EPA-450/3-76-015-a
May 1976
THE IMPACT
OF PRODUCING LOW-SULFUR,
UNLEADED MOTOR GASOLINE
ON THE PETROLEUM REFINING
INDUSTRY: VOLUME I -
PROJECT SUMMARY
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Air and Waste Management
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
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EPA-450/3-76-015-a
THE IMPACT
OF PRODUCING LOW-SULFUR,
UNLEADED MOTOR GASOLINE
ON THE PETROLEUM REFINING
INDUSTRY: VOLUME I -
PROJECT SUMMARY
by
Authur D. Little, Inc.
Acorn Park
Cambridge, Massachusetts 02140
Contract No. 68-02-1332, Task Order No. 8
EPA Project Officer: Richard K. Burr
Prepared for
ENVIRONMENTAL PROTECTION AGENCY
Office of Air and Waste Management
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
May 1976
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This report is issued by the Environmental Protection Agency to report
technical data of interest to a limited number of readers. Copies are
available free of charge to Federal employees, current contractors and
grantees, and nonprofit organizations - in limited quantities - from the
Library Services Office (MD35), Research Triangle Park, North Carolina
27711; or, for a fee, from the National Technical Information Service,
5285 Port Royal Road, Springfield, Virginia 22161.
This report was furnished to the Environmental Protection Agency by Authur
D. Little, Inc. , Cambridge, Massachusetts 02140, in fulfillment of Contract
No. 68-02-1332, Task Order No. 8. The contents of this report are reproduced
herein as received from Authur D. Little, Inc. The opinions, findings,
and conclusions expressed are those of the author and not necessarily
those of the Environmental Protection Agency. Mention of company or
product names is not to be considered as an endorsement by the Environmen-
tal Protection Agency.
Publication No. EPA-450/3-76-015-a
11
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ABSTRACT
The objective of this project was to assess the impact on the U. S. petroleum
refining industry of possible EPA regulations restricting the sulfur content
of unleaded gasoline. Sulfur levels of 100 ppm and 50 ppm were considered.
Computer models representative of specific refineries in six geographical
regions of the U. S. were developed as the basis for determining the impact
on the existing refining industry. New refinery construction during the
period under analysis (1975-1985) was considered by development of separate
computer models rather than expansion of existing refineries. These models
were utilized to assess investment and energy requirements and the incremental
cost to manufacture low sulfur unleaded gasoline. Sensitivity analyses
examined the effect of variations in key assumptions on the results of the
study, such as the type of imported crude oil available for future domestic
refining and the projected sulfur level of residual fuel oil manufactured
in the U. S. Other sensitivity studies examined in more detail the processing
options available to meet the two sulfur levels and the assumptions regarding
sulfur distribution in refinery process streams.
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TABLE OF CONTENTS
Volume I
Page
i. EXECUTIVE SUMMARY :... 1
A. INTRODUCTION 1
B. SCOPE AND APPROACH 2
C. CONCLUSIONS 6
1. Calibration Summary 6
2. Qualitative Study Results 8
3. Economic Penalties 9
4. Crude Oil and Energy Penalties ^
5. Sensitivity Studies 12
6. Other Major Implications ^5
D. RECOMMENDATIONS FOR FURTHER ACTION 16
II. STUDY BASIS 17
A. APPROACH 17
B. CASE DEFINITIONS 20
C. PLANNING ASSUMPTIONS 25
1. Crude Slate Projections 25
2. U.S. Supply/Demand Proj ections 28
a. Uniform Product Growth at 2% Per Annum 29
b. Non-Uniform Petroleum Product Growth Rates ^^ -^Q
c. Gasoline Grade Distribution 32
3. Key Product Specifications . . 32
a. Motor Gasoline Specifications 34
b. Sulfur Content of Residual Fuel Oils 37
iv
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TABLE OF CONTENTS - Volume I (cont.)
i. Page
4. Processing and Blending Routes 41
5. Calibration of Cluster Models . .. . 47
6. Existing and Grassroots Refineries 50
7. Economic Basis for Study 53
8. Scale Up to National Capacity 59
III. STUDY RESULTS 63
A. BACKGROUND DISCUSSION 63
B. MANUFACTURE OF 100 PPM GASOLINE . . 65
1. 1985 Results 65
2. 1980 Results 68
3. 1977 Results 69
C. MANUFACTURE OF 50 PPM GASOLINE 70
1. 1985 Results 70
2. 1980 Results 70
3. 1977 Results 72
D. SUMMARY OF THE ECONOMIC PENALTIES 72
E. SUMMARY OF CRUDE OIL AND ENERGY PENALTIES 76
IV. SENSITIVITY STUDY RESULTS 81
A. SULFUR DISTRIBUTION IN FCC UNITS 81
B. IMPORTED CRUDE OIL FOR GRASSROOTS CAPACITY 83
C. EFFECT OF TARGET RESIDUAL FUEL OIL SULFUR LEVEL 83
D. ALTERNATIVE METHOD OF DESULFURIZING FCC GASOLINE 85
V. DISCUSSION 88
VI. REFERENCES 90
v
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LIST OF TABLES'
Volume I
TABLE 1. Economic Penalties for the Manufacture
of Low Sulfur Unleaded Gasoline by 1985 . • 10
TABLE 2. Crude Oil and Energy Penalties for the
Manufacture of Low Sulfur Unleaded Gasoline 13
TABLE 3. Effect of Increased FCC Gasoline Sulfur Levels
on the 1985 Economic Penalty for Manufacturing
Low Sulfur, Unleaded Gasoline • • ^
TABLE 4. Parametric Studies 22
TABLE 5. U.S. Refinery Crude Run 27
TABLE 6. Gasoline Grade Requirements by Percent 33
TABLE 7. Motor Gasoline Survey Data 35
TABLE 8. Motor Gasoline Survey, Winter 1974-75 Average
Data for Unleaded Gasoline in Each District 36
TABLE 9 Availability of Residual Fuel Oil by Sulfur
Level, 1973 40
TABLE 10 Grassroots Refinery Fuel Oil Sulfur Projection -. 1985
Scenario A - East of Rockies Only 42
TABLE 11. FCC Unit Sulfur Distribution - Large Midwest Cluster
65% Conversion 45
TABLE 12. Illustrative Blending Octane Number Comparison 46
TABLE 13. Refineries Simulated by Cluster Models 48
TABLE 14. Calibration Results for Large Midwest Cluster 51
TABLE 15. Onsite Process Unit Costs 54
TABLE 16. Offsite and Other Associated Costs of Refineries
Used in Estimating Cost of Grass Roots Refineries 56
TABLE 17. Grass Roots Refinery Capital Investment •••• 57
TABLE 18. Model Scale-Up Comparison, 1973 gl
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LIST OF TABLES - Volume I (cont.)
Page
TABLE 19. Relationship of Crude Sulfur Level, FCC Intake
and Method Chosen to Manufacture Low Sulfur (100 PPM)
Unleaded Gasoline - 1985 66
TABLE 20. Relationship of Crude Sulfur Level, FCC Intake and
Method Chosen to Manufacture Low Sulfur (50 PPM)
Unleaded Gasoline - 1985 . . 71
TABLE 21. Capital Requirements to Manufacture Low Sulfur
Unleaded Gasoline 73
TABLE 22. Economic Penalties for Manufacture of
Low Sulfur Unleaded Gasoline 74
TABLE 23. Breakdown of 1985 Economic Penalty to Manufacture
Low Sulfur Unleaded Gasoline 75
TABLE 24. Capital Requirements and Economic Penalties for
the Manufacture of Low Sulfur Gasoline in 1985 Assuming
a 20% Blending Tolerance (Total U.S.A.) 77
TABLE 25. Energy Penalties in 1985 for the Manufacture of Low
Sulfur Unleaded Gasoline 78
TABLE 26. Energy Penalties in 1985 for the Manufacture of Low
Sulfur Unleaded Gasoline with Sulfur Blending
Tolerances of 20% 80
TABLE 27. Effect of Increased F.C.C. Gasoline Sulfur Levels on
the 1985 Economic Penalty for Manufacturing Low Sulfur
Unleaded Gasoline 82
TABLE 28. Effect of Changing Imported Crude Oil Type Processed
in Grass Roots Capacity on the 1985 Economic Penalty
for Manufacturing Low Sulfur Unleaded Gasoline 84
TABLE 29. Effect of Lower Target Sulfur Level of Production of
U.S. Residual Fuel Oil on the 1985 Economic Penalty
for Manufacturing Low Sulfur Unleaded Gasoline 86
vii
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LIST OF FIGURES
Volume I PaSe
FIGURE 1. Agreement of Model Prediction with 1973 B.O.M.
Total Refinery Raw Material Intake Data ................ 7
FIGURE 2. Economic Penalty for the Production of Low Sulfur
Unleaded Gasoline Relative to Unleaded Gasoline ........ H
FIGURE 3. Historic Trend of Heavy Fuel Oil Sulfur Content as
Produced and Marketed in U.S ..................... . ..... 39
Vlll
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Volume II
APPENDIX A
CRUDE SLATES
Page
A. METHODOLOGY A-l
B. MODEL CRUDE SLATES A-2
C. CRUDE MIX FOR TOTAL U.S. • A-10
APPENDIX B
U.S. SUPPLY/DEMAND PROJECTIONS
A, DEMAND ASSUMPTIONS FOR MODEL RUNS B-l
B. DETAILED U.S. PRODUCT DEMAND FORECAST ' B-7
1. Methodology B-7
2. Product Forecast B-12
APPENDIX C
PRODUCT SPECIFICATIONS
APPENDIX D
BASE LEVEL OF CLUSTER REFINERY FUEL SULFUR CONTENT
A. METHODOLOGY OF CALCULATIONS D-2
1. Fuel Oil Sulfur Content by State D-2
2. Combustion Unit Size D-2
B. RESULTS D-3
C. CLUSTER MODEL REFINERY FUEL SPECIFICATION , . . . D-6
IX
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TABLE OF CONTENTS - Volume II (cont.)
APPENDIX E
CAPITAL INVESTMENT FOR PROCESS UNIT SEVERITY
UPGRADING AND UTILIZATION OF CAPACITY ALREADY CONSTRUCTED
Page
A. CATALYTIC REFORMING E-2
B. HYDROCRACKING E-8
C. ALKYLATION E-16
D. ISOMERIZATION E_!9
APPENDIX F
DEVELOPMENT OF CLUSTER MODELS
A. SELECTION OF CLUSTER MODELS F-2
B. COMPARISON OF CLUSTER MODEL TO PAD DISTRICT F-5
APPENDIX G
SCALE UP OF CLUSTER RESULTS -
DERIVATION OF PRODUCT DEMANDS FOR GRASS ROOTS REFINERIES
A. INTRODUCTION G-l
B. 1973 CALIBRATION SCALE UP G-l
C. DERIVATION OF MODEL FIXED INPUTS AND OUTPUTS FOR FUTURE YEARS . G-6
D. SCALE UP OF RESULTS FOR FUTURE YEARS G-10
1. 1977 Scale Up G-10
2. 1985 Scale Up , G-12
3. 1980 Scale Up G-15
E. SCALE UP OF CAPITAL INVESTMENTS G-l?
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TABLE OF CONTENTS - Volume II(cont.)
APPENDIX H
TECHNICAL DOCUMENTATION
Page
A. CRUDE OIL PROPERTIES H-l
B. PROCESS DATA H-2
C. GASOLINE BLENDING QUALITIES H-5
D. SULFUR DISTRIBUTION H-5
E. OPERATING COSTS H-6
F. CAPITAL INVESTMENTS H-6
APPENDIX I
MODEL CALIBRATION
A. BASIC DATA FOR CALIBRATION 1-1
1. Refinery Input/Output 1-1
2. Processing Configurations 1-10
3. Product Data 1-18
4. Calibration Economic Data 1-21
B. CALIBRATION RESULTS FOR CLUSTER MODELS 1-22
APPENDIX J
STUDY RESULTS
A. MASS AND SULFUR BALANCE J-l
1. Crude-Specific Streams • J-2
2." Cluster Specific Streams J-3
3. Miscellaneous Streams J-4
xi
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TABLE OF CONTENTS - Volume II (cont.)
APPENDIX K
CONVERSION FACTORS AND NOMENCLATURE
xn
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VOLUME II
LIST OF TABLES
APPENDIX A
TABLE A-l. Bureau of Mines Receipts of Crude by Origin 1973 A~3
TABLE A-2. ADL Model Crude Slates and Sulfur Contents
for 1973 A~4
TABLE A-3. Model Crude Slates - Small Midcontinent A-5
TABLE A-4. Model Crude Slates - Large Midwest A-7
TABLE A-5. Model Crude Slates - Texas Gulf . A-8
TABLE A-6. Model Crude Slates - East Coast A-9
TABLE A-7. Model Crude Slates - West Coast A-ll
TABLE A-8. Model Crude Slates - Louisiana Gulf A-12
TABLE A-9. Scale Up of Model Crude Slates, Scenario A A-14
TABLE A-10. Total Crude Run to Grass Roots Refineries A-15
TABLE A-ll. Distribution of Sweet and Sour Crude Run A-16
APPENDIX B
TABLE B-l. Projections of Major Product Demand in Total U.S.
Assumed in Making Model Runs B-3
TABLE B-2. A Comparison of Projected "Simulated" Demand
for Major Products with Results of Detailed Forecast .... 3-5
TABLE B-3. A Comparison of Projected Total Petroleum Product
Demand in "Simulated" Demand Case With Detailed
Forecast B-6
TABLE B-4. Projection of U.S. Primary Energy Supplies
with Oil as the Balancing Fuel B_9
TABLE B-5.
Forecast of U.S. Product Demand B-ll
Xlll
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APPENDIX C
TABLE C-l. Product Specifications, Gasoline C-2
TABLE C-2. Other Product Specifications C-4
APPENDIX D
TABLE D-l. Refinery Fuel Sulfur Regulations by State D-4
TABLE D-2. Refinery Fuel Sulfur Regulations by PAD D-5
TABLE D-3. Refinery Fuel Sulfur Regulations Applicable to
Individual Refineries in Cluster Models D-7
TABLE D-4. Base Level of Cluster Refinery Fuel
Sulfur Content Used in Model Runs D-9
APPENDIX E
TABLE E-l. Catalytic Reforming Capacity Availability E-4
TABLE E-2. Catalytic Reformer Investment for Capacity
Utilization and Severity Upgrading E-6
TABLE E-3. Costs of Additional Reformer Capacity E-7
TABLE E-4. Cost of Severity Upgrading E-9
TABLE E-5. Hydrocracking Capacity Availability E-ll
TABLE E-6. Hydrocracking Investment for Capacity Utilization,
New Capacity, and Severity Flexibility E-12
TABLE E-7. Costs of Additional Hydrocracking Capacity E-13
TABLE E-8. Cost of Hydrocracker Severity Flexibility E-15
TABLE E-9. Alkylation and Isomerization Capacity Availability E-17
TABLE E-10. Utilization of Existing Alkylation Capacity E-18
TABLE E-ll. Isomerization Investment for Capacity Utilization
and Once Through Upgrading E-20
TABLE E-12. Costs of Additional Isomerization Capacity E-21
TABLE E-13. Cost of Once Through Isomerization Upgrading E-23
xiv
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APPENDIX F
Page
TABLE F-l. Texas Gulf Cluster Processing Configuration F-6
TABLE F-2. Louisiana Gulf Cluster Processing Configuration F-7
TABLE F-3. Large Midwest Cluster Process Configuration F-8
TABLE F-4. Small Midcontinent Cluster Processing Configuration F~9
TABLE F-5. East Coast Cluster Processing Configuration F-10
TABLE F-6. West Coast Cluster Processing Configuration F"11
TABLE F-7. Summary of Major Refinery Processing Units F-12
TABLE F-8. Comparison of Product Output of East Coast
Cluster to PAD District 1, 1973 • • • F~14
TABLE F-9. Comparison of Product Output of Midcontinent Clusters
to PAD District II, 1973 F-15
TABLE F-10. Comparison of Product Output of Gulf Coast Clusters
to PAD District III, 1973 F-16
TABLE F-ll. Comparison of Product Output of West Coast Cluster
to PAD District V, 1973 F-l7
TABLE F-12. Comparison of Crude Input of East Coast Cluster
to PAD District 1, 1973 F-18
TABLE F-13. Comparison of Crude Input to Midcontinent Cluster
to PAD District II, 1973 F-19
TABLE F-1A. Comparison of Crude Input of Gulf Coast Clusters
to PAD District III, 1973 F-20
TABLE F-15. Comparison of Crude Input to West Coast Cluster
PAD District V, 1973 . F-21
xv
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APPENDIX G
Page
TABLE G-l. ADL Model Input/Outturn Data for Calibration - 1973 G-2
TABLE G-2. Comparison of 1973 B.O.M. Data and Scale Up of 1973
Calibration Input/Outturn G-3
TABLE G-3. L. P. Model Input/Outturns 1977 G-7
TABLE G-4. L.P. Model Input/Outturns 1980 G-8
TABLE G-5. L.P. Model Input/Outturns - 1985 G-9
TABLE G-6. Scale Up Input/Outturns 1977 G-ll
TABLE G-7. Atypical Refinery Intake/Outturn Summary G-13
TABLE G-8. Scale Up Input/Output - 1985 G-14
TABLE G-9. Scale Up Input/Output - 1980 G-16
APPENDIX H
TABLE H-l. Crude and Natural Gasoline Yields; Crude Properties H-8
TABLE H-2. Yield Data-Reforming of SR Naphtha . H-9
TABLE H-3. Yield Data-Reforming of Conversion Naphtha H-12
TABLE H-4. Yield Data-Catalytic Cracking ; H-13
TABLE H-5. Yield Data-Hydrocracking H-14
TABLE H-6. Yield Data-Coking H-15
TABLE H-7. Yield Data-Visbreaking H-16
TABLE H-8. Yield Data-Desulfurization H-17
TABLE H-9. Yield Data-Miscellaneous Process Units H-18
TABLE H-10. Hydrogen Consumption Data - Desulfurization of Crude-
Specific Streams H-19
TABLE H-ll. Hydrogen Consumption Data - Hydrocracking and
Desulfurization of Model-Specific Streams H-20
TABLE H-12. Sulfur Remova] H-21
TABLE H-13. Stream Qualities - Domestic Crudes H-22
xvi
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APPENDIX H '- (cont.)
Page
TABLE-H-14. Stream Qualities - Foreign Crudes and Natural
Gasoline H-25
TABLE H-15. Stream Qualities - Miscellaneous Streams H-28
TABLE H-16. Stream Qualities - Variable Sulfur Streams H-30
TABLE H-17. Sulfur Distribution - Coker and Visbreaker H-31
TABLE H-18. Sulfur Distribution - Catalytic Cracking H-32
TABLE H-19. Alternate Yield Data - High and Low Severity Reforming
of SR Naphtha H-33
TABLE H-20. Alternate Yield Data - High and Low Pressure Reforming
of Conversion Naphtha H-36
TABLE H-21. Operating Cost Consumptions - Reforming H-37
TABLE H-22. Operating Cost Consumptions - Catalytic Cracking H-38
TABLE H-23. Operating Cost Consumptions - Hydrocracking H-39
TABLE H-24. Operating Cost Consumptions - Desulfurization H-40
TABLE H-25. Operating Cost Consumptions - Miscellaneous Process
Units . H-41
TABLE H-26. Operating Costs Coefficients H-42
TABLE H-27. Process Unit Capital Investment Estimates H-43
TABLE H-28. Offsite and Other Associated Costs of Refineries Used
in Estimating Cost of Grassroots Refineries H-44
APPENDIX I
TABLE 1-1. Bureau of Mines Refinery Input/Output Data for
Cluster Models: 1973 1-2
.TABLE 1-2. Bureau of Mines Receipts of Crude by Origin 1973 1-3
TABLE 1-3. • Bureau of Mines Refinery Fuel Consumption for
Cluster Models 1973 1-4
xvi i
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APPENDIX I - (Cont.)
