EPA-600/2-76-161a
June 1976
Environmental Protection Technology Series
IMPACT OF SOX EMISSIONS CONTROL ON
PETROLEUM REFINING INDUSTRY
Volume I
Study Results and Planning Assumptions
Industrial Environmental Research Laboratory
Office of Research and Development
U.S. Environmental Protection Agency
Research Triangle Park, North Carolina 27711
-------
RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have oeen grouped into five series. These five broad
categories were established to facilitate further development and application of
environmental technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
The five series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconornic Environmental Studies
This report has been assigned to the ENVIRONMENTAL PROTECTION
TECHNOLOGY series. This series describes research performed to develop and
demonstrate instrumentation, equipment, and methodology to repair or prevent
environmental degradation from point and non-point sources of pollution. This
work provides the new or improved technology required for the control and
treatment of pollution sources to meet environmental quality standards.
EPA REVIEW NOTICE
This report has been reviewed by the U.S. Environmental
Protection Agency, and approved for publication. Approval
does not signify that the contents necessarily reflect the
views and policy of the Agency, nor does mention of trade
names or commercial products constitute endorsement or
recommendation for use.
This document is available to the public through the National Technical Informa-
tion Service. Springfield. Virginia 22161.
-------
EPA-600/2-76-161a
June 1976
IMPACT OF SOx EMISSIONS CONTROL
ON PETROLEUM REFINING INDUSTRY
VOLUME I: STUDY RESULTS AND PLANNING ASSUMPTIONS
by
James R. Kittrell and Nigel Godley
Arthur D. Little, Inc.
20 Acorn Park
Cambridge, Massachusetts 02140
Contract No. 68-02-1332, Task 1
ROAPNo. 21ADC-030
Program Element No. 1AB013
EPA Task Officer: Max Samfield
Industrial Environmental Research Laboratory
Office of Energy, Minerals, and Industry
Research Triangle Park, NC 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, DC 20460
-------
TABLE OF CONTENTS
Volume I
Page
I. EXECUTIVE SUMMARY 1
A. Introduction 1
B. Scope and Approach 2
C. Conclusions 5
1. Calibrat ion Summary 5
2. Qualitative Study Results 6
3. Economic Penalties 10
A. Crude Oil and Energy Penalties 13
5. Sensitivity Studies 13
6. Other Major Implications 15
> / i
D. Recommendations for Further Action 16
II. STUDY BASIS 17
A. Approach 17
B. Case Definitions 20
C. Planning Assumptions 25
1. Crude Slate Proj ections 25
2. U.S. Supply/Demand Projections 28
a. Uniform Product Growth at 2% Per Annum 29
b. Non-Uniform Petroleum Product Growth Rates 30
c. Gasoline Grade Distribution 32
3. Key Product Specifications 32
a. Motor Gasoline Specifications 34
b. Sulfur Content of Residual Fuel Oils 37
iii
-------
TABLE OF CONTENTS - Volume I (cont.)
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. Study Results 66
1. 1985 Results 66
2. 1977 Results 72
C. SUMMARY OF ECONOMIC PENALTIES 74
D. SUMMARY OF CRUDE OIL AND ENERGY PENALTIES 78
IV. SENSITIVITY STUDY RESULTS 80
A. Imported Crude Oil for Grassroots Capacity 80
B. Effect of Target Residual Fuel Oil Sulfur Level 82
C. Use of Stack Gas Scrubbing 84
V. DISCUSSION 85
VI. REFERENCES 87
iv
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LIST OF TABLES
Volume I
Page
TABLE 1. Reduction of SO Emission Lev?! s, 1985 9
x
TABLE 2. Penalties for the Reduction of SO Emissions by Jซ85 12
x
TABLE 3. Effect of Imported Crude Sulfur Content on 1985
Economic Penalties 14
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 44
TABLE 12. Illustrative Blending Octane Number Comparison : 1.. . 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 58
TABLE 18. Model Scale Up Comparison, 1973 61
TABLE 19. Maximum Allowable Sulfur Levels of Fuels Burned in
Refineries 65
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LIST OF TABLES - Volume I - (cont.)
Page
TABLE 20. SO Emission Levels, Total U.S. Basis 1985 67
x
TABLE 21. Percentage Distribution of Sulfur - Large Midwest, 1985. 68
TABLE 22. Sulfur Recovery, SO Emissions, and Sulfur Content of
Gasoline, Salable Fuel Oil, and Refinery Fuel, 1985 70
TABLE 23. Sulfur Recovery, SO Emissions, and Sulfur Content of
Gasoline, Salable Fuel Oil and Refinery Fuel, 1977 73
TABLE 24. Capital Requirements to Reduce Refinery SO
Emission Levels 75
TABLE 25. Economic Penalties for Reducing Refinery SO Emissions . 76
X
TABLE 26. Breakdown of Economic Penalty to Reduce Refinery SO
Emissions 77
TABLE 27. Energy Penalties for Reducing Refinery SO Emissions ... 79
x
TABLE 28. Effect of Changing Imported Crude Oil Type Processed
in Grassroots Capacity on the 1985 Economic Penalty for
Reducing Refinery SO Emissions 81
x
TABLE 29. Effect of Lower Target Sulfur Level of Production
of U.S. Residual Fuel Oil on the 1985 Economic Penalty
for Reduction of SO Emissions 83
x
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LIST OF FIGURES
Volume I Page
FIGURE 1. Agreement of Model Prediction with 1973 B.O.M.
Total Refinery Raw Material Intake Data 7
FIGURE 2. Control of SO Emissions by Source, Large Midwest
Cluster, 1985X 11
FIGURE 3. Historic Trend of Heavy Fuel Oil Sulfur Content as
Produced and Marketed in U. S 39
vli
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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
viii
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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-17
IX
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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-1
1. Crude-Specific Streams J-2
2. Cluster Specific Streams J-3
3. Miscellaneous Streams J-4
X
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TABLE OF CONTENTS - Volume II (cont.)
APPENDIX K
CONVERSION FACTORS AND NOMENCLATURE
APPENDIX L
ALTERNATE FOR REFINERY SO CONTROL STUDY
'"'-""-" L " IL __--r- -I - - Tฃ
FLUE GAS DESULFURIZATION TECHNOLOGY
Page
A. BACKGROUNP L-l
1. Commercial and Near Commercial Technologies L-l
2. Initial Process Selection L-3
B. DETAILED EVALUATION OF SELECTION PROCESSES L-5
1. Basis L-5
a. Technical Assumptions L-5
b. Economic Assumptions L-9
2. Chiyoda L~12
a. Process Description L-12
b. Process Reliability L-15
c. Application to Refinery SO Control L-16
X
d. Capital and Operating Requirements L-17
3. Dual Alkali and Wet Lime Scrubbing L-23
a. Process Description L-23
b. Process Reliability L~26
c. Application to Refinery SO Control L-27
X
d. Capital and Operating Requirements L-28
e. Wet Lime Scrubbing L-33
XI
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TABLE OF CONTENTS - Volume^I (cont. )
APPENDIX L (cont.)
Page
(1) Process Description L-33
(2) Process Reliability L-34
(3) Applicability to Refinery SO Control L-36
J\
4. Magnesia Scrubbing L-38
a. Process Description L-38
(1) SO Absorption L-40
(2) Slurry Processing L-42
(3) Dewatering L-45
(4) Drying ( L-46
(5) Calcining L-46
(6) Slurry Makeup L-48
(7) Sulfuric Acid Production L-48
b. Process Reliability L-50
c. Application to Refinery SO Control L-54
X
d. Capital and Operating Requirements L-57
5. Shell/OOP L-62
a. Process Description L-62
b. Process Reliability L-68
c. Application to Refinery SO Control L-71
X
d. Capital and Operating Requirements L-74
6. Wellman-Lord L-80
a. Process Description L-80
(1) Gas Pretreatment L-81
xii
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TABLE OF CONTENTS - Volume II (cont,)
APPENDIX L (cont.)
Page
(2) SO Absorption L-84
(3) Absorbent Regeneration L-86
(4) System Purge & Makeup L-88
b. Process Reliability L-91
c. Applicability to Refinery SO Control L-94
X
d. Capital and Operating Requirements L-96
(1) Scrubber System L-96
(2) Regeneration System L-99
C. OFF-LINE COMPARATIVE ECONOMIC ANALYSIS L-101
D. CONTROL OF SULFUR PLANT EMISSIONS L-110
1. Alternatives L-110
2. Economics L-113
3. Claus Tail-Gas-Cleanup Processes L-114
E. INTEGRATION OF SO REMOVAL PROCESSES L-116
1. Davy Powergas Process L-116
2. Process Requirements L-118
xiii
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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 g_3
TABLE B-2. A Comparison of Projected "Simulated" Demand
for Major Products with Results of Detailed Forecast .... B-5
TABLE B-3. A Comparison of Projected Total Petroleum Product
Demand in "Simulated" Demand Case With Detailed
Forecast g_6
TABLE B-4. Projection of U.S. Primary Energy Supplies
with Oil as the Balancing Fuel 3-9
TABLE B-5.
Forecast of U.S. Product Demand B-ll
xiv
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APPENDIX C
Page
TABLE C-l. Product Specifications, Gasoline C-2
TABLE C-2. Other Product Specifications C-A
APPENDIX D
TABLE D-l. Refinery Fuel Sulfur Regulations by State D-A
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-A. 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
XV
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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-17
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-14. 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
xvi
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APPENDIX G
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/Out turns 1980 G-8
TABLE G-5. L.P. Model Input/Outturns - 1985 G-9
TABLE G-6. Scale Up Input/Outturns 1977 G-n
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 Removal H-21
TABLE H-13. Stream Qualities - Domestic Crudes H-22
xvii
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APPENDIX H - (cent.)
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
xvriii
-------
APPENDIX * - (cent.)
Page
TABLE 1-4. Bureau of Mines Refinery Fuel Consumption for cluster
Models 1973 I_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
XIX
-------
_APPENDIX__I_ - cont.)
