186) (637) 

Catalytic Reformer—Net Contribution to H2 Pool 814 2,782 

* Hydrogen use for hydrotreating will be discussed in greater detail in subsequent sections 

 

§ A sensitivity analysis was performed on these parameters. 
 

 56

Hydrogen produced from the catalytic reformer must be allocated 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 operate the catalytic reformer and reformer feed 

hydrotreater) must be allocated to the co-products of the operation, gasoline and hydrogen. 

Typical methods for allocation considered are examined below: 

• Historically the catalytic reformer burden has been assigned principally—if not 

entirely—to the gasoline fraction. However, hydrogen usage is now a critical component 

for meeting regulatory requirements regarding sulfur content. 

• If the energetic burden is divided between the reformate and hydrogen based on the 

energetic content of the species, then the reformate (gasoline) bears the lion’s share of the 

energy burden. The value of the hydrogen is not as an energy carrier, but rather as a 

reactant. This distinction in the intrinsic value of hydrogen prevents straight-forward 

comparison to the reformate. 

Alternatively, this study uses “system expansion” to determine the “value” of hydrogen. If the 

catalytic reformer was not sufficient/operational/present to meet the hydrogen needs, hydrogen 

would need to be produced by the next best method—steam methane reforming. Therefore, the 

energetic burden associated with producing hydrogen 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 hydrogen stream from a dedicated hydrogen plant is of higher purity—

generally 97+% hydrogen while hydrogen from a catalytic 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 (Energetics 2007). This corresponds to a daily energy 

consumption for the reformer of 384 Btu/scf H2 net output from the reformer. This is lower than 

the 388 Btu/scf H2 required to produce hydrogen via SMR (from Table 4-27). Therefore, 

reformate—a high-quality gasoline blendstock—and hydrogen are both produced during the 

operation with less energy consumption than would 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 burdened 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 production 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 H2) 

Percent 

Contribution 

Catalytic Reformer 2,782 43.4% 

On-Site H2 Plant 2,400 37.5% 

Off-Site H2 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 for 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 total 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 H2 Plant 87,472 

Off-Site H2 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 does not include emissions associated with fuels consumed at the 

refinery. Those emissions are captured in the refinery fuels combustion emissions 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 

CO2 CH4 N2O 

Catalytic Reformer 0 0 0 

On-Site H2 Plant 

NG feedstock cradle-to-gate 

GHG emissions + CO2

process emissions from H2

production 

51,350,819 74,346 123 

Off-Site H2 Plant 

Complete cradle-to-gate LCA 

inventory/profile for H2

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 not generally tracked for petroleum refineries 

across the United States. For this study, U.S. refinery flare operations and emissions have been 

estimated by taking data from two air quality districts in California—which require refineries to 

report flaring operations—and extrapolating 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 District2 (BA AQMD) and the South Coast Air Quality Management District3

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. These data were extracted from the BA AQMD and 

SCAQMD websites and totaled. The total flare gas 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 operations and extrapolating those values 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 requires 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 CO2 Emissions 

Given that the composition of flared gas is unknown, it is necessary to estimate CO2 combustion 

emissions without an understanding of the composition of the gas. The minimum CO2 emissions 

consistent with flaring would result from the combustion of flare gas composed entirely of 

natural gas (since it has the lowest 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 CO2 emissions from flaring would be 0.308 kg CO2 per barrel of atmospheric 

distillation capacity. This represents the minimum CO2 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) 

CH4 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 estimate for refinery flare emissions if natural 

gas is considered to be the flare gas, as well as the actual (reported) refinery 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. total refinery methane emissions from flaring 

activities. 

Table 4-36. Estimate of GHG Emissions Consistent with Flaring Activities 2006 

Source/Method CH4 Emitted from Flares 

(kg CH4 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 N2O 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 N2O emissions from flaring would be 3.306E-06 kg 

N2O per barrel of atmospheric distillation capacity. 

4.2.7 Vented/Fugitive Emissions 

The primary source of methane emissions from refineries is vented emissions, with smaller 

amounts of unburned CH4 in process heater stack emissions and unburned CH4 in engine 

exhausts and flares(EPA 2007b). Methane emissions from refinery operations have not 

generally been tracked or estimated and very little information is available regarding estimation 

procedures and data for estimates. The Petroleum Industry Guidelines for Reporting Greenhouse 

Gas Emissions (IPIECA et al. 2003) does not consider methane in any of its GHG estimation 

tiers for refining operations (see Appendix 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 shows the EPA estimates of methane emissions 

from petroleum refinery operations for 2005. 

For the purpose of this study, methane emissions associated with asphalt blowing have not been 

included in the refinery methane emissions which are allocated to liquid fuel production. 

Asphalt blowing emissions are one of the primary sources of refinery methane emissions but 

these operations are not attributable to liquid fuels production and thus should be allocated 

exclusively to asphalt production. 

It is important to note that environmental regulations and industry responsible care has increased 

in the interim since 1996 and 1999 when the estimates for process emissions were developed. 

Thus, these values may be inflated for refineries 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 (vented emissions, excluding asphalt blowing, plus 

fugitive emissions). §

4.2.8 Refinery Emissions Profile 

Table 4-38 summarizes the refinery emissions from fuels consumption (direct fuel combustion 

emissions as well as indirect emissions), hydrogen production, flaring, and methane 

venting/fugitives. 

The indirect refinery emissions listed in Table 4-38 include upstream emissions associated with 

purchased power and steam. The emissions associated 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 upstream 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 from Petroleum Refining (EPA 2007c)

Activity/Equipment Emission Factor 

Units 

Activity Factor 

Units Emissions (Bcf/yr) 

Vented Emissions 1.252 

Tanks 20.6 scf CH4/Mbbl 1,951 Mbbl/cd heavy 

crude feed 0.015 

System Blowdowns 137 scf CH4/Mbbl 15,204 Mbbl/cd 

refinery feed 0.760 

Asphalt Blowing 2,555 scf CH4/Mbbl 510 Mbbl/cd 

production 0.477 

Fugitive Emissions 0.086 

Fuel Gas System 439 Mcf 

CH4/refinery/yr 142 Refineries 0.062 

Floating Roof Tanks 587 scf CH4/floating 

roof tank/yr 

767 No. of floating 

roof tanks 0.000 

Wastewater Treating 1.88 scf CH4/Mbbl 15,204 Mbbl/cd 

refinery feed 0.010 

Cooling Towers 2.36 scf CH4/Mbbl 15,204 Mbbl/cd 

refinery feed 0.013 

Combustion Emissions 0.094 

Atmospheric Distillation 3.61 scf CH4/Mbbl 15,479 Mbbl/cd 

refinery feed 0.021 

Vacuum Distillation 3.61 scf CH4/Mbbl 6,966 Mbbl/cd feed 0.009 

Thermal Operations 6.02 scf CH4/Mbbl 2,181 Mbbl/cd feed 0.005 

Catalytic Cracking 5.17 scf CH4/Mbbl 5,239 Mbbl/cd feed 0.010 

Catalytic Reforming 7.22 scf CH4/Mbbl 3,222 Mbbl/cd feed 0.008 

Catalytic Hydrocracking 7.22 scf CH4/Mbbl 1,340 Mbbl/cd feed 0.003 

Hydrorefining 2.17 scf CH4/Mbbl 2,167 Mbbl/cd feed 0.002 

Hydrotreating 6.50 scf CH4/Mbbl 9,941 Mbbl/cd feed 0.023 

Alkylation/Polymerization 12.6 scf CH4/Mbbl 1,111 Mbbl/cd feed 0.005 

Aromatics/Isomeration 1.80 scf CH4/Mbbl 992 Mbbl/cd feed 0.001 

Lube Oil Processing 0.00 scf CH4/Mbbl 185 Mbbl/cd feed 0.000 

Engines 0.006 scf CH4/hp-hr 1,187 MMhp-hr/yr 0.007 

Flares 0.189 scf CH4/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 CO2 CH4 N2O 

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 

H2 Production Emissions** 5,337,947 2,524 57 

CH4 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 H2 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 refinery 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 consumers. 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 CO2E per MMBtu of coal delivered while natural gas 

extraction, processing, and transport emits 9.58 kg CO2E per MMBtu delivered. 

The emissions associated with hydrogen production create a second pool. These pools will be 

allocated to various petroleum refinery products 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 production are allocated to products 

based upon each product’s consumption of resources (hydrocarbon feedstocks, fuels/energy, and 

hydrogen). To do this, the individual unit operations within the refineries 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 refinery emissions and hydrogen production emissions 

pools developed in this section. Additional information on the selection of the allocation 

technique is provided in Appendix F.
63

Figure 4-6. Representation of Allocation of Life Cycle Stage #3 Emissions to Product Cate

Gasoline

Diesel

Jet Fuel

Fuel Oil

Coke

"Light Ends"

"Heavy Ends"

Fraction of Refinery 

Energy Attributable to 

Each Product

Gasoline

Diesel

Jet Fuel

Fuel Oil

Coke

"Light 

Ends"

"Heavy 

Ends"

AB

CD

E

F

G

% of Volumetric Throughput

Process 

Units

Energy 

Usage

Hydrogen 

Consumption

Gasoline

Diesel

Jet Fuel

Fuel Oil

Fraction 

Consumption 

to Each P

Gasoline

Diesel

Jet Fuel

Fuel Oil

Coke

"Light Ends"

"Heavy Ends"

Emissions Attributable to 

Each 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 per calendar day. Barrels per stream day (bpsd) is defined as the 

maximum number of barrels input to a unit operation which can be processed within a 24-hour 

period when running at full capacity under optimal crude and product 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 usual operating conditions. Thus, barrels per 

calendar day is representative of actual operating conditions and barrels per stream day is 

representative of a theoretical maximum capacity. Table 4-39 shows U.S. refineries total unit 

operation capacities in barrels per stream day and barrels per calendar day (where reported) for 

2005 (plant capacities reported as of January 1, 2006). It is assumed that plant capacity reported 

on January 1, 2006, is representative of the capacity 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 defined 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 (oF)

Naphtha 122 - 400 

Kerosene and Light Gas Oils 401 – 650 

Heavy Gas Oils 651 – 1,000 

Residuum > 1,000 

Visbreaking and other thermal cracking capacity were excluded from the thermal 

cracking/coking category because the total visbreaking plus other capacity amounts to less than 

1% of the coking capacity. In addition, visbreaking unit 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 therefore questionable and has been excluded from this life cycle study. 

Aromatics, asphalts, and fuels solvent deasphalting are also excluded and thus are not captured in 

the refinery modeling for liquid fuels production. It is not practical to attempt to estimate 

throughput and energy consumption associated with these downstream operations due to the 

variability in refinery designs, unspecified final 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 operations in barrels per calendar day, as 

indicated in Table 4-39. The actual daily operating capacity for unit operations—as a percent of 

the stream day capacity—varies by operation. The atmospheric distillation 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 process units) input into certain key refinery unit 

operations are collected by EIA. The actual inputs (in barrels per calendar day) into the 

atmospheric distillation column, catalytic cracking units, catalytic hydrocracking units, and 

delayed and fluid coking units are 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 Hydrocracking 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 associated with individual unit operations, it is 

necessary to determine the input to those operations. The actual throughputs/inputs for the 

atmospheric distillation column, catalytic cracking units, catalytic 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 refinery 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)/National Petroleum Refiners Association (NPRA) 

survey of refinery operations and product quality (API 1997) was used to estimate the actual 

inputs to the vacuum distillation, hydrotreating, catalytic reforming, alkylation, and 

isomerization units. The survey details the “percent capacity utilization” for the aforementioned 

units but the API/NPRA survey (API 1997) definition of “percent capacity utilization” is slightly 

different than that of EIA. The API/NPRA survey definition of percent capacity utilization is 

({Actual Unit Daily Charge or Production/Stream Day Capacity} x 100). Hence the capacity 

reduction associated with the stream day to calendar day conversion (optimum to usual), as well 

as the decrease in utilization from the capacity at usual operating 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 utilization rate since crude 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 operation utilization rate. 

In 2005, there was 168,000 bpd of lubricant production (EIA 2008) resulting 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 others 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 Operations’ Energy Consumption 

In order to allocate refinery energy usage and associated emissions, it is first necessary to 

determine the energy requirements for the individual unit operations found in refineries. Energy 

utilization for each of the operations 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 electricity and hydrocarbon fuels, and reports total energy 

requirements after incorporating exported energy and electricity losses. The unit process energy 

requirements used from the report specifically exclude energy associated with hydrogen 

production and consumption. 

The estimated net electricity requirements (based 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 refineries’ electricity is produced on site in combined heat and power 

(CHP) units or other power generation activities. To account for 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 thermal energy is necessary as a 

refinery input. 

Table 4-43 shows the original ranges and averages reported by Energetics including all 

electricity losses and the adjusted values incorporating only those electricity losses associated 

with power generation occurring 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 (desulfurization) to meet 

product quality requirements. Hydrotreating also removes nitrogen, oxygen, halides, and metals 

from petroleum fractions. U.S. refineries have the capacity to hydrotreat a combined volume 

equivalent to approximately 81% of the atmospheric distillation capacity. Hydrocracking—a 

more severe hydrotreating process which simultaneously hydrotreats and breaks down larger 

hydrocarbons— can treat a volume equivalent to approximately 9% of the atmospheric 

distillation capacity. Together, these 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 include electricity generation and transmission losses 

** Specific energy usage is inflated to include electricity generation losses associated with 

power generation occurring at the refinery 

*** Energetics fluid coking category encompasses 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 hydrotreating is a function of the species being 

treated and the sulfur content of the fraction. Generally, for straight-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 hydrogenation of these compounds. Figure 

4-7 shows the increasing hydrogen requirement as the hydrotreated fraction becomes heavier and 

demonstrates the variability in hydrogen requirements 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 consumption 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 complicated by the fact that the total 

required hydrogen is generally higher 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 becomes heavier and the degree of hydrocracking 

increases. Hydrogen consumption for hydrocracking 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 hydrocracking 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 hydrotreating/hydrocracking includes the hydrogen 

chemically consumed as well as excess hydrogen for operation and hydrogen lost as a dissolved 

species in the liquid product. Not all produced hydrogen 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 gas” 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 utilization of the hydrogen 

stream as a fuel gas. 

For this study, a mass balance determines the hydrogen requirements for hydrotreating. The 

quantity of hydrogen produced was detailed in Section 4.2.5 and this hydrogen is then distributed 

to the hydrotreating and hydrocracking operations. 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 H2) 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 requirements, the quantity of hydrogen required for refinery 

operation is estimated for each of the hydrotreating operations. This method balances refinery 

consumption with hydrogen production. Table 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 different product categories: gasoline, diesel, 

kerosene and kerosene-based jet fuel, residual fuel oil, coke, “light 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 category 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 gasoline, as well as gasoline blendstocks produced 

at the refineries (but which was not yet blended to produce finished gasoline). Diesel includes 

all types of distillate fuel oil (with varying sulfur content). Residual fuel oil includes all types 

(with varying sulfur content). Coke includes both catalyst and marketable coke. This table also 
 

 73

shows the portion of each product category that is associated with the liquid fuels of interest: 

conventional gasoline, conventional diesel and kerosene-based jet fuel. When determining the 

contribution of each of the unit operations to the product categories, no differentiation is made 

between these subcategories. For gasoline and kerosene, the subcategory for the fuel of interest 

makes up more than 95% of the category. For diesel, however, conventional diesel makes up 

only 75% of the of the distillate 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 Allocation to Product Categories 

Historical information from 1996 serves as the primary basis for allocation of the contribution of 

various unit operations to the finished liquid fuels product slate. The 1996 API/NPRA refining 

survey took a detailed look at refining operations and product quality for a 4-month time frame 

(API 1997). These data have been adjusted to account 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, becoming 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. The average API gravity for crude 

oil inputs was 31.14 degrees in 1996 and was 30.20 in 2005—a 0.94 degree drop in API gravity 

(indicating heavier crude oil). 

Diesel production has increased since 1996 and the product slate is moving towards lower sulfur 

products. Ultra low sulfur diesel (ULSD) was not produced in 1996 and accounted for less than 

1% of distillate production in 2005. Table 4-50 shows diesel production 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 survey report and presents the 

estimates used in this study for 2005. Data are presented for catalytic cracking, coking, catalytic 

hydrocracking, and hydrotreating operations 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 

1996 

Contribution (%) 

to LowSulfur 

Diesel* 

1996 

Contribution (%) 

to All 

Diesel* 

Estimate 

of 2005 

(%) 

Contribution to 

Diesel 

1996 

Contribution (%) 

to US 

Gasoline*

Estimate 

of 2005 

(%) 

Contribution to 

Gasoline 

1996 

Contribution (%) 

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 Institute/National Petroleum Refiners Association 

Survey of Refining Operation and Product Quality 

* Total U.S. data, excludes California 

** Catalytic cracked gasoline amounts to approximately 60% of the catalytic cracking unit feed 

*** In California, coking contributes 40.5% to the low-sulfur diesel fraction 

Individual Unit Operation Allocations to Product Categories 

The volumetric capacities of the individual unit operations have been assigned to the seven 

product categories based upon the relative contribution of the throughput of that operation to the 

final product category. Table 4-52 summarizes the volumetric throughput allocations to the final 

product fractions. The rationale for the individual unit operations’ capacity assignments to 

product categories is described in greater detail below. 
75

Table 4-52. Summary of Unit Operation Contribution to End Products 

Gasoline Diesel 

Kerosene/ 

KeroseneBased Jet 

Fuel 

Residual 

Fuel Oil Coke Ligh

Atmospheric Distillation Relative to final product slate Vacuum Distillation 

Equal to catalytic cracking throughput contribution for 

Gasoline, Diesel or Kerosene plus the remainder (after fuel 

oil, coke, heavy ends is assigned) ratioed to Gasoline, 

Diesel and Kerosene relative to respective throughput 

contribution of coking units 

Equal to final product slate 

Catalytic Cracking 60% of throughput 25% of diesel produced 5% of kerosene produced All catalyst coke BaDistillate Hydrocracking 75% 10% 15% Gas Oil Hydrocracking 50% 40% 10% Residual Hydrocracking Balance 40% 10% Delayed Coking Fluid Coking 

10% of 

throughput 

45% of 

throughput 

5% of 

throughput 

All marketable 

coke distributed 

based on 

throughput 

Ba

Naphtha Hydrotreating 95% of throughput 5

thro

Reformer Feed Hydrotreating* 95% of throughput* 5

throu

Gasoline Hydrotreating All Heavy Gas Oil Hydrotreating Kerosene/Jet Fuel Hydrotreating All Diesel Fuel Hydrotreating All Other Distillate Hydrotreating Relative to final product slate Residual Fuel Oil Hydrotreating All Other Hydrotreating Balance relative to final product slate Catalytic Reforming* 95% of throughput* 5

throu

Alkylation All Isomerization All Lubricants Sulfur 

* Allocations for reformer feed hydrotreating and catalytic reforming include only energy requirements remaining after assigning energy 

1,850 kbbl/day is catalytic cracker feed hydrotreating and is distributed as in catalytic cracking; 
 

 76

Atmospheric Distillation

Since all refinery products pass through the atmospheric distillation column in the form of the 

initial feedstock, the atmospheric distillation capacity is divided among all seven product 

categories according to that product category’s fraction of the total refinery output (includes 

fuels produced and consumed in the refinery). 