Page
TABLE 1-4. Bureau of Mines Refinery Fuel Consumption for Cluster
Models 1973 1-5
TABLE 1-5. ADL Model Input/Outturn Data for Calibration 1-7
TABLE 1-6. Conversion of BOM Input/Outturn Data to ADL Model
Format 1-8
TABLE 1-7. ADL Model Crude Slates and Sulfur Contents for
Refinery Clusters 1-11
TABLE 1-8. Texas Gulf Cluster Processing Configuration 1-12
TABLE 1-9. Louisiana Gulf Cluster Processing Configuration 1-13
TABLE 1-10. Large Midwest Cluster Process Configuration 1-14
TABLE 1-11. Small Midcontinent Cluster Processing Configuration .... 1-15
TABLE 1-12. West Coast Cluster Model Processing Configuration 1-16
TABLE 1-13. East Coast Cluster Processing Configuration 1-17
TABLE 1-14. Cluster Model Gasoline Production and Properties
1973 1-19
TABLE 1-15. Key Product Specifications 1-20
TABLE 1-16. Cluster Model Processing Data - 1973 ; 1-23
TABLE 1-17. Louisiana Gulf Cluster Model 1-32
TABLE 1-18. Texas Gulf Cluster Model 1-33
TABLE 1-19. Large Midwest Cluster Model 1-34
TABLE 1-20. Small Midcontinent Cluster Model 1-35
TABLE 1-21. West Coast Cluster Model 1-36
TABLE 1-22. East Coast Cluster Model 1-37
TABLE 1-23. Louisiana Gulf Calibration 1-39
TABLE 1-24. Texas Gulf Calibration 1-40
TABLE 1-25. Small Midcontinent Calibration 1-41
xviii
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APPENDIX I - (cqnt.).
Page
TABLE 1-26. Large Midwest Calibration 1-42
TABLE 1-27. West Coast Calibration I_43
TABLE 1-28. East Coast. Calibration I_44
APPENDIX J
TABLE J-l. Economic Penalty for the Manufacture of Low Sulfur
(100 ppm) Lead-Free Gasoline - 1977 J-5
TABLE J-2. Economic Penalty for the Manufacture of Low Sulfur
(100 ppm) Lead-Free Gasoline - 1980 J-6
TABLE J-3. Economic Penalty for the Manufacture of Low Sulfur
(100 ppm) Lead-Free Gasoline - 1985 J-7
TABLE J-4. Economic Penalty for the Manufacture of Low Sulfur
(50 ppm) Lead-Free Gasoline - 1977 J-8
TABLE J-5. Economic Penalty for the Manufacture of Low Sulfur
(50 ppm) Lead-Free Gasoline - 1980 J-9
TABLE J-6. Economic Penalty for the Manufacture of Low Sulfur
(50 ppm) Lead Free Gasoline - 1985 J-10
TABLE J-7. Energy Penalty for the Manufacture of Low Sulfur
(100 ppm) Lead-Free Gasoline - 1977 J-ll
TABLE J-8. Energy Penalty for the Manufacture of Low Sulfur
(100 ppm) Lead-Free Gasoline - 1980 J-12
TABLE J-9. Energy Penalty for the Manufacture of Low Sulfur
(100 ppm) Lead-Free Gasoline - 1985 J-13
TABLE J-10. Energy Penalty for the Manufacture of Low Sulfur
(50 ppm) Lead-Free Gasoline - 1977 J-14
TABLE J-ll. Energy Penalty for the Manufacture of Low Sulfur
(50 ppm) Lead-Free Gasoline - 1980 J-1 5
TABLE J-12. Energy Penalty for the Manufacture of Low Sulfur
(50 ppm) Lead-Free Gasoline - 1985 J-16
TABLE J-13. Capital Investment Requirements to Manufacture J-17
Low Sulfur Lead-Free Gasoline
xix
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APPENDIX J -(cont.)
TABLE J-14. Operating Costs Required to Manufacture Low Sulfur
Lead-Free Gasoline J-18
TABLE J-15. Basis for Cluster Capital Investment Requirements .... J-19
TABLE J-16. L.P. Model Results: - Capital Investment Requirements
and Operating Costs - East Coast J-20
TABLE J-17. L.P. Model Results: - Capital Investment Requirements
and Operating Costs - East Coast J-21
TABLE J-18. L.P. Model Results: - Capital Investment Requirements
and Operating Costs - Large Midwest J-22
-TABLE J-19. L.P. Model Results: - Capital Investment Requirements
and Operating Costs - Large Midwest J-23
TABLE J-20. L.P. Model Results: - Capital Investment Requirements
and Operating Costs - Small Midcontinent J-24
TABLE J-21. L.P. Model Results: - Capital Investment Requirements
and Operating Costs - Small Midcontinent j-25
TABLE J-22. L.P. Model Results: - Capital Investment Requirements
and Operating Costs - Louisiana Gulf J-26
TABLE J-23. L.P. Model Results: - Capital Investment Requirements
and Operating Costs - Louisiana Gulf J-27
TABLE J-24. L.P. Model Results: - Capital Investment Requirements
and Operating Costs - Texas Gulf j-28
TABLE J-25. L.P. Model Results: - Capital Investment Requirements
and Operating Costs - Texas Gulf j_29
TABLE J-26. L.P. Model Results: - Capital Investment Requirements
and Operating Costs - West Coast j_30
TABLE J-27. L.P. Model Results: - Capital Investment Requirements
and Operating Costs - West Coast j-31
TABLE J-28. L.P. Model Results: - Capital Investment Requirements
and Operating Costs - Grassroots East of Rockies j-32
TABLE J-29. L.P. Model Results: - Capital. Investment Requirements
and Operating Costs - Grassroots West of Rockies .... J-33
TABLE J-30. L.P. Model Results - Fixed Inputs and Outputs
East Coast J-34
'xx
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APPENDIX J - (cont.)
TABLE J-31. ' L.P. Model Results - Fixed Inputs and Outputs
Large Midwest . J-35
TABLE J-32. L.P. Model Results - Fixed Inputs and Outputs
Small Midcontinent J-36
TABLE J-33. L.P. Model Results - Fixed Inputs and Outputs
Louisiana Gulf J-37
TABLE J-34. L.P. Model Results - Fixed Inputs and Outputs
Texas Gulf J-38
TABLE J-35. L.P. Model Results - Fixed Inputs and Outputs
West Coast J-39
TABLE J-36. L.P. Model Results - Inputs and Fixed Outputs
Grassroots Refineries J-40
TABLE J-37. L.P. Model Results - Processing and Variable Outputs
Cluster: East Coast J-41
TABLE J-38. L.P. Model Results - Processing and Variable Outputs
Cluster: Large Midwest J-42
TABLE J-39. L.P. Model Results - Processing and Variable Outputs
Cluster: Small Midcontinent J-43
TABLE J-40. L.P. Model Results - Processing and Variable Outputs
Cluster: Louisiana Gulf J-44
TABLE J-41. L.P. Model Results - Processing and Variable Outputs
Cluster: Texas Gulf J-45
TABLE J-42. L.P. Model Results - Processing and Variable Outputs
Cluster: West Coast J-46
TABLE J-43. L.P. Model Results - Processing and Variable Outputs
Grassroots Refineries, 1985 J-47
TABLE J-44. L.P. Model Results - Gasoline Blending - East Coast ... J-48
TABLE J-45. L.P. Model Results - Gasoline Blending - East Coast ... J-49
TABLE J-46. L.P. Model Results - Gasoline Blending - Large Midwest J-50
TABLE J-47. L.P. Model Results - Gasoline Blending - Large Midwest J-51
TABLE J-48. L.P. Model Results - Gasoline Blending -
Small Midcontinent J-52
xxi
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APPENDIX J - (cont.)
Page
TABLE J-49. L.P. Model Results - Gasoline Blending -
Small Midcontinent J~53
TABLE J-50. L.P. Model Results - Gasoline Blending - Louisiana Gulf J~5^
TABLE J-51. L.P. Model Results - Gasoline Blending - Louisiana Gulf J-55
TABLE J-52. L.P. Model Results - Gasoline Blending - Texas Gulf ... J~56
TABLE J-53. L.P. Model. Results - Gasoline Blending - Texas Gulf ... J-57
TABLE J-54. L.P. Model Results - Gasoline Blending - West Coast ... J-58
TABLE J-55. L.P. Model Results - Gasoline Blending - West Coast ••• J-59
TABLE J-56. L.P. Model Results - Gasoline Blending - Grassroots •• J-60
TABLE J-57. L.P. Model Results - Gasoline Blending - Grassroots ••• J-61
TABLE J-58. L.P. Model Results - Residual Fuel Oil Sulfur Levels -
1977 J-62
TABLE J-59. L.P. Model Results - Residual Fuel Sulfur Levels - 1980 J-63
TABLE J-60. L.P. Model Results - Residual Fuel Oil Sulfur Levels -
1985 J-64
TABLE J-61. L.P. Model Results - Refinery Fuel Sulfur Levels - 1977 J-65
TABLE J-62. L.P. Model Results - Refinery Fuel Sulfur Levels - 1980 J-66
TABLE J-63. L.P. Model Results - Refinery Fuel Sulfur Levels - 1985 J-67
TABLE J-64. Sample Calculations for Mass and Sulfur Balance
Texas Gulf 1985, Scenario B/C
Stream Values - Gas Oil 375-650°F J-69
TABLE J-65. Sample Calculations for Mass and Sulfur Balance
Texas Gulf 1985 B/C
Desulfurization of Light Gas Oil J-70
TABLE J-66. Sample Calculations for Mass and Sulfur Balance
Texas Gulf 1985, Scenario B/C
Feed Sulfur Levels J-71
TABLE J-67. Sample Calculations for Mass and Sulfur Balance
Texas Gulf 1985, Scenario B/C
Stream Qualities - Cluster-Specific Streams J-72
-xxii
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APPENDIX J- (cont.)
Page
TABLE J-68. Sample Calculations for Mass and Sulfur Balance
Texas Gulf 1985, Scenario B/C
Stream Qualities - Cluster-Specific Streams J-73
TABLE J-69. Specific Gravities and Densities for Miscellaneous
Streams J-74
TABLE J-70. Mass and Sulfur Balance - Texas Gulf Cluster 1985,
Scenario B/C J-75
TABLE J-71. Mass and Sulfur Balance, Texas Gulf Cluster 1985,
Scenario D J-83
APPENDIX K
TABLE K-l. Weight Conversions K-l
TABLE K-2. Volume Conversions K-2
TABLE K-3. Gravity, Weight and Volume Conversions for Petroleum
Products K-3
TABLE K-4. Representative Weights of Petroleum Products K-4
TABLE K-5. Heating Values of Crude Petroleum and Petroleum
Products K-5
TABLE K-6. Nomenclature K-6
XXlll
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VOLUME II
LIST OF FIGURES
APPENDIX F
FIGURE F-l. Geographic Regions Considered in Development of
Cluster Models F-3
APPENDIX I
FIGURE 1-1. Louisiana Gulf Cluster Model Calibration 1-25
FIGURE 1-2. Texas Gulf Cluster Model Calibration 1-26
FIGURE 1-3. Small Midcontinent Cluster Model Calibration 1-27
FIGURE 1-4. Large Midwest Cluster Model Calibration 1-28
FIGURE 1-5. West Coast Cluster Model Calibration 1-29
FIGURE 1-6. East Coast Cluster Model Calibration 1-30
APPENDIX J
FIGURE J-l. Texas Gulf Cluster 1985 Sulfur and Material Balance J-68
XX3.V
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I. EXECUTIVE SUMMARY
A. INTRODUCTION
This report summarizes a study performed for the Environmental
Protection Agency, which was part of a three-phase program undertaken in
parallel using a similar conceptual approach and data base. The other two
studies are entitled, "The Impact of Lead Additive Regulations on the
Petroleum Refining Industry" and "The Impact of SO Emission Controls on the
X
Petroleum Refining Industry", published as EPA report numbers EPA- ^50/3-76-Ol6a,b
and-EPA-6oO/2-76-l6la,"b, respectively. Significant synergy of data gathering,
scenario development, computer simulation time and subsequent analysis was
achieved by performing the three separate studies as part of an integrated
work program. However, the combined cost of implementing all three
regulations cannot be obtained by direct summation of the results of the
three individual reports.
Initial work on this program began in late 1973. An interim Phase I
report was published in May, 1974, entitled "Impact of Motor Gasoline Lead
Additive Regulations on Petroleum Refineries and Energy Resources - 1974-
1980, Phase I", EPA report number 450/3-74-032a. In this Phase I study,
the U.S. refining industry was simulated as a single composite model which
allowed a rapid overview analysis, but lacked in the desired level of
precision.
Accordingly, a more detailed simulation of the U.S. refining industry
was developed via a "cluster" model approach which was used in this three-
phase effort. This project included collection and collation of an exten-
sive base of refinery data supplied by the Bureau of Mines and individual
oil companies which was used to achieve satisfactory calibration of the
cluster models. It is felt that the development and calibration of the
cluster models represent a significant achievement in the area of refinery
simulation.
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In the present report, several scenarios are developed to describe how
the petroleum refining industry will likely operate for the next decade,
with and without possible regulations controlling the sulfur level of un-
leaded gasoline to either 100 ppm or 50 ppm, thereby reducing sulfate
emissions from automobiles employing catalytic converters. The report then
summarizes the detailed planning assumptions required to execute the task,
along with the methodology used to develop these assumptions. The primary
study results are then presented herein, defining the impact of control of sulfur
in unleaded gasoline in terms of capital investment requirements, increased
refining costs per gallon of unleaded gasoline, and energy penalties.
A complete presentation of planning assumptions, calculational methods, and
study results is contained in the appendices of Volume II of this report.
B. SCOPE AND APPROACH
The objective of this study is to determine the impact on the petro-
leum refining industry of a limitation on the sulfur content of unleaded
gasoline (a) to an average level of 100 ppm and (b) to an average level of
50 ppm.
The specific goals of the study are to determine for the period through
1985 the impact of the control of sulfur content of unleaded gasoline in
terms of (a) capital investment requirements; (b) composite increase in
refining costs per gallon of low sulfur unleaded gasoline, including
return on capital, manufacturing cost, and yield losses; (c) increased crude
oil requirements; and (d) net energy penalties, reflecting increased crude
oil requirements less the heating value of increased refinery byproducts
such as liquefied petroleum gases (LPG).
In the study, limitations of present and future refinery configurations
are taken into consideration. However, considerations outside the
scope of the study include availability of capital requirements, impact
upon the competitive structure of the industry, ability of the construction
industry to meet the associated refinery construction needs, and costs of
distribution and marketing of low sulfur unleaded gasoline. The study focused
upon the large, complex refineries processing about three-fourths of the crude
oil refined in the United States. The impact upon the small refineries
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comprising over half of the number of U.S. refineries has not been fully
assessed. On a relative basis, the penalties to the small refiner probably
exceed those reported herein.
In approaching this problem, it was recognized .that there are many
complex interactions in the petroleum refining industry. Also, there is
a necessity for compromises between various process routes for making low
sulfur unleaded gasoline, including consideration of their capital invest-
ments and manufacturing costs. Therefore, a standard analytical tool of
the petroleum industry was applied to this problem, computer refinery model
simulation with an associated linear programming (L.P.) optimization
algorithm. This provided an assessment of the impact of the control of
unleaded gasoline sulfur content with an optimal, minimum cost selection
of processing and blending schemes to achieve this end.
Although this analytical method has been used by the petroleum
industry for more than a decade for studies of individual refineries, its
use in simulation of the entire U.S. refining industry has been limited.
Therefore, one of the requirements of this program was the development of
a methodology for industry-wide simulation, collection and utilization of
a data base to confirm the utility of this methodology, and definition of
a means to utilize model results to determine national implications of a
proposed policy. Equally important was the careful assessment of the
planning assumptions regarding the constraints which may be imposed on the
petroleum refining industry over the next decade. In all of these
activities, Arthur D. Little, Inc., cooperated extensively with representa-
tives of the Environmental Protection Agency and with members of a task
force comprised of representatives of the American Petroleum Institute (API)
and the National Petroleum Refiners Association (NPRA). As a result of these
efforts, the utility of the model in faithfully representing the likely
behavior of the petroleum refining industry over the next decade was greatly
enhanced.
The modeling approach developed in this study provided for a specific
simulation of the existing U.S. refining industry, processing domestic
crude oils, including Alaskan North Slope crude oil, to the extent available.
Any additional crude oil required to meet petroleum product demand was
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assumed to be imported. Two simulation models, called "grassroots models",
were developed to provide for any new refining capacity which would be re-
quired to meet product demands in 1980/1985. The grassroots model for the
western U.S. used North Slope crude oil, whereas a separate grassroots
model for the eastern U.S. used imported oil.
The existing U.S. refining industry was simulated by six individual
computer models, constructed to represent clusters of three refineries
each in six geographical areas of the United States. These cluster models,
therefore, represented refineries typical of the refining industry in terms
of crude oil type, processing configuration, and product slate. They
ranged in crude oil capacity from 48,000 to 350,000 bbls/day. To ensure
that the cluster models adequately represented the industry, an extensive
data base on these 18 refineries was collected and analyzed. Processing
yield and property data was assimilated to ensure adequate representation
of the refinery processes and blending operations. Finally, each cluster
model was calibrated by comparison to the extensive data base.
In addition, a methodology for scaling up the results of the cluster1
models to the entire United States was developed, including these 18
cluster model refineries as well as atypical refineries. In a comparison
with 1973 Bureau of Mines data, the most recent year for which complete
information was available, the total petroleum products output and crude
oil consumption predicted by the model agreed with Bureau of Mines data
within 2%. This scale up technique allows assessment of the national impact
for the four specific goals of the present program, including an estimate
of the impact on small refiners.
Several planning assumptions were required; each of these required
auxiliary studies of considerable detail, because of the importance of
these planning assumptions to the study results.
Since the difficulty of controlling the sulfur content of unleaded
gasoline is dependent on the nature of the crude oil being refined,
a separate study was made to determine the types of crude oil to be proc-
essed by the U.S. refining industry over the next decade. Estimates of
domestic crude oil availability were made, including quantity and disposi-
tion of Alaskan North Slope and offshore fields. Also, estimates of
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worldwide crude oil production and disposition were made, taking into
account future product demand in Europe, Japan and the United States in
terms of product type and sulfur level requirements. Likely production
rates from the North Sea, OPEC countries, and Far East countries, including
China, were included in this analysis, as .was the likely availability of
non-oil energy sources such as coal and nuclear power. When more than one
future scenario for the next decade was likely, sensitivity studies
were included in the current program to determine the effect of this
uncertainty on the study results.
Since the cost of controlling the sulfur content of unleaded gasoline
depends directly upon the demand for unleaded gasoline and indirectly upon
the demand for other petroleum products, a separate forecast was made of
petroleum product supply/demand for the next decade. This forecast in-
cluded an evaluation of the demand for products by individual end-use
sector, including the effects of non-petroleum energy sources, conser-
vation, import levels, expanded petrochemical demand for certain products,
and the future course of governmental regulation in improving energy self-
sufficiency . for the U.S. Because of the uncertainties in this area,
sensitivity studies were included to ensure that these uncertainties did
not influence study results.
The impact of any potential regulation also depends upon certain key
product specifications on the primary product under control as well as
other major refinery products. Present and possible future octane require-
ments on unleaded gasoline were evaluated. Projections were also made of
the future sulfur level requirements of residual fuel oil. To assist in
this evaluation, field interviews were conducted with East Coast utilities,
accounting for over 90% of the utility fuel oil consumption on the East
Coast. Again, certain sensitivity studies were required to define the
effects of uncertainties in projections on the study results.
Several other significant assumptions were made in the execution of
this program, which are discussed in detail in the following report.
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C. CONCLUSIONS
1. Calibration Summary
In order to simulate the existing U.S. petroleum industry, six
cluster models were developed to describe the regional characteristics of
the refining industry and the processing configurations typical of the
industry. Each of these six cluster models represented a cluster of three
similar, existing refineries in the United States.
A critical component of the model development was to ensure that
these models effectively represented the refineries as well as the section
of ,the United States containing the refineries. Therefore, an extensive
calibration effort was undertaken by Arthur D. Little, Inc., in collabora-
tion with representatives of the Environmental Protection Agency (EPA) and a
task force of the American Petroleum Institute/National Petroleum Refiners
Association.
Data on raw material intake, fuel consumption, and product outturns
for each of the refinery clusters and for regions of the U.S. containing
these clusters were furnished by the Bureau of Mines. Proprietary operating
data on these refineries were compiled and combined for each cluster by
representatives of the EPA. Processing information was obtained from
sources in the petroleum industry. Using this processing information the
individual cluster models were run on the computer, and compared with the
industry data. This task was continued until each cluster model was
calibrated with the industry data.