Page
TABLE 1-26. Large Midwest Calibration 1-42
TABLE 1-27. West Coast Calibration 1-43
TABLE 1-28. East Coast Calibration 1-44
APPENDIX J
TABLE J-l. Economic Penalty for Reducing Refinery SO Emissions -
1977 * J-5
TABLE J-2. Economic Penalty for Reducing Refinery SO Emissions -
1985 * J-6
TABLE J-3. Energy Penalty for Reducing Refinery SO Emissions -
1977 J-7
TABLE J-4. Energy Penalty for Reducing Refinery SO Emissions -
1985 * J-8
TABLE J-5. Capital Investment Requirements to Reduce Refinery
SO Emission Levels J-9
x
TABLE J-6. Operating Costs Required to Reduce Refinery SO
Emission Levels * J-10
TABLE J-7. Basis for Cluster Capital Investment Requirements J-ll
TABLE J-8. L.P. Model Results: - Capital Investment Requirements
and Operating Costs - East Coast J-12
TABLE J-9. L.P. Model Results: - Capital Investment Requirements
and Operating Costs - Large Midwest J-13
TABLE J-10. L.P. Model Results: - Capital Investment Requirements
and Operating Costs - Small Midcontinent J-14
TABLE J-ll. L.P. Model Results: - Capital Investment Requirements
and Operating Costs - Louisiana Gulf J-15
TABLE J-12. L.P. Model Results: - Capital Investment: Requirements
and Operating Costs - Texas Gulf j_16
TABLE J-13. L.P. Model Results: - Capital Investment Requirements
and Operating Costs - West Coast J-17
TABLE J-14. L.P. Model Results: - Capital Investment Requirements
and Operating Costs - Grassroots Refinery
East of Rockies J-18
XX
-------
APPENDIX^ J ( cont . )
TABLE J-15. L.P. Model Results - Capital Investment Requirements
and Operating Costs - Grassroots Refinery -
West of Rockies ...................................... J-19
TABLE J-16. L.P. Model Results - Fixed Inputs and Outputs -
East Coast ............................................ J-20
TABLE J-17. L.P. Model Results - Fixed Inputs and Outputs -
Large Midwest ......................................... J-21
TABLE J-18. L.P. Model Results - Fixed Inputs and Outputs -
Small Midcontinent .................................... j-22
TABLE J-19. L.P. Model Results - Fixed Inputs and Outputs -
Louisiana Gulf ........................................ J-23
TABLE J-20. L.P. Model Results - Fixed Inputs and Outputs -
Texas Gulf ............................................ j-24
TABLE J-21. L.P. Model Results - Fixed Inputs and Outputs -
West Coast ............................................ J-25
TABLE J-22. L.P. Model Results - Inputs and Fixed Outputs
Grassroots Refineries ................................. J-26
TABLE J-23. L.P. Model Results - Processing and Variable Outputs
East Coast Cluster .................................... J-27
TABLE J-24. L.P. Model Results - Processing and Variable Outputs -
Large Midwest Cluster ................................. J-28
TABLE J-25. L.P. Model Results - Processing and Variable Outputs
Small Midcontinent Cluster ............................ J-29
TABLE J-26. L.P. Model Results - Processing and Variable Outputs -
Louisiana Gulf Cluster ................................ J-30
TABLE J-27. L.P. Model Results - Processing and Variable Outputs -
Texas Gulf Cluster .................................... J-31
TABLE J-28. L.P. Model Results - Processing and Variable Outputs -
West Coast Cluster .................................... J-32
TABLE J-29. L.P. Model Results - Processing and Variable Outputs -
Grassroots Refineries, 1985 ........................... J-33
TABLE J-30. L.P. Model Results Summary - Gasoline Blending -
East Coast ............. .............................. J~34
xxi
-------
APPENDIX J - (cont.)
Page
TABLE J-31. L.P. Model Results - Gasoline Blending - East Coast .... J-35
TABLE J-32. L.P. Model Results - Gasoline Blending - Large Midwest . J-36
TABLE J-33. L.P. Model Results - Gasoline Blending - Large Midwest . J-37
TABLE J-34. L.P. Model Results Summary - Gasoline Blending -
Small Midcontinent J-38
TABLE J-35. L.P. Model Results - Gasoline Blending -
Small Midcontinent J-39
TABLE J-36. L.P. Model Results Summary - Gasoline Blending -
Louisiana Gulf J-40
TABLE J-37. L.P. Model Results - Gasoline Blending - Louisiana Gulf J-41
TABLE J-38. L.P. Model Results Summary - Gasoline Blending -
Texas Gulf J-42
TABLE J-39. L.P. Model Results Summary - Gasoline Blending -
Texas Gulf J-43
TABLE J-40. L.P. Model Results Summary - Gasoline Blending -
West Coast J-44
TABLE J-41. L.P. Model Results - Gasoline Blending - West Coast J-45
TABLE J-42. L.P. Model Results Summary - Gasoline Blending -
Grassroots Refineries J-46
I
TABLE J-43. L.P. Model Results Summary - Gasoline Blending -
Grassroots Refineries J-47
TABLE1J-44. L.P. Model Results - Residual Fuel Oil Sulfur Levels -
1977 J-48
TABLE J-45. L.P. Model Results - Residual Fuel Oil Sulfur Levels -
1985 T-49
TABLE J-46. L.P. Model Results - Refinery Fuel Sulfur Levels -
1977 1-50
TABLE J-47. L.P. Model Results - Refinery Fuel Sulfur Levels -
1985 J-51
XX11
-------
APPENDIX J - (cont.)
TABLE J-48. Sample Calculations for Mass and Sulfur Balance Page
Texas Gulf 1985, Scenario B/C - Stream Values -
Gas Oil 375-65,0ฐF j_53
TABLE J-49. Sample Calculations for Mass and Sulfur Balance
Texas Gulf 1985 B/C - Desulfurization of
Light Gas Oil j-54
TABLE J-50. Sample Calculations for Mass and Sulfur Balance
Texas Gulf 1985, Scenario B/C - Feed Sulfur Levels ... J-55
TABLE J-51. Sample Calculations for Mass and Sulfur Balance
Texas Gulf 1985, Scenario B/C - Stream Qualities -
Cluster-Specific Streams J-56
TABLE J-52. Sample Calculations for Mass and Sulfur Balance
Texas Gulf 1985 Scenario B/C - Stream Qualities -
Cluster-Specific Streams J-57
TABLE J-53. Specific Gravities for Miscellaneous Streams J-58
TABLE J-54. Mass and Sulfur Balance - Texas Gulf Cluster 1985
Scenario B/C J-59
TABLE J-55. Mass and Sulfur Balance - Texas Gulf Cluster 1985
Scenario F J-67
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
xxiii
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APPENDIX L
TABLE L-l.
TABLE L-2.
TABLE L-3.
TABLE L-4.
TABLE L-5.
TABLE L-6.
TABLE L-7.
TABLE L-8.
TABLE L-9.
TABLE L-10.
TABLE L-ll.
TABLE L-12.
TABLE L-13.
TABLE L-14.
TABLE L-15.
TABLE L-16.
TABLE L-l7.
Development Status of Significant S02 Control
Processes
Page
L-2
Major Sources of SOX Emissions in Refineries L-6
Refinery Sulfur Emission Sources L-7
Unit Costs Applied in Off-Line Economics , L-ll
Chiyoda Thoroughbred 101 Process Estimated Capital Cost
and Operating Requirements - Gas Side L-18
Chiyoda Thoroughbred 101 Process Estimated Capital Cost
and Operating Requirements - Liquor Side L-21
Dual Alkali Process Estimated Capital Cost and Operating
Requirements - Gas Side L-29
Dual Alkali Process Estimated Capital and Operating
Costs - Liquor Side L-31
Capital and Operating Requirements - Magnesium Oxide
Scrubbing System L-58
Capital and Operating Requirements - Magnesium Oxide
Regeneration System L-59
Capital and Operating Cost Estimate - Shell Flue Gas
Desulfurization Acceptor System L-75
Capital and Operating Cost Estimate - Shell Flue Gas
Desulfurization Regeneration/Reduction Section L-77
Capital and Operating Cost Estimates - Wellman-Lord
Scrubbing System L-92
Capital and Operating Cost Estimates - Wellman-Lord
Regeneration System L-97
Flue Gas Desulfurization Processes Off-Line
Comparative Economic L-102
Exxon R and E FCC Scrubbing System Capital and
Operating Requirements L-109
Beavon Tail-Gas-Cleanup Process Typical Investment
and Operating Requirements L-115
XXIV
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APPENDIX L-(cont.)
Page
TABLE L-18. Flue Gas Desulfurization Process Economics -
Capital Requirements L-119
TABLE L-19. Refinery Flue Gas Desulfurization Process
Operating Requirements L-120
TTXV
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VOLUME II
LIST OF FIGURES
APPENDIX F
Page
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-52
APPENDIX L
FIGURE L-l, Process Flow Diagram, Chiyoda Thoroughbred 101 L-13
t
FIGURE L-2. Chiyoda Engineering, Capital Investment
Scrubbing Section L-20
FIGURE L-3. Chiyoda Engineering, Capital Investment
Regeneration Section L-22
FIGURE L-4. Dual Alkali System L-24
FIGURE L-5. Double Alkali, Capital Investment - Scrubbing Section ... L-30
FIGURE L-6. Double Alkali, Capital Investment - Regeneration
Section L-32
FIGURE L-7. Dual Alkali Scrubbing With Lime Regeneration L-35
xxvi
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APPENDIX L (cont.)