Vacuum Distillation

The vacuum distillation column separates the bottoms from the atmospheric distillation column 

into additional boiling-point cuts for appropriate downstream treating. The primary downstream 

operations used to upgrade the heavy vacuum distillation 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 column throughput is heavy oils destined for the 

catalytic cracking unit. The vacuum distillation column capacity is ratioed to the products from 

the catalytic cracking unit relative to that unit’s contribution to the final product slate. For 

example, based on the 1996 API/NPRA refining survey (API 1997), 60% of the catalytic cracker 

input is slated to go to the gasoline fraction; therefore, 60% of the catalytic cracker throughput is 

slated to go through the vacuum distillation column to the gasoline fraction. The vacuum 

distillation contribution to the diesel and kerosene/jet-fuel fractions is calculated relative to the 

catalytic cracking contribution in the same manner (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—16.7% to gasoline, 75% to diesel, and 8.3% to 

kerosene/jet fuel (see subsequent discussion 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 operation 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 total 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/jet fuel total production is estimated to be 

cracked.§

EIA reports that 239,000 bpd of catalyst coke was produced in 2005. The catalytic cracker is 

assumed to be the sole producer of this catalyst 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 catalytic 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 residual. The severity of the hydrocracking operation, as well as the 

feed quality, determines the product quality/category. The hydrocracking throughput allocations 

to the final products have a high degree of uncertainty. 

Distillate hydrocracking is assumed to produce predominantly gasoline; 75% of distillate 

hydrocracking capacity has been assigned to gasoline, 15% to kerosene/jet fuel, and 10% to 

diesel fuel. 

Gas oil hydrocracking is a more severe (higher pressure and higher hydrogen consumption) 

process than distillate hydrocracking. The throughput capacity for this operation has been 

allocated 50% to gasoline, 40% to diesel, and 10% to kerosene/jet fuel.§

Residual hydrocracking is the most severe of the three types listed. According to the Oil and Gas 

Journal Worldwide Refining Survey (O&GJ 2005) there was 57,000 bpcd of installed 

hydrocracking capacity for lube oil 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 has been allocated to the diesel fraction and 10% has been 

allocated to the kerosene/jet fuel fraction. The remainder (14%) has been allocated to the 

gasoline fraction. 

Coking

The coking operation is divided into two types, delayed and fluid. 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 capacities. In 2005, a total of 596,000 bpd of marketable petroleum 

coke was produced and the production was allocated to the coke fraction (delayed and fluid) in 

the same ratio as their respective installed capacity. The allocation of the remaining capacity 

was performed using information derived from 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 assigned 10% of the coking 

throughput, diesel was assigned 45% (reported yield 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 the catalytic reformer 

energy to be assigned to the liquid products. Note that the allocation detailed here applies only 

 

§ A sensitivity analysis was performed on these parameters. 
 

 78

to any portion of the catalytic reformer energy requirement that is assigned to the reformate after 

energy requirements are distributed to the hydrogen pool. 

In addition to hydrogen, the catalytic 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 attributable to the gasoline fraction and 5% is 

attributable to the light ends (due to decomposition and removal of miscellaneous hydrocarbon 

gases during the reforming operation). 

Hydrotreating

The hydrotreating operations are subdivided into several categories based upon the species being 

hydrotreated. The hydrotreating categories are broken down as follows: naphtha/reformer feed, 

heavy gas oil, kerosene/jet fuel, diesel fuel, other distillate, residual fuel oil, and other. 

Reformer feed hydrotreating capacity has been assigned to the final product slate based on the 

catalytic reformer output assignments. Hence, after 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 hydrotreating capacity has been assigned as 95% to the gasoline 

fraction and 5% to the light ends fraction. 

Heavy gas oil hydrotreating is assumed to be attributed primarily to catalytic 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 allocated to the diesel fraction. 

Kerosene/jet fuel hydrotreating capacity has been assigned exclusively to the kerosene/jet fuel 

final product fraction. 

Diesel fuel hydrotreating capacity has been allocated exclusively to the diesel fuel product 

fraction. 

Other distillate hydrotreating capacity has been allocated to the gasoline and diesel fuel fractions 

based upon the relative production volume of gasoline and diesel, due to a lack of information 

allowing a more definitive classification. 

Residual fuel oil hydrotreating capacity 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 product fractions. Hydrogen is used for lube oil “polishing” and 

according to the Oil and Gas Journal Worldwide Refining Survey (O&GJ 2005) there was 

128,450 bpcd of installed capacity for lube oil polishing. Therefore, 115,605 bpcd (based on an 

assumed 90% utilization rate) has been assigned to the heavy ends product fraction. The 

remainder of "other" hydrotreating capacity has been assigned to gasoline, diesel, and 

kerosene/jet fuel based on their relative production quantities. 

Alkylation

The alkylation operations and the throughput for those operations are assigned exclusively to the 

gasoline fraction. 
 

 79

Isomerization

Isomerization is further categorized into isobutane or isopentane/isohexane isomerization. The 

products of this operation are assumed to contribute 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 operations 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 allocation of refining energy use and hydrogen 

production/consumption has been developed for 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 estimated 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 product 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 the seven product categories by multiplying the 

process input/throughput for each operation by the specific hydrogen consumption and summing. 

Hydrogen requirements for the reformer feed hydrotreating operation are excluded from this total 

because hydrogen used for pretreatment of the reformer feed (recycle stream) is subtracted from 

the reformer output prior to contribution to the hydrogen pool. 

The concept of a refinery hydrogen pool was developed earlier and is described 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 consumption consistent with hydrogen consumption is 

calculated by multiplying the total refinery energy associated with hydrogen from Table 4-32 by 

the fraction of the total hydrogen requirement 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 consumed by refinery operations across all seven 

product categories. The fraction of the total refinery energy that is attributable to the product 

slate is determined by summing the refining process unit energy requirements and the hydrogen 

production energy requirements for each category and dividing by the total energy requirements 

for the entire refinery. 

Note that the refinery energy requirement calculated here is based on estimated unit operation 

throughput and energy usage and only includes those operations modeled. This total is 

approximately 75% of the total energy input calculated from the fuels consumed as reported by 

refiners to EIA. 
80

Figure 4-8. Percent of Volumetric Throughput Allocated to End Products 

0% 10% 20% 30% 40% 50% 60% 70% 80% 

Sulfur

Lubricants

Isomerization

Alkylation

Other Hydrotreating

Residual Fuel Oil Hydrotreating

Other Distillate Hydrotreating

Diesel Fuel Hydrotreating

Kerosene/Jet Fuel Hydrotreating

Heavy Gas Oil Hydrotreating

Gasoline Hydrotreating

Naphtha Hydrotreating

Fluid Coking

Delayed Coking

Residual Hydrocracking

Gas Oil Hydrocracking

Distillate Hydrocracking

Catalytic Cracking

Vacuum Distillation

Atmospheric Distillation

Light Ends Gasoline Kerosene Diesel Residual Fuel Oil Heavy 
 

 81

A refinery performance summary with allocation of refining energy use and hydrogen 

production/consumption has been calculated for the product fractions outlined above. Table 

4-54 summarizes the refinery performance. 

Fuels Combustion and Acquisition Emissions Allocation to Product Fractions 

Fuels-consumed emissions are assigned to the product fractions based upon the fractional energy 

usage required to produce these products. Table 4-54 reports the fraction of total refinery energy 

consumption attributable to the seven product categories. The GHG emissions consistent with 

fuels consumption is then multiplied by the appropriate energy consumption fraction for each 

category. 

Hydrogen Production Emissions Allocation to Product Fractions 

Hydrogen production emissions associated with operations not included in the refinery energy 

and emissions profile have been assigned to the product fractions according to each category’s 

hydrogen consumption fraction. 

Flaring and Methane Venting/Fugitive Emissions Allocation to Product Fractions 

Refinery flaring and methane venting/fugitive emissions 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 product 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 shows the information for the refinery products of interest on a CO2

equivalent basis. 

Table 4-53 provides the CO2, methane and nitrous oxide emissions 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 

CO2 CH4 N2O 

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 
82

Figure 4-9. Life Cycle Stage #3 GHG Emissions for Domestic Refineries - Key Produc

6.45

5.96

3.78

1.20 1.11

0.70

0.23 0.21 0.13

0.90 0.83

0.53

0.08 0.07 

0.89

1.37

0.85

02468

10

Gasoline

Diesel

Jet Fuel

Gasoline

Diesel

Jet Fuel

Gasoline

Diesel

Jet Fuel

Gasoline

Diesel

Jet Fuel

Gasoline

Diesel

Jet Fuel

Gasoline

Diesel

Refinery

Fuels

Combustion

Steam & 

Electricity 

Acquisition

Natural 

Gas & Coal 

Acquisition

RefineryProduced 

Fuels 

Acquisition

Hydrogen 

Production*

Flaring, 

Venting, 

& Fugitiv

GHG Emissions 

(kg CO

2E/MMBtu LHV of fuel refined)

 Carbon Dioxide Methane Nitrous Oxide

* Does not include fuel usage at the refineries (and associated emissions) that is attributable to hydrogen 
83

Table 4-54. Refinery Performance Summary for Product Fractions 

 Properties Gasoline Diesel 

Kerosene 

& 

KeroseneBased Jet 

Fuel 

Residual 

Fuel Oil Coke L

E

H2 Requirement (MMscfd) [Excluding reformer feed hydrotreating] 

2,751 2,414 577 219 63 

Fraction of H2 Consumption Requirement 0.430 0.377 0.090 0.034 0.010 0Refinery Energy Requirement for H2 Production (MMBtu HHV/day) 496,515 435,814 104,213 39,612 11,295 37Estimated Energy Requirement for Refining Unit Operations Modeled (MMBtu HHV/day) [excludes H2 production energy consumption] 

2,378,144 1,077,947 267,077 134,126 293,143 36

Estimated Energy Requirement for Refining Unit Operations Modeled (MMBtu HHV/day) [includes H2 production energy consumption] 

2,874,660 1,513,760 371,290 173,738 304,438 40

Fraction of Refinery Energy Consumed Attributable to Refinery Unit Operations Modeled 

0.47 0.25 0.06 0.03 0.05 0

Total Refinery Energy Usage Attributable to Product Category (MMBtu HHV/day)[Based on total fuels consumed for 2005] 

3,811,449 2,006,952 492,258 230,343 403,625 53

Fraction of Total Refinery Production Attributable to Products (volumetric) 0.45 0.23 0.09 0.04 0.05 0
84

Table 4-55. Life Cycle Stage #3 GHG Emissions for Domestic Refineries by Activity Sub-Ca

 Source Gasoline Diesel 

Kerosene 

& 

Kerosenetype Jet 

Fuel 

Residual 

Fuel Oil Coke L

E

CO2 Emissions (kg/bbl Refined Product) 46.0 50.8 30.5 35.7 42.4 2Refinery Fuels Combustion 31.4 32.6 19.6 23.6 31.1 2Purchased Steam and Electricity 5.66 5.89 3.55 4.26 5.61 Acquisition of Natural Gas & Coal 0.86 0.89 0.54 0.64 0.85 Acquisition of Refinery-Produced Fuels 3.66 3.81 2.29 2.75 3.63 2Hydrogen Production* 4.19 7.27 4.27 4.17 0.89 Flaring, Vented & Fugitive 0.32 0.34 0.20 0.24 0.32 CH4 Emissions (kg/bbl Refined Product) 5.62E-02 6.27E-02 3.76E-02 4.38E-02 5.10E-02 3.5Refinery Fuels Combustion 7.87E-04 8.19E-04 4.93E-04 5.92E-04 7.80E-04 5.1Purchased Steam and Electricity 6.89E-03 7.17E-03 4.32E-03 5.19E-03 6.83E-03 4.5Acquisition of Natural Gas & Coal 1.02E-02 1.06E-02 6.40E-03 7.69E-03 1.01E-02 6.6Acquisition of Refinery-Produced Fuels 2.93E-02 3.05E-02 1.84E-02 2.21E-02 2.91E-02 1.9Hydrogen Production* 6.09E-03 1.06E-02 6.20E-03 6.05E-03 1.30E-03 2.1Flaring, Vented & Fugitive 2.89E-03 3.01E-03 1.81E-03 2.17E-03 2.86E-03 1.8N2O Emissions (kg/bbl Refined Product) 7.45E-04 7.85E-04 4.72E-04 5.64E-04 7.28E-04 4.8Refinery Fuels Combustion 5.62E-04 5.85E-04 3.52E-04 4.23E-04 5.58E-04 3.6Indirect Energy Inputs 7.14E-05 7.43E-05 4.47E-05 5.37E-05 7.08E-05 4.6Acquisition of Purchased Fuels 1.68E-05 1.75E-05 1.05E-05 1.26E-05 1.66E-05 1.1Acquisition of Refinery-Produced Fuels 7.75E-05 8.06E-05 4.85E-05 5.83E-05 7.68E-05 5.0Hydrogen Production* 1.37E-05 2.37E-05 1.39E-05 1.36E-05 2.91E-06 4.8Flaring, Vented & Fugitive 3.47E-06 3.61E-06 2.17E-06 2.61E-06 3.44E-06 2.2
85

 Source Gasoline Diesel 

Kerosene 

& 

Kerosenetype Jet 

Fuel 

Residual 

Fuel Oil Coke L

E

GWP in CO2E (kg/bbl Refined Product) 47.7 52.6 31.6 36.9 43.9 2Refinery Fuels Combustion 31.5 32.8 19.8 23.7 31.3 2Purchased Steam and Electricity 5.86 6.10 3.67 4.41 5.81 Acquisition of Natural Gas & Coal 1.12 1.16 0.70 0.84 1.11 Acquisition of Refinery-Produced Fuels 4.42 4.60 2.77 3.32 4.38 2Hydrogen Production* 4.35 7.55 4.43 4.32 0.93 Flaring, Vented & Fugitive 0.40 0.41 0.25 0.30 0.39 

 * Does not include fuel usage at the refineries (and associated emissions) that is attributable to hydrogen production 

Table 4-56. Life Cycle Stage #3 GHG Emissions for Domestic Refineries by Sub-Categ

 Source Gasoline Diesel 

Kerosene & 

Kerosenetype Jet 

Fuel 

GWP in CO2E (kg CO2E/MMBtu LHV of 

Refined Product) 9.74 9.55 6.04 

Refinery Fuels Combustion 6.45 5.96 3.78 Purchased Steam and Electricity 1.20 1.11 0.70 Acquisition of Natural Gas & Coal 0.228 0.211 0.134 Acquisition of Refinery-Produced Fuels 0.903 0.834 0.529 Hydrogen Production* 0.889 1.369 0.847 Flaring, Vented & Fugitive 0.081 0.075 0.048 

* Does not include fuel usage at the refineries (and associated emissions) that is attributable to 

hydrogen production 
 

 86

4.3 Liquid Fuels Production at Foreign Refineries 

Determining emissions consistent with refining operations for foreign entities is not a trivial 

matter due to the inherent variability in feedstocks and technologies employed, as well as 

different product emphasis and environmental regulations. Information extracted from foreign 

studies of gasoline and diesel production vary widely due to differences in study assumptions, 

system boundaries, and information sources. Three publicly available sources of information for 

gasoline and diesel production emissions are discussed 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 jointly by representatives of EUCAR (the 

European Council for Automotive R&D), CONCAWE (the oil companies’ European 

association for environment, health and safety in refining and distribution) and JRC/IES 

(the Institute for Environment and Sustainability of the EU Commission’s Joint 

Research Centre), assisted by personnel from L-B-Systemtechnik GmbH (LBST) and 

the Institut Français de Pétrole (IFP). The 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 Cycle Data System" (ELCD) of Life Cycle 

Inventory (LCI) data sets (ELCD 2008). Life cycle inventory 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 free-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 cycle inventory is publicly 

available for the largest petroleum refinery in Brazil—REPLAN Refinery (Refinaria de 

Paulínia) located in Sao Paulo Brazil (BNLD 2008). Refinery experts deemed that 

refinery to be a “representative Brazilian refinery” (BNLD 2008). Life cycle inventory 

data is available for gasoline (200 ppm sulfur), diesel (500 ppm sulfur), and kerosene 

(2,000 ppm sulfur) production in 2005, as well as other refinery products. These data 

were used to determine the refining emissions consistent with gasoline, diesel, and 

kerosene production by subtracting the crude oil free-to-customer emissions for the 

2002 Brazilian 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). 

Figure 4-10 shows a comparison of this study’s results for gasoline and diesel refining with that 

of the three aforementioned foreign studies modeling gasoline and diesel production. Figure 

4-10 also shows a comparison of this study’s results for kerosene-based jet fuel with Brazilian 

results for kerosene production. The results are presented in CO2E. 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

Refinery

GHG 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 associated 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 presented 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 CO2 CH4 N2O 

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 refineries 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 jet 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 and 

KeroseneBased Jet 

Fuel 

Imported by 

the U.S.

Pipeline 

Transport 

to Port

Tanker 

Transport

Pipeline 

Transport 

to Border

Conventional 

Gasoline 

Consumption 

in Passenger 

Bulk Vehicle

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 imported 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 operation are the primary GHG 

emission sources. Losses during product transport 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 pipeline 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 are 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 the overall life cycle emissions is minor. 

The energy requirement for transporting liquid fuels via tanker is calculated by multiplying the 

number of barrels of fuel shipped by the distance traveled 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 emissions 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 intensity ranges from 7.4 to 10.9 Btu per barrel-nautical mile of fuel 

transported. The assumed study value for product 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 (m3) 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 operations is essentially 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 CO2 CH4 N2O 

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 shipments of gasoline and gasoline blendstocks in 

2005 totaling 403,950,000 barrels. Gasoline is imported to 89 different 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 gasoline 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 consumption are shown in Table 5-3. 

Specific port-to-port travel distances were estimated for imports from Canada (98% of gasoline 

imports received via waterborne transit) and the Virgin Islands because of their high volume of 

exports to the U.S. Given the complexity involved in determining transit distances for all other 

import shipments, all other imports were estimated 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 and the total foreign transport emissions. 

Table 5-3. GHG Emissions Associated with Transport of Imported Gasoline to 

Domestic Ports 

Emissions (kg/bbl refined) Source CO2 CH4 N2O 

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 from Canada (82% of diesel imports received via waterborne 

transit) and the Virgin Islands and these two sources 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. distillate 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 assumed 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 estimated 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 distances for all other import shipments, all other 

imports were estimated 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 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 CO2 CH4 N2O 

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 Fuel 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 imports 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 pipeline 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 assumed 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 Canada and the Virgin 

Islands) are assumed to have a two week transit time (effectively 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 CO2 CH4 N2O 

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. via 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 transportation 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, Table 2.4, in 2004 natural gas and electricity 

were the primary fuels for effecting pipeline transport. Since natural gas is used primarily for 

fueling natural gas pipeline transport, all crude oil and petroleum product transport 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. Water carriers transporting freight are powered by 

diesel fuel and residual fuel oil (30.5 % diesel fuel and 69.5% residual fuel oil on an energetic 

basis). Medium/heavy trucks were powered primarily (90%) by diesel fuel and all petroleum 

tanker trucks in this study are assumed to be powered exclusively with diesel fuel. 

Table 5-6. Total Petroleum Products Carried 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 breakdown 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 determine a quantity of energy expended for petroleum 

products transport and the fuel type powering the operation for the whole U.S. for 2004. In the 

absence of a better method for allocating transportation energy to petroleum products4

, the total 

energy consumption for transport of petroleum products 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/reports6.htm 
 

 93

products plus natural gas liquids production.§ This transportation energy is assumed to be the 

same for 2005. Results of this energy usage allocation are summarized 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 emissions factors are applied to the 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 transportation. The emissions factors for diesel fuel and 

residual fuel oil take into account combustion of the fuel only. The upstream emissions 

associated with production of these secondary fuels contribute only 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) 

CO2 

(g CO2/

gallon) 

CH4

(g CH4

/gallon) 

N2O 

(g N2O/ 

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 associated 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 CO2 CH4 N2O 

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 estimated. 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 the U.S. EPA eGRID database (EPA 2007a). A 

discussion of the power-related GHG emissions 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 station occur in this stage. 

5.2.1.1 Gasoline Refueling Operations 

Electricity usage at service station to pump liquid fuels from the underground storage tank and 

meter them into vehicles is relatively minor. The electrical consumption for a gasoline 

dispensing unit was calculated based on assumptions 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 the flow rate, the amount of energy consumed by 

the motor for an hour per gallon is found. Dispensing gasoline into vehicles required 0.00125 

kWh per gallon of gasoline dispensed. 