The results of these calibrated cluster models were then scaled up to
determine the accuracy with which the refining districts in the U.S. were
described. In Figure 1 is shown the deviation of the model predictions
from the total raw material intake for the several Petroleum Allocation for
Defense (PAD) districts in the U.S. As noted therein, the maximum deviation
was 6.8% (PAD V), and the deviation from the total U.S. raw material intake
was 1.0%. PAD IV (less than 5% of U.S. crude oil capacity) was not simu-
lated by a cluster model, but was included in the scale up method. Thus, as
a result of this extensive calibration effort, the cluster models demon-
strate an excellent ability to simulate the existing U.S. petroleum refining
industry, using processing information describing individual refinery units.
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P.A.D. Ill
0.1% DEVIATION
P.A.D. II
0.7% DEVIATION
P.A.D. V
6.8% DEVIATION
P.A.D. I
0.2% DEVIATION
U.S. Total Deviation = 1%
*Not simulated, but included in scale-up
FIGURE 1. AGREEMENT OF MODEL PREDICTION WITH 1973 B.O.M.
TOTAL REFINERY RAW MATERIAL INTAKE DATA
(Area on chart represents percentage of total U.S. refinery
intake by P.A.D. District)
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2. Qualitative Study Results
Gasolines produced in the U.S. today have an average sulfur level of
around 400 ppm. The primary source of this sulfur is gasoline produced
from the fluid catalytic cracking (FCC) unit. Although gasolines from
coking units tend to have higher sulfur levels than FCC gasolines, the
volume of coker gasoline produced is significantly less than the volume of
FCC gasolines produced.
If refiners are to manufacture unleaded gasolines with sulfur levels
of 100 ppm or 50 ppm, they must reduce the sulfur level of the FCC gasoline.
The choices available are desulfurization of the feed to the FCC unit or
direct desulfurization of FCC gasoline. Desulfurization of FCC feed often
cannot remove desired amounts of sulfur if the sulfur level of the FCC feed
is high, whereas direct desulfurization of FCC gasoline can remove virtually
all of the sulfur. However, FCC feed desulfurization does allow higher
conversion and improved product selectivity in the FCC unit. The octane,
number of FCC gasolines tends to increase slightly as conversion increases
and this is another benefit of FCC feed desulfurization. Direct desulfuri-
zation of FCC gasoline, however, results in a reduction of the clear octane
levels of this gasoline component as a result of the saturation of higher
octane olefinic compounds into lower octane paraffinic compounds (associated
with the desulfurization process). This results in increased requirements
for catalytic reforming to make up the lost octane. Therefore, the pre-
ferred route to manufacture low sulfur, unleaded gasoline is by FCC feed
desulfurization if this can achieve the desired sulfur level in the unleaded
gasoline pool.
The results of this study indicate that those refiners who process
very high sulfur crude oils will probably have to use the direct desulfuri-
zation of FCC gasoline to produce unleaded gasolines with a sulfur level of
100 ppm or 50 ppm. The threshold level of crude oil sulfur which differen-
tiates between the two choices is not clearly defined since it will depend
on the amount of FCC and coking capacity in any particular refinery. Of
the six cluster models studied, only the Large Midwest cluster required
direct desulfurization of FCC gasoline to manufacture 100 ppm gasoline and
both the Large Midwest and Texas Gulf clusters required this for the
manufacture of 50 ppm gasoline.
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3. Economic Penalties
The economic impact by 1985 on the U.S. refining industry for the
manufacture of low sulfur unleaded gasolines is shown in Table 1. This
shows estimates of the capital requirements to be 2.6 billion dollars for
the manufacture of 100 ppm gasoline and 4.0 billion dollars for the manu-
facture of 50 ppm gasoline. These capital estimates are on a first
quarter 1975 basis and the final capital requirements are expected to be
of the order of 7.0 and 10.4 billion dollars based on the timing of the
investments and forecasted inflation rates in refinery process construction.
The additional cost to the U.S. refining industry is estimated to be 0.78
cents per gallon of unleaded gasoline for 100 ppm gasoline and 1.63 cents
per gallon of gasoline for 50 ppm gasoline based on first quarter 1975
costs, relative to unleaded gasoline. This includes an annual capital
charge of 25% of the total additional capital required.
Figure 2 shows the estimates of the economic penalty in 1977, 1980
and 1985, and breaks down the cost into capital charge, operating costs
and crude and product penalties. This illustrates a lower cost in 1977
and 1980 because high sulfur gasoline components have to some extent been
blended into leaded grades of gasolines. However, by 1985 when 100%
unleaded gasoline production was assumed, the estimated full cost of
sulfur removal emerges.
These estimates have been based on the scale up of the results from
eight different refinery LP models which blended the loxj sulfur gasoline
to exactly 100 ppm and 50 ppm. They therefore represent estimates of the
economic penalties for manufacturing gasolines with average sulfur levels
of 100 ppm and 50 ppm. They do not represent the penalties for manufactur-
ing gasolines with maximum specification of 100 ppm and 50 ppm. The
penalties for manufacturing gasolines with maximum specifications of
100 ppm and 50 ppm have been estimated assuming that average blending
targets of 80 ppm and 40 ppm would be required to ensure the maximum
specification is met. The estimated capital requirements increase to 3.2
and 4.4 billion dollars and the economic penalties relative to unleaded
gasoline increase to 1.12 and 1.99 cents per gallon of gasoline for the
manufacture of gasoline meeting 100 ppm and 50 ppm maximum specifications,
respectively.
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Table 1. ECONOMIC PENALTIES FOR THE MANUFACTURE OF
LOW SULFUR UNLEADED GASOLINE BY 1985
Capital required — billions of dollars
Non-inflated (1Q 1975 basis)
Inflated
Total economic penalty relative to unleaded gasoline
Cents per gallon of
low sulfur unleaded gasoline
(1Q 1975 basis)
100 PPM
(average level)
gasoline
2.6
7.0
0.78
50 PPM
(average level)
gasoline .
4.0
10.4
1.63
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1.5
1.0
CENTS
PER
GALLON
LOW
SULFUR
UNLEADED
GASOLINE
0.5
KEY:
CRUDE AND PRODUCT
PENALTIES
OPERATING COSTS
CAPITAL CHARGE
0.30
0.21
0.02'
\ 0.04V
WA
0.44
0.05
1.11
0.10
100 ppm 50 ppm
1977
100 ppm 50 ppm
1980
1.63
0.78
0.08
0.15
100 ppm 50 ppm
1985
FIGURE 2 ECONOMIC PENALTY FOR THE PRODUCTION OF LOW SULFUR UNLEADED GASOLINE
RELATIVE TO UNLEADED GASOLINE
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4. Crude Oil and Energy Penalties
The estimates of the crude oil and energy penalties for manufacturing
low sulfur unleaded gasoline are shown in Table 2. Relative to unleaded
gasoline, by 1985, it is estimated that the U.S. refining industry will
have to process additional crude oil approaching 80,000 barrels per day to
manufacture 100 ppm unleaded gasoline and nearly 350,000 barrels per day
to manufacture 50 ppm unleaded gasoline. However, the industry would
produce more LPG as a result of manufacturing low sulfur gasoline which
would partially offset this crude oil penalty. The net energy penalties
by 1985 are estimated to be 42,000 barrels per calendar day of fuel oil
equivalent for the manufacture of 100 ppm gasoline and 160,000 barrels
per calendar day for 50 ppm gasoline.
5. Sensitivity Studies
The manufacture of low sulfur, unleaded gasoline must be achieved by
reducing the sulfur levels of FCC gasolines. The sulfur levels in FCC
gasolines are themselves dependent on the sulfur level in the feed to the
FCC unit. However, the relationship between FCC feed sulfur level and
FCC gasoline sulfur level, differs considerably, depending on the source
of the FCC feed. To date, limited data are available on this relationship,
which is critical in determining the impact of manufacturing low sulfur
gasolines. A recently published report analyzed this relationship for
several FCC feedstocks and these relationships were used in calculating
FCC gasoline sulfur levels in the present study. However, applying the
results of such a study of a limited number of feedstocks to the whole of
the U.S. refining industry obviously has its shortcomings. Therefore, a
sensitivity study was done using different assumptions on FCC gasoline
sulfur levels. In the base study the percentage of the FCC feed sulfur
that was assumed to be present in FCC gasoline was approximately 4.7% (it
varied from a low of 3.1% to a high of 10.1%). The sensitivity study
examined the impact of assuming that FCC gasolines contained an average of
7.0% of the feed sulfur. •
The results of the sensitivity study are shown in Table 3. These
show a significant increase in the capital investment requirements and in
the economic penalty of 25% to 35%.
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Table 2. CRUDE OIL AND ENERGY PENALTIES FOR THE
MANUFACTURE OF LOW SULFUR UNLEADED GASOLINE a
1977
1980
1985
100 PPM gasoline
Additional crude oil required
thousands barrels per calendar day
Additional LPG produced
thousands barrels per calendar day
Net energy penalty
thousands barrels per calendar day
of fuel oil equivalent
50 PPM gasoline
Additional crude oil required
thousands barrels per calendar day
Additional LPG produced
thousands barrels per calendar day
Net energy penalty
thousands barrels per calendar day
of fuel oil equivalent
6.9 27.8
5.8
3.3
10.9
5.7
7.1
13.1
18.1
88.7
23.0
68.3
78.7
53.2
42.1
343.2
244.3
160.2
aRelative to unleaded gasoline
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Table 3. EFFECT OF INCREASED FCC GASOLINE SULFUR LEVELS
ON THE 1985 ECONOMIC PENALTY FOR MANUFACTURING
LOW SULFUR, UNLEADED GASOLINE
FCC sulfur distribution
Capital requirement
billions dollars
(10. 1975 basis)
Economic penalty
cents per gallon
low sulfur gasoline
(relative to unleaded gasoline)
(1Q 1975 basis)
100 PPM Gasoline
Base
Case
4.7% av
2.6
0.78
Sensitivity
Case
7.0%
3.3
1.02
50 PPM Gasoline
Base
Case
4.7% av
4.0
1.63
Sensitivity
Case
7.0%
5.5
2.16
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6. Other Major Implications
The choice of six different cluster models to represent the existing
U.S. refining industry was made to provide a reasonable representation of
the different types of refineries operating today. Over 80% of the U.S.
refining capacity has been represented in the cluster models. However,
no cluster model was constructed which could be considered representative
of the small refiner (less than 50,000 barrels per day), nor would such a
model be sufficient to a study of the impact on small refiners. These
refiners represent less than 20% of total U.S. refining capacity and any
understatement of their penalties will not significantly affect the overall
conclusions. However, the production of low sulfur gasolines could have a
significant impact on the smaller refiner. He may not have the wide choice
of blending components available to the larger refiners and little, if any,
existing treatment equipment. Because of the economies of scale the unit
cost to the small refiner of manufacturing low sulfur, unleaded gasoline
could be appreciably higher than those indicated in this study. This
could have a significant impact on the competitive structure of the re-
fining industry.
An alternative method of direct desulfurization of catalytic cracker
gasoline was examined, wherein the FCC gasoline was split and only the
heavy fraction desulfurized. The limited data available suggests that
this method would remove 70% to 80% of the sulfur in the FCC gasoline.
At the same time it would avoid having to hydrotreat the lighter, olefinic
fractions in the FCC gasoline, which result in substantial loss of octane.
Since the data available on sulfur distribution within FCC gasolines for
various crude oil types is limited, it is difficult to suggest an optimal
scheme which would achieve the correct balance between sulfur removal and
octane loss. However, refiners who must desulfurize FCC gasolines (because
FCC feed desulfurization will not meet the required sulfur level) will
undoubtedly consider this alternative method of desulfurizing FCC gasolines
The more conservative approach of desulfurizing the whole FCC gasoline with
subsequently large octane losses has been assumed in the study because of
lack of available data on the alternative method. The capital, economic,
and energy penalties estimated for the manufacture of low sulfur gasoline
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therefore may be conservative, since they may be reduced somewhat by this
alternative method of FCC gasoline desulfurization.
D. RECOMMENDATIONS FOR FURTHER ACTION
In order to assess more fully the impact of manufacturing low sulfur,
unleaded gasoline, several areas are worthy of more consideration than
possible with this study:
1. The relationship between FCC feed sulfur and FCC product
sulfur level should be refined, particularly for gas oil
derived from North Slope crude oil. With this information,
additional model runs could be undertaken.
2. Similar information should be ascertained for delayed coking
units.
3. The distribution of sulfur and the octane loss upon desulfuri-
zation of FCC gasoline fractions should be refined for the
crude oil types in the model simulation. With this information,
additional model runs could be undertaken to estimate industry
impact using selective desulfurization of FCC gasoline
fractions.
4. The impact of sulfur control should be assessed more fully
for the small refiners processing less than 50,000 barrels
per day. Such studies should examine the economic impact on
the refiners as well as the likely effect on the competitive
structure of the indust-ry.
5. Costs of distribution and marketing of low sulfur, unleaded
gasoline should be assessed to determine if they differ from
analogous costs of unleaded gasoline.
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II. STUDY BASIS
A. APPROACH
The objective of this study is to determine the impact on the petroleum
refining industry of a possible Environmental Protection Agency (EPA)
regulation requiring the reduction of sulfur content in unleaded gasoline
to either 100 ppm or 50 ppm, taking into consideration limitations of
present refinery configuration and potential grassroots refinery construc-
tion. Since the processing interactions in any single refinery are exceed-
ingly complex, and indeed even more complex for the industry as a whole,
such an assessment of the impact of this potential regulation could be
addressed by two possible approaches.
1 2
First, a survey could be conducted by sending out a questionnaire '
to individual refiners across the country, requesting an assessment of their
individual costs for meeting' the potential regulation. The results could
then be composited to define the cost to the industry. Although this is a
valid approach, it is often difficult to determine if the specific regula-
tion is being interpreted equivalently by all refiners across the country,
if they are using a similar analytical procedure, if they are using the
0
most efficient means of meeting the regulation, and if they are using a
common basis for cost estimation. This method, however, does have the
decided attribute of allowing each individual refiner to assess his unique
problems in meeting the regulation.
An alternative approach, used in the present study, is to simulate the
U.S. refining industry using computer models. Computer simulation of indi-
vidual refineries is well-known and. has benn practiced for over a decade.
Such a simulation normally utilizes a linear, programming (L.P.) model to
represent the individual process units and the process interactions of the
refinery. In the present study, however, simulation of a single refinery
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is not sufficient in that no single refinery can be said to represent the
entire refining industry. Therefore, eight computer models were used
simulating individual refineries which, when composited, would be typical
of the industry as a whole.
In the use of any L.P. model it is necessary to define the types of
crude oils available to the model, the individual process yields, the
streams that can be used to connect the processes, and the products pro-
duced from the refinery. The model then uses an optimization algorithm to
select the optimal combination of process units meeting the objective of
the study. If all product prices are given as input to the model, the model
will select that set of product outturns and processing configurations
which will maximize profit derived from the complex. However, this method
of L.P. optimization may not assure that the quantities of products being
produced from the complex meet the product demands of the region being
served by that refinery. If this happened in the actual operation of the
refinery, market forces would increase the prices of those products in
short supply and decrease those in excess supply, so that the entire
refinery operation would be adjusted with the product outturns just meet-
ing the product demands. In a computer simulation of a refining industry,
however, it is very difficult to predict those product prices which are
required to match the product outturns with the market demands. In the
present studies, an alternate approach was taken, wherein the product out-
turns from the refinery were fixed in order to meet the projected product
demands imposed upon the U.S. refining industry. Therefore, the L.P.
algorithm selected a set of processing configurations which allowed this
specified product demand to be met at minimum cost. However, it is neces-
sary that the problem being optimized be carefully constructed such that
the real-world constraints on the industry in meeting these minimum cost
objectives would be met, allowing a realistic simulation of the operation
of the industry. The definition and inclusion of these constraints is
an exceedingly important component of a study of the impact of any potential
regulation on the industry. This activity was greatly benefited by the
results of a Federal Energy Administration/National Petroleum Refiners
Association conference on refining industry modeling.
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In order to meet the constraints which would be imposed upon the re-
fining industry, comprised of nearly 300 individual refineries spread
throughout the United States, Arthur D. Little, Inc. (ADL), representatives
of the EPA, and a task force comprised of representatives of the American
Petroleum Institute and the National Petroleum Refiners Association selected
three refineries in each of six geographic regions to simulate the existing
U.S. refining industry. These six refinery models (cluster models) were
4
constructed and calibrated against the three actual refineries in each
region to ensure that the product blead flexibility and the processing
configuration flexibility did not exceed that available to these refineries.
In simulating these existing refineries over the next decade, the crude run
for the individual cluster models was not allowed to exceed the crude capac-
ity for those refineries being simulated. All new crude capacity required
to meet increased product demand was met by the construction of new, grass-
roots refineries.
In the construction of new grassroots refineries, the refining industry
.East of the Rockies was represented by a class of refineries feeding crude
oil typical of imported oil likely to be available in the coming decade.
Another simulation model was developed for grassroots refineries to be
constructed West of the Rockies, feeding Alaskan North Slope crude oil.
The product outturn from all of the existing refineries (cluster models)
and the new refinery installations (grassroots models) was then composited
to ensure that the overall product demand for the United States refining
industry was met.
It is also important that the major pr.oducts of the models meet appro-
priate quality constraints typical of the product quality demand by the
market place over the next decade. It some cases these product quality
definitions are implicit in the EPA ragulation under study, for example
the constraint that unleaded motor gasoline contain no more than 100 ppra
sulfur. In other cases, projections of future product quality requirements
are necessary in order that the study.be a realistic representation of the
industry over the next decade. Of particular importance in this regard is
the sulfur level of the residual fuel oil being produced by the industry.
Separate studies were made of these product qualities to determine the likely
levels associated with the industry ovsr the next decade, discussed in the
planning assumptions for the study.
-19-
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The impact upon the refining industry which is evaluated in the present
study includes: the capital investment requirements for the refinery to
aeet the potential regulation, the composite capital charge and operating
:ost expressed per gallon of low sulfur unleaded gasoline, the crude oil
penalty, and the net energy penalty associated with the regulation (includ-
Lng byproducts which have an energy value).
There are other considerations important to the determination of the
Lmpact of the regulation. These other considerations were beyond the
scope of the study and have not been evaluated in detail. For example, the
study determines the capital outlay squired to meet the potential regula-
tion by the industry. However, it is likely that, for many of the small
refiners in the country, the projected capital outlay will require financing
that may not be available to them at the present time. The availability of
capital required by the potential regulation is specifically beyond the scope
of this study, as was the impact of the regulation on the competitive struc-
ture of the industry. Also, some of the processing requirements needed to
meet the regulation require significant construction of heavy-walled
vessels. The impact of the regulations upon the construction industry,
including the fabricators and vendors, is also not considered to be within
the scope of the present study. The impact of the distribution and market-
ing requirement of the possible regulation is also not addressed herein.
B. CASE DEFINITIONS
The cluster model approach used ir. the present study of the possible
regulation requiring reduction of the sulfur content of unleaded gasoline
was also used in two other studies, which were conducted simultaneously:
(1) a study of a possible regulation requiring reduction of gaseous sulfur-
oxide (SO ) emissions from petroleum refineries, and (2) reassessment of
X ,
promulgated regulations relating to lead additive content of gasoline
(Federal Register, December 6, 1973; January 10, 1973). To conduct these
studies, six scenarios were created as possible modes of operation of the
refining industry, each of which were evaluated for 1977, 1980 and 1985.
These scenarios are:
Scenario A: Unregulated operatior and expansion of refining industry
to meet projected petroleum product deiand over the next decade.
-20-
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Scenario B: Manufacture of unleaded gasoline to meet projected
demands, with no lead restriction on the total gasoline pool or sulfur
restrictions on unleaded gasoline.
Scenario C: Phased reduction in the lead additive content of the
total gasoline pool, with no sulfur restrictions on unleaded gasoline.
Scenario D: Manufacture of unleaded gasoline with a maximum of 100
ppm sulfur, while reducing the lead content of the gasoline pool.
Scenario E: Manufacture of unleaded gasoline with a maximum of 50
ppm sulfur, while reducing the lead content of the gasoline pool.
Scenario F: Reduction of refinery gaseous sulfur-oxide emissions by
restrictions on the sulfur content of the refinery fuel, by restriction of
fluid catalytic cracker plant emissions, and by restriction of sulfur
recovery (Glaus) plant emissions, while meeting all the requirements of
Scenario C.
The complete definition of the computer cases to be run under these
several scenarios requires assumptions of crude intakes to the U.S. refinery
industry, processing configurations, and product outturns and qualities.