Page
FIGURE L-8. Flow Diagram - Magnesia Slurry Scrubbing-Regeneration L-41
FIGURE L-9. MagOx (Chemico) Capital Investment - Scrubbing Section L-60
FIGURE L-10. MagOx (Chemico) Capital Investment - Regeneration Section .. L-61
FIGURE L-ll. Simplified Process Flow Scheme of SFGD L-65
FIGURE L-12. Simplified Flow Scheme of SFGD Demonstration Unit for
Coal Fired Utility Boiler at Tampa Electric, Florida L-73
FIGURE L-13. Shell/UOP, Capital Investment - Acceptor Section L-76
FIGURE L-14. Shell/UOP, Capital Investment - Regeneration Section >. .. L-79
^
FIGURE L-15. Schematic Flowsheet - Wellman-Lord Process L-82
FIGURE L-16. Davy Power Gas, Capital Investment - Scrubbing Section L-98
FIGURE L-17. Davy Power Gas, Capital Investment - Regeneration Section .. L-100
FIGURE L-18. Typical Flow Diagram - Exxon FCC Caustic Scrubbing System .. L-107
FIGURE L-19. Glaus Tail Gas Cleanup - Scheme I and II L-lll
FIGURE L-20. Conceptual Refinery SOX Control System Based on
Wellman-Lord Process L-117
xxvii
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I. EXECUTIVE SUMMARY
A. INTRODUCTION
This report summarizes a study performed forป|thei 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 Producing Low-Sulfur,
Unleaded Motor Gasoline on the Petroleum Refining Industry." Significant
coordination 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 l", 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 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
extensive 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.
In the present report, several scenarios are developed to describe how
-1-
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the petroleum refining industry will likely operate for the next decade,
with and without potential regulations controlling SO emissions from
Jx
the petroleum refining industry. 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 SO emissions
X
in terms of capital investment requirements, increased refining costs per
gallon of total refinery products, 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
petroleum refining industry of a limitation on SO emissions, within
X
reasonable limits of existing technology, from refinery process heaters
and boilers, fluid catalytic cracking units, and sulfur recovery units.
The specific goals of the study are to determine for the period
through 1985 the impact of the control of refinery SO emissions in terms
X
of (a) capital investment requirements; (b) composite increase in refining
costs per gallon of total products, including return on capital, manu-
facturing cost, and yield losses; (c) increased crude oil requirements;
and (d) net energy penalties, reflecting increased crude oil requirements
less the heating value of an increase in tjhe production of refinery by-
products such as liquefied petroleum gases (LPG).
In the study, limitations of present and future refinery configura-
tions 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, and ability of the
construction industry to meet the associated refinery construction needs.
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 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.
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In approaching this problem, it was recognized that there are many
complex interactions in the petroleum refining industry. Also, there is
a necessity for consideration of the secondary impact of certain SO
X
control techniques on refinery process units, including consideration of
their capital investments and operating 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 SO emissions with an optimal, minimum cost selection
X
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 avail-
able. Any additional crude oil required to meet petroleum product demand
was assumed to be imported. Two simulation models, called "grassroots
models," were developed to provide for any new refining capacity which
would be required 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.
-3-
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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 were 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 cluster
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 SO emission level from petroleum refineries is dependent
X
on the nature of the crude oil being refined, a separate study was made
to determine the types of crude oils to be processed by the U.S. refining
industry over the next decade. Estimates of domestic crude oil avail-
ability were made, including quantity and disposition of Alaskan North
Slope and offshore fields. Also, estimates of world-wide 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
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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 total cost of controlling the refinery SO emissions depends
directly upon the demand for petroleum products, a separate forecast was
made of petroleum product supply/demand for the next decade. This forecast
included an evaluation of the demand for products by individual end-use
sector, including the effects of non-petroleum energy sources, conservation,
import levels, expanded petrochemical demand for certain products, and the
future course of governmental regulation in improving energy self-sufficiency
for the U.S.
The impact of SO controls also depends upon certain key product
X
specifications on the fuel oil as well as other major refinery products.
Present and possible future octane requirements on unleaded gasoline were
evaluated. Projections were also made of the future sulfur level require-
ments 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, discussed in detail in the following report.
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
-5-
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effort was undertaken by Arthur D. Little, Inc., in collaboration with
the 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 the regions of the U.S. contain-
ing 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 Administration
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 simulated by a cluster model, but was included in the scale up method.
Thus, as a result of this extensive calibration effort, the cluster models
demonstrate an excellent ability to simulate the existing U.S. petroleum
refining industry, using processing information describing individual
refinery units.
2. Qualitative Study Results
Refinery sulfur oxide (SO ) emissions emanate from three primary sources.
X.
The first is from refinery process furnaces and boilers. Control of these
emissions can be achieved either by restricting the sulfur level in refinery
fuel or by scrubbing the stack gases prior to discharge into the atmosphere.
The second source of SO emissions is from fluid catalytic cracking (FCC)
X
units. These can be .controlled to some extent by desulfurizing the hydro-
carbon feed to the unit or by scrubbing the regenerator stack gas prior to
discharge. The third source of SO emission is from the refinery process
X
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P.A.D. III
0.1% DEVIATION
P.A.D.V
6.8% DEVIATION
P.A.D. II
0.7% 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)
-7-
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which ultimately recovers the sulfur removed in the various treating
processes in an elemental form (for example, a Claus unit). Control of
these emissions is obtained by increased levels of sulfur recovery or by
stack gas scrubbing.
Stack gas scrubbing has not been Included as an alternative in the
detailed computer model in this study of the control of refinery SO
X
emissions, except for Claus units. Preliminary calculations have indicated
f '
that the capital investment requirements to install stack gas scrubbing to
control refinery SO emissions will be at least as great as the alternatives
X
of reducing refinery fuel sulfur levels and FCC feed sulfur levels. Further-
more, FCC feed sulfur reduction results in significant yield benefits in
the FCC unit and would also be required by the majority of refiners to meet
proposed reductions in the maximum allowable sulfur levels in gasoline.
, i
To reduce emissions from process furnaces and boilers, refinery fuel
sulfur levels were reduced consistent with potential regional regulations
for combustion sources.
Emissions from FCC units were controlled by feed desulfurization to a
level that was compatible with existing technology for the desulfurization
of feed to FCC units. The FCC feed was desulfurized to a level of 0.2 wt.%
sulfur or 85% sulfur removal, whichever was the lower.
Emissions from the sulfur recovery plants were reduced by increasing
the level of sulfur recovery to 99.95%. This level of sulfur removal can
be obtained by using the Beavon-Stretford process, for example, to clean up
the tail gases from Claus plants.
The effects of the imposed operational constraints on total refinery
SO emissions is summarized for 1985 in Table 1 for each region in the U.S.
X
By reducing refinery fuel sulfur levels, desulfurizing FCC feed, and
increasing sulfur recovery from the Claus plant, SO emissions from refineries
X
were reduced by 76% for the total U.S., on a weight basis, relative to pro-
jected base emissions levels. The regional variations in percentage emissions
reduction can be attributed to such variables as crude sulfur content, FCC
throughputs and feed quality, level of refinery fuel sulfur allowed, and the
ability to dispose of sulfur in products, given product quality constraints.
-8-
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Table 1. REDUCTION OF BO EMISSION LEVELS, 1985
PAD District
1
II
II
III
III
V
J-IV
V
I-V
Model
East Coast
Large Midwest
Small Midcontinent
Louisiana Gulf
Texas Gulf
West Coast
East Grassroots
West Grassroots
Total U.S. average
Reduction after SO,, control, wt.%a
/C
76
81
75
88
62
72
82
65
76
aRelative to projected base levels of SCซ emissions in petroleum refining industry (Scenario C).
X
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In general, those clusters with high sulfur content crude slates the
East Coast, Large Midwest and East of the Rockies grassroots showed
the highest level of SO emissions reduction.
X
In Figure 2 is shown the disposition of sulfur oxides emissions by
refinery source, for the Large Midwest cluster model in 1985 with and
without imposition of SO controls. The areas on this chart attributable
to each source of SO emissions are proportional to the total SO emissions
x ' x
levels in tons/day. Before controls, the Glaus plant was responsible for
25% of all SO emissions in the refinery, accounting for 3.1% of the sulfur
X
in the crude oil entering the refinery. After controls, the Glaus unit was
responsible for 1% of all SO emissions in the refinery, or 0.03% of the
X
crude oil sulfur. After controls, 83% of the SO emissions from the refinery
A.
originate in the process heaters and boilers; the sulfur limitation on the
fuel burned in these furnaces varied from 0.3, wt.% to 0.5 wt.%, depending
upon the geographic region in which the refinery existed. Obviously, a
high level of SO emissions control has been attained.
X
In this regard, note also that, before controls, 88% of the sulfur
entering the refinery in crude oil is contained either in liquid products
or as elemental sulfur product (i.e., not present as SO emissions). After
X
control, 97.6% of this sulfur is contained either in liquid products or as
elemental sulfur product.
3. Economic Penalties
The economic impact by 1985 on the U.S. refining industry for the
control of SO emissions is shown in Table 2. This shows estimates of the
x
capital requirements to be 4.5 billion dollars on a first quarter 1975 basis.
The final capital requirements are expected to be on the order of 8.8 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 0.71 cents per gallon of total products, based
on first quarter 1975 costs. This includes an annual capital charge of 25%
of the total additional capital investment required.
Of this economic penalty, 65% was for investment related costs, 11% was
for increased operating costs, and 17% was for crude oil costs.
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Glaus emissions
FCC emissions
Refinery fuel emissions
Before
S0x
control
After
SOX
control
o
1% of total SOX
0.03% of crude sulfur
16% of total SOX
0.4% of crude sulfur
83% of total SOX
2% of crude sulfur
FIGURE 2 CONTROL OF SOX EMISSIONS BY SOURCE, LARGE MIDWEST CLUSTER, 1985
(AREA ON CHART REPRESENTS RELATIVE SO EMISSIONS LEVEL IN TONS/DAY)
-------
Table 2. PENALTIES FOR THE REDUCTION OF SOX EMISSIONS BY 1985a
Capital investment required billionscof dollars
Non-inflated (1Q 1975 basis)
Inflated
Total economic penalty
cents per gallon of total products
(1Q 1975 basis)
Additional crude oil required, MB/CD
Net energy penalty (MB/CD FOE)
4.5
8.8
0.71
63
96
3 Relative to Scenario C.
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4. Crude Oil and Energy Penalties
The estimates of the crude oil and energy penalties for SO emissions
controls are also shown in Table 2. By 1985 it is estimated that the U.S.
refining industry will have to process additional crude oil in excess of
60,000 barrels per day. Furthermore, the model results indicate less LPG
is produced, so the net energy penalty by 1985 is estimated to be nearly
100,000 barrels per calendar day of fuel oil equivalent.