GHG emissions associated with vehicle refueling 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 

CO2 CH4 N2O 

Gasoline Dispenser Operation 0.0388 4.50E-05 5.03E-07 

5.2.1.2 Diesel Refueling Operations 

The electricity needed to effect fuel transfer operations for diesel is calculated the same as for 

gasoline transfer. Hence the electricity requirement for dispensing 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 transfer of jet fuel from the airport 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 transport emissions profile. 
 

 96

5.3 Summary of Life Cycle Stage #4 GHG Emissions Profiles 

Table 5-12 summarizes the emissions profiles associated with transport of gasoline, diesel and jet 

fuel. The foreign transport profile 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 required to deliver each barrel of product (due to 

transport losses detailed in Appendix H) are applied. Emissions for the transport profiles are 

presented as per barrel delivered to U.S. ports/borders for foreign transport and per barrel 

delivered to the airport or refueling station for domestic transport. Refueling emissions are 

presented as per barrel delivered to the vehicle tank. 

Table 5-12. Summary of GHG Emissions Consistent with Transport of 

Gasoline, Diesel and Jet Fuel in 2005 

 CO2 CH4 N2O 

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 maintenance of the vehicle over the useful lifespan is excluded from 

the study boundary. 

6.1 Vehicle Operation 

This LC stage starts when refueling of the vehicle is complete and continues as the fuel is burned 

for the energy it provides. The primary focus of analysis 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 Transportation and Air Quality, Motor Vehicle Emission 

Simulator (MOVES) model (EPA 2008). A conventional 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. Table 6-1 shows the fuel efficiency and vehicle 

use emissions on a per-mile and per-MMBtu LHV-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: 

 CO2 kg/mile 0.365 0.286 

 CH4 kg/mile 2.37E-05 2.99E-07 

 N2O kg/mile 2.43E-05 6.53E-07 

 CO2 kg/MMBtu LHV 75.0 76.6 

 CH4 kg/MMBtu LHV 4.9E-03 8.0E-05 

 N2O kg/MMBtu LHV 5.0E-03 1.7E-04 

 

5

 Differences in vehicle engine efficiency result in different methane and nitrous oxide emissions, however, the 

contribution to the total GWP, on a CO2 equivalent basis, is orders of magnitude smaller than the CO2 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 focus of analysis in this stage is the emissions 

which are created during the combustion process. 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 landing 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 aircraft emissions for both LTO and cruise are utilized in 

this study. The CO2 cruise emissions—like LTO emissions—assume all carbon in the fuel is 

converted to CO2 and CO2 emissions are estimated to be 3.16 kg CO2 per kg of fuel (IPCC 

2006). The cruise emission estimates are considered 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 CH4 emission factor has been generated by the 

IPCC (2006) for flights assuming that the LTO emission factor is 5 kg/TJ (0.005 kg CH4/MMBtu 

LHV) (10% of total VOC factor) and that globally about 10% of the total fuel is consumed 

during LTO cycles, resulting in a fleet averaged CH4 emission factor of 0.5 kg/TJ (0.0005 kg 

CH4/MMBtu LHV). N2O emissions are computed indirectly and the default value is 2 kg/TJ 

LHV (0.002 kg/MMBtu LHV) for flight 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 

CO2 CH4 N2O 

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 with 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 

CO2 CH4 N2O 

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 includes 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 

CO2, CH4, and N2O emission profiles were developed for each life cycle stage associated with 

both U.S. and foreign petroleum feedstock acquisition and transport, 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 output for the individual operations. For example, 

emissions associated with crude oil extraction are reported on a per-barrel-of-crude-oil-extracted 

basis. The following factors must be taken into account when relating the 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 products; (2) the relationship between 

imported and domestically produced fuels; (3) losses occurring during transport of the crude oil 

and the finished product and the necessary increase in feedstock acquisition 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 Transport 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 contribution). 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 energy content (and not all 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 total production is shown in Table 4-54 of Section 4.2.9.5. This 

allocation method results in emissions for each of the products being equivalent on a per-barrelrefined basis (but varying on an energetic basis). 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 calculated using U.S. refining data is assumed to also be applicable 

to foreign refinery operations. 
 

 100

Volumetric Representation of Imported and Domestically-Produced Fuels 

Figure 7-1 shows an overview of the volumetric flows of feedstock and products for U.S. 

refineries and imported and exported conventional 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 diesel fuel and kerosene-based jet fuel. The 

relationship between imported and domestically-produced transportation fuels discussed in 

Appendix A and loss factors developed and discussed in Appendix H were utilized in 

development of these figures. 

Conversion to Energetic Basis 

After the emissions factors for each activity in each LC Stage are combined with the volumetric 

flows associated with each activity, 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 2008 
101

Figure 7-1. Feedstock and Product Volumetric Flows for Consumption of Conventional Gasoline, Conv

Kerosene-Based Jet Fuel in the U.S. in 2005 

Feedstock Acquisitionfor U.S. Refineries- Domestic Crude Oil- Foreign Crude Oil- Other Inputs

Other

Refinery

Products

Exported

Conventiona

Diesel

Exported

Conventiona

Gasoline

Refinery Fuels

340 MMbbl/yr

Crude Oil Extraction 

for Foreign Production

of Gasoline

379 MMbbl/yr*

54 MMbbl/yr*

57 MMbbl/yr

404 MMbbl/yr

65 MMbbl/yr*

69 MMbbl/yr

1,056 MMbbl/yr

545 MMbbl/yr

2,772 MMbbl/yr

Exported

Jet Fuel

1,488 MMbbl/yr

19 MMbbl/yr14 MMbbl/yr73 MMbbl/yr

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

Volume Gain

387 MMbbl/yr

Volume Gain

32 MMbbl/yr

Other Inputs: 365 MMbbl/yrDomestic: 1,876 MMbbl/yrForeign: 3,679 MMbbl/yr

Crude Oil Extraction 

for Foreign Production

of Diesel

Crude Oil Extraction 

for Foreign Production

of Jet Fuel

Foreign Refineries Exporting 

Gasoline to the U.S.

(59 Countries)

Foreign Refineries Exporting 

Diesel to the U.S.

(26 Countries)

Foreign Refineries Exporting 

Kerosene Jet Fuel to the U.S.

(26 Countries)

149

U.S.

Refineries

* Crude oil input to FOREIGN refineries include only the portion of crude oil considered to be contributing to gasoline, diesel 
102

Figure 7-2. Feedstock and Product Requirements Consistent with One Thousand Barrels of Conven

Consumed in the U.S. in 2005 
103

Figure 7-3. Feedstock and Product Requirements Consistent with One Thousand Barrels of Convention

in the U.S. in 2005 

LC Stage #1:

Raw Material 

Acquisition

LC Stage #2:

Raw Material Transport

LC Stage #3:

Liquid Fuels 

Production

LC Stage #4:

Final Product 

Transport and Vehic

Refueling

Domestic Crude Oil 

Extraction

Acquisition of Other 

Inputs

Foreign Crude Oil 

Extraction

Crude Oil Extraction 

for Virgin Island 

Refinery

Crude Oil Extraction 

for Canadian 

Refineries

Crude Oil Extraction 

for all other Foreign 

Refineries

U.S. Refinery Operations

Canada Refinery 

Operations

Virgin Island 

Refinery 

Operations

Foreign Refinery 

Operations 

(24 countries exporting 

diesel to U.S. in 2005)

Transport 

Within U.S., 

Bulk Storage 

and Vehicle 

Refueling

Transport 

from 

Foreign 

Refinery to 

U.S. Port

282.9 bbl

crude oil

554.8 bbl

feedstock

55.0 bbl

crude oil

890.3 bbl

crude oil

18.1 bbl

crude oil

15.1 bbl

crude oil

15.3 bbl

crude oil

18.1 bbl

crude oil

15.1 bbl

crude oil

15.2 bbl

crude oil

19.2 bbl

diesel

16.1 bbl

diesel

16.2 bbl

diesel

948.5 bbl

diesel

51.5 bbl

diesel

1

Losses 

From

Domestic

Transport,

Bulk

Storage,

Refueling

<0.1 bbl

diesel

Losses 

From

Foreign

Transport

<0.1 bbl

diesel

Losses from

Crude Oil Transport

2.5 bbl

crude oil

All crude oil and other refinery feedstock volumes shown (LC Stages #1 & #2) include only the portion of feedstock considered to be contributing to DIESEL production

Volume Gain

58.2 bbl

Volume Gain

3.1 bbl

Transport 

Within 

U.S.

Pipeline 

Transport 

to Foreign 

Port

Mix of Domestic/

Foreign Transport

Transport by 

Tanker 

Pipeline Transport 

to Foreign Port

Pipeline Transport 

to Foreign Port/

Refinery

Transport by 

Tanker (excluding 

U.S. and Canadian)

Transport (Pipeline, Tanker, etc) 

from Point of Extraction to Foreign 

Refinery

Transport 

by Tanker 

(excluding 

portion of 

Canada 

crude oil)
104

Figure 7-4. Feedstock and Product Requirements Consistent with One Thousand Barrels of Kerosen

Consumed 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 

CO2, CH4, and N2O emission profiles were developed for the mix of the domestically-produced 

and imported fuels of interest for 2005. The results from the first four life cycle stages are 

applicable to any source consuming these petroleum-based fuels. Vehicle/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 containing non-petroleum based 

fuels, off-road diesel fuel (>500 ppm sulfur), aviation gasoline or kerosene for other than aircraft 

use. 

Table 7-2 shows the GWP for production and consumption of the three liquid fuels on a perMMBtu-LHV-consumed basis using the global warming potentials for CO2, CH4, and N2O listed 

in Table 1-1. To help demonstrate the contributions each GHG species makes to the total GWP, 

the contribution of CO2, CH4, and N2O (in CO2E) 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 their emissions for the five life 

cycle stages for conventional motor gasoline, conventional 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 

Total 

Well-toWheels 

Conventional Gasoline (kg CO2E/ MMBtu LHV fuel consumed) 

Total 7.32 1.44 9.78 1.09 76.6 96.3 

CO2 4.89 1.41 9.45 1.07 75.0 91.9 

CH4 (CO2E) 2.39 0.0193 0.288 0.0149 0.12 2.84 

N2O (CO2E) 0.0394 0.0084 0.0456 0.0065 1.49 1.59 

Conventional Diesel (kg CO2E/ MMBtu LHV fuel consumed) 

Total 6.64 1.32 9.55 0.88 76.7 95.0 

CO2 4.46 1.30 9.22 0.86 76.6 92.4 

CH4 (CO2E) 2.14 0.0175 0.285 0.0130 0.0020 2.46 

N2O (CO2E) 0.0361 0.0078 0.0424 0.0051 0.0521 0.143 

Kerosene-Based Jet Fuel (kg CO2E/ MMBtu LHV fuel consumed) 

Total 6.76 1.35 6.04 1.00 77.7 92.9 

CO2 4.54 1.32 5.83 0.978 77.1 89.8 

CH4 (CO2E) 2.18 0.0178 0.180 0.0137 0.013 2.40 

N2O (CO2E) 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 

Total 

Well-toWheels 

Petroleum 

Product 

kg CH4/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 

Total 

Well-toWheels 

Petroleum 

Product 

kg N2O/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 basis of one mile traveled in Table 7-5. This 

metric is important since gasoline and diesel-powered vehicles have different fuel efficiencies. 

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

Conventional 

Gasoline 

Conventional 

GHG Diesel 

kg/mile traveled 

CO2 0.447 0.345 

CH4 5.52E-04 3.68E-04 

N2O 2.59E-05 1.80E-06 

GHG, CO2E 0.468 0.355 

Figure 7-5 thru Figure 7-8 graphically portray the individual GHG species and their emissions 

for the five life cycle stages for conventional motor gasoline, conventional diesel, and kerosenebased jet fuel on a per-MMBtu-LHV-consumed basis. 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 global warming potential values based on the 1996 and 

2001 technical reports. 

To allow a more detailed examination of upstream fuels processing and their 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 cycle stages on the total 

emissions. 
108

Figure 7-5. GHG Emissions for Liquid Fuels’ Individual Life Cycle Stages and Complete Well-to-W

7.3 6.6 6.8

1.4 1.3 1.3

9.8 9.5

6.0

1.1 0.9 1.0

76.6 76.7 77.7

0

20406080

100

Gasoline

Diesel

Jet Fuel

Gasoline

Diesel

Jet Fuel

Gasoline

Diesel

Jet Fuel

Gasoline

Diesel

Jet Fuel

Gasoline

Diesel

Jet Fuel

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

GHG Emissions 

(kg CO

2E/MMBtu LHV of fuel consumed)

Carbon Dioxide Methane Nitrous Oxide
109

Figure 7-6. Carbon Dioxide Emissions for Liquid Fuels’ Individual Life Cycle Stages and Complete W

Cycle 

4.9 1.4

9.4

1.1

4.5 1.3

9.2

0.9

4.5 1.3 5.8 1.0

75.0 76.6 77.1

0

20406080

100

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

W

CO

2 Emissions 

(kg CO

2/MMBtu LHV fuel consumed)

Conventional Gasoline Conventional Diesel Kerosene-Based Jet F
110

Figure 7-7. Methane Emissions for Liquid Fuels’ Individual Life Cycle Stages and Complete Well-to-W

0.000.050.100.15

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

Methane Emissions 

(kg CH

4/MMBtu LHV fuel consumed)

Conventional Gasoline Conventional Diesel Kerosene-Based Jet F
111

Figure 7-8. Nitrous Oxide Emissions for Liquid Fuels’ Individual Life Cycle Stages and Complete Well-t

0.0000.0010.0020.0030.0040.0050.006

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

N O Emissions 2

(kg N O/MMBtu LHV fuel consumed) 2

Conventional Gasoline Conventional Diesel Kerosene-Based Jet Fu
112

Figure 7-9. Well-to-Tank GHG Emissions for Liquid Fuels 

7.3

6.6 6.8

1.4 1.3 1.3

9.8 9.5

6.0

1.1 0.9 1.0

19.6

05

101520

Gasoline

Diesel

Jet Fuel

Gasoline

Diesel

Jet Fuel

Gasoline

Diesel

Jet Fuel

Gasoline

Diesel

Jet Fuel

Gasoline

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

GHG Emissions 

(kg CO

2E/MMBtu LHV of fuel delivered)

Carbon Dioxide Methane Nitrous Oxide
113

Figure 7-10. Life Cycle Stage Percent Contributions to Total Life Cycle GHG Emission

Conventional

Gasoline

Conventional

Diesel

Kerosene-Based

Jet Fuel

0%

20%40%60%80%

100%

Percent of WTW GWP

LC Stage #1: Raw Material AcquisitionLC Stage #2: Raw Material TransportLC Stage #3: Liquid Fuels ProductionLC Stage #4: Product Transport and RefuelingLC Stage #5: Vehicle / Aircraft Operation
 

 114

7.2.1 Life Cycle Stage #1 

Life Cycle Stage #1 includes emissions associated with the extraction and post-extraction 

processing of refinery feedstocks for U.S. refineries and for foreign refineries providing imported 

gasoline, conventional diesel and kerosene-based jet fuel. Crude oil mix (conventional and 

synthetic crude oil/blended bitumen) is the primary feedstock of interest. For U.S. refineries, 

inputs of NGL and unfinished oils are also included. The primary sources for feedstock 

acquisition emissions are country-specific crude oil extraction emission profiles (PE 2008) and 

country-specific delivered crude oil mix emission profiles for foreign refineries (as available) 

extracted from GaBi 4 (2007). The PE International and GaBi profiles are 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 distributed to all refinery products on a volumetric 

basis. The relationship between volumetric input 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 methane emissions. Flare operations contribute 

significantly to the extraction CO2 emissions profile. 

7.2.2 Life Cycle Stage #2 

Life Cycle Stage #2 includes transport of feedstocks from the extraction/processing location to a 

refinery—either domestic or foreign. Modeling of this transport component includes (1) foreign 

transport of crude in-country via pipeline to either a port 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 feedstocks and foreign imports via a combination of 

pipeline, waterborne vessel, rail, and truck transport to domestic refineries. 

This life cycle stage accounts for 1-2% of the total life cycle GHG emissions. These emissions 

are primarily CO2 from fuel combustion. 

7.2.3 Life Cycle Stage #3 

Life Cycle Stage #3 includes emissions associated with petroleum refinery operations: 

• Extraction, transport, and production (collectively acquisition) of refinery fuels and 

energy inputs including purchased power and steam, purchased coal and natural gas, and 

fuels produced and subsequently consumed at petroleum refineries 

• Combustion of fuels at petroleum refineries 

• Cradle-to-gate emissions associated with hydrogen production 

• Flaring, venting, and fugitive emissions 

Not all GHG emissions for this life cycle stage are actually occurring at the 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 emissions, 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 allocation used here is based on the relative energy and hydrogen 

usage attributable to the production of each of the products, as determined through process unitlevel analysis. Capacities, volumetric throughput, energy usage, and hydrogen consumption and 

production are estimated for 11 process unit categories. The contribution of each process unit to 

each of the product categories is determined, combined with the above, and the result is the 

fraction of energy and hydrogen usage attributable to each product. Throughput capacities of 

process units are as reported by U.S. refineries for January 1, 2006 (EIA 2008), but a wide range 

of sources are utilized to determine capacity utilization, energy usage, hydrogen usage and 

contribution of process unit operations to end products. Refinery data are aggregate U.S. data 

and the refineries were modeled for steady-state operation. Start-up, shut-down, systemic 

anomalies and perturbations are difficult to quantify and thus excluded 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, differing feedstock qualities, etc. Secondly, there are 

miscellaneous other downstream operations that are not tracked by EIA that contribute to the 

total refinery energy consumption (e.g. Merox process unit, etc.) It is acknowledged that liquid 

fuels will, therefore, bear some burden for these operations. 

Foreign refineries producing petroleum products for export to the U.S. have been assumed to 

have the same refining GHG profile as U.S. refineries. There is a lack of publicly available, 

accurate information for foreign refinery operations that covers the appropriate system boundary 

(i.e. indirect emissions associated 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 product losses associated with transport of liquid 

fuels from the refinery to either the vehicle 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 combination of pipeline, waterborne vessel, rail, and 

truck transport to refueling facilities. 
 

 116

Life Cycle Stage #4 does not include any emissions consistent with blender operations (other 

than bulk storage). Since only conventional gasoline is modeled, blender operations necessary to 

add oxygenates or other fuel additives, or create boutique fuel blends would not be required. 

Life Cycle Stage #4 also includes emissions associated with refueling operations for passenger 

vehicles and aircraft. For gasoline and diesel, the only direct GHG emissions 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 losses. These evaporative losses do not have an 

associated GHG emissions profile. However, they do indirectly 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 requirements are 1 MMBtu 

(LHV) consumed by a vehicle or aircraft. 

Transportation and refueling operations 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 three liquid fuels modeled. As expected, combustion 

emissions generated during the use phase are the primary contributors 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 Transportation and Air Quality, Motor Vehicle Emission 

Simulator (MOVES) model (EPA 2008). A conventional 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 fuel efficiency (i.e., fuel consumed per mile 

traveled) and are therefore only applicable to the applied vehicle class. 