However, other planning assumptions -/hich have a possibility of occurring
over the next decade were also consilered. Variations in these assumptions
were investigated by a series of parametric runs, wherein the assumptions
were modified, one at a time, to reassess the impact on the industry. The
scope of these parametric studies is summarized in Table 4.
For the study of lead in gasoline (Scenarios A, B, and C) five major
parametric studies were undertaken. A basic premise of the study in the
base case is that unleaded gasoline will be produced by the industry
meeting 92 Research Octane Number (R-jN) and 84 Motor Octane Number (MON).
These specifications were set one octane number higher than the minimum
required by the EPA regulation to allow for refinery blending margin. To
evaluate the effect of producing even higher octane unleaded gasoline, two
parametric runs were conducted as summarized in Table 4.
Projections of the future sulfur content of residual fuel oil
consumed in the United States are between 1.1 and 1.4%. As a base
planning assumption, it was considered that the residual fuel oil
-21-
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Table 4 . PARAMETRIC STUDIES
Lead in gasoline
Low sulfur unleaded gasoline
Refinery sulfur oxide emissions
Unleaded gasoline RON/MON = 93/85
Unleaded gasoline RON/MON = 94/86
Residual fuel oil
sulfur level projection
Variation in product demand
Variation in imported crude slate
Residual fuel oil
Sulfur level projection
Variation in imported crude
slate
Sulfur distribution around
FCC unit
Method of FCC gasoline
desulfurization
Variation in imported crude
slate
Residual fuel oil, sulfur level
projection
Stack gas scrubbing
-22-
-------
being consumed in the United States would have a sulfur content of approxi-
mately 1.3%. Since this requires extensive desulfurization in the new grass-
roots refinery facilities, an additional parametric run at 1.1% sulfur
was conducted to ensure that study results were not being unduly influenced
by this assumption. It must be emphasized, of course, that the average
sulfur level of the fuel oil consumed by all sectors in the United States
is below even 1.1%, because of significant levels of imports of low-sulfur
fuel oil into the United States over the next decade.
In the base case studies defined by the above scenarios, it was assumed
that all petroleum products would grow at a level of 2% per annum. This is
a reasonable estimate of the growth of all petroleum products. However, it
is likely that each individual product will not grow at 2% per annum, so
parametric runs were undertaken to evaluate the impact of growth rates for
petroleum products other than 2%.
Arthur D. Little, Inc., has conducted a worldwide survey of crude oil
production and disposition to the various refining regions. This indicated
that two alternatives might be considered for the imported crude oil into
the East Coast region: (1) the imported oil could be of relatively high
sulfur content characteristic of Arabian crudes, or (2) the imported oil
may be of relatively lower sulfur level,characteristic of Nigerian crudes.
There is great uncertainty as to the demand and availability of various
crude oils in the United States and the ultimate selection of crude oils
would depend upon this uncertain demand as well as a variety of political
factors. The base case under the above scenarios assumed a predominately
Arabian-type imported oil. An additional parametric run was made with a
lower-sulfur oil being characteristic of the imported oil.
In the program to evaluate the impact of a reduction of sulfur levels
in unleaded gasoline .a similar set of parametric studies were required. As
indicated in Table 4, projections of the refinery residual fuel oil sulfur
level and variations in imported crud3 slate, discussed above, were also
considered.
The attention of the refinery industry to sulfur levels in gasoline in
general has been minimal over the last few decades because of the relative
-23-
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lack of importance of sulfur level as a product specification. Therefore,
there is limited information available regarding the sulfur level of some
of the high sulfur gasoline blend components from the various refinery
processes under various conditions of operation. One of the most critical
refinery units with regard to the suliur content of unleaded gasoline is
the fluid catalytic cracker (FCC). Sulfur levels of the products from the
FCC unit were obtained by consideration of available data on the FCC unit,
feeding various types of gas oil and under various types of operating
conditions. However, since there are uncertainties in the sulfur content
of gasoline from FCC units, a parametric run was instituted to evaluate the
impact of higher levels of sulfur in the FCC gasoline than was assumed in
the base case scenarios above. This, then, led to a range of potential
impact on the petroleum industry in consideration of both the base case
sulfur level as well as the new parametric case sulfur level.
Because the interest in the sulfur content of FCC gasoline has been
recent, the most efficient means of desulfurizing FCC gasoline has not been
determined. One attractive method of reducing the sulfur level in the FCC
gasoline is by hydrotreating the FCC feedstock. Another method is to
directly desulfurize FCC gasoline, requiring further reforming of the de-
sulfurized product. However, laboratory data has shown that the sulfur
distribution in FCC gasoline is heavily weighted toward the heavy gasoline
component. This suggests that only the heavy gasoline component need be
directly desulfurized, with the light FCC gasoline component going directly
into the gasoline blend stock. This method of desulfurization of FCC
gasoline could potentially reduce the impact on the refining industry of
meeting the possible sulfur regulation. Consequently, one parametric run
was made to determine the possible savings from this method of desulfurizing
FCC gasoline.
In the study of the impact of proposed regulations reducing the sulfur
oxide emissions from refineries, several parametric studies were also
undertaken. Variations .in the sulfur level of imported crude slate and
sulfur level of the product residual fuel oil are clearly of potential
importance in the impact of regulations reducing refinery sulfur oxide
emissions. These parametric studies, discussed above, were included in
this particular task.
-24-
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It is felt that the most likely means by which the refining industry
will meet possible regulations regarding sulfur oxide emissions is to
control the sulfur level of the refinery fuel system, to desulfurize the
FCC feedstock (thereby reducing FCC regenerator sulfur oxide emissions),
and to add tailgas cleanup processes to the sulfur recovery unit (Glaus
process). However, it is also possible that the emissions from the FCC
unit and the refinery fuel system could be reduced by the utilization of
stack gas scrubbing techniques, under extensive study for possible appli-
cation in the utility industry. Consequently, parametric runs were under-
taken to determine if the total impact of the regulations reducing sulfur
oxide emissions could be diminished by application of the utility-based
stack gas scrubbing techniques.
The present report deals with the impact: only of the possible regula-
7 8
tion reducing the sulfur content of unleaded gasoline. Companion reports '
have been produced which address the impact of the promulgated regulations
for lead additives in gasoline and the consequences of a possible regu-
lation to reduce sulfur oxide emissions from the petroleum refining
industry. All further discussions in the present report will address the
possible sulfur reduction regulation for unleaded gasoline.
C. PLANNING ASSUMPTIONS
This subsection defines the methodology used in developing planning
assumptions required for the present study, as well as identifying the
primary assumptions used. Because of the amount of detail required in
presenting these planning assumptions, only an outline of this information
will be presented below. Additional detail on all of the topics discussed
is presented in the appendices of Volume II of this report.
1. Crude Slate Projections
Projection of the crude slate available for the domestic U.S. refinery
industry depends upon a complex interaction of the production capability
of domestic U.S. crudes, the demand for petroleum products, the influence
of alternate energy sources within tae U.S., the worldwide availability
of crude oils and the demand worldwide for these same international crude
oils. Arthur D. Little, Inc., investigated the worldwide oil supply by
consideration of production potential from the North Sea, OPEC countries,
-25-
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the United States, South America and the socialist countries. Superimposed
upon this production potential was the investigation of world oil demand
forecasts and product demand forecasts for the major refining and consuming
areas, i.e., the U.S.A., the Caribbean, Western Europe, and Japan. These
product demand forecasts indicated, for example, a significant lightening
of the future product demand barrel in Europe, a similar but less signifi-
cant change in Japan, and virtually no change in the relative proportions
of demand within the United States. This led to a projection that there
would be a tendency for heavier crudes, including Nigerian, to be
attracted to the U.S.A. and lighter crudes, including Algerian, to be
attracted to Europe. Crude oil demanu for Japan included both imports
from the OPEC countries as well as probable production of Chinese crude
oil. In addition, the demand for sulfur content of various products was
investigated, allowing .an assessment of the likely movements of crude oils
of various sulfur levels into the various consuming regions in the world.
The assessment of all these factors in combination allowed projections of
the disposition of the various crude oils to the various refining regions.
Superimposed upon any such projection of the availability of crude
oils to the United States must be an evaluation of the proportion of the
U.S. refineries which can run sweet and sour crudes. Obviously, a refinery
designed for sweet crude operation can be redesigned to allow operation
with sour crudes, but this would be accomplished only if there is sufficient
price driving force between the sweet and sour crudes. For example, the
NPRA has evaluated the availability of refineries which depend upon low-
sulfur crude oil and have indicated that 9% of the refining capacity would
be unavailable if the industry were forced to substitute high-sulfur crude
9
oil for 20% of the sweet crude they are now running.
After consideration of all of these factors the planning assumption
for the crude oil to be run by the U.S. refining industry over the next
decade is summarized in Table 5. Additional detail on the crude oils run
to the refining industry in 1973 as well as the assumptions made in reducing
this number of crude oils to a smaller but still descriptive level is
contained in Appendices F and I. Additional detail on the methodology
utilized to obtain the projected crude run shown in Table 5 is presented
in Appendix A.
-26-
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Table5. U.S. REFINERY CRUDE RUN
(millions of barrels per calendar day)
Domestic
Alaskan North Slope
Other
Subtotal domestic
Domestic, percent of total
Imported
Arabian
African
South American
Other
Subtotal imported
Imported, percent of total
Total crude run
1977
-
9.4
9.4
70.7%
2.1
0.8
0.5
0.5
3.9
29.3%
13.3
1980
1.3
9.0
10.3
70.1%
2.7
1.3
0.4
-
4.4
29.9%
14.7
1985
1.5
8.5
10.0
61.0%
4.0
2.0
0.4
-
6.4
39.0%
16.4
-27-
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In addition to the overall crude slate to be processed by the U.S.
refining industry, a breakdown between the crudes being processed by exist-
ing refineries and those to be processed by new grassroots refineries over
the next decade must be specified. As described below, the existing U.S.
industry is simulated by means of six cluster models. The cluster models
process all available domestic crude over the time span of the ne.xt decade
and use imported crude as required to meet overall product demand. In
the base case, these imported crudes were assumed to be comprised pre-
dominantly of Arabian Light crude oil. The grassroots model on the West
Coast processes only Alaskan North Slope crude oil, because projections
indicate an ample supply of North Slope crude oil to meet the demands of
PAD District V. Note, however, that although some published reports
indicate an ample supply of North Slope crude oil for PAD District V (even
leading to planning for a pipeline transport of excess North Slope oil to
the Midcontinent), there is not a consensus among the major U.S. refiners
as to whether the North Slope crude will be sufficient to exceed the petro-
leum product demand in District V.
The crude oil to be processed in the new grassroots refineries East of
the Rockies is assumed to be imported oil, predominantly Arabian Light crude
oil. However, as noted above, a parametric run was made to investigate the
impact of importation of lower sulfur crude oils, such as Nigerian-type
oils. This parametric run would also be indicative of the result of the
introduction of Alaskan North Slope crude oil into the Midcontinent, used
in new grassroots refinery construction East of the Rockies.
2. U.S. Supply/Demand Projections
Prior to 1973, forecasting the oil demand in the United States was a
straightforward exercise, involving the application of historically deter-
mined growth rates to base year consumption data. However, the pattern
of continuous growth was interrupted by increases in foreign and domestic
oil prices, .the oil embargo, and a period of economic recession.
The general approach which has been used by ADL in product demand fore-
casting is to conduct an indepth analysis of total energy requirements by
individual end-uses, which are then matched with projections of supplies
-28-
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of basic energy sources, including oil, gas, coal, nuclear and hydro-
electric power. Because of the stimulus of high oil prices and considera-
tions of security of supply, non-oil energy supplies are developed as
rapidly as possible, limited only by technical, environmental, governmental,
and resource considerations on the one hand, and by end-use considerations
on the other, such as the nuclear contribution being limited to the base
load electric power generation. The availability of non-oil energy sources
are also evaluated in the light of the recent declines of United States
natural gas production, potential environmental constraints on exploitation
of coal reserves, inflation-caused reappraisal of the capital intensive new
energy forms such as oil shales, and failure to meet targets for nuclear
generation capacity. Furthermore, the product demands incorporate recent
changes in the structure of energy use within end-use sectors, such as
increased electricity consumption in the domestic sector and an increased
use of oil as petrochemical feed stock. Also included is the effect of
energy conservation. Of course, the impact of energy conservation is
difficult to assess from recent product demand data because of the simul-
taneous occurrence of economic recession, mild winters, and high oil prices.
In the current study the demand forecast for the United States refin-
ing industry was obtained by two different approaches. To facilitate the
task of combining the demand forecast with the scale up of the cluster
models (Appendix G), one simplistic forecasting approach was utilized which
led to a growth rate of 2% per annum for all products from the domestic
refining industry. However, to ensure that the study results were not
unduly influenced by this simplistic approach, parametric runs were under-
taken to evaluate the affect of a more sophisticated forecasting technique.
Each of these forecasting techniques will be discussed in summary form
here, while additional information of a detailed nature is presented in
Appendix B.
a. Uniform Product Growth at 2% Pet Annum -
Since the demand forecasts are intended simply to identify differences
in refining requirements among the six scenarios, the actual demand fore-
cast for each product may be relatively unimportant. Therefore, the
methodology, discussed in additional detail in Appendix B, contains three
key simplifying assumptions: (1) demand for all products grows at one
-29-
-------
uniform rate of 2% per annum between 1975 and 1985; (2) demand growth
occurs in equal increments throughout this forecasting period; and (3)
product imports are maintained at 1973 levels.
From the base year, 1973, product demand was forecast to realize zero
growth over 1974 and 1975, and average 2% per annum thereafter. Beyond
1975, published projections of oil demand growth rate range between 1% and
3.5% per annum, depending upon assumptions regarding oil prices, consumer
price sensitivity, conservation incentives, the availability of alternate
energy forms, and U.S. government policy. An estimate of 2% average annual
growth was selected to reflect generally slower than historical growth
rates resulting from higher oil prices, but assuming some optimism re-
garding the future economic growth of the country.
It is not likely that this demand forecast will closely approximate
the real growth of petroleum products over the next decade; however, this
was demonstrated in the present study to be an adequate assumption of
this product growth rate. To arrive at this conclusion, a parametric run
was made utilizing more detailed evaluations of product demand growth, the
methodology for which is discussed below.
b. Non-Uniform Petroleum Product Growth Rates -
In this more sophisticated projaction of product demand growth rate,
two sets of assumptions were used to develop a definitive range of energy
supply/demand balances. In one case, economic growth was assumed to be
somewhat slower than historical rates, but high enough to permit a rising
standard of living. Higher energy prices alone (but not governmental
action) are assumed to result in consumer energy conservation. Likewise
higher energy prices provide the incentive for the development of domestic
energy resources. A second case was defined in which economic and total
energy growth fall further off historic rates as a result of both strong
governmental action and higher energy prices. Government action in the
form of conservation incentives, selactive taxes on oil, import tariffs
on oil, etc., is taken to enhance the effects of higher prices in dampen-
ing demand and stimulating the development of domestic resources.
-30-
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In both of these categories, coal production and consumption, which
have declined in recent years, are expected to be rejuvenated as a result
of higher energy prices. After development of the coal industry, production
capacity will no longer be such a severe limitation on coal consumption
after 1980. Natural gas is assumed to be supply-constrained throughout the
forecast period, as production from the contiguous United States fields
continues to decline and is not offset by volumes from Alaskan sources
until very late in the forecast period. Nuclear power is expected to be
the most rapidly growing primary energy form, showing 25- to 30-fold
increase over the forecast period. Nonconventional energy sources, such as
solar, are not expected to play a significant role during the time frame of
this forecast.
The demand for energy was developed by breaking down the total energy
consumption into demand by various end-use sectors (e.g., transportation,
industrial, residential/commercial, etc.). At the end-use sector level, .
the historical growth trends in energy consumption were identified and
then modified in line with the basic assumptions described above. The
modification of historic growth rates took into account our expectations
of the impact of consumer conservation, government policy, energy prices,
and macro-economic conditions.
The breakdown of oil demand by product was accomplished by examining
the oil consumption patterns of specific end-use sectors. To project
future oil consumption patterns in the transportation sector, for example,
separate forecasts were developed for automotive, rail, marine, and air
transport, and the fuels were projected accordingly, taking into account
any efficiency improvements expected.
The product forecast from this analysis is shown in detail in Appendix
B. Imported petroleum products were assumed to be held constant in the
results of both of these demand forecasts at the 1973 level, as a result
of governmental policy considerations. It is therefore possible to
compare product imports with the domestic U.S. demand to arrive at the
domestic refinery demand for the next decade. These refinery production
expectations were used in the LP model studies.
-31-
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c. Gasoline Grade Distribution -
For both of these demand forecasts, it is necessary to project the
gasoline grade requirements over the next decade, under the scenarios
pertaining to lead regulations. By consideration of the expected growth
rate of introduction of new cars (requiring unleaded gasoline),. new car
imports, and automotive distribution by weight, the grade distribution
under these scenarios was projected as defined in Table 6.
3. Key Product Specifications
The definition of future product specifications is quite important
to the successful operation of the cluster and grassroots models. For
example, in the study of sulfur regulations on unleaded gasoline, one of
the common methods to lower the sulfur content is to hydrotreat the
fluid catalytic cracker (FCC) feed stock. When this hydrotreating is
accomplished, the sulfur level of all of the FCC products are diminished
(not only the sulfur level of the FCC gasoline), including the sulfur level
of blending components in the fuel oil pool. To actually represent the
cost of sulfur reduction, therefore, a specification must be placed to
prevent the fuel oil pool sulfur level from changing. Hence, in any
study of the impact of a potential regulation on the refining industry,
accurate definition of the product specifications for all of the major
petroleum products must be considered in order that the computer model
operate in a fashion which would be realistic in terms of petroleum in-
dustry flexibility or market demand.
The importance of economic factors in the determination of petroleum
product specifications is well known. For example, there is usually a
price premium associated with the lower sulfur levels of heavy fuel oil.
In addition, there are performance requirements for certain product
specifications, such as the distillation and volatility characteristics
of motor gasoline. In recent years, however, the impact of governmental
regulations on the specifications for petroleum products has become in-
creasingly pronounced, such as a regulation which.would specify the
sulfur level of unleaded motor gasoline. Hence, an assessment is re-
quired of the likely future course of governmental regulations on
major products over the next decade.
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Table 6. GASOLINE GRADE REQUIREMENTS BY PERCENT
Grade Distribution %
A. No lead regulations
Premium (100 RON)
Regular (94 RON)
Unleaded (92 RON)
B. Unleaded with no lead phasedown
Percent of pool
Premium
Regular
Unleaded
C. Unleaded with lead phasedown3
Promulgated lead
phasedown pool
average, grams/gal.
Allowable grams of
lead per gallon of leaded gasoline
1977
PAD I II III IV V
27 16 25 13 38
65 76 68 80 52
8 8 7 7 10
15 5 13 3 22
54 63 56 66 42
31 32 31 31 36
1.0
1.74
1980
I II III IV V
33 22 31 19 44
64 75 67 79 52
33224
41315
37 39 38 40 31
59 60 59 59 64
0.5
1.66
1985
1 II III IV V
40 29 38 26 50
58 69 60 72 48
2 2 2 2. 2
00000
00000
100 100 100 100 100
b
b
U.S. average
1977 1980 1985
24 30 37
68 68 61
832
12 3 0
56 37 0
32 60 100
1.0 0.5 b
1.74 1.66 b
I
LO
CO
I
asame distribution pattern used as in unleaded (Item B.)
b100% unleaded gasoline
-------
Complete identification of product specifications in the computer
models is contained in Appendix C. The highlights of the analysis and
the principal product specifications used are summarized here.
a. Motor Gasoline Specifications -
Among the most important product specifications for motor gasoline
in such a study is the octane number of the several grades, of motor
gasoline to be produced from the refining industry. Survey data on the
three grades of motor gasoline is shown in Table 7. In the modeling
studies of .the present investigation, the projected research and motor
octane numbers for regular, premium and unleaded gasoline, respectively,
over the remainder of the decade varied by region (Appendix C), but were
approximately 93/85, 99/91, and 92/84. Some studies ' may be interpreted
to indicate that the unleaded gasoline octane numbers shown in Table 7
will be increased over the next decade. Evaluation of the impact of pro-
ducing higher octane unleaded gasoline is included elsewhere .