5. Sensitivity Studies
A nuinber of sensitivity studies were evaluated; as would be expected,
the impact of reducing SO emissions depends upon the sulfur level of the
X
crude oil being processed. Furthermore, the study projections indicate
that the sulfur content of imported oil for the next decade is uncertain.
Since imported oil is the only source of crude oil assumed for the new
grassroots refineries East of the Rockies, sensitivity analyses were
conducted with this model.
The effects of reducing refinery SO emissions on the East of Rockies
j^
grassroots refineries were determined by model runs for both a sweet crude
oil refinery (processing a 50/50 Algerian/Nigerian crude mix) and for a
sour crude oil refinery (processing 100% Saudi Arabian Light crude). Model
results were scaled up for the base case on the basis that one-third of
East of Rockies grassroots refineries will process a sweet crude slate
and two-thirds will process sour crude. This sensitivity study examines
the effects on 1985 economic penalties if all grassroots refineries East
of Rockies were based on 100% sour crude, and if all were based on 100%
sweet crude.
The results of this sensitivity analysis are shown in Table 3. With
grassroots capacity used for processing all sweet crude, capital investment
for reduction of SO emissions would be 4.1 billion dollars (first quarter
A
. 1975 basis), 430 million dollars less than the base case. If East of
Rockies grassroots capacity is for processing sour crude, the capital
investment for emissions reduction will be 216 million dollars higher than
the base case. Similarly, the economic penalty is .04 cents lower and 0.03
cents higher than the base case for the all-sweet and all-sour crudes,
respectively. -13-
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Table 3. EFFECT OF IMPORTED CRUDE SULFUR CONTENT ON
1985 ECONOMIC PENALTIES
Crude oil sulfur, wt%
Capital investment
Billion dollars
(1Q 1975 basis)
Economic Penalty
Cents per gallon
total products
(1Q 1975 basis)
Base case
1.18
4.5
0.71
Crude for East of Rockies
Grassroots Model
100% Sour
1.68
4.7
0.74
100% Sweet
0.17
4.1
0.67
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Thus, the sulfur content of the crude processed does significantly
affect the magnitude of investment and economic penalties. Furthermore,
other changes in imported crude type, such as higher utilization of Arabian
Heavy crude oil, would be expected to significantly alter the investment
impact of SO emissions controls.
JV
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 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 understate-
ment of their penalties will not significantly affect the overall conclusions.
However, the control of SO emissions could have a significant impact on the
X
smaller refiner. He does not have the wide choice of blending components
available to the larger refiners and little, if any, existing treatment
equipment. For example, few of the small refiners have any existing Glaus
plants for sulfur recovery. Although costs for addition of these plants have
been included in the present study, assessments have not been made of the
ultimate means of disposition of the sulfur product or the financing ability
of the small refiner to install these plants. Because of these considerations
and the economies of scale, the unit cost to the small refiner for SO
3C
emission control will be higher than those indicated in this study. This
could have a significant impact on the competitive structure of the refining
industry.
As is apparent from Figure 1, the emissions from Claus units and FCC
units have been greatly reduced. In fact, the emissions from process heaters
and boilers constitute 83% of the refinery S0x emissions after S0x controls
are instituted, and these flue gas emission controls are more stringent than
normally in effect at the present time in the utility industry. This raises
the possibility that the SO emissions control requirements of the present
study were too stringent for the Claus and FCC units, relative to their
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Importance in contributing to total refinery SO emissions. A detailed
X
assessment of this possibility and proposals of alternative control
strategies have not been made in the present study.
One means of controlling SO emissions is by hydrotreating FCC feed;
J\.
also, FCC gasolines constitute a primary source of sulfur in unleaded
gasoline, possibly leading to sulfate emissions from automobiles employing
catalytic converters. Hence, significant improvement in sulfur content of
unleaded gasoline can be obtained as an indirect result of the strategy
employed herein for refinery SO emissions control. No economic benefit
X
has been included in consideration of the impact of SO controls for this
improvement.
D. RECOMMENDATIONS FOR FURTHER ACTION
In order to assess more fully the impact of refinery SO emissions
X
controls, several areas are worthy of more consideration than possible with
this study:
1. Exploitation of the synergy available from simultaneous
regulations on refinery SO emissions and sulfur content
X
of unleaded gasoline should be explored more thoroughly.
It is possible that there is a point of minimum cost control
for both, with sharply increasing penalties as control of
either variable is made more stringent. This could lead to
a more economic level of control for both sources of sulfur.
2. The impact of SO emissions control should be assessed more
*v
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 industry.
3. Studies should be conducted of interactions of SO emissions
X
regulations and other environmental regulations applicable
to the petroleum refining industry. This investigation should
include examination of possible processing changes used to meet
SO regulations but which are precluded by other environmental
X.
regulations.
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II. STUDY BA^IS
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 refinery sulfur
oxides emissions, taking into consideration limitations of present
refinery configuration and potential grassroots refinery construction.
i i
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 regulation is being interpreted equlvalently by all refiners
across the country, if they are using a similar analytical procedure,
if they are using the 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
individual refineries is well-known and has been 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 is not sufficient in that no single refinery can be said to
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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
produced 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 configura-
tions which will maximize profit derived from the complex. However, this
imethod 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
i
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 meeting
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
necessary 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
3
Refiners Association conference on refining industry modeling.
In order to meet the constraints which would be imposed upon the
refining industry, comprised of nearly 300 individual refineries spread
throughout the United States, Arthur D. Little, Inc., (ADL), representatives
-18-
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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 constructed and calibrated Against the three actual
refineries in each region to ensure that the product blend 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 capacity for those refineries being simulated.
All new crude capacity required to meet increased product demand was met
by the construction of new, grassroots 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 products of the models meet
appropriate quality constraints typical of the prpduct quality demand by
the marketplace over the next decade. Projections of future, product quality
requirements are necessary in order that the study be a realistic representa-
tion 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 over the next
decade, discussed in the planning assumptions for the study.
The impact upon the refining industry which is evaluated in the
present study includes: the capital investment requirements for the
refinery to meet the potential regulation, the composite capital charge
and operating cost expressed per gallon of total product, the crude oil
-19-
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penalty, and the net energy penalty associated with the regulation
(including by-products which have an energy value).
There are other considerations important to the determination of
the impact 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 required to meet the potential
regulation 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 possible regulation is specifically
beyond the scope of this study, as was the impact of the regulation on the
competitive structure of the industry. Also, many 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.
B. CASE DEFINITIONS
The cluster model approach used in the present study of the possible
regulation requiring reduction of sulfur oxide (SO ) emissions from
jฃ
petroleum refineries was also used in two other studies, which were
conducted simultaneously: a study of a possible regulation requiring
reduction of the sulfur content of unleaded gasoline, and (2) reassessment
of promulgated regulations relating to lead additive content of gasoline
(Federal Register, December 6, 1973; January 10, 1973). To conduct these
studies, iix 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 operation and expansion of refining industry
to meet projected petroleum product demand over the next decade.
Scenario B: Manufacture of unleaded gasoline to meet projected
demands, with no lead restrictions on the total gasoline pool or sulfur
restrictions on unleaded gasoline.
-20-
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Scenario C: Manufacture of unleaded gasoline to meet projected
demands, with phased reduction in the lead additive content of the total
gasoline pool, and with no sulfur restrictions.
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 gaseous refinery sulfur-oxide emissions by
restrictions on the sulfur content of the refinery fuel, by restriction of
fluid catalytic cracker regenerator 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. refining
industry, processing configurations, and product outturns and qualities.
However, other planning assumptions which have a possibility of occurring
over the next decade were also considered. Variations in study 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 (RON) 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 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 being consumed in the U.S.
would have a sulfur content of approximately 1.3%. Since this requires
extensive desulfurlzation in the new grassroots refinery facilities,
-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-
-------
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 predominantly 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 (Scenarios C, D, and E) 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 crude 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 lack of importance of sulfur level as a product specification.
Therefore, there is limited information available regarding the sulfur
-23-
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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 sulfur 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 the 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 considera-
tion of both the base case sulfur level as well as the new parametric case
sulfur level.
i
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
desulfurized 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 (Scenarios C and F), 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-
-------
It is felt that the most likely general 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 (Claus
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 application in
the utility industry. Consequently-, parametric runs were undertaken to
determine if the total impact of the regulations reducing sulfur oxide
emissions cpulc} be diminished by application of the utility-based stack gas
scrubbing techniques.
The. present report deals with the impact only of the possible regulation
7 8
reducing sulfur oxides emissions from the refinery. Companion reports '
have been produced which address the impact of the promulgated regulations
i i
for lead additives in gasoline and the consequences of a possible regulation
to reduce the sulfur content of unleaded gasoline. All further discussions
in the present report will be addressed to the possible regulation on
reduction of sulfur oxides emissions.
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. refining
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 the 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 considera-
-25-
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tion of production potential from the North Sea, OPEC countries, 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 significant
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 demand 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 were investigated, allow-
ing 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 nigh-
ty
sulfur crude 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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Table 5. 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
existing 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 next
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 petroleum 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 effect of
introducing 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
determined growth rates to base year consumption data. However, the pattern
of continuous growth was interrupted by massive increases in foreign oil
prices (and later domestic decontrolled prices), the Arab oil embargo, and
a period of economic recession.
The general approach which has been used by ADL in product demand
forecasting is to conduct an indepth analysis of total energy requirements
-28-
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by individual end-uses, which are then matched with projections of supplies
of basic energy sources, including oil, gas, coal, nuclear and hydroelectric
power. Because of the stimulus of high oil prices and considerations 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 feedstock. 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 simultaneous
occurrence of economic recession, mild winters, and high oil prices.