The IPCC methodology for estimating aircraft emissions for both LTO and cruise are utilized in 

this study. The CO2 cruise emissions—like LTO emissions—assume all carbon in the fuel is 

converted to CO2 and CO2 emissions are estimated to be 3.16 kg CO2 per kg of fuel (IPCC 

2006). The cruise emission estimates are considered 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 CH4 emission factor has been generated by the 

IPCC (2006) for flights assuming that the LTO emission factor is 5 kg/TJ (0.005 kg CH4/MMBtu 

LHV) (10% of total VOC factor) and that globally about 10% of the total fuel is consumed 

during LTO cycles, resulting in a fleet averaged CH4 emission factor of 0.5 kg/TJ (0.0005 kg 

CH4/MMBtu LHV). N2O 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 efficiency result in different methane and nitrous oxide emissions, however, the 

contribution to the total GWP, on a CO2 equivalent basis, is orders of magnitude smaller than the CO2 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 cycle 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 extraction profile. LC Stage #2 emissions for 

refinery feedstock transport for U.S. fuel production 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 feedstocks. LC Stage #3 emissions for refinery 

operation are the same for both U.S. and foreign 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 tanker transport). LC Stage #5 emissions will be 

the same for both fuel sources since it is assumed that there is no difference in final fuel quality 

between U.S. and foreign fuel sources.
118

Figure 7-11. GHG Emissions for Liquid Fuels Produced Domestically 

7.5 6.7 7.0

1.5 1.4 1.4

9.8 9.5

6.0

1.0 0.8 0.9

76.6 76.7 77.7

0

20406080

100

Gasoline

Diesel

Jet Fuel

Gasoline

Diesel

Jet Fuel

Gasoline

Diesel

Jet Fuel

Gasoline

Diesel

Jet Fuel

Gasoline

Diesel

Jet Fuel

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

GHG Emissions 

(kg CO

2E/MMBtu LHV of fuel consumed)

Carbon Dioxide Methane Nitrous Oxide
119

Figure 7-12. Well-to-Tank GHG Emissions for Liquid Fuels Produced Domestically 

7.5

6.7 7.0

1.5 1.4 1.4

9.8 9.5

6.0

1.0 0.8 0.9

19.8

05

101520

Gasoline

Diesel

Jet Fuel

Gasoline

Diesel

Jet Fuel

Gasoline

Diesel

Jet Fuel

Gasoline

Diesel

Jet Fuel

Gasoline

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

GHG Emissions 

(kg CO

2E/MMBtu LHV of fuel delivered)

Carbon Dioxide Methane Nitrous Oxide
120

Figure 7-13. Comparison of GHG Emissions for Conventional Gasoline Produced at U.S. Refineries a

Foreign Refineries 

7.5

5.8

1.5

0.8

9.8 9.8

1.0

2.0

19

05

101520

U.S. Imports U.S. Imports U.S. Imports U.S. Imports U.

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

GHG Emissions 

(kg CO

2E/MMBtu LHV of fuel delivered)

Carbon Dioxide Methane Nitrous Oxide
121

Figure 7-14. Comparison of GHG Emissions for Conventional Diesel Fuel Produced at U.S. Refineries 

Foreign Refineries 

6.7

6.2

1.4

0.6

9.5 9.5

0.8

1.4

18

05

101520

U.S. Imports U.S. Imports U.S. Imports U.S. Imports U.

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

GHG Emissions 

(kg CO

2E/MMBtu LHV of fuel delivered)

Carbon Dioxide Methane Nitrous Oxide
122

Figure 7-15. Comparison of GHG Emissions for Kerosene-Based Jet Fuel Produced at U.S. Refineries 

Foreign Refineries 

7.0

4.7

1.4

0.7

6.0 6.0

0.9

1.9

15

05

101520

U.S. Imports U.S. Imports U.S. Imports U.S. Imports U.

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

GHG Emissions 

(kg CO

2E/MMBtu LHV of fuel delivered)

Carbon Dioxide Methane Nitrous 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 fitness 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 profile. To understand and quantify the effects of 

such uncertainty, a data quality assessment is discussed 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 the fuel cycle. While this stage contributes a 

significant portion of the total life cycle GHG profile, the variability 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 fraction of the well-to-tank profile. 

8.1 Life Cycle Stage #1 

LC Stage #1 includes emissions associated with the extraction and post-extraction processing of 

refinery feedstocks for U.S. refineries and for foreign refineries providing imported gasoline, 

conventional diesel and kerosene-based jet fuel. Figure 8-1 thru Figure 8-3 show the results of 

the sensitivity analysis for LC Stage #1 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 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 profiles. 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 crude oil inputs to Canadian refineries in 2005. 

Country-specific crude oil GHG emissions profiles, either for extraction 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 delivered 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-specific crude oil extraction profiles are highly 

dependent on flaring and venting and, while a linear relationship between CO2 emissions and 

flaring is apparent, the U.S. profile is above the CO2 emissions predicted from this relationship. 

Because U.S. data is often more readily available and transparent, the higher U.S. value relative 

to the trend for GHG emissions associated with crude oil extraction 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 extraction technologies, mix of on-
 

 124

shore/off-shore, maturity of fields, etc), all of the foreign extraction profiles would be increased 

by 3.4 kg CO2E/bbl. 

The extraction profiles for all countries are representative of 2002 rather than 2005. Significant 

changes in the flaring and venting rates relative to crude oil production in the countries of 

interest would change the profiles. 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 Figure 8-1 as “Baseline adjustment in line with 

U.S. profile” and “Reduced flaring/venting.” The impact of reduction in flaring and venting has 

the greatest impact on the GHG profile for this life cycle stage, but results in less than 5% 

percent reduction in the well-to-tank profiles and less than 1% percent reduction in the well-towheels profiles. 

While not quantified here, it is important to note that the impact of flaring and venting highlights 

the substantial reliance on country-reported flaring and venting rates, although to a lesser degree 

in countries where multi-national companies operate the crude oil and natural gas production. 

Foreign Average Crude Oil Extraction Profile 

Country-specific crude oil extraction profiles for the countries contributing over 90% of the 

crude oil input to U.S. refineries in 2005 are modeled 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 less than ±2% with these changes. 

Foreign Average Delivered Crude Oil Profile 

Country-specific delivered profiles or extraction profiles were used for foreign refineries 

producing conventional gasoline, conventional diesel, or kerosene-based 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 profiles were not available. For 

imported fuels, the foreign average is used for 9% of the gasoline crude oil mix, 12% of the 

diesel crude oil mix, and 22% of the jet fuel crude oil mix. The sensitivity 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 profile) was found to be 

insignificant. 

8.1.2 Oil Sands/Heavy Oils GHG Emissions Profiles 

Oil sands and other heavy oils and synthetic crude oil are emerging as unconventional feedstocks 

to refineries and the extraction process and subsequent upgrading associated with these oils are 

more energy intensive than traditional crude oil extraction. The specific quantity of Canadian oil 

sands utilized by U.S. refineries in 2005 is available, however, data are limited for other 

countries that may have supplied similar unconventional 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 bitumen and another producing synthetic crude oil 

were used and assumed to be representative of the industry. While these companies are well 

established and represented approximately 33% of the Canadian oil sands bitumen production in 

2005 (AEUB 2006), it is expected that there is uncertainty in this profile of Canadian oil sands. 

The GHG well-to-tank emissions profile for each of the 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 upgrading is a growing piece of Venezuelan oil production. However, 

due to limited availability of information, the extraction emissions profile used does not 

incorporate such activities. The sensitivity analysis shows what the well-to-tank emissions 

profile would be if 25% of the Venezuelan crude oil input to U.S. and foreign refineries were set 

equal to the Canadian oil sands extraction profile (50/50 mix of synthetic crude oil and blended 

bitumen). Increasing Venezuelan crude oil 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 CO2E 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 CO2E 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 CO2E 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 associated with the transport of crude oil and other feedstocks 

from the point of extraction to the refinery that processes the crude oil. This is applicable to both 

crude oil for use in U.S. refineries and for foreign refineries providing imported gasoline, 

conventional diesel, and kerosene-based jet fuel. Figure 8-4 thru Figure 8-6 show the results of 

the sensitivity analysis for LC Stage #2 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 profile for several factors. The baseline 

value is represented by the dotted line. 
 

 127

8.2.1 Waterborne Transport 

Transport of crude oil by tanker from foreign ports to refineries in the U.S., Canada, Virgin 

Islands and South Korea was modeled. EIA volume and receiving port data are available for 

each shipment received by the U.S. and Virgin Islands in 2005. While specific ports of receipt 

were not available for Canada, a similar approach was used for distance traveled calculations. 

For foreign countries where a delivered crude oil profile was not available, any waterborne 

transport associated with shipment of crude oil is embedded in that profile and thus is not 

impacted by the sensitivity analysis. 

Crude Oil Carrier Energy Intensity 

A crude oil carrier energy intensity factor was determined after conducting a survey of crude oil 

vessels. The energy intensity factor will be specific 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 Btu/bbl-nautical mile) in line with the range 

occurring in the survey of tankers conducted as part of this study. The resulting 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 from foreign ports to refineries in the U.S., 

Canada, Virgin Islands and South Korea used estimated port-to-port travel 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-tank GHG emissions profile of minor consequence. 

8.2.2 Pipeline Transport 

All transport from the point of extraction 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 foreign transport is simultaneously varied from 80% to 120%. 

For foreign countries where a delivered crude oil profile was not available, any pipeline 

movements associated with crude oil transport is embedded in that profile and thus is not 

impacted by the sensitivity analysis. 

8.2.3 Crude Oil Loss Factor 

Losses associated with crude oil 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 reported by a European company for 2005 that imports a 

majority of its crude oil (Eni 2006). This loss factor was applied to all crude oil transported. 

The sensitivity analysis shows that varying the crude oil loss factor from 50% to 200% of the 

base value has an insignificant impact on the final well-to-tank emissions profile. Note that 

crude oil losses occur during LC Stage 2 activities, 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 CO2E 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

4.25 Btu / bbl-mile 7.25 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 CO2E 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

4.25 Btu / bbl-mile 7.25 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 CO2E 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

4.25 Btu / bbl-mile 7.25 Btu / bbl-mile

50% of study value 200% of study value

8.3 Life Cycle Stage #3 

Life Cycle Stage #3 includes emissions associated with the following petroleum refinery 

operations: 

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

• Combustion of fuels for use as an energy source at petroleum refineries 

• Cradle-to-gate emissions associated with hydrogen production 

• Flaring, venting and fugitive methane emissions 

Figure 8-7 thru Figure 8-9 at the end of the discussion show the results 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 factors. 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. petroleum 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 and venting at refineries, and energy usage and 

resulting GHG emissions associated with merchant hydrogen production. Sensitivity analysis on 

these factors will generally raise or lower the GHG emissions profile 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 gas consumed at refineries is reported by EIA and 

these data are of high quality. One area of uncertainty however, is still gas composition. The 
 

 130

carbon content and resulting GHG emissions are not specifically known. However, the impact of 

varying the CO2 emissions equal to that from combustion of liquid propane gas to pentanes plus 

is minor. The emissions factors for liquid propane gas and pentanes plus utilized for this 

analysis are 62.3 and 66.9 kg CO2/MMBtu HHV, respectively (API 2004). The still gas study 

value used is 64.2 kg CO2/MMBtu HHV. 

Electricity Profile for Refineries 

The U.S. average mix of electricity sources (coal, nuclear, renewables, etc.) in 2004 was used to 

represent to GHG emissions profile for electricity purchased and used 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 sensitivity analysis varying the electricity profile 

from 90% to 115% of the study value shows 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 range 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 increasing 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. This is due to the system expansion 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 catalytic reformer being greater than for the model 

hydrogen plant (SMR). This results in 6% of the catalytic reformer energy requirement being 

allocated to the reformate and thus to gasoline. 

Off-Site Hydrogen Production 

Merchant hydrogen consumption by U.S. refineries 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 affects the GHG WTT emissions profiles with greater 

variability for diesel (due to the greater hydrogen consumption associated with its production), 

but to a small extent (~0.6% difference). 

On-Site Hydrogen Plant Capacity Utilization 

Hydrogen plant capacity at U.S. refineries is provided by EIA, however the 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 CO2 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% capacity utilization. 

Flaring and Venting/Fugitive Methane Emissions 

Emissions associated with flaring 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 which reporting of such data is required. It was 

assumed that the flared gas is natural gas. Because California generally has more stringent 
 

 131

restrictions on such activities and because combustion emissions from natural gas are expected to 

underpredict GHG emissions related to refinery flaring, a sensitivity analysis has been conducted 

to show the impact of a value 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 extrapolated from 1996 and 1999 EPA studies (EPA 1996; 

EPA 1999) of refinery process unit methane emissions. It is important to note that 

environmental regulations and industry responsible care has increased in the interim since 1996 

and 1999. Thus, these values may be inflated for 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 report process unit capacities for January 1st of each year, 

capacity utilization, unit-specific energy and hydrogen requirements, 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 analysis on these factors will 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 associated products that consume more hydrogen. 

Catalytic Reformer Hydrogen Production 

Hydrogen production by the catalytic 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 average 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 varied 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 complex effect and thus a greater impact. This 

change increases the energy requirements for the catalytic reformer to produce hydrogen to a 

value greater than that for hydrogen production by SMR. Application 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 component, 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 profile shifts, but it is 

less than a 3% change from baseline 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 system. This means that varying the hydrocracker hydrogen 

consumption also varies the hydrotreater hydrogen consumption. The results of varying the 

hydrocracker hydrogen consumption from 80% to 150% of the baseline value for all 

hydrocracking operations are shown. Varying hydrocracker 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 volumetric throughput for the atmospheric distillation 

column, catalytic cracking units, hydrocracking 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 utilization is difficult to predict. 

Hydrotreating Capacity Utilization 

A large volume of intermediate and final products are hydrotreated in refineries 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 utilization 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 Capacity Utilization 

Increasing the vacuum distillation column capacity 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, with even less of an 

impact on the gasoline and jet fuel profiles. 

8.3.2.3 Energy Consumption 

Process unit-specific energy consumption was used 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 (Energetics 2007). This source draws on the reported 

energy requirements of multiple licensed technologies employed by U.S. refineries in 2005. The 

ranges represent different technologies and are not intended to provide a range for the aggregated 

average value for the year 2005. They are, however, used as a guide for this sensitivity analysis. 

Vacuum Distillation Energy Consumption 

The vacuum distillation column energy intensity is varied here in the range 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 associated emissions are allocated to heavier nontransportation fuel products such as lubricants and coke, and less are allocated to gasoline, diesel, 

and jet fuel. 
 

 133

Delayed Coker Energy Consumption 

The delayed coker energy intensity range reported by Energetics is wide (115 MBtu/bbl), 

representing various technologies and severity of operations. In the sensitivity analysis 

presented here, for the range evaluated (115 to 175 MBtu HHV per barrel of throughput versus 

the study value of 147) a minor shift in the emissions profile from lighter to heavier products is 

observed. 

Catalytic Reformer Energy Consumption 

The catalytic reformer energy intensity reported range is wide (130 MBtu/bbl), representing 

various technologies and severity of operations. For the sensitivity 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 not linear due to a shifting of GHG 

emissions between the hydrogen and reformate. 

Hydrotreater Energy Consumption 

EIA provides volumetric throughput capacity data on a variety of hydrotreating and hydrocracker 

subcategories. Energetics (2007) reports average energy intensities for the broad categories of 

hydrotreating and hydrocracking and the average values are applied 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 decrease for gasoline. This shift is expected as 

jet fuel is generally made from a lighter, lower sulfur cut of the crude oil and generally has a less 

stringent sulfur specification, as compared to gasoline and diesel. 

Table 8-1. Adjustments to Hydrotreating Subcategory Energy Consumption 

Utilized in Sensitivity Analysis 

Study Value 

Sensitivity 

Analysis Hydrotreating Subcategory Value 

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 Operations to Product Categories 

An API/NPRA 1996 refinery survey was the primary source used to determine the contribution 

of each of the process units to the product categories (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 consider 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 assignment also impacts the distribution of energy 

usage associated with the vacuum distillation column. These two unit operations combined 

contribute to 27% of the modeled energy consumption. The sensitivity analysis shows that 

simply shifting the contribution to gasoline between 56% and 64% (study value of 60%) results 

in one of the more significant changes to the gasoline and diesel emissions profiles. The overall 

impact on the well-to-tank GHG emissions profiles is around 2%. 

Gas Oil Hydrocracking Contribution to Product Categories 

Allocation of hydrocracking operations between final products is noted as a data gap in this 

analysis. For this sensitivity analysis, the allocation of gas oil hydrocracking, which is the 

greatest subcategory of hydrocracking, was varied between gasoline and diesel. The baseline 

values of 50% gasoline/40% diesel 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 results 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 fuels used and technologies employed at foreign 

refineries. 

All profiles (gasoline, diesel and jet fuel) for foreign refineries are varied from 65% to 130% to 

characterize the influence of this parameter on the well-to-tank GHG emissions profile. 

Variation of this parameter has 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 gasoline 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 CO2E per MMBtu LHV of Conventional Gasoline Consumed 

in the U.S. in 2005

Equal to LPG Equal to pentanes plus

Baseline

Value

375 Btu HHV/ 

scf hydrogen

325 Btu HHV/

scf hydrogen

80% of study value 125% of study value

90% capacity 

utilization

80% capacity

utilization

300% of study flaring 

value

25% of study venting/

fugitive value

800 scf hydrogen/ 

bbl throughput

1,200 scf hydrogen/

bbl throughput

80% of study value 150% of study value

85% capacity

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% capacity

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)

65% of study value 130% of study value

90% of study value 115% 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 CO2E per MMBtu LHV of Conventional Diesel Fuel Consumed 

in the U.S. in 2005

Baseline

Value

Equal to LPG Equal to pentanes plus

375 Btu HHV/ 

scf hydrogen

325 Btu HHV/

scf hydrogen

80% of study value 125% of study value

90% capacity 

utilization

80% capacity

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% capacity

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)

65% of study value 130% of study value

90% of study value 115% 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 CO2E per MMBtu LHV of Kerosene-Based Jet Fuel Consumed 

in the U.S. in 2005

Baseline

Value

Equal to LPG Equal to pentanes plus

375 Btu HHV/ 

scf hydrogen

325 Btu HHV/

scf hydrogen

80% of study value 125% of study value

90% capacity 

utilization

80% capacity

utilization

300% of study flaring 

value

25% of study venting/

fugitive value

800 scf hydrogen/

bbl throughput

1,200 scf hydrogen/ 

bbl throughput

80% of study value 150% 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% capacity

utilization

Adjusted by

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)

65% of study value 130% of study value

90% of study value 115% of study value
 

 138

8.4 Life Cycle Stage #4 

LC Stage #4 consists of activities to transport 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 assumptions are not expected to have a significant 

impact on the overall GHG emissions profiles because 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 baseline value is represented by the dotted line. 

Product Water Carrier Energy Intensity 

The product water carrier energy intensity was varied based on a survey of tankers conducted as 

part of this study for transport of imported gasoline, diesel, and jet fuel. For this sensitivity 

analysis, the petroleum product tanker energy intensity was varied from 7.4 to 10.9 Btu/bblnautical mile (study value of 10 Btu/bbl-nautical mile). The resulting variability in the well-totank GHG emissions profile is minimal for all profiles, 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 determined 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 waterborne travel distances 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 diesel and jet fuel profiles. 

Total Products Transported Domestically 

Based on availability of data on transport modes and volumes of petroleum products transported 

domestically, it was assumed that all petroleum products moved the same distance and by the 

same mix of modes of transportation. 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 transport 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 analysis shows the impact of using 80% of the study 

value to simulate a shift towards 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 value results in a minor shift in 

the gasoline profile, and essentially no change in the diesel and 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 CO2E 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 CO2E 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 CO2E 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 and 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 CO2 emissions value used in this study is the same 

value used by the FAA and EPA to calculate annual 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 for approximately 80% of the total life cycle 

GHG emissions), sensitivity analysis was not conducted on these factors. This limitation should 

instead be managed by ensuring consistent and comparable vehicle use profiles are applied when 

evaluating alternative transportation fuel options. 

8.6 Data Quality and Sensitivity Analysis Summary 

Analysis of the data quality and sensitivity studies on parameters in each life cycle stage show 

that while there are many factors of uncertainty, no single variable shifts 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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Petroleum Refineries to Petroleum Products: 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. Geophys. Res. Lett., 28(9), 1719–1722. 2001. 
 

 148

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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 conventional diesel (<500 ppm sulfur), and finished 

kerosene-type jet fuel for the year 2005. The resulting weighting factors in Table A-2 are used in 

combination with the modeling of domestically-produced and imported finished fuels described 

in Sections 2.0 to 5.0 to develop a composite profile for the transportation 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 transportation 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

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 B - 1

Appendix B 

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

U.S. (Average) Grid Mix 

Certain emissions from electricity generating facilities are tracked by EPA (EPA 2007a) and are 

publically available in the Emissions & Generation Resource Integrated Database (eGRID). 