* In Table 8 are shown selected results of a survey on unleaded gasoline,
broken down by district. It is apparent that the 92/84 specification on
the research and motor octane numbers used in this study describes a
large fraction of the United States marketing area, particularly since
MON is the limiting specification. The average sensitivity is somewhat
larger than used in the present study. This will make the study results
conservative in principle; in practice, it will have no effect due to MON
being the limiting specification.
The Reid vapor pressure of the gasoline pool, as shown in Table 7,
varies significantly between summer operation and winter operation.
12
Previous .studies have shown that the summer/winter operation can be
effectively simulated by means of an average Reid vapor pressure, re-
flective of both summer and winter operations. Consequently, in the
present program all gasoline specifications were .set at 10.5 Ibs. RVP.
13 -
It has also been reported that realistic distillation specifications
on motor gasoline must be used in computer simulations to ensure that the
model adequately represents the refining industry. Table 7 provides
historical data on distillation specifications for comparison with those
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Table 7. MOTOR GASOLINE SURVEY DATA
Research octane no.
Motor octane no.
Lead, g/gal
Reid vapor pressure, Ib.
Distillation, °F
20% evaporation
30% evaporation
50% evaporation
Grades of motor gasoline
Regular
Winter
1974-1975
93.4
86.1
1.58
12.0
129
152
202
Summer
1974
93.4
85.9
1.90
9.6
142
164
211
Premium
Winter
1974-1975
98.9
91.6
2.10
11.8
134
161
210
Summer
1974
98.9
91.5
2.32
9.7
146
172
217
Unleaded
Winter
1974-1975
92.3
84.0
0.02
10.9
139
166
214
Source: U.S. Dept. of Interior, Bureau of Mines, Petroleum Products Survey Motor Gasolines,
Summer 1974 and Energy Research & Development Administration,
BER C/PPS-75/1 - Motor Gasolines, Winter 1974-75.
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Table 8. MOTOR GASOLINE SURVEY, WINTER 1974-75
AVERAGE DATA FOR UNLEADED GASOLINE IN EACH DISTRICT
District name
Northeast
Mid-Atlantic Coast
Southeast
Appalachian
Michigan
North Illinois
Central Mississippi
Lower Mississippi
North Plains
Central Plains
South Plains
South Texas
South Mountain States
North Mountain States
Pacific Northwest
North California
South California
Average
Gr.,
ASTM
D287
°API
59.2
60.2
59.8
60.6
61.7
61.2
62.5
61.2
63.3
65.1
63.9
60.6
61.9
63.8
61.8
56.9
59.0
61.3
Sulf.,
ASTM
D1266
wt. %
0.029
.027
.024
.022
.033
.026
.024
.034
.052
.037
.033
.019
.038
.033
.010
.016
.044
.029
Octane number
RON
ASTM
D2699
92.8
92.5
92.5
92.9
91.9
92.3
92.0
92.5
92.0
92.0
92.0
92.0
91.5
91.5
92.7
93.2
92.5
92.3
MON
ASTM
D2700
83.9
83.8
83.7
84.5
83.9
84.3
83.8
83.8
84.3
84.3
84.6
83.7
83.4
83.6
84.7
83.9
83.5
84.0
R +M
2
88.4
88.2
88.1
88.7
87.9
88.3
87.9
88.2
88.2
88.2
88.3
87.9
87.5
87.6
88.7
88.6
88.0
88.2
RVP,
ASTM
D323
Ib
11.0
11.4
11.0
11.8
12.1
12.2
10.9
11.5
11.1
10.8
10.8
11.1
9.7
10.0
11.0
9.4
9.7
10.9
Source: Energy Research & Development Administration, BER C/PPS—75/1 — Motor Gasoline,
Winter 1974-1975.
-36-
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placed on gasoline products as follows. For premium gasoline the 150°F
distillation temperature is reached between 20 and 28% distilled overhead,
and the 210°F distillation temperature is reached between 42 and 54% dis-
tilled overhead. With regular and unleaded grades the 150°F distillation
point is reached between 20 and 30% distilled overhead, whereas the 210°F
specifications were identical to those of the premium grade gasoline.
b. Sulfur Content of Residual Fuel Oils -
As indicated above, one of the key product specifications required
to ensure that the model approximates realistic operation is the sulfur
level of the residual fuel oil. This specification is important because
the minimum cost approach of the LP model is to produce higher sulfur
fuel oils rather than adding desulfurization and Glaus plant investment.
This subsection summarizes the methodology and results of our forecast for
the U.S. fuel oil demand of differing sulfur contents. Of particular
emphasis here is the sulfur level of residual fuel oils produced from
domestic U.S. refineries, in contrast to the sulfur level of total U.S.
residual fuel oil demand, which is influenced by imported fuel oils.
To determine the allowable sulfur content of fuel oil to be burned
as refinery fuel (and not marketed) for each of the cluster models, an
evaluation was made of the existing state regulations on allowable SO
emissions. This analysis included an investigation of the regulations
applicable to the particular refineries being simulated in the cluster
models as well as those for the P.A.D. district the model was intended
to simulate. From this analysis of regulations, sulfur specifications
were determined for refinery fuel for each cluster model, ranging from
0.6% to 1.5% depending on the geographical location of the cluster model
simulation. A complete discussion of the methodology and results of this
analysis is presented in Appendix D.
The remainder of this section deals with the sulfur specification of
residual fuel oils manufactured and marketed in the U.S. (as distinguished
from fuel oils burned within the refinery or imported for domestic sales).
The forecast of the sulfur level of residual fuel oils manufactured
and marketed in the U.S. was based upon an analysis of the current air
quality regulations required by federal, state, and city agencies; the
-37-
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current status of these regulations, with particular attention to variances
being granted; the likely future trend of environmental regulation; and the
overall economic environment. In the course of this program, discussions
have been held with federal, state, and city environmental protection
authorities. A program of interviews with East Coast electric utility
companies, accounting for over 90% of the total fuel oil consumed by
East Coast utilities, was also conducted.
The current inflationary tendency in the United States and the U.S.
policy of energy independence could be contributory factors to the re-
laxation of air pollution regulations, particularly if the use of domestic
coal is to be emphasized. Tendencies to use higher sulfur fuel oils when
meteorological conditions are favorable and lower sulfur oils when
meteorological conditions are adverse will also play a potential role in
the average sulfur level of the fuel oil burned in the U.S. during the next
decade. On the other hand, environmental regulations now in effect will
not be rapidly changed. Most of the existing variances are temporary and
there will still be areas in the United States which are unlikely to grant
or renew exemptions.
The historic trend of the sulfur content of heavy fuel oils manufactur-
ed and marketed in the United States is shown in Figure 3. It is apparent
that the sulfur content of the lighter grade fuel oils has diminished
considerably in the last five years. However, the trend of the heavier
grade fuel oils is less evident. Table 9 shows the availability of residual
fuel oil by sulfur level for the year 1973 and it is apparent that the re-
finery residual fuel oil production in each of the PAD districts has been
at relatively high sulfur levels, between about 1 and 1.5% on average.
However, considerable quantities of imported low sulfur oil is marketed,
which allows the burning of fuel oils that will meet the statewide sulfur
regulations discussed in Appendix D.
Our projections of future sulfur levels for U.S. fuel demand stem from
the foregoing discussion and also draw upon more detailed information about
likely developments in individual states. From a consideration of such
factors it was projected that the sulfur content of the U.S. residual fuel
oil demand would be between 1.1 and 1.4%.
-38-
-------
Grade 4 Burner Fuel Oils
l.t
S 1.2
CJ
u
£ 1.0
I1 0.8
1
0.6
/
/
X
-X
M
^*A
x
>
^
k
\
s
"~*~<
/
/
1962 1964
1966 1968 1970 1972 1974
Grade 5 (Light) Burner Fuel Oils
1962 1964
1966 1968 1970 1972 1974
1962
Grade 5 (Heavy) Burner Fuel Oils
Percent
-• -» N
n bo c
£
O)
1 1.4
1 7
s
* 4
^
•-^
k-
~*
;
/
\
\
r~~*
k
S
S
r
\
\
1964 1966 1968 1970 1972 1974
1962
Grade 6 Burner Fuel Oils
1964 1966 1968 1970 1972 1974
Source: U.S. Dept. of Interior, Bureau of Mines, Petroleum Products Survey, Burner Fuel Oils, 1974
FIGURE 3 HISTORIC TREND OF HEAVY FUEL OIL SULFUR CONTENT AS PRODUCED
AND MARKETED IN U.S.
-39-
-------
o
Table9. AVAILABILITY OF RESIDUAL FUEL OIL BY SULFUR LEVEL, 1973
(Thousands of Barrels)
P.A.D. District
1
II
III
IV
V
U.S. Total
Fuel oil source
Refinery production
imports
Refinery production
imports
Refinery production
imports
Refinery products
Imports
Refinery production
Imports
Refinery production
Imports
Sulfur content, wt%
0-0.5
11,743
232,889
985
1,654
12,790
201
824
0
70,348
9,542
96,690
244,286
0.51-1.00
15,834
130,258
30,368
1,964
26,462
2,303
2,451
0
7,385
32
82,500
134,557
1.01-2.00
16,112
74,732
25,952
1,719
9,927
547
3,323
0
47,528
1,464
102,842
78,860
over 2.00
8,569
160,814
13,815
770
39,276
1,408
3,266
0
7,639
221
72,565
163,212
Total
52,258
598,912
71,120
6,107
88,455
4,459
9,864
0
132,900
11,259
354,597
620,736
Source: U.S. Dept of Interior, Bureau of Mines, Availability of Heavy Fuel Oils by Sulfur Level, Dec, 1973.
-------
For purposes of this study we assumed an overall U.S. average sulfur
content for residual fuel of 1.3 wt.%, representing maximum sulfur levels
of 1.4 wt.% east of the Rockies and 0.9 wt.% west of the Rockies. A
parametric analysis assumed a U.S. average residual fuel sulfur content of
1.1 wt.%, the weighted average of 1.2 wt.% sulfur east of the Rockies and
0.75 wt.% west of the Rockies.
The importance of testing the sensitivity of study results to the
overall U.S. average residual fuel sulfur level is highlighted .in Table 10
for the East of Rockies grassroots, Scenario A. It can be seen that the
impact on the industry simulation for variations between 1.4% (base case)
and 1.2% (parametric run) sulfur level of the East of Rockies residual fuel
oil pool is quite marked. As shown-in that table, the imported residual
fuel oil and the production from existing refineries must be added to
the production from new East of Rockies grassroots refineries in 1985 to
match the total residual fuel oil sulfur content on the East Coast. Be-
cause of the leverage effect of the small volume of residual fuel' oil
produced from grassroots refineries versus the volume available from imports
and existing refineries, the variation in sulfur content of residual fuel
oil produced in East of Rockies grassroots refineries is from about 0.6 wt.%
to 1.8 wt.% depending upon whether the East of Rockies pool is at 1.2 wt.%
or 1.4 wt.% (corresponding to overall U.S. pool averages of 1.1 wt.%
and 1.3 wt.%, respectively). Obviously the cost of desulfurization
capability in the grassroots refineries varies accordingly.
Other specifications on the residual fuel oil produced from the U.S.
refinery industry in addition to the sulfur content were, of course, re-
quired. These specifications are summarized in Appendix C.
4. Processing and Blending Routes
The computer simulation of the U.S. refining industry utilized
cluster models, chosen to represent the existing refinery structure, and
grassroots models, chosen to represent either new grassroots refinery con-
struction or major expansions of existing refineries. The cluster models
were allowed to add new downstream process equipment of reasonable
economic size. Accordingly, these models had essentially the same
processing and blending capability during the study period.
-41-
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Table 10. GRASSROOTS REFINERY FUEL OIL SULFUR PROJECTION - 1985
SCENARIO A - EAST OF ROCKIES ONLY
Total East-of-Rockiesa
Sulfur content
(wt%)
1.2
1.4
Fuel oil
(MBPD)
2,852
2,852
Imports
Sulfur content
(wt%)
1.28
1.28
Fuel oil
(MBPD)
1,797.7
1,797.7
Existing refineries^
Sulfur content
(wt%)
1.44
1.44
Fuel oil
(MB/CD)
561.3
561.3
Grassroots refineries^
Sulfur content
(wt%)
0.63
1.78
Fuel oil
(MBPD)
493
493
N)
I
aFuel oil produced in refineries plus imports
''Fuel oil produced and marketed in U.S.
-------
The unit yields and product properties were obtained from a variety of
sources, including the petroleum literature and process licensors. The
ability of the cluster models to represent actual refineries when using
these unit yields and product properties was confirmed in calibration
studies, discussed below. These same unit yields and product properties
were also used in the grassroots refinery simulations. A complete dis-
cussion of the unit yields and product properties available in the computer
program is contained in Appendix H.
Hydrogen generation in the cluster models was obtained solely from
refinery gas or imported natural gas. In the grassroots refinery, the first
option was also allowed, as well as the ability to generate hydrogen from
petroleum naphtha.
Coking capacity for the cluster refineries was maintained at a level
similar to that derived during the calibration runs. No coker capacity
was allowed to be constructed in the East Coast grassroots refinery, be-
cause of market demand considerations. Coker capacity in the West Coast
grassroots refineries for the several scenarios discussed above was not
allowed to exceed that available from Scenario C. There was a tendency for
coker capacity to be greatly increased as an inexpensive means to remove
sulfur for Scenarios D, E, and F, resulting in coke production exceeding
likely West Coast demand capabilities. Visbreaking and solvent deasphalting
were not allowed in the grassroots models.
In the cluster refineries desulfurization of atmospheric bottoms and
vacuum bottoms was not allowed, because the cluster refineries were in-
tended to be descriptive of the current operation of certain existing
refineries. In the grassroots refineries, both atmospheric and vacuum
bottoms desulfurization were allowed.
As discussed above, the properties of the products fron the fluid
catalytic cracking (FCC) unit are particularly significant to the assessment
of the impact of the possible EPA regulation. For reasons already de-
scribed, the sulfur distribution of the products from this processing unit
is not well defined at present. Moreover, FCC gasoline is a major source
of sulfur to the unleaded gasoline pool and the combustion of coke in the
regenerator is a major source of gaseous sulfur oxide emissions in the
-43-
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refinery. Consequently the sulfur distribution among several products of
the FCC unit were studied in a parametric run. The distribution shown
in Table 11 for the Large Midwest cluster illustrates the cases considered .
Additional detail on the product properties for the FCC unit as well as
the many other units used in the models are discussed in Appendix H.
Another unit critical to the success of a study of motor gasoline
properties is the catalytic reforming unit. A significant amount of effort
was expended in the development and confirmation of the yields and
properties of this particular unit. Yields for low pressure operation,
high pressure operation, and an average operation of reformers across the
industry were simulated in detail for several different cases to ensure
that the assumptions made in the yield patterns of this critical unit did
not significantly detract from the assessment of the impact of the possible
regulation under consideration. A detailed discussion of the reformer
evaluations is contained in Appendix E.
Another factor critical to the success of the impact study is the
blending octane numbers of reformate, FCC gasoline, etc., for the variety
of feedstocks, operating conditions, and gasoline pool compositions used
in the study. Because of their importance, blending numbers used in this
study were circulated to representatives of the API/NPRA Task Force assist-
ing in the study. For the purposes of the study of the sulfur level of
unleaded gasoline, there was good agreement between the blending numbers
utilized in the present study and the suggestions made by members of this
task force, as summarized in Table 12.
In the model, two distinct hydrogen systems were employed. A high
purity hydrogen system was fed by steam-methane reforming and was de-
livered to high pressure desulfurization and hydrocracking units. The low
purity hydrogen system was produced from catalytic reformer units and was
distributed to low pressure desulfurization units. Allowances were pro-
vided for interchanges from the high purity hydrogen system to the low
purity hydrogen system. In addition normal allowances for solution losses
and flaring circumstances were also provided. Careful analysis of this
hydrogen distribution system indicates that it is a reasonable simulation
of refinery systems and will be an adequate description for the purposes of
the study. If additional purification of the low purity hydrogen system
-44-
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Table 11. FCC UNIT SULFUR DISTRIBUTION
LARGE MIDWEST CLUSTER, 65% CONVERSION
Stream
H2S
Gasoline
Gas oil
Clarified oil
Coke
Percentage distribution of feed stock sulfur
Base, 1985
39.7
4.3
27.7
22.5
5.9
Parametric run
40.0
6.0
33.0
15.0
6.0
-45-
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Table 12. ILLUSTRATIVE BLENDING OCTANE NUMBER COMPARISON
(Clear Motor Octane Number)
Stream
90 Sev. reformate
100 Sev. reformate
FCC gasoline (full range)
Alkylate
ADL model
80.1
86.0
80.0
89.8
Ethyl
81-82
87-88
80
-
DuPont
82
87
79-80
-
Marathon
-
-
82-83
92-93
Citgo
-
87.1
79.9
88.7
-46-
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is required cryogenic units can be added without having a major impact on
the overall capital investment penalty associated with the potential regu-
lations.
5. Calibration of Cluster Models
The U.S. refining industry is composed of nearly 300 individual
refineries scattered throughout the country, each characterized by a unique
capacity, processing configuration, and product distribution. There are,
however, logical regional groupings of major refineries with similar crude
supply patterns, processing configurations, and product outputs. Therefore,
the cluster model approach was developed for this study, in which the
existing U.S. refining industry was simulated by the average operation of
three similar refineries located in each of six selected regions. The
selection of the three refineries as well as the six selected regions was
accomplished with the assistance of the API/NPRA Task Force cooperating in
this study. The most important criteria guiding the selection of these
cluster models were: (1) each cluster model was to represent, as closely
as possible, a realistic mode of operation, in that processing units were
to be of normal commercial size and that plants would be allowed normal
flexibility in regard to raw material selection and product mix, (2) the
cluster model crude slate, processing configurations, and product outputs
were to bracket as best as possible those variations peculiar to each
geographic region.
The final selection of refineries to be represented by the cluster
models is shown in Table 13.
PAD District I was simulated by three refineries in the Philadelphia-
New Jersey area with capacities ranging from 160,000 to 255,000 bbls/day.
PAD District II was characterized by two refinery clusters, one represented
by the Large Midwest cluster model simulating the Indiana/Illinois/Kentucky
district and processing high sulfur crudes. The Small Midcontinent cluster
was also used to represent PAD II, simulating refineries in the Oklahoma/
Kansas/Missouri district. This Small Midcontinent model was also used to
represent small refiners in PAD District II, as described in Appendix G.
PAD District III, which represents about 40% of the U.S. refining capacity,
was simulated by two models because of its overall importance and because
-47-
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Table 13. REFINERIES SIMULATED BY CLUSTER MODELS
PAD district
Cluster identification
Refineries simulated
1973
Crude capacity,
MB/CD
V
East Coast
Large Midwest
Small Midcontinent
Texas Gulf
Louisiana Gulf
West Coast
Arco - Philadelphia, Pa.
Sun Oil — Marcus Hook Pa.
Exxon - Linden, New Jersey
Mobil - Joliet, Illinois
Union — Lemont, Illinois
Arco — East Chicago, Illinois
Skelly - El Dorado, Kansas
Gulf Oil -Toledo, Ohio
Champlin — Enid, Oklahoma
Exxon — Baytown, Texas
Gulf Oil - Port Arthur, Texas
Mobil — Beaumont, Texas
Gulf Oil -Alliance, La.
Shell Oil - Norco, La.
Cities Service - Lake Charles, La,
Mobil — Torrance, California
Arco — Carson, California
Socat — El Segundo, California
160.0
163.0
255.0
160.0
140.0
135.0
67.0
48.8
48.0
350.0
312.1
335.0
174.0
240.0
240.0
123.5
165.0
220.0
-48-
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differing types of refinery configurations could be identified. The Texas
Gulf cluster was typified by a crude capacity exceeding 300,000 bbls/day
and heavy involvement in petrochemicals, lubes and other specialty products.
The Louisiana Gulf Coast cluster represented refineries between 174,000
and 240,000 bbls/day and processed a single source of sweet crude. PAD
District V was simulated by a West Coast cluster model and was represented
by refineries in the Southern California area. PAD District IV was not
explicity simulated because it represents less than 5% of the total U.S.
refining capacity. It was included in the scale up, however, as discussed
in Appendix G.
Additional detail on the development of the cluster model concept is
contained in Appendix F.
Upon completion of the development of the cluster refinery modeling
concept, an extensive calibration effort was undertaken by ADL with the
assistance of the Bureau of Mines, Environmental Protection Agency, and
the API/NPRA Task Force. A complete discussion of the calibration effort
is contained in Appendix I. Only the highlights of this effort will be
summarized here.