In the current study the demand forecast for the United States refining
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% Per 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
-29-
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key simplifying assumptions: (1) demand for all products grows at one
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 regarding 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 elsewhere 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 projection 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, selective taxes on oil, import tariffs on oil, etc.,
is taken to enhance the effects of higher prices in dampening 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 modifica-
tion 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 constant in the results
of both of these demand forecasts at the 1973 level, as a result of govern-
mental 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 L.P. model studies.
31
-------
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 unloaded 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 regulations on sulfur oxides emissions, the most likely
method to reduce fluid catalytic cracker (FCC) regenerator sulfur oxides
emissions is to hydrotreat the fluid catalytic cracker feedstock. When this
hydrotreating is accomplished, the sulfur levels of all of the FCC products
are diminished, including the sulfur levels of blending components in the
fuel oil pool. To actually represent the cost of emissions 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
inspection for 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 industry 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 specifica-
tions, 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 increasingly
pronounced, a regulation which would specify the lead level of motor
gasoline. Hence, an assessment is required of the likely future course of
governmental regulations on all major products over the next decade.
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.
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Table & 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
I II III IV V
40 29 38 26 50
58 69 60 72 48
22222
00000
ooooo
100 100 100 100 100
b
b
U.S. average
1977
24
68
8
12
56
32
1.0 ~
1.74
1980 1985
30 37
68 61
3 2
3 0
37 0
60 100
0.5 b
1.66 b
asame distribution pattern used as in unleaded (Item B.)
b100% unleaded gasoline
-------
a. Motor Gasoline Specifications -
Among the most important product specification 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 to satisfy the octane requirements of an aging auto-
motive fleet. Evaluation of the impact of producing higher octane unleaded
gasoline is discussed 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. Previous
12
studies have shown that the summer/winter operation can be effectively
simulated by means of an average Reid vapor pressure, reflective 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 to those
placed on gasoline products as follows. For premium gasoline the 150ฐF
distillation temperature is reached between 20 and 28% distilled overhead,
-34-
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Table 7. MOTOR GASOLINE SURVEY DATA
Research octane no.
Motor octane no.
Lead, g/gal
Reid vapor pressure, Ib.
Distillation, ฐF
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.
-35-
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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
ฐAPI
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 i
.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/PPS75/1 Motor Gasoline,
Winter 1974-1975.
-36-
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and the 210ฐF distillation temperature is reached between 42 and 54%
distilled overhead. With regular and unleaded grades the 150ฐF
distillation point is reached between 20 and 30% distilled overhead,
whereas the 210ฐF 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
X
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 PAD 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, discuss-
ions 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 relaxation
of air pollution regulations, particularly if the use of domestic coal is
to be emphasized. Tendencies to use higher sulfur fuel oils when meteor-
ological conditions are favorable and lower sulfur oils when meteorological
qonditions 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 manu-
factured 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. Howeverf 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 refinery 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 state-
wide 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-
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Grade 4 Burner Fuel Oils
0.6
1962 1964 1966 1968 1970 1972 1974
Grade 5 (Light) Burner Fuel Oils
1.2
1962 1964 1966 1968 1970 1972 1974
Grade 5 (Heavy) Burner Fuel Oils
/.u
1.8
1.6 i
1.4
1 ?
s
H
/
^
^1
/
/
^
s
, '
^N
S
S
^
\
\
1962 1964 1966 1968 1970 1972 1974
Grade 6 Burner Fuel Oils
1962 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
Table 9. 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
0.51-7.00
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 oil 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)
v
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. Because 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 desulfur-
ization capability in the grassroots refineries varies accordingly.
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
constructions 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.
The unit yields and product properties were obtained from a variety
of petroleum industry sources. 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
-41-
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Table 10. GRASSROOTS REFINERY FUEL OIL SULFUR PROJECTION - 1985
SCENARIO A - EAST OF ROCKIES ONLY
Total East-of-Rockies3
. 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'5
Sulfur content
(wt%>
1.44
1.44
Fuel oil
(MB/CD)
561.3
561.3
Grassroots refineries'5
Sulfur content
(wt%)
0.63
1.78
Fuel oil
(MBPD)
493
493
aFuel oil produced in refineries plus imports
''Fuel oil produced and marketed in U.S.
-------
same unit yields and product properties were also used in the grassroots
refinery simulations. A complete discussion 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,
because 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 Scenario 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
Intended 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 primary products and by-
products from the fluid catalytic cracking (FCC) unit are particularly
significant to the assessment of the impact of the possible EPA regulation.
For reasons already described, 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 oxides emissions in the refinery. In a parallel study on reducing
Q
sulfur in unleaded gasoline, the sulfur distribution among several products
of the FCC unit were varied in a parametric run, with the distribution shown
in Table 11. It can be seen that the percentage of feedstock sulfur going
-43-
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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
-44-
-------
to coke does not change considerably between the base case and parametric
run. Hence, the effect of FCC sulfur distribution on reducing sulfur oxides
emissions was not further examined in a parametric study. 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 any study of the refining
industry 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 H.
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
assisting in the study. In general 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 delivered
to high pressure desulfurization and hydrocracking units. The low purity
hydrogen system was produced from catalytic reformer units and was dis-
tributed to low pressure desulfurization units. Allowances were provided
fpr 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 is required
-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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cryogenic units can be added without having a major impact on the overall
capital Investment penalty associated with the potential regulations.
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. There-
fore, the cluster model approach was developed for this study, in which
the existing U.S. refinery 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 has 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
III
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
Socal 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
explicitly 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 determining 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 require-
ments); (2) refinery 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
detail 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. refinery 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
-50-
-------
TabU 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.)8
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
aExdudei catalyst coke
-51-
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to provide a conservative assessment of when new capacity is required,
thereby providing a conservative assessment of the penalties associated
with the 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
when reducing refinery SO emissions, an increase in crude run to each
X
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 limitation 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 dis-
tillation 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 con-
sideration 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.
-52-
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The yields and product qualities for new capacity additions were
Identical to those provided in the cluster model operation, with the
exception of catalytic reforming, wherein all new capacity was assumed
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.
. i
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
t
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.
Onslte capital investments were estimated by compositing the information
available from these several sources. The onsite process unit estimates
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 reduction of refinery
SO emissions. Consequently, economic penalties for the cluster models
Jnn
were determined by comparing Scenario F with Scenario C. Therefore, for
the cluster model, only the incremental downstream capacity required for
-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, $/B/SD
1975, 1st quarter
165
185
925
800
1,400
620
1,240
1,400
235
320
230
250
370
775
1,500
930
230a
260a
25,000
50,000
a$/MSCF/SD
-54-
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Scenario F versus Scenario C was determined and costed. As part of this
analysis, charges were assessed for the Utilization of spare, idle
capacity which was available in 1974 but was incrementally consumed at
a faster rate for Scenario F 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 higher in
Scenario F than in Scenario C, then the incremental cost was charged
to Scenario F 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 RON severity operation. Therefore the remaining 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 complete refinery was costed as required
for each scenario. For example, the capital cost for the grassroots
refinery in Scenario F 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
assessment 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 approxi-
mately 200-300% of onsite costs. For these grassroots refineries the
complete onsite plus offsite refinery costs range from about $2900 per barrel
-55-
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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 complexity8
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
574
39.0
96.4
3.0
5.8
70.0
20.0
98.8
aSee reference #17.
-------
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.
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
determined 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 consideration. Maintenance costs were assessed at a level of
3% of onsite investments 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 80<: 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. This
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
-57-
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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
Off site 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
-58-
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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 variety of
factors, such as further increases in foreign oil prices, general inflationary
tendencies in the United States, 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 refining industry will be summarized in the following body of the
report both on a 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
represent 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 foe 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 refineries 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.
-59-
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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 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 calibrated
well with the Bureau of Mines data for the purposes of the present study,
which emphasizes total energy penalties of the refinery and addresses 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 industry.
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
-60-
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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
^^^^^^^^^^^^^^^^^(^^^^^^i
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
^^^^^^^H
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
I II II -'- IIIIPII "IN
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
U"T ' ^ ^ '
-61-
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crude oil distillation capacity for that region, defined as 90% of the
calendar day rated capacity.
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 results
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 Districts
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,
because this approach does not weigh sufficiently heavily the capital
requirements 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.
-62-
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III. STUDY RESULTS
A. BACKGROUND DISCUSSION
SO emissions in refineries emanate from three distinct sources. The
x
first is from refinery process furnaces and boilers. Control of these
emissions can be achieved either by restricting the sulfur level in
refinery fuel or by scrubbing the stack gases prior to discharge into the
atmosphere. The second source of SO emissions is from fluid catalytic
X
cracking (FCC) units. These can be controlled to some extent by limiting
the sulfur content of the feed to the unit or by scrubbing the stack gas
(
prior to discharge. The third source of SO emissions is from the refinery
X
process which ultimately recovers the sulfur removed in the various treating
i
processes in an elemental form (commonly known as the Glaus unit). Control
of these emissions is obtained by increased levels of sulfur recovery or
by stack gas scrubbing.
With the exception of the Claus plant application, stack gas scrubbing
has not been included as an alternative in the computer model in this study
of the control of refinery SO emissions. Preliminary calculations have
X
indicated that the capital investment requirements to install stack gas
scrubbing to control refinery SO emissions will be at least as great as
X
the alternatives of reducing refinery fuel sulfur levels and FCC feed
sulfur levels. Furthermore, FCC feed sulfur reduction results in signifi-
cant yield benefits in the FCC unit and would also be required by the
majority of refiners to meet possible reductions in the maximum allowable
sulfur levels in gasolines.