While this database includes comprehensive coverage of CO2 emissions from these generating 

facilities, it does not address other GHG constituents such as N2O and CH4 in its inventory.8 

The emissions data within e-GRID only includes that attributable to operations and does not 

represent construction or upstream emissions. Therefore, GaBi 4 modeling data were modified 

to generate a profile more inclusive of upstream and construction emissions not represented 

within eGRID. 

A U.S. electric grid mix was generated where the individual electricity source profiles (solar, 

wind, hydro, etc.) were aggregated into a mix consistent with the 2004 U.S. electricity source 

mix. Figure B-1 shows the source mix as a percentage 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 the U.S. electricity mix is shown in Figure B-2. 

The process plan incorporates power inputs derived from the electricity generation mix discussed 

previously and includes 98.2 percent 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 September 2008 following the completion of this analysis. 

eGRID2007 Version 1.0 contains CO2, CH4, and N2O 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. “other fossil generation” (tires, chemicals, batteries, 

etc.) and “unknown/purchased generation” are allocated 100 percent to lignite (surrogate profile) 

and 3) No cradle to gate profile is currently available for “biomass/wood generation”, “solar 

generation”, and “geothermal generation.” The resulting 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 

CO2

Emissions 

(kg/kWh) 

CH4

Emissions 

(kg/kWh) 

N2O 

Emissions 

(kg/kWh) 

2004 U.S. Average 

Electricity Grid Mix 0.739 8.58E-04 9.59E-06 
C - 1

Appendix C 

Cradle-to-Gate GHG Emissions Profile for Fuels Produced in Domestic Refineries 

The cradle-to-gate environmental profile (LC Stages #1-3) for production of refinery products is also the upstreafor the petroleum products that are input to the refinery as a fuel. However, the upstream emissions profile for fuconsumed in the refinery are also part of the LC Stage #3 profile requiring an iterative solution to determine this 

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 Fuels 

Refinery Fuel 

2005 Fuel 

Consumption 

by U.S. 

Refineries 

(bpd) 

Product Category 

for Refinery Fuel 

LPG 11,438 Light Ends Distillate 2,068 Diesel Residual Fuel Oil 6,047 Residual Fuel Oil Still Gas 652,701 Light Ends Petroleum Coke 245,622 Coke Other Products 14,600 Average of All 

Table C-2 shows the preliminary cradle-to-gate profile (LC Stage #1-3) excluding the upstream profile for refineThis profile is on a per-barrel-refined basis does not include loss factors associated with product transport, but doassociated with feedstock transport. 
C - 2

Table C-2. “Cradle-to-Gate” GHG Emissions Profile for Domestic Refineries Excluding Upstrea

Refinery-Produced Fuels 

Emissions Units Gasoline Diesel 

Kerosene 

& 

Kerosenetype Jet 

Fuel 

Residual 

Fuel Oil Coke Lig

En

kg CO2/day 581,279,653 312,441,600 96,975,964 40,730,261 59,063,564 98,47

CO2

kg CO2/bbl refined 74.4 79.0 60.2 64.9 70.7 58

kg CH4/day 3,958,551 2,023,864 803,809 314,617 418,700 834,

CH4

kg CH4/bbl refined 0.51 0.51 0.50 0.50 0.50 0.5

kg N2O/day 11,612 6,020 2,001 831 1,227 2,1

N2O 

kg N2O/bbl refined 0.00149 0.00152 0.00124 0.00132 0.00147 0.00

For example, as a starting point, the upstream profile for still gas is 58.5 kg CO2 per barrel (corresponding to ligh

multiplying this factor by the consumption of still gas at the refinery is 38 million kg CO2 per day and the cradle-

profile should be increased by this amount. An iterative solution to calculate the total cradle-to-gate refinery proresulting profile for each of the fuels is shown in Table C-3. The emissions associated with production of these s

to the product slate according to each product category’s energy consumption. 

Table C-3. GHG Emissions Profile Consistent with Acquisition of Refinery-Produced Fu

Fuel CO2 (kg/day) CH4 (kg/day) N2O (kg/day) 

LPG 696,439 5,886 15 Distillate 171,312 1,122 3 Residual Fuel Oil 409,065 3,165 8 Still Gas 39,740,582 335,879 850 Petroleum Coke 18,267,585 130,326 380 Other Products 1,095,456 7,768 22 Total 60,380,439 484,146 1,278 
 

 D - 1

Appendix D 

Petroleum Industry Guidelines for Reporting Greenhouse Gas 

Emissions 

The Petroleum Industry Guidelines for Reporting Greenhouse Gas Emissions (IPIECA et al. 

2003) outlines various tiers for GHG emissions estimation using data with different levels of 

detailed information—and hence different 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 table refer to detailed calculation procedures 

presented in the American Petroleum Institute’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 

CO2

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 

CH4 Not considered Not considered Not considered 

CO2

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 composition 

based on spot samples -ORestimated directly from 

measured CO and CO2

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 composition 

based on spot samples -ORestimated directly from 

measured CO and CO2

concentrations in exhaust 

(spot samples) and 

air/oxygen flow rate to 

regenerator 

FCC Coke Burn 

CH4 Not considered Not considered Not considered 

CO2

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 

CH4 Not considered Not considered Not considered 

CO2

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) 

CH4 Not considered Not considered 

Not considered (spot check 

on methane content of CO2

vent stream) 

CO2 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 

CH4 Not considered Not considered Not considered 

Process CO2 Not considered Not considered Not considered 

Fugitives CH4 Not considered Not considered Not considered 
 

 E - 1

Appendix E 

Nitrous Oxide Emission Factors 

Table E-1 lists N2O emission factors for the various combustion operations encountered in 

refinery operations. The emission factors were compiled from various sources and reported in 

the American Petroleum Institute (API) Compendium of Greenhouse Gas Emissions 

Methodologies for the 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. N2O Emission Factors for Various Combustion Operations Encountered in 

Refinery Operations (API 2004) 

N2O 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/106 scf 2.8×10-7 tonne/106

 Btu 

(HHV) 

Uncontrolled 2.2 lb/106 scf 9.8×10-7 tonne/106

 Btu 

(HHV) 

Natural Gas Combustion Turbines

Controlled (SCR) 0.03 lb/106 Btu 1.4×10-5 tonne/106

 Btu 

(HHV) 

Uncontrolled 0.003 lb/106 Btu 1.4×10-6 tonne/106

 Btu 

(HHV) 

Stationary Gas-fired IC Engines (without catalyst controls)

4-stroke rich burn 0.001 lb/106 Btu (HHV) 4.5×10-7 tonne/106

 Btu 

(HHV) 

4-stroke lean burn 0.003 lb/106 Btu (HHV) 1.4×10-6 tonne/106

 Btu 

(HHV) 

2-stroke 0.005 lb/106 Btu (HHV) 2.3×10-6 tonne/106

 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/106 Btu 

(HHV) 

Large Bore Diesel Engine (> 600 hp) 0.08 g/L 

3.03×10-7 tonne/gal 

2.2×10-6 tonne/106

 Btu 

(HHV) 
 

 E - 2

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 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 petroleum refining LCA process. It is commonly accepted that gasoline 

production is a more energy-intensive process than diesel production due to the additional 

processing steps required to develop optimal gasoline and boutique blends. For example, while 

all refinery products pass through the atmospheric distillation column, the catalytic reformer, 

alkylation unit and isomerization unit predominantly process gasoline precursors. 

Several allocation methodologies have evolved over time with different allocation mechanisms 

of varying complexity. These allocation methodologies are most broadly broken into economicbased and process-based allocations. 

Economic-based Allocations 

Economic-based allocation techniques assert that emissions from 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 techniques have been developed to allocate 

CO2 emissions to the various products at an oil refinery using economic factors (Babusiaux 

2007). 

There are many inherent problems that arise when considering product 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 (excluding hydrogen considerations), domestic diesel 

selling price has been steadily climbing in the past 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 refining “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 analyses 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 sold 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 during 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-07

Cents

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 performing 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. Thus products that require extensive processing are allocated the 

same level of emissions as streams which require very little processing. Attempts to divide 

refinery level emissions into process unit and associated emissions are extremely difficult to do 

and detailed process information is not readily available. 

It has been suggested by Argonne National Laboratory (ANL) researchers that a simplified 

approach be used where each individual unit process energy use (energy from incoming streams 

and energy provided directly to the process) be divided among the 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 consumption and there is no accounting for hydrogen 

utilization. 

The GREET model developed by ANL divides the 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 products based on unit process operations and the 

associated utilities and emissions of that particular 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 hydrogen utilized at a refinery is 

produced as a by-product of reformer operation (Aitani 1996). Discounting this contribution to 

diesel production (for hydrotreating) biases the results and burdens gasoline with a larger 

emissions profile and artificially lowers the diesel 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 capacity, 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 case) and must be allocated to the benefitting 

distillate fractions (Alireza 2007). 

Hydrogen is used in refineries primarily for desulfurization and hydrocracking processes, with 

waste (impure) hydrogen being burned as a fuel. To meet current sulfur-level requirements for 

fuels, practically all finished diesel and gasoline products must be desulfurized during 

processing. Thus, the utilization of hydrogen must be appropriately allocated to the various 

product species and their precursors. For example, ten times more hydrogen may be needed to 

desulfurize diesel than is necessary to desulfurize naphtha fed to a catalytic reformer to produce 

gasoline (Parkash 2003). 

The integrated and complex nature of modern refineries precludes simplistic determinations of 

energy/utility requirements for any particular unit operation. All allocation mechanisms will be 

controversial and no mechanism is correct. Thermal inefficiencies are not the same for all unit 

operations and thus some units will have lower efficiencies than others. 

Study Allocation Technique 

Allocation of energy (utilities) and hydrogen usage are estimated for the major unit operations 

undertaken for liquid fuels production at U.S. refineries using system expansion to the extent 

possible before allocating unit operation throughput to final liquid fuel fractions. 

Petroleum products output from refineries have been broadly divided into seven different product 

categories: gasoline, diesel, kerosene and kerosene-type jet fuel, residual fuel oil, coke, “light 

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 category is 

composed of asphalt and road oil, lubricants, waxes, and miscellaneous. 

The volumetric capacity of the individual 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 throughput of that operation to the final product category. Rationale 

for each individual unit operation’s capacity assignments to product categories has been 

discussed. 

Fuels-consumed emissions are assigned to the product fractions based upon the fractional energy 

usage required to produce these products. The GHG emissions consistent with fuels 

consumption (minus the quantity attributed to secondary, unrelated production 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 associated with the fuels consumed are allocated 

equivalently for each unit of energy consumed. 

Refinery flaring and methane venting/fugitive emissions 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 regard 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 using hydrogen production via SMR as the next best 

alternative. This results in all energy for operation of the catalytic 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 the reformate (gasoline fraction), then the hydrogen 

is “free.” As a result, the gasoline GHG emissions 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

Reformate

GHG Emissions

 (kg CO2E/MMBtu LHV fuel consumed)

Conventional Gasoline Conventional Diesel Kerosene-Based Jet Fuel
 

 G - 1

Appendix G 

Cradle-to-Gate GHG Emissions Inventory 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 H2. It is assumed that hydrogen compression to elevated pressures 

is performed at the refinery and 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/ft3

 (API 

2004). Average natural gas density is assumed to be 23.8 ft3

 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 H2 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 usage that is attributable to hydrogen production. When the natural 

gas feed requirements are excluded from the above data, the result is a net energy requirement of 

35.6 Btu HHV per scf of hydrogen. For U.S. petroleum refineries it was estimated, as discussed 

in Section 4.2.9.2, that for the portion of electricity assumed to be produced at the petroleum 

refinery, electricity losses must be incorporated. This raises the refinery energy associated with 

on-site hydrogen plants to 36.5 Btu HHV per scf of hydrogen. 

For both merchant and captive hydrogen production, process emissions of CO2 from the 

separation/purification process must be determined. CO2 is produced during the hydrogen 

production process, as shown in the following equation, and subsequently vented to the 

atmosphere during hydrogen purification. Thus, for every four moles of hydrogen produced, one 

mole of CO2 is emitted. 

CxH(2x+2) + 2xH2O Æ (3x+1)H2 + xCO2

Combustion emissions associated with reformer 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 combustion in a boiler/furnace/heater. The N2O 

emissions from the boiler are modeled as uncontrolled since the energy requirements listed in 

Table G-1 do not include selective 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) 

CO2 0.0531 

CH4 1.0E-06 

N2O 9.8E-07 (uncontrolled) 

2.8E-07 (controlled) 

Using the above information and upstream life cycle emissions presented in Section 3.0, the 

following emissions profile was generated for hydrogen production: 

Table G-3. Hydrogen Production Emissions and Sources on the Basis of 1 scf H2

Produced 

(kg) 

NG 

Upstream 

Profile 

H2

Process 

Emissions 

(CO2) 

H2 Plant 

Fuel 

Combustion 

Emissions 

Electricity 

Emissions 

Steam 

Credit Total 

CO2 3.64E-03 1.88E-02 7.43E-03 3.84E-04 -9.85E-03 2.04E-02 

CH4 4.33E-05 0 1.40E-07 4.46E-07 -1.41E-05 2.98E-05 

N2O 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 does not contribute directly to life cycle GHG 

emissions, it contributes indirectly 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 applied at the end of each activity and for all 

activities occurring prior to the loss. For example, losses for all product 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% 0.00019% 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 oil transport include more than volatilization losses and, in the 

absence of better data, a total transport loss was 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 losses 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 and Marketing of Petroleum Liquids) for tanker 

operations (EPA 1995). Table H-3 lists the emissions factors for crude oil 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 transferred 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 reported 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 transport to the U.S. are estimated using EPA AP-42 

emissions factors (Section 5.2 Transportation and Marketing of Petroleum Liquids) for tanker 

operations (EPA 1995). Table H-5 lists the emissions 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 associated 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 service stations were estimated using EPA AP-42 

emissions factors (Section 5.2 Transportation and Marketing of Petroleum Liquids). Table 5.2-7 

of the EPA document outlines evaporative emissions from gasoline service station operations 

(see Table H-7). It is assumed that the underground 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 gasoline 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 derived from a report entitled Methodologies for 

Estimating Air Pollutant Emissions from Transport (Lewis 1997). For diesel, the filling station 

emissions are 0.0551 g/GJ (2.53 x 10-6 bbl/bbl, or 0.0003%) and the vehicle refueling emissions 

are 0.0903 g/GJ (4.14 x 10-6 bbl/bbl, or 0.0004%). The total evaporative losses for this stage are 

0.1454 g/GJ (0.0007%). 

Kerosene-Based Jet Fuel

According to the U.S. Federal Aviation Administration (FAA) Air Quality Handbook, Appendix 

D: Aircraft Emission Methodology, there is currently no information available on calculating 

evaporative-related emissions (e.g., refueling emissions) from commercial aircraft (FAA 1997). 

The FAA Air Quality Handbook notes that these evaporative related emissions are small due to 

the low vapor pressure of the fuel and the quick-connect refueling nozzles. 

In the absence of use-specific emissions factors for aircraft refueling, product losses associated 

with kerosene refueling operations (filling station 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 WTW and WTT results are presented on the basis of lower heating 

values for conventional gasoline, conventional diesel and kerosene-based jet fuel. The energy 

content and densities used for these final results conversions for the 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 refinery fuel on a higher heating value basis (see 

Table I-2). 

Densities of various petroleum refining 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 percent-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/m3 (EPA 2007c) 
 

 J - 1

Appendix J 

Emissions Factors for Various Vehicle Types 

The following emissions are for different vehicle types and are representative 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 - 2

Table J-1. 2005 Fleet Vehicle Emissions for Conventional Gasoline 

Total 

Fuel 

Use 

Vehicle 

Efficiency 

CO2

Emissions 

(per mile) 

CH4

Emissions 

(per mile) 

N2O 

Emissions 

(per mile) 

GHG 

Emissions 

(per mile) 

CO2

Emissions 

CH4

Emissions 

Em

MOVES Vehicle Class Btu 

LHV/ 

mile 

mpg kg CO2/ mile kg CH4/ mile kg N2O/ mile kg CO2E/ mile kg CO2/ MMBtu LHV kg CH4/ MMBtu LHV k

M

11. Motorcycle 4,905 23.7 0.368 4.88E-05 5.44E-06 0.371 75.0 9.95E-03 121. Passenger Car 4,866 23.9 0.365 2.37E-05 2.43E-05 0.373 75.0 4.88E-03 431. Passenger Truck 6,785 17.2 0.509 3.95E-05 5.50E-05 0.526 75.0 5.83E-03 832. Light Commercial Truck 7,436 15.7 0.558 4.56E-05 5.82E-05 0.576 75.0 6.13E-03 742. Transit Bus 15,543 7.5 1.166 2.31E-05 3.03E-05 1.176 75.0 1.49E-03 143. School Bus 12,663 9.2 0.950 1.94E-04 9.05E-05 0.982 75.0 1.53E-02 751. Refuse Truck 13,509 8.6 1.014 1.80E-05 1.89E-05 1.020 75.0 1.33E-03 152. Single-Unit Short-Haul Truck 58,321 2.0 4.376 6.04E-05 4.18E-05 4.390 75.0 1.03E-03 753. Single-Unit Long-Haul Truck 38,958 3.0 2.923 2.53E-05 3.08E-05 2.933 75.0 6.50E-04 754. Motor Home 16,014 7.3 1.202 1.02E-04 3.75E-05 1.215 75.0 6.34E-03 261. Combination Short-Haul Truck 15,501 7.5 1.163 1.21E-05 1.44E-05 1.168 75.0 7.79E-04 962. Combination Long-Haul Truck 15,374 7.6 1.154 9.76E-06 1.38E-05 1.158 75.0 6.35E-04 8

Table J-2. 2005 Fleet Vehicle Emissions for Conventional Diesel 

Total 

Fuel 

Use 

Vehicle 

Efficiency 

CO2

Emissions 

(per mile) 

CH4

Emissions 

(per mile) 

N2O 

Emissions 

(per mile) 

GHG 

Emissions 

(per mile) 

CO2

Emissions 

CH4

Emissions 

Em

MOVES Vehicle Class Btu 

LHV/ 

mile 

mpg kg CO2/ mile kg CH4/ mile kg N2O/ mile kg CO2E/ mile kg CO2/ MMBtu LHV kg CH4/ MMBtu LHV k

M

21. Passenger Car 3,737 35.1 0.286 2.99E-07 6.53E-07 0.286 76.6 8.00E-05 131. Passenger Truck 5,884 22.3 0.451 7.61E-07 1.27E-06 0.451 76.6 1.29E-04 232. Light Commercial Truck 6,385 20.6 0.489 9.67E-07 1.57E-06 0.490 76.6 1.51E-04 241. IntercityBus 15,383 8.5 1.178 2.37E-06 2.40E-06 1.179 76.6 1.54E-04 142. Transit Bus 13,108 10.0 1.004 2.34E-06 2.81E-06 1.005 76.6 1.78E-04 243. School Bus 10,062 13.0 0.771 2.33E-06 4.13E-06 0.772 76.6 2.31E-04 451. Refuse Truck 10,890 12.1 0.834 2.32E-06 2.54E-06 0.835 76.6 2.13E-04 252. Single-Unit Short-Haul Truck 42,541 3.1 3.259 1.97E-06 2.51E-06 3.259 76.6 4.63E-05 553. Single-Unit Long-Haul Truck 28,933 4.5 2.216 2.04E-06 2.48E-06 2.217 76.6 7.07E-05 854. Motor Home 13,851 9.5 1.061 2.27E-06 2.60E-06 1.062 76.6 1.64E-04 161. Combination Short-Haul Truck 23,211 5.7 1.778 1.90E-06 2.08E-06 1.779 76.6 8.19E-05 862. Combination Long-Haul Truck 23,947 5.5 1.834 1.86E-06 2.02E-06 1.835 76.6 7.77E-05 8
 

 K - 1

Appendix K 

LTO Emission Factors and Emissions for Various Aircraft 

Emissions for aircraft operation are examined for 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 CO2

(11) CH4(7) N2O(9)

LTO Fuel 

Consumption 

(kg/LTO) 

CO2

(11) CH4(7) N2O(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 0.00274 

Large 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 CO2

(11) CH4(7) N2O(9)

LTO Fuel 

Consumption 

(kg/LTO) 

CO2

(11) CH4(7) N2O(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 0.00407 

Regional Jets 

Yak-42M 2,880 0.25 0.1 910 77.2 0.0067 0.00268 

Jets (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 average measured data. 