The annual refining surveys published in the Oil and Gas Journal were
used as the basic reference source for determing the cluster model process-
ing configurations, allowing simulation of those refineries listed in Table
13. This source also provided the processing unit capacity available in
these cluster refineries, used to limit the available capacity in the
cluster models.
The 1973 annual input and output data was furnished by the Bureau of
Mines for the aggregate of the three specific refineries comprising each
individual cluster model (Table 13). These data included the following:
(1) crude oil and other raw materials fed to the refineries, broken down
by individual state of origin for domestic crudes and by country of origin
for foreign sources; (2) statistics on fuel consumed for all purposes in
the refineries; and (3) all petroleum products manufactured by refineries
for the year.
Each individual oil company furnished EPA the following proprietary
data for 1973: (1) gasoline grade distribution and the associated octane
-49-
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levels and lead levels for each grade, (2) total gasoline volumes and
average sulfur contents, (3) crude slates and sulfur levels, and (4)
intakes and operating conditions on selected units. The EPA averaged
these data to obtain information representing the cluster models, and
supplied these data to ADL.
As summarized in Appendix I, four main areas were considered to compare
the degree of calibration to the cluster models. These were: (1) overall
refinery material balance (i.e., volume of the crude intake required to
balance specified product demands and internal fuel requirements), (2) re-
finery energy consumption, (3) processing configuration, throughputs and
operating severities, and (4) key product properties (e.g., gasoline clear
pool octanes, lead levels, etc.).
A selected result showing a portion of the calibration results for the
Large Midwest cluster is presented in Table 14. Shown here is the crude
intake, as specified by the Bureau of Mines data and industry data to pro-
vide a given product outturn, as well as a result of the computer model
simulation. Also shown is the energy consumption required for this crude
intake and product outturn, and a summary of the principle refinery process
operations. It is apparent that the agreement of the model prediction and
the data base for this Large Midwest cluster is excellent. Additional de-
tail on other clusters as well as other calibration criteria are contained
in the discussions of Appendix I.
6. Existing and Grassroots Refineries
The existing U.S. refining industry was simulated by means of the
six cluster models, as discussed above. New grassroots capacity was
required when atmospheric distillation requirements exceeded 90% of the
calendar day capacity listed in the Oil and Gas Journal for the specific
refineries being simulated by these cluster models. In practice, operation
at 100% of the calendar day capacity cannot be achieved due to unscheduled
refinery turnarounds, limitations on secondary processing capacity imposed
by product specifications, variations in crude slate, crude supply re-
strictions, regional and logistical constraints, and imbalances between
individual product output and market demand. The industry has historically
14
achieved about 90% of calendar day capacity , so this limitation was used
to provide a conservative assessment of the penalties associated with the
-50-
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Table 14. CALIBRATION RESULTS FOR LARGE MIDWEST CLUSTER
Material balances
Total crude intake MB/CD
Energy consumption
Purchased natural gas MB/CD (F.O.E.).
Total fuel consumption MB/CD (F.O.E.)3
Electricity MKWH/D
Processing summary
Catalytic reforming Intake MB/CD
severity RON
Catalytic cracking Intake MB/CD
conversion % vol.
Alkylation Production MB/CD
Coking Intake MB/CD
BOM Data
146.1
.2
8.1
843
Oil and gas
capacity MB/SD
32.7
-
55.0
-
13.4
15.8
Industry
data
145.5
-
-
-
Industry
data
27.8
90.7
51.2
74.9
11.4
13.6
Model
run
145.5
.2
8.4
545
Model
run
27.6
90.0
48.7
74.3
12.0
14.1
aExcludes catalyst coke
-.SI-
-------
potential regulation. However, since all penalties are reported as
differences between the various scenarios considered, a precise figure of
calendar day utilization is unnecessary.
To meet increased product demand and provide additional crude required
to manufacture low sulfur gasoline, an increase in crude run to each cluster
is required as the decade proceeds. The existing refining industry (cluster
model) is allowed to expand down-stream processing capacity as required
to meet these constraints. However, when the crude run reaches the limi-
tation of the atmospheric distillation capacity, the expansion of the
cluster model is no longer allowed, and new grassroots facilities must be
constructed.
The grassroots models used in this study represent either new, basic
grassroots refineries to be built in the United States over the next decade
or major expansions in crude distillation capacity in existing refineries.
Those major expansions of existing refining capacity which have taken
place within the last few years are often noted by new atmospheric distilla-
tion capacity, new tankage requirements, and frequently new or greatly
expanded production of refinery products which have otherwise been only a
minor component of total product outturn. An example of such major new
expansion is the production of large quantities of low sulfur fuel oil.
In any event, this type of new major refinery expansion frequently exhibits
relatively little interaction with existing refinery processing units, and
little additional flexibility for product blending over that of a refinery
built on a segregated grassroots basis. Therefore, any requirements for
distillation capacity in the industry were simulated by addition of new
grassroots capacity. The product outturn and therefore the crude run
required for this new grassroots capacity was chosen to be sufficient to
balance the product demand and product quality requirements for the United
States as a whole. New grassroots construction was simplified by consider-
ation only of a location typified as "east of the Rockies" and another
location typified as "west of the Rockies", each location with its own
crude slate as discussed in Appendix A.
The yields and product qualities for new capacity additions were
identical to those provided in the cluster model operation, with the
-52-
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exception of catalytic reforming, wherein all new capacity was assmumed to
utilize a yield structure and investment representative of low pressure,
bimetallic reformers.
The refinery fuel system for both the cluster models and the grassroots
models was constrained to meet environmental regulations typical of the
refining regions in which these models operated. A complete discussion of
the allowable refinery fuel sulfur level and the methodology by which it
was determined is contained in Appendix D.
7. Economic Basis for Study
The estimation of capital investments and operating costs for petroleum
processing units is difficult at the present time because of the rapid rate
of inflation and the long elapsed time that it takes to build a large and
complex petroleum refinery. Investment estimates were obtained by using
data from a variety of literature sources, such as the Oil and Gas Journal,
and by extensive discussions with process licensors and contractors. In
order to minimize the effect of future cost escalations on the cost
estimations, the investment estimates were made on a 1975 first quarter
basis. This investment estimate will be applicable for refineries which
were conceived, designed, equipment ordered, and constructed all within
the first quarter of 1975. Escalation of these costs are reported separately
in order to allow recalculation of these ultimate investments on other
inflation schedules if so desired.
Onsite capital investments were estimated by compositing the informa-
tion available from these several sources. The onsite process unit esti-
mates used in this study are typified in Table 15. Additional detail of
the specific information on capital investments is contained in Appendix H.
The primary purpose of the economic study was to determine the capital
investment and operating costs associated with the production of low sulfur
gasoline. Consequently economic penalties for the cluster models were
determined by comparing Scenario D versus Scenario C, for example for 100
ppm gasoline. Therefore, only the incremental downstream capacity re-
quired for Scenario D versus Scenario C was determined and costed. As part
of the analysis, charges were assessed for the utilization of spare, idle
capacity which was available in 1974 but was incrementally consumed at a
-53-
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Table 15. ONSITE PROCESS UNIT COSTS
Process unit
Atmospheric distillation
Vacuum distillation
Catalytic cracking
Catalytic reforming (low pressure)
Alkylation (product basis)
Isomerization - once through
Isomerization — recycle
Hydrocracking (high severity)
Naphtha hydrotreating
FCC/coker gasoline hydrotreating
Light distillate hydrotreating
Heavy distillate hydrotreating
Vacuum gas oil desulfurization (also FCC feed)
Atmospheric residual desulfurization
Vacuum residual desulfurization
Coking — delayed
Hydrogen generation — Methane $/MMSCF/SD
- Naphtha $/MMSCF/SD
Sulfur recovery (95% removal) - $/short tons/SD
~ Sulfur recovery (99.95% removal) - $/short tons/SD
Size basis, MB/SD
100
40
40
20
10
10
10
25
20
15
30
30
25
50
15
10
50
50
100
100
Investment, S/B/SD
1975, 1st quarter
165
185
925
800
1,400
620
1,240
1,400
235
320
230
250
370
775
1,500
930
230a
260a
25,000
50,000
a$/MSCF/SD
-54-
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faster rate for Scenario D than for Scenario C. Any processing unit
severity upgrading that was required was also costed. For example if
the severity of the catalytic reforming unit required was 100 RON in
Scenario D but was only 90 RON in Scenario C, then the incremental'cost
was charged to Scenario D for upgrading this existing catalytic reformer
capacity. To determine whether or not the catalytic reformer severity
needed to be upgraded, discussions were held with industry sources, who
estimated that approximately 25% of the existing catalytic reformer
capacity was already capable of 100 severity operation. Therefore the re-
maining 75% of catalytic reformers which were not capable of this mode of
operation required an upgrading cost if 100 RON severity were required.
Additional discussions of the method of calculation for spare capacity
utilization and severity upgrading for all the refinery processing units
is contained in Appendix E.
Associated with the onsite costs of incremental downstream capacity
in the cluster models is the cost requirement for offsite investment and-
working capital. As discussed in Appendix E, these costs were taken as
a constant 40% of the onsite costs for the cluster models.
For the grassroots models the coriplete refinery was costed as re-
quired for each scenario. For example, the capital cost for the grassroots
refinery in Scenario D was then compared to that of Scenario C to determine
the incremental costs associated with the potential regulation. In this
case the onsite process costs were determined in a fashion analogous to
that discussed for the cluster model. However, the offsite costs were
determined by the Nelson complexity factor approach and a separate assess-
ment of working capital requirements was made, at approximately 70% of the
total onsite capital investment. A summary of the items included is shown
in Table 16. The net effect of this method of calculation was that offsite
and associated costs (including working capital) were approximately 200-300%
of onsite costs. For these grassroots refineries the complete onsite plus
offsite refinery costs range from.about $2900 per barrel per day for a
low sulfur crude up to about $3500 per barrel per day for a high sulfur
crude, on a 1975 first quarter basis. An illustration of the investment
requirements for a grassroots refinery of the present study is shown in
Table 17.
-55-
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Ul
a^
i
Table 16. OFFSITE AND OTHER ASSOCIATED COSTS OF REFINERIES USED IN
ESTIMATING COST OF GRASS ROOTS REFINERIES
1st Quarter 1975 Basis
(% onsite cost)
Type of cost
Mainly complexity-related offsites, %
Utilities, safety, fire and chemical handling
Buildings
Piping, product handling
Site preparation, blending, roads and others
Subtotal, complexity-related
Other offsites, %
— Includes tankage, ecology and land
Total offsites
Associated costs
Chemicals and catalysts
Marine or equivalent facilities
Working capital
Other
— Includes training, spares, autos, telephone,
domestic water, cafeteria and recreation
Total associated
Refinery complexity3
3
61.0
14.0
40.0
23.0
138.0
87.0
225.0
6.0
20.0
70.0
20.0
116.0
4
51.4
9.8
26.0
15.8
103.0
67.0
170.0
5.0
15.5
70.0
20.0
110.5
5
46.2
8.2
21.4
13.1
88.9
59.0
147.9
4.5
12.8
70.0
20.0
107.3
6
41.0
6.6
16.8
10.3
74.7
51.0
125.7
4.0
10.0
70.0
20.0
104.0
7
39.2
6.2
15.6
9.4
70.4
48.0
118.4
3.8
8.8
70.0
20.0
102.6
8
36.9
5.6
14.1
8.3
64.9
44.2
109.1
3.5
7.8
70.0
20.0
101.3
9
35.7
5.2
13.2
7.6
61.7
42.0
103.7
3.3
6.8
70.0
20.0
100.1
10
34.0
4.7
12.0
6.7
57.4
39.0
96.4
3.0
5.8
70.0
20.0
98.8
See reference #17.
-------
Table 17. GRASS ROOTS REFINERY CAPITAL INVESTMENT
Location:
Crude processed:
Refinery complexity:
East of Rockies
Arabian Light
7.01
Scenario: C
Process unit
Atmospheric distillation
Vacuum distillation
Catalytic reforming
Catalytic cracking
Hydrocracking
Isomerization-recycle
Alkylation (product basis)
Hydrogen manufacture
(MMSCF/SD)
Desulfurization
Full range naphtha
Straight run distillate
Vacuum residue
Sulfur recovery and amine
treat (short tons/SD)
Throughput
(MB/SD)
231.7
100.1
52.2
47.4
26.6
11.5
14.9
62.1
62.9
26.4
21.1
366
Total onsite investment
Offsite and associated costs at 151.0% onsite
investment
Working capital at 70.0% onsite investment
Total cost
Investment/B/SD
Onsite investment
(millions of dollars)
28.1
12.5
36.5
42.0
32.2
13.8
17.8
13.3
9.4
6.7
27.0
9.4
248.7
375.6
174.1
798.4
3,446
-57-
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Operating costs were determined by a direct assessment, on a unit-by-
unit basis, of either the additional downstream processing requirements of
the cluster models or the complete refinery requirements for the grassroots
models. Catalysts and chemicals, cooling water and electricity were deter-
mined from the processing unit intakes themselves and tetraethyl lead was
determined as required to meet the gasoline blend requirements. Maintenance
and manpower assessments were determined on an off-line basis, i.e., they
were not determined by the computer model directly. Manpower requirements
were determined both for severity upgrading and for new unit construction by
examination of operating requirements of the particular units under consider-
ation. Maintenance costs were assessed at a level of 3% of onsite invest-
ments and 1.5% of offsite investments.
In addition a capital charge was assessed for new investment in any
processing unit, either in a cluster model or a grassroots model. The
capital charge was taken to be 25% of the total capital investment, which
is approximately 12% rate of return, on an after tax, discounted cash
flow basis. The same capital charge was applied to both the downstream
capacity additions in the cluster model and new grassroots facilities in
a grassroots model, on the philosophy that the amortization for both
types of investments must be approximately equivalent in the present
economic climate. A typical level of cash operating expenses (exclusive
of capital charge) for the grassroots refinery was approximately 80c per
barrel of crude capacity.
An assessment of cost escalations over the next decade was made to
reflect the actual capital investment which may be required in the time
interval in which the actual refinery construction will take place. Such
an escalation of costs can result from increases in the costs of refinery
equipment which outpace the general inflationary trend in the United
States. As a basis for this cost escalation, an approach similar to the
usual construction S-curve escalation analysis was conducted, in which the
annual escalation for the years 1975-1985 were taken to be 20%, 17%,
15%, 10%, 10%, 10%, 9%, 9%, 8%, 8%, 8%. Clearly, assessments of the
rate of cost escalation for the coming decade are highly intuitive and
will depend upon a varieity of factors, such as further increases in
foreign oil prices, general inflationary tendencies in the United States,
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and many others which are difficult to predict with any degree of precision.
Indeed, cost escalation now appears to be flat through 1975. Therefore,
the impact of the potential regulation on the refinery industry will be
summarized in the following body of the report both on 1975 first quarter
basis and on an escalated basis, with the above assumed escalation schedule.
8. Scale Up to National Capacity
In the cluster model approach, the U.S. refining industry has been
simulated by six individual cluster models, each cluster representing three
existing refineries in different regions of the United States. To repre-
sent the impact on the U.S. refining industry, it is necessary to scale up
the results of the cluster model analysis to a regional and a national basis.
From this estimate of the total production capability of the existing U.S.
refining industry, requirements of the new grassroots models are obtained
by subtracting existing capability from the total product demand of the
U.S. refining industry. Appendix G discusses the scale up method and the
derivation of product demands for grassroots refineries in detail.
The general method employed in scaling up data from the cluster runs
to the existing U.S. refining industry is to compare the gasoline outturn
of the region being simulated by the cluster model to that of the cluster
model itself. For example, the East Coast cluster represents the refineries
in PAD District I, so a scale up factor in 1973 of 7.127 is used, since
this is the ratio of gasoline production of District I to the gasoline
production of the East Coast cluster. However, the cluster model used
for PAD I is known to be typical only of the major gasoline producing re-
fineries in that region. Therefore, there is, by definition, a quantity
of atypical refining capacity which is not represented by the yields used
in the East Coast cluster model. Hence an estimate was made also of the
atypical refining capacity in PAD I, to be included as a component of the
scale up of the East Coast cluster model results to PAD I.
PAD II is represented by two cluster models. It has been assumed in
scale up that the Small Midcontinent cluster represents operations of the
Oklahoma/Kansas/Missouri district and that the balance of District II is
represented by the Large Midwest cluster. Similarly, in PAD III, it has
been assumed that the Louisiana Gulf cluster represents the Louisiana
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Gulf refining district and the Texas Gulf cluster represents the balance
of PAD III.
The West Coast cluster is assumed to represent the operation of PAD V.
PAD IV was not represented by a specific cluster model so that the total
refining capacity of PAD IV was similarly included as an atypical factor
in the scale up analysis.
The results of the application of this scale up method, when composited
for the total U.S. refining industry are shown in Table 18, for 1973. Here,
the crude consumption by the cluster models agrees with the Bureau of Mines
data to within about 2% and the total refinery intake agrees to within
about 1%.
The major refinery products agree with the Bureau of Mines data within
about 5%, with the exception of LPG (which was a swing product in the
computer runs) which deviates from the Bureau of Mines data by about 15%.
The total product outturn agrees with the Bureau of Mines data to within
about 2%. Therefore, it is felt that the model scale up method is cali-
brated well with the Bureau of Mines data for the purposes of the present
study, which emphasizes total energy penalties of the refinery and ad-
dresses itself to gasoline production capability. For other types of
studies, the scale up method could be further refined, if so desired, to
provide a closer match of the other minor products from the refining in-
dustry.
Model results for the study years of 1977, 1980, and 1985 were scaled
up using the atypical refining concept described above. In 1977 scale up
factors were based on meeting gasoline demand for the total U.S. For 1980
and 1985, however, the scale up factor approach was based on total crude
run in each cluster and the effective crude oil distillation capacity for
the region being simulated by that cluster. The scale up factors used
were calculated by making the crude run in each region equal to the effective
crude oil distillation capacity for that region, defined as 90% of the calen-
dar day rated capacity.
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Table 18. MODEL SCALE-UP COMPARISON, 1973
U.S. total input/output data, thousands of barrels
Refinery intakes/outturns
Intakes:
Crude oil
Butanes
Natural gasoline
Other
Total intake
Outturns:
LPG
Gasoline
Naphtha
BTX
Distillate fuel oil
Residual fuel oil
Other
Total outturn
Cluster
model
results
12,713.6
254.2
365.2
167.6
13,500.6
401.2
6,572.1
227.5
164.5
3,157.9
956.0
1,886.7
13,365.9
Bureau of
Mines data
12,430.7
219.8
439.2
281.3
13,371.0
349.8
6,572.2
234.7
156.7
2,992.8
971.5
1,849.7
13,127.4
Deviation of
model from
B.O.M. data (%)
2.3
15.6
16.8
-
1.0
14.7
0
3.1
5.0
5.5
1.6
-
1.8
-61-
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As discussed in Appendix B, the import levels of products were held
constant at the 1973 level for the coming decade. Therefore, after scaling
up of the cluster results, adding atypical factors, and adding import
levels, the product outturn from the grassroots refineries could be obtained
by difference from the forecast total petroleum products demand. The re-
sults showed that by 1980 seven new grassroots refineries at approximately
200,000 BPD each would be required in PAD Districts I through IV and two
new refineries would be required to meet PAD District V product demands.
By 1985, a total of fifteen new refineries were required for PAD District I
through IV and a total of three refineries were needed for PAD V.
The utilization of such scale up factors allowed a direct assessment
of the total energy penalties associated with each of the scenarios under
discussion, as well as an assessment of the operating costs required to
meet the possible regulation. However, capital investments were not
determined solely by a direct utilization of the scale up approach, be-
cause this approach does not weight sufficiently heavily the capital re-
quirements of the small refineries simulated by the Small Midcontinent
cluster. Therefore, an additional factor was utilized in a scale up for
capital costs, as discussed in detail in Appendix G. Such an approach
adequately includes the dollar cost to the small refiner as a component
of the overall cost to the industry, because his percentage of the total
cost is relatively small. However, it does not adequately address the total
impact on the small refiner nor the possible impact on the competitive
structure of the petroleum industry.
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III. STUDY RESULTS
A. BACKGROUND DISCUSSION
In the manufacture of gasoline, blending of different components is
required which, when mixed together, produce a product meeting the re-
quired specifications. Certain blending components have sulfur levels
much higher than others and it is particularly these components whose
sulfur levels must be reduced in order to supply a blended low sulfur
gasoline.