Since natural gas fuel for refineries was displaced by residual fuel
oil over the study period (due to assumed natural gas curtailment), SO
X.
emissions from process furnaces and boilers became relatively large over
the study period. To reduce emissions from process furnaces and boilers,
-63-
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refinery fuel sulfur levels were reduced consistent with potential regional
regulations for new sources (as discussed in Appendix D). Table 19
summarizes the existing and potential future regulations (used for planning
assumptions in the present study) on maximum allowable sulfur levels of
refinery fuels applied to each computer model. All .cluster models and
the West of Rockies grassroots model have refinery fuel sulfur levels
which are consistent with regulations for their respective PAD districts
(see Appendix D). For the East of the Rockies grassroots, representing
new capacity in Districts I-IV, the maximum allowable refinery fuel sulfur
content under a reduced SO emissions scenario was based on the average of
x
PAD I-IV. In all models the sulfur level of residual fuel oils produced
was also controlled to levels specified in Appendix C to prevent reduction
of emissions by increasing the sulfur level of this product.
Emissions from FCC units were controlled by feed desulfurization to a
level that was compatible with existing technology for the desulfurization
of feed to FCC units. The FCC feed was desulfurized to a level of 0.2 wt.%
sulfur or 85% sulfur removal, whichever was the lower.
Emissions from the sulfur recovery plants were reduced by increasing
the level of sulfur recovery to 99.95%. This level of sulfur removal can
be obtained by using the Beavon-Stretford process, for example, to clean up
18
the tail gases from Claus plants.
The approach taken in this study on reducing refinery SO emissions
X
levels was thus to impose constraints on the operations of the three
sources of SO emissions as discussed above, within reasonable limits of
X
existing technology.
Finally, it should be pointed out that this study was conducted in
parallel with studies on the impact of unleaded gasoline production and
lead phase down. Gasoline and LPG production by the cluster models were
therefore allowed to vary in reaching an optimal solution when changing
operations from the base level of emissions without the above controls
(Scenario C) to the controlled level of emissions (Scenario F). Loss of
gasoline production as a result of the control of refinery SO emissions
X
was then assumed to be made up with the grassroots models.
-64-
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Table 19. MAXIMUM ALLOWABLE SULFUR LEVELS OF FUELS BURNED IN REFINERIES
Region (cluster)
East Coast
Large Midwest
Small Midcontinent
Louisiana Gulf
Texas Gulf
West Coast
West of Rockies Grassroots
East of Rockies Grassroots
Sulfur maximum wt %
Estimated existing regulations8
0.6
1.5
1.5
0.9
0.9
0.7
0.7
1.0
Potential future regulations
0.3
0.5
0.5
0.5
0.5
0.3
0.3
0.4
aSee Appendix D.
-65-
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Detailed results showing unit throughputs, severities, gasoline
blends, inputs and outputs, costs, etc., are given in Appendix J for the
base case (Scenario C) and for the reduction of SO emissions (Scenario F).
A.
Below is a discussion of those results.
B. STUDY RESULTS
1. 1985 Results
The effects on an aggregate U.S. basis of the imposed operational
constraints on total refinery SO emissions is summarized for 1985 in
x
Table 20. By reducing refinery fuel sulfur levels as specified previously,
desulfurizing FCC feed, and increasing sulfur recovery from the Glaus
plant, SO emissions were reduced by 76% for the total U.S. relative to the
X
base case of Scenario C. The regional variations in percentage emissions
reduction can be attributed to such variables as crude sulfur content, FCC
throughputs and feed quality, level of refinery fuel sulfur allowed, and
the ability to dispose of sulfur in products, given product quality con-
straints. In general, those clusters with high sulfur content crude
slatesthe East Coast, Large Midwest and East of Rockies grassrootsshowed
the greatest amount of SOX emissions reduction.
There are significant changes in the disposition of sulfur and its
distribution between recovered elemental sulfur, SO emissions and product
3t
outturns. Table 21 shows sulfur distributions for the base case (Scenario
C) and the reduced emissions case (Scenario F) for the Large Midwest
cluster. Sulfur disposed in all products was, of course, essentially
unchanged with reduced SO emissions. Elemental sulfur production was
X
increased from 59% to 69% of total sulfur output, while sulfur in SO
X
emissions was reduced from 12.4% to 2.4% of the total sulfur entering the
model refinery. In Table 21 it can also be seen that the dominant source
of SO emissions changed considerably. In the base case over half the
X
sulfur in SO emissions originated in the FCC and Claus plants. By
X
controlling SO emissions, over 80% of the sulfur in SO emissions
originated from the combustion of process refinery fuel. Similar results
are found in the other cluster models.
-66-
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Table 20. SO.. EMISSION LEVELS, TOTAL U.S. BASIS 1985
Model
East Coast
Large Midwest
Small Midcontinent
Louisiana Gulf
Texas Gulf
West Coast
West Grassroots
East Grassroots
Total U.S.
Short tons/day
Before control
449
1,323
393
188
1,019
572
165
1,335
5,444
After control
107
254
98
23
387
158
57
240
1.324
Reduction, wt%
76
81
75
88
62
72
65
82
76
-67-
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Table 21. PERCENTAGE DISTRIBUTION OF SULFUR - LARGE MIDWEST, 1985
Sulfur output
To products
Elemental sulfur
SOX emissions
from FCC plant
from Glaus plant
from refinery fuel
Total
Total sulfur output
Percent of Total SOX emissions
From FCC plant
From Glaus plant
From refinery fuel
Scenario C
% of total
28.3
59.3
3.8
3.1
5.5
12.4
100.0
30.4%
25.2
44.4
100.0
Scenario F
% of total
' 28.3
69.3
0.4
2.0
2.4
100.0
15.6%
1.4
83.0
100.0
-68-
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Although the total sulfur disposed in final products did not change
greatly, the distribution of the sulfur among individual products changed
considerably in all clusters. The sulfur contents both before and after
S0x emissions reductions for gasoline, residual fuel oil and internally
consumed oil for refinery fuel are given in Table 22. Also shown are
total elemental sulfur recovered (indicative of Glaus plant throughput)
and SO emissions. In all clusters the sulfur in gasoline was reduced
X
significantly when SO emissions were controlled. The reduction in gaso-
X
line sulfur content ranged from a 61% decrease in the Louisiana Gulf to a
94% decrease in the West Coast. FCC gasoline contributes the major portion
of sulfur to be found in gasoline. Desulfurization of FCC feed to reduce
SO emissions also reduces the sulfur content in the total gasoline pool.
X
Some reductions in residual fuel oil sulfur content similarly took place.
To reduce SO emissions the cluster models did not require significant
J\,
changes in the processing configurations other than the FCC feed desulfuri-
zation and the Beavon-Stretford tail gas cleanup on the Glaus plants.
In the East Coast cluster catalytic reformer and hydrocracker through-
put remained essentially the same under a reduced emissions scenario
versus the base scenario. FCC throughput was increased 5.9 MB/CD. A 2.4
MB/CD drop in alkylation was balanced by a 2.7 MB/CD increase in isomer-
ization.
The major processing change in the Large Midwest cluster was a decrease
of 10.2 MB/CD in FCC throughput and a subsequent 1.1 MB/CD drop in alkylation
throughput, resulting in lower gasoline production. Catalytic reformer and
isomerization throughputs increased by 4 MB/CD and 0.5 MB/CD respectively.
For the Small Midcontinent cluster there were small throughput increases
totaling 1.2 MB/CD in catalytic reforming, FCC, and isomerization. A 1.3
MB/CD decrease in alkylation and reduced FCC conversion resulted in a drop
in gasoline production, to be made up in the grassroots refineries.
In the Louisiana Gulf cluster, FCC throughput was reduced 3.9 MB/CD
and catalytic reforming was correspondingly increased 3.6 MB/CD. Isomer-
ization and alkylation were reduced a total of about 1 MB/CD.
-69-
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Table 22, SULFUR RECOVERY, SOX EMISSIONS, AND SULFUR CONTENT OF GASOLINE.
SALABLE FUEL OIL, AND REFINERY FUEL, 1985
Scenario
Elemental sulfur produced
(T/D)
SOX emissions {T/D)
Sulfur content
Gasoline (PPM)
Salable fuel oil (%wt.)
Refinery fuel (%wt.)
Maximum allowable sulfur
Salable fuel oil (% wt.)
Refinery fuel oil (% wt.)
Cluster
East Coast
C F
114 185
59 14
394 57
1.8 1.03
0.6 0.3
2.0
0.6 0.3
Large
Midwest
C F
174 204
73 14
746 148
0.98 1.13
1.5 0.5
1.5
1.5 0.5
Small
Midcontinent
C F
19 27
24 6
237 65
0.33 0.45
1.4 0.5
1.5
1.5 0.5
Louisiana
Gulf
C F
60 71
24 2
217 84
0.61 0.30
0.4 <0.1
1.5
0.9 0.5
Texas
Gulf
C F
173 229
92 35
309 65
1.22 1.42
0.9 0.5
1.5
0.9 0.5
West
Coast
C F
171 187
47 13
779 47
0.69 0.87
0.7 0.3
1.0
0.7 0.3
. ' . ' -
Grassroots
East of
Rockies
Sour
C F
31 1 365
118 22
433 40
1.97 2.12
1.0 0.4
1.97 2.12
1.0 0.4
East of
Rockies
Sweet
C F
12 18
30 12
70 7
0.41 0.36
0.5 0.4
0.82 0.96
1.0 0.4
West of
Rockies
C F
141 207
55 19
331 31
1.63 1.16
0.7 0.3
1.63 1.16
0.7 0.3
o
-------
A FCC throughput increase for the Texas Gulf cluster was essentially
balanced by a drop in volume conversion to gasoline. Alkylation was reduced
by 2.3 MB/CD. Catalytic reforming and hydrocracking were decreased 1 MB/CD
and 0.4 MB/CD respectively, and isomerization was increased .8 MB/CD.
In the West Coast cluster, catalytic reforming and isomerization were
reduced a total of 1.8 MB/CD. FCC throughput was decreased by 4.3 MB/CD,
however, conversion to gasoline was raised to 72.5% from 68.6% in the base
case.
In the grassroots models, comparisons of process configurations are
less meaningful since some differences will result from the variations in
the cluster model gasoline production. Specifically, due to the purpose of
the grassroots refineries of balancing total demand and refinery outturn
from existing clusters under the two scenarios, grassroots refinery gaso-
line requirements for Scenario F were higher than those under Scenario C.