Emissions factors apply to LTO (Landing and Take off) only. 

(2) Engine types for each aircraft were selected on a consistent basis of the engine with the most LTOs. 

This approach, for some engine types, may underestimate (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 cycles 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 assumed to be 0.05% (as in the 1996 IPCC Guidelines). 

(11) CO2 for each aircraft based on 3.16 kg CO2 produced for each kg fuel used, then rounded to the 

nearest 10 kg. 

(12) Information regarding the uncertainties associated with this data can be found in: Lister and 

Norman, 2003; ICAO, 1993. 
 

 L - 1

Appendix L 

Study GHG Results Presented in Alternate Units 

The following tables and figures present GHG emissions on a kg-per-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 1.1). 

Table L-1. GHG Emissions for Liquid Fuels Production (kg CO2E/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 

Total 

Well-toWheels 

Conventional Gasoline (kg CO2E/barrel consumed) 

Total 35.8 7.0 47.9 5.3 375 471 

CO2 23.9 6.9 46.2 5.2 367 449 

CH4 (CO2E) 11.7 0.1 1.4 0.1 0.6 13.9 

N2O (CO2E) 0.2 0.0 0.2 0.0 7.3 7.8 

Conventional Diesel (kg CO2E/barrel consumed) 

Total 36.6 7.3 52.6 4.8 422 524 

CO2 24.6 7.1 50.8 4.7 422 509 

CH4 (CO2E) 11.8 0.1 1.6 0.1 0.0 13.6 

N2O (CO2E) 0.2 0.0 0.2 0.0 0.3 0.8 

Kerosene-Based Jet Fuel (kg CO2E/barrel consumed) 

Total 35.3 7.0 31.6 5.2 407 486 

CO2 23.8 6.9 30.5 5.1 403 470 

CH4 (CO2E) 11.4 0.1 0.9 0.1 0.1 12.6 

N2O (CO2E) 0.2 0.0 0.1 0.0 3.3 3.7 
 

 L - 2

Table L-2. GHG Emissions for Liquid Fuels Production (kg CO2E/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 

Total 

Well-toWheels 

Conventional Gasoline (kg CO2E/GJ LHV fuel consumed) 

Total 6.94 1.36 9.27 1.03 72.6 91.21 

CO2 4.63 1.34 8.96 1.01 71.1 87.0 

CH4 (CO2E) 2.27 0.02 0.27 0.01 0.11 2.68 

N2O (CO2E) 0.04 0.008 0.04 0.006 1.41 1.51 

Conventional Diesel (kg CO2E/GJ LHV fuel consumed) 

Total 6.29 1.25 9.05 0.83 72.7 90.13 

CO2 4.23 1.23 8.74 0.82 72.6 87.6 

CH4 (CO2E) 2.03 0.02 0.27 0.01 0.00 2.33 

N2O (CO2E) 0.03 0.007 0.04 0.005 0.05 0.14 

Kerosene-Based Jet Fuel (kg CO2E/GJ LHV fuel consumed) 

Total 6.41 1.28 5.72 0.95 73.6 88.00 

CO2 4.30 1.25 5.53 0.93 73.1 85.1 

CH4 (CO2E) 2.07 0.02 0.17 0.01 0.01 2.28 

N2O (CO2E) 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 CO2E/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 

Total 

Well-toWheels 

Conventional Gasoline (kg CO2E/MMBtu LHV fuel consumed) 

Total 6.94 1.44 9.74 1.09 76.7 95.9 

CO2 4.89 1.41 9.45 1.07 75.0 91.9 

CH4 (CO2E) 2.01 0.0162 0.242 0.0125 0.10 2.38 

N2O (CO2E) 0.0410 0.0087 0.0474 0.0067 1.55 1.65 

Conventional Diesel (kg CO2E/MMBtu LHV fuel consumed) 

Total 6.30 1.32 9.51 0.88 76.7 94.6 

CO2 4.46 1.30 9.22 0.86 76.6 92.4 

CH4 (CO2E) 1.80 0.0147 0.239 0.0109 0.0017 2.07 

N2O (CO2E) 0.0376 0.0081 0.0442 0.0053 0.0541 0.149 

Kerosene-Based Jet Fuel (kg CO2E/MMBtu LHV fuel consumed) 

Total 6.41 1.35 6.01 1.00 77.8 92.5 

CO2 4.54 1.32 5.83 0.978 77.1 89.8 

CH4 (CO2E) 1.83 0.0147 0.151 0.0115 0.011 2.02 

N2O (CO2E) 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 CO2E/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 

Total 

Well-toWheels 

Conventional Gasoline (kg CO2E/MMBtu LHV fuel consumed) 

Total 7.13 1.44 9.76 1.09 76.6 96.0 

CO2 4.89 1.41 9.45 1.07 75.0 91.9 

CH4 (CO2E) 2.20 0.0177 0.265 0.0137 0.11 2.61 

N2O (CO2E) 0.0391 0.0083 0.0453 0.0064 1.47 1.58 

Conventional Diesel (kg CO2E/MMBtu LHV fuel consumed) 

Total 6.47 1.32 9.53 0.88 76.7 94.8 

CO2 4.46 1.30 9.22 0.86 76.6 92.4 

CH4 (CO2E) 1.97 0.0161 0.262 0.0120 0.0018 2.26 

N2O (CO2E) 0.0359 0.0077 0.0422 0.0050 0.0517 0.143 

Kerosene-Based Jet Fuel (kg CO2E/MMBtu LHV fuel consumed) 

Total 6.58 1.35 6.02 1.00 77.7 92.7 

CO2 4.54 1.32 5.83 0.978 77.1 89.8 

CH4 (CO2E) 2.00 0.0163 0.165 0.0126 0.012 2.21 

N2O (CO2E) 0.0363 0.0079 0.0267 0.0059 0.625 0.701 
L - 4

Figure L-1. GHG Emissions for Liquid Fuels Production (kg CO2E/barrel consumed) 

35.8 36.6 35.3

7.0 7.3 7.0

47.9 52.6

31.6

5.3 4.8 5.2

375.0

422.5

406.6

0

50

100150200250300350400450500550

Gasoline

Diesel

Jet Fuel

Gasoline

Diesel

Jet Fuel

Gasoline

Diesel

Jet Fuel

Gasoline

Diesel

Jet Fuel

Gasoline

Diesel

Jet Fuel

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

GHG Emissions 

(kg CO

2E/Barrel of fuel consumed)

Carbon Dioxide Methane Nitrous Oxide
L - 5

Figure L-2. GHG Emissions for Liquid Fuels Production (kg CO2E/GJ LHV fuel consum

6.9 6.3 6.4

1.4 1.3 1.3

9.3 9.1

5.7

1.0 0.8 0.9

72.7 73.7 72.6

0

20406080

100

Gasoline

Diesel

Jet Fuel

Gasoline

Diesel

Jet Fuel

Gasoline

Diesel

Jet Fuel

Gasoline

Diesel

Jet Fuel

Gasoline

Diesel

Jet Fuel

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

GHG Emissions 

(kg CO

2E/GJ LHV of fuel consumed)

Carbon Dioxide Methane Nitrous Oxide
L - 6

Figure L-3. GHG Emissions for Liquid Fuels Production Based on 1996 IPCC GWP (kg CO2E/MMBtu LHV 

6.9 6.3 6.4

1.4 1.3 1.3

9.7 9.5

6.0

1.1 0.9 1.0

76.7 76.7 77.8

0

20406080

100

Gasoline

Diesel

Jet Fuel

Gasoline

Diesel

Jet Fuel

Gasoline

Diesel

Jet Fuel

Gasoline

Diesel

Jet Fuel

Gasoline

Diesel

Jet Fuel

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

GHG Emissions 

(kg CO

2E/MMBtu LHV of fuel consumed)

Carbon Dioxide Methane Nitrous Oxide
L - 7

Figure L-4. GHG Emissions for Liquid Fuels Production Based on 2001 IPCC GWP (kg CO2E/MMBtu LHV 

7.1 6.5 6.6

1.4 1.3 1.3

9.8 9.5

6.0

1.1 0.9 1.0

9

76.6 76.7 77.7

0

20406080

100

Gasoline

Diesel

Jet Fuel

Gasoline

Diesel

Jet Fuel

Gasoline

Diesel

Jet Fuel

Gasoline

Diesel

Jet Fuel

Gasoline

Diesel

Jet Fuel

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

GHG Emissions 

(kg CO

2E/MMBtu LHV of fuel consumed)

Carbon Dioxide Methane Nitrous Oxide
 

 L - 8

This page intentionally left blank. 
 

 

Attachment 1 

Documentation Associated with Profiles Extracted from GaBi 4 
Documentation 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 production 

1.1 Introduction 

The production of crude oil was modelled as a combined natural gas and crude oil production. In most cases beside crude oil, different parts of natural gas and NGL (natural gas 

liquids) are produced as by-products. For the different by-products allocation by lower 

calorific 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 

data set includes all relevant parts of the upstream industry. Production may take place 

onshore and offshore. Both are taken into account proportionate 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 by 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 steel hull with 3 or more legs, semisubmersible rigs, which float at all times on pontoons, or drill ships are used. The oil rig 

contains machinery and fulfils the role of superstructure 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 removed 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 the surface between drill string and the inner 

surface of the well due to the high pressure generated by piston pumps. At the rig the drilling fluid is separated from drill cuttings and circulated. The drilling fluid also serves to cool 

the drill bit, to seal the drill hole against seepage and to prevent wall cave-ins. Depending 

on geology and technology water-based, oil-based and synthetic-based fluids are used. 

They are mixed with barium sulphate and bentonite to increase the density of the fluid as 

well as further additives. After finishing the drilling 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 infrastructure for preparing and transportation, produced oil and gas is flared. Small amounts of gas are 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 brought 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 mixture 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 or when the pressure was already lower at 

the beginning. For further exploitation it is necessary to use pumps or to reinject a part of 

the separated natural gas to maintain a high pressure in the deposit. Advanced measures 

raise the production are the reinjection of produced water or sea water and the reinjection 

of steam to increase the viscosity or surface tension of the oil-gas mixture. 

The produced oil-gas mixture is a composite of crude 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 separated 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 are often still flared, sometimes also 

vented, due to missing preparation and transportation opportunities. Hydrogen sulphide 

contained in the natural gas in different concentrations, has to be removed before transportation via pipelines due to the high corrosive impact. The hydrogen sulphide is recovered from the natural gas by the Claus process 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 and used 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 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 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 principal modelling approach. 

2.1 System boundaries and functional unit 

Functional unit: The functional unit is 1 bbl of crude 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]. Amount of Bentonite and Bariumsulphate 

and water for drilling mud is taken from [6]. The material 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 composition 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 flaring 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, natural gas, natural gas liquids) is 90% of 

mass and energy and 95% of the environmental relevance (expert judgement). 

2.4 Data selection and combination principles 

The data sources for the complete product system are sufficiently consistent: The data on 

the energy carrier supply chain is based on statistics 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 some of the emission data and product 

properties are sourced from different years representativeness for the reference year is 

considered good. 

2.6 Data treatment and extrapolations principles 

In terms of the country/region specific crude oil production, missing data of certain parameters has been used from countries with a comparable technology1

. Data measured at 

a group of representative production facilities have 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 produced. 

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 electricity 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 for 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 natural 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 during 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 product 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 Agency, 2004

[2] Pennwell: The international petroleum Encyclopaedia 1997

[3] Shell Nigeria 2004 People and the environment Annual Report, 2005 

[4] IEA: Natural Gas Information 2002, International Energy Agency, 2004 

[5] EIA: International Energy Annual 2003; Energy Information 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 Foundation, 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 Drilling, Production and work over, 

2nd Edition, Golf Professional Publishing, 2002 

[10] Gordon, D. et al. Underbalanced Drilling with casing SPE, SPE Drilling & completion 

2005 

[11] Ohio Department of Health: Materials used in drilling 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 testing, 2000 

[14] BP: Das Buch zum Erdöl (The book on Crude oil), 1989 

[15] OGP, International Association of Oil and Gas Producers: Environmental performance in the E&P industry 2003, 2004 

[16] US EPA: Compilation of Air pollutant emission factors, AP 42, Volume I: Stationary 

point and area sources, Fifth edition, United States Protection Agency, Office of 

air quality planning and standards, 1995-2000. 

[17] US EPA: Profile of the Oil and Gas Extraction Industry, 2nd Section, 2000 

[18] PSI: Management of produced water on offshore oil installations, Policy Studies Institute, 2005 
Documentation 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 substances in produced water on the 

marine environment, International Association of Oil and Gas Producers, 2005 

[21] Leahey, G et at.: Theoretical and observational assessments of flare efficiencies, 

Journal of Air & Waste Management Association, Volume 51, December 2001 

[22] Johnson, M.R. et al.: Efficiency measurements of flares in a cross flow, Dep. Of Mechanical Engineering, University of Alberta, Combustion Canada conference, 

1999 

[23] EIA: C.5 Gross Heat Content of Dry Natural Gas Production, 1980-2004, Energy 

Information Administration, 2005

[24] World Bank: Global gas Flaring reduction initiative, 2004 
Documentation 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 production 

1.1 Introduction 

The production of crude oil was modelled as a combined natural gas and crude oil production. In most cases beside crude oil, different parts of natural gas and NGL (natural gas 

liquids) are produced as by-products. For the different by-products allocation by lower 

calorific 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 

data set includes all relevant parts of the upstream industry. Production may take place 

onshore and offshore. Both are taken into account proportionate 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 by 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 steel hull with 3 or more legs, semisubmersible rigs, which float at all times on pontoons, or drill ships are used. The oil rig 

contains machinery and fulfils the role of superstructure 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 removed 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 the surface between drill string and the inner 

surface of the well due to the high pressure generated by piston pumps. At the rig the drilling fluid is separated from drill cuttings and circulated. The drilling fluid also serves to cool 

the drill bit, to seal the drill hole against seepage and to prevent wall cave-ins. Depending 

on geology and technology water-based, oil-based and synthetic-based fluids are used. 

They are mixed with barium sulphate and bentonite to increase the density of the fluid as 

well as further additives. After finishing the drilling 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 infrastructure for preparing and transportation, produced oil and gas is flared. Small amounts of gas are 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 brought 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 mixture 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 or when the pressure was already lower at 

the beginning. For further exploitation it is necessary to use pumps or to reinject a part of 

the separated natural gas to maintain a high pressure in the deposit. Advanced measures 

raise the production are the reinjection of produced water or sea water and the reinjection 

of steam to increase the viscosity or surface tension of the oil-gas mixture. 

The produced oil-gas mixture is a composite of crude 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 separated 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 are often still flared, sometimes also 

vented, due to missing preparation and transportation opportunities. Hydrogen sulphide 

contained in the natural gas in different concentrations, has to be removed before transportation via pipelines due to the high corrosive impact. The hydrogen sulphide is recovered from the natural gas by the Claus process 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 and used 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 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 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 principal modelling approach. 

2.1 System boundaries and functional unit 

Functional unit: The functional unit is 1 bbl of crude 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]. Amount 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 gas 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 considered. 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, natural gas, natural gas liquids) is 90% of 

mass and energy and 95% of the environmental relevance (expert judgement). 

2.4 Data selection and combination principles 

The data sources for the complete product system are sufficiently consistent: The data on 

the energy carrier supply chain is based on statistics 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 some of the emission data and product 

properties are sourced from different years representativeness for the reference year is 

considered good. 

2.6 Data treatment and extrapolations principles 

In terms of the country/region specific crude oil production, missing data of certain parameters has been used from countries with a comparable technology1

. Data measured at 

a group of representative production facilities have 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 produced. 

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 electricity 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 region 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 natural 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 during 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 product 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 Energy Agency, 2004 

[2] IEA: Oil information 2002, International Energy Agency, 2004 

[3] Pennwell: The international petroleum Encyclopaedia 1997

[4] Shell Nigeria 2004 People and the environment Annual Report, 2005 

[5] EIA: C.5 Gross Heat Content of Dry Natural Gas Production, 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 Information 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 Foundation, 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 Drilling, Production and work over, 

2nd Edition, Golf Professional Publishing, 2002 

[16] Gordon, D. et al. Underbalanced Drilling with casing SPE, SPE Drilling & completion 

2005 

[17] Ohio Department of Health: Materials used in drilling 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 testing, 2000 

[20] BP: Das Buch zum Erdöl (The book on Crude oil), 1989 

[21] OGP, International Association of Oil and Gas Producers: Environmental performance in the E&P industry 2003 
Documentation Crude oil production 2002 

Oil production in AngolaAngola 8 / 8 05/08/2008

[22] US EPA: Compilation of Air pollutant emission factors, AP 42, Volume I: Stationary 

point and area sources, Fifth edition, United States Protection Agency, Office of 

air quality planning and standards, 1995-2000. 

[23] US EPA: Profile of the Oil and Gas Extraction Industry, 2nd Section, 2000 

[24] PSI: Management of produced water on offshore oil installations, 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 substances in produced water on the 

marine environment, International Association of Oil and Gas Producers, 2005 

[27] Leahey, G et at.: Theoretical and observational assessments of flare efficiencies, 

Journal of Air & Waste Management Association, Volume 51, December 2001 

[28] Johnson, M.R. et al.: Efficiency measurements of flares in a cross flow, Dep. Of Mechanical Engineering, University of Alberta, Combustion Canada conference, 

1999 
Documentation 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 production 

1.1 Introduction 

The production of crude oil was modelled as a combined natural gas and crude oil production. In most cases beside crude oil, different parts of natural gas and NGL (natural gas 

liquids) are produced as by-products. For the different by-products allocation by lower 

calorific 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 

data set includes all relevant parts of the upstream industry. Production may take place 

onshore and offshore. Both are taken into account proportionate 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 by 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 steel hull with 3 or more legs, semisubmersible rigs, which float at all times on pontoons, or drill ships are used. The oil rig 

contains machinery and fulfils the role of superstructure 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 removed 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 the surface between drill string and the inner 

surface of the well due to the high pressure generated by piston pumps. At the rig the drilling fluid is separated from drill cuttings and circulated. The drilling fluid also serves to cool 

the drill bit, to seal the drill hole against seepage and to prevent wall cave-ins. Depending 

on geology and technology water-based, oil-based and synthetic-based fluids are used. 

They are mixed with barium sulphate and bentonite to increase the density of the fluid as 

well as further additives. After finishing the drilling 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 infrastructure for preparing and transportation, produced oil and gas is flared. Small amounts of gas are 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 brought 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 mixture 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 or when the pressure was already lower at 

the beginning. For further exploitation it is necessary to use pumps or to reinject a part of 

the separated natural gas to maintain a high pressure in the deposit. Advanced measures 

raise the production are the reinjection of produced water or sea water and the reinjection 

of steam to increase the viscosity or surface tension of the oil-gas mixture. 

The produced oil-gas mixture is a composite of crude 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 separated 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 are often still flared, sometimes also 

vented, due to missing preparation and transportation opportunities. Hydrogen sulphide 

contained in the natural gas in different concentrations, has to be removed before transportation via pipelines due to the high corrosive impact. The hydrogen sulphide is recovered from the natural gas by the Claus process 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 and used 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 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 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 principal modelling approach. 

2.1 System boundaries and functional unit 

Functional unit: The functional unit is 1 bbl of crude 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]. Amount 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 gas 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 flaring 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, natural gas, natural gas liquids) is 90% of 

mass and energy and 95% of the environmental relevance (expert judgement). 