The two components normally found to have the highest sulfur levels
are those gasolines produced from the fluid catalytic cracking (FCC)
process and from the coking process. The sulfur level of these gasoline
components is primarily dependent on the sulfur level of the feed stream
to these processes. However, the relationship between the gasoline
sulfur level and the feed sulfur level is not always the same for feed
streams from different crude oil sources. Limited data is available on
this relationship, which is critical in a study of the impact of manu-
facturing low sulfur gasoline. A recent study conducted by Gulf Research
on the feed sulfur distribution to the products in catalytic cracking
units highlighted the differences between feed types. The percentage of
feed sulfur found in the gasoline varied from a low of 3.5% to a high of
9.5%. The assumptions with regard to sulfur distribution in FCC products
used in this study have been based on the work done by Gulf Research.
There is less information on the sulfur distribution in coking units.
However, the amount of coker gasoline in the gasoline blend is much lower
than FCC gasoline. Also, coker gasoline has been assumed to be split into
a light stream, which goes directly to gasoline blending, and a heavy
stream, which is fed to the catalytic reforming process and is therefore
desulfurized in the reformer feed hydrotreater. Hence, the impact of
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coker gasoline on the sulfur level of the gasoline blend is much less
than that of FCC gasoline, even though its inherent sulfur content is
higher than that of FCC gasoline in any given cluster model.
The sulfur content of straight run naphtha can also be high, but the
value is well known. Such naphthas are normally desulfurized before
blending in a low sulfur pool.
The sulfur level of FCC gasoline can be reduced by either desulfuriz-
ing the feed to the catalytic cracking unit or by direct desulfurization of
the FCC gasoline. The first method is usually preferable if it can reduce
the sulfur levels sufficiently to meet the required level in gasoline, be-
cause of the associated yield benefits of FCC feed hydrotreating. By contrast,
direct desulfurization of the FCC gasoline has associated disadvantages.
Desulfurization of whole FCC gasoline results in a significant reduction of
its clear octane numbers because high octane olefinic compounds are satu-
rated in the presence of hydrogen into low octane parraffinic compounds.
As a result, it is necessary to split the desulfurized catalytic cracker
gasoline into a light fraction, which is routed direct to gasoline blend-
ing, and a heavy fraction, which must be reformed to improve its octane
to an acceptable level. It is important to note, however, that direct
desulfurization of FCC gasoline can achieve much lower gasoline sulfur
levels than FCC feed hydrotreating.
One variation in the method of direct desulfurization of catalytic
cracker gasoline is to split the FCC gasoline into a light fraction and a
heavy fraction prior to desulfurization. Evidence to date suggests that
approximately 85% of the sulfur in FCC gasoline is contained in the heavi-
est 25% of the gasoline. By desulfurizing only the heavy fraction, a
major proportion of the sulfur is removed and the reduction of octane is
much less since the olefinic compounds are contained in the light fraction.
The option was not allowed in the base runs because of a lack of quanti-
tative information on the processing steps employed.
Only direct desulfurization of a light coker gasoline has been con-
sidered as a method of reducing its sulfur content (the heavy coker naphtha
is reformed). Direct desulfurization of light coker gasoline has only
been considered in conjunction with the direct desulfurization of FCC
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gasoline. In practice, the same desulfurization unit could be used for
both light coker gasoline and FCC gasoline. Desulfurization of light coker
gasoline alone was not allowed because of the uneconomic size of the unit
that would be required.
One other alternative to reduce the impact of high sulfur light coker
gasoline on the gasoline pool is to burn small quantities as refinery fuel.
In blending of gasolines to 100 ppm and 50 ppm, the computer does not
provide any tolerance in the blending of gasoline component sulfur levels,
i.e., the gasoline blends are exactly at 100 ppm or 50 ppm. The results
of this study are therefore considered to reflect what will be required to
produce unleaded gasolines which on average meet sulfur levels of 100 ppm
and 50 ppm. Should any proposed legislation set maximum specifications of
100 ppm and 50 ppm, it would be necessary to set lower target levels for
refiners, probably at 80 ppm and 40 ppm. This blending tolerance would
be required to ensure that the customer never received gasolines exceeding
100 ppm and 50 ppm. The implications of setting maximum specifications are
discussed later.
The detailed results showing unit throughputs, severities, gasoline
blends, inputs and outputs are given in Appendix J for the base case
(Scenario C), for the manufacture of 100 ppm unleaded gasoline (Scenario
D) and for the manufacture of 50 ppm unleaded gasoline (Scenario E).
A discussion of those results now follows.
B. MANUFACTURE OF 100 PPM GASOLINE
1. 1985 Results
With the exception of the Large Midwest cluster, 100 ppm unleaded
gasoline was manufactured in all the cluster and grassroots model runs by
desulfurization of FCC feedstock, thereby reducing the sulfur level of the
FCC gasoline. In the Large Midwest cluster this method was not capable of
lowering the sulfur level to 100 ppm and direct desulfurization of FCC
gasoline and some light coker gasoline was required.
As summarized in Table 19, the crude oils processed in the Large Mid-
west cluster have an average sulfur level of 1.4 wt. %, the highest of all
the cluster models. This factor, along with the high level of FCC gasoline
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Table 19. RELATIONSHIP OF CRUDE SULFUR LEVEL, FCC INTAKE AND METHOD CHOSEN TO
MANUFACTURE LOW SULFUR (100 PPM) UNLEADED GASOLINE-1985
Crude sulfur level, wt %
FCC intake, % of crude run
Coker intake, % of crude run
Desulfurization option chosen
Cluster
East
Coast
1.08
30
-
FCC feed
Large
Midwest
1.4
35
10
FCC gasoline
Small
Midcontinent
0.53
34
6
FCC feed
Louisiana
Gulf
0.33
37
8
FCC feed
Texas
Gulf
0.76
27
5
FCC feed
West
Coast
1.14
25
20
FCC feed
ON
ON
I
-------
and coker gasoline in the gasoline pool, makes the FCC feed desulfurization
route for the Large Midwest cluster incapable of producing 100 ppia gaso-
line. Catalytic cracking throughput is over 35% of crude run and coking
throughput is 10% of crude run. This cluster model does not have any
hydrocracking which, in all other clusters, provides a significant volume of
gasoline which is virtually sulfur free. Because direct desulfurization of
FCC gasoline is required, there is a significant increase in the require-
ment for catalytic reforming as well, due to the loss of octane in the FCC
gasoline as a result of desulfurization.
The load on the Glaus plant is a complex function of crude run, sulfur
content of the crude, amount of desulfurization capacity, and whether FCC
feed or FCC gasoline is being desulfurized. Furthermore, the amount of
each of these generally varies over the study period. Nevertheless, as
shown in Appendix J, the quantity of sulfur produced generally increases
for the 100 ppm gasoline case (Scenario D) relative to the base case
(Scenario C), particularly after consideration of round-off error.
The West Coast cluster has the next highest average crude oil sulfur
level, 1.14 wt. %. However, catalytic cracking throughput is much lower
than in the Large Midwest cluster, at about 25% of crude run. The West
Coast cluster has the highest level of coking, with coker throughputs at
20% of crude run. Light coker gasoline produced in the coking operation
is of a relatively low octane but has an extremely high sulfur level. To
avoid the need to desulfurize FCC gasoline, approximately 1.5 MB/CD of
light coker gasoline was allowed into the refinery fuel system. Taking
into account the resulting heat equivalency losses (and in practice some
possible investment in conversion of burners), that was still a much more
attractive route than forcing all the light coker gasoline into the gaso-
line pool and having to desulfurize FCC gasoline.
The East Coast cluster, with an average crude oil sulfur level of
1.08 wt. %, has an FCC throughput of 30% of crude run, but does not have
a coking unit. It is able to meet the 100 ppm specification with FCC
feed desulfurization.
The Texas Gulf cluster has catalytic cracking requirements at 27% of
crude run and coking at 5% of crude run. However, the average sulfur level
-67-
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of the crude oil processed is 0.76 wt. % and FCC gasoline desulfurization
was avoided. Only FCC feed desulfurization was used to manufacture 100 ppm
gasoline.
The Small Midcontinent and Louisiana Gulf clusters, with average crude
oil sulfur levels of 0.53 wt. % and 0.33 wt. %, respectively, are able to
meet the 100 ppm level with FCC feed desulfurization.
In the grassroots models, the 100 ppm level was also achieved with
FCC feed desulfurization. Additional refining capacity East of the Rockies
was simulated with both a sour crude oil (Arabian Light) and a sweet crude
oil (Nigerian/Algerian mix) refinery. The sour crude oil refinery, al-
though having a crude oil sulfur level as high as 1.7 wt. %, needed a
catalytic cracking throughput of only 23% of crude runs and was thus able
to avoid FCC gasoline desulfurization. No coking was allowed in the East
of the Rockies grassroots, because of marketing considerations.
Additional refining capacity West of the Rockies was assumed to run
100% Alaskan North Slope crude oil, with a sulfur level of 0.96 wt. %.
However, the catalytic cracking requirement was only 16% of crude run, so
that gasoline at a 100 ppm sulfur level was achieved with FCC feed
desulfurization.
2. 1980 Results
Before executing the 1980 model runs, certain restrictions were placed
on the processing choices available within the model. These restrictions
were based on the results of the 1985 runs and were used to avoid the
selection of different processing options to produce low sulfur unleaded
gasoline in 1980 compared with 1985. Processing options not chosen in the
1985 results were not made available in the 1980 runs. For example, the
Large Midwest cluster required FCC gasoline desulfurization to meet 100 ppm
sulfur gasoline in 1985. Therefore, in 1980 the alternative of FCC feed
desulfurization was not allowed in this cluster model.
In 1980 the percentage of total gasoline produced as low sulfur, un-
leaded gasoline is only 60%; hence, some of the cluster models are able to
meet 100 ppra sulfur gasoline without desulfurization facilities. This is
achieved by blending the high sulfur gasoline components into the leaded
gasolines and the low sulfur components into the unleaded gasoline. There
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is, however, a loss of gasoline production (which is made up by grassroots
refineries) because of the non-optimum blending of gasoline from an octane
standpoint.
The Texas Gulf, Louisiana Gulf, Small Midcontinent and West Coast
cluster models did not require desulfurization facilities by 1980. They do
require some increases in severity and throughput of gasoline-producing
units to compensate for octane losses as a result of different blending
schemes. They produce reduced gasoline volumes when compared with the
unrestricted gasoline sulfur level case. This deficit of gasoline is met
by the grassroots models which do, of course, require desulfurization
facilities. It would therefore be misleading to conclude that no desul-
furization facilities will be required in practice by 1980 for the regions
represented by these four clusters. Desulfurization facilities will be
required by 1980 in all regions to meet the 100 ppm sulfur level and the
total gasoline volume.
3. 1977 Results
The volume of low sulfur, unleaded gasoline produced is approximately
30% of the total gasoline by 1977. In all cluster models except the East
Coast the production of 100 ppm sulfur, unleaded gasoline was achieved by
blending. Desulfurization facilities (FCC feed) were only required in the
East Coast cluster model. It is reasonable to assume, then, that desul-
furization facilities will not be required by 1977 in most refineries which
have the flexibility to meet the 100 ppm level by blending methods.
However, for many small refiners with a limited number of blending
components and treating facilities, desulfurization facilities could well
be required by 1977. Although the results of the cluster models give a
reasonable representation for a major portion of the U.S. refining
industry, they probably do not adequately reflect the situation to be
faced by the small refiner. However, many small refiners preferentially
process low sulfur crude oils and may be able to avoid the need to install
desulfurization facilities by 1977. .
Grassroots model runs were not allowed in 1977. The total U.S. gaso-
line demand, taking into account gasoline imports, was assumed to be met
from existing refineries.
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C. MANUFACTURE OF 50 PPM GASOLINE
1. 1985 Results
As shown in Table 20, the direct desulfurization of FCC gasoline was
required in the Large Midwest cluster model to meet 50 ppm sulfur in the
unleaded pool, with a subsequent increase in the need for catalytic re-
forming. The Texas Gulf Coast cluster model also required this route to
meet the 50 ppm sulfur level. The effect of the combined intakes to the
FCC and coker units made it unable to meet the 50 ppm level with FCC feed
desulfurization.
All other cluster models were able to meet the 50 ppm level with in-
creased requirements for FCC feed desulfurization. In all cases the volume
of gasoline produced in the cluster models was reduced when making 50 ppm
gasoline compared with 100 ppm gasoline, and this loss of gasoline is
made up in the grassroots models.
In the West Coast cluster model the volume of light coker gasoline in
refinery fuel increased to 2.5 MB/CD to allow FCC feed desulfurization to
meet 50 ppm. Light coker gasoline was also routed to refinery fuel in the
Small Midcontinent model to allow FCC feed desulfurization to meet 50 ppm.
The volume, however, was only 300 B/CD for the cluster model.
The grassroots models were still able to meet the 50 ppm level with
desulfurization of FCC feed. The crude oil requirement was much higher for
50 ppm gasoline than for 100 ppm gasoline.
2. 1980 Results
As in the previous discussion of 100 ppm gasoline, the need to install
desulfurization facilities by 1980 is reflected principally in the grass-
roots model. In a similar manner the cluster models for the Louisiana
Gulf, Texas Gulf and West Coast did not show any requirement for desulfuri-
zation facilities; the 50 ppm gasoline being met by blending alone. How-
ever, the loss of gasoline volume as a result of the blending schemes
required to meet 50 ppm gasoline is made up by the grassroots models, which
do require desulfurization facilities. All regions will therefore require
some form of desulfurization facilities by 1980.
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Table 20. RELATIONSHIP OF CRUDE SULFUR LEVEL, FCC INTAKE AND METHOD CHOSEN TO
MANUFACTURE LOW SULFUR (50 PPM) UNLEADED GASOLINE-1985
Cluster
Crude sulfur level, wt %
FCC intake, % of crude run
Coker intake, % of crude run
Desulfurization option chosen
East
Coast
1.08
30
-
FCC feed
Large
Midwest
1.4
35
10
FCC gasoline
Small
Mjdcontinent
0.53
34
6
FCC feed
Louisiana
Gulf
0.33
37
8
FCC feed
Texas
Gulf
0.76
27
5
FCC gasoline
West
Coast
1.14
25
20
FCC feed
-------
3. 1977 Results
Once again the cluster model results (with the exception of the East
Coast) did not show any need for desulfurization facilities by 1977.
While this is probably true of large refineries with good gasoline blend-
ing flexibility, small refineries processing high sulfur crude oils may
require desulfurization facilities by 1977 to be able to manufacture 50
ppm gasoline.
D. SUMMARY OF THE ECONOMIC PENALTIES
The economic impact of manufacturing low sulfur unleaded gasoline on
a U.S. aggregate basis has been calculated by scaling up the results from
the cluster and grassroots model runs, using the methodology developed and
discussed in Appendix G.
The capital requirements based on first quarter 1975 cost data .are
shown in Table 21. To manufacture unleaded gasoj.ine with a sulfur level' of
100 ppm, a total of 2.6 billion dollars (first quarter 1975 basis) will be
required by 1985 and to manufacture 50 ppm gasoline a total of 4.0 billion
dollars (first quarter 1975 basis) will be required by 1985. The method of
calculation of capital requirements is shown in Appendix E. The capital
requirements have also been inflated to estimate the final cost, and they
will increase to approximately 7.0 and 10.4 billion dollars respectively.
The economic penalties in terms of cents per gallon of low sulfur
gasoline produced are given in Table 22. These show that, by 1985, there
will be an additional cost of 0.78 cents per gallon of unleaded gasoline to
manufacture to a sulfur level of 100 ppm, and 1.63 cents per gallon to
manufacture to a sulfur level of 50 ppm, relative to unleaded gasoline
without sulfur control (Scenario C). These costs are based on first
quarter 1975 cost levels and would be about two and a half times greater in
inflated cost terms. The cents per gallon penalties are made up of five
components: capital charge, operating costs, crude penalties, LPG credits
and sulfur credits, details of which can be found in Appendix J. The
breakdown of the 1985 penalties are shown in Table 23. The capital charge
has been set at 25% of investment, crude oil has been valued at $12.50/bbl,
LPG at $8.75/bbl and sulfur at $10/short ton.
-72-
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Table 21. CAPITAL REQUIREMENTS TO MANUFACTURE LOW SULFUR UNLEADED GASOLINE
Millions of Dollars
Non-inflated
(1st Q 1975 basis)
100 PPM gasoline
1977
1980
1985
Total
50 PPM gasoline
1977
1980
1985
Total
Inflated
100 PPM gasoline
1977
1980
1985
Total
50 PPM gasoline
1977
1980
1985
Total
Model results for PAD -IV
East
Coast
98
31
200
329
108
50
271
429
138
61
596
795
152
98
807
1,057
Large
Midwest
58
34
435
527
54
79
492
625
81
66
1,296
1,443
76
154
1,466
1,696
Small
Midcont.
35
(12)
238
261
58
(58)
309
309
49
(23)
709
735
81
(113)
921
889
Louisiana
Gulf
8
37
109
154
9
95
125
229
11
72
325
408
13
186
372
571
Texas
Gulf
-
26
558
584
-
63
490
553
—
51
1,662
1,713
-
123
1,460
1,583
Grass Roots
PAD I-IV
-
150
171
321
-
621
709
1,330
—
293
509
802
— "
1,213
2,112
3,325
Total
PAD I-IV
199
266
1,711
2,176
229
850
2,396
3,475
279
520
5,097
5,896
322
1,661
7,138
9,121
Model results for PAD-V . _ ..
West
Coast
-
27
151
178
—
37
179
216
-
53
450
503
-
72
533
605
Grass Roots
PAD V
-
180
90
270
-
185
92
277
-
352
268
620
-
361
274
635
Total
PAD V
-
207
241
448
-
222
271
493
-
405
718
1,123
—
433
807
1,240
Total
U.S.A.
199
473
1,952
2,624
229
1,072
2,667
3,968
279
925
5,815
7,019
322
2,094
7,945
10,361
(.0
-------
Table 22. ECONOMIC PENALTIES FOR MANUFACTURE OF
LOW SULFUR UNLEADED GASOLINE3
CENTS PER GALLON LOW SULFUR GASOLINE
100 PPM gasoline
1977
1980
1985
50 PPM gasoline
1977
1980
1985
PAD I-IV
0.25
0.39
0.78
0.36
1.17
1.75
PAD V
-
0.69
0.84
—
0.77
0.95
Total
U.S.A.
0.21
0.44
0.78
0.30
1.11
1.63
Relative to unleaded gasoline
-74-
-------
Table 23. BREAKDOWN OF 1985 ECONOMIC PENALTY TO MANUFACTURE
LOW SULFUR UNLEADED GASOLINE3
(1st quarter 1975 cost basis)
100 PPM gasoline • 50 PPM gasoline
Capital charge
Operating costs
Crude penalties 0.30 j
LPG credits (0.14) \
Sulfur credits (0.01) \
cents/gallon
0.55
0.08
0.15
0.78
%
71
10
1.30 1
19 (0.65) V
100 (0.01) )
cents/gallon
0.84
0.15
0.64
1.63
%
52
9
39
100
arelative to unleaded gasoline
-75-
-------
The investment related (capital charge) penalties account for over 70%
of the cost of manufacturing 100 ppm gasoline but these drop to 52% of the
cost of manufacturing 50 ppm gasoline. This is because the net crude oil
and products penalties increase from 0.15 cents/gallon to 0.64 cents/gallon.
This reflects the significant drop in gasoline production capability that
existing refineries would face in trying to manufacture 50 ppm gasoline as
opposed to 100 ppm gasoline.
The capital requirements and economic penalties just described are
estimates based on manufacturing unleaded gasolines with average sulfur
levels of 100 ppm and 50 ppm. Should the proposed regulations require
maximum specifications of 100 ppm and 50 ppm, then the target blending
levels would have to be set at about 80 ppm and 40 ppm.
Based on the results of this study the capital and economic penalties
in 1985 have been estimated for the manufacture of low-sulfur gasolines
with maximum specifications of 100 ppm and 50 ppm and are given in Table 24.
This indicates capital requirements increasing to 3.2 and 4.4 billion
dollars and the economic penalties to 1.12 and 1.99 cents per gallon of
unleaded gasoline, relative to unleaded gasoline without sulfur control
(Scenario C).
E. SUMMARY OF CRUDE OIL AND ENERGY PENALTIES
The model results have been scaled up to give an estimate of the crude
oil and energy penalties on an aggregate U.S. basis in a similar manner to
that used for the economic penalties (Appendix G).