In general, however, the East of Rockies grassroots cluster representing
sour crude refining showed increases in the throughput of conversion
processes but alkylation was decreased, as well as FCC conversion. The
major change in both the East of Rockies grassroots processing sweet crude
and the West of Rockies grassroots was an increase in catalytic cracker
conversion. All three grassroots clusters showed changes in hydrocracking
throughputthe East grassroots with sour crude increased hydrocracking
3.9 MB/CD, the East grassroots with sweet crude decreased 4.1 MB/CD and
the West grassroots raised hydrocracking throughput 17.7 MB/CD.
Hydrogen production was either decreased slightly or showed no change
in all but the Large Midwest and grassroots clusters. The East of Rockies
sour crude grassroots and West of Rockies grassroots increased hydrogen
generation 12.1 MMSCF/CD and 33.3 MMSCF/CD respectively. This is to meet
higher hydrocracking throughputs mentioned previously in addition to extra
hydrogen needs for desulfurization. In the East of Rockies sweet crude
grassroots the drop in hydrocracker utilization resulted in a decrease of
7.4 MMSCF/CD of hydrogen manufacture. For the Large Midwest cluster, 15.4
MMSCF/CD of additional hydrogen manufacture was necessary to meet the
increased desulfurization requirements.
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Desulfurization of straight run distillate and heavier naphtha
fractions was increased slightly in the East Coast, Large Midwest, Louisiana
Gulf, and East of Rockies grassroots models.
In summary, apart from installation of FCC feed desulfurization
capacity, major processing changes did not occur with reductions in SO
A
emissions.
2. 1977 Results
In general, the results of reducing refinery SO emissions in 1977
X
directionally followed those of 1985. The major processing configuration
differences were those associated with catalytic cracking of desulfurized
feed. As in 1985, additional desulfurization of heavier naphtha and
distillate cuts was required for the East Coast, Large Midwest and
Louisiana Gulf cluster as well as the Texas Gulf cluster.
It is expected that certain processing changes will be required
relative to 1985 results, since the gasoline pool in that year was 100%
unleaded whereas in 1977 about 70% of the gasoline produced was leaded.
For example, in 1985 the base scenario of the Texas Gulf cluster was
operating at a higher level of conversion in order to meet the required
volume of high clear octane product. In 1977, only 31% of the Texas Gulf
gasoline pool was unleaded and hence, total gasoline requirements could
be met at a lower level of cat cracker conversion.
Table 23 shows the 1977 cluster results for elemental sulfur recovery
and SO emissions as well as the sulfur contents of the total gasoline
X
pool, residual fuel oil and refinery fuel. As in 1985, some trade-offs
were achieved in redirecting high sulfur fuel streams to blending for
residual fuel oil product, given reduced allowable refinery fuel sulfur
levels and the capability to absorb additional sulfur in the residual fuel
oil. Again, the gasoline pool sulfur content has been significantly re-
duced with catalytic cracking of desulfurized feed.
Although desulfurization of FCC feed to 0.2 wt. % sulfur and 99.95%
sulfur recovery are possible with existing technology, these operations
are not commonly practiced at present. Hence, it may be unrealistic to
expect that significant installation of these units could practically
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I
-J
Table 23. SULFUR RECOVERY, SOX EMISSIONS, AND SULFUR CONTENT OF GASOLINE,
SALABLE FUEL OIL AND REFINERY FUEL, 1977
Cluster
Scenario
Elemental sulfur produced
(T/D)
SOX emissions (T/D)
Sulfur content
Gasoline (PPM)
Salable fuel oil (% wt.)
Refinery fuel (% wt.)
Maximum allowable sulfur
Salable fuels (% wt.)
Refinery fuels (% wt.)
East Coast
C F
104 185
51 13
324 58
2.00 1.30
0.6 0.3
2.0
0.6 0.3
Large Midwest
C F
156 174
61 13
738 171
0.48 0.94
1.5 0.5
1.5
1.5 0.5
Small
Midcontinent
C F
14 21
21 5
178 58
0.33 0.23
1.3 0.5
1.5
1.5 0.5
Louisiana Gulf
C F
58 71
18 2
258 74
0.60 0.11
0.2 <0.1
1.5
0.9 0.5
Texas Gulf
C F
186 233
74 25
401 75
1.43 1.29
0.9 0.5
1.5
0.9 0.5
West Coast
C F
198 221
46 10
673 111
0.12 0.43
0.7 0.3
1.0
0.7 0.3
-------
be realized by 1977. This factor has been taken into account in the
analysis of economic penalties, discussed below.
C. SUMMARY OF ECONOMIC PENALTIES
The economic impact of reducing refinery SO emissions via the methods
studied here were determined for the total U.S. refining industry by
scaling up the results of the cluster models (Appendix G).
Table 24 shows that the capital investment required to reduce refinery
SO emissions will be 4.5 billion dollars (first quarter 1975 basis) by
x
1985. Taking into account the timing of investment and inflation in re-
finery construction costs the estimate of ultimate capital investment by
1985 is 8.5 billion dollars. This figure assumes that emissions reductions
as defined in the study could be achieved by 1977. Under this assumption,
69% of total investment (on a first quarter 1975 basis) would be required
in 1977. A second estimate of inflated capital investment is provided
in Table 24 which assumes that all capacity needed by 1985 is installed in
1980. Under this assumption the inflated capital investment for the
aggregate U.S. is 8.8 billion dollars.
The economic penalties on a cents per gallon of total products basis
for reduction of SO emissions is given in Table 25. By 1985 the additional
X
costs required to reduce emissions is estimated to be 0.71 cents per gallon
of total products produced. This figure is in terms of first quarter 1975
cost levels and would be increased about two and one-half times to reflect
inflated costs. The cents per gallon penalties are calculated on the basis
of five factorscapital charge, operating costs, crude penalties, LPG
credits and sulfur creditsand are given in more detail in Appendix J.
The capital charge has been set at 25% of investment, crude oil has been
valued at $12.50/bbl, and LPG and sulfur have been valued at $8.75/bbl
and $10/short ton, respectively.
Table 26 shows the breakdown by component of the total penalties for
1985. The largest component of the additional cost is the investment-
related penalty at 65% of the total economic penalty. Although on a total
U.S. basis there is a 26,000 dollars per day credit for sulfur output in
1985 (as shown in Appendix J), when spread among total U.S. products the
credit essentially disappears.
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Table 24. CAPITAL REQUIREMENTS TO REDUCE REFINERY SOV EMISSION LEVELS3
A
millions of dollars
Uninflated
(1st Qtr 1975 basis)
1977
1985
Total
Inflated
1977
1985
Total
Alternate inflated
total b
Clusters representing PAD I-IV
East
Coast
397
38
435
557
113
670
850
Large
Midwest
1,017
(49)
968
1,428
(146)
1,282
1,891
Small
Midcontinent
415
(67)
348
583
(199)
384
680
Louisiana
Gulf
304
7
311
427
21
448
608
Texas
Gulf
599
263
862
841
783
1,624
1,684
Grassroots
PAD I-IV
-
874
874
-
2,604
2,604
1,708
Total
PAD I-IV
2,732
1,066
3,798
3,836
3,176
7,012
7,421
Cluster
PADV
West Coast
389
31
420
546
92
638
821
Grassroots
PADV
-
275
275
-
819
819
537
Total
PADV
389
306
695
546
911
1,457
1,358
Total
U.S. A.
3,121
1,372
4,493
4,382
4,087
8,469
8,779
Ln
aRelative to Scenario C.
Assumes all capacity needed by 1985 is installed by 1980.
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Table 25. ECONOMIC PENALTIES FOR REDUCING REFINERY SOV EMISSIONS3
JC
(cents per gallon total products)
1977
1985
PAD I-IV
0.60
0.71
PADV
0.33
0.72
Total U.S.A.
0.55
0.71
aRelative to Scenario C.
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Table 26. BREAKDOWN OF ECONOMIC PENALTY TO REDUCE
REFINERY SOX EMISSIONS3
(1st quarter 1975 cost basis)
Capital charge"
Operating costs
Crude penalties
LPG penalties (credits)
Sulfur credits
Total
1985
Cents/gallon total products
0.46
0.08
0.12
0.05
-
0.71
% of total penalty
65
11
17
7
-
100
aRelative to Scenario C.
b25% of capital investment required.
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D. SUMMARY OF CRUDE OIL AND ENERGY PENALTIES
As with economic penalties, model results have been scaled up to
give an estimate of total crude oil and energy penalties to the U.S.
refining industry for reducing SO emission levels. Energy penalties
X
are comprised of additional crude oil processed and additional purchased
power required. Also, an energy credit is taken for additional LPG pro-
duced, or if LPG production is less than that in the base scenario, a
penalty is incurred. Table 27 summarizes the scaled up penalties for 1985.
By that year, additional crude oil processing required as a result of re-
ducing emissions will be in excess of 60 MB/CD. Because LPG production
decreased 39.3 MB/CD relative to the base scenario, an additional energy
penalty was incurred. The total U.S. net energy penalty amounts to nearly
100 MB/CD of fuel oil equivalent.
Appendix J contains more detail on the 1985 energy penalties as well
as those for 1977.
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Table 27. ENERGY PENALTIES FOR REDUCING
REFINERY SOX EMISSIONS3
Basis
Additional crude
oil required MB/CD
Additional LPG
produced MB/CD
Additional purchased
power required MKWH/CD
Energy penalties
10ฎ BTU/CD
Crude oil
LPG
Purchased power
Total 109 BTU/CD
Total MB/CD of fuel oil
equivalent
1985
PAD I-IV
47.4
(38.8)
7,891
265
155
79
499
79
PADV
i
*
15.2i
(0.5)
2,224
85
2
22
109
17
Total U.S.A.
62.6
(39.3)
10,115
350
157
101
608
96
aRelative to Scenario C.