2.4 Data selection and combination principles 

The data sources for the complete product system are sufficiently consistent: The data on 

the energy carrier supply chain is based on statistics 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 some of the emission data and product 

properties are sourced from different years representativeness for the reference year is 

considered good. 

2.6 Data treatment and extrapolations principles 

In terms of the country/region specific crude oil production, missing data of certain parameters has been used from countries with a comparable technology1

. Data measured at 

a group of representative production facilities have 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 produced. Note that all values are given for 

unallocated joint production of Natural gas, NGL and 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 electricity 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 calculations 

Mechanical energy demand 412.71 Btu/lb HC [5] and own 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 natural 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 during 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 product 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 Energy Agency, 2004 

[2] IEA: Oil information 2002, International Energy Agency, 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 facilities, 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/sustainable2003/zzz_lhn.html&FC3

=/myen/html/iwgen/society_environment/environment/sustainable2003/sd03_protectthee

nvironment_1008.html, 2004 

[10] Shell Nigeria 2004 People and the environment Annual Report,2005

[11] Nederlandse Aardolie Maatschappij (NAM): Bron van energie, 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, 1980-2003, 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, 2003 
Documentation 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 Foundation, 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 Drilling, Production and work over, 

2nd Edition, Golf Professional Publishing, 2002 

[25] Gordon, D. et al. Underbalanced Drilling with casing SPE, SPE Drilling & completion 

2005 

[26] Ohio Department of Health: Materials used in drilling 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 testing, 2000 

[29] Uniongas, http://www.uniongas.com/aboutus/aboutng/composition.asp,2006 

[30] OGP, International Association of Oil and Gas Producers: Environmental performance in the E&P industry 2003 

[31] US EPA: Compilation of Air pollutant emission factors, AP 42, Volume I: Stationary 

point and area sources, Fifth edition, United States Protection Agency, Office of 

air quality planning and standards, 1995-2000. 

[32] US EPA: Profile of the Oil and Gas Extraction Industry, 2nd Section, 2000 

[33] PSI: Management of produced water on offshore oil installations, 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 substances in produced water on the 

marine environment, International Association of Oil and Gas Producers, 2005 

[36] Leahey, G et at.: Theoretical and observational assessments of flare efficiencies, 

Journal of Air & Waste Management Association, Volume 51, December 2001 

[37] Johnson, M.R. et al.: Efficiency measurements of flares in a cross flow, Dep. Of Mechanical Engineering, University of Alberta, Combustion Canada conference, 

1999 
Documentation 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 production 

1.1 Introduction 

The production of crude oil was modelled as a combined natural gas and crude oil production. In most cases beside crude oil, different parts of natural gas and NGL (natural gas 

liquids) are produced as by-products. For the different by-products allocation by lower 

calorific 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 

data set includes all relevant parts of the upstream industry. Production may take place 

onshore and offshore. Both are taken into account proportionate 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 by 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 steel hull with 3 or more legs, semisubmersible rigs, which float at all times on pontoons, or drill ships are used. The oil rig 

contains machinery and fulfils the role of superstructure 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 removed 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 the surface between drill string and the inner 

surface of the well due to the high pressure generated by piston pumps. At the rig the drilling fluid is separated from drill cuttings and circulated. The drilling fluid also serves to cool 

the drill bit, to seal the drill hole against seepage and to prevent wall cave-ins. Depending 

on geology and technology water-based, oil-based and synthetic-based fluids are used. 

They are mixed with barium sulphate and bentonite to increase the density of the fluid as 

well as further additives. After finishing the drilling 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 infrastructure for preparing and transportation, produced oil and gas is flared. Small amounts of gas are 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 brought 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 mixture 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 or when the pressure was already lower at 

the beginning. For further exploitation it is necessary to use pumps or to reinject a part of 

the separated natural gas to maintain a high pressure in the deposit. Advanced measures 

raise the production are the reinjection of produced water or sea water and the reinjection 

of steam to increase the viscosity or surface tension of the oil-gas mixture. 

The produced oil-gas mixture is a composite of crude 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 separated 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 are often still flared, sometimes also 

vented, due to missing preparation and transportation opportunities. Hydrogen sulphide 

contained in the natural gas in different concentrations, has to be removed before transportation via pipelines due to the high corrosive impact. The hydrogen sulphide is recovered from the natural gas by the Claus process 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 and used 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 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 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 principal modelling approach. 

2.1 System boundaries and functional unit 

Functional unit: The functional unit is 1 bbl of crude 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]. Amount 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 gas composition is [19]. The energy demand for production is given in section 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 [4],[25],[26]. Solid wastes and waste water are considered. The referring data is sourced from [4], [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 Ecuador 4 / 8 05/08/2008 

2.3 Data completeness 

The coverage for the exploration data (crude oil, natural gas, natural gas liquids) is 90% of 

mass and energy and 95% of the environmental relevance (expert judgement). 

2.4 Data selection and combination principles 

The data sources for the complete product system are sufficiently consistent: The data on 

the energy carrier supply chain is based on statistics 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 some of the emission data and product 

properties are sourced from different years representativeness for the reference year is 

considered good. 

2.6 Data treatment and extrapolations principles 

In terms of the country/region specific crude oil production, missing data of certain parameters has been used from countries with a comparable technology1

. Data measured at 

a group of representative production facilities have 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 produced. 

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 electricity 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 Latin 

America [4] and own calulations 

Mechanical energy demand 206.36 Btu/lb HC 

Value for Region Latin 

America [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 natural 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 during 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 product 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 Energy Agency, 2004 

[2] IEA: Oil information 2002, International Energy Agency, 2004 

[3] Pennwell: The international petroleum Encyclopedia 1997

[4] OGP, International Association of Oil and Gas Producers: 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, 1980-2003, 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 Information 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 Foundation, 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 Drilling, Production and work over, 

2nd Edition, Golf Professional Publishing, 2002 

[15] Gordon, D. et al. Underbalanced Drilling with casing SPE, SPE Drilling & completion 

2005 

[16] Ohio Department of Health: Materials used in drilling 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 testing, 2000 

[19] EIA: C.5 Gross Heat Content of Dry Natural Gas Production, 1980-2004, 2005 

[20] US EPA: Compilation of Air pollutant emission factors, AP 42, Volume I: Stationary 

point and area sources, Fifth edition, United States 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 Industry, 2nd Section, 2000 

[22] PSI: Management of produced water on offshore oil installations, 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 substances in produced water on the 

marine environment, International Association of Oil and Gas Producers, 2005 

[25] Leahey, G et at.: Theoretical and observational assessments of flare efficiencies, 

Journal of Air & Waste Management Association, Volume 51, December 2001 

[26] Johnson, M.R. et al.: Efficiency measurements of flares in a cross flow, Dep. Of Mechanical Engineering, University of Alberta, Combustion Canada conference, 

1999 
Documentation 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 production 

1.1 Introduction 

The production of crude oil was modelled as a combined natural gas and crude oil production. In most cases beside crude oil, different parts of natural gas and NGL (natural gas 

liquids) are produced as by-products. For the different by-products allocation by lower 

calorific 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 

data set includes all relevant parts of the upstream industry. Production may take place 

onshore and offshore. Both are taken into account proportionate 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 by 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 steel hull with 3 or more legs, semisubmersible rigs, which float at all times on pontoons, or drill ships are used. The oil rig 

contains machinery and fulfils the role of superstructure 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 removed 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 the surface between drill string and the inner 

surface of the well due to the high pressure generated by piston pumps. At the rig the drilling fluid is separated from drill cuttings and circulated. The drilling fluid also serves to cool 

the drill bit, to seal the drill hole against seepage and to prevent wall cave-ins. Depending 

on geology and technology water-based, oil-based and synthetic-based fluids are used. 

They are mixed with barium sulphate and bentonite to increase the density of the fluid as 

well as further additives. After finishing the drilling 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 infrastructure for preparing and transportation, produced oil and gas is flared. Small amounts of gas are 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 brought 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 mixture 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 or when the pressure was already lower at 

the beginning. For further exploitation it is necessary to use pumps or to reinject a part of 

the separated natural gas to maintain a high pressure in the deposit. Advanced measures 

raise the production are the reinjection of produced water or sea water and the reinjection 

of steam to increase the viscosity or surface tension of the oil-gas mixture. 

The produced oil-gas mixture is a composite of crude 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 separated 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 are often still flared, sometimes also 

vented, due to missing preparation and transportation opportunities. Hydrogen sulphide 

contained in the natural gas in different concentrations, has to be removed before transportation via pipelines due to the high corrosive impact. The hydrogen sulphide is recovered from the natural gas by the Claus process 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 and used 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 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 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 principal modelling approach. 

2.1 System boundaries and functional unit 

Functional unit: The functional unit is 1 bbl of crude 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]. Amount 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 gas 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 flaring region specific flare amounts and 

emissions are included, see section 3.3 and [4], [28], [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, natural gas, natural gas liquids) is 90% of 

mass and energy and 95% of the environmental relevance (expert judgement). 

2.4 Data selection and combination principles 

The data sources for the complete product system are sufficiently consistent: The data on 

the energy carrier supply chain is based on statistics 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 some of the emission data and product 

properties are sourced from different years representativeness for the reference year is 

considered good. 

2.6 Data treatment and extrapolations principles 

In terms of the country/region specific crude oil production, missing data of certain parameters has been used from countries with a comparable technology1

. Data measured at 

a group of representative production facilities have 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 produced. 

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 electricity 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 middle 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 natural 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 during 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 product 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 Energy Agency, 2004 

[2] IEA: Oil information 2002, International Energy Agency, 2004 

[3] Pennwell: The international petroleum Encyclopaedia 1997

[4] OGP, International Association of Oil and Gas Producers: 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&FC2=/myen/html/iwgen/society_environment/environment/sustainable2003/zzz_lhn.html&FC3

=/myen/html/iwgen/society_environment/environment/sustainable2003/sd03_protectthee

nvironment_1008.html, 2004 

[7] Shell Nigeria 2004 People and the environment Annual Report, 2005

[8] Nederlandse Aardolie Maatschappij (NAM): Bron van energie, 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 Information 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 Foundation, 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 Drilling, Production and work over, 

2nd Edition, Golf Professional Publishing, 2002 

[19] Gordon, D. et al. Underbalanced Drilling with casing SPE, SPE Drilling & completion 

2005 
Documentation Crude oil production 2002 

Oil production in Iraq 8 / 8 05/08/2008 

[20] Ohio Department of Health: Materials used in drilling 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 testing, 2000 

[23] US EPA: Compilation of Air pollutant emission factors, AP 42, Volume I: Stationary 

point and area sources, Fifth edition, United States Protection Agency, Office of 

air quality planning and standards, 1995-2000. 

[24] US EPA: Profile of the Oil and Gas Extraction Industry, 2nd Section, 2000 

[25] PSI: Management of produced water on offshore oil installations, 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 substances in produced water on the 

marine environment, International Association of Oil and Gas Producers, 2005 

[28] Leahey, G et at.: Theoretical and observational assessments of flare efficiencies, 

Journal of Air & Waste Management Association, Volume 51, December 2001 

[29] Johnson, M.R. et al.: Efficiency measurements of flares in a cross flow, Dep. Of Mechanical Engineering, University of Alberta, Combustion Canada conference, 

1999 

[30] EIA: C.5 Gross Heat Content of Dry Natural Gas Production, 1980-2004, 2005 
Documentation 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 production 

1.1 Introduction 

The production of crude oil was modelled as a combined natural gas and crude oil production. In most cases beside crude oil, different parts of natural gas and NGL (natural gas 

liquids) are produced as by-products. For the different by-products allocation by lower 

calorific 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 

data set includes all relevant parts of the upstream industry. Production may take place 

onshore and offshore. Both are taken into account proportionate 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 by 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 steel hull with 3 or more legs, semisubmersible rigs, which float at all times on pontoons, or drill ships are used. The oil rig 

contains machinery and fulfils the role of superstructure 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 removed 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 the surface between drill string and the inner 

surface of the well due to the high pressure generated by piston pumps. At the rig the drilling fluid is separated from drill cuttings and circulated. The drilling fluid also serves to cool 

the drill bit, to seal the drill hole against seepage and to prevent wall cave-ins. Depending 

on geology and technology water-based, oil-based and synthetic-based fluids are used. 

They are mixed with barium sulphate and bentonite to increase the density of the fluid as 

well as further additives. After finishing the drilling 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 infrastructure for preparing and transportation, produced oil and gas is flared. Small amounts of gas are 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 brought 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 mixture 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 or when the pressure was already lower at 

the beginning. For further exploitation it is necessary to use pumps or to reinject a part of 

the separated natural gas to maintain a high pressure in the deposit. Advanced measures 

raise the production are the reinjection of produced water or sea water and the reinjection 

of steam to increase the viscosity or surface tension of the oil-gas mixture. 

The produced oil-gas mixture is a composite of crude 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 separated 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 are often still flared, sometimes also 

vented, due to missing preparation and transportation opportunities. Hydrogen sulphide 

contained in the natural gas in different concentrations, has to be removed before transportation via pipelines due to the high corrosive impact. The hydrogen sulphide is recovered from the natural gas by the Claus process 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 and used 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 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 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 principal modelling approach. 

2.1 System boundaries and functional unit 

Functional unit: The functional unit is 1 bbl of crude 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 demand for drilling is taken from [22]. For 

venting of natural gas the averaged national natural 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 sourced 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 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 Kuwait 4 / 8 05/08/2008 

2.3 Data completeness 

The coverage for the exploration data (crude oil, natural gas, natural gas liquids) is 90% of 

mass and energy and 95% of the environmental relevance (expert judgement). 

2.4 Data selection and combination principles 

The data sources for the complete product system are sufficiently consistent: The data on 

the energy carrier supply chain is based on statistics 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 some of the emission data and product 

properties are sourced from different years representativeness for the reference year is 

considered good. 

2.6 Data treatment and extrapolations principles 

In terms of the country/region specific crude oil production, missing data of certain parameters has been used from countries with a comparable technology1

. Data measured at 

a group of representative production facilities have 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 produced. 

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 electricity 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 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 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 natural 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 during 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 product 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 Agency, 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&FC2=/myen/html/iwgen/society_environment/environment/sustainable2003/zzz_lhn.html&FC3

=/myen/html/iwgen/society_environment/environment/sustainable2003/sd03_protectthee

nvironment_1008.html, 2004 

[6] Shell Nigeria 2004 People and the environment Annual Report, 2005

[7] Nederlandse Aardolie Maatschappij (NAM): Bron van energie, 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, 1980-2003, 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 Information Administration, 2004 

[16] Da Prat, G.: Well Testing management , SPE Foundation, 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 Drilling, Production and work over, 

2nd Edition, Golf Professional Publishing, 2002 

[19] Gordon, D. et al. Underbalanced Drilling with casing SPE, SPE Drilling & completion 

2005 

[20] Ohio Department of Health: Materials used in drilling and construction of wells, 1999 
Documentation 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 testing, 2000 

[23] BP: Das Buch zum Erdöl (The book on Crude oil), 1989 

[24] OGP, International Association of Oil and Gas Producers: Environmental performance in the E&P industry 2003, 2004 

[25] US EPA: Compilation of Air pollutant emission factors, AP 42, Volume I: Stationary 

point and area sources, Fifth edition, United States Protection Agency, Office of 

air quality planning and standards, 1995-2000. 

[26] US EPA: Profile of the Oil and Gas Extraction Industry, 2nd Section, 2000 

[27] PSI: Management of produced water on offshore oil installations, 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 substances in produced water on the 

marine environment, International Association of Oil and Gas Producers, 2005 

[30] Leahey, G et at.: Theoretical and observational assessments of flare efficiencies, 

Journal of Air & Waste Management Association, Volume 51, December 2001 

[31] Johnson, M.R. et al.: Efficiency measurements of flares in a cross flow, Dep. Of Mechanical Engineering, University of Alberta, Combustion Canada conference, 

1999 

[32] EIA: C.2 of Dry Natural Gas Production, 1980-2004, 2005

[33] IEA: Natural Gas Information 2002, International Energy Agency, 2004 
Documentation 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 production 

1.1 Introduction 

The production of crude oil was modelled as a combined natural gas and crude oil production. In most cases beside crude oil, different parts of natural gas and NGL (natural gas 

liquids) are produced as by-products. For the different by-products allocation by lower 

calorific 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 

data set includes all relevant parts of the upstream industry. Production may take place 

onshore and offshore. Both are taken into account proportionate 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 by 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 steel hull with 3 or more legs, semisubmersible rigs, which float at all times on pontoons, or drill ships are used. The oil rig 

contains machinery and fulfils the role of superstructure 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 removed 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 the surface between drill string and the inner 

surface of the well due to the high pressure generated by piston pumps. At the rig the drilling fluid is separated from drill cuttings and circulated. The drilling fluid also serves to cool 

the drill bit, to seal the drill hole against seepage and to prevent wall cave-ins. Depending 

on geology and technology water-based, oil-based and synthetic-based fluids are used. 

They are mixed with barium sulphate and bentonite to increase the density of the fluid as 

well as further additives. After finishing the drilling 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 infrastructure for preparing and transportation, produced oil and gas is flared. Small amounts of gas are 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 brought 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 mixture 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 or when the pressure was already lower at 

the beginning. For further exploitation it is necessary to use pumps or to reinject a part of 

the separated natural gas to maintain a high pressure in the deposit. Advanced measures 

raise the production are the reinjection of produced water or sea water and the reinjection 

of steam to increase the viscosity or surface tension of the oil-gas mixture. 

The produced oil-gas mixture is a composite of crude 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 separated 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 are often still flared, sometimes also 

vented, due to missing preparation and transportation opportunities. Hydrogen sulphide 

contained in the natural gas in different concentrations, has to be removed before transportation via pipelines due to the high corrosive impact. The hydrogen sulphide is recovered from the natural gas by the Claus process 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 and used 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 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 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 principal modelling approach. 

2.1 System boundaries and functional unit 

Functional unit: The functional unit is 1 bbl of crude 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]. Amount 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 gas composition is considered [24], [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 flaring region specific flare emissions 

are included see section 3.3 and [4],[30],[31]. Solid 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, natural gas, natural gas liquids) is 90% of 

mass and energy and 95% of the environmental relevance (expert judgement). 

2.4 Data selection and combination principles 

The data sources for the complete product system are sufficiently consistent: The data on 

the energy carrier supply chain is based on statistics 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 some of the emission data and product 

properties are sourced from different years representativeness for the reference year is 

considered good. 

2.6 Data treatment and extrapolations principles 

In terms of the country/region specific crude oil production, missing data of certain parameters has been used from countries with a comparable technology1

. Data measured at 

a group of representative production facilities have 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 produced. Note that all values are given for 

unallocated joint production of Natural gas, NGL and 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 electricity 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 natural 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 during 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 product 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 Energy Agency, 2004

[3] Pennwell: The international petroleum Encyclopedia 1997

[4] OGP, International Association of Oil and Gas Producers: 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&FC2=/myen/html/iwgen/society_environment/environment/sustainable2003/zzz_lhn.html&FC3

=/myen/html/iwgen/society_environment/environment/sustainable2003/sd03_protectthee

nvironment_1008.html, 2004 

[7] Shell Nigeria 2004 People and the environment Annual Report, 2005

[8] Nederlandse Aardolie Maatschappij (NAM): Bron van energie, 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, 1980-2003, 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 Foundation, 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 Drilling, Production and work over, 

2nd Edition, Golf Professional Publishing, 2002 
Documentation Crude oil production 2002 

Oil production in Mexico 8 / 8 05/08/2008

[20] Gordon, D. et al. Underbalanced Drilling with casing SPE, SPE Drilling & completion 

2005 

[21] Ohio Department of Health: Materials used in drilling 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 testing, 2000 

[24] EIA: C.5 Gross Heat Content of Dry Natural Gas Production, 1980-2004, 2005 

[25] US EPA: Compilation of Air pollutant emission factors, AP 42, Volume I: Stationary 

point and area sources, Fifth edition, United States Protection Agency, Office of 

air quality planning and standards, 1995-2000. 