Net energy penalties are comprised of additional crude oil processed
and additional purchased power required, with an energy credit taken for
additional LPG produced. Table 25 gives the net energy penalties that will
be incurred by 1985 to manufacture low-sulfur gasoline, relative to un-
leaded gasoline without sulfur control (Scenario C).
The results show that the manufacture of 100 ppm and 50 ppm gasoline
will result in net energy penalties by 1985 of 42 and 160 thousand barrels
per calendar day of fuel oil equivalent, respectively.
The USA will have to process 78.7 MB/CD and 343.2 MB/CD of additional
crude oil to manufacture 100 ppm and 50 ppm gasoline, respectively, although
-76-
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Table 24. CAPITAL REQUIREMENTS AND ECONOMIC PENALTIES FOR
THE MANUFACTURE OF LOW SULFUR GASOLINE IN 1985 ASSUMING
A 20% BLENDING TOLERANCE (TOTAL U.S.A.)
100 PPM gasoline max.
Blended to 80 PPM
50 PPM gasoline max.
Blended to 40 PPM
Capital requirement
billions of dollars
(1Q 1975 basis)
Economic penalty
cents per gallon
low sulfur gasoline
relative to unleaded gasoline
(1Q 1975 basis)
3.2
1.12
4.4
1.99
-77-
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Table 25. ENERGY PENALTIES IN 1985 FOR THE MANUFACTURE OF LOW SULFUR UNLEADED GASOLINE3
Basis
Additional crude
oil required MB/CD
Additional LPG
produced MB/CD
Additional purchased
power required MKWH/CD
Energy penalties
109 Btu/CD
Crude oil
LPG
Purchased power
Total 109 Btu/CD
Thousands barrels of
fuel oil equivalent
per calendar day
100 PPM gasoline
PAD I-IV
48.0
13.7
3066
268
(54)
31
245
39
PADV
30.7
39.5
687
172
(158)
6
20
3
Total U.S.A.
78.7
53.2
3753
440
(212)
37
265
42
50 PPM gasoline
PAD I-IV
313.3
207.7
6102
1754
(833)
61
982
156
PADV
29.9
36.6
758
167
(147)
7
27
4
Total U.S.A.
343.2
244.3
6860
1921
(980)
68
1009
160
00
I
arelative to unleaded gasoline
-------
it will manufacture more LPG to offset this.
Details of the 1977 and 1980 penalties are to be found in Appendix J,
along with more background data on the 1985 figures.
The energy penalties described above have been based on manufacturing
gasolines with average sulfur levels of 100 ppm and 50 ppm. As in the case
of the economic penalties, an estimate has been made of the energy penalties
that would be incurred if the gasolines were manufactured to meet maximum
specifications of 100 ppm and 50 ppm. This is to reflect the fact that
refineries will require blending tolerances in order to be able to ensure
100 ppm and 50 ppm gasoline production. The results based on the inclusion
of blending tolerances are given in Table 26, relative to unleaded gasoline.
-79-
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Table 26. ENERGY PENALTIES IN 1985 FOR THE MANUFACTURE OF LOW SULFUR UNLEADED GASOLINE
WITH SULFUR BLENDING TOLERANCES OF 20%a
Basis
Additional crude
oil required
Additional LPG
produced
Additional purchased
power required
Energy penalties
109 Btu/CD
Crude oil
LPG
Purchased power
Total 109 Btu/CD
Thousands barrels of
fuel oil equivalent
per calendar day
100 PPM gasoline max. (blended to 80 PPM)
PAD I-IV
154.1
91.3
4192
863
(366)
42
539
85
PADV
30.4
38.3
669
170
(154)
7
23
4
Total U.S.A.
184.5
129.6
4861
1033
(520)
49
562
89
50 PPM gasoline max. (blended to 40 PPM)
PAD I-IV
366.4
246.5
6465
2052
(989)
65
1128
179
PADV
29.7
36.0
725
166
(144)
7
29
5
Total U.S.A.
396.1
282.5
7190
2218
1133
72
1157
184
I
CO
o
I
arelative to unleaded gasoline
-------
IV. SENSITIVITY STUDY RESULTS
A. SULFUR DISTRIBUTION IN FCC UNITS
As mentioned in Section III, the assumed distribution of sulfur among
the products from FCC units has been based on recent work done by Gulf
Research. Although the data published by the Gulf Research study is
the best available, it was based on a limited number of feedstocks. There-
fore, a sensitivity study was carried out to determine the effect of
different FCC gasoline sulfur levels.
In the model runs, the percentage of the FCC feed sulfur that was
assumed to be present in the gasoline product varied between 3.5% and 4.4%
depending on feed source, with the exception of feeds from California
and Alaskan North Slope crude oils. FCC gasoline from California gas oil
was assumed to contain about 9.5% of the feed sulfur, and the FCC gasoline
from North Slope gas oil contained about 7.0% of the feed sulfur. These
percentages applied at conversion levels of 80%. The sensitivity study
examined the impact of assuming all FCC gasolines contained 7.0% of the
feed sulfur at the 80% conversion level. The results of the sensitivity
study (completed for 1985 only) are shown in Table 27.
The sensitivity study indicated that the capital investment required
would increase by 27% to manufacture 100 ppm gasoline, requiring a total
of 3.3 billion dollars (IQ 1975), and by 39% to manufacture 50 ppm gasoline,
requiring a total of 5.5 billion dollars (IQ 1975 basis). Economic penalties
in terms of cents per gallon of low sulfur gasoline produced increased by
similar amounts.
-81-
-------
Table 27. EFFECT OF INCREASED F.C.C. GASOLINE SULFUR LEVELS ON THE 1985
ECONOMIC PENALTY FOR MANUFACTURING LOW SULFUR UNLEADED GASOLINE
FCC sulfur distribution
Capital requirement
billions dollars
(1Q 1975 basis)
Economic penalty
cents per gallon
low sulfur gasoline
relative to unleaded gasoline
(1Q 1975 basis)
100 PPM gasoline
Base
Case
4.7% av
2.6
0.78
Sensitivity
Case
7.0%
3.3
1.02
50 PPM gasoline
Base
Case
4.7% av
4.0
1.63
Sensitivity
Case
7.0%
5.5
2.16
-82-
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B. IMPORTED CRUDE OIL FOR GRASSROOTS CAPACITY
Model runs for the grassroots refineries East of the Rockies were
executed for a sweet crude oil refinery (processing a 50/50 Algerian/
Nigerian mix) and for a sour crude oil refinery (processing Saudi Arabian
Light). The final results were scaled up on the basis that 1/3 of the
grassroots capacity required East of the Rockies, would be sweet crude oil
capacity and 2/3 would be sour crude oil capacity. This sensitivity
study examines the effects on the 1985 economic penalties if all the grass-
roots capacity were based on 100% sweet crude oil and also on 100% sour
crude oil.
The results of the sensitivity study are given in Table 28. Only
minor changes in the total U.S. economic penalties are indicated by this
crude slate sensitivity study, even though a .pronounced impact on the
ability to produce low sulfur fuel oil would be expected.
This sensitivity study did not include the possibility that Arabian
Heavy or Medium crudes could be the primary import oils as a result of
Saudi Arabian marketing policy. However, based upon these results, this
possibility would probably not have a major impact on the economic penalties
to produce low-sulfur gasoline.
C. EFFECT OF TARGET RESIDUAL FUEL OIL SULFUR LEVEL
The sulfur level of the residual fuel oils produced in the cluster
models was allowed to vary, but not to exceed a reasonable maximum specified
for each cluster model. The grassroots models were then used to balance
the volume of residual fuel oil required from U.S. refineries and also to
balance the sulfur level of the fuel oil. Hence, the sulfur level of
residual fuel oil produced in the grassroots models will depend on the
target sulfur level set for the residual fuel oil produced from all U.S.
refineries. A small change in the target sulfur level on residual fuel
oil for the whole U.S.A. will have a significant effect on the sulfur
level required of residual fuel oil produced in the grassroots models
because of the leverage effect (see Section II.C.3.b) of total U.S.
residual fuel oil production compared with grassroots residual fuel oil
production.
-83-
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Table 28. EFFECT OF CHANGING IMPORTED CRUDE OIL TYPE PROCESSED IN
GRASS ROOTS CAPACITY ON THE 1985 ECONOMIC PENALTY FOR MANUFACTURING
LOW SULFUR UNLEADED GASOLINE
Crude oil sulfur, wt %
Capital requirement
billion dollars
(1Q 1975 basis)
Economic penalty
cents per gallon
low sulfur gasoline
relative to unleaded
gasoline
(10 1975 basis)
100 PPM gasoline
Base
case
1.18
2.62
0.78
I mported crude
for Grass Roots
100%
sour
1.68
2.67
0.79
100%
sweet
0.17
2.52
0.77
50 PPM gasoline
Base
case
1.18
3.97
1.63
Imported crude
for Grass Roots
100%
sour
1.68
3.97
1.64
100%
sweet
0.17
3.95
1.62
-84-
-------
The base case study assumed residual fuel oil sulfur target levels of
1.4 wt. % East of the Rockies and 0.90 wt. % West of the Rockies. This
resulted in East of the Rockies grassroots residual fuel oil sulfur levels
of 2.45 wt. % and 2.40 wt. % when manufacturing 100 ppm and 50 ppm
gasoline, respectively. West of the Rockies grassroots production required
residual fuel oil sulfur levels of 1.38 wt. % for both 100 ppm and 50 ppm
gasoline.
This sensitivity study examines the effect of meeting target residual
fuel oil sulfur levels for the whole of the U.S. of 1.2 wt. % East of the
Rockies and 0.75 wt. % West of the Rockies. This required the East of
the Rockies grassroots models to produce residual fuel oils with sulfur
levels of 1.30 wt. % and 1.25 wt. % when manufacturing 100 ppm and 50 ppm
gasoline,respectively. West of the Rockies required residual fuel oil
sulfur levels of 0.75 wt. % for both 100 ppm and 50 ppm gasoline.
The results of this sensitivity study are given in Table 29. The
effect is to increase slightly the capital requirements for the manu-
facture of 50 ppm gasoline. The economic penalty shows no change for
manufacture of 100 ppm gasoline and a small increase for manufacture of
50 ppm gasoline. It can be concluded that the target residual fuel oil
sulfur level has a relatively small impact on the cost of producing low
sulfur gasoline.
D. ALTERNATIVE METHOD OF DESULFURIZING FCC GASOLINE
In Section III, an alternative method of direct desulfurization of cata-
lytic cracker gasoline was discussed, wherein the FCC gasoline was split
and only the heavy fraction desulfurized. The limited data available
suggests that this method would remove 70% to 80% of the sulfur in the
FCC gasoline. At the same time it would avoid having to hydrotreat the
lighter, olefinic fractions in the FCC gasoline, which result in substantial
loss of octane. Since the data available on sulfur distribution within
FCC gasolines is limited, it is very difficult to suggest an optimal
scheme which would achieve the correct balance between sulfur removal
and octane loss. However, refiners who must desulfurize FCC gasolines
(because FCC feed desulfurization will not meet the required sulfur level)
-85-
-------
Table 29. EFFECT OF LOWER TARGET SULFUR LEVEL OF PRODUCTION OF U.S.
RESIDUAL FUEL OIL ON THE 1985 ECONOMIC PENALTY FOR MANUFACTURING
LOW SULFUR UNLEADED GASOLINE
Capital requirement
billion dollars
(1Q 1975 basis)
Economic penalty
cents per gallon
low sulfur gasoline
relative to unleaded
gasoline
(1Q 1975 basis)
100 PPM gasoline
Base
case
2.62
0.78
Lower residual
fuel oil sulfur
2.55
0.78
50 PPM gasoline
Base
case
3.97
1.63
Lower residual
fuel oil sulfur
4.04
1.67
-86-
-------
will undoubtedly choose this alternative method of desulfurizing FCC
gasolines. The more conservative approach of desulfurizing the whole
FCC gasoline with subsequently large octane losses has been assumed in the
study because of lack of available data on the alternative method. The
capital investment requirements and economic and energy penalties calculated
for the manufacture of low-sulfur gasoline are therefore conservative
estimates since it is likely that they can be reduced somewhat by this
alternative method of FCC gasoline desulfurization.
Most cluster and grassroots models choose the FCC feed desulfurization
route to manufacture low-sulfur gasoline. The purpose of this sensitivity
study is to determine if this alternative method of FCC gasoline desulfur-
ization described above was more attractive than the feed desulfurization
route. This alternative FCC gasoline desulfurization route was based upon
desulfurization of the heaviest 25% fraction of the FCC gasoline, which
was assumed to contain 85% of the sulfur. A clear motor octane loss of
only 4 numbers was. assumed when desulfurizing the heavy catalytic cracker
gasoline.
The result of this sensitivity study was that the preferred route
was still FCC feed desulfurization. The main reason for this choice is
that, as a result of desulfurizing the FCC feed, the conversion level in
the FCC unit is increased. Increased conversion levels improve yields
and result in higher motor octane numbers of the FCC gasoline and these
benefits more than offset the higher investment cost for FCC feed
desulfurization versus FCC gasoline desulfurization.
Of course, this preliminary analysis is not sufficient to indicate
that, under all circumstances, refiners would wish to choose the FCC feed
desulfurization route. This will depend on individual circumstances.
-87-
-------
V. DISCUSSION
The most likely route for the majority of refiners to manufacture 100
ppm gasoline will be by FCC feed desulfurization. However, those refiners
with large volumes of coking (typically found in PAD District V) may not be
able to meet the 100 ppm level with FCC feed desulfurization, if all the
light coker gasoline is routed to the gasoline pool. Diverting some light
coker gasoline to the refinery fuel systems will probably enable the FCC
feed desulfurization route to meet the 100 ppm level. Although this results
in a loss of gasoline production capability, it is probably preferred to
the direct desulfurization of FCC gasoline. To manufacture 50 ppm gaso-
line, over half of the U.S. refiners must desulfurize FCC gasoline.
The most significant conclusion that can be derived from the sensi-
tivity studies is the importance of the assumptions with regard to the
distribution of sulfur in the products from catalytic cracking. The esti-
mated capital investment requirements to manufacture 100 ppm gasoline varied
by a factor of 25% depending on the FCC unit sulfur distribution. More data
on this subject is required to provide a better assessment of the penalties
for the manufacture of low-sulfur gasoline.
Throughout this analysis, the impact on small refineries has not been
considered in detail. The capital and economic penalties have been adjusted
to minimize this effect by giving a greater weighting to the results obtained
from the Small Midcontinent cluster. Refineries with a capacity of less than
50,000 barrels per day represent a small enough percentage of the total U.S.
refining capacity and any understatement of the penalties they will incur
will not seriously effect the overall conclusions. However, this group
of refiners represents about half of the total number of refineries and they
may have much more difficulty meeting the regulation than the larger refin-
eries.
-88-
-------
A comparison of the results of this study .with the survey conducted by
1 2
the NPRA ' in 1974 indicates penalties of the same order of magnitude for
the manufacture of low-sulfur gasoline. The NPRA survey covered 148 refin-
eries, accounting for about 95% of the U.S. finished gasoline manufacturing
capability. It indicated a capital investment requirement of some 3.7
billion dollars (average 1974 basis) to manufacture 100 ppm low-sulfur gas-
oline. The NPRA capital investment estimate was presumably based on the
need to meet a maximum specification of 100 ppm. The range of capital in-
vestment requirements (depending on FCC gasoline sulfur levels) to meet a
maximum specification of 100 ppm, based on the results of this study, would
be 3.2 to 4.1 billion dollars (IQ 1975 basis).
The NPRA survey also indicated an increased fuel oil equivalent require-
ment of between 100,000 and 200,000 barrels per day. This compares with the
estimate for this study of total energy penalties of 89,000 barrels per day
of fuel oil equivalent to manufacture gasoline with a maximum specification
of 100 ppm.
-89-
-------
VI. REFERENCES
1. "U.S. Domestic Petroleum Refining Industry's Capability to Manufacture
Low-Sulfur, Unleaded Motor Gasoline", NPRA Special Report No. 4,
August 30 (1974).
2. Oil and Gas Journal. 72, No. 36, p. 48, September 9 (1974).
3. Transcript of FEA & NPRA Refinery Studies Conference on Methods for
Evaluating Policy Impact on the Refinery Industry, Arlington, Va. ,
September 4-5 (1974).
4. Johnson, W.A. and J.R. Kittrell, Transcript of FEA/NPRA Refinery Studies
Conference, p. 170, Arlington, Va., Sept. 4-5 (1974).
5. Oil and Gas Journal. 73. No. 45, 159 (1975).
6. Oil and Gas Journal. 73, No. 42, 25 (1975).
7. "The Impact of Lead Additive Regulations on the Petroleum Refining
Industry", EPA-XXX/X-XX-XXX, December (1975).
8. "The Impact of SOX Emissions Control on the Petroleum Refining Industry",
EPA-YYY/Y-YY-YYY, December (1975).
9. Oil and Gas Journal, Tl, No. 21, p. 76, May 21 (1973).
10. Stahman, Ralph C., "Octane Requirement Increase with Unleaded Fuel",
U.S. EPA Office of Air and Waste Management, Ann Arbor, Mich., July
19 (1975).
11. "Octane Requirements of 1975 Model Year Automobiles Fueled with
Unleaded Gasoline", Technology Assessment and Evaluation Branch, Emission
Control Technology Division, Office of Mobile Source Air Pollution
Control, EPA, August (1975).
12. "Impact of Motor Gasoline Lead Additive Regulations on Petroleum Re-
fineries and Energy Resources - 1974-1980, Phase I", EPA-450/3-74-032-a,
May (1974).
-90-
-------
13. Unzelman, G.H., G.W. Michalski, and W.W. Sabin, Transcript of
FEA/NPRA Refinery Studies Conference, p. 236, Arlington, Va.,
Sept. 4-5 (1974).
14. Peer, E.L. and F.V. Marsik, "Trends in Refinery Capacity and Utili-
zation", Office of Oil and Gas, Federal Energy Administration,
June (1975).
15. Ruling, G.P., J.D. McKinney, and T.C. Readal, Oil and Gas Journal,
73, No. 20, May 19 (1975).
16. Blazek, J.J., Oil and Gas Journal. 69_, No. 45, Nov. 8(1971).
17. Nelson, W.L., Oil and Gas Journal, 72, No. 29, July 22 (1974).
-91-
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
EPA-450/3-76-015a
3. RECIPIENT'S ACCESSION"NO.
4. TITLE AND SUBTITLE
The Impact of Producing Low-Sulfur, Unleaded Gasoline
on the Petroleum Refining Industry
Volume I - Project Summary
5. REPORT DATE
May 1976
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
N. Godley, S. G. Johnson, W. A. Johnson,
J. R. Kittrell, T. G. Pollitt
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Arthur D. Little, Incorporated
Acorn Park
Cambridge, Massachusetts 02140
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
68-02-1332
Task No. 8
12. SPONSORING AGENCY NAME AND ADDRESS
U. S. Environmental Protection Agency
Research Triangle Park, North Carolina
13. TYPE OF REPORT AND PERIOD COVERED
Final Report
27711
14. SPONSORING AGENCY CODE
15. SUPPLEMENTARY NOTES
16. ABSTRACT
The objective of this project was to assess the impact on the U. S. petroleum
refining industry o.f possible EPA regulations restricting the sulfur content of
unleaded gasoline. Sulfur levels of 100 ppm and 50 ppm were considered. Computer
models representative of specific refineries in six geographical regions of the
U. S. were developed as the basis for determining the impact on the existing
refining industry. New refinery construction during the period under analysis
(1975-1985) was considered by development of separate computer models rather than
expansion of existing refineries. These models were utilized to assess investment
and energy requirements and the incremental cost to manufacture low sulfur unleaded
gasoline. Sensitivity analyses examined the effect of variations in key assumptions
on the results of the study, such as the type of imported crude oil available for
future domestic refining and the projected sulfur level of residual fuel oil
manufactured in the U. S. Other sensitivity studies examined in more detail the
processing options available to meet the two sulfur levels and the assumptions
regarding sulfur distribution in refinery process streams.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS C. COSATI Held/Group
Gasoline
Sulfur
Desulfurization
Petroleum Refining
. Octane Number
Unleaded Gasoline
Low Sulfur Unleaded
Gasoline
13, 08
12. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (Tin's Report/
Unclassified
21. NO. OF PAGES
116
20. SECURITY CLASS (This page I
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
92
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