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IV. SENSITIVITY STUDY RESULTS
A. IMPORTED CRUDE OIL FOR GRASSROOTS CAPACITY
The effects of reducing refinery SO emissions on the East of Rockies
2v
grassroots refineries were determined by model runs for both a sweet crude
oil refinery (processing a 50/50 Algerian/Nigerian crude mix) and for a
sour crude oil refinery (processing 100% Saudi Arabian light crude). Model
results were scaled up on the basis that one-third of East of Rockies grass-
roots refineries will prpcess a sweet crude slate and two-thirds will process
sour crude, to derive the final results presented in Section III. This
sensitivity study examines the effects on 1985 economic penalties if all
grassroots refineries East of Rockies were based on 100% sour crude, and
if all were based on 100% sweet crude.
The results of this sensitivity analysis are shown in Table 28. With
grassroots capacity used for processing all sweet crude, capital investment
for reduction of SO emissions would be 4.1 billion dollars (first quarter
X
1975 basis), 430 million dollars less than the base case. If East of
Rockies grassroots capacity is for processing of sour crude, the capital
investment for emissions reduction will be 216 million dollars higher than
the base case, or 16% higher than for sweet crude. Similarly, the economic
penalty is .04 cents lower and 0.03 cents higher than the base case for the
all-sweet and all-sour crudes, respectively.
Thus, the sulfur content of the crude processed does significantly
affect the magnitude of investment and economic penalties. It is expected
that processing of crude oils such as Arabian Heavy would have a further
significant effect.
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Table 28. EFFECT OF CHANGING IMPORTED CRUDE OIL TYPE PROCESSED
IN GRASSROOTS CAPACITY ON THE 1985 ECONOMIC PENALTY FOR
REDUCING REFINERY SOX EMISSIONS
Crude oil sulfur, wt%
Capital investment
million dollars
(1Q 1975 basis)
Economic penalty
cents per gallon
Total products
(IQ 1975 basis)
Base case
1.18
4,493
0.71
Imported crude for grassroots
100% sour
1.68
4,709
0.74
100% sweet
0.17
4,063
0.67
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B. EFFECT OF TARGET RESIDUAL FUEL OIL SULFUR LEVEL
The sulfur levels of the residual fuel oils produced in the cluster
models were 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 re-
sidual 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 of total U.S. residual fuel oil production compared with grassroots
residual fuel oil production (see Table 10).
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 re-
sulted in an East of the Rockies grassroots residual fuel oil sulfur level
of 2.12 wt. % when reducing refinery SO emissions. West of the Rockies re-
X
quired a residual fuel oil sulfur level of 1.16 wt. % for emissions re-
duction.
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 oil with a sulfur level
of 0.96 wt. % when reducing SO emissions. West of the Rockies required
x
a residual fuel oil sulfur level of 0.53 wt. % for reduction of emissions.
The results of the sensitivity study are provided in Table 29. The
effect is to increase the capital investment about 100 million dollars, with
no change in the economic penalty. Thus, the target residual fuel oil
sulfur level has a relatively small impact on the cost of reducing refinery
SO emissions.
x
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Table 29. EFFECT OF LOWER TARGET SULFUR LEVEL OF PRODUCTION
OF U.S. RESIDUAL FUEL OIL ON THE 1985 ECONOMIC PENALTY
FOR REDUCTION OF SOX EMISSIONS
Base case
Lower residual
fuel oil sulfur
Capital investment
Millions dollars
(IQ 1975 basis)
Economic penalty
Cents per gallon
Total products
(IQ 1975 basis)
4,493
0.71
4,603
0.71
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C. USE OF STACK GAS SCRUBBING
A detailed investigation was made of the potential of stack gas
scrubbing as a means to control refinery SO emissions, as reported in
3C
Appendix L. The results indicated that the capital investment require-
ments to install stack gas scrubbing will be at least as great as the
alternatives discussed herein. Since the route of desulfurizing FCC
feedstock also results in significant yield benefits in controlling FCC
emissions, stack gas scrubbing was not allowed in the computer model studies
of the FCC unit. Since the cluster models represent existing refineries
with many dispersed stacks, it was also not used to control emissions from
process furnaces and boilers. However, stack gas scrubbing was used in
the model to control Claus plant SO emissions.
x
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V. DISCUSSION
The intent of this study was to assess the impact of imposing
operational constraints on the three sources of refinery SO emissions
process furnaces and boilers, FCC units, and Glaus plants. On a total
U.S. basis, final results indicate that a 76% reduction in SO emissions
x
below estimated current levels can be achieved within reasonable limits
of existing technology but with substantial investment of capital by the
refining industry. This assumes the control of SO emissions by reducing
refinery fuel sulfur content, by desulfurization of FCC feed, and by
increased sulfur recovery in Claus plants.
To effect even greater levels of emissions reductions would require
stack gas scrubbing. As discussed in Section III, capital investment re-
quirements for installation of stack gas scrubbers are anticipated to be
at least as high as the alternatives of reducing refinery fuel and FCC
feed sulfur levels. In addition, FCC feed desulfurization exhibits yield
benefits that, given the concerns of Project Independence, cannot be over-
looked. FCC feed desulfurization also contributes a substantial reduction
of sulfur in the gasoline pool and in fact would be required by a majority
of refiners to meet possible regulations on maximum allowable unleaded
gasoline sulfur contents. Finally, although stack gas scrubbing plants
have been employed in the utility industry, they have not been widely
demonstrated in the petroleum refining industry. Extensive discussion of
the evaluation of the applicability of stack gas scrubbing to the refining
industry is contained in Appendix L.
The results of our sensitivity analysis on the type of crude oil
processed indicate that the impact of emissions reduction will vary de-
pending on the sulfur content of crudes available to particular refiners.
As discussed in Section III, all model runs were required to remove at least
-85-
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85% of sulfur in FCC feed. However, some Middle East type cuts would
require 95% desulfurization to reach the target 0.2 wt. % FCC feed sulfur
level. This would, of course, involve greater operating costs and invest-
ment penalties.
This study did not specifically address the impact of reducing SO
X
emissions on the small refiner by simulation of his operations. Penalties
were adjusted by giving greater weight to results from the Small Midcontinent
cluster to take account of higher costs due to economies of scale. Since
these small refineries represent a relatively small percentage of total
U.S. refining capacity, any underestimation of penalties to the small
refiner will not appreciably alter the overall results of this study. This
is not to say that the small refiner would be uneffected, for impacts on
the total U.S. refining industry would translate into higher relative
economic penalties for the small refiner which could be difficult to
finance, would require installation of Glaus plants often not now in place,
and could require difficult means to dispose of elemental sulfur produced.
These factors could have a significant effect on the competitive structure
of the petroleum refining industry.
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VI. REFERENCES
1. "U.S. Domestic Petroleum Refining Industry's Capability to Manufacture
Low-Sulfur, Unleaded Motor Ga'soline", 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, 7j3, No. 45, 159 (1975).
6. Oil and Gas Journal, ^3_, No. 42, 25 (1975).
i
7. "The Impact of Lead Additive Regulations on the Petroleum Refining
Industry", EPA-XXX/X-XX-XXX, December (1975).
8. "The Impact of Producing Low-Sulfur, Unleaded Motor Gasoline on the
Petroleum Refining Industry", EPA-rXXX/X-XX-XXX, December (1975).
9. Oil and Gas Journal, 71, 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, Michigan, 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).
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).
-87-
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14. Peer, E.L. and F.V- Marsik, "Trends in Refinery Capacity and Utilization",
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)
18. "Characterization of Claus Plant Emissions", EPA-R2-73-188,
EPA Office of Research and Monitoring, April (1973).
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TECHNICAL REPORT DATA
ft lease read Instructions on the reverse before completing)
REPORT NO.
EPA-600/2-76-161a
4. TITLE ANDSUBTITLE
2.
Impact of SOx Emissions Control on
Petroleum Refining Industry
Volume I. Study Results and Planning Assumptions
3. RECIPIENT'S ACCESSION-NO.
5. REPORT DATE
June 1976
6. PERFORMING ORGANIZATION CODE
1. AUTHOR(S)
James R. Kittrell and Nigel Godley
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING OR9ANIZATION NAME AND ADDRESS
Arthur D. Little, Inc.
20 Acorn Park
Cambridge, Massachusetts 02140
10. PROGRAM ELEMENT NO.
1AB013; ROAP 21ADC-030
11. CONTRACT/GRANT NO.
68-02-1332, Taskl
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Task Final; 9/73-5/76
14. SPONSORING AGENCY CODE
EPA-ORD
i SUPPLEMENTARY NOTES IERL_RTP Task officer for this repOrt is Max Samfield, Mail
Drop 62, (919) 549-8411, Ext 2547.
16. ABSTRACT The repOrt gives results of an assessment of the impact on the U.S. petro-
leum refining industry of a possible EPA regulation limiting the level of gaseous
refinery sulfur oxide (SOx) emissions. Computer models representing specific refi-
nerie^ in six geographical regions of the U.S. were developed as the basis for deter-
mining the impact on the existing refining industry. New refinery construction during
the period under analysis (1975-1985) was also considered by development of computer
models representing new grassroots refineries. Control of refinery SOx emissions
from both existing and new refineries was defined for the purposes of this study by
maximum sulfur levels on refinery fuel and on fluid catalytic cracking unit feedstock
and by increased sulfur recovery in the Glaus plant. The computer models thus
constrained were utilized to assess investment and energy requirements to meet the
possible regulation and the incremental cost to manufacture all refinery products as
a result of the regulation. Parametric studies evaluated the impact of variations in
the types of imported crude oils available for future domestic refining and the projec-
ted sulfur level of residual fuel oil manufactured in the U.S.
17.
KEY WORDS AND DOCUMENT ANALYSIS
a.
DESCRIPTORS
Air Pollution
Sulfur Oxides
Petroleum Industry
Petroleum Refining
Refineries
Catalytic Cracking
b.lDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Air Pollution Control
Stationary Sources
Refinery Fuel
Claus Plant
13B
07B
05C
13H
131
07A
18. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (This Report)
Unclassified
116
20. SECURITY CLASS (Thispage)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
89-
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