[26] US EPA: Profile of the Oil and Gas Extraction Industry, 2nd Section, 2000 

[27] PSI: Management of produced water on offshore oil installations, 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 substances in produced water on th 

marine environment, International Association of Oil and Gas Producers, 2005 

[30] Leahey, G et at.: Theoretical and observational assessments of flare efficiencies, 

Journal of Air & Waste Management Association, Volume 51, December 2001 

[31] Johnson, M.R. et al.: Efficiency measurements of flares in a cross flow, Dep. Of Mechanical Engineering, University of Alberta, Combustion Canada conference, 

1999 

[32] California Energy Commission: Natural gas composition and Quality, 2005 

[33] IEA: Oil Information 2002, International Energy Agency, 2004

[34] EIA: International Energy Annual 2003; Energy Information Administration, 2004 
Documentation 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 production 

1.1 Introduction 

The production of crude oil was modelled as a combined natural gas and crude oil production. In most cases beside crude oil, different parts of natural gas and NGL (natural gas 

liquids) are produced as by-products. For the different by-products allocation by lower 

calorific 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 

data set includes all relevant parts of the upstream industry. Production may take place 

onshore and offshore. Both are taken into account proportionate 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 by 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 steel hull with 3 or more legs, semisubmersible rigs, which float at all times on pontoons, or drill ships are used. The oil rig 

contains machinery and fulfils the role of superstructure 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 removed 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 the surface between drill string and the inner 

surface of the well due to the high pressure generated by piston pumps. At the rig the drilling fluid is separated from drill cuttings and circulated. The drilling fluid also serves to cool 

the drill bit, to seal the drill hole against seepage and to prevent wall cave-ins. Depending 

on geology and technology water-based, oil-based and synthetic-based fluids are used. 

They are mixed with barium sulphate and bentonite to increase the density of the fluid as 

well as further additives. After finishing the drilling 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 infrastructure for preparing and transportation, produced oil and gas is flared. Small amounts of gas are 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 brought 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 mixture 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 or when the pressure was already lower at 

the beginning. For further exploitation it is necessary to use pumps or to reinject a part of 

the separated natural gas to maintain a high pressure in the deposit. Advanced measures 

raise the production are the reinjection of produced water or sea water and the reinjection 

of steam to increase the viscosity or surface tension of the oil-gas mixture. 

The produced oil-gas mixture is a composite of crude 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 separated 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 are often still flared, sometimes also 

vented, due to missing preparation and transportation opportunities. Hydrogen sulphide 

contained in the natural gas in different concentrations, has to be removed before transportation via pipelines due to the high corrosive impact. The hydrogen sulphide is recovered from the natural gas by the Claus process 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 and used 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 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 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 principal modelling approach. 

2.1 System boundaries and functional unit 

Functional unit: The functional unit is 1 bbl of crude 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]. Amount 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 gas composition is considered [27], [19]. 

The energy demand for production is given in section 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, natural gas, natural gas liquids) is 90% of 

mass and energy and 95% of the environmental relevance (expert judgement). 

2.4 Data selection and combination principles 

The data sources for the complete product system are sufficiently consistent: The data on 

the energy carrier supply chain is based on statistics 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 some of the emission data and product 

properties are sourced from different years representativeness for the reference year is 

considered good. 

2.6 Data treatment and extrapolations principles 

In terms of the country/region specific crude oil production, missing data of certain parameters has been used from countries with a comparable technology1

. Data measured at 

a group of representative production facilities have 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 produced. 

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 electricity 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 natural 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 during 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 product 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 Energy Agency, 2004 

[2] Pennwell: The international petroleum Encyclopaedia 1997

[3] OGP, International Associations of Oil and Gas Producers: Environmental performance in the E&P industry 2003, 2004 

[4] Shell Nigeria 2004 People and the environment Annual 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, 1980-2003, 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 Information 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 Foundation, 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 Drilling, Production and work over, 

2nd Edition, Golf Professional Publishing, 2002 

[15] Gordon, D. et al. Underbalanced Drilling with casing SPE, SPE Drilling & completion 

2005 

[16] Ohio Department of Health: Materials used in drilling 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 testing, 2000 

[19] BP: Das Buch zum Erdöl (The book on Crude oil), 1989 

[20] US EPA: Compilation of Air pollutant emission factors, AP 42, Volume I: Stationary 

point and area sources, Fifth edition, United States 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 Industry, 2nd Section, 2000 

[22] PSI: Management of produced water on offshore oil installations, 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 substances in produced water on the 

marine environment, International Association of Oil and Gas Producers, 2005 

[25] Leahey, G et at.: Theoretical and observational assessments of flare efficiencies, 

Journal of Air & Waste Management Association, Volume 51, December 2001 

[26] Johnson, M.R. et al.: Efficiency measurements of flares in a cross flow, Dep. Of Mechanical Engineering, University of Alberta, Combustion Canada conference, 

1999 

[27] EIA: C.5 Gross Heat Content of Dry Natural Gas Production, 1980-2004, 2005 

[28] IEA: Oil Information 2002, International Energy Agency, 2004 
Documentation 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 production 

1.1 Introduction 

The production of crude oil was modelled as a combined natural gas and crude oil production. In most cases beside crude oil, different parts of natural gas and NGL (natural gas 

liquids) are produced as by-products. For the different by-products allocation by lower 

calorific 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 

data set includes all relevant parts of the upstream industry. Production may take place 

onshore and offshore. Both are taken into account proportionate 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 by 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 steel hull with 3 or more legs, semisubmersible rigs, which float at all times on pontoons, or drill ships are used. The oil rig 

contains machinery and fulfils the role of superstructure 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 removed 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 the surface between drill string and the inner 

surface of the well due to the high pressure generated by piston pumps. At the rig the drilling fluid is separated from drill cuttings and circulated. The drilling fluid also serves to cool 

the drill bit, to seal the drill hole against seepage and to prevent wall cave-ins. Depending 

on geology and technology water-based, oil-based and synthetic-based fluids are used. 

They are mixed with barium sulphate and bentonite to increase the density of the fluid as 

well as further additives. After finishing the drilling 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 infrastructure for preparing and transportation, produced oil and gas is flared. Small amounts of gas are 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 brought 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 mixture 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 or when the pressure was already lower at 

the beginning. For further exploitation it is necessary to use pumps or to reinject a part of 

the separated natural gas to maintain a high pressure in the deposit. Advanced measures 

raise the production are the reinjection of produced water or sea water and the reinjection 

of steam to increase the viscosity or surface tension of the oil-gas mixture. 

The produced oil-gas mixture is a composite of crude 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 separated 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 are often still flared, sometimes also 

vented, due to missing preparation and transportation opportunities. Hydrogen sulphide 

contained in the natural gas in different concentrations, has to be removed before transportation via pipelines due to the high corrosive impact. The hydrogen sulphide is recovered from the natural gas by the Claus process 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 and used 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 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 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 principal modelling approach. 

2.1 System boundaries and functional unit 

Functional unit: The functional unit is 1 bbl of crude 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]. Amount 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 gas 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 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 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, natural gas, natural gas liquids) is 90% of 

mass and energy and 95% of the environmental relevance (expert judgement). 

2.4 Data selection and combination principles 

The data sources for the complete product system are sufficiently consistent: The data on 

the energy carrier supply chain is based on statistics 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 some of the emission data and product 

properties are sourced from different years representativeness for the reference year is 

considered good. 

2.6 Data treatment and extrapolations principles 

In terms of the country/region specific crude oil production, missing data of certain parameters has been used from countries with a comparable technology1

. Data measured at 

a group of representative production facilities have 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 produced. 

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 electricity 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 natural 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 during 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 product 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 Energy Agency, 2004 

[2] Pennwell: The international petroleum Encyclopaedia 1997 

[3] OGP, International Association of Oil and Gas Producers: 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&FC2=/myen/html/iwgen/society_environment/environment/sustainable2003/zzz_lhn.html&FC3

=/myen/html/iwgen/society_environment/environment/sustainable2003/sd03_protectthee

nvironment_1008.html, 2004 

[6] Shell Nigeria 2004 People and the environment Annual Report, 2005

[7] Nederlandse Aardolie Maatschappij (NAM): Bron van energie, 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, 1980-2003, 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 Information 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 Foundation, 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 Drilling, Production and work over, 

2nd Edition, Golf Professional Publishing, 2002 
Documentation Crude oil production 2002 

Oil production in Saudi Arabia 8 / 8 05/08/2008 

[20] Gordon, D. et al. Underbalanced Drilling with casing SPE, SPE Drilling & completion 

2005 

[21] Ohio Department of Health: Materials used in drilling 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 testing, 2000 

[24] OGP, International Association of Oil and Gas Producers: Environmental performance in the E&P industry 2003 

[25] US EPA: Compilation of Air pollutant emission factors, AP 42, Volume I: Stationary 

point and area sources, Fifth edition, United States Protection Agency, Office of 

air quality planning and standards, 1995-2000. 

[26] US EPA: Profile of the Oil and Gas Extraction Industry, 2nd Section, 2000 

[27] PSI: Management of produced water on offshore oil installations, 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 substances in produced water on th 

marine environment, International Association of Oil and Gas Producers, 2005 

[30] Leahey, G et at.: Theoretical and observational assessments of flare efficiencies, 

Journal of Air & Waste Management Association, Volume 51, December 2001 

[31] Johnson, M.R. et al.: Efficiency measurements of flares in a cross flow, Dep. Of Mechanical Engineering, University of Alberta, Combustion Canada conference, 

1999 

[32] EIA: C.5 Gross Heat Content of Dry Natural Gas Production, 1980-2004, 2005 

[33] IEA: Oil Information 2002, International Energy Agency, 2004 
Documentation 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 production 

1.1 Introduction 

The production of crude oil was modelled as a combined natural gas and crude oil production. In most cases beside crude oil, different parts of natural gas and NGL (natural gas 

liquids) are produced as by-products. For the different by-products allocation by lower 

calorific 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 

data set includes all relevant parts of the upstream industry. Production may take place 

onshore and offshore. Both are taken into account proportionate 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 by 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 steel hull with 3 or more legs, semisubmersible rigs, which float at all times on pontoons, or drill ships are used. The oil rig 

contains machinery and fulfils the role of superstructure 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 removed 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 the surface between drill string and the inner 

surface of the well due to the high pressure generated by piston pumps. At the rig the drilling fluid is separated from drill cuttings and circulated. The drilling fluid also serves to cool 

the drill bit, to seal the drill hole against seepage and to prevent wall cave-ins. Depending 

on geology and technology water-based, oil-based and synthetic-based fluids are used. 

They are mixed with barium sulphate and bentonite to increase the density of the fluid as 

well as further additives. After finishing the drilling 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 infrastructure for preparing and transportation, produced oil and gas is flared. Small amounts of gas are 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 brought 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 mixture 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 or when the pressure was already lower at 

the beginning. For further exploitation it is necessary to use pumps or to reinject a part of 

the separated natural gas to maintain a high pressure in the deposit. Advanced measures 

raise the production are the reinjection of produced water or sea water and the reinjection 

of steam to increase the viscosity or surface tension of the oil-gas mixture. 

The produced oil-gas mixture is a composite of crude 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 separated 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 are often still flared, sometimes also 

vented, due to missing preparation and transportation opportunities. Hydrogen sulphide 

contained in the natural gas in different concentrations, has to be removed before transportation via pipelines due to the high corrosive impact. The hydrogen sulphide is recovered from the natural gas by the Claus process 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 and used 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 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 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 principal modelling approach. 

2.1 System boundaries and functional unit 

Functional unit: The functional unit is 1 bbl of crude 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]. Amount 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 gas composition is considered [19], [27]. 

The energy demand for production is given in section 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]. 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 Venezuela 4 / 8 05/08/2008 

2.3 Data completeness 

The coverage for the exploration data (crude oil, natural gas, natural gas liquids) is 90% of 

mass and energy and 95% of the environmental relevance (expert judgement). 

2.4 Data selection and combination principles 

The data sources for the complete product system are sufficiently consistent: The data on 

the energy carrier supply chain is based on statistics 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 some of the emission data and product 

properties are sourced from different years representativeness for the reference year is 

considered good. 

2.6 Data treatment and extrapolations principles 

In terms of the country/region specific crude oil production, missing data of certain parameters has been used from countries with a comparable technology1

. Data measured at 

a group of representative production facilities have 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 produced. 

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 electricity 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 Latin 

America [3] and own calculations 

Mechanical energy demand 206.36 Btu/lb HC 

Value for Region Latin 

America [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 natural 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 during 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 product 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 Energy Agency, 2004 

[2] Pennwell: The international petroleum Encyclopedia 1997

[3] OGP, International Association of Oil and Gas Producers: 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, 1980-2003, 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 Information 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 Foundation, 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 Drilling, Production and work over, 

2nd Edition, Golf Professional Publishing, 2002 

[15] Gordon, D. et al. Underbalanced Drilling with casing SPE, SPE Drilling & completion 

2005 

[16] Ohio Department of Health: Materials used in drilling 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 testing, 2000 

[19] EIA: C.5 Gross Heat Content of Dry Natural Gas Production, 1980-2004, 2005 

[20] US EPA: Compilation of Air pollutant emission factors, AP 42, Volume I: Stationary 

point and area sources, Fifth edition, United States 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 Industry, 2nd Section, 2000 

[22] PSI: Management of produced water on offshore oil installations, 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 substances in produced water on the 

marine environment, International Association of Oil and Gas Producers, 2005 

[25] Leahey, G et at.: Theoretical and observational assessments of flare efficiencies, 

Journal of Air & Waste Management Association, Volume 51, December 2001 

[26] Johnson, M.R. et al.: Efficiency measurements of flares in a cross flow, Dep. Of Mechanical Engineering, University of Alberta, Combustion Canada conference, 

1999 

[27] California Energy Commission: Natural gas composition and Quality, 2005 

[28] IEA: Oil Information 2002, International Energy Agency, 2004

[29] EIA: International Energy Annual 2003; Energy Information Administration, 2004 

[30] World Bank: Global gas flaring reduction initiative, 2004 
Documentation Crude oil & Natural gas production 2002 

Oil_Natural gas production in the USA 1 / 9 05/08/2008 

Production of crude oil and natural gas in the USA 

1. Technology description of the Crude oil production 

1.1 Introduction 

The production of crude oil and natural was modelled as a combined natural gas and 

crude oil production. In the case of crude oil wells, different parts of natural gas and NGL 

(natural gas liquids) are produced as co-products and vice versa for natural gas wells. For 

the different co-products allocation by lower calorific 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 data set includes all relevant parts of the 

upstream industry. Production may take place onshore and offshore. Both are taken into 

account proportionate 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 by 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 steel hull with 3 or more legs, semisubmersible rigs, which float at all times on pontoons, or drill ships are used. The oil rig 

contains machinery and fulfils the role of superstructure 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 removed 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 the surface between drill string and the inner 

surface of the well due to the high pressure generated by piston pumps. At the rig the drilling fluid is separated from drill cuttings and circulated. The drilling fluid also serves to cool 

the drill bit, to seal the drill hole against seepage and to prevent wall cave-ins. Depending 

on geology and technology water-based, oil-based and synthetic-based fluids are used. 

They are mixed with barium sulphate and bentonite to increase the density of the fluid as 

well as further additives. After finishing the drilling 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 infrastructure for preparing and transportation, produced oil and gas is flared. Small amounts of gas are 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 brought ashore depending on drilling fluid 

and legislation. 
Documentation Crude oil & Natural gas production 2002 

Oil_Natural gas production in the USA 2 / 9 05/08/2008 

1.3 Production & Preparation 

Crude oil 

Ideally the oil is transported as an oil-gas mixture 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 or when the pressure was already lower at 

the beginning. For further exploitation it is necessary to use pumps or to reinject a part of 

the separated natural gas to maintain a high pressure in the deposit. Advanced measures 

raise the production are the reinjection of produced water or sea water and the reinjection 

of steam to increase the viscosity or surface tension of the oil-gas mixture. 

The produced oil-gas mixture is a composite of crude 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 separated 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 are often still flared, sometimes also 

vented, due to missing preparation and transportation opportunities. 

Natural gas 

Due to the high pressure in the gas field the production 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 porosity, the production rate is increased by 

pumping liquids under high pressure into the deposit 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 corrosive impact. The hydrogen sulphide 

is recovered from the natural gas by the Claus process 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 and used 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 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 2002 

Oil_Natural gas production in the USA 3 / 9 05/08/2008 

2 General comments of the LCA assessment method 

This chapter gives background information on the principal modelling approach. 

2.1 System boundaries and functional unit 

Crude oil: 

Functional unit: The functional unit is 1 bbl of crude 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 cubic 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 outputs 
Documentation Crude oil & Natural gas production 2002 

Oil_Natural gas production in the USA 4 / 9 05/08/2008 

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 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 [17]-[19]. Amount 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 gas composition is considered [33], [35]. 

The energy demand for production is given in section 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, natural gas, natural gas liquids) is 90% of 

mass and energy and 95% of the environmental relevance (expert judgement). 
Documentation Crude oil & Natural gas production 2002 

Oil_Natural gas production in the USA 5 / 9 05/08/2008 

2.4 Data selection and combination principles 

The data sources for the complete product system are sufficiently consistent: The data on 

the energy carrier supply chain is based on statistics 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 some of the emission data and product 

properties are sourced from different years representativeness for the reference year is 

considered good. 

2.6 Data treatment and extrapolations principles 

In terms of the country/region specific crude oil production, missing data of certain parameters has been used from countries with a comparable technology1

. Data measured at 

a group of representative production facilities have 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 2002 

Oil_Natural gas production in the USA 6 / 9 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 produced. Note that all values are given for 

unallocated joint production of Natural gas, NGL and 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 production2

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 electricity 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 North 

America [25] and own calculations 

Mechanical energy demand 236.45 Btu/lb HC 

Value for region North 

America [25] and own calculations 

Total energy demand 262.25 Btu/lb HC Value for region North 

America [25] 

 

2

 Based on gross withdrawal 
Documentation Crude oil & Natural gas production 2002 

Oil_Natural gas production in the USA 7 / 9 05/08/2008 

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 natural 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 calculations 

3.4 Waste and waste water 

The amount of solid waste and waste water emitted during 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 product 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 2002 

Oil_Natural gas production in the USA 8 / 9 05/08/2008 

4 References 

[1] IEA Natural Gas Information 2002, International Energy 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&FC2=/myen/html/iwgen/society_environment/environment/sustainable2003/zzz_lhn.html&FC3

=/myen/html/iwgen/society_environment/environment/sustainable2003/sd03_protectthee

nvironment_1008.html, 2004 

[5] Shell Nigeria 2004 People and the environment Annual Report, 2005

[6] Nederlandse Aardolie Maatschappij (NAM): Bron van energie, 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, 1980-2003, 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 Crude Oil Assay, West Texas 

sour, 2000 

[15] Aaron Dillard: Crude oil Quality Programs, Light Louisiana Sweet,2001 

[16] EIA: International Energy Annual 2003; Energy Information 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 Foundation, 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 Drilling, Production and work over, 

2nd Edition, Golf Professional Publishing, 2002 
Documentation Crude oil & Natural gas production 2002 

Oil_Natural gas production in the USA 9 / 9 05/08/2008 

[21] Gordon, D. et al. Underbalanced Drilling with casing SPE, SPE Drilling & completion 

2005 

[22] Ohio Department of Health: Materials used in drilling 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 testing, 2000 

[25] OGP, International Association of Oil and Gas Producers: Environmental performance in the E&P industry 2003 

[26] US EPA: Compilation of Air pollutant emission factors, AP 42, Volume I: Stationary 

point and area sources, Fifth edition, United States Protection Agency, Office of 

air quality planning and standards, 1995-2000. 

[27] US EPA: Profile of the Oil and Gas Extraction Industry, 2nd Section, 2000 

[28] PSI: Management of produced water on offshore oil installations, 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 substances in produced water on the 

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